NOBLE ENERGY INC
Item 1A.
Risk Factors
Item 1B.
Unresolved Staff Comments
Item 3. Legal Proceedings
During 2011, we received two Notices of Alleged Violation (NOAV) from the COGCC regarding the reporting of the presence of hydrogen sulfide to the COGCC and local government designee within certain areas of our Piceance Basin and Grover field operations. At this time, the COGCC has not established a proposed penalty for either NOAV. Given the inherent uncertainty in administrative actions of this nature, we are unable to predict the ultimate outcome of this action at this time. However, we believe that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on our financial position, results of operations or cash flows.
See Item 8. Financial Statements and Supplementary Data - Note 21. Commitments and Contingencies.
Item 4. [Removed and Reserved]
Executive Officers
The following table sets forth certain information, as of February 9, 2012, 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 Royal Dutch Shell plc (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 Shell 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, Related Stockholder Matters and Issuer Purchases of Equity Securities
Common Stock Our common stock, $3.33 1/3 par value, is listed and traded on the NYSE under the symbol “NBL.” The declaration and payment of dividends are at the discretion of our Board of Directors and the amount thereof will depend on our results of operations, financial condition, contractual restrictions, cash requirements, future prospects and other factors deemed relevant by the Board of Directors.
Stock Prices and Dividends by Quarters The high and low sales price per share of our common stock on the NYSE and quarterly dividends paid per share were as follows:
On January 24, 2012, the Board of Directors declared a quarterly cash dividend of $0.22 per common share, which will be paid February 21, 2012 to shareholders of record on February 6, 2012.
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 13, 2012, the number of holders of record of our common stock was 674.
Stock Repurchases The following table summarizes repurchases of our common stock occurring fourth quarter 2011.
(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, 2011.
Stock Performance Graph This graph shows our cumulative total shareholder return over the five-year period from December 31, 2006 to December 31, 2011. The graph also shows the cumulative total returns for the same five-year period of the S&P 500 Index, and our peer group of companies. The cumulative total return of the common stock of our peer group of companies includes the cumulative total return of our common stock.
At December 31, 2011 our peer group of companies consisted of the following:
Anadarko Petroleum Corp.
Newfield Exploration Company
Apache Corp.
Noble Energy, Inc.
Cabot Oil & Gas Corp.
Pioneer Natural Resources Company
Chesapeake Energy Corp.
Plains Exploration and Production Company
Devon Energy Corp.
Range Resources Corp.
EOG Resources, Inc.
Southwestern Energy Company
Forest Oil Corp.
Talisman Energy Inc.
Murphy Oil Corp.
The comparison assumes $100 was invested on December 31, 2006 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
(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.
(2)
Prior to 2008, US NGL sales volumes were included with natural gas volumes. Effective in 2008 we began reporting US NGLs separately where we have the right to take title, which lowered the comparative natural gas sales volumes for 2008.
Item 7. 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
We are a worldwide producer of crude oil and natural gas. Our strategy is to achieve growth in value and cash flows through the continued expansion of a high quality portfolio of producing assets that is balanced and diversified among US and international projects, crude oil and natural gas, and near, medium and long-term opportunities.
Strategy We seek to achieve growth in value and cash flows through exploration success and the development of a high quality, diverse portfolio of assets that is balanced between US and international projects, while maintaining a strong balance sheet and ample liquidity levels. We primarily focus on organic growth from exploration and development drilling, and we augment that with a periodic, opportunistic new business development (mergers and acquisition) capability. We manage the portfolio for high returns and to ensure geographic portfolio balance. We actively manage our portfolio with periodic divestments to “high grade” the portfolio. 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; Galapagos and Gunflint in the deepwater Gulf of Mexico; Tamar and Leviathan, offshore Israel; Aseng (which commenced oil production in November 2011), Alen 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 balanced portfolio between US and international assets and strive to maintain a balanced geographic and political risk profile. We also maintain a geographical diversity of production mix among crude oil, US natural gas, and international natural gas.
Current Business and Industry Environment The global economy continued to gain momentum during 2011 with the US ending in a slightly better position than the previous year. China and other emerging markets continue to maintain solid growth rates and contribute strongly to global commodity demand. However, the European economy remains threatened by the Eurozone debt crisis and its effects on economic growth rates. The global crude oil market has generally been robust driven by increased demand in developing countries coupled with continued threats to the global crude oil supply system and shrinking OPEC spare production capacity supporting oil price levels. The global LNG market has strengthened after the impact of the tsunami on Japan’s nuclear plants and the announced phase out of German nuclear generation capacity. In the US, the application of horizontal drilling technology significantly changed the natural gas markets, resulting in an oversupply of natural gas and significantly lower Henry Hub spot and forward prices. Horizontal technology has also been applied to liquids (oil and natural gas liquids) plays and has yielded significant growth in onshore US liquids production. Crude oil transportation constraints in the US resulted in a disparity between WTI and Brent pricing, and Brent pricing remains somewhat higher than WTI. Third party service costs face some inflationary pressures in response to robust US drilling activity.
2011 Results Despite the uncertain economic situation, 2011 was another strong year for Noble Energy as we continued to lay the foundation for significant future growth from our major development projects while maintaining our strong balance sheet and financial flexibility. Our strategic entry into the Marcellus Shale Joint Venture strengthens and rebalances our portfolio, providing a new, material growth area which we believe will contribute to future reserves, production, and cash flows. The Marcellus Shale is a low-cost natural gas play located near the nation's largest natural gas market. The innovative structure of the joint venture, with a carried cost arrangement that is suspended when natural gas prices decline to certain predetermined levels, ensures economic alignment with our partner at low natural gas prices.
In the deepwater Gulf of Mexico, we contributed to leading our industry back to work, receiving the first post-moratorium drilling permit, and had an exploration success at our Santiago prospect. We are working to strengthen the industry and our company by continuing to enhance safety processes and spill response through the development of a Safety and Environmental Management System (SEMS) in response to new workplace safety rules. We also have a membership in Helix Energy Solutions Group, an oil spill containment response group.
In Equatorial Guinea we brought our Aseng major development project online earlier than scheduled and 13% under budget, significantly adding to our liquids production, which is sold at prices linked to Brent. We continued to make progress on our major development project Alen, continued exploration activities offshore Cameroon, and farmed into a significant acreage exploration position in Senegal/Guinea-Bissau.
In the Eastern Mediterranean, sales volumes increased as we continued to support the Israeli market as it experienced interruptions in Egyptian gas supplies. We made significant progress on our Tamar project, which remains on schedule and on budget with first sales targeted for second quarter 2013. We continued appraisal work at the Leviathan discovery and made another significant natural gas discovery offshore Cyprus.
Our 2011 financial results included the following:
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net income of $453 million as compared with $725 million for 2010;
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gain on divestitures of $25 million as compared with $113 million for 2010;
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asset impairment charges of $759 million as compared with $144 million for 2010;
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gain on commodity derivative instruments of $42 million (including unrealized mark-to-market loss of $22 million) as compared with $157 million gain on commodity derivative instruments (including unrealized mark-to-market gain of $70 million) for 2010;
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diluted earnings per share of $2.54, as compared with $4.10 for 2010;
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cash flows provided by operating activities of $2.2 billion, as compared with $1.9 billion in 2010;
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capital spending on a cash basis of $3.2 billion (including $596 million for the Marcellus Shale asset acquisition) as compared with $2.3 billion in 2010 (including $458 million for the DJ Basin acquisition);
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issuance of $850 million of 30-year unsecured notes and $1 billion of 10-year unsecured notes;
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new credit agreement providing a $3 billion unsecured revolving credit facility (replacing our $2.1 billion credit facility);
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ending cash and cash equivalents balance of almost $1.5 billion at December 31, 2011, as compared with $1.1 billion at December 31, 2010;
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total liquidity of $4.5 billion at December 31, 2011, consisting of year-end cash balance plus funds available under our credit facility, as compared with $2.8 billion at December 31, 2010; and
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year-end ratio of debt-to-book capital of 38%, as compared with 25% at December 31, 2010.
Significant operational highlights for 2011 included the following:
Overall
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total sales volumes of 222 MBoe/d, a 3% increase as compared with 2010; and
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year-end proved reserves of 1.2 BBoe, an increase of 11% from year-end 2010.
Onshore United States
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closed the Marcellus Shale Joint Venture which produced an average of 74 MMcf/d of natural gas, net to our interest, in the fourth quarter of 2011;
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increased DJ Basin volumes to 66 MBoe/d in the fourth quarter of 2011 with horizontal production exiting the quarter at 17 MBoe/d;
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drilled longest-ever horizontal Niobrara well in the DJ Basin with over 9,100 foot lateral in the Wattenberg field; and
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drilled and completed 64 horizontal wells in the DJ Basin Niobrara formation and added a fifth rig to the program.
Deepwater Gulf of Mexico
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announced Santiago discovery and increased the expected initial net production at the Galapagos project to over 10 MBbl/d of crude oil; and
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received Gunflint drilling permit.
International
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startup of Aseng, which exited the year producing 19 MBbl/d of crude oil, net to our interest;
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a world-class discovery offshore Cyprus;
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oil discovery at the Carla prospect in Block O, offshore Equatorial Guinea;
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sanctioned the development plan for the Noa project, offshore Israel, and drilled two development wells;
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natural gas sales in Israel of 173 MMcf/d, net to our interest;
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completed transfer of assets and exit from Ecuador;
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completed seismic acquisition of 3-D data offshore Nicaragua; and
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successfully appraised the Leviathan discovery offshore Israel.
Acquisitions and Divestitures
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 strengthens and rebalances our portfolio, providing a new, material growth area, which will contribute to future reserves, production, and cash flows. This transaction complements and further strengthens our US portfolio by adding a high quality asset with substantial growth potential. It significantly increases our inventory of low risk repeatable projects while exposing us to more US unconventional resources. The Marcellus Shale Joint Venture, combined with our other domestic projects in the DJ Basin and the deepwater Gulf of Mexico, provide balance to our rapidly expanding international programs.
Under the terms of the agreement, we acquired 50% interests in approximately 628,000 net undeveloped acres, existing Marcellus Shale production, and existing infrastructure for approximately $1.3 billion, including post-closing adjustments. Payments will be made in three annual installments, with the first installment made at closing. We will pay an additional $2.1 billion in the form of a carry of CONSOL’s drilling and completion costs. The carry, which we expect to extend over approximately eight years or more, is capped at $400 million annually and suspended if average Henry Hub natural gas prices fall and remain below $4.00 per MMBtu for three consecutive months. The carry terms ensure economic alignment with our partner in periods of low natural gas prices. Initially, we will be the designated operator of the wet-gas areas (areas with more condensate or liquids) and CONSOL will be the designated operator of the dry-gas areas (areas with little or no condensate or liquids).
As a result of this transaction, we are now focusing on three core areas within the US: the DJ Basin; the Marcellus Shale; and the deepwater Gulf of Mexico. We are also considering the divestiture of certain non-core onshore US properties from our portfolio.
Exit from Ecuador In 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 by November 23, 2010. It also allows the Ecuadorian government to nationalize oil and gas fields if a private operator does not comply with local laws.
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, which was terminated by the government of Ecuador on November 25, 2010, 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.
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 included properties located in the DJ Basin, one of our core operating areas. 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, and will provide significant growth potential. Included in the purchase were 323,000 total net acres, nearly 183,000 of which are located in the DJ Basin.
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 were 3% higher in 2011 as compared with 2010. Our mix of sales volumes was 39% global liquids, 32% international natural gas with long-term pricing contracts, and 29% US natural gas. In the US, production was higher in the onshore areas due to record production in Wattenberg primarily due to continued horizontal Niobrara field development and the addition of the Marcellus Shale production in the fourth quarter of 2011. Additionally, international oil production was higher due to Aseng commencing production in November 2011.
In Israel, there was an increase in demand for natural gas to produce electricity due to disruptions with the Egyptian imports during 2011 and warmer weather which led to a higher percentage of the demand being met by production from our properties.
Commodity Price Changes and Hedging Historically, oil and gas prices have exhibited significant volatility. The liquids (crude oil) market remained relatively robust during 2011, benefiting from the continued global economic recovery and continued threats to the global oil supply system. However, the domestic natural gas market continued to weaken significantly, primarily due to an abundant supply and above average levels of gas in storage. US natural gas prices remain volatile and prices are still significantly below the prices realized in 2007 - 2008. See Item 6. Selected Financial Data.
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 2012. 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 2011, we recorded impairment charges of $759 million mainly related to our onshore US assets. The significant decline in spot and five-year forward natural gas prices, approximately 17% over the five-year forward period, during the fourth quarter of 2011 was the major triggering event for most of these impairments. Field performance issues also contributed to impairments. See Item 8. Financial Statements and Supplementary Data - Note 4. Asset Impairments.
OPERATING OUTLOOK
2012 Outlook We remain hopeful for a continued recovery of the global economy; however, we continue to monitor the outlook for the global economy and numerous critical factors including the Chinese economic growth rates, the European debt crisis and its potential impacts on global economic growth and the banking and financial sectors, the US federal budget deficit situation, and commodity prices. We expect crude oil prices to remain at or above current levels as long as the global economic recovery continues, OPEC spare production capacity shrinks as a percentage of global oil demand and threats remain to the global crude oil supply system. Disruption to the global oil supply system could trigger volatility and price spikes with resulting economic shocks which ultimately lead to demand destruction and price declines. We also expect US natural gas prices to remain low as long as the US drilling rig count remains near current levels, storage remains at high levels, and production growth continues. 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 2012 Capital Investment Program below.
2012 Production Our expected crude oil, natural gas and NGL production for 2012 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;
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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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ramp-up of development activity in the Marcellus Shale;
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natural field decline in the deepwater Gulf of Mexico, Gulf Coast and Mid-Continent areas of our US operations, in the North Sea 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 and competing deliveries of natural gas from Egypt and commencement of production from the Noa field and Pinnacles project (if approved by partners as expected) offshore Israel;
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variations in West Africa and North Sea 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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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/or divestments of non-core operating assets; and
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potential shut-in of US producing properties if storage capacity becomes unavailable.
2012 Capital Investment Program Our total capital investment program for 2012 is estimated at $3.5 billion. The capital investment program allocates approximately 51% to onshore US, 7% for deepwater Gulf of Mexico, 22% to the Eastern Mediterranean, 14% to West Africa and 6% to corporate and other. Exploration and appraisal activity within these geographic areas is expected to receive 16% of total capital.
We expect that the 2012 capital investment program will be funded from cash flows from operations, cash on hand, and borrowings under our revolving credit facility and/or other financing such as an issuance of long-term debt. Funding may also be provided by proceeds from divestment of non-core onshore US 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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property acquisitions and divestitures;
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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 Act, on our business practices.
Exploration Program We have significant future exploration potential, primarily in the onshore US, deepwater Gulf of Mexico, offshore West Africa, Eastern Mediterranean and other international areas where we hold acreage positions. As of January 2012, we have returned to drilling at the Leviathan-1 well, which was suspended during 2011, in order to evaluate additional intervals for the existence of other hydrocarbons. Results from the deeper tests, which have a low chance of success, are expected the first half of 2012.
We recently resumed appraisal drilling at Gunflint in the deepwater Gulf of Mexico. In addition, we are planning further exploratory drilling in the Gulf of Mexico, offshore West Africa and in the Eastern Mediterranean.
Exploration activity, particularly offshore, requires significant capital investment. We do not always encounter commercially productive reservoirs through our drilling operations and, as a result, could incur significant dry hole cost. We are planning an active exploratory drilling program in 2012. As a result, dry hole cost could be significant.
Major Development Project Inventory Our current inventory of major development projects includes the horizontal Niobrara, Marcellus Shale, Galapagos, Tamar, Alen, Diega, Gunflint, Leviathan, and other West Africa gas projects. These projects will require significant capital investments. For example, total development costs for the first phase of the Tamar natural gas project are estimated at $3.0 billion ($1.1 billion for our share).
As noted above, we expect to spend substantial amounts on our major development projects in 2012. 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. We commenced oil production from the first of our major projects, Aseng, in November 2011 and ahead of the original schedule. First production from our remaining major offshore development projects is targeted to occur when Galapagos begins to produce in the second quarter of 2012, and Tamar begins to produce in second quarter 2013. Once these two major projects begin producing along with Aseng, we expect to begin generating sufficient amounts of cash flow to self-fund the remaining discovered major projects investments.
As operator on the majority of our development projects, we pay gross joint venture expenses and make cash calls on our nonoperating partners for their respective shares of joint venture costs. These projects are capital cost intensive and a nonoperating partner may experience a delay in obtaining financing for its share of the joint venture costs. In addition, some of our joint venture partners, 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 and we are exposed to counterparty credit risk as a result of our receivables, hedging transactions, and cash investments.
Potential for Future Asset Impairments The US natural gas market remains weak. A further decrease in forward natural gas prices during 2012 could result in impairment charges. Certain of our onshore US properties have significant natural gas reserves and therefore are sensitive to declines in natural gas prices. These assets, which have a combined net book value of approximately $1.0 billion at December 31, 2011, are at risk of impairment if future NYMEX Henry Hub natural gas prices experience further decline. The cash flow model that we use to assess proved properties for impairment includes numerous assumptions, such as management’s estimates of future oil and gas production, market outlook on forward commodity prices, operating and development costs, and discount rates. All inputs to the cash flow model must be evaluated at each date of estimate. However, a decrease in forward natural gas prices alone could result in an impairment of properties that are sensitive to declines in natural gas prices. A significant drop in global oil prices may also trigger impairment. See Item 1A. Risk Factors - Crude oil and natural gas prices are volatile and a substantial reduction in these prices could adversely affect our results of operations and the price of our common stock. See Item 8. Financial Statements and Supplementary Data - Note 4. Asset Impairments.
Potential Changes in Fiscal Regimes and Market Regulations Future economic and political changes in the US or other countries in which we operate could result in governments enacting additional taxes and/or other market interventions, which could be detrimental to oil and gas companies. Any such changes could have an adverse effect on our financial position, results of operations and cash flows.
During 2011, fiscal regime changes occurred in both Israel and the UK. See Item 8. Financial Statements and Supplementary Data - Note 13. Income Taxes.
See also Item 1A. Risk Factors Our operations may be adversely affected by changes in the fiscal regimes and government policies and regulation of oil and gas development in the countries in which we operate for a discussion of the American Jobs Act and the Israeli Interministerial Committee.
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. During 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 fuelling extreme weather and predicted that there will be an escalation of impacts on people and economies.
The oil and natural gas exploration and production industry is a source of certain GHGs, namely carbon dioxide and methane, and future restrictions on the combustion of fossil fuels or the venting of natural gas could have a significant impact on our future operations. We are actively monitoring the following climate change related issues:
Impact of Legislation and Regulation The commercial risk associated with the exploration and production of fossil fuels lies in the uncertainty of government-imposed climate change legislation, including cap and trade schemes, and regulations that may affect us, our suppliers, and our customers. The cost of meeting these requirements may have an adverse impact on our financial condition, results of operations and cash flows, and could reduce the demand for our products.
Climate change legislation and regulations have been adopted by many foreign countries and states in the US; however, legislation and regulations have not been enacted in all of the foreign countries where we operate or at the federal level in the US. 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 2011, the annual conference of parties reconvened in Durban, South Africa to continue pursuing the global accord, committing countries to cut GHG emissions. The parties, including both developed and developing countries, renewed the Protocol and committed to work on an agreement that would be legally binding on all parties, to be written by 2015 and to come into force after 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 61% of our 2011 total sales volume 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 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, tornados 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 Account Policies.
RESULTS OF OPERATIONS
Selected financial information is as follows:
Factors contributing to the decrease in income before income taxes in 2011 as compared with 2010 included the following:
·
$48 million increase in total production expense;
·
$34 million increase in exploration expense;
·
$82 million increase in DD&A expense;
·
$64 million increase in general and administrative expense;
·
$88 million decrease in net gain on asset sales;
·
$615 million increase in asset impairment charges; and
·
$115 million decrease in gain on commodity derivative instruments;
offset by:
·
$741 million increase in total revenues due to higher commodity prices and higher sales volumes.
Factors contributing to the increase in income (loss) before income taxes in 2010 as compared with 2009 included the following:
·
$709 million increase in total revenues due primarily to higher commodity prices;
·
$460 million decrease in asset impairment charges;
·
$91 million increase in net gain on asset sales; and
·
$157 million mark-to-market gain on commodity derivative instruments as opposed to a $110 million mark-to-market loss in 2009;
offset by:
·
$45 million increase in total production expense;
·
$101 million increase in exploration expense; and
·
$67 million increase in DD&A expense.
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:
Average daily sales volumes and average realized sales prices were as follows:
(1)
Natural gas is converted on the basis of six Mcf of gas per one Bbl of oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given commodity price disparities, the price for a Bbl of oil equivalent for natural gas is significantly less than the price for a Bbl of oil.
(2)
Average realized crude oil and condensate prices reflect reductions of $1.32 per Bbl for 2010 and $2.13 per Bbl for 2009 from hedging activities. Average realized natural gas prices reflect a decrease of $0.01 per Mcf for 2010 from hedging activities. The effect of hedging activities on the average realized natural gas price for 2009 was de minimis.
The price reductions resulted from hedge gains and losses that had been previously deferred AOCL. All hedge gains or losses relating to US production had been reclassified to revenues by December 31, 2010.
(3)
Average realized crude oil and condensate prices reflect a reduction of $5.57 per Bbl for 2009 from hedging activities.
The price reduction resulted from hedge losses that had been previously deferred in AOCL. All hedge gains or losses relating to Equatorial Guinea production had been reclassified to revenues by December 31, 2009.
(4)
Natural gas from the Alba field in Equatorial Guinea is sold under contract for $0.25 per MMBtu to a methanol plant, an LPG plant and an LNG plant. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method of accounting.
(5)
Our Block 3 PSC was terminated by the Ecuadorian government on November 25, 2010. Intercompany natural gas sales for 2010 and 2009 were eliminated for accounting purposes. Electricity sales (through May 2011) are included in other revenues. See Item 8. Financial Statements and Supplementary Data - Note 3. Acquisitions and Divestitures.
(6)
Volumes represent sales of condensate and LPG from the Alba Plant in Equatorial Guinea. See Income from Equity Method Investees below.
If the realized gains and losses on commodity derivative instruments, which are included in (gain) loss on commodity derivative instruments in our consolidated statements of operations, had been included in oil and gas revenues, the effect on average realized prices would have been as follows:
Crude Oil and Condensate Sales Revenues from crude oil and condensate sales increased by a net $578 million, or 32%, in 2011 as compared with 2010 due to the following:
·
a 32% 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 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;
·
a decrease in deepwater Gulf of Mexico volumes due to natural field decline and third party downstream facility constraints; and
·
a decrease in North Sea volumes due to downtime in the Dumbarton field for GP III FPSO maintenance.
Revenues from crude oil and condensate sales increased by a net $534 million, or 42%, in 2010 as compared with 2009 due to the following:
·
a 37% increase in total consolidated average realized prices due to increased demand resulting from the global economic recovery;
·
increased production due to ongoing development activity in the DJ Basin, including the horizontal Niobrara drilling program;
·
additional production from the DJ Basin asset acquisition in March 2010;
·
crude oil production from a Swordfish side track oil well that commenced production first quarter 2010;
·
renewed production from Ticonderoga in the deepwater Gulf of Mexico which was off-line first quarter 2009 as a result of hurricane damage to third-party processing and pipeline facilities; and
·
an increase in North Sea sales volumes primarily as a result of increased deliverability at the Dumbarton complex, which included the addition of two Lochranza wells in 2010;
partially offset by
·
a decrease in onshore US volumes due to the divestment of non-core crude oil producing assets;
·
a decrease in deepwater Gulf of Mexico volumes due to natural field decline and third party downstream facility constraints;
·
a decrease in onshore US volumes due to natural field decline in the Mid-Continent and Gulf Coast areas; and
·
a decrease in Equatorial Guinea sales volumes due to the planned shut-down of the Alba field for facilities maintenance and repair during 2010 and the timing of liftings.
Revenues from crude oil and condensate sales included deferred losses of $19 million in 2010 and $58 million in 2009 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 increased by a net $65 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 sales increased by a net $133 million, or 19%, in 2010 as compared with 2009 due to the following:
·
an increase in total consolidated and US average realized prices due to increased demand resulting from the economic recovery;
·
an increase in Israel average realized prices under the terms of a natural gas sales contract entered into in the third quarter of 2009;
·
increased production due to ongoing development activity in the DJ Basin, including the horizontal Niobrara drilling program;
·
additional production from the DJ Basin asset acquisition in March 2010; and
·
an increase in Israel sales volumes due to an increase in demand for our natural gas driven by increased electricity production due to warmer weather and lower levels of competitor natural gas imports from Egypt;
partially offset by
·
a decrease in Equatorial Guinea sales volumes due to the planned shut-down of the Alba field for facilities maintenance and repair; and
·
natural field decline in the deepwater Gulf of Mexico, Gulf Coast and Mid-Continent areas.
Revenues from natural gas included a deferred loss of $1 million in 2010 reclassified from AOCL related to commodity derivative instruments previously accounted for as cash flow hedges. The effect of hedging activities for 2009 was de minimis. 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 and deepwater Gulf of Mexico. NGL sales revenues increased $61 million, or 30%, 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.
NGL sales revenues increased $105 million during 2010 as compared with 2009 due to an increase in sales volumes from ongoing development activity in the DJ Basin, including our horizontal Niobrara drilling program, as well as an increase in consolidated average realized prices which benefited from increased demand resulting from the global economic recovery.
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 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.
Net income from AMPCO and affiliates increased in 2010 as compared with 2009 due to an increase in average realized methanol prices from increased demand due to the global economic recovery. During fourth quarter 2010, the methanol plant successfully completed a major turnaround in 31 days. Production resumed on October 30, 2010.
Alba Plant 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.
Net income from Alba Plant increased in 2010 as compared with 2009 due to an increase in average realized condensate and LPG prices from increased demand due to the global economic recovery.
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. 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 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 (1) below.
(1)
Other international includes China and unallocated expenses incurred at the corporate level.
(2)
Lease operating expense includes oil and gas operating costs (labor, fuel, repairs, replacements, saltwater disposal and other related lifting costs) and workover and repair expense.
(3)
Consolidated unit rates exclude sales volumes and costs attributable to equity method investees.
Lease Operating Expense Lease operating expense 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, as discussed above;
·
higher operating costs associated with the Aseng field which began producing in November 2011; and
·
higher operating costs at the North Sea Dumbarton field related to maintenance at the GP III FPSO;
offset by
·
the sale of certain Oklahoma and Illinois Basin assets in 2010, which had higher lease operating costs.
Lease operating expense was flat in 2010 as compared with 2009. Changes included following:
·
an increase in US sales volumes due to ongoing development activity in DJ Basin, including horizontal drilling in the Niobrara formation;
·
an increase in US production volumes due to the DJ Basin asset acquisition; and
·
an increase in North Sea lease operating expense due to higher sales volumes;
offset by
·
a decrease in Equatorial Guinea lease operating expense due to the planned shut-down of the Alba field for facilities maintenance and repair; and
·
the sale of non-core assets in the Mid-Continent and Illinois Basin areas, which had higher lease operating costs.
Production and Ad Valorem Tax Expense In the US, the sale of certain non-core Oklahoma and Illinois Basin assets in 2010 and natural field decline in the Mid-Continent area resulted in a decrease in production and ad valorem taxes in 2011 as compared with 2010. 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.
Production and ad valorem tax expense for 2010 increased as compared with 2009 due to higher commodity prices.
Transportation Expense 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.
Transportation expense increased in 2010 as compared with 2009 due to an increase in crude oil and condensate production in the DJ Basin and the use of a new interstate crude oil transportation pipeline system to market production.
Unit Rate Per BOE 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.
The unit rate of total production expense per BOE increased for 2010 as compared with 2009 primarily due to increases in production and ad valorem taxes and transportation expense.
Oil and Gas Exploration Expense Exploration expense was as follows:
(1)
West Africa includes Equatorial Guinea, Cameroon, and Senegal/Guinea-Bissau.
(2)
Eastern Mediterranean includes Israel and Cyprus.
(3)
Other international, corporate includes China and various international new ventures such as offshore Nicaragua and offshore France.
Oil and gas exploration expense for 2011 increased by $34 million, or 14%, as compared with 2010. 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 seismic information for Wattenberg, Rocky Mountain and deepwater Gulf of Mexico areas in the US, offshore Nicaragua, offshore France, and offshore Cyprus. Increases in staff expense were due to new ventures mainly offshore Nicaragua and offshore France.
Oil and gas exploration expense for 2010 increased by $101 million, or 70%, as compared with 2009. US dry hole expense was associated with the Double Mountain exploration well in the deepwater Gulf of Mexico, which found noncommercial quantities of hydrocarbons. Seismic expenditures related to the Central Gulf of Mexico lease sale, and the acquisition of 3-D seismic information for offshore Israel, Cameroon, Nicaragua, and France.
Exploration expense included stock-based compensation expense of $11 million in 2011, $10 million in 2010, and $9 million in 2009.
Depreciation, Depletion and Amortization Expense Depreciation, depletion and amortization (DD&A) expense was as follows:
(1)
DD&A expense includes accretion of discount on asset retirement obligations of $20 million in 2011, $17 million in 2010, and $14 million in 2009.
(2)
Consolidated unit rates exclude sales volumes and costs attributable to equity method investees.
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.
Total DD&A expense increased for 2010 as compared with 2009 due to the following:
·
higher sales volumes in the DJ Basin, Piceance Basin and Western Oklahoma areas of our US operations, which have higher DD&A rates relative to sales volume from Equatorial Guinea and Israel;
·
ongoing development activity in DJ Basin, including horizontal drilling in the Niobrara formation; and
·
higher sales volumes in the North Sea;
partially offset by
·
lower DD&A expense in the Mid-Continent area which has a reduced net book value resulting from an impairment recorded at the end of 2009; and
·
the cessation of DD&A associated with assets sold or held-for-sale during the year.
General and Administrative Expense General and administrative (G&A) expense was as follows:
(1)
Consolidated unit rates exclude sales volumes and costs attributable to equity method investees.
G&A expense increased for 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 increased for 2010 as compared with 2009 primarily due to additional expenses relating to personnel and office costs in support of our major development projects and increased performance incentive compensation.
G&A expense 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 $42 million in 2011, $39 million in 2010, and $36 million in 2009. See Item 8. Financial Statements and Supplementary Data - Note 15. Stock-Based Compensation.
Gain on Divestitures Gain on divestitures was as follows:
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. See Item 8. Financial Statements and Supplementary Data - Note 3. Acquisitions and Divestitures.
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. Net gain on asset sales for 2009 includes a $24 million gain on the sale of our Argentina assets. We sold our Argentina assets in 2008; however, recognition of the gain on the sale was deferred until 2009 when the Argentine government approved the sale. See Item 8. Financial Statements and Supplementary Data - Note 3. Acquisitions and Divestitures.
Asset Impairments Asset impairment expense was as follows:
For information regarding asset impairment charges, see Critical Accounting Policies and Estimates - Impairment of Proved Oil and Gas Properties and Other Investments and Impairment of Unproved Oil and Gas Properties, below, and Item 8. Financial Statements 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:
(Gain) Loss 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 16. 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 $58 million in 2011 as compared with 2010. The increase in interest expense prior to the reduction of capitalized interest resulted 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 $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-term projects in the deepwater Gulf of Mexico, West Africa, and Eastern Mediterraean 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 expense prior to the reduction of capitalized interest increased $10 million from 2009 to 2010 due to the higher interest rate associated with our $1 billion 8¼% senior unsecured notes due March 1, 2019, which were outstanding for a full 12 months in 2010 as compared with ten months in 2009. The increase in interest expense prior to the reduction of capitalized interest was more than offset by an increase in the amount of interest capitalized due to higher work in progress amounts related to major long-term projects in the deepwater Gulf of Mexico, West Africa, and Israel.
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, West Africa and Eastern Mediterraean. 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, 2011, approximately 49% 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 $8 million in 2011, $15 million in 2010, and $23 million in 2009. See Item 8. Financial Statements and Supplementary Data - Note 14. Benefit Plans.
Interest Income Interest income includes $3 million in 2010 and $11 million in 2009 related to interest received on the refund of deepwater Gulf of Mexico royalties.
Income Tax Provision (Benefit) The income tax provision (benefit) was as follows:
See Item 8. Financial Statements and Supplementary Data - Note 13. Income Taxes.
PROVED RESERVES
We have historically added reserves through our exploration program, development activities, and acquisition of producing properties. (See Items 1. and 2. Business and Properties). Changes in proved reserves were as follows:
Revisions Revisions of previous estimates represent changes in previous reserves estimates, either upward (positive) or downward (negative), resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs, or development costs. Revisions included the following:
·
changes for the year ended December 31, 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.
·
changes for the year ended December 31, 2010 included a positive revision of 43 MMBoe due to higher year-end commodity prices, a negative revision of 30 MMBoe due to reclassifications of proved undeveloped reserves to probable reserves as a result of the SEC’s five year development rule, a negative revision of 7 MMBoe due to a change in the likelihood that the Noa field, offshore Israel, will be pursued for development, and a negative revision of 2 MMBoe due to well performance; and
·
changes for the year ended December 31, 2009 included a negative revision of 37 MMBoe due to reclassifications of proved undeveloped reserves to probable reserves as a result of the SEC’s new five year development rule and 27 MMBoe due to lower natural gas prices, partially offset by positive revisions due to higher crude oil prices.
Extensions, Discoveries and Other Additions These are additions to proved reserves that result from (1) extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (2) discovery of new fields with proved reserves or of new reservoirs of proved reserves in old fields. Extensions, discoveries and other additions included the following:
·
changes for the year ended December 31, 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.
·
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; and
·
changes for the year ended December 31, 2009 included US additions of 67 MMBoe, which were primarily driven by the execution of low-risk development projects onshore in Wattenberg and the Piceance Basin, as well as from the sanctioning of the development plan for Galapagos in the deepwater Gulf of Mexico, and international additions of 28 MMBoe, related primarily to the initial recording of reserves at the Aseng oil project, 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, Alen, Tamar and Leviathan and from new discoveries resulting from our active exploration programs in the deepwater Gulf of Mexico and international locations. 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 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 ample liquidity throughout the commodity price cycle. Specifically, we strive to retain the ability to fund long-cycle, multi-year, capital-intensive development projects while also maintaining the capability to execute a robust exploration program and financially attractive periodic mergers and acquisitions activity. We endeavor to maintain an investment grade debt rating in service of these objectives. We also utilize a commodity price hedging program to reduce commodity price uncertainty and enhance the predictability of cash flows along with a risk and insurance program to protect against disruption to our cash flows and operations.
Traditional sources of our liquidity are cash on hand, cash flows from operations and available borrowing capacity under our credit facility. During 2011, we strengthened our liquidity position with two public debt offerings. Occasional sales of non-core crude oil and natural gas properties as well as our periodic access to debt and capital markets may also provide cash to support opportunities.
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.
Marcellus Shale Joint Venture On September 30, 2011, we closed a joint venture arrangement with a subsidiary of CONSOL Energy, Inc. See Item 8. Financial Statements and Supplementary Data - Note 3. Acquisitions and Divestitures and Note 12. Long-Term Debt.
The transaction is structured in a unique way from a financial perspective. We have 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, at a minimum, over an eight-year period and is capped at $400 million in each calendar year and will be 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. These conditions allow us to integrate a new core area into our existing long range plan while maintaining our strong balance sheet and financial flexibility. We funded the initial cash payment with cash on hand and borrowings under our credit facility and expect to fund the remaining installment payments and CONSOL Carried Cost Obligation with cash on hand and our credit facility. Targeted divestments of non-core assets may also be a source of funding. At December 31, 2011 the CONSOL Carried Cost Obligation was suspended. See Off-Balance Sheet Arrangements below.
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 $1.5 billion in cash and cash equivalents at December 31, 2011, compared with approximately $1.1 billion at December 31, 2010. At December 31, 2011, our cash was primarily denominated in US dollars and was invested in money market funds and short-term deposits with major financial institutions. Almost $800 million of this cash is attributable to our foreign subsidiaries and most would be subject to US income taxes if repatriated. We currently expect to use a significant amount of this cash during 2012 to fund international projects, including the development of our properties in West Africa and the Eastern Mediterranean.
Credit Facility On October 14, 2011, we entered into a Credit Agreement which provides for a new $3.0 billion unsecured revolving credit facility due October 14, 2016. The new credit facility replaced the previous credit facility of $2.1 billion due to mature December 9, 2012. See Financing Activities - New Credit Facility below.
Derivative Instruments We use various derivative instruments in connection with anticipated crude oil and natural gas sales to minimize the impact of product price fluctuations and ensure cash flow for future capital needs. Such instruments include variable to fixed price commodity swaps, two and three-way collars and basis swaps. We also use 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.
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, 2011 the fair value of our commodity derivative assets was $47 million and the fair value of our commodity derivative liabilities was $83 million (after consideration of netting 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.
Current period settlements on commodity derivative instruments impact our liquidity, since we are either paying cash to or receiving cash from, our counterparties. If actual commodity prices are higher than the fixed or ceiling prices in our derivative instruments, our cash flows will be lower than if we had no derivative instruments. Conversely, if actual commodity prices are lower than the fixed or floor prices in our derivative instruments, our cash flows will be higher than if we had no derivative instruments. None of our counterparty agreements currently contain margin requirements. However, see Item 1A. Risk Factors - Derivatives regulation included in current 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.
See Critical Accounting Policies and Estimates - Derivative Instruments and Hedging Activities,
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
Derivative Instruments Held for Non-Trading Purposes We are exposed to market risk in the normal course of business operations, and the uncertainty of crude oil and natural gas prices continues to impact the oil and gas industry. Due to the volatility of crude oil and natural gas prices, we continue to use derivative instruments as a means of managing our exposure to price changes.
At December 31, 2011, we had entered into variable to fixed price commodity swaps, two-way and three-way collars and basis swaps related to future crude oil and natural gas sales. Our open commodity derivative instruments were in a net payable position with a fair value of $36 million. Based on the December 31, 2011 published forward commodity price curves, a price increase of $1.00 per Bbl for crude oil would increase the fair value of our net commodity derivative payable by approximately $18 million. A price increase of $0.10 per MMBtu for natural gas would increase the fair value of our net commodity derivative payable by approximately $6 million. Our derivative instruments are executed under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net settled at the time of election. See
Item 8. 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, 2011, 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, 2011, 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, 2011 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, 2011 and 2010, and the related consolidated statements of operations, comprehensive income, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2011. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We did not audit the financial statements of the Alba Plant LLC (Alba) for the year ended December 31, 2009, the investment in which, as discussed in Note 8 of the consolidated financial statements, is accounted for by the equity method of accounting. The Company’s equity in earnings of Alba was $66 million, for the year ended December 31, 2009. The financial statements of Alba were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Alba, is based solely on the report of the other auditors.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, based on our audits and the report of the other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Noble Energy, Inc. and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2011, 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, 2011, 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 9, 2012, expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ KPMG LLP
Houston, Texas
February 9, 2012
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, 2011, 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, 2011, 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, 2011 and 2010, and the related consolidated statements of operations, comprehensive income, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2011, and our report dated February 9, 2012 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
Houston, Texas
February 9, 2012
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
(in millions)
The accompanying notes are an integral part of these financial statements.
Noble Energy, Inc.
Consolidated Balance Sheets
(in millions)
The accompanying notes are an integral part of these financial statements.
Noble Energy, Inc.
Consolidated Statements of Cash Flows
(in millions)
The accompanying notes are an integral part of these financial statements.
Noble Energy, Inc.
Consolidated Statements of Shareholders’ Equity
(in millions)
The accompanying notes are an integral part of these financial statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 1. Summary of Significant Accounting Policies
General Noble Energy, Inc. (Noble Energy, we or us) is a leading independent energy company engaged in worldwide oil and gas exploration and production. Our core operating areas are the DJ Basin, Marcellus Shale, deepwater Gulf of Mexico, offshore Eastern Mediterranean, and offshore West Africa.
Basis of Presentation and Consolidation Accounting policies used by us and our subsidiaries conform to US GAAP. Significant policies are discussed below. Our consolidated accounts include our accounts and the accounts of our wholly-owned subsidiaries. We use the equity method of accounting for investments in entities that we do not control but over which we exert significant influence. We carry equity method investments at our share of net assets of the equity investees plus our loans and advances. Differences in the basis of the investment and the separate net asset value of the investee, if any, are amortized into income over the remaining useful life of the underlying assets. See Note 8. Equity Method Investments. All significant intercompany balances and transactions have been eliminated upon consolidation.
Use of Estimates The preparation of consolidated financial statements in conformity with US GAAP requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.
Estimated quantities of crude oil and natural gas reserves are the most significant of our estimates. All the reserves data included in this Form 10-K are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserves estimates may be different from the quantities of crude oil and natural gas that are ultimately recovered. Qualified petroleum engineers in our Houston and Denver offices prepare all reserves estimates for our different geographical regions. These reserves estimates are reviewed and approved by senior engineering staff and division management with final approval by the Vice President - Strategic Planning, Environmental Analysis & Reserves and certain members of senior management. See Supplemental Oil and Gas Information (Unaudited).
Other items subject to estimates and assumptions include the carrying amounts of property, plant and equipment and goodwill, asset retirement obligations, valuation allowances for receivables and deferred income tax assets, valuation of derivative instruments, and obligations related to employee benefits, among others. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. The volatility of commodity prices, including the further decline in US natural gas prices occurring in early 2012, 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 2010 and 2009 consolidated financial statements to conform to the 2011 presentation. These reclassifications were not material to the financial statements.
Fair Value Measurements Fair value measurements are based on a hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three levels. The fair value hierarchy is as follows:
·
Level 1 measurements are fair value measurements which use quoted market prices (unadjusted) in active markets for identical assets or liabilities.
·
Level 2 measurements are fair value measurements which use inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly.
·
Level 3 measurements are fair value measurements which use unobservable inputs.
The fair value hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. We use Level 1 inputs when available as Level 1 inputs generally provide the most reliable evidence of fair value. See Note 16. Fair Value Measurements and Disclosures.
Cash and Cash Equivalents For purposes of reporting cash flows, cash and cash equivalents include unrestricted cash on hand and investments with original maturities of three months or less at the time of purchase.
Allowance for Doubtful Accounts We routinely assess the recoverability of all material trade and other receivables to determine their collectibility. We accrue a reserve on a receivable when, based on management’s judgment, it is probable that a receivable will not be collected and the amount of such reserve may be reasonably estimated. See Note 5. Allowance for Doubtful Accounts.
Inventories Inventories consist primarily of tubular goods and production equipment used in our oil and gas operations, and crude oil produced but not yet sold. Materials and supplies inventories are stated at the lower of average cost or market. The cost of crude oil inventory includes production costs and DD&A of oil and gas properties. See Note 6. Inventories.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Property, Plant and Equipment Significant accounting policies for our property, plant and equipment are as follows:
Successful Efforts Method We account for crude oil and natural gas properties under the successful efforts method of accounting. Under this method, costs to acquire mineral interests in crude oil and natural gas properties, drill and equip exploratory wells that find proved reserves, and drill and equip development wells are capitalized. Capitalized costs of producing crude oil and natural gas properties, along with support equipment and facilities, are amortized to expense by the unit-of-production method based on proved crude oil and natural gas reserves on a field-by-field basis, as estimated by our qualified petroleum engineers. Our policy is to use quarter-end reserves and add back current period production to compute quarterly DD&A expense. Costs of certain gathering facilities or processing plants serving a number of properties or used for third-party processing are depreciated using the straight-line method over the useful lives of the assets ranging from five to 14 years. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized. Repairs and maintenance are expensed as incurred.
Proved Property Impairment We review individually significant proved oil and gas properties and other long-lived assets for impairment at least bi-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 2011, 2010, and 2009. It is likely that other proved oil and gas properties could become impaired in the future if commodity prices significantly 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 crude oil and natural gas reserves. We estimate future prices to apply to the estimated reserves quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net cash flows. For the fair value assigned to proved reserves, future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the business combination. To compensate for the inherent risk of estimating and valuing unproved reserves, discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors. See Note 3. Acquisitions and Divestitures.
Exploration Costs Geological and geophysical costs, delay rentals, amortization of unproved leasehold costs, and costs to drill exploratory wells that do not find proved reserves are expensed as oil and gas exploration. We carry the costs of an exploratory well as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as we are making sufficient progress assessing the reserves and the economic and operating viability of the project. For certain capital-intensive deepwater Gulf of Mexico or international projects, it may take us more than one year to evaluate the future potential of the exploration well and make a determination of its economic viability. Our ability to move forward on a project may be dependent on gaining access to transportation or processing facilities or obtaining permits and government or partner approval, the timing of which is beyond our control. In such cases, exploratory well costs remain suspended as long as we are actively pursuing access to necessary facilities and access to such permits and approvals and believe they will be obtained. We assess the status of suspended exploratory well costs on a quarterly basis. See Note 7. Capitalized Exploratory Well Costs.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Other Property Other property includes automobiles, trucks, airplanes, office furniture, computer equipment and other fixed assets such as building and leasehold improvements. These items are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets or group of assets, which range from three to ten years.
Capitalization of Interest We capitalize interest costs associated with the development and construction of significant properties or projects to bring them to a condition and location necessary for their intended use, which for crude oil and natural gas assets is at first production from the field. Interest is capitalized using an interest rate equivalent to the 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 $132 million in 2011, $67 million in 2010, and $45 million in 2009.
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 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 In September 2011, the FASB issued Accounting Standards Update No. 2011-08: Intangibles - Goodwill and Other (Topic 350): Testing Goodwill for Impairment (ASU 2011-08). ASU 2011-08 permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. The more-likely-than-not threshold is defined as having a likelihood of more than 50 percent. Under ASU 2011-08, an entity is not required to calculate the fair value of a reporting unit unless the entity determines that it is more likely than not that its fair value is less than its carrying amount. ASU 2011-08 is effective for annual periods beginning after December 15, 2011, but early adoption is permitted. We adopted ASU 2011-08 as of December 31, 2011. The adoption of ASU 2011-08 did not have any impact on our financial position and results of operations as of December 31, 2011 as it is a change in application of the goodwill impairment test only.
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, 2011. However, it is possible that goodwill could become impaired in the future if commodity prices or other economic factors become less favorable. See Note 9. Goodwill.
Derivative Instruments and Hedging Activities All derivative instruments (including certain derivative instruments embedded in other contracts) are recorded in our consolidated balance sheets as either an asset or liability and measured at fair value. Changes in the derivative instrument’s fair value are recognized currently in earnings, unless the derivative instrument has been designated as a cash flow hedge and specific cash flow hedge accounting criteria are met. Under cash flow hedge accounting, unrealized gains and losses are reflected in shareholders’ equity as 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.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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 netting arrangement.
Accounting for Interest Rate Derivative Instruments We designate interest rate derivative instruments as cash flow hedges. Changes in fair value of interest rate swaps or interest rate “locks” used as cash flow hedges are reported in AOCL, to the extent the hedge is effective, until the forecasted transaction occurs, at which time they are recorded as adjustments to interest expense over the term of the related notes.
See Note 10. Derivative Instruments and Hedging Activities.
Pension and Other Postretirement Benefit Plans We recognize the funded status (the difference between the fair value of plan assets and the projected benefit obligation) of our defined benefit pension, restoration and other postretirement benefit plans in the consolidated balance sheets, with a corresponding adjustment to AOCL, net of tax. The amount remaining in AOCL at December 31, 2011 represents unrecognized net actuarial loss, unrecognized prior service cost, and unrecognized net transition obligation remaining from the initial adoption of US GAAP for employers’ accounting for pensions and other postretirement benefits. These amounts are currently being recognized as net periodic benefit cost pursuant to our historical accounting policy for amortizing such amounts. Any actuarial gains and losses that arise during the plan year, but which are not required to be recognized as net periodic benefit cost in the same period, are recognized as a component of AOCL. See Note 14. Benefit Plans.
Stock-Based Compensation 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 15. Stock-Based Compensation.
Income Taxes Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized when items of income and expense are recognized in the financial statements in different periods than when recognized in the applicable tax return. Deferred tax assets arise when expenses are recognized in the financial statements before the tax 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.
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 17. Earnings Per Share.
Contingencies We are subject to legal proceedings, claims and liabilities that arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are considered probable and the amounts can be reasonably estimated. See Note 21. Commitments and Contingencies.
We self-insure the medical and dental coverage provided to certain employees, 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.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Foreign Currency The US dollar is considered the functional currency for each of our international operations. Transactions that are completed in foreign currencies are remeasured into US dollars and recorded in the financial statements at prevailing foreign exchange rates. Transaction gains or losses were not material in any of the periods presented and are included in other non-operating (income) expense, net in the consolidated statements of operations.
Segment Information Accounting policies for geographical segments are the same as those described above. Transfers between segments are accounted for at market value. We do not consider interest income and expense or income tax benefit or expense in our evaluation of the performance of geographical segments. See Note 18. Segment Information.
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 U.S. GAAP and IFRSs (ASU 2011-04). ASU 2011-04 clarifies application of fair value measurement and disclosure requirements and is effective for annual periods beginning after December 15, 2011. We are currently evaluating the provisions of ASU 2011-04 and assessing the impact, if any, it may have on our financial position and results of operations.
In June 2011, the FASB issued Accounting Standards Update No. 2011-05: Comprehensive Income (Topic 220): Presentation of Comprehensive Income (ASU 2011-05). ASU 2011-05 provides that an entity that reports items of other comprehensive income has the option to present comprehensive income in either one continuous financial statement or two consecutive financial statements. The update is intended to increase the prominence of other comprehensive income in the financial statements. ASU 2011-05 is effective for annual periods beginning after December 15, 2011.
In December 2011, the FASB issued Accounting Standards Update No. 2011-12: Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 (ASU 2011-12). The Update defers the specific requirement to present items that are reclassified from accumulated other comprehensive income to net income separately with their respective components of net income and other comprehensive income. As part of this update, the FASB did not defer the requirement to report comprehensive income either in a single continuous statement or in two separate but consecutive financial statements. ASU 2011-12 is effective for annual periods beginning after December 15, 2011.
As of December 31, 2011, we early adopted the provisions of ASU 2011-05 requiring presentation of comprehensive income in two consecutive financial statements.
As of December 31, 2011, we early adopted the provisions of ASU 2011-08. See Goodwill, above.
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)
Amount represents electricity sales from the Machala power plant located in Machala, Ecuador. Electricity generation expense includes all operating and non-operating expenses associated with the plant, including DD&A and changes in the allowance for doubtful accounts. See Note 3. Acquisitions and Divestitures, Note 4. Asset Impairments, and Note 5. Allowance for Doubtful Accounts.
(2)
The refund was attributable to royalties that we previously paid on crude oil and natural gas produced in the deepwater Gulf of Mexico from January 1, 2003 through July 31, 2009.
(3)
Amounts relate to rig stand-by expense incurred prior to receiving a permit to resume drilling activities in the deepwater Gulf of Mexico in 2011 and costs to terminate a deepwater Gulf of Mexico drilling rig contract due to the deepwater Gulf of Mexico drilling moratorium in 2010.
(4)
See Note 5. Allowance for Doubtful Accounts.
(5)
The loss on involuntary conversion represents our insurance deductible related to the Leviathan-2 appraisal well control incident. We suspended operations on the Leviathan-2 well, offshore Israel, in May 2011 when we identified water flowing to the sea floor from the wellbore. The incident was a covered event under our well control insurance. At this time, we expect to recover most of the costs from insurance, subject to a deductible. The final amount to be recovered will be based on the cost to drill the Leviathan-3 replacement well down to the same depth at which the incident occurred, possible remediation activities and/or abandonment activities at the Leviathan-2 well, which have not yet been determined, and other factors. See footnote (2) below.
(6)
Amount represents increases in the fair value of shares of our common stock held in a rabbi trust. See Note 14. Benefit Plans.
(7)
Interest income for 2010 and 2009 includes $3 million and $11 million, respectively, related to the refund of deepwater Gulf of Mexico royalties.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Additional balance sheet information is as follows:
(1)
The decrease in the allowance for doubtful accounts from December 31, 2010 is due primarily to the transfer of assets to the Ecuadorian government. See Note 3. Acquisitions and Divestitures and Note 5. Allowance for Doubtful Accounts.
(2)
Amount represents the costs incurred to date, net of insurance deductible and cash receipts for the Leviathan-2 appraisal well. See footnote (5) above.
(3)
The increase in equity method investments from December 31, 2010 is due primarily to our acquisition of a 50% interest in CONE. See Note 3. Acquisitions and Divestitures.
(4)
See Note 11. Asset Retirement Obligations.
(5)
See Note 3. Acquisitions and Divestitures and Note 12. Long-Term Debt.
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
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 50% interests in approximately 628,000 net undeveloped acres, certain producing properties, and existing infrastructure 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 $596 million to date, and, other than post-closing adjustments, the remainder will be paid in two annual installments. See Note 8. Equity Method Investments and 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, up to approximately $2.1 billion (CONSOL Carried Cost Obligation). The CONSOL Carried Cost Obligation is expected to extend over approximately eight years or more. The CONSOL Carried Cost Obligation is capped at $400 million in each calendar year and will be 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. Amounts paid pursuant to the CONSOL Carried Cost Obligation will be recorded as increases in property, plant and equipment in our consolidated balance sheets and as investing activities in our consolidated statements of cash flows. See Note 21. Commitments and Contingencies.
In connection with the joint venture transaction and formation of CONE, we recorded the following:
(1) Total reflects impact of discount on CONSOL installment payments.
To estimate the fair value of the proved oil and gas properties as of the acquisition date, we used an income approach. 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
·
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. See, Note 16. Fair Value Measurements and Disclosures.
Certain data necessary to complete the final purchase price allocation for proved oil and gas properties is not yet available, and includes, but is not limited to, final appraisals of assets acquired and liabilities assumed. We expect to complete the final purchase price allocation during the 12-month period following the acquisition date, during which time the preliminary allocation may be revised.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Gas Gathering Agreement with CONE In connection with the Marcellus Shale Joint Venture described above, we entered into a 50-year gathering and marketing agreement with CONE. Under the terms of the gathering and marketing agreement, we will pay CONE a minimum annual revenue commitment (MARC). The MARC will be adjusted annually based on projected gathering volumes, operating expenses, capital expenditures, and other factors. For fiscal year 2011, the MARC totaled approximately $3 million. See Note 21. Commitments and Contingencies.
We also have agreed to fund an annual work program for the construction of additional pipeline assets to receive and deliver production from future wells. Amounts to be contributed in future years to fund our proportionate share of the annual work program will be dependent upon anticipated production locations, volumes and other factors. We account for our 50% interest in CONE using the equity method; therefore, our share of income is reported as income from equity method investees in our consolidated statements of operations. Our investment in CONE is reported as investment in equity method investee in our consolidated balance sheets and reflects our cash contributions to the entity. See Note 8. Equity Method Investments.
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:
Note 4. Asset Impairments
Pre-tax (non-cash) asset impairment charges were as follows:
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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. The discounted cash flow models included management’s estimates of future oil and gas production, commodity prices based on forward commodity price curves as of the date of the estimate, operating and development costs, and discount rates.
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.
2009 Asset Impairments Declines in natural gas prices resulted in impairments of Granite Wash, an onshore US area where we significantly reduced our investment beginning in 2007, and our New Albany Shale development. We also impaired our deepwater Gulf of Mexico development at Raton, primarily due to well performance issues and our Gulf of Mexico shelf asset at Main Pass, which had been reclassified from held-for-sale to held-and-used. The assets were written down to their estimated fair values, which were determined using discounted cash flow models, as described above.
We also reviewed our investment in Ecuador for impairment, as a result of the increasingly unsettled economic and political environment in Ecuador, and determined that the carrying value of our investment exceeded its fair value. We estimated the fair value of our investment using a probability-weighted discounted cash flow model that considered the likelihood of possible outcomes of (1) the event of continued operation of the assets in contemplation of resolving the dispute and in accordance with the existing contract, (2) the event of a sale of our investment to a third party, and (3) the event of arbitration with varying degrees of award and collection. The use of alternative judgments and/or assumptions could have resulted in the recognition of an impairment charge that was significantly different.
See also Note 16. 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. Amount in 2009 was received in accordance with the terms of a settlement agreement and included as a reduction in electricity generation expense.
(2)
SemCrude, L.P. was a crude oil purchaser who filed a voluntary petition for reorganization under Chapter 11 of the Bankruptcy Code in 2008.
Note 6. Inventories
Inventories consisted of the following:
Note 7. Capitalized Exploratory Well Costs
We capitalize exploratory well costs until a determination is made that the well has found proved reserves or is deemed noncommercial. If a well is deemed to be noncommercial, the well costs are immediately charged to exploration expense.
Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed in the same period:
Noble Energy, Inc.
Notes to Consolidated Financial Statements
The following table provides an aging of capitalized exploratory well costs (suspended well costs) based on the date that drilling commenced and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the commencement of drilling:
The following table provides a further aging of those exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling as of December 31, 2011:
Blocks O and I Blocks O and I are crude oil, natural gas and natural gas condensate discoveries. During the second quarter of 2011, we drilled the successful Diega appraisal well which encountered both crude oil and natural gas. We have drilled two sidetracks, each of which encountered hydrocarbons. We are currently finalizing our appraisal of Diega and are evaluating regional development scenarios.
YoYo YoYo is a 2007 natural gas and condensate discovery. During 2011 we acquired and processed additional 3-D seismic information and are evaluating for future drilling potential.
Leviathan Leviathan is a 2010 natural gas discovery. We are continuing to evaluate the discovery with the successful drilling of the Leviathan-3 appraisal well. In January 2012, we resumed drilling at the Leviathan-1 well in order to evaluate two additional intervals for the existence of crude oil. Results from these deeper tests are expected during the first half 2012. We will require an additional one or two appraisal wells to further define Leviathan’s boundaries in order to determine the best development option including subsea tieback to existing shallow water platform, semi-submersible platform, FPSO, or floating LNG.
Dalit Dalit is a 2009 natural gas discovery. We are currently working with our partners on a cost-effective development plan.
Gunflint Gunflint (Mississippi Canyon Block 948) is a 2008 crude oil discovery. Our plans to drill two or three appraisal wells in 2011 were delayed by the post-Deepwater Moratorium permitting process. In October 2011, we received a drilling permit and in December 2011 we resumed drilling at Gunflint. We currently anticipate drilling up to three appraisal wells to fully evaluate the extent of the reservoir. We are also reviewing host platform options including: subsea tieback to an existing third-party host and construction of a new facility. If we are able to connect to an existing third-party host, the project could have an accelerated completion schedule, thereby potentially absorbing time lost due to the drilling delay caused by the Deepwater Moratorium and permit-related delay.
Deep Blue Deep Blue (Green Canyon Block 723) was a significant test well, which began drilling during 2009. When the Deepwater Moratorium was announced in May 2010, we were required to suspend side track drilling activities at the Deep Blue prospect. In November 2011 we announced that we have finished the well and found additional hydrocarbons in high quality reservoirs. During first quarter of 2012, we will be completing additional analysis of the data from the side track well.
Selkirk The Selkirk project is located in the UK sector of the North Sea. Capitalized costs to date primarily consist of the cost of drilling an exploratory well. We are currently working with our partners on a cost-effective development plan, including selection of a host facility.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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, 2011, our retained earnings included $106 million related to the undistributed earnings of equity method investees.
The carrying value of our AMPCO investment was $14 million higher than the underlying net assets of the investee at December 31, 2011. The difference includes $10 million relating to capitalized interest which is being amortized into earnings over the remaining useful life of the plant. The remaining $4 million relates to a note receivable from our funding a portion of the local government’s share of the plant’s development. The note receivable is being recovered through distributions from AMPCO.
Equity method investments are as follows:
Summarized, 100% combined financial information for equity method investees is as follows:
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 9. Goodwill
Changes in the carrying amount of goodwill were as follows:
(1)
See Note 3 - Acquisitions and Divestitures.
Note 10. Derivative Instruments and Hedging Activities
Objective and Strategies for Using Derivative Instruments In order to mitigate the effect of commodity price uncertainty and enhance the predictability of cash flows relating to the marketing of our crude oil and natural gas, we enter into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production. The derivative instruments we use include variable to fixed price commodity swaps, two-way and three-way collars and basis swaps.
The fixed price swap, two-way collar, and basis swap contracts entitle us (floating price payor) to receive settlement from the counterparty (fixed price payor) for each calculation period in amounts, if any, by which the settlement price for the scheduled trading days applicable for each calculation period is less than the fixed strike price or floor price. We would pay the counterparty if the settlement price for the scheduled trading days applicable for each calculation period is more than the fixed strike price or ceiling price. The amount payable by us, if the floating price is above the fixed or ceiling price, is the product of the notional quantity per calculation period and the excess 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 have also entered into forward contracts to hedge anticipated exposure to interest rate risk associated with public debt financing.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
While these instruments mitigate the cash flow risk of future reductions in commodity prices or increases in interest rates, they may also curtail benefits from future increases in commodity prices or decreases in interest rates.
See Note 16. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of our derivative instruments.
Counterparty Credit Risk Derivative instruments expose us to counterparty credit risk. Our commodity derivative instruments are currently with a diversified group of highly rated major banks or market participants, and we 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 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. On February 15, 2011 we settled the interest rate swap, which had a net liability position of $40 million. 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. See Note 12. Long-Term Debt.
Unsettled Derivative Instruments As of December 31, 2011, we have entered into the following crude oil derivative instruments:
As of December 31, 2011, we have entered into the following natural gas derivative instruments:
Noble Energy, Inc.
Notes to Consolidated Financial Statements
As of December 31, 2011, we have entered into the following natural gas basis swaps:
(1)
Colorado Interstate Gas - Northern System
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:
Commodity Derivative Instruments Not Designated as Hedging Instruments
Amount of (Gain) Loss on Derivative Instruments Recognized in Income
Derivative Instruments in Cash Flow Hedging Relationships
(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.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
AOCL - Interest Rate Derivative Instruments At December 31, 2011, AOCL included deferred losses of $26 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.
Note 11. Asset Retirement Obligations
Changes in asset retirement obligations were as follows:
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 related to deepwater and shelf properties in the Gulf of Mexico. Revisions resulted from changes in estimated abandonment costs mainly in the DJ Basin and deepwater Gulf of Mexico.
For the year ended December 31, 2010, liabilities incurred were primarily due to the DJ Basin asset acquisition. Liabilities settled related to non-core onshore US properties sold, abandoned Gulf of Mexico shelf assets, and Block 3 offshore Ecuador. Revisions resulted from changes in estimated timing of actual abandonment due to shortened field lives for certain UK assets and overall cost increases for assets located primarily in the deepwater Gulf of Mexico.
Accretion expense is included in DD&A expense in the consolidated statements of operations.
Note 12. Long-Term Debt
Our debt consists of the following:
(1)
Amount reported at December 31, 2010 was based on percentage of Aseng FPSO construction activities completed as of December 31, 2010. Amounts do not reflect future minimum lease payments. See Aseng FPSO Lease Obligation below.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
All of our long-term debt is senior unsecured debt and is, therefore, pari passu with respect to the payment of both principal and interest. The indenture documents of each of our notes provide that we may prepay the instruments by creating a defeasance trust. The defeasance provisions require that the trust be funded with securities sufficient, in the opinion of a nationally recognized accounting firm, to pay all scheduled principal and interest due under the respective agreements. Interest on each of these issues is payable semi-annually. Debt issuance costs of approximately $35 million remain and are being amortized to expense over the life of the related debt issues.
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 will be used for general corporate purposes.
New Credit Facility On October 14, 2011, we entered into a credit agreement with certain commercial lending institutions (the Credit Agreement) which provides for a new $3.0 billion unsecured five-year revolving credit facility (the New Credit Facility). The New Credit Facility replaces our $2.1 billion credit facility maturing December 9, 2012. Also on October 14, 2011, we borrowed $400 million under the New Credit Facility, which was used to repay outstanding borrowings under and to terminate the $2.1 billion credit facility. Other than amounts drawn and repaid under our credit facility, we did not engage in any other short-term borrowing arrangements during 2010 or 2011.
The New Credit Facility (i) provides for an initial commitment of $3.0 billion with an option to increase the overall commitment amount by up to an additional $1.0 billion, subject to the consent of any increasing lenders, (ii) will mature on October 14, 2016, (iii) provides for facility fee rates that range from 12.5 basis points to 30 basis points per year depending upon our credit rating, (iv) includes sub-facilities for short-term loans and letters of credit up to an aggregate amount of $500 million under each sub-facility and (v) 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 New Credit Facility and require the immediate repayment of any outstanding advances under the New Credit Facility. As of December 31, 2011, we were in compliance with our debt covenants.
The New 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.
Old Credit Facility Our previous bank revolving credit facility (the Old Credit Facility), which was in place as of December 31, 2010 and 2009, was committed in the amount of $2.1 billion until December 9, 2011 at which time the commitment reduced to $1.8 billion. The Old Credit Facility (i) provided for credit facility fee rates that ranged from 5 basis points to 15 basis points per year depending upon our credit rating, (ii) made available short-term loans up to an aggregate amount of $300 million within the current $2.1 billion commitment and (iii) provided for interest rates that were based upon the Eurodollar rate plus a margin that ranges from 20 basis points to 70 basis points depending upon our credit rating and utilization of the Old Credit Facility. The Old Credit Facility required that our total debt to capitalization ratio (as defined in the credit agreement), expressed as a percentage, not exceed 60% at any time. A violation of this covenant would have resulted in a default under the Old Credit Facility, which would have permitted the participating banks to restrict our ability to access the Old Credit Facility and require the immediate repayment of any outstanding advances under the Old Credit Facility. As of December 31, 2010, we were in compliance with our debt covenants. The Old Credit Facility was with certain commercial lending institutions and was available for general corporate purposes.
Certain lenders that were a party to the Old Credit Facility have in the past performed investment banking, financial advisory, lending or commercial banking services for us, for which they have received customary compensation and reimbursement of expenses.
The Old Credit Facility did not restrict the payment of dividends on our common stock, except, if after giving effect thereto, an Event of Default had occurred and be continuing or been caused thereby.
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 on September 30, 2012 and 2013. The installment payments have been discounted at the prevailing market rates for similar debt instruments. See Note 3. Acquisitions and Divestitures and Note 16. Fair Value Measurements and Disclosures.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Aseng FPSO Lease Obligation We have entered into an agreement to lease a FPSO to be used in the development of 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, as of December 31, 2010, the percentage of construction activities completed, 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 as lease payments begin. In November 2011, production commenced and lease payments began. See Note 21. Commitments and Contingencies for future Aseng FPSO lease payments.
2009 Debt Offering In 2009, we closed an offering of $1.0 billion senior unsecured notes receiving net proceeds of $989 million, after deducting the discount and underwriting fees. The notes are due March 1, 2019, and pay interest semi-annually at 8¼%. Debt issuance costs of approximately $2 million were incurred and are being amortized to expense over the life of the debt issue. Substantially all of the net proceeds from the offering were used to repay outstanding indebtedness under our revolving credit facility maturing 2012.
2009 Debt Repurchase In 2009, we repurchased $5 million of our Senior Debentures due August 1, 2097, recognizing a debt extinguishment gain of $1 million.
Annual Debt Maturities Annual maturities of outstanding debt, excluding Aseng FPSO lease payments, are as follows:
Note 13. Income Taxes
Components of income (loss) before income taxes are as follows:
The income tax provision (benefit) consists of the following:
Noble Energy, Inc.
Notes to Consolidated Financial Statements
A reconciliation of the federal statutory tax rate to the effective tax rate is as follows:
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, 2011. 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.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Deferred tax assets associated with foreign loss carryforwards totaled $47 million in 2009, $70 million in 2010, and $65 million in 2011. Losses continue to be incurred on our project in Cameroon and other new venture activities which are not yet commercial.
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 is now fully offset by a valuation allowance because, based on our forecast of foreign tax credits, we do not believe it is more likely than not that the asset will be realized.
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 2011 as compared with 2010. This was primarily due to the changes in Israeli and UK tax law discussed below. Partially offsetting this increase was the impact of higher earnings from equity method subsidiaries in 2011, which has the effect of decreasing the rate when we have pre-tax income. 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.
Our effective tax rate decreased in 2010 as compared with 2009. For 2010, the effective rate was lower than the federal statutory rate because our income from equity method investees and other permanent differences have the impact of decreasing the effective rate when we have pre-tax income. The reversal of a $28 million deferred tax asset valuation allowance, discussed above, also reduced income tax expense.
Changes in Israeli Tax Law In March 2011, the Israeli government enacted the Oil 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.
Changes in UK Tax Law The Finance Bill 2011, which became law on July 19, 2011, increased the rate of the Supplementary Charge levied on oil and gas income in the UK from 20% to 32% effective March 24, 2011. This change increased the tax rate on our UK oil and gas income from 50% to 62% and our 2011 consolidated effective income tax rate by approximately 7%. The change also resulted in a remeasurement of our UK deferred tax liability as of December 31, 2010 to reflect the higher effective rate. As a result of the enactment, we recorded a $34 million increase in both our deferred income tax liability and deferred income tax expense during 2011.
Accumulated Undistributed Earnings of Foreign Subsidiaries As of December 31, 2011, the accumulated undistributed earnings of the foreign subsidiaries on which no US taxes have been recorded were approximately $2.0 billion. Upon distribution of additional earnings in the form of dividends or otherwise, we would likely be subject to US income taxes and foreign withholding taxes. It is not practicable, however, to determine precisely the amount of taxes that may be payable on the eventual remittance of these earnings because of the possible application of US foreign tax credits. Although we are currently claiming foreign tax credits, we may not be in a credit position when any future remittance of foreign earnings takes place, or the limitations imposed by the Internal Revenue Code and IRS Regulations may not allow the credits to be utilized during the applicable carryback and carryforward periods. However, if full use of tax credits is assumed, we estimate that the future US taxes on eventual remittance would be approximately $329 million.
During 2009, we repatriated $180 million of accumulated earnings of foreign subsidiaries and used the proceeds for debt repayment and general corporate purposes. The repatriation increased US tax expense by $13 million, of which $9 million was recorded in 2008. Repatriation of additional earnings in the future could result in a decrease in our net income and cash flows.
Unrecognized Tax Benefits We did not have significant unrecognized tax benefits resulting from differences between positions taken in tax returns and amounts recognized in the financial statements as of December 31, 2011 or 2010. Our policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense. However, we did not accrue interest or penalties at December 31, 2011 or 2010, because the jurisdiction in which we have unrecognized tax benefits does not currently impose interest on underpayments of tax and we believe that we are below the minimum statutory threshold for imposition of penalties. We do not expect that the total amount of unrecognized tax benefits will significantly increase or decrease during the next 12 months.
Years Open to Examination In our major tax jurisdictions, the earliest years remaining open to examination are as follows: US - 2008, Equatorial Guinea - 2007, Israel - 2008, UK - 2007, the Netherlands - 2009, and China - 2006.
Note 14. Benefit Plans
Pension and Other Postretirement Benefit Plans We have a noncontributory, tax-qualified defined benefit pension plan covering employees who were hired prior to May 1, 2006. The benefits are based on an employee’s years of service and average earnings for the 60 consecutive calendar months of highest compensation. Our funding policy has been to make annual contributions equal to at least the minimum required contribution, but no greater than the maximum deductible for federal income tax purposes. We also have an unfunded, nonqualified restoration plan that provides the pension plan formula benefits that cannot be provided by the qualified pension plan because of pay deferrals and the compensation and benefit limitations imposed on the pension plan by the Internal Revenue Code of 1986, as amended. We sponsor other plans for the benefit of our employees and retirees, which include medical and life insurance benefits. We use a December 31 measurement date for the plans.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Changes in the benefit obligation and plan assets of the pension, restoration and other postretirement benefit plans were as follows at December 31:
(1)
Plan amendments relate to an increase in the monthly retiree contributions, changes to annual deductible, co-pays and annual out-of-pocket limit and change to reflect trend on retiree contributions for the medical and life plan.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Net periodic benefit cost recognized for the pension, restoration and other postretirement benefit plans was as follows:
(1)
The discount rates used to determine benefit obligations at December 31, 2010 were 5.50% for the retirement plan and 5.25% for the restoration plan.
(2)
The rate of compensation increase used to determine benefit obligations at December 31, 2011 ranged from 4% to 13%. The rate of compensation increase assumption was determined using a historical age based table grouped in five year age intervals.
(3)
The discount rates used to determine net periodic benefit costs for the year ended December 31, 2011 were 5.50% for the retirement plan and 5.25% for the restoration plan. The discount rates used to determine net periodic benefit costs for the year ended December 31, 2009 were 6.00% for the retirement plan and 6.25% for the restoration plan.
Additional disclosures for the retirement and restoration plans are as follows:
In selecting the assumption for expected long-term rate of return on assets, we consider the average rate of earnings expected on the funds to be invested to provide for plan benefits. This includes considering the plan’s asset allocation, historical returns on these types of assets, the current economic environment and the expected returns likely to be earned over the life of the plan. During 2011, we changed the plan’s target asset allocation from 70% equity and 30% fixed income to 60% equity and 40% fixed income. The change was made to more closely align the plan’s expected future payment streams with the expected duration of plan liabilities. The change was also made to reduce the plan’s market risk and the degree of volatility in the plan’s investments. Because a larger portion of the plans funds are now invested in fixed income, which are considered to be less risky investments, the plan’s returns will likely be reduced in times of market upswings, while losses will be reduced in times of market downswings. We assume the long-term asset mix will be consistent with the target asset allocation, with a range in the acceptable degree of variation in the plan’s asset allocation of plus or minus 10%. Based on these factors we assumed an average of 7.25% per annum over the life of the plan for the calculation of 2011 net periodic benefit cost. The assumption will be reduced to 6.50% for the calculation of 2012 net periodic benefit cost. No plan assets are expected to be returned to us in 2012.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
In order to determine an appropriate discount rate at December 31, 2011, we performed an analysis of the Citigroup Pension Discount Curve (the CPDC) and various AA corporate bond yields as of that date for each of our plans. The CPDC uses spot rates that represent the equivalent yield on high quality, zero-coupon bonds for specific maturities. We used these rates to develop an equivalent single discount rate based on our plans’ expected future benefit payment streams and duration of plan liabilities. A 1% increase in the discount rate would have resulted in a decrease in net periodic benefit cost of approximately $3 million in 2011. A 1% decrease in the discount rate would have resulted in an increase in net periodic benefit cost of approximately $2 million in 2011.
Assumed health care cost trend rates were as follows:
Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
Weighted-average asset allocations for the tax-qualified defined benefit pension plan are as follows:
The investment policy for the tax-qualified defined benefit pension plan is determined by an employee benefits committee (the committee) with input from a third-party investment consultant. Based on a review of historical rates of return achieved by equity and fixed income investments in various combinations over multi-year holding periods and an evaluation of the probabilities of achieving acceptable real rates of return, the committee has determined the target asset allocation deemed most appropriate to meet immediate and future benefit payment requirements for the plan and to provide a diversification strategy which reduces market and interest rate risk. The fixed income allocation is expected to directionally track a portion of the plan’s liabilities, thus reducing overall plan interest rate risk. A 1% increase (decrease) in the expected return on plan assets would have resulted in a (decrease) increase, respectively, in net periodic benefit cost of approximately $2 million in 2011.
We base our determination of the asset return component of pension expense on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets. Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded. As of January 1, 2012, we had cumulative asset losses of approximately $10 million, which remain to be recognized in the calculation of the market-related value of assets.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Additional fair value disclosures about plan assets are as follows:
(1)
See Note 1. Summary of Significant Accounting Policies - Fair Value Measurements for a description of the fair value hierarchy.
Additional information about plan assets, including methods and assumptions used to estimate the fair values of plan assets, is as follows:
Federal Money Market Funds Investments in federal money market funds consist of portfolios of high quality fixed income securities (such as US Treasury securities) which, generally, have maturities of less than one year. The fair value of these investments is based on quoted market prices for identical assets as of the measurement date.
Mutual Funds Investments in mutual funds consist of diversified portfolios of common stocks and fixed income instruments. The common stock mutual funds are diversified by market capitalization and investment style as well as economic sector and industry. The fixed income mutual funds are diversified primarily in government bonds, mortgage backed securities, and corporate bonds, most of which are rated investment grade. The fair values of these investments are based on quoted market prices for identical assets as of the measurement date.
Common Collective Trust Funds Investments in common collective trust funds consist of common stock investments in both US and non-US equity markets. Portfolios are diversified by market capitalization and investment style as well as economic sector and industry. The investments in the non-US equity markets are used to further enhance the plan’s overall equity diversification which is expected to moderate the plan’s overall risk volatility. In addition to the normal risk associated with stock market investing, investments in foreign equity markets may carry additional political, regulatory, and currency risk which is taken into account by the committee in its deliberations. The fair value of these investments is based on quoted prices for similar assets in active markets. All of the investments in common collective trust funds represent exchange-traded securities with readily observable prices.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Contributions We expect to make cash contributions of approximately $13 million to the pension plan during 2012. We expect to make cash contributions of $3 million to the unfunded restoration plan and $1 million to the medical and life plans in 2012, which amounts equal expected benefit payments from those plans. (Unaudited).
Estimated Future Benefit Payments As of December 31, 2011, the following future benefit payments are expected to be paid:
The estimate of expected future benefit payments is based on the same assumptions used to measure the benefit obligation at December 31, 2011 and includes estimated future employee service.
401(k) Plan We sponsor a 401(k) savings plan. All regular employees are eligible to participate. We make contributions to match employee contributions up to the first 6% of compensation deferred into the plan, and certain profit sharing contributions for employees hired on or after May 1, 2006, based upon their ages and salaries. We made cash contributions of $14 million in 2011, $11 million in 2010, and $9 million in 2009.
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 value. See Note 16. Fair Value Measurements and Disclosures. The mutual funds are included in the mutual fund investments account in other noncurrent assets in the consolidated balance sheets.
Shares of our common stock held by the rabbi trust are accounted for as treasury stock (recorded at cost, $33.44 per share) in the shareholders’ equity section of the consolidated balance sheets. The amounts payable to the plan participants are included in other noncurrent liabilities in the consolidated balance sheets and include the market value of the shares of our common stock. Approximately 800,000 shares, or 94%, of our common stock held in the plan at December 31, 2011 were attributable to a member of our Board of Directors. The shares are being distributed in equal installments over the next eight years. Distributions of 100,000 shares were made in each of 2010 and 2011. In addition, plan participants sold 100 shares of our common stock in 2011, 100 shares in 2010, and 1,892 shares in 2009. Proceeds were invested in mutual funds and/or distributed to plan participants. Distributions to plan participants were valued at $17 million in 2011, $17 million in 2010 and were de minimis in 2009.
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 $8 million in 2011, $15 million in 2010 and $23 million in 2009.
We also maintain an unfunded deferred compensation plan for the benefit of certain of our employees. Deferred compensation liabilities of $60 million, $51 million and $45 million were outstanding at December 31, 2011, 2010 and 2009, respectively, under the unfunded plan.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 15. Stock-Based Compensation
We recognized total stock-based compensation expense as follows:
Stock Option and Restricted Stock Plans and Incentive Plan Our stock option and restricted stock plans and incentive plan are described below.
1992 Stock Option and Restricted Stock Plan Under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan, as amended (the 1992 Plan), the Compensation, Benefits and Stock Option Committee of the Board of Directors (the Committee) may grant stock options and award restricted stock to our officers or other employees and those of our subsidiaries. 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, 2011, 16,216,198 shares of our common stock were reserved for issuance, including 9,143,929 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.
2004 Long-Term Incentive Plan Under the Noble Energy, Inc. 2004 Long-Term Incentive Plan (the 2004 LTIP), the Committee may make incentive awards to our key employees and those of our subsidiaries. Incentive compensation is based upon the attainment of specific market and performance goals established by the Committee. Awards may be in the form of stock options or restricted stock or in the form of performance units or other incentive measurements providing for the payment of bonuses in cash, or in any combination thereof, as determined by the Committee in its discretion. Stock options granted and restricted stock awarded under the 2004 LTIP are granted and awarded pursuant to the terms of the 1992 Plan.
2005 Stock Plan for Non-Employee Directors The 2005 Stock Plan for Non-Employee Directors of Noble Energy, Inc. (the 2005 Plan) provides for grants of stock options and awards of restricted stock to our non-employee directors. The 2005 Plan superseded and replaced the 1988 Nonqualified Stock Option Plan for Non-Employee Directors. The total number of shares of our common stock that may be issued under the 2005 Plan is 800,000. At December 31, 2011, 705,778 shares of our common stock were reserved for issuance, including 504,841 shares available for future grants and awards under the 2005 Plan.
The 2005 Plan provides for the granting to a non-employee director of up to a maximum of 11,200 stock options on the date of election to the Board of Directors, annual grants of 2,800 options per non-employee director on February 1 of each year, and discretionary grants by the Board of Directors (with the February 1 annual and the discretionary grants made to a non-employee director during any calendar year being limited to a combined maximum of 11,200 options). Options are issued with an exercise price equal to the market price of our common stock on the date of grant and may be exercised one year after the date of grant. The options expire ten years from the date of grant.
The 2005 Plan also provides for the awarding to a non-employee director of up to a maximum of 4,800 shares of restricted stock on the date of election to the Board of Directors, annual awards of 1,200 shares of restricted stock per non-employee director on February 1 of each year, and discretionary awards by the Board of Directors (with the February 1 annual and the discretionary awards made to a non-employee director during any calendar year being limited to a combined maximum of 4,800 shares of restricted stock). Restricted stock is restricted for a period of at least one year from the date of award.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
1988 Nonqualified Stock Option Plan for Non-Employee Directors The 1988 Nonqualified Stock Option Plan for Non-Employee Directors of Noble Energy, Inc., as amended, (the 1988 Plan) provided for the issuance of stock options to our non-employee directors. Options issued under the 1988 Plan may be exercised one year after grant and expire ten years from the grant date. The 1988 Plan provided for the granting of a fixed number of stock options to each non-employee director annually (10,000 stock options for the first calendar year of service and 5,000 stock options for each year thereafter) on February 1 of each year. The 1988 Plan was terminated in 2005, and no additional options can be granted thereunder.
Stock Option Grants The fair value of each stock option granted was estimated on the date of grant using a Black-Scholes-Merton option valuation model that used the assumptions described below:
·
Expected term The expected term represents the period of time that options granted are expected to be outstanding, which is the grant date to the date of expected exercise or other expected settlement for options granted. The hypothetical midpoint scenario we use considers our actual exercise and post-vesting cancellation history and expectations for future periods, which assumes that all vested, outstanding options are settled halfway between their vesting date and their expiration date.
·
Expected volatility The expected volatility represents the extent to which our stock price is expected to fluctuate between the grant date and the expected term of the award. We use the historical volatility of our common stock for a period equal to the expected term of the option prior to the date of grant. We believe that historical volatility produces an estimate that is representative of our expectations about the future volatility of our common stock over the expected term.
·
Risk-free rate The risk-free rate is the implied yield available on US Treasury securities with a remaining term equal to the expected term of the option. We base our risk-free rate on a weighting of five and seven year US Treasury securities as of the date of grant.
·
Dividend yield The dividend yield represents the value of our stock’s annualized dividend as compared to our stock’s average price for the three-year period ended prior to the date of grant. It is calculated by dividing one full year of our expected dividends by our average stock price over the three-year period ended prior to the date of grant.
The assumptions used in valuing stock options granted were as follows:
Stock option activity was as follows:
The total intrinsic value of options exercised was $40 million in 2011, $68 million in 2010, and $19 million in 2009.
As of December 31, 2011, $30 million of compensation cost related to unvested stock options granted under the Plans remained to be recognized. The cost is expected to be recognized over a weighted-average period of 1.3 years. We issue new shares of our common stock to settle option exercises. Dividends are not paid on unexercised options.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Restricted Stock Awards Restricted stock activity was as follows:
The total fair value of restricted stock that vested was $57 million in 2011, $43 million in 2010, and $4 million in 2009.
The weighted average award-date fair value of restricted stock awarded was $90.32 per share in 2011, $75.07 per share in 2010, and $51.63 per share in 2009.
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, 2011, $37 million of compensation cost related to all of our unvested restricted stock awarded under the Plans remained to be recognized. The cost is expected to be recognized over a weighted-average period of 1.3 years. Common stock dividends accrue on restricted stock awards and are paid upon vesting. We issue new shares of our common stock when awarding restricted stock.
Note 16. Fair Value Measurements and Disclosures
Assets and Liabilities Measured at Fair Value on a Recurring Basis Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:
Cash, Cash Equivalents, Accounts Receivable and Accounts Payable The carrying amounts approximate fair value due to the short-term nature or maturity of the instruments.
Mutual Fund Investments Our mutual fund investments, which primarily include assets held in a rabbi trust, consist of various publicly-traded mutual funds that include investments ranging from equities to money market instruments. The fair values are based on quoted market prices for identical assets.
Commodity Derivative Instruments Our commodity derivative instruments consist of variable to fixed price commodity swaps, two-way and three-way collars and basis swaps. We estimate the fair values of these instruments using a discounted cash flow method based on published forward commodity price curves as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. In addition, for collars, we estimate the option values of the put options sold (for three-way collars) and the contract floors and ceilings (for two-way and three-way collars) using an option pricing model which takes into account market volatility, market prices and contract terms. See Note 10. Derivative Instruments and Hedging Activities.
Interest Rate Derivative Instrument We estimate the fair values of forward starting swaps using a discounted cash flow method based on published interest rate yield curves as of the date of the estimate. The fair values of interest rate derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of interest rate derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. As of December 31, 2011 there were no outstanding interest rate derivative instruments. 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.
Noble Energy, Inc.
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 master netting agreements that allow us to settle asset and liability positions with the same counterparty.
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.
See Note 3. Acquisitions and Divestitures for a discussion of the methods and assumptions used to estimate the fair values of the acquired assets.
Asset Impairments Information about impaired assets as of the date of the assessment is as follows:
(1)
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 date of assessment.
See Note 4. Asset Impairments for a discussion of the methods and assumptions used to estimate the fair values of the impaired assets.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Additional Fair Value Disclosures
Debt The fair value of fixed-rate debt is estimated based on the published market prices for the same or similar issues. The carrying amount of floating-rate debt approximates fair value because the interest rates paid on such debt are set for periods of three months or less. The carrying amounts of the CONSOL installment payments approximate fair value because they have been discounted at the prevailing market rates for similar instruments. See Note 12. Long-Term Debt.
Fair value information regarding our debt is as follows:
(1)
Excludes Aseng FPSO lease obligation.
Note 17. Earnings Per Share
The following table summarizes the calculation of basic and diluted earnings per share:
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 18. Segment Information
We have operations throughout the world and manage our operations by country. The following information is grouped into five components that are all primarily in the business of crude oil and natural gas exploration, development, and acquisition: the United States; West Africa (Equatorial Guinea, Cameroon and Senegal/Guinea-Bissau); Eastern Mediterranean (Israel and Cyprus); the North Sea (UK and the Netherlands); and Other International and Corporate. Other International includes China, Ecuador (through May 2011), and new ventures.
(1)
Revenues from third parties for all foreign countries, in total, were $1.6 billion in 2011, $1.0 billion in 2010, and $791 million in 2009.
(2)
Long-lived assets located in all foreign countries, in total, were $3.5 billion, $2.4 billion, and $1.6 billion at December 31, 2011, 2010, and 2009, respectively.
(3)
Revenues through 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.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 19. Concentration of Risk
Concentration of Market Risk The largest single non-affiliated purchasers of our production were as follows:
We believe the loss of any one purchaser would not have a material effect on our financial position or results of operations since there are numerous potential purchasers of our production.
Concentration of Credit Risk Certain of our financial instruments, including cash equivalents, trade and joint interest receivables and derivative instruments, may expose us to credit risk. 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, 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.
Note 20. Additional Shareholders’ Equity Information
Activity in shares of our common stock and treasury stock was as follows:
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Accumulated other comprehensive loss in the shareholders’ equity section of the balance sheet included:
All amounts in the table above are reported net of tax. The effective income tax rate applied to AOCL was 37.6% at December 31, 2008 and 35.0% at December 31, 2009, 2010 and 2011.
Note 21. Commitments and Contingencies
Legal Proceedings We are involved in various legal proceedings in the ordinary course of business. These proceedings are subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters and we believe that the ultimate disposition of such proceedings will not have a material adverse effect on our financial position, results of operations or cash flows.
During 2011, we received two Notices of Alleged Violation (NOAV) from the COGCC regarding the reporting of the presence of hydrogen sulfide to the COGCC and local government designee within certain areas of our Piceance Basin and Grover field operations. At this time, the COGCC has not established a proposed penalty for either NOAV. Given the inherent uncertainty in administrative actions of this nature, we are unable to predict the ultimate outcome of this action at this time. However, we believe that the resolution of these proceedings through settlement or adverse judgment 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, 2011 Henry Hub natural gas price strip, we forecast our CONSOL Carried Cost Obligation will be suspended throughout the 2012 fiscal year and resume during first quarter of 2013. 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.
CONE MARC The CONE MARC, which we expect to total approximately $23 million in 2012, is included in transportation and gathering below. Amounts to be paid in years beyond 2012 have not yet been determined by the partners.
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 $31 million in 2011, $27 million in 2010, and $22 million in 2009.
Minimum commitments as of December 31, 2011 consist of the following:
(1)
Annual lease payments, net to our interest, exclude regular maintenance and operational costs, and began during fourth quarter of 2011 once the Aseng FPSO initiated producing operations. See Note 12. Long-Term Debt.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
In accordance with US GAAP for disclosures about oil and gas producing activities, and SEC rules for oil and gas reporting disclosures, we are making the following disclosures about our crude oil and natural gas reserves and exploration and production activities.
Reserves
There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Crude oil and natural gas 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, 2011, 2010, and 2009 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. Thus far in 2012, there have been significant declines in natural gas prices. Further significant declines in natural gas prices or significant declines in crude oil prices, could result in negative reserves revisions.
SEC and FASB Rule-Making Activity Effective December 31, 2009, we implemented the SEC’s final rules on the Modernization of Oil and Gas Reporting. The new rules included revisions designed to modernize the oil and gas company reserves reporting requirements.
The rule changes, including those related to pricing and technology, are included in our reserves estimates as of December 31, 2009, 2010 and 2011.
In addition, in 2010, the FASB issued ASU 2010-03, “Oil and Gas Reserve Estimation and Disclosures”, to provide consistency with the new SEC rules. ASU 2010-03 amended existing standards to align the reserves calculation and disclosure requirements under US GAAP with the requirements in the SEC rules. We adopted the new standards effective December 31, 2009. The new standards were applied prospectively as a change in estimate.
Impact of Implementation Implementation of the SEC’s updated rules resulted in the use of lower prices at December 31, 2009 for both oil and gas than would have resulted under the previous rules. Use of 12-month average pricing at December 31, 2009 as required by the updated rules resulted in a decrease in proved reserves of approximately 27 MMBoe. Use of year-end prices as required by the previous rules would have resulted in an increase in proved reserves of approximately 34 MMBoe at December 31, 2009. Therefore, the total impact of the new price methodology was negative reserves revisions of 61 MMBoe. In addition, the new proved undeveloped reserves rules resulted in a reduction of proved reserves of approximately 18 MMBoe due to limiting proved undeveloped reserves locations to those scheduled to be drilled within the next five years. The majority of the reserves reclassified out of proved reserves were associated with the DJ Basin, where we maintain an extensive multi-year development program.
Because we use quarter-end reserves and add back current period production to calculate quarterly DD&A, adoption of the updated FASB standards had an impact on fourth quarter 2009 DD&A expense. We estimated the impact of using 12-month average commodity prices, as required by the updated standards, instead of year-end commodity prices, to be an increase in fourth quarter 2009 DD&A expense of approximately $16 million (or $0.06 per share).
Reserves Estimates Qualified petroleum engineers in our Houston and Denver offices prepare all reserves estimates for our different geographical regions. These reserves estimates are reviewed and approved by regional management and senior engineering staff with final approval by the Vice President - Strategic Planning, Environmental Analysis & Reserves and certain members of senior management. For additional information regarding our reserves estimation process and internal controls see Items 1. and 2. Business and Properties - Proved Reserves Disclosures - Internal Controls Over Reserves Estimates and Technologies Used in Reserves Estimation.
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, 2011. See Items 1. and 2. Business and Properties - Proved Reserves Disclosures.
Geographic Areas Our supplemental disclosures are grouped by geographic area and include the United States, Equatorial Guinea, Israel and Other International. Other International includes Ecuador (through November 24, 2010), North Sea, China, Senegal/Guinea-Bissau, Cameroon, Cyprus, Nicaragua, France and other new ventures, where applicable. Operations in Equatorial Guinea, China, Cyprus, and Senegal/Guinea-Bissau are conducted in accordance with the terms of PSCs. Operations in Cameroon are conducted in accordance with the terms of a PSC and a mining concession. Operations in other foreign locations are conducted in accordance with concession agreements, permits or licenses.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Definitions The following definitions apply to the terms used in the paragraphs above:
Reserves Estimate The determination of an estimate of a quantity of oil or gas reserves that are thought to exist at a certain date, considering existing prices and reservoir conditions.
Reserves Audit The process of reviewing certain of the pertinent facts interpreted and assumptions underlying a reserves estimate prepared by another party and the rendering of an opinion about the appropriateness of the methodologies employed, the adequacy and quality of the data relied upon, the depth and thoroughness of the reserves estimation process, the classification of reserves appropriate to the relevant definitions used, and the reasonableness of the estimated reserves quantities.
The following definitions apply to our categories of proved reserves:
Proved Oil and Gas Reserves Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
Developed Oil and Gas Reserves Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well.
Undeveloped Oil and Gas Reserves Proved undeveloped oil and gas reserves (PUDs) are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
For complete definitions of proved natural gas, natural gas liquids and crude oil reserves, refer to SEC Regulation S-X, Rule 4-10(a)(6), (22) and (31).
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Proved Oil Reserves (Unaudited) The following reserves schedule was developed by our qualified petroleum engineers and sets forth the changes in estimated quantities of proved crude oil reserves:
(1)
Other International includes the North Sea and China.
(2)
The 2009 negative revisions within the US are primarily due to performance revisions, the majority of which related to Main Pass (10 MMBbl) and reclassifications of PUDs to probable reserves as a result of the SEC’s new five year development rule (5 MMBbl), partially offset by higher year-end prices (10 MMBbl). The 2010 US revisions include the impacts of higher prices and additional NGLs 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 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.
(3)
The 2009 increase in proved reserves includes 20 MMBbl related to the ongoing development of Wattenberg, 11 MMBbl in the deepwater Gulf of Mexico for the Santa Cruz, Isabela and Swordfish fields, and 26 MMBbl in Equatorial Guinea for the Aseng field. The 2010 increase in US proved reserves relates to continuing development of onshore assets, primarily in the 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.
(4)
The 2010 increase relates to the DJ Basin asset acquisition. See Note 3. Acquisitions and Divestitures.
(5)
We sold non-core, onshore US assets in the Mid-Continent and Illinois Basin in 2010. See Note 3. Acquisitions and Divestitures.
(6)
Equatorial Guinea production includes sales from the Alba field to the Alba LPG plant of 3 MMBbl in each of 2011, 2010, and 2009.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Proved Gas Reserves (Unaudited) The following reserves schedule was developed by our qualified petroleum engineers and sets forth the changes in estimated quantities of proved natural gas reserves:
(1)
Other International includes the North Sea, Ecuador (at December 31, 2009 and 2008), and China. See Note 3. Acquisitions and Divestitures and Note 4. Asset Impairments.
(2)
The 2009 negative revisions in the US are primarily due to lower year-end prices (224 Bcf), reclassifications of PUDs to probable reserves as a result of the SEC’s new five year development rule (75 Bcf), and increased lease operating expense and various well performance issues (98 Bcf). The 2010 US revisions are a combination of increases from higher natural gas prices, which were more than offset by gas shrinkage from additional NGLs 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 revisions in 2009 and 2010 are primarily due to additional production allowances related to LNG sales. Israel’s revisions in 2010 reflect a change in the likelihood that the Noa field will 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.
(3)
The 2009 increase in US proved reserves is primarily due to ongoing low-risk development programs onshore in Wattenberg, the Rocky Mountain area, and East Texas. The 2010 increase in US proved reserves is due to continuing development of onshore assets, primarily in the DJ Basin, Piceance Basin, and East Texas. The 2010 increase in Israel is due to the recording of initial reserves at the Tamar development. 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 have decided to develop.
(4)
The increase relates to our Marcellus Shale asset acquisition in 2011 and our DJ Basin asset acquisition in 2010. See Note 3. Acquisitions and Divestitures.
(5)
We sold non-core, onshore US assets in the Mid-Continent and Illinois Basin in 2010. Other International sales in 2010 include 160 Bcf due to the termination of the Block 3 PSC by the Ecuadorian government.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Results of Operations for Oil and Gas Producing Activities (Unaudited) Aggregate results of operations for crude oil and natural gas producing activities are as follows:
(1)
Other International includes the North Sea, Ecuador (through November 24, 2010), China, Cameroon, Cyprus, Senegal/Guinea-Bissau, Nicaragua, France 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)
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.
(4)
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 the North Sea, Ecuador (through November 24, 2010), China, Cameroon, Cyprus, Senegal/Guinea-Bissau, Nicaragua, France 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, $352 million related to the DJ Basin asset acquisition in 2010 and a $6 million downward purchase price adjustment related to the Mid-Continent acquisition in 2009.
(4)
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 Profound block), $31 million related to additional acreage in the DJ Basin and $58 million related to other onshore US in 2011; $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 in 2010; $56 million for deepwater Gulf of Mexico lease blocks and the remainder primarily for other onshore US lease acquisitions in 2009.
(5)
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. 2009 exploration costs include drilling and completion costs of $57 million in deepwater Gulf of Mexico, $19 million in Equatorial Guinea and $71 million in Israel.
(6)
Worldwide development costs include amounts spent to develop PUDs of approximately $1.4 billion in 2011, $1.1 billion in 2010 and $440 million in 2009. Equatorial Guinea development costs include non-cash accruals related to estimated construction progress to date on an FSPO to be used in the development of the Aseng field of $66 million in 2011, $266 million in 2010 and $29 million in 2009. These capitalized costs are included in development costs as the Aseng FPSO is constructed. US development costs include increases in asset retirement obligations of $115 million in 2011, $15 million in 2010, and $11 million in 2009. Other international development costs include increases in asset retirement obligations of $13 million in 2011, $2 million in 2010, and $5 million in 2009.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Capitalized Costs Relating to Oil and Gas Producing Activities (Unaudited) Aggregate capitalized costs relating to crude oil and natural gas producing activities are as follows:
(1)
Unproved oil and gas properties includes $874 million, including $792 million for Marcellus Shale at December 31, 2011, and $304 million at December 31, 2010, remaining from the allocation of costs to unproved properties acquired in previous acquisitions.
(2)
Proved oil and gas properties include asset retirement costs of $310 million and $208 million at December 31, 2011 and 2010, respectively.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited) The following information is based on our best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows in accordance with US GAAP for extractive activities. The standards require the use of a 10% discount rate. This information is not the fair value nor does it represent the expected present value of future cash flows of our proved oil and gas reserves.
(1)
Other International includes the North Sea, Ecuador (at December 31, 2009), and China. See Note 3. Acquisitions and Divestitures.
(2)
The standardized measure of discounted future net cash flows does not include cash flows relating to anticipated future methanol sales.
(3)
Production costs include oil and gas lease operating expense, production and ad valorem taxes, transportation expense and general and administrative expense supporting oil and gas operations.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Prices and Other Assumptions in Discounted Future Net Cash Flows (Unaudited) Future cash inflows are computed by applying a 12-month average commodity price, adjusted for location and quality differentials on a field-by-field basis, to year-end quantities of proved reserves, except in those instances where fixed and determinable price changes are provided by contractual arrangements at year-end. The discounted future cash flow estimates do not include the effects of derivative instruments. Average prices per region are as follows:
(1)
Other International includes the North Sea, Ecuador (at December 31, 2009), and China. 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 2011 would change the discounted future net cash flows before income taxes by approximately $214 million. We estimate that a $0.10 per Mcf change in the average price of natural gas from the 12-month average price for 2011 would change the discounted future net cash flows before income taxes by approximately $221 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 $2.4 billion in 2012, $1.3 billion in 2013 and $1.0 billion in 2014.
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.
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 2011 included the following:
·
$8 million asset 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:
·
$143 million gain on commodity derivative instruments, including unrealized mark-to-market gain of $142 million (See Note 10. Derivative Instruments and Hedging Activities);
·
$25 million pre-tax gain on divestitures due to the completed transfer of assets and exit from Ecuador (See Note 3. Acquisitions and Divestitures); and
·
$131 million asset impairment charges (See Note 4. Asset Impairments).
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 loss of $162 million (See Note 10. Derivative Instruments and Hedging Activities).
(2)
First quarter 2010 included the following:
·
$145 million gain on commodity derivative instruments, including unrealized mark-to-market gain of $147 million (See Note 10. Derivative Instruments and Hedging Activities).
Second quarter 2010 included the following:
·
$96 million gain on commodity derivative instruments, including unrealized mark-to-market gain of $63 million (See Note 10. Derivative Instruments and Hedging Activities); and
·
$26 million rig contract termination expense due to the Deepwater Moratorium.
Third quarter 2010 included the following:
·
$38 million gain on commodity derivative instruments, including unrealized mark-to-market gain of $5 million (See Note 10. Derivative Instruments and Hedging Activities);
·
$114 million gain on sale of non-core onshore US assets (See Note 3. Acquisitions and Divestitures); and
·
$100 million asset impairment charges (See Note 4. Asset Impairments).
Fourth quarter 2010 included the following:
·
$122 million loss on commodity derivative instruments, including unrealized mark-to-market loss of $145 million (See Note 10. Derivative Instruments and Hedging Activities); and
·
$44 million asset impairment charges (See Note 4. Asset Impairments).
(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 and September 30, 2011 exclude deferred compensation gains of $4 million and $12 million, respectively, net of tax, and for the three months ended June 30, 2010 excludes a deferred compensation gain of $9 million, net of tax.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
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, 2011. 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
None.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
The information required by this item is incorporated herein by reference to the 2012 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2011.
Item 11. Executive Compensation
The information required by this item is incorporated herein by reference to the 2012 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2011.
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 2012 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2011.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this item is incorporated herein by reference to the 2012 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2011.
Item 14. Principal Accounting Fees and Services
The information required by this item is incorporated herein by reference to the 2012 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2011.
PART IV
Item 15. Exhibits, Financial Statements Schedules
a) The following documents are filed as a part of this report:
(3)
Exhibits: The exhibits required to be filed by this Item 15 are set forth in the Index to Exhibits accompanying this report.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
NOBLE ENERGY, INC.
(Registrant)
Date: February 9, 2012
By: /s/ Charles D. Davidson
Charles D. Davidson,
Chairman of the Board,
Chief Executive Officer and Director
Date: February 9, 2012
By: /s/ Kenneth M. Fisher
Kenneth M. Fisher,
Senior Vice President, Chief Financial Officer
Date: February 9, 2012
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 9, 2012
Charles D. Davidson
Chief Executive Officer and Director
(Principal Executive Officer)
/s/ Kenneth M. Fisher
Senior Vice President, Chief Financial Officer
February 9, 2012
Kenneth M. Fisher
(Principal Financial Officer)
/s/ Dustin A. Hatley
Vice President, Chief Accounting Officer and Controller
February 9, 2012
Dustin A. Hatley
(Principal Accounting Officer)
/s/ Jeffrey L. Berenson
Director
February 9, 2012
Jeffrey L. Berenson
/s/ Michael A. Cawley
Director
February 9, 2012
Michael A. Cawley
/s/ Edward F. Cox
Director
February 9, 2012
Edward F. Cox
/s/ Thomas J. Edelman
Director
February 9, 2012
Thomas J. Edelman
/s/ Eric P. Grubman
Director
February 9, 2012
Eric P. Grubman
/s/ Kirby L. Hedrick
Director
February 9, 2012
Kirby L. Hedrick
/s/ Scott D. Urban
Director
February 9, 2012
Scott D. Urban
/s/ William T. Van Kleef
Director
February 9, 2012
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.