Item 1A. Risk Factors
You should carefully consider the following risk factors in addition to the other information included in this report. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock or debt securities.
Volatile oil and gas prices could adversely affect our financial condition and results of operations.
Our success is largely dependent on oil and gas prices, which are extremely volatile. Any substantial or extended decline in the price of oil and gas below current levels will have a negative impact on our business operations and future revenues. Moreover, oil and gas prices depend on factors we cannot control, such as:
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supply and demand for oil and gas and expectations regarding supply and demand;
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weather;
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actions by OPEC and other major producing companies;
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political conditions in other oil-producing and gas-producing countries, including the possibility of insurgency, terrorism or war in such areas;
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the prices of foreign exports and the availability of alternate fuel sources;
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general economic conditions in the United States and worldwide, including the value of the U.S. Dollar relative to other major currencies; and
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governmental regulations.
With respect to our business, prices of oil and gas will affect:
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our revenues, cash flows, profitability and earnings;
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our ability to attract capital to finance our operations and the cost of such capital;
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the amount that we are allowed to borrow; and
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the value of our oil and gas properties and our oil and gas reserve volumes.
Estimates of oil and gas reserves depend on many assumptions that may be inaccurate. Any material inaccuracies could adversely affect the quantity and value of our oil and gas reserves.
The proved and probable oil and gas reserve information included in this document represents only estimates. These estimates are based on reports prepared by independent petroleum engineers and us. The estimates were calculated using the twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials. Any significant price changes will have a material effect on the quantity and present value of our reserves.
Petroleum engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including:
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historical production from the area compared with production from other comparable producing areas;
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the assumed effects of regulations by governmental agencies;
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assumptions concerning future oil and gas prices; and
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assumptions concerning future operating costs, transportation costs, severance and excise taxes, development costs and workover and remedial costs.
Because all reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating reserves:
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the quantities of oil and gas that are ultimately recovered;
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the timing of the recovery of oil and gas reserves;
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the production and operating costs incurred; and
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the amount and timing of future development expenditures.
Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same available data. Actual production, revenues and expenditures with respect to reserves will vary from estimates and the variances may be material, with the variability likely to be higher for probable reserves estimates.
The discounted future net revenues included in this document should not be considered as the market value of the reserves attributable to our properties. As required by the SEC, the estimated discounted future net revenues from proved reserves are generally based on costs as of the date of the estimates and the twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials. Actual future prices and costs may be materially higher or lower. Actual future net revenues will also be affected by factors such as:
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the amount and timing of actual production;
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supply and demand for oil and gas; and
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changes in governmental regulations or taxation.
In addition, the 10% discount factor, which the SEC requires to be used to calculate discounted future net revenues for reporting purposes, is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and gas industry in general.
Oil and natural gas prices have the potential to be volatile. As of February 2012, the twelve-month average of the first-day-of-the-month reference price for natural gas has declined from $4.12 per MMBtu at year-end 2011 to $3.86 per MMBtu, while the comparable price for oil has increased from $95.99 per Bbl at year-end 2011 to $97.28 per Bbl. Lower oil and natural gas prices not only decrease our revenues, but also may reduce the amount of hydrocarbons that we can produce economically and therefore potentially reduce the amount of our proved reserves. Reductions in the amount of our proved reserves, in turn, may reduce the borrowing base under our senior revolving credit facility. The borrowing base is determined at the discretion of our lenders based on, among other things, the collateral value of our proved reserves and is subject to regular redeterminations on May 1 of each year, as well as unscheduled redeterminations as set forth in the credit agreement.
If we are unable to replace the reserves that we have produced, our reserves and revenues will decline.
Our future success depends on our ability to find, develop and acquire additional oil and gas reserves that are economically recoverable which, in itself, is dependent on oil and gas prices. Without continued successful acquisition or exploration activities, our reserves and revenues will decline as a result of our current reserves being depleted by production. We may not be able to find or acquire additional reserves at acceptable costs.
The geographic concentration and lack of marketable characteristics of our oil reserves may have a greater effect on our ability to sell our oil production.
A substantial portion of our reserves are located in California. Any regional events, including price fluctuations, natural disasters and restrictive regulations that increase costs, reduce availability of equipment or supplies, reduce demand or limit our production may impact our operations more than if our reserves were more geographically diversified.
Our California oil production is, on average, heavier than premium grade light oil and the margin (sales price minus production costs) is generally less than that of lighter oil sales due to the processes required to refine this type of oil and the transportation requirements. As such, the effect of material price decreases will more adversely affect the profitability of heavy oil production compared with lighter grades of oil.
We could lose all or part of our investment in McMoRan common stock.
We owned approximately 31.6% of the outstanding shares of common stock of McMoRan as of December 31, 2011. We may sell shares of McMoRan common stock pursuant to underwritten offerings, in periodic sales under a shelf registration statement to be filed by McMoRan (subject to certain volume limitations), pursuant to the exercise of piggyback registration rights or as otherwise permitted by applicable law. Our ability to sell shares of McMoRan common stock could be severely limited, both as to timing and amount, and as a result of factors beyond our control. In addition, the market price of shares of McMoRan common stock that we hold may decline substantially before we sell them.
We do not control McMoRan’s assets and operations and the value of our investment in McMoRan’s common stock is subject to all of the risks and uncertainties inherent in McMoRan’s business, which include, but are not limited to, the following:
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general economic and business conditions;
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variations in the market demand for, and prices of, oil and natural gas;
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drilling results;
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unanticipated fluctuations in flow rates of producing wells due to mechanical or operational issues (including those experienced by wells operated by third parties where McMoRan is a participant);
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oil and natural gas reserve expectations;
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the potential adoption of new governmental regulations;
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the failure of third party partners to fulfill their commitments;
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the ability to hold current or future lease acreage rights;
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the ability to satisfy future cash obligations and environmental costs;
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adverse conditions, such as high temperatures and pressure that could lead to mechanical failures or increased costs;
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access to capital to fund drilling activities;
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other general exploration and development risks and hazards inherent in the production of oil and natural gas;
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tropical storms, hurricanes and other adverse weather conditions, which are common in the Gulf of Mexico during certain times of the year;
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the exercise of preferential rights by third parties; and
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other factors discussed in McMoRan’s Annual Report on Form 10-K and as are included from time to time in McMoRan’s public announcements and other filings with the SEC.
For the reasons described above, we may not realize an adequate return on our investment and we may incur losses on sales of our investment. We have elected to measure our equity investment in McMoRan at fair value. As a result, unrealized gains and losses on the investment will be reported in our consolidated statement of income, which could result in volatility in our earnings. If we are required to write down the value of our investment, it could reduce our net income, result in losses and have a significant impact on our working capital. The value of our investment in shares of McMoRan common stock is subjective. Declines in the valuation of our investment may result in other than temporary impairments of this asset, which would lead to accounting charges that could have a material adverse effect on our net income and results of operations.
We intend to continue to enter into derivative contracts for a portion of our oil and gas production, which exposes us to the risk of financial loss, may result in us making cash payments or prevent us from receiving the full benefit of increases in prices for oil and gas and may cause volatility in our reported earnings.
We use derivative instruments to manage our commodity price risk for a portion of our oil and gas production. This practice may prevent us from receiving the full advantage of increases in oil and gas prices above the maximum fixed amount specified in the derivative agreement. The derivative instruments also expose us to the risks of financial loss in a variety of circumstances, including when:
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a counterparty to the derivative contract is unable to satisfy its obligations;
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production is delayed or less than expected; or
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there is an adverse change in the expected differential between the underlying price in the derivative instrument and actual prices received for our production.
The level of derivative activity depends on our view of market conditions, available derivative prices and our operating strategy.
See Item 7A - Quantitative and Qualitative Disclosures About Market Risk - Commodity Price Risk for a summary of our current derivative positions. Since all of our derivative contracts are accounted for using mark-to-market accounting, we expect continued volatility in derivative gains or losses on our income statement as changes occur in the NYMEX and ICE price indices.
Potential regulations regarding derivatives could adversely impact our ability to engage in commodity price risk management activities.
On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act, or Dodd-Frank Act. The Dodd-Frank Act creates a new regulatory framework for oversight of derivatives transactions by the Commodity Futures Trading Commission, or CFTC, and the SEC. Among other things, the Dodd-Frank Act subjects certain swap participants to new capital, margin and business conduct standards. In addition, the Dodd-Frank Act contemplates that where appropriate in light of outstanding exposures, trading liquidity and other factors, swaps (broadly defined to include most hedging instruments other than futures) will be required to be cleared through a registered clearing facility and traded on a designated exchange or swap execution facility. There are some exceptions to these requirements for entities that use swaps to hedge or mitigate commercial risk. While we may qualify for one or more of such exceptions, the scope of these exceptions is uncertain and will be further defined through rulemaking proceedings at the CFTC and SEC in the coming months. Further, although we may qualify for exceptions, our derivatives counterparties may be subject to new capital, margin and business conduct requirements imposed as a result of the new legislation, which may increase our transaction costs or make it more difficult for us to enter into hedging transactions on favorable terms. Our inability to enter into hedging transactions on favorable terms, or at all, could increase our operating expenses and put us at increased exposure to the risk of adverse changes in oil and natural gas prices, which could adversely affect the predictability of cash flows from sales of oil and natural gas.
Our offshore operations are subject to substantial regulations and risks, which could adversely affect our ability to operate and our financial results.
We conduct operations offshore California and the U.S. Gulf of Mexico. Our offshore activities are subject to more extensive governmental regulation than our other oil and gas activities. In addition, we are vulnerable to the risks associated with operating offshore, including risks relating to:
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hurricanes and other adverse weather conditions;
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oil field service costs and availability;
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compliance with environmental and other laws and regulations;
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remediation and other costs resulting from oil spill releases of hazardous materials and other environmental damages; and
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failure of equipment or facilities.
We are currently conducting some of our exploration in the deeper waters of the Gulf of Mexico, where operations are more difficult and costly than in shallower waters. The deeper waters in the Gulf of Mexico lack the physical and oilfield service infrastructure present in its shallower waters. As a result, deepwater operations may require a significant amount of time between a discovery and the time that we can market our production, thereby increasing the risk involved with these operations.
Our operations in the Gulf of Mexico and offshore California could be adversely impacted by the Macondo accident and resulting oil spill.
The six-month moratorium on the drilling of new deepwater wells and a suspension of permitted wells being drilled in the Outer Continental Shelf regions of the Gulf of Mexico and Pacific Ocean was conditionally lifted in October 2010. Notwithstanding the lifting of the moratorium some permits have been issued, but at a much slower rate than before the Macondo accident.
We have offshore exploration, development and production ongoing in the Gulf of Mexico and California. The BOEM/BSEE is expected to issue additional governmental regulation of the offshore exploration and production industry. Recent legislative proposals include limitations upon, or elimination of, existing liability caps, an increased minimum level of financial responsibility and additional safety and spill-response requirements. We cannot predict with any certainty what form the additional regulation or limitations will take. The impact upon our business of such regulations or limitations could include cost increases, offshore exploration and development activity delay, as well as changes in the availability and cost of insurance.
A significant portion of our oil production is dedicated to one customer and as a result, our credit exposure to this customer is significant.
We have entered into an oil marketing arrangement with ConocoPhillips under which ConocoPhillips purchases a significant portion of our oil production. We generally do not require letters of credit or other collateral to support these trade receivables. Accordingly, a material adverse change in their financial condition could adversely impact our ability to collect the applicable receivables, and thereby affect our financial condition.
Operating hazards, natural disasters or other interruptions of our operations could result in potential liabilities, which may not be fully covered by our insurance.
The oil and gas business involves certain operating hazards such as:
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well blowouts;
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cratering;
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explosions;
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uncontrollable flows of oil, gas or well fluids;
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fires;
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pollution; and
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releases of toxic gas.
In addition, our operations in California are susceptible to damage from natural disasters, such as earthquakes, mudslides and fires and our Gulf of Mexico operations are susceptible to hurricanes. Any of these operating hazards could cause serious injuries, fatalities, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages, or property damage, all of which could expose us to liabilities. The payment of any of these liabilities could reduce, or even eliminate, the funds available for exploration, development and acquisition, or could result in a loss of our properties.
Consistent with insurance coverage generally available to the industry, our insurance policies provide limited coverage for losses or liabilities. The insurance market in general and the energy insurance market in particular have been difficult markets over the past several years. As a result, we do not believe that insurance coverage for the full potential liability, especially environmental liability, is currently available at reasonable cost. In addition, we are self-insured for named windstorms in the Gulf of Mexico. If we incur substantial liability and the damages are not covered by insurance or are in excess of policy limits, or if we incur liability at a time when we are not able to obtain liability insurance, then our business, results of operations and financial condition could be materially adversely affected.
We may not be successful in acquiring, developing or exploring for oil and gas properties.
The successful acquisition or development of, or exploration for, oil and gas properties requires an assessment of recoverable reserves, future oil and gas prices and operating costs, potential environmental and other liabilities and other factors. These assessments are necessarily inexact. As a result, we may not recover the purchase price of a property from the sale of production from the property or may not recognize an acceptable return from properties we do acquire. In addition, our development and exploration operations may not result in any increases in reserves. Our operations may be curtailed, delayed or canceled as a result of:
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increases in the costs of, or inadequate access to, capital or other factors, such as title problems;
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weather;
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compliance with governmental regulations or price controls;
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mechanical difficulties; or
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shortages or delays in the delivery of equipment.
In addition, development costs may greatly exceed initial estimates. In that case, we would be required to make unanticipated expenditures of additional funds to develop these projects, which could materially and adversely affect our business, financial condition and results of operations.
Furthermore, exploration for oil and gas, particularly offshore, has inherent and historically higher risk than development activities. Future reserve increases and production may be dependent on our success in our exploration efforts, which may be unsuccessful.
Adverse capital and credit market conditions may significantly affect our ability to meet liquidity needs, access to capital and cost of capital.
There is potential for volatility and disruption in the capital and credit markets which could negatively impact our business, financial condition and results of operations, as well as our ability to access capital.
During 2011, there was significant volatility within the global economy, particularly in certain countries of the European Union. Should this financial concern continue to cause disruption, it may negatively impact stock price and credit capacity for certain issuers, even those without exposure to the affected countries.
The impairment of financial institutions could adversely affect us.
We have exposure to different counterparties, and we have entered into transactions with counterparties in the financial services industry, including commercial banks, investment banks, insurance companies, other investment funds and other institutions. These transactions expose us to credit risk in the event of default of our counterparties. Deterioration in the global economy and financial markets may impact the credit ratings of our current and potential counterparties, including those counterparties who may have exposure to certain European sovereign debt, and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us. We have exposure to these financial institutions in the form of oil and gas derivative contracts, which protect our cash flows when commodity prices decline. During periods of low oil and gas prices, we may have significant exposure to our derivative counterparties and the value of our derivative positions may provide a significant amount of cash flow. We also maintain insurance policies with insurance companies to protect us against certain risks inherent in our business. In addition, if any lender under our credit facilities is unable to fund its commitment, our liquidity will be reduced by an amount up to the aggregate amount of such lender’s commitment under our credit facilities. The commitments under our senior revolving credit facility and the Plains Offshore senior credit facility are from a diverse syndicate of 21 lenders. At December 31, 2011, no single lender’s commitments under both credit facilities combined represented more than 8% of our total commitments. However, if banks continue to consolidate, we may experience a more concentrated credit risk.
Any prolonged, substantial reduction in the demand for oil and gas, or distribution problems in meeting this demand, could adversely affect our business.
Our success is materially dependent upon the demand for oil and gas. The availability of a ready market for our oil and gas production depends on a number of factors beyond our control, including the demand for and supply of oil and gas, the availability of alternative energy sources, the proximity of reserves to, and the capacity of, oil and gas gathering systems, pipelines or trucking and terminal facilities. We may also have to shut-in some of our wells temporarily due to a lack of market demand. If the demand for oil and gas diminishes, our financial results would be negatively impacted.
In addition, there are limitations related to the methods of transportation and processing for our production. Substantially all of our oil and gas production is transported by pipelines and trucks and/or processed in facilities owned by third parties. The inability or unwillingness of these parties to provide transportation and processing services to us for a reasonable fee could result in us having to find transportation and processing alternatives, increased transportation and processing costs or involuntary curtailment of a significant portion of our oil and gas production, any of which could have a negative impact on our results of operations and cash flows.
Our asset carrying values may be impaired in future periods if oil and gas prices decline.
Under the SEC’s full cost accounting rules, we review the carrying value of our oil and gas properties each quarter. Under these rules, for each cost center, capitalized costs of oil and gas properties (net of accumulated depreciation, depletion and amortization and related deferred income taxes) may not exceed a “ceiling” equal to:
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the present value, discounted at 10%, of estimated future net cash flows from proved oil and gas reserves, net of estimated future income taxes; plus
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the cost of unproved properties not being amortized; plus
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the lower of cost or estimated fair value of unproved properties included in the costs being amortized (net of related tax effects).
These rules generally require that we price our future oil and gas production at the twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials and require an impairment if our capitalized costs exceed this “ceiling”. For 2011, the twelve-month average of the first-day-of-the-month reference prices (prior to adjustment for location and quality differentials) were $95.99 per Bbl for oil and $4.12 per MMBtu for natural gas. At December 31, 2011, the ceiling with respect to our domestic oil and gas properties exceeded the net capitalized costs of those properties by approximately 30%.
Given the volatility of oil and gas prices, it is likely that our estimate of discounted future net revenues from proved oil and gas reserves will change in the near term. We may be required to recognize non-cash pre-tax impairment charges in future reporting periods if market prices for oil or natural gas decline.
Loss of key executives and failure to attract qualified management could limit our growth and negatively impact our operations.
Successfully implementing our strategies will depend, in part, on our management team. The loss of members of our management team could have an adverse effect on our business. Our exploration success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced engineers, geoscientists and other professionals. Competition for experienced professionals is extremely intense. If we cannot attract or retain experienced technical personnel, our ability to compete could be harmed. We do not have key man insurance.
We are subject to certain regulations, some of which require permits and other approvals. These regulations could increase our costs and may terminate, delay or suspend our operations.
Our business is subject to federal, state and local laws and regulations as interpreted by governmental agencies and other bodies, including those in California, vested with broad authority relating to the exploration for, and the development, production and transportation of, oil and gas, as well as environmental and safety matters. Certain of these regulations require permits for the drilling and operation of wells. The permits required for various aspects of our operations are subject to enforcement for noncompliance as well as revocation, modification and renewal by issuing authorities.
Existing laws and regulations, or their interpretations, could be changed, and any changes could increase costs of compliance and costs of operating drilling equipment or significantly limit drilling activity.
Under certain circumstances, the BOEM/BSEE may require that our operations on federal leases be suspended or terminated. These circumstances include our failure to pay royalties or our failure to comply with safety and environmental regulations. The requirements imposed by these laws and regulations are frequently changed and subject to new interpretations.
In addition, our real estate entitlement efforts are subject to regulatory approvals. Some of these regulatory approvals are discretionary by nature. The entitlement approval process is often a lengthy and complex procedure requiring, among other things, the submission of development plans and reports and presentations at public hearings. Because of the provisional nature of these procedures and the concerns of various environmental and public interest groups, our ability to entitle and realize future income from our surface properties could be delayed, prevented or made more expensive.
Regulations related to global warming and climate change could have an adverse effect on our operations and the demand for oil and natural gas.
Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” may be contributing to the warming of the Earth’s atmosphere. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of refined oil products and natural gas, are examples of greenhouse gases. From time to time the U.S. Congress has considered climate-related legislation to reduce emissions of greenhouse gases. In addition, many states have developed measures to regulate emissions of greenhouse gases, primarily through the planned development of greenhouse gas emissions inventories and/or regional greenhouse gas cap and trade programs. In California, for example Assembly Bill 32 requires the CARB to establish and adopt regulations by 2012 that will achieve an overall reduction in greenhouse gas emissions from all sources in California of 25% by 2020. In October 2011, the CARB adopted the final cap and trade regulation, including a delay in the start of the cap and trade rule’s compliance obligations until 2013.
Because our operations emit greenhouse gases, our operations in California are subject to regulations issued under Assembly Bill 32. These regulations increase our costs for those operations and adversely affect our operating results. The EPA has also adopted regulations imposing permitting and best available control technology requirements on the largest greenhouse gas stationary sources, regulations requiring reporting of greenhouse gas emissions from certain facilities and is considering additional regulation of greenhouse gases as “air pollutants” under the existing federal Clean Air Act. Passage of climate change legislation or other regulatory initiatives by Congress or various states, or the adoption of regulations by the EPA or analogous state agencies, that regulate or restrict emissions of greenhouse gases (including methane or carbon dioxide) in areas in which we conduct business could have an adverse effect on our operations and the demand for oil and natural gas.
Environmental liabilities could adversely affect our financial condition.
The oil and gas business is subject to environmental hazards, such as oil spills, gas leaks and ruptures and discharges of petroleum products and hazardous substances and historical disposal activities. These environmental hazards could expose us to material liabilities for property damages, personal injuries or other environmental harm, including costs of investigating and remediating contaminated properties. We also may be liable for environmental damages caused by the previous owners or operators of properties we have purchased or are currently operating. A variety of stringent federal, state and local laws and regulations govern the environmental aspects of our business and impose strict requirements for, among other things:
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well drilling or workover, operation and abandonment;
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waste management;
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land reclamation;
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financial assurance under the Oil Pollution Act of 1990; and
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controlling air, water and waste emissions.
Any noncompliance with these laws and regulations could subject us to material administrative, civil or criminal penalties or other liabilities. Additionally, our compliance with these laws may, from time to time, result in increased costs to our operations or decreased production, and may affect our costs of acquisitions.
In addition, environmental laws may, in the future, cause a decrease in our production or cause an increase in our costs of production, development or exploration. Pollution and similar environmental risks generally are not fully insurable.
Some of our onshore California fields have been in operation for more than 100 years, and current or future local, state and federal environmental and other laws and regulations may require substantial expenditures to remediate the properties or to otherwise comply with these laws and regulations. The Montebello field operates under a number of federal and California permits that are over and above what may be required in our other California facilities. The primary reason for the additional permits and associated restrictions on property use is the property’s location within what has been designated critical habitat for the federally threatened songbird, known as the California gnatcatcher, in accordance with Section 7 of the federal Endangered Species Act of 1973. A variety of existing laws, rules and guidelines govern activities that can be conducted on properties that contain coastal sage scrub and gnatcatchers and generally limit the scope of operations that we can conduct on this property. The presence of coastal sage scrub and gnatcatchers in the Montebello field and other existing or future laws, rules and guidelines could prohibit or limit our operations and our planned activities for this property.
Legislation and regulatory initiatives relating to hydraulic fracturing could increase our cost of doing business and adversely affect our operations.
From time to time, legislation has been introduced in Congress to amend the federal SDWA to eliminate exemptions for most fracturing activities. Similar efforts to review the practice and impose new regulatory conditions are taking place at the state and local level in states where we operate, several of which have adopted or are considering new regulations and statutes. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formation to stimulate oil and natural gas production. The use of hydraulic fracturing is necessary to produce commercial quantities of oil and natural gas from many reservoirs, especially shale formations such as the Haynesville Shale and the Eagle Ford Shale. These new requirements will (and future regulatory and legislative changes, if enacted, could) create new permitting and financial assurance requirements, require us to adhere to certain construction specifications, fulfill monitoring, reporting and recordkeeping obligations, and meet plugging and abandonment requirements. The imposition of stringent new regulatory and permitting requirements related to the practice of hydraulic fracturing could significantly increase our cost of doing business and adversely affect our operations.
Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.
As of December 31, 2011, we had leases on approximately 84,000 net acres in the Haynesville Shale area and approximately 60,000 net acres in the Eagle Ford Shale area. Over 85% of our acreage in the Haynesville Shale and over 25% of our acreage in the Eagle Ford Shale is currently held by production or held by operations. Unless production in paying quantities is established on units containing these leases during their terms, the leases will expire. If our leases expire and we are unable to renew the leases, we will lose our right to develop the related properties. Our drilling plans for these areas are subject to change based upon various factors, including drilling results, gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. Further, since we do not operate the Haynesville Shale acreage and portions of the Eagle Ford Shale acreage, we have limited impact upon the drilling schedule for those leases.
Increased drilling in the Eagle Ford Shale may cause pipeline and gathering system capacity constraints that could limit our ability to sell our oil and gas.
Because of the current economic climate, certain pipeline projects that are planned for the Haynesville Shale and the Eagle Ford Shale may not occur because the prospective owners of these pipelines may be unable to secure the necessary financing. In such event, this could result in wells being shut-in awaiting a pipeline connection or capacity and/or gas being sold at much lower prices than those quoted on the NYMEX or than we currently project, which would adversely affect our results of operations.
Our acquisition strategy could fail or present unanticipated problems for our business in the future, which could adversely affect our ability to make acquisitions or realize anticipated benefits of those acquisitions.
Our growth strategy may include acquiring oil and gas businesses and properties. We may not be able to identify suitable acquisition opportunities or finance and complete any particular acquisition successfully. Furthermore, acquisitions involve a number of risks and challenges, including:
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diversion of management’s attention;
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the need to integrate acquired operations;
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potential loss of key employees of the acquired companies;
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difficulty in assessing recoverable reserves, exploration potential, future production rates, operating costs, infrastructure requirements, future oil and natural gas prices, environmental and other liabilities, and other factors beyond our control;
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potential lack of operating experience in a geographic market of the acquired business; and
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an increase in our expenses and working capital requirements.
Assessments associated with an acquisition are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform a review of the acquired properties which we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every oil and gas well or the facilities associated with those wells. Even when we perform inspections, we do not always discover structural, subsurface and environmental problems that may exist or arise. As a result of these factors, the purchase price we pay to acquire oil and gas properties may exceed the value we realize.
Any of these factors could adversely affect our ability to achieve anticipated levels of cash flows from the acquired businesses or realize other anticipated benefits of those acquisitions.
Our results of operations could be adversely affected as a result of goodwill impairments.
In a purchase transaction, goodwill represents the excess of the purchase price plus the liabilities assumed (including deferred income taxes recorded in connection with the transaction) over the fair value of the net assets acquired. At December 31, 2011, goodwill totaled $535 million and represented approximately 5% of our total assets.
Goodwill is not amortized; instead it is tested at least annually for impairment at a level of reporting referred to as a reporting unit. Impairment occurs when the carrying amount of goodwill exceeds its implied fair value. An impairment of goodwill could significantly reduce earnings during the period in which the impairment occurs and would result in a corresponding reduction to goodwill and equity.
See Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Policies and Estimates - Goodwill.
We face strong competition.
We face strong competition in all aspects of our business. Competition is particularly intense for prospective undeveloped leases and purchases of proved oil and gas reserves. There is also competition for the rigs and related equipment and services that are necessary for us to develop and operate our oil and natural gas properties. Our competitive position is also highly dependent on our ability to recruit and retain geological, geophysical and engineering expertise. We compete for prospects, proved reserves, field services and qualified oil and gas professionals with major and diversified energy companies. Some companies may be able to more successfully define, evaluate, bid for and purchase properties and prospects than us.
Certain federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.
Among the changes contained in the Obama Administration’s Fiscal Year 2013 budget proposal, released by the Office of Management and Budget on February 13, 2012, is the elimination or deferral of certain U.S. federal income tax deductions and credits currently available to oil and gas exploration companies. Such changes include, but are not limited to, (i) the elimination of current deductions for intangible drilling and development costs; (ii) the elimination of the deduction for certain U.S. production activities for oil and gas properties; (iii) an extension of the amortization period for certain geological and geophysical expenditures and (iv) the repeal of the enhanced oil recovery credit. Some of these same proposals to repeal or limit oil and gas tax deductions and credits have been included in legislation that has recently been considered by Congress. It is unclear whether any such changes will be enacted or how soon such changes could be effective. The passage of any legislation as a result of the budget proposal, or the passage of bills containing similar changes in U.S. federal income tax law could eliminate or defer certain tax deductions and credits that are currently available with respect to oil and gas exploration and development and could negatively affect our financial results.
We have limited control over the activities on properties we do not operate.
Some of our properties, including our Haynesville Shale acreage and portions of our Eagle Ford Shale acreage, in which we have an interest are operated by other companies and involve third-party working interest owners. As a result, we have limited ability to influence or control the operation or future development of such properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures that we will be required to fund with respect to such properties. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects. These limitations and our dependence on the operator and other working interest owners for these projects could cause us to incur unexpected future costs, result in lower production and materially and adversely affect our financial condition and results of operations.
The high cost or unavailability of drilling rigs, equipment, supplies and other oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget, which could have an adverse effect on our business, financial condition or results of operations.
Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment or supplies. During these periods, the costs of rigs, equipment and supplies are substantially greater and their availability may be limited. Additionally, these services may not be available on commercially reasonable terms. The high cost or unavailability of drilling rigs, equipment, supplies, personnel and other oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget, which could have an adverse effect on our business, financial condition or results of operations.
Item 1B.
Item 1B. Unresolved Staff Comments
Not applicable.
Item 3.
Item 3. Legal Proceedings
We are a defendant in various lawsuits arising in the ordinary course of our business. While the outcome of these lawsuits cannot be predicted with certainty and could have a material adverse effect on our financial position, we do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows.
Item 4.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5.
Item 5. Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Price Range of Common Stock
Our common stock is listed on the New York Stock Exchange under the symbol “PXP”. The following table sets forth the range of high and low sales prices for our common stock as reported on the New York Stock Exchange Composite Tape for the periods indicated below:
At January 31, 2012, we had approximately 2,338 shareholders of record.
Dividend Policy
We have not paid any cash dividends and do not anticipate declaring or paying any cash dividends in the future. We intend to retain our earnings to finance the expansion of our business, repurchase shares of our common stock and for general corporate purposes. Our Board of Directors has the authority to declare and pay dividends on our common stock at their discretion, as long as we have funds legally available to do so. As discussed in Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations - Financing Activities, our senior revolving credit facility and indentures restrict our ability to pay cash dividends.
Issuer Purchases of Equity Securities
On December 17, 2007, we announced that our Board of Directors had authorized the repurchase of up to $1.0 billion of PXP common stock from time to time in open market transactions or privately negotiated transactions at our discretion, subject to market conditions and other factors. The following is a summary of our repurchases of common stock during the three-month period ended December 31, 2011 under this plan:
In addition, we repurchased an additional 2,390 shares in January 2012. Subsequent to these repurchases, our Board of Directors reset the authorization to $1.0 billion of PXP common stock and extended the program until January 2016.
Item 6.
Item 6. Selected Financial Data
The following selected financial information was derived from our consolidated financial statements, including the consolidated balance sheet at December 31, 2011 and 2010 and the related consolidated statements of income and cash flows for each of the three years in the period ended December 31, 2011 and the notes thereto, appearing elsewhere in this report. You should read this information in conjunction with Item 7
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following information should be read in connection with the information contained in the consolidated financial statements and notes thereto included elsewhere in this report.
Company Overview
Plains Exploration & Production Company, a Delaware corporation formed in 2002, is an independent energy company engaged in the upstream oil and gas business. The upstream business acquires, develops, explores for and produces oil and gas. Our upstream activities are located in the United States. We own oil and gas properties with principal operations in:
•
Onshore California;
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Offshore California;
•
the Gulf Coast Region;
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the Gulf of Mexico; and
•
the Rocky Mountains.
Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities, as well as newer properties with development and exploration potential. We believe our balanced portfolio of assets and our ongoing risk management program position us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities, including our California, Eagle Ford Shale, Haynesville Shale and Gulf of Mexico plays. As of December 31, 2011, we had estimated proved reserves of 410.9 MMBOE, of which 59% was comprised of oil and 55% was proved developed. Our primary sources of liquidity are cash generated from our operations, our senior revolving credit facility and periodic public offerings of debt and equity.
Our assets include 51.0 million shares of McMoRan common stock, approximately 31.6% of its common shares outstanding. We measure our equity investment at fair value. Unrealized gains and losses on the investment are reported in our income statement and could result in volatility in our earnings. See Item 7A
ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
Our primary market risk is oil and gas commodity prices. The markets for oil and gas have historically been volatile and are likely to continue to be volatile in the future. We use various derivative instruments to manage our exposure to commodity price risk on sales of oil and gas production. All derivative instruments are recorded on the balance sheet at fair value. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in fair value, both realized and unrealized, are recognized currently in our income statement as a gain or loss on mark-to-market derivative contracts. Cash flows are only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty. The derivative instruments we have in place are not classified as hedges for accounting purposes. See Note 6 - Commodity Derivative Contracts and Note 8 - Fair Value Measurements of Assets and Liabilities in the accompanying financial statements for a discussion of our derivative activities and fair value measurements.
In September 2011, and in response to our higher priced marketing contracts, we realigned our existing 2012 WTI crude oil put option spread contracts that had an $80 per barrel floor price with a $60 per barrel limit on 40,000 BOPD by acquiring 2012 Brent crude oil three-way collars that have a $100 per barrel floor price with an $80 per barrel limit and a weighted average ceiling price of $120 per barrel. Additionally, we converted 40,000 of the 160,000 MMBtu per day 2012 natural gas put option spread contracts that had a $4.30 per MMBtu floor price with a $3.00 per MMBtu limit to natural gas three-way collars that have a $4.30 per MMBtu floor price with a $3.00 per MMBtu limit and a weighted average ceiling price of $4.86 per MMBtu. We also acquired 2013 Brent crude oil put option spread contracts that have a $90 per barrel floor price with a $70 per barrel limit and weighted average deferred premium and interest of $6.237 per barrel on 22,000 BOPD. In December 2011, we entered into natural gas swap contracts at a weighted average price of $4.27 per MMBtu, on 110,000 MMBtu per day for 2013.
During the period from January 1, 2012 through February 22, 2012, we converted 5,000 of the 22,000 BOPD of Brent crude oil put option contracts in 2013 to three-way collars. These modified three-way collars have a floor price of $90 per barrel with a limit of $70 per barrel and a weighted average ceiling price of $126.08 and eliminates approximately $11 million of deferred premiums. Additionally, we entered into the following Brent oil derivatives for 2013 and 2014:
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Brent crude oil put option spread contracts on 13,000 BPOD for 2013 with a floor price of $100 per barrel and a limit of $80 per barrel.
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Brent three-way collars on 25,000 BOPD for 2013 that have a floor price of $100 per barrel with a limit of $80 per barrel and a weighted average ceiling price of $124.29 per barrel.
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Brent crude oil put option spread contracts on 20,000 BOPD for 2014 with a floor price of $90 per barrel and a limit of $70 per barrel.
In February 2012, we entered into natural gas swap contracts, at an average price of $4.16 per MMBtu, on 70,000 MMBtu per day for 2014.
As of February 22, 2012, we had the following outstanding commodity derivative contracts, all of which settle monthly:
(1) The average strike prices do not reflect any premiums to purchase the put options.
(2) If the index price is less than the $100 per barrel floor, we receive the difference between the $100 per barrel floor and the index price up to a maximum of $20 per barrel. We pay the difference between the index price and $120 per barrel if the index price is greater than the $120 per barrel ceiling. If the index price is at or above $100 per barrel but at or below $120 per barrel, no cash settlement is required.
(3) If the index price is less than the $90 per barrel floor, we receive the difference between the $90 per barrel floor and the index price up to a maximum of $20 per barrel less the option premium. If the index price is at or above $90 per barrel, we pay only the option premium.
(4) If the index price is less than the $100 per barrel floor, we receive the difference between the $100 per barrel floor and the index price up to a maximum of $20 per barrel less the option premium. If the index price is at or above $100 per barrel, we pay only the option premium.
(5) If the index price is less than the $100 per barrel floor, we receive the difference between the $100 per barrel floor and the index price up to a maximum of $20 per barrel. We pay the difference between the index price and $124.29 per barrel if the index price is greater than the $124.29 per barrel ceiling. If the index price is at or above $100 per barrel but at or below $124.29 per barrel, no cash settlement is required.
(6) If the index price is less than the $90 per barrel floor, we receive the difference between the $90 per barrel floor and the index price up to a maximum of $20 per barrel. We pay the difference between the index price and $126.08 per barrel if the index price is greater than the $126.08 per barrel ceiling. If the index price is at or above $90 per barrel but at or below $126.08 per barrel, no cash settlement is required.
(7) If the index price is less than the $4.30 per MMBtu floor, we receive the difference between the $4.30 per MMBtu floor and the index price up to a maximum of $1.30 per MMBtu less the option premium. If the index price is at or above $4.30 per MMBtu, we pay only the option premium.
(8) If the index price is less than the $4.30 per MMBtu floor, we receive the difference between the $4.30 per MMBtu floor and the index price up to a maximum of $1.30 per MMBtu. We pay the difference between the index price and $4.86 per MMBtu if the index price is greater than the $4.86 per MMBtu ceiling. If the index price is at or above $4.30 per MMBtu but at or below $4.86 per MMBtu, no cash settlement is required.
(9) If the index price is less than the fixed price ($4.27 per MMBtu for the 2013 contracts and $4.16 per MMBtu for the 2014 contracts), we receive the difference between the fixed price and the index price. We pay the difference between the index price and the fixed price if the index price is greater than the fixed price.
For put options, we typically pay a premium to the counterparty in exchange for the sale of the instrument. If the index price is below the floor price of the put option, we receive the difference between the floor price and the index price multiplied by the contract volumes less the option premium. If the index price settles at or above the floor price of the put option, we pay only the option premium.
In a typical collar transaction, if the floating price based on a market index is below the floor price in the derivative contract, we receive from the counterparty an amount equal to this difference multiplied by the specified volume. If the floating price exceeds the ceiling price, we must pay the counterparty an amount equal to the difference multiplied by the specified volume. We may pay a premium to the counterparty in exchange for a certain floor or ceiling. Any premium reduces amounts we would receive under the floor or increases amounts we would pay above the ceiling. If the floating price exceeds the floor price and is less than the ceiling price, then no payment, other than the premium, is required. If we have less production than the volumes specified under the collar transaction when the floating price exceeds the ceiling price, we must make payments against which there are no offsetting revenues from production.
Under a swap contract, the counterparty is required to make a payment to us if the index price for any settlement period is less than the fixed price, and we are required to make a payment to the counterparty if the index price for any settlement period is greater than the fixed price. The amount we receive or pay is the difference between the index price and the fixed price multiplied by the contract volumes. If we have less production than the volumes specified under the swap transaction when the index price exceeds the fixed price, we must make payments against which there are no offsetting revenues from production.
The fair value of outstanding crude oil and natural gas commodity derivative instruments at December 31, 2011 and the change in fair value that would be expected from a 10% price increase or decrease is shown below (in millions):
None of our offsetting physical positions are included in the above table. Price risk sensitivities were calculated by assuming an across-the-board 10% increase or decrease in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price.
Our management intends to continue to maintain derivative arrangements for a portion of our production. These contracts may expose us to the risk of financial loss in certain circumstances. Our derivative arrangements provide us protection on the volumes if prices decline below the prices at which these derivatives are set, but ceiling prices in our derivatives may cause us to receive less revenue on the volumes than we would receive in the absence of derivatives.
Price Differentials. Our realized wellhead oil prices are higher than the NYMEX index level and our realized wellhead gas prices are lower than the NYMEX index level. See Items 1 and 2 - Business and Properties - Product Markets and Major Customers.
Approximately 20% of our 2011 crude oil production was sold under contracts that provide for NYMEX less a fixed price differential (as of December 31, 2011 the fixed price differential averaged $4.66 per barrel) with the remainder sold under contracts that provide for monthly field posted prices.
Approximately 50% of our gas production is sold monthly using industry recognized, published index pricing and the remainder is priced daily on the spot market. Fluctuations between the two pricing mechanisms can significantly impact the overall differential to the Henry Hub.
Interest Rate Risk
We are exposed to market risk due to the floating interest rates on our senior revolving credit facility, the Plains Offshore senior credit facility and our short-term credit facility. At December 31, 2011, $735.0 million was outstanding under our senior revolving credit facility at an effective interest rate of 2.08%. Based on the $735.0 million outstanding under our senior revolving credit facility at December 31, 2011, on an annualized basis a 1% change in the effective interest rate would result in a $7.4 million change in our interest costs. At December 31, 2011, no amounts were outstanding under the Plains Offshore senior credit facility or our short-term credit facility.
Equity Price Risk
We are exposed to market risk because we own an equity investment in McMoRan common stock. See Note 7 - Investment and Note 8 - Fair Value Measurements of Assets and Liabilities in the accompanying financial statements for a discussion of our equity investment. At December 31, 2011, the investment, comprised of 51.0 million shares of McMoRan common stock, was valued at approximately $611.7 million. A 10% change in the underlying equity market price per share would result in a $61.2 million increase or decrease in the fair value of our investment, recognized in the income statement.
Item 8.
Item 8. Financial Statements and Supplementary Data
The information required here is included in this report as set forth in the Index to Consolidated Financial Statements on page.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not Applicable.
Item 9A.
Item 9A. Controls and Procedures
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
Under the supervision and with the participation of our management, including our Chief Executive Officer (our principal executive officer) and our Chief Financial Officer (our principal financial officer), we evaluated the effectiveness of our disclosure controls and procedures (as defined under Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended, or the Exchange Act). Based on this evaluation, our Chief Executive Officer and our Chief Financial Officer believe that the disclosure controls and procedures as of December 31, 2011 were effective to ensure that information we are required to disclose in the reports that we file or submit under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (ii) accumulated and communicated to our management, including our principal executive and financial officers, as appropriate to allow timely decisions regarding required disclosure.
Management’s Annual Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is a process designed by, or under the supervision of, the Company’s principal executive and principal financial officers and implemented by the Company’s Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and 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.
Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2011.
The effectiveness of the Company’s internal control over financial reporting as of December 31, 2011 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting during the quarter ended December 31, 2011 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B.
Item 9B. Other Information
Not Applicable.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
Information regarding our directors, executive officers and certain corporate governance items will be included in an amendment to this Form 10-K or in the proxy statement for the 2012 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2011, and is incorporated by reference to this report.
Directors and Executive Officers of Plains Exploration & Production Company
Listed below are our directors and executive officers, their age as of January 31, 2012 and their business experience for the last five years.
Directors
James C. Flores, age 52, Chairman of the Board, President and Chief Executive Officer and a Director since September 2002. He has been Chairman of the Board and Chief Executive Officer of PXP since December 2002, and President since March 2004. He was also Chairman of the Board of Plains Resources, Inc., or Plains Resources (now known as Vulcan Energy Corporation), from May 2001 to June 2004 and is currently a director of Vulcan Energy and McMoRan Exploration Co. He was Chief Executive Officer of Plains Resources from May 2001 to December 2002. He was Co-founder as well as Chairman, Vice Chairman and Chief Executive Officer at various times from 1992 until January 2001 of Ocean Energy, Inc., an oil and gas company.
Isaac Arnold, Jr., age 76, Director since May 2004. He was also a director of Nuevo Energy Company from 1990 to May 2004. He has been a director of Legacy Holding Company since 1989 and Legacy Trust Company since 1997 and is currently Director Emeritus of both. He became a director of Cullen Frost Bankers, Inc. (formerly Cullen Center Bank & Trust) at its inception in 1969. He became a director of The Frost National Bank in 1994. He served as a director of the boards of Cullen Frost Bankers, Inc. and The Frost National Bank until he retired from both in 2006 and is currently Director Emeritus of both. Mr. Arnold also served on the Audit and Strategic Planning Committees for Cullen Frost Bankers, Inc. from 1995 to 2006. Mr. Arnold is a trustee of the Museum of Fine Arts Houston and The Texas Heart Institute.
Alan R. Buckwalter, III, age 64, Director since March 2003. He retired in January 2003 as Chairman of JPMorgan Chase Bank, South Region, a position he had held since 1998. From 1990 to 1998 he was President of Texas Commerce Bank-Houston, the predecessor entity of JPMorgan Chase Bank. Prior to 1990 Mr. Buckwalter held various executive management positions within the organization. Mr. Buckwalter currently serves on the boards of Service Corporation International, the Texas Medical Center and the Greater Houston Area Red Cross and is Vice Chairman of Torch Securities LLC. He sits on the Nominating and Governance Committee, the Audit Committee and is Chairman of the Compensation Committee for Service Corporation International. Mr. Buckwalter previously served on the board of BCM Technologies, Inc. from 2003 to 2009.
Jerry L. Dees, age 71, Director since September 2002. He was also a director of Plains Resources from 1997 to December 2002. Mr. Dees has been a director of Geotrace Technologies, Inc. since 2005. He retired in 1996 as Senior Vice President, Exploration and Land, for Vastar Resources, Inc. (previously ARCO Oil and Gas Company), a position he had held since 1991.
Tom H. Delimitros, age 71, Director since September 2002. He was also a director of Plains Resources from 1988 to December 2002. He has been a General Partner of AMT Venture Funds, a venture capital firm, since 1989. He is also a director of Tetra Technologies, Inc., a publicly traded energy services company, and is the Chairman of the Audit Committee as well as member of the Management and Compensation Committee and the Reserves Committee. He currently serves as a director for three privately owned companies. Previously, he has served as President and CEO for Magna Corporation, (now Baker Petrolite, a unit of Baker Hughes). Mr. Delimitros currently serves on two Development Committees for the College of Engineering at the University of Washington in Seattle and is a member of the University of Washington Foundation Board.
Thomas A. Fry, III, age 67, Director since November 2007. He was also a director of Pogo from 2004 to November 2007. He was the President of National Ocean Industries Association, or NOIA, from December 2000 until January 2010. Before joining NOIA, Mr. Fry served as the Director of the Department of Interior’s Bureau of Land Management and has also served as the Director of the Minerals Management Service. He currently serves as a director of the National Energy Education and Development Project as well as the National Marine Sanctuary Foundation, where he is head of the Audit Committee.
Charles G. Groat, age 71, Director since November 2007. He was also a director of Pogo from 2005 to November 2007. Dr. Groat currently serves as the Director of both the Center for International Energy and Environment Policy and the Energy and Earth Resources Graduate Program at the University of Texas at Austin. He is also a professor of Geological Sciences and Public Affairs at the University of Texas at Austin. Before joining the University of Texas at Austin, Dr. Groat served for more than six years as Director of the U.S. Geological Survey, having been appointed by President Clinton and retained by President Bush. Dr. Groat currently serves as a director on the board of The Water Institute of the Gulf.
John H. Lollar, age 73, Director since September 2002. He was also a director of Plains Resources from 1995 to December 2002. He has been the Managing Partner of Newgulf Exploration L.P. since December 1996. He is also a director of Lufkin Industries, Inc., a manufacturing firm, where he is Chairman of the Compensation Committee and a member of the Audit Committee. Mr. Lollar was Chairman of the Board, President and Chief Executive Officer of Cabot Oil & Gas Corporation from 1992 to 1995, and President and Chief Operating Officer of Transco Exploration Company from 1982 to 1992.
Executive Officers
James C. Flores, age 52, Chairman of the Board, President and Chief Executive Officer and a Director since September 2002. He has been Chairman of the Board and Chief Executive Officer of PXP since December 2002, and President since March 2004. He was also Chairman of the Board of Plains Resources, Inc. (now owned by Vulcan Energy Corporation), from May 2001 to June 2004 and is currently a director of Vulcan Energy and McMoRan Exploration Co. He was Chief Executive Officer of Plains Resources from May 2001 to December 2002. He was Co-founder as well as Chairman, Vice Chairman and Chief Executive Officer at various times from 1992 until January 2001 of Ocean Energy, Inc., an oil and gas company.
Doss R. Bourgeois, age 54, Executive Vice President-Exploration and Production since June 2006. He was PXP’s Vice President of Development from April 2006 to June 2006. He was also PXP’s Vice President Eastern Development Unit from May 2003 to April 2006. Prior to that time, Mr. Bourgeois was Vice President from August 1993 to May 2003 at Ocean Energy, Inc.
Winston M. Talbert, age 49, Executive Vice President and Chief Financial Officer since June 2006. He joined PXP in May 2003 as Vice President Finance & Investor Relations and in May 2004, Mr. Talbert became Vice President Finance & Treasurer. Prior to joining PXP, Mr. Talbert was Vice President and Treasurer at Ocean Energy, Inc. from August 2001 to May 2003 and Assistant Treasurer from October 1999 to August 2001.
John F. Wombwell, age 50, Executive Vice President, General Counsel and Secretary since September 2003. He was also Plains Resources’ Executive Vice President, General Counsel, and Secretary from September 2003 to June 2004. Mr. Wombwell serves on the board of McMoRan Exploration Co. He was previously a partner at the law firm of Andrews Kurth LLP with a practice focused on representing public companies and an executive officer with two New York Stock Exchange traded companies.
Item 11.
Item 11. Executive Compensation
Information regarding executive compensation will be included in an amendment to this Form 10-K or in the proxy statement for the 2012 annual meeting of stockholders and is incorporated by reference to this report.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information regarding beneficial ownership will be included in an amendment to this Form 10-K or in the proxy statement for the 2012 annual meeting of stockholders and is incorporated by reference to this report.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information regarding certain relationships and related transactions and director independence will be included in an amendment to this Form 10-K or in the proxy statement for the 2012 annual meeting of stockholders and is incorporated by reference to this report.
Item 14.
Item 14. Principal Accounting Fees and Services
Information regarding principal accounting fees and services will be included in an amendment to this Form 10-K or in the proxy statement for the 2012 annual meeting of stockholders and is incorporated by reference to this report.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules
(a) (1) and (2) Financial Statements and Financial Statement Schedules
See Index to Consolidated Financial Statements set forth on Page.
(a) (3) Exhibits
* Filed herewith.
+ Management contracts or compensatory plans or arrangements.
# Pursuant to a request for confidential treatment, portions of this exhibit have been redacted from the publicly filed document and have been furnished separately to the SEC.
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.
PLAINS EXPLORATION & PRODUCTION COMPANY
Date: February 23, 2012
/s/ James C. Flores
James C. Flores, Chairman of the Board, President and Chief Executive Officer (Principal Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
PLAINS EXPLORATION & PRODUCTION COMPANY
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
All other schedules are omitted because they are not applicable or the required information is shown in the financial statements or notes thereto.
Report of Independent Registered Public Accounting Firm
To The Board of Directors and Shareholders
of Plains Exploration & Production Company:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, equity and cash flows present fairly, in all material respects, the financial position of Plains Exploration & Production Company and its subsidiaries (the Company) at December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Annual Report on Internal Control Over Financial Reporting appearing under Item 9A - Controls and Procedures. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we consider necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 23, 2012
PLAINS EXPLORATION & PRODUCTION COMPANY
CONSOLIDATED BALANCE SHEETS
(in thousands of dollars)
See notes to consolidated financial statements.
PLAINS EXPLORATION & PRODUCTION COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(in thousands, except per share data)
See notes to consolidated financial statements.
PLAINS EXPLORATION & PRODUCTION COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in thousands of dollars)
See notes to consolidated financial statements.
PLAINS EXPLORATION & PRODUCTION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands of dollars)
See notes to consolidated financial statements.
PLAINS EXPLORATION & PRODUCTION COMPANY
CONSOLIDATED STATEMENTS OF EQUITY
(share and dollar amounts in thousands)
See notes to consolidated financial statements
PLAINS EXPLORATION & PRODUCTION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 - Summary of Significant Accounting Policies
General. Plains Exploration & Production Company, a Delaware corporation formed in 2002 (“PXP”, the “Company”, “us”, “our”, or “we”), is an independent energy company engaged in the upstream oil and gas business. The upstream business acquires, develops, explores for and produces oil and gas. Our upstream activities are located in the United States.
Our consolidated financial statements include the accounts of all our consolidated subsidiaries. We consolidate entities when we have the ability to control or direct the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity. The determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment. All significant intercompany transactions have been eliminated. Certain reclassifications have been made to prior year statements to conform to the current year presentation.
Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates made by management include: (1) oil and natural gas reserves; (2) depreciation, depletion and amortization; (3) timing of transfers from oil and gas properties not subject to amortization; (4) valuation of our investment; (5) allocating purchase price in connection with business combinations and determining fair value, including goodwill; (6) noncontrolling interest in the form of preferred stock of subsidiary; (7) income taxes; (8) accrued assets and liabilities; (9) stock-based compensation; (10) asset retirement obligations and (11) valuation of derivative instruments. Although management believes these estimates are reasonable, changes in facts and circumstances or discovery of new information may result in revised estimates, and actual results may differ from these estimates.
Oil and Gas Properties. We follow the full cost method of accounting whereby all costs associated with property acquisition, exploration and development activities are capitalized. Such costs include internal general and administrative costs such as payroll and related benefits and costs directly attributable to employees engaged in acquisition, exploration and development activities. General and administrative costs associated with production, operations, marketing and general corporate activities are expensed as incurred. Capitalized costs, along with our estimated future costs to develop proved reserves and asset retirement costs which are not already included in oil and gas properties, net of related salvage value, are amortized to expense by the unit-of-production method using engineers’ estimates of proved oil and natural gas reserves. The costs of unproved oil and gas properties are excluded from amortization until the properties are evaluated. Interest is capitalized on oil and natural gas properties not subject to amortization and in the process of development. See Note 18 - Oil and Natural Gas Activities - Capitalized Costs. Proceeds from the sale of oil and natural gas properties are accounted for as reductions to capitalized costs unless such sales cause a significant change in the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center, in which case a gain or loss is recognized.
Under the SEC’s full cost accounting rules, we review the carrying value of our oil and gas properties each quarter on a country-by-country basis. Under these rules, for each cost center, capitalized costs of oil and gas properties (net of accumulated depreciation, depletion and amortization and related deferred income taxes) may not exceed a “ceiling” equal to:
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the present value, discounted at 10%, of estimated future net cash flows from proved oil and gas reserves, net of estimated future income taxes; plus
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the cost of unproved properties not being amortized; plus
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the lower of cost or estimated fair value of unproved properties included in the costs being amortized (net of related tax effects).
These rules generally require that we price our future oil and gas production at the twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials. Our reference prices are the West Texas Intermediate, or WTI, for oil and the Henry Hub spot price for gas. Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. The reserve estimates exclude the effect of any derivatives we have in place. The rules require an impairment if our capitalized costs exceed this “ceiling”.
During the third quarter of 2011, we determined not to develop the Friesian prospect and the lease terminated by its terms. The accumulated costs of approximately $460 million associated with the project were transferred to the full cost pool.
During the second quarter of 2010, we completed our interpretation of seismic and drilling data from our two offshore Vietnam exploratory wells and decided not to pursue additional exploratory activities in this area. We terminated our production sharing contract in accordance with its terms. The costs related to our Vietnam oil and gas properties not subject to amortization were transferred to our Vietnam full cost pool where they were subject to the ceiling limitation. Because our Vietnam full cost pool had no associated proved oil and gas reserves, we recorded a non-cash pre-tax impairment charge of $59.5 million. We also recorded a corresponding tax benefit of $23.0 million.
Asset Retirement Obligation. We record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred with an offsetting increase to proved oil and gas properties. For oil and gas properties, this is the period in which the well is drilled or acquired. A legal obligation is a liability that a party is required to settle as a result of an existing or enacted law, statute, ordinance or contract. Each period we accrete the liability to its then present value and depreciate the capitalized cost over the useful life of the related asset.
Other Property and Equipment. Other property and equipment is recorded at cost and consists primarily of land and real estate development costs, aircraft, office furniture and fixtures and computer hardware and software. Acquisitions, renewals, and betterments are capitalized; maintenance and repairs are expensed. Depreciation is calculated using the straight-line method over estimated useful lives of three to twenty years. Net gains or losses on property and equipment disposed of are included in operating income in the period in which the transaction occurs.
Cash and Cash Equivalents. Cash and cash equivalents consist primarily of highly liquid money market mutual funds that hold U.S. government securities and demand deposits with financial institutions. The mutual funds are available to us upon demand. Accounts payable at December 31, 2011 and 2010 included $7.0 million and $4.3 million, respectively, representing outstanding checks that had not been presented for payment.
Inventory. Oil inventories are carried at the lower of the cost to produce or market value, and materials and supplies inventories are stated at the lower of cost or market with cost determined on an average cost method. At December 31, 2011 and 2010, inventory consisted of the following (in thousands):
Federal and State Income Taxes. We recognize deferred tax liabilities and assets for expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between the financial statement and tax bases of assets and liabilities using tax rates in effect for the year in which the differences are expected to reverse. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that some portion or all of the related tax benefits will not be realized.
We have also established a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. The tax benefit from an uncertain tax position is recognized when it is more likely than not, based on the technical merits of the position, that the position will be sustained on examination by the taxing authorities. Additionally, the amount of the tax benefit recognized is the largest amount of benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. Furthermore, we recognize potential penalties and interest related to unrecognized tax benefits as a component of income tax expense. See Note 11 - Income Taxes.
Revenue Recognition. Oil and gas revenue from our interests in producing wells is recognized upon delivery and passage of title using the sales method for gas imbalances, net of any royalty interests or other profit interests in the produced product. If our sales of production volumes for a well exceed our portion of the estimated remaining recoverable reserves of the well, a liability is recorded. No receivables are recorded for those wells on which we have taken less than our ownership share of production unless the amount taken by other parties exceeds the estimate of their remaining reserves. We had no material gas imbalances at December 31, 2011 or 2010.
Derivative Financial Instruments. We use various derivative instruments to manage our exposure to commodity price risk on sales of oil and gas production. We do not enter into derivative instruments for speculative trading purposes. We present the fair value of our derivative contracts on a net basis where the right of offset is provided for in our counterparty agreements. See Note 6 - Commodity Derivative Contracts.
Investment. We have elected to measure our investment at fair value with changes in fair value included in our income statement. If we had not elected the fair value method, the investment would have qualified for the equity method of accounting, under which our proportionate share of the investee’s income would have been reported in our income statement. See Note 7 - Investment and Note 8 - Fair Value Measurements of Assets and Liabilities.
Fair Value. Fair value is the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants. The authoritative guidance characterizes inputs used in determining fair value according to a hierarchy that prioritizes inputs based upon the degree to which they are observable. The three levels of the fair value hierarchy are as follows:
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Level 1 - Valuations utilizing quoted, unadjusted prices for assets or liabilities in active markets for identical assets or liabilities as of the reporting date. This is the most reliable evidence of fair value and does not require a significant amount of judgment.
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Level 2 - Valuations utilizing market-based inputs that are directly or indirectly observable but not considered Level 1 quoted prices, including quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; or valuation techniques whose inputs are observable. If the asset or liability has a specified contractual term, the Level 2 input must be observable for substantially the full term of the asset or liability.
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Level 3 - Valuations utilizing techniques whose significant inputs are unobservable. This provides the least objective evidence of fair value and requires a significant degree of judgment.
A financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. We estimate the fair values of our derivative instruments and investment and determine their placement within the fair value hierarchy levels as described above. See Note 8 - Fair Value Measurements of Assets and Liabilities.
Goodwill. In a purchase transaction, goodwill represents the excess of the purchase price plus the liabilities assumed (including deferred income taxes recorded in connection with the transaction) over the fair value of the net assets acquired. At December 31, 2011, goodwill totaled $535 million and represented approximately 5% of our total assets.
Goodwill is not amortized; instead it is tested at least annually for impairment at a level of reporting referred to as a reporting unit. Impairment occurs when the carrying amount of goodwill exceeds its implied fair value. A two-step impairment test is used to identify potential goodwill impairment and measure the amount of goodwill impairment loss to be recognized, if any. The first step of the goodwill impairment test compares the fair value of a reporting unit with its carrying amount, including goodwill. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is considered not to be impaired, thus the second step of the impairment test is unnecessary.
The second step of the goodwill impairment test, used to measure the amount of impairment loss, compares the implied fair value of the reporting unit’s goodwill with the carrying amount of that goodwill. If the carrying amount of that reporting unit’s goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to that excess. The loss recognized cannot exceed the carrying amount of goodwill.
We follow the full cost method of accounting for oil and gas activities and all of our producing properties are located in the United States. We have determined that for the purpose of performing an impairment test, we have one reporting unit.
In September 2011, the Financial Accounting Standards Board, or FASB, issued authoritative guidance which amends the rules for testing goodwill for impairment. Under the new rules, companies are permitted to make a qualitative assessment of a reporting unit’s fair value prior to performing the
two-step goodwill impairment test. If it is determined through the qualitative assessment that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, then performing the two-step impairment test is unnecessary. The qualitative assessment is optional, allowing companies to go directly to the quantitative assessment. As of December 31, 2011, we have elected to continue performing our annual goodwill impairment assessment under the quantitative two-step impairment test.
The first step of the goodwill impairment test requires that we make an estimate of the fair value of the reporting unit. Quoted market prices in active markets are the best evidence of fair value. We estimate the fair value of the reporting unit by applying a control premium to the quoted market price of our common stock. We determine the control premium through reference to control premiums in merger and acquisition transactions for our industry and other comparable industries. This requires that we make certain judgments about the selection of merger and acquisition transactions and transaction premiums.
We perform our goodwill impairment test annually as of December 31 and have recorded no impairment. We also perform interim impairment tests if events occur or circumstances change that would indicate the fair value of our reporting unit may be below its carrying amount.
Events affecting oil and gas prices may cause a decrease in the fair value of the reporting unit, and we could have an impairment of our goodwill in future periods. An impairment of goodwill could significantly reduce earnings during the period in which the impairment occurs and would result in a corresponding reduction to goodwill and equity.
Noncontrolling Interest in the Form of Preferred Stock of Subsidiary. Noncontrolling interest in the form of preferred stock of subsidiary represents third-party ownership in the net assets of our consolidated subsidiary Plains Offshore Operations Inc., or Plains Offshore, in the form of convertible perpetual preferred stock and associated non-detachable warrants, which are classified as permanent equity in our consolidated balance sheet since redemption for cash of the preferred stock is within our control. See Note 4 - Noncontrolling Interest in the Form of Preferred Stock of Subsidiary.
Business Segment Information. We acquire, develop, explore for and produce oil and gas in the United States. We allocate capital resources on a project-by-project basis across our entire asset base to maximize profitability and measure financial performance as a single enterprise and not on an area-by-area basis. Accordingly, we have one operating segment, our oil and gas operations.
Stock-Based Compensation. Our stock-based compensation cost is measured based on the fair value of the award on the grant date and remeasured each reporting period for liability-classified awards. The compensation cost is recognized net of estimated forfeitures over the requisite service period. See Note 10 - Stock-Based and Other Compensation Plans.
Pension. As a result of our acquisition of Pogo Producing Company we recorded assets and liabilities for a defined benefit pension plan. We terminated the plan and in May 2009, we made final lump sum distributions and annuity purchases in settlement of the plan’s obligations and recognized in income the remaining balance in accumulated other comprehensive loss.
Recent Accounting Pronouncements. In December 2010, the FASB issued authoritative guidance clarifying the acquisition date that should be used for reporting the pro forma financial information disclosures when comparative financial statements are presented. The guidance also improves the usefulness of the pro forma revenue and earnings disclosures by requiring a description of the nature and amount of material, nonrecurring pro forma adjustments that are directly attributable to the business combination. We adopted the provisions of this standard effective January 1, 2011, and it did not have a significant impact on our consolidated financial position, results of operations or cash flows.
In December 2010, the FASB issued authoritative guidance amending the criteria for performing the second step of the goodwill impairment test for companies with reporting units with zero or negative carrying amounts. The amended guidance requires performance of the second step if qualitative factors indicate that it is more likely than not that a goodwill impairment exists. We adopted the provisions of this standard effective January 1, 2011, and it did not have a significant impact on our consolidated financial position, results of operations or cash flows.
In May 2011, the FASB issued authoritative guidance amending certain accounting and disclosure requirements related to fair value measurements. The guidance clarifies (i) the requirement that the highest and best use concept is only relevant for measuring nonfinancial assets, (ii) requirements to measure the fair value of instruments classified in shareholders’ equity and (iii) the requirement to disclose quantitative information about the unobservable inputs used in a fair value measurement that is categorized within Level 3 of the fair value hierarchy. The guidance also (i) permits a reporting entity to measure the fair value of certain financial assets and liabilities managed in a portfolio at the price that would be received to sell a net asset position or transfer a net liability position for a particular risk, (ii) eliminates premiums or discounts related to size as a characteristic of the reporting entity’s holding and (iii) expands disclosures for fair value measurement. The guidance is effective for interim and annual periods beginning after December 15, 2011. Early adoption is not permitted. We do not expect this guidance to have a significant impact on our consolidated financial position, results of operations or cash flows.
In June 2011, the FASB issued authoritative guidance to improve the comparability, consistency and transparency of financial reporting and to increase the prominence of items reported in other comprehensive income. The guidance requires entities to report components of comprehensive income in either (i) a single continuous statement of comprehensive income or (ii) two separate but consecutive statements. The guidance also requires entities to present on the face of the financial statements reclassification adjustments for items that are reclassified from other comprehensive income to net income in the statements where the components of net income and other comprehensive income are presented. In December 2011, the FASB issued further authoritative guidance deferring the requirements for entities to present on the face of the financial statements those reclassification adjustments for items that are reclassified from other comprehensive income to net income. The guidance reinstates the requirements for the presentation of reclassification adjustments on either the face of financial statements where comprehensive income is reported or in the notes to the financial statements. The requirements of both standards are effective for interim and annual periods beginning after December 15, 2011, with early adoption permitted. We adopted the provisions of the June 2011 guidance, excluding the requirements deferred in the December 2011 guidance, effective December 31, 2011 and these provisions require that we position our statement of comprehensive income consecutively to the income statement.
In September 2011, the FASB issued authoritative guidance permitting companies to make a qualitative assessment of a reporting unit’s fair value prior to performing the two-step goodwill impairment test. If it is determined through the qualitative assessment that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, then performing the two-step impairment test is unnecessary. The qualitative assessment is optional, allowing companies to go directly to the quantitative assessment. The guidance is effective for interim and annual goodwill impairment tests performed in fiscal years beginning after December 15, 2011, with early adoption permitted. We perform our goodwill impairment test annually as of December 31. We adopted the provisions of this standard effective December 31, 2011 and elected to continue performing our annual goodwill impairment assessment under the quantitative two-step impairment test.
In December 2011, the FASB issued authoritative guidance requiring entities to disclose both gross and net information about financial instruments and transactions eligible for offset in the statement of financial position as well as financial instruments and transactions subject to agreements similar to master netting arrangements. The additional disclosures will enable users of the financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. The guidance is effective for interim and annual periods beginning after January 1, 2013, and will primarily impact our disclosures associated with our commodity derivative instruments. We are currently evaluating the impact of this guidance.
Note 2 - Acquisitions
Eagle Ford Shale
During the fourth quarter of 2010, we completed the acquisition of approximately 60,000 net acres in the Eagle Ford Shale oil and gas condensate windows in South Texas for approximately $596.3 million in cash. We funded the acquisition primarily with borrowings under our senior revolving credit facility.
In conjunction with the acquisition of our Eagle Ford Shale properties, and in anticipation of divesting our deepwater Gulf of Mexico properties, we entered into a series of reverse like-kind exchange agreements pursuant to Section 1031 of the Internal Revenue Code, or IRC. The purchase consideration related to our Eagle Ford Shale properties was loaned by PXP to the qualified intermediary, PXP Operations LLC, to facilitate the potential tax deferred reverse like-kind exchange treatment under IRC 1031. During the first half of 2011, the reverse like-kind arrangements pursuant to IRC Section 1031 were concluded prior to the completion of a like-kind exchange involving any disposition of PXP properties. As a result, the related Eagle Ford Shale properties were transferred from PXP Operations LLC, which was reported as a Non-Guarantor Subsidiary, to PXP, which is reported as Issuer, and the outstanding notes between PXP Operations LLC and PXP were settled. See Note 16 - Consolidating Financial Statements.
Chesapeake Participation Agreement
In July 2008, we acquired from a subsidiary of Chesapeake Energy Corporation a 20% interest in Chesapeake’s Haynesville Shale leasehold for approximately $1.65 billion in cash and we agreed, over a multi-year period, to fund 50% of Chesapeake’s drilling and completion costs associated with future Haynesville Shale wells, up to an additional $1.65 billion, which we refer to as the Haynesville Carry.
In August 2009, we amended the participation agreement with Chesapeake to accelerate the payment of the remaining Haynesville Carry. On September 29, 2009, we paid $1.1 billion to Chesapeake for the remaining Haynesville Carry balance as of September 30, 2009, which we estimated to be $1.25 billion, an approximate 12% reduction. We funded the payment with net proceeds from the sale of our common stock and issuance of $400 million of 8 5/8% Senior Notes due 2019, cash on hand and borrowings under our senior revolving credit facility. As a result of the prepayment of the Haynesville Carry, we do not pay promoted well costs for costs attributable to periods subsequent to the third quarter of 2009.
We have the option to participate for 20% of any additional leasehold that Chesapeake, or its affiliates, acquires in the Haynesville Shale within a designated area of mutual interest.
Note 3 - Divestments
Panhandle and South Texas Properties
In December 2011, we completed the divestment of our Texas Panhandle properties to Linn Energy, LLC. After the exercise of third party preferential rights and preliminary closing adjustments, we received approximately $554.8 million in cash. At December 31, 2011, we continue to have interests in approximately 50,000 gross leasehold acres. We expect to receive additional proceeds from future closings, as may be further modified for additional post-closing adjustments. The cash proceeds received, net of approximately $6.2 million in transaction costs, were primarily used to reduce indebtedness. Our aggregate working interest in the Texas Panhandle properties generated total sales volumes of approximately 84 MMcfe per day during the third quarter of 2011 and had 263 Bcfe of estimated proved reserves as of December 31, 2010. The transaction was effective November 1, 2011.
In December 2011, we completed the divestment of all our working interests in our South Texas conventional natural gas properties to a third party. After preliminary closing adjustments, we received $181.0 million in cash. The cash proceeds received were primarily used to reduce indebtedness. The transaction was effective September 1, 2011.
The proceeds from the 2011 sales of oil and gas properties were recorded as reductions to capitalized costs pursuant to full cost accounting rules.
Gulf of Mexico
In December 2010, we completed the divestment of our Gulf of Mexico shallow water shelf properties to McMoRan Exploration Co. At closing and after preliminary closing adjustments, we received approximately $86.1 million in cash, which included $11.1 million in working capital adjustments, and 51.0 million shares of McMoRan common stock in exchange for all our interests in our Gulf of Mexico leasehold located in less than 500 feet of water. The transaction was completed pursuant to an Agreement and Plan of Merger dated as of September 19, 2010, and effective as of August 1, 2010, between us and certain of our subsidiaries and McMoRan and certain of its subsidiaries. The McMoRan shares were valued at approximately $665.9 million based on McMoRan’s closing stock price of $17.18 on December 30, 2010 discounted to reflect certain limitations on the marketability of the McMoRan shares under the registration rights agreement and stockholder agreement entered into by us and McMoRan at the closing of the transaction. The cash proceeds received, net of approximately $8.8 million in transaction costs, were primarily used to repay outstanding borrowings under our credit facilities. The proceeds were recorded as reductions to capitalized costs pursuant to full cost accounting rules.
Note 4 - Noncontrolling Interest in the Form of Preferred Stock of Subsidiary
In October 2011, we entered into a securities purchase agreement with EIG Global Energy Partners, or EIG, pursuant to which we received $430.2 million of net cash proceeds in November 2011, upon closing of the transaction, in exchange for a 20% equity interest in Plains Offshore. Plains Offshore holds all of our oil and natural gas properties and assets located in the United States Gulf of Mexico in water depths of 500 feet or more. The proceeds raised are expected to be used to fund Plains Offshore’s share of capital investment in the Lucius oil field and the Phobos prospect exploratory drilling planned for 2012 and other activities. Under the agreement and upon closing of the transaction, Plains Offshore issued to EIG managed funds and accounts, or the EIG Funds (i) 450,000 shares of Plains Offshore 8% convertible perpetual preferred stock and (ii) non-detachable warrants to purchase in aggregate 9,121,000 shares of Plains Offshore’s common stock with an exercise price of $20 per share. In addition, Plains Offshore issued 87 million shares of Plains Offshore Class A
common stock, which will be held in escrow until the conversion and cancellation of the preferred stock or the exercise of the warrants held by EIG. The preferred stock will pay quarterly cash dividends of 6% per annum and an additional 2% per annum dividend. The 2% dividend may be deferred and accumulated quarterly until paid. The shares of preferred stock also fully participate, on an as-converted basis at four times, in cash dividends distributed to any class of common stockholders of Plains Offshore.
The preferred holders have the right, at any time at their option, to convert any or all of such holder’s preferred stock and exercise any of the associated non-detachable warrants into shares of Class A common stock of Plains Offshore, at an initial conversion/exercise price of $20 per share; the conversion price is subject to adjustment as a result of certain events. Furthermore, under the terms of the securities purchase agreement, Plains Offshore has the right to convert all or a portion of the outstanding shares of preferred stock if certain events occur more than 180 days after an initial public offering or a qualified public offering of Plains Offshore. We have a right to purchase shares of preferred stock, common stock and warrants under certain circumstances in order to permit the consolidation of Plains Offshore for federal income tax purposes. Additionally, at any time on or after the fifth anniversary of the closing date, we may exercise a call right to purchase all, but not less than all, of the outstanding preferred stock and associated non-detachable warrants for cash, at a price equal to the liquidation preference described below.
At any time after the fourth anniversary of the closing date, a majority of the preferred holders may cause Plains Offshore to use its commercially reasonable efforts to consummate an exit event. An exit event, as defined in the stockholders agreement, means, at the sole option of Plains Offshore (i) the purchase by us or the redemption by Plains Offshore of all the preferred stock, warrants and common stock held by the EIG Funds for the aggregate fair value thereof, or the repurchase option; (ii) a sale of Plains Offshore or a sale of all or substantially all of its assets, in each case in an arms’ length transaction with a third party, at the highest price available after reasonable marketing efforts by Plains Offshore; or (iii) a qualified initial public offering. Under the repurchase option, the form of consideration shall be at our sole discretion, which could be (a) cash, (b) our shares of registered, freely-tradable common stock (valued at 95% of the average closing sale price) or (c) a combination of (a) and (b) above. In the event that Plains Offshore fails to consummate an exit event prior to the applicable exit event deadline, the conversion price of the preferred stock and the exercise price of the warrants will immediately and automatically be adjusted such that all issued and outstanding shares of preferred stock on an as-converted basis taken together with shares of common stock issuable upon exercise of the warrants, in the aggregate, will constitute 49% of the common equity securities of Plains Offshore on a fully diluted basis. In addition, we will be required to purchase $300 million of junior preferred stock in Plains Offshore. If this occurs, our cash expenditures relating to the assets of Plains Offshore will approximate the cash contribution made by EIG to Plains Offshore. Plains Offshore must use the proceeds to repay its senior credit facility. See Note 5 - Long-Term Debt.
The preferred holders are entitled to vote on all matters on which common stockholders are entitled to vote. Each holder is entitled to one vote for each share that such holder would be entitled to receive if such holder’s shares of preferred stock were converted into common shares on the record date set by the board of directors for such vote. Prior to an initial public offering, the holders have preemptive rights with respect to certain issuances of equity securities of Plains Offshore. In the event that we or any of our affiliates intend to transfer any of their common shares to an unaffiliated third party purchaser, each other equity holder will have certain tag along rights.
In the event of liquidation of Plains Offshore, each preferred holder is entitled to receive the liquidation preference before any payment or distribution is made on any junior or common stock. A liquidation event includes any of the following events: (i) the liquidation, dissolution or winding up of Plains Offshore, whether voluntary or involuntary, (ii) a sale, consolidation or merger of Plains Offshore
in which the stockholders immediately prior to such event do not own at least a majority of the outstanding shares of the surviving entity, or (iii) a sale or other disposition of all or substantially all of Plains Offshore’s assets to a person other than us or our affiliates. The liquidation preference is equal to (i) the greater of (a) 1.25 times the initial offering price and (b) the sum of (1) the fair market value of the shares of common stock issuable upon conversion of the preferred stock and (2) the applicable tax adjustment amount, plus (ii) any accrued dividends and accumulated dividends.
The non-detachable warrants may be exercised at any time on the earlier of (i) the eighth anniversary of the original issue date or (ii) a termination event. Under the terms of the securities purchase agreement, a termination event is defined as the occurrence of any of (a) the conversion of the preferred stock, (b) the redemption of the preferred stock, (c) the repurchase by us or any of our affiliates of the preferred stock or (d) a liquidation event described above. The non-detachable warrants are considered to be embedded instruments for accounting purposes as the instrument cannot be both legally detached and separately exercised from the host preferred stock, nor can the non-detachable warrants be transferred or sold without also transferring the ownership in the preferred stock.
The preferred stock of Plains Offshore is classified as permanent equity in our consolidated balance sheet since redemption for cash of the preferred interests is within our and Plains Offshore’s control.
In December 2011, Plains Offshore announced a quarterly dividend on the preferred stock of $1.4 million, or $3.11 per share of preferred stock, 75% of which was paid in cash with the remaining 25% deferred.
Note 5 - Long-Term Debt
At December 31, 2011 and 2010, long-term debt consisted of (in thousands):
(1) The amount is net of unamortized discount of $9.5 million and $34.2 million at December 31, 2011 and December 31, 2010, respectively.
(2) The amount is net of unamortized discount of $5.6 million and $6.1 million at December 31, 2011 and December 31, 2010, respectively.
As of December 31, 2011, aggregate total maturities of long-term debt in the next five years are $999.2 million, including $79.3 million in 2015 and $919.9 million in 2016.
Senior Revolving Credit Facility. As of December 31, 2011, our borrowing base is $1.8 billion and commitments are $1.4 billion. In May 2011, we entered into an amendment to our senior revolving credit facility, adjusting our borrowing rates and extending the maturity date to May 4, 2016. In connection with the EIG preferred stock private placement, we further amended our senior revolving credit facility in November 2011. See Plains Offshore Senior Credit Facility. The amendment requires, among other things, that we make a mandatory prepayment if the combined total borrowings under both our senior revolving credit facility and the Plains Offshore senior credit facility exceed the borrowing base, which remained at $1.8 billion. In connection with our divestments in December 2011, we further amended our senior revolving credit facility. The amendment provided for no reduction to our borrowing base. The borrowing base will be redetermined on an annual basis, with us and the lenders each having the right to one annual interim unscheduled redetermination, and adjusted based on our oil and gas properties, reserves, other indebtedness and other relevant factors. Additionally, our senior revolving credit facility contains a $250 million limit on letters of credit and a $50 million commitment for swingline loans. At December 31, 2011, we had $1.2 million in letters of credit outstanding under our senior revolving credit facility.
Amounts borrowed under our senior revolving credit facility, as amended, bear an interest rate, at our election, equal to either: (i) the Eurodollar rate, which is based on LIBOR, plus an additional variable amount ranging from 1.50% to 2.50%; (ii) a variable amount ranging from 0.50% to 1.50% plus the greater of (1) the prime rate, as determined by JPMorgan Chase Bank, (2) the federal funds rate, plus 1/2 of 1%, and (3) the adjusted LIBOR plus 1%; or (iii) the overnight federal funds rate plus an additional variable amount ranging from 1.50% to 2.50% for swingline loans. The additional variable amount of interest payable is based on the utilization rate as a percentage of (a) the total amount of funds borrowed under both our senior revolving credit facility and the Plains Offshore senior credit facility and (b) the borrowing base under our senior revolving credit facility. Letter of credit fees under our senior revolving credit facility are based on the utilization rate and range from 1.50% to 2.50%. Commitment fees range from 0.375% to 0.50% of amounts available for borrowing. The effective interest rate on borrowings under our senior revolving credit facility was 2.08% at December 31, 2011.
Our senior revolving credit facility is secured by 100% of the shares of stock in certain of our domestic subsidiaries, 65% of the shares of stock in certain foreign subsidiaries and mortgages covering at least 75% of the total present value of our domestic proved oil and gas properties. Our senior revolving credit facility contains negative covenants that limit our ability, as well as the ability of our restricted subsidiaries to, among other things, incur additional debt, pay dividends on stock, make distributions of cash or property, change the nature of our business or operations, redeem stock or redeem subordinated debt, make investments, create liens, enter into leases, sell assets, sell capital stock of subsidiaries, guarantee other indebtedness, enter into agreements that restrict dividends from subsidiaries, enter into certain types of swap agreements, enter into take-or-pay or other prepayment arrangements, merge or consolidate and enter into transactions with affiliates. In addition, we are required to maintain a ratio of debt to EBITDAX (as defined) of no greater than 4.50 to 1.
Plains Offshore Senior Credit Facility. The aggregate commitments of the lenders under the Plains Offshore senior credit facility are $300 million. The Plains Offshore senior credit facility contains a $50 million limit on letters of credit and matures on November 18, 2016. At December 31, 2011, Plains Offshore had no letters of credit outstanding under its senior credit facility.
Amounts borrowed under the Plains Offshore senior credit facility bear an interest rate, at Plains Offshore’s election, equal to either: (i) the Eurodollar rate, which is based on LIBOR, plus an additional variable amount ranging from 1.50% to 2.50%; (ii) a variable amount ranging from 0.50% to 1.50% plus the greater of (1) the prime rate, as determined by JPMorgan Chase Bank, (2) the federal funds rate, plus 1/2 of 1%, and (3) the adjusted LIBOR plus 1%. The additional variable amount of interest payable is based on the utilization rate as a percentage of (a) the total amount of funds borrowed under both
our senior revolving credit facility and the Plains Offshore senior credit facility and (b) the borrowing base under our senior revolving credit facility. Letter of credit fees under the Plains Offshore senior credit facility are based on the utilization rate and range from 1.50% to 2.50%. Commitment fees range from 0.375% to 0.50% of amounts available for borrowing.
The borrowings under the Plains Offshore senior credit facility are guaranteed on a senior basis by PXP and certain of our subsidiaries, and are secured on a pari passu basis by liens on the same collateral that secures PXP’s senior revolving credit facility. The Plains Offshore senior credit facility contains certain affirmative and negative covenants, including limiting Plains Offshore’s ability, among other things, to create liens, incur other indebtedness, make dividends (excluding dividends on preferred stock) or other distributions, make investments, change the nature of Plains Offshore’s business and merge or consolidate, sell assets, enter into certain types of swap agreements and enter into certain transaction with affiliates, as well as other customary events of default, including a cross-default to PXP’s senior revolving credit facility. If an event of default (as defined in our senior revolving credit facility) has occurred and is continuing under our senior revolving credit facility that has not been cured or waived by the lenders thereunder then the Plains Offshore lenders could accelerate and demand repayment of the Plains Offshore senior credit facility.
Short-term Credit Facility. We have an uncommitted short-term unsecured credit facility, or short-term facility, under which we may make borrowings from time to time until June 1, 2012, not to exceed at any time the maximum principal amount of $75.0 million. No advance under the short-term facility may have a term exceeding 14 days and all amounts outstanding are due and payable no later than June 1, 2012. Each advance under the short-term facility shall bear interest at a rate per annum mutually agreed on by the bank and us.
We borrow under our short-term facility to fund our working capital needs. The funding requirements are typically generated due to the timing differences between payments and receipts associated with our oil and gas production. We generally pay off the short-term facility with receipts from the sales of our oil and gas production or borrowings under our senior revolving credit facility. No amounts were outstanding under the short-term facility at December 31, 2011. The daily average outstanding balance for the quarter and year ended December 31, 2011 was $43.0 million and $52.6 million, respectively. The weighted average interest rate on borrowings under our short-term credit facility was 1.5% for the years ended December 31, 2011 and 2010.
6 3/4% Senior Notes. In November 2011, we issued $1 billion of 6 3/4% Senior Notes due 2022, or the 6 3/4% Senior Notes, at par. We received approximately $984 million of net proceeds, after deducting the underwriting discount and offering expenses. We used the net proceeds to reduce indebtedness outstanding under our senior revolving credit facility and for general corporate purposes. We may redeem all or part of the 6 3/4% Senior Notes on or after February 1, 2017 at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to February 1, 2015 we may, at our option, redeem up to 35% of the 6 3/4% Senior Notes with the proceeds of certain equity offerings.
6 5/8% Senior Notes. In March 2011, we issued $600 million of 6 5/8% Senior Notes due 2021, or the 6 5/8% Senior Notes, at par. We received approximately $590 million of net proceeds, after deducting the underwriting discount and offering expenses. We used the net proceeds to reduce indebtedness outstanding under our senior revolving credit facility and for general corporate purposes. We may redeem all or part of the 6 5/8% Senior Notes on or after May 1, 2016 at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to May 1, 2014 we may, at our option, redeem up to 35% of the 6 5/8% Senior Notes with the proceeds of certain equity offerings.
7 5/8% Senior Notes due 2020. In March 2010, we issued $300 million of 7 5/8% Senior Notes due 2020, at par. We received approximately $294 million of net proceeds, after deducting the underwriting discount and offering expenses. We used the net proceeds to reduce indebtedness outstanding under our senior revolving credit facility and for general corporate purposes. We may redeem all or part of the 7 5/8% Senior Notes due 2020 on or after April 1, 2015 at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to April 1, 2013 we may, at our option, redeem up to 35% of the 7 5/8% Senior Notes due 2020 with the proceeds of certain equity offerings.
8 5/8% Senior Notes. In September 2009, we issued $400 million of 8 5/8% Senior Notes due 2019, or the 8 5/8% Senior Notes, at 98.335% of the face value to yield 8.875% to maturity. We received approximately $386 million of net proceeds after deducting the underwriting discount, original issue discount and offering expenses. We used the net proceeds for general corporate purposes, including to fund a portion of the remaining Haynesville Carry balance. See Note 2 - Acquisitions. We may redeem all or part of the 8 5/8% Senior Notes on or after October 15, 2014 at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to October 15, 2012 we may, at our option, redeem up to 35% of the 8 5/8% Senior Notes with the proceeds of certain equity offerings.
10% Senior Notes. In March 2009, we issued $365 million of 10% Senior Notes due 2016, or the 10% Senior Notes, at 92.373% of the face value to yield 11.625% to maturity. In April 2009, an additional $200 million of 10% Senior Notes were sold to the public at 92.969% of the face value, plus interest accrued from March 6, 2009, to yield 11.5% to maturity. We received approximately $330 million and $181 million of net proceeds, respectively, after deducting the underwriting discounts, original issue discount and offering expenses. We used the net proceeds to reduce indebtedness outstanding under our senior revolving credit facility and for general corporate purposes, including capital expenditures. We may redeem all or part of the 10% Senior Notes on or after March 1, 2013 at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to March 1, 2012 we may, at our option, redeem up to 35% of the 10% Senior Notes with the proceeds of certain equity offerings. In December 2011, we made payments totaling $429.5 million to retire $380.1 million of the $565 million outstanding principal amount of our 10% Senior Notes.
7 5/8% Senior Notes due 2018. In May 2008, we issued $400 million of 7 5/8% Senior Notes due 2018, at par. We may redeem all or part of the 7 5/8% Senior Notes due 2018 on or after June 1, 2013 at specified redemption prices and prior to such date at a “make-whole” redemption price.
3/4% Senior Notes. In June 2007, we issued $600 million principal amount of 7 3/4% Senior Notes due 2015, or the 7 3/4% Senior Notes, at par. In December 2011, we made payments totaling $542.2 million to retire $520.7 million of the $600 million outstanding principal amount of our 7 3/4% Senior Notes.
7% Senior Notes. In March 2007, we issued $500 million principal amount of 7% Senior Notes due 2017, or the 7% Senior Notes, at par. We may redeem all or part of the 7% Senior Notes on or after March 15, 2012 at specified redemption prices and prior to such date at a “make-whole” redemption price. In December 2011, we made payments totaling $442.1 million to retire $423.1 million of the $500 million outstanding principal amount of our 7% Senior Notes.
The 7 3/4% Senior Notes, 10% Senior Notes, 7% Senior Notes, 7 5/8% Senior Notes due 2018, 8 5/8% Senior Notes, 7 5/8% Senior Notes due 2020, 6 5/8% Senior Notes and 6 3/4% Senior Notes (together, the Senior Notes) are our general unsecured senior obligations. The Senior Notes are jointly and severally guaranteed by certain of our existing domestic subsidiaries. In the future, the guarantees may be released or terminated under the following circumstances: (i) in connection with any sale or other disposition of all or substantially all of the assets of that subsidiary guarantor; (ii) in connection
with any sale or other disposition of all the capital stock of a subsidiary guarantor; (iii) if designated to be an unrestricted subsidiary; (iv) upon legal defeasance or satisfaction and discharge of the indenture; (v) upon the liquidation or dissolution of such subsidiary guarantor provided no default or event of default has occurred or is continuing; or (vi) at such time as such subsidiary guarantor does not have outstanding any guarantee of any of our or any of our subsidiary guarantor’s indebtedness (other than the notes) in excess of $10.0 million in aggregate principal amount. The Senior Notes rank senior in right of payment to all of our existing and future subordinated indebtedness; pari passu in right of payment with any of our existing and future unsecured indebtedness that is not by its terms subordinated to the Senior Notes; effectively junior to our existing and future secured indebtedness, including indebtedness under our senior revolving credit facility and the Plains Offshore senior credit facility, to the extent of our assets constituting collateral securing that indebtedness; and effectively subordinate to all existing and future indebtedness and other liabilities (other than indebtedness and liabilities owed to us) of our non-guarantor subsidiaries. In the event of a change of control, as defined in the indenture, we will be required to make an offer to repurchase the Senior Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase.
The indentures governing the Senior Notes contain covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to incur additional debt; make certain investments or pay dividends or distributions on our capital stock or purchase or redeem or retire capital stock; sell assets, including capital stock of our restricted subsidiaries; restrict dividends or other payments by restricted subsidiaries; create liens that secure debt; enter into transactions with affiliates; and merge or consolidate with another company.
Debt Extinguishment Costs. During 2011, we recognized $121.0 million of debt extinguishment costs, including $30.9 million of unamortized debt issue costs and original issue discount, in connection with the retirement of a portion of our 7 3/4% Senior Notes, 10% Senior Notes and 7% Senior Notes. During 2010 and 2009, we recognized $1.2 million and $12.1 million, respectively, of debt extinguishment costs in connection with reductions in our borrowing base and commitments under our senior revolving credit facility.
Subsequent Event
In February 2012, our borrowing base was increased from $1.8 billion to $2.3 billion until the next scheduled redetermination date on or before May 1, 2013. The commitments remained unchanged at $1.4 billion.
Note 6 - Commodity Derivative Contracts
General
We are exposed to various market risks, including volatility in oil and gas commodity prices and interest rates. The level of derivative activity we engage in depends on our view of market conditions, available derivative prices and operating strategy. A variety of derivative instruments, such as swaps, collars, puts, calls and various combinations of these instruments, may be utilized to manage our exposure to the volatility of oil and gas commodity prices. Currently, we do not use derivatives to manage our interest rate risk. The interest rate on our senior revolving credit facility and Plains Offshore’s senior credit facility is variable, while our senior notes are at fixed rates.
All derivative instruments are recorded on the balance sheet at fair value. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in fair value, both realized and unrealized, are recognized in our income statement as a gain or loss on mark-to-market derivative contracts. Cash flows are only impacted to the extent the actual settlements under the contracts result
in making a payment to or receiving a payment from the counterparty. The derivative instruments we have in place are not classified as hedges for accounting purposes.
Cash settlements with respect to derivatives that are not accounted for under hedge accounting and do not have a significant financing element are reflected as investing activities in the statement of cash flows. Cash settlements with respect to derivatives that contain a significant financing element are reflected as financing activities in the statement of cash flows.
For put options, we typically pay a premium to the counterparty in exchange for the sale of the instrument. If the index price is below the floor price of the put option, we receive the difference between the floor price and the index price multiplied by the contract volumes less the option premium. If the index price settles at or above the floor price of the put option, we pay only the option premium.
In a typical collar transaction, if the floating price based on a market index is below the floor price in the derivative contract, we receive from the counterparty an amount equal to this difference multiplied by the specified volume. If the floating price exceeds the ceiling price, we must pay the counterparty an amount equal to the difference multiplied by the specified volume. We may pay a premium to the counterparty in exchange for a certain floor or ceiling. Any premium reduces amounts we would receive under the floor or increases amounts we would pay above the ceiling. If the floating price exceeds the floor price and is less than the ceiling price, then no payment, other than the premium, is required. If we have less production than the volumes specified under the collar transaction when the floating price exceeds the ceiling price, we must make payments against which there are no offsetting revenues from production.
Under a swap contract, the counterparty is required to make a payment to us if the index price for any settlement period is less than the fixed price, and we are required to make a payment to the counterparty if the index price for any settlement period is greater than the fixed price. The amount we receive or pay is the difference between the index price and the fixed price multiplied by the contract volumes. If we have less production than the volumes specified under the swap transaction when the index price exceeds the fixed price, we must make payments against which there are no offsetting revenues from production.
In December 2011, we entered into natural gas swap contracts at a weighted average price of $4.27 per MMBtu on 110,000 MMBtu per day for 2013.
In September 2011, and in response to our higher priced marketing contracts, we realigned our existing 2012 WTI crude oil put option spread contracts that had an $80 per barrel floor price with a $60 per barrel limit on 40,000 BOPD by acquiring 2012 Brent crude oil three-way collars that have a $100 per barrel floor price with an $80 per barrel limit and a weighted average ceiling price of $120 per barrel. The realignment eliminated $89.1 million of deferred premiums and interest associated with the previous 2012 WTI crude oil put option spread contracts. We also paid net upfront premiums of approximately $2.6 million to enter into the 2012 Brent three-way collars. Additionally, we converted 40,000 of the 160,000 MMBtu per day 2012 natural gas put option spread contracts that had a $4.30 per MMBtu floor price with a $3.00 per MMBtu limit to natural gas three-way collars that have a $4.30 per MMBtu floor price with a $3.00 per MMBtu limit and a weighted average ceiling price of $4.86 per MMBtu and reduced 2012 deferred premiums and interest by approximately $4.1 million. We also acquired 2013 Brent crude oil put option spread contracts that have a $90 per barrel floor price with a $70 per barrel limit and weighted average deferred premium and interest of $6.237 per barrel on 22,000 BOPD.
In April 2010, we entered into crude oil put option spread contracts on 31,000 BOPD for 2011 and 40,000 BOPD for 2012. Additionally, during April 2010 we acquired crude oil three-way collars on 9,000 BOPD for 2011. In November 2010, we acquired natural gas three-way collars on 200,000 MMBtu per day for 2011 and natural gas put options on 160,000 MMBtu per day for 2012.
In the first quarter of 2009, we monetized our 2009 and 2010 crude oil put option contracts on 40,000 BOPD with weighted average strike prices of $106.16 per barrel and $111.49 per barrel, respectively. In addition, we terminated our crude oil swaps on 20,000 BOPD in 2009. As a result of this monetization, we received approximately $1.1 billion in net proceeds, which we used to reduce the outstanding balance on our senior revolving credit facility and for other general corporate purposes.
See Note 8 - Fair Value Measurements of Assets and Liabilities, for additional discussion on the fair value measurement of our derivative contracts.
As of December 31, 2011, we had the following outstanding commodity derivative contracts, all of which settle monthly:
(1) The average strike prices do not reflect any premiums to purchase the put options.
(2) If the index price is less than the $100 per barrel floor, we receive the difference between the $100 per barrel floor and the index price up to a maximum of $20 per barrel. We pay the difference between the index price and $120 per barrel if the index price is greater than the $120 per barrel ceiling. If the index price is at or above $100 per barrel but at or below $120 per barrel, no cash settlement is required.
(3) If the index price is less than the $90 per barrel floor, we receive the difference between the $90 per barrel floor and the index price up to a maximum of $20 per barrel less the option premium. If the index price is at or above $90 per barrel, we pay only the option premium.
(4) If the index price is less than the $4.30 per MMBtu floor, we receive the difference between the $4.30 per MMBtu floor and the index price up to a maximum of $1.30 per MMBtu less the option premium. If the index price is at or above $4.30 per MMBtu, we pay only the option premium.
(5) If the index price is less than the $4.30 per MMBtu floor, we receive the difference between the $4.30 per MMBtu floor and the index price up to a maximum of $1.30 per MMBtu. We pay the difference between the index price and $4.86 per MMBtu if the index price is greater than the $4.86 per MMBtu ceiling. If the index price is at or above $4.30 per MMBtu but at or below $4.86 per MMBtu, no cash settlement is required.
(6) If the index price is less than the $4.27 per MMBtu fixed price, we receive the difference between the $4.27 per MMBtu fixed price and the index price. We pay the difference between the index price and the fixed price if the index price is greater than the fixed price.
Balance Sheet
At December 31, 2011 and 2010, we had the following outstanding commodity derivative contracts recorded in our balance sheet (in thousands):
The following table provides supplemental information to reconcile the fair value of our derivative contracts to our balance sheet at December 31, 2011 and 2010, considering the deferred premiums, accrued interest and related settlement payable/receivable amounts which are not included in the fair value amounts disclosed in the table above (in thousands):
We present the fair value of our derivative contracts on a net basis where the right of offset is provided for in our counterparty agreements.
Income Statement
During the years ended December 31, 2011, 2010 and 2009, pre-tax amounts recognized in our income statements for derivative transactions were as follows (in thousands):
Cash Payments and Receipts
During the years ended December 31, 2011, 2010 and 2009 cash (payments) receipts for derivatives were as follows (in thousands):
Credit Risk
We generally do not require collateral or other security to support derivative instruments subject to credit risk. However, the agreements with each of the counterparties to our derivative instruments contain netting provisions within the agreements. If a default occurs under the agreements, the non-defaulting party can offset the amount payable to the defaulting party under the derivative contracts with the amount due from the defaulting party under the derivative contracts. As a result of the netting provisions under the agreements, our maximum amount of loss due to credit risk is limited to the net amounts due to and from the counterparties under the derivative contracts. The maximum amount of loss due to credit risk that we would have incurred if all the counterparties to our derivative contracts failed to perform according to the terms of the derivative contracts at December 31, 2011 was $63.6 million.
Contingent Features
As of December 31, 2011, the counterparties to our commodity derivative contracts consisted of eight financial institutions. Our counterparties or their affiliates are generally also lenders under our senior revolving credit facility. As a result, the counterparties to our derivative agreements share in the collateral supporting our senior revolving credit facility. Therefore, we are not generally required to post additional collateral under our derivative agreements.
Certain of our derivative agreements contain cross default and acceleration provisions relative to our material debt agreements. If we were to default on any of our material debt agreements, it would be a violation of these provisions, and the counterparties to our derivative agreements could request immediate payment on derivative instruments that are in a net liability position at that time. As of December 31, 2011, we were in a net liability position with one of the counterparties to our derivative instruments, totaling $3.5 million.
Subsequent Events
During the period from January 1, 2012 through February 22, 2012, we converted 5,000 of the 22,000 BOPD of Brent crude oil put option contracts in 2013 to three-way collars. These modified three-way collars have a floor price of $90 per barrel with a limit of $70 per barrel and a weighted average ceiling price of $126.08 and eliminates approximately $11 million of deferred premiums. Additionally, we entered into the following Brent oil derivatives for 2013 and 2014:
•
Brent crude oil put option spread contracts on 13,000 BPOD for 2013 with a floor price of $100 per barrel and a limit of $80 per barrel.
•
Brent three-way collars on 25,000 BOPD for 2013 that have a floor price of $100 per barrel with a limit of $80 per barrel and a weighted average ceiling price of $124.29 per barrel.
•
Brent crude oil put option spread contracts on 20,000 BOPD for 2014 with a floor price of $90 per barrel and a limit of $70 per barrel.
In February 2012, we entered into natural gas swap contracts, at an average price of $4.16 per MMBtu, on 70,000 MMBtu per day for 2014.
Note 7 - Investment
At December 31, 2011 and 2010, we owned 51.0 million shares of McMoRan Exploration Co. common stock, approximately 31.6% and 32.4%, respectively, of its common shares outstanding. McMoRan is a publicly traded oil and gas exploration and production company (New York Stock Exchange listing MMR) engaged in the exploration, development and production of natural gas and oil in the United States, specifically offshore in the shallow waters of the Gulf of Mexico Shelf and onshore in the Gulf Coast area. In December 2010, we acquired the McMoRan common stock and other consideration in exchange for all of our interests in our U.S. Gulf of Mexico leasehold located in less than 500 feet of water. See Note 3 - Divestments.
As contemplated by the Agreement and Plan of Merger, we and McMoRan entered into a registration rights agreement and a stockholder agreement at the closing of the transaction. Under the terms of the registration rights agreement, McMoRan filed a registration statement covering the McMoRan shares within 60 days after closing. The registration rights agreement also gives us piggyback registration rights and demand registration rights under certain circumstances. Under the terms of the stockholder agreement, McMoRan expanded its board of directors and we have the right to designate two board members for so long as we own at least 10% of the outstanding shares of McMoRan. If our ownership falls below 10%, but is at least 5%, we will have the right to designate one director. The stockholder agreement requires us to refrain from certain activities that could be undertaken to acquire control of McMoRan and from transferring any McMoRan shares for one year after closing (subject to certain exceptions). The one year restriction ended on December 30, 2011, and we may now sell shares of McMoRan common stock pursuant to underwritten offerings, in periodic sales under the shelf registration statement filed by McMoRan (subject to certain volume limitations), pursuant to the exercise of piggyback registration rights or as otherwise permitted by applicable law. Our investment in McMoRan was reclassified from long-term to current assets as the one year restriction to sell the shares ended on December 30, 2011.
We are deemed to exercise significant influence over the operating and investing policies of McMoRan but do not have control. We have elected to measure our equity investment in McMoRan at fair value, and the change in fair value of our investment is recognized as a gain or loss on investment measured at fair value in our income statement. We believe that using fair value as a measurement basis for our investment is useful to our investors because our earnings on the investment will be dependent on the fair value on the date we divest the shares. At December 31, 2011 and 2010, the McMoRan shares were valued at approximately $611.7 million and $664.3 million, respectively, based on McMoRan’s closing stock prices of $14.55 and $17.14 on December 31, 2011 and 2010, respectively, discounted to reflect certain limitations on the marketability of the McMoRan shares. During the years ended December 31, 2011 and 2010, we recorded unrealized losses of $52.7 million and $1.6 million, respectively, on our investment.
McMoRan follows the successful efforts method of accounting for its oil and natural gas activities. Under this method of accounting, all costs associated with oil and gas lease acquisition, successful exploratory wells and all development wells are capitalized and amortized on a unit-of-production basis over the remaining life of proved developed reserves and proved reserves on a field basis. Unproved leasehold costs are capitalized pending the results of exploration efforts. Exploration costs, including geological and geophysical expenses, exploratory dry holes and delay rentals, are charged to expense when incurred. Below is summarized financial information of our proportionate share of McMoRan’s financial position and results of operations (in thousands):
(1) Amounts represent our 31.6% and 32.4% equity ownership in McMoRan as of December 31, 2011 and 2010, respectively. We acquired our McMoRan investment on December 30, 2010. Our proportionate share of McMoRan’s 2010 results of operations is not presented because it is insignificant as PXP owned the investment for one day and it is not practicable to determine one day’s results of operations.
Note 8 - Fair Value Measurements of Assets and Liabilities
Authoritative guidance on fair value measurements defines fair value, establishes a framework for measuring fair value and stipulates the related disclosure requirements. We follow a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Our commodity derivative instruments and investment are recorded at fair value on a recurring basis in our balance sheet with the changes in fair value recorded in our income statement. The following table presents, for each fair value hierarchy level, our commodity derivative assets and liabilities and our investment measured at fair value on a recurring basis as of December 31, 2011 and 2010 (in thousands):
(1) Option premium and accrued interest of $62.4 million and $164.2 million at December 31, 2011 and 2010, respectively, settlement payable of $5.1 million and $6.2 million at December 31, 2011 and 2010, respectively, and settlement receivable of $0.2 million at December 31, 2011 are not included in the fair value of derivatives.
(2) Represents our equity investment in McMoRan which would otherwise be reported under the equity method of accounting.
The fair value amounts of our put and collar derivative instruments are estimated using an option-pricing model, which uses various inputs including NYMEX and ICE price quotations, volatilities, interest rates and contract terms. The fair value of our swap derivative instruments are estimated using a pricing model which has various inputs including NYMEX price quotations, interest rates and contract terms. We adjust the valuations from the model for credit quality, using the counterparties’ credit quality for asset balances and our credit quality for liability balances. For asset balances, we use the credit default swap value for counterparties when available or the spread between the risk-free interest rate and the yield on the counterparties’ publicly traded debt for similar maturities. We consider the impact of netting agreements on counterparty credit risk, including whether the position with the counterparty is a net asset or net liability.
We classify derivatives that have identical assets or liabilities with quoted, unadjusted prices in active markets as Level 1. We classify derivatives as Level 2 if the inputs used in the valuation model are directly or indirectly observable for substantially the full term of the instrument; however, if the significant inputs are not observable for substantially the full term of the instrument, we classify those derivatives as Level 3. We determine whether the market for our derivative instruments is active or
inactive based on transaction volume for such instruments and classify as Level 3 those instruments that are not actively traded. For these inputs, we utilize pricing and volatility information from other instruments with similar characteristics and extrapolate and/or interpolate data between data points for thinly traded instruments. As of December 31, 2011, our 2013 natural gas swaps and certain of our 2012 crude oil collars are classified as Level 2, certain of our 2012 crude oil collars are classified as Level 3 and all of our 2012 natural gas and 2013 crude oil contracts are classified as Level 3 instruments.
We determine the fair value of our investment by discounting for lack of marketability at the reporting date. The discount factor for lack of marketability is determined by utilizing both Protective put and Asian put option models. Both of these options are valued using a Black-Scholes option-pricing model which utilizes various inputs including the closing price of the McMoRan common stock, implied volatility of the instrument, number of shares being valued, length of time that would be necessary to dispose of our investment, expected dividend and risk-free interest rates. As of December 31, 2011, we have classified our investment as Level 3 since the fair value is determined by utilizing significant inputs that are unobservable.
We determine the appropriate level for each financial asset and liability on a quarterly basis and recognize any transfers at the beginning of the reporting period.
The following table presents a reconciliation of changes in fair value of financial assets and liabilities classified as Level 3 for the years ended December 31, 2011 and 2010 (in thousands):
(1) Deferred option premiums and interest are not included in the fair value of derivatives.
(2) During the third quarter of 2011, the inputs used to value certain of our 2011 natural gas collars were directly or indirectly observable and those contracts were transferred to Level 2.
(3) Realized and unrealized gains and losses included in earnings for the period are reported as gain (loss) on mark-to-market derivative contracts and loss on investment measured at fair value in our income statement for our commodity derivative contracts and our investment, respectively.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Nonfinancial assets and liabilities, such as goodwill and other property and equipment, are measured at fair value on a nonrecurring basis upon impairment; however, we have no material assets or liabilities that are reported at fair value on a nonrecurring basis in our balance sheet.
Fair Value of Other Financial Instruments
Authoritative guidance on financial instruments requires certain fair value disclosures, such as those on our long-term debt, to be presented in both interim and annual reports. The estimated fair value amounts of financial instruments have been determined using available market information and valuation methodologies described below.
The carrying values of items comprising current assets and current liabilities approximate fair value due to the short-term maturities of these instruments. Derivative financial instruments included in our balance sheet are stated at fair value; however, certain of our derivative financial instruments have a deferred premium, including our crude oil and natural gas put options. The deferred premium reduces the asset or increases the liability depending on the fair value of the derivative financial instrument.
The following table presents the carrying amounts and fair values of our other financial instruments as of December 31, 2011 and 2010 (in thousands):
The carrying value of our senior revolving credit facility approximates its fair value, as interest rates are variable, based on prevailing market rates. The fair value of our Senior Notes is based on quoted market prices from trades of such debt.
Note 9 - Asset Retirement Obligation
The following table reflects the changes in our asset retirement obligation during the years ended December 31, 2011, 2010 and 2009 (in thousands):
(1) $7.7 million and $13.9 million are included in other current liabilities at December 31, 2011 and 2010, respectively.
Our change in estimate during 2009 is attributable to increased costs to plug and abandon wells and retire equipment, primarily in our California fields, and a change in estimated useful lives of certain offshore platforms for which we retain the asset retirement obligation.
Note 10 - Stock-Based and Other Compensation Plans
We have four stock incentive plans: the 2002 Stock Incentive Plan, or 2002 Plan, which provides for a maximum of 1.5 million shares available for awards; the 2004 Stock Incentive Plan, or 2004 Plan, which provides for a maximum of 8.4 million shares available for awards; the 2006 Incentive Plan, or the 2006 Plan, which provides for a maximum of 5.0 million shares available for awards; and the 2010 Incentive Award Plan, or the 2010 Plan, which provides for a maximum of 5.0 million shares available for awards. Our 2002 Plan, 2004 Plan and 2010 Plan provide for the grant of stock options and other awards (including performance units, performance shares, share awards, restricted stock, restricted stock units, or RSUs, and stock appreciation rights, or SARs) to our directors, officers, employees, consultants and advisors. Our 2006 Plan provides for the grant of cash-only SARs and RSUs to non-officer employees. Our compensation committee may grant options and SARs on such terms, including vesting and payment forms, as it deems appropriate in its discretion, however, no option or SAR may be exercised more than ten years after its grant date, and the purchase price for incentive stock options and non-qualified stock options may not be less than 100% of the fair market value of our common stock on the date of grant. The compensation committee may grant restricted stock awards, RSUs, share awards, performance units and performance shares on such terms and conditions as it may decide in its discretion.
Upon an event constituting a “change in control” (as defined in the plans) of PXP, all options and SARs will become immediately exercisable in full. In addition, in such an event, unless otherwise determined by our compensation committee, or employee agreement, generally all other awards will vest and all restrictions on such awards will lapse. We may, at our discretion, issue new shares or use treasury shares to satisfy vesting requirements.
Stock-based compensation is measured at the grant date, based on the calculated fair value of the award and is remeasured each reporting period for liability-classified awards. Stock-based compensation is recognized over the requisite employee service period (generally the vesting period of the grant). Stock-based compensation is expensed or capitalized based on the nature of the employee’s activities, and for the years ended December 31, 2011, 2010 and 2009 was (in thousands):
Stock-based compensation charged to earnings for the years ended December 31, 2011, 2010 and 2009 was (in thousands):
At December 31, 2011, there was $169.5 million of total unrecognized compensation cost related to unvested stock-based compensation arrangements that is expected to be recognized over a weighted-average period of approximately 3.9 years.
SARs
SAR grants generally vest ratably over three years or 100% at the end of three years and expire within five years after the date of grant. These awards are similar to stock options, but are settled in cash rather than in shares of common stock and are classified as liability awards. Compensation cost for these awards is determined using a fair-value method and remeasured at each reporting date until the date of settlement. Stock-based compensation expense recognized is based on the number of SARs ultimately expected to vest and has been reduced for estimated forfeitures.
The following table summarizes the status of our SARs at December 31, 2011 and the changes during the year then ended:
The total intrinsic value of SARs exercised during the years ended December 31, 2011, 2010 and 2009 was $2.9 million, $0.6 million and $0.4 million, respectively. The weighted average grant date fair value per share for SARs granted in 2011, 2010 and 2009 was $13.65, $11.08 and $6.44, respectively.
We estimate the fair value of SARs granted using the Black-Scholes valuation model. The following assumptions are as of December 31, 2011, 2010 and 2009:
The expected life represents the period of time that SARs granted are expected to be outstanding. We use historical experience with exercise and post-vesting exercise behavior to determine the expected life of the SARs granted. Expected volatility is based on the historical volatility of our common stock and other factors. The risk-free interest rate is based on the U.S. Treasury rate with a maturity date corresponding to the SARs’ expected life.
Restricted Stock and RSUs
Our stock compensation plans allow grants of restricted stock and RSUs. Restricted stock is issued on the grant date but is restricted as to transferability. RSU awards represent the right to receive common stock when vesting occurs.
Restricted stock and RSU grants generally vest over periods ranging from one to five years of service. Compensation cost for these awards is based on the closing market price of our common stock on the date of grant. Stock-based compensation expense is based on the awards ultimately expected to vest, and has been reduced for estimated forfeitures.
The following table summarizes the status of our restricted stock and RSUs at December 31, 2011 and the changes during the year then ended:
The total intrinsic value of restricted stock and RSUs vested in 2011, 2010 and 2009 was $54.0 million, $41.0 million and $24.6 million, respectively. The intrinsic value was based upon the closing price of common stock on the date restricted stock and RSUs vested. The weighted average grant date fair value of RSUs granted during the years ended December 31, 2010 and 2009 was $31.23 per share and $22.27 per share, respectively.
In 2006, we granted 300,000 RSUs to certain executives that will vest only upon a change of control (as defined). Because, in our assessment, a change of control is not probable, no compensation cost has been recognized for these awards.
The nonvested shares in the tables above include 1.9 million shares that were deemed granted in 2005 for accounting purposes under the 2004 Plan in accordance with the provisions of our Long-Term Retention and Deferred Compensation Plan. The plan allows certain executive officers to defer awards of equity compensation and in lieu thereof, an equivalent number of RSUs available under stockholder-approved plans will be credited to an account for the executive. Under the terms of this plan, certain executives were granted the right under the 2004 Plan to receive annual RSU grants beginning in 2005 and continuing until 2014. Each annual credit is subject to continued service by the executive and all such future grants are deemed granted in 2005 for the purpose of determining stock-based compensation expense. The grants have varying vesting dates from 2012 through 2015 but payment of vested RSUs will be generally deferred until September 30, 2015, subject to certain exceptions. At December 31, 2011, 1.2 million nonvested shares had been granted and 0.7 million nonvested shares will be granted in 2012 through 2014.
In addition, under the terms of our Long-Term Retention and Deferred Compensation Plan, annual grants may be increased if certain common stock price targets are achieved. We used a Monte-Carlo simulation model to estimate the value and number of RSUs expected to be granted in the future. This model involves forecasting potential future stock price paths based on the expected return on the common stock and its volatility, then calculating the number of RSUs expected to be granted based on the results of the simulations.
The following assumptions were used with respect to the Monte Carlo simulation model:
We estimated that 0.4 million restricted units would be granted as a result of achieving the common stock price targets. Such units had a weighted average fair value of $46.61 per unit, an aggregate fair value of $18.7 million and a weighted average remaining contractual life of six years.
The tables above also include 1.0 million RSUs deemed granted in 2008 for accounting purposes. An executive was granted the right to receive five annual grants of 200,000 RSUs beginning in September 2015 and continuing until 2019. Each annual grant is subject to continued service by the executive. The first three annual grants will each vest in full in 2020 and the fourth and fifth annual grants will each vest ratably over a three year period from the date of the grant. The grant date for accounting purposes for all 1.0 million of these RSUs is March 2008.
At certain times a sufficient number of shares are not available for issuance under our stock compensation plans to satisfy all awards deemed granted for accounting purposes. At such times, we have reclassified and accounted for as liability awards the number of shares deemed granted in excess of available shares, until such time that the number of available shares is increased to a sufficient level to satisfy such awards, at which point the awards are reclassified back to equity awards.
Stock Options
At December 31, 2011, there were 6,176 stock options outstanding with an average exercise price of $7.92 per share and an average remaining life of 0.7 years. The intrinsic value of options exercised in the years ended December 31, 2011, 2010 and 2009 was $22,000, $0.4 million and $0.1 million, respectively, and we received $8,000, $0.2 million and $0.1 million, respectively, upon the exercise of such options.
Other
We have a 401(k) defined contribution plan whereby we have matched 100% of an employee’s contribution (subject to certain limitations in the plan). In 2011, 2010 and 2009 we made cash contributions totaling $10.3 million, $9.2 million and $9.3 million, respectively, to the 401(k) plan.
We have certain awards which have vested, but the issuance of those common shares has been deferred. During 2011, 2010 and 2009, approximately 318,000, 348,000 and 163,000 common shares, respectively, vested and were deferred resulting in a total of approximately 1,046,000 deferred common shares at December 31, 2011. These common shares will be issued upon the earliest of the deferral date, their retirement or death.
Note 11 - Income Taxes
For the years ended December 31, 2011, 2010 and 2009 our income (loss) before income taxes consisted of (in thousands):
For the years ended December 31, 2011, 2010 and 2009 our income tax (benefit) expense consisted of (in thousands):
Our deferred income tax assets and liabilities at December 31, 2011 and 2010 consist of the tax effect of income tax carryforwards and differences related to the timing of recognition of certain types of costs as follows (in thousands):
Tax carryforwards at December 31, 2011, which are available for future utilization on income tax returns, are as follows (in thousands):
Set forth below is a reconciliation between the income tax provision computed at the United States statutory rate on income before income taxes and the income tax provision in the accompanying income statement (in thousands):
Tax Relationship with Plains Offshore. As of December 31, 2011, Plains Offshore was not consolidated with us for federal income tax purposes. Plains Offshore files a separate federal tax return and has its own federal tax loss carryforwards and other tax attributes. Plains Offshore may or may not be combined with us and our other subsidiaries for state tax filing purposes dependent upon the applicable state tax rules. We and Plains Offshore have entered into a Tax Matters Agreement, or TMA, which governs Plains Offshore’s and our respective rights, responsibilities, and obligations with respect to the filing of tax returns, payment of taxes, conduct of tax audits and certain other tax matters.
Under the TMA, Plains Offshore is obligated to reimburse us for its share of taxes that are paid by us and can receive payment from us for any Plains Offshore tax attributes utilized by us related to our tax returns filed on a consolidated, combined or unitary basis including Plains Offshore but only to the extent and at such time as Plains Offshore would have paid the tax or utilized such attributes on a separate return basis. To the extent Plains Offshore files tax returns which are not consolidated, combined or unitary with us, Plains Offshore pays its tax liabilities directly to the applicable taxing authority.
Tax Loss and Credit Carryovers. Certain of our U.S. tax loss and credit carryovers obtained as a result of the acquisitions of Nuevo Energy Company and Pogo are subject to IRC limitations as to the amount that can be used each year. We do not expect these limitations to materially impact our ability to utilize these losses.
Valuation Allowance. In assessing the realizability of deferred tax assets, we consider whether it is more likely than not that some portion or all of the related deferred tax benefits will not be realized. We consider the scheduled reversal of deferred tax liabilities, projected future income and tax planning strategies in making the assessment of whether it is more likely than not that some portion or all of our deferred tax assets will not be realized. Based on this assessment as of December 31, 2011, no valuation allowances were necessary.
Other Tax Matters. We did not record a tax benefit related to non-cash employee compensation for 2011 since we generated a net operating loss for federal tax purposes in 2011 which will be carried forward to future periods. As the Company utilizes this net operating loss in future periods, a tax benefit of $0.2 million will be credited to additional paid-in capital as a result of the non-cash employee compensation that vested in 2011. In 2010 and 2009 we recorded tax expense of $2.7 million and $5.1 million, respectively, related to non-cash employee compensation that vested in those years.
Unrecognized Tax Benefits. A reconciliation of the beginning and ending amount of gross unrecognized tax benefits (excluding accrued interest) is as follows (dollars in thousands):
During 2011, our balance of net unrecognized tax benefits decreased by $6.1 million primarily as a result of the expiration of the statute of limitations for various tax years. During 2010, we concluded our administrative appeal with the IRS and as a result reduced our balance of gross unrecognized tax benefits by $2.6 million primarily related to certain tax deductions for these same tax years. During 2009, we received revenue agent reports from the IRS relating to tax years under audit. As a result of these reports, we reduced our balance of gross unrecognized tax benefits by $30.7 million primarily related to certain tax credits.
We estimate our balance of net unrecognized tax benefits will be reduced by $5.0 million over the next twelve months as the statute of limitations expires for various tax years. Included in the balance at December 31, 2011 is approximately $6.9 million that would affect our effective tax rate if recognized. The difference between this amount and the $7.3 million ending balance of gross unrecognized tax benefits represents the federal benefit of state tax positions.
We had approximately $1.8 million and $3.1 million of accrued interest on unrecognized tax benefits in our balance sheets as of December 31, 2011 and 2010, respectively. We did not have any accrued liabilities for penalties related to unrecognized tax benefits for the years ended December 31, 2011 and 2010.
We file income tax returns in the U.S. federal and various state and foreign jurisdictions. As of December 31, 2011, we are not under examination by the IRS and are no longer subject to U.S. federal income tax examinations for years prior to 2007 except for certain tax credit carryforwards generated before 2007, but utilized after 2006.
In December 2010, the state of California commenced an audit of our 2008 California income tax return. In December 2011, the state of New Mexico commenced an audit of Pogo’s 2007 New Mexico income tax return. Also in 2011, the state of Texas informed us that an audit of our 2008 Texas Franchise Tax return will commence in 2012. In all states except California and New Mexico, we are no longer subject to state income tax examinations by the relevant tax authorities for years prior to 2008. For California and New Mexico, we are no longer subject to state income tax examinations for years prior to 2007 except for certain California tax loss and credit carryforwards generated before 2007 but utilized after 2006.
Note 12 - Commitments, Contingencies and Industry Concentration
Commitments and Contingencies
Operating Leases. Our operating leases relate primarily to obligations associated with aircraft and office facilities. Future non-cancellable commitments related to these leases are as follows (in thousands):
Total expenses related to such leases were $12.2 million, $12.3 million and $13.0 million in 2011, 2010 and 2009, respectively.
Contractual Obligations. As is common within the industry, we have entered into various commitments and operating agreements associated with, among other things, oil and gas exploration, development and production activities, gathering and transportation, drilling rig and oilfield and other services. Aggregate future obligations under these agreements, described below, total $770.4 million, of which approximately $226.6 million is expected to be paid in 2012, $176.9 million in 2013, $112.2 million in 2014, $39.8 million in 2015, $39.4 million in 2016 and $175.5 million thereafter.
Through our ownership in Lucius, located in the deepwater U.S. Gulf of Mexico, we joined the Lucius and Hadrian working interest partners and executed a unit participation and unit operating agreement effective June 1, 2011. As part of the agreements, we have agreed to share in our portion of certain long lead equipment orders and detailed engineering work and have a commitment of approximately $314.3 million remaining under the development plan.
Plains Offshore and its partners have entered into various agreements with third parties for long-term oil and gas gathering and transportation services at the Lucius oil field. Beginning in 2014, Plains Offshore will pay guaranteed fixed minimum monthly fees plus additional variable gathering fees based upon actual throughput. The commitments of Plains Offshore under the oil gathering agreements are guaranteed by PXP.
We have commitments for hydraulic fracturing services, coil tubing services and drilling rig contracts with terms from one year up to three years primarily to perform our Eagle Ford Shale drilling program.
At our Arroyo Grande field in San Luis Obispo County, California, we have committed for the design and construction of a produced water reclamation facility. Additionally, we have signed a ten-year operations agreement for the facility which will commence upon commercial operations.
Environmental Matters. As an owner or lessee and operator of oil and gas properties, we are subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. Often these regulations are more burdensome on older properties that were operated before the regulations came into effect such as some of our properties in California that have operated for over 100 years. We have established policies for continuing compliance with
environmental laws and regulations. We also maintain insurance coverage for environmental matters which we believe is customary in the industry, but we are not fully insured against all environmental risks. There can be no assurance that current or future local, state or federal rules and regulations will not require us to spend material amounts to comply with such rules and regulations.
Plugging, Abandonment and Remediation Obligations. Consistent with normal industry practices, substantially all of our oil and gas leases require that, upon termination of economic production, the working interest owners plug and abandon non-producing wellbores, remove tanks, production equipment and flow lines and restore the wellsite. Typically, when producing oil and gas assets are purchased, the purchaser assumes the obligation to plug and abandon wells that are part of such assets. However, in some instances, we have received an indemnity with respect to those costs. We cannot be assured that we will be able to collect on these indemnities.
We estimate our 2012 cash expenditures related to plugging, abandonment and remediation will be approximately $7.7 million. At the Point Arguello Unit, offshore California, the companies from which we purchased our interests retained responsibility for the majority of the abandonment costs, including: (1) removing, dismantling and disposing of the existing offshore platforms; (2) removing and disposing of all existing pipelines; and (3) removing, dismantling, disposing and remediating all existing onshore facilities. We are responsible for our 69.3% share of other abandonment costs which primarily consist of well bore abandonments, conductor removals and site cleanup and preparation. Although our offshore California properties have a shorter reserve life, third parties have retained the majority of the obligations for abandoning these properties.
In connection with the sale of certain properties offshore California in December 2004, we retained the responsibility for certain abandonment costs, including removing, dismantling and disposing of the existing offshore platforms. The present value of such abandonment costs, $82.6 million ($145.2 million undiscounted), is included in our asset retirement obligation as reflected on our balance sheet. In addition, we agreed to guarantee the performance of the purchaser with respect to the remaining abandonment obligations related to the properties (approximately $86.1 million). To secure its abandonment obligations, the purchaser of the properties is required to periodically deposit funds into an escrow account. At December 31, 2011, the escrow account had a balance of $17.7 million. The fair value of our guarantee at December 31, 2011, $0.7 million, considers the payment/performance risk of the purchaser and is included in other long-term liabilities in our balance sheet.
Operating Risks and Insurance Coverage. Our operations are subject to all of the risks normally incident to the exploration for and the production of oil and gas, including well blowouts, cratering, explosions, oil spills, releases of gas or well fluids, fires, pollution and releases of toxic gas, each of which could result in damage to or destruction of oil and gas wells, production facilities or other property or injury to persons. Our operations in California, including transportation of oil by pipelines within the city and county of Los Angeles, are especially susceptible to damage from earthquakes and involve increased risks of personal injury, property damage and marketing interruptions because of the population density of southern California. We maintain coverage for earthquake damages in California but this coverage may not provide for the full effect of damages that could occur and we may be subject to additional liabilities. Although we maintain insurance coverage considered to be customary in the industry, we are not fully insured against all risks, either because insurance is not available or because of high premium costs. We are self-insured for named windstorms in the Gulf of Mexico. The occurrence of a significant event that is not fully insured against could have a material adverse effect on our financial position. Our insurance does not cover every potential risk associated with operating our pipelines, including the potential loss of significant revenues. Consistent with insurance coverage generally available to the industry, our insurance policies provide limited coverage for losses or liabilities relating to pollution, with broader coverage for sudden and accidental occurrences.
In the event we make a claim under our insurance policies, we will be subject to the credit risk of the insurers. Volatility and disruption in the financial and credit markets may adversely affect the credit quality of our insurers and impact their ability to pay out claims.
Other Commitments and Contingencies. We are a defendant in various lawsuits arising in the ordinary course of our business. While the outcome of these lawsuits cannot be predicted with certainty and could have a material adverse effect on our financial position, we do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows.
Industry Concentration
Financial instruments that potentially subject us to concentrations of credit risk consist principally of accounts receivable with respect to our oil and gas operations and derivative instruments. During 2011, 2010 and 2009, sales to ConocoPhillips accounted for 41%, 57% and 44%, respectively, of our total revenues. During 2011, sales to Tesoro Corporation and Valero Energy Corporation accounted for 13% and 11%, respectively, of our total revenues. The contract with Tesoro Corporation expired in November 2011. We did not renew this contract, and upon expiration we entered into a contract with ConocoPhillips for these volumes. During 2009, sales to Plains Marketing, L.P., or PMLP, accounted for 22% of our total revenues. The contract with PMLP expired in November 2009, and we entered into contracts with purchasers who previously purchased through PMLP, the most significant of which was ConocoPhillips. During 2011, 2010 and 2009, no other purchaser accounted for more than 10% of our total revenues. The loss of any single significant customer or contract could have a material adverse short-term effect; however, we do not believe that the loss of any single significant customer or contract would materially affect our business in the long-term. We believe such purchasers could be replaced by other purchasers under contracts with similar terms and conditions. However, their role as the purchaser of a significant portion of our oil production does have the potential to impact our overall exposure to credit risk, either positively or negatively, in that they may be affected by changes in economic, industry or other conditions. We do not currently require letters of credit or other collateral from the above stated purchasers to support trade receivables. Accordingly, a material adverse change in purchaser’s financial condition could adversely impact our ability to collect the applicable receivables, and thereby affect our financial condition.
There are a limited number of alternative methods of transportation for our production. Substantially all of our oil and gas production is transported by pipelines and trucks owned by third parties. The inability or unwillingness of these parties to provide transportation services to us for a reasonable fee could result in us having to find transportation alternatives, increased transportation costs or involuntary curtailment of a significant portion of our oil and gas production which could have a negative impact on future results of operations or cash flows.
Note 13 - Supplemental Cash Flow Information
Cash payments for interest and income taxes were as follows (in thousands):
At December 31, 2011 and 2010, accrued capital expenditures included in accounts payable in the balance sheet were $196.0 million and $150.1 million, respectively.
Common stock and treasury shares issued in connection with our compensation plans were as follows (in thousands):
(1) The number of shares is net of shares withheld for employee taxes and the amount is based on the grant date price.
Non-cash oil and gas property reductions and additions included:
•
non-cash reductions to oil and gas properties in 2010 of $665.9 million related to the sale of our Gulf of Mexico shallow water shelf properties in exchange for 51.0 million shares of McMoRan common stock; and
•
non-cash additions to oil and gas properties of $12.9 million, $21.8 million and $55.3 million in 2011, 2010 and 2009, respectively, related to our asset retirement obligation.
Certain of our commodity derivative contracts include deferred premiums to be paid to the counterparty based on the settlement terms specified in the contract. During 2011, 2010 and 2009, we entered into derivative contracts with deferred premiums of $49.2 million, $162.9 million and $74.1 million, respectively. In connection with our September 2011 derivative transactions, we eliminated $93.2 million of deferred premiums and interest associated with contracts entered into in 2010.
Note 14 - Equity
Earnings Per Common Share
Weighted average common shares outstanding for computing basic and diluted earnings were as follows (in thousands):
Included in computing our basic earnings per common share are certain awards which have vested, but, at the election of the award recipients, the issuance of those common shares has been deferred. For the years ended December 31, 2011, 2010 and 2009, 1.4 million, 1.8 million and 2.4 million, respectively, restricted stock units were excluded in computing diluted earnings per common share because they were antidilutive due to the impact of the unrecognized compensation cost on the calculation of assumed proceeds in the application of the treasury stock method.
In computing our earnings per share for 2011, we decreased our reported net income by the $1.4 million in preferred stock dividends attributable to the noncontrolling interest associated with our consolidated subsidiary Plains Offshore. We owned 100% of the common shares of Plains Offshore during 2011, and because Plains Offshore had a net loss for 2011, we did not allocate any undistributed earnings to the noncontrolling interest preferred stock. In the event that Plains Offshore has net income in future periods, we will be required to allocate distributed and undistributed earnings between the common and preferred shares of Plains Offshore.
Common Stock Offerings
During the second quarter of 2009, we sold 13.8 million shares of our common stock at a price of $18.70 per share to the public and received $250.9 million of net proceeds after deducting the underwriting discounts and offering expenses.
During the third quarter of 2009, we sold 17.25 million shares of our common stock at a price of $24.00 per share to the public and received $397.1 million of net proceeds after deducting the underwriting discounts and offering expenses.
Authorized Shares
The number of our authorized common shares at December 31, 2011 is 250.0 million, with a par value of $0.01.
The number of our authorized preferred shares at December 31, 2011 is 5.0 million, with a par value of $0.01. No PXP preferred shares were issued as of December 31, 2011.
Stock Repurchase Program
During the year ended December 31, 2011, we repurchased 10.4 million common shares at an average cost of $34.73 per share totaling $361.7 million.
In January 2012, we completed the purchase of an additional 2.4 million common shares at an average cost of $37.02 per share totaling $88.5 million. Subsequent to those purchases, our Board of Directors reset the authorization to $1.0 billion of PXP common stock, all of which is available for repurchase, and extended the program until January 2016.
Note 15 - Other Operating (Income) Expense and Other Income
Other operating income for 2011 and 2010 primarily consists of production tax abatements related to production in prior years. Other operating expense in 2009 consists primarily of a restocking fee related to a cancelled purchase order, a valuation adjustment for materials and supplies inventory and idle drilling equipment costs resulting from unused contract commitments partially offset by a reduction in preacquisition operating expense accruals related to our acquisition of Pogo.
Other income consists of the following (in thousands):
(1) Reflects preacquisition amounts for properties sold by Pogo prior to our acquisition of Pogo.
Note 16 - Consolidating Financial Statements
We are the issuer of 7 3/4% Senior Notes, 10% Senior Notes, 7% Senior Notes, 7 5/8% Senior Notes due 2018, 8 5/8% Senior Notes, 7 5/8% Senior Notes due 2020, 6 5/8% Senior Notes and 6 3/4% Senior Notes as of December 31, 2011, which are jointly and severally guaranteed by certain of our existing domestic subsidiaries (referred to as “Guarantor Subsidiaries”). In the future, the guarantees may be released or terminated under the following circumstances: (i) in connection with any sale or other disposition of all or substantially all of the assets of that subsidiary guarantor; (ii) in connection with any sale or other disposition of all the capital stock of a subsidiary guarantor; (iii) if designated to be an unrestricted subsidiary; (iv) upon legal defeasance or satisfaction and discharge of the indenture; (v) upon the liquidation or dissolution of such subsidiary guarantor provided no default or event of default has occurred or is continuing; or (vi) at such time as such subsidiary guarantor does not have outstanding any guarantee of any of our or any of our subsidiary guarantor’s indebtedness (other than the notes) in excess of $10.0 million in aggregate principal amount. Certain of our subsidiaries do not guarantee the Senior Notes (referred to as “Non-Guarantor Subsidiaries”).
PXP Operations LLC. During the first half of 2011, the reverse like-kind exchange arrangements pursuant to IRC Section 1031 were concluded prior to the completion of a like-kind exchange involving any disposition of PXP properties. As a result, the related Eagle Ford Shale properties were transferred from PXP Operations LLC, which was reported as a Non-Guarantor Subsidiary, to PXP, which is reported as Issuer, and the outstanding notes between PXP Operations LLC and PXP were settled. We have retrospectively adjusted the Issuer, Non-Guarantor Subsidiaries and Intercompany Eliminations columns of the condensed consolidating balance sheet at December 31, 2010 and the consolidating statements of income and cash flows for the year ended December 31, 2010 to reflect the unwind of the reverse like-kind exchange arrangement involving PXP Operations LLC.
Plains Offshore. In October 2011, we entered into a securities purchase agreement with EIG pursuant to which we received $430.2 million of net cash proceeds in exchange for a 20% equity interest in Plains Offshore. Plains Offshore holds all of our oil and natural gas properties and assets located in the United States Gulf of Mexico in water depths of 500 feet or more. As a result, the associated deepwater properties were transferred from PXP, which is reported as Issuer, to Plains Offshore, which is reported as a Non-Guarantor Subsidiary. We have retrospectively adjusted the Issuer, Non-Guarantor Subsidiaries and Intercompany Eliminations columns of the condensed consolidating balance sheet at December 31, 2010 and the consolidating statements of income and cash flows for the years ended December 31, 2010 and 2009 to reflect the transfer of these deepwater assets.
The following financial information presents consolidating financial statements, which include:
•
PXP (the “Issuer”);
•
the Guarantor Subsidiaries on a combined basis;
•
the Non-Guarantor Subsidiaries on a combined basis;
•
elimination entries necessary to consolidate the Issuer, Guarantor Subsidiaries and Non-Guarantor Subsidiaries; and
•
PXP on a consolidated basis.
PLAINS EXPLORATION & PRODUCTION COMPANY
CONDENSED CONSOLIDATING BALANCE SHEET
DECEMBER 31, 2011
(in thousands of dollars)
PLAINS EXPLORATION & PRODUCTION COMPANY
CONDENSED CONSOLIDATING BALANCE SHEET
DECEMBER 31, 2010
(in thousands of dollars)
PLAINS EXPLORATION & PRODUCTION COMPANY
CONDENSED CONSOLIDATING STATEMENT OF INCOME
YEAR ENDED DECEMBER 31, 2011
(in thousands of dollars)
PLAINS EXPLORATION & PRODUCTION COMPANY
CONDENSED CONSOLIDATING STATEMENT OF INCOME
YEAR ENDED DECEMBER 31, 2010
(in thousands of dollars)
PLAINS EXPLORATION & PRODUCTION COMPANY
CONDENSED CONSOLIDATING STATEMENT OF INCOME
YEAR ENDED DECEMBER 31, 2009
(in thousands of dollars)
PLAINS EXPLORATION & PRODUCTION COMPANY
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31, 2011
(in thousands of dollars)
PLAINS EXPLORATION & PRODUCTION COMPANY
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31, 2010
(in thousands of dollars)
PLAINS EXPLORATION & PRODUCTION COMPANY
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31, 2009
(in thousands of dollars)
Note 17 - Quarterly Financial Data (Unaudited)
The following table shows summary financial data for 2011 and 2010 (in thousands, except per share data):
Note 18 - Oil and Natural Gas Activities
Investment
At December 31, 2011 and 2010, we owned 51.0 million shares of McMoRan common stock, approximately 31.6% and 32.4%, respectively, of its common shares outstanding. McMoRan is a publicly traded oil and gas exploration and production company (New York Stock Exchange listing MMR) engaged in the exploration, development and production of natural gas and oil in the United States, specifically offshore in the shallow waters of the Gulf of Mexico Shelf and onshore in the Gulf Coast area. We acquired the McMoRan common stock and other consideration in exchange for all of our interests in our Gulf of Mexico leasehold located in less than 500 feet of water. See Note 3 - Divestments.
McMoRan follows the successful efforts method of accounting for its oil and natural gas activities. See Note 7 - Investment.
Costs Incurred
Our oil and natural gas acquisition, exploration and development activities are conducted in the United States. The following table summarizes the costs incurred during the last three years (in thousands):
(1) Amounts relate to our equity investment in McMoRan acquired on December 30, 2010. Our proportionate share of McMoRan’s 2010 costs incurred is not presented because it is insignificant as PXP owned the investment for one day and it is not practicable to determine one day of costs incurred.
Amounts presented include capitalized general and administrative expense of $77.1 million, $68.0 million and $67.3 million in 2011, 2010 and 2009, respectively, and capitalized interest expense of $115.4 million, $128.0 million and $113.8 million in 2011, 2010 and 2009, respectively. We had no international exploration costs in 2011; in 2010 and 2009, our international exploration costs, primarily in offshore Vietnam, were $1.7 million and $42.3 million, respectively.
During the second quarter of 2010, we completed our interpretation of seismic and drilling data from our two offshore Vietnam exploratory wells and decided not to pursue additional exploratory activities in this area. We terminated our production sharing contract in accordance with its terms. The costs related to our Vietnam oil and gas properties not subject to amortization were transferred to our Vietnam full cost pool where they were subject to the ceiling limitation. Because our Vietnam full cost pool had no associated proved oil and gas reserves, we recorded a non-cash pre-tax impairment charge of $59.5 million. We also recorded a corresponding tax benefit of $23.0 million.
Capitalized Costs
The following table presents the aggregate capitalized costs subject to amortization relating to our oil and gas acquisition, exploration and development activities, and the aggregate related accumulated depreciation, depletion and amortization, or DD&A, and impairment (in thousands):
(1) Amounts relate to our equity investment in McMoRan acquired on December 30, 2010.
Our average DD&A rate per BOE was $17.76, $15.87 and $12.79 in 2011, 2010 and 2009, respectively.
Costs not subject to amortization
The following table summarizes the categories of costs comprising the amount of unproved properties not subject to amortization by the year in which such costs were incurred (in thousands):
(1) Includes amounts attributable to our Eagle Ford Shale acquisition in the fourth quarter of 2010. See Note 2 - Acquisitions.
(2) Includes amounts attributable to the September 2009 pre-payment of the Haynesville Carry associated with the Chesapeake acquisition. See Note 2 - Acquisitions.
The costs of unproved oil and gas properties are excluded from amortization until the properties are evaluated. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. Unproved properties are assessed periodically, at least annually, to determine whether impairment has occurred. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment considers the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. The transfer of costs into the amortization base involves a significant amount of judgment and may be subject to changes over time based on our drilling plans and results, geological and geophysical evaluations, the assignment of proved reserves, availability of capital, and other
factors. Costs not subject to amortization consist primarily of capital costs incurred for undeveloped acreage and wells in progress pending determination, together with capitalized interest costs for these projects. Due to the nature of the reserves, the ultimate evaluation of the properties will occur over a period of several years. We expect that 57% of the costs not subject to amortization at December 31, 2011 will be transferred to the amortization base over the next five years and the remainder in the next seven to ten years.
Approximately 21% of our total net undeveloped acreage is covered by leases that will expire from 2012 to 2014. In 2008 and 2010, we added a significant number of new leases in the Haynesville Shale and the Eagle Ford Shale, respectively, with lease terms generally ranging from two to three years. Over 85% of our acreage in the Haynesville Shale and over 25% of our acreage in the Eagle Ford Shale is currently held by production or held by operations and future plans include drilling or extending leases on our remaining acreage.
During the third quarter of 2011, we determined not to develop the Friesian prospect and the lease terminated by its terms. The accumulated costs of approximately $460 million associated with the project were transferred to the full cost pool.
Results of Operations for Oil and Gas Producing Activities
The results of operations from oil and gas producing activities below exclude non-oil and gas revenues, general and administrative expenses, interest charges and interest income. Income tax expense was determined by applying the statutory rates to pre-tax operating results (in thousands):
(1) Amounts relate to our equity investment in McMoRan acquired on December 30, 2010. We completed the divestment of our Gulf of Mexico shallow water properties on December 30, 2010. Our proportionate share of McMoRan’s 2010 results of operations is not presented because it is insignificant as PXP owned the investment for one day and it is not practicable to determine one day’s results of operations.
Supplemental Reserve Information (unaudited)
The following information summarizes our net proved reserves of oil (including condensate and natural gas liquids) and gas and the present values thereof for the three years ended December 31, 2011. All of our reserves are located in the United States. The following table sets forth certain information with respect to our proved reserves that for 2011 are based upon (1) reserve reports prepared by the independent petroleum engineers of Netherland, Sewell & Associates, Inc., or NSA (95% of proved reserve volumes) and (2) reserve volumes prepared by us, which were not audited by an independent petroleum engineer (5% of proved reserve volumes). In 2010, our proved reserves were based upon (1) reserve reports prepared by the independent petroleum engineers of NSA and Ryder Scott Company L.P., or Ryder Scott (99% of proved reserve volumes) and (2) reserve volumes prepared by us, which were not audited by an independent petroleum engineer (1% of proved reserve volumes). In 2009, our proved reserves were based upon reserve reports prepared by NSA and Ryder Scott.
Management believes the reserve estimates presented herein, in accordance with generally accepted engineering and evaluation principles consistently applied, are reasonable. However, there are numerous uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and the amount and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all reserve estimates are to some degree subjective, the quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and gas sales prices may all differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. Therefore, the Standardized Measure shown below represents estimates only and should not be construed as the current market value of the estimated oil and gas reserves attributable to our properties. In this regard, the information set forth in the following tables includes revisions of reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions reflect additional information from subsequent development activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices.
Decreases in the prices of oil and natural gas have had, and could have in the future, an adverse effect on the carrying value of our proved reserves, reserve volumes and our revenues, profitability and cash flow. As of February 2012, the twelve-month average of the first-day-of-the-month reference price for natural gas has declined from $4.12 per MMBtu at year-end 2011 to $3.86 per MMBtu, while the comparable price for oil has increased from $95.99 per Bbl at year-end 2011 to $97.28 per Bbl.
Historically, the market price for California crude oil differs from the established market indices in the United States due principally to the higher transportation and refining costs associated with heavy oil. Recently, however, the market price for California crude oil has strengthened relative to NYMEX and WTI primarily due to world demand and declining domestic supplies of both Alaskan and California crude oil. Approximately 53% of our 2011 reserve volumes are attributable to properties in California where differentials to the reference prices have been volatile due to these factors.
Estimated Quantities of Oil and Natural Gas Reserves (unaudited)
The following table sets forth certain data pertaining to our proved, proved developed and proved undeveloped reserves for the three years ended December 31, 2011.
Table continued on following page.
(1) Amounts relate to our equity investment in McMoRan acquired on December 30, 2010.
(2) Reserve estimates as of January 1, 2009 are calculated using year-end reference prices adjusted for location and quality differentials as required by SEC reporting rules at December 31, 2008.
Revisions of Previous Estimates
In 2011, we had net positive revisions of 1 MMBOE. Positive revisions of 21 MMBOE were primarily related to higher realized oil prices principally at our California properties. Negative revisions of 20 MMBOE were mostly related to lower gas prices, primarily at our Panhandle properties prior to the divestment in December 2011.
In 2010, we had net positive revisions of 20 MMBOE. Positive revisions of 8 MMBOE were primarily related to higher realized oil prices principally at our California properties while positive revisions of 12 MMBOE were primarily related to higher realized gas prices principally at our Panhandle, Haynesville Shale and South Texas properties.
In 2009, we had net positive revisions of 39 MMBOE. Positive revisions of 77 MMBOE were primarily related to higher oil prices principally at our California properties. Negative revisions of 13 MMBOE mostly related to lower gas prices, primarily at our Panhandle and South Texas properties. Additionally, certain of our undeveloped locations are scheduled for development beyond five years and were excluded from our proved reserves, resulting in a negative revision of 25 MMBOE.
Purchases of Reserves in-Place
In 2011, proved reserves acquired in the Texas Panhandle were 4 MMBOE. These proved reserves were subsequently divested in December 2011.
In 2010, proved reserve additions acquired in the Eagle Ford Shale were 1 MMBOE.
In 2009, we had a total of 2 MMBOE of proved reserve additions related to interests acquired in the Haynesville Shale.
Extensions, Discoveries and Other Additions
In 2011, we had a total of 75 MMBOE of extensions and discoveries, including 25 MMBOE in the Haynesville Shale and 22 MMBOE in the Eagle Ford Shale resulting from successful drilling during 2011 that extended and developed our proved acreage and 19 MMBOE in the deepwater Gulf of Mexico resulting from sanctioning of the Lucius project.
In 2010, we had a total of 77 MMBOE of extensions and discoveries, including 54 MMBOE in the Haynesville Shale resulting from successful drilling during 2010 that extended and developed the proved acreage and 17 MMBOE of extensions and discoveries in the Panhandle resulting from successful horizontal development and extension of the proved acreage in the Granite/Atoka Wash.
In 2009, we had a total of 57 MMBOE of extensions and discoveries, including 53 MMBOE in the Haynesville Shale resulting from successful drilling during 2009 that extended and developed our proved acreage and 2 MMBOE of extensions and discoveries in the Gulf of Mexico, primarily attributable to continued success in the Flatrock area.
Sales of Reserves in-Place
In 2011, we had a total of 50 MMBOE of divestments, which were primarily from our Panhandle and South Texas properties.
In 2010, we had a total of 9 MMBOE of divestments, all of which were from our shallow water Gulf of Mexico divestment to McMoRan.
Standardized Measure of Discounted Future Net Cash Flows (unaudited)
The Standardized Measure of discounted future net cash flows relating to proved crude oil and natural gas reserves is presented below (in thousands):
(1) Amounts relate to our equity investment in McMoRan acquired on December 30, 2010.
The Standardized Measure of Discounted Future Net Cash Flows (discounted at 10%) from production of proved reserves was developed as follows:
1. An estimate was made of the quantity of proved reserves and the future periods in which they are expected to be produced based on year-end economic conditions.
2. In accordance with SEC guidelines, the engineers’ estimates of future net revenues from our proved properties and the present value thereof are made using the twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials. These prices are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. We use various derivative instruments to manage our exposure to commodity prices. Arrangements in effect at December 31, 2011 are discussed in Note 6 - Commodity Derivative Contracts. The derivative instruments we have in place are not classified as hedges for accounting purposes. The realized sales prices used in the reserve reports as of December 31, 2011, 2010 and 2009 were $104.59, $72.83 and $54.38 per barrel of oil, respectively, and $4.08, $4.29 and $3.53 per Mcf of gas, respectively.
3. The future gross revenue streams were reduced by estimated future operating costs (including production and ad valorem taxes) and future development and abandonment costs, all of which were based on current costs in effect at December 31 of the year presented and held constant throughout the life of the properties.
4. Future income taxes were calculated by applying the statutory federal and state income tax rate to pre-tax future net cash flows, net of the tax basis of the properties involved and utilization of available tax carryforwards related to oil and gas operations.
The principal sources of changes in the Standardized Measure of the Future Net Cash Flows for the three years ended December 31, 2011, are as follows (in thousands):
(1) Reserve estimates as of January 1, 2009 are calculated using year-end reference prices adjusted for location and quality differentials as required by the SEC reporting rules at December 31, 2008.
(2) Amounts relate to our equity investment in McMoRan acquired on December 30, 2010. Our proportionate share of McMoRan’s changes in the standardized measure for the year ended December 31, 2010 is not presented because it is insignificant as PXP owned the investment for one day and it is not practicable to determine one day’s change in the standardized measure.