SEC Form 10-K Filing Report

Company: NOBLE ENERGY INC
CIK: 72207
SIC Code: 1311
Filing Date: 2017-02-14 00:00:00
Market Capitalization: 16234718.30796051

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ITEM 1. BUSINESS

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

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

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ITEM 2. PROPERTIES

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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. For discussion of material legal proceedings, see Item 8. Financial Statements and Supplementary Data - Note 18. Commitments and Contingencies.

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

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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 24, 2017, our Board of Directors declared a quarterly cash dividend of $0.10 per common share. The dividend will be paid February 21, 2017, to shareholders of record on February 6, 2017. 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 17, 2017, the number of holders of record of our common stock was 570.
Stock Repurchases The following table summarizes repurchases of our common stock occurring in fourth quarter 2016:
(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.
Stock Performance Graph This graph shows our cumulative total shareholder return over the five-year period from December 31, 2011 to December 31, 2016. 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.
Our peer group includes a broad group of onshore US and global exploration and production companies which are further diversified by location and number of resource plays as well as level of integration within the crude oil and natural gas business cycle. Our peer group consists of the following:
Anadarko Petroleum Corp.
Hess Corp.
Apache Corp.
Marathon Oil Corp.
Cabot Oil & Gas Corp.
Murphy Oil Corp.
Chesapeake Energy Corp.
Noble Energy, Inc.
Continental Resources, Inc.
Pioneer Natural Resources Co.
Devon Energy Corp.
Range Resources Corp.
EOG Resources, Inc.
Southwestern Energy Co.
The comparison assumes $100 was invested on December 31, 2011 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. In addition, the peer group investment is weighted based upon the market capitalization of each individual company within the peer group.
Equity Compensation Plan Information The information required by this item is incorporated herein by reference to the 2017 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2016.

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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)
Goodwill was fully impaired at December 31, 2015. See Item 8. Financial Statements and Supplementary Data - Note 1. Summary of Significant Accounting Policies.

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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 Summary;
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Executive Overview;
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Operating Outlook;
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Results of Operations;
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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 SUMMARY
Noble Energy Key Metrics (see links below for further information)
Items 1. and 2. Business and Properties - Sales Volume, Price and Cost Data
Items 1. and 2. Business and Properties - Proved Reserves Disclosures
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Revenues
Item 8. Financial Statements and Supplementary Data - Supplementary Oil and Gas Information (Unaudited)
Liquidity and Capital Resources - Cash Flows
Items 1. and 2. Business and Properties - Domestic and International
Item 8. Financial Statements and Supplementary Data - Consolidated Statements of Cash Flows
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Acquisition, Capital and Other Exploration Expenditures
Items 1. and 2. Business and Properties - Sales Volume, Price and Cost Data
Items 1. and 2. Business and Properties - Proved Reserves Disclosures
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Revenues
Item 8. Financial Statements and Supplementary Data - Supplementary Oil and Gas Information (Unaudited)
EXECUTIVE OVERVIEW
Industry Outlook
Crude Oil The oil and gas industry is cyclical, and global crude oil prices are volatile due to three key drivers: OPEC crude oil supply, non-OPEC crude oil supply and global crude oil demand.
The crude oil price downturn that began in 2014 has entered its third year. During 2014, crude oil became oversupplied as production from non-OPEC producers increased, primarily driven by US production growth from tight formations and the de-bottlenecking of transportation infrastructure, while global crude oil demand growth was muted on sub-par global economic growth. This oversupply, coupled with OPEC’s decision not to reduce production quotas, resulted in crude oil futures prices falling rapidly in late 2014.
During 2015, prices fell to multi-year lows and the lowest levels since the global 2008 financial crisis. Crude oil prices continued to trade in a lower range during most of 2016 as continued oversupply, and uncertainty surrounding potential OPEC quota reductions, prevented a recovery.
In late 2016, OPEC reached an agreement for a limited, six-month production cut, and, in response, global crude oil prices began to rise. However, OPEC's agreement is contingent on the cooperation of non-OPEC countries, including Russia; therefore, the extent to which these plans will be carried out remains uncertain.
The outlook for 2017 crude oil prices will continue to depend on supply and demand dynamics and global geopolitical and security concerns in crude oil-producing nations. Production levels will be a primary determinant for 2017 as the global crude oil market remains substantially oversupplied. However, it appears that demand has begun to recover in some countries indicating that a sustainable, yet slow, price recovery may have begun.
Longer term, we expect supply and demand to continue to re-balance. Recent reductions in industry investment will, over time, reduce production, helping to balance supply and demand in the crude oil market.
Natural Gas The US domestic natural gas market is also oversupplied due to production growth from tight formations. During 2015 and most of 2016, prices remained weak, falling to multi-year lows. In addition, location differentials increased in some regions, resulting in further realized price declines. For a time, domestic production continued to grow, due to drilling efficiency and a backlog of drilled but uncompleted wells in the Marcellus Shale that came online with completion of new pipeline infrastructure, thereby outstripping demand growth.
More recently, however, domestic prices have begun to rebound, primarily in response to slower storage growth, an increase in domestic natural gas consumption, and higher LNG and pipeline exports.
Although the pace of drilling has slowed, it is possible that there may not be more significant improvement in the domestic natural gas supply and demand balance and that oversupply will persist, which could lead to continued price softness in 2017. At a minimum, we expect US natural gas prices to continue to trade in a low range for the near term.
Impact of Current Commodity Prices Although a modest commodity price improvement began in late 2016, our consolidated average realized crude oil price for fiscal year 2016 was 10% lower than for 2015, while our consolidated average natural gas price remained relatively flat as compared with 2015. Over the last two years, lower commodity prices have resulted in a reduction in our capital spending; significantly lower revenues, lower profitability and cash flows; asset and goodwill impairments; and negative (commodity-price driven) reserves revisions. All of these have led to reductions in our stock price in 2015 and 2016. The chart below shows the historical trend in benchmark prices for West Texas Intermediate (WTI) crude oil, Brent crude oil and U.S. Henry Hub natural gas.
Commodity prices continue to be volatile, and the current price improvement trend could stall, or the industry could enter another downturn causing 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.
Because the global economic outlook and commodity price environment are uncertain, we have built a liquidity position to ensure financial flexibility. We have also planned a 2017 capital investment program that will be responsive to positive or negative conditions that may develop and support continued investment in a volatile commodity price environment. See 2017 Capital Investment Program, below.
See Item 1A. Risk Factors - The oil and gas industry is cyclical and an extended period of suppressed commodity prices could have material adverse effects on our operations, our liquidity, and the price of our common stock.
Potential Cost Inflation Third party oilfield service and supply costs are also subject to supply and demand dynamics. When drilling and development activities slow, in response to extended commodity price declines, third party service and supply costs also tend to decline. During 2016, certain costs declined in response to reduced oilfield activities. However, if the trend toward commodity price improvement continues, and the recovery is robust, we expect demand for oilfield services and supplies to grow, and the costs of drilling, equipping and operating our wells and infrastructure could begin to rise.
Pending Acquisition of Clayton Williams Energy, Inc. On January 13, 2017 we executed a definitive agreement to acquire all of the outstanding common stock of Clayton Williams Energy, Inc. for $2.7 billion in cash and Noble Energy stock. See Items 1. and 2. Business and Properties - Pending Acquisition of Clayton Williams Energy, Inc.
Operational Success Despite the negative financial impacts of the low commodity price environment, 2016 was a very successful year operationally and strategically. We directed our focus to the enhancement of onshore US drilling and completions, advancement of Eastern Mediterranean regional natural gas developments, completion of the Gunflint development project in the Gulf of Mexico, start-up of the Alba B3 compression project offshore Equatorial Guinea, initial public offering of our midstream assets, and execution of certain other asset transactions allowing acceleration of asset development.
Just as importantly, we continued to achieve material reductions in capital and controllable unit costs, supporting project returns and margin improvements, and delivered year-over-year volume growth of approximately 19% (or year-over-year organic volume growth of approximately 8% excluding the addition of the Rosetta assets) resulting in record total consolidated sales volumes of 413 MBoe/d (excluding sales volumes from equity investees).
Recent Achievements Our current strategy has enhanced our future outlook and includes:
Portfolio Enhancements, Including:
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integration of Rosetta Resources Inc., which expanded our portfolio with entry into two top-tier US Basins, the Eagle Ford Shale and Permian Basin;
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additional Permian Basin bolt-on acquisitions;
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improvement in the DJ Basin regulatory and legislative environment;
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exchange of acreage in the DJ Basin which increased our contiguous acreage position; and
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dissolution of the Marcellus Shale joint venture, providing increased flexibility and control over our investment.
Operational Accomplishments, Including:
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project sanction readiness at Leviathan;
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increased production with less capital investment;
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improved returns with technology advancements and structural cost savings; and
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delivery of major offshore projects on budget and on schedule.
Financial Strength, Including:
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proactive and strategic action to manage within cash flows;
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strong liquidity position including cash on hand and unused borrowing capacity;
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portfolio management and midstream strategy, which increase our future financial capacity;
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reduction of our outstanding debt through cash on hand; and
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maintenance of our investment grade credit rating.
In summary, during 2016 we maintained our operational momentum, investment flexibility, and strong financial liquidity which we expect to carry over to 2017.
2016 Successes More specifically, our 2016 successes included the following:
Onshore US Growth Onshore, we continued our excellent safety performance while increasing our development activity in the DJ Basin, Eagle Ford Shale and Permian Basin. We expanded our Permian Basin position with an acreage acquisition and further enhanced our Colorado Wells Ranch position through an acreage exchange.
In October, we entered into a definitive agreement to separate our Marcellus Shale 50-50 Joint Venture, providing for greater control and flexibility over our future pace of development.
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 approximately 19% resulting in record total consolidated average sales volumes of 413 MBoe/d.
Capital Cost Reductions While delivering higher production volumes, we realized significant reductions in capital expenditures, over 45% from 2015, excluding the impact of the Rosetta Merger.
Lease Operating and G&A Expense Reductions We continued to realize significant reductions in unit costs for lease operating and general and administrative (G&A) expenses, 19% and 15%, respectively, on a BOE basis from 2015.
Major Project Successes Offshore, our major project execution capabilities enabled start up at our new Gunflint project in the Gulf of Mexico in July. Offshore Israel, the establishment of the Natural Gas Framework by the Government of Israel and execution of additional long-term natural gas sales agreements positioned us for sanction of our next major offshore development project, Leviathan. And offshore Equatorial Guinea, the Alba B3 compression platform was successfully installed, on schedule and within budget, and commenced production, extending the resource recovery life and slowing the natural decline of the Alba field. Our operated projects in the Eastern Mediterranean and West Africa continue to provide a source of reliable production and cash flows.
Liquidity Enhancements While accelerating our onshore US program, we ensured liquidity and enhanced our financial flexibility by generating over $1.5 billion of proceeds from property divestments and the initial public offering of Noble Midstream Partners common units. We used new Term Loan Facility proceeds to repurchase higher cost public debt, and, more recently were able to repay $850 million of the Term Loan Facility borrowings.
2016 Financial Results Our financial results included:
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crude oil, natural gas and NGL revenues of $3.4 billion, as compared with $3.1 billion for 2015;
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net loss attributable to Noble Energy of $998 million, as compared with net loss of $2.4 billion for 2015;
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net loss on commodity derivative instruments of $139 million (including $708 million non-cash loss), as compared with $501 million net gain (including $508 million non-cash loss) for 2015;
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dry hole expense of $579 million, as compared with $266 million for 2015;
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undeveloped leasehold impairment expense of $93 million, as compared with $21 million for 2015;
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reduced lease operating expense of $3.59 per BOE, as compared with $4.43 per BOE for 2015, a reduction of 19%;
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reduced general and administrative expense of $2.64 per BOE, as compared with $3.11 per BOE for 2015, a reduction of 15%;
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asset impairment expense of $92 million, as compared with $533 million for 2015;
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diluted loss per share attributable to Noble Energy of $2.32, as compared with diluted loss per share of $6.07 for 2015;
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cash flows provided by operating activities of $1.4 billion, as compared with $2.1 billion in 2015; and
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capital expenditures of $1.6 billion, as compared with $2.9 billion, excluding the Rosetta Merger, in 2015.
Significant Events Impacting Liquidity Included:
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net cash proceeds of $299 million received from issuance of Noble Midstream Partners common units, net of offering costs;
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proceeds of $1.2 billion from asset sales; and
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prepayment of $850 million of borrowings under our Term Loan Facility.
Year-end Financial Metrics Included:
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cash balance of $1.2 billion, as compared with $1.0 billion at December 31, 2015;
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total liquidity of $5.2 billion, as compared with $5.0 billion at December 31, 2015; and
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ratio of debt-to-book capital of 43%, as compared with 43% at December 31, 2015.
See Results of Operations and Liquidity and Capital Resources, below.
Sales Volumes On a BOE basis, total consolidated sales volumes were 19% higher for 2016 as compared with 2015, and our mix of sales volumes was 43% global liquids, 36% US natural gas and 21% international natural gas. See Results of Operations - Revenues, below.
Cost Reduction Efforts During 2016, we continued to focus on maintaining our strong safety culture, driving operational efficiencies and reducing our cost structure. Continued cost reduction initiatives, including both operational enhancements and new pricing arrangements with suppliers, enabled us to reduce unit costs in lease operating expense and general and administrative expense as compared with 2015. Our global portfolio provides significant optionality, allowing us to adjust spending in response to the commodity price environment. Capital spending reductions, coupled with cost reduction activities, have aligned overall cash expenditures more closely with operating cash flows in the lower commodity price environment. Over the last two years, we also implemented organizational changes including a workforce reduction.
Acquisitions and Divestitures During 2016, we engaged in various acquisition and divestiture activity. See Item 8. Financial Statements and Supplementary Data - Note 3. Acquisitions, Divestitures and Merger.
OPERATING OUTLOOK
Positioned for the Future We believe the following factors will contribute to the sustainability of our business throughout the commodity price cycle, including extended periods of lower prices:
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we have a high-quality, globally diversified portfolio of assets, focused on top-tier basins, and the majority of our assets are held by production, which provides investment optionality and flexibility;
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we have exploration expertise which has led to numerous discoveries, in the deepwater Gulf of Mexico, Levant Basin offshore Eastern Mediterranean and the Douala Basin offshore West Africa, resulting in major development project opportunities;
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we have operational and technical expertise which has led to our delivery of major development projects on schedule and within budget providing a competitive and financial advantage in our industry;
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we have achieved substantial cost reductions (and are well-positioned on the global cost supply curve) impacting both operating expenses and capital expenditures;
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we have designed a capital investment program, with flexibility allowing us to respond to changing commodity price conditions in 2017;
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we have adjusted our quarterly dividend to 10 cents per common share; and
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we have robust liquidity of $5.2 billion at December 31, 2016 and ability to access capital markets.
See also Results of Operations and Liquidity and Capital Resources, below.
As we enter 2017, we believe we have positioned the Company for sustainability, operational efficiency, and long-term success throughout the oil and gas business cycle. However, 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 proved reserves, and in response, we may 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 potential developments. See Item 1A. Risk Factors - The oil and gas industry is cyclical and an extended period of suppressed commodity prices could have material adverse effects on our operations, our liquidity, and the price of our common stock.
2017 Production We continue our comprehensive effort to spend within cash flow, manage the Company's balance sheet and position ourselves for future growth. To this end, we have adopted a 2017 capital program closely aligned with expected cash flow. Therefore, our total crude oil, natural gas and NGL production for 2017 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 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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Israeli industrial and residential demand for electricity, which is largely impacted by weather conditions and conversion of Israeli electricity portfolio from coal to natural gas;
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timing of the divestiture of the remaining 7.5% working interest in the Tamar field which will lower our sales volumes;
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potential growth in the Israeli natural gas export market;
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timing of crude oil and condensate liftings impacting sales volumes in West Africa;
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natural field decline in onshore US, deepwater Gulf of Mexico and offshore Equatorial Guinea;
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potential weather-related volume curtailments due to hurricanes in the deepwater Gulf of Mexico and Gulf Coast areas, or winter storms and flooding impacting onshore US operations;
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reliability of support equipment and facilities, pipeline disruptions, and/or potential pipeline and processing facility capacity constraints which may cause restrictions or interruptions in production and/or midstream processing;
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malfunctions and/or mechanical failures at terminals or other onshore US delivery points;
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impact of enhanced completion efforts for onshore US assets;
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potential shut-in of US producing properties if storage capacity becomes unavailable;
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potential drilling and/or completion permit delays due to future regulatory changes; and
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potential purchases of producing properties or divestments of operating assets.
2017 Capital Investment Program Given the current commodity price environment, we have designed a flexible capital investment program as part of our comprehensive effort to spend within cash flows and manage the Company's balance sheet.
Our preliminary 2017 capital investment program will accommodate an investment level of approximately $2.3 to $2.6 billion. Approximately 75% of the total capital program is allocated to US onshore development, primarily focused on liquids-rich opportunities in the DJ Basin, Delaware Basin, and Eagle Ford Shale. Eastern Mediterranean capital expenditures, including initial development costs associated with the Leviathan project, represent over 20% of the total.
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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drilling results;
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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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permitting activity in the deepwater Gulf of Mexico;
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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.
We plan to fund our capital investment program from cash flows from operations, cash on hand, proceeds from divestments of assets, borrowings under our Revolving Credit Facility, and/or other sources of funding. See Liquidity and Capital Resources - Financing Activities, and - Contractual Obligations - Exploration Commitments and Continuous Development Obligations.
Potential for Future Dry Hole Cost, Lease Abandonment Expense or Property Impairments
Exploration Activities As we develop our near-term inventory, we will consider expanding the portfolio to include additional long-term and/or large-scale exploration opportunities. In this regard, we continue to conduct exploration activities in various geographical areas and have capitalized a significant amount of exploratory drilling costs. In the event we conclude that an exploratory well did not encounter hydrocarbons or that a discovery or prospect is not economically or operationally viable, the associated capitalized exploratory well costs would be charged to expense. For example, in 2016, we recorded impairments or dry hole expense totaling $579 million primarily associated with exploration activities in the deepwater Gulf of Mexico, offshore Israel and offshore West Africa.
We are currently evaluating development scenarios and assessing plans to progress appraisal at our Katmai discovery, deepwater Gulf of Mexico. We currently have capitalized costs of approximately $150 million for Katmai.
In addition, we have a potential commitment to drill an exploration well offshore Suriname, pending seismic survey evaluation.
We may also relinquish certain undeveloped leases prior to expiration, based upon geological evaluation or other factors. For example, in 2016, we wrote off $58 million of cost related to deepwater Gulf of Mexico undeveloped leases and $25 million for Falkland Islands licenses.
We have numerous leases for deepwater Gulf of Mexico prospects that have not yet been drilled. A significant portion of these leases are scheduled to expire over the years 2018 to 2020 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 or other factors.
At December 31, 2016, we have capitalized costs related to exploratory wells of $768 million. We also have capitalized undeveloped leasehold cost of approximately $105 million related to deepwater Gulf of Mexico. As a result of our exploration activities, future exploration expense, including undeveloped leasehold amortization and impairment expense, could be significant.
See Item 1A. Risk Factors, Results of Operations - Operating Costs and Expenses - Oil and Gas Exploration Expense, and Item 8. Financial Statements and Supplementary Data - Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
Development Concept Selection Costs
When we discover significant resources, such as our Leviathan and Cyprus discoveries in the Eastern Mediterranean, full field development may require several phases, with various facilities serving both domestic and regional export demand. In order to determine an optimum development concept for these discoveries, we and our partners engage in development planning, also known as pre-FEED and FEED studies. Furthermore, we may progress pre-FEED and FEED studies simultaneously for multiple development concepts, with the realization that only one concept may ultimately be approved or be economically feasible. This simultaneous progression of multiple concepts enables us to advance a final investment decision and quality development of resources in a timely and efficient manner.
Conducting pre-FEED and FEED work to varying degrees for a range of phased development concepts may result in our incurring significant charges, as compared with pre-FEED and FEED costs incurred for previous offshore projects where the resources were not as significant. Other factors that may increase our pre-FEED and FEED costs include location of a field in a remote and/or under-developed area, lack of availability of, or capacity at, third party production platforms or other infrastructure, technical complexity, market availability, and significant time and effort required for government approval. While a development project may not be formally sanctioned, such as our Leviathan discovery, once a final development concept has been determined, we expect to identify certain concepts that must be eliminated from further consideration, and their associated costs written off. In fourth quarter 2016, we selected the initial development concept for the first phase of the Leviathan development project and wrote off $88 million associated with concepts that were not selected. See Items 1. and 2. Business and Properties - International - Eastern Mediterranean (Israel and Cyprus).
Producing Properties
During a significant portion of 2016, commodity prices, including WTI, Brent and HH, continued to trade in a low range, and prices 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, and the market outlook on forward commodity prices. 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 and may require several phases over a multi-year period, such as the current decommissioning activities occurring at the MacCulloch field in the North Sea. 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 asset retirement obligation (ARO) estimates may change, sometimes significantly, and could result in asset impairment. See Items 1. and 2. Business and Properties.
Climate Change Climate change has become the subject of significant global focus. The impact of human activity on the climate remains a complex issue. Numerous governments around the world have concluded that it poses an urgent threat that requires the reduction of greenhouse gas emissions and other governments are responding with similar policies.
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 crude oil and natural gas 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 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. It is not yet clear how the current US Administration and Congress will impact these initiatives.
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 more than 190 countries, including the US, signing a new climate change agreement in Paris in 2015. The Paris Agreement 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 (NDCs) 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 entered into force in November 2016, thirty days after the required ratification by at least 55 countries that produce at least 55% of the world’s GHGs. That same month, at the 22nd Conference of the Parties to the Convention (COP 22), State Parties to the Agreement collaborated on efforts focused on implementation of the Agreement. The previous US Administration's NDC sets an economy-wide target by 2025 of reducing GHG emissions by 26-28% as compared to 2005 levels, and to make best efforts to reach 28%. The US presidential climate action plan discussed above reportedly is expected to account for much, but not all, of the reduction. This may change in the future with the current US Administration.
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 57% of our 2016 total sales volumes. 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.
Further, 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. See also Items 1. and 2. Business and Properties - Regulations and Item 1A. Risk Factors.
RESULTS OF OPERATIONS
Selected financial information is as follows:
See following discussion for explanation of year-to-year changes.
Revenues
Oil, Gas and NGL Sales Agreements 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 fractionation and processing costs.
Historically, we recorded revenue at the net price we received from the purchaser, net of transportation, fractionation or processing costs. Beginning in 2016, we changed our presentation of revenue to no longer include expenses netted from revenue by the purchaser. Crude oil, natural gas and NGL sales are now shown without deductions relating to transportation, fractionation or processing. These deductions are now recorded as production expense. Prior year amounts, including revenues, expenses, average realized sales prices and average production costs per BOE, have been reclassified to conform to the current presentation. For NGL sales, amounts reclassified for 2015 and 2014 totaled $50 million and $14 million, respectively. Amounts reclassified for crude oil and natural gas sales were de minimis.
In addition, commodity prices we receive may be reduced by location basis differentials, which can be significant. For example, transportation bottlenecks and oversupply in the Marcellus Shale have reduced the amount of production reaching higher priced out-of-basin locations. As a result of location basis differentials, our reported sales prices may differ significantly from published commodity price benchmarks for the same period.
Average Oil, Gas and NGL Sales Volumes and Prices 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 is 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 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.
(3)
Volumes represent sales of condensate and LPG from the Alba plant in Equatorial Guinea.
An analysis of revenues from sales of crude oil, natural gas and NGLs is as follows:
Crude Oil and Condensate Sales Revenues Revenues from crude oil and condensate sales remained relatively flat in 2016 as compared with 2015 due to the following:
•
higher sales volumes of 9 MBbl/d in the Eagle Ford Shale and Permian Basin primarily attributable to full year consolidation following the Rosetta Merger;
•
sales volumes from the Big Bend and Dantzler developments (deepwater Gulf of Mexico), which began producing fourth quarter 2015 and contributed 12 MBbl/d, net, collectively in 2016; and
•
start up of the deepwater Gulf of Mexico Gunflint development in July 2016 which contributed 3 MBbl/d;
partially offset by:
•
a 10% 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 into 2016; and
•
decrease in sales volumes due to natural field decline at Aseng and Alen, offshore Equatorial Guinea.
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.
Natural Gas Sales Revenues Revenues from natural gas sales increased by $183 million, or 17%, in 2016 as compared with 2015. Although consolidated average realized prices remained flat, sales volume increases were due to the following:
•
higher sales volumes of 93 MMcf/d in the Marcellus Shale primarily attributable to well completion and infrastructure development;
•
higher sales volumes of 81 MMcf/d in the Eagle Ford Shale and Permian Basin primarily attributable to full year consolidation following the Rosetta Merger;
•
record sales volumes from the Tamar field, offshore Israel, which contributed an incremental 29 MMcf/d, in response to higher power generation needs; and
•
higher sales volumes offshore Equatorial Guinea due to the completion of the Alba B3 compression project.
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 an incremental 21 MMcf/d, in response to higher power generation needs.
NGL Sales Revenues Revenues from NGL sales increased by $99 million, or 50%, in 2016 as compared with 2015 due to the following:
•
higher sales volumes of 14 MBbl/d in the Eagle Ford Shale and Permian Basin primarily attributable to a full year of production as well as increased development activity;
•
a 7% increase in total consolidated average realized prices, primarily due to higher spot prices in the Marcellus Shale; and
•
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;
partially offset by:
•
slightly lower sales volumes in the Marcellus Shale due to the higher dry gas composition of wells that were brought online in 2016.
Revenues from NGL sales decreased by $87 million, or 31%, during 2015 as compared with 2014 due to the following:
•
a 59% 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.
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:
CONE Gathering and CONE Midstream In 2014, our jointly-owned 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 cash to us.
During fourth quarter 2016, CONE Gathering contributed its remaining 25% ownership interest in CONE Midstream DevCo I LP to CONE Midstream for a total valuation of $248 million. Upon closing, we received $70 million in cash and approximately 2.6 million CNNX limited partnership units.
AMPCO and Affiliates Net income from AMPCO and affiliates increased in 2016 as compared with 2015 primarily due to higher methanol sales volumes offset by lower methanol prices.
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.
Alba Plant Net income from Alba Plant remained flat in 2016 as compared to 2015.
Net income from Alba Plant in 2015 decreased as compared to 2014 primarily due to the decrease in the average realized sales prices of condensate and LPG resulting from lower global demand.
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 and include expenses related to Noble Midstream Partners.
(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 2016 as compared with 2015 due to the following:
•
decrease of $92 million onshore US, primarily in the DJ Basin and Marcellus Shale, and $27 million offshore Equatorial Guinea due to cost reduction initiatives, including lower equipment utilization and saltwater disposal costs;
partially offset by:
•
increase of $74 million attributable to new production from onshore US and deepwater Gulf of Mexico development activities; and
•
increase of $38 million related to the acquisition of Eagle Ford Shale and Permian Basin production third quarter 2015.
Lease operating expense decreased in 2015 as compared with 2014 due to the following:
•
decrease of $17 million from sales of non-strategic 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.
Production and Ad Valorem Tax Expense
Production and ad valorem taxes decreased in 2016 as compared with 2015, primarily due to lower revenues and an onshore US severance tax refund, both driven by a decline in US commodity prices.
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.
Transportation Expense
Transportation expense increased in 2016 as compared with 2015 due to:
•
increase of $66 million related to higher production from our Marcellus Shale assets;
•
increase of $57 million related to change in mix of transportation methods used for our DJ Basin production;
•
increase of $49 million related to higher production from our Eagle Ford Shale assets acquired third quarter 2015; and
•
increase of $17 million related to production from our new deepwater Gulf of Mexico projects at Big Bend and Dantzler (which began producing fourth quarter 2015) and Gunflint (which began producing in July 2016).
Transportation expense increased in 2015 as compared with 2014 due to:
•
increase of $81 million in the Marcellus Shale due to higher production and increased expenses due to service contracts with CONE Gathering;
•
increase of $33 million due to recently-acquired Eagle Ford Shale and Permian Basin properties; and
•
increase of $12 million in the DJ Basin due to the May 2015 commencement of Tallgrass pipeline, which transports DJ Basin crude oil;
partially offset by:
•
$8 million decrease due to the sale of non-strategic onshore US, China and North Sea properties in 2014.
Unit Rate Per BOE While total production expense increased as a result of higher production for 2016 as compared with 2015, costs on a per BOE basis declined. The decline on a per unit basis is driven primarily by lower production and ad valorem taxes as a result of the current commodity price environment and lower lease operating expenses as we continue to strive for cost reductions in certain areas, such as equipment utilization and saltwater disposal. The decrease in the unit rate per BOE was partially offset by higher transportation and gathering expenses due to higher-cost production volumes from certain onshore US assets.
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 commodity price environment in addition to cost reduction initiatives in lease operating expense and higher production volumes.
Exploration Expense Components of exploration expense were as follows:
(1)
Eastern Mediterranean includes Israel and Cyprus.
(2)
West Africa includes Equatorial Guinea, Cameroon and Gabon.
(3)
Other International, Corporate includes the Falkland Islands, Suriname and other new ventures and corporate expenditures.
(4)
For a discussion of 2016 dry hole cost, see Items 1. and 2. Business and Properties - International - West Africa and Item 8. Financial Statements and Supplementary Data - Note 6. Capitalized Exploratory Well Costs.
(5)
Includes lease rental and other exploration expense.
Exploration expense for 2016 included:
•
leasehold impairment expense including the write-off of leases and licenses of $58 million for the deepwater Gulf of Mexico, $25 million for the Falkland Islands and $10 million for other onshore US;
•
dry hole cost including costs related to the Silvergate exploratory well, deepwater Gulf of Mexico, the Dolphin 1 natural gas discovery, offshore Israel, and certain discoveries offshore West Africa;
•
seismic expense relating to the acquisition of 3D seismic data in West Africa and other international areas;
•
other cost for onshore US including lease rentals primarily related to Permian Basin leases; and
•
salaries and related expenses for corporate exploration and new ventures personnel.
Oil and gas exploration expense decreased in 2015 as compared with 2014. Expense for 2015 includes the following:
•
leasehold impairment expense including the write-off of our northeast Nevada leases of $21 million;
•
US dry hole cost including 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 including the Cheetah well (offshore Cameroon) and Other International dry hole cost including 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.
Exploration expense included stock-based compensation expense of $10 million in 2016, $13 million in 2015 and $17 million in 2014.
Depreciation, Depletion and Amortization DD&A expense was as follows:
(1)
DD&A expense includes accretion of discount on asset retirement obligations of $48 million in 2016, $43 million in 2015, and $36 million in 2014.
(2)
Consolidated unit rates exclude sales volumes and costs attributable to equity method investees.
Total DD&A expense increased for 2016 as compared with 2015 due to the following:
•
increase of $178 million related to higher sales volumes resulting from commencement of production from the Big Bend, Dantzler and Gunflint development projects in deepwater Gulf of Mexico in 2016 and 2015;
•
increase of $134 million related to the acquisition of Eagle Ford Shale and Permian Basin production third quarter 2015; and
•
$121 million related to the reduction in proved reserves in fourth quarter 2015 primarily due to downward price revisions in DJ Basin and Marcellus Shale;
partially offset by:
•
an overall lower segment rate for offshore Equatorial Guinea due to the fluctuation in production from higher DD&A rate assets Aseng and Alen to lower DD&A rate asset Alba field.
The decrease in the unit rate per BOE for 2016 as compared with 2015 was due primarily to lower-cost production volumes from the Tamar and Alba fields and net book value impairments in fourth quarter 2015 mainly due to downward commodity price revisions. The decrease in the unit rate per BOE was partially offset by increased higher-cost production volumes from certain onshore US properties and recently commenced production from deepwater Gulf of Mexico assets, including Big Bend, Dantzler and Gunflint.
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.
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 2016 was flat as compared with 2015 primarily due to sustained cost savings initiatives and decreases in employee personnel costs. Our total number of employees decreased from 2,395 at December 31, 2015 to 2,274 at December 31, 2016.
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 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 various valuation models. G&A included stock-based compensation expense of $62 million in 2016, $50 million in 2015 and $63 million in 2014. 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 Item 8. Financial Statements and Supplementary Data - Note 1. Summary of Significant Accounting Policies.
Other Operating (Income) Expense, Net Other operating (income) expense, net was as follows:
For additional information regarding items of other operating (income) expense, net, see Item 8. Financial Statements and Supplementary Data - Note 2. Additional Financial Statement Information and Note 4 Noble Midstream Partners LP.
Other (Income) Expense Other (income) expense was as follows:
For additional information regarding items of other (income) expense, see Item 8. Financial Statements and Supplementary Data - Note 2. Additional Financial Statement Information.
Loss (Gain) on Commodity Derivative Instruments (Gain) loss on commodity derivative instruments includes:
•
cash settlements (received) or paid relating to our crude oil and natural gas commodity derivative contracts, and
•
non-cash (increases) or decreases in the fair values of our crude oil and natural gas commodity derivative contracts.
Year Ended December 31, 2016
Cash settlement receipts of $569 million in 2016 included:
•
$499 million contributed by crude oil contracts; and
•
$70 million contributed by natural gas contracts.
Non-cash decreases in fair value of $708 million in 2016 were primarily driven by the commodity price improvement that began in late 2016 and included the following:
•
$582 million related to crude oil contracts; and
•
$126 million related to natural gas contracts.
Year Ended December 31, 2015
Cash settlement receipts of $1.0 billion in 2015 included:
•
$755 million contributed by crude oil contracts entered into by Noble and $89 million contributed by crude oil contracts acquired in the Rosetta Merger; and
•
$120 million contributed by natural gas contracts entered into by Noble, $27 million contributed by natural gas contracts acquired in the Rosetta Merger and $18 million contributed by NGL contracts acquired in the Rosetta Merger.
Non-cash decreases in fair value of $508 million in 2015, were primarily driven by further declines in commodity prices and included the following:
•
$423 million related to crude oil contracts;
•
$65 million related to natural gas contracts; and
•
$20 million related to NGL contracts.
Year Ended December 31, 2014
Cash settlement receipts of $29 million in 2014 included:
•
$34 million contributed by crude oil contracts;
offset by:
•
$5 million paid for natural gas contracts.
Non-cash increases in fair value of $947 million in 2014, were primarily driven by well-positioned commodity price floors amidst the commodity price downturn and included the following:
•
$863 million related to crude oil contracts; and
•
$84 million related to natural gas contracts.
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.
The increase in interest expense in 2016 as compared with 2015 is primarily due to the impact of senior notes assumed by us in the Rosetta Merger during third quarter 2015, a portion of which were subsequently tendered during first quarter 2016 through proceeds derived from our Term Loan Facility.
The decrease in capitalized interest in 2016 as compared with 2015 is primarily due to lower work in progress amounts related to major long-term projects including Big Bend and Dantzler, deepwater Gulf of Mexico, which were completed in fourth quarter 2015, and Gunflint, deepwater Gulf of Mexico, and the Alba B3 compression project, offshore Equatorial Guinea, which were completed in July 2016. Additional items that contributed to the decrease in capitalized interest include the farm-out of a portion of Block 12, offshore Cyprus, during fourth quarter 2015, the write-off of the Humpback dry hole, offshore Falkland Islands, during fourth quarter 2015 and timing of onshore US activities.
The increase in interest expense in 2015 as compared with 2014 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 Revolving Credit Facility for working capital purposes. There were no other significant changes in our debt.
The increase in capitalized interest in 2015 as compared with 2014 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 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 and Undeveloped Leasehold Costs.
Other Non-operating (Income) Expense, Net Other non-operating (income) expense, net includes deferred compensation (income) expense, and other items of (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, 2016, approximately 30% of the market value of the assets in the rabbi trust related to our common stock. Increases in the market value of our common stock held in the trust result in the recognition of deferred compensation expense. Decreases in the market value of our common stock held in the trust result in the recognition of deferred compensation income. We recognized deferred compensation expense of $11 million in 2016 and deferred compensation income of $12 million and $25 million in 2015, and 2014, respectively. See Item 8. Financial Statements and Supplementary Data - Note 12. Stock-Based and Other Compensation Plans.
Income Tax Provision (Benefit) The income tax provision (benefit) was as follows:
See Item 8. Financial Statements and Supplementary Data - Note 11. Income Taxes.
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 commodity price cycle, including the sustained period of low prices. Specifically, we strive to retain the ability to fund long cycle, multi-year, capital intensive development projects throughout a range of scenarios, while also funding a continuing exploration program and maintaining capacity to capitalize on financially attractive periodic mergers and acquisitions opportunities. We endeavor to maintain a strong balance sheet and investment grade debt rating in service of these objectives.
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 Revolving Credit Facility, and proceeds from divestitures of properties. We evaluate potential strategic farm-out arrangements of our working interests for reimbursement of our capital spending. We occasionally access the capital markets and, in 2016, we generated cash of over $1.5 billion through asset sales, a working interest farm-out and the initial public offering of Noble Midstream Partners common units. We may consider repatriations of foreign cash to increase our financial flexibility and fund our capital investment program.
As of December 31, 2016, our outstanding debt (excluding capital lease and other obligations) totaled $6.7 billion. While we have no near-term debt maturities, we may periodically seek to access the capital markets to refinance a portion of our outstanding indebtedness.
Pending Acquisition of Clayton Williams Energy, Inc. We recently executed a definitive agreement to acquire all of the outstanding common stock of Clayton Williams Energy, Inc. for $2.7 billion in Noble Energy stock and cash. We expect to assume $500 million in net debt in the transaction and intend to fund the cash portion of the acquisition through a draw on our Revolving Credit Facility. We also anticipate retiring the outstanding debt of Clayton Williams Energy assumed as part of the transaction at or following the closing. See Item 8. Financial Statements and Supplementary Data - Note 3. Acquisitions, Divestitures, and Merger.
Available Liquidity
Year-end liquidity was as follows:
(1)
Total cash includes cash and cash equivalents of almost $1.2 billion, which includes $57 million cash relating to Noble Midstream Partners, as well as restricted cash of $30 million related to the Permian Basin property acquisition that closed in January 2017.
(2)
Excludes $350 million available to be borrowed under Noble Midstream Services Revolving Credit Facility, which is not available to Noble Energy, as of December 31, 2016. See Revolving Credit Facilities, below.
(3)
Total debt includes capital lease and other obligations and excludes unamortized debt discount/premium, and issuance costs.
(4)
We define our ratio of debt-to-book capital as total debt (which includes long-term debt excluding unamortized discount/premium and issuance costs, the current portion of long-term debt, and short-term borrowings) divided by the sum of total debt plus Noble Energy's share of equity.
Cash and Cash Equivalents We had approximately $1.2 billion in cash and cash equivalents at December 31, 2016, compared with approximately $1.0 billion at December 31, 2015. At December 31, 2016, our cash was primarily denominated in US dollars and invested in money market funds and short-term deposits with major financial institutions. Approximately $435 million of this cash was attributable to foreign subsidiaries. We have recorded a related deferred tax liability on undistributed foreign earnings of $241 million for the future additional US tax liability for the US and foreign tax rate differences, net of estimated foreign tax credits. Our cash on hand at December 31, 2016 also included $57 million relating to Noble Midstream Partners.
Revolving Credit Facilities Noble Energy's Revolving Credit Facility of $4.0 billion committed amount matures in 2020. We expect to use the Revolving Credit Facility to fund our capital investment program and the acquisition of Clayton Williams Energy, Inc., and may periodically borrow amounts for working capital purposes. Noble Midstream Services' Revolving Credit Facility of $350 million committed amount matures in 2021. No amounts were drawn under either of these facilities at December 31, 2016. See Item 8. Financial Statements and Supplementary Data - Note 10. Long-Term Debt.
Term Loan We occasionally access the capital markets to ensure adequate liquidity exists in the form of unutilized capacity under our Revolving Credit Facility or to refinance scheduled debt maturities. In first quarter 2016, we entered into the Term Loan Facility which provides for a three-year term loan facility for a principal amount of $1.4 billion. In connection with the Term Loan Facility, we launched cash tender offers for certain senior notes assumed in the Rosetta Merger. The borrowings under the Term Loan Facility were used solely to fund the tender offers, which resulted in a gain of $80 million. Collectively, the result of these transactions provides for significant future interest expense savings with a shorter term debt maturity.
In fourth quarter 2016, we prepaid $850 million of long-term debt outstanding under the Term Loan Facility from cash on hand. See Item 8. Financial Statements and Supplementary Data - Note 10. Long-Term Debt.
Activities Enhancing Our Liquidity Position
We were able to employ the above strategy successfully in 2016, taking steps to further position us for long-term operational performance and future growth even in a period of lower commodity prices. The following activities have further enhanced our liquidity position:
Asset Divestitures We evaluate potential strategic farm-out arrangements of our working interests for reimbursement of our capital spending and may consider asset sales or other sources of funding. We generated cash proceeds of almost $1.2 billion in 2016, $151 million in 2015 and $321 million in 2014 from asset sales and farm-out arrangements.
Noble Midstream Partners IPO On September 20, 2016, our subsidiary, Noble Midstream Partners, completed its public offering of 14,375,000 common units representing limited partner interests in Noble Midstream Partners. In connection with the offering, Noble Midstream Partners generated net proceeds of $299 million from the issuance of common units. As of December 31, 2016, we owned 1,527,584 of Noble Midstream Partners common units and 15,902,584 of Noble Midstream Partners subordinated units, which together represented a 54.8% limited partner interest.
The Noble Midstream Partners partnership agreement provides for a minimum quarterly distribution to the holders of common units and subordinated units of $0.3750 per unit for each whole quarter, or $1.5000 per unit on an annualized basis, to the extent Noble Midstream Partners has sufficient available cash after the establishment of cash reserves and the payment of certain costs and expenses. On January 26, 2017, the board of directors of Noble Midstream Partners declared a quarterly cash distribution of $0.4333 per common unit, to be paid February 14, 2017, to unitholders of record on February 6, 2017. The distribution is comprised of $0.3925 per unit for fourth quarter 2016 and $0.0411 per unit for the 10-day period following the closing of the offering through September 30, 2016.
We own all of Noble Midstream Partners subordinated units and incentive distribution rights. Upon completion of certain events as outlined in the Noble Midstream Partners partnership agreement, we will be entitled to receive additional distributions associated with these units.
We consolidate Noble Midstream Partners for financial reporting purposes; however, Noble Midstream Partners' sources of liquidity are independent of Noble Energy. See Item 8. Financial Statements and Supplementary Data - Note 1. Summary of Significant Accounting Policies.
CONE Midstream Dropdown Transaction In fourth quarter 2016, our equity investee, CONE Gathering LLC contributed its remaining 25% ownership interest in CONE Midstream DevCo I LP to CONE Midstream Partners LP. Through this transaction, we received $70 million in cash and approximately 2.6 million common units of CONE Midstream Partners LP.
Cash Dividend Repatriations During 2016, almost $1.2 billion was paid from foreign operations on an outstanding note payable, leaving a balance of approximately $710 million that can be repaid without US tax impact. 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 operating results. As of December 31, 2016, approximately $435 million of our $1.2 billion cash and cash equivalents was held by foreign subsidiaries.
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, and further enhances our liquidity.
Equity Offering 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 which had been drawn for short-term purposes in February 2015, and the remainder was used for general corporate purposes, including the funding of our capital investment program.
In accordance with our accounting policy, we netted the intra-quarter Revolving Credit Facility activity to zero for purposes of consolidated statements of cash flows disclosure.
Current Activity - Impact on Liquidity
Due to a significant reduction in capital spending versus 2015, and significant decreases in operating expenses, we were able to substantially fund all our capital expenditures with operating cash flows in 2016. For 2017, we continue our effort to spend within cash flows and manage the Company's balance sheet and have designed a flexible capital investment program which will be responsive to changes in the commodity price environment.
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 volatile commodity price environment, we believe our financial capacity, coupled with our diversified portfolio, provides us with flexibility in our investment decisions including execution of development projects as well as exploration activity in the current commodity price environment. See Operating Outlook - 2017 Capital Investment Program, above.
To support our investment program, we expect that production resulting from our onshore US development programs, combined with new production from the Gunflint development project, as well as increased production at Tamar, and presuming no significant further deterioration of commodity prices, will result in an increase in cash flows which will be available to meet a portion of future capital commitments in 2017 and subsequent years.
We are currently progressing toward sanction of the Leviathan development project offshore Eastern Mediterranean. The magnitude of this discovery presents technical and financial challenges for us due to the large-scale development requirement. The first phase of Leviathan will require a multi-billion dollar investment and 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 2017. 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.
Counterparty Credit Risk We monitor the creditworthiness of our trade creditors, joint venture partners, hedge counterparties, and financial institutions on an ongoing basis. Counterparty credit downgrades or liquidity problems could result in a delay in our receiving proceeds from commodity sales, reimbursement of joint venture costs, and potential delays in our development projects. As operator of the joint ventures, we pay joint venture expenses and make cash calls on our nonoperating partners for their respective shares of joint venture costs. Our projects are capital cost intensive and, in some cases, a nonoperating partner may experience a delay in obtaining financing for its share of the joint venture costs or have liquidity problems resulting in slow payment of joint venture costs.
We are unable to predict sudden changes in a party's creditworthiness or ability to perform. Even if we do accurately predict such sudden changes, our ability to negate these risks may be limited and we could incur significant financial losses.
Credit enhancements have been obtained from some parties in the form of parental guarantees, letters of credit or credit insurance; however, not all of our counterparty credit is protected through guarantees or credit support. In addition, we maintain credit insurance associated with specific purchasers. However, nonperformance by a trade creditor, hedge counterparty or financial institution could result in significant financial losses. See Item 1A. Risk Factors - We are exposed to counterparty credit risk as a result of our receivables, hedging transactions and cash investments.
Cash Flows
Summary cash flow information is as follows:
Operating Activities Net cash provided by operating activities for 2016 decreased as compared with 2015. Decreases in average realized commodity prices and lower settlements of commodity derivative instruments were partially offset by increases in sales volumes. Working capital changes resulted in a $460 million operating cash flow reduction in 2016 as compared with a negative impact of $129 million in 2015 and were due primarily to decreases in capital accruals related to reduced development activity, as well as an increase in accounts receivable related to higher revenues. See Item 8. Financial Statements and Supplementary Data - Consolidated Statements of Cash Flows.
Net cash provided by operating activities for 2015 decreased as compared with 2014. Decreases in average realized commodity prices were partially offset by higher settlements of commodity derivative instruments and increases in sales volumes. Working capital changes resulted in a $129 million operating cash flow reduction in 2015 as compared with a positive impact of $412 million in 2014.
Investing Activities Our investing activities include capital spending on a cash basis for oil and gas properties and investments in unconsolidated subsidiaries accounted for by the equity method. These investing activities may be offset by proceeds from property sales or dispositions, including farm-out arrangements, which may result in reimbursement for capital spending that had occurred in prior periods.
Capital spending for property, plant and equipment totaled $1.5 billion in 2016, or nearly half, as compared with 2015, primarily due to the Rosetta Merger in 2015 and the timing of completion of major project development activities in the Gulf of Mexico. We received approximately $1.2 billion of proceeds from asset divestitures during 2016 as compared with $151 million of proceeds from divestitures during 2015. We invested $8 million in CONE Gathering, and received cash distributions of $70 million, accounted for as investing activity, from CONE Midstream, during 2016.
Capital spending for property, plant and equipment totaled $3.0 billion in 2015, representing a decrease of $1.9 billion as compared with 2014, primarily due to decreased major project development activity in our operational areas. We received $151 million of proceeds from asset divestitures during 2015 as compared with $321 million proceeds from divestitures during 2014, and acquired cash of $61 million in the Rosetta Merger. We also invested $104 million in CONE Gathering in 2015.
Capital spending for property, plant and equipment totaled $4.9 billion in 2014, representing an increase of $924 million as compared with 2013, primarily due to increased major project development activity in our operational areas. We invested $71
million in CONE Gathering, and received cash distributions of $156 million, accounted for as investing activity, from CONE Midstream, during 2014. We also received $321 million proceeds from non-strategic asset divestitures during 2014.
Financing Activities Our financing activities include the issuance or repurchase of our common stock, payment of cash dividends on our common stock, the borrowing of cash and the repayment of borrowings.
In 2016, net cash used in financing activities was $768 million. We used Term Loan proceeds of $1.4 billion to repay $1.4 billion of senior notes. We subsequently repaid $850 million of the Term Loan from cash on hand. We received $299 million net proceeds from the issuance of Noble Midstream Partners common units in a public offering. Funds were also provided by cash proceeds from, and tax benefits related to, the exercise of stock options ($18 million). We used cash to pay dividends on our common stock ($172 million), make principal payments related to capital lease obligations ($53 million), and repurchase shares of our common stock ($4 million).
In 2015, net cash provided by financing activities was $654 million. We received approximately $1.1 billion net proceeds from the issuance of shares of common stock in a public offering. Funds were also provided by cash proceeds from, and tax benefits related to, the exercise of stock options ($7 million). We used cash to pay dividends on our common stock ($291 million), make principal payments related to capital lease obligations ($67 million), and repurchase shares of our common stock ($21 million). Subsequent to the Rosetta Merger, we incurred financing cash outflows to facilitate the exchange of Rosetta's debt ($12 million) as well as repay the balance outstanding under Rosetta's credit facility ($70 million).
In 2014, net cash provided by financing activities was $1.0 billion. We received approximately $1.5 billion net proceeds from the issuance of senior notes. Funds were also provided by cash proceeds from, and tax benefits related to, the exercise of stock options ($67 million). We used cash to repay senior notes due ($200 million), pay dividends on our common stock ($249 million), make principal payments related to capital lease obligations ($55 million), and repurchase shares of our common stock ($16 million).
Acquisition, Capital and Other Exploration Expenditures
Acquisition, Capital and Other Exploration Expenditures Information (on an accrual basis) is as follows:
(1)
Proved property acquisition costs for 2015 relates to proved properties acquired in the Rosetta Merger. See Item 8. Financial Statements and Supplementary Data - Note 3. Acquisitions, Divestitures and Merger.
(2)
2016 unproved property acquisition costs relate to the termination of the Marcellus Shale joint development. Costs in 2015 primarily relate to unproved properties acquired in the Rosetta Merger. See Item 8. Financial Statements and Supplementary Data - Note 3. Acquisitions, Divestitures and Merger. Additionally, unproved property acquisition cost for 2015 includes $49 million in the DJ Basin, $60 million in the Marcellus Shale, and $10 million and $5 million for costs incurred after the Rosetta Merger in the Permian Basin and Eagle Ford Shale, respectively.
Unproved property acquisition cost for 2014 includes $68 million in the DJ Basin, $160 million in the Marcellus Shale and $16 million in the deepwater Gulf of Mexico.
(3)
2016 includes expenditures of Noble Midstream Partners, and 2015 includes midstream assets acquired in the Rosetta Merger. See Item 8. Financial Statements and Supplementary Data - Note 3. Acquisitions, Divestitures and Merger.
(4)
We own a 50% interest in CONE Gathering which is accounted for using the equity method. CONE Gathering constructs, owns and operates gathering lines and facilities related to the Marcellus Shale development.
(5)
Relates to onshore US assets.
Total expenditures decreased during 2016 as compared with 2015, excluding the Rosetta Merger, as we responded to the lower commodity price environment.
Excluding the Rosetta Merger, total expenditures decreased in 2015 as compared with 2014 due to our reduced capital spending program. Given the 2015 commodity price environment and an industry cost structure that had yet to fully reset to lower revenue levels, we designed a substantially reduced capital investment program that was appropriate for the price environment.
Asset Divestitures Asset divestitures generated cash proceeds of approximately $1.2 billion in 2016, $151 million in 2015 and $321 million in 2014.
Risk and Insurance Program
Our business is subject to all of the inherent and unplanned operating risks normally associated with the exploration, production, gathering, processing, transportation and marketing of crude oil, natural gas and NGLs. Such risks include hurricanes, earthquakes, blowouts, well cratering, fire, loss of well control, pipeline disruptions, mishandling of fluids and chemicals and possible underground migration of hydrocarbons and chemicals, any of which could result in damage to, or destruction of, crude oil and natural gas wells or formations or production facilities and other property, environmental pollution, injury to persons, or loss of life. As protection against financial loss resulting from many, but not all of these operating hazards, we maintain insurance coverage, including certain physical damage, business interruption (loss of production income), employer's liability, third party liability and worker's compensation insurance. We maintain insurance at levels that we believe are appropriate and consistent with industry practice and we regularly review our potential risks of loss and the cost and availability of insurance and the company's ability to sustain uninsured losses, and revise our insurance program accordingly. Limits and deductibles were revised for the property and business interruption programs, as well as the excess liability program, in 2016.
We carry some business interruption insurance for loss of production income arising from physical damage to our major facilities. The coverage is subject to customary deductibles, waiting periods and recovery limits. We also maintain credit insurance to mitigate commodity receivables concentration risk.
Availability of insurance coverage, subject to customary deductibles and recovery limits, for certain perils such as war or political risk is often excluded or limited within property policies. In Israel and Equatorial Guinea, we insure against acts of war and terrorism in addition to providing insurance coverage for normal operating hazards facing our business. Additionally, as being part of critical national infrastructure, the Israel offshore and onshore assets are included in a special property coverage afforded under the Israeli government's Property Tax and Compensation Fund Law; however, the amount of financial recovery through the fund is not guaranteed.
In the Gulf of Mexico, we self-insure for windstorm related exposures, unless contractually required to purchase windstorm coverage for third party facilities. Currently, our Gulf of Mexico assets are primarily subsea operations; therefore, our direct windstorm exposure is limited. However, we do have some exposure through the use of third party production platforms and one Noble-owned floating production facility. In addition, the cost of windstorm insurance continues to be very expensive and coverage amounts are limited. As a result, we currently believe it is more cost-effective for us to self-insure, or absorb any physical loss or damage to these assets, including any business interruption attributable to windstorm exposures. We continually assess our offshore insurance needs in response to our changing business requirements.
As is customary with industry practice, crude oil and natural gas well owners generally indemnify drilling rig contractors against certain risks, such as those arising from property and environmental losses, pollution from sources such as oil spills, or contamination resulting from well blowout or fire or other uncontrolled flow of hydrocarbons. Most of our US and international drilling contracts contain such indemnification clauses. In addition, crude oil and natural gas well owners typically assume all costs of well control in the event of an uncontrolled well. We currently carry more than $1.05 billion in insurance protection, depending on our ownership interest, for potential financial losses occurring as a result of events such as the Deepwater Horizon incident of 2010. This protection consists of $850 million of well control, pollution cleanup and consequential damages coverage and more than $200 million of additional pollution cleanup and consequential damages coverage, which also covers third-party personal injury and death.
We have contracts with third-party service providers to perform hydraulic fracturing operations for us. The master service agreements signed by hydraulic fracturing contractors contain indemnification provisions similar to those noted above. Our liability insurance policies do not contain any specific exclusion for liabilities from hydraulic fracturing operations and we believe our policies would cover third party claims related to hydraulic fracturing operations and associated legal expenses in accordance with, and subject to, the terms of such policies. We do not have insurance for gradual pollution nor do we have coverage for penalties or fines that may be assessed by a governmental authority.
We expect the future availability and cost of insurance to be impacted by the various catastrophic events and large losses that insurers have incurred over the past several years. Impacts could include tighter underwriting standards, limitations on scope and amount of coverage, and higher premiums.
We have a risk assessment program that analyzes safety and environmental hazards and establishes procedures, work practices, training programs and equipment requirements, including monitoring and maintenance rules, for continuous improvement. We also use third party consultants to help us identify and quantify our risk exposures at major facilities. We have a robust prevention program and continue to manage our risks and operations such that we believe the likelihood of a significant event is remote. However, if an event occurs that is not covered by insurance, not fully protected by insured limits or our non-
operating partners are not fully insured, it could have a material adverse impact on our financial condition, results of operations and cash flows.
We are a member in Oil Insurance Limited (OIL). OIL is a mutual insurance company which insures property, pollution liability, control of well and other catastrophic risks. See Contractual Obligations below for a discussion of our theoretical withdrawal premium liability.
We maintain membership in Clean Gulf Associates (CGA), a nonprofit association of production and pipeline companies operating in the Gulf of Mexico. See Items 1. and 2. Business and Properties - Oil Spill Response Preparedness.
Financing Activities
Long-Term Debt Our long-term debt totaled $6.7 billion (excluding capital lease and other obligations) at December 31, 2016, with maturities ranging from 2019 to 2097.
Debt Refinancing On January 6, 2016, we announced a series of transactions, consisting of a new term loan (New Term Loan) and cash tender offers for certain outstanding notes, which collectively enhances our financial flexibility and results in future interest expense savings. The New Term Loan is a three-year agreement, due January 6, 2019, with seven lending institutions for a principal amount of up to $1.4 billion. Provisions of the New Term Loan agreement, including pricing and covenants, are consistent with those contained in our existing Revolving Credit Facility. Borrowings under the New Term Loan agreement may be pre-paid in full or in part at any time prior to its maturity without premium.
In connection with the New Term Loan commitments, we simultaneously launched cash tender offers for the following series of our notes: 5.875% Senior Notes due 2024, 5.875% Senior Notes due 2022 and 5.625% Senior Notes due 2021, all of which were originally assumed as part of the Rosetta Merger. The maximum aggregate purchase price (exclusive of accrued interest) of the notes to be purchased, plus fees, was limited to $1.4 billion and funded by borrowings under the New Term Loan. As a result, we recognized a gain of $80 million which is reflected in other operating (income) expense, net in our consolidated statements of operations.
In fourth quarter 2016, we prepaid $850 million of borrowings under the Term Loan Facility from cash on hand.
See Item 8. Financial Statements and Supplementary Data - Note 10. Long-Term Debt.
Credit Facilities Our principal source of liquidity is our Revolving Credit Facility that matures August 27, 2020. During 2015, we entered into the Second Amendment to Credit Agreement (Second Amendment) which, among other things, extended the maturity date of the Revolving Credit Facility from October 3, 2018 to August 27, 2020.
Our Revolving Credit Facility is available for general corporate purposes and has a commitment of $4.0 billion through the maturity date. 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.
At December 31, 2016, there were no amounts outstanding under the Revolving Credit Facility, leaving the entire $4.0 billion available for use. We may rely on our Revolving Credit Facility to help fund our capital investment program and may periodically borrow amounts for working capital purposes. See Item 8. Financial Statements and Supplementary Data - Note 10. Long-Term Debt.
Noble Midstream Partners IPO On September 20, 2016, Noble Midstream Partners, one of our subsidiaries, completed its public offering of 14,375,000 common units representing limited partner interests in Noble Midstream Partners. In connection with the offering, Noble Midstream Partners generated net proceeds of $299 million from the issuance of common units. See Item 8. Financial Statements and Supplementary Data - Note 4. Noble Midstream Partners LP.
Public Debt Offerings We occasionally enter into public debt offerings to increase our liquidity. On November 7, 2014, we completed 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. Net proceeds were used to repay outstanding indebtedness under our Revolving Credit Facility and for general corporate purposes.
Capital Lease and Other Obligations We occasionally enter into lease agreements for operating assets or corporate buildings that are accounted for as capital leases. Capital leases are included in debt in our consolidated balance sheets. See Item 8. Financial Statements and Supplementary Data - Note 10. Long-Term Debt.
Fixed-Rate Debt Our outstanding fixed-rate debt (excluding capital lease and other obligations) totaled $6.1 billion at December 31, 2016. The weighted average interest rate on fixed-rate debt was 5.69%, with maturities ranging from 2019 to 2097. See Item 8. Financial Statements and Supplementary Data - Note 10. Long-Term Debt.
Ratio of Debt-to-Book Capital Our ratio of debt-to-book capital remained flat at 43% year to year. Significant changes in our financial position impacting the ratio included the following:
•
$1.0 billion net decrease in debt;
offset by:
•
$172 million decrease in shareholders' equity from dividends paid; and
•
$1.0 billion decrease in shareholders' equity from current year net loss.
Cash Interest Payments We made cash interest payments related to our outstanding debt of $412 million in 2016, $404 million in 2015, and $305 million in 2014.
Exercise of Stock Options Proceeds from the exercise of stock options totaled $24 million in 2016, $8 million in 2015 and $48 million in 2014. Proceeds received from the exercise of stock options fluctuate primarily based on the number of options exercised which is influenced by the price at which our common stock trades on the NYSE in relation to the exercise price of the options issued.
Dividends We paid cash dividends totaling 40 cents per common share in 2016, 68 cents per common share in 2015 and 55 cents per common share in 2014.
On January 24, 2017, our Board of Directors declared a quarterly cash dividend of 10 cents per common share payable on February 21, 2017, to the shareholders of record at the close of business on February 6, 2017.
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.
Common Stock Repurchases We receive shares of our common stock from employees for the payment of withholding taxes due on the vesting of restricted shares issued under stock-based compensation plans. We received approximately 237,000 shares with a total value of $8 million in 2016, 491,000 shares with a total value of $21 million in 2015, and 255,000 shares with a total value of $16 million in 2014.
Off-Balance Sheet Arrangements
We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2016, the material off-balance sheet arrangements and transactions that we have entered into included drilling rig contracts, operating lease agreements, and undrawn letters of credit, all of which are customary in the oil and gas industry.
Termination of Marcellus Shale Joint Development Agreement In late 2016, we and CONSOL agreed to terminate our Joint Development Agreement and extinguish the carried cost obligation. See Items 1. and 2. Business and Properties - Marcellus Shale.
Other Other than the off-balance sheet arrangements listed above, we have no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our financial condition, results of operations, liquidity or availability of or requirements for capital resources. See also Contractual Obligations below.
Contractual Obligations
The following table summarizes certain contractual obligations as of December 31, 2016 that are reflected in the consolidated balance sheets and/or disclosed in the accompanying notes. Unless otherwise noted, the table excludes amounts related to Noble Midstream Partners, and all amounts shown are net to our interest.
(1)
Long-term debt excludes our capital lease and other obligations. See Item 8. Financial Statements and Supplementary Data - Note 10. Long-Term Debt.
(2)
Interest payments are based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2016. See Item 8. Financial Statements and Supplementary Data - Note 10. Long-Term Debt.
(3)
Annual capital lease payments, net to our interest, exclude regular maintenance and operational costs. See Item 8. Financial Statements and Supplementary Data - Note 10. Long-Term Debt.
(4)
Drilling and equipment obligations represent our working interest share of contractual agreements with third-party service providers to procure drilling rigs, such as the Atwood Advantage drill ship, and other related equipment for exploratory and development drilling activities. See Counterparty Credit Risk, above, and Item 8. Financial Statements and Supplementary Data - Note 18. Commitments and Contingencies.
(5)
Purchase obligations represent our working interest share of contractual agreements to purchase goods or services that are enforceable, are legally binding and specify all significant terms, including fixed and minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction. See Counterparty Credit Risk, above, and Item 8. Financial Statements and Supplementary Data - Note 18. Commitments and Contingencies.
(6)
Transportation and gathering obligations represent minimum charges for firm transportation and gathering agreements related to our production. See Items 1. and 2. Business and Properties - Delivery Commitments. See Item 8. Financial Statements and Supplementary Data - Note 18. Commitments and Contingencies.
(7)
Operating lease obligations represent non-cancelable leases for office buildings and facilities and oil and gas operations equipment used in our daily operations. Amounts have not been discounted. See Item 8. Financial Statements and Supplementary Data - Note 18. Commitments and Contingencies.
(8)
The table excludes deferred compensation liabilities of $218 million as specific payment dates are unknown. See Item 8. Financial Statements and Supplementary Data - Note 12. Stock-Based and Other Compensation Plans.
(9)
Asset retirement obligations are discounted. See Item 8. Financial Statements and Supplementary Data - Note 9. Asset Retirement Obligations.
(10)
Amount represents open commodity derivative instruments that were in a net payable position with the counterparty at December 31, 2016. See Item 8. Financial Statements and Supplementary Data - Note 8. Derivative Instruments and Hedging Activities.
Exploration Commitments The terms of some of our PSCs, licenses or concession agreements may require us to conduct certain exploration activities, including drilling one or more exploratory wells or acquiring seismic data, within specific time periods. These obligations can extend over periods of several years, and failure to conduct such exploration activities within the prescribed periods could lead to loss of leases or exploration rights. Our exploration commitments currently include 3D seismic obligations for certain international locations.
Continuous Development Obligations Although the majority of our assets are held by production, certain of our onshore US assets are held through continuous development obligations. Therefore, we are contractually obligated to fund a level of development activity in these areas and failure to meet these obligations may result in the loss of a lease.
Leviathan Natural Gas Project Timing of the Leviathan project sanction depends on numerous factors, including completion of necessary marketing activities, engineering and construction planning and availability of funds from us and our partners to invest in the project. We have made significant progress on these fronts and are nearing project sanction. Upon sanction of the Leviathan project, we expect to enter into several contractual agreements for the construction of facilities and development of the Leviathan field.
OIL Contingency As of December 31, 2016, we accrued approximately $18 million for an insurance contingency due to our membership in OIL. OIL is a mutual insurance company which insures specific property, pollution liability and other catastrophic risks. As part of our membership, we are contractually committed to pay termination fees should we elect to withdraw from OIL. We do not anticipate withdrawing from OIL; however, the potential termination fee is calculated annually based on OIL’s past losses and the liability reflecting this potential charge has been accrued as of December 31, 2016.
Letters of Credit In the ordinary course of business, we maintain letters of credit with a variety of banks in support of certain performance obligations of our subsidiaries. Outstanding letters of credit totaled approximately $122 million at December 31, 2016.
Ratings Triggers We do not have triggers on any of our corporate debt that would cause an event of default in the case of a downgrade of our credit rating. In addition, there are no existing ratings triggers in any of our commodity hedging agreements that would require the posting of collateral. However, a series of downgrades or other negative rating actions could increase our cost of financing, and may increase our requirements to post collateral as financial assurance of performance under certain other contractual arrangements such as pipeline transportation contracts, crude oil and natural gas sales contracts, work commitments and certain abandonment obligations. A requirement to post collateral could have a negative impact on our liquidity.
Other
Pension Plan In 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 expensed all remaining unamortized prior
service costs and actuarial losses from accumulated other comprehensive loss (AOCL). During 2015, we expensed $88 million related to the pension plan termination.
Income Taxes We made cash payments for income taxes, net of refunds, of $236 million in 2016, $202 million in 2015 and $150 million in 2014.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of the consolidated financial statements requires our management to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the period. When alternatives exist among various accounting methods, the choice of accounting method can have a significant impact on reported amounts. The following is a discussion of the accounting policies, estimates and judgments which management believes are most significant in the application of US GAAP used in the preparation of the consolidated financial statements.
Reserves All of the reserves data in this Form 10-K are estimates. Estimates of our crude oil, natural gas and NGL reserves are prepared by our qualified petroleum engineers in accordance with guidelines established by the SEC. 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. Uncertainties include the projection of future production rates and the expected timing of development expenditures. 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. In addition, economic producibility of reserves is dependent on the commodity prices used in the reserves estimate. Our reserves estimates are based on 12-month average commodity prices, unless contractual arrangements designate the price to be used, in accordance with SEC rules. However, crude oil and natural gas prices are volatile and, as a result, our reserves estimates will change in the future.
Estimates of proved crude oil, natural gas and NGL reserves significantly affect our DD&A expense. For example, if estimates of proved reserves decline, the DD&A rate will increase, resulting in a decrease in net income. A decline in estimates of proved reserves could also cause us to perform an impairment analysis to determine if the carrying amount of crude oil and natural gas properties exceeds fair value and could result in an impairment charge, which would reduce earnings. See Item 8. Financial Statements and Supplementary Data - Supplemental Oil and Gas Information (Unaudited).
Oil and Gas Properties We account for crude oil and natural gas properties under the successful efforts method of accounting. Under the successful efforts method, costs to acquire mineral interests in crude oil and natural gas properties, drill and equip exploratory wells that find commercial quantities of proved reserves, and drill and equip development wells are capitalized. Proved property acquisition costs are amortized to expense by the unit-of-production method on a field-by-field basis based on total proved crude oil, natural gas and NGL reserves as estimated by our qualified petroleum engineers. Costs to drill and equip exploratory wells that find proved reserves and drill and equip development wells are also amortized to expense by the unit-of-production method on a field-by-field basis. These costs, along with support equipment and facilities, are amortized based on proved developed crude oil, natural gas and NGL reserves. 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. Application of the successful efforts method results in the expensing of certain costs, including geological and geophysical costs and delay rentals, during the periods the costs are incurred, and, in the case of dry hole costs, in the period the well is deemed noncommercial.
The alternative method of accounting for crude oil and natural gas properties is the full cost method. Under the full cost method, geological and geophysical costs, exploratory dry holes and delay rentals are capitalized as assets and charged to earnings in future periods as a component of DD&A expense. In addition, under the full cost method, capitalized costs are accumulated in pools on a country-by-country basis. DD&A is computed on a country-by-country basis, and capitalized costs are limited on the same basis through the application of a ceiling test. We believe the successful efforts method is the most appropriate method to use in accounting for our crude oil and natural gas properties because it provides a better representation of our results of operations, especially during periods of active exploration. If we had used the full cost method, our financial position and results of operations could have been significantly different.
Exploratory Well Costs In accordance with the successful efforts method of accounting, the costs associated with drilling an exploratory well may be capitalized temporarily, or “suspended,” pending a determination of whether crude oil or natural gas have been discovered and can be estimated with reasonable certainty to be economically producible. We carry the costs of an exploratory well as an asset if the well has found a sufficient quantity of reserves to justify its completion 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 several years 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 submitting requests for permits and approvals and believe they will be obtained.
Management assesses the status of suspended exploratory well costs on a quarterly basis. These costs may be charged to exploration expense in future periods if we decide not to pursue additional exploratory or development activities.
At December 31, 2016, the balance of property, plant and equipment included $768 million of suspended exploratory well costs, $699 million of which had been capitalized for a period greater than one year. The wells relating to these suspended costs continue to be evaluated by various means including additional seismic work, drilling additional appraisal wells to confirm the size of the hydrocarbon deposit, or evaluating the potential commerciality of the exploratory wells. During 2016, previously capitalized exploratory well costs of $525 million were expensed. See Item 8. Financial Statements and Supplementary Data - Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
Impairment of Proved Oil and Gas Properties and Other Investments We assess proved crude oil and natural gas properties and other investments for possible impairment whenever events or circumstances indicate that the recorded carrying values of the assets may not be recoverable. We recognize an impairment loss as a result of an event that causes us to consider the possibility that impairment may have occurred and when the estimated undiscounted future net cash flows from a property or other investment are less than the carrying value.
If impairment is indicated, the carrying values are written down to fair value, which, in the absence of comparable market data, is estimated using a discounted cash flow method. In our cash flow method, cash flows are discounted using a risk-adjusted rate and compared to the carrying value for determining the amount of the impairment loss to record. Estimated future net cash flows are based on management’s expectations for the future and include estimates of crude oil, natural gas and NGL reserves and future commodity prices, revenues and operating and development costs. Negative revisions in estimates of reserves quantities or expectations of falling commodity prices, rising operating or development costs, or changes in intended use could result in a reduction in undiscounted future net cash flows and could indicate property impairment.
We recorded total pre-tax (non-cash) asset impairment charges of $92 million in 2016, $533 million in 2015 and $500 million in 2014 for proved oil and gas properties and other investments. See Item 8. Financial Statements and Supplementary Data - Note 5. Asset Impairments.
Impairment of Unproved Oil and Gas Properties We also perform assessments of individually significant unproved crude oil and natural gas properties for impairment on a quarterly basis and recognize a loss with a charge to exploration expense 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 values to a significant unproved property (probable and/or possible reserves) as the result of a business combination or other purchase of proved and/or unproved properties, we use a future cash flows analysis to assess the property for impairment. Cash flows used in the impairment analysis are determined based upon management’s estimates of probable and possible reserves, future commodity prices, and future costs to produce the reserves. Probable reserves are defined in SEC Regulation S-X, Rule 4-10(a)(18) as those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are more likely than not (generally having more than 50% probability) to be recovered. Possible reserves are defined in SEC Regulation S-X, Rule 4-10(a)(17) as those additional reserves that are less certain to be recovered than probable reserves.
At December 31, 2016, the net book value of our unproved properties includes significant amounts allocated in previous business combinations or acquisitions, including the Rosetta Merger and Marcellus Shale joint venture. See Supplemental Oil and Gas Disclosures (Unaudited) - Capitalized Costs Related to Oil and Gas Producing Properties.
Negative revisions in estimated reserves quantities, reductions in commodity prices, or increases in estimated costs could cause a reduction in the value of an unproved property and, therefore, could also cause a reduction in the carrying amount of the property. If undiscounted future net cash flows are less than the carrying value of the property, indicating impairment, the cash flows are discounted using a risk-adjusted rate and compared to the carrying value for determining the amount of the impairment loss to record. The estimated prices used in the cash flow analysis are determined by management based on forward commodity price curves as of the date of the estimate, adjusted for average historical location and quality differentials. Estimates of cash flows related to probable and possible reserves are reduced by additional risk-weighting factors.
Due to the volatility of crude oil, natural gas and NGL prices, these cash flow estimates are inherently imprecise. Management’s assessment of the results of exploration activities, availability of funds for future activities and the current and projected political and regulatory climate in areas in which we operate also impact the amounts and timing of impairment provisions.
Purchase Price Allocations We occasionally acquire assets and assume liabilities in transactions accounted for as business combinations, such as the Rosetta Merger in 2015. In connection with a purchase business combination, the acquiring company must allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Deferred taxes must be recorded for any differences between the assigned values and tax bases of assets and liabilities. Any excess of the purchase price over amounts assigned to assets and liabilities is recorded as goodwill. The amount of goodwill or
gain on bargain purchase recorded in any particular business combination can vary significantly depending upon the values attributed to assets acquired and liabilities assumed.
In estimating the fair values of assets acquired and liabilities assumed in a business combination, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved and unproved crude oil and natural gas properties. In most cases, sufficient market data is not available regarding the fair values of proved and unproved properties and we must prepare estimates. To estimate the fair values of these properties, we prepare estimates 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 estimated proved reserves, the future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved reserves, the discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors.
Estimated deferred taxes are based on available information concerning the tax bases of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.
Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future. A higher fair value assigned to a property results in higher DD&A expense, which results in lower net earnings. Fair values are based on estimates of future commodity prices, reserves quantities, operating expenses and development costs. This increases the likelihood of impairment if future commodity prices or reserves quantities are lower than those originally used to determine fair value, or if future operating expenses or development costs are higher than those originally used to determine fair value. Impairment would have no effect on cash flows, but would result in a decrease in net income for the period in which the impairment is recorded. See Item 8. Financial Statements and Supplementary Data - Note 3. Acquisitions, Divestitures and Merger.
Derivative Instruments and Hedging Activities
We may enter into crude oil and natural gas price hedging arrangements in an effort to mitigate the effects of commodity price volatility and enhance the predictability of cash flows relating to the marketing of a portion of our crude oil and natural gas production. Management exercises significant judgment in determining the types of instruments to be used, production volumes to be hedged, prices at which to hedge and the counterparties’ creditworthiness. All commodity derivative instruments are reflected at fair value in our consolidated balance sheets.
Our open commodity derivative instruments were in a net payable position with a fair value of $116 million at December 31, 2016. In order to determine the fair value at the end of each reporting period, we compute discounted cash flows for the duration of each commodity derivative instrument using the terms of the related contract. Inputs consist of published forward commodity price curves as of the date of the estimate. We compare these prices to the price parameters contained in our hedge contracts to determine estimated future cash inflows or outflows. We then discount the cash inflows or outflows using a combination of published LIBOR rates, Eurodollar futures rates and interest swap rates. The fair values of our commodity derivative assets and liabilities include a measure of credit risk based on current published credit default swap rates. In addition, for collars, we estimate the option value of the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract parameters.
Changes in the fair values of our commodity derivative instruments have a significant impact on our net income (loss) because we apply mark-to-market accounting and recognize all gains and losses on such instruments in earnings in the period in which they occur. For the year ended December 31, 2016, we reported net loss on commodity derivative instruments of $139 million.
We compare our estimates of the fair values of our commodity derivative instruments with those provided by our counterparties. There have been no significant differences. See

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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 commodity price volatility, we may use derivative instruments as a means of managing our exposure to price changes.
At December 31, 2016, we had various open commodity derivative instruments related to global crude oil and domestic natural gas. Changes in fair value of commodity derivative instruments are reported in earnings in the period in which they occur. Our open commodity derivative instruments were in a net liability position at December 31, 2016 with a fair value of $116 million. Based on the December 31, 2016 published commodity futures price curves for the underlying commodities, a hypothetical price increase of 10% per Bbl for crude oil would increase the fair value of our net commodity derivative liability by approximately $83 million. A hypothetical price increase of 10% per MMBtu for natural gas would increase the fair value of our net commodity derivative liability by approximately $40 million. Our derivative instruments are executed under master agreements which allow us to net settle by counterparty. Net settlements take into account deferred premiums we have agreed to pay for put options. In addition, in the event of default, these master agreements allow us 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. None of our counterparty agreements contain margin requirements.
Even with certain hedging arrangements in place to mitigate the effect of commodity price volatility, our 2017 revenues 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.
While we use commodity derivative instruments to mitigate our exposure to commodity price risk, thereby mitigating our exposure to price declines, these instruments may also limit our potential cash flows in periods of rising commodity prices or even place us in a liability position respective to our counterparties. For example, should commodity prices increase, certain of our swaptions are likely to be extended by our counterparties which could require us to pay monthly cash settlements if market prices exceed the contracted swap prices.
See Item 1A. Risk Factors - Commodity hedging transactions may limit our potential gains or fail to protect us from declines in commodity prices, Critical Accounting Policies and Estimates - Derivative Instruments and Hedging Activities and

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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, 2016, 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, 2016, based on those criteria.
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, 2016 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, 2016 and 2015, 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, 2016. 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, 2016 and 2015, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2016, 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, 2016, 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 14, 2017 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ KPMG LLP
Houston, Texas
February 14, 2017
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, 2016, 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, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Noble Energy, Inc. and subsidiaries as of December 31, 2016 and 2015, 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, 2016, and our report dated February 14, 2017 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
Houston, Texas
February 14, 2017
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)
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 crude oil and natural gas exploration and production. Our operating areas are onshore US (DJ Basin, Eagle Ford Shale, Permian Basin, and Marcellus Shale), deepwater Gulf of Mexico, offshore Eastern Mediterranean and offshore West Africa.
Basis of Presentation and Consolidation Accounting policies used by us and our subsidiaries conform to US GAAP. Significant policies are discussed below. Our consolidated accounts include our accounts and the accounts of our wholly-owned subsidiaries. All significant intercompany balances and transactions have been eliminated upon consolidation.
Equity Method of Accounting We use the equity method of accounting for investments in entities that we do not control but over which we exert significant influence. Our equity investees own and operate various midstream assets which we consider an essential component of our business and a necessary and integral element to our value chain involving the monetization of natural gas in our Marcellus Shale and West Africa operating areas. With our partners, we engage in joint strategic operational and financial decision making for these entities.
In order to reflect the economics associated with our integrated upstream value chain described above, we include income from equity method investees as a component of revenue in our consolidated statements of operations.
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.
Noncontrolling Interests In third quarter 2016, Noble Midstream Partners LP (Noble Midstream Partners), a subsidiary of Noble Energy, completed its initial public offering of common units. As a result, we present our consolidated financial statements with a noncontrolling interest section representing the public's ownership in Noble Midstream Partners. See Note 4. Noble Midstream Partners LP.
Consolidated VIE Noble Energy has determined that the partners with equity at risk in Noble Midstream Partners lack the authority, through voting rights or similar rights, to direct the activities that most significantly impact Noble Midstream Partners' economic performance; therefore, Noble Midstream Partners is considered a VIE. Through Noble Energy's ownership interest in Noble Midstream GP LLC (the General Partner to Noble Midstream Partners), Noble Energy has the authority to direct the activities that most significantly affect economic performance and the obligation to absorb losses or the right to receive benefits that could be potentially significant to Noble Midstream Partners. Therefore, Noble Energy is considered the primary beneficiary and consolidates Noble Midstream Partners.
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 2015 and 2014 consolidated financial statements to conform to the 2016 presentation. These reclassifications were not material to the financial statements.
Noble Energy, Inc.
Notes to Consolidated 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 cost or net realizable value. 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.
Property Impairment For our proved properties, we routinely assess whether impairment indicators arise during any given quarter and have processes in place to ensure that we become aware of such indicators. Impairment indicators include, but are not limited to, sustained decreases in commodity prices, negative revisions of proved reserves, and increases in development or operating costs. In the event that impairment indicators exist, we conduct an impairment test. To that end, we estimate future net cash flows expected in connection with the property and compare such future net cash flows to the carrying amount of the property to determine if the carrying amount is recoverable.
When the carrying amount of a property exceeds its estimated undiscounted future net 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.
Other long-lived assets, such as our midstream assets, are evaluated for potential impairment whenever events or changes in circumstances indicate that their carrying value may be greater than the undiscounted future net cash flows. Impairment, if any, is measured as the excess of an asset’s carrying amount over its estimated fair value, which is estimated as described above.
We recorded property impairment charges in 2016, 2015 and 2014 and it is possible 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
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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 over an average holding period.
We recorded an unproved property impairment charge in 2016. It is possible that unproved oil and gas properties could become impaired in the future if commodity prices decline. See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
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.
Assets Held for Sale We occasionally market for sale 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 and 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. See Note 3. Acquisitions, Divestitures and Merger.
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 and Undeveloped Leasehold 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. Other property also includes linefill which is recorded at cost to produce into the production line. Linefill is not subject to depreciation but is reviewed for impairment.
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 (Revolving 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 $84 million in 2016, $144 million in 2015, and $116 million in 2014.
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
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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). 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.
Our goodwill related 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 was 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.
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 was zero and, as such, goodwill was fully impaired.
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 Restricted stock and stock options issued to employees and directors are recorded at grant-date fair value. Expense is recognized on a straight-line basis over the employee’s and director’s requisite service period (generally the vesting period of the award) in the consolidated statements of operations. In 2016, we issued cash-settled awards to certain employees in lieu of a portion of restricted stock and stock options. We recognize the value of our cash-settled awards utilizing the liability method as defined under Accounting Standards Codification Topic 718, Compensation - Stock Compensation. The fair value of liability awards is remeasured at each reporting date, based on the fair market value of a share of common stock of the Company as of the reporting date, through the settlement date with the change in fair value recognized as compensation expense over that period. 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 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, 2016 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.
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
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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.
Historically, we had certain immaterial domestic natural gas sales agreements for which we previously used the entitlement method to account for imbalances. In 2016, we divested assets which were subject to this accounting and therefore, we no longer have contracts that are accounted for under the entitlement method.
Basic and Diluted Earnings (Loss) Per Share Attributable to Noble Energy 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.
Contingencies We are subject to legal proceedings, claims and liabilities that arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are considered probable and the amounts can be reasonably estimated. See Note 18. Commitments and Contingencies.
We self-insure the medical and dental coverage provided to certain employees, and the deductibles for workers’ compensation, automobile liability and general liability coverage. Liabilities are accrued for self-insured claims, or when estimated losses exceed coverage limits, and when sufficient information is available to reasonably estimate the amount of the loss.
Foreign Currency The US dollar is considered the functional currency for each of our international operations. Transactions that are completed in foreign currencies are remeasured into US dollars and recorded in the financial statements at prevailing foreign exchange rates. Transaction gains or losses are included in other non-operating (income) expense, net in the consolidated statements of operations.
Segment Information Accounting policies for geographical segments are the same as those described above. Transfers between segments are accounted for at market value. We do not consider interest income and expense or income tax benefit or expense in our evaluation of the performance of geographical segments. See Note 15. Segment Information.
Changes in Shareholders’ Equity On April 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
Consolidation - Interests Held through Related Parties That Are under Common Control In October 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2016-17 (ASU 2016-17): Consolidation - Interests Held through Related Parties That Are under Common Control. The update changes the process through which a reporting entity determines whether it is the primary beneficiary of a variable interest entity (VIE). As a result, the single decision maker of a VIE uses economic exposure to determine its classification as the primary beneficiary as opposed to evaluating which party is most closely associated with the VIE. In February 2015, the FASB issued ASU 2015-02, which changed 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. During third quarter 2016, Noble Midstream Partners closed on its initial public offering of common units. Under the provisions of both Accounting Standards Updates, Noble Midstream Partners is considered a VIE, and Noble Energy is considered the primary beneficiary of that VIE. We have adopted these provisions, which did not have a material effect on our consolidated financial statements or related disclosures.
Leases In February 2016, the FASB issued Accounting Standards Update No. 2016-02 (ASU 2016-02): Leases. The guidance requires lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by leases with terms of more than 12 months. This ASU also requires disclosures designed to give financial statement users information on the
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amount, timing, and uncertainty of cash flows arising from leases. The standard will be effective for annual and interim periods beginning after December 15, 2018, with earlier application permitted. In the normal course of business, we enter into capital and operating lease agreements to support our exploration and development operations and lease assets such as drilling rigs, platforms, storage facilities, field services and well equipment, pipeline capacity, office space and other assets. We believe the adoption and implementation of this ASU will likely have a material impact on our balance sheet resulting from an increase in both assets and liabilities relating to our leasing activities. As part of our assessment to date, we have formed an implementation work team, prepared educational and training materials pertinent to this ASU and have begun contract review and documentation.
Compensation - Stock Compensation In March 2016, the FASB issued Accounting Standards Update No. 2016-09 (ASU 2016-09): Compensation - Stock Compensation, to reduce complexity and enhance several aspects of accounting and disclosure for share-based payment transactions, including the accounting for income taxes, award forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The ASU will be effective for annual and interim periods beginning after December 15, 2016, with earlier application permitted. Certain aspects of this guidance will require retrospective application while other aspects are to be applied prospectively. Based upon our evaluation, the adoption of this ASU will not have a material effect on our consolidated financial statements or related disclosures.
Financial Instruments - Credit Losses In June 2016, the FASB issued Accounting Standards Update No. 2016-13 (ASU 2016-13): Financial Instruments - Credit Losses, which replaces the incurred loss impairment methodology in current US GAAP with a methodology that reflects expected credit losses. The update is intended to provide financial statement users with more useful information about expected credit losses. The amended guidance is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. We are currently evaluating the effect, if any, that the guidance will have on our consolidated financial statements and related disclosures.
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 elected to early adopt this ASU as of December 31, 2016 and have applied the new measurement principle to our inventory balance. Adoption of this ASU did not have a material impact on our consolidated financial statements or related disclosures.
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. In summary, revenue recognition would occur upon the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Additionally, ASU 2014-09 requires enhanced financial statement disclosures over revenue recognition as part of the new accounting guidance. The standard will be effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. In March 2016, the FASB released certain implementation guidance through ASU 2016-08 to clarify principal versus agent considerations. Currently, we do not have any contracts that would require a change from the entitlements method, historically used for certain domestic natural gas sales, to the sales method of accounting. We are continuing to evaluate the provisions of this ASU as pertinent to certain sales contracts and in particular as it relates to disclosure requirements.
Investments - Equity Method and Joint Ventures In March 2016, the FASB issued Accounting Standards Update No. 2016-07 (ASU 2016-07): Investments - Equity Method and Joint Ventures, to eliminate retroactive application of equity method accounting when an investment becomes qualified for equity method accounting as a result of an increase in the level of ownership interest or degree of influence. The ASU will be effective for annual and interim periods beginning after December 15, 2016, with earlier application permitted. Based upon our evaluation, the adoption of this ASU will not have a material effect on our consolidated financial statements or related disclosures as all material investments are accounted for under the equity method of accounting.
Statement of Cash Flows - Restricted Cash In November 2016, the FASB issued Accounting Standards Update No. 2016-18 (ASU 2016-18): Statement of Cash Flows - Restricted Cash, which requires amounts generally described as restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the total beginning and ending amounts for the periods shown on the statement of cash flows. This ASU will be effective for annual and interim periods beginning after December 15, 2017, with earlier application permitted. We do not believe adoption of ASU 2016-18 will have a material impact on our statement of cash flows and related disclosures.
Statement of Cash Flows - Classification of Certain Cash Receipts and Cash Payments In August 2016, the FASB issued Accounting Standards Update No. 2016-15 (ASU 2016-15): Statement of Cash Flows - Classification of Certain Cash Receipts
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and Cash Payments, to clarify how certain cash receipts and cash payments should be presented in the statement of cash flows. Specifically, ASU 2016-15 provides additional guidance for certain cash flow items which may impact our presentation and classification within our statement of cash flows, including debt prepayments or debt extinguishment costs and distributions received from equity method investees. ASU 2016-15 will be effective for annual and interim periods beginning after December 15, 2017, with earlier application permitted. We do not believe adoption of ASU 2016-15 will have a material impact on our statement of cash flows and related disclosures as this update pertains to classification of items and is not a change in accounting principle.
Note 2. Additional Financial Statement Information
Additional statements of operations information is as follows:
(1)
Certain of our revenue received from purchasers was historically presented with deductions for transportation, gathering, fractionation or processing costs. Beginning in 2016, we have changed our presentation of revenue to no longer include these expenses as deductions from revenue. These costs are now included within production expense. Prior year amounts of $50 million and $14 million for the years ended December 31, 2015 and 2014, respectively, have been reclassified to transportation and gathering expense to conform to the current presentation.
(2)
See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
(3)
Amounts represent expense for unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments. Prior year amounts of $33 million and $16 million for the years ended December 31, 2015 and 2014, respectively, were previously presented within transportation and gathering expense. These amounts have been reclassified to conform to the current presentation. See Note 18. Commitments and Contingencies.
(4)
Amount relates to the termination of a rig contract offshore Falkland Islands as a result of a supplier's non-performance.
(5)
Includes gain related to the sale of 3.5% working interest in the Tamar field, offshore Israel. See Note 3. Acquisitions, Divestitures and Merger.
(6)
Amount represents expenses associated with organizational activities.
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(7)
Amount relates to the tendering of senior notes assumed in the Rosetta Merger. See Note 10. Long-Term Debt.
(8)
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).
(9)
Amounts represent a purchase price allocation adjustment in 2016 and merger expenses in 2015. See Note 3. Acquisitions, Divestitures and Merger.
(10)
Amounts represent increases (decreases) in the fair values of shares of our common stock held in a rabbi trust and mutual funds.
Additional balance sheet information is as follows:
(1) Proceeds relate to our farm-out of a 35% interest in Block 12 offshore Cyprus and were received in January 2017. See Note 3. Acquisitions, Divestitures and Merger.
(2) Assets held for sale at December 31, 2016 included assets in the Greeley Crescent area of the DJ Basin. Assets held for sale at December 31, 2015 included the Karish and Tanin natural gas discoveries, offshore Israel. See Note 3. Acquisitions, Divestitures and Merger.
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(3) Represents amount held in escrow at December 31, 2016 for the purchase of certain Permian Basin properties. See Note 3. Acquisitions, Divestitures and Merger.
Supplemental statements of cash flow information is as follows:
Note 3. Acquisitions, Divestitures and Merger
Pending Acquisition of Clayton Williams Energy, Inc. On January 13, 2017 we executed a definitive agreement to acquire all of the outstanding common stock of Clayton Williams Energy, Inc. for $2.7 billion in Noble Energy stock and cash.
The transaction has been unanimously approved by the Boards of Directors of both Noble Energy and Clayton Williams Energy and is subject to approval by stockholders of Clayton Williams Energy. If approved, Clayton Williams Energy stockholders will receive 2.7874 shares of Noble Energy common stock and $34.75 in cash for each share of common stock held. In the aggregate, this totals 55 million shares of Noble Energy stock and $665 million in cash. The value of the transaction, based on Noble Energy's closing stock price as of January 13, 2017, is approximately $3.2 billion in the aggregate including the assumption of approximately $500 million in net debt. We intend to fund the cash portion of the acquisition through a draw on our Revolving Credit Facility.
Closing is expected to occur second quarter 2017 and is subject to customary regulatory approvals, approval by the holders of a majority of Clayton Williams Energy common stock, and certain other conditions.
Property Acquisition In fourth quarter 2016, we entered an agreement to purchase Permian Basis properties, including seven producing wells. The acquisition, which has a total transaction price of $295 million, will increase our contiguous acreage position in the Reeves County area. In December 2016, we paid initial consideration of $30 million into an escrow account, which is reflected as a restricted asset in our consolidated balance sheet. We paid the remaining consideration and completed the acquisition in January 2017.
Termination of Marcellus Shale JDA In fourth quarter 2016, we and CONSOL agreed to terminate our 50-50 Joint Development Agreement (JDA) in the Marcellus Shale. In connection with the terminated JDA, we executed and closed an exchange agreement whereby we and CONSOL each transferred all of our interest in a portion of co-owned properties to one another. As a result, we now hold an almost 100% operated working interest in approximately 363,000 acres, primarily located in northwest West Virginia. In addition to the acreage and production realignment between the two companies, we remitted a cash payment of approximately $213 million to CONSOL at closing. Terminating the JDA resulted in the elimination of the remaining outstanding carried cost obligation due from us. No gain or loss was recognized on the exchange. See Supplementary Data - Supplemental Oil and Gas Information (Unaudited), below, for discussion of proved reserves divested in connection with the transaction.
DJ Acreage Exchange We closed a cashless acreage exchange in the DJ Basin receiving approximately 11,700 net acres within our Wells Ranch development area in exchange for approximately 13,500 net acres primarily from our Bronco area. No gain or loss was recognized.
Divestitures We maintain an ongoing portfolio management program. Accordingly, we may periodically divest assets or engage in acreage exchanges.
2016 Asset Sales During 2016, we engaged in the following sales transactions:
•
entered an agreement to divest certain producing and non-producing properties covering approximately 33,100 net acres in the DJ Basin for proceeds of $505 million. We closed the sale on a portion of the properties in 2016, receiving proceeds of $486 million. We expect to close the sale of the remaining properties, which are classified as held for sale at December 31, 2016, and receive the remaining proceeds, subject to post-close adjustments, in mid-2017. Proceeds were applied to reduce field basis with no recognition of gain or loss.
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•
sold additional DJ Basin non-producing properties, certain Eagle Ford properties, our Bowdoin property in northern Montana, and certain other smaller onshore US properties, generating total net proceeds of $152 million, a net loss of $23 million on the Bowdoin sale, and no further gain or loss recognized on the remaining transactions.
•
sold our 47% interest in the Alon A and Alon C licenses, offshore Israel, which included the Karish and Tanin fields, for a total sales price of $73 million ($67 million for asset consideration and $6 million from cost adjustments). Proceeds were applied to reduce field basis with no recognition of gain or loss.
•
sold a 3.5% working interest in the Tamar field, offshore Israel, in compliance with the terms of the Israel Natural Gas Framework, which requires us to reduce our ownership interest in Tamar to 25% by year-end 2021. The sales price totaled $431 million, and we received net cash proceeds of $316 million, after consideration of timing and tax adjustments, at closing. Proceeds were ratably applied to the field's basis and resulted in the recognition of a $261 million gain.
•
received proceeds of $131 million related to a farm-out agreement for a 35% interest in Block 12, offshore Cyprus, which includes the Aphrodite natural gas discovery. We received the remaining proceeds of $40 million in January 2017. Proceeds were applied to reduce field basis with no recognition of gain or loss.
See Supplementary Data - Supplemental Oil and Gas Information (Unaudited), below, for discussion of proved reserves divested in connection with the above transactions.
2015 Asset Sales In 2015, we sold certain non-strategic onshore US properties, receiving proceeds of $151 million, with no gain or loss recorded.
2014 Asset Sales In 2014, we sold certain non-strategic onshore US properties, receiving proceeds of $135 million, and recorded a net gain of $36 million. We also sold our China assets, receiving proceeds of $186 million, and recorded a gain of $35 million.
Aggregated information regarding assets sold is as follows:
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 added 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, 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.
Purchase Price Allocation The merger was accounted for as a business combination, using the acquisition method. The following table represents the final allocation of the total purchase price of Rosetta to the assets acquired and the liabilities assumed based on the fair values at the merger date, with any excess of the purchase price over the estimated fair values of the identifiable net assets acquired recorded as goodwill.
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The following table sets forth our final purchase price allocation:
(1) As of December 31, 2015, our preliminary purchase price allocation reflected goodwill of $163 million based on the fair value of assets acquired and liabilities assumed at the Rosetta Merger date. In conducting our goodwill impairment test as of December 31, 2015, we determined that our goodwill balance was no longer recoverable and fully impaired it, resulting in a goodwill impairment charge in fourth quarter 2015. In second quarter 2016, we finalized the purchase price allocation and recorded a $25 million gain to other operating expense, net driven by adjustments made based on the filing of the final Rosetta federal income tax return for the period ending on the Rosetta Merger date.
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 crude 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 crude 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 crude 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.
The results of operations attributable to Rosetta are included in our consolidated statement of operations beginning on July 21, 2015. Revenues of $457 million and pre-tax net loss of $20 million, exclusive of a $25 million purchase price allocation adjustment, from Rosetta were generated for the year ended December 31, 2016. Revenues of $181 million and pre-tax net loss
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of $120 million, inclusive of a $163 million goodwill impairment, from Rosetta were generated from July 21, 2015 to December 31, 2015.
Pro Forma 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.
(1) No pro forma adjustments were made for the period as Rosetta's operations are included in our consolidated historical results.
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Note 4. Noble Midstream Partners LP
Noble Midstream Partners LP In December 2014, we formed Noble Midstream Partners LP, a growth-oriented Delaware master limited partnership, to own, operate, develop and acquire a wide range of domestic midstream infrastructure assets. Noble Midstream Partners' current areas of focus are in the DJ Basin in Colorado and in the Delaware Basin within the Permian Basin in Texas.
Initial Public Offering of Noble Midstream Partners LP On September 15, 2016, Noble Midstream Partners common units began trading on the New York Stock Exchange under the symbol "NBLX." On September 20, 2016, Noble Midstream Partners completed its public offering of 14,375,000 common units representing limited partner interests in Noble Midstream Partners, which included 1,875,000 common units issued pursuant to the underwriters’ exercise of their option to purchase additional common units, at a price to the public of $22.50 per common unit ($21.21 per common unit, net of underwriting discounts).
In exchange for the contributed assets, Noble Energy received:
•
1,527,584 common units, representing a 4.8% limited partner interest in Noble Midstream Partners;
•
15,902,584 subordinated units, representing an approximate 50.0% limited partner interest in Noble Midstream Partners;
•
incentive distribution rights in Noble Midstream Partners; and
•
the right to receive a cash distribution from Noble Midstream Partners.
In addition and concurrent with the closing of the offering, the General Partner retained a non-economic general partnership interest in Noble Midstream Partners, which is not entitled to receive cash distributions.
Noble Midstream Partners generated net proceeds of $299 million from the issuance of common units to the public, after deducting the underwriting discount, structuring fees and estimated offering expenses of $24 million.
Note 5. Asset Impairments
Pre-tax (non-cash) asset impairment charges were as follows:
2016 Asset Impairments While the Leviathan development project was not formally sanctioned at December 31, 2016, in fourth quarter 2016, we selected the initial development concept for the first phase of development of the Leviathan natural gas project and wrote off $88 million associated with certain development concepts that were not selected.
2015 Asset Impairments During 2015, certain properties in the deepwater Gulf of Mexico, offshore Israel and offshore Equatorial Guinea 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.
We also recorded impairment charges of approximately $47 million primarily related to revisions in expected field abandonment and other costs for properties in the deepwater Gulf of Mexico and offshore Israel and $5 million related to the pending sale of our interest in the Alon A and Alon C licenses, offshore Israel, which included the Karish and Tanin fields.
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.
We also recorded impairment charges of $74 million for the South Raton development, deepwater Gulf of Mexico, due to mechanical issues; $51 million related to asset retirement obligation increases for certain properties in the deepwater Gulf of Mexico and offshore Israel; $31 million related to the reclassification of certain non-strategic properties as assets held for sale; and $94 million related to North Sea MacCulloch field abandonment.
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Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs
Capitalized Exploratory Well Costs We capitalize exploratory well costs until a determination is made that the well has found proved reserves or is deemed noncommercial. If a well is deemed to be noncommercial, the well costs are immediately charged to exploration expense as dry hole cost.
Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed in the same period:
(1) The 2016 amount relates to our farm-down of a 35% interest in Block 12 offshore Cyprus to a new partner.
(2) 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.
(3) Capitalized exploratory well costs charged to expense are included within exploration expense in our consolidated statements of operations.
The 2016 amount relates primarily to discoveries offshore West Africa. Following review of additional 3D seismic data, we determined these discoveries were impaired in the current forward outlook for crude oil prices. We also incurred expenses associated with our Silvergate exploratory well in the deepwater Gulf of Mexico. The well did not encounter commercial hydrocarbons and has been plugged and abandoned.
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-strategic 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, 2016:
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Undeveloped Leasehold Costs Undeveloped leasehold costs as of December 31, 2016 totaled $2.2 billion, including $2.1 billion related to onshore US unproved properties, $105 million related to deepwater Gulf of Mexico unproved properties, and $32 million related to international unproved properties.
We evaluate our exploration opportunities as part of our periodic impairment review. If, based upon a change in exploration plans, availability of capital and suitable rig and drilling equipment, resource potential, comparative economics, changing regulations and/or other factors, an impairment is indicated, we record either (1) impairment expense related to individually significant leases or (2) a decrease in the valuation of our pool of individually insignificant leases.
During 2016, we completed our geological evaluation of certain deepwater Gulf of Mexico and offshore Falkland Islands leases and licenses and determined that several, representing $127 million of undeveloped leasehold cost, should be relinquished or exited. As a result, we recognized $93 million of undeveloped leasehold impairment expense and recorded a $34 million decrease in our valuation pool of individually insignificant leases.
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:
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50% interest in CONE Gathering LLC (CONE Gathering), which owns and operates natural gas gathering facilities servicing our properties in the Marcellus Shale;
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33.5% interest in CONE Midstream Partners, LP (CONE Midstream), a public master limited partnership, which constructs, owns and operates natural gas gathering and other midstream energy assets in support of our Marcellus Shale activities;
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45% interest in Atlantic Methanol Production Company, LLC (AMPCO), which owns and operates a methanol plant and related facilities in Equatorial Guinea; and
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28% interest in Alba Plant LLC (Alba Plant), which owns and operates a liquefied petroleum gas processing plant in Equatorial Guinea.
CONE Midstream Dropdown Transaction In fourth quarter 2016, CONE Midstream, completed its first acquisition of midstream assets (dropdown) from CONE Gathering since its initial public offering in 2014. CONE Gathering subsequently distributed $70 million cash and additional CONE Midstream common units to us. We currently own 7,110,638 common units and 14,581,560 subordinated units of CONE Midstream.
Equity method investments are as follows:
(1)
CONE Investments include CONE Midstream and CONE Gathering.
Other At December 31, 2016, consolidated retained earnings included $95 million related to the undistributed earnings of equity method investees.
The carrying value of our AMPCO investment was $12 million higher than the underlying net assets of the investee at December 31, 2016. The difference is related to capitalized interest which is being amortized into earnings over the remaining useful life of the plant.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Summarized, 100% combined financial information for equity method investees is as follows:
Note 8. Derivative Instruments and Hedging Activities
Objective and Strategies for Using Derivative Instruments We may enter into crude oil and natural gas price hedging arrangements in an effort to mitigate the effects of commodity price volatility and enhance the predictability of cash flows relating to the marketing of a portion of our crude oil and natural gas production. 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, 2016.
While these instruments mitigate the cash flow risk of future reductions in commodity prices, they may also curtail benefits during periods of increasing commodity prices.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
See Note 13. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of our derivative instruments.
Counterparty Credit Risk Derivative instruments expose us to counterparty credit risk. Our commodity derivative instruments are currently with a diversified group of major banks or market participants, and we monitor and manage our level of financial exposure. Our commodity derivative contracts are executed under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net settled at the time of election.
We monitor the creditworthiness of our commodity derivatives counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk.
Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices and could incur a loss.
Unsettled Derivative Instruments As of December 31, 2016, we had entered into the following crude oil derivative instruments:
(1)
We traditionally enter into a hedge contract term of one year. For 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)
We have entered into certain derivative contracts (swaptions), which give counterparties the option to extend with similar terms for an additional 6-month or 12-month period.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
As of December 31, 2016, we had entered into the following natural gas derivative instruments:
(1)
We traditionally enter into a hedge contract term of one year. For 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 certain derivative contracts (swaptions), which give counterparties the option to extend with similar terms for an additional 6-month or 12-month period.
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 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:
Year Ended December 31, 2016 Liabilities incurred were due to new wells and facilities placed into service for onshore US, deepwater Gulf of Mexico, and offshore Israel.
Liabilities settled were related to wells and facilities permanently abandoned at the end of their useful lives and to assets sold. Settlements included $65 million related to abandonment of deepwater Gulf of Mexico properties, $49 million related to onshore US properties abandoned or sold, $5 million related to offshore Israel properties and $1 million related to the North Sea.
Year Ended December 31, 2015 Liabilities incurred were due to new wells and facilities and included $22 million for onshore US, $16 million for deepwater Gulf of Mexico and $29 million for properties acquired in the Rosetta Merger.
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 onshore US developments.
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. Acquisitions, Divestitures and Merger.
(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.
Revolving Credit Facility On August 27, 2015, we amended our $4.0 billion Revolving Credit Facility to extend the maturity date to August 27, 2020. We periodically borrow amounts for working capital purposes.
Our Revolving 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 Revolving Credit Facility and require the immediate repayment of any outstanding advances under the Revolving Credit Facility. As of December 31, 2016, we were in compliance with our debt covenants.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
The Revolving 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.
Noble Midstream Services Revolving Credit Facility On September 20, 2016, Noble Midstream Services LLC, a subsidiary of Noble Midstream Partners, entered into a credit agreement for a $350 million revolving credit facility (Noble Midstream Revolving Credit Facility). The Noble Midstream Revolving Credit Facility has a five year maturity and includes a letter of credit sublimit of up to $100 million for issuances of letters of credit. The borrowing capacity on the Noble Midstream Revolving Credit Facility may be increased by an additional $350 million subject to certain conditions and is available to fund working capital and to finance acquisitions and other capital expenditures of Noble Midstream Partners.
Borrowings by Noble Midstream Services under the Noble Midstream Revolving Credit Facility bear interest at a rate equal to an applicable margin plus, at Noble Midstream Service's option, either:
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in the case of base rate borrowings, a rate equal to the highest of (1) the prime rate, (2) the greater of the federal funds rate or the overnight bank funding rate, plus 0.5% and (3) the LIBOR for an interest period of one month plus 1.00%; or
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in the case of London interbank offered rate (LIBOR) borrowings, the offered rate per annum for deposits of dollars for the applicable interest period.
The Noble Midstream Revolving Credit Facility includes certain financial covenants as of the end of each fiscal quarter, including a (1) consolidated leverage ratio to consolidated adjusted earnings before interest expense, income taxes, depreciation, depletion, and amortization (EBITDA) and (2) consolidated interest coverage ratio (each covenant as described in the Noble Midstream Revolving Credit Facility). All obligations of Noble Midstream Services, as the borrower under the Noble Midstream Revolving Credit Facility, are guaranteed by Noble Midstream Partners and all wholly-owned material subsidiaries of Noble Midstream Partners. Debt issuance costs associated with this facility were de minimis.
Term Loan Agreement and Completed Tender Offers On January 6, 2016, we entered into a term loan agreement (Term Loan Facility) 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 $1.4 billion. Provisions of the Term Loan Facility are consistent with those in the Revolving Credit Facility. Borrowings under the Term Loan Facility may be prepaid prior to maturity without premium. The Term Loan Facility accrues interest, at our option, at either (a) a base rate equal to the highest of (i) the rate announced by Citibank, N.A., as its prime rate, (ii) the Federal Funds Rate plus 0.5%, and (iii) a LIBOR plus 1.0%, plus a margin that ranges from 10 basis points to 75 basis points depending upon our credit rating, or (b) a LIBOR, plus a margin that ranges from 100 basis points to 175 basis points depending upon our credit rating. The interest rate for our Term Loan Facility is 2.01% as of December 31, 2016.
In connection with the Term Loan Facility, 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 in the Rosetta Merger. The borrowings under the Term Loan Facility were used solely to fund the tender offers. Approximately $1.4 billion of notes were validly tendered and accepted by us, with a corresponding amount borrowed under the new Term Loan Facility. As a result, we recognized a gain of $80 million which is reflected in other operating (income) expense, net in our consolidated statements of operations.
In fourth quarter 2016, we prepaid $850 million of borrowings under our Term Loan Facility from cash on hand.
See Note 13. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of debt.
Debt Exchange On July 29, 2015, we completed our debt exchange offers to exchange all validly tendered and accepted senior 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.
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.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Annual Debt Maturities Annual maturities of outstanding debt, excluding capital lease payments, are as follows:
Note 11. Income Taxes
Components of income (loss) from operations before income taxes are as follows:
The income tax provision (benefit) consists of the following:
Noble Energy, Inc.
Notes to Consolidated Financial Statements
A reconciliation of the federal statutory tax rate to the effective tax rate is as follows:
Deferred tax assets and liabilities resulted from the following:
Net deferred tax liabilities were classified in the consolidated balance sheets as follows:
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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, 2016. 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 $242 million in 2016 and $206 million in 2015. 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.
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 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, 2016 are no longer considered to be indefinitely reinvested outside the US and, during 2016, we recorded a $128 million deferred tax benefit to reduce the deferred tax liability recorded at the end of 2015, net of estimated foreign tax credits. In 2015, we changed our indefinite reinvestment assertion (APB 23 assertion) based 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 increased in 2016 as compared with 2015 primarily due to adjustments to deferred taxes for removal of the APB 23 assertion, as noted above, decreased earnings in foreign jurisdictions with rates that vary from the US statutory rate, a decrease in the Israeli income tax rate, as well as the 2015 impact of foreign dividend repatriation and goodwill impairment.
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.
Changes in Israeli Tax Law Effective January 2016, the Israeli government decreased the corporate income tax rate from 26.5% to 25%, and in December 2016 announced a further rate decrease to 24% effective January 2017. The change decreased the deferred tax expense for 2016 by $30 million.
Unrecognized Tax Benefits We file a consolidated income tax return in the US federal jurisdiction, and we file income tax returns in various states and foreign jurisdictions. Our income tax returns are routinely audited by the applicable revenue authorities, and provisions are made in the financial statements for differences between positions taken in tax returns and amounts recognized in the financial statements in anticipation of audit results.
In our major tax jurisdictions, the earliest years remaining open to examination are: US - 2013, Equatorial Guinea - 2011 and Israel - 2015.
Our policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
A reconciliation of our beginning and ending amounts of unrecognized tax benefits follows:
Unrecognized tax benefits which would impact our effective tax rate if recognized were approximately $3 million as of December 31, 2016. The changes to our unrecognized tax benefits during 2016 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 2016, we recognized and accrued a de minimis amount of interest and no penalties.
We expect that our unrecognized tax benefits will continue to change due to the settlement of audits and the expiration of statutes of limitation during 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.
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, 2016, 27,581,280 shares of our common stock were reserved for issuance, including 13,059,725 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 in 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 two or three year period. 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
Noble Energy, Inc.
Notes to Consolidated Financial Statements
shares of our common stock that may be issued under the 2015 Plan is 708,996. At December 31, 2016, 705,615 shares of our common stock were reserved for issuance including 563,075 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. At December 31, 2016, 404,865 shares of our common stock were reserved for issuance in accordance with the 2005 Plan; however, the 2005 Plan was terminated in 2015, and no additional options can be granted thereunder. Options were 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.
Stock Option Grants The fair value of each stock option granted is 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.
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Expected volatility The expected volatility represents the extent to which our stock price is expected to fluctuate between the grant date and the expected term of the award. We use the historical volatility of our common stock for a period equal to the expected term of the option prior to the date of grant. We believe that historical volatility produces an estimate that is representative of our expectations about the future volatility of our common stock over the expected term.
•
Risk-free rate The risk-free rate is the implied yield available on US Treasury securities with a remaining term equal to the expected term of the option. We base our risk-free rate on a weighting of five and seven year US Treasury securities as of the date of grant.
•
Dividend yield The dividend yield represents the value of our stock’s annualized dividend as compared to our stock’s average price for the three-year period ended prior to the date of grant. It is calculated by dividing one full year of our expected dividends by our average stock price over the three-year period ended prior to the date of grant.
The assumptions used in valuing stock options granted were as follows:
Stock option activity was as follows:
The total intrinsic value of options exercised was $10 million in 2016, $7 million in 2015, and $58 million in 2014.
As of December 31, 2016, $26 million of compensation cost related to unvested stock options granted under the Plans remained to be recognized. The cost is expected to be recognized over a weighted-average period of 1.3 years. We issue new shares of our common stock to settle option exercises. Dividends are not paid on unexercised options.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Restricted Stock Awards 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 value of the market based restricted stock awards was estimated on the date of award using a Monte Carlo valuation model that uses the assumptions in the following table. The Monte Carlo valuation 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 $24 million in 2016, $62 million in 2015, and $50 million in 2014.
The weighted average award-date fair value of restricted stock awarded was $29.99 per share in 2016, $35.53 per share in 2015, and $41.22 per share in 2014.
As of December 31, 2016, $32 million of compensation cost related to all of our unvested restricted stock awarded under the Plans remained to be recognized. The cost is expected to be recognized over a weighted-average period of 1.3 years years. Common stock dividends accrue on restricted stock awards and are paid upon vesting. We issue new shares of our common stock when awarding restricted stock.
Cash-Settled Awards On February 1, 2016, we issued cash-settled awards to certain employees under the 1992 Plan in lieu of a portion of restricted stock and stock options. We issued approximately one million awards (so called phantom units, the nomenclature used in accounting literature), a portion of which are subject to the Company's achievement of certain levels of total shareholder return relative to a pre-determined industry peer group. The fair value of the market based phantom unit awards was estimated on the date of award using a Monte Carlo valuation model based on the assumptions below.
These phantom units represent a hypothetical interest in the Company, and, once vested, are settled in cash. The phantom unit value at vesting will equal the lesser of the fair market value of a share of common stock of the Company as of the vesting date (2-year cliff vesting for officers and 3-year cliff vesting for non-officers) or up to four times the fair market value of a share of common stock of the Company, which was $31.65, as of the grant date.
As of December 31, 2016, we had accrued a liability of $9 million related to the phantom units.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
The assumptions used in valuing market based phantom units awarded were as follows:
Phantom unit activity was as follows:
As of December 31, 2016, $18 million of compensation cost related to phantom units remained to be recognized. The cost is expected to be recognized over a weighted-average period of 2.0 years. The total fair value of phantom units that vested in 2016 was de minimis. Common stock dividends accrue on phantom units and will be paid upon vesting.
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 $32 million in 2016, $35 million in 2015, and $26 million in 2014.
As a result of the termination of the pension plan, 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 Plan 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.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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 600,000 shares, or 89%, of our common stock held in respect of one nonqualified deferred compensation plan at December 31, 2016 were attributable to a member of our Board of Directors. The shares are being distributed in equal installments over the next three years. Distributions of 200,000 shares were made in 2016, 200,000 shares in 2015 and 200,000 shares in 2014. In addition, plan participants sold 1,009 shares of our common stock in 2016, 1,009 shares in 2015, and 19,049 shares in 2014. Proceeds were invested in mutual funds and/or distributed to plan participants. Distributions to plan participants were valued at $22 million in 2016, $18 million in 2015 and $22 million in 2014.
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 $11 million in 2016, $(12) million in 2015 and $(25) million in 2014.
We also maintain other nonqualified deferred compensation plans for the benefit of certain of our employees. Deferred compensation liabilities of $121 million and $119 million were outstanding at December 31, 2016 and 2015, respectively, under those other plans.
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.
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.
Stock-Based Compensation Liability A portion of the value of the liability associated with our phantom unit plan is dependent upon the fair value of Noble Energy common stock as of the end of each reporting period. See Note 12. Stock-Based and Other Compensation Plans.
Deferred Compensation Liability The value is dependent upon the fair values of mutual fund investments and shares of our common stock held in a rabbi trust. See Mutual Fund Investments above.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Measurement information for assets and liabilities that are measured at fair value on a recurring basis was as follows:
(1)
See Note 1. Summary of Significant Accounting Policies - Fair Value Measurements for a description of the fair value hierarchy.
(2)
Amount represents the impact of netting clauses within our master agreements that allow us to net cash settle asset and liability positions with the same counterparty.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Certain assets and liabilities are measured at fair value on a nonrecurring basis in our consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:
Asset Impairments In 2016, 2015 and 2014, 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 as noted below.
Inventory Impairment In 2016 and 2015, we determined that the carrying amount of certain of our materials and supplies inventory was greater than its net realizable value or not recoverable from future cash flows. These assets were, therefore, adjusted as noted below.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Information about the impaired assets is as follows:
(1)
See Note 1. Summary of Significant Accounting Policies - Fair Value Measurements for a description of the fair value hierarchy.
(2)
Amount represents net book value at the date of assessment.
The fair values of the properties held and used were determined as of the date of the assessment using discounted cash flow models. The discounted cash flows were based on management’s expectations for the future. Inputs included estimates of future crude oil and natural gas production, commodity prices based on sales contract terms or commodity price curves as of the date of the estimate, estimated operating and development costs, and a risk-adjusted discount rate of 10%. The fair values of assets held for sale were based on anticipated sales proceeds less costs to sell. See Note 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.
Our Term Loan Facility is variable-rate, non-public debt. The carrying amount of floating-rate debt approximates fair value as the interest rates are variable and reflective of market rates. 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.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 14. Earnings (Loss) Per Share Attributable to Noble Energy
Noble Energy's basic earnings (loss) per share of common stock is computed by using net income (loss) attributable to Noble Energy divided by the weighted average number of shares of Noble Energy common stock outstanding during each period. The diluted earnings (loss) per share of common stock includes 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 years ended December 31, 2016 and 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. 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 for the year ended December 31, 2015 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.
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 (which includes consolidated accounts of Noble Midstream Partners); West Africa (Equatorial Guinea, Cameroon, Gabon and Sierra Leone (which we exited in second quarter 2015)); 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 exited first quarter 2015) and new ventures. Net income (loss) before income taxes for the US and West Africa includes gains and losses on commodity derivative instruments.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
(1) Revenues from third parties for all foreign countries, in total, were $973 million in 2016, $1.1 billion in 2015 and $1.8 billion 2014.
(2) Long-lived assets located in all foreign countries, in total, were $3.0 billion, $3.9 billion, and $4.4 billion at December 31, 2016, 2015, and 2014, respectively.
(3) As of December 31, 2015, our goodwill was fully impaired. See Note 1. Summary of Significant Accounting Policies.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 16. Concentration of Risk
Concentration of Market Risk The largest single non-affiliated purchasers of our production were as follows:
(1)
Includes sales to Shell Trading (US) Company and/or 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, including one of our significant crude oil purchasers, in the way of parental guarantees or letters of credit. 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.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 17. Additional Shareholders’ Equity Information
Activity in shares of our common stock and treasury stock was as follows:
Equity Offering 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, which had been drawn for short-term purposes on February 27, 2015. The remainder of the net proceeds was used for general corporate purposes, including the funding of our capital investment program.
In accordance with our accounting policy, we excluded the intra-quarter Revolving Credit Facility activity from gross presentation in our consolidated statements of cash flows. We use net presentation when such activity includes short maturities (i.e., less than 90 days) with quick turnover.
Accumulated Other Comprehensive Loss 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, 2016 included deferred losses of $21 million, net of tax, related to interest rate derivative instruments. This amount is being reclassified to earnings as an adjustment to interest expense over the term of our senior notes due March 2041.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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 US District Court of Colorado 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 which were paid in 2015. Mitigation costs of $4.5 million and SEP costs of $4 million are being expended in accordance with schedules established in the Consent Decree. Costs associated with the injunctive relief are also being expended in accordance with schedules established in the Consent Decree. During 2015 and 2016, we spent approximately $54.7 million to undertake injunctive relief at certain tank systems following the outcome of adequacy of design evaluations and certain operation and maintenance activities to handle potential peak instantaneous vapor flow rates. Future costs associated with injunctive relief are not yet precisely quantifiable as we are continually evaluating various approaches to meet the ongoing obligations of the Consent Decree.
Overall compliance with the Consent Decree has resulted in the temporary shut-in and permanent plugging and abandonment of certain wells and associated tank batteries. Consent Decree compliance could result in additional temporary shut-ins and 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 that may be extended depending on certain situations. The Consent Decree contains additional obligations for ongoing inspection and monitoring beyond that which is required under existing Colorado regulations.
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 from the Colorado Department of Public Health and Environment's Air Pollution Control Division (APCD) 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 that applied to assets currently owned and operated by both Noble Energy and Noble Midstream Services, LLC. In May 2016, Noble Energy on behalf of itself and its wholly owned subsidiary Noble Midstream Services, LLC, on behalf of itself and its wholly owned subsidiary Colorado River DevCo LP, reached a final resolution with the APCD, which requires completion of compliance testing, modification of certain permits, payment of a civil penalty of $44,695, and an expenditure of no less than $178,780 on an approved SEP. This resolution is not believed to have a material adverse effect on our financial position, results of operations or cash flows.
Transportation and Gathering Obligations We have transportation and gathering obligations to flow Marcellus Shale natural gas production to various markets inside and outside of the Marcellus Basin. Our financial commitment for these agreements, which have remaining terms of one to 32 years, is approximately $2.1 billion, undiscounted. The agreements for firm transportation relate to 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. The commitment is included in the table below.
We also have transportation and gathering obligations to flow DJ Basin, Eagle Ford Shale, and Gulf of Mexico production to various markets. Our financial commitment for these agreements, which have remaining terms of one to 12 years, is approximately $850 million, undiscounted. 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 $76 million in 2016, $84 million in 2015, and $69 million in 2014.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Minimum commitments as of December 31, 2016 consist of the following:
(1)
Annual lease payments, net to our interest, exclude regular maintenance and operational costs. See Note 10. Long-Term Debt.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
In accordance with US GAAP for disclosures about oil and gas producing activities, and SEC rules for oil and gas reporting disclosures, we are making the following disclosures about our crude oil, 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, 2016, 2015, and 2014 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. Production, development and abandonment costs are based on year-end economic conditions; therefore increases in these costs could also 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, 2016. See Items 1. and 2. Business and Properties - Proved Reserves Disclosures.
Definitions The following definitions apply to the terms used in the paragraphs above:
Reserves Estimate The determination of an estimate of a quantity of oil or gas reserves that are thought to exist at a certain date, considering existing prices and reservoir conditions.
Reserves Audit The process of reviewing certain of the pertinent facts interpreted and assumptions underlying a reserves estimate prepared by another party and the rendering of an opinion about the appropriateness of the methodologies employed, the adequacy and quality of the data relied upon, the depth and thoroughness of the reserves estimation process, the classification of reserves appropriate to the relevant definitions used, and the reasonableness of the estimated reserves quantities.
The following definitions apply to our categories of proved reserves:
Proved Oil and Gas Reserves Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to produce the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
Developed Oil and Gas Reserves Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well.
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 (through 2014) and Israel.
(2)
The 2014 US revisions were 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 were associated with negative price revisions.
The 2016 US revisions associated with positive performance and/or decreases in development or operating costs included revisions of 33 MMBbls in the DJ Basin, Marcellus Shale, Permian Basin and deepwater Gulf of Mexico; partially offset by negative revisions of 19 MMBbls due to lower commodity prices. Equatorial Guinea revisions were primarily due to lower commodity prices.
(3)
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 was attributable to DJ Basin development.
The 2016 increase in US reserves primarily includes 38 MMBbls in the DJ Basin and 28 MMBbls in the Permian Basin and Eagle Ford Shale, and was associated with increased performance from our horizontal drilling programs.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
(4)
The 2015 increase is attributable to reserves acquired in the Rosetta Merger.
(5)
In 2014, we sold our China assets.
In 2015, we sold onshore US assets.
In 2016, we sold onshore US assets.
(6)
Equatorial Guinea production includes sales from the Alba LPG plant of approximately 3 MMBbl in each of the years 2016, 2015, and 2014.
See Items 1. and 2. Business and Properties - Proved Undeveloped Reserves (PUDs) and Note 3. Acquisitions, Divestitures and Merger.
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 are required to reduce our ownership in the Tamar field to 25% by year-end 2021. During 2016, we reduced our ownership to 32.5% through a sale.
(2)
Other International includes China.
(3)
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.
The 2016 US revisions were primarily associated with positive performance and/or decreases in development or operating costs and included 167 Bcf in the Marcellus Shale and 95 Bcf in the DJ Basin, partially offset by negative commodity price revisions of 81 Bcf. Equatorial Guinea revisions are associated with positive performance revisions of 58 Bcf at the Alba field, partially offset by negative commodity price revisions of 20 Bcf.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
(4)
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.
The 2016 increase in US reserves included positive performance revisions associated with our horizontal drilling programs including 230 Bcf in the Marcellus Shale, 185 Bcf in the DJ Basin, and 77 Bcf in the Permian Basin and Eagle Ford Shale.
(5)
The 2015 increase is attributable to reserves acquired in the Rosetta Merger.
(6)
In 2014, we sold onshore US and China assets.
In 2015, we sold onshore US assets in the DJ Basin.
In 2016, we sold onshore US assets in the DJ Basin and Eagle Ford Shale. We also executed an acreage exchange in the Marcellus Shale where we relinquished 185 Bcf, and we reduced our ownership in the Tamar field, offshore Israel.
See Items 1. and 2. Business and Properties - Proved Undeveloped Reserves (PUDs) and Note 3. Acquisitions, Divestitures and Merger.
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 were primarily associated with negative price revisions of 44 MMBbls related 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.
The 2016 US revisions were primarily associated with positive performance revisions of 11 MMBbls in the Marcellus Shale and 9 MMBbls in the DJ Basin, partially offset by negative commodity price revisions of 4 MMBbls.
(2)
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 included 14 MMBbls due to positive producing well performance and optimized lateral lengths in the DJ Basin.
The 2016 additions in US reserves primarily included an increase of 15 MMBbls in the DJ Basin and 14 MMBbls in the Permian Basin and Eagle Ford shale due to improved well performance and/or decreases in development or operating costs.
(3) Equatorial Guinea production represents sale from the Alba LPG plant.
(4) The 2015 increase was attributable to reserves acquired in the Rosetta Merger.
The 2016 increase was attributable to the acreage exchange in the Marcellus Shale.
See Items 1. and 2. Business and Properties - Proved Undeveloped Reserves (PUDs) and Note 3. Acquisitions, Divestitures and Merger.
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 (through 2014), China (through June 30, 2014) and new ventures.
(2)
Production costs consist of lease operating expense, production and ad valorem taxes, transportation and gathering expense, and general and administrative expense supporting oil and gas operations.
(3)
Equatorial Guinea exploration expense includes $468 million for the write off of costs associated with certain discoveries. See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
(4)
Asset impairments relate to certain Leviathan development concepts costs. See Note 5. Asset Impairments.
(5)
Income tax expense is based upon respective corporate statutory tax rates. During 2016, 2015, and 2014, 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.
(6)
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) and new ventures. See Note 3. Acquisitions, Divestitures and Merger.
(3)
2016 unproved property acquisition costs relate to the termination of the Marcellus Shale joint development. See Note 3. Acquisitions, Divestitures and Merger.
2015 proved and unproved property acquisitions include amounts allocated from the Rosetta Merger. See Note 3. Acquisitions, Divestitures and Merger.
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.
(4)
2016 exploration costs include drilling and completion of $1 million in the Marcellus Shale and $44 million in the deepwater Gulf of Mexico.
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.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
(5)
Worldwide development costs include amounts spent to develop PUDs of approximately $656 million in 2016, $1.5 billion in 2015, and $2.0 billion in 2014.
US development costs include Noble Midstream Partners capital expenditures of approximately $50 million in 2016, gathering and processing assets acquired in the Rosetta Merger in 2015 and increases in asset retirement obligations of $18 million in 2016, $194 million in 2015, and $106 million in 2014.
Equatorial Guinea development costs include increases (decreases) in asset retirement obligations of $(10) million in 2015, and $34 million in 2014.
Israel development costs include increases in asset retirement obligations of $46 million in 2015, and $19 million in 2014.
Other International development costs include increases in asset retirement obligations of $2 million in 2015, and $71 million in 2014.
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, 2016 include previous acquisition costs of $1.2 billion related to the Eagle Ford Shale and Permian Basin properties and $758 million related to the Marcellus Shale.
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. See Note 3. Acquisitions, Divestitures and Merger.
(2)
Proved oil and gas properties at December 31, 2016 include asset retirement costs of $897 million and exclude assets held for sale of $18 million.
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.
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 are required to reduce our ownership in the Tamar field to 25% by year-end 2021. During 2016, we reduced our ownership to 32.5% through a sale. Therefore, 2016 amounts reflect a 32.5% working interest, while 2015 and 2014 amounts reflect a 36% working interest. See Note 3. Acquisitions, Divestitures and Merger.
(2)
Other International represents North Sea abandonment costs.
(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. 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 2016 and 2015, future income tax expense for Israel also includes the effect of estimated future profit levy taxes and changes to corporate income tax rates.
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:
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% per Bbl reduction in the average price of crude oil from the 12-month average price for 2016 would reduce the discounted future net cash flows before income taxes by approximately $910 million. We estimate that a 10% per Mcf reduction in the average price of natural gas from the 12-month average price for 2016 would reduce the discounted future net cash flows before income taxes by approximately $695 million.
Future production and development costs, which include dismantlement and restoration expense, are computed by estimating the expenditures to be incurred in developing and producing the proved crude oil, 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 $1.1 billion in 2017, $0.9 billion in 2018 and $800 million in 2019.
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 were as follows:
(1)
Imbalance receivables and liabilities for 2015 and 2014 related primarily to onshore US assets which were sold in 2016.
Imbalance receivables and liabilities have been excluded from the standardized measure of discounted future net cash flows for all years presented.
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)
The decrease in 2015 is driven primarily by lower 12-month average commodity prices.
(2)
Purchase of minerals in 2015 relates to reserves acquired in the Rosetta Merger.
(3)
The increase in 2015 reflects 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)
The 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 2016 included the following:
•
$44 million gain on commodity derivative instruments, including non-cash portion of loss on commodity derivative instruments of $134 million (See Note 8. Derivative Instruments and Hedging Activities); and
•
$80 million gain on extinguishment of debt.
Second quarter 2016 included the following:
•
$151 million loss on commodity derivative instruments, including non-cash portion of loss on commodity derivative instruments of $295 million (See Note 8. Derivative Instruments and Hedging Activities); and
•
$25 million purchase price allocation adjustment related to Rosetta Merger (See Note 3. Merger, Acquisitions and Divestitures).
Third quarter 2016 included the following:
•
$81 million undeveloped leasehold impairment expense (See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs);
•
$55 million gain on commodity derivative instruments, including non-cash portion of loss on commodity derivative instruments of $77 million (See Note 8. Derivative Instruments and Hedging Activities).
Fourth quarter 2016 included the following:
•
$579 million dry hole costs included in exploration expense (See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs);
•
$87 million loss on commodity derivative instruments, including non-cash portion of loss on commodity derivative instruments of $201 million (See Note 8. Derivative Instruments and Hedging Activities); and
•
$92 million property impairment charges (See Note 5. Asset Impairments)
(2) First quarter 2015 included the following:
•
$150 million gain on commodity derivative instruments, including non-cash portion of 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 non-cash portion of 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 non-cash portion of 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 non-cash portion of loss on commodity derivative instruments of $157 million (See Note 8. Derivative Instruments and Hedging Activities);
•
$779 million goodwill impairment charge (See Note 1. Summary of Significant Accounting Policies); and
•
$490 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.

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

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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 were effective and provide an effective means 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 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, 2016. Based on our assessment, our internal controls over financial reporting were effective. There were no changes in internal controls over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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

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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 2017 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2016.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation
The information required by this item is incorporated herein by reference to the 2017 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2016.

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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 2017 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2016.

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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 2017 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2016.

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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 2017 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2016.
PART IV

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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.
Item 16. Form 10-K Summary
See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Executive Summary.
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 14, 2017
By: /s/ David L. Stover
David L. Stover,
Chairman of the Board, President and Chief Executive Officer
Date:
February 14, 2017
By: /s/ Kenneth M. Fisher
Kenneth M. Fisher,
Executive Vice President, Chief Financial Officer
Date:
February 14, 2017
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 14, 2017
David L. Stover
(Principal Executive Officer)
/s/ Kenneth M. Fisher
Executive Vice President, Chief Financial Officer
February 14, 2017
Kenneth M. Fisher
(Principal Financial Officer)
/s/ Dustin A. Hatley
Vice President, Chief Accounting Officer and Controller
February 14, 2017
Dustin A. Hatley
(Principal Accounting Officer)
/s/ Jeffrey L. Berenson
Director
February 14, 2017
Jeffrey L. Berenson
/s/ Michael A. Cawley
Director
February 14, 2017
Michael A. Cawley
/s/ Edward F. Cox
Director
February 14, 2017
Edward F. Cox
/s/ James E. Craddock
Director
February 14, 2017
James E. Craddock
/s/ Thomas J. Edelman
Director
February 14, 2017
Thomas J. Edelman
/s/ Eric P. Grubman
Director
February 14, 2017
Eric P. Grubman
/s/ Kirby L. Hedrick
Director
February 14, 2017
Kirby L. Hedrick
/s/ Scott D. Urban
Director
February 14, 2017
Scott D. Urban
/s/ William T. Van Kleef
Director
February 14, 2017
William T. Van Kleef
/s/ Molly K. Williamson
Director
February 14, 2017
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
GSPA
Gas Sales Purchase Agreement
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

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Stock Performance Metrics:
Return: -0.02106077969074249
1-Day Return: $1_day_return
3-Day Return: $3_day_return
5-Day Return: $5_day_return
10-Day Return: $10_day_return
20-Day Return: $20_day_return
40-Day Return: $40_day_return
60-Day Return: $60_day_return
80-Day Return: $80_day_return
100-Day Return: $100_day_return
150-Day Return: $150_day_return
252-Day Return: $252_day_return