Company: NOBLE ENERGY INC
CIK: 72207
SIC: 1311
Filing Date: 2016-02-17 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
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.
See Item 8. Financial Statements and Supplementary Data - Note 18. 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:
On January 26, 2016, the Board of Directors declared a quarterly cash dividend of $0.10 per common share, which represents a reduction of $0.08 from fourth quarter 2015, and aligns the dividend yield with historical levels. The dividend will be paid February 22, 2016, to shareholders of record on February 8, 2016. The amount of future dividends will be determined on a quarterly basis at the discretion of our Board of Directors and will depend on earnings, financial condition, capital requirements and other factors.
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, 2016, the number of holders of record of our common stock was 595.
Stock Repurchases The following table summarizes repurchases of our common stock occurring in fourth quarter 2015.
(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, 2015:
Stock Performance Graph This graph shows our cumulative total shareholder return over the five-year period from December 31, 2010 to December 31, 2015. The graph also shows the cumulative total returns for the same five-year period of the S&P 500 Index and a peer group of companies. The cumulative total return of the common stock of our peer group of companies includes the cumulative total return of our common stock.
The companies in our peer group consist 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, 2010 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)
2015 includes $61 million cash received in the Rosetta Merger, an all-stock transaction.
(3)
Goodwill was fully impaired at December 31, 2015. See Item 8. Financial Statements and Supplementary Data - Note 4. Goodwill.

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 globally diversified explorer and 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 and diverse, worldwide portfolio of assets with investment flexibility between onshore unconventional developments and offshore organic exploration leading to major development projects. Our portfolio is further diversified through US and international projects and production mix among crude oil, natural gas, and NGLs. Our legacy core operating areas include 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 attractive returns over the oil and gas business cycle.
In third quarter 2015, we added two new core operating areas, the Eagle Ford Shale and the Permian Basin, as a result of our merger with Rosetta. We also seek to enter other potential new core areas and are conducting exploration activities in locations such as the Falkland Islands, Cameroon, Suriname and Gabon. We may also conclude that an exploration area is not commercially viable and, therefore, may exit locations, such as we did in 2015 with Nevada, Sierra Leone and Nicaragua.
Impact of Current Commodity Prices The upstream oil and gas business is cyclical and we are currently operating in a sustained lower commodity price environment. Our consolidated average realized prices for fiscal year 2015 decreased 51% for crude oil, 28% for natural gas and 68% for NGLs as compared with 2014. These low prices resulted in a reduction in our capital spending program, had significant negative impacts on our revenues, profitability, cash flows and proved reserves, resulted in asset and goodwill impairments, caused us to execute certain organizational changes, and led to reductions in our stock price.
Thus far in 2016, commodity prices have continued to trade in a low range, with crude oil prices falling below $30.00 per barrel on some occasions. If the industry downturn continues for an extended period, or becomes more severe, we could experience additional material negative impacts on our revenues, profitability, cash flows, liquidity, and reserves, and we could consider further reductions in our capital program or dividends, asset sales or additional organizational changes. Our production and our stock price could decline further as a result of these activities. See Item 1A. Risk Factors - We are currently experiencing a severe downturn in the oil and gas business cycle, and an extended or more severe downturn could have material adverse effects on our results of operations, our liquidity, and the price of our common stock.
2015 Achievements Despite operating in a low commodity price environment, there were numerous operational successes in 2015. Just as importantly, we positioned ourselves for long-term operational performance and future growth in the current commodity price environment. We achieved material reductions in capital and controllable unit costs, supporting project returns and margin improvements, while delivering year-over-year volume growth. In addition, we took numerous steps to enhance our liquidity position. In summary, we exited 2015 with operational momentum, investment flexibility, and strong financial liquidity which we expect to carry over to 2016.
Our successes included the following:
Onshore US Growth Onshore, we continued our DJ Basin development activity and, in third quarter, added two new onshore US core areas through the Rosetta Merger in an all-stock transaction. By the end of 2015, we had fully integrated Rosetta’s operations. In addition, by leveraging our expertise in other premier US onshore basins, we have begun to realize significant operational synergies positively impacting our drilling and production activities.
Production Volume Increases Efficiencies generated by drilling time reductions and completion improvements resulted in increased production as we delivered year-over-year volume growth of almost 20% (10% excluding the impact of the Rosetta Merger) resulting in record average sales volumes of 355 MBoe/d.
Capital Cost Reductions While delivering higher production volumes, we realized significant reductions in capital expenditures, over 40% from 2014.
Lease Operating and G&A Expense Reductions We realized significant reductions in unit costs for lease operating and general and administrative (G&A) expenses, 21% and 34%, respectively, on a BOE basis.
Major Projects Advancement Offshore, our major project execution capabilities enabled us to deliver two new major projects and progress on a third in the Gulf of Mexico. Our operated projects in West Africa and Israel continued to provide world-class reliability and, in Israel, we achieved substantial progress on the government framework for crude oil and natural gas resource development.
Liquidity Enhancements We ensured liquidity by accessing the capital markets with a common stock offering and extending our Credit Facility maturity date by two years. More recently, we generated over $190 million of cash from the close of our Cyprus farmout and sale of Karish and Tanin discoveries, and undertook debt refinancing activities to enhance our financial flexibility.
Positioned for the Future We believe the following factors will contribute to the sustainability of our business in a lower commodity price environment:
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we have a high-quality, globally diversified portfolio of assets, the majority of which are held by production and provide investment flexibility;
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we have achieved sustainable cost reductions (and are well-positioned on the US supply curve) impacting both operating expenses and capital items, positively impacting operating cash flows;
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we are focused on operational efficiencies and projects that can be profitable in the current commodity price environment;
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we have designed a substantially-reduced capital investment program, with flexibility allowing us to respond to changing commodity price conditions in 2016;
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we plan to defer certain activities to protect our strong liquidity position and expect the capital investment program to be more closely aligned with cash flow;
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we have established a commodity price hedging program for 2016; and
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we have robust liquidity of $5.0 billion at December 31, 2015 and ability to access capital markets.
See also Operating Outlook, Results of Operations, and Liquidity and Capital Resources, below.
2015 Financial Results Our financial results, some of which were significantly impacted by declining crude oil and natural gas prices, included:
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net loss of $2.4 billion, as compared with net income of $1.2 billion for 2014;
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net gain on commodity derivative instruments of $501 million (including $508 million non-cash loss), as compared with $976 million net gain (including $947 million non-cash gain) for 2014;
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dry hole expense of $266 million, as compared with $226 million for 2014;
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reduced lease operating expense of $4.43 per BOE, as compared with $5.58 per BOE for 2014, a reduction of 21%;
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reduced general and administrative expense of $3.11 per BOE, as compared with $4.73 per BOE for 2014, a reduction of 34%;
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asset impairment charges of $533 million, as compared with $500 million for 2014;
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goodwill impairment charge of $779 million;
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diluted loss per share of $6.07, as compared with diluted earnings per share of $3.27 for 2014;
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cash flows provided by operating activities of $2.1 billion, as compared with $3.5 billion in 2014; and
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capital expenditures, excluding Rosetta Merger, of $2.9 billion, as compared with $5.0 billion in 2014.
Significant Events Impacting Liquidity Included:
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net cash proceeds of $1.1 billion received from public offering of shares of common stock;
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extension of Credit Facility maturity date to August 27, 2020; and
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cash dividend repatriation of $858 million from foreign operations.
Year-end Financial Metrics Included:
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cash balance of $1.0 billion, as compared with $1.2 billion at December 31, 2014;
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total liquidity of $5.0 billion, as compared with $5.2 billion at December 31, 2014; and
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ratio of debt-to-book capital of 43%, as compared with 38% at December 31, 2014.
Cost Reduction Efforts During 2015, we focused on maintaining our strong safety culture, driving operational efficiencies and reducing our cost structure. Cost reduction initiatives, including both operational enhancements and new pricing arrangements with suppliers, resulted in significantly reduced unit costs in lease operating expense and general and administrative expense as compared with 2014. Our global portfolio provides significant optionality, allowing us to reduce our
capital spending, excluding the Rosetta Merger, by 42% for 2015, as compared with 2014. This capital spending reduction, coupled with cost reduction activities, has aligned overall cash expenditures more closely with operating cash flows in the current commodity price environment. We also implemented organizational changes including relocating our Ardmore, Oklahoma office, reducing our total workforce and consolidating our Houston personnel to our corporate headquarters in Houston.
Sales Volumes On a BOE basis, total consolidated sales volumes were 20% higher for 2015 as compared with 2014, and our mix of sales volumes was 43% global liquids, 23% international natural gas, and 34% US natural gas. On a BOE basis and excluding the impact of the Rosetta Merger, total sales volumes were 10% higher for 2015 as compared with 2014, and our mix of sales volumes was 41% global liquids, 25% international natural gas, and 34% US natural gas. See Results of Operations - Revenues, below.
Merger, Acquisitions and Divestitures During 2015, activity included the following:
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completion of the Rosetta Merger;
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acquisition of a non-operated 20% working interest in Block 54 offshore Suriname;
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sale of certain non-core onshore US properties, generating net proceeds of $151 million;
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farm-out of a portion of our interest in Block 12 offshore Cyprus for total consideration of $165 million, $125 million of which was received in January 2016; and
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sale of our 47% interest in the Alon A and Alon C licenses offshore Israel, which include Karish and Tanin natural gas discoveries, for total transaction value of $73 million ($67 million for asset consideration and $6 million from adjustment of costs), which closed in January 2016.
See Item 8. Financial Statements and Supplementary Data - Note 3. Merger, Acquisitions and Divestitures.
Commodity Hedging Activities To enhance the predictability of our cash flows and support our capital investment program, we have historically hedged portions of our expected global crude oil and domestic natural gas revenues. In the current crude oil price environment, our hedges for 2016 revenues are expected to contribute to cash flows from operations, offsetting a portion of declines in revenues. Our 2016 hedges cover approximately 35% of our expected global crude oil and 25% of our expected US natural gas production.
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 8. Derivative Instruments and Hedging Activities.
Update on Israel Antitrust Matters During 2015, the Israeli government implemented the Natural Gas Framework to support development of offshore natural gas reserves and natural gas exports. See Items 1. and 2. Business and Properties - Update on Israel - Israel Natural Gas Framework.
Goodwill Impairment Prior to conducting our goodwill impairment test, our consolidated balance sheet included $779 million of goodwill, all of which was attributable to the US reporting unit. This goodwill related primarily to the excess purchase price over amounts assigned to assets and liabilities from the Rosetta Merger in 2015 of $163 million and the Patina Merger in 2005. Primarily due to the current commodity price environment, we determined that our goodwill balance was not recoverable and fully impaired it, recording goodwill impairment charges of $779 million during fourth quarter 2015. See Item 8. Financial Statements and Supplementary Data - Note 4. Goodwill.
Asset Impairment As an oil and gas company, we have capitalized costs associated with activities along the entire range of the oil and gas investment cycle. These investments are included in property, plant and equipment in our consolidated balance sheet and consist primarily of acquisition costs, capitalized exploratory well costs and development costs. In line with applicable accounting conventions, we periodically evaluate our investments for impairment whenever events or circumstances indicate that the recorded carrying values of the assets may not be recoverable. We use forward-looking models that include various assumptions, such as anticipated exploration activities, economic evaluation of exploratory wells and future cash flows, and apply the model that is most closely aligned with the maturity of the asset along the investment cycle.
We recorded total property impairment charges of $533 million in 2015, including $490 million during fourth quarter 2015. Declines in crude oil prices triggered $481 million of the total impairment charges, which were related to certain deepwater Gulf of Mexico, Eastern Mediterranean and Equatorial Guinea properties. See Critical Accounting Policies - 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 5. Asset Impairments.
OPERATING OUTLOOK
2016 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 lower 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. During 2015, prices fell to multi-year lows and the lowest levels since the 2008 financial crisis. Thus far, there has been no price recovery in 2016, prices have fallen to new lows and NYMEX crude oil futures continue to be weak.
The outlook for crude oil prices during 2016 depends primarily on supply and demand dynamics and global security concerns in crude oil-producing nations. Production levels will be a primary determinant for 2016. If, during 2016, OPEC maintains its position against cutting production, we expect prices to be low or move lower. 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 2016 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 re-balance. If prices remain at lower levels, we expect producers will reduce investment which will, over time, reduce production, helping to balance supply and demand in the crude oil market.
Natural Gas The US domestic natural gas market continues to be oversupplied. During 2015, prices remained weak, falling to multi-year lows. In addition, location differentials increased in some regions, such as the Marcellus Shale, resulting in further declines in natural gas prices. Infrastructure projects are in place to move natural gas out of the Marcellus Shale which should improve differentials in the future. Domestic production has continued to grow, due to drilling efficiency and a backlog of drilled but uncompleted wells that came online with completion of new pipeline infrastructure in 2015, which outstripped demand growth.
Although the pace of drilling has 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 2016. At a minimum, we expect US natural gas prices to continue to trade in a low range for the near term.
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 2016 capital investment program that will be responsive to conditions that develop in 2016. This program, coupled with our commodity hedging programs, will support continued investment in a volatile commodity price environment. See 2016 Capital Investment Program, below.
2016 Production We have adopted a comprehensive effort to spend within cash flow, manage the Company's balance sheet and position ourselves for future growth. To this end, we plan to defer certain activities to protect our liquidity position and adopted a 2016 capital program more closely aligned with expected cash flow. Therefore, our total crude oil, natural gas and NGL production for 2016 may not grow at a rate consistent with prior years. Production may be impacted by factors including:
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commodity prices, which, if subject to further decline, could result in current production becoming uneconomic;
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overall level and timing of capital expenditures which, as discussed below and dependent upon our drilling success, will impact near-term production volumes;
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the reduced level of horizontal drilling activity onshore US and the decline in DJ Basin legacy vertical well production;
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timing of start-up of a low pressure line-loop system, performance of gathering and processing infrastructure, capacity constraints of midstream facilities serving those wells, offset by additional capacity from new facilities, and occurrence of other events which impact capacity constraints of midstream facilities serving our DJ Basin wells;
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timing of start-up of the Gunflint project (deepwater Gulf of Mexico) and Alba compression project (offshore Equatorial Guinea);
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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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conversion of Israeli electricity portfolio from coal to natural gas;
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potential for exports of natural gas to Egypt and Jordan;
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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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overall performance from onshore US wells;
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potential weather-related volume curtailments due to hurricanes in the deepwater Gulf of Mexico, or winter storms and flooding impacting onshore US operations;
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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;
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.
2016 Capital Investment Program Given the current commodity price environment, we have designed a substantially reduced and flexible capital investment program that is part of our comprehensive effort to spend within cash flow and manage the Company's balance sheet.
Our preliminary 2016 capital investment program will accommodate an investment level of approximately $1.5 billion, approximately 50% lower than the 2015 program. The program allocates two-thirds of total investment to core onshore US assets and the remaining one-third to offshore development and exploration.
Specifically, the capital investment program allocates approximately $600 million to the DJ Basin, $150 million to the Marcellus Shale, $250 million to the Eagle Ford Shale and Permian Basin, $250 million to the Gulf of Mexico, and $100 million to offshore Israel, with the remainder for West Africa and other projects.
See Liquidity and Capital Resources - Financing Activities and Contractual Obligations.
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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production, drilling, delivery commitments or other contractual obligations;
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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;
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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 Items 1. and 2. Business and Properties - Update on Israel - Israel Natural Gas Framework, and Liquidity and Capital Resources - Contractual Obligations - Marcellus Joint Development Agreement, Exploration Commitments and Continuous Development Obligations.
Exploration Program We continually evaluate our exploration inventory to provide additional long-term growth opportunities and potential new core areas. In addition, each of our existing core areas has remaining exploration upside, including the potential for low-cost addition of new acreage or bolt-on activity. We continue to leverage existing activities to improve our exploration programs in these core areas.
Prior to the commodity price downturn in 2014, we devoted 10% or more of our capital investment program to exploration and associated appraisal activities. Our 2016 exploration program has been reduced commensurate with overall capital reductions.
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 2016. 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 Dry Hole Cost, Lease Abandonment Expense or Property Impairments
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 are currently drilling the Silvergate prospect in the deepwater Gulf of Mexico. If we conclude that the well does not encounter hydrocarbons or that this prospect is not economically viable, the costs incurred would be recorded as dry hole expense.
Total capitalized costs related to previous exploratory wells totaled $1.4 billion at December 31, 2015. If, in the future, we determine that the well has not found proved reserves or a potential project is deemed noncommercial, the related well costs would immediately be charged to exploration expense as dry hole cost. See Item 8. Financial Statements and Supplementary Data - Note 6. Capitalized Exploratory Well Costs.
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.
In addition, new regulations are being considered by various federal agencies, including the BSEE and the BOEM, overseeing our activities in the Gulf of Mexico. These regulations, if ultimately adopted, could, among other things, significantly increase the costs associated with our activities in the Gulf of Mexico and result in some of our undrilled leasehold becoming uneconomic to drill and therefore written off. See Items 1. and 2. Business and Properties - Regulations - US Offshore Regulatory Developments.
We currently have capitalized undeveloped leasehold cost of approximately $247 million related to deepwater Gulf of Mexico prospects that have not yet been drilled. These leases will expire over the years 2016 - 2024 and some leases may become impaired if production is not established, we do not take action to extend the terms of the leases, or the leases become uneconomic due to low commodity prices, costs of complying with new regulations, or other factors.
As a result of our exploration activities, future exploration expense, including leasehold expense, could be significant. See Results of Operations - Oil and Gas Exploration Expense, below. See also Item 1A. Risk Factors.
Producing Properties In 2016, commodity prices, including WTI, Brent and HH, have continued to trade in a low range and remain volatile. A decline in future crude oil, natural gas or NGL prices could result in some of our properties becoming uneconomic, resulting in additional impairment charges, decrease in proved reserves and/or shut-in of currently producing wells.
In addition, in certain onshore US areas, transportation bottlenecks caused by oversupply and/or lack of infrastructure can reduce the amount of production reaching premium markets, resulting in higher basis differentials, or differences between WTI and HH pricing and the average prices we actually receive. An increase in these basis differentials could also reduce cash flows and result in property impairment charges.
The cash flow model that we use to assess proved properties for impairment includes numerous assumptions, such as management’s estimates of future crude oil and natural gas production 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, or increases in basis differentials, alone could result in an impairment.
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 and less expensive in periods of low demand. Furthermore, regulations for decommissioning activities are under constant review for amendment and expansion and more stringent requirements are frequently mandated. Therefore, our ARO estimates may change, sometimes significantly, and could result in asset impairment.
See Items 1. and 2. Business and Properties.
Divestments We occasionally market certain 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.
Recently Issued Accounting Standards Updates See Item 8. Financial Statements and Supplementary Data - Note 1. Summary of Significant Accounting Policies.
Climate Change Climate change has become the subject of significant public policy debate. While climate change remains a complex technical issue, governments around the world have concluded that it poses an urgent and potentially irreversible threat and that global greenhouse gas emissions must be reduced to address that threat.
Our crude oil and natural gas exploration and production operations are a direct source of certain GHGs, namely carbon dioxide and methane, and an indirect source of GHGs from the combustion of our products. Future restrictions on the production, use, emission or combustion of hydrocarbons could have a significant impact on our operations. We therefore are actively monitoring the following climate change related issues:
Impact of Legislation and Regulation Among the commercial risks associated with the exploration and production of hydrocarbons is the uncertainty of government-imposed climate change obligations, including cap and trade schemes, carbon taxes, and other controls 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 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 (Protocol) to the United Nations Framework Convention on Climate Change (Convention) 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. Certain parties then agreed to a second commitment period of the Kyoto Protocol which will last until December 31, 2020. Although a party to the Convention, the US did not ratify the Protocol.
Continuing international negotiations resulted in 195 countries, including the US, signing a new climate change agreement in Paris in 2015. While hailed as a significant political achievement, the Paris Agreement largely creates a foundation for further action. It aims to limit any increase in global temperature to less than 2°C greater than pre-industrial levels and to pursue efforts to limit the increase to 1.5°C. Parties are to submit their own nationally determined contributions toward GHG emissions reductions, which, unlike the reductions in the Protocol, will not be binding obligations. To help developing countries address climate change, moreover, the Paris Agreement sets a floor of $100 billion in annual aid collectively from developed countries. A new mitigation mechanism also will be developed over the next several years. The Paris Agreement will enter into force on the 30th day after being ratified by at least 55 parties representing at least 55% of global GHG emissions.
The US had submitted its emissions pledge in advance of the Paris Agreement. It sets an economy-wide target in 2025 of reducing GHG emissions by 26-28% as compared to 2005 levels, and to make best efforts to reach 28%. The Presidential climate action plan discussed above reportedly is expected to account for much, but not all, of the reduction.
The current state of development of the ongoing international climate initiatives and any related domestic actions make it difficult to assess the timing or effect on our operations or to 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 climate change initiatives. 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 56% of our 2015 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.
However, future restrictions on emissions of GHGs, or related measures to encourage use of renewable energy, could have a significant impact on our future operations and reduce demand for our products. And to the extent that international efforts are not successful in preventing climate change, any resulting increase in severity or frequency of storms, rise in sea levels, extreme temperatures or other extreme environmental effects may have an adverse impact on our financial condition, results of operations and cash flows. 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 year ended 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 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 this case, we record NGL 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 revenues from sales of crude oil, natural gas and NGLs is as follows:
Changes in revenue are discussed below.
Oil, Gas and NGL Sales Average daily sales volumes and average realized sales prices were as follows:
(1)
Natural gas 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 US natural gas and NGLs are significantly less than the price for a barrel of crude oil. In Israel, we sell natural gas under contracts where the majority of the price is fixed, resulting in less commodity price disparity.
(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 $1.6 billion, or 46%, in 2015 as compared with 2014 due to the following:
•
a 51% decrease in total consolidated average realized prices primarily due to the decline in global crude oil prices that began in the second half of 2014 and continued in 2015;
•
decrease in sales volumes due to planned downtime and maintenance as well as natural field decline in the deepwater Gulf of Mexico and the Aseng field, offshore Equatorial Guinea; and
•
decrease in sales volumes due to the sale of our China assets at the end of second quarter 2014;
partially offset by:
•
higher sales volumes of 7 MBbl/d in the DJ Basin primarily attributable to increased well productivity due to enhanced completion techniques and increased processing capacity;
•
sales volumes of 7 MBbl/d contributed by our recently-acquired Eagle Ford Shale and Permian Basin assets; and
•
start up of the deepwater Gulf of Mexico Rio Grande development in fourth quarter 2015 which contributed 2 MBbl/d.
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 certain North Sea assets during 2013;
partially offset by:
•
higher sales volumes of 4 MBbl/d in the DJ Basin primarily attributable to our horizontal drilling programs; and
•
higher sales volumes of 2 MBbl/d in West Africa primarily due to the timing of crude oil and condensate liftings.
Natural Gas Sales Revenues from natural gas sales decreased by $167 million, or 14%, in 2015 as compared with 2014 due to the following:
•
a 28% decrease in total consolidated average realized natural gas prices, including a 46% decrease in US average realized prices primarily due to oversupply; and
•
a widening of location basis differentials in the Marcellus Shale due to an oversupply of natural gas in the region which lowered the price we received;
partially offset by:
•
higher sales volumes of 28 MMcf/d in the DJ Basin primarily attributable to increased well productivity due to enhanced completion techniques and increased processing capacity;
•
higher sales volumes of 131 MMcf/d in the Marcellus Shale primarily attributable to well completion and infrastructure development;
•
sales volumes of 58 MMcf/d contributed by our recently-acquired Eagle Ford Shale and Permian Basin assets; and
•
record sales volumes from the Tamar field, offshore Israel, which contributed 21 MMcf/d, in response to higher power generation needs;
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.
NGL Sales Revenues from NGL sales decreased by $123 million, or 46%, in 2015 as compared with 2014 due to the following:
•
a 68% decrease in total consolidated average realized NGL prices, which are closely linked to the NYMEX WTI crude oil price decline, particularly in the Marcellus Shale;
partially offset by:
•
higher sales volumes of 2 MBbl/d in the DJ Basin primarily attributable to increased well productivity due to enhanced completion techniques and increased processing capacity;
•
higher sales volumes of 5 MBbl/d in the Marcellus Shale primarily attributable to well completion and infrastructure development; and
•
sales volumes of 9 MBbl/d contributed by our recently-acquired Eagle Ford Shale and Permian Basin assets.
Revenues from NGL sales increased by $55 million, or 26%, during 2014 as compared with 2013 due to the following:
•
higher sales volumes of 3 MBbl/d in the DJ Basin, due to increased horizontal drilling activity; and
•
higher sales volumes of 4 MBbl/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.
Income from Equity Method Investees We have interests in various equity method investees that 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) CONE Gathering distributed $204 million of dividends following the CONE Midstream IPO in 2014.
AMPCO and Affiliates Net income from AMPCO and affiliates decreased in 2015 as compared with 2014 primarily due to lower average realized methanol prices resulting from lower global demand and expenses associated with plant turnaround activities conducted first quarter 2015.
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.
Alba Plant Net income from Alba Plant in 2015 decreased as compared to 2014 primarily due to the decrease in the average realized sales price of condensate and LPG resulting from lower global demand.
Net income from Alba Plant in 2014 decreased as compared to 2013, primarily due to a decrease in the average realized sales price of condensate and LPG while sales volumes remained flat.
CONE Gathering and CONE Midstream 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:
N/M amount is not meaningful.
Changes in operating costs and expenses are discussed below.
Production Expense Components of production expense were as follows:
N/M Amount is not meaningful.
(1)
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.
(2)
Other International, Corporate includes the North Sea (in 2014 and 2015), China (through June 30, 2014) and corporate expenditures.
(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 decreased in 2015 as compared with 2014 due to the following:
•
decrease of $17 million from sales of non-core onshore US properties in 2014;
•
decrease of $17 million due to the sale of our China assets at the end of second quarter 2014;
•
decrease of $15 million in deepwater Gulf of Mexico due to cessation of operations at South Raton, natural field decline and cost reduction initiatives;
•
decrease of $15 million offshore West Africa due to cost reduction initiatives and lower production;
•
decrease of $6 million in offshore Israel due to cost reduction initiatives; and
•
decrease of $9 million in other international/corporate due to cost reduction initiatives;
partially offset by:
•
increase of $38 million attributable to our recently-acquired Eagle Ford Shale and Permian Basin assets; and
•
increase of $11 million in the Marcellus Shale due to increased production.
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.
See also Discontinued Operations, below.
Production and Ad Valorem Tax Expense Production and ad valorem taxes decreased in 2015 as compared with 2014, primarily driven by lower revenues resulting from the decline in commodity prices in the US as well as a reduction of $17 million resulting from the sale of our China assets at the end of the second quarter 2014.
Production and ad valorem tax expense 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.
Transportation Expense Transportation expense increased in 2015 as compared with 2014 related to an increase of $81 million in the Marcellus Shale due to higher production and increased expenses due to service contracts with CONE Gathering, an increase of $33 million due to recently-acquired Eagle Ford Shale and Permian Basin properties and an increase of $12 million in the DJ Basin due to the May 2015 commencement of Tallgrass pipeline, which transports DJ Basin crude oil. Increases were offset by $8 million decrease due to the sale of non-core onshore US, China and North Sea properties in 2014.
Transportation expense increased in 2014 as compared with 2013 related to an increase of $44 million in the DJ Basin and Marcellus Shale due to higher production volumes from ongoing development activities offset by an $8 million decrease primarily due to the sale of non-core onshore US, China and North Sea properties in 2013 and 2014.
Unit Rate Per BOE The unit rate of total production expense per BOE decreased for 2015 as compared with 2014 primarily due to lower production and ad valorem taxes as a result of the pricing environment in addition to cost reduction initiatives in lease operating expense and higher production volumes.
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.
Exploration Expense Components of exploration expense were as follows:
(1)
West Africa includes Equatorial Guinea, Cameroon and Gabon.
(2)
Eastern Mediterranean includes Israel and Cyprus.
(3)
Other International, Corporate includes the Falkland Islands, Suriname and other new ventures and corporate expenditures.
(4)
Includes unproved leasehold amortization expense of $43 million in 2015, $43 million in 2014, and $30 million in 2013.
Oil and gas exploration expense decreased in 2015 as compared with 2014. Expense for 2015 includes the following:
•
US dry hole cost includes amounts related to northeast Nevada exploration efforts which we elected to discontinue after assessing commercial viability in the current commodity price environment;
•
West Africa dry hole cost includes the Cheetah well (offshore Cameroon) and Other International dry hole cost includes the Humpback well (offshore Falkland Islands), neither of which identified commercial quantities of hydrocarbons; and
•
salaries and related expenses for corporate exploration and new ventures personnel.
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.
Exploration expense included stock-based compensation expense of $13 million in 2015, $17 million in 2014 and $15 million in 2013.
Depreciation, Depletion and Amortization DD&A expense was as follows:
(1)
DD&A expense includes accretion of discount on asset retirement obligations of $43 million in 2015, $36 million in 2014, and $26 million in 2013.
(2)
Consolidated unit rates exclude sales volumes and costs attributable to equity method investees.
Total DD&A expense increased for 2015 as compared with 2014 due to the following:
•
increase of $332 million in the DJ Basin and Marcellus Shale due to higher sales volumes and a reduction in proved reserves at year end primarily due to downward price revisions;
•
increase of $93 million related to our recently-acquired Eagle Ford Shale and Permian Basin assets;
•
increase of $55 million related to the Rio Grande development, deepwater Gulf of Mexico, which began producing in 2015;
•
increase in Equatorial Guinea due to a reduction in proved reserves at year end primarily due to downward price revisions; and
•
increase due to record sales volumes from the Tamar field, offshore Israel;
partially offset by:
•
decrease of $92 million in the deepwater Gulf of Mexico due to planned downtime and maintenance and proved reserves additions; and
•
decrease due to the sale of our China assets during 2014.
Changes in the unit rate per BOE for 2015 as compared with 2014 were due to increased higher-cost production volumes in the DJ Basin and deepwater Gulf of Mexico, reductions in proved reserves at year-end due to downward price revisions, offset by increased lower-cost production volumes from the Tamar field.
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 due to 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.
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 2015 decreased as compared with 2014 primarily due to cost savings initiatives, including reduced use of contractors and consultants and decreases in special projects and other discretionary expenses, and decreases in employee personnel costs. Our total number of employees decreased from 2,735 at December 31, 2014 to 2,395 at December 31, 2015.
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 is impacted by the number of stock-based awards, the market price of our common stock and price volatility which may result in a higher or lower fair value of stock-based awards as calculated using the Black-Scholes-Merton option pricing model. G&A included stock-based compensation expense of $50 million in 2015, $63 million in 2014 and $58 million in 2013. See Item 8. Financial Statements and Supplementary Data - Note 12. Stock-Based and Other Compensation Plans.
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 and Item 8. Financial Statements and Supplementary Data - Note 5. Asset Impairments.
Goodwill Impairment Goodwill impairment expense was as follows:
For information regarding goodwill impairment charges, see Critical Accounting Policies and Estimates - Goodwill and Item 8. Financial Statements and Supplementary Data - Note 4. Goodwill.
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 8. Derivative Instruments and Hedging Activities and Note 13. Fair Value Measurements and Disclosures.
Interest Expense and Capitalized Interest Interest expense and capitalized interest were as follows:
(1)
Consolidated unit rates exclude sales volumes and costs attributable to equity method investees.
Interest expense prior to the reduction of capitalized interest increased in 2015 as compared with 2014. The increase in interest expense is related to a full year of interest on senior debt issued in November 2014, as well as interest on senior notes assumed by us in the Rosetta Merger during third quarter 2015. 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 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. We drew down and repaid amounts under our Credit Facility for working capital purposes. There were no other significant changes in our debt.
Interest capitalized in 2015 increased as compared with 2014. The increase is primarily due to higher work in progress amounts related to major long-term projects in deepwater Gulf of Mexico, offshore West Africa, and offshore Israel, as well as expansion of midstream infrastructure in the DJ Basin.
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.
Interest is capitalized on exploration and development projects using an interest rate equivalent to the average rate paid on long-term debt. Capitalized interest is included in the cost of oil and gas assets and amortized with other costs on a unit-of-production basis. The majority of the capitalized interest is related to long lead-time projects in the deepwater Gulf of Mexico, offshore West Africa and offshore Eastern Mediterranean. See Item 8. Financial Statements and Supplementary Data - Note 6. Capitalized Exploratory Well Costs.
Other Non-operating (Income) Expense, Net Other non-operating (income) expense, net includes deferred compensation (income) expense, interest income and other (income) expense, net. See Item 8. Financial Statements and Supplementary Data - Note 2. Additional Financial Statement Information.
Deferred Compensation (Income) Expense We have assets and liabilities related to a deferred compensation plan. The assets of the deferred compensation plan are held in a rabbi trust and include shares of our common stock and mutual fund investments. At December 31, 2015, approximately 36% 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 $12 million and $25 million in 2015 and 2014, respectively, and deferred compensation expense of $26 million in 2013. See Item 8. Financial Statements and Supplementary Data - Note 12. Stock-Based and Other Compensation Plans.
Income Tax Provision The income tax provision from continuing operations was as follows:
See Item 8. Financial Statements and Supplementary Data - Note 11. Income Taxes.
Discontinued Operations
Summarized results of discontinued operations, comprising our North Sea geographical segment during 2013, were as follows:
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. Merger, Acquisitions and Divestitures.
PROVED RESERVES
We have historically added reserves through our exploration program, development activities, and acquisition of producing properties. See Items 1. and 2. Business and Properties. Changes in proved reserves were as follows:
Revisions Revisions of previous estimates represent changes in previous reserves estimates, either upward (positive) or downward (negative), resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs, or development costs. Revisions included the following:
•
changes for the year ended December 31, 2015 include negative revisions of 307 MMBoe due to lower commodity prices, downward revisions of 9 MMBoe and 5 MMBoe for the DJ Basin and Eagle Ford Shale, respectively, primarily due to current drilling and development plans in the DJ Basin and expected reserve recovery from existing producing wells in the Eagle Ford Shale, and downward revisions of 3 MMBoe due to natural field decline from the Mari-B field, offshore Israel; offset by positive performance revisions of 81 MMBoe for the Marcellus Shale, 17 MMBoe for the Permian Basin and 10 MMBoe for Alba field;
•
changes for the year ended December 31, 2014 included positive performance revisions of 18 MMBoe for the Marcellus Shale, 4 MMBoe for deepwater Gulf of Mexico, 4 MMBoe for Alba field, and 3 MMBoe for the Tamar field; 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 prices; and
•
changes for the year ended December 31, 2013 included positive performance revisions of 48 MMBoe for the DJ Basin and Marcellus Shale, 11 MMBoe for the Alba field, and 21 MMBoe for the Tamar field; and positive price revisions of 13 MMBoe due to higher 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, 2015 include increases of 86 MMBoe in the DJ Basin and 14 MMBoe in the Marcellus Shale associated with our horizontal drilling programs;
•
changes for the year ended December 31, 2014 included 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; and
•
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.
We expect that a significant portion of future reserves additions will come from our major development projects onshore US and deepwater Gulf of Mexico, and new discoveries resulting from our 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 Eagle Ford Shale and Permian Basin in Texas in 2015, in connection with the Rosetta Merger, and 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 assets in 2015;
•
the sale of non-core onshore US and China assets in 2014; and
•
the sale of non-core onshore US and North Sea assets and the net impact of the DJ Basin acreage exchange in 2013.
See Items 1. and 2. Business and Properties and Item 8. Financial Statements and Supplementary Data - Note 3. Merger, Acquisitions and Divestitures.
Production See Results of Operations - Revenues - Oil, Gas and NGL Sales, above.
See also Items 1. and 2. Business and Properties, 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 commodity price environment. 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. 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 consider repatriations of foreign cash to increase our financial flexibility and fund our capital investment program. In addition, we evaluate potential strategic farm-out arrangements of our working interests for reimbursement of our capital spending and may consider non-core asset sales or other sources of funding.
During 2015, we were able to employ the above strategy successfully, taking steps to position us for long-term operational performance and future growth even in a period of lower commodity prices. See Activities Enhancing Liquidity Position, below. During 2015, low commodity prices resulted in a reduction in our capital spending program, had significant negative impacts on our revenues, profitability, and cash flows and led to a reduction in our stock price. In January 2016, our Board of Directors declared a reduced quarterly cash dividend in response to our comprehensive effort to spend within cash flow and also align the dividend yield with historical levels. However, a sustained or more severe commodity price downturn could result in material negative impacts on our cash flows and liquidity. See Item 1A. Risk Factors - We are currently experiencing a severe downturn in the oil and gas business cycle, and an extended or more severe downturn could have material adverse effects on our results of operations, our liquidity, and the price of our common stock.
Activities Enhancing Liquidity Position
During 2015 and early 2016, the following activities enhanced our liquidity position:
Common Stock Issuance In March 2015, we closed an underwritten public offering of over 24 million shares of common stock with aggregate net proceeds of approximately $1.1 billion (after deducting underwriting discounts and commissions and estimated offering expenses). We used approximately $150 million of the net proceeds to repay outstanding indebtedness under our revolving Credit Facility and the remainder was used for general corporate purposes, including the funding of our capital investment program.
Maturity Date Extension During 2015, we extended the maturity date of the Credit Facility from October 3, 2018 to August 27, 2020.
Cash Dividend Repatriations During 2015, we repatriated cash dividends of $858 million from our foreign operations. We do not expect to incur significant cash tax on these repatriations due to usage of foreign tax credits and current US tax deductions.
As of December 31, 2015, approximately $457 million of our $1.0 billion cash and cash equivalents was held by foreign subsidiaries.
Non-Core Asset Sales and Other Divestitures During 2015, we generated $151 million cash from divestitures of non-core onshore US assets. More recently, in January 2016, we received over $190 million cash from the close of our Cyprus farmout and sale of Tanin and Karish discoveries.
Debt Refinancing Also in January 2016, we completed a series of transactions, consisting of a new term loan and cash tender offers for certain outstanding notes, which we expect will collectively enhance our financial flexibility and result in future interest expense savings. See Financing Activities, below.
Dividend Reduction On January 26, 2016, our Board of Directors adjusted the quarterly dividend to 10 cents per common share, which represents a reduction of 8 cents from fourth quarter 2015, aligns the dividend yield with historical levels, and further enhances our liquidity.
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, premium, and issuance costs.
(3)
We define our ratio of debt-to-book capital as total debt (which includes long-term debt excluding unamortized premium/discount and unamortized debt issuance costs, 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
Despite a 42% reduction in capital spending, excluding the Rosetta Merger, in 2015 versus 2014, and significant decreases in operating and general and administrative expenses, continually falling commodity prices resulted in capital expenditures exceeding operating cash flows for fiscal year 2015. For 2016, our comprehensive effort to spend within cash flow includes both a substantially reduced and flexible capital program, as well as a dividend adjustment. In January 2016, our Board of Directors adjusted the Company's quarterly cash dividend to 10 cents per common share, which represents a reduction of 8 cents from fourth quarter 2015 and aligns the dividend yield with historical levels.
The extent to which capital investment could exceed operating cash flows in the future depends on the pace of future 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.
Despite the low commodity price environment, we believe our financial capacity, coupled with our increasingly 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 - 2016 Capital Investment Program, above.
To support our investment program, we expect that production resulting from our core onshore US development programs, including production from our Texas assets, combined with new production from the Big Bend and Dantzler development projects, which have recently begun producing, and from the Gunflint development, which is expected to begin producing in 2016, as well as increased peak deliverability resulting from the Tamar compression project, and presuming no significant further deterioration of prices, will result in an increase in cash flows which will be available to meet a portion of future capital commitments in 2016 and subsequent years.
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 2016. However, a downgrade or other negative action with respect to our credit rating could trigger requirements to post collateral as financial assurance of performance under certain contractual arrangements potentially impacting our liquidity and/or negatively impacting 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 $1.0 billion in cash and cash equivalents at December 31, 2015, compared with approximately $1.2 billion at December 31, 2014. At December 31, 2015, our cash was primarily denominated in US dollars and invested in money market funds and short-term deposits with major financial institutions. Approximately $457 million of this cash was attributable to foreign subsidiaries. We have recorded a related deferred tax liability on undistributed foreign earnings for the future additional US tax liability for the US and foreign tax rate differences, net of estimated foreign tax credits.
Credit Facility We maintain a Credit Facility with a committed amount of $4.0 billion through 2020. 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, 2015. 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 may include variable to fixed price commodity swaps, enhanced swaps, two-way and three-way collars, basis swaps and/or 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. Our 2016 hedges cover approximately 35% of our expected global crude oil and 25% of our expected US natural gas production.
As of December 31, 2015, the fair value of our commodity derivative assets was $592 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, 2015, we had entered into commodity derivative instruments 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, 2015 with a fair value of $592 million. Based on the December 31, 2015 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 $133 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 $28 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.
Even with certain hedging arrangements in place to mitigate the effect of commodity price volatility, our 2016 revenue and results of operations will be adversely affected if commodity prices remain at current levels or decline further. In the current commodity price environment, we are unlikely to hedge future revenues at the same level as our previous hedging arrangements. As such, our revenues will be more susceptible to commodity price volatility as our commodity price derivatives settle and are not replaced.
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, 2015, 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 (2013), 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, 2015, based on those criteria. Our assessment of, and conclusion on, the effectiveness of internal control over financial reporting did not include the internal controls of the entities acquired in the Rosetta Merger on July 20, 2015. Rosetta's consolidated total assets and total revenues represent approximately 14% of our consolidated total assets at December 31, 2015 and 6% of our consolidated total revenues for the year ended December 31, 2015. We are in the process of integrating Rosetta's and our internal control over financial reporting. As a result of these integration activities, certain controls will be evaluated and may be changed. We believe, however, that we will be able to maintain sufficient internal control over financial reporting throughout this integration process.
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, 2015 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, 2015 and 2014, and the related consolidated statements of operations, comprehensive income (loss), shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2015. 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, 2015 and 2014, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2015, 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, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 17, 2016 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ KPMG LLP
Houston, Texas
February 17, 2016
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, 2015, based on criteria established in Internal Control - Integrated Framework (2013) 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, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
Noble Energy, Inc. acquired Rosetta Resources Inc. during 2015, and management excluded from its assessment of the effectiveness of Noble Energy, Inc.’s internal control over financial reporting as of December 31, 2015, Rosetta Resources Inc.’s internal control over financial reporting which represented 14% of total assets and 6% of total revenues included in the consolidated financial statements of Noble Energy, Inc. and subsidiaries as of and for the year ended December 31, 2015. Our audit of internal control over financial reporting of Noble Energy, Inc. also excluded an evaluation of the internal control over financial reporting of Rosetta Resources Inc.
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, 2015 and 2014, and the related consolidated statements of operations, comprehensive income (loss), shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2015, and our report dated February 17, 2016 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
Houston, Texas
February 17, 2016
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 (Loss)
(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 natural gas exploration and production. Our core operating areas are onshore US (DJ Basin, Marcellus Shale, Eagle Ford Shale, and Permian Basin), deepwater Gulf of Mexico, offshore Eastern Mediterranean and offshore West Africa.
Basis of Presentation and Consolidation Accounting policies used by us and our subsidiaries conform to US GAAP. Significant policies are discussed below. Our consolidated accounts include our accounts and the accounts of our wholly-owned subsidiaries. We use the equity method of accounting for investments in entities that we do not control but over which we exert significant influence. We carry equity method investments at our share of net assets of the equity investees plus our loans and advances. Differences in the basis of the investment and the separate net asset value of the investee, if any, are amortized into income over the remaining useful life of the underlying assets. See Note 7. Equity Method Investments. All significant intercompany balances and transactions have been eliminated upon consolidation.
Use of Estimates The preparation of consolidated financial statements in conformity with US GAAP requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.
Estimated quantities of crude oil, 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 inventory, 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 commodity 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 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 2014 and 2013 consolidated financial statements to conform to the 2015 presentation. These reclassifications were not material to the financial statements.
Fair Value Measurements Fair value measurements are based on a hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three levels. The fair value hierarchy is as follows:
•
Level 1 measurements are fair value measurements which use quoted market prices (unadjusted) in active markets for identical assets or liabilities.
•
Level 2 measurements are fair value measurements which use inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly.
•
Level 3 measurements are fair value measurements which use unobservable inputs.
The fair value hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. We use Level 1 inputs when available as Level 1 inputs generally provide the most reliable evidence of fair value. See Note 13. Fair Value Measurements and Disclosures.
Cash and Cash Equivalents For purposes of reporting cash flows, cash and cash equivalents include unrestricted cash on hand and investments with original maturities of three months or less at the time of purchase.
Allowance for Doubtful Accounts We routinely assess the recoverability of all material trade and other receivables to determine their collectibility. We accrue a reserve on a receivable when, based on management’s judgment, it is probable that a receivable will not be collected and the amount of such reserve may be reasonably estimated.
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 crude oil and natural 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 2015, 2014, and 2013. 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 5. 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 5. 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. Merger, Acquisitions and Divestitures.
Exploration Costs Geological and geophysical costs, delay rentals, amortization of unproved leasehold costs, and costs to drill exploratory wells that do not find proved reserves are expensed as oil and gas exploration. We carry the costs of an exploratory well as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as we are making sufficient progress assessing the reserves and the economic and operating viability of the project. For certain capital-intensive deepwater Gulf of Mexico or international projects, it may take us more than one year to evaluate the future potential of the exploratory well and make a determination of its economic viability. Our ability to move forward on a project may be dependent on gaining access to transportation or processing facilities or obtaining permits and government or partner approval, the timing of which is beyond our control. In such cases, exploratory well costs remain suspended as long as we are actively pursuing access to necessary facilities and access to such permits and approvals and believe they will be obtained. We assess the status of suspended exploratory well costs on a quarterly basis. See Note 6. Capitalized Exploratory Well Costs.
Other Property Other property includes automobiles, trucks, airplanes, office furniture, computer equipment and other fixed assets such as buildings and leasehold improvements. These items are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets or group of assets, which range from 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 $144 million in 2015, $116 million in 2014, and $121 million in 2013.
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 9. Asset Retirement Obligations.
Goodwill Goodwill represents the excess of the cost of an acquired entity over the net amounts assigned to assets acquired and liabilities assumed. Goodwill is subject to annual impairment testing in December (or more frequently as circumstances dictate). Noble has allocated goodwill to the US reporting unit. As of December 31, 2015, our goodwill was fully impaired. See Note 4. Goodwill.
Derivative Instruments and Hedging Activities All derivative instruments (including certain derivative instruments embedded in other contracts) are recorded in our consolidated balance sheets as either an asset or liability and measured at fair value. 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.
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
Noble Energy, Inc.
Notes to Consolidated Financial Statements
period (generally the vesting period of the award) in the consolidated statements of operations. See Note 12. Stock-Based and Other Compensation Plans.
Pension and Other Postretirement Benefit Plans We recognize the funded status (the difference between the fair value of plan assets and the projected benefit obligation) of our defined benefit pension, restoration and other postretirement benefit plans in the consolidated balance sheets, with a corresponding adjustment to AOCL, net of tax. The amount remaining in AOCL at December 31, 2015 represents unrecognized net actuarial loss and unrecognized prior service cost related to our restoration plan. 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. In third quarter 2015, we completed the process of terminating our noncontributory, tax-qualified defined benefit pension plan through the purchase of annuities for the remaining participants. As a result, we reclassified all remaining unamortized prior service cost and actuarial losses relating to the pension plan from AOCL to earnings. See Note 12. Stock-Based and Other Compensation Plans.
Income Taxes Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized when items of income and expense are recognized in the financial statements in different periods than when recognized in the applicable tax return. Deferred tax assets arise when expenses are recognized in the financial statements before the tax return or when income items are recognized in the tax return prior to the financial statements. Deferred tax assets also arise when operating losses or tax credits are available to offset tax payments due in future years. Deferred tax liabilities arise when income items are recognized in the financial statements before the tax returns or when expenses are recognized in the tax return prior to the financial statements. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date when the change in the tax rate was enacted.
In addition, we provide a deferred tax liability for the US and foreign tax rate differences for the future additional US tax liability on accumulated undistributed foreign earnings of our foreign subsidiaries, net of estimated foreign tax credits. See Note 11. Income Taxes.
Treasury Stock We record treasury stock purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as reductions in shareholders’ equity in the consolidated balance sheets.
Revenue Recognition and Imbalances We record revenues from the sales of crude oil, natural gas and NGLs when the product is delivered at a fixed or determinable price, title has transferred and collectibility is reasonably assured.
When we have an interest with other producers in properties from which natural gas is produced, we use the entitlements method to account for any imbalances. Imbalances occur when we sell more or less product than we are entitled to under our ownership percentage. Revenue is recognized only on the entitlement percentage of volumes sold. Any amount that we sell in excess of our entitlement is treated as a liability and is not recognized as revenue. Any amount of entitlement in excess of the amount we sell is recognized as revenue and a receivable is accrued.
Basic and Diluted Earnings (Loss) Per Share Basic earnings (loss) per share (EPS) of our common stock is computed on the basis of the weighted average number of shares outstanding during each period. The diluted EPS of our common stock includes the effect of outstanding common stock equivalents such as stock options, shares of restricted stock, and/or shares of our stock held in a rabbi trust, except in periods in which there is a net loss.
On April 22, 2013, Noble Energy’s Board of Directors approved a 2-for-1 split of its common stock to be effected in the form of a stock dividend. The stock dividend was distributed on May 28, 2013 to shareholders of record as of May 14, 2013. Earnings per share and common shares outstanding are reported giving retrospective effect to the common stock split. See Note 14. Earnings (Loss) Per Share.
Contingencies We are subject to legal proceedings, claims and liabilities that arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are considered probable and the amounts can be reasonably estimated. See Note 18. Commitments and Contingencies.
We self-insure the medical and dental coverage provided to certain employees, and the deductibles for workers’ compensation, automobile liability and general liability coverage. Liabilities are accrued for self-insured claims, or when estimated losses exceed coverage limits, and when sufficient information is available to reasonably estimate the amount of the loss.
Foreign Currency The US dollar is considered the functional currency for each of our international operations. Transactions that are completed in foreign currencies are remeasured into US dollars and recorded in the financial statements at prevailing foreign exchange rates. Transaction gains or losses are included in other non-operating (income) expense, net in the consolidated statements of operations.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Segment Information Accounting policies for geographical segments are the same as those described above. Transfers between segments are accounted for at market value. We do not consider interest income and expense or income tax benefit or expense in our evaluation of the performance of geographical segments. See Note 15. Segment Information.
Changes in Shareholders’ Equity On April 28, 2015, our shareholders voted to approve an amendment to the Company’s Certificate of Incorporation to increase the number of authorized shares of our common stock from 500 million to 1 billion shares.
Recently Issued Accounting Standards
Income Taxes In November 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2015-17 (ASU 2015-17): Income Taxes (Topic 940), effective for annual and interim reporting periods beginning after December 15, 2016, with early adoption permitted. ASU 2015-17 requires that all deferred tax liabilities and assets, as well as any related valuation allowance, be classified in the balance sheet as noncurrent. This guidance may be applied either prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented. We elected to early adopt ASU 2015-17 as of December 31, 2015 with prospective application. See Note 10. Income Taxes.
Business Combinations In September 2015, the FASB issued Accounting Standards Update No. 2015-16 (ASU 2015-16): Business Combinations (Topic 805), effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period, to simplify the accounting for measurement-period adjustments for an acquirer in a business combination. ASU 2015-16 requires an acquirer to recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The acquirer is required to adjust its financial statements for the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts calculated as if the accounting had been completed at the acquisition date. We are currently evaluating the provisions of ASU 2015-16 and assessing the impact, if any, it may have on our financial position and results of operations.
Inventory In July 2015, the FASB issued Accounting Standards Update No. 2015-11 (ASU 2015-11): Simplifying the Measurement of Inventory, effective for annual and interim periods beginning after December 15, 2016. ASU 2015-11 changes the inventory measurement principle for entities using the first-in, first out (FIFO) or average cost methods. For entities utilizing one of these methods, the inventory measurement principle will change from lower of cost or market to the lower of cost and net realizable value. We follow the average cost method and are currently evaluating the provisions of ASU 2015-11 and assessing the impact, if any, it may have on our financial position and results of operations.
Debt Issuance Costs In April 2015, the FASB issued Accounting Standards Update No. 2015-03 (ASU 2015-03): Simplifying the Presentation of Debt Issuance Costs, effective for annual and interim periods beginning after December 15, 2015. ASU 2015-03 requires that all costs incurred to issue debt be presented in the balance sheet as a direct deduction from the carrying value of the debt. It is effective retrospectively for all prior periods presented in the financial statements beginning in first quarter 2016 and is only expected to impact the presentation of our consolidated balance sheet. In August 2015, the FASB issued ASU 2015-15 to specifically address the presentation and subsequent measurement of debt issuance costs related to line-of-credit arrangements. ASU 2015-15 allows entities to defer and present debt issuance costs related to line-of-credit arrangements as an asset and amortize the costs ratably over the term of the line-of-credit arrangement. We elected to early adopt ASU 2015-03 as of December 31, 2015 and have applied the new guidance to debt issuance costs related to our senior notes. Debt issuance costs related to our Credit Facility will continue to be presented as an asset and amortized over the term of the Credit Facility. As of December 31, 2015 and 2014, we had $12 million and $15 million of capitalized, unamortized debt issuance costs, respectively, related to our Credit Facility included in other noncurrent assets in our consolidated balance sheet. See Note 10. Long-Term Debt.
Consolidation In February 2015, the FASB issued Accounting Standards Update No. 2015-02 (ASU 2015-02): Consolidation - Amendments to the Consolidation Analysis, effective for annual and interim periods beginning after December 15, 2015. ASU 2015-02 changes the guidance as to whether an entity is a variable interest entity (VIE) or a voting interest entity and how related parties are considered in the VIE model. We are currently evaluating the provisions of ASU 2015-02 and assessing the impact, if any, it may have on our financial position and results of operations.
Revenue Recognition 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
Noble Energy, Inc.
Notes to Consolidated Financial Statements
for those goods or services. Additionally, ASU 2014-09 requires enhanced financial statement disclosures over revenue recognition as part of the new accounting guidance. Initially, the amendments in ASU 2014-09 were effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, and early application was not permitted. In August 2015, the FASB agreed to give companies an extra year to comply with the new standard through the issuance of ASU 2015-14. The standard will be effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. We are currently evaluating the provisions of ASU 2014-09 and implementation guidance to determine the impact, if any, it may have on our financial position and results of operations.
Note 2. Additional Financial Statement Information
Additional statements of operations information is as follows:
(1)
Amount represents expenses associated with the relocation of our Ardmore, Oklahoma office to our corporate headquarters in Houston and other organizational activities.
(2)
Amount represents the day rate cost associated with drilling rigs under contract, but not currently being utilized in our US onshore drilling programs.
(3)
Amount includes reclassification of the actuarial loss from AOCL related to the re-measurement and termination of our defined benefit pension plan to net income (loss).
(4)
Amount represents expenses associated with the completion of the Rosetta Merger. See Note 3. Merger, Acquisitions and Divestitures.
(5)
Amount represents lower of cost or market adjustment to materials and supplies inventory. See Note 13. Fair Value Measurements.
(6)
Amounts represent increases (decreases) in the fair values of shares of our common stock held in a rabbi trust and mutual funds.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Additional balance sheet information is as follows:
(1) Assets held for sale at December 31, 2015 include the Karish and Tanin natural gas discoveries, offshore Israel.
Supplemental statements of cash flow information is as follows:
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 3. Merger, Acquisitions and Divestitures
Rosetta Merger On July 20, 2015, Noble Energy completed the merger of Rosetta into a subsidiary of Noble Energy (Rosetta Merger). The results of Rosetta's operations since the merger date are included in our consolidated statement of operations. The merger was effected through the issuance of approximately 41 million shares of Noble Energy common stock in exchange for all outstanding shares of Rosetta using a ratio of 0.542 of a share of Noble Energy common stock for each share of Rosetta common stock and the assumption of Rosetta's liabilities, including approximately $2 billion fair value of outstanding debt.
The merger adds two new onshore US shale positions to our portfolio including approximately 50,000 net acres in the Eagle Ford Shale and 54,000 net acres in the Permian Basin (45,000 acres in the Delaware Basin and 9,000 acres in the Midland Basin). In connection with the Rosetta Merger, we incurred merger-related costs of approximately $81 million to date, including (i) $66 million of severance, consulting, investment, advisory, legal and other merger-related fees, and (ii) $15 million of noncash share-based compensation expense, all of which were expensed and are included in Other Operating (Income) Expense, Net.
Allocation of Purchase Price The merger has been accounted for as a business combination, using the acquisition method. The following table represents the preliminary allocation of the total purchase price of Rosetta to the assets acquired and the liabilities assumed based on the fair value at the merger date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill. Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, valuation of pre-merger contingencies, final tax returns that provide the underlying tax basis of Rosetta's assets and liabilities, and final appraisals of assets acquired and liabilities assumed. We expect to complete the purchase price allocation during the 12-month period following the merger date, in line with the acquisition method of accounting, during which time the value of the assets and liabilities may be revised as appropriate.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
The following table sets forth our preliminary purchase price allocation which was based on fair values of assets acquired and liabilities assumed at the merger date, July 20, 2015, with the excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill:
(1) Goodwill was fully impaired at December 31, 2015. See Note 4. Goodwill.
The fair value measurements of derivative instruments assumed were determined based on published forward commodity price curves as of the date of the merger and represent Level 2 inputs. 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. The fair value measurements of long-term debt were estimated based on published market prices and represent Level 1 inputs. The long-term debt balance includes amounts outstanding under Rosetta's credit facility which was assumed by Noble and repaid subsequent to the merger in third quarter 2015.
The fair value measurements of oil and natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties included estimates of: (i) recoverable reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average cost of capital rate. These inputs required significant judgments and estimates by management at the time of the valuation and are the most sensitive and may be subject to change.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
The results of operations attributable to Rosetta are included in our consolidated statement of operations beginning on July 21, 2015. Revenues of $181 million and pre-tax net loss of $120 million, inclusive of $163 million goodwill impairment, from Rosetta were generated from July 21, 2015 to December 31, 2015.
Proforma Financial Information The following pro forma condensed combined financial information was derived from the historical financial statements of Noble Energy and Rosetta and gives effect to the merger as if it had occurred on January 1, 2014. The below information reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including (i) Noble Energy's common stock and equity awards issued to convert Rosetta's outstanding shares of common stock and equity awards as of the closing date of the merger, (ii) adjustments to conform Rosetta's historical policy of accounting for its oil and natural gas properties from the full cost method to the successful efforts method of accounting, (iii) depletion of Rosetta's fair-valued proved oil and gas properties, and (iv) the estimated tax impacts of the pro forma adjustments. Additionally, pro forma earnings for the year ended December 31, 2015 were adjusted to exclude $81 million of merger-related costs incurred by Noble Energy and $37 million incurred by Rosetta. The pro forma results of operations do not include any cost savings or other synergies that may result from the Rosetta Merger or any estimated costs that have been or will be incurred by us to integrate the Rosetta assets.
The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Rosetta Merger taken place on January 1, 2014; furthermore, the financial information is not intended to be a projection of future results.
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. The information regarding the assets sold is as follows:
(1) See Note 4. Goodwill.
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:
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Assets Held for Sale In November 2015, we executed an agreement to divest our 47% interest in the Alon A and Alon C offshore Israel licenses, which include the Karish and Tanin fields, for a total transaction value of $73 million ($67 million for asset consideration and $6 million from adjustment of costs). These assets were held for sale as of December 31, 2015, and the transaction closed in January 2016.
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.
North Sea Properties During 2013, we sold additional non-operated, North Sea properties. The 2013 sales resulted in a $65 million gain based on net sales proceeds of $56 million. During 2013, the North Sea geographical segment was presented as discontinued operations in our consolidated statements of operations. However, we were unable to locate purchasers for the remaining properties, and 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 5. Asset Impairments.
Summarized results of discontinued operations are as follows:
Note 4. Goodwill
Our goodwill relates primarily to the excess purchase price over amounts assigned to assets and liabilities from the Rosetta Merger in 2015 and the Patina Merger in 2005 and is associated with our US reporting unit. During 2015, goodwill increased $163 million due to the Rosetta Merger and decreased $4 million due to allocations of goodwill to onshore US properties sold.
During 2015, we reviewed our goodwill balance for impairment in accordance with our accounting policy and identified factors, including continuing declines in commodity prices and the market value of our common stock, indicating that the fair value of our goodwill could have fallen below its book value. As of December 31 2015, we determined that our goodwill was fully impaired and recognized a loss of $779 million.
For purposes of determining the goodwill impairment, we estimated the implied fair value of the goodwill using a variety of valuation methods, including the income and market approaches. Our estimate of fair value required us to use significant unobservable inputs, representative of a Level 3 fair value measurement, including assumptions for future crude oil and natural gas production, commodity prices based on forward commodity price curves, operating and development costs and other factors. The analysis supported that the implied fair value of goodwill is zero and, as such, goodwill was fully impaired.
Note 5. Asset Impairments
Pre-tax (non-cash) asset impairment charges were as follows:
2015 Asset Impairments During 2015, certain deepwater Gulf of Mexico, Eastern Mediterranean and Equatorial Guinea 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 $481 million resulted from reductions in the forward crude oil prices as of December 31, 2015. In addition, we recorded approximately $47 million of impairment primarily related to revisions in expected field abandonment and other costs for deepwater Gulf of Mexico and Eastern Mediterranean properties.
During fourth quarter 2015, we executed an agreement to divest our interest in the Alon A and Alon C offshore Israel licenses, which include the Karish and Tanin fields. As a result, these assets were written down to expected proceeds less costs to sell, resulting in a $5 million impairment.
2014 Asset Impairments As a result of declining crude oil prices at the end of 2014, we recorded impairment charges of $250 million related to certain onshore US and deepwater Gulf of Mexico properties.
During 2014, 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 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.
See Note 13. Fair Value Measurements and Disclosures.
Note 6. Capitalized Exploratory Well Costs
We capitalize exploratory well costs until a determination is made that the well has found proved reserves or is deemed noncommercial. If a well is deemed to be noncommercial, the well costs are immediately charged to exploration expense as dry hole cost.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed in the same period:
(1) The 2015 amount relates primarily to onshore US exploration activity.
The 2014 amount relates primarily to the Dantzler well (deepwater Gulf of Mexico), for which we sanctioned a development plan, and the Karish and Tanin 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 2015 amount relates primarily to northeast Nevada. After assessing its commercial viability in the current commodity price environment, we elected to discontinue our exploration efforts.
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 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:
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, 2015:
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 7. 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, 2015, consolidated retained earnings included $106 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, 2015. The difference is related to capitalized interest which is being amortized into earnings over the remaining useful life of the plant.
Summarized, 100% combined financial information for equity method investees is as follows:
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 8. Derivative Instruments and Hedging Activities
Objective and Strategies for Using Derivative Instruments In order to mitigate the effect of commodity price volatility and enhance the predictability of cash flows relating to the marketing of our crude oil and natural gas, we enter into crude oil and natural gas price hedging arrangements. The derivative instruments we use may include variable to fixed price commodity swaps, enhanced swaps, two-way and three-way collars, basis swaps and/or 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, 2015.
We also may enter into forward contracts to hedge anticipated exposure to interest rate risk associated with public debt financing. As of December 31, 2015 we did not have any interest rate derivatives outstanding.
While these instruments mitigate the cash flow risk of future reductions in commodity prices or increases in interest rates, they may also curtail benefits from future increases in commodity prices or decreases in interest rates.
See Note 13. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of our derivative instruments.
Counterparty Credit Risk Derivative instruments expose us to counterparty credit risk. Our commodity derivative instruments are currently with a diversified group of major banks or market participants, and we monitor and manage our level of financial exposure. Our commodity derivative contracts are executed under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net settled at the time of election.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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, 2015, we had entered into the following crude oil derivative instruments:
(1)
We traditionally enter into a hedge contract term of one year. For 2016 and 2017 we have entered into various derivative hedging arrangements with a contract term of six months resulting in non-uniform annual volumes and weighted average prices.
(2)
We have entered into crude oil derivative enhanced swaps with strike prices that are above the market value as of trade commencement. To effect the enhanced non-cash swap structure, we sold call options to the applicable counterparty to receive the above market terms.
(3) Includes derivative instruments assumed by our subsidiary, NBL Texas, LLC, in connection with the Rosetta Merger.
(4) The index for these derivative instruments is NYMEX WTI and Argus LLS indices.
(5) We have entered into certain Dated Brent derivative contracts (swaptions), which give counterparties the option to extend for an additional 6-month period. Options covering a notional volume of 3,000 Bbls/d are exercisable on June 30, 2017. If the counterparties exercise all such options, the notional volume of our existing Dated Brent derivative contracts will increase by 3,000 Bbls/d at an average price of $62.80 per Bbl for each month during the period July 1, 2017 through December 31, 2017.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
As of December 31, 2015, we had entered into the following natural gas derivative instruments:
(1)
We have entered into certain natural gas derivative contracts (swaptions), which give counterparties the option to extend for an additional 12-month period. Options covering a notional volume of 30,000 MMBtu/d are exercisable on December 22 and 23, 2016. If the counterparties exercise all such options, the notional volume of our existing natural gas derivative contracts will increase by 30,000 MMBtu/d at an average price of $3.50 per MMBtu for each month during the period January 1, 2017 through December 31, 2017.
(2)
Includes derivative instruments assumed by our subsidiary, NBL Texas, LLC, in connection with the Rosetta Merger.
Fair Value Amounts and Gains and Losses on Derivative Instruments The fair values of derivative instruments in our consolidated balance sheets were as follows:
Noble Energy, Inc.
Notes to Consolidated Financial Statements
The effect of derivative instruments on our consolidated statements of operations was as follows:
(1) Amounts for NGLs relate to commodity derivative instruments, acquired in the Rosetta Merger, which expired as of December 31, 2015.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 9. Asset Retirement Obligations
Asset retirement obligations (ARO) consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. Changes in asset retirement obligations were as follows:
For the year ended December 31, 2015
Liabilities incurred were due to new wells and facilities and included $22 million primarily for onshore US, $16 million for deepwater Gulf of Mexico and $29 million for Rosetta Merger related assets.
We settled liabilities of $23 million for the DJ Basin, $2 million for deepwater Gulf of Mexico and $13 million for the North Sea.
Revisions were primarily due to changes in estimated costs for future abandonment activities and acceleration of timing of abandonment and included $96 million for the DJ Basin, $48 million for Eastern Mediterranean, $35 million for deepwater Gulf of Mexico, and decreases of $10 million for Equatorial Guinea and $3 million for other non-core, onshore US developments.
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 an 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 of abandonment and included $33 million for DJ Basin, $29 million for 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.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 10. Long-Term Debt
Our debt consists of the following:
(1) Represents senior notes assumed in the Rosetta Merger. See Note 3. Merger, Acquisitions and Divestitures.
(2) Debt premium is attributable to senior notes assumed in the Rosetta Merger.
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 $12 million related to our Credit Facility remain and are being amortized to expense over the life of the Credit Facility.
Credit Facility On August 27, 2015, we amended our $4.0 billion Credit Facility to extend the maturity date to August 27, 2020. We periodically borrow amounts for working capital purposes.
Our Credit Facility (i) provides for facility fee rates that range from 10 basis points to 25 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 90 basis points to 150 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, 2015, 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.
Debt Exchange On July 29, 2015, we completed our debt exchange offers to exchange all validly tendered and accepted senior
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notes assumed in the Rosetta Merger. We were able to exchange 99.4% of the outstanding Rosetta senior notes, whereby we issued (i) $693 million senior unsecured 5.625% notes due May 1, 2021, (ii) $597 million senior unsecured 5.875% notes due June 1, 2022 and (iii) $499 million senior unsecured 5.875% notes due June 1, 2024. We incurred financing costs of $12 million related to the debt exchange. We also repaid the balance outstanding under, and terminated, Rosetta's credit facility of $70 million.
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. 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.
Capital Lease and Other Obligations The amounts of the capital lease obligations are based on the discounted present value of future minimum lease payments, and therefore do not reflect future cash lease payments. Amounts due within one year equal the amount by which the capital lease obligations are expected to be reduced during the next 12 months. See Note 18. Commitments and Contingencies for future capital lease payments.
Annual Debt Maturities Annual maturities of outstanding debt, excluding capital lease payments, are as follows:
Subsequent Event On January 6, 2016, we entered into a term loan agreement with Citibank, N.A., as administrative agent, Mizuho Bank, Ltd., as syndication agent, and certain other financial institutions party thereto, which provides for a three-year term loan facility for a principal amount of up to $1.4 billion. Provisions of the term loan are consistent with those in the Credit Facility. Borrowings under the term loan agreement may be prepaid prior to maturity without premium. In connection with the term loan, we launched cash tender offers for the 5.875% Senior Notes due June 1, 2024, 5.875% Senior Notes due June 1, 2022 and 5.625% Senior Notes due May 1, 2021, all of which were assumed as part of the Rosetta Merger. The borrowings under the term loan will be used solely to fund the tender offers. As of January 21, 2016, approximately $1.38 billion of notes had been validly tendered and accepted by the Company, with a corresponding amount borrowed under the new term loan. We are currently evaluating the accounting for the tendered notes to determine the impact, if any, it may have on our financial position and results of operations.
Note 11. Income Taxes
Components of income (loss) from continuing operations before income taxes are as follows:
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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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Deferred tax assets and liabilities resulted from the following:
Net deferred tax liabilities were classified in the consolidated balance sheets as follows:
(1) As discussed in Note 1. Summary of Significant Accounting Policies, we have elected to early adopt and apply the presentation requirements of ASU 2015-17, Balance Sheet Classification of Deferred Taxes, as of December 31, 2015. Prior periods have not been retrospectively adjusted.
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, 2015. 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 $206 million in 2015 and $145 million in 2014. 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 2015, as a result of cash repatriation, we released a valuation allowance of $60 million on our foreign tax credits.
During fourth quarter 2014, fluctuations in crude oil and natural 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 accumulated undistributed foreign earnings and a corresponding valuation allowance of $36 million on our foreign tax credits.
Rosetta Merger On July 20, 2015, we completed the Rosetta Merger. For federal income tax purposes, the merger qualified as a tax free merger and we acquired carryover tax basis in Rosetta’s assets and liabilities. Rosetta had a net deferred tax asset resulting from its federal net operating loss (NOL) estimated at $681 million through the date of acquisition. The merger
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resulted in a change of control for federal income tax purposes, and the NOL’s usage will be subject to an annual limitation in part based on Rosetta’s value at the date of the merger. We anticipate full utilization of the total NOL prior to its expiration.
Accumulated Undistributed Earnings of Foreign Subsidiaries Our foreign subsidiaries’ undistributed earnings of approximately $1.6 billion at December 31, 2015 are no longer considered to be indefinitely reinvested outside the United States and, accordingly, we recorded$227 million in deferred income taxes in 2015, net of estimated foreign tax credits. We based our change in the indefinite reinvestment assertion on the continued and prolonged decline in global commodity prices and an evaluation of our operations’ anticipated capital requirements and projected foreign cash positions given the adoption of the Israel Natural Gas Framework in December 2015. The actual tax impact upon distribution would depend on our tax positions at the time of repatriation and could be significantly different from this estimate.
Effective Tax Rate Our effective tax rate decreased in 2015 as compared with 2014 primarily due to a shift from pre-tax earnings in 2014 to a pre-tax loss in 2015 and the removal of our permanent reinvestment assertion discussed above. In the case of a pre-tax loss, our favorable permanent differences, such as income from equity method investees, have the effect of increasing the tax benefit which, in turn, increases the effective tax rate. Unfavorable permanent differences, such as non-deductible goodwill impairment expense, have the effect of decreasing the tax benefit which, in turn, decreases the effective tax rate. The decrease in the effective tax rate was partially offset by a release of the valuation allowance on foreign tax credits due to usage and losses from funding foreign exploration projects.
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.
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.
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 - 2012, Equatorial Guinea - 2010 and Israel - 2011.
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, 2015, approximately $8 million of unrecognized tax benefits would impact our effective tax rate if recognized. The changes to our unrecognized tax benefits during 2015 primarily resulted from changes in various foreign tax return filings, positions and audit settlements. The adjustments to our reserves for uncertain tax positions had a de minimis impact on our net income.
During 2015, we recognized and accrued a de minimis amount of interest and none in penalties.
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 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 2014, we recognized and accrued a de minimis amount of interest and none in penalties.
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We expect that our unrecognized tax benefits could continue to change due to the settlement of audits and the expiration of statutes of limitation in the next twelve months; however, we do not anticipate any such change to have a significant impact on our results of operations, financial position or cash flows in the next twelve months.
Note 12. Stock-Based and Other Compensation Plans
We recognized total stock-based compensation expense as follows:
Stock Option and Restricted Stock Plans Our stock option and restricted stock plans are described below.
1992 Stock Option and Restricted Stock Plan Under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan, as amended (the 1992 Plan), the Compensation, Benefits and Stock Option Committee of the Board of Directors (the Committee) may grant stock options and 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 77,400,000 shares of common stock. At December 31, 2015, 35,850,503 shares of our common stock were reserved for issuance, including 16,019,550 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.
2015 Stock Plan for Non-Employee Directors The 2015 Stock Plan for Non-Employee Directors of Noble Energy, Inc., as amended (the 2015 Plan) provides for grants of stock options and awards of restricted stock to our non-employee directors. The 2015 Plan superseded and replaced the 2005 Stock Plan for Non-Employee Directors of Noble Energy, Inc. The total number of shares of our common stock that may be issued under the 2015 Plan is 708,996. At December 31, 2015, 705,615 shares of our common stock were reserved for issuance including 693,665 shares available for future grants and awards, under the 2015 Plan.
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, 2015, 469,597 shares of our common stock were reserved for issuance.
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 2005 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 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:
•
Expected term The expected term represents the period of time that options granted are expected to be outstanding, which is the grant date to the date of expected exercise or other expected settlement for options granted. The hypothetical midpoint scenario we use considers our actual exercise and post-vesting cancellation history and expectations for future periods, which assumes that all vested, outstanding options are settled halfway between the current date and their expiration date.
•
Expected volatility The expected volatility represents the extent to which our stock price is expected to fluctuate between the grant date and the expected term of the award. We use the historical volatility of our common stock for a period equal to the expected term of the option prior to the date of grant. We believe that historical volatility produces an estimate that is representative of our expectations about the future volatility of our common stock over the expected term.
•
Risk-free rate The risk-free rate is the implied yield available on US Treasury securities with a remaining term equal to the expected term of the option. We base our risk-free rate on a weighting of five and seven year US Treasury securities as of the date of grant.
•
Dividend yield The dividend yield represents the value of our stock’s annualized dividend as compared to our stock’s average price for the three-year period ended prior to the date of grant. It is calculated by dividing one full year of our expected dividends by our average stock price over the three-year period ended prior to the date of grant.
The assumptions used in valuing stock options granted were as follows:
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Stock option activity was as follows:
The total intrinsic value of options exercised was $7 million in 2015, $58 million in 2014, and $64 million in 2013.
As of December 31, 2015, $34 million of compensation cost related to unvested stock options granted under the Plans remained to be recognized. The cost is expected to be recognized over a weighted-average period of 1.3 years. We issue new shares of our common stock to settle option exercises. Dividends are not paid on unexercised options.
Restricted Stock Awards Awards of time-vested restricted stock (shares subject to service conditions) are valued at the price of our common stock at the date of award. The fair values of market based restricted stock awards are estimated on the date of award using a Monte Carlo valuation model that uses the assumptions in the following table. The Monte Carlo model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility represents the extent to which our stock price is expected to fluctuate between now and the award’s anticipated term. We use the historical volatility of Noble Energy common stock for the three-year period ended prior to the 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 $62 million in 2015, $50 million in 2014, and $43 million in 2013.
The weighted average award-date fair value of restricted stock awarded was $35.53 per share in 2015, $41.22 per share in 2014, and $38.07 per share in 2013.
As of December 31, 2015, $42 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 1.7 years. Common
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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 $35 million in 2015, $26 million in 2014, and $21 million in 2013.
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.
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 13. Fair Value Measurements and Disclosures. The mutual funds are included in the mutual fund investments account in other noncurrent assets in the consolidated balance sheets.
Shares of our common stock held by the rabbi trust 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 800,000 shares, or 92%, of our common stock held in respect of one nonqualified deferred compensation plan at December 31, 2015 were attributable to a member of our Board of Directors. The shares are being distributed in equal installments over the next four years. Distributions of 200,000 shares were made in 2015 and 200,000 shares in 2014. In addition, plan participants sold 1,009 shares of our common stock in 2015, 19,049 shares in 2014, and 1,008 shares in 2013. Proceeds were invested in mutual funds and/or distributed to plan participants. Distributions to plan participants were valued at $18 million in 2015, $22 million in 2014 and $25 million in 2013.
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 $(16) million in 2015, $(25) million in 2014 and $26 million in 2013.
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 $119 million and $84 million were outstanding at December 31, 2015 and 2014, 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 provided the pension plan formula benefits that could not 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.
During 2015, we completed the termination of the pension plan. We liquidated the associated pension obligation through lump-sum payments to participants or the purchase of annuities on their behalf. Upon termination of the pension plan, all unamortized prior service cost and net actuarial loss remaining in AOCL was charged to expense. This amount totaled $88 million.
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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 were given the option to have the lump sum present value of their restoration plan benefits converted into an account balance under our nonqualified deferred compensation plan.
During 2014, we curtailed the retiree medical program, resulting in a gain of $21 million, and, at December 31, 2014, 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:
(1) The retirement (pension) plan was terminated during 2015. Balances at December 31, 2015 relate to the restoration plan only.
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 $16 million in 2015, $11 million in 2014, and $37 million in 2013.
Note 13. Fair Value Measurements and Disclosures
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheet. 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.
Inventories We carry inventory consisting 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.
Mutual Fund Investments Our mutual fund investments 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 may include variable to fixed price commodity swaps, two-way collars, three-way collars, swaptions and extendable/enhanced swaps. We estimate the fair values of these instruments using 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 8. Derivative Instruments and Hedging Activities.
Deferred Compensation Liability The value is dependent upon the fair values of mutual fund investments and shares of our common stock held in a rabbi trust. See Mutual Fund Investments above.
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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:
Inventory Impairment We determined that the carrying amount of certain of our materials and supplies inventory was not recoverable from future cash flows and, therefore, was impaired. Inventory was reduced to its estimated market value.
Asset Impairments We determined that the carrying amounts of certain oil and gas 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
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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 5. Asset Impairments.
Additional Fair Value Disclosures
Debt The fair value of fixed-rate, public debt is estimated based on the published market prices for the same or similar issues. As such, we consider the fair value of our public fixed rate debt to be a Level 1 measurement on the fair value hierarchy. See Note 10. Long-Term Debt. Fair value information regarding our debt is as follows:
(1)
Net of unamortized discount, premium and debt issuance costs and excludes capital lease and other obligations. No floating rate debt was outstanding at December 31, 2015 or December 31, 2014.
Note 14. Earnings (Loss) Per Share
Basic earnings (loss) per share of common stock is computed using the weighted average number of shares of common stock outstanding during each period. The diluted earnings (loss) 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 (loss) per share:
(1)
For the year ended December 31, 2015, all outstanding options and non-vested restricted shares have been excluded from the calculation of diluted earnings (loss) per share as Noble Energy incurred a loss from continuing operations. Therefore, inclusion of outstanding options and non-vested restricted shares in the calculation of diluted earnings (loss) per share would be anti-dilutive.
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 (loss) per share calculation for the year ended December 31, 2014 excludes deferred compensation gains, net of tax.
(2)
The weighted average number of shares outstanding includes the weighted average shares of common stock issued in connection with the underwritten public offering of 24.15 million shares of Noble Energy common stock in first quarter 2015 and issued in connection with the exchange of approximately 41 million shares for all outstanding shares of Rosetta common stock on July 20, 2015.
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Note 15. Segment Information
We have operations throughout the world and manage our operations by region. The following information is grouped into four components that are all primarily in the business of crude oil, natural gas and NGL exploration, development, production and acquisition: the United States; West Africa (Equatorial Guinea, Cameroon, Gabon and Sierra Leone (which we have exited)); Eastern Mediterranean (Israel and Cyprus); and Other International and Corporate. Other International includes the Falkland Islands, Suriname, the North Sea, China (through June 2014), Nicaragua (which we have exited) and new ventures. The North Sea geographical segment is included in continuing operations in 2015 and 2014 and in 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.
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(1) Revenues from third parties for all foreign countries, in total, were $1.1 billion in 2015 and $1.8 billion in both 2014 and 2013.
(2) As of December 31, 2015, our goodwill was fully impaired. See Note 4. Goodwill.
(3) Long-lived assets located in all foreign countries, in total, were $3.9 billion, $4.4 billion, and $4.5 billion at December 31, 2015, 2014, and 2013, respectively.
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Note 16. Concentration of Risk
Concentration of Market Risk The largest single non-affiliated purchasers of our production were as follows:
(1) Includes sales to both Shell Trading (US) Company and Shell International Trading and Shipping Limited.
We believe the loss of any one purchaser would not have a material effect on our financial position or results of operations since there are numerous potential purchasers of our production.
Concentration of Credit Risk Certain of our financial instruments, including cash equivalents, trade and joint interest receivables and derivative instruments, may expose us to credit risk.
A significant portion of our cash is located in our foreign subsidiaries. The cash is denominated in US dollars and invested in highly liquid money market funds and short term deposits with original maturities of three months or less at the time of purchase. Although our cash and cash equivalents are deposited with major international banks and financial institutions, concentrations of cash in certain foreign locations may increase credit risk. We monitor the creditworthiness of the banks and financial institutions with which we invest and review the securities underlying our investment accounts. We believe that losses from nonperformance are unlikely to occur; however, we are not able to predict sudden changes in creditworthiness.
Our accounts receivable result from sales of crude oil, natural gas and NGL production, and joint interest billings to our partners for their share of expenses on joint venture projects for which we are the operator. Joint venture projects, 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 or joint interest receivables protected through guarantees or credit support. Nonperformance by a trade creditor or joint venture partner could result in losses.
Our 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.
Note 17. Additional Shareholders’ Equity Information
Equity Offerings On March 3, 2015, we closed an underwritten public offering of 21 million shares of common stock, par value $0.01 per share, at a price of $47.50 per share. In addition, on March 25, 2015, we completed the issuance of an additional 3.15 million shares of common stock, par value $0.01 per share, in connection with the exercise of the option of the underwriters to purchase additional shares of common stock. The aggregate net proceeds of the offerings were approximately $1.1 billion (after deducting underwriting discounts and commissions and offering expenses). We used approximately $150 million of the net proceeds to repay outstanding indebtedness under our revolving credit facility and the remainder was used for general corporate purposes, including the funding of our capital investment program.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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, 2015 included deferred losses of $22 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 18. Commitments and Contingencies
Legal Proceedings We are involved in various legal proceedings in the ordinary course of business. These proceedings are subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters and we believe that the ultimate disposition of such proceedings will not have a material adverse effect on our financial position, results of operations or cash flows.
Colorado Air Matter In April 2015, we entered into a joint consent decree (Consent Decree) with the US Environmental Protection Agency, US Department of Justice, and State of Colorado to improve emission control systems at a number of our condensate storage tanks that are part of our upstream oil and natural gas operations within the Non-Attainment Area of the DJ Basin. The Consent Decree was entered by the Court on June 2, 2015.
The Consent Decree, which alleges violations of the Colorado Air Pollution Prevention and Control Act and Colorado’s federal approved State Implementation Plan, specifically Colorado Air Quality Control Commission Regulation Number 7, requires us to perform certain injunctive relief activities to complete mitigation projects and supplemental environmental projects (SEP), and pay a civil penalty. Costs associated with the settlement consist of $4.95 million in civil penalties, $4.5 million in mitigation projects, and $4 million in SEPs. Costs associated with the injunctive relief are not yet precisely quantifiable as they
Noble Energy, Inc.
Notes to Consolidated Financial Statements
will be determined in accordance with the outcome of evaluations on the adequate design, operation, and maintenance of certain aspects of tank systems to handle potential peak instantaneous vapor flow rates between now and mid-2017.
Compliance with the Consent Decree could result in the temporary shut in or permanent plugging and abandonment of certain wells and associated tank batteries. The Consent Decree sets forth a detailed compliance schedule with deadlines for achievement of milestones through early 2019. The Consent Decree contains additional obligations for ongoing inspection and monitoring beyond that which is required under existing Colorado regulations. Inspection and monitoring findings may influence decisions to temporarily shut in or permanently plug and abandon wells and associated tank batteries.
We have concluded that the penalties, injunctive relief, and mitigation expenditures that resulted from this settlement did not have, and based on currently available information will not have, a material adverse effect on our financial position, results of operations or cash flows.
Colorado Air Compliance Order on Consent In December 2015, we received a proposed Compliance Order on Consent (COC) from the Colorado Department of Public Health and Environment's Air Pollution Control Division to resolve allegations of noncompliance associated with certain engines subject to various General Permit 02 conditions and/or individual permit conditions as well as certain emission control devices subject to various individual permit conditions. The COC, which provides for an opportunity to further discuss the offer of settlement, has not yet been executed. At present, the COC seeks payment of a reduced penalty of $247,625 and provides the opportunity to mitigate up to 80% of the reduced penalty by pursuing a SEP or SEPs. Given the inherent uncertainty in administrative actions of this nature, we are unable to predict the ultimate outcome of this action at this time. However, we believe that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on our financial position, results of operations or cash flows.
CONSOL Carried Cost Obligation 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, 2015.
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 to lower natural gas prices. Based on the December 31, 2015 NYMEX Henry Hub natural gas price curve, we forecast the CONSOL Carried Cost Obligation will be suspended in 2016.
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 $84 million in 2015, $69 million in 2014, and $50 million in 2013.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Minimum commitments as of December 31, 2015 consist of the following:
(1) Annual lease payments, net to our interest, exclude regular maintenance and operational costs. See Note 10. Long-Term Debt.
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, 2015, 2014, and 2013 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 and 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, 2015. 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, and Sierra Leone (which we exited in 2015)); Eastern Mediterranean (Israel and Cyprus); and Other International and Corporate. Other International includes the North Sea, China (through June 2014), Falkland Islands, Nicaragua, Suriname and new ventures. The North Sea geographical segment is included in continuing operations in 2015 and 2014 and discontinued operations in 2013.
Operations in Cyprus, Equatorial Guinea, Gabon and Suriname 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 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
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
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.
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 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.
The 2015 US revisions were primarily associated with negative price revisions of 70 MMBbls to our onshore programs due to a decline in the 12-month average price of crude oil, offset by positive revisions of 14 MMBbls due to producing well performance and optimized lateral lengths in the Permian Basin and Eagle Ford Shale. Equatorial Guinea revisions are associated with negative price revisions of 5 MMBbls.
(3)
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 2015 increase in US reserves is attributable to 42 MMBbls from DJ Basin development.
(4)
The 2015 increase is attributable to reserves acquired in the Rosetta Merger.
(5)
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.
In 2015, we sold non-core onshore US assets.
(6)
Equatorial Guinea production includes sales from the Alba field to the Alba LPG plant of 3 MMBbl in 2015, 2014, 2013.
See Items 1. and 2. Business and Properties - Proved Undeveloped Reserves (PUDs) and Note 3. Merger, Acquisitions and Divestitures.
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)
In accordance with the terms of the Israel Natural Gas Framework, we will be required to reduce our ownership in the Tamar field to 25% within six years. See Items 1. and 2. Business and Properties - Update on Israel - Israel Natural Gas Framework.
(2)
Other International includes China (through June 2014) and the North Sea. See Note 3. Merger, Acquisitions and Divestitures.
(3)
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.
The 2015 US revisions are primarily associated with negative price revisions of 1.1 Tcf to our onshore programs due to a decline in the 12-month average price, offset by a positive revision primarily to our Marcellus Shale program due to positive well performance. Equatorial Guinea revisions are associated with positive performance revisions to the Alba field. Israel revisions are primarily associated with negative performance revisions in the Mari-B field.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
(4)
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.
The 2015 increase in US reserves included an increase of 176 Bcf in the DJ Basin and 81 Bcf from Marcellus Shale development due to positive producing well performance and optimized lateral lengths.
(5)
The 2013 increase is attributable to the acquisition of additional acreage in the Marcellus Shale and other onshore US locations.
The 2015 increase is attributable to reserves acquired in the Rosetta Merger.
(6)
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.
In 2015, we sold non-core onshore US in the DJ Basin.
See Items 1. and 2. Business and Properties - Proved Undeveloped Reserves (PUDs) and Note 3. Merger, Acquisitions and Divestitures.
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 2015 US revisions are primarily associated with negative price revisions of 44 MMBbls to our onshore programs due to a decline in the 12-month average price, offset by a positive revision from our Marcellus Shale program due to positive well performance.
(2)
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.
The 2015 additions include 14 MMBbls due to positive producing well performance and optimized lateral lengths in the DJ Basin .
(3) The 2015 increase is attributable to reserves acquired in the Rosetta Merger.
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 (which we exited in 2015), Cyprus, Nicaragua (which we exited in 2015), Falkland Islands, Suriname, Corporate and other new ventures. See Note 3. Merger, Acquisitions and Divestitures.
(2)
Production costs consist of lease operating expense, production and ad valorem taxes, transportation expense, and general and administrative expense supporting oil and gas operations.
(3)
Income tax expense is based upon respective corporate statutory tax rates. During 2015, 2014 and 2013, we incurred exploration expense in currently non-commercial other international locations; therefore, no tax benefit was included in income tax expense associated with Other International as we could not conclude it was more likely than not that some portion or all of the deferred tax assets would be realized.
(4)
Results of operations exclude the mark-to-market gain or loss on commodity derivative instruments, corporate overhead and interest costs. See Note 8. Derivative Instruments and Hedging Activities.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities (Unaudited) (1)
Costs incurred in connection with crude oil and natural gas acquisition, exploration and development are as follows:
(1)
Costs incurred include capitalized and expensed items.
(2)
Other International includes the North Sea, China (through June 30, 2014), Cameroon, Gabon, Sierra Leone, Cyprus, Nicaragua, Falkland Islands and Suriname. See Note 3. Merger, Acquisitions and Divestitures.
(3)
2015 proved and unproved property acquisitions include amounts allocated from the Rosetta Merger. See Note 3. Merger, Acquisitions and Divestitures.
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.
(4)
2015 exploration costs include drilling and completion of $4 million in the DJ Basin, $22 million in the deepwater Gulf of Mexico, $1 million in Equatorial Guinea and $4 million in Cyprus.
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.
(5)
Worldwide development costs include amounts spent to develop PUDs of approximately $1.5 billion in 2015, $2.0 billion in 2014, and $1.0 billion in 2013.
US development costs include gathering and processing assets acquired in the Rosetta Merger in 2015 and increases in asset retirement obligations of $194 million in 2015, $106 million in 2014, and $214 million in 2013.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
EG development costs include increases (decreases) in asset retirement obligations of $(10) million in 2015, $34 million in 2014, and $9 million in 2013.
Israel development costs include increases in asset retirement obligations of $46 million in 2015, $19 million in 2014, and $14 million in 2013.
Other International development costs include increases in asset retirement obligations of $2 million in 2015, $71 million in 2014, and $9 million in 2013.
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 property cost at December 31, 2015 include previous acquisition costs of $1.2 billion related to the Eagle Ford Shale and Permian Basin properties and $566 million related to the Marcellus Shale.
Unproved oil and gas property cost at December 31, 2014 include previous acquisition costs of $655 million related to the Marcellus Shale.
See Note 3. Merger, Acquisitions and Divestitures.
(2)
Proved oil and gas properties at December 31, 2015 include asset retirement costs of $864 million and exclude assets held for sale of $67 million related to the Karish and Tanin natural gas discoveries offshore Israel.
Proved oil and gas properties at December 31, 2014 include asset retirement costs of $639 million and exclude assets held for sale of $180 million.
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)
In accordance with the Israel Natural Gas Framework, we will be required to reduce our ownership in the Tamar field to 25% within six years. See Items 1. and 2. Business and Properties - Update on Israel - Israel Natural Gas Framework.
(2)
Other International includes China (through June 30, 2014) and the North Sea. See Note 3. Merger, Acquisitions and Divestitures.
(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 9. Asset Retirement Obligations.
(6)
Future income tax expense includes the effect of statutory tax rates and the impact of tax deductions, tax credits and allowances relating to our proved reserves. For 2015, future income tax expense for Israel also includes the effect of estimated future profit levy taxes.
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. Merger, Acquisitions and Divestitures.
The discounted future net cash flows are computed using a 12-month average commodity price applied to our year-end quantities of proved reserves. 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 2015 would reduce the discounted future net cash flows before income taxes by approximately $2.9 billion. We estimate that a $0.50 per Mcf reduction in the average price of natural gas from the 12-month average price for 2015 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 approximately $0.7 billion in 2016, $0.7 billion in 2017 and $0.8 billion in 2018.
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:
(1)
Decrease in 2015 is driven primarily by lower 12-month average commodity prices.
(2)
Purchase of minerals in 2015 is driven by reserves acquired in the Rosetta Merger.
(3)
Increase in 2015 is reflective of lower estimated future income tax expense primarily driven by lower 12-month average commodity prices. For 2015, future income tax expense for Israel includes the effect of estimated future profit levy taxes which partially offset the increase in future net cash flows.
(4)
Decrease in 2015 reflects revisions in our estimated timing of production and development activity.
Supplemental Quarterly Financial Information
(Unaudited)
Supplemental quarterly financial information is as follows:
(1)
First quarter 2015 included the following:
•
$150 million gain on commodity derivative instruments, including the non-cash portion of the loss on commodity derivative instruments of $60 million (See Note 8. Derivative Instruments and Hedging Activities); and
•
$27 million property impairment charges (See Note 5. Asset Impairments).
Second quarter 2015 included the following:
•
$87 million loss on commodity derivative instruments, including the non-cash portion of the loss on commodity derivative instruments of $274 million (See Note 8. Derivative Instruments and Hedging Activities); and
•
$15 million property impairment charges (See Note 5. Asset Impairments).
Third quarter 2015 included the following:
•
$267 million gain on commodity derivative instruments, including the non-cash portion of the loss on commodity derivative instruments of $17 million (See Note 8. Derivative Instruments and Hedging Activities); and
•
$71 million of other operating expenses associated with the Rosetta Merger.
Fourth quarter 2015 included the following:
•
$171 million gain on commodity derivative instruments, including the non-cash portion of the loss on commodity derivative instruments of $157 million (See Note 8. Derivative Instruments and Hedging Activities);
•
$779 million goodwill impairment charge (See Note 4. Goodwill); and
•
$490 million property impairment charges (See Note 5. Asset Impairments).
(2)
First quarter 2014 included the following:
•
$75 million loss on commodity derivative instruments, including non-cash portion of the loss on commodity derivative instruments of $42 million (See Note 8. Derivative Instruments and Hedging Activities);
•
$97 million property impairment charges (See Note 5. Asset Impairments); and
•
$1 million pre-tax loss on sale of non-core assets (See Note 3. Merger, Acquisitions and Divestitures).
Second quarter 2014 included the following:
Supplemental Quarterly Financial Information
(Unaudited)
•
$236 million loss on commodity derivative instruments, including the non-cash portion of the loss on commodity derivative instruments of $187 million (See Note 8. Derivative Instruments and Hedging Activities);
•
$34 million property impairment charges (See Note 5. Asset Impairments); and
•
$42 million pre-tax gain on sale of non-core assets (See Note 3. Merger, Acquisitions and Divestitures).
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 8. Derivative Instruments and Hedging Activities);
•
$33 million property impairment charges (See Note 5. Asset Impairments); and
•
$30 million pre-tax gain on sale of non-core assets (See Note 3. Merger, Acquisitions and Divestitures).
Fourth quarter 2014 included the following:
•
$903 million gain on commodity derivative instruments, including the non-cash portion of gain on commodity derivative instruments of $779 million (See Note 8. Derivative Instruments and Hedging Activities);
•
$2 million pre-tax gain on sale of non-core assets (See Note 3. Merger, Acquisitions and Divestitures); and
•
$336 million property impairment charges (See Note 5. Asset Impairments).
(3)
The sum of the individual quarterly earnings (loss) may not agree with year-to-date earnings as each quarterly computation is based on the earnings for the individual quarter as reported with rounding applied.
(4)
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.
(5)
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, 2015. As noted in the management report called for by Item 308(a) of Regulation S-K and incorporated by reference above, our assessment of, and conclusion on, the effectiveness of internal control over financial reporting did not include the internal controls of the entities acquired in the Rosetta Merger on July 20, 2015. Under guidelines established by the SEC, companies are permitted to exclude acquisitions from their assessment of internal control over financial reporting during the first year of an acquisition while integrating the acquired company. We are in the process of integrating Rosetta's and our internal controls over financial reporting. As a result of these integration activities, certain controls will be evaluated and may be changed. We believe, however, that we will be able to maintain sufficient internal control over financial reporting throughout this integration process. Except as noted above, there were no changes in our internal control over financial reporting during our most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. Based on our assessment, our internal controls over financial reporting were effective.

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 2016 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2015.

ITEM 11 - EXECUTIVE COMPENSATION
Item 11. Executive Compensation
The information required by this item is incorporated herein by reference to the 2016 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2015.

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 2016 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2015.

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 2016 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2015.

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 2016 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2015.
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 17, 2016
By: /s/ David L. Stover
David L. Stover,
Chairman of the Board, President and Chief Executive Officer
Date:
February 17, 2016
By: /s/ Kenneth M. Fisher
Kenneth M. Fisher,
Executive Vice President, Chief Financial Officer
Date:
February 17, 2016
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
Chairman of the Board, President and Chief Executive Officer
February 17, 2016
David L. Stover
(Principal Executive Officer)
/s/ Kenneth M. Fisher
Executive Vice President, Chief Financial Officer
February 17, 2016
Kenneth M. Fisher
(Principal Financial Officer)
/s/ Dustin A. Hatley
Vice President, Chief Accounting Officer and Controller
February 17, 2016
Dustin A. Hatley
(Principal Accounting Officer)
/s/ Jeffrey L. Berenson
Director
February 17, 2016
Jeffrey L. Berenson
/s/ Michael A. Cawley
Director
February 17, 2016
Michael A. Cawley
/s/ Edward F. Cox
Director
February 17, 2016
Edward F. Cox
/s/ James E. Craddock
Director
February 17, 2016
James E. Craddock
/s/ Thomas J. Edelman
Director
February 17, 2016
Thomas J. Edelman
/s/ Eric P. Grubman
Director
February 17, 2016
Eric P. Grubman
/s/ Kirby L. Hedrick
Director
February 17, 2016
Kirby L. Hedrick
/s/ Scott D. Urban
Director
February 17, 2016
Scott D. Urban
/s/ William T. Van Kleef
Director
February 17, 2016
William T. Van Kleef
/s/ Molly K. Williamson
Director
February 17, 2016
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: 13036612.712696075
1-Year Return: 0.06215086206793785
252-Day Return: $252_day_return