Company: NOBLE ENERGY INC
CIK: 72207
SIC: 1311
Filing Date: 2013-02-07 00:00:00

ITEM 1 - BUSINESS

ITEM 1A - RISK FACTORS
Item 1A.
Risk Factors

ITEM 1B - UNRESOLVED STAFF COMMENTS
Item 1B.
Unresolved Staff Comments

ITEM 2 - PROPERTIES

ITEM 3 - LEGAL PROCEEDINGS
Item 3. Legal Proceedings
See Item 8. Financial Statements and Supplementary Data - Note 20. Commitments and Contingencies.

ITEM 4 - RESERVED
Item 4. Mine Safety Disclosures
Not Applicable.
Executive Officers
The following table sets forth certain information, as of February 7, 2013, 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 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 Company (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 Noble Energy 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 a Vice President of Noble Energy in November 2007 and is responsible for Human Resources and Administration. 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 - MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Common Stock Our common stock, $0.01 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 28, 2013, the Board of Directors declared a quarterly cash dividend of $0.25 per common share, which will be paid February 25, 2013 to shareholders of record on February 11, 2013.
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 18, 2013, the number of holders of record of our common stock was 635.
Stock Repurchases The following table summarizes repurchases of our common stock occurring fourth quarter 2012.
(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, 2012.
Stock Performance Graph This graph shows our cumulative total shareholder return over the five-year period from December 31, 2007 to December 31, 2012. 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 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.
On January 23, 2012, the Compensation, Benefits and Stock Option Committee of the Board of Directors (the Committee) made changes to our compensation peer group to remove Forest Oil Corp. and Talisman Energy Inc. from the old peer group listed above given their growing dissimilarity to our operational and financial characteristics, and add Marathon Oil Corporation and Continental Resources, Inc., which are US companies listed on the NYSE with a balance of projects similar in size and scope to ours. After the change in companies, the 2012 compensation peer group 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
Continental Resources, Inc.
Plains Exploration and Production Company
Devon Energy Corp.
Range Resources Corp.
EOG Resources, Inc.
Southwestern Energy Company
Marathon Oil Corporation
The comparison assumes $100 was invested on December 31, 2007 in our common stock, in the S&P 500 Index and in our peer group of companies and assumes that all of the dividends were reinvested.

ITEM 6 - SELECTED FINANCIAL DATA
Item 6. Selected Financial Data
(1)
Prices through 2010 include effects of oil and gas hedging activities. See Item 8. Financial Statements and Supplementary Data - Note 10. Derivative Instruments and Hedging Activities.

ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide a narrative about our business from the perspective of our management. Our MD&A is presented in the following major sections:
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Executive Overview;
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Operating Outlook;
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Results of Operations;
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Proved Reserves;
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Liquidity and Capital Resources; and
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Critical Accounting Policies and Estimates.
The accompanying consolidated financial statements, including the notes thereto, contain detailed information that should be read in conjunction with our MD&A.
EXECUTIVE OVERVIEW
Strategy We are a worldwide producer of crude oil and natural gas. We aim to achieve sustainable growth in value and cash flow through exploration success and the development of a high-quality, diversified, growing 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 augment that with a periodic, opportunistic new business development (mergers and acquisition) capability. We manage the portfolio for superior returns and to ensure geographic portfolio diversification, with periodic divestments of non-core assets. We focus on basins or plays where we have strategic competitive advantage and which we believe generate superior returns.
Core operating areas are the onshore US (DJ Basin and Marcellus Shale), deepwater Gulf of Mexico, offshore West Africa and offshore Eastern Mediterranean. 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 horizontal Niobrara in the DJ Basin and the Marcellus Shale, onshore US; Gunflint and Big Bend in the deepwater Gulf of Mexico; Tamar and Leviathan, offshore Israel; offshore Cyprus; Alen, Carla, and Diega, offshore West Africa.
Our major development projects typically offer long life, sustained cash flows after investment and attractive financial returns. We maintain a diversified 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.
Current Business and Industry Environment The global economy continued its recovery during 2012. Although there was modest growth in the US, China and emerging markets, Europe continued to struggle with its debt crisis. In the US, uncertainty continues to surround resolution of federal deficit issues. It is difficult to predict the economic consequences on global markets as governments attempt to resolve these issues.
In the global crude oil market, supplies grew, primarily due to the application of horizontal drilling technology to liquids plays and increasing supplies from unconventional sources (oil from tight formations and oil sands) in the US and Canada. Prices remained strong, supported by modest demand growth and continued security and other threats to the global crude oil supply system. Brent prices remain at a premium to WTI primarily due to transportation constraints in the US Mid-Continent area which impact WTI netbacks.
In the US, the application of horizontal drilling technology has significantly changed the natural gas markets, resulting in an oversupply of natural gas and considerably lower Henry Hub spot and forward prices. Increased drilling in liquids-rich gas areas and increased associated gas production from oil plays has yielded significant growth in onshore US NGL production. As a result, the NGL market softened during 2012, and NGL prices declined.
Despite the uncertainty surrounding the global economy and continued volatility in commodity prices, we believe our portfolio positions us well moving forward. We have material new production onshore US and offshore Equatorial Guinea, substantial liquidity and cash flow, a solid balance sheet, and a line-up of major development projects which we expect to contribute to future growth.
2012 Results Noble Energy delivered significant growth in 2012. Expansion of our horizontal Niobrara and Marcellus Shale developments resulted in a 24% increase in Wattenberg production and a four fold increase in Marcellus Shale production. We realized further production increases from major new developments at Aseng, offshore Equatorial Guinea, and Galapagos,
deepwater Gulf of Mexico, that came on line in 2011 and 2012, respectively. We moved forward on our major development projects, each of which will yield significant new production in future years, discovered new resources at Big Bend in the deepwater Gulf of Mexico and Carla, offshore Equatorial Guinea, and farmed into new opportunities offshore the Falkland Islands and Sierra Leone. Finally, we enhanced our portfolio with selective divestitures of non-core, onshore US and North Sea properties, and maintained our strong balance sheet.
Our 2012 financial results included:
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net income over $1.0 billion (including $965 million from continuing operations) as compared with $453 million (including $412 million from continuing operations) for 2011 ;
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dry hole cost of $155 million, as compared with $105 million for 2011;
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gain on divestitures of $154 million as compared with $25 million for 2011;
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asset impairment charges of $104 million as compared with $757 million for 2011;
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gain on commodity derivative instruments of $75 million (including unrealized mark-to-market gain of $109 million) as compared with $42 million gain on commodity derivative instruments (including unrealized mark-to-market loss of $22 million) for 2011;
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diluted earnings per share of $5.71, as compared with $2.54 for 2011;
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cash flows provided by operating activities of $2.9 billion, as compared with $2.2 billion in 2011;
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received $1.2 billion in proceeds from divestments of non-core assets, as compared with $77 million in 2011;
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capital spending on a cash basis of $3.7 billion as compared with $3.1 billion in 2011 (including $527 million for the Marcellus Shale asset acquisition);
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exercised option to increase credit facility from $3.0 billion to $4.0 billion, enhancing our liquidity position;
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ending cash and cash equivalents balance of $1.4 billion at December 31, 2012, as compared with $1.5 billion at December 31, 2011;
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total liquidity of $5.4 billion at December 31, 2012, consisting of year-end cash balance plus funds available under our credit facility, as compared with $4.5 billion at December 31, 2011; and
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year-end ratio of debt-to-book capital of 33%, as compared with 38% at December 31, 2011.
Significant operational highlights for 2012 included the following:
Overall
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total sales volumes from continuing operations of 239 MBoe/d, a 12% increase as compared with 2011;
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liquids represent 46% of total sales volumes from continuing operations as compared to 37% in 2011; and
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year-end proved reserves of 1.2 BBoe, a decrease of 2% from year-end 2011.
Onshore United States
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increased DJ Basin (Wattenberg) total sales volumes to 77 MBoe/d, net, with horizontal production contributing 28 MBoe/d, net;
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spud 200 and completed 193 horizontal wells in the DJ Basin;
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expanded the Northern Colorado acreage position by 26,000 net acres to 230,000 net acres, where recent horizontal Niobrara results indicate recoveries comparable to Wattenberg;
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Marcellus Shale production grew to 92 MMcfe/d, net, as compared with 19 MMcfe/d, net, in 2011;
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drilled to total depth 89 and completed 71 gross horizontal wells in the Marcellus Shale and initiated production from the wet gas area;
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experienced higher recovery rates than anticipated in the DJ Basin and Marcellus Shale;
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entered new exploration area in Northeast Nevada; and
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completed non-core onshore asset dispositions.
Deepwater Gulf of Mexico
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announced a discovery at the Big Bend prospect;
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Galapagos produced at an average rate of 6 MBbl/d of crude oil, net; and
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acquired six deepwater Gulf of Mexico blocks at the Outer-Continental Shelf Sale 222;
International
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discovery of a new crude oil reservoir at Carla, offshore Equatorial Guinea;
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Aseng field, offshore Equatorial Guinea, produced at an average gross rate of 62 MBbl/d of crude oil (21 MBbl/d, net);
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acceleration of Alen development, offshore Equatorial Guinea;
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installed the Tamar platform and initiated the commissioning process;
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announced a strategic development partner for the Leviathan project, offshore Israel;
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announced the Tanin natural gas discovery, offshore Israel;
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entered into new positions offshore Falkland Islands and Sierra Leone;
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secured contract with new-build drillship capable of reaching deep oil targets in the Eastern Mediterranean; and
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completed the sale of our Dumbarton and Lochranza assets in the North Sea.
Acquisitions and Divestitures
Strategic Partner for Leviathan The Leviathan field, offshore Israel, is the largest conventional natural gas discovery in our history, with resources available for both domestic and export markets. During 2012, we and our existing partners in the Leviathan project commenced a process to identify a partner who could provide technical and financial support as well as midstream and downstream expertise. On December 2, 2012, we and our existing partners announced that we had agreed in principle on a proposal to sell a 30% working interest in the Leviathan licenses to Woodside Energy Ltd. (Woodside). Woodside is Australia's largest producer of LNG with over 25 years of experience and has strong working relationships with many potential customers in the Asian LNG markets. We expect to execute a final agreement with Woodside during the first half of 2013.
2012 Non-Core Divestiture Program Our non-core divestiture program is designed to generate organizational and operational efficiencies as well as cash for use in our capital investment program. Divestitures of non-core properties allow us to allocate capital and employee resources to high-value and high-growth areas. Further, proceeds from divestitures provide additional flexibility in the implementation of our international exploration and development programs and the acceleration of horizontal drilling activities in the DJ Basin and Marcellus Shale. During 2012, divestitures generated net proceeds of approximately $1.2 billion.
On August 13, 2012, we closed the sale of our 30% non-operated working interest in the Dumbarton and Lochranza fields, located in the UK sector of the North Sea. Proceeds from the transaction were $117 million, and included final closing adjustments from the effective date of January 1, 2012. The net book value of assets sold was $255 million. We reversed a deferred tax liability and recognized a corresponding income tax benefit of $99 million related to the sale. Net daily production was approximately 5 MBoe/d at the time of the sale.
During third quarter 2012, we closed on three sales of onshore US properties in Kansas, western Oklahoma, western Texas, and the Texas Panhandle for total proceeds of $1.0 billion. The properties included our interests in about 1,400 producing wells on approximately 109,000 net acres. As of the effective date, April 1, 2012, net daily production was approximately 12.5 MBoe/d.
Additionally, we are continuing the process of marketing certain non-core onshore US properties and are currently soliciting bids. As of December 31, 2012, the Board of Directors and management had not committed to any specific plans to sell the assets, individually or as packaged groups. Therefore, none of these assets was reclassified as held-for-sale at December 31, 2012.
2012 Entry into Falkland Islands Joint Venture In August 2012, we entered into an agreement with Falkland Oil and Gas Limited (FOGL) and subsequently acquired an interest in FOGL's extensive license areas consisting of approximately 10 million undeveloped acres, gross, located south and east of the Falkland Islands.
2012 Entry into Sierra Leone In September 2012, the Government of Sierra Leone awarded us participation in two offshore exploration blocks, SL 8A-10 and SL 8B-10, covering almost 1.4 million acres, gross. Under the terms of the award, Chevron (SL) Ltd. will be the operator and we will have a non-operated 30% working interest.
2012 Exit from Senegal/Guinea-Bissau We decided not to participate in additional appraisal activities and relinquished our acreage.
2011 Entry into Marcellus Shale Joint Venture On September 30, 2011, we entered an agreement with CONSOL to jointly develop oil and gas assets in the Marcellus Shale areas of southwest Pennsylvania and northwest West Virginia. The Marcellus Shale joint venture strengthened and rebalanced our portfolio, providing a new, material growth area, which has contributed to reserves and production growth and provides balance to our rapidly expanding international programs.
2011 Ecuador Exit In May 2011, we transferred our assets in Ecuador to the Ecuadorian government, receiving cash proceeds of $73 million. The net book value of the assets had been reduced due to previous impairment charges, resulting in a pre-tax gain of $25 million.
2010 DJ Basin Asset Acquisition In March 2010, we acquired substantially all of the US Rocky Mountain assets of Petro-Canada Resources (USA) Inc. and Suncor Energy (Natural Gas) America Inc. for a total purchase price of $498 million. The acquisition added approximately 46 MMBoe of proved reserves at closing date, and approximately 10 MBoe/d to our daily production base, starting from the closing date. Included in the purchase were 323,000 total net acres, nearly 183,000 of which are located in the DJ Basin.
2010 Onshore US Sale In August 2010, we closed the sale of non-core assets in the Mid-Continent and Illinois Basin areas for cash proceeds of $552 million and recorded a gain of $110 million. The sale included approximately 32 MMBoe of proved reserves, at closing date, and approximately 5.7 MBoe/d of production.
See Item 8. Financial Statements and Supplementary Data - Note 3. Acquisitions and Divestitures and Note 12. Long-Term Debt.
Sales Volumes
On a BOE basis, total sales volumes from continuing operations were 12% higher in 2012 as compared with 2011, and our mix of sales volumes in 2012 was 46% global liquids, 23% international natural gas, and 31% US natural gas. Onshore US sales volumes increased due to continued acceleration of our horizontal drilling programs in Wattenberg and the Marcellus Shale program, which began at the end of the third quarter of 2011. In the deepwater Gulf of Mexico, new production from Galapagos and South Raton contributed to the increase in sales volumes. International crude oil sales volumes were higher in Equatorial Guinea due to the commencement of crude oil production at Aseng in the fourth quarter of 2011. Israel natural gas sales volumes were lower as we have reduced the rate of production from the Mari-B field in order to manage the reservoir. See Results of Operations - Revenues below.
Commodity Price Changes and Hedging
Historically, crude oil, natural gas and NGL prices have exhibited significant volatility. The crude oil market remained relatively robust during 2012, benefiting from continued threats to the global crude oil supply system. Total consolidated average realized crude oil prices for 2012 increased 2% as compared with 2011.
The domestic natural gas market remains weak, primarily due to an abundant supply and higher levels of gas in storage. US average realized natural gas prices for 2012 decreased 33% as compared with 2011.
Prices continue to be impacted by the slowdown in the global economic recovery, influenced by uncertainty over the eurozone debt crisis, and an increase in supply. As long as development activity continues at, or near, the current level and there is no significant increase in demand, downward pressure on commodity prices is likely to continue. See Item 6. Selected Financial Data for average realized prices for 2008 - 2012. See also Operating Outlook - Potential for Future Asset Impairments, below.
To enhance the predictability of our cash flows and support our capital investment program, we have hedged a portion of our expected global crude oil and natural gas production for 2013. 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 2012, we recorded impairment charges of $104 million, related to our South Raton and Piceance developments due to near-term declines in crude oil and natural gas prices, respectively, and our Mari-B, Pinnacles and Noa fields, offshore Israel, due to end-of-field life declines in production. See Item 8. Financial Statements and Supplementary Data - Note 4. Asset Impairments.
OPERATING OUTLOOK
2013 Outlook We continue to monitor the outlook for the global economy and numerous critical factors including the US federal budget deficit and long-term fiscal situation, the European debt crisis and their potential impacts on global economic growth and commodity prices. We expect the overall global economy to continue a pattern of modest growth, while the European economy is likely to continue to struggle with low growth resulting from its debt crisis.
We expect global crude oil production volumes to continue to grow, primarily due to increases in the US and Canada from continued application of horizontal drilling technology. This growth will likely result in an increase in OPEC spare production capacity. Meanwhile, political risk remains strong: North African and Mideast conflicts, civil unrest, and other potential supply interruption risks are likely to continue. Global crude oil demand is expected to grow in 2013 as the global economy continues to grow. Global crude oil prices will be determined by these supply and demand factors. In the US, de-bottlenecking in the Mid-Continent as transportation improves will also increase Gulf Coast supply; as a result, we expect that US prices will continue to trade at a discount to Brent.
In the US, we expect natural gas prices to be range-bound, as production has continued to increase, even with lower rig counts, until new demand sources catch up with supply growth. One significant issue potentially impacting the industry is the amount of US natural gas exports via LNG that will be approved by the DOE.
Because the global economic outlook and commodity price environment are uncertain, we have built a strong liquidity position to ensure financial flexibility and planned a flexible capital spending program which will support both major project development and exploration activities in a volatile commodity price environment. See 2013 Capital Investment Program below.
2013 Production Our expected crude oil, natural gas and NGL production for 2013 may be impacted by several factors including:
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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;
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timing of major development project completion and initial production, including Tamar, offshore Israel, and Alen, offshore Equatorial Guinea, which are scheduled to begin producing in 2013;
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ongoing development activity in the Wattenberg area and horizontal drilling in the Niobrara formation in the DJ Basin;
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pace of increase of development activity in both wet gas and dry gas areas of the Marcellus Shale;
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divestments of non-core operating assets;
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natural field decline in the deepwater Gulf of Mexico, Gulf Coast and Mid-Continent areas of our US operations, and the Mari-B field in Israel (See Items 1. and 2. Business and Properties - Delivery Commitments);
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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;
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Israeli demand for electricity which affects demand for natural gas as fuel for power generation, market growth, production rates from the Mari-B, Noa and Pinnacles wells, and anticipated production from Tamar, offshore Israel;
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variations in West Africa sales volumes due to potential FPSO downtime and timing of liftings;
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potential hurricane-related volume curtailments in the deepwater Gulf of Mexico and Gulf Coast areas;
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potential winter storm-related volume curtailments in the Rocky Mountain and/or Marcellus Shale areas of our US operations;
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third party facilities reliability in the Wattenberg and/or Rocky Mountain areas of our US properties which may cause restrictions or interruptions in mid-stream processing facilities;
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potential pipeline and processing facility capacity constraints in the Rocky Mountain and/or Marcellus Shale areas of our US operations;
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potential drilling and/or hydraulic fracturing permit delays due to future regulatory changes;
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potential purchases of producing properties; and
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potential shut-in of US producing properties if storage capacity becomes unavailable.
2013 Capital Investment Program Our total capital investment program for 2013 is estimated at $3.9 billion. The capital investment program allocates approximately 60% to onshore US, 6% for deepwater Gulf of Mexico, 10% to the Eastern Mediterranean, 15% to West Africa and 9% to corporate and other. Exploration and appraisal activity within these geographic areas is expected to receive 15% of total capital.
The 2013 capital investment program will exceed operating cash flows and is expected to 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. Funding may also be provided by proceeds from divestment of non-core assets. See Liquidity and Capital Resources - Financing Activities.
We will evaluate the level of capital spending and remain flexible throughout the year based on the following factors, among others:
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commodity prices, including price realizations on specific crude oil and natural gas production including the impact of NGLs;
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cash flows from operations;
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operating and development costs and possible inflationary pressures;
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permitting activity in the deepwater Gulf of Mexico;
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drilling results;
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CONSOL Carried Cost Obligation (See Liquidity and Capital Resources - Off-Balance Sheet Arrangements)
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property acquisitions and divestitures;
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increase in exploration activities in new areas, including offshore Sierra Leone and the Falkland Islands;
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availability of financing;
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potential legislative or regulatory changes regarding the use of hydraulic fracturing;
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potential changes in the fiscal regimes of the US and other countries in which we operate; and
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impact of new laws and regulations, including implementation of the Dodd-Frank Wall Street Reform and Consumer Protection Act, which has resulted in significant derivatives regulations and disclosure requirements, on our business practices.
Exploration Program We continue to evaluate and build upon our significant exploration inventory in the onshore US, deepwater Gulf of Mexico, offshore West Africa, offshore Eastern Mediterranean and other new international locations. During 2012, we expanded our global presence by entering into joint ventures in two new areas, offshore Falkland Islands and offshore Sierra Leone, and by acquiring acreage in Northeast Nevada. Additionally, we drilled a successful exploratory well at Big Bend in the deepwater Gulf of Mexico and drilled our first exploratory well at Scotia, offshore Falkland Islands.
In furtherance of our commitment to global offshore exploration and development, on September 27, 2012, we announced that we have entered into a 36-month drilling services contract for a new-build drillship, the Atwood Advantage. See Items 1. and 2. Business and Properties - International, above.
We continually evaluate and high-grade our exploration inventory to provide additional growth opportunities and potential new core areas. In addition, each of our existing core areas has significant remaining exploration upside. We continue to leverage existing activities to improve our exploratory programs in these core areas.
We devote significant capital to our exploration program. Approximately 15% of our $3.9 billion capital investment program in 2013 is dedicated to exploration and associated appraisal activities. However, we do not always encounter hydrocarbons through our drilling activities. In addition, we may find hydrocarbons but subsequently reach a decision, through additional analysis or appraisal drilling, that a project is not economically or operationally viable.
We are currently conducting, or planning to conduct, exploratory drilling activities in previously unexplored areas as well as appraisal activities at several of our discoveries. In the event we conclude that one of our exploratory wells did not encounter hydrocarbons or that a discovery is not economically or operationally viable, the associated capitalized exploratory well costs would be charged to expense. As a result, in a future period, dry hole cost could be material. See Results of Operations - Oil and Gas Exploration Expense, below. See also Item 1A. Risk Factors - Our entry into new exploration ventures in areas in which we have no prior experience subjects us to additional risks.
Major Development Project Inventory Our current inventory of major development projects includes the horizontal Niobrara, Marcellus Shale, Tamar, Alen, Diega and Carla, Gunflint, Big Bend, Leviathan, Cyprus and other West Africa gas projects. These projects will require significant capital investments.
As noted above, we expect to spend substantial amounts on our major development projects in 2013. 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.
The second of our major development projects brought online since 2011, Galapagos, located in the deepwater Gulf of Mexico, began commercial crude oil production in June 2012 and two additional major development projects, Tamar, offshore Israel, and Alen, offshore Equatorial Guinea, are on schedule to begin commercial production in 2013. The additional production from these three major development projects, along with Aseng, offshore Equatorial Guinea, which began production in 2011, is expected to begin generating significant cash flow which will be available to meet a substantial portion of future capital requirements. See Liquidity and Capital Resources - Capital Structure/Financing Strategy.
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, including our partners in our Eastern Mediterranean projects, 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, liquidity and financial position, Failure of our partners to fund their share of development costs or obtain project financing could result in delay or cancellation of future projects, thus limiting our growth and future cash flows, and We are exposed to counterparty credit risk as a result of our receivables, hedging transactions, and cash investments.
Potential for Future Asset Impairments We recorded asset impairment charges of $104 million during 2012. A further decline in future NYMEX crude oil or natural gas prices could result in additional impairment charges. 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, 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 crude oil or natural gas prices alone could result in impairment.
We are currently marketing certain non-core onshore US properties. If the properties are reclassified as assets held for sale, they will be valued at the lower of net book value or anticipated sales proceeds less costs to sell. Impairment expense would be recorded for any excess of net book value over anticipated sales proceeds less costs to sell. In addition, we would allocate a portion of goodwill to any non-core onshore US property held for sale that constitutes a business, which could potentially decrease any gain or increase any loss recorded on the sale.
Occasionally, well mechanical problems arise, which can reduce production and potentially result in reductions in proved reserves estimates. For example, our South Raton development in the deepwater Gulf of Mexico is currently shut-in due to mechanical issues. We are currently testing the well to determine appropriate remediation efforts. South Raton had a net book value of approximately $116 million at December 31, 2012.
See Item 1A. Risk Factors - Crude oil, natural gas, and NGL prices are volatile and a reduction in these prices could adversely affect our results of operations, our liquidity, and the price of our common stock. See Item 8. Financial Statements and Supplementary Data - Note 4. Asset Impairments.
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. In 2011, the United Nations-sponsored Intergovernmental Panel on Climate Change, a scientific body which provides an assessment of the risk of climate change, issued its Special Report on Managing the Risks of Extreme Events and Disasters to Advance Climate Change Adaptation, in which it concluded that it is likely that climate change is fueling extreme weather and predicted that there will be an escalation of impacts on people and economies.
In November 2012, the World Bank issued a report based on recent scientific literature and new analysis of likely impacts and risks that would be associated with a 4oC warming within this century. Risks include rise in sea-levels, increases in tropical cyclone intensity, increasing aridity and drought. The report predicted severe impacts on coastal cities, food and water systems, ecosystems, and human health and called for international cooperation to prevent global warming. Also in 2012, a coalition of institutional investors said that rapidly growing greenhouse gas and more extreme weather were increasing investment risks globally and called on governments to increase action on climate change and boost investment in clean energy technology.
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, carbon taxes, 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. Due to the current global economic environment and debt crisis, many countries are facing pressure to reduce spending or implement austerity measures. This could result in the diverting of attention away from the environmental agenda as well as limited financial resources available for spending on environmental policies. 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. However, the EPA has indicated that it will use data collected through the reporting rules to decide whether to promulgate future GHG limits. These and other 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 required all industrialized nations that ratified the Protocol to reduce or limit GHG emissions to a specified level by 2012. The US did not ratify the Protocol.
In December 2012, the annual conference of parties reconvened in Doha, Qatar, to continue pursuing the global accord, committing countries to cut GHG emissions. The parties agreed to a second commitment period of the Kyoto Protocol which will last until December 31, 2020.
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 - Regulations and the following risk factors listed in Item 1A. Risk Factors -
•
We are subject to increasing governmental regulations and environmental requirements that may cause us to incur substantial incremental costs; and
•
The adoption of GHG emission or other environmental legislation could result in additional 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 54% of our 2012 total sales volumes from continuing operations were natural gas. GHG emissions regulation could reduce the demand for the crude oil we produce. At the same time, the burning of natural gas produces lower levels of emissions than other readily available fossil fuels such as crude oil and coal. Therefore, the use of natural gas may increase should the use of other fossil fuels decrease due to GHG emissions regulation.
The 2011 incident at the Fukushima nuclear plant in Japan has re-opened debate about the future of nuclear power as an alternative to fossil fuels, and public concern about nuclear safety has been heightened. In response, Germany, Japan, and other nations have announced future shutdowns of nuclear plants and/or moratoria on future nuclear plant construction, resulting in increased demand for alternate fuel sources, including natural gas, for power generation.
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 became 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, tornadoes and snow or ice storms, as well as rising sea levels. Extreme weather conditions limit our production and 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 and our onshore US operations in the DJ Basin and Marcellus Shale. See Item 1A. Risk Factors - The insurance we carry is insufficient to cover all of the risks we face, which could result in significant financial exposure.
Recently Issued Accounting Standards Update See Item 8. Financial Statements and Supplementary Data - Note 1. Summary of Significant Accounting Policies.
RESULTS OF OPERATIONS
In the discussion below, prior year amounts have been reclassified to reflect the North Sea segment as discontinued operations. See Discontinued Operations, below. Financial information presented is from continuing operations, unless otherwise noted.
Selected financial information is as follows:
Factors contributing to the increase in income from continuing operations before income taxes in 2012 as compared with 2011 included the following:
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$819 million increase in total revenues due to higher sales volumes and higher average realized crude oil prices;
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$129 million increase in gain on divestitures;
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$33 million increase in gain on commodity derivative instruments; and
•
$653 million decrease in asset impairment charges;
offset by:
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$115 million increase in total production expense;
•
$132 million increase in exploration expense;
•
$492 million increase in DD&A expense; and
•
$45 million increase in general and administrative expense.
Factors contributing to the decrease in income from continuing operations before income taxes in 2011 as compared with 2010 included the following:
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$43 million increase in total production expense;
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$35 million increase in exploration expense;
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$59 million increase in DD&A expense;
•
$66 million increase in general and administrative expense;
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$88 million decrease in net gain on asset sales;
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$613 million increase in asset impairment charges; and
•
$115 million decrease in gain on commodity derivative instruments;
offset by:
•
$691 million increase in total revenues due primarily to higher commodity prices and higher sales volumes.
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 is as follows:
Changes in revenue are discussed below.
Oil, Gas and NGL Sales Average daily sales volumes and average realized sales prices were as follows:
(1)
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.
(2)
Volumes represent sales of condensate and LPG from the Alba plant in Equatorial Guinea. See Income from Equity Method Investees below.
(3)
Includes sales volumes 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 Item 8. Financial Statements and Supplementary Data - Note 3. Acquisitions and Divestitures.
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 $1.2 billion, or 58% in 2012 as compared with 2011 due to the following:
•
higher sales volumes in the DJ Basin attributable to the acceleration of our horizontal drilling programs in the Wattenberg area;
•
commencement of production at Galapagos and South Raton in the deepwater Gulf of Mexico which increased production by approximately seven MBoe/d, net, during 2012;
•
higher sales volumes in Equatorial Guinea due to the commencement of oil production at Aseng during the fourth quarter of 2011, which impacted our sales volumes by approximately 21 MBbl/d, net, in 2012 as compared with 2011; and
•
a 2% increase in total consolidated average realized prices primarily due to higher Brent pricing resulting from the global economic recovery
partially offset by
•
reduction in sales volumes due to the sales of non-core, onshore US properties during the third quarter of 2012;
•
a volume reduction in the Gulf of Mexico of nearly seven MBoe/d as a result of shut-ins due to Hurricane Isaac; and
•
natural field decline in non-core onshore US and deepwater Gulf of Mexico areas.
Revenues from crude oil and condensate sales increased by $535 million, or 36%, in 2011 as compared with 2010 due to the following:
•
a 31% increase in total consolidated average realized prices due to increased demand resulting from the global economic recovery;
•
higher sales volumes in the DJ Basin, including a 21% increase in Wattenberg sales volumes, attributable to the continued acceleration of our horizontal Niobrara development project; and
•
higher sales volumes in Equatorial Guinea due to a higher number of liftings from our Alba field and due to the commencement of oil production at Aseng which impacted our sales volumes by approximately 9 MBbl/d in the fourth quarter;
partially offset by
•
a decrease in onshore US volumes due to the divestment of non-core oil assets; and
•
a decrease in deepwater Gulf of Mexico volumes due to natural field decline and third party downstream facility constraints.
Revenues from crude oil and condensate sales included deferred losses of $19 million in 2010 reclassified from AOCL related to commodity derivative instruments previously accounted for as cash flow hedges. As of 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 decreased by $263 million, or 30%, in 2012 as compared with 2011 due to the following:
•
decreases in US average realized prices primarily due to oversupply and above average levels of natural gas in storage;
•
lower sales volumes due to the sales of non-core onshore US properties during the third quarter of 2012;
•
lower sales volumes in the Wattenberg and Rocky Mountain areas of our US operations due to third-party processing facility constraints;
•
lower sales volumes from the Alba field, offshore Equatorial Guinea, due to scheduled maintenance activities at the non-operated Alba facilities; and
•
lower sales volumes in Israel due to a reduction in the rate of production from the Mari-B field in order to manage the reservoir;
partially offset by
•
higher sales volumes attributable to the acceleration of our horizontal drilling programs in the Wattenberg area; and
•
new sales volumes from Marcellus Shale producing properties which we acquired September 30, 2011 and current Marcellus Shale development activities, which added 90 MMcf/d, net to our sales volumes for 2012.
Revenues from natural gas sales increased by $62 million, or 8%, in 2011 as compared with 2010 due to the following:
•
higher natural gas prices in Israel which benefit from strong global liquids markets;
•
an increase in Israel sales volumes due to an increase in demand for our natural gas driven by higher electricity production and lower levels of competitor natural gas imports from Egypt;
•
higher sales volumes in the DJ Basin, including a 10% increase in Wattenberg sales volumes, attributable to the continued acceleration of our vertical and horizontal Niobrara drilling programs in the Wattenberg area;
•
sales volumes from Marcellus Shale producing properties which we acquired September 30, 2011 and which added 19 MMcf/d to our 2011 sales volumes; and
•
higher sales volumes in Equatorial Guinea as compared with 2010, during which time the Alba field experienced a planned shut-down for facilities maintenance and repair;
partially offset by
•
a decrease in US realized natural gas prices which declined during 2011 primarily due to oversupply;
•
a decrease in onshore US sales volumes due to the sale of certain non-core Oklahoma and Illinois Basin assets in 2010; and
•
natural field decline in the deepwater Gulf of Mexico, Gulf Coast and Mid-Continent areas.
Revenues from natural gas included a deferred loss of $1 million in 2010 reclassified from AOCL related to commodity derivative instruments previously accounted for as cash flow hedges. As of 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 the Wattenberg area. NGL sales revenues decreased $50 million, or 19%, during 2012 as compared with 2011 as a result of lower realized prices offset by an increase in sales volumes. Our average realized prices declined 27% during 2012 compared to 2011 primarily due to higher supplies of NGLs resulting from increased wet gas drilling activities.
NGL sales revenues increased $59 million, or 29%, during 2011 as compared with 2010 due to higher realized prices and a slight increase in sales volumes due to ongoing development in the DJ Basin.
Income from Equity Method Investees We have a 45% interest in AMPCO, which owns and operates a methanol plant and related facilities, and a 28% interest in Alba Plant, which owns and operates an LPG processing plant. Both plants and related facilities are located onshore Bioko Island in Equatorial Guinea. We also have a 50% interest in CONE Gathering LLC (CONE), which owns and operates natural gas gathering facilities servicing our joint venture properties in the Marcellus Shale. 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 decreased in 2012 as compared with 2011 primarily due to increased other non-operating expense.
Net income from AMPCO and affiliates increased in 2011 as compared with 2010 due to increases in average realized methanol prices due to global economic recovery, and increases in methanol sales volumes as compared with 2010 when the plant experienced down time related to a major turnaround.
Alba Plant Net income from Alba Plant decreased slightly in 2012 as compared with 2011 due to lower realized price.
Net income from Alba Plant increased in 2011 as compared with 2010 due to increases in average realized condensate and LPG prices due to global economic recovery.
CONE Gathering LLC Under the terms of the gathering and marketing agreement that we entered into with CONE, we will pay CONE a minimum annual revenue commitment (MARC). The fee will be adjusted annually based on projected gathering volumes, operating expenses, capital expenditures, and other factors. Our share of CONE earnings were de minimis for the year ended December 31, 2012 and 2011. During 2012, we contributed $41 million to CONE. See Item 8. Financial Statements and Supplementary Data - Note 3. Acquisitions and Divestitures.
Other Revenues Other revenues were as follows:
Other revenues include electricity sales from the Machala power plant, located in Machala, Ecuador, (through May 2011) and other revenue items. See Item 8. Financial Statements and Supplementary Data - Note 2. Additional Financial Statement Information.
Operating Costs and Expenses
Operating costs and expenses were as follows:
Changes in operating costs and expenses are discussed below.
Production Expense Components of production expense were as follows:
N/M Amount is not meaningful. See (2) below.
(1)
Consolidated unit rates exclude sales volumes and costs attributable to equity method investees
(2)
Other international includes China and unallocated expenses incurred at the corporate level.
(3)
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.
Lease Operating Expense Lease operating expense was $431 million in 2012 as compared with $346 million 2011, a 25% increase. Changes included the following:
•
higher sales volumes from the Wattenberg area due to ongoing development activities accounted for an increase of $24 million in US lease operating expense;
•
new production at Galapagos and higher production handling costs at Swordfish, deepwater Gulf of Mexico, accounted for an increase of $22 million;
•
a full year of production from Marcellus Shale properties acquired in 2011, and additional development activity accounted for an increase of $17 million;
•
lease operating expense associated with the Aseng field, offshore Equatorial Guinea, which began producing in November 2011, accounted for an increase of $36 million; and
•
the start-up of the Noa and Pinnacles wells, offshore Israel, in second quarter of 2012 accounted for an increase of $8 million;
partially offset by
•
lower volumes in the US due to the sale of non-core onshore US properties during the third quarter of 2012.
Lease operating expense increased in 2011 as compared to 2010 due to the following:
•
higher US sales volumes from the DJ Basin due to ongoing development activities;
•
higher sales volumes in Equatorial Guinea and Israel; and
•
higher operating costs associated with the Aseng field which began producing in November 2011;
offset by
•
the sale of certain Oklahoma and Illinois Basin assets in 2010, which had higher lease operating costs.
Production and Ad Valorem Tax Expense In the US, taxes increased in 2012 as compared with 2011 due to the enactment of the annual Marcellus Shale well impact fee by the Pennsylvania legislature in first quarter 2012. This enactment increased taxes approximately $8 million, of which approximately $4 million related to wells spud prior to 2012. Additionally, higher volumes for the Wattenberg area resulted in an increase of $15 million. This increase was offset by non-core onshore US property sales during 2012.
Production and ad valorem tax expense decreased in 2011 as compared with 2010 due to the sale of certain non-core Oklahoma and Illinois Basin assets in 2010 and natural field decline in the Mid-Continent area. This decrease was offset by higher production and ad valorem taxes in the DJ Basin due to increased production volumes and higher sales prices. Production and ad valorem tax expense for 2011 increased in China as compared with 2010 due to higher sales prices.
Transportation Expense Transportation expense increased in 2012 as compared with 2011. Higher US crude oil sales volumes from the DJ Basin as a result of ongoing development activities resulted in an increase of $21 million. A full year of production from our Marcellus Shale producing properties, acquired on September 30, 2011, resulted in an increase of $8 million. These increases were offset by reductions in transportation expense due to non-core onshore US property sales during the third quarter of 2012.
Transportation expense increased in 2011 as compared with 2010 due to higher sales volumes in the DJ Basin and new production from our Marcellus Shale producing properties acquired on September 30, 2011, offset by lower transportation expense in the deepwater Gulf of Mexico due to declining production.
Unit Rate Per BOE The unit rate of total production expense per BOE increased for 2012 as compared with 2011 primarily due to a change in the mix of production, including new production at Galapagos and South Raton, and the start-up of the Noa and Pinnacles wells, each of which has a higher production rate than our other projects, and the enactment of the Marcellus Shale well impact fee.
The unit rate of total production expense per BOE increased for 2011 as compared with 2010 primarily due to higher production tax rates on certain onshore US and China production, transportation charges related to Marcellus Shale producing properties and the startup of the Aseng field.
Exploration Expense Components of exploration expense were as follows:
(1)
West Africa includes Equatorial Guinea, Cameroon, Sierra Leone, and Senegal/Guinea-Bissau.
(2)
Eastern Mediterranean includes Israel and Cyprus.
(3)
Other International includes various international new ventures such as offshore Nicaragua and offshore Falkland Islands.
Oil and gas exploration expense increased in 2012 as compared with 2011 due to the following:
•
US dry hole expense associated with the Deep Blue exploratory well (deepwater Gulf of Mexico) totaled $117 million. Although Deep Blue was successful in locating hydrocarbons, we decided not to develop the prospect due to near-term lease expiration as well as other considerations;
•
dry hole expense in West Africa related to the Trema exploratory well, which found noncommercial quantities of hydrocarbons, totaled $32 million;
•
exploration expense in West Africa includes $40 million for the non-operated AGC Profond block offshore Senegal/Guinea-Bissau, which was written off during the third quarter of 2012 when we decided not to proceed with additional appraisal activities. We relinquished our acreage;
•
seismic expenditures related to the deepwater Gulf of Mexico lease sale and international new ventures; and
•
exploration expense also includes staff expense associated with new ventures and corporate expenditures.
Oil and gas exploration expense increased in 2011 as compared with 2010 due to the following:
•
US dry hole expense was associated with the Rocky Mountain area and the Redrock exploration well in the deepwater Gulf of Mexico, which we decided not to pursue for development due to the significant decline in natural gas prices;
•
dry hole expense in West Africa related to the Kora-1 exploration well offshore Senegal/Guinea-Bissau and the Bwabe exploration well offshore Cameroon, which found noncommercial quantities of hydrocarbons;
•
seismic expenditures related to acquisition of information for Wattenberg, Rocky Mountain and deepwater Gulf of Mexico areas in the US, offshore Nicaragua, offshore France, and offshore Cyprus; and
•
increases in staff expense were due to new ventures mainly offshore Nicaragua and offshore France.
Exploration expense included stock-based compensation expense of $12 million in 2012, $11 million in 2011, and $10 million in 2010.
Depreciation, Depletion and Amortization DD&A expense was as follows:
(1)
DD&A expense includes accretion of discount on asset retirement obligations of $22 million in 2012, $13 million in 2011, and $13 million in 2010.
(2)
Consolidated unit rates exclude sales volumes and costs attributable to equity method investees.
Total DD&A expense increased for 2012 as compared with 2011 due to the following:
•
higher sales volumes in the DJ Basin onshore US accounted for $189 million of the increase and the addition of DD&A expense related to the Marcellus Shale accounted for $46 million of the increase;
•
the start up of Noa and Pinnacles (offshore Israel), which have higher DD&A rates, accounted for $86 million of the increase;
•
the start up of Galapagos and South Raton in the deepwater Gulf of Mexico, which have higher DD&A rates, accounted for $92 million of the increase;
•
a full year of production from the Aseng field, offshore Equatorial Guinea, which includes the Aseng FPSO in its depreciation base, accounted for $183 million of the increase; and
•
higher costs associated with development activities in China;
partially offset by
•
the impact of sales of non-core, onshore US properties during 2012.
Changes in the unit rate per BOE for 2012 as compared with 2011 were due to changes in the mix of production, primarily due to volumes from the start-up of the Galapagos, Noa, Pinnacles and South Raton projects and a full year of production from Aseng, which have comparatively higher DD&A rates, and increased horizontal drilling activity.
Total DD&A expense increased for 2011 as compared with 2010 due to the following:
•
higher sales volumes in the DJ Basin of our onshore US operations resulting from ongoing capital spending;
•
higher sales volumes in Equatorial Guinea and the startup of the Aseng field which includes the Aseng FPSO in its depreciation base;
•
higher costs associated with development activities in China; and
•
the impact of negative reserves revisions at December 31, 2011, due to revised performance expectations in the North Sea and China;
partially offset by
•
lower sales volumes in the deepwater Gulf of Mexico, Gulf Coast, and Mid-Continent areas of our US operations resulting from natural field decline.
General and Administrative Expense General and administrative expense (G&A) was as follows:
(1)
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.
G&A expense for 2012 increased as compared with 2011 primarily due to additional personnel and office space supporting growth in the Wattenberg and Marcellus Shale core areas and augmentation of environmental, health and safety, geoscience, and information technology departments in support of our major development projects and increased exploration activities, and increased performance incentive compensation.
G&A expense increased for 2011 as compared with 2010 primarily due to additional expenses relating to personnel, office costs and information technology costs in support of our major development and exploration projects and increased performance incentive compensation.
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 $48 million in 2012, $42 million in 2011 and $39 million in 2010. See Item 8. Financial Statements and Supplementary Data - Note 14. Stock-Based and Other Compensation Plans.
Gain on Divestitures Gain on divestitures was as follows:
Gain on divestitures for 2012 is related to the sale of certain non-core onshore US assets. See Item 8. Financial Statements and Supplementary Data - Note 3. Acquisitions and Divestitures.
Gain on divestitures for 2011 includes a $25 million gain on the transfer of assets and the associated PSC and electricity concession to the Ecuadorian government. Gain on divestitures for 2010 includes a $110 million gain on the sale of certain non-core assets in the Mid-Continent and Illinois Basin areas. 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 and Supplementary Data - Note 4. Asset Impairments.
Other Operating Expense, Net Other operating expense, net was as follows:
See Item 8. Financial Statements and Supplementary Data - Note 2. Additional Financial Statement Information.
Other (Income) Expense Other (income) expense was as follows:
See Item 8. Financial Statements and Supplementary Data - Note 2. Additional Financial Statement Information.
Gain on Commodity Derivative Instruments 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 15. Fair Value Measurements and Disclosures.
Interest Expense and Capitalized Interest Interest expense and capitalized interest were as follows:
(1)
Consolidated unit rates exclude sales volumes and costs attributable to equity method investees.
Interest expense prior to the reduction of capitalized interest increased $79 million from 2011 to 2012 due to our December 2011 debt issuance, an additional month of interest for our February 2011 debt issuance and interest related to our Aseng FPSO lease obligation.
Interest expense prior to the reduction of capitalized interest increased $58 million in 2011 as compared with 2010 resulting from a higher outstanding debt balance during the period and the interest associated with our 2011 public debt issuances. The higher rate on the senior unsecured notes replaced the substantially lower rate applicable to our revolving credit facility which was repaid with proceeds from our debt offering.
The increase of $19 million in the amount of interest capitalized in 2012 compared to 2011 is due to higher work in progress amounts related to major long-term projects in the deepwater Gulf of Mexico, offshore West Africa, and Eastern Mediterranean.
The increase of $65 million in the amount of interest capitalized in 2011 compared to 2010 is due to higher work in progress amounts related to major long lead-time projects in the deepwater Gulf of Mexico, offshore West Africa, and Eastern Mediterranean and a higher weighted average interest rate due to our fixed rate senior unsecured note issuances in 2011, which impacted the average rate we pay on long-term debt.
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, offshore West Africa and offshore Eastern Mediterranean. 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 includes deferred compensation (income) expense, interest income and other (income) expense, net. See Item 8. Financial Statements and Supplementary Data - Note 2. Additional Financial Statement Information.
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, 2012, approximately 48% 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 $6 million in 2012, $8 million in 2011, and $15 million in 2010. See Item 8. Financial Statements and Supplementary Data - Note 14. Stock-Based and Other Compensation Plans.
Income Tax Provision The income tax provision was as follows:
See Item 8. Financial Statements and Supplementary Data - Note 13. Income Taxes.
Discontinued Operations
Summarized results of discontinued operations, comprising our North Sea geographical segment, were as follows:
(1)
Includes exploration expense of $27 million in 2012 related to the Selkirk field. During 2012, the nearby Bligh well, a potential co-development candidate for Selkirk, was drilled. Bligh encountered hydrocarbons but disappointingly tight non-commercial reservoirs. Therefore, we determined that Selkirk was uneconomic for joint development.
Our long-term debt is recorded at the consolidated level and is not reflected by each component. Thus, we have not allocated interest expense to discontinued operations.
See Item 8. Financial Statements and Supplementary Data - Note 3. Acquisitions and Divestitures.
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, 2012 included a negative revision of 94 MMBoe due to our decision to terminate the legacy vertical drilling program in Wattenberg and focus on the horizontal development of the Niobrara; net positive revisions of 23 MMBoe, primarily related to better than expected well performance in the Marcellus Shale, the deepwater Gulf of Mexico, and the Aseng field; and negative revisions of 26 MMBoe due to changes in commodity prices;
•
changes for the year ended December 31, 2011 include a negative revision of 28 MMBoe, due primarily to reclassifications of proved undeveloped reserves in Wattenberg that are no longer expected to be developed within five years due to additional shifting of activity from vertical to horizontal development, a negative revision of 10 MMBoe due to reduced activity assumptions for dry gas properties onshore US, as well as other lesser revisions in various other areas related to well performance and changes in commodity prices; and
•
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, would be pursued for development, and a negative revision of 2 MMBoe due to well performance.
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, 2012 included an increase of 149 MMBoe in the DJ Basin as a result of our decision to focus capital and resources on horizontal development of the Niobrara, 56 MMBoe related to ongoing development of the Marcellus Shale, 7 MMBoe related to the ongoing appraisal of Tamar, and 6 MMBoe for other projects;
•
changes for the year ended December 31, 2011 included increases of 97 MMBoe in the onshore US, primarily associated with horizontal drilling in the DJ Basin and development activities in the Marcellus Shale, 80 MMBoe at Tamar due to appraisal activities, and 3 MMBoe for other projects; and
•
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.
We expect that a significant portion of future reserves additions will come from our major development projects at the DJ Basin, Marcellus Shale, Gunflint, Tamar and Leviathan and from new discoveries resulting from our active exploration programs in both core areas and global new ventures programs. We may also purchase proved properties in strategic acquisitions. See Operating Outlook - Major Development Project Inventory, above, and Liquidity and Capital Resources - 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 Marcellus Shale asset acquisition in 2011; and
•
the DJ Basin asset acquisition in 2010.
Sale of Minerals in Place We maintain an ongoing portfolio management program. Sales included the following:
•
the sale of non-core, onshore US assets in the Kansas, western Oklahoma, west Texas and Wyoming areas and the North Sea in 2012; and
•
the sale of non-core assets in the Mid-Continent and Illinois Basin areas in 2010.
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 in November 2010. See Items 1. and 2. Business and Properties and Item 8. Financial Statements and Supplementary Data - Note 3. Acquisitions and Divestitures.
Production See Results of Operations - Revenues - 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 sufficient liquidity throughout the commodity price cycle. Specifically, we strive to retain the ability to fund long cycle, multi-year, capital intensive development projects throughout a range of scenarios, while also maintaining the capability to execute a robust exploration program and capitalize on financially attractive periodic mergers and acquisitions activity. We endeavor to maintain an investment grade debt rating in service of these objectives, while delivering competitive returns and a growing dividend. We also utilize a commodity price hedging program to reduce the impacts of commodity price volatility and enhance the predictability of cash flows along with a risk and insurance program to protect against disruption to our cash flows and the funding of our business.
Our current line-up of major development projects, as well as our planned exploration and appraisal drilling activities, will result in capital expenditures exceeding cash flows from operating activities over the near term. The amount by which capital investment will exceed operating cash flows depends on our success in sanctioning future development projects, the results of our exploration activities, and new business opportunities. To support our investment program, we expect that higher production resulting from our accelerated horizontal Niobrara development program combined with new production from Tamar and Alen will result in an increase in cash flows which will be available to meet a substantial portion of future capital requirements. In addition, our current liquidity level and strong balance sheet provide flexibility. We believe that we are well-positioned to fund our long-term growth plans. See Available Liquidity, below.
We are currently evaluating potential development scenarios for our significant natural gas discoveries offshore Eastern Mediterranean, including Leviathan and Cyprus Block 12. The magnitude of these discoveries presents financial and technical challenges for us due to the large-scale development requirements. Potential development scenarios may include the construction of LNG terminals, floating LNG, subsea pipeline or other options. Each of these development options would require a multi-billion dollar investment and require a number of years to complete. We have announced a potential strategic partner for Leviathan, Woodside, who could provide midstream expertise as well as LNG project execution and marketplace expertise. We are in the process of negotiating a definitive agreement. See Items 1. and 2. Business and Properties - Acquisition and Divestiture Activities.
We strive to maintain a minimum liquidity level to address volatility and risk. Traditional sources of our liquidity are cash on hand, cash flows from operations, available borrowing capacity under our credit facility, and proceeds from sales of non-core properties, such as certain onshore US and North Sea properties in 2012. We may also access debt and/or capital markets for additional financing, such as an issuance of long-term debt or project finance, for our large development projects. We exercised our option to increase our Credit Facility's overall commitment amount by an additional $1.0 billion, on September 28, 2012. See Credit Facility below. See also Item 1A. Risk Factors - Unavailability of capital resources at reasonable cost could have a negative impact on our liquidity and limit our growth.
Marcellus Shale Joint Venture Our joint venture arrangement with a subsidiary of CONSOL Energy, Inc. is structured in a manner to address partner alignment and financial affordability. We spread the $1.3 billion acquisition cost over a three-year period, beginning at closing. The $2.1 billion CONSOL Carried Cost Obligation is expected to extend over a multi-year period and is capped at $400 million maximum in each calendar year. The obligation is suspended if average Henry Hub natural gas prices fall and remain below $4.00 per MMBtu in any three consecutive month period and will remain suspended until average Henry Hub natural gas prices are above $4.00 per MMBtu for three consecutive months. The carry terms ensure economic alignment with our partner in periods of low natural gas prices. Due to the suppressed natural gas price, we did not make any payments towards the CONSOL Carried Cost Obligation in 2012 and expect the carry to remain suspended in 2013. See Off-Balance Sheet Arrangements below. See Item 8. Financial Statements and Supplementary Data - Note 3. Acquisitions and Divestitures and Note 12. Long-Term Debt.
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.
Available Liquidity Information regarding cash and debt balances was as follows:
(1)
See Credit Facility below.
(2)
Total debt includes Aseng FPSO lease obligation and remaining CONSOL installment payments and excludes unamortized debt discount.
(3)
We define our ratio of debt-to-book capital as total debt (which includes long-term debt excluding unamortized discount, the current portion of long-term debt, and short-term borrowings) divided by the sum of total debt plus shareholders’ equity.
Cash and Cash Equivalents We had approximately $1.4 billion in cash and cash equivalents at December 31, 2012, compared with approximately $1.5 billion at December 31, 2011. At December 31, 2012 our cash was primarily denominated in US dollars and invested in money market funds and short-term deposits with major financial institutions. Approximately $1.0 billion 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 cash during 2013 to fund international projects, including the planned developments in West Africa and the Eastern Mediterranean.
Credit Facility We have an unsecured revolving credit facility that matures on October 14, 2016. The commitment is $4.0 billion through the maturity date of the credit facility. See Financing Activities - Long-Term Debt below.
Derivative Instruments We use various derivative instruments in combination 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 price commodity swaps, two and three-way collars and basis swaps. We have also used derivative instruments to manage interest rate risk by entering into forward contracts or swap agreements to minimize the impact of interest rate fluctuations associated with fixed or floating rate borrowings. Current period settlements on derivative instruments impact our liquidity, since we are either paying cash to, or receiving cash from, our counterparties.
None of our counterparty agreements contain margin requirements. Depending on the rules and definitions adopted by the CFTC and prudential regulators pursuant to the requirements of the Dodd-Frank Act, we could be required to post significant amounts of collateral with our dealer counterparties for our derivative transactions. A sudden margin call driven by an increase in commodity prices 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 result in negative impacts on our liquidity and financial flexibility and also cause us to incur additional debt. See Item 1A. Risk Factors - Derivatives regulation included in current or proposed financial legislation and rulemaking 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.
Commodity derivative instruments are recorded at fair value in our consolidated balance sheets, and changes in fair value are recorded in earnings in the period in which the change occurs. As of December 31, 2012, the fair value of our commodity derivative assets was $84 million and the fair value of our commodity derivative liabilities was $10 million (after consideration of netting clauses within our master agreements). 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.
See Critical Accounting Policies and Estimates - Derivative Instruments and Hedging Activities,

ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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 volatility 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, 2012, we had entered into variable to fixed price commodity swaps, collars and basis swaps related to crude oil and natural gas sales. Changes in fair value of commodity derivative instruments are reported in earnings in the period in which they occur. Our open commodity derivative instruments were in a net asset position with a fair value of $74 million. Based on the December 31, 2012 published commodity futures price curves for the underlying commodities, a hypothetical price increase of $1.00 per Bbl for crude oil would decrease the fair value of our net commodity derivative asset by approximately $20 million. A hypothetical price increase of $0.10 per MMBtu for natural gas would decrease the fair value of our net commodity derivative asset 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 cash settled at the time of election. See

ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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, 2012, 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, 2012, 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, 2012 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, 2012 and 2011, and the related consolidated statements of operations, comprehensive income, shareholders' equity, and cash flows for each of the years in the three-year period ended December 31, 2012. 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 conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Noble Energy, Inc. and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2012, 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, 2012, 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 7, 2013 expressed an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.
/s/ KPMG LLP
Houston, Texas
February 7, 2013
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, 2012, 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, 2012, 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, 2012 and 2011, and the related consolidated statements of operations, comprehensive income, shareholders' equity, and cash flows for each of the years in the three-year period ended December 31, 2012, and our report dated February 7, 2013 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
Houston, Texas
February 7, 2013
Noble Energy, Inc.
Consolidated Statements of Operations
(millions, except per share amounts)
The accompanying notes are an integral part of these financial statements.
Noble Energy, Inc.
Consolidated Statements of Comprehensive Income
(millions)
The accompanying notes are an integral part of these financial statements.
Noble Energy, Inc.
Consolidated Balance Sheets
(millions)
The accompanying notes are an integral part of these financial statements.
Noble Energy, Inc.
Consolidated Statements of Cash Flows
(millions)
The accompanying notes are an integral part of these financial statements.
Noble Energy, Inc.
Consolidated Statements of Shareholders' Equity
(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 core operating areas are onshore US (DJ Basin and Marcellus Shale), deepwater Gulf of Mexico, offshore West Africa and offshore Eastern Mediterranean.
Basis of Presentation and Consolidation Accounting policies used by us and our subsidiaries conform to 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, goodwill and asset retirement obligations, valuation allowances for receivables and deferred income tax assets, and valuation of derivative instruments, 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. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. Further decline in natural gas prices or a significant decline in crude oil prices could result in a reduction in our fair value estimates and cause us to perform analyses to determine if our oil and gas properties and/or goodwill are impaired. As future commodity prices cannot be determined accurately, actual results could differ significantly from our estimates. See Supplemental Oil and Gas Information (Unaudited).
Reclassification Certain reclassifications have been made to the 2011 and 2010 consolidated financial statements to reflect the operations of our North Sea geographical segment as discontinued, as well as to conform to the 2012 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 15. Fair Value Measurements and Disclosures.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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 of oil and gas properties. See Note 6. Inventories.
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 individually significant proved oil and gas properties and other long-lived assets for impairment at least semi-annually, at year-end and mid-year, or quarterly 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 2012, 2011, and 2010. It is likely 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 Our unproved properties consist of leasehold costs and allocated value to probable and possible reserves from acquisitions. We assess individually significant unproved properties for impairment 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 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. It is reasonably possible that 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 When 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 cash flows from the production 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
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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.
Assets Held for Sale We occasionally market non-core oil and gas properties. At the end of each reporting period, we evaluate our properties being marketed to determine whether any should be reclassified as held-for-sale. The held-for-sale criteria include: a commitment to a plan to sell; the asset is available for immediate sale; an active program to locate a buyer exists; the sale of the asset is probable and expected to be completed within one year; the asset is being actively marketed for sale; and it is unlikely that significant changes to the plan will be made. If each of these criteria is met, the property is reclassified as held-for-sale in our consolidated balance sheets. 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.
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 weighted 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 $151 million in 2012, $132 million in 2011, and $67 million in 2010.
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. We recognize the fair value of a liability for an ARO in the period in which it is incurred when we have an existing legal obligation associated with the retirement of our oil and gas properties that can reasonably be estimated, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and gas asset. The asset retirement cost is determined at current costs and is inflated into future dollars using an inflation rate that is based on the consumer price index. The future projected cash flows are then discounted to their 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 and included in our DD&A 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 qualitatively assessed annually in the fourth quarter. If, based on our qualitative procedures, it is more likely than not that the fair value of the reporting unit is less than its carrying amount, we perform the two-step goodwill impairment test. The two-step goodwill impairment test is also performed whenever events or changes in circumstances indicate that the carrying value may not be recoverable. No goodwill impairment was indicated at December 31, 2012. However, it is possible that goodwill could become impaired in the future if commodity prices or other economic factors become less favorable.
When we dispose of a reporting unit or a portion of a reporting unit that constitutes a business, we include goodwill associated with that business in the carrying amount of the business in order to determine the gain or loss on disposal. The amount of goodwill allocated to the carrying amount of a business can significantly impact the amount of gain or loss recognized on the sale of that business. The amount of goodwill to be included in that carrying amount is based on the relative fair value of the business to be disposed of and the portion of the reporting unit that will be retained. See Note 9. Goodwill.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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 accumulated 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.
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 arrangement with netting clauses.
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.
See Note 10. Derivative Instruments and Hedging Activities.
Stock-Based Compensation Stock options and other stock-based compensation issued to employees and directors are recorded at grant-date fair value. Expense is recognized on a straight-line basis over the employee’s and director’s requisite service period (generally the vesting period of the award) in the consolidated statements of operations. See Note 14. Stock-Based and Other Compensation Plans.
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, 2012 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. Stock-Based and Other Compensation Plans.
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 return 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.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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 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.
Basic and Diluted Earnings Per Share Basic earnings per share (EPS) of our common stock is 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 16. 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 20. Commitments and Contingencies.
We self-insure the medical and dental coverage provided to certain employees, and the deductibles for workers’ compensation, automobile liability and 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 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 17. Segment Information.
Changes in Shareholders’ Equity On April 24, 2012, our shareholders voted to approve an amendment to the Company’s Certificate of Incorporation to (i) increase the number of authorized shares of our common stock from 250 million to 500 million shares and (ii) reduce the par value of the Company’s common stock from $3.33 1/3 per share to $0.01 per share. See the Consolidated Statements of Shareholders' Equity.
Recently Issued Accounting Standards In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2011-04: Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in US GAAP and IFRSs (ASU 2011-04). ASU 2011-04 clarifies application of fair value measurement and disclosure requirements and is effective for annual and interim periods beginning after December 15, 2011. As of March 31, 2012, we have adopted the provisions of ASU 2011-04, which did not impact our consolidated financial statements. The only impact was to our fair value disclosures. See Note 15. Fair Value Measurements and Disclosures.
In December 2011, the FASB issued Accounting Standards Update No. 2011-11 Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities (ASU 2011-11). ASU 2011-11 requires that an entity disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. ASU 2011-11 is effective for annual periods beginning on or after January 1, 2013. We are currently evaluating the provisions of ASU 2011-11 and assessing the impact, if any, it may have on our financial position and results of operations.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 2. Additional Financial Statement Information
Additional statements of operations information is as follows:
(1)
Other revenues consist primarily of electricity sales from the Machala power plant, located in Machala, Ecuador, through May 2011. Electricity generation expense includes all operating and non-operating expenses associated with the plant, including depreciation and changes in the allowance for doubtful accounts. In May 2011, we transferred our assets in Ecuador to the Ecuadorian government.
(2)
Amounts relate to rig stand-by expense incurred due to the deepwater Gulf of Mexico drilling moratorium.
(3)
Amounts represent increases in the fair value of shares of our common stock held in a rabbi trust.
(4)
Interest income for 2010 includes $3 million 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:
(1)
Increase from December 31, 2011 is due to reclassification of deferred income tax assets from long-term to short-term as certain foreign entities are estimated to begin utilizing net operating loss carryforwards in 2013.
(2)
Amounts represent the costs incurred to date of the Leviathan-2 appraisal well and expected well abandonment costs in excess of the insurance deductible less insurance proceeds received to date. See Note 11. Asset Retirement Obligations.
(3)
Assets held for sale consist primarily of North Sea oil and gas properties, and liabilities associated with assets held for sale consists primarily of asset retirement obligations. See Note 3. Acquisitions and Divestitures.
(4)
See Note 3. Acquisitions and Divestitures and Note 12. Long-Term Debt.
(5)
Amount includes liabilities accrued under our defined benefit pension plan, restoration plan, and other postretirement benefit plans. See Note 14. Stock-Based and Other Compensation Plans.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Supplemental statements of cash flow information is as follows:
(1)
See Note 3. Acquisitions and Divestitures and Note 12. Long-Term Debt.
Note 3. Acquisitions and Divestitures
Sale of North Sea Properties On August 13, 2012, we closed the sale of our 30% non-operated working interest in the Dumbarton and Lochranza fields, located in the UK sector of the North Sea. Proceeds from the transaction were $117 million and included final closing adjustments from the effective date of January 1, 2012. The net book value of assets sold was $255 million. Asset retirement obligations associated with the sale were $55 million. We reversed a deferred tax liability and recognized a corresponding income tax benefit of $99 million related to the sale.
We continue to market our remaining North Sea properties. As of December 31, 2012, all the properties remaining in our North Sea geographical segment are included in assets held for sale in our consolidated balance sheet. Our consolidated statements of operations have been reclassified for all periods presented to reflect the operations of our North Sea geographical segment as discontinued.
Included in income before income taxes during 2012, below, is exploratory expense of $27 million related to our Selkirk field. During the fourth quarter of 2012, the nearby Bligh well, a potential co-development candidate for Selkirk, was drilled. Bligh encountered hydrocarbons but disappointingly tight non-commercial reservoirs. Therefore, we determined that Selkirk was uneconomic for joint development.
Upon reclassification as held for sale, depreciation, depletion, and amortization (DD&A) ceased for the North Sea segment. Our long-term debt is recorded at the consolidated level; therefore no interest expense has been allocated to discontinued operations.
Summarized results of discontinued operations are as follows:
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Sale of Onshore US Properties During the third quarter of 2012, we closed the sales of certain crude oil and natural gas properties in Kansas, western Oklahoma, western Texas, and the Texas Panhandle with an effective date of April 1, 2012. Additionally, in June 2012, we closed the sale of non-core assets located in Wyoming. The information regarding the assets sold is as follows:
We continue to market certain non-core onshore US properties. However, none of these assets met the criteria for reclassification as an asset held-for-sale at December 31, 2012.
Marcellus Shale Joint Venture On September 30, 2011, we closed an agreement with a subsidiary of CONSOL Energy Inc. (CONSOL) for the development of Marcellus Shale properties in southwest Pennsylvania and northwest West Virginia. Under the agreement, we acquired a 50% interest in approximately 628,000 net undeveloped acres, certain producing properties, and existing infrastructure, such as pipeline and gathering facilities, for approximately $1.3 billion, including post-closing adjustments. We and CONSOL also formed CONE Gathering LLC (CONE) to own and operate the existing and future infrastructure. We have paid a total of $938 million as of December 31, 2012, and the remainder is due September 30, 2013. See Note 12. Long-Term Debt.
As part of the joint venture transaction, we agreed to fund one-third of CONSOL’s 50% working interest share of future drilling and completion costs, capped at $400 million each year, up to approximately $2.1 billion (CONSOL Carried Cost Obligation), which is expected to be paid out over a multi-year period. The CONSOL Carried Cost Obligation is suspended if average Henry Hub natural gas prices fall and remain below $4.00 per MMBtu in any three consecutive month period and will remain suspended until average Henry Hub natural gas prices are above $4.00 per MMBtu for three consecutive months. The CONSOL Carried Cost Obligation is currently suspended due to low natural gas prices.
As a result of the transaction, we recorded the following:
(1)
Total reflects impact of $17 million imputed interest on CONSOL installment payments.
We used an income approach to estimate the fair value of the proved oil and gas properties as of the acquisition date. 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 reserves prepared by our qualified petroleum engineers;
•
management’s estimates of future commodity prices based on NYMEX Henry Hub natural gas futures prices and adjusted for estimated location and quality differentials;
•
estimated future production rates based on our experience with similar properties which we operate; and
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Notes to Consolidated Financial Statements
•
estimated timing and amounts of future operating and development costs based on our experience with similar properties which we operate.
We discounted the resulting future net cash flows using a market-based weighted average cost of capital rate determined appropriate at the acquisition date. The fair value of the proved producing properties is considered a Level 3 fair value measurement.
Exit from Ecuador On November 25, 2010, 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 aimed to change current production-sharing arrangements into service contracts and provided for renegotiation of certain contracts.
In May 2011, we transferred our assets in Ecuador to the Ecuadorian government. We received cash proceeds of $73 million for the transfer of our offshore Amistad field assets, onshore gas processing facilities and Block 3 PSC and the assignment of the Machala Power electricity concession and its associated assets. Our net book value for the assets had been reduced due to previous impairment charges, resulting in a pre-tax gain of $25 million. We did not consider the property disposition material for discontinued operations presentation.
DJ Basin Asset Acquisition In March 2010, we acquired substantially all of the US Rocky Mountain assets of Petro-Canada Resources (USA) Inc. and Suncor Energy (Natural Gas) America Inc. for $498 million. The acquisition included properties located in the DJ Basin, one of our core operating areas. The total purchase price was allocated to the proved and unproved properties acquired based on fair values at the acquisition date.
The total purchase price and allocation of the total purchase price are as follows:
Sale of Onshore US Assets In August 2010, we sold 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
Note 4. Asset Impairments
Pre-tax (non-cash) asset impairment charges were as follows:
2012 Asset Impairments Due to recent declines in realized natural gas prices associated with our Piceance development, onshore US, and recent declines in near-term crude oil prices associated with our South Raton development in the deepwater Gulf of Mexico, we determined that their carrying amounts were not recoverable from future cash flows and, therefore, were impaired. In addition, due to end-of-field life declines in production of our Mari-B, Noa and Pinnacles fields, offshore Israel, we determined that the carrying amount was not recoverable from future cash flows and, therefore, was impaired. The 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 or contract prices as of the date of the estimate, operating and development costs, and discount rates.
2011 Asset Impairments Due to a significant decline in spot and five-year forward natural gas prices, specifically during the fourth quarter of 2011, as well as field performance, we determined that the carrying amounts of certain of our onshore US developments were not recoverable from future cash flows and, therefore, were impaired. The assets were written down to their estimated fair values, which were determined using discounted cash flow models, as described above.
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. At December 31, 2010, we believed that it was less likely that Noa would 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. During 2011, due to unexpected natural gas supply disruptions into Israel, we decided to develop Noa/Noa South. 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, as described above. The New Albany shale assets were written down to anticipated sales proceeds less costs to sell.
See also Note 15. Fair Value Measurements and Disclosures.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 5. Allowance for Doubtful Accounts
Changes in the allowance for doubtful accounts were as follows:
(1)
During 2011, recovery of approximately $19 million for outstanding receivables was included in the final terms of our agreement to transfer our assets and the associated electricity concession and PSC to the Ecuadorian government. See Note 3. Acquisitions and Divestitures.
Note 6. Inventories
Inventories consisted of the following:
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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 as dry hole cost.
Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed in the same period:
(1)
Amount primarily represents Deep Blue (deepwater Gulf of Mexico) exploratory well costs capitalized prior to December 31, 2012. Although hydrocarbons were found in both the initial exploration well and subsequent sidetrack, we and our partners decided not to proceed with additional appraisal activities.
(2)
Amount relates to Selkirk (North Sea) exploratory well costs capitalized prior to December 31, 2012. During the fourth quarter of 2012, our Selkirk field, which is included in discontinued operations, was determined to be uneconomic for joint development and was charged to exploration expense. See Note 3. Acquisitions and Divestitures.
The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced, and the number of projects that have been capitalized for a period greater than one year:
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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 commencement of drilling as of December 31, 2012:
Carla/Carmen/Diega Carla is a 2011 crude oil discovery on both Block O and I, Carmen is a 2009 crude oil discovery on Block O, and Diega is a 2008 condensate and oil discovery on Block I. We continue our appraisal program for Carla and Diega and have encountered hydrocarbons in multiple appraisal wells and side-tracks. We are currently evaluating regional development scenarios for these three discoveries, which includes possible sanctioning of Carla during 2013.
Felicita/Yolanda Felicita is a 2008 condensate and natural gas discovery on Block O. Yolanda is a 2008 condensate and natural gas discovery on Block I. We are currently evaluating regional natural gas development options for these discoveries.
YoYo YoYo is a 2007 natural gas and condensate discovery. During 2011 we acquired and processed additional 3-D seismic information and are continuing evaluations for future drilling potential. We are also working with the government of Cameroon to assess gas commercialization options.
Leviathan Leviathan is a 2010 natural gas discovery. During 2012, we continued to evaluate the discovery with the successful drilling of the Leviathan-3 appraisal well and spud the Leviathan-4 appraisal well. We have project and commercial teams in place and are in the process of screening multiple development concepts. Due to Leviathan's size, full field development, and realization of maximum economic value will require several development phases. Each of these development options would require a multi-billion dollar investment and require a number of years to complete. Engineering design and planning work are currently underway for a potential first phase of development. In addition, we announced that the partners in the Leviathan Project had agreed in principle on a proposal to sell a 30% working interest in the Leviathan licenses to Woodside Energy Ltd. (Woodside). Woodside is Australia’s largest producer of LNG with over 25 years of experience and has strong working relationships with many potential customers in the Asian LNG markets.
Leviathan-1 Deep In January 2012, we returned to the Leviathan-1 well and began drilling toward two deeper intervals in order to evaluate them for the existence of crude oil (Leviathan-1 Deep). In May 2012, due to high well pressure and the
Noble Energy, Inc.
Notes to Consolidated Financial Statements
mechanical limits of the wellbore design, we suspended drilling operations. Although the well did not reach the planned objective, we are encouraged by the possibility of an active thermogenic (crude oil generating) hydrocarbon system at greater depths within the basin. We are continuing our evaluation of Leviathan-1 Deep and will integrate the data from the Leviathan-1 Deep well into our model to update our analysis and design a drilling plan specifically to test the deep oil concept. We have secured a rig with the capabilities necessary to reach the target objective and plan to begin drilling an exploratory well in fourth quarter of 2013.
Tanin 1 Tanin 1 is a 2011 natural gas discovery located in the Alon A block, offshore Israel. We and our partners are currently reviewing alternatives for the development of reserves from this asset.
Dolphin 1 Dolphin 1 is a 2011 natural gas discovery located in the Hanna license, southwest of the Tamar gas field. We and our partners are currently reviewing alternatives for the development of reserves from this asset.
Dalit Dalit is a 2009 natural gas discovery. We and our partners are working on a development plan which would include tie-in to the Tamar platform and have submitted a development plan to the Israeli government.
Cyprus During the fourth quarter of 2011, we drilled a successful natural gas exploration well (A-1) in Block 12. We submitted an appraisal plan to the Cyprus government during July 2012 and are reviewing locations for appraisal drilling activities.
Gunflint Gunflint (Mississippi Canyon Block 948) is a 2008 crude oil discovery. In July 2012, we drilled a successful Gunflint appraisal well. We plan to drill a second appraisal well targeting the south area of the reservoir during first quarter of 2013. Front-end conceptual studies have been completed, and we are working toward sanctioning of a scalable development project in 2013. We are currently targeting 2017 for production start-up utilizing a standalone facility. If we choose to connect to an existing third-party host, the project could have an accelerated completion schedule.
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;
•
28% interest in Alba Plant LLC (Alba Plant), which owns and operates a liquefied petroleum gas processing plant in Equatorial Guinea; and
•
50% interest in CONE Gathering LLC (CONE), which owns and operates natural gas gathering facilities servicing our joint venture properties in the Marcellus Shale.
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 investees and is not included in our income tax provision in our consolidated statements of operations. At December 31, 2012, our retained earnings included $111 million related to the undistributed earnings of equity method investees.
The carrying value of our AMPCO investment was $10 million higher than the underlying net assets of the investee at December 31, 2012. The difference is related to capitalized interest which is being amortized into earnings over the remaining useful life of the plant.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Equity method investments are as follows:
Summarized, 100% combined financial information for equity method investees is as follows:
Note 9. Goodwill
Changes in the carrying amount of goodwill were as follows:
(1) See Note 3. Acquisitions and Divestitures.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 10. Derivative Instruments and Hedging Activities
Objective and Strategies for Using Derivative Instruments In order to mitigate the effect of commodity price volatility 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 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 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 may enter into forward contracts to hedge anticipated exposure to interest rate risk associated with public debt financing.
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 15. 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 major banks or market participants, and we monitor and manage 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.
We monitor the creditworthiness of our commodity derivatives 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.
Interest Rate Derivative Instrument In January 2010, we entered into an interest rate forward starting swap to effectively fix the cash flows related to interest payments on our anticipated March 2011 debt issuance. During first quarter 2011, the net liability position on the swap was reduced in our mark to market calculation, and we recognized a corresponding gain of $23 million, net of tax, in AOCL. On February 15, 2011 we settled the interest rate swap, which had a net liability position of $40 million at the time of settlement. Approximately $26 million, net of tax, was recorded in accumulated other comprehensive loss (AOCL) and is being reclassified to interest expense over the term of the notes. The ineffective portion of the interest rate swap was de minimis.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Unsettled Derivative Instruments As of December 31, 2012, we had entered into the following crude oil derivative instruments:
As of December 31, 2012, we had entered into the following natural gas derivative instruments:
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:
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. All net derivative gains and losses that were deferred in AOCL as a result of previous cash flow hedge accounting, had been reclassified to earnings by December 31, 2010.
AOCL at December 31, 2012 included deferred losses of $25 million, net of tax, related to interest rate derivative instruments. This amount will be reclassified to earnings as an adjustment to interest expense over the terms of our senior notes due April 2014 and March 2041. Approximately $2 million of deferred losses (net of tax) will be reclassified to earnings during the next 12 months and will be recorded as an increase in interest expense.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 11. Asset Retirement Obligations
Asset retirement obligations (ARO) consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. Changes in asset retirement obligations were as follows:
For the year ended December 31, 2012, liabilities incurred include $6 million for onshore US development, $8 million for deepwater Gulf of Mexico, and $30 million for offshore Israel. Liabilities settled in 2012 include $20 million related to non-core onshore US assets sold, $55 million related to North Sea assets sold, and $34 million related to the Leviathan-2 appraisal well, offshore Israel. Revisions relate primarily to changes in estimated costs for future abandonment activities and include $54 million for onshore US, $6 million for deepwater Gulf of Mexico, $26 million for offshore Israel, and $16 million for offshore China. Other includes North Sea ARO liabilities transferred to liabilities associated with assets held for sale. See Note 2. Additional Financial Statement Information and Note 3. Acquisitions and Divestitures.
For the year ended December 31, 2011, liabilities incurred were primarily due to the Marcellus Shale asset acquisition as well as additions for the Alen project in Equatorial Guinea and Lochranza project in the North Sea. Liabilities settled in 2011 related primarily to deepwater Gulf of Mexico and Gulf of Mexico shelf properties. Revisions in 2011 resulted from changes in estimated abandonment costs mainly in the DJ Basin and deepwater Gulf of Mexico.
Accretion expense is included in DD&A expense in the consolidated statements of operations.
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Note 12. Long-Term Debt
Our debt consists of the following:
(1)
Our Credit Agreement provides for a $4.0 billion unsecured revolving Credit Facility. The Credit Facility is available for general corporate purposes.
(2)
Imputed rate based on the prevailing market rates for similar debt instruments at the date of assessment.
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 $35 million remain and are being amortized to expense over the life of the related debt issues and are included in current and long-term assets based on their related debt terms.
Credit Facility On September 28, 2012, we exercised our option to increase our bank revolving credit facility (the Credit Facility) to $4.0 billion. The credit facility was previously committed in the amount of $3.0 billion as of December 31, 2011. Debt issuance costs of approximately $4 million were incurred and are being amortized to expense over the remaining term of the Credit Facility which will mature on October 14, 2016.
The Credit Facility (i) provides for facility fee rates that range from 12.5 basis points to 30 basis points per year depending upon our credit rating, (ii) includes sub-facilities for short-term loans and letters of credit up to an aggregate amount of $500 million under each sub-facility and (iii) provides for interest rates that are based upon the Eurodollar rate plus a margin that ranges from 100 basis points to 145 basis points depending upon our credit rating.
The Credit Agreement requires that our total debt to capitalization ratio (as defined in the Credit Agreement), expressed as a percentage, not exceed 65% at any time. A violation of this covenant could result in a default under the Credit Agreement, which would permit the participating banks to restrict our ability to access the Credit Facility and require the immediate
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repayment of any outstanding advances under the Credit Facility. As of December 31, 2012, we were in compliance with our debt covenants.
The Credit Facility is available for general corporate purposes. Certain lenders that are a party to the Credit Agreement have in the past performed, and may in the future from time to time perform, investment banking, financial advisory, lending or commercial banking services for us for which they have received, and may in the future receive, customary compensation and reimbursement of expenses.
2011 Debt Offerings On February 18, 2011, we closed an offering of $850 million senior unsecured notes receiving net proceeds of $836 million, after deducting discount and underwriting fees. The notes are due March 1, 2041, and pay interest semi-annually at 6%. Total debt issuance costs of approximately $9 million were incurred and are being amortized to expense over the term of the notes. Approximately $470 million of the net proceeds were used to repay outstanding indebtedness under our revolving credit facility and the balance of the proceeds has been used for general corporate purposes.
On December 8, 2011, we closed an offering of $1.0 billion senior unsecured notes receiving net proceeds of $992 million, after deducting discount and underwriting fees. The notes are due December 15, 2021, and pay interest semi-annually at 4.15%. Total debt issuance costs of approximately $8 million were incurred and are being amortized to expense over the term of the notes. Approximately $400 million of the net proceeds were used to repay outstanding indebtedness under our revolving credit facility and the balance of the proceeds has been used for general corporate purposes.
CONSOL Installment Payments On September 30, 2011, we closed an agreement with CONSOL for the development of Marcellus Shale properties. In addition to the cash paid at closing, we agreed to make two installment payments of $328 million each, the first of which was paid on September 30, 2012. The second installment payment, which has been discounted at the prevailing market rates for similar debt instruments, is due on September 30, 2013 and has been reclassified to current liabilities as of December 31, 2012. See Note 3. Acquisitions and Divestitures and Note 15. Fair Value Measurements and Disclosures.
Aseng FPSO Lease Obligation We lease an FPSO used in the Aseng field, offshore Equatorial Guinea. The amount of the Aseng FPSO lease obligation is based on the discounted present value of future minimum lease payments, and therefore does not reflect future minimum lease payments. Amounts due within one year equal the amount by which the Aseng FPSO lease obligation is expected to be reduced during the next 12 months. See Note 20. Commitments and Contingencies for future Aseng FPSO lease payments.
Annual Debt Maturities Annual maturities of outstanding debt, excluding Aseng FPSO lease payments, are as follows:
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Notes to Consolidated Financial Statements
Note 13. Income Taxes
Components of income (loss) from continuing operations before income taxes are as follows:
The income tax provision (benefit) from continuing operations consists of the following:
A reconciliation of the federal statutory tax rate to the effective tax rate is as follows:
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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, 2012. 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.
The valuation allowance on the deferred tax assets associated with foreign loss carryforwards totaled $81 million in 2012, $65 million in 2011, and $70 million in 2010. The changes to the valuation allowance for the loss carryforwards between periods was attributable to changes in losses on projects in new venture activities which are not yet commercial.
During 2012, as a result of execution of tax planning strategies, we reversed a $57 million deferred tax asset for future foreign tax credits from our foreign branch operations along with the corresponding valuation allowance. Additionally, we recorded a $38 million valuation allowance on excess foreign tax credits and released $12 million of deferred tax liability for a net increase in deferred income tax expense.
During 2011, we recorded a $57 million increase in the valuation allowance against our deferred tax asset for foreign tax credits. This deferred tax asset was fully offset by a valuation allowance because, based on our forecast of foreign tax credits, we did not believe it was more likely than not that the asset would be realized.
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During 2010, we reversed a $28 million valuation allowance that had been established 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 corresponding reduction in income tax expense.
Effective Tax Rate Our effective tax rate increased in 2012 as compared with 2011, primarily due to reduced impact of equity method earnings, which had the effect of decreasing the 2011 rate. The rate also increased due to additional valuation allowances and nondeductible allocation of goodwill to assets sold in 2012.
Our effective tax rate decreased in 2011 as compared with 2010. This decrease was due to the impact of higher equity method earnings in 2011 which had the effect of decreasing the 2011 rate. The decrease was partially offset by the change in the Israeli tax law discussed below. Additionally, in 2010, we reversed a $28 million valuation allowance, as discussed above, which reduced income tax expense. Finally, the rate for 2010 was increased by a nondeductible allocation of goodwill to assets sold.
Changes in Israeli Tax Law In March 2011, the Israeli government enacted the Petroleum Profits Taxation Law, 2011, which imposes additional income tax on oil and gas production. The Israeli government also repealed the percentage depletion deduction and made certain changes to the rules for deducting tangible and intangible development costs. These changes increased our 2011 consolidated effective income tax rate by approximately 4%. There was no remeasurement of our deferred tax assets or liabilities as of December 31, 2010.
Accumulated Undistributed Earnings of Foreign Subsidiaries As of December 31, 2012, the accumulated undistributed earnings of the foreign subsidiaries that have been permanently reinvested were approximately $2.6 billion. No US taxes have been recorded on these earnings. 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 $685 million.
Unrecognized Tax Benefits We file a consolidated income tax return in the US federal jurisdiction, and we file income tax returns in various states and foreign jurisdictions. Our income tax returns are routinely audited by the applicable revenue authorities, and provisions are routinely made in the financial statements for differences between positions taken in tax returns and amounts recognized in the financial statements in anticipation of the results of these audits.
In our major tax jurisdictions, the earliest years remaining open to examination are: U.S. - 2009, Equatorial Guinea - 2007, Israel - 2008, and China - 2006.
Our policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense. However, we did not accrue penalties at December 31, 2012 or 2011, because we believe that we are below the minimum statutory threshold for imposition of penalties.
A reconciliation of our beginning and ending amounts of unrecognized tax benefits follows:
As of December 31, 2012, approximately $23 million of unrecognized tax benefits would impact our effective tax rate if recognized. The changes to our unrecognized tax benefits during the twelve months ended December 31, 2012 primarily
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Notes to Consolidated Financial Statements
resulted from changes in various foreign tax return filings and positions. The adjustments to our reserves for uncertain tax positions had a de minimis impact on our net income.
During the year ended December 31, 2012, we recognized and accrued a de minimis amount of interest and none in penalties.
We expect that our unrecognized tax benefits could continue to change due to the settlement of audits and the expiration of statutes of limitation in the next twelve months; however, we do not anticipate any such change to have a significant impact on our results of operations, financial position or cash flows in the next twelve months.
Note 14. Stock-Based and Other Compensation Plans
We recognized total stock-based compensation expense as follows:
Stock Option and Restricted Stock Plans Our stock option and restricted stock plans 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. On April 26, 2011, our stockholders approved the amendment and restatement of the 1992 Plan to increase the number of shares of our common stock authorized for issuance under the plan from 24 million to 31 million shares and to modify certain plan provisions. At December 31, 2012, 12,180,343 shares of our common stock were reserved for issuance, including 7,009,795 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. During the Restricted Period, unless specifically provided otherwise in accordance with the terms of the 1992 Plan, the recipient of Restricted Stock would be the record owner of the shares and have all the rights of a stockholder with respect to the shares, including the right to vote and the right to receive dividends or other distributions made or paid with respect to the shares. Restricted stock awards generally vest over three years. Shares of restricted stock time-vest 20% after year one, an additional 30% after year two and the remaining 50% after year three.
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, 2012, 696,178 shares of our common stock were reserved for issuance, including 476,873 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
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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 the current date and their expiration date.
•
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 years 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:
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Notes to Consolidated Financial Statements
The total intrinsic value of options exercised was $72 million in 2012, $40 million in 2011, and $68 million in 2010.
As of December 31, 2012, $36 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 1.4 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 $47 million in 2012, $57 million in 2011, and $43 million in 2010.
The weighted average award-date fair value of restricted stock awarded was $101.50 per share in 2012, $90.32 per share in 2011, and $75.07 per share in 2010.
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.
As of December 31, 2012, $45 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 1.4 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.
Other Compensation Plans
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 $17 million in 2012, $14 million in 2011, and $11 million in 2010.
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:
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
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Notes to Consolidated Financial Statements
value. See Note 15. 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, $33.44 per share) in the shareholders’ equity section of the consolidated balance sheets. Amounts payable to 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 700,000 shares, or 94%, of our common stock held in the plan at December 31, 2012 were attributable to a member of our Board of Directors. The shares are being distributed in equal installments over the next seven years. Distributions of 100,000 shares were made in each of 2012 and 2011. In addition, plan participants sold 2,268 shares of our common stock in 2012, 100 shares in 2011, and 100 shares in 2010. Proceeds were invested in mutual funds and/or distributed to plan participants. Distributions to plan participants were valued at $19 million in 2012, $17 million in 2011 and $17 million in 2010.
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 $6 million in 2012, $8 million in 2011 and $15 million in 2010.
We also maintain an unfunded deferred compensation plan for the benefit of certain of our employees. Deferred compensation liabilities of $70 million, $60 million and $51 million were outstanding at December 31, 2012, 2011 and 2010, respectively, under the unfunded plan.
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, and 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, which include medical and life insurance benefits, for the benefit of our employees and retirees.
At December 31, 2012, the benefit obligations for these plans totaled $370 million and the fair value of plan assets totaled $247 million, resulting in a net liability of $123 million recognized in our consolidated balance sheet, of which $116 million was a long-term liability. At December 31, 2011, the benefit obligations for these plans totaled $311 million and the fair value of plan assets totaled $219 million, resulting in a net liability of $92 million recognized in our consolidated balance sheet, of which $88 million was a long-term liability. See Note 2. Additional Financial Statement Information. Pension plan assets include diversified and high-quality federal money market funds, mutual funds and common collective trust funds. Net periodic benefit cost related to these plans totaled $27 million in 2012, $21 million in 2011, and $21 million in 2010. We plan to make contributions of $26 million in 2013.
Note 15. 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.
Deferred Compensation Liability The value is dependent upon the fair values of mutual fund investments and shares of our common stock held in a rabbi trust. See Mutual Fund Investments above.
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Notes to Consolidated Financial Statements
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 netting clauses within our master agreements that allow us to net cash settle asset and liability positions with the same counterparty.
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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. The following methods and assumptions were used to estimate the fair values:
Asset Impairments We determined that the carrying amounts of certain assets were not recoverable from future cash flows and, therefore, were impaired. The assets were reduced to their estimated fair values. Information about the impaired assets is 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 net book value at the date of assessment.
The fair values of the properties were determined as of the date of the assessment using discounted cash flow models. The discounted cash flows were based on management’s expectations for the future. Inputs included estimates of future oil and gas production, commodity prices based on sales contract terms or NYMEX commodity price curves as of the date of the estimate, estimated operating and development costs, and a risk-adjusted discount rate of 10%. See Note 4. Asset Impairments.
Additional Fair Value Disclosures
Debt The fair value of fixed-rate, public debt is estimated based on the published market prices for the same or similar issues. As such, we consider the fair value of our public fixed rate debt to be a Level 1 measurement on the fair value hierarchy. The carrying amounts of the CONSOL installment payments approximate fair value because they have been discounted at the prevailing market rates for similar debt instruments. As such, we consider the fair value of our CONSOL installment payments to be Level 2 measurements on the fair value hierarchy. See Note 12. Long-Term Debt. Fair value information regarding our debt is as follows:
(1)
Excludes Aseng FPSO lease obligation. No floating rate debt was outstanding at December 31, 2012 or December 31, 2011. See Note 12. Long-Term Debt.
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Note 16. Earnings Per Share
Basic earnings per share of common stock is computed using the weighted average number of shares of common stock outstanding during each period. The diluted earnings per share of common stock include the effect of outstanding stock options, shares of restricted stock, or shares of our common stock held in a rabbi trust (when dilutive). The following table summarizes the calculation of basic and diluted earnings per share:
Note 17. Segment Information
We have operations throughout the world and manage our operations by country. The following information is grouped into four 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, Cameroon, Sierra Leone, and Senegal/Guinea-Bissau); Eastern Mediterranean (Israel and Cyprus); and Other International and Corporate. Other International includes China, Ecuador (through May 2011), Falkland Islands, Nicaragua and new ventures. As of December 31, 2012, our remaining North Sea assets were reclassified to assets held for sale, and prior year amounts have been reclassified to exclude the North Sea geographical segment. See Note 3. Acquisitions and Divestitures.
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(1) Revenues from third parties for all foreign countries, in total, were $1.7 billion in 2012, $1.1 billion in 2011, and $722 million in 2010.
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(2) Long-lived assets located in all foreign countries, in total, were $4.2 billion, $3.2 billion, and $2.0 billion at December 31, 2012, 2011, and 2010 respectively.
(3) Revenues for the year ended December 31, 2010 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. All hedge gains and losses had been reclassified to revenues by December 31, 2010.
Note 18. Concentration of Risk
Concentration of Market Risk The largest single non-affiliated purchasers of our production were as follows:
(1) Includes sales to both Shell Trading (US) Company and Shell International Trading and Shipping Limited.
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. A significant portion 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 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 Alen, offshore Equatorial Guinea, and Tamar and Leviathan, 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.
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Note 19. Additional Shareholders’ Equity Information
Activity in shares of our common stock and treasury stock was as follows:
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, using an effective income tax rate of 35%.
Note 20. 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.
CONSOL Carried Cost Obligation Based on the December 31, 2012 Henry Hub natural gas price strip, we forecast our CONSOL Carried Cost Obligation will be suspended throughout the 2013 fiscal year. Therefore, specific payment dates for funding cannot be determined at this time and are excluded from the minimum commitments table below. See Note 3. Acquisitions and Divestitures.
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 $37 million in 2012, $31 million in 2011, and $27 million in 2010.
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Notes to Consolidated Financial Statements
Minimum commitments as of December 31, 2012 consist of the following:
(1)
Annual lease payments, net to our interest, exclude regular maintenance and operational costs. See Note 12. Long-Term Debt.
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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 reserves engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of any reserves 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.
Economic producibility of reserves is dependent on the crude oil and natural gas prices used in the reserves estimate. We based our December 31, 2012, 2011, and 2010 reserves estimates on 12-month average commodity prices, unless contractual arrangements designate the price to be used, in accordance with SEC rules. However, commodity prices are volatile. Declines in crude oil or natural gas prices could result in negative reserves revisions.
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.
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, 2012. See Items 1. and 2. Business and Properties - Proved Reserves Disclosures.
Geographic Areas Our supplemental disclosures are grouped by geographic area, which include the United States, Equatorial Guinea, Israel and Other International. Other International includes Cameroon, China, Cyprus, Ecuador (through November 24, 2010), Falkland Islands, North Sea, Nicaragua, Sierra Leone, Senegal/Guinea-Bissau and other new ventures. The North Sea geographical segment is classified as discontinued operations in our consolidated financial statements.
Operations in China, Cyprus, Equatorial Guinea, and Sierra Leone are conducted in accordance with the terms of PSCs. In Cameroon, we operate in accordance with the terms of a PSC and a mining concession. Operations in Nicaragua, the Falkland Islands, the North Sea, Israel, and 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.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
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. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
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)United States NGL proved reserves totaled:
(2)
Other International includes China and the North Sea.
(3)
The 2010 US revisions include the impacts of higher prices and additional NGLs recorded 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.
The 2011 US revisions were primarily associated with reclassification of vertical PUDs to probable reserves in Wattenberg which are no longer expected to be developed in five years due to shifting emphasis from vertical to horizontal development, partially offset by positive revisions in other onshore US fields. International revisions are associated with performance revisions in China and the North Sea.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
The 2012 US revisions are primarily attributable to our decision to terminate the legacy vertical drilling program in Wattenberg and focus on the horizontal development of the Niobrara formation. Equatorial Guinea revisions are associated with performance revisions for the Aseng field. See Items 1. and 2. Business and Properties - Proved Undeveloped Reserves (PUDs).
(4)
The 2010 increase in US proved reserves relates to continuing development of onshore assets, primarily in the DJ Basin. The 2010 increase in Equatorial Guinea reserves includes 26 MMBbl for the Alen field.
The 2011 increase is from development of onshore assets, primarily in the DJ Basin.
The 2012 increase in US reserves included an increase of 98 MMBbls in the DJ Basin and 8 MMBbls from Marcellus Shale development. International increases were due primarily to additional development in China. See Items 1. and 2. Business and Properties - Proved Undeveloped Reserves (PUDs).
(5)
The 2010 increase relates to the DJ Basin asset acquisition. See Note 3. Acquisitions and Divestitures.
(6)
In 2010, we sold non-core, onshore US assets in the Mid-Continent and Illinois Basin.
In 2012 we sold non-core, onshore US and North Sea assets. See Note 3. Acquisitions and Divestitures.
(7)
Equatorial Guinea production includes sales from the Alba field to the Alba LPG plant of 3 MMBbl in 2012, 2011 and 2010.
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 China, Ecuador (at December 31, 2009), and the North Sea. See Note 3. Acquisitions and Divestitures and Note 4. Asset Impairments.
(2)
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 recorded 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 revision in 2010 is primarily due to additional production allowances related to LNG sales. Israel’s revisions in 2010 reflected a change in the likelihood that the Noa field would be developed.
The 2011 US revisions were primarily associated with reclassification of vertical PUDs in Wattenberg which are no longer expected to be developed in five years due to shifting activity level from vertical to horizontal development and revisions to onshore dry gas assets due to reduced activity assumptions, performance, and price. International revisions are associated with performance revisions in the North Sea.
The 2012 US revisions are primarily attributable to our decision to terminate the legacy vertical drilling program in Wattenberg and focus on the horizontal development of the Niobrara formation and negative price revisions due to lower natural gas prices, partially offset by improved well performance in the Marcellus Shale. International revisions are due to performance revisions in the Mari B field. See Items 1. and 2. Business and Properties - Proved Undeveloped Reserves (PUDs).
(3)
The 2010 increase in US proved reserves is due to continuing development of onshore assets, primarily in the DJ Basin, Piceance Basin, and East Texas. The 2010 increase in Israel is due to the recording of initial reserves at the Tamar development.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
The 2011 increase in the US is primarily due to active development programs in the DJ Basin and the Marcellus Shale. The increase in Israel was primarily due to continuing appraisal at Tamar and includes reserves for Noa which we decided to develop (See Items 1. and 2. Business and Properties - Eastern Mediterranean).
The 2012 increase in US reserves includes 305 Bcf in the DJ Basin and 291 Bcf in the Marcellus Shale. The Equatorial Guinea increase is due to additions at Aseng, and the Israel increase is due to additional appraisal activity at Tamar. See Items 1. and 2. Business and Properties - Proved Undeveloped Reserves (PUDs).
(4)
The increases relate to our DJ Basin asset acquisition in 2010 and our Marcellus Shale asset acquisition in 2011. See Note 3. Acquisitions and Divestitures.
(5)
In 2010, we sold non-core, onshore US assets in the Mid-Continent and Illinois Basin. Other International sales in 2010 include 160 Bcf due to the termination of the Block 3 PSC by the Ecuadorian government.
In 2012, we sold non-core, onshore US and North Sea assets. See Note 3. Acquisitions and Divestitures.
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, Senegal/Guinea-Bissau, Nicaragua, Falkland Islands, Sierra Leone and other new ventures. See Note 3. Acquisitions and Divestitures.
(2)
Production costs consist of lease operating expense, production and ad valorem taxes, transportation expense, and general and administrative expense supporting oil and gas operations.
(3)
During 2012, we incurred exploration expense in currently non-commercial international locations; therefore, no tax benefit was included in income tax expense associated with Other International as we cannot conclude it is more likely than not that some portion or all of the deferred tax assets will be realized.
(4)
Results of operations exclude the mark-to-market gain or loss on certain commodity derivative instruments not designated as cash flow hedges, corporate overhead and interest costs. See Note 10. Derivative Instruments and Hedging Activities.
(5)
Includes impact resulting from applying cash flow hedge accounting for related commodity derivative instruments. 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 Cameroon, China, Cyprus, Ecuador (through November 24, 2010), Falkland Islands, the North Sea, Senegal/Guinea-Bissau, Nicaragua, Sierra Leone and other new ventures. See Note 3. Acquisitions and Divestitures.
(3)
Proved property acquisition costs include $386 million related to the Marcellus Shale asset acquisition in 2011 and $352 million related to the DJ Basin asset acquisition in 2010.
(4)
2012 unproved property acquisition costs for the US include: $63 million related to expanding our position in the DJ Basin, $28 million for deepwater Gulf of Mexico lease blocks, and $27 million related to other onshore US, offset by a downward purchase price adjustments of $50 million related to our Marcellus Shale acquisition. 2012 unproved property acquisition costs for Other International include $25 million related to our position in Falkland Islands
2011 unproved property acquisition costs include: $853 million related to the Marcellus Shale asset acquisition, $40 million related to our position offshore Senegal/Guinea-Bissau (the AGC Profond block), $31 million related to additional acreage in the DJ Basin and $58 million related to other onshore US.
2010 unproved property acquisition costs include: $146 million related to the 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.
(5)
2012 exploration costs include drilling and completion of $102 million in Israel, $71 million in Falkland Islands, $40 million in Equatorial Guinea, $36 million in the DJ Basin, and $13 million in Cyprus.
2011 exploration costs include drilling and completion costs of $74 million in deepwater Gulf of Mexico, $146 million in Israel, $54 million in Equatorial Guinea, $59 million in Cyprus, $36 million in Senegal/Guinea-Bissau and $42 million in the DJ Basin.
2010 exploration costs include drilling and completion costs of $62 million in deepwater Gulf of Mexico and $41 million in Israel.
(6)
Worldwide development costs include amounts spent to develop PUDs of approximately $1.8 billion in 2012, $1.4 billion in 2011 and $1.1 billion in 2010.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
US development costs include increases in asset retirement obligations of $73 million in 2012, $115 million in 2011, and $15 million in 2010. Other international development costs include increases in asset retirement obligations of $72 million in 2012, $13 million in 2011, and $2 million in 2010.
Equatorial Guinea development costs include non-cash accruals related to estimated construction progress to date on an FSPO used in the development of the Aseng field of $66 million in 2011 and $266 million in 2010. These capitalized costs were included in development costs as the Aseng FPSO was constructed.
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 $740 million, of which $734 million is related to Marcellus Shale, at December 31, 2012, and $874 million, of which $792 million is related to Marcellus Shale, at December 31, 2011, remaining from the allocation of costs to unproved properties acquired in previous acquisitions.
(2)
Proved oil and gas properties include asset retirement costs of $334 million and $310 million at December 31, 2012 and 2011, respectively.
(3)
Includes $200 million of proved oil and gas properties and $160 million of accumulated DD&A related to the North Sea classified as assets held for sale at December 31, 2012. See Note 3. Acquisitions and Divestitures.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
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 China and the North Sea. 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 China and the North Sea. See Note 3. Acquisitions and Divestitures.
We estimate that a $1.00 per Bbl change in the average price of crude oil from the 12-month average price for 2012 would change the discounted future net cash flows before income taxes by approximately $216 million. We estimate that a $0.10 per Mcf change in the average price of natural gas from the 12-month average price for 2012 would change the discounted future net cash flows before income taxes by approximately $229 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 $1.8 billion in 2013, $1.5 billion in 2014 and $1.1 billion in 2015.
Future income tax expense is computed by applying the appropriate year-end statutory tax rates to the estimated future pre-tax 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 2012 included the following:
•
$96 million loss on commodity derivative instruments, including unrealized mark-to-market loss of $73 million (See Note 10. Derivative Instruments and Hedging Activities).
Second quarter 2012 included the following:
•
$73 million asset impairment charges (See Note 4. Asset Impairments);
•
$276 million gain on commodity derivative instruments, including unrealized mark-to-market gain of $277 million (See Note 10. Derivative Instruments and Hedging Activities); and
•
$9 million pre-tax gain on sale of non-core onshore US assets (See Note 3. Acquisitions and Divestitures).
Third quarter 2012 included the following:
•
$135 million loss on commodity derivative instruments, including unrealized mark-to-market loss of $131 million (See Note 10. Derivative Instruments and Hedging Activities); and
•
$157 million pre-tax gain on sale of non-core onshore US assets (See Note 3. Acquisitions and Divestitures).
Fourth quarter 2012 included the following:
•
$31 million impairment charges (See Note 4. Asset Impairments);
•
$13 million pre-tax loss on sale of non-core onshore US asset, due to post closing adjustments (See Note 3. Acquisitions and Divestitures); and
•
$30 million gain on commodity derivative instruments, including unrealized mark-to-market gain of $36 million (See Note 10. Derivative Instruments and Hedging Activities).
(2)
First quarter 2011 included the following:
•
$8 million impairment charges (See Note 4. Asset Impairments); and
•
$286 million loss on commodity derivative instruments, including unrealized mark-to-market loss of $303 million (See Note 10. Derivative Instruments and Hedging Activities).
Second quarter 2011 included the following:
•
$131 million impairment charges (See Note 4. Asset Impairments);
•
$143 million gain on commodity derivative instruments, including unrealized mark-to-market gain of $142 million (See Note 10. Derivative Instruments and Hedging Activities); and
•
$25 million pre-tax gain on divestitures due to the completed transfer of assets and exit from Ecuador (See Note 3. Acquisitions and Divestitures).
Third quarter 2011 included the following:
•
$322 million gain on commodity derivative instruments, including unrealized mark-to-market gain of $300 million (See Note 10. Derivative Instruments and Hedging Activities).
Fourth quarter 2011 included the following:
•
$620 million asset impairment charges (See Note 4. Asset Impairments); and
•
$137 million loss on commodity derivative instruments, including unrealized mark-to-market gain of $44 million (See Note 10. Derivative Instruments and Hedging Activities).
(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)
Consistent with GAAP, when dilutive, deferred compensation gains or losses, net of tax, are excluded from net income while the Noble Energy shares held in the rabbi trust are included in the diluted share count. For this reason, the diluted earnings per share calculations for the three months ended June 30, 2012 excludes a deferred compensation gain of $7 million, net of tax, and for the three months ended June 30 and September 30, 2011 exclude deferred compensation gains of $4 million and $12 million, respectively, net of tax.

ITEM 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.

ITEM 9A - CONTROLS AND PROCEDURES
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 US GAAP.
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, 2012. 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 - OTHER INFORMATION
Item 9B. Other Information
None.
PART III

ITEM 10 - DIRECTORS AND EXECUTIVE OFFICERS
Item 10. Directors, Executive Officers and Corporate Governance
The information required by this item is incorporated herein by reference to the 2013 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2012.

ITEM 11 - EXECUTIVE COMPENSATION
Item 11. Executive Compensation
The information required by this item is incorporated herein by reference to the 2013 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2012.

ITEM 12 - SECURITY OWNERSHIP
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 2013 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2012.

ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this item is incorporated herein by reference to the 2013 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2012.

ITEM 14 - PRINCIPAL ACCOUNTANT FEES AND SERVICES
Item 14. Principal Accounting Fees and Services
The information required by this item is incorporated herein by reference to the 2013 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2012.
PART IV

ITEM 15 - EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibits, Financial Statement 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 7, 2013
By: /s/ Charles D. Davidson
Charles D. Davidson,
Chairman of the Board,
Chief Executive Officer and Director
Date:
February 7, 2013
By: /s/ Kenneth M. Fisher
Kenneth M. Fisher,
Senior Vice President, Chief Financial Officer
Date:
February 7, 2013
By: /s/ Dustin A. Hatley
Dustin A. Hatley,
Vice President, Chief Accounting Officer and Controller
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 7, 2013
Charles D. Davidson
Chief Executive Officer and Director
(Principal Executive Officer)
/s/ Kenneth M. Fisher
Senior Vice President, Chief Financial Officer
February 7, 2013
Kenneth M. Fisher
(Principal Financial Officer)
/s/ Dustin A. Hatley
Vice President, Chief Accounting Officer and Controller
February 7, 2013
Dustin A. Hatley
(Principal Accounting Officer)
/s/ Jeffrey L. Berenson
Director
February 7, 2013
Jeffrey L. Berenson
/s/ Michael A. Cawley
Director
February 7, 2013
Michael A. Cawley
/s/ Edward F. Cox
Director
February 7, 2013
Edward F. Cox
/s/ Thomas J. Edelman
Director
February 7, 2013
Thomas J. Edelman
/s/ Eric P. Grubman
Director
February 7, 2013
Eric P. Grubman
/s/ Kirby L. Hedrick
Director
February 7, 2013
Kirby L. Hedrick
/s/ Scott D. Urban
Director
February 7, 2013
Scott D. Urban
/s/ William T. Van Kleef
Director
February 7, 2013
William T. Van Kleef
INDEX TO EXHIBITS
*
Management contract or compensatory plan or arrangement required to be filed as an exhibit hereto.
**
Copies of exhibits will be furnished upon prepayment of 25 cents per page. Requests should be addressed to the Senior Vice President and Chief Financial Officer, Noble Energy, Inc., 100 Glenborough Drive, Suite 100, Houston, Texas 77067.

Market Capitalization: 20217312.421440125
1-Year Return: 0.002905713161453605
252-Day Return: $252_day_return