NOBLE ENERGY INC
Item 1A.
Risk Factors
Item 1B.
Unresolved Staff Comments
Item 3. Legal Proceedings
West Virginia Matter In March 2013, we received seven Notices of Violation (NOV) and two Administrative Orders (Orders) from the West Virginia Department of Environmental Protection Office of Oil and Gas (OOG) regarding the unintentional discharge of a mixture of freshwater and produced water that occurred on or about the evening of February 22, 2013 from one of our permitted water storage facilities in Marshall County, West Virginia. At this time, the OOG has not established a proposed penalty for these NOVs or Orders. Given the 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.
Colorado Matter In July 2013, we received a proposed Compliance Order on Consent (COC) from Colorado Department of Public Health and Environment's Air Pollution Control Division to resolve allegations of noncompliance with our 2012 Ozone Season submissions pursuant to Air Quality Control Commission Regulation 7. The COC sought payment of a reduced penalty of $156,450. On August 7, 2013, we accepted the reduced penalty and executed the COC. Under the terms and conditions of the COC, we agreed to pursue a supplemental environmental project (SEP) to mitigate $125,160 of the total penalty and submitted payment of $31,290 as an administrative penalty. On November 26, 2013, we provided $125,160 to the American Lung Association of Colorado to serve as funding for the development and implementation of its Clear the Air Challenge, which is a pollution prevention and environmental education program that focuses on the reduction and/or elimination of pollutants, to help preserve the region's air quality through conservation of transportation related energy. All penalties associated with this matter have now been paid.
See Item 8. Financial Statements and Supplementary Data - Note 18. Commitments and Contingencies.
Item 4. Mine Safety Disclosures
Not Applicable.
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Common Stock Our common stock, $0.01 par value, is listed and traded on the NYSE under the symbol “NBL.” The declaration and payment of dividends will be determined on a quarterly basis and 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:
(1) Amounts adjusted for the 2-for-1 stock split which occurred during the second quarter of 2013.
On January 28, 2014, the Board of Directors declared a quarterly cash dividend of $0.14 per common share, which will be paid February 24, 2014 to shareholders of record on February 10, 2014.
Transfer Agent and Registrar The transfer agent and registrar for our common stock is Wells Fargo Bank, N.A., 1110 Centre Pointe Curve, Suite 101 Mendota Heights, MN 55120.
Stockholders’ Profile Pursuant to the records of the transfer agent, as of January 13, 2014, the number of holders of record of our common stock was 623.
Stock Repurchases The following table summarizes repurchases of our common stock occurring fourth quarter 2013.
(1) Stock repurchases during the period related to stock received by us from employees for the payment of withholding taxes due on shares of restricted stock issued under our 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, 2013.
Stock Performance Graph This graph shows our cumulative total shareholder return over the five-year period from December 31, 2008 to December 31, 2013. The graph also shows the cumulative total returns for the same five-year period of the S&P 500 Index, an old peer group of companies and a new peer group of companies. The cumulative total return of the common stock of our old and new peer groups of companies includes the cumulative total return of our common stock.
The companies in the old peer group consisted of the following:
Anadarko Petroleum Corp.
Murphy Oil Corp.
Apache Corp.
Newfield Exploration Company
Cabot Oil & Gas Corp.
Noble Energy, Inc.
Chesapeake Energy Corp.
Pioneer Natural Resources Company
Continental Resources, Inc.
Plains Exploration and Production Company
Devon Energy Corp.
Range Resources Corp.
EOG Resources, Inc.
Southwestern Energy Company
Marathon Oil Corporation
On January 28, 2013, the Compensation, Benefits and Stock Option Committee of the Board of Directors (the Committee) made changes to our compensation peer group to remove Plains Exploration and Production Company from the old peer group listed above after being acquired by a global mining company, and add Hess Corporation, which is a US company listed on the NYSE with a balance of projects similar in size and scope to ours. After the change in companies, the 2013 compensation peer group consisted of the following:
Anadarko Petroleum Corp.
Marathon Oil Corporation
Apache Corp.
Murphy Oil Corp.
Cabot Oil & Gas Corp.
Newfield Exploration Company
Chesapeake Energy Corp.
Noble Energy, Inc.
Continental Resources, Inc.
Pioneer Natural Resources Company
Devon Energy Corp.
Range Resources Corp.
EOG Resources, Inc.
Southwestern Energy Company
Hess Corporation
The comparison assumes $100 was invested on December 31, 2008 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.
*$100 invested on 12/31/08 in stock or index, including reinvestment of dividends. Fiscal year ending December 31.
Copyright© 2014 S&P, a division of The McGraw-Hill Companies Inc. All rights reserved.
Item 6. Selected Financial Data
(1)
Amounts adjusted for the 2-for-1 stock split which occurred during the second quarter of 2013.
(2)
Prices through 2010 include effects of oil and gas cash flow hedging activities.
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. We use common industry terms, such as thousand barrels of oil equivalent per day (MBoe/d) and million cubic feet equivalent per day (MMcfe/d), to discuss production and sales volumes. Our MD&A is presented in the following major sections:
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Executive Overview;
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Operating Outlook;
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Results of Operations;
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Proved Reserves;
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Liquidity and Capital Resources; and
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Critical Accounting Policies and Estimates.
The accompanying consolidated financial statements, including the notes thereto, contain detailed information that should be read in conjunction with our MD&A.
EXECUTIVE OVERVIEW
Strategy We are a worldwide producer of crude oil and natural gas. We aim to achieve sustainable growth in value and cash flow through exploration success and the development of a high-quality, diversified, portfolio of assets with investment flexibility between: onshore unconventional developments and offshore organic exploration leading to major development projects; US and international projects; and production mix among crude oil, natural gas, and NGLs. We focus our efforts in five core operating areas: the DJ Basin and Marcellus Shale (onshore US), deepwater Gulf of Mexico, offshore West Africa, and offshore Eastern Mediterranean, where we have strategic competitive advantage and which we believe generate superior returns. We also seek to enter potential new core areas.
2013 Results In pursuit of our strategy, we progressed our exploration program during 2013 with discoveries of new resources at Karish and Tamar Southwest (offshore Israel), Troubadour and Dantzler (deepwater Gulf of Mexico) as well as drilling successful appraisal wells at Leviathan (offshore Israel), Gunflint (deepwater Gulf of Mexico) and offshore Cyprus.
The continuous growth of our development program has propelled consolidated average sales volumes to 265 MBoe/d for 2013. During the year, we delivered two new major offshore development projects within the budgeted cost and timeline. Our growth is driven by our five core areas which will provide for future growth in the years ahead.
Our accelerated horizontal production in the DJ Basin and ramp up of our Marcellus Shale drilling program continue to generate new production records. The outstanding results of these core areas are the product of efficiency gains and operational expertise in each basin.
In the DJ Basin, we have increased 2013 daily production by 23%, as compared with 2012, through realizing economies of scale through our utilization of integrated development plans that allow us to optimize ultimate resource recovery while decreasing our capital and lease operating costs as well as surface and environmental impact. Additionally, the expansion of our extended reach lateral well program and successful downspacing are further increasing our hydrocarbon recoveries. Our recently completed acreage exchange with another operator in the Basin has provided large contiguous acreage blocks and will allow us to optimize drilling, production and gathering activities for the asset.
In the Marcellus Shale, daily production in 2013 increased over 60% as compared with 2012, largely fueled by leveraging best practices in drilling and completions. For example we have obtained fit-for-purpose rigs and seen substantial cost improvement. During 2013, we increased our drilling activity and brought seven new multi-well pads online. We also expanded our acreage position by acquiring drilling rights to approximately 90,000 gross acres.
Our international assets contributed substantially with world-class reliability from our major projects in both the Eastern Mediterranean and West Africa. Two major projects, Tamar (offshore Israel) and Alen (offshore West Africa), were completed during 2013 and began producing ahead of the sanctioned project schedule. Natural gas from the Tamar field flows through the world's longest subsea tieback, more than 90 miles to the Tamar platform and then to the Ashdod onshore terminal before being sold into the domestic Israeli energy market. Condensate from the Alen field utilizes the Aseng FPSO as a regional hub for storage and offloading to the global market. Tamar and Alen are technical and commercial milestones that significantly contributed to our 14% year over year consolidated production growth.
Our deepwater Gulf of Mexico program is progressing as we sanctioned both Big Bend (phase one of our Rio Grande development) and Gunflint during 2013. We expect that these two major projects will utilize existing host facilities via subsea tiebacks and provide new production in late 2015 and 2016, respectively. We also expect to sanction our Dantzler discovery in 2014. Dantzler will likely include a subsea tieback, potentially leveraging the Big Bend subsea infrastructure. Our Galapagos development, which began production in 2012, continues to perform well.
Our 2013 financial results included:
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net income of $978 million (including $907 million from continuing operations), as compared with $1.0 billion (including $965 million from continuing operations) for 2012;
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gain on divestitures of $36 million, as compared with $154 million for 2012;
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dry hole cost of $149 million, as compared with $155 million for 2012;
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asset impairment charges of $86 million, as compared with $104 million for 2012;
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loss on commodity derivative instruments of $133 million (including unrealized mark-to-market loss of $131 million), as compared with $75 million gain on commodity derivative instruments (including unrealized mark-to-market gain of $109 million) for 2012;
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diluted earnings per share of $2.69, as compared with $2.86 for 2012;
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cash flows provided by operating activities of $2.9 billion, as compared with $2.9 billion in 2012;
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capital spending on a cash basis of $3.9 billion, as compared with $3.7 billion in 2012;
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ending cash and cash equivalents balance of $1.1 billion at December 31, 2013, as compared with $1.4 billion at December 31, 2012;
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issuance of $1.0 billion of 30-year unsecured notes;
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proceeds of $327 million from sales of non-core properties and an acreage exchange, as compared with sales proceeds of $1.2 billion in 2012;
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total liquidity of $5.1 billion at December 31, 2013, consisting of year-end cash balance plus funds available under our Credit Facility, as compared with $5.4 billion at December 31, 2012; and
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year-end ratio of debt-to-book capital of 35%, as compared with 33% at December 31, 2012.
Divestitures Our non-core divestiture program is designed to generate organizational and operational efficiencies as well as cash for use in our capital investment program. Divestitures of non-core properties allow us to allocate capital and employee resources to high-value and high-growth areas. Further, proceeds from divestitures provide additional flexibility in the implementation of our international and deepwater Gulf of Mexico exploration and development programs and our horizontal drilling activities in the DJ Basin and Marcellus Shale. Sales of non-core properties, including onshore US and North Sea properties, generated proceeds of approximately $1.4 billion during the last two years, including $206 million during 2013. See Item 8. Financial Statements and Supplementary Data - Note 3. Property Transactions.
Sales Volumes The execution of our business strategy, including production start-up at our Tamar and Alen projects and accelerated activity in onshore US unconventional projects, has delivered well diversified production growth . On a BOE basis, total sales volumes from continuing operations were 14% higher in 2013 as compared with 2012, and our mix of sales volumes in 2013 was 43% global crude oil and NGLs, 29% international natural gas, and 28% US natural gas. See Results of Operations - Revenues, below.
Commodity Price Changes and Hedging Although crude oil, natural gas and NGL prices have historically exhibited significant volatility, the markets remained relatively stable during 2013. Domestic crude oil prices rose steadily into the summer, followed by a few months of decline towards the end of the year, but finished 2013 with modest growth compared to 2012 year-end prices. Total consolidated average realized crude oil prices for 2013 decreased 1% as compared with 2012, due to slight declines in Brent pricing. In the US domestic natural gas pricing continues to improve. Natural gas prices rose sharply early in the year, followed by a steady decline during the summer months, followed by steadily rising prices over the fourth quarter as below normal temperatures across the US increased consumption. US average realized natural gas prices for 2013 increased 36% as compared with 2012.
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 2014 and 2015. 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, which equal cash settlements during the period, 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. Unrealized mark-to-market gains or losses recognized in the current period will be realized in the future when they are settled in cash at maturity date. 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 8. Derivative Instruments and Hedging Activities.
Asset Impairment Charges During 2013, we recorded impairment charges of $86 million primarily related to our Mari-B field, offshore Israel, due to natural field decline, and certain non-core onshore US properties divested during the year and assets held for sale at December 31, 2013. See Item 8. Financial Statements and Supplementary Data - Note 4. Asset Impairments.
OPERATING OUTLOOK
2014 Outlook Global crude oil and US natural gas prices are historically volatile based on supply and demand dynamics. We expect global crude oil production volumes to continue to grow, primarily due to increases in the US supply from continued application of horizontal drilling technology. This growth coupled with potential supply in North Africa and the Middle East returning to the market may result in an increase in OPEC spare production capacity, a key determinant of global crude oil prices. Meanwhile, political risk in key producer nations remains high and numerous producer nations have significant crude oil supply offline. North African and Middle East conflicts, civil unrest, and other potential supply interruption risks are likely to continue and can have a significant impact on crude oil supplies. Meanwhile, global crude oil demand is expected to grow in 2014 as the global economy continues to expand. Global crude oil prices will be determined by these supply and demand factors. In the US, de-bottlenecking of oil transportation routes in the Mid-Continent will increase Gulf Coast supply; as a result, we may see continued volatility among US grades and discount pricing compared with Brent.
In the US, we expect natural gas prices to be range-bound as supply continues to grow, particularly in the northeast from Marcellus Shale and Utica Shale production, and new sources of industrial, power and other demand come on line over the next several years. Longer term, the amount of LNG export capacity approved, sanctioned for investment and built will also be a market consideration.
Because the global economic outlook and commodity price environment are uncertain, we have built a strong liquidity position to ensure financial flexibility. We have also planned a flexible capital spending program coupled with our commodity hedging programs, which will support both major project development and exploration activities in a volatile commodity price environment. See 2014 Capital Investment Program, below.
2014 Production Our expected crude oil, natural gas and NGL production for 2014 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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changes to drilling plans in the DJ Basin and the Marcellus Shale;
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Israeli demand for electricity, which affects demand for natural gas as fuel for power generation and industrial market growth, and which is impacted by unseasonable weather;
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variations in West Africa crude oil and condensate sales volumes due to potential Aseng FPSO downtime and timing of liftings, and variations in natural gas sales volumes related to potential downtime at the methanol, LPG and/or LNG plants;
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natural field decline in the deepwater Gulf of Mexico and non-core onshore US areas and the Alba and Aseng fields offshore Equatorial Guinea;
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potential weather-related volume curtailments due to hurricanes in the deepwater Gulf of Mexico, heat in the Rocky Mountain area of our US operations, or winter storms and flooding in the DJ Basin, Marcellus Shale and/or Rocky Mountain areas;
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reliability of support equipment and facilities and/or potential pipeline and processing facility capacity constraints which may cause restrictions or interruptions in production and/or mid-stream processing;
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potential shut-in of US producing properties if storage capacity becomes unavailable;
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potential drilling and/or completion permit delays due to future regulatory changes; and
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potential purchases of producing properties or divestments of non-core operating assets.
2014 Capital Investment Program Total capital expenditures are estimated at $4.8 billion for 2014. We expect to invest $3.2 billion, or approximately 70% of the program, in onshore US development and $1.5 billion, or approximately 30% of the program, in global deepwater activities.
The 2014 capital investment program is anticipated to exceed operating cash flows and is expected to be funded from cash flows from operations, cash on hand, and borrowings under our Credit Facility and/or other financing such as an issuance of long-term debt. Funding may also be provided by proceeds from divestment of non-core assets and farming out working interests in exploration prospects. See Liquidity and Capital Resources - Financing Activities.
We will evaluate the level of capital spending and remain flexible throughout the year based on the following factors, among others:
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commodity prices, including price realizations on specific crude oil and natural gas production including the impact of NGLs;
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cash flows from operations;
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operating and development costs and possible inflationary pressures;
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permitting activity in the deepwater Gulf of Mexico;
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drilling results;
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CONSOL Carried Cost Obligation (See Liquidity and Capital Resources - Off-Balance Sheet Arrangements);
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property acquisitions and divestitures;
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increase in exploration activities in new areas, including offshore Sierra Leone and the Falkland Islands;
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availability of financing;
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potential legislative or regulatory changes regarding the use of hydraulic fracturing;
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potential changes in the fiscal regimes of the US and other countries in which we operate; and
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impact of new laws and regulations, including implementation of the Dodd-Frank Wall Street Reform and Consumer Protection Act, which has resulted in significant derivatives regulations and disclosure requirements, on our business practices.
Exploration Program We continue to evaluate and build upon our significant exploration inventory in the onshore US, deepwater Gulf of Mexico, offshore West Africa, offshore Eastern Mediterranean and other international locations. During 2013, we drilled successful exploratory wells at Troubadour and Dantzler in the deepwater Gulf of Mexico, as well as Karish and Tamar Southwest offshore Israel.
We continually evaluate our exploration inventory to provide additional growth opportunities and potential new core areas. In addition, each of our existing core areas has significant remaining exploration upside. We continue to leverage existing activities to improve our exploratory programs in these core areas.
We devote significant capital to our exploration program. Approximately 10% of our $4.8 billion capital investment program in 2014 is dedicated to exploration and associated appraisal activities. However, we do not always encounter hydrocarbons through our drilling activities. In addition, we may find hydrocarbons but subsequently reach a decision, through additional analysis or appraisal drilling, that a project is not economically or operationally viable. For example, during 2013 we drilled the Paraiso-1 exploratory well, offshore Nicaragua, which did not encounter commercial quantities of hydrocarbons.
We are currently conducting, or planning to conduct, exploratory drilling activities in previously unexplored areas as well as appraisal activities at several of our discoveries. In the event we conclude that one of our exploratory wells did not encounter hydrocarbons or that a discovery is not economically or operationally viable, the associated capitalized exploratory well costs would be charged to expense. Additionally, we may not conduct exploration activities prior to lease expirations. For example, in the deepwater Gulf of Mexico, while we continue to mature our prospect portfolio, regulations have become more stringent due to the Deepwater Horizon incident in 2010. In some instances, specifically engineered blowout preventers, rigs, and completion equipment may be required for high pressure environments. Regulatory requirements or lack of readily available equipment could prevent us from engaging in future exploration activities during our current lease terms. As a result, in a future period, dry hole cost and/or leasehold impairment charges could be significant. See Results of Operations - Oil and Gas Exploration Expense, below. See also Item 1A. Risk Factors.
Major Development Project Inventory Our current inventory of major development projects includes the horizontal Niobrara, Marcellus Shale, Diega and Carla, Gunflint, Rio Grande (Big Bend and Dantzler), Leviathan, Tamar Expansion, Tamar Southwest, and Cyprus. These projects will require significant capital investments.
As noted above, we expect to spend substantial amounts on our major development projects in 2014. We plan to fund these projects from cash flows from operations, borrowings under our Credit Facility, proceeds from divestments of non-core assets, cash on hand, and/or other financing.
The additional production from our major development projects brought online since 2011 has begun generating significant cash flow which is being utilized to meet a substantial portion of capital requirements. See Liquidity and Capital Resources - Capital Structure/Financing Strategy.
As operator on the majority of our development projects, we pay gross joint venture expenses and make cash calls on our nonoperating partners for their respective shares of joint venture costs. These projects are capital cost intensive and a nonoperating partner may experience a delay in obtaining financing for its share of the joint venture costs. In addition, some of our joint venture partners, including our partners in our Eastern Mediterranean projects, may not be as creditworthy as we are and may experience liquidity problems. This could result in a delay in our receiving reimbursement of joint venture costs and increases our counterparty credit risk. See Item 1A. Risk Factors.
Potential for Future Asset Impairments We recorded asset impairment charges of $86 million during 2013. A decline in future crude oil or natural gas prices could result in additional impairment charges. The cash flow model that we use to assess proved properties for impairment includes numerous assumptions, such as management’s estimates of future crude oil and natural gas production, market outlook on forward commodity prices, operating and development costs, and discount rates. All inputs to the cash flow model must be evaluated at each date of estimate. However, a decrease in forward crude oil or natural gas prices alone could result in impairment.
We are currently marketing certain non-core onshore US properties. If the properties are reclassified as assets held for sale, they will be valued at the lower of net book value or anticipated sales proceeds less costs to sell. Impairment expense would be
recorded for any excess of net book value over anticipated sales proceeds less costs to sell. In addition, we would allocate a portion of goodwill to any non-core onshore US property held for sale that constitutes a business, which could potentially decrease any gain or increase any loss recorded on the sale. Goodwill write-offs result in an increase in our effective tax rate because goodwill is nondeductible for US federal income tax purposes.
Occasionally, well mechanical problems arise, which can reduce production and potentially result in reductions in proved reserves estimates. For example, our South Raton development in the deepwater Gulf of Mexico is currently shut-in due to mechanical issues. We are currently testing the well to determine appropriate remediation efforts. South Raton had a net book value of approximately $117 million at December 31, 2013.
See Item 1A. Risk Factors and Item 8. Financial Statements and Supplementary Data - Note 4. Asset Impairments.
Climate Change The matter of climate change has become the subject of a significant public policy debate. While climate change remains a complex issue, some scientific research suggests that an increase in greenhouse gas emissions (GHGs) may pose a risk to the environment.
The oil and natural gas exploration and production industry is a source of certain GHGs, namely carbon dioxide and methane, and future restrictions on the combustion of hydrocarbons 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 hydrocarbons lies in the uncertainty of government-imposed climate change legislation, including cap and trade schemes, carbon taxes, and regulations that may affect us, our suppliers, and our customers. The cost of meeting these requirements may have an adverse impact on our financial condition, results of operations and cash flows, and could reduce the demand for our products.
In June 2013, President Obama unveiled a Presidential climate change action plan designed to reduce carbon emissions in the US, prepare the US for potential climate change impacts, and lead international efforts to address potential global climate change. The plan, among other things, aims to: establish carbon emission standards for both new and existing power plants; support renewable energy projects and innovative technologies; set new energy efficiency standards for appliances and federal buildings; develop fuel economy standards for heavy-duty vehicles; reduce hydrofluorocarbons; develop a comprehensive methane strategy; update certain flood-risk reduction standards for all federally funded projects; and expand major new and existing international initiatives, including bilateral initiatives with China, India, and other major carbon emitting countries.
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. Parties have agreed to a second commitment period of the Kyoto Protocol which will last until December 31, 2020.
While no specific new international climate change accord has been adopted that would affect our operating locations, the current state of development of many initiatives makes it difficult to assess the timing or effect of any pending discussions of future accords or predict with certainty the future costs that we may incur in order to comply with future international treaties or regulations.
Indirect Consequences of Regulation or Business Trends We believe there are both risks and opportunities arising from the global response to potential climate change. 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, sales of natural gas comprised approximately 55% of our 2013 total sales volumes from continuing operations. The burning of natural gas produces lower levels of emissions than other readily available fuels such as liquid hydrocarbons and coal. In addition, public concern about nuclear safety has increased. These factors could increase the demand for natural gas as fuel for power generation. Also, 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, future GHG standards for vehicles, could result in the use of natural gas as transportation fuel. This may also increase the market demand for natural gas. See also Items 1. and 2. Business and Properties - Regulations and Item 1A. Risk Factors.
RESULTS OF OPERATIONS
In the discussion below, prior year amounts have been reclassified to reflect the North Sea segment as discontinued operations. See Discontinued Operations, below. Financial information presented is from continuing operations, unless otherwise noted.
Selected financial information is as follows:
See following discussion for explanation of year-to-year changes.
Revenues
Oil, Gas and NGL Sales An analysis of the factors contributing to the changes in revenues from sales of crude oil, natural gas and NGLs is as follows:
Changes in revenue are discussed below.
Oil, Gas and NGL Sales Average daily sales volumes and average realized sales prices were as follows:
(1)
Natural gas from the Alba field in Equatorial Guinea is under contract for $0.25 per MMBtu to a methanol plant, an LPG plant and an LNG plant. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method of accounting.
(2)
Volumes represent sales of condensate and LPG from the Alba plant in Equatorial Guinea. See Income from Equity Method Investees below.
Crude Oil and Condensate Sales Revenues from crude oil and condensate sales increased by $413 million, or 13%, in 2013 as compared with 2012 due to the following:
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higher sales volumes of 14 MBoe/d in the DJ Basin attributable to the acceleration of our horizontal drilling program;
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the addition of sales volumes from Alen, offshore Equatorial Guinea, which began producing in late second quarter of 2013; and
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higher production at Galapagos due to continued strong performance and a full year online;
partially offset by:
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reduction in sales volumes due to the sales of non-core, onshore US properties during 2013;
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a 1% decrease in total consolidated average realized prices primarily due to increased supply;
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a volume reduction in West Africa due to natural field decline at Aseng; and
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natural field decline in non-core onshore US and deepwater Gulf of Mexico areas.
Revenues from crude oil and condensate sales increased by $1.2 billion, or 58%, in 2012 as compared with 2011 due to the following:
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higher sales volumes in the DJ Basin attributable to the acceleration of our horizontal drilling programs onshore US;
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commencement of production at Galapagos and South Raton in the deepwater Gulf of Mexico which increased production by approximately 7 MBoe/d, net, during 2012;
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higher sales volumes in Equatorial Guinea due to the commencement of oil production at Aseng during the fourth quarter of 2011, which impacted our sales volumes by approximately 21 MBbl/d, net, in 2012 as compared with 2011; and
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a 2% increase in total consolidated average realized prices primarily due to higher Brent pricing resulting from the global economic recovery;
partially offset by:
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reduction in sales volumes due to the sales of non-core, onshore US properties during the third quarter of 2012;
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a volume reduction in the Gulf of Mexico of nearly 7 MBoe/d as a result of shut-ins due to Hurricane Isaac; and
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natural field decline in non-core onshore US and deepwater Gulf of Mexico areas.
Natural Gas Sales Revenues from natural gas sales increased by $356 million, or 57%, in 2013 as compared with 2012 due to the following:
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increases in total consolidated average realized prices primarily due to increased demand from expectations of cooler weather and higher-than-expected inventory withdrawals;
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higher sales volumes in Israel from Tamar, which began production at the end of the first quarter of 2013 and contributed 153 Mmcf/d during 2013; and
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higher sales volumes in the DJ Basin (15 MMcf/d) and Marcellus Shale (49 MMcf/d) in 2013 primarily attributable to our horizontal drilling programs;
partially offset by:
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lower sales volumes due to our non-core onshore US divestiture program; and
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lower sales volumes due to natural field decline from Mari-B, Noa and Pinnacles, offshore Israel, which contributed a combined 56 Mmcf/d during 2013, compared with 101 Mmcf/d during 2012.
Revenues from natural gas sales decreased by $263 million, or 30%, in 2012 as compared with 2011 due to the following:
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decreases in US average realized prices primarily due to oversupply and above average levels of natural gas in storage;
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lower sales volumes due to the sales of non-core onshore US properties during the third quarter of 2012;
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lower sales volumes in the DJ Basin and Rocky Mountain area of our US operations due to third-party processing facility constraints;
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lower sales volumes from the Alba field, offshore Equatorial Guinea, due to scheduled maintenance activities at the non-operated Alba facilities; and
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lower sales volumes in Israel due to a reduction in the rate of production from the Mari-B field in order to manage the reservoir;
partially offset by:
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higher sales volumes attributable to the acceleration of our horizontal drilling programs in the DJ Basin; and
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new sales volumes from Marcellus Shale producing properties, which we acquired September 30, 2011 and current Marcellus Shale development activities, which added 90 MMcf/d, net to our sales volumes for 2012.
NGL Sales Most of our US NGL production is from the DJ Basin. NGL sales revenues increased $3 million, or 1%, during 2013 as compared with 2012 as a result of slightly higher realized prices and a slight increase in sales volumes.
NGL sales revenues decreased $50 million, or 19%, during 2012 as compared with 2011 as a result of lower realized prices offset by an increase in sales volumes. Our average realized prices declined 27% during 2012 compared with 2011 primarily due to higher supplies of NGLs resulting from increased wet gas drilling activities.
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 2013 as compared with 2012 primarily due to higher sales revenue from a 19% increase in average realized sales price of methanol.
Net income from AMPCO and affiliates decreased in 2012 as compared with 2011 primarily due to increased other non-operating expense.
Alba Plant Net income from Alba Plant in 2013 was consistent with 2012.
Net income from Alba Plant decreased slightly in 2012 as compared with 2011 due to lower realized price.
CONE Gathering LLC Under the terms of the gathering and marketing agreement that we entered into with CONE, we pay CONE a minimum annual revenue commitment (MARC). The fee is adjusted annually based on projected gathering volumes, operating expenses, capital expenditures, and other factors. Our share of CONE earnings are netted within our transportation and gathering expense. During 2013, we contributed $48 million to CONE. See Item 8. Financial Statements and Supplementary Data - Note 3. Property Transactions.
Operating Costs and Expenses
Operating costs and expenses were as follows:
Changes in operating costs and expenses are discussed below.
Production Expense Components of production expense were as follows:
N/M Amount is not meaningful. See (2) below.
(1)
Consolidated unit rates exclude sales volumes and costs attributable to equity method investees.
(2)
Other Int'l/Corporate includes China and unallocated expenses incurred at the corporate level.
(3)
Lease operating expense includes oil and gas operating costs (labor, fuel, repairs, replacements, saltwater disposal and other related lifting costs) and workover and repair expense.
Lease Operating Expense Lease operating expense increased in 2013 as compared with 2012 due to the following:
•
increases of $46 million in the DJ Basin and $4 million in the Marcellus Shale due to new wells coming on line and increased production;
•
an increase of $58 million in the deepwater Gulf of Mexico due to a full year of production at Galapagos, mechanical repairs at Swordfish, and other repair and maintenance expense;
•
operating expenses of $24 million related to the Tamar field, offshore Israel, which began producing at the end of first quarter 2013; and
•
operating expenses of $18 million related to the Alen field, offshore Equatorial Guinea, which began producing at the end of second quarter of 2013;
partially offset by:
•
a reduction of $52 million related to the sale of non-core, onshore US properties in 2012 and 2013.
Lease operating expense increased in 2012 as compared with 2011 due to the following:
•
higher sales volumes from the DJ Basin due to ongoing development activities accounted for an increase of $24 million in US lease operating expense;
•
new production at Galapagos and higher production handling costs at Swordfish, deepwater Gulf of Mexico, accounted for an increase of $22 million;
•
a full year of production from Marcellus Shale properties acquired in 2011, and additional development activity accounted for an increase of $17 million;
•
lease operating expense associated with the Aseng field, offshore Equatorial Guinea, which began producing in November 2011, accounted for an increase of $36 million; and
•
the start-up of the Noa and Pinnacles wells, offshore Israel, in second quarter of 2012 accounted for an increase of $8 million;
partially offset by:
•
lower volumes in the US due to the sale of non-core onshore US properties during the third quarter of 2012.
Production and Ad Valorem Tax Expense In the US, production and ad valorem taxes increased in 2013 as compared with 2012. An increase of approximately $52 million due to higher production volumes and higher average prices in the DJ Basin in 2013 was offset by a $10 million decrease primarily due to the sale of non-core, onshore US properties in 2012 and 2013.
Production and ad valorem tax expense increased in 2012 as compared with 2011 due to the enactment of the Pennsylvania well impact fee. This enactment increased taxes approximately $8 million, of which approximately $4 million related to wells spud prior to 2012. Additionally, higher volumes for the DJ Basin resulted in an increase of $15 million. This increase was offset by non-core onshore US property sales during 2012.
Transportation Expense Transportation expense increased in 2013 as compared with 2012 related to increases of $25 million in the DJ Basin and $14 million in the Marcellus Shale due to increased production from ongoing development activities.
Transportation expense increased in 2012 as compared with 2011 due to higher US crude oil sales volumes from the DJ Basin as a result of ongoing development activities resulted in an increase of $21 million. A full year of production from our Marcellus Shale producing properties, acquired on September 30, 2011, resulted in an increase of $8 million. These increases were offset by reductions in transportation expense due to non-core onshore US property sales during the third quarter of 2012.
Unit Rate Per BOE The unit rate of total production expense per BOE increased for 2013 as compared with 2012 primarily due to a change in the mix of production, including higher DJ Basin volumes, which has higher cost to operate than our Equatorial Guinea and Israel production.
The unit rate of total production expense per BOE increased for 2012 as compared with 2011 primarily due to a change in the mix of production, including new production at Galapagos and South Raton, and the start-up of the Noa and Pinnacles wells, each of which has a higher cost to operate than our other projects, and the enactment of the Marcellus Shale well impact fee.
Exploration Expense Components of exploration expense were as follows:
(1)
West Africa includes Equatorial Guinea, Cameroon, Sierra Leone, and Senegal/Guinea-Bissau, which we exited in 2012.
(2)
Eastern Mediterranean includes Israel and Cyprus.
(3)
Other International includes various international new ventures such as offshore Nicaragua and offshore Falkland Islands.
Oil and gas exploration expense increased in 2013 as compared with 2012. Expense for 2013 includes the following:
•
Other Int'l dry hole cost related to the Paraiso exploratory well, offshore Nicaragua, which did not find commercial quantities of hydrocarbons;
•
seismic expense related to the Gulf of Mexico lease sale and our exploration programs offshore Cyprus and offshore Falkland Islands; and
•
staff expense associated with new ventures and corporate expenditures.
Oil and gas exploration expense increased in 2012 as compared with 2011. Expense for 2012 includes the following:
•
US dry hole cost related primarily to the Deep Blue exploratory well (deepwater Gulf of Mexico);
•
West Africa dry hole cost related to the Trema exploratory well, offshore West Africa, which found noncommercial quantities of hydrocarbons;
•
exploration expense in West Africa includes $40 million for the non-operated AGC Profond block offshore Senegal/Guinea-Bissau, which was written off during the third quarter of 2012 when we decided not to proceed with additional appraisal activities;
•
seismic expenditures related to the deepwater Gulf of Mexico lease sale and international new ventures; and
•
exploration expense also includes staff expense associated with new ventures and corporate expenditures.
Exploration expense included stock-based compensation expense of $15 million in 2013, $12 million in 2012, and $11 million in 2011.
Depreciation, Depletion and Amortization DD&A expense was as follows:
(1)
DD&A expense includes accretion of discount on asset retirement obligations of $26 million in 2013, $22 million in 2012, and $13 million in 2011.
(2)
Consolidated unit rates exclude sales volumes and costs attributable to equity method investees.
Total DD&A expense increased for 2013 as compared with 2012 due to the following:
•
higher sales volumes due to increased development activity in the DJ Basin and Marcellus Shale accounted for increases of $218 million and $34 million, respectively;
•
higher production at Galapagos and a new well at Ticonderoga, deepwater Gulf of Mexico, resulted in additional DD&A expense of approximately $48 million;
•
the start up of Alen, offshore Equatorial Guinea, resulted in additional DD&A expense of $44 million; and
•
the start up of Tamar, offshore Israel, resulted in additional DD&A expense of $40 million;
partially offset by:
•
a decrease of approximately $53 million onshore US, primarily due to the impact of sales of non-core properties during 2012 and 2013;
•
a decrease of $52 million in the deepwater Gulf of Mexico due to maintenance and repair downtime and declining production at older fields;
•
a decrease of $40 million at the Aseng field, offshore Equatorial Guinea, due to natural field decline and timing of liftings; and
•
a decrease of $54 million at the Mari-B/Noa/Pinnacles fields, offshore Israel, due to natural field decline and decreased book value from impairments.
Changes in the unit rate per BOE for 2013 as compared with 2012 were due to change in the mix of production, including higher production in the DJ Basin and Marcellus Shale, which has a higher DD&A rate than our Equatorial Guinea and Israel production.
Total DD&A expense increased for 2012 as compared with 2011 due to the following:
•
higher sales volumes in the DJ Basin accounted for $189 million of the increase and the addition of DD&A expense related to the Marcellus Shale accounted for $46 million of the increase;
•
the start up of Noa and Pinnacles (offshore Israel), which have higher DD&A rates, accounted for $86 million of the increase;
•
the start up of Galapagos and South Raton in the deepwater Gulf of Mexico, which have higher DD&A rates, accounted for $92 million of the increase;
•
a full year of production from the Aseng field, offshore Equatorial Guinea, which includes the Aseng FPSO in its depreciation base, accounted for $183 million of the increase; and
•
higher costs associated with development activities in China;
partially offset by:
•
the impact of sales of non-core, onshore US properties during 2012.
General and Administrative Expense General and administrative expense (G&A) was as follows:
(1)
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.
G&A expense for 2013 increased as compared with 2012 primarily due to additional expenses relating to personnel, office, and information technology costs in support of our major development projects and increased exploration activities.
G&A expense increased for 2012 as compared with 2011 primarily due to additional personnel and office space supporting growth in the DJ Basin and Marcellus Shale and augmentation of environmental, health and safety, geoscience, and information technology departments in support of our major development projects and increased exploration activities, and increased performance incentive compensation.
G&A expense 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 $58 million in 2013, $48 million in 2012 and $42 million in 2011. See Item 8. Financial Statements and Supplementary Data - Note 12. Stock-Based and Other Compensation Plans.
Gain on Divestitures Gain on divestitures was as follows:
Gain on divestitures for 2013 and 2012 is related to the sale of non-core onshore US assets. See Item 8. Financial Statements and Supplementary Data - Note 3. Acquisitions and Divestitures. See Item 8. Financial Statements and Supplementary Data - Note 3. Property Transactions.
Asset Impairments Asset impairment expense was as follows:
For information regarding asset impairment charges, see Critical Accounting Policies and Estimates - Impairment of Proved Oil and Gas Properties and Other Investments and Impairment of Unproved Oil and Gas Properties, below, and Item 8. Financial Statements and Supplementary Data - Note 4. Asset Impairments.
Other Operating Expense, Net Other operating expense, net was as follows:
See Item 8. Financial Statements and Supplementary Data - Note 2. Additional Financial Statement Information.
Other (Income) Expense Other (income) expense was as follows:
See Item 8. Financial Statements and Supplementary Data - Note 2. Additional Financial Statement Information.
(Gain) Loss on Commodity Derivative Instruments (Gain) Loss on commodity derivative instruments is a result of mark-to-market accounting. Many factors impact our (gain) loss on commodity derivative instruments including: increases and decreases in the commodity forward price curves compared with our executed hedging arrangements; increases in hedged future volumes; and the mix of hedge arrangements between NYMEX WTI, Dated Brent and NYMEX HH commodities. See Critical Accounting Policies and Estimates - Derivative Instruments and Hedging Activities, and Item 8. Financial Statements and Supplementary Data - Note 8. Derivative Instruments and Hedging Activities and Note 13. Fair Value Measurements and Disclosures, below.
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 remained flat in 2013 as compared with 2012. A reduction in CONSOL installment payments outstanding was offset by an issuance of new senior debt in November 2013. We drew down amounts under our Credit Facility during third quarter and repaid with proceeds from the debt issuance. There were no other significant changes in our debt.
Interest expense prior to the reduction of capitalized interest increased $79 million in 2012 as compared with 2011 resulting from our December 2011 debt issuance, an additional month of interest for our February 2011 debt issuance and interest related to our Aseng FPSO lease obligation.
The decrease of $30 million in the amount of interest capitalized in 2013 compared with 2012 is due to the completion of major projects at Alen and Tamar, partially offset by higher work in progress amounts related to major long-term projects in the deepwater Gulf of Mexico, offshore West Africa, and offshore Israel.
The increase of $19 million in the amount of interest capitalized in 2012 compared with 2011 is due to higher work in progress amounts related to major long-term projects in the deepwater Gulf of Mexico, offshore West Africa, and Eastern Mediterranean.
Interest is capitalized on exploration and development projects using an interest rate equivalent to the average rate paid on long-term debt. Capitalized interest is included in the cost of oil and gas assets and amortized with other costs on a unit-of-production basis. The majority of the capitalized interest is related to long lead-time projects in the deepwater Gulf of Mexico, offshore West Africa and offshore Eastern Mediterranean. See Item 8. Financial Statements and Supplementary Data - Note 6. 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, 2013, approximately 50% 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 $26 million in 2013, $6 million in 2012, and $8 million in 2011. See Item 8. Financial Statements and Supplementary Data - Note 12. Stock-Based and Other Compensation Plans.
Income Tax Provision The income tax provision from continuing operations was as follows:
See Item 8. Financial Statements and Supplementary Data - Note 11. Income Taxes.
Discontinued Operations
Summarized results of discontinued operations, comprising our North Sea geographical segment, were as follows:
(1)
Includes exploration expense of $27 million in 2012 related to the Selkirk field, which we determined was uneconomic for joint development.
Our long-term debt is recorded at the consolidated level and is not reflected by each component. Thus, we have not allocated interest expense to discontinued operations.
See Item 8. Financial Statements and Supplementary Data - Note 3. Property Transactions.
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, 2013 included positive performance revisions of 48 MMBoe for the DJ Basin and Marcellus Shale programs, 11 MMBoe for Alba field, and 21 MMBoe for the Tamar field, and positive price revisions of 13 MMBoe due to increases in commodity prices;
•
changes for the year ended December 31, 2012 included a negative revision of 94 MMBoe due to our decision to terminate the legacy vertical drilling program in the DJ Basin and focus on horizontal development; net positive revisions of 23 MMBoe, primarily related to better than expected well performance in the Marcellus Shale, the deepwater Gulf of Mexico, and the Aseng field; and negative revisions of 26 MMBoe due to changes in commodity prices; and
•
changes for the year ended December 31, 2011 include a negative revision of 28 MMBoe, due primarily to reclassifications of proved undeveloped reserves in the DJ Basin 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.
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, 2013 included increases of 130 MMBoe in the DJ Basin, 61 MMBoe in the Marcellus Shale, 18 MMBoe deepwater Gulf of Mexico primarily attributable to the sanction of the Big Bend and Gunflint developments, 8 MMBoe in Equatorial Guinea attributable to the Alba and Aseng fields, 30 MMBoe in Israel attributable to the discovery and sanction of the Tamar Southwest field, and 2 MMBoe associated with other development programs.
•
changes for the year ended December 31, 2012 included an increase of 149 MMBoe in the DJ Basin as a result of our decision to focus capital and resources on horizontal development of the Niobrara formation, 56 MMBoe related to ongoing development of the Marcellus Shale, 7 MMBoe related to the ongoing appraisal of the Tamar field, and 6 MMBoe for other projects; and
•
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 the Tamar field due to appraisal activities, and 3 MMBoe for other projects.
We expect that a significant portion of future reserves additions will come from our major development projects at the DJ Basin, Marcellus Shale, deepwater Gulf of Mexico, and new discoveries resulting from our active exploration programs in both core areas and global new ventures programs. We may also purchase proved properties in strategic acquisitions. See Operating Outlook - Major Development Project Inventory, above, and Liquidity and Capital Resources - Acquisition, Capital and Other Exploration Expenditures, below.
Purchase of Minerals in Place We occasionally enhance our asset portfolio with strategic acquisitions of producing properties. Purchases included the following:
•
the acquisition of additional acreage primarily in the Marcellus Shale and DJ Basin in 2013; and
•
the Marcellus Shale asset acquisition in 2011.
Sale of Minerals in Place We maintain an ongoing portfolio management program. Sales included the following:
•
the sales of non-core, onshore US and North Sea assets and the net impact of the DJ Basin acreage exchange in 2013; and
•
the sale of non-core, onshore US and North Sea assets in 2012.
See Items 1. and 2. Business and Properties and Item 8. Financial Statements and Supplementary Data - Note 3. Property Transactions.
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 development and monetize our discovered hydrocarbons, we employ a capital structure and financing strategy designed to provide sufficient liquidity throughout the volatile commodity price cycle. Specifically, we strive to retain the ability to fund long cycle, multi-year, capital intensive development projects throughout a range of scenarios, while also funding a robust exploration program and maintaining capacity to capitalize on financially attractive periodic mergers and acquisitions activity. We endeavor to maintain an investment grade debt rating in service of these objectives, while delivering competitive returns and a growing dividend. We utilize a commodity price hedging program to reduce the impacts of commodity price volatility and enhance the predictability of cash flows along with a risk and insurance program to protect against disruption to our cash flows and the funding of our business.
We strive to maintain a minimum liquidity level to address volatility and risk. Traditional sources of our liquidity are cash flows from operations, cash on hand, available borrowing capacity under our unsecured revolving credit facility (Credit Facility), and proceeds from sales of non-core properties, such as certain onshore US and North Sea properties in 2013 and 2012. We may also access the capital markets to ensure adequate liquidity exists in the form of unutilized capacity under our Credit Facility and to refinance scheduled debt maturities, which includes $200 million due on April 15, 2014. See Credit Facility, below.
Expanded development in the DJ Basin and Marcellus Shale, investment in our recently sanctioned major projects, and our planned exploration and appraisal drilling activities will result in near term capital expenditures exceeding cash flows from operating activities. The extent to which capital investment will continue to exceed operating cash flows depends on our success in sanctioning future development projects, the results of our exploration activities, and new business opportunities as well as external factors such as commodity prices, among others. Our financial capacity, coupled with our diversified portfolio, provides us with flexibility in our investment decisions including execution of our major development projects and increased exploration activity.
To support our investment program, we expect that higher production resulting from our horizontal Niobrara development program combined with new production from Tamar, which began producing late in the first quarter of 2013, and Alen, which began producing late in the second quarter of 2013, will result in an increase in cash flows which will be available to meet a substantial portion of future capital commitments. Cash on hand at December 31, 2013 totaled $1.1 billion, and includes both domestic and foreign cash. To the extent cash held by our foreign subsidiaries is not required for foreign investment projects and we would not incur additional US tax, we may consider repatriating some of our foreign cash to increase our financial flexibility and fund our capital investment program.
We also evaluate potential strategic farm-out arrangements of our working interests in Israel, Cyprus, Cameroon, Nicaragua and the deepwater Gulf of Mexico for reimbursement of our capital spending in these areas. In addition, our current liquidity level and balance sheet, along with our ability to access the capital markets, such as our recent $1.0 billion debt offering on November 8, 2013, provide flexibility. We believe that we are well-positioned to fund our long-term growth plans.
We are currently evaluating potential development scenarios for our significant natural gas discoveries offshore Eastern Mediterranean, including Leviathan and Cyprus Block 12. The magnitude of these discoveries presents technical and financial challenges for us due to the large-scale development requirements. Potential development scenarios may include the construction of subsea pipeline, floating LNG, LNG terminals, FPSO or other options. Each of these development options would require a multi-billion dollar investment and require a number of years to complete. We and our Leviathan partners have announced a potential strategic partner for Leviathan, Woodside, who could provide midstream expertise as well as LNG project execution, marketplace expertise and financial capacity.
See Credit Facility, below. See also Item 1A. Risk Factors
Pension Plan Termination Our pension and restoration plans are in the process of being terminated. We expect to liquidate the associated obligations through lump-sum payments to participants. As of December 31, 2013, the accumulated benefit obligations totaled approximately $394 million and the fair value of plan assets was $265 million, leaving approximately $129 million unfunded. We expect to make additional contributions to the plans during the next 12 to 24 months to the extent necessary to fund these obligations.
In addition, upon plan termination, all unamortized prior service cost and net actuarial loss remaining in AOCL will be charged to expense. These amounts totaled approximately $144 million at December 31, 2013. See Item 8. Financial Statements and Supplementary Data - Note 12. Stock-Based and Other Compensation Plans.
Marcellus Shale Joint Venture Our joint venture arrangement with a subsidiary of CONSOL Energy, Inc. is structured in a manner to address partner alignment and financial affordability. The $2.1 billion CONSOL Carried Cost Obligation is expected to extend over a multi-year period and is capped at $400 million in each calendar year. The obligation is suspended if average Henry Hub natural gas prices fall and remain below $4.00 per MMBtu in any three consecutive month period and will remain suspended until average Henry Hub natural gas prices are above $4.00 per MMBtu for three consecutive months. The carry terms ensure economic alignment with our partner in periods of low natural gas prices.
Due to the natural gas prices, we did not make any payments towards the CONSOL Carried Cost Obligation in 2012 or 2013. However, early winter weather drove an increase in natural gas prices to above $4.00 per MMBtu at the end of 2013, and continuation of this price throughout early 2014. Based on the December 31, 2013 Henry Hub natural gas price strip, and our current development plan, we forecast our CONSOL Carried Cost Obligation may commence in March 2014 and total up to approximately $225 million for 2014. See Off-Balance Sheet Arrangements below. See Item 8. Financial Statements and Supplementary Data - Note 3. Property Transactions.
Available Liquidity Information regarding cash and debt balances was as follows:
(1)
See Credit Facility, below.
(2)
Total debt includes capital lease and other obligations and remaining CONSOL installment payments (at December 31, 2012 and 2011) 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 $1.1 billion in cash and cash equivalents at December 31, 2013, compared with approximately $1.4 billion at December 31, 2012. At December 31, 2013 our cash was primarily denominated in US dollars and invested in money market funds and short-term deposits with major financial institutions. Approximately $810 million of this cash is attributable to our foreign subsidiaries, some of which may be subject to US income taxes if repatriated. During 2014, we currently expect to use a portion of cash to fund international projects, while a significant amount will be used towards our onshore US development.
Credit Facility We recently amended our Credit Facility to mature on October 3, 2018. The commitment is $4.0 billion through the maturity date of the Credit Facility. See Financing Activities - Long-Term Debt below.
Derivative Instruments We use various derivative instruments in 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 put options. Our practice has been to hedge up to 50% of forecasted hedgeable crude oil and natural gas production for the current year plus two additional calendar years. The limit was increased to up to a maximum of 75% of forecasted hedgeable global crude oil production for the years 2014 and 2015.
Current period settlements on commodity derivative instruments impact our liquidity, since we are either paying cash to, or receiving cash from, our counterparties. We net settle by counterparty based on master agreements. The net settlements take into account deferred premiums we have agreed to pay for put options. None of our counterparty agreements contain margin requirements. We have also used derivative instruments to manage interest rate risk by entering into forward contracts or swap agreements to minimize the impact of interest rate fluctuations associated with fixed or floating rate borrowings. However, we currently have no interest rate derivative instruments. See Item 1A. Risk Factors.
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, 2013, the fair value of our commodity derivative assets was $17 million and the fair value of our commodity derivative liabilities was $75 million (after consideration of netting clauses within our master agreements). See Item 1A. Risk Factors.
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 volatility of crude oil and natural gas prices continues to impact the oil and gas industry. Due to the volatility of crude oil and natural gas prices, we continue to use derivative instruments as a means of managing our exposure to price changes.
At December 31, 2013, we had entered into variable to fixed price commodity swaps, collars and basis swaps related to crude oil and natural gas sales. Changes in fair value of commodity derivative instruments are reported in earnings in the period in which they occur. Our open commodity derivative instruments were in a net liability position with a fair value of $58 million. Based on the December 31, 2013 published commodity futures price curves for the underlying commodities, a hypothetical price increase of $1.00 per Bbl for crude oil would decrease the fair value of our net commodity derivative liability by approximately $37 million. A hypothetical price increase of $0.10 per MMBtu for natural gas would decrease the fair value of our net commodity derivative liability by approximately $10 million. Our derivative instruments are executed under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net cash settled at the time of election. See
Item 8. Financial Statements and Supplementary Data
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, 2013, 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 (1992), 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, 2013, 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, 2013 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, 2013 and 2012, and the related consolidated statements of operations, comprehensive income, shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2013. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Noble Energy, Inc. and subsidiaries as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2013, 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, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 6, 2014 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ KPMG LLP
Houston, Texas
February 6, 2014
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, 2013, based on criteria established in Internal Control - Integrated Framework (1992) 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, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
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, 2013 and 2012, and the related consolidated statements of operations, comprehensive income, shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2013, and our report dated February 6, 2014 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
Houston, Texas
February 6, 2014
Noble Energy, Inc.
Consolidated Statements of Operations
(millions, except per share amounts)
The accompanying notes are an integral part of these financial statements.
Noble Energy, Inc.
Consolidated Statements of Comprehensive Income
(millions)
The accompanying notes are an integral part of these financial statements.
Noble Energy, Inc.
Consolidated Balance Sheets
(millions)
The accompanying notes are an integral part of these financial statements.
Noble Energy, Inc.
Consolidated Statements of Cash Flows
(millions)
The accompanying notes are an integral part of these financial statements.
Noble Energy, Inc.
Consolidated Statements of Shareholders' Equity
(millions)
(1)
Amounts restated to reflect impact of 2-for-1 stock split.
The accompanying notes are an integral part of these financial statements.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 1. Summary of Significant Accounting Policies
General Noble Energy, Inc. (Noble Energy, we or us) is a leading independent energy company engaged in worldwide oil and gas exploration and production. Our core operating areas are onshore US (DJ Basin and Marcellus Shale), deepwater Gulf of Mexico, offshore West Africa and offshore Eastern Mediterranean.
Basis of Presentation and Consolidation Accounting policies used by us and our subsidiaries conform to US GAAP. Significant policies are discussed below. Our consolidated accounts include our accounts and the accounts of our wholly-owned subsidiaries. We use the equity method of accounting for investments in entities that we do not control but over which we exert significant influence. We carry equity method investments at our share of net assets of the equity investees plus our loans and advances. Differences in the basis of the investment and the separate net asset value of the investee, if any, are amortized into income over the remaining useful life of the underlying assets. See Note 7. 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 Senior Vice President - Corporate Development and certain members of senior management. See Supplemental Oil and Gas Information (Unaudited).
Other items subject to estimates and assumptions include the carrying amounts of property, plant and equipment, goodwill and asset retirement obligations, valuation allowances for receivables and deferred income tax assets, and valuation of derivative instruments, among others. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. 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 2012 and 2011 consolidated financial statements to conform to the 2013 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 13. 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.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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 2. Additional Financial Statement Information.
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 30 years. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized. Repairs and maintenance are expensed as incurred.
Proved Property Impairment We review individually significant proved oil and gas properties and other long-lived assets for impairment at least semi-annually, at year-end and mid-year, or quarterly when events and circumstances indicate a decline in the recoverability of the carrying values of such properties, such as a negative revision of reserves estimates or sustained decrease in commodity prices. We estimate future cash flows expected in connection with the properties and compare such future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable. When the carrying amount of a property exceeds its estimated undiscounted future cash flows, the carrying amount is reduced to estimated fair value. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and gas production, commodity prices based on published forward commodity price curves or contract prices as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate.
We recorded proved property impairment charges in 2013, 2012, and 2011. It is likely that other proved oil and gas properties could become impaired in the future due to commodity price declines and/or field performance. 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 produce the reserves. Cash flow estimates related to probable and possible reserves are reduced by additional risk-weighting factors. Other individually insignificant unproved properties are amortized on a composite method based on our experience of successful drilling and average holding period. It is reasonably possible that unproved oil and gas properties could become impaired in the future if commodity prices decline. See Note 4. Asset Impairments.
Properties Acquired in Business Combinations When sufficient market data is not available, we determine the fair values of proved and unproved properties acquired in transactions accounted for as business combinations by preparing our own estimates of cash flows from the production of crude oil and natural gas reserves. We estimate future prices to apply to the estimated reserves quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net 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. Property Transactions.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Assets Held for Sale We occasionally market non-core oil and gas properties. At the end of each reporting period, we evaluate our properties being marketed to determine whether any should be reclassified as held-for-sale. The held-for-sale criteria include: a commitment to a plan to sell; the asset is available for immediate sale; an active program to locate a buyer exists; the sale of the asset is probable and expected to be completed within one year; the asset is being actively marketed for sale; and it is unlikely that significant changes to the plan will be made. If each of these criteria is met, the property is reclassified as held-for-sale in our consolidated balance sheets. See Note 3. Acquisitions and Divestitures.
Exploration Costs Geological and geophysical costs, delay rentals, amortization of unproved leasehold costs, and costs to drill exploratory wells that do not find proved reserves are expensed as oil and gas exploration. We carry the costs of an exploratory well as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as we are making sufficient progress assessing the reserves and the economic and operating viability of the project. For certain capital-intensive deepwater Gulf of Mexico or international projects, it may take us more than one year to evaluate the future potential of the exploratory 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 6. Capitalized Exploratory Well Costs.
Other Property Other property includes automobiles, trucks, airplanes, office furniture, computer equipment and other fixed assets such as buildings 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 five to 30 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 $121 million in 2013, $151 million in 2012, and $132 million in 2011.
Asset Retirement Obligations Asset retirement obligations consist of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. We recognize the fair value of a liability for an ARO in the period in which it is incurred when we have an existing legal obligation associated with the retirement of our oil and gas properties that can reasonably be estimated, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and gas asset. The asset retirement cost is determined at current costs and is inflated into future dollars using an inflation rate that is based on the consumer price index. The future projected cash flows are then discounted to their present value using a credit-adjusted risk-free rate. After initial recording, the liability is increased for the passage of time, with the increase being reflected as accretion expense and included in our DD&A expense in the statement of operations. Subsequent adjustments in the cost estimate are reflected in the liability and the amounts continue to be amortized over the useful life of the related long-lived asset. See Note 9. Asset Retirement Obligations.
Goodwill Goodwill represents the excess of the cost of an acquired entity over the net amounts assigned to assets acquired and liabilities assumed. Goodwill is not amortized to earnings but is qualitatively assessed annually in the fourth quarter. If, based on our qualitative procedures, it is more likely than not that the fair value of the reporting unit is less than its carrying amount, we perform the two-step goodwill impairment test. The two-step goodwill impairment test is also performed whenever events or changes in circumstances indicate that the carrying value may not be recoverable. No goodwill impairment was indicated at December 31, 2013. However, it is possible that goodwill could become impaired in the future if commodity prices or other economic factors become less favorable.
When we dispose of a reporting unit or a portion of a reporting unit that constitutes a business, we include goodwill associated with that business in the carrying amount of the business in order to determine the gain or loss on disposal. The amount of goodwill allocated to the carrying amount of a business can significantly impact the amount of gain or loss recognized on the sale of that business. The amount of goodwill to be included in that carrying amount is based on the relative fair value of the business to be disposed of and the portion of the reporting unit that will be retained. The change in goodwill in 2013 is due to amounts allocated to onshore US properties sold. See Note 3. Property Transactions.
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.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
A company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting. Only derivative instruments that are expected to be highly effective in offsetting anticipated gains or losses on the hedged cash flows and that are subsequently documented to have been highly effective can qualify for hedge accounting. Effectiveness must be assessed both at inception of the hedge and on an ongoing basis. Any ineffectiveness in hedging instruments whereby gains or losses do not exactly offset anticipated gains or losses of hedged cash flows is measured and recognized in earnings in the period in which it occurs. When using hedge accounting, we assess hedge effectiveness quarterly based on total changes in the derivative instrument’s fair value by performing regression analysis. A hedge is considered effective if certain statistical tests are met. We record hedge ineffectiveness in (gain) loss on commodity derivative instruments.
Accounting for Commodity Derivative Instruments We account for our commodity derivative instruments using mark-to-market accounting and recognize all gains and losses in earnings during the period in which they occur. Our consolidated statements of cash flows includes the non-cash unrealized gain and loss on commodity derivative instruments, which represented the difference between the total gain and loss on commodity derivative instruments and the cash received or paid on settlements of commodity derivative instruments during the period.
We offset the fair value amounts recognized for derivative instruments and the fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral. The cash collateral (commonly referred to as a “margin”) must arise from derivative instruments recognized at fair value that are executed with the same counterparty under a master arrangement with netting clauses.
Accounting for Interest Rate Derivative Instruments We designate interest rate derivative instruments as cash flow hedges. Changes in fair value of interest rate swaps or interest rate “locks” used as cash flow hedges are reported in AOCL, to the extent the hedge is effective, until the forecasted transaction occurs, at which time they are recorded as adjustments to interest expense over the term of the related notes. See Note 8. Derivative Instruments and Hedging Activities.
Stock-Based Compensation Stock options and other stock-based compensation issued to employees and directors are recorded at grant-date fair value. Expense is recognized on a straight-line basis over the employee’s and director’s requisite service period (generally the vesting period of the award) in the consolidated statements of operations. See Note 12. Stock-Based and Other Compensation Plans.
Pension and Other Postretirement Benefit Plans We recognize the funded status (the difference between the fair value of plan assets and the projected benefit obligation) of our defined benefit pension, restoration and other postretirement benefit plans in the consolidated balance sheets, with a corresponding adjustment to AOCL, net of tax. The amount remaining in AOCL at December 31, 2013 represents unrecognized net actuarial loss and unrecognized prior service cost. 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 12. Stock-Based and Other Compensation Plans.
Income Taxes Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized when items of income and expense are recognized in the financial statements in different periods than when recognized in the applicable tax return. Deferred tax assets arise when expenses are recognized in the financial statements before the tax return or when income items are recognized in the tax return prior to the financial statements. Deferred tax assets also arise when operating losses or tax credits are available to offset tax payments due in future years. Deferred tax liabilities arise when income items are recognized in the financial statements before the tax returns or when expenses are recognized in the tax return prior to the financial statements. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date when the change in the tax rate was enacted. See Note 11. 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.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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.
On April 22, 2013, Noble Energy’s Board of Directors approved a 2-for-1 split of its common stock to be effected in the form of a stock dividend. The stock dividend was distributed on May 28, 2013 to shareholders of record as of May 14, 2013. Earnings per share and common shares outstanding are reported giving retrospective effect to the common stock split. See Note 14. 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 18. Commitments and Contingencies.
We self-insure the medical and dental coverage provided to certain employees, and the deductibles for workers’ compensation, automobile liability and general liability coverage. Liabilities are accrued for self-insured claims, or when estimated losses exceed coverage limits, and when sufficient information is available to reasonably estimate the amount of the loss.
Foreign Currency The US dollar is considered the functional currency for each of our international operations. Transactions that are completed in foreign currencies are remeasured into US dollars and recorded in the financial statements at prevailing foreign exchange rates. Transaction gains or losses are included in other non-operating (income) expense, net in the consolidated statements of operations.
Segment Information Accounting policies for geographical segments are the same as those described above. Transfers between segments are accounted for at market value. We do not consider interest income and expense or income tax benefit or expense in our evaluation of the performance of geographical segments. See Note 15. Segment Information.
Changes in Shareholders’ Equity On April 24, 2012, our shareholders voted to approve an amendment to the Company’s Certificate of Incorporation to (i) increase the number of authorized shares of our common stock from 250 million to 500 million shares and (ii) reduce the par value of the Company’s common stock from $3.33 per share to $0.01 per share. See the Consolidated Statements of Shareholders' Equity.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 2. Additional Financial Statement Information
Additional statements of operations information is as follows:
(1)
Other revenues consist primarily of electricity sales from the Machala power plant, located in Machala, Ecuador, through May 2011. Electricity generation expense includes all operating and non-operating expenses associated with the plant, including depreciation and changes in the allowance for doubtful accounts. In May 2011, we transferred our assets in Ecuador to the Ecuadorian government.
(2)
Amounts relate to rig stand-by expense incurred due to the deepwater Gulf of Mexico drilling moratorium.
(3)
Amounts represent increases in the fair value of shares of our common stock held in a rabbi trust.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Additional balance sheet information is as follows:
(1)
Assets held for sale consist primarily of oil and gas properties and liabilities associated with asset retirement obligations located in China, the North Sea and onshore US at December 31, 2013 and the North Sea at December 31, 2012. See Note 3. Property Transactions.
(2)
See Note 10. Long-Term Debt.
(3)
Amount includes liabilities accrued under our defined benefit pension plan, restoration plan, and other postretirement benefit plans. See Note 12. Stock-Based and Other Compensation Plans.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Supplemental statements of cash flow information is as follows:
(1)
See Note 3. Property Transactions and Note 10. Long-Term Debt.
Note 3. Property Transactions
Sale of North Sea Properties During 2013, we closed three sales of non-operated working interest properties located in the North Sea. The sales resulted in a $65 million gain based on net sales proceeds of $56 million for the fields.
During 2012, we closed the sale of our 30% non-operated working interest in the Dumbarton and Lochranza fields located in the North Sea. Proceeds from the transaction were $117 million and included final closing adjustments from the effective date of January 1, 2012. The net book value of assets sold was $255 million. Asset retirement obligations associated with the sale were $55 million. We reversed a deferred tax liability and recognized a corresponding income tax benefit of $99 million related to the sale.
As of December 31, 2013, all the properties remaining in our North Sea geographical segment are included in assets held for sale in our consolidated balance sheet. Our consolidated statements of operations have been reclassified for all periods presented to reflect the operations of our North Sea geographical segment as discontinued.
Included in income before income taxes during 2012, below, is exploratory expense of $27 million related to our Selkirk field. During the fourth quarter of 2012, the nearby Bligh well, a potential co-development candidate for Selkirk, was drilled. Bligh encountered noncommercial quantities of hydrocarbons; therefore, we determined that Selkirk was uneconomic for joint development.
Upon reclassification as held for sale, depreciation, depletion, and amortization (DD&A) ceased for the North Sea segment. Our long-term debt is recorded at the consolidated level; therefore no interest expense has been allocated to discontinued operations.
Summarized results of discontinued operations are as follows:
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Sale of Onshore US Properties During 2013 and 2012, we closed the sales of non-core onshore US crude oil and natural gas properties. The information regarding the assets sold is as follows:
We continue to market non-core onshore US properties; certain of these assets met the criteria for reclassification as assets held for sale at December 31, 2013.
DJ Basin Acreage Exchange In October 2013, we closed an acreage exchange agreement with another operator related to our position in the DJ Basin. Each party exchanged approximately 50,000 net acres within the same field. The exchange consolidates our acreage into large contiguous blocks, which will provide the opportunity to optimize drilling, production, and gathering activities and add more extended-reach lateral wells to our development program.These opportunities provide efficiencies by owning and operating properties located within a smaller geographical area, with the potential to significantly enhance field economics. In accordance with guidance for oil and gas property conveyances, the transaction was accounted for at net book value, with no gain or loss recognized. We received $105 million in cash related to reimbursement of capital expenditures and other normal closing adjustments from the effective date of January 1, 2013 to closing date, which was recorded as a reduction in the net book value of the field.
Marcellus Shale Joint Venture On September 30, 2011, we closed an agreement with a subsidiary of CONSOL Energy Inc. (CONSOL) for the development of Marcellus Shale properties in southwest Pennsylvania and northwest West Virginia. Under the agreement, we acquired a 50% interest in approximately 628,000 net undeveloped acres, certain producing properties, and existing infrastructure, such as pipeline and gathering facilities, for approximately $1.3 billion, including post-closing adjustments. We and CONSOL also formed CONE Gathering LLC (CONE) to own and operate the existing and future infrastructure. We paid the final installment payment of $328 million as of December 31, 2013. See Note 10. Long-Term Debt.
As part of the joint venture transaction, we agreed to fund one-third of CONSOL’s 50% working interest share of future drilling and completion costs, capped at $400 million each year, up to approximately $2.1 billion (CONSOL Carried Cost Obligation), which is expected to be paid out over a multi-year period. The CONSOL Carried Cost Obligation is suspended if average Henry Hub natural gas prices fall and remain below $4.00 per MMBtu in any three consecutive month period and will remain suspended until average Henry Hub natural gas prices are above $4.00 per MMBtu for three consecutive months. The CONSOL Carried Cost Obligation was suspended during 2011 - 2013 due to low natural gas prices.
The final purchase price allocation resulted in the following:
(1)
Total reflects impact of $17 million imputed interest on CONSOL installment payments.
We used an income approach to estimate the fair value of the proved oil and gas properties as of the acquisition date. We utilized a discounted cash flow model which took into account the following inputs to arrive at estimates of future net cash flows:
•
estimated quantities of crude oil and natural gas reserves prepared by our qualified petroleum engineers;
•
management’s estimates of future commodity prices based on NYMEX Henry Hub natural gas futures prices and adjusted for estimated location and quality differentials;
•
estimated future production rates based on our experience with similar properties which we operate; and
•
estimated timing and amounts of future operating and development costs based on our experience with similar properties which we operate.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
We discounted the resulting future net cash flows using a market-based weighted average cost of capital rate determined appropriate at the acquisition date. The fair value of the proved producing properties is considered a Level 3 fair value measurement.
Exit from Ecuador 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.
Note 4. Asset Impairments
Pre-tax (non-cash) asset impairment charges were as follows:
2013 Asset Impairments We recorded impairments of the Mari-B field, due to natural field decline, and certain non-core, onshore US properties upon reclassification to assets held for sale. The Mari-B field was written down to its estimated fair value using a discounted cash flow model which included management’s estimates of future oil and gas production, commodity prices based on forward commodity price curves or contract prices as of the date of the estimate, operating and development costs, and discount rates. The fair values of onshore US assets held for sale were based on anticipated sales proceeds less costs to sell.
2012 Asset Impairments Due to declines in realized natural gas prices associated with our Piceance development, onshore US, and declines in near-term crude oil prices associated with our South Raton development in the deepwater Gulf of Mexico, we determined that their carrying amounts were not recoverable from future cash flows and, therefore, were impaired. In addition, due to end-of-field life declines in production of our Mari-B, Noa and Pinnacles fields, offshore Israel, we determined that the carrying amount was not recoverable from future cash flows and, therefore, was impaired. The assets were written down to their estimated fair values, which were determined using discounted cash flow models, as described above.
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 assets were not recoverable from future cash flows and, therefore, were impaired. The assets were written down to their estimated fair values, which were determined using discounted cash flow models, as described above.
See also Note 13. Fair Value Measurements and Disclosures.
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. Property Transactions.
Note 6. Capitalized Exploratory Well Costs
We capitalize exploratory well costs until a determination is made that the well has found proved reserves or is deemed noncommercial. If a well is deemed to be noncommercial, the well costs are immediately charged to exploration expense as dry hole cost.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed in the same period:
(1)
The 2013 amount relates primarily to Gunflint (deepwater Gulf of Mexico), for which we sanctioned a development plan.
(2)
The 2012 amount primarily represents Deep Blue (deepwater Gulf of Mexico) exploratory well costs capitalized prior to December 31, 2012.
(3)
The 2012 amount relates to Selkirk (North Sea) exploratory well costs capitalized prior to December 31, 2012. See Note 3. Property Transactions.
The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced, and the number of projects that have been capitalized for a period greater than one year:
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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, 2013:
Note 7. 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
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income tax provision in our consolidated statements of operations. At December 31, 2013, our retained earnings included $105 million related to the undistributed earnings of equity method investees.
The carrying value of our AMPCO investment was $9 million higher than the underlying net assets of the investee at December 31, 2013. The difference is related to capitalized interest which is being amortized into earnings over the remaining useful life of the plant.
Equity method investments are as follows:
Summarized, 100% combined financial information for equity method investees is as follows:
Note 8. Derivative Instruments and Hedging Activities.
Objective and Strategies for Using Derivative Instruments In order to mitigate the effect of commodity price volatility and enhance the predictability of cash flows relating to the marketing of our crude oil and natural gas, we enter into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production. The derivative instruments we use may include variable to fixed price commodity swaps, two-way and three-way collars, basis swaps and put options.
The fixed price swap and two-way collar 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.
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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.
For put options, we typically pay a premium to the counterparty in exchange for the sale of the instrument. If the index price is below the floor price of the put option, we receive the difference between the floor price and the index price multiplied by the contract volumes less the option premium at the time of settlement. If the index price settles at or above the floor price of the put option, we pay only the put option premium at the time of settlement. We had no outstanding put options as of December 31, 2013.
We also may enter into forward contracts to hedge anticipated exposure to interest rate risk associated with public debt financing.
While these instruments mitigate the cash flow risk of future reductions in commodity prices or increases in interest rates, they may also curtail benefits from future increases in commodity prices or decreases in interest rates.
See Note 13. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of our derivative instruments.
Counterparty Credit Risk Derivative instruments expose us to counterparty credit risk. Our commodity derivative instruments are currently with a diversified group of major banks or market participants, and we monitor and manage our level of financial exposure. Our commodity derivative contracts are executed under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net settled at the time of election.
We monitor the creditworthiness of our commodity derivatives counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk.
Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices or higher interest rates, and could incur a loss.
Interest Rate Derivative Instrument In January 2010, we entered into an interest rate forward starting swap to effectively fix the cash flows related to interest payments on our anticipated March 2011 debt issuance. During first quarter 2011, the net liability position on the swap was reduced in our mark to market calculation, and we recognized a corresponding gain of $23 million, net of tax, in AOCL. On February 15, 2011 we settled the interest rate swap, which had a net liability position of $40 million at the time of settlement. Approximately $26 million, net of tax, was recorded in accumulated other comprehensive loss (AOCL) and is being reclassified to interest expense over the term of the notes. The ineffective portion of the interest rate swap was de minimis.
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Unsettled Derivative Instruments As of December 31, 2013, we had entered into the following crude oil derivative instruments:
As of December 31, 2013, we had entered into the following natural gas derivative instruments:
Fair Value Amounts and Gains and Losses on Derivative Instruments The fair values of derivative instruments in our consolidated balance sheets were as follows:
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The effect of derivative instruments on our consolidated statements of operations was as follows:
(1)
Gains and losses on commodity derivative instruments included in net income include both pre-tax realized gains and losses, which equals the cash settlements during the period, 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. Many factors impact our gain and loss on commodity derivative instruments including: increases and decreases in the commodity forward curves compared to our executed hedging arrangements; increases and decreases in hedged future volumes; and the mix of hedge arrangements between NYMEX WTI, Dated Brent and NYMEX HH commodities. Unrealized mark-to-market gains or losses recognized in the current period will be realized in the future when cash settlement occurs.
AOCL at December 31, 2013 included deferred losses of $24 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 $1 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.
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Note 9. Asset Retirement Obligations
Asset retirement obligations (ARO) consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. Changes in asset retirement obligations were as follows
For the year ended December 31, 2013
Liabilities incurred were due to new wells and facilities and included $68 million for deepwater Gulf of Mexico, $15 million for onshore US development, and $7 million for Eastern Mediterranean.
Liabilities settled of $41 million primarily related to deepwater Gulf of Mexico abandonment activities and non-core, onshore US assets sold.
Revisions were primarily due to changes in estimated costs for future abandonment activities and acceleration of timing and included $86 million for DJ Basin, $36 million for deepwater Gulf of Mexico, $10 million for Equatorial Guinea, and $7 million for Eastern Mediterranean. Increased US costs are due primarily to more stringent abandonment standards impacting procedures and materials.
Other includes $17 million for non-core, onshore US, and $32 million for China ARO liabilities transferred to liabilities associated with assets held for sale.
For the year ended December 31, 2012
Liabilities incurred were due to new wells and facilities and included $6 million for onshore US development, $8 million for deepwater Gulf of Mexico, and $29 million for offshore Israel.
Liabilities settled primarily included $20 million related to non-core, onshore US assets sold, $55 million related to North Sea assets sold, and $34 million related to the Leviathan-2 appraisal well, offshore Israel.
Revisions were due to changes in estimated costs for future abandonment activities and included $54 million for onshore US, $6 million for deepwater Gulf of Mexico, $26 million for offshore Israel, and $16 million for offshore China.
Other includes North Sea ARO liabilities transferred to liabilities associated with assets held for sale.
See Note 2. Additional Financial Statement Information and Note 3. Property Transactions.
Accretion expense is included in DD&A expense in the consolidated statements of operations.
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Note 10. Long-Term Debt
Our debt consists of the following:
(1)
Our Credit Agreement provides for a $4.0 billion Credit Facility. The Credit Facility is available for general corporate purposes.
(2)
Imputed rate based on the prevailing market rates for similar debt instruments at the date of assessment.
All of our long-term debt is senior unsecured debt and is, therefore, pari passu with respect to the payment of both principal and interest. The indenture documents of each of our notes provide that we may prepay the instruments by creating a defeasance trust. The defeasance provisions require that the trust be funded with securities sufficient, in the opinion of a nationally recognized accounting firm, to pay all scheduled principal and interest due under the respective agreements. Interest on each of these issues is payable semi-annually. Debt issuance costs of approximately $41 million remain and are being amortized to expense over the life of the related debt issues and are included in current and long-term assets based on their related debt terms.
Credit Facility On October 3, 2013, we amended our $4.0 billion bank unsecured revolving credit facility (Credit Facility) to extend the maturity date to October 3, 2018.
The Credit Facility (i) provides for facility fee rates that range from 12.5 basis points to 30 basis points per year depending upon our credit rating, (ii) includes sub-facilities for short-term loans and letters of credit up to an aggregate amount of $500 million under each sub-facility and (iii) provides for interest rates that are based upon the Eurodollar rate plus a margin that ranges from 100 basis points to 145 basis points depending upon our credit rating.
The Credit Agreement requires that our total debt to capitalization ratio (as defined in the Credit Agreement), expressed as a percentage, not exceed 65% at any time. A violation of this covenant could result in a default under the Credit Agreement, which would permit the participating banks to restrict our ability to access the Credit Facility and require the immediate repayment of any outstanding advances under the Credit Facility. As of December 31, 2013, we were in compliance with our debt covenants.
The Credit Facility is available for general corporate purposes. Certain lenders that are a party to the Credit Agreement have in the past performed, and may in the future from time to time perform, investment banking, financial advisory, lending or commercial banking services for us for which they have received, and may in the future receive, customary compensation and reimbursement of expenses.
2013 Debt Offering On November 8, 2013, we closed an offering of $1.0 billion senior unsecured notes receiving net proceeds of $985 million, after deducting discount and underwriting fees. The notes are due November 15, 2043, and pay interest semi-annually at 5.25%. Total debt issuance costs of approximately $6 million were incurred and are being amortized to expense
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over the term of the notes. Approximately$900 million of the net proceeds were used to repay outstanding indebtedness under our Credit Facility and the balance of the proceeds has been used for general corporate purposes.
CONSOL Installment Payments On September 30, 2011, we closed an agreement with CONSOL for the development of Marcellus Shale properties. In addition to the cash paid at closing, we agreed to make two installment payments of $328 million each, the first of which was paid on September 30, 2012. The second installment payment was paid on September 30, 2013. See Note 3. Property Transactions and Note 13. Fair Value Measurements and Disclosures.
Capital Lease and Other Obligations The amounts of the capital lease obligations are based on the discounted present value of future minimum lease payments, and therefore do not reflect future cash lease payments. Amounts due within one year equal the amount by which the capital lease obligations are expected to be reduced during the next 12 months. See Note 18. Commitments and Contingencies for future capital lease payments.
Annual Debt Maturities Annual maturities of outstanding debt, excluding capital lease payments, are as follows:
Note 11. Income Taxes
Components of income (loss) from continuing operations before income taxes are as follows:
The income tax provision (benefit) from continuing operations consists of the following:
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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, 2013. The amount of the deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced.
The valuation allowance on the deferred tax assets associated with foreign loss carryforwards totaled $135 million in 2013, $81 million in 2012, and $65 million in 2011. The changes to the valuation allowance for the loss carryforwards between periods were attributable to changes in losses on projects in new venture activities which are not yet commercial.
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During 2013, as a result of execution of tax planning strategies, we reversed a $27 million deferred tax asset for future foreign tax credits from our foreign branch operations along with the corresponding valuation allowance. Additionally, we recorded a $20 million valuation allowance on excess foreign tax credits.
During 2012, as a result of execution of tax planning strategies, we reversed a $57 million deferred tax asset for future foreign tax credits from our foreign branch operations along with the corresponding valuation allowance. Additionally, we recorded a $38 million valuation allowance on excess foreign tax credits and released $12 million of deferred tax liability for a net increase in deferred income tax expense.
Effective Tax Rate Our effective tax rate increased in 2013 as compared with 2012 primarily due to a change in the funding of foreign exploration projects and an increase in the Israeli corporate income tax rate. The increase was partially offset by a release of the valuation allowance on foreign tax credits utilized on the 2012 tax return, a change to the tax contingencies, and an increase in the difference between the higher US statutory rate and lower statutory rates in jurisdictions where we are generating income, including Israel and Equatorial Guinea.
Our effective tax rate increased in 2012 as compared with 2011, primarily due to reduced impact of equity method earnings, which had the effect of decreasing the 2011 rate. The rate also increased due to additional valuation allowances and nondeductible allocation of goodwill to assets sold in 2012.
Changes in Israeli Tax Law In July 2013, the Israeli government increased the corporate income tax rate from 25% to 26.5%, effective January 2014. The change increased the deferred tax expense for 2013 by $12 million, which is reported in other, net within our effective rate reconciliation above.
Accumulated Undistributed Earnings of Foreign Subsidiaries As of December 31, 2013, the accumulated undistributed earnings of the foreign subsidiaries that have been permanently reinvested were approximately $3.7 billion. No US taxes have been recorded on these earnings. Upon distribution of earnings classified as permanently reinvested 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 $700 million.
Unrecognized Tax Benefits We file a consolidated income tax return in the US federal jurisdiction, and we file income tax returns in various states and foreign jurisdictions. Our income tax returns are routinely audited by the applicable revenue authorities, and provisions are routinely made in the financial statements for differences between positions taken in tax returns and amounts recognized in the financial statements in anticipation of the results of these audits.
In our major tax jurisdictions, the earliest years remaining open to examination are: U.S. - 2010, Equatorial Guinea - 2008, Israel - 2009, and China - 2010.
Our policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense. However, we did not accrue penalties at December 31, 2012 or 2011, because we believe that we are below the minimum statutory threshold for imposition of penalties.
A reconciliation of our beginning and ending amounts of unrecognized tax benefits follows:
As of December 31, 2013, approximately $28 million of unrecognized tax benefits would impact our effective tax rate if recognized. The changes to our unrecognized tax benefits during the twelve months ended December 31, 2013 primarily resulted from changes in various foreign tax return filings and positions. The adjustments to our reserves for uncertain tax positions had a de minimis impact on our net income.
During the year ended December 31, 2013, we recognized and accrued a de minimis amount of interest and none in penalties.
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We expect that our unrecognized tax benefits could continue to change due to the settlement of audits and the expiration of statutes of limitation in the next twelve months; however, we do not anticipate any such change to have a significant impact on our results of operations, financial position or cash flows in the next twelve months.
Note 12. Stock-Based and Other Compensation Plans
We recognized total stock-based compensation expense as follows:
Stock Option and Restricted Stock Plans Our stock option and restricted stock plans are described below.
1992 Stock Option and Restricted Stock Plan Under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan, as amended (the 1992 Plan), the Compensation, Benefits and Stock Option Committee of the Board of Directors (the Committee) may grant stock options and award restricted stock to our officers or other employees and those of our subsidiaries. At December 31, 2013, 35,652,195 shares of our common stock were reserved for issuance, including 18,549,928 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 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 with a time-vested restriction vest over a three year period (20% after year one, an additional 30% after year two and the remaining 50% after year three) or over a two year period (40% after year one and remaining 60% after year two). Restricted stock awards with a market based restriction cliff vest after a three year period if the Company achieves certain levels of total shareholder return relative to a pre-determined industry peer group.
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 1,600,000. At December 31, 2013, 1,376,644 shares of our common stock were reserved for issuance, including 893,820 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 22,400 stock options on the date of election to the Board of Directors, annual grants of 5,600 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 22,400 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 9,600 shares of restricted stock on the date of election to the Board of Directors, annual awards of 2,400 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 9,600 shares of restricted stock). Restricted stock is restricted for a period of at least one year from the date of award.
1988 Nonqualified Stock Option Plan for Non-Employee Directors The 1988 Nonqualified Stock Option Plan for Non-Employee Directors of Noble Energy, Inc., as amended, (the 1988 Plan) provided for the issuance of stock options to our non-employee directors. Options issued under the 1988 Plan may be exercised one year after grant and expire ten years from the grant date. The 1988 Plan provided for the granting of a fixed number of stock options to each non-employee director annually
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(20,000 stock options for the first calendar year of service and 10,000 stock options for each year thereafter) on February 1 of each year. The 1988 Plan was terminated in 2005, and no additional options can be granted thereunder.
Stock Option Grants The fair value of each stock option granted was estimated on the date of grant using a Black-Scholes-Merton option valuation model that used the assumptions described below:
•
Expected term The expected term represents the period of time that options granted are expected to be outstanding, which is the grant date to the date of expected exercise or other expected settlement for options granted. The hypothetical midpoint scenario we use considers our actual exercise and post-vesting cancellation history and expectations for future periods, which assumes that all vested, outstanding options are settled halfway between the current date and their expiration date.
•
Expected volatility The expected volatility represents the extent to which our stock price is expected to fluctuate between the grant date and the expected term of the award. We use the historical volatility of our common stock for a period equal to the expected term of the option prior to the date of grant. We believe that historical volatility produces an estimate that is representative of our expectations about the future volatility of our common stock over the expected term.
•
Risk-free rate The risk-free rate is the implied yield available on US Treasury securities with a remaining term equal to the expected term of the option. We base our risk-free rate on a weighting of five and seven 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 $64 million in 2013, $72 million in 2012, and $40 million in 2011.
As of December 31, 2013, $39 million of compensation cost related to unvested stock options granted under the Plans remained to be recognized. The cost is expected to be recognized over a weighted-average period of 1.3 years . We issue new shares of our common stock to settle option exercises. Dividends are not paid on unexercised options.
Restricted Stock Awards Awards of time-vested restricted stock (shares subject to service conditions) are valued at the price of our common stock at the date of award. The fair values of market based restricted stock awards are estimated on the date of award using a Monte Carlo valuation model that uses the assumptions in the following table. The Monte Carlo model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility represents the extent to which our stock price is expected to fluctuate between now and the award’s anticipated term. We use the historical volatility of Noble Energy common stock for the three-year period ended prior to the
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date of award. The risk-free rate is based on a three-year period for U.S. Treasury securities as of the year ended prior to the date of award.
The assumptions used in valuing market based restricted stock awards granted were as follows:
Restricted stock activity was as follows:
The total fair value of restricted stock that vested was $43 million in 2013, $47 million in 2012, and $57 million in 2011.
The weighted average award-date fair value of restricted stock awarded was $38.07 per share in 2013, $50.75 per share in 2012, and $45.16 per share in 2011.
As of December 31, 2013, $47 million of compensation cost related to all of our unvested restricted stock awarded under the Plans remained to be recognized. The cost is expected to be recognized over a weighted-average period of 1.4 years. Common stock dividends accrue on restricted stock awards and are paid upon vesting. We issue new shares of our common stock when awarding restricted stock.
Other Compensation Plans
401(k) Plan We sponsor a 401(k) savings plan. All regular employees are eligible to participate. We make contributions to match employee contributions up to the first 6% of compensation deferred into the plan, and certain profit sharing contributions for employees hired on or after May 1, 2006, based upon their ages and salaries. We made cash contributions of $21 million in 2013, $17 million in 2012, and $14 million in 2011.
As a result of the termination of the retirement and restoration plans (see below), employees who were hired prior to May 1, 2006 will become eligible to receive profit sharing contributions effective January 1, 2014. In addition, certain of these employees will also be eligible to receive transition contributions related to the termination of the plans.
Deferred Compensation Plans We have a non-qualified deferred compensation plan for which participant-directed investments are held in a rabbi trust and are available to satisfy the claims of our creditors in the event of bankruptcy or insolvency. Participants may elect to receive distributions in either cash or shares of our common stock. Components of the rabbi trust are as follows:
Assets of the rabbi trust, other than our common stock, are invested in certain mutual funds that cover an investment spectrum ranging from equities to money market instruments. These mutual funds have published market prices and are reported at fair
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value. See Note 13. 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, $16.72 per share) in the shareholders’ equity section of the consolidated balance sheets. Amounts payable to plan participants are included in other noncurrent liabilities in the consolidated balance sheets and include the market value of the shares of our common stock. Approximately 1,200,000 shares, or 93%, of our common stock held in the plan at December 31, 2013 were attributable to a member of our Board of Directors. The shares are being distributed in equal installments over the next six years. Distributions of 200,000 shares were made in each of 2013 and 2012. In addition, plan participants sold 1,008 shares of our common stock in 2013, 4,536 shares in 2012, and 200 shares in 2011. Proceeds were invested in mutual funds and/or distributed to plan participants. Distributions to plan participants were valued at $25 million in 2013, $19 million in 2012 and $17 million in 2011.
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 $26 million in 2013, $6 million in 2012 and $8 million in 2011.
We also maintain an unfunded deferred compensation plan for the benefit of certain of our employees. Deferred compensation liabilities of $77 million, $70 million and $60 million were outstanding at December 31, 2013, 2012 and 2011, respectively, under the unfunded plan.
Pension and Other Postretirement Benefit Plans We have a noncontributory, tax-qualified defined benefit pension plan covering employees who were hired prior to May 1, 2006, and an unfunded, nonqualified restoration plan that provides the pension plan formula benefits that cannot be provided by the qualified pension plan because of pay deferrals and the compensation and benefit limitations imposed on the pension plan by the Internal Revenue Code of 1986, as amended. We sponsor other plans, which include medical and life insurance benefits, for the benefit of our employees and retirees.
During the fourth quarter of 2013, we notified the Retirement Plan participants that, effective December 31, 2013: Retirement Plan benefit accruals will cease and the Retirement Plans will be frozen; and certain plan amendments were adopted related to final average earnings, age 55 subsidies and a lump sum rate change related to this notification. We will begin the process of securing approval from the Pension Benefit Guaranty Corporation and IRS to liquidate the related Retirement Trust and complete the Retirement Plan termination. The Retirement Plan participants will continue to receive benefits until the Retirement Trust is liquidated, primarily through lump-sum payments to participants, and this process could take up to two years to complete. The restoration plan will also be terminated.
As a result of the cessation of accrual of additional Retirement Plan benefits earned, a plan curtailment has been triggered. Moreover, the work force has been reduced or the accrual of benefits for some or all future services has been eliminated, and the Company will not realize all the expected future economic benefits of the plan amendments being amortized as prior service cost over the expected remaining service lives of the participants. Consequently, the unamortized prior service cost of $2 million relating to the Retirement Plan participants affected was expensed as of December 31, 2013. We reduced the pension benefit obligation by approximately $33 million to omit the impact of expected future salary increases due to the plan freeze. This reduction in the benefit obligation from the curtailment resulted in a gain, which was offset by existing unamortized net loss recorded in AOCL.
Regarding the plan amendments, we recorded an increase in the plan benefit obligation and new prior service cost of approximately $88 million. The new prior service costs included in AOCL will be amortized consistent with our amortization policy. Upon plan termination, all remaining unamortized prior service cost and net actuarial loss will be charged to expense.
The benefit obligations, plan assets and AOCL balances for the pension, restoration and other postretirement benefit plans are summarized below as of December 31:
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At December 31, 2013, plan assets were invested primarily in cash and fixed-income securities. We expect to make additional contributions to the pension and restoration plans during the next 12 to 24 months to the extent necessary to fund remaining benefit obligations.
Net periodic benefit cost related to these plans totaled $37 million in 2013, $27 million in 2012, and $21 million in 2011.
Note 13. 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. We estimate the fair values of these instruments based on published forward commodity price curves as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates.
The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. In addition, for collars, we estimate the option values of the put options sold (for three-way collars) and the contract floors and ceilings (for two-way and three-way collars) using an option pricing model which takes into account market volatility, market prices and contract terms. See Note 8. 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.
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.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
(2)
Amount represents the impact of netting clauses within our master agreements that allow us to net cash settle asset and liability positions with the same counterparty.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Certain assets and liabilities are measured at fair value on a nonrecurring basis in our consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:
Asset Impairments We determined that the carrying amounts of certain assets were not recoverable from future cash flows and, therefore, were impaired. The assets were reduced to their estimated fair values. Information about the impaired assets is as follows:
(1)
See Note 1. Summary of Significant Accounting Policies - Fair Value Measurements for a description of the fair value hierarchy.
(2)
Amount represents net book value at the date of assessment.
The fair values of the properties held and used were determined as of the date of the assessment using discounted cash flow models. The discounted cash flows were based on management’s expectations for the future. Inputs included estimates of future oil and gas production, commodity prices based on sales contract terms or NYMEX commodity price curves as of the date of the estimate, estimated operating and development costs, and a risk-adjusted discount rate of 10%. The fair values of assets held for sale were based on anticipated sales proceeds less costs to sell. See Note 4. Asset Impairments.
Additional Fair Value Disclosures
Debt The fair value of fixed-rate, public debt is estimated based on the published market prices for the same or similar issues. As such, we consider the fair value of our public fixed rate debt to be a Level 1 measurement on the fair value hierarchy. The carrying amounts of the CONSOL installment payment at December 31, 2012 approximated fair value because it had been discounted at the prevailing market rate for similar debt instruments. As such, we considered the fair value of our CONSOL installment payment to be a Level 2 measurement on the fair value hierarchy. See Note 10. Long-Term Debt. Fair value information regarding our debt is as follows:
(1)
Excludes capital lease and other obligations. No floating rate debt was outstanding at December 31, 2013 or December 31, 2012. See Note 10. Long-Term Debt.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 14. Earnings Per Share
Basic earnings per share of common stock is computed using the weighted average number of shares of common stock outstanding during each period. The diluted earnings per share of common stock include the effect of outstanding stock options, shares of restricted stock, or shares of our common stock held in a rabbi trust (when dilutive). The following table summarizes the calculation of basic and diluted earnings per share:
Note 15. Segment Information
We have operations throughout the world and manage our operations by region. The following information is grouped into four components that are all primarily in the business of crude oil and natural gas exploration, development, and acquisition: the United States; West Africa (Equatorial Guinea, Cameroon, Sierra Leone, and Senegal/Guinea-Bissau (which we exited in 2012); Eastern Mediterranean (Israel and Cyprus); and Other International and Corporate. Other International includes China, Ecuador (through May 2011), Falkland Islands, Nicaragua and new ventures. As of December 31, 2013, the remaining North Sea assets were reclassified to assets held for sale; prior year amounts have been reclassified to exclude the North Sea geographical segment from continuing operations. See Note 3. Property Transactions.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
(1) Revenues from third parties for all foreign countries, in total, were $1.8 billion in 2013, $1.7 billion in 2012, and $1.1 billion in 2011.
(2) Long-lived assets located in all foreign countries, in total, were $4.5 billion, $4.2 billion, and $3.2 billion at December 31, 2013, 2012, and 2011, respectively.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 16. Concentration of Risk
Concentration of Market Risk The largest single non-affiliated purchasers of our production were as follows:
(1) Includes sales to both Shell Trading (US) Company and Shell International Trading and Shipping Limited.
We believe the loss of any one purchaser would not have a material effect on our financial position or results of operations since there are numerous potential purchasers of our production.
Concentration of Credit Risk Certain of our financial instruments, including cash equivalents, trade and joint interest receivables and derivative instruments, may expose us to credit risk.
A significant portion of our cash is located in our foreign subsidiaries. The cash is denominated in US dollars and invested in highly liquid money market funds and short term deposits with original maturities of three months or less at the time of purchase. Although our cash and cash equivalents are deposited with major international banks and financial institutions, concentrations of cash in certain foreign locations may increase credit risk. We monitor the creditworthiness of the banks and financial institutions with which we invest and review the securities underlying our investment accounts. We believe that losses from nonperformance are unlikely to occur; however, we are not able to predict sudden changes in creditworthiness.
Our accounts receivable result from sales of crude oil, natural gas and NGL production, and joint interest billings to our partners for their share of expenses on joint venture projects for which we are the operator. Joint venture projects, such as 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.
Our increased level of hedging activity may increase our counterparty credit risk, especially during periods of falling commodity prices. We conduct our hedging activities with a diverse group of investment grade major banks and market participants. We monitor the creditworthiness of our hedging counterparties, and our internal hedge policies provide for mark-to-market exposure limits. We use master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be “net settled” at the time of election.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 17. Additional Shareholders’ Equity Information
Activity in shares of our common stock and treasury stock was as follows:
Accumulated other comprehensive loss in the shareholders’ equity section of the balance sheet included:
All amounts in the table above are reported net of tax, using an effective income tax rate of 35%.
Note 18. Commitments and Contingencies
Legal Proceedings We are involved in various legal proceedings in the ordinary course of business. These proceedings are subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters and we believe that the ultimate disposition of such proceedings will not have a material adverse effect on our financial position, results of operations or cash flows.
CONSOL Carried Cost Obligation Based on the December 31, 2013 Henry Hub natural gas price strip, and our current development plan, we forecast our CONSOL Carried Cost Obligation may commence in March 2014.
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 $50 million in 2013, $37 million in 2012, and $31 million in 2011.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Minimum commitments as of December 31, 2013 consist of the following:
(1)Annual lease payments, net to our interest, exclude regular maintenance and operational costs. See Note 10. 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, 2013, 2012, and 2011 reserves estimates on 12-month average commodity prices, unless contractual arrangements designate the price to be used, in accordance with SEC rules. However, commodity prices are volatile. Declines in crude oil or natural gas prices could result in negative reserves revisions.
Reserves Estimates Qualified petroleum engineers in our Houston and Denver offices prepare all reserves estimates for our different geographical regions. These reserves estimates are reviewed and approved by regional management and senior engineering staff with final approval by the Senior Vice President - Corporate Development 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, 2013. See Items 1. and 2. Business and Properties - Proved Reserves Disclosures.
Geographic Areas Our supplemental disclosures are grouped by geographic area, which include the United States, Equatorial Guinea, Israel and Other International. Other International includes Cameroon, China, Cyprus, Falkland Islands, North Sea, Nicaragua, Sierra Leone, Senegal/Guinea-Bissau (through 2011) and other new ventures. The North Sea geographical segment is classified as discontinued operations in our consolidated financial statements.
Operations in China, Cyprus, Equatorial Guinea, and Sierra Leone are conducted in accordance with the terms of PSCs. In Cameroon, we operate in accordance with the terms of a PSC and a mining concession. Operations in Nicaragua, the Falkland Islands, the North Sea, Israel, and other foreign locations are conducted in accordance with concession agreements, permits or licenses.
Definitions The following definitions apply to the terms used in the paragraphs above:
Reserves Estimate The determination of an estimate of a quantity of oil or gas reserves that are thought to exist at a certain date, considering existing prices and reservoir conditions.
Reserves Audit The process of reviewing certain of the pertinent facts interpreted and assumptions underlying a reserves estimate prepared by another party and the rendering of an opinion about the appropriateness of the methodologies employed, the adequacy and quality of the data relied upon, the depth and thoroughness of the reserves estimation process, the classification of reserves appropriate to the relevant definitions used, and the reasonableness of the estimated reserves quantities.
The following definitions apply to our categories of proved reserves:
Proved Oil and Gas Reserves Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to produce 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.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Undeveloped Oil and Gas Reserves Proved undeveloped oil and gas reserves (PUDs) are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
For complete definitions of proved natural gas, natural gas liquids and crude oil reserves, refer to SEC Regulation S-X, Rule 4-10(a)(6), (22) and (31).
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Proved Oil Reserves (Unaudited) The following reserves schedule was developed by our qualified petroleum engineers and sets forth the changes in estimated quantities of proved crude oil reserves:
(1)
United States NGL proved reserves totaled:
(2)
Other International includes China, the North Sea and Israel.
(3)
The 2011 US revisions were primarily associated with reclassification of vertical PUDs to probable reserves in the DJ Basin which were 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 were associated with performance revisions in China and the North Sea.
The 2012 US revisions were primarily attributable to our decision to terminate the legacy vertical drilling program in the DJ Basin and focus on the horizontal development of the Niobrara formation. Equatorial Guinea revisions were associated with performance revisions for the Aseng field.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
The 2013 US revisions are primarily associated with positive performance revisions to our DJ Basin and Marcellus Shale programs as well as 2 MMBbls of positive price revisions. Equatorial Guinea revisions are associated with positive performance revisions to the Alba field.
(4)
The 2011 increase was from development of onshore assets, primarily in the DJ Basin.
The 2012 increase in US reserves included an increase of 98 MMBbls in the DJ Basin and 8 MMBbls from Marcellus Shale development. International increases were due primarily to additional development in China.
The 2013 increase in US reserves included an increase of 89 MMBbls in the DJ Basin and 9 MMBbls from Marcellus Shale development as well as 15 MMBbls in the deepwater Gulf of Mexico from sanctioned development projects. The increase in Equatorial Guinea was attributable to future infill development at the Alba field. The increase to Other International included 1 MMBbls in China.
(5)
The 2013 increase is attributable to the acquisition of additional acreage in the Marcellus Shale and other onshore US locations.
(6)
In 2012, we sold non-core, onshore US and North Sea assets.
In 2013, sales include divestitures of non-core, onshore US and North Sea assets as well as the net impact of the DJ Basin acreage exchange.
(7)
Equatorial Guinea production includes sales from the Alba field to the Alba LPG plant of 3 MMBbl in 2013, 2012 and 2011.
See also Items 1. and 2. Business and Properties - Proved Undeveloped Reserves (PUDs) and Note 3. Property Transactions.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Proved Gas Reserves (Unaudited) The following reserves schedule was developed by our qualified petroleum engineers and sets forth the changes in estimated quantities of proved natural gas reserves:
(1)
Other International includes China and the North Sea. See Note 3. Property Transactions.
(2)
The 2011 US revisions were primarily associated with reclassification of vertical PUDs in the DJ Basin which were 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 were associated with performance revisions in the North Sea.
The 2012 US revisions were primarily attributable to our decision to terminate the legacy vertical drilling program in the DJ Basin and focus on the horizontal development of the Niobrara formation, and negative price revisions due to lower natural gas prices, partially offset by improved well performance in the Marcellus Shale. Israel revisions were due to performance revisions in the Mari-B field.
The 2013 US revisions are primarily associated with positive performance revisions to our DJ Basin and Marcellus Shale programs as well as 68 Bcf of positive price revisions. Equatorial Guinea revisions are associated with positive performance revisions to the Alba field. Israel revisions are primarily associated with positive performance revisions to the Tamar field.
(3)
The 2011 increase in the US was 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 included reserves for Noa which we decided to develop.
The 2012 increase in US reserves included 305 Bcf in the DJ Basin and 291 Bcf in the Marcellus Shale. The Equatorial Guinea increase was due to additions at Aseng, and the Israel increase was due to additional appraisal activity at Tamar.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
The 2013 increase in US reserves include an increase of 250 Bcf in the DJ Basin and 317 Bcf from Marcellus Shale development as well as 18 Bcf in the deepwater Gulf of Mexico primarily from sanctioned development projects. Increases in Equatorial Guinea are attributable to future infill development at the Alba and Alen fields. Increases to Israel are due to discovery and sanction of the Tamar Southwest field.
(4)
The increase related to the Marcellus Shale asset acquisition in 2011.
The 2013 increase is attributable to the acquisition of additional acreage in the Marcellus Shale and other onshore US locations.
(5)
In 2012, we sold non-core, onshore US and North Sea assets.
In 2013, sales include divestitures of non-core, onshore US and North Sea assets as well as the net impact of the DJ Basin acreage exchange.
See also Items 1. and 2. Business and Properties - Proved Undeveloped Reserves (PUDs) and Note 3. Property Transactions.
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, China, Cameroon, Cyprus, Senegal/Guinea-Bissau (through 2011), Nicaragua, Falkland Islands, Sierra Leone and other new ventures. See Note 3. Property Transactions.
(2)
Production costs consist of lease operating expense, production and ad valorem taxes, transportation expense, and general and administrative expense supporting oil and gas operations.
(3)
During 2013 and 2012, we incurred exploration expense in currently non-commercial international locations; therefore, no tax benefit was included in income tax expense associated with Other International as we could not conclude it was more likely than not that some portion or all of the deferred tax assets would be realized.
(4)
Results of operations exclude the mark-to-market gain or loss on commodity derivative instruments, corporate overhead and interest costs. See Note 8. Derivative Instruments and Hedging Activities.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities (Unaudited) (1)
Costs incurred in connection with crude oil and natural gas acquisition, exploration and development are as follows:
(1)
Costs incurred include capitalized and expensed items.
(2)
Other International includes Cameroon, China, Cyprus, Falkland Islands, the North Sea, Nicaragua, Sierra Leone, and Senegal/Guinea-Bissau (through December 31, 2011). See Note 3. Property Transactions.
(3)
2013 unproved property acquisition costs include: $166 million and $27 million related to expanding our positions in the Marcellus Shale and DJ Basin, respectively, and $12 million for deepwater Gulf of Mexico lease blocks.
2012 unproved property acquisition costs for the US include: $63 million related to expanding our position in the DJ Basin, $28 million for deepwater Gulf of Mexico lease blocks, and $27 million related to other onshore US, offset by a downward purchase price adjustments of $50 million related to our Marcellus Shale acquisition. 2012 unproved property acquisition costs for Other International include $25 million related to our position in Falkland Islands.
2011 unproved property acquisition costs include: $853 million related to the Marcellus Shale asset acquisition, $40 million related to our position offshore Senegal/Guinea-Bissau, $31 million related to additional acreage in the DJ Basin and $58 million related to other onshore US.
(4)
2013 exploration costs include drilling and completion of $106 million in the deepwater Gulf of Mexico, $23 million in northeast Nevada, $19 million in the Marcellus Shale, $11 million in the DJ Basin, $187 million in Equatorial Guinea, $93 million in Israel and $115 million in Cyprus.
2012 exploration costs include drilling and completion of $36 million in the DJ Basin, $40 million in Equatorial Guinea, $102 million in Israel, $13 million in Cyprus and $71 million in Falkland Islands.
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.
(5)
Worldwide development costs include amounts spent to develop PUDs of approximately $1.0 billion in 2013, $1.8 billion in 2012 and $1.4 billion in 2011.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
US development costs include increases in asset retirement obligations of $214 million in 2013, $73 million in 2012, and $115 million in 2011. Other international development costs include increases in asset retirement obligations of $32 million in 2013, $72 million in 2012, and $13 million in 2011.
Equatorial Guinea development costs include non-cash accruals related to estimated construction progress to date on an FSPO used in the development of the Aseng field of $66 million in 2011. These capitalized costs were included in development costs as the Aseng FPSO was constructed.
(6)
Proved property acquisition costs include $386 million related to the Marcellus Shale asset acquisition in 2011.
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 include amounts remaining from the allocation of costs to unproved properties acquired in previous acquisitions, primarily the Marcellus Shale, of $860 million and $740 million at December 31, 2013 and 2012, respectively.
(2)
Proved oil and gas properties at December 31, 2013 include assets held for sale of $323 million related to China and $88 million related to the North Sea, and asset retirement costs of $501 million.
Proved oil and gas properties at December 31, 2012 include North Sea assets held for sale of $200 million and asset retirement costs of $334 million.
(3)
Accumulated DD&A at December 31, 2013 includes $187 million related to China assets held for sale and and $50 million related to North Sea assets held for sale.
Accumulated DD&A at December 31, 2012 includes $160 million related to North Sea assets held for sale. See Note 3. Property Transactions.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited) The following information is based on our best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows in accordance with US GAAP. The standards require the use of a 10% discount rate. This information is not the fair value nor does it represent the expected present value of future cash flows of our proved oil and gas reserves.
(1)
Other International includes China and the North Sea. See Note 3. Property Transactions.
(2)
The standardized measure of discounted future net cash flows does not include cash flows relating to anticipated future methanol sales.
(3)
Production costs include oil and gas lease operating expense, production and ad valorem taxes, transportation expense and general and administrative expense supporting oil and gas operations.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Prices and Other Assumptions in Discounted Future Net Cash Flows (Unaudited) Future cash inflows are computed by applying a 12-month average commodity price, adjusted for location and quality differentials on a field-by-field basis, to year-end quantities of proved reserves, except in those instances where fixed and determinable price changes are provided by contractual arrangements at year-end. The discounted future cash flow estimates do not include the effects of derivative instruments. Average prices per region are as follows:
(1)
Other International includes China and the North Sea. See Note 3. Property Transactions.
We estimate that a $1.00 per Bbl change in the average price of crude oil from the 12-month average price for 2013 would change the discounted future net cash flows before income taxes by approximately $253 million. We estimate that a $0.10 per Mcf change in the average price of natural gas from the 12-month average price for 2013 would change the discounted future net cash flows before income taxes by approximately $262 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 $3.2 billion in 2014, $2.1 billion in 2015 and $1.2 billion in 2016.
Future income tax expense is computed by applying the appropriate year-end statutory tax rates to the estimated future pre-tax net cash flows relating to proved crude oil and natural gas reserves, less the tax bases of the properties involved. Future income tax expense gives effect to tax credits and allowances, but does not reflect the impact of general and administrative costs and exploration expenses of ongoing operations.
Imbalance receivables and liabilities are as follows:
Imbalance receivables and imbalance liabilities have been excluded from the standardized measure of discounted future net cash flows.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Sources of Changes in Discounted Future Net Cash Flows (Unaudited) Principal changes in the aggregate standardized measure of discounted future net cash flows attributable to proved crude oil and natural gas reserves are as follows:
Supplemental Quarterly Financial Information
(Unaudited)
Supplemental quarterly financial information is as follows:
(1)
First quarter 2013 included the following:
•
$72 million loss on commodity derivative instruments, including unrealized mark-to-market loss of $79 million (See Note 8. Derivative Instruments and Hedging Activities); and
•
$12 million pre-tax gain on sale of non-core asset (See Note 3. Property Transactions).
Second quarter 2013 included the following:
•
$161 million gain on commodity derivative instruments, including unrealized mark-to-market gain of $159 million (See Note 8. Derivative Instruments and Hedging Activities).
Third quarter 2013 included the following:
•
$157 million loss on commodity derivative instruments, including unrealized mark-to-market loss of $147 million (See Note 8. Derivative Instruments and Hedging Activities); and
•
$63 million impairment charges (See Note 4. Asset Impairments).
Fourth quarter 2013 included the following:
•
$23 million impairment charges (See Note 4. Asset Impairments);
•
$24 million pre-tax gain on sale of non-core onshore US assets (See Note 3. Property Transactions); and
Supplemental Quarterly Financial Information
(Unaudited)
•
$65 million loss on commodity derivative instruments, including unrealized mark-to-market loss of $64 million (See Note 8. Derivative Instruments and Hedging Activities).
(2)
First quarter 2012 included the following:
•
$96 million loss on commodity derivative instruments, including unrealized mark-to-market loss of $73 million (See Note 8. Derivative Instruments and Hedging Activities).
Second quarter 2012 included the following:
•
$73 million asset impairment charges (See Note 4. Asset Impairments);
•
$276 million gain on commodity derivative instruments, including unrealized mark-to-market gain of $277 million (See Note 8. Derivative Instruments and Hedging Activities); and
•
$9 million pre-tax gain on sale of non-core onshore US assets (See Note 3. Property Transactions).
Third quarter 2012 included the following:
•
$135 million loss on commodity derivative instruments, including unrealized mark-to-market loss of $131 million (See Note 8. Derivative Instruments and Hedging Activities); and
•
$157 million pre-tax gain on sale of non-core onshore US assets (See Note 3. Property Transactions).
Fourth quarter 2012 included the following:
•
$31 million impairment charges (See Note 4. Asset Impairments);
•
$13 million pre-tax loss on sale of non-core onshore US assets (See Note 3. Property Transactions); and
•
$30 million gain on commodity derivative instruments, including unrealized mark-to-market gain of $36 million (See Note 8. Derivative Instruments and Hedging Activities).
(3)
The sum of the individual quarterly earnings (loss) per share amounts may not agree with year-to-date earnings per share as each quarterly computation is based on the income or loss for that quarter and the weighted average number of shares outstanding during that quarter.
(4)
Consistent with GAAP, when dilutive, deferred compensation gains or losses, net of tax, are excluded from net income while the Noble Energy shares held in the rabbi trust are included in the diluted share count. For this reason, the diluted earnings per share calculation for the three months ended June 30, 2012 excludes deferred compensation gains of $7 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, 2013. 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 2014 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2013.
Item 11. Executive Compensation
The information required by this item is incorporated herein by reference to the 2014 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2013.
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 2014 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2013.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this item is incorporated herein by reference to the 2014 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2013.
Item 14. Principal Accounting Fees and Services
The information required by this item is incorporated herein by reference to the 2014 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2013.
PART IV
Item 15. Exhibits and Financial Statement Schedules
a) The following documents are filed as a part of this report:
(3)
Exhibits: The exhibits required to be filed by this Item 15 are set forth in the Index to Exhibits accompanying this report.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
NOBLE ENERGY, INC.
(Registrant)
Date:
February 6, 2014
By: /s/ Charles D. Davidson
Charles D. Davidson,
Chairman of the Board,
Chief Executive Officer and Director
Date:
February 6, 2014
By: /s/ Kenneth M. Fisher
Kenneth M. Fisher,
Executive Vice President, Chief Financial Officer
Date:
February 6, 2014
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 6, 2014
Charles D. Davidson
Chief Executive Officer and Director
(Principal Executive Officer)
/s/ Kenneth M. Fisher
Executive Vice President, Chief Financial Officer
February 6, 2014
Kenneth M. Fisher
(Principal Financial Officer)
/s/ Dustin A. Hatley
Vice President, Chief Accounting Officer and Controller
February 6, 2014
Dustin A. Hatley
(Principal Accounting Officer)
/s/ Jeffrey L. Berenson
Director
February 6, 2014
Jeffrey L. Berenson
/s/ Michael A. Cawley
Director
February 6, 2014
Michael A. Cawley
/s/ Edward F. Cox
Director
February 6, 2014
Edward F. Cox
/s/ Thomas J. Edelman
Director
February 6, 2014
Thomas J. Edelman
/s/ Eric P. Grubman
Director
February 6, 2014
Eric P. Grubman
/s/ Kirby L. Hedrick
Director
February 6, 2014
Kirby L. Hedrick
/s/ Scott D. Urban
Director
February 6, 2014
Scott D. Urban
/s/ William T. Van Kleef
Director
February 6, 2014
William T. Van Kleef
/s/ Molly K. Williamson
Director
February 6, 2014
Molly K. Williamson
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 Executive Vice President and Chief Financial Officer, Noble Energy, Inc., 1001 Noble Energy Way, Houston, Texas 77070.
GLOSSARY
In this report, the following abbreviations are used:
Bbl
Barrel
BBoe
Billion barrels oil equivalent
Bcf
Billion cubic feet
Bcf/d
Billion cubic feet per day
BCM
Billion cubic meters
BOE
Barrels oil equivalent. Natural gas is converted on the basis of six Mcf of gas per one barrel of crude oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given commodity price disparities, the price for a barrel of crude oil equivalent for natural gas is significantly less than the price for a barrel of crude oil. The price for a barrel of NGL is also less than the price for a barrel of crude oil.
Boe/d
Barrels oil equivalent per day
Btu
British thermal unit
FPSO
Floating production, storage and offloading vessel
GHG
Greenhouse gas emissions
HH
Henry Hub index
LNG
Liquefied natural gas
LPG
Liquefied petroleum gas
MBbl/d
Thousand barrels per day
MBoe/d
Thousand barrels oil equivalent per day
Mcf
Thousand cubic feet
MMBbls
Million barrels
MMBoe
Million barrels oil equivalent
MMBtu
Million British thermal units
MMBtu/d
Million British thermal units per day
MMcf/d
Million cubic feet per day
MMcfe/d
Million cubic feet equivalent per day
MMgal
Million gallons
NGL
Natural gas liquids
NYMEX
The New York Mercantile Exchange
PSC
Production sharing contract
Tcf
Trillion cubic feet
US GAAP
United States generally accepted accounting principles
WTI
West Texas Intermediate index