ITEM 1A.
RISK FACTORS
You should carefully consider each of the following risks and all of the information provided elsewhere in this Report. If any of the risks described below or elsewhere in this Report were actually to occur, our business, financial condition, results of operations, or cash flows could be materially and adversely affected. In that case, we may be unable to pay interest on, or the principal of, our debt securities, the trading price of our common stock could decline, and you could lose all or part of your investment.
Oil and natural gas prices are very volatile. A decline in commodity prices could materially and adversely affect our financial condition, results of operations, liquidity, and cash flows.
The oil and natural gas markets are very volatile, and we cannot accurately predict future oil and natural gas prices. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty, and a variety of additional factors that are beyond our control, such as:
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overall domestic and global economic conditions;
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weather conditions;
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political and economic conditions in oil and natural gas producing countries, including those in the Middle East, Africa, and South America;
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actions of the Organization of Petroleum Exporting Countries and state-controlled oil companies relating to oil price and production controls;
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the impact of U.S. dollar exchange rates on oil and natural gas prices;
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technological advances affecting energy consumption and energy supply;
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domestic and foreign governmental regulations and taxation;
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the impact of energy conservation efforts;
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the proximity, capacity, cost, and availability of oil and natural gas pipelines and other transportation facilities;
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the availability of refining capacity; and
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the price and availability of alternative fuels.
The worldwide financial and credit crisis has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide. The shortage of liquidity and credit combined with substantial losses in worldwide equity markets could lead to an extended worldwide economic recession. A slowdown in economic activity caused by a recession has reduced worldwide demand for energy and resulted in lower oil and natural gas prices. Oil prices declined from record levels in early July 2008 of over $140 per Bbl to below $39 per Bbl in mid-February 2009 and natural gas prices have declined from over $13 per Mcf to below $4.25 per Mcf over the same period. In addition, the forecasted prices for 2009 have also declined. Notwithstanding significant declines in oil and natural gas prices since July 2008, there has not been a corresponding decrease in oilfield service costs as of February 2009. If oilfield service costs remain elevated in relation to prevailing oil and natural gas prices, our results of operations and cash flows could be adversely affected.
Our revenue, profitability, and cash flow depend upon the prices of and demand for oil and natural gas, and a drop in prices can significantly affect our financial results and impede our growth. In particular, declines in commodity prices will:
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negatively impact the value of our reserves, because declines in oil and natural gas prices would reduce the amount of oil and natural gas that we can produce economically;
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reduce the amount of cash flow available for capital expenditures, repayment of indebtedness, and other corporate purposes; and
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result in a decrease in the borrowing base under our revolving credit facility or otherwise limit our ability to borrow money or raise additional capital.
An increase in the differential between benchmark prices of oil and natural gas and the wellhead price we receive could adversely affect our financial condition, results of operations, and cash flows.
The prices that we receive for our oil and natural gas production sometimes trade at a discount to the relevant benchmark prices, such as NYMEX. The difference between the benchmark price and the price we receive is called a differential. We cannot accurately predict oil and natural gas differentials. For example, the oil production from our Elk Basin assets has historically been sold at a higher discount to NYMEX as compared to our Permian Basin assets due to competition from Canadian and Rocky Mountain producers, in conjunction with limited refining and pipeline capacity from the Rocky Mountain area, and corresponding deep pricing discounts by regional refiners. Increases in differentials could significantly reduce our cash available for development of our properties and adversely affect our financial condition, results of operations, and cash flows.
Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
It is not possible to measure underground accumulations of oil or natural gas in an exact way. In estimating our oil and natural gas reserves, we and our independent reserve engineers make certain assumptions that may prove to be incorrect, including assumptions relating to oil and natural gas prices, production levels, capital expenditures, operating and development costs, the effects of regulation, and availability of funds. If these assumptions prove to be incorrect, our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classification of reserves based on risk of recovery, and our estimates of the future net cash flows from our reserves could change significantly.
Our Standardized Measure is calculated using prices and costs in effect as of the date of estimation, less future development, production, abandonment, and income tax expenses, and discounted at 10 percent per annum to reflect the timing of future net revenue in accordance with the rules and regulations of the SEC. The Standardized Measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved reserves. We base the estimated discounted future net cash flows from our estimated proved reserves on prices and costs in effect on the day of estimate. Over time, we may make material changes to reserve estimates to take into account changes in our assumptions and the results of actual development and production.
The reserve estimates we make for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories. A lack of production history may contribute to inaccuracy in our estimates of proved reserves, future production rates, and the timing of development expenditures.
The timing of both our production and our incurrence of expenses in connection with the development, production, and abandonment 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 percent discount factor we use 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 us or the oil and natural gas industry in general.
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Our oil and natural gas reserves naturally decline and the failure to replace our reserves could adversely affect our financial condition.
Because our oil and natural gas properties are a depleting asset, our future oil and natural gas reserves, production volumes, and cash flows depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically. We may not be able to develop, find, or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition, and results of operations.
We need to make substantial capital expenditures to maintain and grow our asset base. If lower oil and natural gas prices or operating difficulties result in our cash flows from operations being less than expected or limit our ability to borrow under our revolving credit facility, we may be unable to expend the capital necessary to find, develop, or acquire additional reserves.
Price declines may result in a write-down of our asset carrying values, which could have a material adverse effect on our results of operations and limit our ability to borrow funds under our revolving credit facility.
Declines in oil and natural gas prices may result in our having to make substantial downward revisions to our estimated reserves. If this occurs, or if our estimates of development costs increase, production data factors change, or development results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties and goodwill. If we incur such impairment charges, it could have a material adverse effect on our results of operations in the period incurred and on our ability to borrow funds under our revolving credit facility. In addition, any write-downs that result in a reduction in our borrowing base could require prepayments of indebtedness under our revolving credit facility.
If we do not make acquisitions, our future growth could be limited.
Acquisitions are an essential part of our growth strategy, and our ability to acquire additional properties on favorable terms is important to our long-term growth. We may be unable to make acquisitions because we are:
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unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;
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unable to obtain financing for these acquisitions on economically acceptable terms; or
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outbid by competitors.
Competition for acquisitions is intense and may increase the cost of, or cause us to refrain from, completing acquisitions. If we are unable to acquire properties containing proved reserves, our total level of proved reserves could decline as a result of our production. Future acquisitions could result in our incurring additional debt, contingent liabilities, and expenses, all of which could have a material adverse effect on our financial condition and results of operations. Furthermore, our financial position and results of operations may fluctuate significantly from period to period based on whether significant acquisitions are completed in particular periods.
Any acquisitions we complete are subject to substantial risks that could adversely affect our financial condition and results of operations.
Any acquisition involves potential risks, including, among other things:
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the validity of our assumptions about reserves, future production, revenues, capital expenditures, and operating costs, including synergies;
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an inability to integrate the businesses we acquire successfully;
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a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;
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a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;
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the assumption of unknown liabilities, losses, or costs for which we are not indemnified or for which our indemnity is inadequate;
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the diversion of management’s attention from other business concerns;
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an inability to hire, train, or retain qualified personnel to manage and operate our growing business and assets;
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natural disasters;
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the incurrence of other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation, or restructuring charges;
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unforeseen difficulties encountered in operating in new geographic areas; and
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customer or key employee losses at the acquired businesses.
Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses, and seismic and other information, the results of which are often inconclusive and subject to various interpretations.
Also, our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition given time constraints imposed by sellers. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to fully assess their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken.
A substantial portion of our producing properties is located in one geographic area and adverse developments in any of our operating areas would negatively affect our financial condition and results of operations.
We have extensive operations in the CCA. Our CCA properties represented approximately 40 percent of our proved reserves as of December 31, 2008 and accounted for 30 percent of our 2008 production. Any circumstance or event that negatively impacts production or marketing of oil and natural gas in the CCA would materially affect our results of operations and cash flows.
Our commodity derivative contract activities could result in financial losses or could reduce our income and cash flows. Furthermore, in the future our commodity derivative contract positions may not adequately protect us from changes in commodity prices.
To reduce our exposure to fluctuations in the price of oil and natural gas, we enter into derivative arrangements for a significant portion of our forecasted oil and natural gas production. The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities, as well as to the ability of counterparties under our commodity derivative contracts to satisfy their obligations to us. For example, the derivative instruments we utilize are based on posted market prices, which may differ significantly from the actual prices we realize on our production. Changes in oil and natural gas prices could result in losses under our commodity derivative contracts.
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Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the notional amount of our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from the sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our derivative activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, our derivative activities are subject to the following risks:
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a counterparty may not perform its obligation under the applicable derivative instrument, which risk may have been exacerbated by the worldwide financial and credit crisis; and
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there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received, which may result in payments to our derivative counterparty that are not accompanied by our receipt of higher prices from our production in the field.
In addition, certain commodity derivative contracts that we may enter into may limit our ability to realize additional revenues from increases in the prices for oil and natural gas.
We have oil and natural gas commodity derivative contracts covering a significant portion of our forecasted production for 2009. These contracts are intended to reduce our exposure to fluctuations in the price of oil and natural gas. We have a much smaller commodity derivative contract portfolio covering our forecasted production for 2010, 2011, and 2012, and no commodity derivative contracts covering production beyond 2012. After 2009 and unless we enter into new commodity derivative contracts, our exposure to oil and natural gas price volatility will increase significantly each year as our commodity derivative contracts expire. We may not be able to obtain additional commodity derivative contracts on acceptable terms, if at all. Our failure to mitigate our exposure to commodity price volatility through commodity derivative contracts could have a negative effect on our financial condition and results of operation and significantly reduce our cash flows.
The counterparties to our derivative contracts may not be able to perform their obligations to us, which could materially affect our cash flows and results of operations.
As of December 31, 2008, we were entitled to future payments of approximately $387.6 million from counterparties under our commodity derivative contracts. The worldwide financial and credit crisis may have adversely affected the ability of these counterparties to fulfill their obligations to us. If one or more of our counterparties is unable or unwilling to make required payments to us under our commodity derivative contracts, it could have a material adverse effect on our financial condition and results of operations.
We have limited control over the activities on properties we do not operate.
Other companies operated approximately 21 percent of our properties (measured by total reserves) and approximately 46 percent of our wells as of December 31, 2008. We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in development or acquisition activities and lead to unexpected future costs.
Our development and exploratory drilling efforts may not be profitable or achieve our targeted returns.
Development and exploratory drilling and production activities are subject to many risks, including the risk that we will not discover commercially productive oil or natural gas reserves. In order to further our development efforts, we acquire both producing and unproved properties as well as lease undeveloped acreage
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that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not be required to impair our initial investments.
In addition, 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 will be productive, or that we will recover all or any portion of our investment in such unproved property or wells. The costs of drilling and completing wells are often uncertain, and drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors, including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents, weather conditions, and shortages or delays in the delivery of equipment. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry holes, but also from wells that are productive but do not produce sufficient commercial quantities to cover the development, operating, and other costs. In addition, wells that are profitable may not meet our internal return targets, which are dependent upon the current and future market prices for oil and natural gas, costs associated with producing oil and natural gas, and our ability to add reserves at an acceptable cost.
Seismic technology does not allow us to obtain conclusive evidence that oil or natural gas reserves are present or economically producible prior to spudding a well. 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 use of seismic data and other technologies also requires greater up-front costs than development on proved properties.
Developing and producing oil and natural gas are costly and high-risk activities with many uncertainties that could adversely affect our financial condition or results of operations.
The cost of developing, completing, and operating a well is often uncertain, and cost factors can adversely affect the economics of a well. If commodity prices decline, the cost of developing, completing and operating a well may not decline in proportion to the prices that we receive for our production, resulting in higher operating and capital costs as a percentage of oil and natural gas revenues. For instance, oil and natural gas prices declined from record levels in early July 2008 of over $140 per Bbl and $13 per Mcf, respectively, to below $39 per Bbl and $4.25 per Mcf, respectively, in mid-February 2009. Notwithstanding significant declines in oil and natural gas prices since July 2008, there has not been a corresponding decrease in oilfield service costs as of February 2009. If oilfield service costs remain elevated in relation to prevailing oil and natural gas prices, our results of operations and cash flows could be adversely affected. Our efforts will be uneconomical if we drill dry holes or wells that are productive but do not produce as much oil and natural gas as we had estimated. Furthermore, our development and production operations may be curtailed, delayed, or canceled as a result of other factors, including:
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higher costs, shortages, or delivery delays of rigs, equipment, labor, or other services;
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unexpected operational events and/or conditions;
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reductions in oil and natural gas prices;
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increases in severance taxes;
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limitations in the market for oil and natural gas;
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adverse weather conditions and natural disasters;
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facility or equipment malfunctions, and equipment failures or accidents;
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title problems;
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pipe or cement failures and casing collapses;
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compliance with environmental and other governmental requirements;
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environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures, and discharges of toxic gases;
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lost or damaged oilfield development and service tools;
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unusual or unexpected geological formations, and pressure or irregularities in formations;
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loss of drilling fluid circulation;
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fires, blowouts, surface craterings, and explosions;
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uncontrollable flows of oil, natural gas, or well fluids; and
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loss of leases due to incorrect payment of royalties.
If any of these factors were to occur with respect to a particular field, we could lose all or a part of our investment in the field, or we could fail to realize the expected benefits from the field, either of which could materially and adversely affect our revenue and profitability.
Secondary and tertiary recovery techniques may not be successful, which could adversely affect our financial condition or results of operations.
A significant portion of our production and reserves rely on secondary and tertiary recovery techniques. If production response is less than forecasted for a particular project, then the project may be uneconomic or generate less cash flow and reserves than we had estimated prior to investing capital. Risks associated with secondary and tertiary recovery techniques include, but are not limited to, the following:
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lower than expected production;
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longer response times;
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higher operating and capital costs;
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shortages of equipment; and
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lack of technical expertise.
If any of these risks occur, it could adversely affect our financial condition or results of operations.
Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.
There are a variety of operating risks inherent in our wells, gathering systems, pipelines, and other facilities, such as leaks, explosions, mechanical problems, and natural disasters, all of which could cause substantial financial losses. Any of these or other similar occurrences could result in the disruption of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution, impairment of our operations, and substantial revenue losses. The location of our wells, gathering systems, pipelines, and other facilities near populated areas, including residential areas, commercial business centers, and industrial sites, could significantly increase the level of damages resulting from these risks.
We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. 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. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Changes in the insurance markets due to weather and adverse economic conditions have made it more difficult for us to obtain certain types of coverage. We may not be able to obtain the levels or types of insurance we would otherwise
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have obtained prior to these market changes, and our insurance may contain large deductibles or fail to cover certain hazards or cover all potential losses. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, and results of operations.
Our development, exploitation, and exploration operations require substantial capital, and we may be unable to obtain needed financing on satisfactory terms.
We make and will continue to make substantial capital expenditures in development, exploitation, and exploration projects. For example, our Board approved a $310 million capital budget for 2009, excluding proved property acquisitions. We intend to finance these capital expenditures through operating cash flows. However, additional financing sources may be required in the future to fund our capital expenditures. Financing may not continue to be available under existing or new financing arrangements, or on acceptable terms, if at all. If additional capital resources are not available, we may be forced to curtail our development and other activities or be forced to sell some of our assets on an untimely or unfavorable basis.
Shortages of rigs, equipment, and crews could delay our operations.
Higher oil and natural gas prices generally increase the demand for rigs, equipment, and crews and can lead to shortages of, and increasing costs for, development equipment, services, and personnel. Shortages of, or increasing costs for, experienced development crews and oil field equipment and services could restrict our ability to drill the wells and conduct the operations that we have planned. Any delay in the development of new wells or a significant increase in development costs could reduce our revenues.
The loss of key personnel could adversely affect our business.
We depend to a large extent on the efforts and continued employment of I. Jon Brumley, our Chairman of the Board, Jon S. Brumley, our Chief Executive Officer and President, and other key personnel. The loss of the services of any of these persons could adversely affect our business, and we do not have employment agreements with, and do not maintain key person insurance on the lives of, any of these persons.
Our development success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers, and other professionals. Competition for experienced geologists, engineers, and other professionals is extremely intense and the cost of attracting and retaining technical personnel has increased significantly in recent years. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed. Furthermore, escalating personnel costs could adversely affect our results of operations and financial condition.
Our business depends in part on gathering and transportation facilities owned by others. Any limitation in the availability of those facilities could interfere with our ability to market our oil and natural gas production and could harm our business.
The marketability of our oil and natural gas production depends in part on the availability, proximity, and capacity of pipelines, oil and natural gas gathering systems, and processing facilities. The amount of oil and natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage, or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or pipeline capacity could reduce our ability to market our oil and natural gas production and harm our business.
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Competition in the oil and natural gas industry is intense, and many of our competitors have greater resources than we do. As a result, we may be unable to effectively compete with larger competitors.
The oil and natural gas industry is intensely competitive with respect to acquiring prospects and productive properties, marketing oil and natural gas, and securing equipment and trained personnel, and we compete with other companies that have greater resources. Many of our competitors are major and large independent oil and natural gas companies, and possess and employ financial, technical, and personnel resources substantially greater than us. Those companies may be able to develop and acquire more prospects and productive properties than our resources permit. 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. Some of our competitors not only drill for and produce oil and natural gas but also carry on refining operations and market petroleum and other products on a regional, national, or worldwide basis. These companies may be able to pay more for oil and natural gas properties and evaluate, bid for, and purchase a greater number of properties than our resources permit. In addition, there is substantial competition for investment capital in the oil and natural gas industry. These companies may have a greater ability to continue development activities during periods of low oil and natural gas prices and to absorb the burden of present and future federal, state, local, and other laws and regulations. Our inability to compete effectively could have a material adverse impact on our business activities, financial condition, and results of operations.
We are subject to complex federal, state, local, and other laws and regulations that could adversely affect the cost, manner, or feasibility of conducting our operations.
Our oil and natural gas exploration and production operations are subject to complex and stringent laws and regulations. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate, and abandon oil and natural gas wells and related pipeline and processing facilities. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals, and certificates from various federal, state, and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations.
Our business is subject to federal, state, and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and production of, oil and natural gas. Failure to comply with such laws and regulations, as interpreted and enforced, could have a material adverse effect on our business, financial condition, and results of operations. Please read “Items 1 and 2. Business and Properties - Environmental Matters and Regulation” and “ - Other Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect us.
We have significant indebtedness and may incur significant additional indebtedness, which could negatively impact our financial condition, results of operations, and business prospects.
As of December 31, 2008, we had total consolidated debt of $1.3 billion and $615 million of consolidated available borrowing capacity under our revolving credit facility. We have the ability to incur additional debt under our revolving credit facilities, subject to borrowing base limitations. Our future indebtedness could have important consequences to us, including:
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our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions, or other purposes may not be available on favorable terms, if at all;
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covenants contained in future debt arrangements may require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;
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we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations and future business opportunities; and
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our debt level will make us more vulnerable to competitive pressures, or a downturn in our business or the economy in general, than our competitors with less debt.
Our ability to service our indebtedness depends upon, among other things, our future financial and operating performance, which is affected by prevailing economic conditions and financial, business, regulatory, and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms or at all.
In addition, we are not currently permitted to offset the value of our commodity derivative contracts with a counterparty against amounts that may be owing to such counterparty under our revolving credit facilities.
We are unable to predict the impact of the recent downturn in the credit markets and the resulting costs or constraints in obtaining financing on our business and financial results.
U.S. and global credit and equity markets have recently undergone significant disruption, making it difficult for many businesses to obtain financing on acceptable terms. In addition, equity markets are continuing to experience wide fluctuations in value. If these conditions continue or worsen, our cost of borrowing may increase, and it may be more difficult to obtain financing in the future. In addition, an increasing number of financial institutions have reported significant deterioration in their financial condition. If any of the financial institutions are unable to perform their obligations under our revolving credit agreements and other contracts, and we are unable to find suitable replacements on acceptable terms, our results of operations, liquidity and cash flows could be adversely affected. We also face challenges relating to the impact of the disruption in the global financial markets on other parties with which we do business, such as customers and suppliers. The inability of these parties to obtain financing on acceptable terms could impair their ability to perform under their agreements with us and lead to various negative effects on us, including business disruption, decreased revenues, and increases in bad debt write-offs. A sustained decline in the financial stability of these parties could have an adverse impact on our business, results of operations, and liquidity.
Our operations expose us to significant costs and liabilities with respect to environmental and operational safety matters.
We may incur significant costs and liabilities as a result of environmental and safety requirements applicable to our oil and natural gas production activities. In addition, we often indemnify sellers of oil and natural gas properties for environmental liabilities they or their predecessors may have created. These costs and liabilities could arise under a wide range of federal, state, and local environmental and safety laws and regulations, which have become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, imposition of cleanup and site restoration costs, liens and, to a lesser extent, issuance of injunctions to limit or cease operations. In addition, claims for damages to persons or property may result from environmental and other impacts of our operations.
Strict, joint, and several liability may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. New laws, regulations, or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our profitability and our ability to make distributions to unitholders could be adversely affected.
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ITEM 1B.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
There were no unresolved SEC staff comments as of December 31, 2008.
ITEM 3.
ITEM 3.
LEGAL PROCEEDINGS
We are a party to ongoing legal proceedings in the ordinary course of business. Management does not believe the result of these legal proceedings will have a material adverse effect on our results of operations or financial position.
ITEM 4.
ITEM 4.
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of stockholders during the fourth quarter of 2008.
ENCORE ACQUISITION COMPANY
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock, par value $0.01 per share, is listed on the NYSE under the symbol “EAC.” The following table sets forth high and low sales prices of our common stock for the periods indicated:
On February 18, 2009, the closing sales price of our common stock as reported by the NYSE was $23.09 per share, and we had approximately 387 shareholders of record. This number does not include owners for whom common stock may be held in “street” name.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
In October 2008, we announced that the Board authorized a share repurchase program of up to $40 million of our common stock. As of December 31, 2008, we had repurchased and retired 620,265 shares of our outstanding common stock for approximately $17.2 million, or an average price of $27.68 per share, under the share repurchase program. The following table summarizes purchases of our common stock during the fourth quarter of 2008:
(a)
During the fourth quarter of 2008, certain employees directed us to withhold 4,753 shares of common stock to satisfy minimum tax withholding obligations in conjunction with vesting of restricted shares.
Dividends
No dividends have been declared or paid on our common stock. We anticipate that we will retain all future earnings and other cash resources for the future operation and development of our business. Accordingly, we do not intend to declare or pay any cash dividends in the foreseeable future. Payment of any future dividends will be at the discretion of the Board after taking into account many factors, including our operating results, financial condition, current and anticipated cash needs, and plans for expansion. The
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declaration and payment of dividends is restricted by our existing revolving credit facility and the indentures governing our senior subordinated notes. Future debt agreements may also restrict our ability to pay dividends.
Stock Performance Graph
The following graph compares our cumulative total stockholder return during the period from January 1, 2004 to December 31, 2008 with total stockholder return during the same period for the Independent Oil and Gas Index and the Standard & Poor’s 500 Index. The graph assumes that $100 was invested in our common stock and each index on January 1, 2004 and that all dividends, if any, were reinvested. The following graph is being furnished pursuant to SEC rules and will not be incorporated by reference into any filing under the Securities Act of 1933 or the Exchange Act except to the extent we specifically incorporate it by reference.
Comparison of Total Return Since January 1, 2004 Among Encore
Acquisition Company, the Standard & Poor’s 500 Index, and the
Independent Oil and Gas Index
ENCORE ACQUISITION COMPANY
ITEM 6.
ITEM 6.
SELECTED FINANCIAL DATA
The following selected consolidated financial and operating data should be read in conjunction with “Item 7.
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis of our consolidated financial condition and results of operations should be read in conjunction with our consolidated financial statements and notes and supplementary data thereto included in “Item 8. Financial Statements and Supplementary Data.” The following discussion and analysis contains forward-looking statements including, without limitation, statements relating to our plans, strategies, objectives, expectations, intentions, and resources. Actual results could differ materially from those discussed in the forward-looking statements. We do not undertake to update, revise, or correct any of the forward-looking information unless required to do so under federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with our disclosures under the headings: “Information Concerning Forward-Looking Statements” and “Item 1A. Risk Factors.”
Introduction
In this management’s discussion and analysis of financial condition and results of operations, the following are discussed and analyzed:
•
Overview of Business
•
2008 Highlights
•
Recent Developments
•
2009 Outlook
•
Results of Operations
- Comparison of 2008 to 2007
- Comparison of 2007 to 2006
•
Capital Commitments, Capital Resources, and Liquidity
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Changes in Prices
•
Critical Accounting Policies and Estimates
•
New Accounting Pronouncements
•
Information Concerning Forward-Looking Statements
Overview of Business
We are a Delaware corporation engaged in the acquisition, development, exploitation, exploration, and production of oil and natural gas reserves from onshore fields in the United States. Our business strategies include:
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Maintaining an active development program to maximize existing reserves and production;
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Utilizing enhanced oil recovery techniques to maximize existing reserves and production;
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Expanding our reserves, production, and development inventory through a disciplined acquisition program;
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Exploring for reserves; and
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Operating in a cost effective, efficient, and safe manner.
At December 31, 2008, our oil and natural gas properties had estimated total proved reserves of 134.5 MMBbls of oil and 307.5 Bcf of natural gas, based on December 31, 2008 spot market prices of $44.60
ENCORE ACQUISITION COMPANY
per Bbl of oil and $5.62 per Mcf of natural gas. On a BOE basis, our proved reserves were 185.7 MMBOE at December 31, 2008, of which approximately 72 percent was oil and approximately 80 percent was proved developed. Based on 2008 production, our ratio of reserves to production was approximately 12.9 years for total proved reserves and 10.3 years for proved developed reserves as of December 31, 2008.
Our financial results and ability to generate cash depend upon many factors, particularly the price of oil and natural gas. Average NYMEX oil prices strengthened in the first half of 2008 to record levels, but have since experienced a significant deterioration. In addition, our oil wellhead differentials to NYMEX improved in 2008 as we realized 90 percent of the average NYMEX oil price, as compared to 88 percent in 2007. Average NYMEX natural gas prices strengthened in the first half of 2008 to their highest levels since 2005, but have since experienced a significant deterioration. Our natural gas wellhead differentials to NYMEX deteriorated slightly in 2008 as we realized 95 percent of the average NYMEX natural gas price, as compared to 98 percent in 2007. Commodity prices are influenced by many factors that are outside of our control. We cannot accurately predict future commodity prices. For this reason, we attempt to mitigate the effect of commodity price risk by entering into commodity derivative contracts for a portion of our forecasted future production. For a discussion of factors that influence commodity prices and risks associated with our commodity derivative contracts, please read “Item 1A. Risk Factors.”
During 2008, we did not make a significant acquisition of proved reserves. Instead, we acquired unproved acreage in our core areas, continued to make significant investments within our core areas to develop proved undeveloped reserves and increase production from proved developed reserves through various recovery techniques, and made significant investments for exploration within our areas of unproved acreage. We continue to believe that a portfolio of long-lived quality assets will position us for future success.
In May 2008, we announced that our Board had authorized our management team to explore a broad range of strategic alternatives to further enhance shareholder value, including, but not limited to, a sale or merger of the company. In conjunction, our Board approved a retention plan for all of our then-current employees, excluding members of our strategic team, providing for the payment of four months of base salary or base rate of pay, as applicable, upon the completion of the strategic alternatives process, subject to continued employment. This bonus was paid in August 2008.
In July 2008, our Board and management team decided that a sale or merger of the company was not currently in the best interest of our shareholders. In conjunction, our Board approved a separate retention plan for all of our then-current employees, excluding our Chairman and Chief Executive Officer, providing for the payment of eight months of base salary or base rate of pay, as applicable, in August 2009, subject to continued employment.
Our 2008 results of operations include approximately $7.6 million of pre-tax expense related to the four-month retention plan and approximately $6.9 million of pre-tax expense related to the eight-month retention plan.
Highlights
Our financial and operating results for 2008 included the following:
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Our oil and natural gas revenues increased 58 percent to $1.1 billion as compared to $712.9 million in 2007 as a result of increased production volumes and higher average realized prices.
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Our average realized oil price increased 51 percent to $89.30 per Bbl as compared to $58.96 per Bbl in 2007. Our average realized natural gas price increased 38 percent to $8.63 per Mcf as compared to $6.26 per Mcf in 2007.
•
Our average daily production volumes increased six percent to 39,470 BOE/D as compared to 37,094 BOE/D in 2007. Oil represented 70 percent and 71 percent of our total production volumes in 2008 and 2007, respectively.
ENCORE ACQUISITION COMPANY
•
Our production margin (defined as oil and natural gas wellhead revenues less production expenses) increased 54 percent to $842.0 million as compared to $548.5 million in 2007. Total oil and natural gas wellhead revenues per BOE increased by 38 percent while total production expenses per BOE increased by 23 percent. On a per BOE basis, our production margin increased 44 percent to $58.29 per BOE as compared to $40.52 per BOE for 2007.
•
We reported record net income for 2008, which increased to $430.8 million ($8.07 per diluted share) from the $17.2 million ($0.32 per diluted share) reported for 2007.
•
We invested $775.9 million in oil and natural gas activities (excluding asset retirement obligations of $0.6 million), of which $618.5 million was invested in development, exploitation, and exploration activities, yielding 282 gross (104.8 net) productive wells, and $157.4 million was invested in acquisitions, primarily of unproved acreage.
Recent Developments
In January 2009, we sold certain oil and natural gas producing properties and related assets in the Arkoma Basin and royalty interest properties in Oklahoma as well as 10,300 unleased mineral acres to ENP. The sales price was $49 million in cash, subject to customary adjustments (including a reduction in the purchase price for acquisition-related commodity derivative premiums of approximately $3 million).
Outlook
For 2009, the Board has approved a $310 million capital budget for oil and natural gas related activities, excluding proved property acquisitions. We expect to fund our 2009 capital expenditures within cash flows from operations and use the additional cash flows from operations to reduce our debt levels. The following table represents the components of our 2009 capital budget (in thousands):
The prices we receive for our oil and natural gas production are largely based on current market prices, which are beyond our control. For comparability and accountability, we take a constant approach to budgeting commodity prices. We presently analyze our inventory of capital projects based on management’s outlook of future commodity prices. If NYMEX prices continue to trend downward, we may further reevaluate our capital projects. Since the end of 2008, oil NYMEX prices have declined from $44.60 per Bbl to below $39.00 per Bbl in mid-February 2009 and natural gas NYMEX prices have declined from $5.62 per Mcf to below $4.25 per Mcf over the same period. The price risk on a significant portion of our forecasted oil and natural gas production for 2009 is mitigated using commodity derivative contracts. Please read “Item 7A.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The primary objective of the following information is to provide 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 oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of exposure, but rather indicators of potential exposure. This information provides indicators of how we view and manage our ongoing market risk exposures. We do not enter into market risk sensitive instruments for speculative trading purposes.
Derivative policy. Due to the volatility of crude oil and natural gas prices, we enter into various derivative instruments to manage our exposure to changes in the market price of crude oil and natural gas. We use options (including floors and collars) and fixed price swaps to mitigate the impact of downward swings in prices. All contracts are settled with cash and do not require the delivery of physical volumes to satisfy settlement. While this strategy may result in us having lower net cash inflows in times of higher oil and natural gas prices than we would otherwise have, had we not utilized these instruments, management believes that the resulting reduced volatility of cash flow is beneficial.
Counterparties. At December 31, 2008, we had committed greater than 10 percent of either our outstanding oil or natural gas commodity derivative contracts to the following counterparties:
In order to mitigate the credit risk of financial instruments, we enter into master netting agreements with significant counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and us. Instead of treating separately each derivative financial transaction between our counterparty and us, the master netting agreement enables our counterparty and us to aggregate all financial trades and treat them as a single agreement. This arrangement benefits us in three ways: (1) the netting of the value of all trades reduces the likelihood of our counterparties requiring daily collateral posting by us; (2) default by a counterparty under one financial trade can trigger rights for us to terminate all financial trades with such counterparty; and (3) netting of settlement amounts reduces our credit exposure to a given counterparty in the event of close-out.
Commodity price sensitivity. We manage commodity price risk with swap contracts, put contracts, collars, and floor spreads. Swap contracts provide a fixed price for a notional amount of sales volumes. Put
ENCORE ACQUISITION COMPANY
contracts provide a fixed floor price on a notional amount of sales volumes while allowing full price participation if the relevant index price closes above the floor price. Collars provide a floor price on a notional amount of sales volumes while allowing some additional price participation if the relevant index price closes above the floor price. From time to time, we sell floors with a strike price below the strike price of the purchased floors in order to partially finance the premiums paid on the purchased floors. Together the two floors, known as a floor spread or put spread, have a lower premium cost than a traditional floor contract but provide price protection only down to the strike price of the short floor.
As of December 31, 2008, the fair market values of our oil and natural gas commodity derivative contracts were net assets of approximately $374.8 million and $12.8 million, respectively. Based on our open commodity derivative positions at December 31, 2008, a 10 percent increase in the respective NYMEX prices for oil and natural gas would decrease our net derivative fair value asset by approximately $29.2 million, while a 10 percent decrease in the respective NYMEX prices for oil and natural gas would increase our net derivative fair value asset by approximately $29.8 million. These amounts exclude deferred premiums of $67.6 million at December 31, 2008 that are not subject to changes in commodity prices.
The following tables summarize our open commodity derivative contracts as of December 31, 2008:
Oil Derivative Contracts
(a)
In addition, ENP has a floor contract for 1,000 Bbls/D at $63.00 per Bbl and a short floor contract for 1,000 Bbls/D at $65.00 per Bbl.
ENCORE ACQUISITION COMPANY
Natural Gas Derivative Contracts
Interest rate sensitivity. At December 31, 2008, we had total long-term debt of $1.3 billion, net of discount of $5.2 million. Of this amount, $150 million bears interest at a fixed rate of 6.25 percent, $300 million bears interest at a fixed rate of 6.0 percent, and $150 million bears interest at a fixed rate of 7.25 percent. The remaining long-term debt balance of $725 million consists of outstanding borrowings on our revolving credit facilities and is subject to floating market rates of interest that are linked to LIBOR.
At this level of floating rate debt, if LIBOR increased 10 percent, we would incur an additional $2.0 million of interest expense per year on our revolving credit facilities, and if LIBOR decreased 10 percent, we would incur $2.0 million less. Additionally, if the bond discount rate increased 10 percent, we estimate the fair value of our fixed rate debt at December 31, 2008 would decrease from approximately $390 million to approximately $351 million, and if the bond discount rate decreased 10 percent, we estimate the fair value would increase to approximately $429 million.
ENP manages interest rate risk with interest rate swaps whereby it swaps floating rate debt under the OLLC Credit Agreement with a weighted average fixed rate. As of December 31, 2008, the fair market value of ENP’s interest rate swaps was a net liability of approximately $4.6 million. If LIBOR increased 10 percent, we estimate the liability would decrease to approximately $4.1 million, and if LIBOR decreased 10 percent, we estimate the liability would increase to approximately $5.0 million.
The following table summarizes ENP’s open interest rate swaps as of December 31, 2008:
ENCORE ACQUISITION COMPANY
ITEM 8.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Encore Acquisition Company:
We have audited the accompanying consolidated balance sheets of Encore Acquisition Company (the “Company”) as of December 31, 2008 and 2007, 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, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Encore Acquisition Company at December 31, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.
As discussed in Note 9 to the consolidated financial statements, effective January 1, 2007, the Company adopted Financial Accounting Standards Board Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109.”
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2009 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Fort Worth, Texas
February 24, 2009
ENCORE ACQUISITION COMPANY
CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these consolidated financial statements.
ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
The accompanying notes are an integral part of these consolidated financial statements.
ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
AND COMPREHENSIVE INCOME
The accompanying notes are an integral part of these consolidated financial statements.
ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements.
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1.
Description of Business
Encore Acquisition Company (together with its subsidiaries, “EAC”), a Delaware corporation, is engaged in the acquisition and development of oil and natural gas reserves from onshore fields in the United States. Since 1998, EAC has acquired producing properties with proven reserves and leasehold acreage and grown the production and proven reserves by drilling, exploring, and reengineering or expanding existing waterflood projects. EAC’s properties - and oil and natural gas reserves - are located in four core areas:
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the Cedar Creek Anticline (“CCA”) in the Williston Basin of Montana and North Dakota;
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the Permian Basin of West Texas and southeastern New Mexico;
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the Rockies, which includes non-CCA assets in the Williston, Big Horn, and Powder River Basins in Wyoming, Montana, and North Dakota, and the Paradox Basin in southeastern Utah; and
•
the Mid-Continent area, which includes the Arkoma and Anadarko Basins in Oklahoma, the North Louisiana Salt Basin, the East Texas Basin, and the Mississippi Salt Basin.
Note 2.
Summary of Significant Accounting Policies
Principles of Consolidation
EAC’s consolidated financial statements include the accounts of its wholly owned and majority-owned subsidiaries. All material intercompany balances and transactions have been eliminated in consolidation.
In February 2007, EAC formed Encore Energy Partners LP (together with its subsidiaries, “ENP”), a publicly traded Delaware limited partnership, to acquire, exploit, and develop oil and natural gas properties and to acquire, own, and operate related assets. In September 2007, ENP completed its initial public offering (“IPO”). As of December 31, 2008 and 2007, EAC owned approximately 63 percent and 58 percent, respectively, of ENP’s common units, as well as all of the interests of Encore Energy Partners GP LLC (“GP LLC”), a Delaware limited liability company and ENP’s general partner, which is an indirect wholly owned non-guarantor subsidiary of EAC. Considering the presumption of control of GP LLC in accordance with Emerging Issues Task Force Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights,” the financial position, results of operations, and cash flows of ENP are consolidated with those of EAC. EAC elected to account for gains on ENP’s issuance of common units as capital transactions as permitted by Staff Accounting Bulletin (“SAB”) Topic 5H, “Accounting for Sales of Stock by a Subsidiary.” Please read “Note 10. Stockholders’ Equity” for additional discussion.
As presented in the accompanying Consolidated Balance Sheets, “Minority interest in consolidated partnership” as of December 31, 2008 and 2007 of $169.1 million and $122.5 million, respectively, represents third-party ownership interests in ENP. As presented in the accompanying Consolidated Statements of Operations, “Minority interest in income of consolidated partnership” for 2008 of $54.3 million and “Minority interest in loss of consolidated partnership” for 2007 of $7.5 million represents ENP’s results of operations attributable to third-party owners.
Use of Estimates
Preparing financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires management to make certain estimations and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities in the consolidated financial statements and the reported amounts of revenues and expenses. Actual results could differ materially from those estimates.
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Estimates made in preparing these consolidated financial statements include, among other things, estimates of the proved oil and natural gas reserve volumes used in calculating depletion, depreciation, and amortization (“DD&A”) expense; the estimated future cash flows and fair value of properties used in determining the need for any impairment write-down; operating costs accrued; volumes and prices for revenues accrued; estimates of the fair value of equity-based compensation awards; and the timing and amount of future abandonment costs used in calculating asset retirement obligations. Changes in the assumptions used could have a significant impact on reported results in future periods.
Cash and Cash Equivalents
Cash and cash equivalents include cash in banks, money market accounts, and all highly liquid investments with an original maturity of three months or less. On a bank-by-bank basis and considering legal right of offset, cash accounts that are overdrawn are reclassified to current liabilities and any change in cash overdrafts is shown as “Change in cash overdrafts” in the “Financing activities” section of EAC’s Consolidated Statements of Cash Flows.
Supplemental Disclosures of Cash Flow Information
The following table sets forth supplemental disclosures of cash flow information for the periods indicated:
Accounts Receivable
Trade accounts receivable, which are primarily from oil and natural gas sales, are recorded at the invoiced amount and do not bear interest with the exception of the current portion of balances due from ExxonMobil Corporation (“ExxonMobil”) in connection with EAC’s joint development agreement. Please read “Note 4. Commitments and Contingencies” for additional discussion of this agreement. EAC routinely reviews outstanding accounts receivable balances and assesses the financial strength of its customers and records a reserve for amounts not expected to be fully recovered. Actual balances are not applied against the reserve
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
until substantially all collection efforts have been exhausted. The following table summarizes the changes in allowance for doubtful accounts for the periods indicated:
Of the $8.0 million in allowance for doubtful accounts at December 31, 2008, $0.4 million is short-term and $7.6 million is long-term.
Inventory
Inventory includes materials and supplies and oil in pipelines, which are stated at the lower of cost (determined on an average basis) or market. Oil produced at the lease which resides unsold in pipelines is carried at an amount equal to its operating costs to produce. Oil in pipelines purchased from third parties is carried at average purchase price. Inventory consisted of the following as of the dates indicated:
Properties and Equipment
Oil and Natural Gas Properties. EAC uses the successful efforts method of accounting for its oil and natural gas properties under Statement of Financial Accounting Standards (“SFAS”) No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” (“SFAS 19”). Under this method, all costs associated with productive and nonproductive development wells are capitalized. Exploration expenses, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Costs associated with drilling exploratory wells are initially capitalized pending determination of whether the well is economically productive or nonproductive.
If an exploratory well does not find reserves or does not find reserves in a sufficient quantity as to make them economically producible, the previously capitalized costs would be expensed in EAC’s Consolidated Statements of Operations and shown as a non-cash adjustment to net income in the “Operating activities” section of EAC’s Consolidated Statements of Cash Flows in the period in which the determination was made. If an exploratory well finds reserves but they cannot be classified as proved, EAC continues to capitalize the associated cost as long as the well has found a sufficient quantity of reserves to justify its completion as a producing well and sufficient progress is being made in assessing the reserves and the operating viability of the project. If subsequently it is determined that these conditions do not continue to exist, all previously capitalized costs associated with the exploratory well would be expensed and shown as a non-cash adjustment to net income in the “Operating activities” section of EAC’s Consolidated Statements of Cash Flows in the period in which the determination is made. Re-drilling or directional drilling in a previously abandoned well is classified as development or exploratory based on whether it is in a proved or unproved reservoir. Costs for
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
repairs and maintenance to sustain or increase production from the existing producing reservoir are charged to expense as incurred. Costs to recomplete a well in a different unproved reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the costs would be charged to expense. All capitalized costs associated with both development and exploratory wells are shown as “Development of oil and natural gas properties” in the “Investing activities” section of EAC’s Consolidated Statements of Cash Flows.
Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Costs to construct facilities or increase the productive capacity from existing reservoirs are capitalized. Internal costs directly associated with the development of proved properties are capitalized as a cost of the property and are classified accordingly in EAC’s consolidated financial statements. Capitalized costs are amortized on a unit-of-production basis over the remaining life of proved developed reserves or total proved reserves, as applicable. Natural gas volumes are converted to barrels of oil equivalent (“BOE”) at the rate of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“Bbl”) of oil.
The costs of retired, sold, or abandoned properties that constitute part of an amortization base are charged or credited, net of proceeds received, to accumulated DD&A.
Miller and Lents, Ltd., EAC’s independent reserve engineer, estimates EAC’s reserves annually on December 31. This results in a new DD&A rate which EAC uses for the preceding fourth quarter after adjusting for fourth quarter production. EAC internally estimates reserve additions and reclassifications of reserves from proved undeveloped to proved developed at the end of the first, second, and third quarters for use in determining a DD&A rate for the respective quarter.
In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”), EAC assesses the need for an impairment of long-lived assets to be held and used, including proved oil and natural gas properties, whenever events and circumstances indicate that the carrying value of the asset may not be recoverable. If impairment is indicated based on a comparison of the asset’s carrying value to its undiscounted expected future net cash flows, then an impairment charge is recognized to the extent that the asset’s carrying value exceeds its fair value. Expected future net cash flows are based on existing proved reserves (and appropriately risk-adjusted probable reserves), forecasted production information, and management’s outlook of future commodity prices. Any impairment charge incurred is expensed and reduces the net basis in the asset. Management aggregates proved property for impairment testing the same way as for calculating DD&A. The price assumptions used to calculate undiscounted cash flows is based on judgment. EAC uses prices consistent with the prices used in bidding on acquisitions and/or assessing capital projects. These price assumptions are critical to the impairment analysis as lower prices could trigger impairment.
Unproved properties, the majority of which relate to the acquisition of leasehold interests, are assessed for impairment on a property-by-property basis for individually significant balances and on an aggregate basis for individually insignificant balances. If the assessment indicates an impairment, a loss is recognized by providing a valuation allowance at the level at which impairment was assessed. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease terms, and potential shifts in business strategy employed by management. In the case of individually insignificant balances, the amount of the impairment loss recognized is determined by amortizing the portion of these properties’ costs which EAC believes will not be transferred to proved properties over the remaining life of the lease.
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Amounts shown in the accompanying Consolidated Balance Sheets as “Proved properties, including wells and related equipment” consisted of the following as of the dates indicated:
Other Property and Equipment. Other property and equipment is carried at cost. Depreciation is recognized on a straight-line basis over estimated useful lives, which range from three to seven years. Leasehold improvements are capitalized and depreciated over the remaining term of the lease, which is through 2013 for EAC’s corporate headquarters. Gains or losses from the disposal of other property and equipment are recognized in the period realized and included in “Other operating expense” of EAC’s Consolidated Statements of Operations.
Goodwill and Other Intangible Assets
EAC accounts for goodwill and other intangible assets under the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets.” Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill and other intangible assets with indefinite useful lives are tested for impairment annually on December 31 or whenever indicators of impairment exist. If indicators of impairment are determined to exist, an impairment charge would be recognized for the amount by which the carrying value of the asset exceeds its implied fair value. The goodwill test is performed at the reporting unit level. EAC has determined that it has two reporting units: EAC Standalone and ENP. ENP has been allocated $2.6 million of goodwill and the remainder has been allocated to the EAC Standalone segment.
EAC utilizes both a market capitalization and an income approach to determine the fair value of its reporting units. The primary component of the income approach is the estimated discounted future net cash flows expected to be recovered from the reporting unit’s oil and natural gas properties. EAC’s analysis concluded that there was no impairment of goodwill as of December 31, 2008. Prices for oil and natural gas have deteriorated sharply in recent months and significant uncertainty remains on how prices for these commodities will behave in the future. Any additional decreases in the prices of oil and natural gas or any negative reserve adjustments from the December 31, 2008 assessment could change EAC’s estimates of the fair value of its reporting units and could result in an impairment charge.
Intangible assets with definite useful lives are amortized over their estimated useful lives. In accordance with SFAS 144, EAC evaluates the recoverability of intangible assets with definite useful lives whenever events or changes in circumstances indicate that the carrying value of the asset may not be fully recoverable. An impairment loss exists when estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount.
ENP is a party to a contract allowing it to purchase a certain amount of natural gas at a below market price for use as field fuel. The fair value of this contract, net of related amortization, is included in “Other noncurrent assets” on the accompanying Consolidated Balance Sheets. The gross carrying amount of this contract is $4.2 million and as of December 31, 2008 and 2007, accumulated amortization was $0.6 million and $0.3 million, respectively. During each of 2008 and 2007, ENP recorded $0.3 million of amortization expense related to this contract. The net carrying amount is being amortized on a straight-line basis through July 2019. ENP expects to recognize $0.3 million of amortization expense during each of the next five years related to this contract.
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Asset Retirement Obligations
In accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations,” EAC recognizes the fair value of a liability for an asset retirement obligation in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which the property is acquired or a new well is drilled. An amount equal to and offsetting the liability is capitalized as part of the carrying amount of EAC’s oil and natural gas properties. The liability is recorded at its discounted fair value and then accreted each period until it is settled or the asset is sold, at which time the liability is reversed. Estimates are based on historical experience in plugging and abandoning wells and estimated remaining field life based on reserve estimates. EAC does not provide for a market risk premium associated with asset retirement obligations because a reliable estimate cannot be determined. Please read “Note 5. Asset Retirement Obligations” for additional information.
Equity-Based Compensation
EAC accounts for equity-based compensation according to the provisions of SFAS No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123R”), which requires the recognition of compensation expense for equity-based awards over the requisite service period in an amount equal to the grant date fair value of the awards. EAC utilizes a standard option pricing model (i.e., Black-Scholes) to measure the fair value of employee stock options under SFAS 123R. Please read “Note 12. Employee Benefit Plans” for additional discussion of EAC’s employee benefit plans.
SFAS 123R also requires that the benefits associated with the tax deductions in excess of recognized compensation cost be reported as a financing cash flow. This requirement reduces net operating cash flows and increases net financing cash flows. EAC recognizes compensation costs related to awards with graded vesting on a straight-line basis over the requisite service period for each separately vesting portion of the award as if the award was, in-substance, multiple awards. Compensation expense associated with awards to employees who are eligible for retirement is fully expensed on the date of grant.
Segment Reporting
EAC operates in only one industry: the oil and natural gas exploration and production industry in the United States. However, EAC is organizationally structured along two reportable segments: EAC Standalone and ENP. EAC’s segments are components of its business for which separate financial information related to operating and development costs are available and regularly evaluated by the chief operating decision maker in deciding how to allocate capital resources to projects and in assessing performance. Please read “Note 18. Segment Information” for additional discussion. Prior to the fourth quarter of 2007, segment reporting was not applicable to EAC.
Major Customers/Concentration of Credit Risk
In 2008, Eighty-Eight Oil and Tesoro accounted for approximately 14 percent and 12 percent, respectively, of EAC’s sales of oil and natural gas production. On the EAC Standalone segment, two companies accounted for 16 percent and 13 percent of EAC Standalone’s sales of oil and natural gas production. On the ENP segment, three companies accounted for 24 percent, 23 percent, and 10 percent of ENP’s sales of oil and natural gas production.
In 2007, Eighty-Eight Oil accounted for 14 percent of EAC’s sales of oil and natural gas production. On the EAC Standalone segment, one company accounted for 15 percent of EAC Standalone’s sales of oil and natural gas production. On the ENP segment, two companies accounted for 52 percent and 16 percent of ENP’s sales of oil and natural gas production.
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In 2006, Shell Trading Company and ConocoPhillips accounted for 15 percent and 12 percent, respectively, of EAC’s sales of oil and natural gas production.
Income Taxes
Deferred tax assets and liabilities are recognized for future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Valuation allowances are established when necessary to reduce net deferred tax assets to amounts expected to be realized. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled.
Oil and Natural Gas Revenue Recognition
Oil and natural gas revenues are recognized as oil and natural gas is produced and sold, net of royalties and net profits interests. Royalties, net profits interests, and severance taxes are incurred based upon the actual price received from the sales. To the extent actual quantities and values of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded as “Accounts receivable, net” in the accompanying Consolidated Balance Sheets. Natural gas revenues are reduced by any processing and other fees incurred except for transportation costs paid to third parties, which are recorded in “Other operating expense” in the accompanying Consolidated Statements of Operations. Natural gas revenues are recorded using the sales method of accounting whereby revenue is recognized based on actual sales of natural gas rather than EAC’s proportionate share of natural gas production. If EAC’s overproduced imbalance position (i.e., EAC has cumulatively been over-allocated production) is greater than EAC’s share of remaining reserves, a liability is recorded for the excess at period-end prices unless a different price is specified in the contract in which case that price is used. Revenue is not recognized for the production in tanks, oil marketed on behalf of joint owners in EAC’s properties, or oil in pipelines that has not been delivered to the purchaser.
EAC’s net oil inventories in pipelines were 173,119 Bbls and 124,410 Bbls at December 31, 2008 and 2007, respectively. Natural gas imbalances at December 31, 2008 and 2007, were 28,717 million British thermal units (“MMBtu”) and 128,856 MMBtu under-delivered to EAC, respectively.
Marketing Revenues and Expenses
Marketing revenues include the sales of natural gas purchased from third parties as well as pipeline tariffs charged for transportation volumes through EAC’s pipelines. Marketing revenues derived from sales of oil and natural gas purchased from third parties are recognized when persuasive evidence of a sales arrangement exists, delivery has occurred, the sales price is fixed or determinable, and collectibility is reasonably assured. Marketing expenses include the cost of oil and natural gas volumes purchased from third parties, pipeline tariffs, storage, truck facility fees, and tank bottom costs used to support the sale of oil production. As EAC takes title to the oil and natural gas and has risks and rewards of ownership, these transactions are presented gross in the Consolidated Statements of Operations, unless they meet the criteria for netting as outlined in EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.”
Shipping Costs
Shipping costs in the form of pipeline fees and trucking costs paid to third parties are incurred to transport oil and natural gas production from certain properties to a different market location for ultimate sale. These costs are included in “Other operating expense” and “Marketing expense,” as applicable, in the accompanying Consolidated Statements of Operations.
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Derivatives
EAC uses various financial instruments for non-trading purposes to manage and reduce price volatility and other market risks associated with its oil and natural gas production. These arrangements are structured to reduce EAC’s exposure to commodity price decreases, but they can also limit the benefit EAC might otherwise receive from commodity price increases. EAC’s risk management activity is generally accomplished through over-the-counter forward derivative or option contracts with large financial institutions. EAC also uses derivative instruments in the form of interest rate swaps, which hedge risk related to interest rate fluctuation.
EAC applies the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and its amendments, which requires each derivative instrument to be recorded in the balance sheet at fair value. If a derivative does not qualify for hedge accounting, it must be adjusted to fair value through earnings. However, if a derivative qualifies for hedge accounting, depending on the nature of the hedge, changes in fair value can be recognized in accumulated other comprehensive income until such time as the hedged item is recognized in earnings.
To qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting changes in cash flows of the hedged item. In addition, all hedging relationships must be designated, documented, and reassessed periodically. Cash flow hedges are marked to market through accumulated other comprehensive income each period.
EAC has elected to designate its current interest rate swaps as cash flow hedges. The effective portion of the mark-to-market gain or loss on these derivative instruments is recorded in other “Accumulated other comprehensive income” on the accompanying Consolidated Balance Sheets and reclassified into earnings in the same period in which the hedged transaction affects earnings. Any ineffective portion of the mark-to-market gain or loss is recognized in earnings immediately as “Derivative fair value loss (gain)” in the Consolidated Statements of Operations.
EAC has elected to not designate its current portfolio of commodity derivative contracts as hedges and therefore, changes in fair value of these instruments are recognized in earnings as “Derivative fair value loss (gain)” in the accompanying Consolidated Statements of Operations.
Comprehensive Income
EAC has elected to show comprehensive income as part of its Consolidated Statements of Stockholders’ Equity and Comprehensive Income rather than in its Consolidated Statements of Operations.
Reclassifications
Certain amounts in prior periods have been reclassified to conform to the current period presentation. In particular, “Income taxes receivable” has been presented separately on the accompanying Consolidated Balance Sheets.
New Accounting Pronouncements
SFAS No. 157, “Fair Value Measurements” (“SFAS 157”)
In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS 157, which: (1) standardizes the definition of fair value; (2) establishes a framework for measuring fair value in GAAP; and (3) expands disclosures related to the use of fair value measures in financial statements. SFAS 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value, but does not require any new fair value measurements. SFAS 157 was prospectively effective for financial assets and liabilities for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. In February 2008, the FASB issued FASB Staff Position (“FSP”)
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No. FAS 157-2, “Effective Date of FASB Statement No. 157” (“FSP FAS 157-2”), which delayed the effective date of SFAS 157 for one year for nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). EAC elected a partial deferral of SFAS 157 for all instruments within the scope of FSP FAS 157-2, including, but not limited to, its asset retirement obligations and indefinite lived assets. EAC will continue to evaluate the impact of SFAS 157 on these instruments during the deferral period. The adoption of SFAS 157 on January 1, 2008, as it relates to financial assets and liabilities, did not have a material impact on EAC’s results of operations or financial condition. EAC does not expect the adoption of SFAS 157 on January 1, 2009, as it relates to all instruments within the scope of FSP FAS 157-2, to have a material impact on its results of operations or financial condition. Please read “Note 14. Fair Value Measurements” for additional discussion.
SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities - including an amendment of FASB Statement No. 115” (“SFAS 159”)
In February 2007, the FASB issued SFAS 159, which permits entities to measure many financial instruments and certain other assets and liabilities at fair value on an instrument-by-instrument basis. SFAS 159 also allows entities an irrevocable option to measure eligible items at fair value at specified election dates, with resulting changes in fair value reported in earnings. SFAS 159 was effective for fiscal years beginning after November 15, 2007. EAC did not elect the fair value option for eligible instruments and therefore, the adoption of SFAS 159 on January 1, 2008 did not impact EAC’s results of operations or financial condition. EAC will assess the impact of electing the fair value option for any eligible instruments acquired in the future. Electing the fair value option for such instruments could have a material impact on EAC’s future results of operations or financial condition.
FSP on FASB Interpretation (“FIN”) 39-1, “Amendment of FASB Interpretation No. 39” (“FSP FIN 39-1”)
In April 2007, the FASB issued FSP FIN 39-1, which amends FIN No. 39, “Offsetting of Amounts Related to Certain Contracts” (“FIN 39”), to permit a reporting entity that is party to a master netting arrangement to offset the fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments that have been offset under the same master netting arrangement in accordance with FIN 39. FSP FIN 39-1 was effective for fiscal years beginning after November 15, 2007. The adoption of FSP FIN 39-1 on January 1, 2008 did not impact EAC’s results of operations or financial condition.
SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141R”)
In December 2007, the FASB issued SFAS 141R, which replaces SFAS No. 141, “Business Combinations.” SFAS 141R establishes principles and requirements for the reporting entity in a business combination, including: (1) recognition and measurement in the financial statements of the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognition and measurement of goodwill acquired in the business combination or a gain from a bargain purchase; and (3) determination of the information to be disclosed to enable financial statement users to evaluate the nature and financial effects of the business combination. SFAS 141R is prospectively effective for business combinations consummated in fiscal years beginning on or after December 15, 2008, with early application prohibited. EAC currently does not have any pending acquisitions that would fall within the scope of SFAS 141R. Future acquisitions could impact EAC’s results of operations and financial condition and the reporting in the consolidated financial statements.
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SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements - an amendment to ARB No. 51” (“SFAS 160”)
In December 2007, the FASB issued SFAS 160, which amends Accounting Research Bulletin No. 51, “Consolidated Financial Statements” to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS 160 is effective for fiscal years beginning on or after December 15, 2008. SFAS 160 clarifies that a noncontrolling interest in a subsidiary, which is sometimes referred to as minority interest, is an ownership interest in the consolidated entity that should be reported as a component of equity in the consolidated financial statements. Among other requirements, SFAS 160 requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest and the disclosure of consolidated net income attributable to the parent and to the noncontrolling interest on the face of the consolidated statement of operations. EAC is evaluating the impact the adoption of SFAS 160 will have on its results of operations and financial condition.
SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133” (“SFAS 161”)
In March 2008, the FASB issued SFAS 161, which amends SFAS 133, to require enhanced disclosures about: (1) how and why an entity uses derivative instruments; (2) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations; and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 is effective for fiscal years beginning on or after November 15, 2008, with early application encouraged. The adoption of SFAS 161 will require additional disclosures regarding EAC’s derivative instruments; however, it will not impact EAC’s results of operations or financial condition.
SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS 162”)
In May 2008, the FASB issued SFAS 162, which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP. SFAS 162 was effective November 15, 2008. The adoption of SFAS 162 did not impact EAC’s results of operations or financial condition.
FSP No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”)
In June 2008, the FASB issued FSP EITF 03-6-1, which addresses whether instruments granted in equity-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation for computing basic earnings per share (“EPS”) under the two-class method described by SFAS No. 128, “Earnings per Share” (“SFAS 128”). FSP EITF 03-6-1 is retroactively effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years, with early application prohibited. EAC is evaluating the impact the adoption of FSP EITF 03-6-1 will have on its EPS calculations.
Note 3. Acquisitions and Dispositions
Acquisitions
In January 2007, EAC entered into a purchase and sale agreement with certain subsidiaries of Anadarko Petroleum Corporation (“Anadarko”) to acquire oil and natural gas properties and related assets in the Williston Basin of Montana and North Dakota. The closing of the Williston Basin acquisition occurred in April 2007. The Williston Basin acquisition was treated as a reverse like-kind exchange under Section 1031 of
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the Internal Revenue Code of 1986, as amended, (the “Code”) and I.R.S. Revenue Procedure 2000-37 with the Mid-Continent disposition discussed below. The total purchase price for the Williston Basin assets was approximately $392.1 million, including transaction costs of approximately $1.3 million.
Also in January 2007, EAC entered into a purchase and sale agreement with certain subsidiaries of Anadarko to acquire oil and natural gas properties and related assets in the Big Horn Basin of Wyoming and Montana, which included oil and natural gas properties and related assets in or near the Elk Basin field in Park County, Wyoming and Carbon County, Montana and oil and natural gas properties and related assets in the Gooseberry field in Park County, Wyoming. Prior to closing, EAC assigned the rights and duties under the purchase and sale agreement relating to the Elk Basin assets to Encore Energy Partners Operating LLC (“OLLC”), a Delaware limited liability company and wholly owned subsidiary of ENP, and the rights and duties under the purchase and sale agreement relating to the Gooseberry assets to Encore Operating, L.P. (“Encore Operating”), a Texas limited partnership and indirect wholly owned guarantor subsidiary of EAC. The closing of the Big Horn Basin acquisition occurred in March 2007. The total purchase price for the Big Horn Basin assets was approximately $393.6 million, including transaction costs of approximately $1.3 million.
EAC financed the acquisitions of the Gooseberry assets and Williston Basin assets through borrowings under its revolving credit facility. ENP financed the acquisition of the Elk Basin assets through a $93.7 million contribution from EAC, $120 million of borrowings under a subordinated credit agreement with EAP Operating, LLC, a Delaware limited liability company and direct wholly owned guarantor subsidiary of EAC, and borrowings under OLLC’s revolving credit facility. Please read “Note 8. Long-Term Debt” for additional discussion of EAC’s long-term debt.
Dispositions
In June 2007, EAC completed the sale of certain oil and natural gas properties in the Mid-Continent area, and in July 2007, additional Mid-Continent properties that were subject to preferential rights were sold. EAC received total net proceeds of approximately $294.8 million, after deducting transaction costs of approximately $3.6 million, and recorded a loss on sale of approximately $7.4 million. The disposed properties included certain properties in the Anadarko and Arkoma Basins of Oklahoma. EAC retained material oil and natural gas interests in other properties in these basins and remains active in those areas. Proceeds from the Mid-Continent asset disposition were used to reduce outstanding borrowings under EAC’s revolving credit facility.
Pro Formas
The following unaudited pro forma condensed financial data was derived from the historical financial statements of EAC and from the accounting records of Anadarko to give effect to the Big Horn Basin and Williston Basin asset acquisitions and the Mid-Continent asset disposition as if they had each occurred on January 1, 2006. The unaudited pro forma condensed financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Big Horn Basin and Williston Basin asset acquisitions and the Mid-Continent asset disposition taken place on January 1, 2006 and is not intended to be a projection of future results.
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Note 4. Commitments and Contingencies
Litigation
EAC is a party to ongoing legal proceedings in the ordinary course of business. Management does not believe the result of these proceedings will have a material adverse effect on EAC’s business, financial position, results of operations, or liquidity.
Leases
EAC leases office space and equipment that have remaining non-cancelable lease terms in excess of one year. The following table summarizes by year the remaining non-cancelable future payments under these operating leases as of December 31, 2008 (in thousands):
EAC’s operating lease rental expense was approximately $5.8 million, $5.5 million, and $4.6 million in 2008, 2007, and 2006, respectively.
ExxonMobil
In March 2006, EAC entered into a joint development agreement with ExxonMobil to develop legacy natural gas fields in West Texas. Under the terms of the agreement, EAC has the opportunity to develop approximately 100,000 gross acres and earns 30 percent of ExxonMobil’s working interest and 22.5 percent of ExxonMobil’s net revenue interest in each well drilled. EAC operates each well during the drilling and completion phase, after which ExxonMobil assumes operational control of the well.
In July 2008, EAC earned the right to participate in all fields by drilling the final well of the 24-well commitment program and is entitled to a 30 percent working interest in future drilling locations. EAC has the right to propose and drill wells for as long as it is engaged in continuous drilling operations.
During 2008 and 2007, EAC advanced $38.0 million and $37.7 million, respectively, to ExxonMobil for its portion of costs incurred drilling wells under the joint development agreement. At December 31, 2008, EAC had a net receivable from ExxonMobil of $79.0 million, of which $11.2 million was included in “Accounts receivable, net” and $67.8 million was included in “Long-term receivables” on the accompanying
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Consolidated Balance Sheet based on when EAC expects repayment. At December 31, 2007, EAC had a net receivable from ExxonMobil of $51.7 million, of which $12.3 million was included in “Accounts receivable, net” and $39.4 million was included in “Long-term receivables, net” on the accompanying Consolidated Balance Sheet.
Note 5. Asset Retirement Obligations
Asset retirement obligations relate to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal. As of December 31, 2008 and 2007, EAC had $9.2 million and $6.7 million, respectively, held in escrow from which funds are released only for reimbursement of plugging and abandonment expenses on its Bell Creek properties, which is included in other long-term assets in the accompanying Consolidated Balance Sheets. The following table summarizes the changes in EAC’s asset retirement obligations for the periods indicated:
As of December 31, 2008, $48.1 million of EAC’s asset retirement obligations were long-term and recorded in “Future abandonment cost, net of current portion” and $1.5 million were current and included in “Other current liabilities” on the accompanying Consolidated Balance Sheets. Approximately $4.4 million of the future abandonment liability as of December 31, 2008 represents the estimated cost for decommissioning ENP’s Elk Basin natural gas processing plant. ENP expects to continue reserving additional amounts based on the estimated timing to cease operations of the natural gas processing plant.
Note 6. Capitalization of Exploratory Well Costs
EAC follows FSP No. 19-1 “Accounting for Suspended Well Costs” (“FSP 19-1”), which permits the continued capitalization of exploratory well costs if the well found a sufficient quantity of reserves to justify its completion as a producing well and the entity is making sufficient progress towards assessing the reserves and the economic and operating viability of the project. The following table reflects the net changes in
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capitalized exploratory well costs during the periods indicated, and does not include amounts that were capitalized and subsequently expensed in the same period.
All capitalized exploratory well costs have been capitalized for less than one year.
Note 7. Other Current Liabilities
Other current liabilities consisted of the following as of the dates indicated:
Note 8. Long-Term Debt
Long-term debt consisted of the following as of the dates indicated:
Senior Subordinated Notes
As of December 31, 2008 certain of EAC’s subsidiaries were subsidiary guarantors of EAC’s senior subordinated notes. The subsidiary guarantors may without restriction transfer funds to EAC in the form of
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cash dividends, loans, and advances. Please read “Note 16. Financial Statements of Subsidiary Guarantors” for additional discussion.
The indentures governing EAC’s senior subordinated notes contain certain affirmative, negative, and financial covenants, which include:
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limitations on incurrence of additional debt, restrictions on asset dispositions, and restricted payments;
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a requirement that EAC maintain a current ratio (as defined in the indentures) of not less than 1.0 to 1.0; and
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a requirement that EAC maintain a ratio of consolidated EBITDA (as defined in the indentures) to consolidated interest expense of not less than 2.5 to 1.0.
As of December 31, 2008, EAC was in compliance with all covenants of its senior subordinated notes.
If EAC experiences a change of control (as defined in the indentures), subject to certain conditions, it must give holders of its senior subordinated notes the opportunity to sell them to EAC at 101 percent of the principal amount, plus accrued and unpaid interest.
Revolving Credit Facilities
Encore Acquisition Company Senior Secured Credit Agreement
In March 2007, EAC entered into a five-year amended and restated credit agreement (as amended, the “EAC Credit Agreement”) with a bank syndicate including Bank of America, N.A. and other lenders. The EAC Credit Agreement matures on March 7, 2012. Effective February 7, 2008, EAC amended the EAC Credit Agreement to, among other things, provide that certain negative covenants in the EAC Credit Agreement restricting hedge transactions do not apply to any oil and natural gas hedge transaction that is a floor or put transaction not requiring any future payments or delivery by EAC or any of its restricted subsidiaries. Effective May 22, 2008, EAC amended the EAC Credit Agreement to, among other things, increase interest rate margins applicable to loans made under the EAC Credit Agreement, as set forth in the table below, and increase the borrowing base to $1.1 billion. The EAC Credit Agreement provides for revolving credit loans to be made to EAC from time to time and letters of credit to be issued from time to time for the account of EAC or the account of any of its restricted subsidiaries.
The aggregate amount of the commitments of the lenders under the EAC Credit Agreement is $1.25 billion. Availability under the EAC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually on April 1 and October 1 and upon requested special redeterminations. On December 5, 2008, the borrowing base under the EAC Credit Agreement was redetermined with no change. As of December 31, 2008, the borrowing base was $1.1 billion.
EAC’s obligations under the EAC Credit Agreement are secured by a first-priority security interest in EAC’s restricted subsidiaries’ proved oil and natural gas reserves and in EAC’s equity interests in its restricted subsidiaries. In addition, EAC’s obligations under the EAC Credit Agreement are guaranteed by its restricted subsidiaries.
Loans under the EAC Credit Agreement are subject to varying rates of interest based on (1) the total outstanding borrowings in relation to the borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan. Eurodollar loans bear interest at the Eurodollar rate plus the applicable margin indicated in the
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following table, and base rate loans bear interest at the base rate plus the applicable margin indicated in the following table:
The “Eurodollar rate” for any interest period (either one, two, three, or six months, as selected by EAC) is the rate per year equal to LIBOR, as published by Reuters or another source designated by Bank of America, N.A., for deposits in dollars for a similar interest period. The “base rate” is calculated as the higher of (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate” and (2) the federal funds effective rate plus 0.5 percent.
Any outstanding letters of credit reduce the availability under the EAC Credit Agreement. Borrowings under the EAC Credit Agreement may be repaid from time to time without penalty.
The EAC Credit Agreement contains covenants that include, among others:
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a prohibition against incurring debt, subject to permitted exceptions;
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a prohibition against paying dividends or making distributions, purchasing or redeeming capital stock, or prepaying indebtedness, subject to permitted exceptions;
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a restriction on creating liens on EAC’s and its restricted subsidiaries’ assets, subject to permitted exceptions;
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restrictions on merging and selling assets outside the ordinary course of business;
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restrictions on use of proceeds, investments, transactions with affiliates, or change of principal business;
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a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75 percent of anticipated production from proved producing reserves;
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a requirement that we maintain a ratio of consolidated current assets (as defined in the EAC Credit Agreement) to consolidated current liabilities (as defined in the EAC Credit Agreement) of not less than 1.0 to 1.0; and
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a requirement that we maintain a ratio of consolidated EBITDA (as defined in the EAC Credit Agreement) to the sum of consolidated net interest expense plus letter of credit fees of not less than 2.5 to 1.0.
The EAC Credit Agreement contains customary events of default. If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the EAC Credit Agreement to be immediately due and payable.
EAC incurs a commitment fee on the unused portion of the EAC Credit Agreement determined based on the ratio of amounts outstanding under the EAC Credit Agreement to the borrowing base in effect on such
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date. The following table summarizes the calculation of the commitment fee under the EAC Credit Agreement:
On December 31, 2008, there were $575 million of outstanding borrowings and $525 million of borrowing capacity under the EAC Credit Agreement. As of December 31, 2008, EAC was in compliance with all covenants of the EAC Credit Agreement.
Encore Energy Partners Operating LLC Credit Agreement
OLLC is a party to a five-year credit agreement dated March 7, 2007 (as amended, the “OLLC Credit Agreement”) with a bank syndicate including Bank of America, N.A. and other lenders. The OLLC Credit Agreement matures on March 7, 2012. On August 22, 2007, OLLC amended its credit agreement to revise certain financial covenants. The OLLC Credit Agreement provides for revolving credit loans to be made to OLLC from time to time and letters of credit to be issued from time to time for the account of OLLC or any of its restricted subsidiaries.
The aggregate amount of the commitments of the lenders under the OLLC Credit Agreement is $300 million. Availability under the OLLC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually on April 1 and October 1 and upon requested special redeterminations. On December 5, 2008, the borrowing base under the OLLC Credit Agreement was redetermined with no change. As of December 31, 2008, the borrowing base was $240 million.
OLLC’s obligations under the OLLC Credit Agreement are secured by a first-priority security interest in OLLC’s proved oil and natural gas reserves and in the equity interests in OLLC and its restricted subsidiaries. In addition, OLLC’s obligations under the OLLC Credit Agreement are guaranteed by ENP and OLLC’s restricted subsidiaries. EAC consolidates the debt of ENP with that of its own; however, obligations under the OLLC Credit Agreement are non-recourse to EAC and its restricted subsidiaries.
Loans under the OLLC Credit Agreement are subject to varying rates of interest based on (1) the total outstanding borrowings in relation to the borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan. Eurodollar loans bear interest at the Eurodollar rate plus the applicable margin indicated in the following table, and base rate loans bear interest at the base rate plus the applicable margin indicated in the following table:
The “Eurodollar rate” for any interest period (either one, two, three, or six months, as selected by ENP) is the rate per year equal to LIBOR, as published by Reuters or another source designated by Bank of America, N.A., for deposits in dollars for a similar interest period. The “base rate” is calculated as the higher of (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate” and (2) the federal funds effective rate plus 0.5 percent.
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Any outstanding letters of credit reduce the availability under the OLLC Credit Agreement. Borrowings under the OLLC Credit Agreement may be repaid from time to time without penalty.
The OLLC Credit Agreement contains covenants that include, among others:
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a prohibition against incurring debt, subject to permitted exceptions;
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a prohibition against purchasing or redeeming capital stock, or prepaying indebtedness, subject to permitted exceptions;
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a restriction on creating liens on the assets of ENP, OLLC and its restricted subsidiaries, subject to permitted exceptions;
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restrictions on merging and selling assets outside the ordinary course of business;
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restrictions on use of proceeds, investments, transactions with affiliates, or change of principal business;
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a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75 percent of anticipated production from proved producing reserves;
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a requirement that ENP and OLLC maintain a ratio of consolidated current assets (as defined in the OLLC Credit Agreement) to consolidated current liabilities (as defined in the OLLC Credit Agreement) of not less than 1.0 to 1.0;
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a requirement that ENP and OLLC maintain a ratio of consolidated EBITDA (as defined in the OLLC Credit Agreement) to the sum of consolidated net interest expense plus letter of credit fees of not less than 1.5 to 1.0;
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a requirement that ENP and OLLC maintain a ratio of consolidated EBITDA (as defined in the OLLC Credit Agreement) to consolidated senior interest expense of not less than 2.5 to 1.0; and
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a requirement that ENP and OLLC maintain a ratio of consolidated funded debt (excluding certain related party debt) to consolidated adjusted EBITDA (as defined in the OLLC Credit Agreement) of not more than 3.5 to 1.0.
The OLLC Credit Agreement contains customary events of default. If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the OLLC Credit Agreement to be immediately due and payable.
ENP incurs a commitment fee on the unused portion of the OLLC Credit Agreement determined based on the ratio of amounts outstanding under the OLLC Credit Agreement to the borrowing base in effect on such date. The following table summarizes the calculation of the commitment fee under the OLLC Credit Agreement:
On December 31, 2008, there were $150 million of outstanding borrowings and $90 million of borrowing capacity under the OLLC Credit Agreement. As of December 31, 2008, OLLC was in compliance with all covenants of the OLLC Credit Agreement.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Long-Term Debt Maturities
The following table illustrates EAC’s long-term debt maturities as of December 31, 2008:
During 2008, 2007, and 2006, the weighted average interest rate for total indebtedness was 5.6 percent, 6.9 percent, and 6.1 percent, respectively.
Note 9. Taxes
Income Taxes
The components of income tax provision were as follows for the periods indicated:
(a)
Excludes an excess tax benefit related to stock option exercises and vesting of restricted stock, which was recorded directly to additional paid-in capital, of $2.1 million and $1.3 million during 2008 and 2006, respectively. During 2007, EAC did not recognize an excess tax benefit related to stock option exercises and vesting of restricted stock.
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The following table reconciles income tax provision with income tax at the Federal statutory rate for the periods indicated:
A Texas franchise tax reform measure signed into law in May 2006 caused the Texas franchise tax to be applicable to numerous types of entities that previously were not subject to the tax, including several of EAC’s subsidiaries. EAC adjusted its net deferred tax balances using the new higher marginal tax rate it expects to be effective when those deferred taxes reverse resulting in a charge of $1.1 million during 2006.
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The major components of net current deferred taxes and net long-term deferred taxes were as follows as of the dates indicated:
At December 31, 2008, EAC had state net operating loss (“NOL”) carryforwards, which are available to offset future regular state taxable income, if any. At December 31, 2008, EAC also had federal alternative minimum tax (“AMT”) credits, which are available to reduce future federal regular tax liabilities in excess of AMT. EAC believes it is more likely than not that the NOL carryforwards will offset future taxable income prior to their expiration. The AMT credits have no expiration. Therefore, a valuation allowance against these
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deferred tax assets is not considered necessary. If unused, these carryforwards and credits will expire as follows:
On January 1, 2007, EAC adopted the provisions of FIN No. 48, “Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109” (“FIN 48”), which clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. EAC and its subsidiaries file income tax returns in the U.S. federal jurisdiction and various state jurisdictions. Subject to statutory exceptions that allow for a possible extension of the assessment period, EAC is no longer subject to U.S. federal, state, and local income tax examinations for years prior to 2003.
EAC performs a periodic evaluation of tax positions to review the appropriate recognition threshold for each tax position recognized in EAC’s financial statements, including, but not limited to:
•
a review of documentation of tax positions taken on previous returns including an assessment of whether EAC followed industry practice or the applicable requirements under the tax code;
•
a review of open tax returns (on a jurisdiction by jurisdiction basis) as well as supporting documentation used to support those tax returns;
•
a review of the results of past tax examinations;
•
a review of whether tax returns have been filed in all appropriate jurisdictions;
•
a review of existing permanent and temporary differences; and
•
consideration of any tax planning strategies that may have been used to support realization of deferred tax assets.
On the date of adoption of FIN 48 and as of December 31, 2008 and 2007, all of EAC’s tax positions met the “more-likely-than-not” threshold prescribed by FIN 48. As a result, no additional tax expense, interest, or penalties have been accrued. EAC includes interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its Consolidated Statements of Operations. For 2008, 2007, and 2006, EAC recorded only a nominal amount of interest and penalties on certain tax positions.
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Taxes Other than Income Taxes
Taxes other than income taxes included the following for the periods indicated:
Note 10. Stockholders’ Equity
Public Offering of Common Stock
In April 2006, EAC issued 4,000,000 shares of its common stock at a price of $32.00 per share. The net proceeds of approximately $127.1 million were used to (1) reduce outstanding borrowings under EAC’s revolving credit facility, (2) invest in oil and natural gas activities, and (3) pay general corporate expenses.
Stock Option Exercises and Restricted Stock Vestings
During 2008, 2007, and 2006, employees of EAC exercised 45,616 options, 128,709 options, and 178,174 options, respectively, for which EAC received proceeds of $0.6 million, $1.6 million, and $2.3 million in 2008, 2007, and 2006, respectively. During 2008, 2007, and 2006, employees elected to satisfy minimum tax withholding obligations related to the vesting of restricted stock by directing EAC to withhold 32,946 shares, 38,978 shares, and 24,362 shares of common stock, respectively, which are accounted for as treasury stock until they are formally retired.
Preferred Stock
EAC’s authorized capital stock includes 5,000,000 shares of preferred stock, none of which were issued and outstanding at December 31, 2008 or 2007. EAC does not plan to issue any shares of preferred stock.
Stock Repurchase Programs
In December 2007, EAC announced that the Board approved a share repurchase program authorizing EAC to repurchase up to $50 million of its common stock. During 2008, EAC completed the share repurchase program by repurchasing and retiring 1,397,721 shares of its outstanding common stock at an average price of approximately $35.77 per share.
In October 2008, EAC announced that the Board approved a new share repurchase program authorizing EAC to repurchase up to $40 million of its common stock. As of December 31, 2008, EAC had repurchased and retired 620,265 shares of its outstanding common stock for approximately $17.2 million, or an average price of $27.68 per share, under the new share repurchase program.
Issuance of ENP Common Units
In May 2008, ENP acquired an existing net profits interest in certain of its properties in the Permian Basin of West Texas in exchange for 283,700 common units which were valued at $5.8 million at the time of the acquisition. As a result, EAC’s percentage ownership in ENP went from approximately 67 percent to approximately 66 percent. Additionally, EAC reclassified $3.5 million from “Minority interest in consolidated
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partnership” to “Additional paid-in capital” on the accompanying Consolidated Balance Sheets to recognize gains on the issuance of ENP’s common units.
In December 2008, as a result of the conversion of ENP’s management incentive units into ENP common units, EAC recorded a $13.9 million economic uniformity adjustment by reducing “Additional paid-in capital” and increasing “Minority interest in consolidated partnership” in the accompanying Consolidated Balance Sheets.
In September 2007, ENP completed its IPO of 9,000,000 common units at a price to the public of $21.00 per unit, and in October 2007, the underwriters exercised their over-allotment option to purchase an additional 1,148,400 common units. As a result, EAC’s percentage ownership in ENP went from 100 percent to approximately 58 percent. Additionally, EAC reclassified $77.6 million from “Minority interest in consolidated partnership” to “Additional paid-in capital” on the accompanying Consolidated Balance Sheets to recognize gains on the issuance of ENP’s common units.
Rights Plan
In October 2008, the Board declared a dividend of one right for each outstanding share of EAC’s common stock to stockholders of record at the close of business on November 7, 2008. Each right entitles the registered holder to purchase from EAC a unit consisting of one one-hundredth of a share of Series A Junior Participating Preferred Stock, par value $0.01 per share, at a purchase price of $120 per fractional share, subject to adjustment.
The rights will separate from the common stock and a “Distribution Date” will occur, with certain exceptions, upon the earlier of (1) ten days following a public announcement that a person or group of affiliated or associated persons (an “Acquiring Person”) has acquired, or obtained the right to acquire, beneficial ownership of more than 10 percent of EAC’s then-outstanding shares of common stock, or (2) ten business days following the commencement of a tender offer or exchange offer that would result in a person’s becoming an Acquiring Person. In certain circumstances, the Distribution Date may be deferred by the Board. The rights are not exercisable until the Distribution Date and will expire at the close of business on October 28, 2011, unless earlier redeemed or exchanged by EAC.
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Note 11. EPS
EAC calculates EPS in accordance with SFAS 128. The following table reflects EPS computations for the periods indicated:
(a)
For 2008, 2007, and 2006, options to purchase 157,614, 121,651, and 103,856 shares of common stock, respectively, were outstanding but excluded from the diluted EPS calculations because their effect would have been antidilutive.
(b)
For 2008 and 2007, 17,511 and 59,865 shares of restricted stock, respectively, were outstanding but excluded from the diluted EPS calculations because their effect would have been antidilutive. There were no antidilutive shares of restricted stock for 2006.
Note 12. Employee Benefit Plans
401(k) Plan
EAC made contributions to its 401(k) plan, which is a voluntary and contributory plan for eligible employees based on a percentage of employee contributions, of $3.6 million, $2.2 million, and $1.1 million during 2008, 2007, and 2006, respectively. EAC’s 401(k) plan does not allow employees to invest in securities of EAC.
Incentive Stock Plans
In May 2008, EAC’s stockholders approved the 2008 Incentive Stock Plan (the “2008 Plan”). No additional awards will be granted under EAC’s 2000 Incentive Stock Plan (the “2000 Plan”) and any previously granted awards outstanding under the 2000 Plan will remain outstanding in accordance with their terms. The purpose of the 2008 Plan is to attract, motivate, and retain selected employees of EAC and to provide EAC with the ability to provide incentives more directly linked to the profitability of the business and increases in shareholder value. All directors and full-time regular employees of EAC and its subsidiaries and affiliates are eligible to be granted awards under the 2008 Plan. The total number of shares of common stock reserved for issuance pursuant to the 2008 Plan is 2,400,000. No more than 1,600,000 shares of EAC’s common stock will be available for grants of “full value” stock awards, such as restricted stock or stock units. As of December 31, 2008, there were 2,389,000 shares available for issuance under the 2008 Plan. Shares delivered or withheld for payment of the exercise price of an option, shares withheld for payment of tax
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withholding, shares subject to options or other awards that expire or are forfeited, and restricted shares that are forfeited will again become available for issuance under the 2008 Plan. The 2008 Plan provides for the granting of cash awards, incentive stock options, non-qualified stock options, restricted stock, and stock appreciation rights at the discretion of the Compensation Committee of the Board. The Board also has a Restricted Stock Award Committee whose sole member is Jon S. Brumley, EAC’s Chief Executive Officer and President. The Restricted Stock Award Committee may grant up to 25,000 shares of restricted stock on an annual basis to non-executive employees at its discretion.
The 2008 Plan contains the following individual limits:
•
an employee may not be granted awards covering or relating to more than 300,000 shares of common stock during any calendar year;
•
a non-employee director may not be granted awards covering or relating to more than 20,000 shares of common stock during any calendar year; and
•
an employee may not receive awards consisting of cash (including cash awards that are granted as performance awards) in respect of any calendar year having a value determined on the grant date in excess of $5.0 million.
In May 2008, the Board approved certain amendments to the 2000 Plan to ensure compliance with Section 409A of the Code. In particular, the 2000 Plan was amended to allow for the exemption of options from the requirements of Section 409A of the Code by requiring that, upon a change-in-control, options granted or that vest on or after January 1, 2005 be valued at their fair market value as of the date they are cashed out, rather than the highest price per share paid in the 60 days prior to the change-in-control. The amendments to the 2000 Plan did not require stockholder approval under its terms, applicable laws, or the rules of the New York Stock Exchange.
During 2008, 2007, and 2006, EAC recorded non-cash stock-based compensation expense related to its incentive stock plans in the accompanying Consolidated Statements of Operations of $9.0 million, $9.2 million, and $9.0 respectively, and recognized income tax benefits related thereto of $3.4 million, $3.4 million, and $3.2 million, respectively. During 2008, 2007, and 2006, EAC also capitalized $2.3 million, $1.3 million, and $1.1 million, respectively, of non-cash stock-based compensation cost as a component of “Properties and equipment” in the accompanying Consolidated Balance Sheets. Non-cash stock-based compensation expense has been allocated to LOE and general and administrative (“G&A”) expense based on the allocation of the respective employees’ cash compensation.
Please read “Note 17. ENP” for a discussion of ENP’s equity-based compensation plan.
Stock Options. All options have a strike price equal to the fair market value of EAC’s common stock on the grant date, have a ten-year life, and vest over a three-year period. The fair value of options granted was estimated on the grant date using a Black-Scholes option valuation model based on the assumptions noted in the following table. The expected volatility was based on the historical volatility of EAC’s common stock for a period of time commensurate with the expected term of the options. For options granted prior to January 1, 2008, EAC used the “simplified” method prescribed by SAB No. 107, “Valuation of Share-Based Payment Arrangements for Public Companies” to estimate the expected term of the options, which was calculated as the average midpoint between each vesting date and the life of the option. For options granted subsequent to December 31, 2007, EAC determined the expected life of the options based on an analysis of historical exercise and forfeiture behavior as well as expectations about future behavior. The risk-free interest rate is
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based on the U.S Treasury yield curve in effect at the grant date for a period of time commensurate with the expected term of the options.
The following table summarizes the changes in EAC’s outstanding options for the periods indicated:
The weighted average fair value per share of options granted during 2008, 2007, and 2006 was $13.15, $11.16, and $14.96, respectively. The total intrinsic value of options exercised during 2008, 2007, and 2006 was $1.6 million, $2.3 million, and $2.4 million, respectively. During 2008, 2007, and 2006, EAC received proceeds from the exercise of stock options of $0.5 million, $1.6 million, and $2.3 million, respectively. During 2008 and 2006, EAC recognized income tax benefits related to stock options of $0.5 million and $0.9 million, respectively. During 2007, EAC did not recognize any income tax benefits related to stock options. At December 31, 2008, EAC had $1.1 million of total unrecognized compensation cost related to unvested stock options, which is expected to be recognized over a weighted average period of 1.9 years.
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Additional information about options outstanding and exercisable at December 31, 2008 is as follows:
Restricted Stock. Restricted stock awards vest over varying periods from one to five years, subject to performance-based vesting for certain members of senior management. During 2008, 2007, and 2006, EAC recognized expense related to restricted stock of $7.6 million, $7.6 million, and $7.3 million, respectively. During 2008 and 2006, EAC recognized income tax benefits related to the vesting of restricted stock of $1.6 million and $0.4 million, respectively. During 2007, EAC did not recognize any income tax benefits related to the vesting of restricted stock. The following table summarizes the changes in the number of EAC’s unvested restricted stock awards and their related weighted average grant date fair value for 2008:
During 2008, 2007, and 2006, EAC issued 241,515 shares, 169,453 shares, and 277,162 shares, respectively, of restricted stock to employees and members of the Board, the vesting of which is dependent only on the passage of time and continued employment. The following table illustrates outstanding restricted stock at December 31, 2008 the vesting of which is dependent only on the passage of time and continued employment:
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During 2008, 2007, and 2006, EAC issued 72,571 shares, 175,180 shares, and 151,447 shares of restricted stock to certain members of senior management, the vesting of which is dependent not only on the passage of time and continued employment, but also on the achievement of certain performance measures. The performance measures related to the 2007 and 2006 awards were met and therefore, vesting depends only on the passage of time and continued employment. The following table illustrates outstanding restricted stock at December 31, 2008 the vesting of which is dependent not only on the passage of time and continued employment, but also on the achievement of certain performance measures:
As of December 31, 2008, EAC had $8.2 million of total unrecognized compensation cost related to unvested restricted stock, which is expected to be recognized over a weighted average period of 2.7 years. None of EAC’s unvested restricted stock is subject to variable accounting. During 2008, 2007, and 2006, there were 256,785 shares, 184,867 shares, and 101,377 shares, respectively, of restricted stock that vested for which certain employees elected to satisfy minimum tax withholding obligations related thereto by directing EAC to withhold 32,946 shares, 38,978 shares, and 24,362 shares of common stock, respectively. EAC accounts for these shares as treasury stock until they are formally retired and have been reflected as such in the accompanying consolidated financial statements. The total fair value of restricted stock that vested during 2008, 2007, and 2006 was $8.7 million, $5.3 million, and $2.6 million, respectively.
Note 13. Financial Instruments
The following table sets forth EAC’s book value and estimated fair value of financial instrument assets (liabilities) as of the dates indicated:
The book value of cash and cash equivalents, accounts receivable, net, and accounts payable approximate fair value due to the short-term nature of these instruments. The fair values of the Notes were determined using open market quotes. The difference between book value and fair value represents the premium or discount on that date. The book value of the revolving credit facilities approximates fair value as the interest rate is variable. The plugging bond and Bell Creek escrow are included in “Other assets” on the accompanying
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Consolidated Balance Sheets and are classified as “held to maturity” and therefore, are recorded at amortized cost, which was less than fair value. The fair values of the plugging bond and Bell Creek escrow were determined using open market quotes. Commodity derivative contracts and interest rate swaps are marked-to-market each quarter.
Derivative Financial Instruments
Commodity Derivative Contracts. EAC manages commodity price risk with swap contracts, put contracts, collars, and floor spreads. Swap contracts provide a fixed price for a notional amount of sales volumes. Put contracts provide a fixed floor price on a notional amount of sales volumes while allowing full price participation if the relevant index price closes above the floor price. Collars provide a floor price on a notional amount of sales volumes while allowing some additional price participation if the relevant index price closes above the floor price.
As of December 31, 2008, EAC had $67.6 million of deferred premiums payable of which $5.4 million was long-term and included in “Derivatives” in the non-current liabilities section of the accompanying Consolidated Balance Sheet and $62.2 million was current and included in “Derivatives” in the current liabilities section of the accompanying Consolidated Balance Sheet. The premiums relate to various oil and natural gas floor contracts and are payable on a monthly basis from January 2009 to January 2010. EAC recorded these premiums at their net present value at the time the contract was entered into and accretes that value to the eventual settlement price by recording interest expense each period.
From time to time, EAC sells floors with a strike price below the strike price of the purchased floors in order to partially finance the premiums paid on the purchased floors. Together the two floors, known as a floor spread or put spread, have a lower premium cost than a traditional floor contract but provide price protection only down to the strike price of the short floor. As with EAC’s other commodity derivative contracts, these are marked-to-market each quarter through “Derivative fair value loss (gain)” in the accompanying Consolidated Statements of Operations. In the following tables, the purchased floor component of these floor spreads are shown net and included with EAC’s other floor contracts.
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The following tables summarize EAC’s open commodity derivative contracts as of December 31, 2008:
Oil Derivative Contracts
(a)
In addition, ENP has a floor contract for 1,000 Bbls/D at $63.00 per Bbl and a short floor contract for 1,000 Bbls/D at $65.00 per Bbl.
Natural Gas Derivative Contracts
Interest Rate Swaps. ENP manages interest rate risk with interest rate swaps whereby it swaps floating rate debt under the OLLC Credit Agreement with a weighted average fixed rate. These interest rate swaps
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
were designated as cash flow hedges. The following table summarizes ENP’s open interest rate swaps as of December 31, 2008:
As of December 31, 2008, the fair market value of ENP’s interest rate swaps was a net liability of $4.6 million of which, $1.3 million was current and included in the current liabilities line “Derivatives” and $3.3 million was long-term and included in the other liabilities line “Derivatives” in the accompanying Consolidated Balance Sheets. During 2008, settlements of interest rate swaps increased EAC’s consolidated interest expense by approximately $0.2 million.
Current Period Impact. As a result of commodity derivative contracts which were previously designated as hedges, EAC recognized a pre-tax reduction in oil and natural gas revenues of approximately $2.9 million, $53.6 million, and $60.3 million in 2008, 2007, and 2006, respectively. EAC also recognized derivative fair value gains and losses related to: (1) ineffectiveness on designated derivative contracts; (2) changes in the market value of derivative contracts; (3) settlements on commodity derivative contracts; and (4) premium amortization. The following table summarizes the components of “Derivative fair value loss (gain)” for the periods indicated:
Counterparty Risk. At December 31, 2008, EAC had committed greater than 10 percent of either its oil or natural gas commodity derivative contracts to the following counterparties:
In order to mitigate the credit risk of financial instruments, EAC enters into master netting agreements with significant counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and EAC. Instead of treating separately each derivative financial transaction between the counterparty and EAC, the master netting agreement enables the counterparty and EAC to aggregate all financial trades and treat them as a single agreement. This arrangement benefits EAC in three ways: (1) the netting of the value of all trades reduces the likelihood of counterparties requiring daily collateral posting by
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EAC; (2) default by a counterparty under one financial trade can trigger rights to terminate all financial trades with such counterparty; and (3) netting of settlement amounts reduces EAC’s credit exposure to a given counterparty in the event of close-out.
Accumulated Other Comprehensive Loss. At December 31, 2008, accumulated other comprehensive loss consisted entirely of deferred losses, net of tax, on ENP’s interest rate swaps that are designated as hedges of $1.7 million. At December 31, 2007, accumulated other comprehensive loss consisted entirely of deferred losses, net of tax, on commodity derivative contracts that were previously designated as hedges of $1.8 million.
EAC expects to reclassify $1.3 million of deferred losses associated with ENP’s interest rate swaps from accumulated other comprehensive loss to interest expense during 2009. EAC also expects to reclassify $0.2 million of income taxes associated with ENP’s interest rate swaps from accumulated other comprehensive loss to income tax benefit during 2009.
Note 14. Fair Value Measurements
As discussed in “Note 2. Summary of Significant Accounting Policies,” EAC adopted SFAS 157 on January 1, 2008, as it relates to financial assets and liabilities. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy defined by SFAS 157 are as follows:
•
Level 1 - Unadjusted quoted prices are available in active markets for identical assets or liabilities.
•
Level 2 - Pricing inputs, other than quoted prices within Level 1, that are either directly or indirectly observable.
•
Level 3 - Pricing inputs that are unobservable requiring the use of valuation methodologies that result in management’s best estimate of fair value.
EAC’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the financial assets and liabilities and their placement within the fair value hierarchy levels. The following methods and assumptions are used to estimate the fair values of EAC’s financial assets and liabilities that are accounted for at fair value on a recurring basis:
•
Level 2 - Fair values of oil and natural gas swaps were estimated using a combined income and market-based valuation methodology based upon forward commodity price curves obtained from independent pricing services reflecting broker market quotes. Fair values of interest rate swaps were estimated using a combined income and market-based valuation methodology based upon credit ratings and forward interest rate yield curves obtained from independent pricing services reflecting broker market quotes.
•
Level 3 - Fair values of oil and natural gas floors and caps were estimated using pricing models and discounted cash flow methodologies based on inputs that are not readily available in public markets.
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The following table sets forth EAC’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2008:
The following table summarizes the changes in the fair value of EAC’s Level 3 financial assets and liabilities for 2008:
Since EAC does not use hedge accounting for its commodity derivative contracts, all gains and losses on its Level 3 financial assets and liabilities are included in “Derivative fair value loss (gain)” in the accompanying Consolidated Statements of Operations. All fair values reflected in the table above and in the accompanying Consolidated Balance Sheet have been adjusted for non-performance risk, resulting in a reduction of the net asset of approximately $3.4 million as of December 31, 2008.
Note 15. Related Party Transactions
During 2008, 2007, and 2006, EAC received approximately $160.5 million, $85.3 million, and $7.4 million, respectively, from affiliates of Tesoro Corporation (“Tesoro”) related to gross oil and natural gas production sold from wells operated by Encore Operating. Mr. John V. Genova, a member of the Board, served as an employee of Tesoro until May 2008.
Please read “Note 17. ENP” for a discussion of related party transactions with ENP.
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Note 16. Financial Statements of Subsidiary Guarantors
In February 2007, EAC formed certain non-guarantor subsidiaries in connection with the formation of ENP. Please read “Note 17. ENP” for additional discussion of ENP’s formation and other matters. As of December 31, 2008 and 2007, certain of EAC’s wholly owned subsidiaries were subsidiary guarantors of EAC’s senior subordinated notes. The subsidiary guarantees are full and unconditional, and joint and several. The subsidiary guarantors may, without restriction, transfer funds to EAC in the form of cash dividends, loans, and advances. In accordance with the United States Securities and Exchange Commission (“SEC”) rules, EAC has prepared condensed consolidating financial statements in order to quantify the financial position, results of operations, and cash flows of the subsidiary guarantors. The following Condensed Consolidating Balance Sheets as of December 31, 2008 and 2007 and Condensed Consolidating Statements of Operations and Comprehensive Income (Loss) and Condensed Consolidating Statements of Cash Flows for the years ended December 31, 2008 and 2007 present consolidating financial information for Encore Acquisition Company (“Parent”) on a stand alone, unconsolidated basis, and its combined guarantor and combined non-guarantor subsidiaries. As of December 31, 2008, EAC’s guarantor subsidiaries were:
•
EAP Properties, Inc.;
•
EAP Operating, LLC;
•
Encore Operating; and
•
Encore Operating Louisiana, LLC.
As of December 31, 2008, EAC’s non-guarantor subsidiaries were:
•
ENP;
•
OLLC;
•
GP LLC;
•
Encore Partners GP Holdings LLC;
•
Encore Partners LP Holdings LLC;
•
Encore Energy Partners Finance Corporation; and
•
Encore Clear Fork Pipeline LLC.
All intercompany investments in, loans due to/from, subsidiary equity, and revenues and expenses between the Parent, guarantor subsidiaries, and non-guarantor subsidiaries are shown prior to consolidation with the Parent and then eliminated to arrive at consolidated totals per the accompanying consolidated financial statements of EAC. Prior to February 2007, all of EAC’s subsidiaries were subsidiary guarantors of EAC’s senior subordinated notes. Therefore, a Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) and a Condensed Consolidating Statement of Cash Flows are not presented for 2006.
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CONDENSED CONSOLIDATING BALANCE SHEET
December 31, 2008
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CONDENSED CONSOLIDATING BALANCE SHEET
December 31, 2007
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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND
COMPREHENSIVE INCOME
For the Year Ended December 31, 2008
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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND
COMPREHENSIVE INCOME (LOSS)
For the Year Ended December 31, 2007
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Year Ended December 31, 2008
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CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Year Ended December 31, 2007
Note 17. ENP
In September 2007, ENP completed its IPO of 9,000,000 common units at a price to the public of $21.00 per unit. In October 2007, the underwriters exercised their over-allotment option to purchase an additional 1,148,400 common units of ENP. The net proceeds of approximately $193.5 million, after deducting the underwriters’ discount and a structuring fee of approximately $14.9 million, in the aggregate, and offering expenses of approximately $4.7 million, were used to repay in full the $126.4 million of outstanding indebtedness under OLLC’s subordinated credit agreement with EAP Operating, LLC, and reduce outstanding borrowings under the OLLC Credit Agreement.
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In connection with the closing of ENP’s IPO, EAC, ENP, and certain of their respective subsidiaries entered into a contribution, conveyance and assumption agreement (the “Contribution Agreement”) and an amended and restated administrative services agreement (the “Administrative Services Agreement”), each as more fully described below. In addition, prior to ENP’s IPO, GP LLC approved the Encore Energy Partners GP LLC Long-Term Incentive Plan (the “ENP Plan”), as more fully described below.
Contribution, Conveyance and Assumption Agreement
At the closing of ENP’s IPO, the following transactions, among others, occurred pursuant to the Contribution Agreement:
•
Encore Operating transferred certain oil and natural gas properties and related assets in the Permian Basin to ENP in exchange for 4,043,478 common units; and
•
EAC agreed to indemnify ENP for certain environmental liabilities, tax liabilities, and title defects, as well as defects relating to retained assets and liabilities, occurring or existing before the closing.
These transfers and distributions were made in a series of steps outlined in the Contribution Agreement. In connection with the issuance of the common units by ENP in exchange for the Permian Basin assets, ENP’s IPO, and the exercise of the underwriters’ over-allotment option to purchase additional common units, GP LLC exchanged such number of common units for general partner units as was necessary to enable it to maintain its two percent general partner interest in ENP. GP LLC received the common units through capital contributions from EAC and its subsidiaries of common units they owned.
Administrative Services Agreement
ENP does not have any employees. The employees supporting ENP’s operations are employees of EAC. Accordingly, EAC recognizes all employee-related expenses and liabilities in its consolidated financial statements. Encore Operating performs administrative services for ENP, such as accounting, corporate development, finance, land, legal, and engineering, pursuant to the Administrative Services Agreement. In addition, Encore Operating provides all personnel and any facilities, goods, and equipment necessary to perform these services and not otherwise provided by ENP. Encore Operating initially received an administrative fee of $1.75 per BOE of ENP’s production for such services. Effective April 1, 2008, the administrative fee increased to $1.88 per BOE of ENP’s production as a result of the COPAS Wage Index Adjustment. Encore Operating also charges ENP for reimbursement of actual third-party expenses incurred on ENP’s behalf. Encore Operating has substantial discretion in determining which third-party expenses to incur on ENP’s behalf. In addition, Encore Operating is entitled to retain any COPAS overhead charges associated with drilling and operating wells that would otherwise be paid by non-operating interest owners to the operator of a well. Encore Operating is not liable to ENP for its performance of, or failure to perform, services under the Administrative Services Agreement unless its acts or omissions constitute gross negligence or willful misconduct.
ENP also reimburses EAC for any state income, franchise, or similar tax incurred by EAC resulting from the inclusion of ENP and its subsidiaries in consolidated tax returns with EAC and its subsidiaries as required by applicable law. The amount of any such reimbursement is limited to the tax that ENP and its subsidiaries would have incurred had it not been included in a combined group with EAC.
Purchase and Investment Agreement
In December 2007, OLLC entered into a purchase and investment agreement with Encore Operating pursuant to which OLLC agreed to acquire certain oil and natural gas properties and related assets in the Permian and Williston Basins from Encore Operating. The transaction closed in February 2008, but was effective as of January 1, 2008. The consideration for the acquisition consisted of approximately $125.3 million
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
in cash, including post-closing adjustments, and 6,884,776 common units representing limited partner interests in ENP. ENP funded the cash portion of the purchase price with borrowings under the OLLC Credit Agreement. EAC used the proceeds from the sale to reduce outstanding borrowings under the EAC Credit Agreement.
Long-Term Incentive Plan
In September 2007, GP LLC approved the ENP Plan, which provides for the granting of options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other equity-based awards, and unit awards. All employees, consultants, and directors of EAC, GP LLC, and any of their subsidiaries and affiliates who perform services for ENP and its subsidiaries and affiliates are eligible to be granted awards under the ENP Plan. The total number of common units reserved for issuance pursuant to the ENP Plan is 1,150,000. As of December 31, 2008, there were 1,100,000 common units available for issuance under the ENP Plan. The ENP Plan is administered by the board of directors of GP LLC or a committee thereof, referred to as the plan administrator. To satisfy common unit awards under the ENP Plan, ENP may issue new common units, acquire common units in the open market, or use common units owned by EAC and its affiliates.
Phantom Units. From time to time, ENP issues phantom units to members of GP LLC’s board of directors pursuant to the ENP Plan. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit or, at the discretion of the plan administrator, cash equivalent to the value of a common unit. ENP intends to settle the phantom units at vesting by issuing common units; therefore, these phantom units are classified as equity instruments. Phantom units vest in four equal annual installments. The holders of phantom units are also entitled to receive distribution equivalent rights prior to vesting, which entitle them to receive cash equal to the amount of any cash distributions made by ENP with respect to a common unit during the period the right is outstanding. During 2008 and 2007, ENP recognized non-cash equity-based compensation expense for the phantom units of approximately $0.3 million and $31,000, respectively, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations.
The following table summarizes the changes in the number of ENP’s unvested phantom units and their related weighted average grant date fair value for 2008:
During 2008 and 2007, ENP issued 30,000 and 20,000, respectively, phantom units to members of GP LLC’s board of directors pursuant to the ENP Plan the vesting of which is dependent only on the passage of
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
time and continuation as a board member. The following table illustrates by year of grant the vesting of outstanding phantom units at December 31, 2008:
As of December 31, 2008, ENP had $0.6 million of total unrecognized compensation cost related to unvested phantom units, which is expected to be recognized over a weighted average period of 1.5 years. During 2008, there were 6,250 phantom units that vested, the total fair value of which was $0.1 million.
Management Incentive Units
In May 2007, the board of directors of GP LLC issued 550,000 management incentive units to certain executive officers of GP LLC. A management incentive unit is a limited partner interest in ENP that entitles the holder to quarterly distributions to the extent paid to ENP’s common unitholders and to increasing distributions upon the achievement of 10 percent compounding increases in ENP’s distribution rate to common unitholders. On November 14, 2008, the management incentive units became convertible into ENP common units, at the option of the holder, at a ratio of one management incentive unit to approximately 3.1186 ENP common units. During the fourth quarter of 2008, all 550,000 management incentive units were converted into 1,715,205 ENP common units.
The fair value of the management incentive units granted in 2007 was estimated on the date of grant using a discounted dividend model. During 2008 and 2007, ENP recognized total non-cash equity-based compensation expense for the management incentive units of $4.8 million and $6.8 million, respectively, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations. As of December 31, 2008, there have been no additional issuances of management incentive units.
Distributions
During 2008 and 2007, ENP paid cash distributions to unitholders of $74.4 million and $1.3 million, respectively, of which $46.9 million and $0.8 million was paid to EAC and its subsidiaries and had no impact on EAC’s consolidated cash.
Note 18.
Segment Information
The following tables provides EAC’s operating segment information required by SFAS No. 131, “Disclosure about Segments of an Enterprise and Related Information” as well as the results of operations from oil and natural gas producing activities required by SFAS No. 69, “Disclosures about Oil and Gas Producing Activities.” Prior to 2007, segment reporting was not applicable to EAC.
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 19.
Impairment of Long-Lived Assets
During 2008, circumstances indicated that the carrying amounts of certain oil and natural gas properties, primarily four wells in the Tuscaloosa Marine Shale, may not be recoverable. EAC compared the assets’ carrying amounts to the undiscounted expected future net cash flows, which indicated the need for an impairment charge. EAC then compared the net carrying amounts of the impaired assets to their estimated fair value, which resulted in a write-down of the value of proved oil and natural gas properties of $59.5 million. Fair value was determined using estimates of future production volumes and estimates of future prices EAC might receive for these volumes, discounted to a present value. EAC’s estimates of undiscounted cash flows indicated that the remaining carrying amounts of its oil and natural gas properties are expected to be recovered. Nonetheless, if oil and natural gas prices continue to decline, it is reasonably possible that EAC’s estimates of undiscounted cash flows may change in the near term resulting in the need to record an additional write down of oil and natural gas properties to fair value.
Note 20.
Subsequent Events - Unaudited
Commodity Derivative Contracts
Subsequent to December 31, 2008, EAC entered into additional commodity derivative contracts. The following tables summarize EAC’s open commodity derivative contracts as of February 18, 2009:
Oil Derivative Contracts
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Natural Gas Derivative Contracts
As of February 18, 2009, EAC’s total deferred commodity derivative premiums were $58.4 million, $15.7 million, and $0.9 million for the remainder of 2009, 2010, and, 2011, respectively.
Purchase and Sale Agreement
On December 5, 2008, EAC entered into a purchase and sale agreement, with OLLC, pursuant to which OLLC acquired certain oil and natural gas producing properties and related assets in the Arkoma Basin and royalty interest properties in Oklahoma as well as 10,300 unleased mineral acres from EAC. The transaction closed on January 2, 2009, but was effective as of November 1, 2008. The purchase price was $49 million in cash, subject to customary adjustments (including a reduction in the purchase price for acquisition-related commodity derivative premiums of approximately $3 million), which OLLC financed through borrowings under the OLLC Credit Agreement.
The acquisition will be accounted for as a transaction between entities under common control. Therefore, the assets will be recorded on ENP’s balance sheet at EAC’s historical basis, and the historical results of operations of ENP will be restated to reflect the historical operating results of the combined operations.
Other Events
Subsequent to December 31, 2008, EAC granted 269,417 stock options and 378,537 shares of restricted stock to employees as part of its annual incentive program and 144,695 stock options and 376,717 shares of restricted stock vested. Subsequent to December 31, 2008, it was determined that the performance measures related to certain awards granted in 2008 were met and therefore, vesting now depends only on the passage of time and continued employment.
On January 26, 2009, ENP announced a distribution for the fourth quarter of 2008 to unitholders of record as of the close of business on February 6, 2009 at a rate of $0.50 per unit. Approximately $16.8 million was paid on February 13, 2009, $10.7 million of which was paid to EAC and its subsidiaries and had no impact on EAC’s consolidated cash.
ENCORE ACQUISITION COMPANY
SUPPLEMENTARY INFORMATION
Capitalized Costs and Costs Incurred Relating to Oil and Natural Gas Producing Activities
The capitalized cost of oil and natural gas properties was as follows as of the dates indicated:
The following table summarizes costs incurred related to oil and natural gas properties for the periods indicated:
Oil & Natural Gas Producing Activities - Unaudited
The estimates of EAC’s proved oil and natural gas reserves, which are located entirely within the United States, were prepared in accordance with guidelines established by the SEC and the FASB. Proved oil and natural gas reserve quantities are derived from estimates prepared by Miller and Lents, Ltd., who are independent petroleum engineers.
Future prices received for production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. There can be no assurance that the proved reserves will be developed within the periods assumed or that prices and costs will remain constant. Actual production may not equal the estimated amounts used in the preparation of reserve projections. In accordance with SEC guidelines, estimates of future net cash flows from EAC’s properties and the representative value thereof are made using oil and natural gas prices in effect as of the dates of such estimates and are held
ENCORE ACQUISITION COMPANY
SUPPLEMENTARY INFORMATION - (Continued)
constant throughout the life of the properties. Year-end prices used in estimating net cash flows were as follows as of the dates indicated:
EAC’s reserve and production quantities from its CCA properties have been reduced by the amounts attributable to the net profits interest. The net profits interest on EAC’s CCA properties has also been deducted from future cash inflows in the calculation of Standardized Measure. In addition, net future cash inflows have not been adjusted for commodity derivative contracts outstanding at the end of the year. The future net cash flows are reduced by estimated production and development costs, which are based on year-end economic conditions and held constant throughout the life of the properties, and by the estimated effect of future income taxes. Future income taxes are based on statutory income tax rates in effect at year-end, EAC’s tax basis in its proved oil and natural gas properties, and the effect of NOL carryforwards and AMT credits.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. Oil and natural gas reserve engineering is and must be recognized as a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in any exact way, and estimates of other engineers might differ materially from those included herein. The accuracy of any reserve estimate is a function of the quality of available data and engineering, and estimates may justify revisions based on the results of drilling, testing, and production activities. Accordingly, reserve estimates are often materially different from the quantities of oil and natural gas that are ultimately recovered. Reserve estimates are integral to management’s analysis of impairments of oil and natural gas properties and the calculation of DD&A on these properties.
EAC’s estimated net quantities of proved oil and natural gas reserves were as follows as of the dates indicated:
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SUPPLEMENTARY INFORMATION - (Continued)
The changes in EAC’s proved reserves were as follows for the periods indicated:
(a)
Includes reserves of 16.6 MMBbls of oil and 56.5 Bcf of natural gas (26.1 MMBOE) attributable to ENP in which there was a 36 percent minority interest as of December 31, 2008.
EAC’s Standardized Measure of discounted estimated future net cash flows was as follows as of the dates indicated:
ENCORE ACQUISITION COMPANY
SUPPLEMENTARY INFORMATION - (Continued)
(a)
Includes $200.0 million attributable to ENP in which there was a 36 percent minority interest as of December 31, 2008.
The changes in EAC’s Standardized Measure of discounted estimated future net cash flows were as follows for the periods indicated:
Selected Quarterly Financial Data - Unaudited
The following table provides selected quarterly financial data for the periods indicated:
ENCORE ACQUISITION COMPANY
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
In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2008 to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and that information required to be disclosed is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.
Management’s Report on Internal Control Over Financial Reporting
EAC’s management is responsible for establishing and maintaining adequate internal control over financial reporting. EAC’s internal control over financial reporting is a process designed under the supervision of EAC’s Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of EAC’s financial statements for external purposes in accordance with GAAP.
As of December 31, 2008, management assessed the effectiveness of EAC’s internal control over financial reporting based on the criteria for effective internal control over financial reporting established in “Internal Control - Integrated Framework,” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, management determined that EAC maintained effective internal control over financial reporting as of December 31, 2008, based on those criteria.
Ernst & Young, LLP, the independent registered public accounting firm that audited the consolidated financial statements of EAC included in this annual report on Form 10-K, has issued an attestation report on the effectiveness of EAC’s internal control over financial reporting as of December 31, 2008. The report, which expresses an unqualified opinion on the effectiveness of EAC’s internal control over financial reporting as of December 31, 2008, is included below.
ENCORE ACQUISITION COMPANY
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders of
Encore Acquisition Company:
We have audited Encore Acquisition Company’s (the “Company”) internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Encore Acquisition Company’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Encore Acquisition Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Encore Acquisition Company as of December 31, 2008 and 2007, 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, 2008 and our report dated February 24, 2009 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Fort Worth, Texas
February 24, 2009
ENCORE ACQUISITION COMPANY
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting during the fourth quarter of 2008 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B.
ITEM 9B.
OTHER INFORMATION
On February 9, 2009, the Compensation Committee of our Board (the “Compensation Committee”) approved the Strategic Team Bonus Plan (the “Bonus Plan”) to reward selected executive officers, managers, and certain other key employees for making significant contributions to our success. Awards under the Bonus Plan are based on the achievement of corporate objectives applicable to all covered employees and strategic and individual objectives tailored to each covered employee. For 2009, the Compensation Committee has established the following corporate objectives:
•
meet budgeted volumes;
•
achieve negative forecast revisions for proved developed producing properties of one percent or less;
•
generate at least $150 million of free cash flow;
•
achieve development costs of $22 per Bbl or less; and
•
generate a 15 percent rate of return based on constant oil and natural gas prices.
The actual cash bonus for 2009 will be determined based on the following formula: (1) the individual’s target 2009 bonus opportunity (set forth below), multiplied by (2) the level of achievement of corporate, strategic, and individual objectives as determined by the Compensation Committee in its discretion, (3) a corporate performance factor (between zero percent and 100 percent) determined by the Compensation Committee in its discretion, multiplied by (4) an individual performance factor (between zero percent and 100 percent) determined by the Compensation Committee in its discretion. So long as at least one of the five corporate objectives has been achieved, the Compensation Committee has discretion to award bonuses under the Bonus Plan based on the achievement of all, a portion of, or none of the other performance objectives.
The following table sets forth the target 2009 bonus opportunity for our named executive officers (expressed as a percentage of each executive’s annual base salary for 2008):
The Bonus Plan also includes a variety of additional corporate performance measures that can reduce or increase 2009 bonuses, provided that aggregate reductions will not decrease the target 2009 bonus opportunity by more than 50 percent or increase the target 2009 bonus opportunity by more than 150 percent.
Under the Bonus Plan and subject to the limitations described above, the Compensation Committee retains ultimate discretion, based on any factors it deems relevant, to increase or reduce the amount of, or cancel payment of, any award otherwise payable based on the applicable performance objectives for 2009.
Upon a change in control of our company, the Compensation Committee has discretion to pay out all awards under the Bonus Plan at a level determined in its sole discretion. Upon any termination of employment, a participant’s right to a bonus will be forfeited, except as the Compensation Committee may expressly provide otherwise in its discretion, subject to the attainment of the relevant performance goals for the year.
ENCORE ACQUISITION COMPANY
We anticipate that awards under the Bonus Plan for 2009 will be determined and paid in the first quarter of 2010.
PART III
ITEM 10.
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required in response to this item will be set forth in our definitive proxy statement for the 2009 annual meeting of stockholders and is incorporated herein by reference.
We have adopted a Code of Business Conduct and Ethics covering our directors, officers, and employees, which is available free of charge on our website (www.encoreacq.com). We will post on our website any amendments to the Code of Business Conduct and Ethics or waivers of the Code of Business Conduct and Ethics for directors and executive officers.
ITEM 11.
ITEM 11.
EXECUTIVE COMPENSATION
The information required in response to this item will be set forth in our definitive proxy statement for the 2009 annual meeting of stockholders and is incorporated herein by reference.
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The following table sets forth information about our common stock that may be issued under equity compensation plans as of December 31, 2008:
(1)
There are no outstanding warrants or equity rights awarded under our equity compensation plans. Excludes 938,407 shares of unvested restricted stock.
(2)
In May 2008, our stockholders approved the 2008 Incentive Stock Plan. No additional awards will be granted under our 2000 Incentive Stock Plan and any previously granted awards outstanding under the 2000 Plan will remain outstanding in accordance with their terms. Please read Note 12 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding our equity compensation plans.
Additional information required in response to this item will be set forth in our definitive proxy statement for the 2009 annual meeting of stockholders and is incorporated herein by reference.
ENCORE ACQUISITION COMPANY
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required in response to this item will be set forth in our definitive proxy statement for the 2009 annual meeting of stockholders and is incorporated herein by reference.
ITEM 14.
ITEM 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required in response to this item will be set forth in our definitive proxy statement for the 2009 annual meeting of stockholders and is incorporated herein by reference.
PART IV
ITEM 15.
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)
The following documents are filed as a part of this Report:
1. Financial Statements:
2. Financial Statement Schedules:
All financial statement schedules have been omitted because they are not applicable or the required information is presented in the financial statements or the notes to the consolidated financial statements.
(b) Exhibits
ENCORE ACQUISITION COMPANY
ENCORE ACQUISITION COMPANY
ENCORE ACQUISITION COMPANY
*
Filed herewith.
+
Management contract or compensatory plan, contract, or arrangement.
ENCORE ACQUISITION COMPANY
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.
Encore Acquisition Company
Date: February 24, 2009
By:
/s/ Jon S. Brumley
Jon S. Brumley
Chief Executive Officer and President
KNOW ALL MEN BY THESE PRESENTS, that each individual whose signature appears below constitutes and appoints Jon S. Brumley and Robert C. Reeves, and each of them, his true and lawful attorneys-in-fact and agents with full power of substitution, for him and in his name, place, and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Report, and to file the same, with all exhibits thereto, and all documents in connection therewith, with the SEC, granting unto said attorneys-in-fact and agents, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or his or their substitutes, may lawfully do or cause to be done by virtue hereof.
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.
ENCORE ACQUISITION COMPANY