Item 1A.
Risk Factors
Described below are certain risks that we believe are applicable to our business and the oil and gas industry in which we operate. There may be additional risks that are not presently material or known. You should carefully consider each of the following risks and all other information set forth in this Annual Report on Form 10-K.
If any of the events described below occur, our business, financial condition, results of operations, liquidity or access to the capital markets could be materially adversely affected. In addition, the current global economic and political environment intensifies many of these risks.
Crude oil and natural gas prices are volatile and a substantial reduction in these prices could adversely affect our results and the price of our common stock.
Our revenues, operating results and future rate of growth depend highly upon the prices we receive for our crude oil and natural gas production. Historically, the markets for crude oil and natural gas have been volatile and are likely to continue to be volatile in the future. For example, the NYMEX daily average settlement price for the prompt month crude oil contract in 2010 ranged from a high of $89.23 per barrel to a low of $74.12 per barrel. The NYMEX monthly settlement price for the prompt month natural gas contract in 2010 ranged from a high of $5.81 per MMBtu to a low of $3.29 per MMBtu.
The markets and prices for crude oil and natural gas depend on factors beyond our control. These factors include demand for crude oil and natural gas, which fluctuates with changes in economic and market conditions, and other factors, including:
·
economic factors impacting global gross domestic product growth rates;
·
global demand for crude oil and natural gas;
·
global factors impacting supply quantities of crude oil and natural gas;
·
the potential long-term impact of an abundance of natural gas from shale on the global natural gas supply;
·
actions taken by foreign oil and gas producing nations;
·
political conditions and events (including instability or armed conflict) in crude oil or natural gas producing regions;
·
the level of global crude oil and natural gas inventories;
·
the price and level of imported foreign crude oil and natural gas;
·
the price and availability of alternative fuels, including coal, nuclear energy, and biofuels;
·
the long-term impact of the use of natural gas as an alternative fuel on the crude oil market;
·
the availability of pipeline capacity and infrastructure;
·
the availability of crude oil transportation and refining capacity;
·
weather conditions;
·
demand for electricity as well as natural gas used as fuel for electricity generation; and
·
domestic and foreign governmental regulations and taxes.
Significant declines in crude oil and natural gas prices for an extended period may have the following effects on our business:
·
reducing our revenues, operating income and cash flows;
·
reducing the amount of crude oil and natural gas that we can produce economically;
·
limiting our financial condition, liquidity, and/or ability to finance planned capital expenditures and operations;
·
limiting our access to sources of capital, such as equity and long-term debt; or
·
causing us to delay or postpone some of our capital projects.
In addition, lower commodity prices, including significant declines in the forward commodity price curves, may result in the following:
·
asset impairment charges resulting from reductions in the carrying values of our crude oil and/or natural gas properties at the date of assessment, such as occurred in 2008, 2009 and 2010; or
·
a reduction in the carrying value of goodwill.
Failure to effectively execute our major development projects could result in significant delays and/or cost over-runs, damage to our reputation, limitations on our growth and negative effects on our operating results.
We currently have an extensive inventory of major development projects, some of which will take several years before first production, including Aseng, Alen, Galapagos, Tamar, Gunflint, and others. Some of these projects, such as oil and gas projects offshore West Africa and Israel, have a great deal of complexity, including extensive subsea tiebacks to an FPSO or production platform, pressure maintenance systems, gas re-injection systems, onshore receiving terminals, or other specialized infrastructure. This level of development will require significant effort from our management and technical personnel as well as place additional burden on our financial resources and internal financial controls. We may not be able to attract and retain personnel with the skills necessary to bring complicated projects to successful conclusions.
In addition, we have increased dependency on third-party technology and service providers and other suppliers for these complex projects. Significant delays in delivery of essential items or performance of services, cost overruns, supplier insolvency, or other critical supply failure, could adversely affect development of our projects. We may not be able to compensate for, or fully mitigate, these risks.
Concentration of our operations in a few key areas may increase our risk of production loss.
Our operations are concentrated in four key areas: the Central DJ Basin and the deepwater Gulf of Mexico in the US, offshore West Africa, and the Eastern Mediterranean. These key areas provide most of our current crude oil and natural gas production, each of our major development projects, and most of our exploration potential. In the past several years, we have made several asset divestitures to high-grade and focus our portfolio. Divestitures included non-core, non-strategic assets in the Gulf of Mexico shelf, Mid-Continent and Illinois Basin areas in the US, and Argentina.
As a result of these portfolio changes, our operations and production are concentrated in fewer areas. Although none of these areas represented more than 25% of our 2010 total consolidated sales volumes, disruption of our business in one of these areas, such as from an accident, natural disaster, government intervention, or other event, would result in a greater impact on our production profile, cash flows and overall business plan than if we operated in a larger number of areas.
We do not maintain business interruption (loss of production) insurance for all of our assets. Loss of production from one of our key operating areas could have a significant negative impact on our cash flows and profitability.
We are subject to increasing governmental regulations and environmental risks that may cause us to incur substantial costs.
From time to time, in varying degrees, political developments and federal and state laws and regulations affect our operations. In particular, price controls, taxes and other laws relating to the crude oil and natural gas industry, changes in these laws and changes in administrative regulations have affected and in the future could affect crude oil and natural gas production, operations and economics. We cannot predict how agencies or courts will interpret existing laws and regulations or the effect these adoptions and interpretations may have on our business or financial condition.
Our business is subject to laws and regulations promulgated by international, federal, state and local authorities relating to the exploration for, and the development, production and marketing of, crude oil and natural gas, as well as safety matters. Legal requirements are frequently changed and subject to interpretation and we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. We may be required to make significant expenditures to comply with governmental laws and regulations.
Our operations are subject to complex international, federal, state and local environmental laws and regulations including, for example, in the case of federal laws, the Comprehensive Environmental Response, Compensation and Liability Act, as amended, the Resource Conservation and Recovery Act, as amended, the Oil Pollution Act of 1990, the Clean Air Act, the Clean Water Act and the Occupational Safety and Health Act. Environmental laws and regulations change frequently and the implementation of new, or the modification of existing, laws or regulations could negatively impact our operations. The discharge of natural gas, crude oil, or other pollutants into the air, soil or water may give rise to significant liabilities on our part to government agencies and third parties and may require us to incur substantial costs of remediation. In addition, we may incur costs and penalties in addressing regulatory agency procedures involving instances of possible non-compliance.
Our international operations may be adversely affected by economic and political developments.
We have significant international crude oil and natural gas operations compared to companies we consider to be our peers, with approximately 43% of our 2010 total consolidated sales volumes coming from international operations, and will be increasing our exposure through our major development projects offshore Equatorial Guinea and Israel. We are also conducting exploration activities in these and other international areas. Our operations may be adversely affected by political and economic developments, including the following:
·
renegotiation, modification or nullification of existing contracts, such as may occur pursuant to the proposed changes in Israel’s fiscal regime, or the hydrocarbons law enacted in 2006 by the government of Equatorial Guinea, which can result in an increase in the amount of revenues that the host government receives from production (government take) or otherwise decrease project profitability;
·
loss of revenue, property and equipment as a result of actions taken by foreign crude oil and natural gas producing nations, such as expropriation or nationalization of assets or termination of contracts, such as the recent termination of our Block 3 PSC by the Ecuadorian government pursuant to Ecuador's new hydrocarbon law;
·
disruptions caused by territorial or boundary disputes in certain international regions, including the Eastern Mediterranean, where Lebanon recently made claims related to our projects in Israeli waters;
·
changes in drilling or safety regulations in other countries being considered as a result of the Deepwater Horizon Incident, which changes will increase costs and development cycle time;
·
changes in taxation policies, such as the recent recommendations by a committee established by the Israeli Finance Minister to increase government take, the UK Finance Act of 2006, which increased the income tax rate on our UK operations effective January 1, 2006, and the China Petroleum Special Profits Tax enacted in 2006, which imposed an excise tax on crude oil produced in the country;
·
laws and policies of the US and foreign jurisdictions affecting foreign investment, taxation, trade and business conduct;
·
foreign exchange restrictions;
·
international monetary fluctuations and changes in the relative value of the US dollar as compared with the currencies of other countries in which we conduct business, such as Israel and the UK; and
·
other hazards arising out of foreign governmental sovereignty over areas in which we conduct operations.
Certain of these risks could be intensified by significant new discoveries in the Levantine Basin, where we are currently conducting exploration activities, and other developing basins in the Eastern Mediterranean where there is vast exploration potential remaining and where a large discovery could have a significant impact on the natural gas supply for the nations of Europe and the Eastern Mediterranean region.
Such political and economic developments as mentioned above could have a negative impact on our results of operations and cash flows and reduce the fair values of our properties, resulting in impairment charges. In addition, we may not have enough insurance to cover any loss of property resulting from these risks.
Our international operations may be adversely affected by war, terrorist acts, or civil disturbances that may occur in regions that encompass our operations.
We conduct exploration and development activities in the Eastern Mediterranean and offshore West Africa. These areas have historically been less politically stable than other areas in which we conduct business such as Europe or the US.
In recent weeks, civil unrest, which began in Tunisia and resulted in changes in the Tunisian government, has spread to the Middle East. There have been numerous demonstrations by Egyptian protestors demanding a regime change in their country, and some of the demonstrations have been marked by violence. Recently, the King of Jordan reconstituted his government after protestors demanded economic and political reforms.
Civil unrest could continue to spread throughout the region and involve other areas such as the Gaza Strip or nations such as Syria, Yemen, Lebanon or others. Such unrest, if it continues to spread or grow in intensity, could lead to civil wars; regime changes resulting in governments that are hostile to the US and/or Israel, such as has previously occurred in the region; violations of the 1979 Egypt-Israel Peace Treaty; or regional conflict.
At this time, we are uncertain of the outcome of these events. However, prolonged and/or widespread regional conflict in the Middle East could have the following results, among others:
·
volatility in global crude oil prices which could negatively impact the global economy, resulting in slower economic growth rates, which could reduce demand for our products;
·
negative impact on the world crude oil supply if transportation avenues are disrupted, leading to further commodity price volatility;
·
capital market reassessment of risk and subsequent redeployment of capital to more stable areas making it more difficult for partners to obtain financing for potential development projects;
·
security concerns in Israel, making it more difficult for our personnel or supplies to enter or exit the country;
·
reduced market demand in Israel for natural gas due to efforts to conserve domestic resources;
·
security concerns leading to evacuation of our personnel;
·
damage to or destruction of our wells, production facilities, receiving terminals or other operating assets;
·
damage to or destruction of property belonging to our natural gas purchasers leading to interruption of gas deliveries, claims of force majeure, and/or termination of natural gas sales contracts, resulting in a reduction in our revenues;
·
inability of our service and equipment providers to deliver items necessary for us to conduct our operations in the Eastern Mediterranean, resulting in delayed start-up of our Tamar project or shut-in of the Mari-B field; and
·
lack of availability of drilling rig, oilfield equipment or services if third party providers decide to exit the region.
Loss of property and/or interruption of our business plans resulting from hostile acts could have a significant negative impact on our earnings and cash flow. In addition, we may not have enough insurance to cover any loss of property or other claims resulting from these risks.
Our operations may be adversely affected by changes in the fiscal regimes of the countries in which we operate.
Fiscal regimes impact oil and gas companies through laws and regulations governing royalties, taxes or level of government participation in oil and gas projects. We operate in the US and other countries whose fiscal regimes may change over time. Changes in fiscal regimes result in an increase or decrease in the amount of government take, and a corresponding decrease or increase in the revenues of an oil and gas company operating in that particular country.
Governments are currently experiencing fiscal problems triggered by the lingering effects of the global financial crisis, associated recession and current slower economic growth rates. Higher unemployment and slower growth rates, coupled with a reduced tax base, have resulted in reduced government revenues, while government expenditures have increased due to the need for public entitlement or economic stimulus programs. Many countries have generated budget deficits or even approached insolvency and there has been social unrest in many regions.
Due to pressures from local constituents as well as the Organization for Economic Cooperation and Development (OECD) to address these negative fiscal situations and initiate deficit reduction measures, many governments are seeking additional revenue sources, including increases in government take from oil and gas projects.
For example, The US Administration’s fiscal year 2011 budget contained many revenue-raising proposals, including business tax increases, some of which impact oil and gas companies. Notwithstanding the recent extension of reduced tax rates or other favorable energy provisions contained in the Tax Relief Act of 2010, it is likely that some of these proposals will be re-proposed in the fiscal year 2012 budget. It is unclear whether, and to what extent such proposals will pass both houses of Congress and be signed into law. However, it is likely that some of these proposals, such as elimination of certain oil and gas company tax preferences, will receive consideration.
In March 2010, the President of the United States signed into law The Patient Protection and Affordable Care Act and The Health Care and Education Reconciliation Act of 2010 (collectively referred to as Health Insurance Reform Legislation) which enacted significant reforms to various aspects of the US health insurance industry including expansion of health care coverage to many uninsured individuals and expansion of coverage to those already insured. Due to its complexity and need for further implementing regulations, the full impact of the Health Insurance Reform Legislation is not yet fully known. However, any future changes in employer funding requirements or tax benefits will likely increase our employee health care costs and reduce our cash flows.
In 2010, the Finance Minister of Israel established an advisory committee to study the country’s fiscal policy as it relates to the upstream oil and natural gas sector, as well as various options, including an increase in royalties or cancellation of tax incentives. In January 2011, the Finance Ministry advisory committee issued its final recommendations which included cancellation of currently-existing tax incentives, including the depletion allowance, and imposition of a special levy ranging from 20% to 50%, on oil and gas profits after a return on investment has been achieved. At this time we are uncertain of the final outcome of these recommendations, which must be voted on by Israel’s Parliament, and are unable to predict the complete economic impact any change in Israel’s fiscal regime would have on our operations. A change in Israel’s fiscal regime could reduce the profitability of our Tamar project or a future development project at Leviathan. A retroactive change could reduce the cash flows from our Mari-B project.
In 2010, China began implementing a new price-based energy resource tax on oil and gas extraction in certain of its provinces.
Changes in fiscal regimes have long-term impacts on our business strategy, and uncertainty makes it more difficult to formulate capital investment programs. The implementation of new, or the modification of existing, laws or regulations impacting the amount of government take could disrupt our business plans and negatively impact our operations in the following ways, among others:
·
reduce exploration activities, which could have a long-term negative impact on the quantities of proved reserves we record and inhibit future production growth;
·
have a negative impact on the ability of us and/or our partners to obtain project financing;
·
cause delay in or cancellation of development plans, which could also have a long-term negative impact on the quantities of proved reserves we record and inhibit future production growth;
·
reduce the profitability of our projects, resulting in decreases in net income and cash flows;
·
result in current projects becoming uneconomic, to the extent fiscal changes are retroactive, thereby reducing the amount of proved reserves we record and cash flows we receive, and possibly resulting in asset impairment charges;
·
require that valuation allowances be established against deferred tax assets, with offsetting increases in income tax expense, resulting in decreases in net income;
·
restrict our ability to compete with imported volumes of crude oil or natural gas; and/or
·
adversely affect the price of our common stock.
We have insufficient insurance to cover all of the risks we face, which could result in significant financial exposure.
Exploration for and production of crude oil and natural gas can be hazardous, involving natural disasters and other unfortuitous events such as blowouts, well cratering, fire and explosion and loss of well control which can result in damage to or destruction of wells or production facilities, injury to persons, loss of life, or damage to property and the environment. Exploration and production activities are also subject to risk from political developments such as war, terrorist acts, civil disturbances, expropriation or nationalization of assets, which can cause loss of or damage to our property.
In accordance with industry practices, we maintain insurance against many, but not all, potential perils confronting our operations and in coverage amounts and deductible levels that we believe to be economic. Consistent with that profile, our insurance program is structured to provide us financial protection from unfavorable loss severity resulting from damages to or the loss of physical assets or loss of human life, liability claims of third parties, and business interruption (loss of production) attributed to certain assets and including such occurrences as well blowouts and resulting oil spills, at a level that balances cost of insurance with our assessment of risk and our ability to achieve a reasonable rate of return on our investments. Although we believe the coverages and amounts of insurance carried are adequate and consistent with industry practice, we do not have insurance protection against all the risks we face, because we chose not to insure certain risks, insurance is not available at a level that balances the cost of insurance and our desired rates of return, or actual losses exceed coverage limits.We regularly review our risks of loss and the cost and availability of insurance and revise our insurance program accordingly.
We expect the future availability and cost of insurance to be impacted by the Deepwater Horizon Incident. Impacts could include: tighter underwriting standards, limitations on scope and amount of coverage, and higher premiums, and will depend, in part, on future changes in laws and regulations regarding exploration and production activities in the Gulf of Mexico and other areas in which we operate, including possible increases in liability caps for claims of damages from oil spills. We will continue to monitor the legislative and regulatory response to the Incident and its impact on the insurance market and our overall risk profile, and adjust our risk and insurance program to provide protection, at a level that we can afford considering the cost of insurance and our desired rates of return, against disruption to our operations and cash flows.
If an event occurs that is not covered by insurance or not fully protected by insured limits, it could have a significant adverse impact on our financial condition, results of operations and cash flows. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Risk and Insurance Program.
Our operations in the deepwater Gulf of Mexico, as well as onshore US and international locations, could be adversely affected by future changes in laws and regulations which may occur as a result of the Deepwater Horizon Incident.
The legislative and regulatory response to the Deepwater Horizon Incident is ongoing and may not be limited to the US. In 2010, the US Department of the Interior issued new rules designed to improve drilling and workplace safety, and various Congressional committees began pursuing legislation to regulate drilling activities and increase liability. In January 2011, the President’s National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling released its report, recommending that the federal government require additional regulation and an increase in liability caps. The European Commission has recommended that new legislation be enacted to enhance the safety of offshore oil and gas activities.
Additional regulatory review, slower permitting processes and increased oversight will likely result in longer development cycle time for our deepwater Gulf of Mexico projects. Cycle time is the length of time it takes for a project to progress from first discovery to first production, and longer development cycle times could result in lower rates of return on our investments.
Increased regulation could also have a negative impact on our planned deepwater Gulf of Mexico exploration program. A significant delay or cancellation of planned exploratory activities will reduce our longer term ability to replace reserves, resulting in a negative impact on production over time. To the extent current exploration activities are significantly delayed, a gap could occur in our long-term production profile with a negative impact on our operating results and cash flows.
Additional legislation or regulation is being discussed which could require each company doing business in the Gulf of Mexico to establish and maintain a higher level of financial responsibility under its Certificate of Financial Responsibility (COFR), a certificate required by the Oil Pollution Act of 1990 which evidences a company’s financial ability to pay for cleanup and damages caused by oil spills. There have also been discussions regarding the establishment of a new industry mutual fund in which companies would be required to participate and which would be available to pay for consequential damages arising from an oil spill. These and/or other legislative or regulatory changes could require us to maintain a certain level of financial strength and may reduce our financial flexibility.
We are monitoring legislative and regulatory developments; however, the full legislative and regulatory response to the Incident is not yet known. An expansion of safety and performance regulations or an increase in liability for drilling activities may have one or more of the following impacts on our business:
·
increase the costs of drilling exploratory and development wells;
·
cause delays in, or preclude, the development of our projects in the deepwater Gulf of Mexico or other locations;
·
result in higher operating costs;
·
divert cash from our capital investments program in order to maintain minimum financial levels or participate in a mandatory industry mutual clean-up fund;
·
increase or remove liability caps for claims of damages from oil spills; and
·
limit our ability to obtain additional insurance coverage, at a level that balances the cost of insurance and our desired rates of return, to protect against any increase in liability.
Any of the above operating or financial factors may result in a reduction of our cash flows, profitability, and the fair value of our properties or reduce our financial flexibility. Because we strive to achieve certain levels of return on our projects, an increase in financial responsibility requirements could result in certain of our planned projects becoming uneconomic.
Derivatives regulation included in current financial reform legislation could impede our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices and interest rates.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), which was passed by Congress and signed into law in July 2010, contains significant derivatives regulation, including a requirement that certain transactions be cleared on exchanges and a requirement to post cash collateral (commonly referred to as “margin”) for such transactions. The Act provides for a potential exception from these clearing and cash collateral requirements for commercial end-users and it includes a number of defined terms that will be used in determining how this exception applies to particular derivative transactions and the parties to those transactions. The Act requires the Commodities Futures and Trading Commission (CFTC) to promulgate rules to define these terms. The CFTC is in the process of proposing definitions to determine which entities will face additional requirements for clearing, trading and posting of margin. However, the process is incomplete and we are unsure how these definitions will apply to us.
We use crude oil and natural gas derivative instruments with respect to a portion of our expected production in order to reduce commodity price uncertainty and enhance the predictability of cash flows relating to the marketing of our production and in support of our capital investment program. We use interest rate derivative instruments to minimize the impact of interest rate fluctuations associated with anticipated debt issuances. As commodity prices increase or interest rates decrease, our derivative liability positions increase; however, none of our current derivative contracts require the posting of margin or similar cash collateral when there are changes in the underlying commodity prices or interest rates that are referred to in these contracts.
Depending on the rules and definitions adopted by the CFTC, we could be required to post significant amounts of cash collateral with our dealer counterparties for our derivative transactions. A sudden, unexpected margin call triggered by rising commodity prices or falling interest rates would have an immediate negative impact on our business plan, forcing us to divert capital from exploration, development and production activities. Requirements to post cash collateral could not only cause significant liquidity issues by reducing our flexibility in using our cash and other sources of funds such as our credit facility, but could also cause us to incur additional debt. In addition, a requirement for our counterparties to post cash collateral would likely result in additional costs being passed on to us, thereby decreasing the effectiveness of our hedges and our profitability.
We face various risks associated with the trend toward increased activism against oil and gas exploration and development activities.
Opposition toward oil and gas drilling and development activity has been growing globally and is particularly pronounced in OECD countries which include the US, the UK and Israel. Companies in the oil and gas industry, such as us, are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, human rights, environmental compliance and business practices. Anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain projects such as offshore drilling or the development of oil shale. For example, environmental activists have recently challenged decisions to grant air-quality permits for offshore drilling and have advocated for increased regulations on shale drilling in the US.
Future activist efforts could result in the following:
·
delay or denial of drilling permits;
·
shortening of lease terms or reduction in lease size;
·
restrictions on installation or operation of gathering or processing facilities;
·
restrictions on the use of certain operating practices, such as hydraulic fracturing;
·
legal challenges or lawsuits;
·
damaging publicity about us;
·
increased costs of doing business;
·
reduction in demand for our products; and
·
other adverse affects on our ability to develop our properties and expand production.
Our need to incur costs associated with responding to these initiatives or complying with any resulting new legal or regulatory requirements resulting from these activities that are substantial and not adequately provided for, could have a material adverse effect on our business, financial condition and results of operations.
Slower economic growth rates in the US and other countries in which we operate may materially adversely impact our operating results.
The US and other economies are recovering from a global financial crisis and recession which began in 2008. Growth has resumed, but has been modest and at an unsteady rate. There are likely to be significant long-term effects resulting from the financial crisis and recession, including a future global economic growth rate that is slower than what was experienced in the years leading up to the crisis, and more volatility may occur before a sustainable, yet lower, growth rate is achieved.
In addition, the OECD has encouraged countries with large federal budget deficits, such as the US, to initiate deficit reduction measures. Such measures, if they are undertaken too rapidly, could further undermine economic recovery and slow growth by reducing demand.
Global economic growth drives demand for energy from all sources, including fossil fuels. A lower future economic growth rate is likely to result in decreased demand growth for our crude oil and natural gas production. A decrease in demand, excluding changes in other factors, could potentially result in lower commodity prices, which would reduce our cash flows from operations and our profitability.
Failure to fund continued capital expenditures could adversely affect our properties.
Our exploration, development, and acquisition activities require substantial capital expenditures especially in the case of our major development projects, such as the Central DJ Basin, Galapagos in the deepwater Gulf of Mexico, Aseng and Alen, offshore Equatorial Guinea, and Tamar, offshore Israel. Significant capital investments on these major development projects are estimated to total approximately $1.1 billion in 2011. However, first production from the major offshore projects is not expected to occur until Galapagos begins to produce in late 2011 or early 2012.
Historically, we have funded our capital expenditures through a combination of cash flows from operations, our revolving bank credit facility and debt issuances. Future cash flows are subject to a number of variables, such as the level of production from existing wells, prices of crude oil and natural gas, and our success in finding, developing and producing new reserves. If revenues were to decrease as a result of lower crude oil and natural gas prices or decreased production, and our access to debt or capital were limited, we would have a reduced ability to replace our reserves, resulting in lower production over time. If our cash flows from operations are not sufficient to meet our obligations and fund our capital investment program, we may not be able to access capital markets on an economic basis to meet these requirements. If we are not able to fund our capital expenditures, our ownership interests in some properties might be reduced or forfeited as a result.
Commodity and interest rate hedging transactions may limit our potential gains.
In order to reduce commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil and natural gas, we enter into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production. Our hedges, consisting of a series of contracts, are limited in duration, usually for periods of one to three years. While intended to reduce the effects of volatile crude oil and natural gas prices, such transactions may limit our potential gains if crude oil and natural gas prices rise over the price established by the arrangements.
Global commodity prices fluctuated significantly in 2010. Such volatility challenges our ability to forecast and, as a result, it may become more difficult to manage our hedging program. In trying to manage our exposure to commodity price risk, we may end up hedging too much or too little, depending upon how our crude oil or natural gas volumes and our production mix fluctuate in the future. In addition, hedging transactions may expose us to the risk of financial loss in certain circumstances, including instances in which our production is less than expected; there is a widening of price basis differentials between delivery points for our production and the delivery point assumed in the hedge arrangement; the counterparties to our futures contracts fail to perform under the contracts; or a sudden unexpected event materially impacts crude oil or natural gas prices.
We use interest rate derivative instruments to minimize the impact of interest rate fluctuations associated with anticipated debt issuances. Interest rates are also variable and we may also end up hedging too much or too little when we attempt to effectively fix cash flows related to interest payments on an anticipated debt issuance.
We cannot assure that our hedging transactions will reduce the risk or minimize the effect of volatility in crude oil or natural gas prices or interest rates. See Item 8. Financial Statements and Supplementary Data - Note 10. Derivative Instruments and Hedging Activities.
We are exposed to counterparty credit risk as a result of our receivables, hedging transactions and cash investments.
We are exposed to risk of financial loss from trade, joint venture, and other receivables. We sell our crude oil, natural gas and NGLs to a variety of purchasers. In addition, we are the operator on a majority of our large joint venture development projects. As operator of the joint ventures, we pay joint venture expenses and make cash calls on our nonoperating partners for their respective shares of joint venture costs. These projects are capital cost intensive and, in some cases, a nonoperating partner may experience a delay in obtaining financing for its share of the joint venture costs.
In addition, some of our purchasers and joint venture partners are not as creditworthy as we are and may experience credit downgrades or liquidity problems. For example, the international credit rating of IEC, our largest natural gas purchaser in Israel, was recently downgraded. Counterparty liquidity problems could result in a delay in our receiving proceeds from commodity sales or reimbursement of joint venture costs. Credit enhancements have been obtained from some parties in the way of parental guarantees or letters of credit, including our largest crude oil purchaser; however, not all of our trade credit is protected through guarantees or credit support. Nonperformance by a trade creditor or joint venture partner could result in significant financial losses.
Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a contract. During periods of falling commodity prices, our hedge receivable positions increase, which increases our counterparty exposure. We conduct our hedging activities with a diverse group of highly-rated major banks and market participants and control our level of financial exposure. We use master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be “net settled” at the time of election. “Net settlement” refers to a process by which all transactions between counterparties are resolved into a single amount owed by one party to the other.
We had $1.1 billion in cash and cash equivalents, a majority of which was invested in money market funds and short-term deposits with major financial institutions at December 31, 2010. We monitor the creditworthiness of the banks and financial institutions with which we invest and review the securities underlying our investment accounts. However, we are unable to predict sudden changes in solvency of our financial institutions.
We monitor the creditworthiness of our trade creditors, joint venture partners, hedging counterparties and financial institutions on an ongoing basis. However, if one of them were to experience a sudden change in liquidity, it could impair their ability to perform under the terms of our contracts. We are unable to predict sudden changes in creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited and we could incur significant financial losses.
Offshore development involves significant financial risks.
We have ongoing major development projects as well as current or planned exploration activities in the deepwater Gulf of Mexico, offshore West Africa and offshore Eastern Mediterranean. In these areas, there may be limited availability of suitable drilling rigs, drilling equipment, support vessels, and qualified operating personnel. Deepwater drilling rigs are typically subject to long-term contracts. In addition, frontier areas lack the physical and oilfield service infrastructure necessary for production and transportation. As a result, development of an offshore discovery, such as Tamar, Aseng, Alen, or Gunflint, may be a lengthy process and require substantial capital investment.
Difficulty and delays in consistently obtaining drilling rigs and other equipment and services at acceptable rates may lead to project delay, increased costs, and/or inability to forecast production, which could prevent the realization of our targeted return on capital or lead to unexpected future losses.
Due to the current lack of drilling activity in the deepwater Gulf of Mexico caused by the regulatory response to the Deepwater Horizon Incident, drilling, equipment and oilfield services companies may decide to exit the Gulf of Mexico making such services even less available and/or more expensive once drilling activities are allowed to resume.
We may be unable to make attractive acquisitions, successfully integrate acquired businesses and/or assets, or adjust to the effects of divestitures, causing a disruption to our business.
One aspect of our business strategy calls for acquisitions of businesses and assets that complement or expand our current business, such as our Central DJ Basin asset acquisition in 2010. This may present greater risks for us than those faced by peer companies that do not consider acquisitions as a part of their business strategy. We cannot provide assurance that we will be able to identify attractive acquisition opportunities. Even if we do identify attractive opportunities, we cannot provide assurance that we will be able to complete the acquisition due to capital market constraints, even if such capital is available on commercially acceptable terms. If we acquire an additional business, we could have difficulty integrating its operations, systems, management and other personnel and technology with our own, or could assume unidentified or unforeseeable liabilities, resulting in a loss of value.
We maintain an ongoing portfolio management program which includes sales of non-core, non-strategic assets, such as the sales of non-core onshore US assets in 2010 and our interest in Argentina in 2008. These transactions can also result in changes in operations, systems, or management and other personnel.
Organizational modifications due to acquisitions, divestitures or other portfolio management actions, or other strategic changes can alter the risk and control environments, disrupt ongoing business, distract management and employees, increase expenses and adversely affect results of operations. Even if these challenges can be dealt with successfully, we cannot provide assurance that the anticipated benefits of any acquisition, divestiture or other strategic change would be realized.
Estimates of crude oil and natural gas reserves are not precise.
There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and their value, including factors that are beyond our control. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. In accordance with the SEC’s revisions to rules for oil and gas reserves reporting, which we implemented effective December 31, 2009, our reserves estimates are based on 12-month average prices; therefore, reserves quantities will change when actual prices increase or decrease. The reserves estimates depend on a number of factors and assumptions that may vary considerably from actual results, including:
·
historical production from the area compared with production from other areas;
·
the assumed effects of regulations by governmental agencies, including the impact of the SEC’s revisions to oil and gas company reserves reporting requirements;
·
assumptions concerning future crude oil and natural gas prices;
·
anticipated development cycle time;
·
future development costs;
·
future operating costs;
·
severance and excise taxes; and
·
workover and remedial costs.
For these reasons, estimates of the economically recoverable quantities of crude oil and natural gas attributable to any particular group of properties, classifications of those reserves based on risk of recovery and estimates of the future net cash flows expected from them prepared by different petroleum engineers or by the same petroleum engineers but at different times may vary substantially. Accordingly, reserves estimates may be subject to positive or negative revisions, and actual production, revenue and expenditures with respect to our reserves likely will vary, possibly materially, from estimates.
Additionally, because some of our reserves estimates are calculated using volumetric analysis, those estimates are less reliable than the estimates based on a lengthy production history. Volumetric analysis involves estimating the volume of a reservoir based on the net feet of pay of the structure and an estimation of the area covered by the structure. In addition, realization or recognition of proved undeveloped reserves will depend on our development schedule and plans. A change in future development plans for proved undeveloped reserves could cause the discontinuation of the classification of these reserves as proved.
Exploration, development and production risks and natural disasters could result in liability exposure or the loss of production and revenues.
Our operations are subject to hazards and risks inherent in the drilling, production and transportation of crude oil and natural gas, including:
·
injuries and/or deaths of employees, supplier personnel, or other individuals;
·
pipeline ruptures and spills;
·
fires;
·
explosions, blowouts and well cratering;
·
equipment malfunctions;
·
formations with abnormal pressures;
·
release of pollutants;
·
hurricanes, such as Gustav and Ike in 2008, which could affect our operations in areas such as the Gulf Coast and deepwater Gulf of Mexico, and cyclones, which could affect our operations offshore China; and
·
other natural disasters.
Any of these can result in loss of hydrocarbons, environmental pollution and other damage to our properties or the properties of others.
Exploratory drilling may not result in the discovery of commercially productive reservoirs.
We depend on exploration success to provide growth in production and reserves and are planning an active exploratory drilling program in 2011. Exploratory drilling requires significant capital investment and is not always successful. For example, we incurred dry hole expense in 2010 because the Double Mountain exploratory well in the deepwater Gulf of Mexico found noncommercial quantities of hydrocarbons.
Exploratory dry holes can occur because seismic data and other technologies we use to determine potential exploratory drilling locations do not allow us to know conclusively prior to drilling a well that crude oil or natural gas is present or may be produced economically.
Exploratory drilling activities may be curtailed, delayed or canceled, resulting in significant exploration expense, as a result of a variety of factors, including:
·
title problems;
·
compliance with environmental and other governmental requirements;
·
increases in the cost of, or shortages or delays in the availability of, drilling rigs, equipment and qualified personnel;
·
unexpected drilling conditions;
·
pressure or other irregularities in formations;
·
equipment failures or accidents; and
·
adverse weather conditions.
In addition, companies seeking new reserves often face more difficult environments, such as oil sands, deepwater, or ultra-deepwater, and often need to develop or invest in new technologies. This increases cost as well as drilling risk.
For certain capital-intensive deepwater Gulf of Mexico or international projects, it may take several years to evaluate the future potential of an exploration well and make a determination of its economic viability, resulting in delays in cash flows from production start-up and a lower return on our investment.
Due to our level of planned exploration activity, future dry hole cost could be significant and have a negative impact on our results of operations and cash flows.
Development drilling may not result in commercially productive quantities of oil and gas reserves.
Our exploration success has provided us with a number of major development projects on which we are moving forward. We depend on these projects to provide long life, sustained cash flows after investment and attractive financial returns. However, development drilling is not always successful and the profitability of development projects may change over time.
For example, in new development areas such as Gunflint or Tamar, available data may not allow us to completely know the extent of the reservoir or choose the best locations for drilling development wells. Therefore, a development well we drill may be a dry hole or result in noncommercial quantities of hydrocarbons. Projects in frontier areas may require the development of special technology for development drilling or well completion and we may not have the knowledge or expertise in applying new technology. Our efforts may result in a dry hole or a well that finds noncommercial quantities of hydrocarbons. Development drilling has the same legal and physical risks as exploratory drilling, described above, which can result in the drilling of a development dry hole or the incurrence of substantial development costs without a corresponding increase in proved reserves.
All costs of development drilling and other development activities are capitalized, even if the activities do not result in commercially productive quantities of oil and gas. This puts a property at higher risk for future impairment if commodity prices decrease or operating or development costs increase.
Even if development drilling is successful and we find commercial quantities of reserves, we may encounter difficulties or delays in completing development wells. For example, in areas of high activity and demand in which we concentrate, such as the Rocky Mountains, we may experience delays in obtaining well completion rigs and services. Frontier areas may not have adequate infrastructure for gathering, processing or transportation, and production may be delayed until they are constructed. This results in a decrease in current cash flows and reduces the return on our investment.
Costs of drilling, completing and operating wells are often uncertain, and cost factors can adversely affect the economics of a project. Even a development project with significant reserves that is currently economic can become uneconomic in the future if commodity prices decrease or operating or development costs increase, resulting in impairment charges and a negative impact on our results of operations.
The magnitude of the Leviathan discovery will present financial and technical challenges for us due to the large-scale development requirements.
In December 2010, we announced a significant natural gas discovery at the Leviathan prospect, offshore Israel. The Leviathan field is the largest discovery in our history and we believe it is the largest deepwater natural gas discovery in the last decade. As a result of the combined discoveries of Tamar and Leviathan, Israel now faces a potential surplus of natural gas.
Development options for Leviathan include export of surplus natural gas to Europe or Asia through development of LNG terminals or underwater pipelines. Each of these development options would require a multi-billion dollar investment and take several years to complete. We have a nearly 40% working interest in Leviathan. As a result, we will likely seek partners to provide technical and financial support as well as midstream and downstream expertise.
In addition, we must resolve with the Israeli government Leviathan’s treatment as a result of the proposed changes in Israel’s fiscal regime, discussed above, that could potentially reduce the anticipated profitability of the project.
Failure to execute a successful development scenario for Leviathan could result in damage to our reputation, limitations on our growth and negative effects on our operating results.
The unavailability or high cost of drilling rigs, equipment, supplies, other oil field services and personnel could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.
Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies and oilfield services. There may also be a shortage of trained and experienced personnel. During these periods, the costs of such items are substantially greater and their availability may be limited, particularly in areas of high activity and demand in which we concentrate, such as the Rocky Mountains, deepwater Gulf of Mexico, prior to the Deepwater Moratorium, and in some international locations that typically have limited availability of equipment and personnel, such as West Africa and the Eastern Mediterranean.
During periods of increasing levels of industry exploration and production, such as we currently are experiencing in the Rocky Mountains Niobrara formation, the demand for, and cost of, drilling rigs and oilfield services increases. In addition, regulatory changes in response to the Deepwater Horizon Incident may also result in higher costs for these rigs and services. As a result, drilling rigs and oilfield services may not be available at rates that provide a satisfactory return on our investment. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Contractual Obligations for additional information on drilling rig contracts.
We face significant competition and many of our competitors have resources in excess of our available resources.
We operate in the highly competitive areas of crude oil and natural gas exploration, exploitation, acquisition and production. We face intense competition from:
·
large multi-national, integrated oil companies;
·
state-controlled national oil companies;
·
US independent oil and gas companies;
·
service companies engaging in exploration and production activities; and
·
private oil and gas equity funds.
We face competition in a number of areas such as:
·
seeking to acquire desirable producing properties or new leases for future exploration;
·
marketing our crude oil and natural gas production;
·
seeking to acquire the equipment and expertise necessary to operate and develop properties; and
·
attracting and retaining employees with certain skills.
Many of our competitors have financial and other resources substantially in excess of those available to us. Such companies may be able to pay more for seismic and lease rights on crude oil and natural gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. This highly competitive environment could have an adverse impact on our business.
Indebtedness may limit our liquidity and financial flexibility.
As of December 31, 2010, we had long-term indebtedness of $2.3 billion (including an FPSO lease obligation of $295 million), with $350 million drawn under our bank credit facility. Our indebtedness represented 25% of our total book capitalization at December 31, 2010.
Our indebtedness affects our operations in several ways, including the following:
·
a portion of our cash flows from operating activities must be used to service our indebtedness and is not available for other purposes;
·
we may be at a competitive disadvantage as compared to similar companies that have less debt;
·
a covenant contained in our revolving credit facility provides that our total debt to capitalization ratio (as defined) will not exceed 60% at any time, which may limit our ability to borrow additional funds, thereby affecting our flexibility in planning for, and reacting to, changes in the economy and in our industry;
·
a covenant contained in our revolving credit facility restricts the payment of dividends on our common stock if, after giving effect thereto, an Event of Default shall have occurred and be continuing or been caused thereby;
·
additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes may have higher costs and more restrictive covenants;
·
changes in the credit ratings of our debt may negatively affect the cost, terms, conditions and/or availability of future financing, and lower ratings will increase the interest rate and fees we pay on our revolving credit facility; and
·
we may be more vulnerable to general adverse economic and industry conditions.
We may incur additional debt in order to fund our exploration, development and acquisition activities. A higher level of indebtedness increases the risk that our liquidity may deteriorate and we default on our debt obligations. Our ability to meet our debt obligations and service our debt depends on future performance. General economic conditions, crude oil and natural gas prices and financial, business and other factors will affect our operations and our future performance. Many of these factors are beyond our control and we may not be able to generate sufficient cash flow to pay the interest on our debt, and future working capital, borrowings and equity financing may not be available to pay or refinance such debt. See Item 8. Financial Statements and Supplementary Data - Note 12. Long-Term Debt.
The marketability of our Rocky Mountain and deepwater Gulf of Mexico production is dependent upon transportation and processing facilities over which we may have no control.
The marketability of our production from the Rocky Mountain area and the deepwater Gulf of Mexico depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems and processing facilities. We deliver crude oil and natural gas produced from these areas through gathering systems and pipelines that we do not own. The lack of availability of capacity on these systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Although we have some contractual control over the transportation of our production through firm transportation arrangements, third-party systems and facilities may be temporarily unavailable due to market conditions or mechanical or other reasons, including adverse weather conditions, such as occurred when our deepwater Gulf of Mexico Ticonderoga development became shut in as a result of hurricane damage to third party processing and pipeline facilities in 2008.
Third-party systems and facilities may not be available to us in the future at a price that is acceptable to us. Any significant change in market factors or other conditions affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities, could delay production, thereby harming our business and, in turn, our financial condition, results of operations and cash flows.
Our operations and investment in the Machala power plant in Ecuador have been adversely affected by the Ecuadorian government’s termination of our PSC for Block 3.
A newly enacted hydrocarbon law in Ecuador aims to change current production-sharing arrangements into service contracts and provided for renegotiation of certain contracts by November 23, 2010. It also allows the Ecuadorian government to nationalize oil and gas fields if a private operator does not comply with local laws.
A service contract on Block 3 (100% working interest) was not negotiated, and the government of Ecuador terminated the Block 3 PSC with our subsidiary, EDC Ecuador Ltd. on November 25, 2010. We are continuing to work with the government of Ecuador to resolve this matter. However, we are uncertain as to the potential outcome of this matter, resolution of which could ultimately lead to a reduction in the value of the receivable or our investments in Ecuador which, as of December 31, 2010, had a net book value of approximately $66 million.
Our operations require us to comply with a number of US and international laws and regulations, violations of which could result in substantial fines or sanctions and/or impair our ability to do business.
Our operations require us to comply with a number of US and international laws and regulations, including those involving anti-corruption. For example, the US Foreign Corrupt Practices Act (FCPA) and similar laws and regulations enacted or promulgated by countries pursuant to the 1997 Organization for Economic Co-operation and Development Anti-Bribery Convention generally prohibit improper payments to foreign officials for the purpose of obtaining or keeping business. The scope and enforcement of anti-corruption laws and regulations may vary. The recently-enacted UK Bribery Act of 2010, which was originally scheduled to become effective in April 2011, is broader in scope than the FCPA and applies to public and private sector corruption and contains no facilitating payments exception. Violations of such laws or regulations could result in substantial civil or criminal fines or sanctions. Actual or alleged violations could damage our reputation, be expensive to defend, and impair our ability to do business.
We have merged with or acquired other companies in the past. Mergers of businesses often require the approval of certain government or regulatory agencies and such approval could contain terms, conditions, or restrictions that would be detrimental to our business after a merger. US anti-trust laws require waiting periods and even after completion of a merger, governmental authorities could seek to block or challenge a merger as they deem necessary or desirable in the public interest. Prevention of a merger by anti-trust laws could impair our ability to do business.
Increased regulation of business practices could result in higher operating costs.
The current trend is toward increased regulation of business practices and additional reporting requirements. For example the EPA issued the Final Mandatory Reporting of Greenhouse Gases Rule. We are subject to these new reporting requirements Under Subpart W, Petroleum and Natural Gas Systems. Compliance with these and other new rules results in additional effort on the part of our personnel. In addition, other legislation may be enacted in order to restrict GHG emissions in the US or regulate hydraulic fracturing under the Safe Drinking Water Act.
The Dodd-Frank Act requires both the CFTC and the SEC to enact numerous rules and regulations, some of which could impact our business practices and negatively affect our financial flexibility or place additional reporting burdens on us.
Although it is not possible at this time to predict the final outcome of these rule-making and standard-setting efforts, it is likely that the magnitude of these changes will require an unprecedented compliance effort on our part, could divert management’s attention, and may require significant expenditures, as well as place additional burden on our internal financial controls.
We operate in a litigious environment.
We operate in the US and other countries which have proven to be unusually litigious environments. Most oil and gas companies, such as us, are involved in various legal proceedings, such as title, royalty or contractual disputes, in the ordinary course of business. We defend ourselves vigorously in all such matters.
Because we maintain a diversified portfolio that is balanced between US and international projects, the complexity and types of legal procedures with which we may become involved may vary, and we could incur significant legal and support expenses in different jurisdictions. If we are not able to successfully defend ourselves, there could be a delay or even halt in our exploration, development or production activities or other business plans, resulting in a reduction in reserves, loss of production and reduced cash flows. Legal proceedings could result in a substantial liability. In addition, legal proceedings distract management and other personnel from their primary responsibilities.
A change in US energy policy can have a significant impact on our operations and profitability.
US energy policy and laws and regulations could change quickly. Currently, substantial uncertainty exists about the nature of potential rules and regulations that could impact the sources and uses of energy in the US. We design our exploration and development strategy and related capital investment programs years in advance. As a result, we are hindered in our ability to plan, invest and respond to potential changes in our business. This can result in a reduction of our cash flows and profitability to the extent we are unable to respond to sudden or significant changes in our operating environment due to changes in US energy policy.
The adoption of GHG emission or other environmental legislation could result in increased operating costs, create delays in our obtaining air pollution permits for new or modified facilities, and reduce demand for the crude oil and natural gas we produce.
In recent years, each house of Congress has considered legislation to address GHG emissions, such as the American Clean Energy and Security Act of 2009, also known as the Waxman-Markey Bill, passed by the House of Representatives, and The Clean Energy Jobs and American Power Act, or the Boxer-Kerry Bill, introduced to the Senate. Future legislation could include mandatory carbon dioxide emissions goals, measures to encourage use of renewable energy over fossil-based fuels, higher penalties and fines for violations of various environmental laws, or other regulations designed to curb GHG emissions.
One measure considered frequently has been the establishment of a “cap and trade” system for restricting GHG emissions in the US. Under such system, certain sources of GHG emissions would be required to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. The number of emission allowances issued each year would decline as necessary to meet overall emission reduction goals. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly.
The EPA has issued GHG monitoring and reporting regulations that went into effect January 1, 2010, and require reporting by regulated facilities by March 2011 and annually thereafter. Beyond measuring and reporting, the EPA issued an “Endangerment Finding” under section 202(a) of the Clean Air Act, concluding GHG pollution threatens the public health and welfare of current and future generations. The EPA has issued final regulations requiring petroleum and natural gas operators meeting a certain emissions threshold to report their GHG emissions to the EPA (Subpart W). The EPA has indicated that it will use data collected through the reporting rules to decide whether to promulgate future GHG limits.
Since approximately 61% of our total 2010 crude oil and NGL production and 51% of our total 2010 natural gas production derive from the US, any laws or regulations that may be adopted to restrict or reduce emissions of US GHGs could require us to incur higher operating costs, increase our development cycle time, and have an adverse effect on demand for the crude oil and natural gas we produce. In addition, we could be required to make significant capital expenditures to comply with new environmental legislation, which would cause us to divert capital from exploration, development and production activities.
Federal or state hydraulic fracturing legislation could increase our costs and restrict our access to oil and gas reserves.
Hydraulic fracturing involves the injection of a mixture, comprised primarily of water and sand, and a small amount of chemicals, under pressure into rock formations to stimulate production. We find that the use of hydraulic fracturing is necessary to produce commercial quantities of crude oil and natural gas from many reservoirs, including Wattenberg, which represented 25% of our 2010 consolidated sales volumes.
Hydraulic fracturing using fluids other than diesel is currently exempt from regulation under the federal Safe Drinking Water Act, but opponents of hydraulic fracturing have called for further study of the technique’s environmental effects and, in some cases, a moratorium on the use of the technique. Several proposals have been submitted to Congress that, if implemented, would subject all hydraulic fracturing to regulation under the Safe Drinking Water Act. Further, the EPA’s Office of Research and Development (ORD) is conducting a scientific study to investigate the possible relationships between hydraulic fracturing and drinking water. The ORD expects to initiate the study in 2011 and have the initial study results available by late 2012.
In addition, some states have taken actions concerning hydraulic fracturing. In October 2010, the Governor of Pennsylvania issued a moratorium on new natural gas development on state forest lands. The New York Legislature passed a bill imposing a moratorium on issuance of new permits for the drilling of wells that use hydraulic fracturing for the purpose of stimulating natural gas or oil in the Marcellus Shale formation, but the Governor of New York subsequently vetoed the bill. On December 13, 2010, however, the Governor of New York issued Executive Order No. 41, which prohibits issuance of state permits for high-volume hydraulic fracturing combined with horizontal drilling until the New York Department of Environmental Conservation completes its Final Supplemental Generic Environmental Impact Statement (SGEIS). Under the order, the New York Department of Environmental Conservation must publish a revised draft SGEIS on or about June 1, 2011 and allow a public comment period of at least 30 days. Accordingly, this moratorium is expected to last until at least July 1, 2011. Other states could take similar action.
Several states have considered, or are considering, legislation or regulations that would require disclosure of chemicals used for hydraulic fracturing. In June 2010, the Wyoming Oil and Gas Conservation Commission passed a rule requiring disclosure of hydraulic fracturing fluid content. In November 2010, the Pennsylvania Environmental Quality Board proposed regulations that would require reporting of the chemicals used in fracturing fluids.
Although it is not possible at this time to predict the final outcome of the ORD’s study or the requirements of any additional federal or state legislation or regulation regarding hydraulic fracturing, any new federal or state restrictions on hydraulic fracturing that may be imposed in areas in which we conduct business could significantly increase our operating, capital and compliance costs as well as delay our ability to develop oil and gas reserves.
Provisions in our Certificate of Incorporation and Delaware law may inhibit a takeover of us.
Under our Certificate of Incorporation, our Board of Directors is authorized to issue shares of our common or preferred stock without approval of our shareholders. Issuance of these shares could make it more difficult to acquire us without the approval of our Board of Directors as more shares would have to be acquired to gain control. In addition, Delaware law imposes restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock. These provisions may deter hostile takeover attempts that could result in an acquisition of us that would have been financially beneficial to our shareholders.
Disclosure Regarding Forward-Looking Statements
This annual report on Form 10-K and the documents incorporated by reference in this report contain forward-looking statements within the meaning of the federal securities laws. Forward-looking statements give our current expectations or forecasts of future events. These forward-looking statements include, among others, the following:
·
our growth strategies;
·
our ability to successfully and economically explore for and develop crude oil and natural gas resources;
·
anticipated trends in our business;
·
our future results of operations;
·
our liquidity and ability to finance our exploration, development, and acquisition activities;
·
market conditions in the oil and gas industry;
·
our ability to make and integrate acquisitions; and
·
the impact of governmental regulation.
Forward-looking statements are typically identified by use of terms such as “may,” “will,” “expect,” “anticipate,” “target,” “estimate” and similar words, although some forward-looking statements may be expressed differently. These forward-looking statements are made based upon management’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements. You should consider carefully the statements under Item 1A. Risk Factors and other sections of this report, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements.
Item 1B.
Item 1B.
Unresolved Staff Comments
None.
Item 3.
Item 3.
Legal Proceedings
We are involved in various legal proceedings in the ordinary course of business. These proceedings are subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters and we do not believe that the ultimate disposition of such proceedings will have a material adverse effect on our financial position, results of operations or cash flows.
Item 4.
Item 4.
[Removed and Reserved]
Executive Officers
The following table sets forth certain information, as of February 10, 2011, with respect to our executive officers.
(1)
Charles D. Davidson was elected Chief Executive Officer of Noble Energy in October 2000 and Chairman of the Board in April 2001, also serving as President until April 2009 (at which time Mr. Stover assumed that position). Prior to October 2000, he served as President and Chief Executive Officer of Vastar Resources, Inc. from March 1997 to September 2000 (Chairman from April 2000) and was a Vastar Director from March 1994 to September 2000. From September 1993 to March 1997, he served as a Senior Vice President of Vastar. From 1972 to October 1993, he held various positions with ARCO.
(2)
David L. Stover was elected President and Chief Operating Officer of Noble Energy in April 2009. Prior thereto, he served as Executive Vice President and Chief Operating Officer of Noble Energy from August 2006 to April 2009. He served as Senior Vice President of North America and Business Development from July 2004 through July 2006, and he served as Noble Energy’s Vice President of Business Development from December 2002 through June 2004. Previous to his employment with Noble Energy, he was employed by BP America, Inc. as Vice President, Gulf of Mexico Shelf from September 2000 to August 2002. Prior to joining BP, Mr. Stover was employed by Vastar, as Area Manager for Gulf of Mexico Shelf from April 1999 to September 2000, and prior thereto, as Area Manager for Oklahoma/Arklatex from January 1994 to April 1999. From 1979 to 1994, he held various positions with ARCO.
(3)
Kenneth M. Fisher was elected a Senior Vice President and Chief Financial Officer of Noble Energy in November 2009. Prior to joining Noble Energy, Mr. Fisher served as Executive Vice President of Finance for Upstream Americas for Shell from July 2009 to November 2009. Prior to his most recent position with Shell, Mr. Fisher served as Director of Strategy & Business Development for Royal Dutch Shell plc in The Hague from August 2007 to July 2009. He served as Executive Vice President of Strategy & Portfolio for Shell’s downstream business in London from January 2005 to August 2007. Mr. Fisher joined Shell in August 2002 and served as Chief Financial Officer for Shell Oil Products U.S. until December 2004. As Chief Financial Officer for Shell Oil Products U.S., he was responsible for U.S. oil products finance, information technology and contracting and procurement activities. Prior to joining Shell, he held positions of increasing responsibility with General Electric (GE) from 1984 to 2002, including Vice President and Chief Financial Officer of the Aircraft Engines Services division and Director of Finance & Business Development of GE’s Asia Pacific plastics business.
(4)
Ted D. Brown was elected a Senior Vice President of Noble Energy in April 2008 and is currently responsible for the Northern Region of our North America division. He served as Vice President, responsible for the same region, from August 2006 to April 2008 and as a vice president of that division since joining us upon our acquisition of Patina Oil & Gas Corporation (Patina) in May 2005. He served as Senior Vice President of Patina from July 2004 to May 2005. Prior thereto he served as Director, Piceance Basin Asset along with Engineering Manager for Williams and Barrett Resources since 1993 and, before that, in various positions with Union Pacific Resources and Amoco Production Company.
(5)
Rodney D. Cook was elected a Senior Vice President of Noble Energy in April 2008 and is currently responsible for the International division. He served as Vice President of Noble Energy, responsible for the Southern Region of our North America division, from August 2006 to April 2008 and as a vice president of that division from May 2005 to August 2006. He served as Manager of our West Africa and Middle East Business Unit from 2002 to 2005. Prior thereto he served as Operations Manager of the International division since 1996. From 1980 to 1996 he held various positions with Noble Energy. Prior to joining Noble Energy in 1980, Mr. Cook held various positions with Texas Pacific Oil.
(6)
Susan M. Cunningham was elected a Senior Vice President of Noble Energy in April 2001 and is currently responsible for our world-wide exploration. Prior to joining Noble Energy, Ms. Cunningham was Texaco’s Vice President of worldwide exploration from April 2000 to March 2001. From 1997 through 1999, she was employed by Statoil, beginning in 1997 as Exploration Manager for deepwater Gulf of Mexico, appointed a Vice President in 1998 and responsible, in 1999, for Statoil’s West Africa exploration efforts. She joined Amoco Canada in 1980 as a geologist and held various exploration and development positions with Amoco Production Company until 1997.
(7)
Arnold J. Johnson was elected Senior Vice President, General Counsel and Secretary of Noble Energy in July 2008. Prior thereto, he served as Vice President, General Counsel and Secretary of Noble Energy since February 2004. He served as Associate General Counsel and Assistant Secretary of Noble Energy from January 2001 through January 2004. Previous to his employment with Noble Energy, he served as Senior Counsel for BP America, Inc. from October 2000 to January 2001. Mr. Johnson held several positions as an attorney for Vastar and ARCO from March 1989 through September 2000, most recently as Assistant General Counsel and Assistant Secretary of Vastar from 1997 through 2000. From 1980 to March 1989, he held various positions with ARCO.
(8)
Andrea Lee Robison was elected to the position of Vice President of Noble Energy in November 2007 and is responsible for Human Resources. Prior thereto, she served as Director of Human Resources from May 2002 through October 2007. Prior to joining us, Ms. Robison was Manager of Human Resources for the Gulf of Mexico Shelf for BP America, Inc. from September 2000 through April 2002. Prior to her employment at BP, she served as HR Director at Vastar from 1997 through September 2000, and Compensation Consultant from January 1994 through 1996. From 1980 through 1993 she held various positions with ARCO.
PART II
Item 5.
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Common Stock Our common stock, $3.33 1/3 par value, is listed and traded on the NYSE under the symbol “NBL.” The declaration and payment of dividends are at the discretion of our Board of Directors and the amount thereof will depend on our results of operations, financial condition, contractual restrictions, cash requirements, future prospects and other factors deemed relevant by the Board of Directors.
Stock Prices and Dividends by Quarters The high and low sales price per share of our common stock on the NYSE and quarterly dividends paid per share were as follows:
On January 25, 2011, the Board of Directors declared a quarterly cash dividend of $0.18 per common share, which will be paid February 22, 2011 to shareholders of record on February 7, 2011.
Transfer Agent and Registrar The transfer agent and registrar for our common stock is Wells Fargo Bank, N.A., 161 North Concord Exchange, South St. Paul, MN, 55075.
Stockholders’ Profile Pursuant to the records of the transfer agent, as of January 27, 2011, the number of holders of record of our common stock was 723.
Stock Repurchases The following table summarizes repurchases of our common stock occurring fourth quarter 2010.
(1)
Stock repurchases during the period related to stock received by us from employees for the payment of withholding taxes due on shares issued under stock-based compensation plans.
Equity Compensation Plan Information The following table summarizes information regarding the number of shares of our common stock that are available for issuance under all of our existing equity compensation plans as of December 31, 2010.
Stock Performance Graph This graph shows our cumulative total shareholder return over the five-year period from December 31, 2005, to December 31, 2010. The graph also shows the cumulative total returns for the same five-year period of the S&P 500 Index, an old peer group of companies and a new peer group of companies. The cumulative total return of the common stock of our old and new peer groups of companies includes the cumulative total return of our common stock.
The companies in the old peer group, which has been adjusted for the effects of industry consolidation, consisted of the following:
Anadarko Petroleum Corp.
Murphy Oil Corp.
Apache Corp.
Newfield Exploration Company
Cabot Oil & Gas Corp.
Noble Energy, Inc.
Chesapeake Energy Corp.
Pioneer Natural Resources Company
Devon Energy Corp.
Plains Exploration and Production Company
EOG Resources, Inc.
Range Resources Corp.
Forest Oil Corp.
Southwestern Energy Company
At December 31, 2010 (after certain industry consolidation during 2010 and pursuant to a resolution adopted by the Compensation, Benefits and Stock Option Committee of the Board of Directors), our peer group of companies consisted of the following:
Anadarko Petroleum Corp.
Newfield Exploration Company
Apache Corp.
Noble Energy, Inc.
Cabot Oil & Gas Corp.
Pioneer Natural Resources Company
Chesapeake Energy Corp.
Plains Exploration and Production Company
Devon Energy Corp.
Range Resources Corp.
EOG Resources, Inc.
Southwestern Energy Company
Forest Oil Corp.
Talisman Energy Inc.
Murphy Oil Corp.
The comparison assumes $100 was invested on December 31, 2005, in our common stock, in the S&P 500 Index and in our old and new peer groups and assumes that all of the dividends were reinvested.
Item 6.
Item 6.
Selected Financial Data
(1)
Prices include effects of oil and gas hedging activities. See Item 8. Financial Statements and Supplementary Data - Note 10. Derivative Instruments and Hedging Activities.
(2)
Prior to 2008, US NGL sales volumes were included with natural gas volumes. Effective in 2008 we began reporting US NGLs separately where we have the right to take title, which lowered the comparative natural gas sales volumes for 2008.
Item 7.
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
We are a leading independent energy company engaged in worldwide oil and gas exploration and production. The accompanying consolidated financial statements, including the notes thereto, contain detailed information that should be read in conjunction with the following discussion.
EXECUTIVE OVERVIEW
We are a worldwide producer of crude oil and natural gas. Our strategy is to achieve growth in earnings and cash flows through the continued expansion of a high quality portfolio of producing assets that is balanced and diversified among US and international projects, crude oil and natural gas, and near, medium and long-term opportunities.
Strategy We seek to achieve growth in earnings and cash flow through exploration success and the development of a high quality, diverse portfolio of assets that is balanced between US and international projects, while maintaining a strong balance sheet and ample liquidity levels. We primarily focus on organic growth from exploration and development drilling, and we augment that with a strong, opportunistic new business development (mergers and acquisition) capability and ongoing portfolio management. We concentrate on basins or plays where we have strategic competitive advantage and which we believe offer superior returns.
Key operating areas are the onshore US, deepwater Gulf of Mexico, offshore West Africa and the Eastern Mediterranean. We actively manage our portfolio with periodic divestments to “high grade” the portfolio. As a result of our continued exploration success, we are focused on the execution of a significant portfolio of major development projects that will deliver visible growth including: among others, the Central DJ Basin, onshore US; Galapagos and Gunflint in the deepwater Gulf of Mexico; Aseng and Alen, offshore West Africa; and Tamar, offshore Israel. Our major development projects typically offer long life, sustained cash flows after investment and attractive financial returns. We maintain a balanced portfolio between US and international assets and strive to maintain a balanced geographic and political risk profile. We also maintain a geographical diversity of production mix among crude oil, US natural gas, and international natural gas.
Financial and Operating Results During 2010, the US and other economies resumed growth which had been interrupted by the 2008 global financial crisis and associated recession. Although growth has resumed, it has been modest and at an unsteady rate. Commodity prices were volatile, but crude oil prices showed improvement from increased demand. Higher crude oil prices combined with higher sales volumes resulted in significant increases in our net income and cash flows for 2010. In addition, we increased our capital spending program over our 2009 level, advanced our major development projects, and completed a significant property acquisition, while maintaining a strong balance sheet and ample liquidity levels.
Our 2010 financial results included the following:
·
net income of $725 million as compared with a net loss of $131 million for 2009;
·
net gain on asset sales of $113 million as compared with $22 million for 2009;
·
asset impairment charges of $144 million as compared with $604 million for 2009;
·
gain on commodity derivative instruments of $157 million (including unrealized mark-to-market gain of $70 million) as compared with $110 million loss on commodity derivative instruments (including unrealized mark-to-market loss of $606 million) for 2009;
·
diluted earnings per share of $4.10, as compared with diluted loss per share of $0.75 for 2009;
·
cash flows provided by operating activities of $1.9 billion, as compared with $1.5 billion in 2009;
·
capital spending of $2.3 billion (including $458 million for the Central DJ Basin asset acquisition) as compared with $1.3 billion in 2009;
·
refocus of our development activities toward more liquids-rich areas, as opposed to dry gas areas, in response to depressed US natural gas prices, resulting in an increase in our liquids production as compared with 2009;
·
proceeds from property sales of $564 million as compared with $3 million in 2009;
·
ending cash and cash equivalents balance of $1.1 billion at December 31, 2010, as compared with $1 billion at December 31, 2009;
·
net decrease of $32 million principal amount of debt, excluding $266 increase in FPSO accrual, from December 31, 2009;
·
total liquidity of $2.8 billion at December 31, 2010, consisting of year-end cash balance plus funds available under credit facility, as compared with $2.7 billion at December 31, 2009; and
·
year-end ratio of debt-to-book capital of 25% (including FPSO lease accrual), unchanged from December 31, 2009.
Significant operational highlights included the following:
Overall
·
recorded proved reserves of nearly 1.1 billion Boe at December 31, 2010, a 33% increase from year-end 2009; and
·
a 3% increase in total sales volumes as compared with 2009.
Onshore United States
·
Central DJ Basin asset acquisition which enhanced our largest onshore US property in Wattenberg;
·
increased Central DJ Basin position to over 830,000 net acres;
·
drilled and completed 21 horizontal wells in the Central DJ Basin Niobrara formation;
·
increased Wattenberg production volumes to a record 54.2 MBoe/d; and
·
closed on the sale of certain Mid-Continent and Illinois Basin assets for $552 million.
Deepwater Gulf of Mexico
·
successfully adjusted our Gulf of Mexico business plan in response to the Deepwater Moratorium;
·
finalized well completion work at Isabela and Santa Cruz at the Galapagos project in the deepwater Gulf of Mexico; and
·
awarded 11 deepwater lease blocks from the Central Gulf of Mexico lease sale 213.
International
·
sanctioned the development plan for the Tamar project, offshore Israel;
·
sanctioned the development plan for the Alen project, offshore Equatorial Guinea;
·
major exploration discovery at Leviathan, offshore Israel;
·
completed two new Mari-B wells, offshore Israel, maintaining field deliverability of 600 MMcf/d, gross; and
·
concluded field drilling and initiated completions at Aseng, offshore Equatorial Guinea.
Acquisitions and Divestitures On March 1, 2010, we closed the acquisition of substantially all of the US Rockies upstream assets of Petro-Canada Resources (USA) Inc. and Suncor Energy (Natural Gas) America Inc. for cash of $458 million, plus liabilities assumed. The transaction increased our presence in Wattenberg and further expanded our opportunity in the Central DJ Basin. The acquisition added approximately 10 MBoe/d to our daily production base and approximately 46 MMBoe of proved reserves, expanding our acreage and development opportunity in the area. A majority of the reserves are within Wattenberg, where our largest onshore US asset is located.
On August 12, 2010, we closed the sale of certain non-core assets in the Mid-Continent and Illinois Basin areas for sales proceeds of $552 million and recorded a pre-tax gain of $110 million on the sale. The properties represented approximately 5.7 MBoe/d of production and 32 MMBoe of reserves.
The government of Ecuador terminated our PSC for Block 3 (100% working interest) on November 25, 2010. A recently enacted hydrocarbon law required that certain existing PSCs be renegotiated as service contracts by November 23, 2010. A service contract on Block 3 has not been negotiated. We are continuing to work with the government of Ecuador to resolve this matter. The net book value of our investment in Ecuador was approximately $66 million at December 31, 2010.
See Item 8. Financial Statements and Supplementary Data - Note 3. Acquisitions and Divestitures.
Sales Volumes On a BOE basis, total sales volumes were 3% higher in 2010 as compared with 2009. Our mix of sales volumes was 39% global liquids, 30% international natural gas with long-term pricing contracts, and 31% US natural gas. In the US, production was higher in the onshore areas due to record production in Wattenberg primarily due to the recent acquisition of producing properties and continued field development. The Deepwater Moratorium had no impact on deepwater Gulf of Mexico production for 2010. However, it is likely to have an impact on future production. See Deepwater Gulf of Mexico, below.
In Israel, there was an increase in demand for natural gas to produce electricity due to warmer weather, and a higher percentage of the demand was met by production from our properties. There was also an increase in crude oil volumes lifted in the North Sea. These increases were partially offset by a decrease in crude oil volumes lifted in Equatorial Guinea.
Commodity Price Changes and Hedging The liquids (crude oil) market strengthened during 2010, benefiting from the global economic recovery. As a result, 2010 average realized crude oil prices were significantly higher than those we experienced in 2009. However, the domestic natural gas market remains weak primarily due to an abundant supply. Natural gas prices remain volatile and prices are still low compared to prices realized in 2006 - 2008. See Item 6. Selected Financial Data.
We have hedged approximately 50% of our expected global crude oil production and 57% of our expected domestic natural gas production for 2011. We use mark-to-market accounting for our commodity derivative instruments and recognize all gains and losses on such instruments in earnings in the period in which they occur. Derivative gains and losses included in net income include both pre-tax realized gains and losses and pre-tax, unrealized, non-cash gains or losses which are due to the change in the mark-to-market value of our commodity contracts related to production in future periods. Unrealized mark-to-market gains or losses recognized in the current period will be realized in the future when they are cash settled in the month that the related production occurs. The amount of gain or loss actually realized may be more or less than the amount of unrealized mark-to-market gain or loss previously reported. The use of mark-to-market accounting adds volatility to our net income. See Item 8. Financial Statements and Supplementary Data - Note 10. Derivative Instruments and Hedging Activities.
Asset Impairment Charges During 2010, we recorded asset impairment charges of $144 million related to some of our oil and gas assets. The impairments were due to declines in natural gas prices, recent drilling results, the classification of non-core onshore US assets as held-for-sale, and a change in the intended use of certain assets. Future decreases in forward natural gas prices could result in significant additional impairment charges. See Potential for Future Asset Impairments below and Item 8. Financial Statements and Supplementary Data - Note 4. Asset Impairments.
OPERATING OUTLOOK
2011 Production Our expected crude oil, natural gas and NGL production for 2011 may be impacted by several factors including:
·
ongoing development activity in Wattenberg and horizontal drilling in the Niobrara formation;
·
overall level and timing of capital expenditures which, as discussed below, and dependent upon our drilling success, are expected to maintain our near-term production volumes;
·
natural field decline in the deepwater Gulf of Mexico, Gulf Coast and Mid-Continent areas of our US operations and in the North Sea;
·
impact of potential legislative and regulatory changes on deepwater Gulf of Mexico operating and safety standards for producing activities due to the Deepwater Horizon Incident;
·
variations in sales volumes of natural gas from the Alba field in Equatorial Guinea related to potential downtime at the methanol, LPG and/or LNG plants;
·
Israeli demand for electricity which affects demand for natural gas as fuel for power generation, market growth and competing deliveries of natural gas from Egypt;
·
variations in North Sea sales volumes due to potential FPSO downtime and timing of liftings;
·
potential hurricane-related volume curtailments in the deepwater Gulf of Mexico and Gulf Coast areas;
·
potential winter storm-related volume curtailments in the Rocky Mountain area of our US operations;
·
potential pipeline and processing facility capacity constraints in the Rocky Mountain area of our US operations;
·
impact of purchases of producing properties;
·
timing of significant project completion and initial production; and
·
impact of divestments of non-core, non-strategic operating assets.
2011 Capital Investment Program Our total capital investment program for 2011 is estimated at $2.7 billion, with investment split relatively evenly between the US and international operations. Approximately 42% of the program is going toward major project developments, 18% for exploration and appraisal activities, and the remaining 40% for ongoing maintenance and near-term growth opportunities. Major project investments include our development activities in the deepwater Gulf of Mexico, West Africa, Eastern Mediterranean and our horizontal program in the Central DJ Basin.
In addition to the capital investment program discussed above, we expect to accrue approximately $70 million for the Aseng FPSO capital lease obligation.
We expect that the 2011 capital investment program will be funded from cash flows from operations, cash on hand, and borrowings under our revolving credit facility and/or other financing such as an issuance of long-term debt. See Liquidity and Capital Resources - Financing Activities - Interest Rate Locks.
We will evaluate the level of capital spending throughout the year based on the following factors, among others:
·
commodity prices;
·
cash flows from operations;
·
permitting activity in the deepwater Gulf of Mexico;
·
potential changes in the fiscal regimes of the US and other countries in which we operate;
·
impact of implementation of the Dodd-Frank Act on our business practices, including, among others, requirements regarding the posting of cash collateral in hedging transactions;
·
drilling results;
·
property acquisitions and divestitures; and
·
potential legislative or regulatory changes regarding the use of hydraulic fracturing.
Exploration Program We have significant remaining exploration potential, primarily in the onshore US, deepwater Gulf of Mexico, offshore West Africa, Eastern Mediterranean and other international areas where we hold acreage positions. In December 2010, we announced a significant natural gas discovery at the Leviathan prospect, offshore Israel, our largest discovery to date. We are continuing to drill at the Leviathan-1 well in order to evaluate two additional intervals for the existence of other hydrocarbons. Results from the deeper tests, which have a low chance of success, are expected over the next couple of months.
Pending permit approval, we plan to resume exploratory drilling at Deep Blue and Santiago and appraisal drilling at Gunflint in the deepwater Gulf of Mexico in 2011. In addition, we are planning further exploratory drilling offshore West Africa and in the Eastern Mediterranean.
Exploration activity, particularly offshore, requires significant capital investment. We do not always encounter commercially productive reservoirs through our drilling operations and, as a result, could incur significant dry hole cost. We are planning an active exploratory drilling program in 2011. As a result, dry hole cost could be significant.
Major Development Project Inventory Our current inventory of major development projects includes the Central DJ Basin, Galapagos, Gunflint, Tamar, Aseng, Alen, Diega/Carmen and other West Africa gas projects. These projects will require significant capital investments. For example, total development costs for the Aseng oil project, excluding costs related to a leased FPSO, are estimated at $1.3 billion ($530 million for our share). Total development costs for the Tamar natural gas project are estimated at $3.0 billion ($1.1 billion for our share).
We expect to spend approximately $1.1 billion in 2011 for major development projects. We plan to fund these projects from cash flows from operations, cash on hand, and borrowings under our revolving credit facility and/or other financing such as a public debt offering. First production from our major offshore development projects is targeted to occur when Galapagos begins to produce in late 2011 or early 2012. First production at Aseng is targeted for 2012, and first production at Tamar is targeted for late 2012 or early 2013. Once these three projects begin producing, we expect to begin generating sufficient amounts of cash flow to self-fund the remaining discovered major projects investments.
As operator on the majority of our development projects, we pay gross joint venture expenses and make cash calls on our nonoperating partners for their respective shares of joint venture costs. These projects are capital cost intensive and a nonoperating partner may experience a delay in obtaining financing for its share of the joint venture costs. In addition, some of our joint venture partners may not be as creditworthy as we are and may experience liquidity problems. This could result in a delay in our receiving reimbursement of joint venture costs and increases our counterparty credit risk. See Item 1A. Risk Factors - Failure to effectively execute our major development projects could result in significant delays and/or cost over-runs, damage to our reputation, limitations on our growth and negative effects on our operating results and We are exposed to counterparty credit risk as a result of our receivables, hedging transactions, and cash investments.
Potential for Future Asset Impairments The domestic natural gas market remains weak. A decrease in forward natural gas prices during 2011 could result in significant impairment charges. Our Piceance Basin (western Colorado) and Shattuck (western Oklahoma) properties have significant natural gas reserves and therefore are sensitive to declines in natural gas prices. These assets, which have a combined net book value of approximately $923 million at December 31, 2010, are at risk of impairment if future NYMEX Henry Hub natural gas prices experience further decline. The cash flow model that we use to assess proved properties for impairment includes numerous assumptions, such as management’s estimates of future oil and gas production and commodity prices, market outlook on forward commodity prices, operating and development costs, and discount rates. All inputs to the cash flow model must be evaluated at each date of estimate. However, a decrease in forward natural gas prices alone could result in a significant impairment for our properties that are sensitive to declines in natural gas prices. See Item 8. Financial Statements and Supplementary Data - Note 4. Asset Impairments.
Deepwater Gulf of Mexico The Deepwater Horizon Incident will have a significant impact on our industry, most likely in the areas of development cycle time, which is the length of time it takes for a project to progress from first discovery to first production, and in higher expected operating and development costs. Longer development cycle times result from additional regulatory reviews and slower permitting processes and oversight. We are currently experiencing significant delay in the processing and approval of our permits and cannot predict when necessary plans and permits will be approved for our planned future drilling activity. Longer development cycle time could potentially result in lower rates of return on our investments and a negative impact on cash flows from our projects.
Continued delay and disruption in the regulatory and permitting process could potentially have a negative impact our planned exploration program for the deepwater Gulf of Mexico. A significant delay or cancellation of planned exploratory activities reduces our longer term ability to find and develop new reserves, resulting in a negative impact on production over time. To the extent current exploration activities are significantly delayed, a gap could occur in our future production growth late in the decade with a negative impact on our operating results and cash flows.
Despite the Deepwater Moratorium, we were able to move forward on our major development project at Galapagos and are targeting late 2011 or early 2012 for the start-up. At Gunflint, we are reviewing host platform options including: subsea tieback to existing third-party host, procurement and modification of existing platform, and new construction. If we choose to connect to an existing third-party host, the project could have an accelerated completion schedule, thereby potentially absorbing time lost due to the Deepwater Moratorium and permit-related delay. We are targeting 2015 for the start-up of Gunflint. We currently believe there will be no significant impact on the total cash flows we expect to derive from these two projects.
The deepwater Gulf of Mexico is one of our key operating areas. Our net investment in the deepwater Gulf of Mexico was approximately $911 million at December 31, 2010. Notwithstanding our progress at Galapagos and Gunflint, we are adjusting our business model going forward to account for longer development cycle time and higher expected operating and development costs and expect that future projects could be less profitable. In addition, higher development and operating costs could ultimately impact the fair values of our properties in the deepwater Gulf of Mexico.
See also Items 1 and 2. Business and Properties - Deepwater Horizon Incident, Item 1A. Risk Factors - Our operations in the deepwater Gulf of Mexico, as well as onshore US and international locations, could be adversely affected by future changes in laws and regulations which may occur as a result of the Deepwater Horizon Incident, and Liquidity and Capital Resources - Risk and Insurance Program below.
Recent Developments in Israel In 2010, the Finance Minister of Israel established an advisory committee to study the country’s fiscal policy as it relates to the upstream crude oil and natural gas sector. In January 2011, the Finance Ministry advisory committee issued its final recommendations including cancellation of currently-existing tax incentives, including the depletion allowance, and imposition of a special levy ranging from 20% to 50% on oil and gas profits after a return on investment has been achieved. At this time we are uncertain of the final outcome of these proposals which must be legislated by Israel’s Parliament.
We have significant operations offshore Israel including the Mari-B field, a major ongoing development project at Tamar, and a recent exploration success at the Leviathan prospect. Each of these represents a substantial capital investment. At year-end 2010, approximately 28% of our total proved reserves were located in Israel.
A significant change in Israel’s fiscal regime could, among other things, disrupt our business plan for one of our key operating areas, have a negative impact on the ability of us and/or our partners to obtain project financing, cause delay in plans for development in the area, reduce the amount of proved reserves we record, impede our ability to compete with imports of natural gas from Egypt, reduce the profitability of our Tamar project, reduce the cash flows from our Mari-B project if the changes are retroactive, and/or adversely affect the price of our common stock. See Item 1A. Risk Factors - Our operations may be adversely affected by changes in the fiscal regimes of the countries in which we operate.
Climate Change Climate change has become the subject of an important public policy debate. While climate change remains a complex issue, scientific research suggests that an increase in greenhouse gas emissions (GHGs) may pose a risk to society and the environment. The oil and natural gas exploration and production industry is a source of certain GHGs, namely carbon dioxide and methane, and future restrictions on the combustion of fossil fuels or the venting of natural gas could have a significant impact on our future operations. We are actively monitoring the following climate change related issues:
Impact of Legislation and Regulation The commercial risk associated with the exploration and production of fossil fuels lies in the uncertainty of government-imposed climate change legislation, including cap and trade schemes, and regulations that may affect us, our suppliers, and our customers. The cost of meeting these requirements may have an adverse impact on our financial condition, results of operations and cash flows, and could reduce the demand for our products.
Climate change legislation and regulations have been adopted by many foreign countries and states in the US; however, legislation and regulations have not been enacted in all of the foreign countries where we operate or at the federal level in the US. The status of development of many state and federal climate change regulatory initiatives in areas where we operate makes it difficult to predict with certainty the future impact on us, including accurately estimating the related compliance costs that we may incur.
The EPA issued regulations requiring monitoring and reporting of GHG emissions from petroleum and natural gas systems. This action does not require control of GHGs. These new US, and other international, regulations may affect our operations by potentially increasing operating costs for maintaining our facilities, compliance costs for managing new GHG regulatory programs and capital costs for installing new GHG emission controls.
Impact of International Accords The Kyoto Protocol to the United Nations Framework Convention on Climate Change (Protocol) went into effect in February 2005 and requires all industrialized nations that ratified the Protocol to reduce or limit GHG emissions to a specified level by 2012. The US has not ratified the Protocol. The US, Israel, and the European Union have participated in international discussions to develop a treaty or other agreement to require reductions in GHG emissions after 2012 and have indicated that they wish to associate themselves with the Copenhagen Accord, which includes a non-binding commitment to reduce GHG emissions. In December 2010, the annual conference of parties reconvened in Cancun, Mexico to continue pursuing the global accord, committing countries to cut GHG emissions. At this time, no agreement between participating countries has been reached.
While no specific new international climate change accord has been adopted that would affect our operating locations, the current state of development of many initiatives makes it difficult to assess the timing or effect of any pending discussions of future accords or predict with certainty the future costs that we may incur in order to comply with future international treaties or regulations.
Indirect Consequences of Regulation or Business Trends We believe there are both risks and opportunities arising from the global response to potential climate change. See Items 1 and 2. Business and Properties - Regulation and the following risk factors listed in Item 1A. Risk Factors -
·
We are subject to increasing governmental regulations and environmental risks that may cause us to incur substantial costs;
·
Increased regulation of business practices could result in increased operating costs; and
·
The adoption of GHG emission or other environmental legislation could result in increased operating costs, create delays in our obtaining air pollution permits for new or modified facilities, and reduce demand for the crude oil and natural gas we produce.
In terms of opportunities, the regulation of GHGs and introduction of formal technology incentives, such as enhanced oil recovery, carbon sequestration and low carbon fuel standards, could benefit us in a variety of ways.
First, approximately 61% of our 2010 total consolidated production was natural gas. GHG emissions regulation could reduce the demand for the crude oil and natural gas we produce. At the same time, the burning of natural gas produces lower levels of emissions than other readily available fossil fuels such as oil and coal. Therefore, the use of natural gas may increase should the use of other fossil fuels decrease due to GHG emissions regulation. Furthermore, should renewable resources, such as wind or solar power become more prevalent, natural gas-fired electric plants may provide an alternative backup to maintain consistent electricity supply.
Second, market-based incentives for the capture and storage of carbon dioxide in underground reservoirs, particularly in oil and natural gas reservoirs, could benefit us through the potential to obtain GHG allowances or offsets from or government incentives for the sequestration of carbon dioxide.
Finally, as the EPA’s new GHG standards for light duty vehicles become effective in 2011, natural gas may prove to be a more attractive transportation fuel. This may increase the market demand for natural gas.
Physical Impacts of Climate Change on our Costs and Operations There has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels. Extreme weather conditions increase our costs, and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations, particularly our offshore operations. See Item 1A. Risk Factors - We have insufficient insurance to cover all of the risks we face, which could result in significant financial exposure.
RESULTS OF OPERATIONS
Selected financial information is as follows:
Factors contributing to the increase in income (loss) before income taxes in 2010 as compared with 2009 included the following:
·
$709 million increase in total revenues due primarily to higher commodity prices;
·
$460 million decrease in asset impairment charges;
·
$91 million increase in net gain on asset sales; and
·
$157 million mark-to-market gain on commodity derivative instruments as opposed to a $110 million mark-to-market loss in 2009;
offset by:
·
$45 million increase in total production expense;
·
$101 million increase in exploration expense; and
·
$67 million increase in DD&A expense.
Factors contributing to the decrease in income (loss) before income taxes in 2009 as compared with 2008 included the following:
·
$1.6 billion decrease in total revenues due primarily to lower commodity prices;
·
$110 million mark-to-market loss on commodity derivative instruments as compared with a $440 million mark-to-market gain in 2008;
·
$310 million increase in asset impairment charges;
·
$90 million decrease in income from equity investees; and
·
$25 million increase in DD&A expense;
offset by:
·
$86 million refund of deepwater Gulf of Mexico royalties plus interest of $11 million;
·
$69 million decrease in total production expense; and
·
$73 million decrease in exploration expense.
See following discussion for explanation of year-to-year changes.
Revenues
Oil, Gas and NGL Sales An analysis of the factors contributing to the changes in revenues from sales of crude oil, natural gas and NGLs from 2008 through 2010 is as follows:
Average daily sales volumes and average realized sales prices were as follows:
(1)
Natural gas is converted on the basis of six Mcf of gas per one barrel of oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given recent commodity price disparities, the price for a barrel of oil equivalent for natural gas is less than the price for a barrel of oil.
(2)
Average realized crude oil and condensate prices reflect reductions of $1.32 per Bbl for 2010, $2.13 per Bbl for 2009, and $22.06 per Bbl for 2008 from hedging activities. Average realized natural gas prices reflect a decrease of $0.01 per Mcf for 2010 and an increase of $0.23 per Mcf for 2008 from hedging activities. The effect of hedging activities on the average realized natural gas price for 2009 was de minimis. These price increases and reductions resulted from hedge gains and losses that had been previously deferred AOCL. All hedge gains or losses relating to US production had been reclassified to revenues by December 31, 2010.
(3)
Average realized crude oil and condensate prices reflect reductions of $5.57 per Bbl for 2009 and $7.59 per Bbl for 2008 from hedging activities. These price reductions resulted from hedge losses that had been previously deferred in AOCL. All hedge gains or losses relating to Equatorial Guinea production had been reclassified to revenues by December 31, 2009.
(4)
Natural gas from the Alba field in Equatorial Guinea is under contract for $0.25 per MMBtu to a methanol plant, an LPG plant and an LNG plant. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method of accounting.
(5)
Includes production through November 24, 2010. Our Block 3 PSC was terminated by the Ecuadorian government on November 25, 2010. Intercompany natural gas sales were eliminated for accounting purposes. Electricity sales are included in other revenues. See Termination of Ecuador PSC, above.
(6)
Volumes represent sales of condensate and LPG from the Alba Plant in Equatorial Guinea. See Income from Equity Method Investees below.
If the realized gains and losses on commodity derivative instruments, which are included in (gain) loss on commodity derivative instruments in our consolidated statements of operations, had been included in oil and gas revenues, the effect on average realized prices would have been as follows:
Crude Oil and Condensate Sales Revenues from crude oil and condensate sales increased by a net $534 million, or 42%, in 2010 as compared with 2009 due to the following:
·
a 37% increase in total consolidated average realized prices due to increased demand resulting from the global economic recovery;
·
increased production due to ongoing development activity in the Central DJ Basin, including horizontal drilling in the Niobrara formation;
·
additional production from the Central DJ Basin asset acquisition in March 2010;
·
crude oil production from a Swordfish sidetrack oil well that commenced production first quarter 2010;
·
renewed production from Ticonderoga in the deepwater Gulf of Mexico which was off-line first quarter 2009 as a result of hurricane damage to third-party processing and pipeline facilities; and
·
an increase in North Sea sales volumes primarily as a result of increased deliverability at the Dumbarton complex, which included the addition of two Lochranza wells in 2010;
partially offset by
·
a decrease in onshore US volumes due to the divestment of mature oil assets;
·
a decrease in deepwater Gulf of Mexico volumes due to natural field decline and third party downstream facility constraints;
·
a decrease in onshore US volumes due to natural field decline in the Mid-Continent and Gulf Coast areas; and
·
a decrease in Equatorial Guinea sales volumes due to the planned shut-down of the Alba field for facilities maintenance and repair during 2010 and the timing of liftings.
Revenues from crude oil sales decreased by a net $840 million, or 40%, in 2009 as compared with 2008 due to the following:
·
a 32% decline in consolidated average realized prices due to the decreased demand for oil resulting from the economic slowdown;
·
natural field decline in the deepwater Gulf of Mexico and Gulf Coast area;
·
the shut-in of Ticonderoga in the deepwater Gulf of Mexico until August 2009 after being offline due to Hurricane Ike in 2008;
·
a decrease in Equatorial Guinea sales volumes due to timing of liftings; and
·
a decrease in North Sea sales volumes due to natural field decline and downtime beginning in mid-August at the Dumbarton field due to FPSO repairs;
partially offset by
·
increased production due to ongoing development activity in the Central DJ Basin.
Crude oil revenues include amounts reclassified from AOCL related to commodity derivative instruments which were accounted for as cash flow hedges through December 31, 2007. Amounts included decreases of $19 million in 2010, $58 million in 2009, and $365 million in 2008. At December 31, 2010, there were no further amounts related to commodity derivative instruments remaining to be reclassified from AOCL to crude oil revenues. See Item 8. Financial Statements and Supplementary Data - Note 10. Derivative Instruments and Hedging Activities.
Natural Gas Sales Revenues from natural gas sales increased by a net $133 million, or 19%, in 2010 as compared with 2009 due to the following:
·
an increase in total consolidated and US average realized prices due to increased demand resulting from the economic recovery;
·
an increase in Israel average realized prices under the terms of a natural gas sales contract entered into in the third quarter of 2009;
·
increased production due to ongoing development activity in the Central DJ Basin, including the horizontal drilling in the Niobrara formation;
·
additional production from the Central DJ Basin asset acquisition in March 2010; and
·
an increase in Israel sales volumes due to an increase in demand for our natural gas driven by increased electricity production due to warmer weather and lower levels of competitor natural gas imports from Egypt;
partially offset by
·
a decrease in Equatorial Guinea sales volumes due to the planned shut-down of the Alba field for facilities maintenance and repair; and
·
natural field decline in the deepwater Gulf of Mexico, Gulf Coast and Mid-Continent areas.
Revenues from natural gas sales decreased by a net $674 million, or 49%, in 2009 as compared with 2008 due the following:
·
a 50% decline in consolidated average realized prices due to increased supply and decreased demand for natural gas resulting from the economic slowdown;
·
natural field decline in the deepwater Gulf of Mexico, Gulf Coast and Mid-Continent areas;
·
a decrease in Israel sales volumes due to customer power plant downtime, warmer than normal winter weather conditions, and competing natural gas sales from Egypt ; and
·
lower average realized prices in the North Sea;
partially offset by
·
increased production from Wattenberg, Piceance Basin and Western Oklahoma areas of our US operations;
·
an increase in sales volumes to the LNG plant in West Africa; and
·
an increase in average realized sales prices in Israel due to a new natural gas sales contract.
Natural gas revenues include amounts reclassified from AOCL related to commodity derivative instruments which were accounted for as cash flow hedges through December 31, 2007. Amounts included a decrease of $1 million in 2010 and an increase of $34 million in 2008. At December 31, 2010, there were no further amounts related to commodity derivative instruments remaining to be reclassified from AOCL to natural gas revenues. See Item 8. Financial Statements and Supplementary Data - Note 10. Derivative Instruments and Hedging Activities.
NGL Sales Most of our US NGL production is from Wattenberg and deepwater Gulf of Mexico.
NGL sales revenues increased $105 million during 2010 as compared with 2009 due to an increase in sales volumes from ongoing development activity in the Central DJ Basin, including horizontal drilling in the Niobrara formation, as well as an increase in consolidated average realized prices which benefited from increased demand resulting from the global economic recovery.
NGL sales revenues decreased $77 million during 2009 as compared with 2008 due to the decrease in average realized prices resulting from the economic slowdown.
Income from Equity Method Investees We have a 45% interest in AMPCO, which owns and operates a methanol plant and related facilities. We also have a 28% interest in Alba Plant, which owns and operates an LPG processing plant. The plants and related facilities are located in Equatorial Guinea. We account for investments in entities that we do not control but over which we exert significant influence using the equity method of accounting.
Our share of operations of equity method investees was as follows:
AMPCO and Affiliates Net income from AMPCO and affiliates increased in 2010 as compared with 2009 due to an increase in average realized methanol prices from increased demand due to the global economic recovery. During fourth quarter 2010, the methanol plant successfully completed a major turnaround in 31 days. Production resumed on October 30, 2010.
Net income from AMPCO and affiliates decreased in 2009 as compared with 2008 due to the significant decrease in the average realized price for methanol. The price decrease was the result of an oversupply of methanol and the impact of the economic slowdown. Methanol sales volumes increased as there was minimal down time for repairs as compared with 2008.
Alba Plant Net income from Alba Plant increased in 2010 as compared with 2009 due to an increase in average realized condensate and LPG prices from increased demand due to the global economic recovery.
Net income from Alba Plant decreased in 2009 as compared with 2008 due to significant decreases in average realized prices for condensate and LPG. The price decrease was the result of decreases in liquids prices and the impact of the economic slowdown.
Other Revenues Other revenues were as follows:
Other revenues include electricity sales, a refund of deepwater Gulf of Mexico royalties and other revenue items. See Item 8. Financial Statements and Supplementary Data - Note 2. Additional Financial Statement Information.
Costs and Expenses
Production Expense Components of production expense were as follows:
(1)
Other international includes China and Argentina (through February 2008).
(2)
Lease operating expense includes oil and gas operating costs (labor, fuel, repairs, replacements, saltwater disposal and other related lifting costs) and workover and repair expense.
(3)
Consolidated unit rates exclude sales volumes and costs attributable to equity method investees.
Lease Operating Expense Lease operating expense was flat in 2010 as compared with 2009. Changes included following:
·
an increase in US production volumes due to ongoing development activity in Central DJ Basin, including horizontal drilling in the Niobrara formation;
·
an increase in US production volumes due to the Central DJ Basin asset acquisition; and
·
an increase in North Sea lease operating expense due to higher sales volumes;
offset by
·
a decrease in Equatorial Guinea lease operating expense due to the planned shut-down of the Alba field for facilities maintenance and repair ; and
·
the sale of non-core, non-strategic assets in the Mid-Continent and Illinois Basin areas, which had higher lease operating costs.
Lease operating expense remained flat overall in 2009 as compared with 2008. Changes included the following:
·
a decrease in lease operating expense due to cost savings initiatives which included reduced workover and repair programs and a reduction of other discretionary spending in our onshore US operations;
·
a decrease in lease operating expense due to lower sales volumes in the North Sea, where a higher volume of crude oil was inventoried resulting in a deferral of production cost;
offset by
·
an increase in lease operating expense in Equatorial Guinea due to higher contractor costs.
Production and Ad Valorem Tax Expense Production and ad valorem tax expense for 2010 increased as compared with 2009 due to higher commodity prices in the US and China.
Production and ad valorem tax expense for 2009 decreased as compared with 2008 due to reduced proceeds from sales attributable to lower commodity prices and the cessation of production due to the sale of our Argentina assets in 2008.
Transportation Expense Transportation expense increased in 2010 as compared with 2009 due to an increase in crude oil and condensate production in Wattenberg and the use of a new interstate crude oil transportation pipeline system to market production.
Transportation expense increased in 2009 as compared with 2008 due to the start up of a new interstate crude oil transportation pipeline system used to market our Wattenberg production and offset by lower sales volumes in the North Sea.
Unit Rate Per BOE The unit rate of total production expense per BOE increased for 2010 as compared with 2009 primarily due to increases in production and ad valorem taxes and transportation expense.
The unit rate of total production expense per BOE decreased for 2009 as compared with 2008 primarily due to the decline in production and ad valorem taxes.
Oil and Gas Exploration Expense Exploration expense was as follows:
(1)
West Africa includes Equatorial Guinea and Cameroon.
(2)
Eastern Mediterranean includes Israel and Cyprus.
(3)
Other international, corporate includes China and new ventures.
Oil and gas exploration expense for 2010 increased by $101 million, or 70%, as compared with 2009. US dry hole expense was associated with the Double Mountain exploration well in the deepwater Gulf of Mexico, which found noncommercial quantities of hydrocarbons. Seismic expenditures related to the Central Gulf of Mexico lease sale, and the acquisition of 3-D seismic information for offshore Israel, Cameroon, Nicaragua, and France.
Exploration expense for 2009 decreased by $73 million, or 34%, as compared with 2008. The decrease was almost entirely related to the decrease in dry hole expense as a result of our exploration successes in the deepwater Gulf of Mexico, Israel and Equatorial Guinea.
Exploration expense included stock-based compensation expense of $10 million in 2010, $9 million in 2009, and $1 million in 2008.
Depreciation, Depletion and Amortization Expense Depreciation, depletion and amortization (DD&A) expense was as follows:
(1)
DD&A expense includes accretion of discount on asset retirement obligations of $17 million in 2010, $14 million in 2009, and $10 million in 2008.
(2)
Consolidated unit rates exclude sales volumes and costs attributable to equity method investees.
Total DD&A expense increased for 2010 as compared with 2009 due to the following:
·
higher production in the Central DJ Basin, Piceance Basin and Western Oklahoma areas of our US operations, which have higher DD&A rates relative to production from Equatorial Guinea and Israel;
·
ongoing development activity in Central DJ Basin, including horizontal drilling in the Niobrara formation; and
·
higher sales volumes in the North Sea;
partially offset by
·
lower DD&A expense in the Mid-Continent area which has a reduced net book value resulting from an impairment recorded at the end of 2009; and
·
the cessation of DD&A associated with assets sold or held-for-sale during the year.
The unit rate per BOE increased for 2010 as compared with 2009 due to the change in mix of production, including decreases in lower-cost sales volumes from Equatorial Guinea, offset by a lower rate for the Mid-Continent area and the cessation of DD&A associated with assets sold or held-for-sale.
Total DD&A expense increased for 2009 as compared with 2008 due to the following:
·
higher production in Wattenberg, Piceance Basin and Western Oklahoma areas of our US operations which have higher DD&A rates relative to production from Equatorial Guinea and Israel which have lower DD&A rates;
·
ongoing capital spending in our US operations; and
·
negative reserves revisions at December 31, 2009;
partially offset by
·
lower sales volumes in the North Sea.
DD&A expense for the fourth quarter of 2009 increased approximately $16 million due to the change in the SEC’s pricing rules from the use of year-end prices to 12-month average prices, which resulted in negative reserves revisions at December 31, 2009. See Item 8. Financial Statements and Supplementary Data - Supplemental Oil and Gas Information (Unaudited) for effects of reserves revisions due to lower commodity prices at December 31, 2009.
The unit rate per BOE increased for 2009 as compared with 2008 due to the change in the mix of production, including a decrease in lower-cost volumes from Israel; ongoing capital spending in onshore US areas; and negative reserves revisions related to lower year-end 2009 commodity prices.
General and Administrative Expense General and administrative (G&A) expense was as follows:
(1)
Consolidated unit rates exclude sales volumes and costs attributable to equity method investees.
G&A expense increased for 2010 as compared with 2009 primarily due to additional expenses relating to personnel and office costs in support of our major development projects and increased performance incentive compensation. G&A expense remained flat in 2009 as compared with 2008.
G&A expense is impacted by the number of stock-based awards, the market price of our common stock and price volatility, all of which result in a higher fair value of stock-based awards as calculated using the Black-Scholes-Merton option pricing model. G&A included stock-based compensation expense of $39 million in 2010, $36 million in 2009, and $38 million in 2008. See Item 8. Financial Statements and Supplementary Data - Note 15. Stock-Based Compensation.
Net Gain on Asset Sales Net gain on asset sales was as follows:
Net gain on asset sales for 2010 includes a $110 million gain on the sale of certain non-core assets in the Mid-Continent and Illinois Basin areas. Net gain on asset sales for 2009 includes a $24 million gain on the sale of our Argentina assets. We sold our Argentina assets in 2008; however, recognition of the gain on the sale was deferred until 2009 when the Argentine government approved the sale. See Item 8. Financial Statements and Supplementary Data - Note 3. Acquisitions and Divestitures.
Asset Impairments Asset impairment expense was as follows:
For information regarding asset impairment charges, see Critical Accounting Policies and Estimates - Impairment of Proved Oil and Gas Properties and Other Investments and Impairment of Unproved Oil and Gas Properties, below, and Item 8. Financial Statements - Note 4. Asset Impairments.
Other Operating Expense, Net Other operating expense, net was as follows:
Other operating expense, net includes electricity generation expense, rig contract termination expense related to the Deepwater Moratorium, and other items of operating income or expense. See Item 8. Financial Statements and Supplementary Data - Note 2. Additional Financial Statement Information.
(Gain) Loss on Commodity Derivative Instruments Gain (loss) on commodity derivative instruments was as follows:
We recognize all gains and losses on commodity derivative instruments in earnings in the period in which they occur. See Critical Accounting Policies and Estimates - Derivative Instruments and Hedging Activities, below, and Item 8. Financial Statements and Supplementary Data - Note 10. Derivative Instruments and Hedging Activities and Note 16. Fair Value Measurements and Disclosures.
Interest Expense and Capitalized Interest Interest expense and capitalized interest were as follows:
(1) Consolidated unit rates exlude sales volumes and costs attributable to equity method investees.
Net interest expense decreased in 2010 as compared with 2009. However, gross interest expense increased due to the higher interest rate associated with our $1 billion 8¼% senior unsecured notes due March 1, 2019, which were outstanding for a full 12 months in 2010 as compared with ten months in 2009. The increase in gross interest expense was more than offset by an increase in the amount of interest capitalized due to higher work in progress amounts related to major long-term projects in the deepwater Gulf of Mexico, West Africa, and Israel.
Net interest expense increased in 2009 as compared with 2008. The increase primarily relates to our $1 billion 8¼% senior unsecured notes due March 1, 2019, which we issued on February 27, 2009. This increase was partially offset by a significant decrease in credit facility interest expense due to a decline in both the average outstanding balance and the average interest rate.
Interest is capitalized on exploration and development projects using an interest rate equivalent to the average rate paid on long-term debt. Capitalized interest is included in the cost of oil and gas assets and amortized with other costs on a unit-of-production basis. The majority of the capitalized interest is related to long lead-time projects in the deepwater Gulf of Mexico (2008 - 2010), West Africa (2008 - 2010) and Israel (2009 - 2010) and numerous projects in the Rocky Mountain area (2008). See Item 8. Financial Statements and Supplementary Data - Note 7. Capitalized Exploratory Well Costs.
Other Non-operating (Income) Expense, Net Other non-operating (income) expense, net was as follows:
Other non-operating (income) expense, net includes deferred compensation (income) expense, interest income and other (income) expense, net.
Deferred Compensation (Income) Expense We have assets and liabilities related to a deferred compensation plan. The assets of the deferred compensation plan are held in a rabbi trust and include shares of our common stock and mutual fund investments. At December 31, 2010, approximately 46% of the market value of the assets in the rabbi trust related to our common stock. Increases in the market value of our common stock held in the trust result in the recognition of deferred compensation expense. Decreases in the market value of our common stock held in the trust result in the recognition of deferred compensation income. We recognized deferred compensation expense of $15 million in 2010 and $23 million in 2009, and deferred compensation income of $32 million in 2008. See Item 8. Financial Statements and Supplementary Data - Note 14. Benefit Plans.
Interest Income Interest income includes $3 million and $11 million for 2010 and 2009, respectively, related to interest received on the refund of deepwater Gulf of Mexico royalties.
Income Tax Provision (Benefit) The income tax provision (benefit) was as follows:
Our effective tax rate decreased for 2010 as compared with 2009. For 2010, the effective rate is lower than the federal statutory rate because our income from equity method investees and other permanent differences have the impact of decreasing the effective rate when we have pre-tax income. In addition, during 2010, we reversed a valuation allowance of $28 million that, as of December 31, 2009, had been provided against a deferred tax asset of the same amount for the future foreign tax credits associated with deferred tax liabilities recorded by foreign branch operations. The reversal of the valuation allowance resulted in a reduction in income tax expense. We now believe it is more likely than not that this deferred tax asset will be realized.
Our effective tax rate increased for 2009 as compared with 2008 and is the result of a tax benefit divided by a pre-tax loss. In the case of a loss, our favorable permanent differences, such as income from equity method investees, have the effect of increasing the tax benefit which, in turn, increases the effective rate. During 2009, we repatriated $180 million of accumulated earnings of foreign subsidiaries and used the proceeds for debt repayment and general corporate purposes. The repatriation increased US tax expense by $13 million, of which $9 million was recorded in 2008. Repatriation of additional earnings in the future could result in a decrease in our net income and cash flows.
See Item 8. Financial Statements and Supplementary Data - Note 13. Income Taxes.
PROVED RESERVES
We have historically added reserves through our exploration program, development activities, and acquisition of producing properties. (See Items 1. and 2. Business and Properties). Changes in proved reserves were as follows:
Revisions Revisions of previous estimates represent changes in previous reserves estimates, either upward (positive) or downward (negative), resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs, or development costs. Revisions included the following:
·
Changes for the year ended December 31, 2010 included a positive revision of 43 MMBoe due to higher year-end commodity prices, a negative revision of 30 MMBoe due to reclassifications of proved undeveloped reserves to probable reserves as a result of the SEC’s five year development rule, a negative revision of 7 MMBoe due to a change in the likelihood that the Noa field, offshore Israel, will be pursued for development, and a negative revision of 2 MMBoe due to well performance;
·
Changes for the year ended December 31, 2009 included negative revisions due to reclassifications of proved undeveloped reserves to probable reserves as a result of the SEC’s new five year development rule and lower natural gas prices, partially offset by positive revisions due to higher crude oil prices; and
·
Changes for the year ended December 31, 2008 included negative revisions due to lower year-end commodity prices.
Extensions, Discoveries and Other Additions These are additions to proved reserves that result from (1) extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (2) discovery of new fields with proved reserves or of new reservoirs of proved reserves in old fields. Extensions, discoveries and other additions included the following:
·
Changes for the year ended December 31, 2010 included an increase of 48 MMBoe, which were primarily driven by the execution of low-risk development projects onshore in Wattenberg and the Rocky Mountain area, an increase of 286 MMBoe related to the initial recording of reserves for the Tamar field offshore Israel, and an increase of approximately 27 MMBoe related to the initial recording of reserves for the Alen field, offshore Equatorial Guinea;
·
Changes for the year ended December 31, 2009 included US additions, which were primarily driven by the execution of low-risk development projects onshore in Wattenberg and the Piceance Basin, as well as from the sanctioning of the development plan for Galapagos in the deepwater Gulf of Mexico, and international additions, related primarily to the initial recording of reserves at the Aseng oil project, offshore Equatorial Guinea; and
·
Changes for the year ended December 31, 2008 included US additions, which were due to US onshore infill drilling activities and other US development programs, and international additions, which were due to drilling in China.
We expect that a significant portion of future reserve additions will come from our major development projects at the Central DJ Basin, Gunflint, Aseng, Alen, and Tamar and from new discoveries resulting from our active exploration programs in the deepwater Gulf of Mexico and international locations, such as Leviathan, offshore Israel. We may also purchase proved properties in strategic acquisitions. See Operating Outlook - Major Development Project Inventory, above and Acquisition, Capital and Other Exploration Expenditures, below.
Purchase of Minerals in Place We occasionally enhance our asset portfolio with strategic acquisitions of producing properties. Purchases included the following:
·
the Central DJ Basin asset acquisition in 2010; and
·
the Mid-Continent acquisition in 2008.
Sale of Minerals in Place We maintain an ongoing portfolio management program. Sales included the following:
·
the sale of non-core assets in the Mid-Continent and Illinois Basin areas in 2010; and
·
the sale of our Argentina assets in 2008.
Sales of Minerals in Place also included a reduction in natural gas reserves due to the Ecuadorian government’s termination of our Block 3 PSC. See Items 1. and 2. Business and Properties and Item 8. Financial Statements and Supplementary Data - Note 3. Acquisitions and Divestitures.
Production See Oil, Gas and NGL Sales above.
See also Critical Accounting Policies and Estimates - Reserves, below, and Item 8. Financial Statements and Supplementary Data - Supplemental Oil and Gas Information (Unaudited).
LIQUIDITY AND CAPITAL RESOURCES
Capital Structure/Financing Strategy
In seeking to effectively fund and monetize our major development projects, we employ a capital structure and financing strategy designed to provide ample liquidity throughout the commodity price cycle. Specifically, we strive to retain the ability to fund long cycle, multi-year, capital intensive development projects while also maintaining the capability to execute a robust exploration program and financially attractive periodic mergers and acquisitions activity. We endeavor to maintain an investment grade debt rating in service of these objectives. We also utilize a commodity price hedging program to reduce commodity price uncertainty and enhance the predictability of cash flows along with a risk and insurance program to protect against disruption to our cash flows and operations.
Traditional sources of our liquidity are cash on hand, cash flows from operations and available borrowing capacity under our credit facility. Occasional sales of non-strategic crude oil and natural gas properties as well as our periodic access to capital markets may also generate cash.
Our financial capacity, coupled with our balanced and diversified portfolio, provides us with flexibility in our investment decisions including execution of our major development projects and increased exploration activity.
Information regarding cash and debt balances was as follows:
(1)
Our credit facility is committed in the amount of $2.1 billion until December 9, 2011 at which time the commitment reduces to $1.8 billion.
(2)
Total debt includes FPSO obligation and excludes unamortized debt discount.
(3)
We define our ratio of debt-to-book capital as total debt (which includes both long-term debt, excluding unamortized discount, and short-term borrowings) divided by the sum of total debt plus shareholders’ equity.
Cash and Cash Equivalents We had $1.1 billion in cash and cash equivalents at December 31, 2010, compared with $1 billion at December 31, 2009. At December 31, 2010, our cash was primarily denominated in US dollars and was invested in money market funds and short-term deposits with major financial institutions. Substantially all of this cash is attributable to our foreign subsidiaries and most would be subject to US income taxes if repatriated. We currently expect to use a significant amount of this cash during 2011 to fund international projects, including the development of our properties in West Africa and Israel.
Commodity Derivative Instruments We use various derivative contracts in connection with anticipated crude oil and natural gas sales to minimize the impact of product price fluctuations and ensure cash flow for future capital needs. Such instruments include variable to fixed commodity price swaps, two-way and three-way collars and basis swaps.
As of December 31, 2010, we had commodity derivative assets totaling $62 million and commodity derivative liabilities totaling $75 million (after consideration of netting agreements). Our hedging arrangements are currently with a diversified group of highly-rated major banks and market participants. See Item 1A. Risk Factors - Commodity and interest rate hedging transactions may limit our potential gains and We are exposed to counterparty credit risk as a result of our receivables, hedging transactions, and cash investments.
Current period settlements on commodity derivative instruments impact our liquidity, since we are either paying cash to, or receiving cash from, our counterparties. If actual commodity prices are higher than the fixed or ceiling prices in our derivative instruments, our cash flows will be lower than if we had no derivative instruments. Conversely, if actual commodity prices are lower than the fixed or floor prices in our derivative instruments, our cash flows will be higher than if we had no derivative instruments. None of our counterparty agreements currently contain margin requirements. However, see Item 1A. Risk Factors - Derivatives regulation included in current financial reform legislation could impede our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices and interest rates.
See Critical Accounting Policies and Estimates - Derivative Instruments and Hedging Activities, Item 7A.
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
Derivative Instruments Held for Non-Trading Purposes We are exposed to market risk in the normal course of business operations, and the uncertainty of crude oil and natural gas prices continues to impact the oil and gas industry. Due to the volatility of crude oil and natural gas prices, we continue to use derivative instruments as a means of managing our exposure to price changes.
At December 31, 2010, we had entered into variable to fixed price commodity swaps, two-way and three-way collars and basis swaps related to future crude oil and natural gas sales. Our open commodity derivative instruments were in a net payable position with a fair value of $13 million. Based on the December 31, 2010 published forward commodity price curves, a price increase of $1.00 per Bbl for crude oil would increase the fair value of our net commodity derivative payable by approximately $14 million. A price increase of $0.10 per MMBtu for natural gas would increase the fair value of our net commodity derivative payable by approximately $8 million. Our derivative instruments are executed under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net settled at the time of election. See Item 8.
Item 8.
Financial Statements and Supplementary Data
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed under the supervision of our Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.
Because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements. Projections of any evaluation of the 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 processes may deteriorate.
As of December 31, 2010, our management assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control over financial reporting established in Internal Control - Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, management determined that we maintained effective internal control over financial reporting as of December 31, 2010, based on those criteria. Management included in its assessment of internal control over financial reporting all consolidated entities.
KPMG LLP, the independent registered public accounting firm that audited our consolidated financial statements included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of internal control over financial reporting as of December 31, 2010 which is included herein.
Noble Energy, Inc.
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Noble Energy, Inc.:
We have audited the accompanying consolidated balance sheets of Noble Energy, Inc. and subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity, comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2010. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We did not audit the financial statements of the Alba Plant LLC (Alba) as of December 31, 2009 and for each of the years in the two-year period ended December 31, 2009, the investment in which, as discussed in Note 8 of the consolidated financial statements, is accounted for by the equity method of accounting. The Company’s investment in Alba at December 31, 2009 was $111 million, and its equity in earnings of Alba was $66 million, and $118 million, for the years ended December 31, 2009, and 2008, respectively. The financial statements of Alba were audited by other auditors whose reports have been furnished to us, and our opinion, insofar as it relates to the amounts included for Alba, is based solely on the reports of the other auditors.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, based on our audits and the reports of the other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Noble Energy, Inc. and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Noble Energy, Inc.’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 10, 2011 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ KPMG LLP
Houston, Texas
February 10, 2011
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Noble Energy, Inc.:
We have audited Noble Energy, Inc.’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Noble Energy, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Noble Energy, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Noble Energy, Inc. and subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity, comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2010, and our report dated February 10, 2011 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
Houston, Texas
February 10, 2011
Noble Energy, Inc. and Subsidiaries
Consolidated Statements of Operations
(in millions, except per share amounts)
The accompanying notes are an integral part of these financial statements.
Noble Energy, Inc.
Consolidated Balance Sheets
(in millions)
The accompanying notes are an integral part of these financial statements.
Noble Energy, Inc.
Consolidated Statements of Cash Flows
(in millions)
The accompanying notes are an integral part of these financial statements.
Noble Energy, Inc. and Subsidiaries
Consolidated Statements of Shareholders' Equity
(in millions)
The accompanying notes are an integral part of these financial statements
Noble Energy, Inc.
Consolidated Statements of Comprehensive Income
(in millions)
The accompanying notes are an integral part of these financial statements.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 1. Summary of Significant Accounting Policies
General Noble Energy, Inc. (Noble Energy, we or us) is a leading independent energy company engaged in worldwide oil and gas exploration and production. Our key operating areas are the Central DJ Basin, deepwater Gulf of Mexico, offshore Eastern Mediterranean, and offshore West Africa.
Basis of Presentation and Consolidation Accounting policies used by us and our subsidiaries conform to accounting principles generally accepted in the US (US GAAP). Significant policies are discussed below. Our consolidated accounts include our accounts and the accounts of our wholly-owned subsidiaries. We use the equity method of accounting for investments in entities that we do not control but over which we exert significant influence. We carry equity method investments at our share of net assets of the equity investees plus our loans and advances. Differences in the basis of the investment and the separate net asset value of the investee, if any, are amortized into income over the remaining useful life of the underlying assets. See Note 8. Equity Method Investments. All significant intercompany balances and transactions have been eliminated upon consolidation.
Use of Estimates The preparation of consolidated financial statements in conformity with US GAAP requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.
Estimated quantities of crude oil and natural gas reserves are the most significant of our estimates. All the reserves data included in this Form 10-K are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserves estimates may be different from the quantities of crude oil and natural gas that are ultimately recovered. Qualified petroleum engineers in our Houston and Denver offices prepare all reserves estimates for our different geographical regions. These reserves estimates are reviewed and approved by senior engineering staff and division management with final approval by the Vice President - Strategic Planning, Environmental Analysis & Reserves and certain members of senior management. See Supplemental Oil and Gas Information (Unaudited).
Other items subject to estimates and assumptions include the carrying amounts of property, plant and equipment and goodwill, asset retirement obligations, valuation allowances for receivables and deferred income tax assets, valuation of derivative instruments, and obligations related to employee benefits, among others. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. Volatile commodity prices result in increased uncertainty inherent in such estimates and assumptions. As future commodity prices cannot be determined accurately, actual results could differ significantly from our estimates.
Reclassification Certain reclassifications have been made to the 2009 and 2008 consolidated financial statements to conform to the 2010 presentation. These reclassifications were not material to the financial statements.
Fair Value Measurements Fair value measurements are based on a hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three levels. The fair value hierarchy is as follows:
·
Level 1 measurements are fair value measurements which use quoted market prices (unadjusted) in active markets for identical assets or liabilities.
·
Level 2 measurements are fair value measurements which use inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly.
·
Level 3 measurements are fair value measurements which use unobservable inputs.
The fair value hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. We use Level 1 inputs when available as Level 1 inputs generally provide the most reliable evidence of fair value. See Note 16. Fair Value Measurements and Disclosures.
Cash and Cash Equivalents For purposes of reporting cash flows, cash and cash equivalents include unrestricted cash on hand and investments with original maturities of three months or less at the time of purchase.
Allowance for Doubtful Accounts We routinely assess the recoverability of all material trade and other receivables to determine their collectibility. We accrue a reserve on a receivable when, based on management’s judgment, it is probable that a receivable will not be collected and the amount of such reserve may be reasonably estimated. See Note 5. Allowance for Doubtful Accounts.
Inventories Inventories consist primarily of tubular goods and production equipment used in our oil and gas operations, and crude oil produced but not yet sold. Materials and supplies inventories are stated at the lower of average cost or market. The cost of crude oil inventory includes production costs and DD&A expense. See Note 6. Inventories.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Property, Plant and Equipment Significant accounting policies for our property, plant and equipment are as follows:
Successful Efforts Method We account for crude oil and natural gas properties under the successful efforts method of accounting. Under this method, costs to acquire mineral interests in crude oil and natural gas properties, drill and equip exploratory wells that find proved reserves, and drill and equip development wells are capitalized. Capitalized costs of producing crude oil and natural gas properties, along with support equipment and facilities, are amortized to expense by the unit-of-production method based on proved crude oil and natural gas reserves on a field-by-field basis as estimated by our qualified petroleum engineers. Our policy is to use quarter-end reserves and add back current period production to compute quarterly DD&A expense. Costs of certain gathering facilities or processing plants serving a number of properties or used for third-party processing are depreciated using the straight-line method over the useful lives of the assets ranging from five to 14 years. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized. Repairs and maintenance are expensed as incurred.
Proved Property Impairment We review proved oil and gas properties and other long-lived assets for impairment when events and circumstances indicate a decline in the recoverability of the carrying values of such properties, such as a negative revision of reserves estimates or sustained decrease in commodity prices. We estimate future cash flows expected in connection with the properties and compare such future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable. When the carrying amount of a property exceeds its estimated undiscounted future cash flows, the carrying amount is reduced to estimated fair value. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and gas production, commodity prices based on published forward commodity price curves as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate.
We recorded proved property impairment charges in 2010, 2009, and 2008. It is reasonably possible that other proved oil and gas properties could become impaired in the future if commodity prices decline. See Note 4. Asset Impairments.
Unproved Property Impairment We assess individually significant unproved properties for impairment of value on a quarterly basis and recognize a loss at the time of impairment by providing an impairment allowance. In determining whether a significant unproved property is impaired we consider numerous factors including, but not limited to, current exploration plans, favorable or unfavorable exploration activity on the property being evaluated and/or adjacent properties, our geologists' evaluation of the property, and the remaining months in the lease term for the property.
When we have allocated significant fair value to an unproved property as the result of a transaction accounted for as a business combination, we use a future cash flow analysis to assess the unproved property for impairment. Cash flows used in the impairment analysis are determined based on management’s estimates of crude oil and natural gas reserves, future commodity prices and future costs to extract the reserves. Cash flow estimates related to probable and possible reserves are reduced by additional risk-weighting factors. Other individually insignificant unproved properties are amortized on a composite method based on our experience of successful drilling and average holding period.
We recorded unproved property impairment charges in 2008. It is reasonably possible that other unproved oil and gas properties could become impaired in the future if commodity prices decline. See Note 4. Asset Impairments.
Properties Acquired in Business Combinations If sufficient market data is not available, we determine the fair values of proved and unproved properties acquired in transactions accounted for as business combinations by preparing our own estimates of crude oil and natural gas reserves. We estimate future prices to apply to the estimated reserves quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net cash flows. For the fair value assigned to proved reserves, future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the business combination. To compensate for the inherent risk of estimating and valuing unproved reserves, discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors. See Note 3. Acquisitions and Divestitures.
Exploration Costs Geological and geophysical costs, delay rentals, amortization of unproved leasehold costs, and costs to drill exploratory wells that do not find proved reserves are expensed as oil and gas exploration. We carry the costs of an exploratory well as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as we are making sufficient progress assessing the reserves and the economic and operating viability of the project. For certain capital-intensive deepwater Gulf of Mexico or international projects, it may take us more than one year to evaluate the future potential of the exploration well and make a determination of its economic viability. Our ability to move forward on a project may be dependent on gaining access to transportation or processing facilities or obtaining permits and government or partner approval, the timing of which is beyond our control. In such cases, exploratory well costs remain suspended as long as we are actively pursuing access to necessary facilities and access to such permits and approvals and believe they will be obtained. We assess the status of suspended exploratory well costs on a quarterly basis. See Note 7. Capitalized Exploratory Well Costs.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Other Property Other property includes automobiles, trucks, airplanes, office furniture, computer equipment and other fixed assets such as building and leasehold improvements. These items are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets or group of assets, which range from three to ten years.
Capitalization of Interest We capitalize interest costs associated with the development and construction of significant properties or projects to bring them to a condition and location necessary for their intended use, which for crude oil and natural gas assets is at first production from the field. Interest is capitalized using an interest rate equivalent to the average rate we pay on long-term debt, including the credit facility and bonds. Capitalized interest is included in the cost of oil and gas assets and amortized with other costs on a unit-of-production basis. Capitalized interest totaled $67 million in 2010, $45 million in 2009, and $33 million in 2008.
Asset Retirement Obligations Asset retirement obligations consist of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. An asset retirement obligation and the related asset retirement cost are recorded when an asset is first constructed or purchased. The asset retirement cost is determined and discounted to present value using a credit-adjusted risk-free rate. After initial recording the liability is increased for the passage of time, with the increase being reflected as accretion expense in the statement of operations. Subsequent adjustments in the cost estimate are reflected in the liability and the amounts continue to be amortized over the useful life of the related long-lived asset. See Note 11. Asset Retirement Obligations.
Goodwill Goodwill represents the excess of the cost of an acquired entity over the net amounts assigned to assets acquired and liabilities assumed. Goodwill is not amortized to earnings but is tested annually in the fourth quarter or whenever events or changes in circumstances indicate that the carrying value may not be recoverable. No goodwill impairment was indicated at December 31, 2010. However, it is reasonably possible that goodwill could become impaired in the future if commodity prices or other economic factors become less favorable. See Note 9. Goodwill.
Derivative Instruments and Hedging Activities All derivative instruments (including certain derivative instruments embedded in other contracts) are recorded in our consolidated balance sheets as either an asset or liability and measured at fair value. Changes in the derivative instrument’s fair value are recognized currently in earnings, unless the derivative instrument has been designated as a cash flow hedge and specific cash flow hedge accounting criteria are met. Under cash flow hedge accounting, unrealized gains and losses are reflected in shareholders’ equity as accumulative other comprehensive loss (AOCL) until the forecasted transaction occurs. The derivative’s gains or losses are then offset against related results on the hedged transaction in the statements of operations.
A company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting. Only derivative instruments that are expected to be highly effective in offsetting anticipated gains or losses on the hedged cash flows and that are subsequently documented to have been highly effective can qualify for hedge accounting. Effectiveness must be assessed both at inception of the hedge and on an ongoing basis. Any ineffectiveness in hedging instruments whereby gains or losses do not exactly offset anticipated gains or losses of hedged cash flows is measured and recognized in earnings in the period in which it occurs. When using hedge accounting, we assess hedge effectiveness quarterly based on total changes in the derivative instrument’s fair value by performing regression analysis. A hedge is considered effective if certain statistical tests are met. We record hedge ineffectiveness in (gain) loss on commodity derivative instruments.
Accounting for Commodity Derivative Instruments We account for our commodity derivative instruments using mark-to-market accounting and recognize all gains and losses in earnings during the period in which they occur. Prior to January 1, 2008, we elected to designate certain of our commodity derivative instruments as cash flow hedges. Effective January 1, 2008, we voluntarily discontinued cash flow hedge accounting for our commodity derivative instruments. Net derivative gains and losses that were deferred in AOCL as of January 1, 2008, as a result of previous cash flow hedge accounting, were reclassified to earnings during the years ended December 31, 2008 through December 31, 2010 as the original transactions occurred.
We offset the fair value amounts recognized for derivative instruments and the fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral. The cash collateral (commonly referred to as a “margin”) must arise from derivative instruments recognized at fair value that are executed with the same counterparty under a master netting arrangement.
Accounting for Interest Rate Derivative Instruments We designate interest rate derivative instruments as cash flow hedges. Changes in fair value of interest rate swaps or interest rate “locks” used as cash flow hedges are reported in AOCL, to the extent the hedge is effective, until the forecasted transaction occurs, at which time they are recorded as adjustments to interest expense over the term of the related notes.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
See Note 10. Derivative Instruments and Hedging Activities.
Pension and Other Postretirement Benefit Plans We recognize the funded status (the difference between the fair value of plan assets and the projected benefit obligation) of our defined benefit pension, restoration and other postretirement benefit plans in the consolidated balance sheets, with a corresponding adjustment to AOCL, net of tax. The amount remaining in AOCL at December 31, 2010 represents unrecognized net actuarial loss, unrecognized prior service cost, and unrecognized net transition obligation remaining from the initial adoption of US GAAP for employers’ accounting for pensions and other postretirement benefits. These amounts are currently being recognized as net periodic benefit cost pursuant to our historical accounting policy for amortizing such amounts. Any actuarial gains and losses that arise during the plan year, but which are not required to be recognized as net periodic benefit cost in the same period, are recognized as a component of AOCL. See Note 14. Benefit Plans.
Stock-Based Compensation We recognize the grant-date fair value of stock options and other stock-based compensation issued to employees in the statement of operations. Expense is recognized on a straight-line basis over the employee’s requisite service period (generally the vesting period of the award). See Note 15. Stock-Based Compensation.
Income Taxes Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized when items of income and expense are recognized in the financial statements in different periods than when recognized in the applicable tax return. Deferred tax assets arise when expenses are recognized in the financial statements before the tax returns or when income items are recognized in the tax return prior to the financial statements. Deferred tax assets also arise when operating losses or tax credits are available to offset tax payments due in future years. Deferred tax liabilities arise when income items are recognized in the financial statements before the tax returns or when expenses are recognized in the tax return prior to the financial statements. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date when the change in the tax rate was enacted. See Note 13. Income Taxes.
Treasury Stock We record treasury stock purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as reductions in shareholders’ equity in the consolidated balance sheets.
Revenue Recognition and Imbalances We record revenues from the sales of crude oil, natural gas and natural gas liquids (NGLs) when the product is delivered at a fixed or determinable price, title has transferred and collectibility is reasonably assured.
When we have an interest with other producers in properties from which natural gas is produced, we use the entitlements method to account for any imbalances. Imbalances occur when we sell more or less product than we are entitled to under our ownership percentage. Revenue is recognized only on the entitlement percentage of volumes sold. Any amount that we sell in excess of our entitlement is treated as a liability and is not recognized as revenue. Any amount of entitlement in excess of the amount we sell is recognized as revenue and a receivable is accrued.
Revenues derived from electricity generation are recognized when power is transmitted or delivered, the price is fixed and determinable and collectibility is reasonably assured.
Basic and Diluted Earnings Per Share Basic earnings per share (EPS) of our common stock have been computed on the basis of the weighted average number of shares outstanding during each period. The diluted EPS of our common stock includes the effect of outstanding common stock equivalents such as stock options, shares of restricted stock, and/or shares of our stock held in a rabbi trust, except in periods in which there is a net loss. See Note 17. Earnings Per Share.
Contingencies We are subject to legal proceedings, claims and liabilities that arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are considered probable and the amounts can be reasonably estimated. See Note 21. Commitments and Contingencies.
We self-insure the medical and dental coverage provided to certain employees, certain workers’ compensation and the first $1 million of general liability coverage. Liabilities are accrued for self-insured claims, or when estimated losses exceed coverage limits, and when sufficient information is available to reasonably estimate the amount of the loss.
Foreign Currency The US dollar is considered the functional currency for each of our international operations. Transactions that are completed in foreign currencies are remeasured into US dollars and recorded in the financial statements at prevailing foreign exchange rates. Transaction gains or losses were not material in any of the periods presented and are included in other non-operating (income) expense, net in the consolidated statements of operations.
Segment Information Accounting policies for geographical segments are the same as those described above. Transfers between segments are accounted for at market value. We do not consider interest income and expense or income tax benefit or expense in our evaluation of the performance of geographical segments. See Note 18. Segment Information.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 2. Additional Financial Statement Information
Additional statements of operations information is as follows:
(1)
Amount represents electricity sales from the Machala power plant located in Machala, Ecuador. Electricity generation expense includes all operating and non-operating expenses associated with the plant, including DD&A and changes in the allowance for doubtful accounts. See Note 3. Acquisitions and Divestitures, Note 4. Asset Impairments, and Note 5. Allowance for Doubtful Accounts.
(2)
The refund was attributable to royalties that we previously paid on crude oil and natural gas produced in the deepwater Gulf of Mexico from January 1, 2003 through July 31, 2009.
(3)
Amount relates primarily to an agreement to terminate our contract for the Noble Clyde Boudreaux drilling rig as a result of the Deepwater Moratorium.
(4)
See Note 5. Allowance for Doubtful Accounts.
(5)
Amount represents increases (decreases) in the fair value of shares of our common stock held in a rabbi trust. See Note 14. Benefit Plans.
(6)
Interest income for 2010 and 2009 includes $3 million and $11 million, respectively, related to the refund of deepwater Gulf of Mexico royalties.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Additional balance sheet information is as follows:
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Supplemental statements of cash flow information is as follows:
(1)
See Note 12. Long-Term Debt.
Note 3. Acquisitions and Divestitures
Central DJ Basin Asset Acquisition On March 1, 2010, we acquired substantially all of the US Rocky Mountain assets of Petro-Canada Resources (USA) Inc. and Suncor Energy (Natural Gas) America Inc. The acquisition included properties located in the Central DJ Basin, one of our key operating areas.
The total purchase price and allocation of the total purchase price are as follows:
The difference between the total purchase price and the fair values of the assets acquired was de minimis.
To estimate the fair values of the properties as of the acquisition date, we used an income approach as comparable market data was not available. We utilized a discounted cash flow model which took into account the following inputs to arrive at estimates of future net cash flows:
·
estimated quantities of crude oil and natural gas prepared by our qualified petroleum engineers;
·
estimated future commodity prices based on NYMEX crude oil and natural gas futures prices as of the acquisition date and adjusted for estimated location and quality differentials;
·
estimated future production rates based on our experience with similar Central DJ Basin properties which we operate; and
·
estimated timing and amounts of future operating and development costs based on our experience with similar Central DJ Basin properties which we operate.
To estimate the fair value of proved properties, we discounted the future net cash flows using a market-based weighted average cost of capital rate determined appropriate at the acquisition date. To compensate for the inherent risk of estimating and valuing unproved properties, we reduced the discounted future net cash flows of probable and possible reserves by additional risk-weighting factors. The fair values of the proved and unproved oil and gas properties are considered Level 3 fair value measurements.
Certain data necessary to complete the final purchase price allocation is not yet available, and includes, but is not limited to, final appraisals of assets acquired and liabilities assumed. We expect to complete the final purchase price allocation during the 12-month period following the acquisition date, during which time the preliminary allocation may be revised.
Related transaction costs were expensed. We have not presented pro forma information for the acquired business as the impact of the acquisition was not material to our consolidated balance sheet or results of operations. See also Note 16. Fair Value Measurements and Disclosures.
Sale of Onshore US Assets In August 2010, we closed the sale of non-core assets in the Mid-Continent and Illinois Basin areas. Information regarding the assets sold is as follows:
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Mid-Continent Acquisition In 2008, we acquired producing properties in western Oklahoma for $292 million. The total purchase price was allocated to the proved and unproved properties acquired based on fair values at the acquisition date. Approximately $254 million was allocated to proved properties and $38 million to unproved properties.
Sale of Argentina Assets In 2008, we sold our interest in Argentina for a sales price of $117.5 million. The sale was subject to Argentine government approval. The $24 million gain on sale was deferred in other current liabilities until 2009 when the Argentine government approved the sale.
Termination of Ecuador PSC The government of Ecuador terminated the Block 3 PSC (100% working interest) with our subsidiary, EDC Ecuador Ltd. as we had not negotiated a service contract on Block 3 in accordance with the terms of a newly enacted hydrocarbon law. The hydrocarbon law aims to change current production-sharing arrangements into service contracts and provides for renegotiation of certain contracts by November 23, 2010. It also allows the Ecuadorian government to nationalize oil and gas fields if a private operator does not comply with local laws.
We are continuing to work with the government of Ecuador to resolve this matter. However, we are uncertain as to the potential outcome of this matter, resolution of which could ultimately lead to a reduction in the value of our investment in Ecuador which, as of December 31, 2010, had a net book value of approximately $66 million.
Note 4. Asset Impairments
Pre-tax (non-cash) asset impairment charges were as follows:
2010 Asset Impairments Due to declines in natural gas prices and recent drilling results, we determined that the carrying amount of our onshore US development at Iron Horse was not recoverable from future cash flows and, therefore, was impaired. We also recorded impairments of our non-core, New Albany Shale assets which had been reclassified to held-for-sale; our deepwater Gulf of Mexico development at Raton, primarily due to declines in natural gas prices; a Gulf of Mexico shelf asset; and our investment in the Noa/Noa South development, offshore Israel. We believe that it is less likely that Noa will be pursued for development due to near-term capability at the Mari-B field and the longer-term outlook from our discoveries at Tamar and Leviathan.
The Iron Horse, Raton and Gulf of Mexico Shelf assets were written down to their estimated fair values, which were determined using discounted cash flow models. The discounted cash flow models included management’s estimates of future oil and gas production, commodity prices based on forward commodity price curves as of the date of the estimate, operating and development costs, and discount rates. The New Albany Shale assets were written down to anticipated sales proceeds less costs to sell.
2009 Asset Impairments Declines in natural gas prices resulted in impairments of Granite Wash, an onshore US area where we significantly reduced our investment beginning in 2007, and our New Albany Shale development. We also impaired our deepwater Gulf of Mexico development at Raton, primarily due to well performance issues and our Gulf of Mexico shelf asset at Main Pass, which had been reclassified from held-for-sale to held-and-used. The assets were written down to their estimated fair values, which were determined using discounted cash flow models.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
We also reviewed our investment in Ecuador for impairment, as a result of the increasingly unsettled economic and political environment in Ecuador, and determined that the carrying value of our investment exceeded its fair value. We estimated the fair value of our investment using a probability-weighted discounted cash flow model that considered the likelihood of possible outcomes of (1) the event of continued operation of the assets in contemplation of resolving the dispute and in accordance with the existing contract, (2) the event of a sale of our investment to a third party, and (3) the event of arbitration with varying degrees of award and collection. The use of alternative judgments and/or assumptions could have resulted in the recognition of an impairment charge that was significantly different.
2008 Asset Impairments As a result of the depressed economic environment, coupled with a severe decrease in commodity prices during the fourth quarter of 2008, we assessed the recoverability of our proved oil and gas properties, individually significant unproved oil and gas properties, and investment in Ecuador as of December 31, 2008. As a result, we determined that certain of our assets were impaired. The assets were written down to their estimated fair values, which were determined using discounted cash flow models. Onshore US unproved properties impaired in 2008 had been acquired in previous business combinations and fair values were attributable to probable and possible reserves. We also recorded an impairment charge related to our Main Pass asset based on anticipated sales proceeds less costs to sell.
See also Note 16. Fair Value Measurements and Disclosures.
Note 5. Allowance for Doubtful Accounts
Changes in the allowance for doubtful accounts were as follows:
(1)
Amount in 2009 was received in accordance with the terms of a settlement agreement and included as a reduction in electricity generation expense.
(2)
SemCrude, L.P. was a crude oil purchaser who filed a voluntary petition for reorganization under Chapter 11 of the Bankruptcy Code in 2008.
Note 6. Inventories
Inventories consisted of the following:
Note 7. Capitalized Exploratory Well Costs
We capitalize exploratory well costs until a determination is made that the well has found proved reserves or is deemed noncommercial. If a well is deemed to be noncommercial, the well costs are immediately charged to exploration expense.
Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed in the same period:
Noble Energy, Inc.
Notes to Consolidated Financial Statements
The following table provides an aging of capitalized exploratory well costs (suspended well costs) based on the date the drilling was completed and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling:
The following table provides a further aging of those exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling as of December 31, 2010:
Blocks O and I (West Africa) The West Africa project includes Blocks O and I offshore Equatorial Guinea and the YoYo mining concession and Tilapia PSC offshore Cameroon. In December 2010, we and our partners sanctioned the development plan for Alen, which was subsequently approved by the government of Equatorial Guinea in January 2011. Approximately $61 million of capitalized costs were reclassified to proved oil and gas properties. In 2009, we sanctioned the Aseng development project and reclassified $76 million of capitalized costs to proved oil and gas properties. We are evaluating future oil projects and planning to drill an appraisal well at Diega/Carmen, offshore Equatorial Guinea. In Cameroon, we recently completed a 3-D seismic acquisition, and results are being processed for future drilling potential.
Dalit (Israel) Dalit is a 2009 natural gas discovery located offshore Israel. We are currently working with our partners on a cost-effective development plan. In 2010, we sanctioned the Tamar development project and reclassified $77 million of capitalized costs to proved oil and gas properties.
Gunflint (Deepwater Gulf of Mexico) Gunflint (Mississippi Canyon Block 948) is a 2008 crude oil discovery. Our plans to drill one or two appraisal wells in 2010 were delayed by the Deepwater Moratorium. Once a drilling permit is approved, we plan to drill one or two appraisal wells. We are also reviewing host platform options including: subsea tieback to an existing third-party host, procurement and modification of an existing platform, and new construction. If we are able to connect to an existing third-party host, the project could have an accelerated completion schedule, thereby potentially absorbing time lost due to the drilling delay caused by the Deepwater Moratorium.
Redrock (Deepwater Gulf of Mexico) Redrock (Mississippi Canyon Block 204) was a 2006 natural gas/condensate discovery and is currently considered a co-development candidate with Raton South (Mississippi Canyon Block 292). We are in the process of tying back Raton South to a host platform at Viosca Knoll Block 900. We plan to tie back Redrock after Raton South commences production, which is currently expected to occur by the end of 2011.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Deep Blue (Deepwater Gulf of Mexico) Deep Blue (Green Canyon Block 723) was a significant test well, which began drilling during 2009. When the Deepwater Moratorium was announced in May 2010, we were required to suspend sidetrack drilling activities at the Deep Blue prospect. Once a drilling permit is approved, we plan to resume exploration activities at Deep Blue.
Flyndre (North Sea) The Flyndre project is located in the UK sector of the North Sea and we successfully completed an exploratory appraisal well in 2007. We are currently working with the project operator and other partners to finalize the field development plan and relevant operating agreements.
Selkirk (North Sea) The Selkirk project is also located in the UK sector of the North Sea. Capitalized costs to date primarily consist of the cost of drilling an exploratory well. We are currently working with our partners on a cost-effective development plan, including selection of a host facility.
Note 8. Equity Method Investments
Investments accounted for under the equity method consist primarily of the following:
·
45% interest in Atlantic Methanol Production Company, LLC (AMPCO), which owns and operates a methanol plant and related facilities in Equatorial Guinea; and
·
28% interest in Alba Plant LLC (Alba Plant), which owns and operates a liquefied petroleum gas processing plant in Equatorial Guinea.
Equity method investments are included in other noncurrent assets in the consolidated balance sheets, and our share of earnings is reported as income from equity method investees in the consolidated statements of operations. Our share of income taxes incurred directly by the equity method investees is reported in income from equity method investments and is not included in our income tax provision in our consolidated statements of operations. At December 31, 2010, our retained earnings included $122 million related to the undistributed earnings of equity method investees.
The carrying value of our AMPCO investment was $21 million higher than the underlying net assets of the investee at December 31, 2010. The difference includes $12 million relating to capitalized interest which is being amortized into earnings over the remaining useful life of the plant. The remaining $9 million relates to a note receivable from our funding a portion of the local government’s share of the plant’s development. The note receivable is being recovered through distributions from AMPCO.
Equity method investments are as follows:
Summarized, 100% combined financial information for equity method investees is as follows:
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 9. Goodwill
Changes in the carrying amount of goodwill were as follows:
Note 10. Derivative Instruments and Hedging Activities
Objective and Strategies for Using Derivative Instruments In order to reduce commodity price uncertainty and enhance the predictability of cash flows relating to the marketing of our crude oil and natural gas, we enter into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production. The derivative instruments we use include variable to fixed price commodity swaps, two-way and three-way collars and basis swaps.
The fixed price swap, two-way collar, and basis swap contracts entitle us (floating price payor) to receive settlement from the counterparty (fixed price payor) for each calculation period in amounts, if any, by which the settlement price for the scheduled trading days applicable for each calculation period is less than the fixed strike price or floor price. We would pay the counterparty if the settlement price for the scheduled trading days applicable for each calculation period is more than the fixed strike price or ceiling price. The amount payable by us, if the floating price is above the fixed or ceiling price, is the product of the notional quantity per calculation period and the excess, if any, of the floating price over the fixed or ceiling price in respect of each calculation period. The amount payable by the counterparty, if the floating price is below the fixed or floor price, is the product of the notional quantity per calculation period and the excess, if any, of the fixed or floor price over the floating price in respect of each calculation period.
A three-way collar consists of a two-way collar contract combined with a put option contract sold by us with a strike price below the floor price of the two-way collar. We receive price protection at the purchased put option floor price of the two-way collar if commodity prices are above the sold put option strike price. If commodity prices fall below the sold put option strike price, we receive the cash market price plus the delta between the two put option strike prices. This type of instrument allows us to capture more value in a rising commodity price environment, but limits our benefits in a downward commodity price environment.
We also enter into forward contracts or swap agreements to hedge exposure to interest rate risk.
While these instruments mitigate the cash flow risk of future reductions in commodity prices or increases in interest rates, they may also curtail benefits from future increases in commodity prices or decreases in interest rates.
See Note 16. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of our derivative instruments.
Counterparty Credit Risk Derivative instruments expose us to counterparty credit risk. Our commodity derivative instruments are currently with a diversified group of highly rated major banks or market participants, and we control our level of financial exposure. Our commodity derivative contracts are executed under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net settled at the time of election.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
We monitor the creditworthiness of our counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices or higher interest rates, and could incur a loss.
Unsettled Derivative Instruments We have entered into the following crude oil derivative instruments:
(1)
West Texas Intermediate
We have entered into the following natural gas derivative instruments:
(1)
Henry Hub
As of December 31, 2010, we had entered into the following natural gas basis swaps:
(1)
Colorado Interstate Gas - Northern System
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Fair Value Amounts and Gains and Losses on Derivative Instruments The fair values of derivative instruments in our consolidated balance sheets were as follows:
(1)
In 2010, in anticipation of a long-term debt issuance, we entered into an interest rate forward starting swap to effectively fix the cash flows related to interest payments on the anticipated debt issuance. We are accounting for the instrument as a cash flow hedge against the variability of interest payments attributable to changes in interest rates on the forecasted issuance of fixed-rate debt. The swap is in the notional amount of $500 million and is based on a 30-year LIBOR swap rate.
The effect of derivative instruments on our consolidated statements of operations was as follows:
(1)
Includes effect of commodity derivative instruments previously accounted for as cash flow hedges. Net derivative gains and losses that were deferred in AOCL as of January 1, 2008, as a result of previous cash flow hedge accounting, were reclassified to oil, gas and NGL sales in our consolidated statements of operations in 2008, 2009 and 2010 as the original hedged transactions occurred.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
AOCL - Commodity Derivative Instruments At December 31, 2010, AOCL included no further amounts related to commodity derivative instruments. At December 31, 2009, the balance in AOCL included net deferred losses of $12 million (net of deferred income tax benefits of $8 million) related to the fair value of crude oil and natural gas derivative instruments previously designated as cash flow hedges. The net deferred losses were reclassified to earnings during 2010 as the forecasted transactions occurred and recorded as a reduction in oil, gas and NGL sales of approximately $20 million before tax.
AOCL - Interest Rate Derivative Instruments At December 31, 2010, AOCL included deferred losses of $42 million, net of tax, related to interest rate derivative instruments. Of this amount, $1 million, net of tax, is currently being reclassified into earnings as adjustments to interest expense over the term of our Senior Notes due April 2014. Approximately $41 million will remain in AOCL until fixed-rate debt is issued, at which time we will begin amortizing it to interest expense over the life of the related debt issuance.
Note 11. Asset Retirement Obligations
Changes in asset retirement obligations were as follows:
For the year ended December 31, 2010, liabilities incurred were primarily due to the Central DJ Basin asset acquisition. Liabilities settled related to non-core onshore US properties sold, abandoned Gulf of Mexico shelf assets, and Block 3 offshore Ecuador. Revisions resulted from changes in estimated timing of actual abandonment due to shortened field lives for certain UK assets and overall cost increases for assets located primarily in the deepwater Gulf of Mexico.
For the year ended December 31, 2009, liabilities incurred related primarily to properties in the deepwater Gulf of Mexico, the Aseng field, offshore Equatorial Guinea, and North Sea projects. Liabilities settled related primarily to properties in the Main Pass and Viosca Knoll areas of the Gulf of Mexico. Revisions related to the Main Pass asset and a deepwater Gulf of Mexico property.
Accretion expense is included in depreciation, depletion and amortization expense in the consolidated statements of operations.
Note 12. Long-Term Debt
Our debt consists of the following:
(1)
Amount reported is based on percentage of FPSO construction activities completed as of December 31, 2010 and therefore does not reflect future minimum lease payments. See FPSO Lease Obligation below.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
All of our long-term debt is senior unsecured debt and is, therefore, pari passu with respect to the payment of both principal and interest. The indenture documents of each of our notes provide that we may prepay the instruments by creating a defeasance trust. The defeasance provisions require that the trust be funded with securities sufficient, in the opinion of a nationally recognized accounting firm, to pay all scheduled principal and interest due under the respective agreements. Interest on each of these issues is payable semi-annually. Debt issuance costs of approximately $11 million remain and are being amortized to expense over the life of the related debt issues.
Credit Facility Our bank revolving credit facility (the credit facility) is committed in the amount of $2.1 billion until December 9, 2011 at which time the commitment reduces to $1.8 billion. The credit facility (i) provides for credit facility fee rates that range from 5 basis points to 15 basis points per year depending upon our credit rating, (ii) makes available short-term loans up to an aggregate amount of $300 million within the current $2.1 billion commitment and (iii) provides for interest rates that are based upon the Eurodollar rate plus a margin that ranges from 20 basis points to 70 basis points depending upon our credit rating and utilization of the credit facility. The credit facility requires that our total debt to capitalization ratio (as defined in the credit agreement), expressed as a percentage, not exceed 60% at any time. A violation of this covenant could result in a default under the credit facility, which would permit the participating banks to restrict our ability to access the credit facility and require the immediate repayment of any outstanding advances under the credit facility. As of December 31, 2010, we were in compliance with our debt covenants. The credit facility is with certain commercial lending institutions and is available for general corporate purposes.
Certain lenders that are a party to the credit facility have in the past performed investment banking, financial advisory, lending or commercial banking services for us, for which they have received customary compensation and reimbursement of expenses.
The credit facility does not restrict the payment of dividends on our common stock, except, if after giving effect thereto, an Event of Default shall have occurred and be continuing or been caused thereby.
FPSO Lease Obligation In 2009, we entered into an agreement with an unrelated offshore technology provider for the construction and lease of an FPSO to be used for development of the Aseng field, offshore Equatorial Guinea. We serve as technical operator of the development project with a 40% working interest.
Construction of the FPSO is scheduled to be completed in 2012, at which time the FPSO will be delivered to Block I, offshore Equatorial Guinea, for the start-up of the Aseng field. The initial term of the lease is for a period of 15 years. We expect to account for the lease agreement as a capital lease. As a result, the FPSO will be included in oil and gas properties and the associated long-term obligation will be included in our balance sheet. We expect that the lease obligation will total approximately $358 million, net to our 40% interest. This amount represents our share of the expected present value of the future minimum lease payments, excluding executory costs, and is subject to change based on change orders implemented during the construction period, final accounting treatment and other factors.
Throughout the construction phase, we will include both the FPSO asset and associated long-term obligation in our balance sheet, based upon the percentage of construction completed at the end of each reporting period.
Monthly lease payments will exclude regular maintenance and operational costs, and will begin when the FPSO initiates producing operations. See Note 21. Commitments and Contingencies for estimated annual lease payments.
2009 Debt Offering In 2009, we closed an offering of $1 billion senior unsecured notes receiving net proceeds of $989 million, after deducting the discount and underwriting fees. The notes are due March 1, 2019, and pay interest semi-annually at 8¼%. Debt issuance costs of approximately $2 million were incurred and are being amortized to expense over the life of the debt issue. Substantially all of the net proceeds from the offering were used to repay outstanding indebtedness under our revolving credit facility maturing 2012. The notes are senior unsecured debt and rank pari passu with any of our other senior unsecured indebtedness with respect to the payment of both principal and interest.
2009 Debt Repurchase In 2009, we repurchased $5 million of our Senior Debentures due August 1, 2097, recognizing a debt extinguishment gain of $1 million.
Annual Maturities Annual maturities of outstanding debt, excluding FPSO lease payments, are as follows:
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Short-Term Borrowings Our credit agreement is supplemented by short-term borrowings under various uncommitted credit lines used for working capital purposes. Uncommitted credit lines may be offered by certain banks from time to time at rates negotiated at the time of borrowing. No short-term borrowings were outstanding at December 31, 2010 or 2009.
Note 13. Income Taxes
Components of income (loss) before income taxes are as follows:
The income tax provision (benefit) consists of the following:
A reconciliation of the federal statutory tax rate to the effective tax rate is as follows:
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Deferred tax assets and liabilities resulted from the following:
Net deferred tax liabilities were classified in the consolidated balance sheets as follows:
Deferred Tax Assets In assessing the realizability of deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income in the appropriate tax jurisdictions during the periods in which those temporary differences become deductible. We consider the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, we believe it is more likely than not that we will realize the benefits of these deductible differences at December 31, 2010. The amount of the deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced.
We have recognized deferred tax assets associated with foreign loss carryforwards. The tax effects of these carryforwards totaled $35 million in 2008, increased to $47 million in 2009 and increased to $70 million in 2010. Losses continue to be incurred on our projects in Equatorial Guinea and new venture activities which are not yet commercial.
During 2010, we reversed a $28 million valuation allowance that had been provided against a deferred tax asset of the same amount for the future foreign tax credits associated with deferred tax liabilities recorded by foreign branch operations and recorded a reduction in income tax expense. We now believe it is more likely than not that this deferred tax asset will be realized.
Effective Tax Rate Our effective tax rate decreased in 2010 as compared with 2009. For 2010, the effective rate was lower than the federal statutory rate because our income from equity method investees and other permanent differences have the impact of decreasing the effective rate when we have pre-tax income. We also recorded a reduction in income tax expense due to the reversal of a deferred tax asset valuation allowance.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Our effective tax rate increased in 2009 as compared with 2008 and is the result of a tax benefit divided by a pre-tax loss. In the case of a loss, our favorable permanent differences, such as income from equity method investees, have the effect of increasing the tax benefit which, in turn, increases the effective rate.
Repatriation During 2009, we repatriated $180 million of accumulated earnings of foreign subsidiaries and used the proceeds for debt repayment and general corporate purposes. The repatriation increased US tax expense by $13 million, of which $9 million was recorded in 2008. Repatriation of additional earnings in the future could result in a decrease in our net income and cash flows.
Accumulated Undistributed Earnings of Foreign Subsidiaries As of December 31, 2010, the accumulated undistributed earnings of the foreign subsidiaries on which no US taxes have been recorded were approximately $1.5 billion. Upon distribution of additional earnings in the form of dividends or otherwise, we would likely be subject to US income taxes and foreign withholding taxes. It is not practicable, however, to determine precisely the amount of taxes that may be payable on the eventual remittance of these earnings because of the possible application of US foreign tax credits. Although we are currently claiming foreign tax credits, we may not be in a credit position when any future remittance of foreign earnings takes place, or the limitations imposed by the Internal Revenue Code and IRS Regulations may not allow the credits to be utilized during the applicable carryback and carryforward periods. However, if full use of tax credits is assumed, we estimate that the future US taxes on eventual remittance would be approximately $260 million.
Unrecognized Tax Benefits We did not have significant unrecognized tax benefits resulting from differences between positions taken in tax returns and amounts recognized in the financial statements as of December 31, 2010 or 2009. Our policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense. However, we did not accrue interest or penalties at December 31, 2010 or 2009, because the jurisdiction in which we have unrecognized tax benefits does not currently impose interest on underpayments of tax and we believe that we are below the minimum statutory threshold for imposition of penalties. We do not expect that the total amount of unrecognized tax benefits will significantly increase or decrease during the next 12 months.
Years Open to Examination In our major tax jurisdictions, the earliest years remaining open to examination are as follows: US - 2006, Equatorial Guinea - 2007, Israel - 2008, UK - 2007, the Netherlands - 2009, and China - 2006.
Note 14. Benefit Plans
Pension and Other Postretirement Benefit Plans We have a noncontributory, tax-qualified defined benefit pension plan covering employees who were hired prior to May 1, 2006. The benefits are based on an employee’s years of service and average earnings for the 60 consecutive calendar months of highest compensation. Our funding policy has been to make annual contributions equal to at least the minimum required contribution, but no greater than the maximum deductible for federal income tax purposes. We also have an unfunded, nonqualified restoration plan that provides the pension plan formula benefits that cannot be provided by the qualified pension plan because of pay deferrals and the compensation and benefit limitations imposed on the pension plan by the Internal Revenue Code of 1986, as amended. We sponsor other plans for the benefit of our employees and retirees, which include medical and life insurance benefits. We use a December 31 measurement date for the plans.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Changes in the benefit obligation and plan assets of the pension, restoration and other postretirement benefit plans were as follows at December 31:
(1)
Plan amendments relate to an increase in the monthly retiree contributions for the medical and life plan.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Net periodic benefit cost recognized for the pension, restoration and other postretirement benefit plans was as follows:
(1)
The discount rates used to determine benefit obligations at December 31, 2010 were 5.50% for the retirement plan and 5.25% for the restoration plan. The discount rates used to determine benefit obligations at December 31, 2008 and net periodic benefit costs for the year ended December 31, 2009 were 6.00% for the retirement plan and 6.25% for the restoration plan.
Additional disclosures for the retirement and restoration plans are as follows:
In selecting the assumption for expected long-term rate of return on assets, we consider the average rate of earnings expected on the funds to be invested to provide for plan benefits. This includes considering the plan’s asset allocation, historical returns on these types of assets, the current economic environment and the expected returns likely to be earned over the life of the plan. We assume the long-term asset mix will be consistent with a target asset allocation of 70% equity and 30% fixed income, with a range in the acceptable degree of variation in the plan’s asset allocation of plus or minus 10%. Based on these factors we assumed an average of 7.50% per annum over the life of the plan for the calculation of 2010 net periodic benefit cost. The assumption will be reduced to 7.25% for the calculation of 2011 net periodic benefit cost. No plan assets are expected to be returned to us in 2011.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
In order to determine an appropriate discount rate at December 31, 2010, we performed an analysis of the Citigroup Pension Discount Curve (the CPDC) as of that date for each of our plans. The CPDC uses spot rates that represent the equivalent yield on high quality, zero coupon bonds for specific maturities. We used these rates to develop an equivalent single discount rate based on our plans’ expected future benefit payment streams and duration of plan liabilities. A 1% increase in the discount rate would have resulted in a decrease in net periodic benefit cost of approximately $3 million in 2010. A 1% decrease in the discount rate would have resulted in an increase in net periodic benefit cost of approximately $3 million in 2010.
Assumed health care cost trend rates were as follows:
Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
Weighted-average asset allocations for the tax-qualified defined benefit pension plan are as follows:
The investment policy for the tax-qualified defined benefit pension plan is determined by an employee benefits committee (the committee) with input from a third-party investment consultant. Based on a review of historical rates of return achieved by equity and fixed income investments in various combinations over multi-year holding periods and an evaluation of the probabilities of achieving acceptable real rates of return, the committee has determined the target asset allocation deemed most appropriate to meet immediate and future benefit payment requirements for the plan and to provide a diversification strategy which reduces market and interest rate risk. The fixed income allocation is expected to directionally track a portion of the plan’s liabilities, thus reducing overall plan interest rate risk. A 1% increase (decrease) in the expected return on plan assets would have resulted in a (decrease) increase, respectively, in net periodic benefit cost of approximately $2 million in 2010.
We base our determination of the asset return component of pension expense on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets. Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded. As of January 1, 2011, we had cumulative asset losses of approximately $2 million, which remain to be recognized in the calculation of the market-related value of assets.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Additional fair value disclosures about plan assets are as follows:
Additional information about plan assets, including methods and assumptions used to estimate the fair values of plan assets, is as follows:
Federal Money Market Funds Investments in federal money market funds consist of portfolios of high quality fixed income securities (such as US Treasury securities) which, generally, have maturities of less than one year. The fair value of these investments is based on quoted market prices for identical assets as of the measurement date.
Mutual Funds Investments in mutual funds consist of diversified portfolios of common stocks and fixed income instruments. The common stock mutual funds are diversified by market capitalization and investment style as well as economic sector and industry. The fixed income mutual funds are diversified primarily in government bonds, mortgage backed securities, and corporate bonds, most of which are rated investment grade. The fair values of these investments are based on quoted market prices for identical assets as of the measurement date.
Common Collective Trust Funds Investments in common collective trust funds consist of common stock investments in both US and non-US equity markets. Portfolios are diversified by market capitalization and investment style as well as economic sector and industry. The investments in the non-US equity markets are used to further enhance the plan’s overall equity diversification which is expected to moderate the plan’s overall risk volatility. In addition to the normal risk associated with stock market investing, investments in foreign equity markets may carry additional political, regulatory, and currency risk which is taken into account by the committee in its deliberations. The fair value of these investments is based on quoted prices for similar assets in active markets. All of the investments in common collective trust funds represent exchange-traded securities with readily observable prices.
Contributions We expect to make cash contributions of approximately $13 million to the pension plan during 2011. We expect to make cash contributions of $3 million to the unfunded restoration plan and $1 million to the medical and life plans in 2011, which amounts equal expected benefit payments from those plans. (Unaudited).
Estimated Future Benefit Payments As of December 31, 2010, the following future benefit payments are expected to be paid:
Noble Energy, Inc.
Notes to Consolidated Financial Statements
The estimate of expected future benefit payments is based on the same assumptions used to measure the benefit obligation at December 31, 2010 and includes estimated future employee service.
401(k) Plan We sponsor a 401(k) savings plan. All regular employees are eligible to participate. We make contributions to match employee contributions up to the first 6% of compensation deferred into the plan, and certain profit sharing contributions for employees hired on or after May 1, 2006, based upon their ages and salaries. We made cash contributions of $11 million in 2010, $9 million in 2009, and $7 million in 2008.
Deferred Compensation Plans We have a non-qualified deferred compensation plan for which participant-directed investments are held in a rabbi trust and are available to satisfy the claims of our creditors in the event of bankruptcy or insolvency. Participants may elect to receive distributions in either cash or shares of our common stock. Components of the rabbi trust are as follows:
(1)
Shares of our common stock are accounted for as treasury stock and recorded at cost in the consolidated balance sheets.
Assets of the rabbi trust, other than our common stock, are invested in certain mutual funds that cover an investment spectrum ranging from equities to money market instruments. These mutual funds have published market prices and are reported at fair value. See Note 16. Fair Value Measurements and Disclosures. The mutual funds are included in the mutual fund investments account in other noncurrent assets in the consolidated balance sheets.
Shares of our common stock held by the rabbi trust are accounted for as treasury stock (recorded at cost) in the shareholders’ equity section of the consolidated balance sheets. The amounts payable to the plan participants are included in other noncurrent liabilities in the consolidated balance sheets and include the market value of the shares of our common stock. Approximately 900,000 shares, or 95%, of our common stock held in the plan at December 31, 2010 were attributable to a member of our Board of Directors. Plan participants received distributions of 100,000 shares of our common stock in 2010, and sold 100 shares of our common stock in 2010, 1,892 shares in 2009, and 50,000 shares in 2008. Proceeds were invested in mutual funds and/or distributed to plan participants. Distributions to plan participants totaled $17 million in 2010, were de minimis in 2009, and totaled $1 million in 2008.
All fluctuations in market value of the deferred compensation liability have been reflected in other non-operating (income) expense, net in the consolidated statements of operations. We recognized deferred compensation expense of $15 million in 2010 and $23 million in 2009 and deferred compensation income of $32 million in 2008.
We also maintain an unfunded deferred compensation plan for the benefit of certain of our employees. Deferred compensation liabilities of $51 million and $45 million were outstanding at December 31, 2010 and 2009, respectively, under the unfunded plan.
Note 15. Stock-Based Compensation
We recognized total stock-based compensation expense as follows:
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Stock Option and Restricted Stock Plans and Incentive Plan Our stock option and restricted stock plans and incentive plan are described below.
1992 Stock Option and Restricted Stock Plan Under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan, as amended (the 1992 Plan), the Compensation, Benefits and Stock Option Committee of the Board of Directors (the Committee) may grant stock options and award restricted stock to our officers or other employees and those of our subsidiaries. In 2009, our stockholders approved an amendment to the 1992 Plan that increased the maximum number of shares of our common stock that may be issued from 22 million to 24 million shares. At December 31, 2010, 10,684,230 shares of our common stock were reserved for issuance, including 3,438,888 shares available for future grants and awards, under the 1992 Plan.
Stock options are issued with an exercise price equal to the market price of our common stock on the date of grant, and are subject to such other terms and conditions as may be determined by the Committee. Unless granted by the Committee for a shorter term, the options expire ten years from the grant date. Option grants generally vest ratably over a three-year period.
Restricted stock awards made under the 1992 Plan are subject to such restrictions, terms and conditions, including forfeitures, if any, as may be determined by the Committee. Restricted stock awards generally vest over three years. Shares of restricted stock awarded in 2010 and 2009 time-vest 20% after year one, an additional 30% after year two and the remaining 50% after year three.
2004 Long-Term Incentive Plan Under the Noble Energy, Inc. 2004 Long-Term Incentive Plan (the 2004 LTIP), the Committee may make incentive awards to our key employees and those of our subsidiaries. Incentive compensation is based upon the attainment of specific market and performance goals established by the Committee. Awards may be in the form of stock options or restricted stock or in the form of performance units or other incentive measurements providing for the payment of bonuses in cash, or in any combination thereof, as determined by the Committee in its discretion. Stock options granted and restricted stock awarded under the 2004 LTIP are granted and awarded pursuant to the terms of the 1992 Plan.
2005 Stock Plan for Non-Employee Directors The 2005 Stock Plan for Non-Employee Directors of Noble Energy, Inc. (the 2005 Plan) provides for grants of stock options and awards of restricted stock to our non-employee directors. The 2005 Plan superseded and replaced the 1988 Nonqualified Stock Option Plan for Non-Employee Directors. The total number of shares of our common stock that may be issued under the 2005 Plan is 800,000. At December 31, 2010, 715,378 shares of our common stock were reserved for issuance, including 536,841 shares available for future grants and awards under the 2005 Plan.
The 2005 Plan provides for the granting to a non-employee director of up to a maximum of 11,200 stock options on the date of election to the Board of Directors, annual grants of 2,800 options per non-employee director on February 1 of each year, and discretionary grants by the Board of Directors (with the February 1 annual and the discretionary grants made to a non-employee director during any calendar year being limited to a combined maximum of 11,200 options). Options are issued with an exercise price equal to the market price of our common stock on the date of grant and may be exercised one year after the date of grant. The options expire ten years from the date of grant.
The 2005 Plan also provides for the awarding to a non-employee director of up to a maximum of 4,800 shares of restricted stock on the date of election to the Board of Directors, annual awards of 1,200 shares of restricted stock per non-employee director on February 1 of each year, and discretionary awards by the Board of Directors (with the February 1 annual and the discretionary awards made to a non-employee director during any calendar year being limited to a combined maximum of 4,800 shares of restricted stock). Restricted stock is restricted for a period of at least one year from the date of award.
1988 Nonqualified Stock Option Plan for Non-Employee Directors The 1988 Nonqualified Stock Option Plan for Non-Employee Directors of Noble Energy, Inc., as amended, (the 1988 Plan) provided for the issuance of stock options to our non-employee directors. Options issued under the 1988 Plan may be exercised one year after grant and expire ten years from the grant date. The 1988 Plan provided for the granting of a fixed number of stock options to each non-employee director annually (10,000 stock options for the first calendar year of service and 5,000 stock options for each year thereafter) on February 1 of each year. The 1988 Plan was terminated in 2005, and no additional options can be granted thereunder.
Stock Option Grants The fair value of each stock option granted was estimated on the date of grant using a Black-Scholes-Merton option valuation model that used the assumptions described below:
·
Expected term The expected term represents the period of time that options granted are expected to be outstanding, which is the grant date to the date of expected exercise or other expected settlement for options granted. The hypothetical midpoint scenario we use considers our actual exercise and post-vesting cancellation history and expectations for future periods, which assumes that all vested, outstanding options are settled halfway between their vesting date and their expiration date.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
·
Expected volatility The expected volatility represents the extent to which our stock price is expected to fluctuate between the grant date and the expected term of the award. We use the historical volatility of our common stock for a period equal to the expected term of the option prior to the date of grant. We believe that historical volatility produces an estimate that is representative of our expectations about the future volatility of our common stock over the expected term.
·
Risk-free rate The risk-free rate is the implied yield available on US Treasury securities with a remaining term equal to the expected term of the option. We base our risk-free rate on a weighting of five and seven year US Treasury securities as of the date of grant.
·
Dividend yield The dividend yield represents the value of our stock’s annualized dividend as compared to our stock’s average price for the three-year period ended prior to the date of grant. It is calculated by dividing one full year of our expected dividends by our average stock price over the three-year period ended prior to the date of grant.
The assumptions used in valuing stock options granted were as follows:
Stock option activity was as follows:
The total intrinsic value of options exercised was $68 million in 2010, $19 million in 2009, and $67 million in 2008.
As of December 31, 2010, $29 million of compensation cost related to unvested stock options granted under the Plans remained to be recognized. The cost is expected to be recognized over a weighted-average period of 1.3 years. We issue new shares of our common stock to settle option exercises. Dividends are not paid on unexercised options.
Restricted Stock Awards Restricted stock activity was as follows:
The total fair value of restricted stock that vested was $43 million in 2010, $4 million in 2009, and $10 million in 2008.
Awards of time-vested restricted stock (shares subject to service conditions) were valued at the price of our common stock at the date of award.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
As of December 31, 2010, $34 million of compensation cost related to all of our unvested restricted stock awarded under the Plans remained to be recognized. The cost is expected to be recognized over a weighted-average period of 1.3 years. Common stock dividends accrue on restricted stock awards and are paid upon vesting. We issue new shares of our common stock when awarding restricted stock.
Note 16. Fair Value Measurements and Disclosures
Assets and Liabilities Measured at Fair Value on a Recurring Basis Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:
Cash, Cash Equivalents, Accounts Receivable and Accounts Payable The carrying amounts approximate fair value due to the short-term nature or maturity of the instruments.
Mutual Fund Investments Our mutual fund investments, which primarily include assets held in a rabbi trust, consist of various publicly-traded mutual funds that include investments ranging from equities to money market instruments. The fair values are based on quoted market prices for identical assets.
Commodity Derivative Instruments Our commodity derivative instruments consist of variable to fixed price commodity swaps, two-way and three-way collars and basis swaps. We estimate the fair values of these instruments based on published forward commodity price curves as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. In addition, for collars, we estimate the option values of the put options sold (for three-way collars) and the contract floors and ceilings (for two-way and three-way collars) using an option pricing model which takes into account market volatility, market prices and contract terms. See Note 10. Derivative Instruments and Hedging Activities.
Interest Rate Derivative Instrument We estimate the fair value of our forward starting swap based on published interest rate yield curves as of the date of the estimate. The fair values of interest rate derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of interest rate derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. See Note 10. Derivative Instruments and Hedging Activities.
Deferred Compensation Liability The value is dependant upon the fair values of mutual fund investments and shares of our common stock held in a rabbi trust. See Mutual Fund Investments above.
Measurement information for assets and liabilities that are measured at fair value on a recurring basis was as follows:
(1)
See Note 1. Summary of Significant Accounting Policies - Fair Value Measurements for a description of the fair value hierarchy.
(2)
Amount represents the impact of master netting agreements that allow us to settle asset and liability positions with the same counterparty.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Certain assets and liabilities are measured at fair value on a nonrecurring basis in our consolidated balance sheets.
Central DJ Basin Asset Acquisition Information about the acquired assets as of the measurement date is as follows:
See Note 3. Acquisitions and Divestitures for a discussion of the methods and assumptions used to estimate the fair values of the acquired assets.
Asset Impairments Information about impaired assets as of the date of the assessment is as follows:
(1)
Amount represents net book value at date of assessment.
See Note 4. Asset Impairments for a discussion of the methods and assumptions used to estimate the fair values of the impaired assets.
Additional Fair Value Disclosures
Debt The fair value of fixed-rate debt is estimated based on the published market prices for the same or similar issues. The carrying amount of floating-rate debt approximates fair value because the interest rates paid on such debt are set for periods of three months or less. See Note 12. Long-Term Debt.
Fair value information regarding our debt is as follows:
(1)
Excludes FPSO lease obligation.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 17. Earnings Per Share
The following table summarizes the calculation of basic and diluted earnings per share:
(1)
The diluted earnings per share calculation for 2008 includes a decrease to net income related to a deferred compensation gain from shares of our common stock held in a rabbi trust. When dilutive, the deferred compensation gain or loss (net of tax) is excluded from net income while the shares of our common stock held in the rabbi trust are included in the outstanding diluted share count.
Note 18. Segment Information
We have operations throughout the world and manage our operations by country. The following information is grouped into five components that are all primarily in the business of crude oil and natural gas exploration, development, and acquisition: the United States; West Africa (Equatorial Guinea and Cameroon); Eastern Mediterranean (Israel and Cyprus); the North Sea (UK and the Netherlands); and Other International and Corporate. Other International includes China, Ecuador (at December 31, 2010), Argentina (through February 2008) and new ventures.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
(1)
Revenues include decreases resulting from hedging activities. The decreases resulted from hedge gains and losses that were deferred in AOCL, as a result of previous cash flow hedge accounting, and subsequently reclassified to revenues.
(2)
Revenues from third parties for all foreign countries, in total, were $1 billion in 2010, $791 million in 2009, and $1.3 billion in 2008.
(3)
Long-lived assets located in all foreign countries, in total, were $2.4 billion, $1.6 billion, and $1.5 billion at December 31, 2010, 2009, and 2008, respectively.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 19. Concentration of Risk
Concentration of Market Risk The largest single non-affiliated purchasers of our production were as follows:
We believe the loss of any one purchaser would not have a material effect on our financial position or results of operations since there are numerous potential purchasers of our production.
Concentration of Credit Risk Certain of our financial instruments, including cash equivalents, trade and joint interest receivables and derivative instruments, may expose us to credit risk. Substantially all of our cash is located in our foreign subsidiaries. The cash is denominated in US dollars and invested in highly liquid money market funds and short term deposits with original maturities of three months or less at the time of purchase. Although our cash and cash equivalents are deposited with major international banks and financial institutions, concentrations of cash in certain foreign locations may increase credit risk. We monitor the creditworthiness of the banks and financial institutions with which we invest and review the securities underlying our investment accounts. We believe that losses from nonperformance are unlikely to occur; however, we are not able to predict sudden changes in creditworthiness.
Our accounts receivable result from sales of crude oil, natural gas and NGL production and electricity, and joint interest billings to our partners for their share of expenses on joint venture projects for which we are the operator. Joint venture projects, such as Aseng, offshore Equatorial Guinea, and Tamar, offshore Israel can be very capital cost intensive. Thus the receivables from our joint venture partners can become significant.
Our accounts receivable reflect a broad national and international customer base, which limits our exposure to concentrations of credit risk. The majority of these receivables have payment terms of 30 days or less. We continually monitor the creditworthiness of the counterparties, some of which are not as creditworthy as we are and may experience liquidity problems. We have obtained credit enhancements from some parties in the way of parental guarantees or letters of credit, including our largest crude oil purchaser. However, we do not have all of our trade credit protected through guarantees or credit support. Nonperformance by a trade creditor could result in losses. See Note 5. Allowance for Doubtful Accounts.
Note 20. Additional Shareholders’ Equity Information
Activity in shares of our common stock and treasury stock was as follows:
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Accumulated other comprehensive loss in the shareholders’ equity section of the balance sheet included:
All amounts in the table above are reported net of tax. The effective income tax rate applied to AOCL was 37.6% at December 31, 2007 and 2008, and 35.0% at December 31, 2009 and 2010.
Note 21. Commitments and Contingencies
Legal Proceedings We are involved in various legal proceedings in the ordinary course of business. These proceedings are subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters and we believe that the ultimate disposition of such proceedings will not have a material adverse effect on our financial position, results of operations or cash flows.
Non-Cancelable Leases and Other Commitments We hold leases and other commitments for drilling rigs, buildings, equipment and other property. Rental expense for office buildings and oil and gas operations equipment was $27 million in 2010, $22 million in 2009, and $20 million in 2008.
Minimum commitments as of December 31, 2010 consist of the following:
(1)
Estimated annual lease payments, net to our interest, exclude regular maintenance and operational costs, and will begin when the FPSO initiates producing operations. These payments are also subject to change based on change orders implemented during the construction period, final accounting treatment and other factors. See Note 12. Long-Term Debt.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
In accordance with US GAAP for disclosures about oil and gas producing activities, and SEC rules for oil and gas reporting disclosures, we are making the following disclosures about our crude oil and natural gas reserves and exploration and production activities.
Reserves
There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserves estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered.
SEC and FASB Rule-Making Activity Effective December 31, 2009, we implemented the SEC’s final rules on the Modernization of Oil and Gas Reporting. The new rules included revisions designed to modernize the oil and gas company reserves reporting requirements. The most significant amendments to the requirements included the following:
·
Commodity Prices - Economic producibility of reserves and discounted cash flows is now based on a 12-month average commodity price unless contractual arrangements designate the price to be used.
·
Disclosure of Unproved Reserves - Probable and possible reserves may be disclosed separately on a voluntary basis. We have elected not to disclose probable and possible reserves in this report.
·
Proved Undeveloped Reserves Guidelines - Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years.
·
Reserves Estimation Using New Technologies - Reserves may be estimated through the use of reliable technology in addition to flow tests and production history.
·
Reserves Personnel and Estimation Process - Additional disclosure is required regarding the qualifications of the chief technical person who oversees the reserves estimation process. We are also required to provide a general discussion of our internal controls used to assure the objectivity of the reserves estimate.
·
Disclosure by Geographic Area - Reserves in foreign countries or continents must be presented separately if they represent more than 15% of our total oil and gas proved reserves.
·
Non-Traditional Resources - The definition of oil and gas producing activities has expanded and focuses on the marketable product rather than the method of extraction.
The rule changes, including those related to pricing and technology, are included in our reserves estimates as of December 31, 2010 and 2009.
In addition, in 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (Update) 2010-03, “Oil and Gas Reserve Estimation and Disclosures”, to provide consistency with the new SEC rules. The Update amended existing standards to align the reserves calculation and disclosure requirements under US GAAP with the requirements in the SEC rules. We adopted the new standards effective December 31, 2009. The new standards were applied prospectively as a change in estimate.
Impact of Implementation Implementation of the SEC’s updated rules resulted in the use of lower prices at December 31, 2009 for both oil and gas than would have resulted under the previous rules. Use of 12-month average pricing at December 31, 2009 as required by the updated rules resulted in a decrease in proved reserves of approximately 27 MMBoe. Use of year-end prices as required by the old rules would have resulted in an increase in proved reserves of approximately 34 MMBoe at December 31, 2009. Therefore, the total impact of the new price methodology was negative reserves revisions of 61 MMBoe. In addition, the new proved undeveloped reserves rules resulted in a reduction of proved reserves of approximately 18 MMBoe due to limiting proved undeveloped reserves locations to those scheduled to be drilled within the next five years. The majority of the reserves reclassified out of proved reserves were associated with Wattenberg, where we maintain an extensive multi-year development program.
Because we use quarter-end reserves and add back current period production to calculate quarterly DD&A, adoption of the updated FASB standards had an impact on fourth quarter 2009 DD&A expense. We estimated the impact of using 12-month average commodity prices, as required by the updated standards, instead of year-end commodity prices, to be an increase in fourth quarter 2009 DD&A expense of approximately $16 million (or $0.06 per share).
Reserves Estimates Qualified petroleum engineers in our Houston and Denver offices prepare all reserves estimates for our different geographical regions. These reserves estimates are reviewed and approved by regional management and senior engineering staff with final approval by the Vice President - Strategic Planning, Environmental Analysis & Reserves and certain members of senior management. For additional information regarding our reserves estimation process and internal controls see Items 1. and 2. Business and Properties - Proved Reserves Disclosures - Internal Controls Over Reserves Estimates and Technologies Used in Reserves Estimation.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Third-Party Reserves Audit We retained Netherland, Sewell & Associates, Inc. (NSAI), independent, third-party petroleum engineers, to perform a reserves audit of proved reserves as of December 31, 2010. The reserves audit included a detailed review of 13 of our major onshore US, deepwater Gulf of Mexico and international fields, which covered approximately 77% of US proved reserves and 97% of international proved reserves (88% of total proved reserves). For additional information regarding reserves audits for the years 2010, 2009, and 2008, see Items 1. and 2. Business and Properties - Proved Reserves Disclosures.
Geographic Areas Our supplemental disclosures are grouped by geographic area and include the United States, Equatorial Guinea, Israel and Other International. Other International includes Ecuador (through November 24, 2010), North Sea, China, and Argentina (through February 2008). Operations in Equatorial Guinea and China are conducted in accordance with the terms of PSCs. Operations in Cameroon are conducted in accordance with the terms of a PSC and a mining concession. Operations in other foreign locations are conducted in accordance with concession agreements, permits or licenses.
Definitions The following definitions apply to the terms used in the paragraphs above:
Reserves Estimate The determination of an estimate of a quantity of oil or gas reserves that are thought to exist at a certain date, considering existing prices and reservoir conditions.
Reserves Audit The process of reviewing certain of the pertinent facts interpreted and assumptions underlying a reserves estimate prepared by another party and the rendering of an opinion about the appropriateness of the methodologies employed, the adequacy and quality of the data relied upon, the depth and thoroughness of the reserves estimation process, the classification of reserves appropriate to the relevant definitions used, and the reasonableness of the estimated reserves quantities.
The following definitions apply to our categories of proved reserves:
Proved Oil and Gas Reserves Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
Developed Oil and Gas Reserves Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well.
Undeveloped Oil and Gas Reserves Proved undeveloped oil and gas reserves (PUDs) are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
For complete definitions of proved natural gas, natural gas liquids and crude oil reserves, refer to SEC Regulation S-X, Rule 4-10(a)(6), (22) and (31).
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Proved Oil Reserves (Unaudited) The following reserves schedule was developed by our qualified petroleum engineers and sets forth the changes in estimated quantities of proved crude oil reserves:
(1)
Other International includes Israel, the North Sea, China and Argentina. We sold our Argentina assets in 2008.
(2)
The 2008 negative revisions within the US are primarily due to lower year-end prices (28 MMBbl), partially offset by the recording of NGLs which had previously been recorded in proved natural gas reserves. The 2009 negative revisions within the US are primarily due to performance revisions, the majority of which related to Main Pass (10 MMBbl) and reclassifications of PUDs to probable reserves as a result of the SEC’s new five year development rule (5 MMBbl), partially offset by higher year-end prices (10 MMBbl). The 2010 US revisions include the impacts of higher prices and additional NGLs booked in Wattenberg, partially offset by the reclassification of 16 MMBbls of PUD reserves to probable reserves, primarily in Wattenberg, as a result of the SEC's five year development rule. The 2010 revisions to other international reserves are related to performance revisions in China and the North Sea.
(3)
The 2008 increase in proved reserves includes 13 MMBbl in Wattenberg, primarily due to infill drilling activities, and 9 MMBbl in China. The 2009 increase in proved reserves includes 20 MMBbl related to the ongoing development of Wattenberg, 11 MMBbl in the deepwater Gulf of Mexico for the Santa Cruz, Isabela and Swordfish fields, and 26 MMBbl in Equatorial Guinea for the Aseng field. The 2010 increase in US proved reserves relates to continuing development of onshore assets, primarily in the Central DJ Basin. The 2010 increase in Equatorial Guinea reserves includes 26 MMBbl for the Alen field.
(4)
The 2010 increase relates to the Central DJ Basin asset acquisition. See Note 3. Acquisitions and Divestitures.
(5)
We sold non-core, mature onshore US assets in the Mid-Continent and Illinois Basin in 2010 and our Argentina assets in 2008. See Note 3. Acquisitions and Divestitures.
(6)
Equatorial Guinea production includes sales from the Alba field to the Alba LPG plant of 3 MBbl in each of 2010, 2009, and 2008.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Proved Gas Reserves (Unaudited) The following reserves schedule was developed by our qualified petroleum engineers and sets forth the changes in estimated quantities of proved natural gas reserves:
(1)
Other International includes the North Sea, Ecuador (at December 31, 2009 and 2008), and China. See Note 3. Acquisitions and Divestitures and Note 4. Asset Impairments.
(2)
The 2008 negative revisions in the US are primarily due to lower year-end prices (109 Bcf), as well as additional natural gas volumes being reflected in the proved oil reserves table as NGLs. The 2009 negative revisions in the US are primarily due to lower year-end prices (224 Bcf), reclassifications of PUDs to probable reserves as a result of the SEC’s new five year development rule (75 Bcf), and increased lease operating expense and various well performance issues (98 Bcf). The 2010 US revisions are a combination of increases from higher natural gas prices, which were more than offset by gas shrinkage from additional NGLs booked in Wattenberg and the reclassification of 85 Bcf of PUDs to probable reserves, primarily in Wattenberg, as a result of the SEC's five year development rule. Equatorial Guinea’s positive revisions in 2008, 2009 and 2010 are primarily due to additional production allowances related to LNG sales. Israel revisions in 2010 reflect a change in the likelihood that the Noa Field will be developed.
(3)
The 2008 increase in US proved reserves includes 106 Bcf in Wattenberg and 173 Bcf in the Rocky Mountain area, primarily in the Piceance Basin and Niobrara formation, primarily due to infill drilling activities. The remaining increase is due to other development programs. The 2009 increase in US proved reserves is primarily due to ongoing low-risk development programs onshore in Wattenberg, the Rocky Mountain area, and East Texas. The 2010 increase in US proved reserves is due to continuing development of onshore assets, primarily in the Central DJ Basin, Piceance Basin, and East Texas. The 2010 increase in Israel is due to the recording of initial reserves at the Tamar development.
(4)
The increase relates to our Mid-Continent acquisition in 2008 and our Central DJ Basin asset acquisition in 2010. See Note 3. Acquisitions and Divestitures.
(5)
We sold non-core, mature onshore US assets in the Mid-Continent and Illinois Basin in 2010. Other International sales in 2010 include 160 Bcf due to the termination of the Block 3 PSC by the Ecuadorian government.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Results of Operations for Oil and Gas Producing Activities (Unaudited) Aggregate results of operations for crude oil and natural gas producing activities are as follows:
(1)
Other International includes the North Sea, Ecuador (through November 24, 2010) China, Cameroon, Cyprus, Argentina (through February 2008), and new ventures. See Note 3. Acquisitions and Divestitures.
(2)
Includes impact resulting from applying cash flow hedge accounting for related commodity derivative instruments. See Note 10. Derivative Instruments and Hedging Activities.
(3)
Production costs consist of lease operating expense, production and ad valorem taxes, transportation expense, and general and administrative expense supporting oil and gas operations.
(4)
Results of operations exclude the mark-to-market gain or loss on certain commodity derivative instruments designated as cash flow hedges prior to January 1, 2008, corporate overhead and interest costs. See Note 10. Derivative Instruments and Hedging Activities.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities (Unaudited) (1)
Costs incurred in connection with crude oil and natural gas acquisition, exploration and development are as follows:
(1)
Costs incurred include capitalized and expensed items.
(2)
Other International includes the North Sea, Ecuador (through November 24, 2010), China, Argentina (through February 2008), Nicaragua and other new ventures. See Note 3. Acquisitions and Divestitures.
(3)
Proved property acquisition costs include $352 million related to the Central DJ Basin asset acquisition in 2010, a $6 million downward purchase price adjustment related to the Mid-Continent acquisition in 2009, and $254 million related to the Mid-Continent acquisition in 2008.
(4)
Unproved property acquisition costs include $146 million related to the Central DJ Basin asset acquisition, $38 million for deepwater Gulf of Mexico lease blocks and the remainder for other onshore US lease acquisitions primarily in Wattenberg in 2010; $56 million for deepwater Gulf of Mexico lease blocks and the remainder primarily for other onshore US lease acquisitions in 2009; and $179 million for deepwater Gulf of Mexico lease blocks, $38 million related to the Mid-Continent acquisition, $39 million related to lease acquisitions in East Texas, and the remainder primarily for other onshore US lease acquisitions in 2008.
(5)
2010 exploration costs include drilling and completion costs of $62 million in deepwater Gulf of Mexico and $41 million in Israel. 2009 exploration costs include drilling and completion costs of $57 million in deepwater Gulf of Mexico, $19 million in Equatorial Guinea and $71 million in Israel. 2008 exploration costs include drilling and completion costs of $72 million in deepwater Gulf of Mexico, $98 million in Equatorial Guinea and $25 million in Israel.
(6)
Worldwide development costs include amounts spent to develop PUDs of approximately $1.1 billion in 2010, $440 million in 2009, and $528 million in 2008. Equatorial Guinea development costs include non-cash accruals related to estimated construction progress to date on an FSPO to be used in the development of the Aseng field of $266 million in 2010 and $29 million in 2009. These capitalized costs are included in development costs as the FPSO is constructed. US development costs include increases in asset retirement obligations of $15 million in 2010, $11 million in 2009, and $34 million in 2008. Other international development costs include increases in asset retirement obligations of $2 million in 2010, $5 million in 2009, and $18 million in 2008.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Capitalized Costs Relating to Oil and Gas Producing Activities (Unaudited) Aggregate capitalized costs relating to crude oil and natural gas producing activities are as follows:
(1)
Unproved oil and gas properties includes $304 million and $327 million at December 31, 2010 and 2009, respectively, remaining from the allocation of costs to unproved properties acquired in previous acquisitions.
(2)
Proved oil and gas properties include asset retirement costs of $208 million and $176 million at December 31, 2010 and 2009, respectively.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited) The following information is based on our best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows in accordance with US GAAP for extractive activities. The standards require the use of a 10% discount rate. This information is not the fair value nor does it represent the expected present value of future cash flows of our proved oil and gas reserves.
(1)
Other International includes the North Sea, Ecuador (at December 31, 2009 and 2008), and China. See Note 3. Acquisitions and Divestitures.
(2)
The standardized measure of discounted future net cash flows does not include cash flows relating to anticipated future methanol sales.
(3)
Production costs include oil and gas lease operating expense, production and ad valorem taxes, transportation expense and general and administrative expense supporting oil and gas operations.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Prices and Other Assumptions in Discounted Future Net Cash Flows (Unaudited) Future cash inflows are computed by applying a 12-month average commodity price, adjusted for location and quality differentials on a field-by-field basis, to year-end quantities of proved reserves, except in those instances where fixed and determinable price changes are provided by contractual arrangements at year-end. The discounted future cash flow estimates do not include the effects of derivative instruments. Average prices per region are as follows:
(1)
Other International includes the North Sea, Ecuador (at December 31, 2009 and 2008), and China. See Note 3. Acquisitions and Divestitures.
(2)
Average crude oil and natural gas prices are based on 12-month average prices.
(3)
Average crude oil and natural gas prices are based on year-end prices.
We estimate that a $1.00 per Bbl change in the average price of crude oil from the 12-month average price for 2010 would change the discounted future net cash flows before income taxes by approximately $205 million. We estimate that a $0.10 per Mcf change in the average price of natural gas from the 12-month average price for 2010 would also change the discounted future net cash flows before income taxes by approximately $205 million.
Future production and development costs, which include dismantlement and restoration expense, are computed by estimating the expenditures to be incurred in developing and producing the proved crude oil and natural gas reserves at the end of the year, based on year-end costs, and assuming continuation of existing economic conditions.
Future development costs include amounts that we expect to spend to develop PUDs of $1.6 billion in 2011, $1.3 billion in 2012 and $900 million in 2013.
Future income tax expense is computed by applying the appropriate year-end statutory tax rates to the estimated future pretax net cash flows relating to proved crude oil and natural gas reserves, less the tax bases of the properties involved. Future income tax expense gives effect to tax credits and allowances, but does not reflect the impact of general and administrative costs and exploration expenses of ongoing operations.
Imbalance receivables and liabilities are as follows:
Imbalance receivables and imbalance liabilities have been excluded from the standardized measure of discounted future net cash flows.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Sources of Changes in Discounted Future Net Cash Flows (Unaudited) Principal changes in the aggregate standardized measure of discounted future net cash flows attributable to proved crude oil and natural gas reserves are as follows:
Supplemental Quarterly Financial Information (Unaudited)
Supplemental quarterly financial information is as follows:
(1)
First quarter 2010 included the following:
·
$145 million gain on commodity derivative instruments, including unrealized mark-to-market gain of $147 million (See Note 10. Derivative Instruments and Hedging Activities).
Second quarter 2010 included the following:
·
$96 million gain on commodity derivative instruments, including unrealized mark-to-market gain of $63 million (See Note 10. Derivative Instruments and Hedging Activities); and
·
$26 million rig contract termination expense due to the Deepwater Moratorium.
Third quarter 2010 included the following:
·
$38 million gain on commodity derivative instruments, including unrealized mark-to-market gain of $5 million (See Note 10. Derivative Instruments and Hedging Activities);
·
$114 gain on sale of non-core onshore US assets (See Note 3. Acquisitions and Divestitures); and
·
$100 million asset impairment charges (See Note 4. Asset Impairments).
Fourth quarter 2010 included the following:
·
$122 million loss on commodity derivative instruments, including unrealized mark-to-market loss of $145 million (See Note 10. Derivative Instruments and Hedging Activities); and
·
$44 million asset impairment charges (See Note 4. Asset Impairments).
(2)
First quarter 2009 included the following:
·
$73 million gain on commodity derivative instruments, including unrealized mark-to-market loss of $80 million. (See Note 10. Derivative Instruments and Hedging Activities);
·
$437 million asset impairment charges (See Note 4. Asset Impairments); and
·
$46 million reversal of Ecuador allowance for doubtful accounts (See Note 5. Allowance for Doubtful Accounts).
Second quarter 2009 included the following:
·
$139 million loss on commodity derivative instruments, including unrealized mark-to-market loss of $277 million. (See Note 10. Derivative Instruments and Hedging Activities); and
·
$24 million gain on sale of our Argentina assets, which had been deferred until government approval of the sale.
Third quarter 2009 included the following:
·
$28 million loss on commodity derivative instruments, including unrealized mark-to-market loss of $149 million (See Note 10. Derivative Instruments and Hedging Activities); and
·
$12 million write-down of SemCrude, L.P. receivable.
Fourth quarter 2009 included the following:
·
$16 million loss on commodity derivative instruments, including unrealized mark-to-market loss of $99 million (See Note 10. Derivative Instruments and Hedging Activities);
·
$167 million asset impairment charges (See Note 4. Asset Impairments); and
·
$97 million refund of deepwater Gulf of Mexico royalties, including interest (See Note 2. Additional Financial Statement Information).
(3)
The sum of the individual quarterly earnings (loss) per share amounts may not agree with year-to-date earnings per share as each quarterly computation is based on the income or loss for that quarter and the weighted average number of shares outstanding during that quarter.
(4)
The diluted earnings per share calculation for the quarter ended June 30, 2010 includes a decrease to net income of $9 million, net of tax for a deferred compensation gain related to shares of our common stock held in a rabbi trust.
Item 9.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A.
Controls and Procedures
Evaluation of Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports we file or furnish to the SEC under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms, and that information is accumulated and communicated to management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
Our principal executive officer and principal financial officer have evaluated the effectiveness of our “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended, as of the end of the period covered by this Annual Report on Form 10-K. Based upon their evaluation, they have concluded that our disclosure controls and procedures are designed and effective to ensure that information required to be disclosed in the reports that we file or furnish under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms and that information is accumulated and communicated to management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that our controls will succeed in achieving their goals under all potential future conditions.
Management’s Annual Report on Internal Control over Financial Reporting
The management report called for by Item 308(a) of Regulation S-K is incorporated herein by reference to Management’s Report on Internal Control over Financial Reporting, included in Item 8. Financial Statements and Supplementary Data.
The independent auditor’s attestation report called for by Item 308(b) of Regulation S-K is incorporated herein by reference to Report of Independent Registered Public Accounting Firm (Internal Control Over Financial Reporting), included in Item 8. Financial Statements and Supplementary Data.
Changes in Internal Control over Financial Reporting
Our management is also responsible for establishing and maintaining adequate internal controls over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Our internal controls were designed to provide reasonable assurance as to the reliability of our financial reporting and the preparation and presentation of the consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States.
Because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements. Projections of any evaluation of the 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.
Our management has assessed the effectiveness of our internal controls over financial reporting as of December 31, 2010. Based on our assessment, our internal controls over financial reporting were effective. There were no changes in internal controls over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.
Item 9B.
Item 9B.
Other Information
None.
PART III
Item 10.
Item 10.
Directors, Executive Officers and Corporate Governance
The information required by this item is incorporated herein by reference to the 2011 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2010.
Item 11.
Item 11.
Executive Compensation
The information required by this item is incorporated herein by reference to the 2011 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2010.
Item 12.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required by this item is incorporated herein by reference to the 2011 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2010.
Item 13.
Item 13.
Certain Relationships and Related Transactions, and Director Independence
The information required by this item is incorporated herein by reference to the 2011 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2010.
Item 14.
Item 14.
Principal Accounting Fees and Services
The information required by this item is incorporated herein by reference to the 2011 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2010.
PART IV
Item 15.
Item 15.
Exhibits, Financial Statements Schedules
a)
The following documents are filed as a part of this report:
(3)
Exhibits: The exhibits required to be filed by this Item 15 are set forth in the Index to Exhibits accompanying this report.
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.
NOBLE ENERGY, INC.
(Registrant)
Date: February 10, 2011
By: /s/ Charles D. Davidson
Charles D. Davidson,
Chairman of the Board,
Chief Executive Officer and Director
Date: February 10, 2011
By: /s/ Kenneth M. Fisher
Kenneth M. Fisher,
Senior Vice President, Chief Financial Officer
Date: February 10, 2011
By: /s/ Frederick B. Bruning
Frederick B. Bruning,
Vice President, Chief Accounting 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.
Signature
Capacity in which signed
Date
/s/ Charles D. Davidson
Chairman of the Board,
February 10, 2011
Charles D. Davidson
Chief Executive Officer and Director
(Principal Executive Officer)
/s/ Kenneth M. Fisher
Senior Vice President,
February 10, 2011
Kenneth M. Fisher
Chief Financial Officer
(Principal Financial Officer)
/s/ Frederick B. Bruning
Vice President, Chief Accounting Officer
February 10, 2011
Frederick B. Bruning
(Principal Accounting Officer)
/s/ Jeffrey L. Berenson
Director
February 10, 2011
Jeffrey L. Berenson
/s/ Michael A. Cawley
Director
February 10, 2011
Michael A. Cawley
/s/ Edward F. Cox
Director
February 10, 2011
Edward F. Cox
/s/ Thomas J. Edelman
Director
February 10, 2011
Thomas J. Edelman
/s/ Eric P. Grubman
Director
February 10, 2011
Eric P. Grubman
/s/ Kirby L. Hedrick
Director
February 10, 2011
Kirby L. Hedrick
/s/ Scott D. Urban
Director
February 10, 2011
Scott D. Urban
/s/ William T. Van Kleef
Director
February 10, 2011
William T. Van Kleef
INDEX TO EXHIBITS