Company: NOBLE ENERGY INC
CIK: 72207
SIC: 1311
Filing Date: 2015-02-19 00:00:00

ITEM 1 - BUSINESS

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

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

ITEM 2 - PROPERTIES

ITEM 3 - LEGAL PROCEEDINGS
Item 3. Legal Proceedings
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. In July 2014, we reached a resolution with OOG regarding the NOVs and Orders. The resolution of these proceedings did not have a material adverse effect on our financial position, results of operations or cash flows.
Colorado Air Matter In August 2013, we received an information request from the EPA under Section 114 of the Clean Air Act regarding several tank batteries used in our DJ Basin operations. The information request relates to our compliance with certain regulatory requirements at those locations, including air emissions of volatile organic compounds in a marginal ozone non-attainment area. We responded to the EPA’s information requests between November 2013 and April 2014 and are in settlement discussions with the EPA and the State of Colorado regarding potential noncompliance with the Clean Air Act, Colorado's State Implementation Plan, Colorado's Air Pollution Prevention and Control Act and its implementation regulations. To date, no federal or state enforcement action has been commenced in connection with this matter. We anticipate that resolution of this matter will result in civil penalties of an undetermined amount and require us to undertake corrective actions which may increase our development and/or operating costs. Given the uncertainty in matters such as these, we are unable to predict the ultimate outcome of this matter at this time. However, we do not believe that any penalties or remediation expenditures that may result from this matter will have a material adverse effect on our financial position, results of operations or cash flows.
See also Item 8. Financial Statements and Supplementary Data - Note 17. Commitments and Contingencies.

ITEM 4 - RESERVED
Item 4. Mine Safety Disclosures
Not Applicable.
PART II

ITEM 5 - MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Common Stock Our common stock, $0.01 par value, is listed and traded on the NYSE under the symbol “NBL.” The declaration and payment of dividends 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 second quarter 2013.
On January 27, 2015, the Board of Directors declared a quarterly cash dividend of $0.18 per common share, which will be paid February 23, 2015 to shareholders of record on February 9, 2015.
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 15, 2015, the number of holders of record of our common stock was 617.
Stock Repurchases The following table summarizes repurchases of our common stock occurring in fourth quarter 2014.
(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, 2014:
Stock Performance Graph This graph shows our cumulative total shareholder return over the five-year period from December 31, 2009 to December 31, 2014. 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.
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
On January 27, 2014, the Compensation, Benefits and Stock Option Committee of the Board of Directors (the Committee) made changes to our compensation peer group to remove Newfield Exploration Company from the old peer group listed above. After the change in companies, the 2014 compensation peer group consisted of the following:
Anadarko Petroleum Corp.
Hess Corporation
Apache Corp.
Marathon Oil Corporation
Cabot Oil & Gas Corp.
Murphy Oil Corp.
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
The comparison assumes $100 was invested on December 31, 2009 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.
Copyright© 2014 S&P, a division of The McGraw-Hill Companies Inc. All rights reserved.

ITEM 6 - SELECTED FINANCIAL DATA
Item 6. Selected Financial Data
(1)
Amounts adjusted for the 2-for-1 stock split which occurred during second quarter 2013.
(2)
Prices for 2010 include effects of crude oil and natural gas cash flow hedging activities.

ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide a narrative about our business from the perspective of our management. 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, natural gas and NGLs. 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, and we are currently conducting exploration activities in domestic and international locations.
Commodity Price Changes The upstream oil and gas business is cyclical. During fourth quarter 2014, a significant decline in crude oil prices occurred resulting in lower revenues and reduced margins. NYMEX WTI crude oil prices fell approximately 50% between June and December, with a similar Brent crude oil price decline, due to falling demand, as well as world-wide oversupply exacerbated by OPEC's November decision to hold production steady. As a result, our total consolidated average realized crude oil prices for fourth quarter 2014 decreased almost 30% as compared with fourth quarter 2013. During early 2015, crude oil prices have continued to be weak.
We are unable to predict the extent to which crude oil prices may recover during 2015. Prices are likely to remain volatile and could decline further. In addition, we could be entering a period of sustained, lower worldwide crude oil prices.
We plan for these cyclical downturns in our business and feel we are well positioned to withstand current and future commodity price volatility:
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we have a high-quality, diversified portfolio of assets, a majority of which are held by production, which provide investment flexibility;
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we have positive operating cash flow (revenues less cash operating expenses), prior to capital expenditures, in each of our core areas;
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we have designed a substantially-reduced capital investment program which will allow us to respond to conditions that occur in 2015;
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we are well hedged, with approximately 60% of global crude oil and 50% of domestic natural gas production hedged for 2015, with additional quantities hedged into 2016;
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we have a strong balance sheet; and
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we have robust liquidity.
See Operating Outlook - 2015 Outlook below.
2014 Results Our recent growth was driven by our five core areas which we expect to provide for future long-term growth. In pursuit of our strategy, we progressed major development projects onshore US, in the deepwater Gulf of Mexico and offshore Israel, and continued exploration activities.
The growth of our DJ Basin and Marcellus Shale development programs resulted in total daily average sales volumes from continuing operations of 298 MBoe/d for 2014, an increase of 9% over 2013. In the DJ Basin, driven by expansion of horizontal drilling activity, we increased total 2014 daily production by 6%, as compared with 2013. Production from DJ Basin horizontal wells increased 28% year over year, while production from vertical wells declined 25% year over year.
In the Marcellus Shale, due to increased drilling activity, total 2014 daily production doubled as compared with 2013. We and our partner brought 129 new wells online.
Our equity method investee, CONE Gathering, contributed a significant majority of its existing assets to a newly-formed master limited partnership, CONE Midstream. We own a 32.1% interest in CONE Midstream, which constructs, owns and operates natural gas midstream assets in support of our Marcellus Shale joint venture activities.
The deepwater Gulf of Mexico program moved forward with continued progress at the Gunflint, Big Bend and Dantzler developments and successful well results at the Dantzler-2 appraisal well and the Katmai exploratory well. We also drilled the Bright and Madison exploratory wells, which did not encounter commercial quantities of hydrocarbons.
Our international assets continue to contribute substantially with world-class reliability from major projects in the Eastern Mediterranean and West Africa, including Tamar (offshore Israel), Aseng (offshore West Africa), and Alen (offshore West Africa). Each of these projects is a technical and commercial milestone that significantly adds to our production profile. We have also been engaged in marketing activities for our Eastern Mediterranean natural gas discoveries, for both domestic and export sale. See Update on Israel Antitrust Matters, below.
2014 Financial Results Included:
•
net income of $1.2 billion (all from continuing operations), as compared with $978 million (including $907 million from continuing operations) for 2013;
•
gain on divestitures of $73 million, as compared with $36 million for 2013;
•
dry hole expense of $226 million, as compared with $149 million for 2013;
•
asset impairment charges of $500 million, as compared with $86 million for 2013;
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gain on commodity derivative instruments of $976 million (including $947 million non-cash portion), as compared with $133 million loss on commodity derivative instruments (including $131 million non-cash portion) for 2013;
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diluted earnings per share of $3.27, as compared with $2.69 for 2013;
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cash flows provided by operating activities of $3.5 billion, as compared with $2.9 billion in 2013; and
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capital spending of $5.0 billion, as compared with $4.4 billion in 2013.
Significant Events Impacting Liquidity Included:
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proceeds of $321 million from sales of non-core properties;
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cash distributions of $204 million from CONE Gathering subsequent to the formation of a master limited partnership for Marcellus Shale midstream assets and completion of the initial public offering; and
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issuance of $1.5 billion unsecured notes at Company-record low coupon levels.
Year-end Financial Metrics Included:
•
ending cash and cash equivalents balance of approximately $1.2 billion at December 31, 2014, as compared with $1.1 billion at December 31, 2013;
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total liquidity of $5.2 billion at December 31, 2014 (consisting of year-end cash balance plus funds available under our Credit Facility) as compared with $5.1 billion at December 31, 2013; and
•
year-end ratio of debt-to-book capital of 38%, as compared with 35% at December 31, 2013.
Update on Israel Antitrust Matters In March 2014, we and our partners reached an agreement with the Israeli Antitrust Authority on various matters. On December 23, 2014, the Israel Antitrust Authority advised us of its decision to not submit the agreement to the Antitrust Tribunal for final approval. We requested an oral hearing with the Antitrust Authority, which took place on January 27, 2015, and await final disposition. See Items 1. and 2. Business and Properties - Update on Core Area - Israel.
Asset Impairment Charges We recorded property impairment charges of $500 million for the year, including $336 million for fourth quarter 2014. See Item 8. Financial Statements and Supplementary Data - Note 4. Asset Impairments.
Acquisitions During second quarter 2014, we acquired working interests in 17 deepwater exploration leases in the Gulf of Mexico Atwater Valley protraction area. We acquired a 50% working interest in 13 leases and an average 26% working interest in four leases.
Divestitures Sales of non-core properties, including onshore US and China, generated proceeds of approximately $321 million during 2014, including $135 million related to the sale of onshore US assets and $186 million related to the sale of our China assets. See Item 8. Financial Statements and Supplementary Data - Note 3. Property Transactions.
Sales Volumes The execution of our business strategy, including accelerated activity in onshore US unconventional projects, delivered production growth during 2014. On a BOE basis, total sales volumes were 9% higher in 2014 as compared with 2013, and our mix of sales volumes in 2014 was 43% global crude oil and NGLs, 27% international natural gas, and 30% US natural gas. See Results of Operations - Revenues, below.
Commodity Hedging Activities To enhance the predictability of our cash flows and support our capital investment program, we hedged portions of our expected global crude oil and domestic natural gas production. In the current crude oil price environment, our hedges for 2015 production will contribute to our cash flows from operations, offsetting a portion of declines in crude oil revenues caused by lower prices. For example, during fourth quarter 2014, net cash received in settlement of commodity derivative instruments totaled almost $124 million, and our commodity derivative receivables totaled $890 million at December 31, 2014.
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 cash settlements during the period and non-cash gains or losses due to the change in the mark-to-market value. The use of mark-to-market accounting adds volatility to our net income. See Item 8. Financial Statements and Supplementary Data - Note 7. Derivative Instruments and Hedging Activities.
OPERATING OUTLOOK
2015 Outlook
Crude Oil The oil and gas industry is cyclical and commodity prices are volatile. Three key drivers of global crude oil prices are: OPEC crude oil supply, non-OPEC crude oil supply and global crude oil demand. During 2014, crude oil became oversupplied as production from non-OPEC producers increased, primarily driven by US crude oil production growth from tight formations and the de-bottlenecking of transportation infrastructure, while global crude oil demand growth was muted on low global economic growth especially in Europe, coupled with slower growth in China.
Crude oil futures prices began softening in third quarter 2014, and fell rapidly in November 2014, following OPEC’s decision not to reduce production quotas. Prices have fallen to lows not experienced in almost six years and the lowest levels since the 2008 financial crisis. Thus far in 2015, there has been little to no recovery of prices and NYMEX crude oil futures continue to be weak.
The outlook for crude oil prices during the remainder of 2015 depends primarily on supply and demand dynamics and global security concerns in crude oil-producing nations. Production levels will be a key determinant for 2015. If, during 2015, OPEC maintains its position against cutting production, we expect prices to remain at or near current levels. In addition, record crude oil inventories exert downward pressure on prices. On the demand side, recent projections have reduced anticipated global crude oil demand growth for 2015 and Chinese economic indicators continue to soften which supports the current oversupply situation and a soft pricing environment.
Longer term, we expect supply and demand to balance. If prices remain at lower levels, we expect non-OPEC producers will reduce investment which will, over time, reduce production helping to balance supply and demand in the crude oil market.
Natural Gas The domestic natural gas market remains weak with prices recently falling to two-year lows. Causes include continued growth in domestic natural gas production, particularly from shale plays as well as de-bottlenecking of natural gas processing and transportation facilities in prolific production areas.
Although the pace of drilling appears to have slowed, it is possible that there may not be much improvement in the domestic natural gas supply and demand balance and that oversupply will persist, which could lead to continued price softness in 2015. At a minimum, we expect US natural gas prices to be range-bound. In addition, domestic production growth could continue through 2015 and 2016 as we see the impacts of increases in drilling efficiency and a backlog of drilled but uncompleted wells come online with completion of new pipeline infrastructure, especially in the northeast.
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 substantially-reduced 2015 capital investment program that will be responsive to conditions that will develop in 2015. This program, coupled with our commodity hedging programs, will support continued investment in a volatile commodity price environment. See 2015 Capital Investment Program, below.
2015 Production Our expected crude oil, natural gas and NGL production for 2015 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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the level of horizontal drilling activity in the DJ Basin and the Marcellus Shale;
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decline in DJ Basin legacy vertical well production and capacity constraints of midstream facilities serving those wells;
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timing of start-up of the Big Bend project (deepwater Gulf of Mexico);
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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 offshore Equatorial Guinea;
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potential weather-related volume curtailments due to hurricanes in the deepwater Gulf of Mexico, or winter storms and flooding in the DJ Basin and/or Marcellus Shale;
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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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pending Alba and Alen field unitizations in West Africa;
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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.
2015 Capital Investment Program Given the current commodity price environment with low prices and an industry cost structure that has yet to fully reset to lower revenue levels, we have designed a substantially-reduced capital investment program that is appropriate for the environment and will be responsive to conditions that develop during 2015. Our preliminary capital program for 2015 will accommodate an investment level of approximately $2.9 billion which represents an approximate 40% reduction from 2014. The program allocates more than 60% of total investment to core onshore US assets and 35% for global offshore development activities including the deepwater Gulf of Mexico, and approximately 5% for global offshore exploration.
Specifically, the 2015 investment program allocates approximately $1.8 billion to onshore US development split between DJ Basin and Marcellus Shale drilling programs and continued infrastructure investments. Approximately $600 million will be invested in the continued development of our sanctioned Gulf of Mexico projects. Additional amounts have been allocated to the Alba and Tamar compression projects.
The 2015 capital investment program is anticipated to exceed operating cash flows during the first half of 2015 and may be funded from cash flows from operations, cash on hand, proceeds from divestments of non-core assets, borrowings under our Credit Facility and/or other sources of funding. We are targeting a cash neutral position, whereby the capital investment program is equal to operating cash flows, by the second half of 2015. See Liquidity and Capital Resources - Financing Activities.
We will evaluate the level of capital spending throughout the year based on the following factors, among others, and their effect on project financial returns:
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commodity prices, including price realizations on specific crude oil, natural gas and NGL production;
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operating and development costs and the ability to achieve material supplier price reductions;
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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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exploration activity offshore Cameroon and the Falkland Islands;
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cash flows from operations;
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indebtedness levels;
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availability of financing or other sources of funding;
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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 on our business practices.
See also See Items 1. and 2. Business and Properties - Update on Core Area - Israel, and Liquidity and Capital Resources - Contractual Obligations - Marcellus Joint Development Agreement and Exploration Commitments.
Exploration Program 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 remaining exploration upside. We continue to leverage existing activities to improve our exploratory programs in these core areas.
In recent years, we have devoted 10% or more of our capital investment program to exploration and associated appraisal activities. However, due to the current low commodity price environment, our 2015 exploration program has been reduced. At this time, we expect that approximately 5% of our 2015 capital investment program will be dedicated to global offshore exploration activities, including drilling the Cheetah exploration well, offshore Cameroon, and frontier exploration activities in the Falkland Islands. 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.
Major Development Project Inventory Our current inventory of major development projects requires significant capital investments.
As noted above, we expect to continue to invest in our onshore US and deepwater Gulf of Mexico development projects in 2015. We plan to fund these projects from cash flows from operations, cash on hand, proceeds from divestments of non-core assets, borrowings under our Credit Facility, and/or other sources of funding. 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 may not be as creditworthy as we are and may experience liquidity problems, exacerbated by low commodity prices. 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, Dry Hole or Lease Abandonment Expense
Exploration Activities We have an active exploratory drilling program. In the event we conclude that an exploratory well 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. For example, we expect to conduct exploration activities offshore Cameroon and the Falkland Islands in 2015. If we conclude that a prospect is not economically viable, costs incurred would be recorded as dry hole expense. Capitalized costs related to previous exploration activities totaled $1.3 billion at December 31, 2014. See Item 8. Financial Statements and Supplementary Data - Note 5. Capitalized Exploratory Well Costs.
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 of 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. In addition, the current low commodity price environment may render certain prospects economically less attractive and we may not conduct exploration activities before lease expiration.
For example, we have worked to mature one particular deepwater Gulf of Mexico lease, which was acquired under regulations in effect prior to the Deepwater Gulf of Mexico Moratorium, and identified a potential subsalt hydrocarbon-bearing formation below 25,000 feet. The lease passed its original expiration date of July 31, 2014; however, it has been classified as inactive pending BSEE's decision on our timely application for a suspension of operations (SOO). Based on recent discussion with BSEE, we expect that the SOO application will be approved. According to proposed SOO terms, we must, by October 31, 2015, commit to drilling an exploratory well and commence drilling of the well by October 31, 2016. If BSEE does not approve our SOO application, or if we are unable to comply with approved SOO terms, the lease will expire and associated costs will be written off to exploration expense. The lease had a net book value of $42 million at December 31, 2014.
As a result of our exploration activities, future leasehold expense could be significant. See Results of Operations - Oil and Gas Exploration Expense, below. See also Item 1A. Risk Factors.
Producing Properties Commodity prices remain volatile and crude oil prices have continued to be weak in first quarter 2015. 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 along with operating and development costs, market outlook on forward commodity prices, and interest rates. All inputs to the cash flow model must be evaluated at each date of estimate. However, a decrease in forward commodity prices alone could result in additional property impairment charges in first quarter 2015. Further decline in commodity prices could also result in an impairment of goodwill.
In addition, well decommissioning programs, especially in deepwater or remote locations, are often complex and expensive. It may be difficult to estimate timing of actual abandonment activities, which are subject to regulatory approval, and the
availability of rigs and services. It may be difficult to estimate costs as rigs and services become more expensive in periods of higher demand. Therefore, our ARO estimates may change, sometimes significantly, and could result in asset impairment charges.
Israel Certain assets offshore Israel were classified as held for sale at December 31, 2014. No impairments are indicated at this time. However, failure to achieve acceptable sale terms or delays in closing sales of these properties could result in impairment and/or loss on sale.
In addition, we are monitoring developments in the Israeli regulatory environment to assess the possible impact, positive or negative, of any resulting laws or regulations on our future development activities in Israel. Certain changes in Israel's fiscal and/or regulatory regimes or energy policies occurring as a result of the Antitrust Authority rulings or government policy on natural gas development and/or exports could delay or reduce the profitability of our Tamar and/or Leviathan development projects, and/or render future exploration and development projects uneconomic, resulting in impairment charges. See Items 1. and 2. Business and Properties - Update on Core Area - Israel.
Divestments We are currently marketing certain non-core onshore US properties. If properties are reclassified as assets held for sale in the future, 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.
Recently Issued Accounting Standards Updates See Item 8. Financial Statements and Supplementary Data - Note 1. Summary of Significant Accounting Policies.
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 GHGs may pose a risk to the environment.
The crude 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. In furtherance of that plan, the Obama Administration has launched a number of initiatives, including the development of standards to increase vehicle fuel economy and a Strategy to Reduce Methane Emissions from the oil and gas industry. See also Items 1. and 2. Business and Properties - Regulations. We are continuing to monitor implementation of the Presidential climate change plan.
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.
International negotiations over a new climate change accord are continuing. While no new 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 2014 total sales volumes from continuing operations. The burning of natural gas produces lower levels of GHG emissions as compared to 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 for the years ended December 31, 2012 and December 31, 2013. As of January 1, 2014, the remaining North Sea assets were reclassified as assets held and used. 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 We generally sell crude oil, natural gas, and NGLs under two types of agreements, which are common in our industry. Both types of agreements may include transportation charges. One type of agreement is a netback agreement, under which we sell crude oil and natural gas at the wellhead and receive a price, net of transportation expense incurred by the purchaser. In the case of NGLs, we may receive a price from the purchaser, which is net of processing costs. In each case, we record revenue at the net price we receive from the purchaser. The second type of agreement is one whereby we pay transportation expense directly. In that case, transportation expense is included within production expense in our consolidated statements of operations.
In addition, commodity prices we receive may be reduced by location basis differentials, which can be significant. As a result of both netback agreements and location basis differentials, our reported sales prices may differ significantly from published commodity price benchmarks for the same period.
An analysis of the factors contributing to the changes in revenues from sales of crude oil, natural gas and NGLs is as follow:
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 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.
(2)
Natural gas from the Alba field in Equatorial Guinea is under contract for $0.25 per MMBtu to a methanol plant, an LPG plant, an LNG plant and a power generation plant. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method of accounting.
(3)
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 decreased by $180 million, or 5%, in 2014 as compared with 2013 due to the following:
•
a 9% decrease in total consolidated average realized prices primarily due to the NYMEX WTI crude oil price decline between June and December 2014, with a similar Brent crude oil price decline; and
•
lower sales volumes due to the sale of our China assets at the end of second quarter 2014 and the sale of the North Sea assets during 2013;
partially offset by:
•
higher sales volumes of 4 MBoe/d in the DJ Basin primarily attributable to our horizontal drilling programs; and
•
higher sales volumes of 2 MBoe/d in West Africa primarily due to the timing of crude oil and condensate liftings.
Revenues from crude oil and condensate sales increased by $413 million, or 13%, in 2013 as compared with 2012 due to the following:
•
higher sales volumes of 14 MBoe/d in the DJ Basin attributable to the acceleration of our horizontal drilling program;
•
the addition of sales volumes from Alen, offshore Equatorial Guinea, which began producing in late second quarter 2013; and
•
higher production at Galapagos due to continued strong performance and a full year online;
partially offset by:
•
reduction in sales volumes due to the sales of non-core, onshore US properties during 2013;
•
a 1% decrease in total consolidated average realized prices primarily due to increased supply;
•
a volume reduction in West Africa due to natural field decline at Aseng; and
•
natural field decline in non-core onshore US and deepwater Gulf of Mexico areas.
Natural Gas Sales Revenues from natural gas sales increased by $247 million, or 25%, in 2014 as compared with 2013 due to the following:
•
higher sales volumes of 123 MMcf/d in the Marcellus Shale primarily attributable to our horizontal drilling program and continued ramp-up of activity;
•
higher sales volumes of 22 MMcf/d in the Eastern Mediterranean due to a full year of production from the Tamar field; and
•
a 14% increase in total consolidated average realized prices primarily due to increased demand from cooler weather earlier in 2014 and higher-than-expected inventory withdrawals in the US during the first quarter of 2014, which increased the market price in our producing areas;
•
partially offset by:
•
lower sales volumes due to non-core onshore US properties divested during 2013 and 2014.
Revenues from natural gas sales increased by $356 million, or 57%, in 2013 as compared with 2012 due to the following:
•
increases in total consolidated average realized prices primarily due to increased demand from expectations of cooler weather and higher-than-expected inventory withdrawals;
•
higher sales volumes in Israel from Tamar, which began production at the end of first quarter 2013 and contributed 153 MMcf/d during 2013; and
•
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:
•
lower sales volumes due to our non-core onshore US divestiture program; and
•
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.
NGL Sales Revenues from NGL sales increased by $55 million, or 26%, in 2014 as compared with 2013 due to the following:
•
higher sales volumes of 3 MBoe/d in the DJ Basin, due to increased horizontal drilling activity; and
•
higher sales volumes of 4 MBoe/d in the Marcellus Shale, due to a full year of production from the wet gas acreage;
partially offset by:
•
a 10% decrease in total consolidated average realized NGL prices, which are closely linked to the NYMEX WTI crude oil price declines between June and December 2014.
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.
Income from Equity Method Investees We have interests in various equity method investees that own and operate midstream assets onshore US and West Africa. Equity method investments are included in other noncurrent assets in our consolidated balance sheets, and our share of earnings is reported as income from equity method investees in our consolidated statements of operations. Within our consolidated statements of cash flows, activity is reflected within cash flows provided by operating activities and cash flows provided by (used in) investing activities.
Our share of operations of equity method investees was as follows:
(1) $204 million dividends were distributed from CONE Gathering following the Midstream IPO.
AMPCO and Affiliates Net income from AMPCO and affiliates decreased in 2014 as compared with 2013 primarily due to a 16% decrease in methanol sales from plant interruptions in 2014 and higher storage of inventories to cover scheduled downtime for plant maintenance and upgrades in 2015.
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.
Alba Plant Net income from Alba Plant in 2014 decreased as compared to 2013 and 2012, primarily due to an 8% decrease in the average realized sales price of LPG while sales volumes remained flat.
CONE Gathering On September 24, 2014, our equity method investee, CONE Gathering, contributed a significant majority of its existing assets to a newly-formed master limited partnership, CONE Midstream, concurrently with an initial public offering of limited partner units. CONE Gathering subsequently distributed $204 million of offering proceeds to us.
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 expenses attributable to equity method investees.
(2)
Other International includes the North Sea (in 2014) and China (through June 30, 2014).
(3)
Lease operating expense includes oil and gas operating costs (labor, fuel, repairs, replacements, saltwater disposal and other related lifting costs) and workover expense.
Lease operating expense increased in 2014 as compared with 2013 due to the following:
•
increases of $63 million in the DJ Basin and $5 million in the Marcellus Shale due to increased development activity resulting in higher production;
•
increase of $41 million offshore Equatorial Guinea primarily driven by a full year of labor and FPSO expense resulting from the start up of the Alen field during the second half of 2013;
•
increase of $7 million offshore Israel primarily driven by a full year of expense for the Tamar field, which began producing at the end of first quarter 2013; and
•
increase of $15 million other international and corporate due to inclusion of North Sea in continuing operations during 2014, which was included in discontinued operations in 2013;
partially offset by:
•
decrease of $45 million due to the acquisition of the Neptune facility in deepwater Gulf of Mexico;
•
decrease of $10 million from sales of non-core onshore US properties in 2014;
•
decrease of $8 million from the sale of our China assets at the end of second quarter 2014; and
•
decrease of $1 million from natural field decline from the Mari-B field, offshore Israel.
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 2013;
partially offset by:
•
a reduction of $52 million related to the sale of non-core onshore US properties in 2012 and 2013.
See also Discontinued Operations, below.
Production and Ad Valorem Tax Expense Production and ad valorem taxes decreased in 2014 as compared with 2013, primarily driven by a reduction of $17 million resulting from the sale of our China assets at the end of the second quarter 2014 along with a decrease in average realized crude oil prices between June and December 2014. This decrease was partially offset by higher taxes of $12 million in the DJ Basin and Marcellus Shale due to increased revenues resulting from higher production volumes and higher average realized natural gas prices.
Production and ad valorem tax expense 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.
Transportation Expense Transportation expense increased in 2014 as compared with 2013 related to increases of $44 million in the DJ Basin and Marcellus Shale due to higher production volumes from ongoing development activities offset by $8 million decrease primarily due to the sale of non-core onshore US, China and North Sea properties in 2013 and 2014.
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.
Unit Rate Per BOE The unit rate of total production expense per BOE increased for 2014 as compared with 2013 primarily due to a change in the mix of production. Higher-cost production volumes in the DJ Basin and deepwater Gulf of Mexico were offset by lower cost volumes produced in the Marcellus Shale, Equatorial Guinea and Israel.
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.
Exploration Expense Components of exploration expense were as follows:
(1)
West Africa includes Equatorial Guinea, Cameroon, Sierra Leone, Gabon, 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, which we are currently exiting, and offshore Falkland Islands.
Oil and gas exploration expense increased in 2014 as compared with 2013. Expense for 2014 includes the following:
•
dry hole cost related to the following exploratory wells which did not locate commercial quantities of hydrocarbons: Comanche Plains (onshore US); Bright (deepwater Gulf of Mexico); Madison (deepwater Gulf of Mexico); and Scotia (offshore Falkland Islands);
•
seismic expense related to the acquisition of 3D seismic data in the deepwater Gulf of Mexico, Equatorial Guinea, and Falkland Islands; and
•
salaries and related expenses for corporate exploration and new ventures personnel.
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 exploration programs offshore Cyprus and offshore Falkland Islands; and
•
salaries and related expenses for corporate exploration and new ventures personnel.
Exploration expense included stock-based compensation expense of $17 million in 2014, $15 million in 2013, and $12 million in 2012.
Depreciation, Depletion and Amortization DD&A expense was as follows:
(1)
DD&A expense includes accretion of discount on asset retirement obligations of $36 million in 2014, $26 million in 2013, and $22 million in 2012.
(2)
Consolidated unit rates exclude sales volumes and costs attributable to equity method investees.
Total DD&A expense increased for 2014 as compared with 2013 due to the following:
•
higher sales volumes associated with increased development activity in the DJ Basin and the Marcellus Shale accounted for increases of $109 million and $95 million, respectively;
•
increase of $15 million in the deepwater Gulf of Mexico due to a full year of production for a new well at Ticonderoga and the addition of the Neptune spar at Swordfish;
•
increase of $38 million offshore Equatorial Guinea primarily due to a full year of production at the Alen field;
•
increase of $15 million from a full year of production at the Tamar field, offshore Israel;
•
increase of $11 million due to North Sea properties reclassified to continuing operations for 2014; and
•
increase of $16 million associated with corporate assets;
partially offset by:
•
decrease of $32 million due to sales of non-core onshore US properties in 2014 and 2013;
•
decrease of $49 million from natural field decline at the Mari-B, Noa and Pinnacles fields, offshore Israel; and
•
decrease of $35 million due to sale of China assets in 2014.
Changes in the unit rate per BOE for 2014 as compared with 2013 were due to change in mix of production. Higher-cost production volumes in the DJ Basin and deepwater Gulf of Mexico were offset by lower cost volumes produced at Tamar.
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 previous 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.
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 2014 increased as compared with 2013 primarily due to additional expenses relating to personnel, office, and information technology costs in support of our major development projects and exploration activities. For example, our total number of employees increased from 2,527 at December 31, 2013 to 2,735 at December 31, 2014. Increases in G&A were offset by a decrease in G&A due to reduced employee incentive compensation.
G&A expense increased for 2013 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 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 $63 million in 2014, $58 million in 2013 and $48 million in 2012. See Item 8. Financial Statements and Supplementary Data - Note 11. Stock-Based and Other Compensation Plans.
Gain on Divestitures Gain on divestitures was as follows:
Gain on divestitures for 2014 relates to the sale of non-core onshore US properties and our China assets. 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. 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 (Income) Expense, Net Other operating (income) 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 7. Derivative Instruments and Hedging Activities and Note 12. 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 increased in 2014 as compared with 2013. Interest related to a full year of interest on senior debt issued in November 2013, as well as interest related to senior debt issued in November 2014 was offset by a reduction in interest related to repayment of an installment loan. During the year, we drew down and repaid amounts under our Credit Facility for working capital purposes. There were no other significant changes in our debt.
Interest expense prior to the reduction of capitalized interest remained flat in 2013 as compared with 2012. Decreased interest expense related to the repayment of an installment loan was offset by interest expense related to an issuance of new senior debt in November 2013. We drew down amounts under our Credit Facility during third quarter 2013 and repaid with proceeds from the debt issuance. There were no other significant changes in our debt.
Interest capitalized in 2014 decreased slightly as compared with 2013. The decrease is due primarily to the completion of major projects at Alen and Tamar in 2013 offset by higher work in progress amounts related to major long-term projects onshore US and deepwater Gulf of Mexico.
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.
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 5. 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, 2014, approximately 38% 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 income of $25 million in 2014, deferred compensation expense of $26 million in 2013, and deferred compensation expense of $6 million in 2012. See Item 8. Financial Statements and Supplementary Data - Note 11. 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 10. Income Taxes.
Discontinued Operations
Summarized results of discontinued operations, comprising our North Sea geographical segment during 2012 and 2013, 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 did not allocate 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, 2014 include positive performance revisions of 18 MMBoe for the Marcellus Shale program, 4 MMBoe for deepwater Gulf of Mexico, 4 MMBoe for Alba field, and 3 MMBoe for the Tamar field; and offset by a downward revision of 8 MMBoe for the DJ Basin primarily due to planned reduction in pace of drilling activity due to lower commodity price outlook;
•
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 the Alba field, and 21 MMBoe for the Tamar field; and positive price revisions of 13 MMBoe due to increases in commodity prices; and
•
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.
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, 2014 include increases of 47 MMBoe in the DJ Basin, 62 MMBoe in the Marcellus Shale, and 10 MMBoe deepwater Gulf of Mexico primarily attributable to sanction of the Dantzler development. The decrease in the DJ Basin changes from prior years is primarily due to the reduced pace of drilling activity in response to the lower commodity price outlook.
•
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; and
•
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.
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 core areas as well as 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 acquisition of additional acreage primarily in the Marcellus Shale and DJ Basin in 2013.
Sale of Minerals in Place We maintain an ongoing portfolio management program. Sales included the following:
•
the sale of non-core onshore US and China assets in 2014;
•
the sale 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 Items 1. and 2. Business and Properties including Update on Core Area - Israel, Critical Accounting Policies and Estimates - Reserves, below, and Item 8. Financial Statements and Supplementary Data - Supplemental Oil and Gas Information (Unaudited).
LIQUIDITY AND CAPITAL RESOURCES
Capital Structure/Financing Strategy
In seeking to effectively fund and monetize our discovered hydrocarbons, we employ a capital structure and financing strategy designed to provide sufficient liquidity throughout the volatile commodity price cycle, including the current downturn in crude oil prices. 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 continuing exploration program and maintaining capacity to capitalize on financially attractive periodic mergers and acquisitions activity.
We endeavor to maintain a strong balance sheet and 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 Credit Facility, and proceeds from sales of non-core properties.
We occasionally access the capital markets to ensure adequate liquidity exists in the form of unutilized capacity under our Credit Facility or to refinance scheduled debt maturities. We also consider repatriations of foreign cash to increase our financial flexibility and fund our capital investment program to the extent such cash is not required to fund foreign investment projects and would not incur material incremental US tax. We evaluate potential strategic farm-out arrangements of our working interests for reimbursement of our capital spending and may consider other sources of funding.
During 2014, our liquidity position was enhanced by the following activities:
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 higher-value and higher-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 generated proceeds of $2.4 billion over the last five years, including $321 million during 2014. See Item 8. Financial Statements and Supplementary Data - Note 3. Property Transactions.
Midstream IPO On September 24, 2014, our equity method investee, CONE Gathering, contributed a significant majority of its existing assets to a newly-formed master limited partnership, CONE Midstream, concurrently with an initial public offering of limited partner units. CONE Gathering subsequently distributed $204 million of offering proceeds to us.
Public Debt Offering On November 7, 2014, we closed an offering of $1.5 billion senior unsecured notes, at Company-record low coupon levels, the proceeds from which were used to repay the outstanding indebtedness under our Credit Facility and for general corporate purposes. See Item 8. Financial Statements - Note 9. Long-Term Debt.
Cash Repatriations During 2014, we repatriated $1.3 billion from our foreign operations. We do not expect to incur material incremental US tax on these repatriations due to foreign tax credit usage.
Available Liquidity
Year-end liquidity was as follows:
(1)
See Credit Facility, below.
(2)
Total debt includes capital lease and other obligations 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.
Current Activity - Impact on Liquidity
Expanded development in the DJ Basin and Marcellus Shale, investment in major deepwater development projects, and planned exploration and appraisal drilling activities, as well as the fourth quarter 2014 decline in crude oil prices, resulted in capital expenditures exceeding cash flows from operating activities for 2014. The extent to which capital investment will exceed operating cash flows in the future depends on the pace of future DJ Basin and Marcellus Shale development activities, timing of future development project sanction, the results of our exploration activities, and new business opportunities, as well as external factors such as commodity prices, among others. In particular, a sustained period of low crude oil prices would have a significant negative impact on our cash flows.
However, our financial capacity, coupled with our diversified portfolio, provides us with flexibility in our investment decisions including execution of major development projects as well as exploration activity in the current commodity price environment. See Operating Outlook - 2015 Capital Investment Program, above.
To support our investment program, we expect that higher production resulting from our core onshore US development programs combined with new production from the Big Bend development project and additional production from the Tamar compression project, will result in an increase in cash flows which will be available to meet a substantial portion of future capital commitments.
We are currently evaluating potential development and/or financing scenarios for significant discoveries, including the Leviathan development project offshore Eastern Mediterranean. The magnitude of certain discoveries presents technical and financial challenges for us due to the large-scale development requirements. Some development options, such as development of Leviathan Phase 1, require a multi-billion dollar investment and require a number of years to complete.
We believe our current liquidity level and balance sheet, along with our ability to access the capital markets, provide flexibility and that we are well-positioned to fund our business throughout the commodity price cycle. We will continue to evaluate the commodity price environment and our level of capital spending throughout 2015. However, a downgrade or other negative action with respect to our credit rating could exert significant additional liquidity pressures by triggering requirements to post collateral as financial assurance of performance under certain contractual arrangement and/or negatively impact our our cost, terms, conditions and availability of future financing. See Item 1A. Risk Factors - A downgrade or other negative action with respect to our credit rating could negatively impact our business and financial condition.
Cash and Cash Equivalents We had approximately $1.2 billion in cash and cash equivalents at December 31, 2014, compared with approximately $1.1 billion at December 31, 2013. At December 31, 2014, our cash was primarily denominated in US dollars and invested in money market funds and short-term deposits with major financial institutions. Approximately $600 million of this cash was attributable to foreign subsidiaries. We estimate that there would have been no cash tax impact if this amount had been repatriated at December 31, 2014, due to estimated foreign tax credit usage and our domestic tax position.
Credit Facility We maintain a Credit Facility with a committed amount of $4.0 billion through 2018. We expect to use the Credit Facility to fund our capital investment program, and may periodically borrow amounts for working capital purposes. No amounts were drawn under the Credit Facility at December 31, 2014. 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 global crude oil and domestic 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.
During fourth quarter 2014, almost one-third of our hedged crude oil volumes were attributable to three-way collars. As crude oil began trading below the strike price of the sold put option contract of the three-way collars during fourth quarter, the cash settlements received by us were limited. However, we still received the cash market price plus the delta between the purchased put option floor price of the two-way collar contract and the sold put option strike price. Almost half of our 2015 hedged crude oil volumes are attributable to three-way collars. Although three-way collars may limit benefits in low commodity price environments, they allow us to capture more value than swaps or two-way collars in a rising commodity price environment. In addition, the proceeds received from selling the put option contract of the three-way collar allow us to purchase the two-way collar contract with a higher floor price.
As of December 31, 2014, the fair value of our commodity derivative assets was $890 million and the fair value of our commodity derivative liabilities was zero (after consideration of netting clauses within our master agreements). We net settle by counterparty based on master agreements. Net settlements take into account deferred premiums we have agreed to pay for put options. None of our counterparty agreements contain margin requirements.
See Item 1A. Risk Factors - Commodity, interest rate and exchange rate hedging transactions may limit our potential gains, Critical Accounting Policies and Estimates - Derivative Instruments and Hedging Activities,

ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
Derivative Instruments Held for Non-Trading Purposes We are exposed to commodity price risk in the normal course of business operations, as 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, 2014, we had entered into variable to fixed price commodity swaps and three way collars related to global crude oil and domestic natural gas sales. Changes in fair value of commodity derivative instruments are reported in earnings in the period in which they occur. Our open commodity derivative instruments were in a net asset position at December 31, 2014 with a fair value of $890 million. Based on the December 31, 2014 published commodity futures price curves for the underlying commodities, a hypothetical price increase of $10.00 per Bbl for crude oil would decrease the fair value of our net commodity derivative asset by approximately $232 million. A hypothetical price increase of $0.50 per MMBtu for natural gas would decrease the fair value of our net commodity derivative asset by approximately $36 million. Our derivative instruments are executed under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net cash settled at the time of election. See

ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. Financial Statements and Supplementary Data
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed under the supervision of our Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.
Because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements. Projections of any evaluation of the effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or processes may deteriorate.
As of December 31, 2014, 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, 2014, 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, 2014 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, 2014 and 2013, 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, 2014. 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, 2014 and 2013, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2014, 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, 2014, 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 19, 2015 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ KPMG LLP
Houston, Texas
February 19, 2015
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, 2014, 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, 2014, 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, 2014 and 2013, 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, 2014, and our report dated February 19, 2015 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
Houston, Texas
February 19, 2015
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 reflect impact of 2-for-1 stock split which occurred during second quarter 2013.
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 Eastern Mediterranean and offshore West Africa.
Basis of Presentation and Consolidation Accounting policies used by us and our subsidiaries conform to US GAAP. Significant policies are discussed below. Our consolidated accounts include our accounts and the accounts of our wholly-owned subsidiaries. We use the equity method of accounting for investments in entities that we do not control but over which we exert significant influence. We carry equity method investments at our share of net assets of the equity investees plus our loans and advances. Differences in the basis of the investment and the separate net asset value of the investee, if any, are amortized into income over the remaining useful life of the underlying assets. See Note 6. 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, natural gas and NGL 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, natural gas and NGLs. There are numerous uncertainties inherent in estimating quantities of proved crude oil, natural gas and NGL 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, natural gas and NGLs 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. Further declines in crude oil prices or a significant decline in natural gas 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 2013 and 2012 consolidated financial statements to conform to the 2014 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 12. 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.
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, natural gas and NGL 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 three to thirty 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 2014, 2013, and 2012. 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, natural gas and NGL 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, natural gas and NGL 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.
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. Property Transactions.
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 5. 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 3 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 our unsecured revolving credit facility (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 $116 million in 2014, $121 million in 2013, and $151 million in 2012.
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 recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at our 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 8. 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, 2014. However, it is possible that goodwill could become impaired in the future if commodity prices or other economic factors continue to decline.
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 2014 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)
Noble Energy, Inc.
Notes to Consolidated Financial Statements
until the forecasted transaction occurs. The derivative’s gains or losses are then offset against related results on the hedged transaction in the statements of operations.
A company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting. Only derivative instruments that are expected to be highly effective in offsetting anticipated gains or losses on the hedged cash flows and that are subsequently documented to have been highly effective can qualify for hedge accounting. Effectiveness must be assessed both at inception of the hedge and on an ongoing basis. Any ineffectiveness in hedging instruments whereby gains or losses do not exactly offset anticipated gains or losses of hedged cash flows is measured and recognized in earnings in the period in which it occurs. When using hedge accounting, we assess hedge effectiveness quarterly based on total changes in the derivative instrument’s fair value by performing regression analysis. A hedge is considered effective if certain statistical tests are met. We record hedge ineffectiveness in (gain) loss on commodity derivative instruments.
Accounting for Commodity Derivative Instruments We account for our commodity derivative instruments using mark-to-market accounting and recognize all gains and losses in earnings during the period in which they occur. Our consolidated statements of cash flows includes the non-cash portion of 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.
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 11. 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, 2014 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 11. 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 10. 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
Noble Energy, Inc.
Notes to Consolidated Financial Statements
excess of our entitlement is treated as a liability and is not recognized as revenue. Any amount of entitlement in excess of the amount we sell is recognized as revenue and a receivable is accrued.
Basic and Diluted Earnings Per Share Basic earnings per share (EPS) of our common stock is computed on the basis of the weighted average number of shares outstanding during each period. The diluted EPS of our common stock includes the effect of outstanding common stock equivalents such as stock options, shares of restricted stock, and/or shares of our stock held in a rabbi trust, except in periods in which there is a net loss.
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 13. 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 17. 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 14. 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.
Recently Issued Accounting Standards In April 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2014-08: Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (ASU 2014-08). ASU 2014-08 changes the criteria for reporting discontinued operations while enhancing disclosures in this area and is effective for annual and interim periods beginning after December 15, 2014. Early adoption is permitted for disposals or for assets classified as held for sale that have not been reported in previously issued financial statements. We elected to early adopt ASU 2014-08 on a prospective basis, and the adoption did not have a material impact on our consolidated financial statements.
In May 2014, the FASB issued Accounting Standards Update No. 2014-09 (ASU 2014-09), which creates Topic 606, Revenue from Contracts with Customers, and supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, including most industry-specific revenue recognition guidance throughout the Industry Topics of the Codification. In addition, ASU 2014-09 supersedes the cost guidance in Subtopic 605-35, Revenue Recognition - Construction-Type and Production-Type Contracts, and creates new Subtopic 340-40, Other Assets and Deferred Costs - Contracts with Customers. In summary, the core principle of Topic 606 is that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Additionally, ASU 2014-09 requires enhanced financial statement disclosures over revenue recognition as part of the new accounting guidance. The amendments in ASU 2014-09 are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, and early application is not permitted. We are currently evaluating the provisions of ASU 2014-09 and awaiting implementation guidance to determine the impact, if any, it may have on our financial position and results of operations.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 2. Additional Financial Statement Information
Additional statements of operations information is as follows:
(1)
Amounts represent increases (decreases) 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:
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Supplemental statements of cash flow information is as follows:
Note 3. Property Transactions
Sale of Non-Core Onshore US Properties During the past three years, we closed the sales of non-core onshore US crude oil and natural gas properties, including our Piceance, Tri-State, and Powder River properties. The information regarding the assets sold is as follows:
We continue to market non-core onshore US properties; certain of these assets, as discussed below, met the criteria for reclassification as assets held for sale at December 31, 2014.
China In June 2014, we sold our China assets. We determined the sale of our China assets did not meet the criteria for discontinued operations presentation under ASU 2014-08. The information regarding the China assets sold is as follows:
Assets Held for Sale Assets held for sale as of December 31, 2014 include non-core onshore US assets ($105 million) in the DJ Basin and two natural gas discoveries, Tanin and Karish, offshore Israel ($75 million). Regarding Tanin and Karish, we agreed to divest these assets pursuant to an agreement we and our partners reached with the Israeli Antitrust Authority in March 2014 on various antitrust matters. See also Note 5. Capitalized Exploratory Well Costs.
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 consolidated our acreage into large contiguous blocks, which has provided the opportunity to optimize drilling, production, and gathering activities and add more extended-reach lateral wells to our development program. 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.
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Notes to Consolidated Financial Statements
North Sea Properties During 2012 and 2013, we sold the majority of our non-operated, North Sea properties. The 2013 sales resulted in a $65 million gain based on net sales proceeds of $56 million. In 2012, proceeds from sales totaled $117 million, the net book value of assets sold was $255 million, and associated asset retirement obligations were $55 million. We also reversed a deferred tax liability and recognized a corresponding income tax benefit of $99 million related to the sale. During 2012 and 2013, the North Sea geographical segment was presented as discontinued operations in our consolidated statements of operations.
We were unable to locate purchasers for the remaining properties. As of January 1, 2014, we no longer considered a sale probable. Therefore, the remaining assets were reclassified to assets held and used. See Note 4. Asset Impairments.
Summarized results of discontinued operations are as follows:
(1) Income before income taxes for 2012 includes exploration expense of $27 million related to the Selkirk field which was determined uneconomic for joint development.
Note 4. Asset Impairments
Pre-tax (non-cash) asset impairment charges were as follows:
2014 Asset Impairments During 2014, certain onshore US and deepwater Gulf of Mexico properties were written down to their estimated fair values using a discounted cash flow model. The cash flow model included management’s estimates of future crude oil and natural 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. Impairment charges of $250 million resulted from declines in crude oil prices at year end 2014.
During 2013, South Raton in the deepwater Gulf of Mexico was shut-in due to mechanical issues; therefore, we recorded additional impairment charges of $74 million for South Raton in fourth quarter 2014.
Additionally, the asset carrying values of certain crude oil and natural gas properties in the deepwater Gulf of Mexico and offshore Israel increased when we recorded associated increases in asset retirement obligations. We determined that the recorded carrying values of some of these assets were not recoverable from future cash flows and recorded impairment expense of $51 million.
During third quarter 2014, we reclassified certain non-core properties as assets held for sale. The assets were written down to expected proceeds less costs to sell, resulting in a $31 million impairment.
In March 2014, the operator of the MacCulloch North Sea field notified the working interest owners that expected field abandonment costs would be higher than originally projected, and that field abandonment would occur sooner than anticipated. As a result of this new information, we adjusted the asset retirement obligation to reflect the updated estimate of abandonment costs and timing. We assessed the asset for impairment and determined that it was impaired.
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
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Notes to Consolidated Financial Statements
value using a discounted cash flow model, as described above. 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 an onshore US property, and declines in near-term crude oil prices associated with a deepwater Gulf of Mexico property, 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, 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 a discounted cash flow model, as described above.
See also Note 12. Fair Value Measurements and Disclosures.
Note 5. Capitalized Exploratory Well Costs
We capitalize exploratory well costs until a determination is made that the well has found proved reserves or is deemed noncommercial. If a well is deemed to be noncommercial, the well costs are immediately charged to exploration expense as dry hole cost.
Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed in the same period:
(1)
The 2014 amount primarily relates to the Dantzler well (deepwater Gulf of Mexico), for which we sanctioned a development plan, and the Tanin and Karish wells (offshore Israel), which were reclassified to assets held for sale. The 2013 amount relates primarily to Gunflint (deepwater Gulf of Mexico), for which we sanctioned a development plan.
(2)
The 2014 amount relates to non-core onshore US exploratory well costs and the Scotia exploratory well (offshore Falkland Islands) which were determined to be non-commercial. The 2012 amount primarily represents deepwater Gulf of Mexico exploratory well costs.
(3)
The 2012 amount relates to North Sea exploratory well costs included in discontinued operations. 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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Notes to Consolidated Financial Statements
The following table provides a further aging of those exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling as of December 31, 2014:
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Notes to Consolidated Financial Statements
(1)
In March 2014, we and our partners reached an agreement with the Israel Antitrust Authority on various matters (Consent Decree). The Consent Decree, which was subject to final approval by the Antitrust Tribunal, granted the rights, to us and our partners, to jointly market natural gas from the Leviathan field. Also as a result of the Consent Decree, we agreed to divest our Tanin and Karish natural gas discoveries. However, on December 23, 2014, we and our partners in the Leviathan field were advised by the Israel Antitrust Authority of its decision to not submit the Consent Decree to the Antitrust Tribunal for final approval. This is a matter that we believed was resolved some time ago and we had received recent assurances from the Antitrust Authority that approval was forthcoming. We requested an oral hearing with the Antitrust Authority, which took place on January 27, 2015, and await final disposition.
Note 6. Equity Method Investments
Equity Method Investments Equity method investments are included in other noncurrent assets in the consolidated balance sheets, and our share of earnings is reported as income from equity method investees in the consolidated statements of operations. Our share of income taxes incurred directly by the equity method investees is reported in income from equity method investees and is not included in our income tax provision in our consolidated statements of operations. 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;
•
50% interest in CONE Gathering LLC (CONE Gathering), which owns and operates natural gas gathering facilities servicing our joint venture properties in the Marcellus Shale; and
•
32% interest in CONE Midstream Partners, LP (CONE Midstream), which constructs, owns and operates natural gas gathering and other midstream energy assets in support of our Marcellus Shale joint venture activities.
Midstream IPO On September 24, 2014, our equity method investee, CONE Gathering, contributed a significant majority of its existing assets to a newly-formed master limited partnership, CONE Midstream, concurrently with an initial public offering of limited partner units. CONE Gathering subsequently distributed $204 million of offering proceeds to us, which is reflected within cash flows from operating activities ($48 million) and cash flows from investing activities ($156 million) within our consolidated statement of cash flows.
Equity method investments are as follows:
(1) CONE Investments includes our investments in CONE Midstream and CONE Gathering.
Other At December 31, 2014, consolidated retained earnings included $100 million related to the undistributed earnings of equity method investees.
The carrying value of our AMPCO investment was $8 million higher than the underlying net assets of the investee at December 31, 2014. The difference is related to capitalized interest which is being amortized into earnings over the remaining useful life of the plant.
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Notes to Consolidated Financial Statements
Summarized, 100% combined financial information for equity method investees is as follows:
Note 7. 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.
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, 2014.
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.
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See Note 12. 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.
Unsettled Derivative Instruments As of December 31, 2014, we had entered into the following crude oil derivative instruments:
As of December 31, 2014, we had entered into the following natural gas derivative instruments:
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Notes to Consolidated Financial Statements
Fair Value Amounts and Gains and Losses on Derivative Instruments The fair values of derivative instruments in our consolidated balance sheets were as follows:
The effect of derivative instruments on our consolidated statements of operations was as follows:
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Notes to Consolidated Financial Statements
Note 8. 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, 2014
Liabilities incurred were due to new wells and facilities and included $20 million for onshore US, $25 million for deepwater Gulf of Mexico, $2 million for Cameroon, and $10 million for Eastern Mediterranean. Additional liabilities of $18 million were incurred for wells in Equatorial Guinea.
We settled liabilities of $33 million for the DJ Basin, $62 million for deepwater Gulf of Mexico, and $28 million for other non-core, onshore US developments and $1 million for China. At December 31, 2013, our non-operated North Sea fields were classified as held for sale, which included the related ARO for these fields. During 2014 the unsold North Sea properties were reclassified as held and used, resulting in a offset of $23 million to the balance of liabilities settled.
Revisions were primarily due to changes in estimated costs for future abandonment activities and acceleration of timing and included $33 million for DJ Basin, $29 million for the deepwater Gulf of Mexico, $16 million for Equatorial Guinea, $8 million for Eastern Mediterranean, and $69 million related to a non-operated North Sea field.
Accretion expense is included in DD&A expense in the consolidated statements of operations.
For the year ended December 31, 2013
Liabilities incurred were due to new wells and facilities and included $15 million for onshore US development, $68 million for deepwater Gulf of Mexico, 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.
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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Notes to Consolidated Financial Statements
Note 9. Long-Term Debt
Our debt consists of the following:
(1)
We repaid the senior notes on their due date.
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 $50 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 Credit Facility to extend the maturity date to October 3, 2018. We periodically borrow amounts for working capital purposes.
Our 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, 2014, 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.
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Notes to Consolidated Financial Statements
2014 Debt Offering On November 7, 2014, we closed an offering of $650 million senior unsecured 3.90% notes due November 15, 2024 and $850 million senior unsecured 5.05% notes due November 15, 2044, receiving aggregate net proceeds of almost $1.5 billion. Both notes pay interest semiannually, with total debt issuance costs of approximately $15 million being amortized to expense over the terms of the notes. Approximately $1.1 billion 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.
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 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.
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 17. Commitments and Contingencies for future capital lease payments.
Annual Debt Maturities Annual maturities of outstanding debt, excluding capital lease payments, are as follows:
Note 10. Income Taxes
Components of income from continuing operations before income taxes are as follows:
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Notes to Consolidated Financial Statements
The income tax provision from continuing operations consists of the following:
A reconciliation of the federal statutory tax rate to the effective tax rate is as follows:
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Notes to Consolidated Financial Statements
Deferred tax assets and liabilities resulted from the following:
Net deferred tax liabilities were classified in the consolidated balance sheets as follows:
Deferred Tax Assets In assessing the realizability of deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income in the appropriate tax jurisdictions during the periods in which those temporary differences become deductible. We consider the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, we believe it is more likely than not that we will realize the benefits of these deductible differences at December 31, 2014. 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 $145 million in 2014 and $135 million in 2013. 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.
During fourth quarter 2014, fluctuations in oil and gas prices resulted in an inability to determine whether we would be able to utilize all of our foreign tax credits in the future. Therefore, we set up a deferred tax liability of $141 million on our non-permanent reinvested foreign earnings and a corresponding valuation allowance of $36 million on our foreign tax credits.
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.
Effective Tax Rate Our effective tax rate decreased in 2014 as compared with 2013 primarily due to our ability to benefit from previously unrecognized foreign tax credits, increased earnings in our foreign jurisdictions with rates that vary from the US statutory rate, and a decrease in our Israeli oil profits tax, offset by a change in our state tax estimates and foreign dividend repatriation.
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Notes to Consolidated Financial Statements
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.
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, 2014, the accumulated undistributed earnings of the foreign subsidiaries that have been permanently reinvested were approximately $3.5 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. The actual tax impact would depend on our tax positions at the time of payment and could be significantly different from this estimate. 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 $850 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: US - 2011, Equatorial Guinea - 2009 and Israel - 2010.
Our policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense.
A reconciliation of our beginning and ending amounts of unrecognized tax benefits follows:
As of December 31, 2014, approximately $29 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, 2014 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, 2014, we recognized and accrued a de minimis amount of interest and none in penalties.
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.
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.
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Notes to Consolidated Financial Statements
Note 11. 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 stock appreciation rights and award restricted stock and cash awards to our officers or other employees and those of our subsidiaries. The maximum number of shares that may be granted under the 1992 Plan is 71,600,000 shares of common stock. At December 31, 2014, 32,962,380 shares of our common stock were reserved for issuance, including 14,380,862 shares available for future grants and awards, under the 1992 Plan.
Stock options are issued with an exercise price equal to the fair market value 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 10 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 period during which such restrictions apply, 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. The dividends or other distributions pertaining to the restricted shares will be held by the Company until the restriction period ends and the shares vest or forfeit. If the restricted shares forfeit, then the recipient shall not be entitled to receive the dividend or distribution which will transfer to the Company. 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 the remaining 60% after year two). Restricted stock awards with a performance-vested 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., as amended (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 of Noble Energy, Inc. The total number of shares of our common stock that may be issued under the 2005 Plan is 1,600,000. At December 31, 2014, 1,359,832 shares of our common stock were reserved for issuance, including 843,285 shares available for future grants and awards under the 2005 Plan.
Prior to March 17, 2011, the 2005 Plan provided for the automatic granting to a non-employee director of up to a maximum of 11,200 stock options on the date of election to the Board of Directors, annual grants of 2,800 options per non-employee director on February 1 of each year, and discretionary grants by the Board of Directors (with the February 1 annual and the discretionary grants made to a non-employee director during any calendar year being limited to a combined maximum of 11,200 options). The 2005 Plan was amended so that no automatic option grants would be made under the 2005 Plan on or after March 17, 2011. Discretionary grants by the Board of Directors continue to be permitted under the 2005 Plan (with the grants made to a non-employee director during any calendar year being limited to a maximum of 22,400). 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. Unless granted by the Board of Directors for a shorter term, the options expire 10 years from the date of grant.
Prior to March 17, 2011, the plan also provided for the awarding to a non-employee director of up to a maximum of 4,800 shares of restricted stock on the date of election to the Board of Directors, annual awards of 1,200 shares of restricted stock per non-employee director on February 1 of each year, and discretionary awards by the Board of Directors (with the February 1 annual and the discretionary awards made to a non-employee director during any calendar year being limited to a combined maximum of 4,800 shares of restricted stock). The 2005 Plan was amended so that no automatic grants of restricted stock awards would be made under the 2005 Plan on or after March 17, 2011. Discretionary grants by the Board of Directors
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continue to be permitted under the 2005 Plan (with the grants made to a non-employee director during any calendar year limited to a maximum of 9,600). 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 10 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 (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:
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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.
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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 $58 million in 2014, $64 million in 2013, and $72 million in 2012.
As of December 31, 2014, $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.
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Notes to Consolidated Financial Statements
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 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 $50 million in 2014, $43 million in 2013, and $47 million in 2012.
The weighted average award-date fair value of restricted stock awarded was $41.22 per share in 2014, $38.07 per share in 2013, and $50.75 per share in 2012.
As of December 31, 2014, $38 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 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 $26 million in 2014, $21 million in 2013, and $17 million in 2012.
As a result of the termination of the pension plan (see below), employees who were hired prior to May 1, 2006 became eligible to receive profit sharing contributions effective January 1, 2014. In addition, certain of these employees are eligible to receive transition contributions related to the termination of the plan.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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 in that nonqualified deferred compensation plan may elect to receive distributions in either cash or shares of our common stock. Components of that rabbi trust are as follows:
Assets of that rabbi trust, other than our common stock, are invested in certain mutual funds that cover an investment spectrum ranging from equities to money market instruments. These mutual funds have published market prices and are reported at fair value. See Note 12. 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 holding common stock 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 1,000,000 shares, or 93%, of our common stock held in respect of one nonqualified deferred compensation plan at December 31, 2014 were attributable to a member of our Board of Directors. The shares are being distributed in equal installments over the next five years. Distributions of 200,000 shares were made in 2014 and 200,000 shares in 2013. In addition, plan participants sold 19,049 shares of our common stock in 2014, 1,008 shares in 2013, and 4,536 shares in 2012. Proceeds were invested in mutual funds and/or distributed to plan participants. Distributions to plan participants were valued at $22 million in 2014, $25 million in 2013 and $19 million in 2012.
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 (income) of $(25) million in 2014, $26 million in 2013 and $6 million in 2012.
We also maintain other nonqualified deferred compensation plan (besides the restoration plan described below) for the benefit of certain of our employees. Deferred compensation liabilities of $84 million, $77 million and $70 million were outstanding at December 31, 2014, 2013 and 2012, respectively, under those other plans.
Pension and Other Postretirement Benefit Plans We have had a noncontributory, tax-qualified defined benefit pension plan (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 have also sponsored other plans, which include plans offering medical and life insurance benefits, for the benefit of our employees and retirees.
We are in the process of terminating the pension plan. We expect to liquidate the associated pension obligation through lump-sum payments to participants or the purchase of annuities on their behalf. As of December 31, 2014, the latest actuarial measurement date for the pension plan, the accumulated benefit obligation totaled $287 million, and the fair value of plan assets was $242 million. We expect to make additional contributions to the plan during the period leading up to final termination and distribution to the extent necessary to fund the net obligation.
In addition, upon termination of the pension plan, all unamortized prior service cost and net actuarial loss remaining in AOCL will be charged to expense. This amount totaled $82 million at December 31, 2014. We expect liquidation of the pension plan to occur in the first half of 2015.
In coordination with the termination and liquidation of the pension plan, we also amended our restoration plan to freeze the accrual of benefits. Payments under the restoration plan will continue to be made in ordinary course without acceleration. Restoration plan participants who remain employed by us upon final liquidation and distribution of assets of the pension plan may elect to have the lump sum present value of their restoration plan benefits converted into an account balance under our nonqualified deferred compensation plan.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
We also curtailed the retiree medical program during 2014, resulting in a gain of $21 million and accrued a one-time taxable cash payment of $20 million to certain employees who would have been eligible for retiree medical benefits at any point during the next 10 years.
The benefit obligations, plan assets and AOCL balances for the pension, restoration and other postretirement benefit plans are summarized below as of December 31:
At December 31, 2014, pension plan assets were invested in cash and separately managed accounts consisting primarily of short term fixed income securities.
Net periodic benefit cost related to these plans totaled $11 million in 2014, $37 million in 2013, and $27 million in 2012.
Note 12. 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/or 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 and the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract terms. See Note 7. Derivative Instruments and Hedging Activities.
Deferred Compensation Liability The value is dependent upon the fair values of mutual fund investments and shares of our common stock held in a rabbi trust. See Mutual Fund Investments above.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Measurement information for assets and liabilities that are measured at fair value on a recurring basis was as follows:
(1)
See Note 1. Summary of Significant Accounting Policies - Fair Value Measurements for a description of the fair value hierarchy.
(2)
Amount represents the impact of 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 crude oil and natural gas production, commodity prices based on sales contract terms or 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.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Additional Fair Value Disclosures
See Note 9. 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, 2014 or December 31, 2013. See Note 9. Long-Term Debt.
Note 13. 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:
(1)
Consistent with GAAP, when dilutive, deferred compensation gains or losses, net of tax, are excluded from net income while our common shares held in the rabbi trust are included in the diluted share count. For this reason, the diluted earnings per share calculations for the year ended December 31, 2014 excludes deferred compensation gains, net of tax.
Note 14. 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, natural gas and NGL exploration, development, and acquisition: the United States; West Africa (Equatorial Guinea, Cameroon, Gabon, Sierra Leone, and Senegal/Guinea-Bissau (which we exited in 2012); Eastern Mediterranean (Israel and Cyprus); and Other International and Corporate. Other International includes the North Sea, China (through June 2014), Falkland Islands, Nicaragua and new ventures. The North Sea geographical segment is included in continuing operations in 2014 and discontinued operations in 2013. Income (loss) from continuing operations before income taxes for the United States and West Africa includes gains and losses on commodity derivative instruments.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
(1) Revenues from third parties for all foreign countries, in total, were $1.8 billion in both 2014 and 2013, and $1.7 billion in 2012.
(2) Long-lived assets located in all foreign countries, in total, were $4.4 billion, $4.5 billion, and $4.2 billion at December 31, 2014, 2013, and 2012, respectively.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 15. 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, especially in deepwater, 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.
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 hedge 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 16. 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%.
AOCL at December 31, 2014 included deferred losses of $23 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 March 2041.
Note 17. 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 In accordance with our Marcellus Shale joint venture arrangement with a subsidiary of CONSOL Energy Inc. (CONSOL), 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 (CONSOL Carried Cost Obligation). The remaining obligation totaled approximately $1.6 billion at December 31, 2014.
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 remain suspended until average Henry Hub natural gas prices equal or exceed $4.00 per MMBtu for three consecutive months. Due to low natural gas prices, the CONSOL Carried Cost Obligation was suspended from the end of 2011 until February 28, 2014. We began funding a portion of CONSOL's working interest share of certain drilling and completion costs as of March 1, 2014; however, the funding was suspended again in November 2014 due
Noble Energy, Inc.
Notes to Consolidated Financial Statements
to lower natural gas prices. Based on the December 31, 2014 NYMEX Henry Hub natural gas price curve, we forecast the CONSOL Carried Cost Obligation will be suspended in 2015.
Marcellus Shale Firm Transportation Agreements During 2014, we signed precedent agreements for firm transportation (the Agreements) to flow approximately 320 MMBtu per day of our Marcellus Shale natural gas production to various markets outside of the Marcellus Basin. The Agreements are for firm transportation services on new pipeline projects to be constructed by, and connecting to, existing and new interstate pipeline systems. The pipeline projects are expected to be complete and operational in 2017 and 2018. Our financial commitment for these Agreements is approximately $1.5 billion, undiscounted, over a 15-year period. Final agreements are subject to various conditions, including regulatory approval of the pipeline projects. The commitment is included in the table below.
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 $69 million in 2014, $50 million in 2013, and $37 million in 2012.
Minimum commitments as of December 31, 2014 consist of the following:
(1)
Annual lease payments, net to our interest, exclude regular maintenance and operational costs. See Note 9. 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, natural gas and NGL reserves and exploration and production activities.
Reserves
There are numerous uncertainties inherent in estimating quantities of proved crude oil, natural gas and NGL reserves. Crude oil, natural gas and NGL 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, natural gas and NGLs that are ultimately recovered.
Economic producibility of reserves is dependent on the crude oil, natural gas and NGL prices used in the reserves estimate. We based our December 31, 2014, 2013, and 2012 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, natural gas or NGL 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, 2014. 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; West Africa (Equatorial Guinea, Cameroon, Gabon, Sierra Leone, and Senegal/Guinea-Bissau (which we exited in 2012); Eastern Mediterranean (Israel and Cyprus); and Other International and Corporate. Other International includes the North Sea, China (through June 2014), Falkland Islands, Nicaragua and new ventures. The North Sea geographical segment is included in continuing operations in 2014 and discontinued operations in 2013 and 2012.
Operations in Cyprus, Equatorial Guinea, Gabon 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)
Other International includes China (through June 2014) , the North Sea and Israel.
(2)
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.
The 2013 US revisions were 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.
The 2014 US revisions are primarily associated with positive performance revisions to our Marcellus Shale program and our deepwater Gulf of Mexico Swordfish field, offset by DJ Basin negative revisions due to a revised drilling plan in response to the current commodity price environment.
(3)
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.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
The 2014 increase in US reserves included an increase of 21 MMBbls in the DJ Basin and 2 MMBbls from Marcellus Shale development as well as 7 MMBbls in the deepwater Gulf of Mexico due to sanction of the Dantzler development project.
The 2013 increase is attributable to the acquisition of additional acreage in the Marcellus Shale and other onshore US locations.
(4)
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.
In 2014, we sold non-core onshore US and China assets.
(5)
Equatorial Guinea production includes sales from the Alba field to the Alba LPG plant of 3 MMBbl in 2014, 2013 and 2012.
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)
We are working with the Israeli government to reach agreement on various regulatory matters. See Items 1. and 2. Business and Properties - Update on Core Area - Israel.
(2)
Other International includes China (through June 2014) and the North Sea. See Note 3. Property Transactions.
(3)
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 were 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.
The 2014 US revisions were primarily associated with a positive performance revision to our Marcellus Shale program offset by a negative revision to our DJ Basin program due to a revised drilling program in response to the current commodity price environment. 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.
(4)
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 included 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.
The 2014 increase in US reserves included an increase of 110 Bcf in the DJ Basin and 309 Bcf from Marcellus Shale development as well as 14 Bcf in the deepwater Gulf of Mexico.
(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.
In 2014, we sold non-core onshore US and China assets.
See also Items 1. and 2. Business and Properties - Proved Undeveloped Reserves (PUDs). See also Note 3. Property Transactions.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Proved NGL Reserves (Unaudited) The following reserves schedule was developed by our qualified petroleum engineers and sets forth the changes in estimated quantities of proved NGL reserves:
(1)
The 2012 additions in US reserves included an increase of 5 MMBbls in the DJ Basin and 7 MMBbls from Marcellus Shale development.
The 2013 additions in US reserves included an increase of 19 MMBbls in the DJ Basin and 8 MMBbls from Marcellus Shale development.
The 2014 additions in US reserves included an increase of 8 MMBbls in the DJ Basin and 8 MMBbls from Marcellus Shale development.
See also Items 1. and 2. Business and Properties - Proved Undeveloped Reserves (PUDs).
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 (through June 30, 2014), Cameroon, Gabon, Sierra Leone, Cyprus, Nicaragua, Falkland Islands, 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 2014, 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 7. Derivative Instruments and Hedging Activities.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities (Unaudited) (1)
Costs incurred in connection with crude oil and natural gas acquisition, exploration and development are as follows:
(1)
Costs incurred include capitalized and expensed items.
(2)
Other International includes the North Sea, China (through June 30, 2014), Cameroon, Gabon, Sierra Leone, Cyprus, Nicaragua, and Falkland Islands. See Note 3. Property Transactions.
(3)
2014 unproved property acquisition costs include $68 million and $160 million related to expanding our positions in the DJ Basin and Marcellus Shale, respectively, and $16 million for deepwater Gulf of Mexico lease blocks.
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.
(4)
2014 exploration costs include drilling and completion of $14 million in the DJ Basin, $2 million in the Marcellus Shale, $117 million in the deepwater Gulf of Mexico, $16 million in Equatorial Guinea, $13 million in Israel and $4 million in Cyprus.
2013 exploration costs include drilling and completion of $11 million in the DJ Basin, $19 million in the Marcellus Shale, $106 million in the deepwater Gulf of Mexico, $23 million in northeast Nevada, $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.
(5)
Worldwide development costs include amounts spent to develop PUDs of approximately $2.0 billion in 2014, $1.0 billion in 2013 and $1.8 billion in 2012.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
US development costs include increases in asset retirement obligations of $106 million in 2014, $214 million in 2013 and $73 million in 2012. EG development costs include increases in asset retirement obligations of $34 million in 2014, $9 million in 2013 and $1 million in 2012. Israel development costs include increases in asset retirement obligations of $19 million in 2014, $14 million in 2013 and $54 million in 2012. Other International development costs include increases in asset retirement obligations of $71 million in 2014, $9 million in 2013 and $17 million in 2012.
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 $655 million and $860 million at December 31, 2014 and 2013, respectively.
(2)
Proved oil and gas properties at December 31, 2014 include assets held for sale of $105 million related to non-core onshore US assets and $75 million related to two natural gas discoveries, Tanin and Karish, offshore Israel, and asset retirement costs of $639 million.
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.
(3)
Accumulated DD&A at December 31, 2013 includes $187 million related to China assets held for sale and $50 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)
We are working with the Israeli government to reach agreement on various regulatory matters. See Items 1. and 2. Business and Properties - Update on Core Area - Israel.
(2)
Other International includes China (through June 30, 2014) and the North Sea. See Note 3. Property Transactions.
(3)
The standardized measure of discounted future net cash flows does not include cash flows relating to anticipated future methanol sales.
(4)
Production costs include lease operating expense, production and ad valorem taxes, transportation expense and general and administrative expense supporting crude oil and natural gas operations.
(5)
Future development costs include future abandonment costs for each location. Specifically, Other International future development costs as of December 31, 2014 primarily includes the MacCulloch field (North Sea) abandonment costs. See Note 8. Asset Retirement Obligations.
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 (through June 2014) and the North Sea. See Note 3. Property Transactions.
Because the discounted future net cash flows are computed using a 12-month average commodity price applied to our year-end quantities of proved reserves, the significant decline in crude oil prices at the end of 2014 is not fully reflected in our discounted future net cash flows. We performed a sensitivity of our discounted future net cash flows to reflect a price reduction to our 12-month average commodity price. We estimate that a $10.00 per Bbl reduction in the average price of crude oil from the 12-month average price for 2014 would reduce the discounted future net cash flows before income taxes by approximately $2.5 billion. We estimate that a $0.50 per Mcf reduction in the average price of natural gas from the 12-month average price for 2014 would reduce the discounted future net cash flows before income taxes by approximately $1.3 billion.
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, natural gas and NGL reserves at the end of the year, based on year-end costs, and assuming continuation of existing economic conditions.
Future development costs include amounts that we expect to spend to develop PUDs of $2.2 billion in 2015, $1.8 billion in 2016 and $1.7 billion in 2017.
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, natural gas and NGL 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, natural gas and NGL reserves are as follows:
Supplemental Quarterly Financial Information
(Unaudited)
Supplemental quarterly financial information is as follows:
(1)
First quarter 2014 included the following:
•
$75 million loss on commodity derivative instruments, including the non-cash portion of the loss on commodity derivative instruments of $42 million (See Note 7. Derivative Instruments and Hedging Activities);
•
$1 million pre-tax loss on sale of non-core assets (See Note 3. Property Transactions); and
•
$97 million impairment charges (See Note 4. Asset Impairments).
Second quarter 2014 included the following:
•
$236 million loss on commodity derivative instruments, including the non-cash portion of the loss on commodity derivative instruments of $187 million (See Note 7. Derivative Instruments and Hedging Activities);
•
$42 million pre-tax gain on sale of non-core assets (See Note 3. Property Transactions); and
•
$34 million impairment charges (See Note 4. Asset Impairments).
Third quarter 2014 included the following:
•
$385 million gain on commodity derivative instruments, including the non-cash portion of the gain on commodity derivative instruments of $397 million (See Note 7. Derivative Instruments and Hedging Activities);
•
$30 million pre-tax gain on sale of non-core assets (See Note 3. Property Transactions); and
•
$33 million impairment charges (See Note 4. Asset Impairments).
Supplemental Quarterly Financial Information
(Unaudited)
Fourth quarter 2014 included the following:
•
$903 million gain on commodity derivative instruments, including the non-cash portion of the gain on commodity derivative instruments of $779 million (See Note 7. Derivative Instruments and Hedging Activities);
•
$2 million pre-tax gain on sale of non-core assets (See Note 3. Property Transactions); and
•
336 million impairment charges (See Note 4. Asset Impairments).
(2)
First quarter 2013 included the following:
•
$72 million loss on commodity derivative instruments, including non-cash portion of the loss on commodity derivative instruments of $79 million (See Note 7. Derivative Instruments and Hedging Activities); and
•
$12 million pre-tax gain on sale of non-core assets (See Note 3. Property Transactions).
Second quarter 2013 included the following:
•
$161 million gain on commodity derivative instruments, including the non-cash portion of the gain on commodity derivative instruments of $159 million (See Note 7. Derivative Instruments and Hedging Activities).
Third quarter 2013 included the following:
•
$157 million loss on commodity derivative instruments, including the non-cash portion of the loss on commodity derivative instruments of $147 million (See Note 7. Derivative Instruments and Hedging Activities); and
•
$63 million impairment charges (See Note 4. Asset Impairments).
Fourth quarter 2013 included the following:
•
$65 million loss on commodity derivative instruments, including the non-cash portion of loss on commodity derivative instruments of $64 million (See Note 7. Derivative Instruments and Hedging Activities);
•
$24 million pre-tax gain on sale of non-core assets (See Note 3. Property Transactions); and
•
$23 million impairment charges (See Note 4. Asset Impairments).
(3)
The sum of the individual quarterly earnings (loss) per share amounts may not agree with year-to-date earnings per share as each quarterly computation is based on the income or loss for that quarter and the weighted average number of shares outstanding during that quarter.
(4)
Consistent with GAAP, when dilutive, deferred compensation gains or losses, net of tax, are excluded from net income while the Noble Energy shares held in the rabbi trust are included in the diluted share count. For this reason, the diluted earnings per share calculation for both the three month period ended December 31, 2014 and the year ended December 31, 2014 excludes deferred compensation gains of $17 million, net of tax.

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

ITEM 9A - CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports we file or furnish to the SEC under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms, and that information is accumulated and communicated to management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
Our principal executive officer and principal financial officer have evaluated the effectiveness of our “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended, as of the end of the period covered by this Annual Report on Form 10-K. Based upon their evaluation, they have concluded that our disclosure controls and procedures are designed and effective to ensure that information required to be disclosed in the reports that we file or furnish under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms and that information is accumulated and communicated to management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that our controls will succeed in achieving their goals under all potential future conditions.
Management’s Annual Report on Internal Control over Financial Reporting
The management report called for by Item 308(a) of Regulation S-K is incorporated herein by reference to Management’s Report on Internal Control over Financial Reporting, included in Item 8. Financial Statements and Supplementary Data.
The independent auditor’s attestation report called for by Item 308(b) of Regulation S-K is incorporated herein by reference to Report of Independent Registered Public Accounting Firm (Internal Control Over Financial Reporting), included in Item 8. Financial Statements and Supplementary Data.
Changes in Internal Control over Financial Reporting
Our management is also responsible for establishing and maintaining adequate internal controls over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Our internal controls were designed to provide reasonable assurance as to the reliability of our financial reporting and the preparation and presentation of the consolidated financial statements for external purposes in accordance with US GAAP.
Because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements. Projections of any evaluation of the effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Our management has assessed the effectiveness of our internal controls over financial reporting as of December 31, 2014. Based on our assessment, our internal controls over financial reporting were effective. There were no changes in internal controls over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

ITEM 9B - OTHER INFORMATION
Item 9B. Other Information
None.
PART III

ITEM 10 - DIRECTORS AND EXECUTIVE OFFICERS
Item 10. Directors, Executive Officers and Corporate Governance
The information required by this item is incorporated herein by reference to the 2015 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2014.

ITEM 11 - EXECUTIVE COMPENSATION
Item 11. Executive Compensation
The information required by this item is incorporated herein by reference to the 2015 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2014.

ITEM 12 - SECURITY OWNERSHIP
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required by this item is incorporated herein by reference to the 2015 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2014.

ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this item is incorporated herein by reference to the 2015 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2014.

ITEM 14 - PRINCIPAL ACCOUNTANT FEES AND SERVICES
Item 14. Principal Accounting Fees and Services
The information required by this item is incorporated herein by reference to the 2015 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2014.
PART IV

ITEM 15 - EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibits, Financial Statement Schedules
(a) The following documents are filed as a part of this report:
(3)
Exhibits: The exhibits required to be filed by this Item 15 are set forth in the Index to Exhibits accompanying this report.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
NOBLE ENERGY, INC.
(Registrant)
Date:
February 19, 2015
By: /s/ David L. Stover
David L. Stover,
President, Chief Executive Officer
Date:
February 19, 2015
By: /s/ Kenneth M. Fisher
Kenneth M. Fisher,
Executive Vice President, Chief Financial Officer
Date:
February 19, 2015
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/ David L. Stover
President, Chief Executive Officer and Director
February 19, 2015
David L. Stover
(Principal Executive Officer)
/s/ Kenneth M. Fisher
Executive Vice President, Chief Financial Officer
February 19, 2015
Kenneth M. Fisher
(Principal Financial Officer)
/s/ Dustin A. Hatley
Vice President, Chief Accounting Officer and Controller
February 19, 2015
Dustin A. Hatley
(Principal Accounting Officer)
/s/ Charles D. Davidson
Chairman of the Board and Director
February 19, 2015
Charles D. Davidson
/s/ Jeffrey L. Berenson
Director
February 19, 2015
Jeffrey L. Berenson
/s/ Michael A. Cawley
Director
February 19, 2015
Michael A. Cawley
/s/ Edward F. Cox
Director
February 19, 2015
Edward F. Cox
/s/ Thomas J. Edelman
Director
February 19, 2015
Thomas J. Edelman
/s/ Eric P. Grubman
Director
February 19, 2015
Eric P. Grubman
/s/ Kirby L. Hedrick
Director
February 19, 2015
Kirby L. Hedrick
/s/ Scott D. Urban
Director
February 19, 2015
Scott D. Urban
/s/ William T. Van Kleef
Director
February 19, 2015
William T. Van Kleef
/s/ Molly K. Williamson
Director
February 19, 2015
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
OPEC
The Organization of Petroleum Exporting Countries
PSC
Production sharing contract
Tcf
Trillion cubic feet
US GAAP
United States generally accepted accounting principles
WTI
West Texas Intermediate index

Market Capitalization: 17984293.17607498
1-Year Return: -0.01953043788671494
252-Day Return: $252_day_return