SEC Form 10-K Filing Report

Company: NOBLE ENERGY INC
CIK: 72207
SIC Code: 1311
Filing Date: 2018-02-20 00:00:00
Market Capitalization: 14169996.248376846

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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 17. 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 30, 2018, our Board of Directors declared a quarterly cash dividend of $0.10 per common share. The dividend will be paid February 26, 2018, to shareholders of record on February 12, 2018. 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 February 9, 2018, the number of holders of record of our common stock was 561.
Stock Repurchases The following table summarizes repurchases of our common stock occurring in fourth quarter 2017:
(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, 2012 to December 31, 2017. 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 US onshore 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, 2012 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 2018 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2017.

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. Selected Financial Data
(1)
Proceeds for 2017 relate to the Marcellus Shale upstream divestiture and proceeds received from other transactions. Proceeds for 2016 primarily relate to US onshore non-strategic asset divestiture activity and the sell-down of Tamar interest. See Item 8. Financial Statements and Supplementary Data - Note 4. Acquisitions, Divestitures and Merger
(2)
Goodwill at December 31, 2017 related to the Clayton Williams Energy Acquisition. Our previous goodwill balance 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. 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 - E&P;
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Results of Operations - Midstream;
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Results of Operations - Corporate;
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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
Results of Operations - E&P
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
Liquidity and Capital Resources - Acquisition, Capital Expenditures 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
Results of Operations - E&P
Item 8. Financial Statements and Supplementary Data - Supplemental Oil and Gas Information (Unaudited)
EXECUTIVE OVERVIEW
Industry Outlook
Crude Oil The global oil and gas industry is cyclical, and crude oil prices are volatile, driven by crude oil supply, which includes OPEC and non-OPEC producers, and global crude oil demand.
In 2014, our industry entered a downturn due to oversupplied crude oil production from non-OPEC producers, primarily driven by US unconventional oil production growth from tight formations and the de-bottlenecking of transportation infrastructure. Coupled with OPEC’s decision not to reduce production quotas and muted global crude oil demand growth, crude oil prices began falling rapidly in late 2014.
The rapid decline in crude oil prices impacted US and other non-OPEC producers' capital budgets, which resulted in lower crude oil production. Further, in late 2016, OPEC announced voluntary production curtailments in an effort to stabilize excess crude oil supply and crude oil prices and to rebalance crude oil inventories. The decline in supply from these producers has aided in stabilizing the crude oil market. As a result, crude oil prices have recently recovered to three-year record highs, while production from the US has increased, allowing US producers to absorb global market share.
Global crude oil products demand has increased, supported by lower crude oil prices and a synchronized global economic recovery, leading to increased refinery utilization and crude oil demand. Increased demand has further contributed to stabilizing crude oil prices.
The outlook for 2018 crude oil prices will continue to depend on supply and demand dynamics, as well as global geopolitical and security factors in crude oil-producing nations. Reductions in industry investment, particularly for conventional crude oil development, will, over time, contribute to production declines, helping to balance supply and demand in the crude oil market.
Natural Gas The US domestic natural gas market remains oversupplied as domestic production has continued to grow due to drilling efficiencies, completion of DUC well inventory and de-bottlenecking of transportation infrastructure. In contrast to crude oil supply curtailments, there has been little to offset natural gas supply growth, which continues to outpace demand domestically. As a result, natural gas prices remained range-bound in 2017. We expect this situation to continue into 2018, with natural gas prices at or near current or recent trading levels.
Impact of Current Commodity Prices Modest commodity price improvement has increased both our consolidated average realized crude oil and consolidated average natural gas prices by approximately 20% in 2017 as compared to 2016. The chart below shows the historical trend in benchmark prices for West Texas Intermediate (WTI) crude oil, Brent crude oil and US Henry Hub natural gas.
Because the global economic outlook and commodity price environment are uncertain, we have maintained a robust financial liquidity position to ensure financial flexibility. We have also planned a 2018 capital investment program that will be flexible and responsive to positive or negative price conditions that may develop and support continued business investment in a volatile commodity price environment. See 2018 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.
Development and Operating Costs Third party oilfield service and supply costs are also subject to supply and demand dynamics. During 2017, increases in US onshore drilling and completion activity resulted in higher demand for oilfield services. As a result, the costs of drilling, equipping and operating wells and infrastructure experienced some inflation, which,
along with commodity prices, impacted industry operating margins. Conversely, the industry has reduced capital-intensive offshore exploration and drilling activities in response to the commodity price environment. Demand for and costs associated with offshore conventional oil services have declined and, in the near-term, will likely not be subject to cost inflation.
Recent Activities Implementation of our focused strategy has enhanced our future outlook. Over the past three years, we have made significant changes and enhancements to our business:
Portfolio Transformation, Including:
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entered the liquids-rich Eagle Ford Shale and Delaware Basin through the Rosetta Merger;
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expanded our Delaware Basin position through the Clayton Williams Energy Acquisition;
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exited the Marcellus Shale upstream and are exiting the Marcellus Shale midstream, thereby accelerating monetization of assets not attracting capital;
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established the Noble Midstream business, including an initial public offering of Noble Midstream Partners, and executed the first asset drop down transaction; and
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accelerated DJ Basin value through numerous acreage exchanges and sales.
Operational Accomplishments, Including:
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focused capital and resources on highest-margin assets within US onshore liquids plays and the Eastern Mediterranean;
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sanctioned the initial phase of Leviathan development, with first natural gas sales targeted for the end of 2019;
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excluding the impact of the Marcellus Shale upstream divestiture, increased proved reserves by more than 65% from 2016;
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excluding the impact of the Marcellus Shale upstream divestiture, increased total US onshore sales volumes by more than 15% from 2016 and shifted to an oilier production mix, with more than 40% of our US onshore consolidated sales volumes attributable to crude oil; and
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improved well level and corporate returns with technology advancements and structural cost savings.
Financial Strength, Including:
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proactive and strategic action to manage within cash flows;
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made net repayments of debt totaling $1.69 billion, since beginning of 2016 through cash on hand, proceeds from asset sales, and cash generated by our midstream business;
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maintained a strong liquidity position including cash on hand and unused borrowing capacity; and
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maintained our investment grade credit ratings.
In summary, during 2017, we closed several strategic portfolio transactions demonstrating our continued focus on enhancing company margins and returns. Our current portfolio includes assets which are well-positioned on the industry cost of supply curve, offering growth at financially attractive rates of return. Operationally, we continued to drive efficiencies in our US onshore drilling and completions, while advancing our Eastern Mediterranean regional natural gas developments. Financially, we continued to maintain our strong balance sheet and robust liquidity position.
Subsequent Events The Company has evaluated the period after the balance sheet date, noting no subsequent events or transactions that required recognition or disclosure in the financial statements, other than as previously disclosed or noted below.
Share Repurchase Program On February 15, 2018, we announced the Company's Board of Directors authorized a share repurchase program of $750 million which expires December 31, 2020. All purchases will be made in accordance with applicable securities laws from time to time in open market or private transactions, depending on market conditions, and may be discontinued at any time.
Gulf of Mexico Divestiture On February 15, 2018, we announced the Company signed a definitive agreement to sell its assets in the Gulf of Mexico for cash consideration of $480 million. As part of the transaction, the buyer will assume all abandonment obligations associated with the properties which we estimate to approximate $230 million as of December 31, 2017. The net book value of the Gulf of Mexico assets as of December 31, 2017 was approximately $750 million. We expect to incur a charge in early 2018, subject to customary closing adjustments. The transaction is expected to close during second quarter 2018, contingent upon the buyer’s successful implementation of its contemplated restructuring, and will be effective as of January 1, 2018.
GSPAs - Israel Export On February 19, 2018, we executed two independent GSPAs for the sale of natural gas from the Leviathan and Tamar fields to Dolphinus Holdings Limited to supply natural gas in Egypt. Sales volumes under the GSPA associated with the Leviathan field are anticipated to begin at a firm rate of approximately 350 MMcf/d, gross, (approximately 139 MMcf/d, net) at the startup of the Leviathan project currently anticipated at the end of 2019. For the Tamar agreement, sales volumes are anticipated to begin at an interruptible rate of up to 350 MMcf/d, gross, (approximately 114 MMcf/d, net)
dependent upon gas availability beyond existing customer obligations in Israel and Jordan. The GSPA includes an option to convert the Tamar interruptible quantity to a firm-basis with a take or pay commitment. Both contracts are for a 10-year term and have pricing terms indexed to Brent crude, similar to other export contracts in the region. The GSPAs are subject to satisfaction of conditions precedent, including regulatory approvals and licenses, and finalizing gas transportation agreements.
OPERATING OUTLOOK
Growing Long-Term Value We believe the following guiding principles will contribute to growing long-term value:
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Execution of a disciplined capital allocation process by:
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designing a flexible investment program aligned with the current commodity price environment; and
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maintaining a strong balance sheet and liquidity position.
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Enhancing capital efficiencies through:
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utilizing our technical competencies and applying historical learnings from unconventional US shale plays to reduce US onshore finding and development costs; and
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driving Delaware Basin economics through development cycle efficiencies.
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Leveraging the benefits of our well-positioned and diversified portfolio including:
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exercising investment optionality and flexibility afforded by our assets, which are largely held by production; and
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continuing portfolio optimization actions to maximize strategic value.
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Capitalizing on a currently low-cost offshore environment with execution of high-quality, long-cycle development projects, such as:
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progressing Leviathan field development.
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Maintaining financial strength through:
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focusing operational activities on high-margin, high-return assets;
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improving overall corporate returns; and
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ensuring cash flow sources and uses remain balanced.
As we enter 2018, we believe we have positioned the Company for sustainability, operational efficiency, and long-term success throughout the oil and gas business cycle. However, if commodity prices decline or operating costs begin to rise, we could experience material negative impacts on our revenues, profitability, cash flows, liquidity and proved reserves, and, in response, we may consider reductions in our capital program or dividends, asset sales or otherwise. Our production and our stock price could decline 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.
2018 Production 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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increased drilling activity, which may cause US onshore cost inflation pressure and result in certain current production becoming less profitable or uneconomic;
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Israeli industrial and residential demand for electricity, which is largely impacted by weather conditions and the conversion of Israel's 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 and Dalit fields, in accordance with the Framework, which will leave us with a 25% working interest and will accelerate value realization, but lower our forward sales volumes;
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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 US onshore, Gulf of Mexico and offshore Equatorial Guinea;
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additional purchases of producing properties or divestments of operating assets;
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potential weather-related volume curtailments due to hurricanes in the Gulf of Mexico and Gulf Coast areas, or winter storms and flooding impacting US onshore operations;
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availability or reliability of supplier services, including access to support equipment and facilities, occurrence of pipeline disruptions, and/or potential pipeline and processing facility capacity constraints, which may cause delays, restrictions or interruptions in production and/or midstream processing;
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timing and completion of midstream expansion projects by Noble Midstream Partners in areas that provide services to our assets;
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malfunctions and/or mechanical failures at terminals or other US onshore delivery points;
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impact of enhanced completion efforts for US onshore assets;
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potential growth from participation in future, or decline from existing, non-operated wells;
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abandonment of low-margin US onshore wells;
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shut-in of US producing properties if storage capacity becomes unavailable; and
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potential drilling and/or completion permit delays due to future regulatory changes.
2018 Capital Investment Program
Our 2018 capital investment program is designed to deliver near and long-term value and is flexible in the current commodity price environment. Excluding capital funded by Noble Midstream Partners, our preliminary 2018 program accommodates an investment level of approximately $2.7 to $2.9 billion, with approximately 95% being allocated to US onshore development and the Eastern Mediterranean. The remaining portion of our 2018 capital program is designated for other activities, including exploration for lease acquisition, seismic and other geological analysis in support of future exploration prospects for potential development post 2020, as well as other corporate activities.
2018 Budget Principles Our 2018 capital program anticipates a similar level of investment directed to our US onshore assets, as compared with 2017. We will continue to advance our US onshore program through investments in liquids-rich and high-return projects, improve execution efficiency, enhance our midstream business value, grow our high margin Delaware Basin position and invest capital supporting drilling commitments to retain leases in line with our strategy. In the Eastern Mediterranean, our 2018 capital program accommodates increased investment as we progress toward development of the Leviathan project. We expect our level of capital investment in the Leviathan project to peak in 2018 and will be supported by proceeds received from the divestiture of the remaining 7.5% working interest in the Tamar field.
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;
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production, drilling and 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, including cash flows from potential midstream drop-down transactions;
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indebtedness levels;
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availability of financing or other sources of funding;
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impact of new laws and regulations on our business practices, including potential legislative or regulatory changes regarding the use of hydraulic fracturing; and
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potential changes in the fiscal regimes of the US and other countries in which we operate.
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 - Cash Flows - Financing Activities, and - Contractual Obligations - Exploration Commitments and Continuous Development Obligations.
Impact of Recent Changes in US Tax Law
On December 22, 2017, the US Congress enacted the Tax Reform Legislation, making significant changes to US federal income tax law beginning in 2018. See Item 1A. Risk Factors
While we believe that certain aspects of the new law will positively impact our future after-tax earnings, primarily due to the lower federal statutory tax rate, the ultimate impact of the Tax Reform Legislation may differ from our estimates due to changes in interpretations and assumptions made by us as well as additional regulatory guidance that may be issued. See Item 8. Financial Statements and Supplementary Date - Note 11. Income Taxes.
Potential for Future Impairments
We have had in the past, and may incur in the future, various impairments of proved and unproved properties, related to the following:
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Exploration Activities and Unproved Properties We may impair and/or relinquish certain undeveloped leases prior to expiration based upon changes in exploration plans, timing and extent of development activities, availability of capital and suitable rig and drilling equipment, resource potential, comparative economics, changing regulations and/or other factors. In addition, 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.
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Development Concept Selection Costs We may write-off costs related to certain development concepts, including costs of related pre-FEED and FEED studies, associated with significant offshore projects, particularly those in remote or under-developed areas, when such development concepts are eliminated from further consideration based on the
determination of the final development concept or when the concept itself is determined to be economically unfeasible.
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Producing Properties We may impair a proved property based on a decrease in forward commodity prices, or widening of basis differentials, or an increase in abandonment costs, among other factors.
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Divestments We may periodically divest certain assets to reposition our portfolio. When properties meet the criteria for reclassification as assets held for sale, they are valued at the lower of net book value or anticipated sales proceeds less transaction-related costs to sell. Impairment expense would be recorded for any excess of net book value over anticipated sales proceeds less transaction-related costs to sell. In addition, a further loss, which could be material, could occur upon closing of a sales transaction.
See also: Item 1A. Risk Factors; Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Exploration Expense; Item 8. Financial Statements and Supplementary Data - Note 5. Asset Impairments and - Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
RESULTS OF OPERATIONS - E&P
Highlights for our E&P business were as follows:
2017 Significant E&P Operating Highlights Included:
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total average daily sales volumes of 381 MBoe/d;
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record average daily sales volumes for US onshore crude oil of 90 MBbl/d; and
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average daily sales volumes for natural gas of 272 MMcf/d, net, in Israel, and an all-time record for full year average daily gross sales volumes for natural gas of 956 MMcfe/d, primarily from the Tamar field.
2017 E&P Financial Results Included:
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average realized crude oil price increase of 23% as compared to 2016;
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average realized NGL price increase of 56% as compared to 2016;
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average realized natural gas price increase of 24% as compared to 2016;
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pre-tax loss of $1.8 billion, as compared with pre-tax loss of $1.3 billion for 2016; and
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capital expenditures of $2.4 billion, excluding acquisitions, as compared with $1.2 billion for 2016.
Following is a summarized statement of operations for our E&P business:
(1)
See Item 8. Financial Statements and Supplementary Data - Note 4. Acquisitions, Divestitures and Merger.
(2)
See Item 8. Financial Statements and Supplementary Data - Note 5. Asset Impairments.
(3)
See Item 8. Financial Statements and Supplementary Data - Note 3. Clayton Williams Energy Acquisition.
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. We record crude oil, natural gas and NGL sales without deductions relating to transportation, fractionation or processing. These deductions are recorded as production expense.
In addition, commodity prices we receive may be reduced by location-basis differentials, which can be significant. For example, transportation bottlenecks or infrastructure limitations may increase demand for available transportation and gathering facilities, which could lead to competitive pricing between operators of a particular area. 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 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 increased in 2017 as compared with 2016 due to the following:
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23% increase in average realized prices due to the partial rebalancing of global supply and demand factors;
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higher US onshore sales volumes of 16 MBbl/d, including 5 MBbl/d contributed by recently acquired Clayton Williams Energy assets, primarily attributable to increased development and enhanced well design and completion techniques; and
•
higher sales volumes of 2 MBbl/d due to full year of production at Gunflint, a Gulf of Mexico project that started production in July 2016;
partially offset by:
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lower sales volumes of 14 MBbl/d primarily due to natural field decline in the Gulf of Mexico and Equatorial Guinea.
Revenues from crude oil and condensate sales remained relatively flat in 2016 as compared with 2015 due to the following:
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higher sales volumes of 9 MBbl/d in the Eagle Ford Shale and Delaware Basin, primarily attributable to full year consolidation following the Rosetta Merger;
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sales volumes from the Big Bend and Dantzler developments (Gulf of Mexico), which began producing fourth quarter 2015 and contributed 12 MBbl/d, net, collectively in 2016; and
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sales volume from the start up of the Gulf of Mexico Gunflint development in July 2016 which contributed 3 MBbl/d;
partially offset by:
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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
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decrease in sales volumes due to natural field decline at the Aseng and Alen fields, offshore Equatorial Guinea.
NGL Sales Revenues Revenues from NGL sales increased in 2017 increased as compared with 2016 due to the following:
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56% increase in average realized prices due to the partial rebalancing of global supply and demand factors; and
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higher US onshore sales volumes of 7 MBbl/d, including 1 MBbl/d contributed by recently acquired Clayton Williams Energy assets, primarily attributable to increased development and enhanced well design and completion techniques;
partially offset by:
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lower sales volumes of 4 MBbl/d due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017.
Revenues from NGL sales increased in 2016 as compared with 2015 due to the following:
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higher sales volumes of 14 MBbl/d in the Eagle Ford Shale and Delaware Basin, primarily attributable to a full year of production as well as increased development activity;
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7% increase in total consolidated average realized prices, primarily due to higher spot prices in the Marcellus Shale; and
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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:
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slightly lower sales volumes in the Marcellus Shale due to the higher dry gas composition of wells that were brought online in 2016.
Natural Gas Sales Revenues Revenues from natural gas sales decreased slightly in 2017 as compared with 2016 due to the following:
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lower sales volumes of 312 MMcf/d due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017; and
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lower sales volumes of 29 MMcf/d as a result of the sale of a 3.5% working interest in the Tamar field, offshore Israel, in December 2016, partially offset by higher gross sales volumes from the field;
partially offset by:
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24% increase in average realized prices due to the partial rebalancing of global supply and demand factors; and
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higher US onshore sales volumes of 40 MMcf/d, including 6 MMcf/d contributed by recently acquired Clayton Williams Energy assets.
Revenues from natural gas sales in 2016 as compared with 2015 due to the following:
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higher sales volumes of 93 MMcf/d in the Marcellus Shale, primarily attributable to well completion and infrastructure development;
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higher sales volumes of 81 MMcf/d in the Eagle Ford Shale and Delaware Basin, primarily attributable to full year consolidation following the Rosetta Merger;
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record sales volumes from the Tamar field, offshore Israel, which contributed an incremental 29 MMcf/d, in response to higher power generation needs; and
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higher sales volumes offshore Equatorial Guinea due to the completion of the Alba B3 compression project.
Income from Equity Method Investees Our share of operations of equity method investees was as follows:
Changes for 2017 as compared with 2016 included the following:
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net income from AMPCO and affiliates increased primarily due to higher realized methanol prices; and
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net income from Alba Plant increased primarily due to higher LPG sales volumes and higher realized commodity prices.
Changes for 2016 as compared with 2015 included the following:
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net income from AMPCO and affiliates increased in 2016 as compared with 2015 primarily due to higher methanol sales volumes, partially offset by lower methanol prices; and
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net income from Alba Plant remained relatively flat.
Production Expense Components of production expense were as follows:
N/M Amount is not meaningful.
(1)
United States upstream production expense includes charges from our midstream operations that are eliminated on a consolidated basis. See Item 1. Financial Statements - Note 15. Concentration of Risk.
(2)
Other International includes the North Sea in 2015.
(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 Lease operating expense increased in 2017 as compared with 2016 primarily due to the following:
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increase of $82 million in US onshore, primarily in the DJ Basin, Delaware Basin and Eagle Ford Shale due to increased activity;
partially offset by:
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decrease of $19 million due to natural field decline in the Gulf of Mexico;
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decrease of $17 million related to the divestiture of the Marcellus Shale upstream assets in second quarter 2017;
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decrease of $15 million due to various cost reduction initiatives offshore West Africa; and
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decrease of $11 million due to a 3.5% lower working interest in the Tamar field, offshore Israel, following the partial divestiture in December 2016.
Lease operating expense decreased in 2016 as compared with 2015 due to the following:
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decrease of $92 million in US onshore, 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:
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increase of $74 million attributable to new production from US onshore and Gulf of Mexico development activities; and
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increase of $38 million related to the acquisition of Eagle Ford Shale and Delaware Basin production third quarter 2015.
Production and Ad Valorem Tax Expense Production and ad valorem taxes increased in 2017 as compared with 2016, primarily due to higher commodity prices and a $28 million US onshore severance tax refund recorded in first quarter 2016 versus a $7 million US onshore severance tax charge recorded in first quarter 2017.
Production and ad valorem taxes decreased in 2016 as compared with 2015, primarily due to lower revenues and a US onshore severance tax refund, both driven by a decline in US commodity prices.
Gathering, Transportation and Processing Expense Gathering, transportation and processing expense remained relatively flat in 2017 as compared with 2016 primarily due to:
•
decrease of $120 million related to the divestiture of the Marcellus Shale upstream assets in second quarter 2017;
partially offset by:
•
increase of $57 million in the DJ Basin due to the shifting of crude oil volumes onto a new export pipeline and contractual increases of pipeline fees; and
•
increase of $47 million related to higher production in the Delaware Basin and Eagle Ford Shale.
Gathering, transportation and processing 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 new Gulf of Mexico projects at Big Bend and Dantzler (which began producing fourth quarter 2015) and Gunflint (which began producing in July 2016).
Unit Rate Per BOE Production expense on a per BOE basis increased in 2017 compared to 2016, primarily due to the increases in certain production expenses noted above. In addition, the Marcellus Shale upstream divestiture resulted in the removal of lower-cost, natural gas-focused sales volumes from our portfolio, while an increase in Delaware Basin and Eagle Ford Shale volumes contributed higher-cost, crude oil-focused sales volumes, thereby increasing our average production expense per BOE. Also, higher commodity prices led to higher production and ad valorem taxes per BOE.
The unit rate of total production expense per BOE decreased for 2016 as compared with 2015, primarily driven by lower production and ad valorem taxes as a result of lower commodity prices and lower lease operating expenses as a result of 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 US onshore assets.
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 includes Newfoundland, Suriname and other new ventures.
(4)
For a discussion of 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 and Undeveloped Leasehold Costs.
(5)
Includes lease rental and other exploration expense.
Exploration expense for 2017 included:
•
leasehold impairment expense related primarily to Gulf of Mexico unproved properties; and
•
dry hole cost of $7 million for the Araku-1 exploration well, offshore Suriname.
Exploration expense for 2016 included:
•
leasehold impairment expense including the write-off of leases and licenses of $58 million for the Gulf of Mexico, $25 million for other international locations, and $10 million for other US onshore; and
•
dry hole cost including costs related to the Silvergate exploratory well, Gulf of Mexico, the Dolphin 1 natural gas discovery, offshore Israel, and certain discoveries offshore West Africa.
Exploration expense for 2015 included:
•
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; and
•
dry hole cost including the Cheetah well, offshore West Africa, and Other International dry hole cost.
Exploration expense included stock-based compensation expense of $7 million in 2017, $10 million in 2016 and $13 million in 2015.
Depreciation, Depletion and Amortization DD&A expense was as follows:
N/M Amount is not meaningful.
(1)
DD&A expense includes accretion of discount on asset retirement obligations of $47 million in 2017, $48 million in 2016, and $43 million in 2015.
Total DD&A expense decreased in 2017 as compared with 2016 due to the following:
•
year-end reserve additions, primarily in US onshore due to enhanced well design and completion techniques in our horizontal drilling program and globally due to positive price revisions. For more information, see reserves discussion in Supplemental Oil and Gas Information (Unaudited);
•
slightly lower sales volumes in the DJ Basin and the impact of certain property divestitures since the second quarter 2016;
•
the Marcellus Shale upstream divestiture in second quarter 2017, which reduced 2017 DD&A expense by $291 million;
•
the sale of a 3.5% working interest in the Tamar field, offshore Israel, in December 2016, which reduced 2017 DD&A expense by approximately $7 million;
•
a reduction in depletable costs of $153 million in the second quarter 2017 due to the reallocation of common asset costs from the Alen field, offshore Equatorial Guinea, to the West Africa natural gas monetization development project, which reduced 2017 DD&A expense by $37 million; and
•
lower sales volumes in the Gulf of Mexico due to natural field decline and reduction in the depletable costs due to downward revisions in estimates of asset retirement costs;
partially offset by:
•
higher US onshore sales volumes of 29 MBoe/d during 2017, including 7 MBoe/d contributed by recently acquired Clayton Williams Energy assets;
•
an increase in sales volumes from the Gunflint development, Gulf of Mexico, which commenced production in July 2016; and
•
higher gross sales volumes from the Tamar field, offshore Israel, due to higher domestic demand.
The unit rate per BOE for 2017 decreased 9% as compared with 2016, primarily due to year-end reserve additions in US onshore, a reduction in the Alen field net book value in second quarter 2017, and certain DJ Basin property divestitures since second quarter 2016. These decreases were offset by the commencement of sales volumes from new crude oil-focused wells in US onshore, as well as the divestiture of natural gas-focused sales volumes from Marcellus Shale upstream assets.
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 the Gulf of Mexico in 2016 and 2015;
•
increase of $134 million related to the acquisition of Eagle Ford Shale and Delaware Basin production in 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, the Aseng and Alen fields, to a lower DD&A rate asset, the Alba field.
The unit rate per BOE for 2016 decreased as compared with 2015, primarily due to lower-cost production volumes from the Tamar and Alba fields and net book value impairments in fourth quarter 2015 related to downward commodity price revisions. The decrease in the unit rate per BOE was partially offset by increased higher-cost production volumes from certain US onshore properties and recently commenced production from Gulf of Mexico assets, including Big Bend, Dantzler and Gunflint.
RESULTS OF OPERATIONS - MIDSTREAM
The Midstream segment owns, operates, develops and acquires domestic midstream infrastructure assets, with current focus areas being the DJ and Delaware Basins.
Major Midstream Activities - Noble Midstream Partners During 2017, major activities included the following:
•
progressed the construction and development of multiple major projects in the DJ and Delaware Basins;
•
began providing crude oil and produced water gathering services to an unaffiliated third party;
•
entered into the Advantage Joint Venture; and
•
entered into the Black Diamond Gathering arrangement with definitive agreements to acquire the Saddle Butte system.
Major Midstream Activities - Noble Energy During 2017, we entered into an agreement to sell our 50% interest in CONE Gathering. We closed the sale in January 2018, receiving cash proceeds of $308 million.
Results of Operations
Highlights for the Midstream segment were as follows:
2017 Midstream Financial Results Included:
•
pre-tax income of $233 million, as compared with pre-tax income of $176 million for 2016; and
•
capital expenditures, excluding acquisitions, of $399 million compared with capital expenditures of $42 million for 2016.
Following is a summarized statement of operations for the Midstream segment:
Midstream Services and Intersegment Revenues The amount of revenue generated by the Midstream business depends primarily on the volumes of crude oil, natural gas and water for which services are provided to our E&P business and to third party customers. These volumes are affected by the level of drilling and completion activity in our areas of upstream operations and by changes in the supply of, and demand for, crude oil, natural gas and NGLs in the markets served directly or indirectly by our midstream assets.
Total revenues, excluding income from equity method investees, for 2017 increased from 2016 by $96 million mainly due to increases of $60 million and $17 million driven by our drilling and completion activities in the DJ and Delaware Basins, respectively, and an increase of $19 million primarily due to commencement of services in the DJ Basin to an unaffiliated third party.
Total revenues, excluding income from equity method investees, for 2016 increased from 2015 by $81 million due to our drilling and completion activities in the DJ Basin.
Income from Equity Method Investees and Other Midstream's share of operations of equity method investees was as follows:
Gathering, Transportation and Processing Expense
Total expense for 2017 increased by $26 million as compared with 2016 due to the following:
•
an increase of $20 million in water services expense due to increased services provided by third parties as well as higher throughput volumes associated with fresh water services; and
•
an increase of $6 million in gathering and facilities operating expense due to higher gathered volumes, as well as due to new systems placed in service and expansion of the gathering infrastructure in 2017.
Total expense for 2016 increased by $19 million as compared with 2015 due to the following:
•
an increase of $12 million in water services expense due to an expanded scope of water services delivered; and
•
an increase of $7 million in gathering systems and facilities operating expense associated with higher gathered volumes as well as general repairs and maintenance of our gathering systems and facilities.
DD&A Expense
Depreciation. depletion and amortization expense for 2017 increased by $11 million as compared with 2016 due to the assets placed in service in 2017, specifically assets associated with the construction of the Greeley Crescent facilities and the Delaware Basin gathering systems, including completion of two CGFs, and expansion of gathering and fresh water systems in the Wells Ranch, East Pony and Mustang IDP areas.
Depreciation, depletion and amortization expense for 2016 increased by $5 million as compared with 2015 due to assets placed in service as a result of the expansion of Wells Ranch CGF in 2016 and in second half 2015 and commissioning of the East Pony crude oil gathering system during 2016.
RESULTS OF OPERATIONS - CORPORATE
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 2017 increased slightly as compared with 2016 primarily due to increased employee costs driven by acquisition activities. The increase in the unit rate per BOE for 2017 as compared with 2016 was due primarily to the decrease in total sales volumes driven by the divestiture of the Marcellus Shale upstream assets. Our total number of employees increased from 2,274 at December 31, 2016 to 2,277 at December 31, 2017.
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 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 expense included stock-based compensation expense of $54 million in 2017, $62 million in 2016 and $50 million in 2015. See Item 8. Financial Statements and Supplementary Data - Note 12. Stock-Based and Other Compensation Plans.
Other Operating Expense See Item 8. Financial Statements and Supplementary Data - Note 2. Additional Financial Statement Information for a discussion of our other operating expense.
Loss (Gain) on Extinguishment of Debt See Item 8. Financial Statements and Supplementary Data - Note 10. Long-Term Debt for discussion of our extinguishment of debt activities.
Interest Expense and Capitalized Interest Interest expense and capitalized interest were as follows:
(1)
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.
The decrease in interest expense in 2017 as compared with 2016 is due to the repayment of our Term Loan Facility due January 6, 2019 (Term Loan Facility) and refinancing of our 8.25% senior notes. See Liquidity and Capital Resources - Capital Structure/Financing Strategy.
The decrease in capitalized interest in 2017 as compared with 2016 is primarily due to the write off of discoveries offshore Equatorial Guinea, lower work in progress amounts related to major long-term projects, including Gunflint, Gulf of Mexico, and the Alba B3 compression project, offshore Equatorial Guinea, offset by a higher work in progress amount related to the Leviathan major long-term development project, offshore Israel.
The increase in interest expense in 2016 as compared with 2015 is primarily due to the impact of senior notes assumed 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, Gulf of Mexico, which were completed in fourth quarter 2015, and Gunflint, 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 US onshore activities.
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 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.
Income Taxes 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 a 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, such as the recent Clayton Williams Energy Acquisition. We endeavor to maintain a strong balance sheet and investment grade credit 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 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. We also evaluate potential strategic farm-out arrangements of our working interests for reimbursement of our capital spending. We may consider repatriations of foreign cash to increase our financial flexibility and fund our capital investment program. See Operating Outlook - Impact of Recent Changes in US Tax Law.
During 2017, we focused on implementation of our portfolio transformation strategy and executed a number of divestitures which generated cash proceeds of over $2 billion. We utilized the proceeds from divestitures to improve our capital structure by repayment of $1.3 billion of borrowing under our Revolving Credit Facility associated with the Clayton Williams Energy Acquisition and $550 million of the remaining balance outstanding under our Term Loan Facility due January 6, 2019. To further strengthen our liquidity profile we performed a series of financing transactions, including retirement of $1 billion of our 8.25% senior notes due March 1, 2019 with the proceeds from issuance of $600 million of 3.85% and $500 million of 4.95% senior notes due January 15, 2028 and August 15, 2047, respectively. Through the repayment of our Term Loan Facility and refinancing of our 8.25% senior notes, we effectively eliminated our near-term debt maturities and lowered our future interest expense by $48 million on an annual basis.
We aim to fund our capital program through operating cash flows and utilize borrowings under our Revolving Credit Facility to fund additional requirements. In 2017, we borrowed and repaid amounts under our Revolving Credit Facility resulting in $230 million remaining outstanding as of December 31, 2017. Funds were utilized for general corporate purposes and for funding of our capital development program. As a result of our 2017 financing activities, we ended 2017 with over $4.5 billion in liquidity, including almost $3.8 billion of availability under our Revolving Credit Facility.
During 2017, we also focused on the continued execution of our integrated midstream strategy through Noble Midstream Partners. In addition to completion of several key infrastructure assets in the DJ and Delaware Basins, as well as continuing significant construction activities in the DJ Basin, Noble Midstream Partners purchased certain midstream assets from Noble Energy for $270 million and expanded its business through entry into certain arrangements to acquire and operate midstream assets. Funding for these transactions included $312 million raised through the issuance of Noble Midstream Partners common units and borrowings under the Noble Midstream Services LLC Revolving Credit Facility (Noble Midstream Services Revolving Credit Facility). As of December 31, 2017, $85 million was outstanding under the Noble Midstream Services Revolving Credit Facility. Funds were used to partially fund 2017 acquisitions and to finance the midstream capital investment program. See Item 8. Financial Statements and Supplementary Data - Note 4. Acquisitions, Divestitures and Merger.
In addition, we received $300 million in payments from foreign operations on an outstanding note payable in 2017, leaving a balance of approximately $434 million that can be repaid without additional US tax impact.
As of December 31, 2017, our outstanding debt (excluding capital lease and other obligations) totaled $6.5 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.
We may from time to time seek to retire or purchase our outstanding senior notes, and/or seek to improve shareholder returns, through cash purchases in the open market, privately negotiated transactions or otherwise. Such activities, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
Sources and Uses of Liquidity
Our operating cash flows are a significant source of our liquidity. In 2017, we experienced strengthening crude oil prices and completed several transformative transactions, repositioning our portfolio from low-margin natural gas-focused assets to high margin crude oil-rich assets, which significantly contributed to the funding of our capital program. Additional sources of funding were available through debt financing activities, including borrowings under our Revolving Credit Facility, and divestment of certain non-strategic oil and gas properties. During 2017, we continued investment in our high cash flow growth assets and, excluding effects of divestitures, increased production levels from prior years, while also increasing per unit profit margins. We also improved our financial profile by reducing our debt balance by $255 million with the use of proceeds from divestments, and decreasing our future interest expense.
For 2018, we will continue our effort to manage our cash flows through capital efficiencies, cost management endeavors, and focusing on the growth of production from high-margin, high-return assets. With such an approach, nearly all of our 2018 capital investment is allocated to our US onshore plays and the Eastern Mediterranean, specifically the Leviathan development project, offshore Israel.
Our 2018 production target is in the range of 343 MBoe/d to 353 MBoe/d and we expect our 2018 capital spending program (excluding acquisitions and Noble Midstream Partners capital), to be in the range of $2.7 to $2.9 billion, or approximately $400 million higher than the 2017 budget. Should WTI and Brent oil prices continue to improve in 2018, we expect future operating cash flows to increase and provide additional sources of liquidity compared to 2017. We expect to support our investment program with operating cash flows resulting from our US onshore and Israel offshore assets, with the remainder of the future capital commitments funded with cash on hand, borrowings under our Revolving Credit Facility and divestment of non-strategic assets.
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 2018. 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.
The table below summarizes our cash, debt balances and available liquidity:
(1)
Total cash at December 31, 2017 includes $18 million cash of Noble Midstream Partners and $37.5 million restricted cash related to the Saddle Butte acquisition that closed in first quarter of 2018. Total cash at December 31, 2016 includes $57 million cash of Noble Midstream Partners, and restricted cash of $30 million related to the Delaware Basin property acquisition that closed in January 2017.
(2)
In 2017, amount available to be borrowed under the Revolving Credit Facility excludes $265 million and $625 million available to be borrowed under the Noble Midstream Services Revolving Credit Facility and Leviathan Term Loan Facility (defined below), respectively, which are not available to Noble Energy for general corporate purposes. In 2016, it excludes $350 million available to be borrowed under the Noble Midstream Services Revolving Credit Facility. See discussion below.
(3)
Total debt includes capital lease and other obligations and excludes unamortized debt discount/premium, and issuance costs.
Our long-term debt (excluding capital lease and other obligations) totaled $6.5 billion at December 31, 2017, with maturities ranging from 2020 to 2097.
(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. Significant changes in our financial position impacting the ratio included $255 million net decrease in debt, $1.9 billion increase in shareholders' equity due to issuance of stock as part of consideration paid for Clayton Williams Energy Acquisition, $312 million increase due to issuance of Noble Midstream Partners Common Units and $100 million increase due to stock based compensation, offset by $190 million decrease in shareholders' equity from dividends paid and $1.1 billion decrease in shareholders' equity from current year net loss.
Cash and Cash Equivalents Our cash is primarily denominated in US dollars and invested in money market funds and short-term deposits with major financial institutions. Approximately $493 million of this cash was attributable to foreign subsidiaries at December 31, 2017.
Revolving Credit Facilities Noble Energy's Revolving Credit Facility of $4.0 billion matures in 2020. The Noble Midstream Services Revolving Credit Facility of $350 million matures in 2021. These facilities are used to fund capital investment programs and acquisitions and may periodically provide amounts for working capital purposes. At December 31, 2017, $230 million was outstanding under the Revolving Credit Facility and $85 million was outstanding under the Noble Midstream Services Revolving Credit Facility, leaving $3.8 billion and $265 million in remaining availability under the respective credit facilities. See Item 8. Financial Statements and Supplementary Data - Note 10. Long-Term Debt.
Leviathan Term Loan Facility On February 24, 2017, we entered into a facility agreement (Leviathan Term Loan Facility) providing for a limited recourse secured term loan facility with an aggregate principal borrowing amount of up to $1 billion, of which $625 million is initially committed. Any amounts borrowed under the Leviathan Term Loan Facility will be available to fund a portion of our share of costs for the initial phase of development of the Leviathan field, offshore Israel. To support the Leviathan development program and to bring first production online by the end of 2019, we may borrow amounts under this facility in the near-term. As of December 31, 2017, no amounts were drawn under this facility.
Term Loan Facility In fourth quarter 2017, we utilized proceeds received from sale of non-strategic acreage in the DJ Basin to repay the remaining outstanding balance of $550 million under this $1.4 billion facility. See Item 8. Financial Statements and Supplementary Data - Note 10. Long-Term Debt.
Senior Notes During 2017 we took steps in managing our long-term debt maturities and liquidity through a series of financing transactions. We issued $600 million of 3.85% senior unsecured notes that will mature on January 15, 2028 and $500 million of 4.95% senior unsecured notes that will mature on August 15, 2047. We used the proceeds to redeem $1 billion of our 8.25% senior unsecured notes which were due March 1, 2019. Through these transactions, we effectively enhanced our financial flexibility and lowered our future cash interest expense by approximately $35 million on an annual basis. See Item 8. Financial Statements and Supplementary Data - Note 10. Long-Term Debt.
Cash Flows
The following table summarizes our cash flows from operating, investing and financing activities:
Operating Activities Cash flows from operating activities include all transactions and other events that are not defined as investing or financing activities and are generally the cash effects of transactions and other events that enter into the determination of net income.
In 2017, net cash provided by operating activities increased as compared with 2016. The change in cash flows from operating activities was primarily the result of higher average realized commodity prices partially offset by lower sales volumes and lower settlements of commodity derivative instruments. The reduction of our sales volumes was mainly driven by the decrease in sale of natural gas as a result of Marcellus Shale upstream asset divestiture. The increase in cash flows from sales was offset by the decrease in settlements proceeds from our commodity derivative instruments. The decrease in cash received from derivative settlements is reflective of an increase in the commodity prices as crude oil and natural gas prices strengthened in the second half of 2017.
Working capital changes resulted in a $150 million operating cash flow decrease in 2017 as compared with a $460 million operating cash flow decrease in 2016. The changes in working capital were primarily due to an increase in our current liabilities, including accrued liabilities and trade payables for drilling and development costs and midstream capital expenditures. The increase in current liabilities was partially offset by the increase in accounts receivable resulting from higher revenues and higher joint interest billing receivables, primarily due to billings associated with Leviathan development project costs.
In 2017, we made cash interest payments related to outstanding debt of $394 million as compared to $412 million in 2016.
In 2016, 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.
In 2016, we made cash interest payments related to outstanding debt of $412 million as compared to $404 million in 2015.
Investing Activities Our investing activities include capital spending on a cash basis for oil and gas properties and midstream infrastructure 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.
In 2017, capital spending for additions to property, plant and equipment, excluding acquisitions, totaled $2.6 billion compared to $1.5 billion in 2016. Approximately $700 million of the increase was due to increased US onshore development activity in response to a more favorable commodity price environment, as well as our focus on development of high margin areas in the DJ and Delaware Basins, and approximately $416 million increase was related to the initial Leviathan project development.
In addition, we used $637 million of cash, net of $21 million of cash acquired, to fund a portion of the consideration paid in the Clayton Williams Energy Acquisition, and we acquired Delaware Basin and other assets for $327 million.
In 2017, we received net cash proceeds of over $2 billion from divestitures of non-core assets, including:
•
$1.0 billion from the Marcellus Shale upstream divestiture;
•
$568 million on the sale of Greeley Crescent and Bronco acreage in the DJ Basin; and
•
$335 million from the sale of mineral and royalty assets.
See Item 8. Financial Statements and Supplementary Data - Note 3. Clayton Williams Energy Acquisition and Note 4. Acquisitions, Divestitures and Merger.
We utilized these sales proceeds to partially fund our Clayton Williams Energy Acquisition, support our development activities in core operational areas, repay outstanding balances under the Term Loan Facility and further strengthen our liquidity position.
Other investing activities provided a net $87 million of cash as of December 31, 2017.
In comparison, capital expenditures in 2016 were $1.5 billion or nearly half of capital spent in 2015 due to the timing of completion of major project development activities in the Gulf of Mexico, DJ Basin and Marcellus Shale. We received approximately $1.2 billion of proceeds from asset divestitures during 2016 as compared with $151 million of proceeds from divestitures during 2015. In 2016, we invested $8 million in CONE Gathering, and received cash distributions of $70 million, accounted for as investing activity, from CONE Midstream.
In 2015, capital spending for property, plant and equipment was $3.0 billion, 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.
Financing Activities Our financing activities include the issuance or repurchase of Noble Energy common stock and Noble Midstream Partners common units, payment of cash dividends to Noble Energy shareholders and cash distributions to Noble Midstream Partners noncontrolling interest owners, and debt transactions.
In 2017, our primary financing activities included $230 million net Revolving Credit Facility borrowings (including the borrowing and repayment of $1.3 billion associated with the Clayton Williams Energy Acquisition), $85 million net Noble Midstream Services Revolving Credit Facility borrowings used primarily to fund an acquisition, a $1.1 billion senior note refinancing, $595 million related to the repayment of Clayton Williams Energy debt, and a $550 million Term Loan Facility repayment. In addition, we received $312 million net proceeds from the issuance of Noble Midstream Partners common units, paid $190 million of cash dividends and $28 million of cash distributions, and made $60 million of capital lease principal payments.
We also received $10 million cash proceeds from the exercise of stock options and purchased 1,031,000 shares of treasury stock with a value of $36 million. These shares included 719,849 shares with a value of $25 million related to vesting of Clayton Williams Energy restricted stock and options in connection with the Clayton Williams Energy Acquisition. The remaining shares were surrendered for the payment of withholding taxes due on the vesting of employee restricted stock awards.
In 2016, we used Term Loan Facility proceeds of $1.4 billion to redeem $1.4 billion of senior notes. We subsequently repaid $850 million of the Term Loan Facility 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 237,000 shares of our common stock ($4 million).
In 2015, 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 491,000 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).
See Item 8. Financial Statements and Supplementary Data - Consolidated Statements of Cash Flows.
Dividends We paid cash dividends totaling 40 cents per common share in 2017, 40 cents per common share in 2016, and 72 cents per common share in 2015. See Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Acquisition, Capital Expenditures and Other Exploration Expenditures
Our capital expenditures (on an accrual basis) were as follows for the year ended December 31, 2017:
(1)
2017 costs include $1.6 billion related to the Clayton Williams Energy Acquisition and $246 million related to the Delaware Basin asset acquisition.
2016 costs relate to properties exchanged with CONSOL upon termination of the Marcellus Shale joint development agreement.
2015 costs include $1.4 billion related to the Rosetta Merger.
(2)
2017 costs include $722 million of proved properties and $63 million of asset retirement obligations acquired in the Clayton Williams Energy Acquisition and $58 million related to the Delaware Basin asset acquisition.
2015 costs of $1.6 billion are related to the Rosetta Merger.
(3)
2017 includes gathering and processing assets of $48 million related to the Clayton Williams Energy Acquisition.
2016 includes Noble Midstream Partners expenditures.
2015 includes midstream assets acquired in the Rosetta Merger.
(4)
2017 includes our contribution to the Advantage Joint Venture, in which Noble Midstream Partners owns a 50% interest.
2015 includes investments in CONE Gathering, in which we previously owned a 50% interest. See Item 8. Financial Statements and Supplementary Data - Note 4. Acquisitions, Divestitures and Merger.
(5)
Relates to US onshore assets.
Total capital expenditures increased during 2017 as compared with 2016 as we pursued strategic portfolio repositioning through a number of acquisitions in our core onshore operational areas in the Delaware Basin and also continued execution of our midstream capital investment program through Noble Midstream Partners. The increase in development capital is in response to the strengthening of commodity prices in the second half of 2017 and is primarily related to drilling and development costs of $1.9 billion incurred mainly in our three US onshore plays (DJ Basin, Delaware Basin and Eagle Ford Shale). Additionally, $416 million of capital expenditures in 2017 was associated with the initial Leviathan project development, while in 2016 we incurred $106 million of project development costs, offshore Israel.
In 2016, total expenditures decreased as compared with 2015, excluding acquisition costs of $3.2 billion related to the Rosetta Merger, as we responded to the lower commodity price environment.
2015 expenditures, excluding the Rosetta Merger, reflect 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.
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, 2017, material off-balance sheet arrangements and transactions that we have entered into included drilling rig contracts, transportation and gathering agreements, operating lease agreements, and undrawn letters of credit, all of which are customary in the oil and gas industry (see cross references to the Notes to the Financial Statements in the table below). Other than these aforementioned arrangements, 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, 2017 that are reflected in the consolidated balance sheets and/or disclosed in the accompanying notes. Unless otherwise noted, all amounts shown are net to our interest.
(1)
References are to the Notes accompanying Item 8. Financial Statements and Supplementary Data.
(2)
Long-term debt excludes capital lease obligations and includes our fixed rate debt and revolving credit facilities balances based on the maturity dates of the facilities.
(3)
Interest payments are based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2017.
(4)
Annual capital lease payments, net to our interest, exclude regular maintenance and operational costs.
(5)
Drilling and equipment obligations represent our working interest share of contractual agreements with third-party service providers to procure drilling rigs and other related equipment for exploratory and development drilling activities. See Counterparty Credit Risk, above.
(6)
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.
(7)
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 and Firm Transportation Commitments.
(8)
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.
(9)
The table excludes deferred compensation liabilities of $197 million as specific payment dates are unknown.
(10)
Asset retirement obligations are discounted.
(11)
Amount represents open commodity derivative instruments that were in a net payable position with the counterparty at December 31, 2017.
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 US onshore assets, such as our Eagle Ford Shale and Delaware Basin properties, are held through continuous development obligations. Therefore, we are contractually obligated to fund a level of development activity in these areas which could be substantial. Failure to meet these obligations may result in the loss of a lease.
Leviathan Natural Gas Project The initial development of the Leviathan field requires substantial infrastructure and capital. We have executed major equipment and installation contracts in support of development activities. As of December 31, 2017, we had entered into contracts with remaining obligations of approximately $464 million, net, to support development and bring first production online by the end of 2019.
Marcellus Shale Firm Transportation Agreements In connection with the Marcellus Shale upstream divestiture, we reduced our firm transportation financial commitments through the transfer of several contracts to the acquirer and retained certain other firm transportation contracts representing a total financial commitment of approximately $1.4 billion, undiscounted, primarily with remaining contract terms of two to 16 years.
One of the retained contracts relates to the Texas Eastern Pipeline, a major interstate natural gas transmission pipeline delivering natural gas to the northeastern US. This contract will be fully utilized through an agreement with the acquirer, whereby the acquirer will deliver quantities of natural gas to us and receive a netback sales price that reflects the value received by us at the sales point, less our effective fixed transportation fees and other expenses, plus a margin. This contract represents an undiscounted financial commitment of approximately $114 million as of December 31, 2017, before offset by the netback agreement, thus reducing the remaining overall commitment noted above.
Two of the retained contracts relate to the Leach Xpress and Rayne Xpress projects. These are interstate natural gas transmission pipelines, which were completed and placed in service in late 2017 and early 2018 to transport production from the Marcellus Shale to markets outside the basin. In fourth quarter 2017, we permanently assigned a portion of our retained capacity to a third party and reduced our remaining undiscounted financial commitment to approximately $418 million. At this time, we are unable to predict with certainty the outcome of our commercialization activities, our ability to utilize retained capacity and the timing of when we may recognize a non-cash exit cost in line with accounting for exit costs associated with these two pipeline projects.
Two additional retained contracts relate to the NEXUS and WB Xpress projects. These projects also include interstate natural gas transmission pipelines designed to transport production from the Marcellus Shale to markets outside the basin. Both projects have received FERC approval, will undergo construction activities and are targeted for in-service late 2018. These contracts represent an undiscounted financial commitment of approximately $870 million.
We are currently engaged in actions to commercialize and address these remaining commitments, which provide for the transportation of approximately 450,000 MMBtu/d of natural gas. Actions include the permanent assignment of capacity, negotiation of capacity release, utilization of capacity through purchase of third party natural gas, and other potential arrangements. In addition, we have a “call” or right to purchase natural gas, priced at a regional index, from the acquirer of the Marcellus Shale upstream assets. This call extends through July 1, 2022 and may be exercised on quantities of the acquirer's production between 431,100 MMBtu/d and 832,645 MMBtu/d.
We expect these actions, some of which may require pipeline and/or FERC approval, to ultimately reduce the financial commitment associated with these contracts. At the date each pipeline is placed in service and our commitment begins, we will evaluate our position. If we determine that we will not utilize a portion, or all, of the contracted pipeline capacity, we will accrue a liability, at fair value, for the net amount of the estimated remaining financial commitment and include the related expense in operating expense in our consolidated statements of operations.
In accordance with US GAAP, we recognize the fair value of a liability for an exit cost in the period in which a liability is incurred. As a result, in second quarter 2017, we accrued non-cash exit costs of $41 million, discounted, relating to our transportation contract with the Appalachian Gateway Project (Gateway). Gateway, another natural gas transmission pipeline, is currently in service. We no longer have production to satisfy this commitment and do not plan to utilize this capacity in the future. In addition, we recorded a $52 million accrual, discounted, in fourth quarter 2017 relating to future commitments to the third party who assumed a portion of our capacity on the Leach Xpress and Rayne Xpress Projects. Both charges are included in loss on Marcellus Shale upstream divestiture in our consolidated statements of operations. See Item 8. Financial Statements and Supplementary Data - Note 17. Commitments and Contingencies.
Other US Transportation Agreements Certain of these contracts require us to make payments for any shortfalls in delivering or transporting minimum volumes under the commitments. As properties are undergoing development activities, we may experience temporary shortfalls until production volumes increase to meet or exceed the minimum volume commitments and will incur expense related to volume deficiencies and/or unutilized commitments. These amounts are recorded as marketing expense in our consolidated statements of operations. We expect to continue to incur expense related to deficiency and/or unutilized commitments in the near-term. Should commodity prices decline or if we are unable to continue to develop our properties as planned, or certain wells become uneconomic and are shut-in, we could incur additional shortfalls in delivering or
transporting the minimum volumes, and we could be required to make payments in the event that these commitments are not otherwise offset. We continually seek to optimize under-utilized assets through capacity release and third-party arrangements, as well as, for example, through the shifting of transportation of production from rail cars to pipelines when we receive a higher netback price. We may continue to experience these shortfalls both in the near and long-term. Item 8. Financial Statements and Supplementary Data - Note 2. Additional Financial Statement Information
OIL Contingency As of December 31, 2017, we accrued approximately $19 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, 2017.
Letters of Credit In the ordinary course of business, we maintain letters of credit and bank guarantees with a variety of banks in support of certain performance obligations of our subsidiaries. Outstanding letters of credit and bank guarantees totaled approximately $90 million at December 31, 2017.
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.
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
Description All of the reserves data in this Annual Report on 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 with numerous uncertainties inherent in estimating underground accumulations of crude oil, natural gas and NGLs, including the projection of future production rates and the expected timing of development expenditures. In addition, economic producibility of reserves is dependent on the commodity prices used in the reserves estimate. Our reserves estimates are based on historical 12-month average commodity prices, unless contractual arrangements designate the price to be used, in accordance with SEC rules.
Reserves estimates impact our financial statements and disclosures, as the estimates are used as an input in calculation of our DD&A expense, assessment of impairment of crude oil and natural gas properties and in preparation of Supplemental Oil and Gas Disclosures.
Judgment and Uncertainties The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Commodity prices and development and production costs are factors used in determining reserves economics and reserves estimates. As a result, our reserves estimates will change in the future due to commodity price volatility and cost changes, as well as due to new information obtained from development drilling and production history.
Effect if Actual Results Differ from Assumptions Our reserves estimates are based on year-end cost, development, production and historical 12-month average price data. 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 due to reservoir performance and new geological and geophysical data. Additionally, increases in future drilling, development, production and abandonment costs and changes in commodity prices may result in future revisions to our reserves.
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 the 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 - Successful Efforts Method of Accounting
Description We account for crude oil and natural gas properties under the successful efforts method of accounting. Application of the successful efforts method results in the capitalization of costs directly related to specific oil and gas reserves when results are positive and 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 non-commercial.
Under the successful efforts method, we capitalize the following:
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Acquisition costs - Costs associated with the purchase, lease or other costs to acquire mineral interests in crude oil and natural gas properties are initially capitalized as unproved property acquisition costs. These costs are commonly attributable to undeveloped leasehold costs or are derived from allocated fair values as a result of business combinations. Continued capitalization of these costs is dependent upon discovery of proved reserves. For example:
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If no proved reserves are discovered after exploration, drilling or lapse of the lease, then costs are impaired. As part of our periodic impairment review, we review undeveloped leasehold costs for potential impairment and if, based upon a change in exploration plans, timing and extent of development activities, availability of capital and suitable rig and drilling equipment, resource potential, comparative economics, changing regulations and/or other factors, an impairment is indicated, we will record impairment expense related to the respective lease.
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. Estimates of cash flows related to probable and possible reserves are reduced by additional risk-weighting factors.
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 to determine the amount of the impairment loss to record.
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If proved reserves are discovered, the related acquisition costs are reclassified to proved properties. 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, adjusted for location and quality differentials, revenues and operating and development costs.
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Exploratory well costs - 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 we have 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 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.
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Development well costs - Costs associated with drilling a development well to obtain access to and to produce proved reserves are capitalized. Development well costs are included in our periodic proved property impairment test noted above.
These costs, along with those for support equipment and facilities, 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 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.
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.
Judgment and Uncertainties The determination of the carrying value of our oil and gas properties includes assessment of impairment and the calculation of amortization expense.
In determination of whether significant unproved crude oil and natural gas properties are impaired, we apply a significant amount of judgment in assessing entity-specific assumptions and assumptions related to the future economic environment, as well as potential impacts of the political and regulatory climate on future development activity. We also 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. In addition, impairment assessment involves a high degree of estimation uncertainty as it requires us to make assumptions and apply judgment to estimate future cash flows related to proved and unproved reserves. Such assumptions include commodity prices, capital spending, production and abandonment costs and reservoir data. Significant judgment is involved in estimating these factors, and they include uncertainties. In cases where probable and possible reserves cash flows are utilized to assess properties for impairment, we use the same pricing, cost and future production assumptions.
We apply significant judgment in determining whether sufficient progress has been made in assessing the reserves and the economic and operational viability of a project to continue capitalization of the exploratory well costs. Such assessment requires consideration of the following factors: commitment of project personnel, costs incurred to assess reserves and potential development, assessment process in progress covering economic, legal, political and environmental aspects of potential development, existence or active negotiations of agreements with governments and venture partners or sales contracts with customers, identification of existing transportation and other infrastructure that is or will be available for the project and other factors. Consideration of these factors requires us to make assumptions and apply judgment to assess industry and economic conditions, as well as our future drilling and development plans. Future changes in our exploratory and drilling activities or economic conditions may result in determination not to pursue certain projects, resulting in future write-offs of the capitalized exploratory well costs.
Calculation of unit-of-production rates is performed on a field-by-field basis and includes estimation of the period-end reserves base and production data for each respective field, including estimates of production for non-operated properties.
Effect if Actual Results Differ from Assumptions We have not made any material changes in the accounting methodology we use to account for our oil and gas properties. 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.
At December 31, 2017, the net book value of our unproved properties includes significant amounts allocated in previous business combinations or acquisitions, including the Clayton Williams Energy Acquisition and the Rosetta Merger. See Supplemental Oil and Gas Information (Unaudited) - Capitalized Costs Relating to Oil and Gas Producing Activities. Unfavorable revisions to our reserves and/or changes in our exploration and development plans or the economic, political or regulatory environment in areas where we operate, or changes in the availability of funds for future activities may result in abandonment and impairment of unproved leases and oil and gas properties. During 2017 we recognized undeveloped leasehold impairment expense of $62 million primarily attributable to Gulf of Mexico leases. We recorded leasehold impairment expense of $93 million in 2016 and $21 million in 2015.
Impairment assessment incorporates expected future cash flows using expected prices, cost rates and future production. For the purpose of impairment testing, we used the five-year strip prices for crude oil and natural gas, with prices subsequent to the fifth year held constant as the benchmark price, unless contractual arrangements designate the price to be used, in the
undiscounted future net cash flows. Capital and operating costs were estimated assuming 0% escalation. Unfavorable changes in these pricing and cost assumptions in the future may result in negative revisions to our reserves and associated cash flows, causing us to record impairment of proved oil and gas properties. We recorded total pre-tax (non-cash) impairment charges of $70 million in 2017, $92 million in 2016, and $533 million in 2015 for proved oil and gas properties. See Item 8. Financial Statements and Supplementary Data - Note 5. Asset Impairments.
At December 31, 2017, the balance of property, plant and equipment included $520 million of suspended exploratory well costs, $510 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 2017, previously capitalized exploratory well costs of $65 million were expensed. See Item 8. Financial Statements and Supplementary Data - Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
Additionally, the carrying value of our oil and gas properties is sensitive to reserves estimates. Unit-of-production rates are revised at least once a year or when the reserves estimates are updated due to major revisions or transactions. The change in unit-of-production rates will affect the carrying value of our oil and gas properties and DD&A expense. If the estimates of proved reserves used in the unit-of-production calculations had been lower by 10% across all properties, 2017 DD&A expense would have increased by approximately $210 million.
Furthermore, a change in groupings of our oil and gas properties for the purpose of the DD&A calculation and impairment review could affect the calculation of unit-of-production rates, DD&A expense and determination of impairment.
Asset Retirement Obligations
Description Our asset retirement obligations (AROs) 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 an ARO liability in the period in which it is incurred, which is when we have an existing legal obligation associated with the retirement of our oil and gas properties and the obligation can be reasonably estimated.
The associated asset retirement cost is capitalized as part of the carrying cost of the oil and gas asset. In determining the fair value of an ARO, we utilize the estimated future cash flows method. The recognition of an ARO requires that management make numerous estimates, assumptions and judgments regarding such factors as: the existence of a legal obligation for an ARO; estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates.
In periods subsequent to initial measurement of the ARO, we recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted future cash flows. Revisions also result in increases or decreases in the carrying cost of the oil and gas asset. Increases in the ARO liability due to passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through DD&A or exploration expense.
Judgment and Uncertainties The process for determining the fair value of an ARO requires us to make subjective judgments and assumptions concerning field life, timing of abandonment activities, cost structures, future labor rates and heavy equipment rental costs, expected inflation rates and changes in the regulatory environment. ARO estimates must be continually revised to reflect changes in these factors. Accordingly, we perform a comprehensive review of ARO estimates semi-annually with the proposed estimates and changes reflected in June 30 and December 31 period-end financial statements.
Effect if Actual Results Differ from Assumptions As of December 31, 2017, our consolidated balance sheet includes ARO liabilities of $875 million. Changes in the fair value of our ARO balance from prior year included both upward and downward revisions primarily due to revised timing and scope of remediation work resulting from assessment of abandonment work performed to-date and current cost experience on retirement obligations in the same operational areas. Future changes in rig rates, labor rates, inflation and interest rates, timing of settlements, scope of work, technological developments and changes in the environmental and regulatory climate may result in revisions to our ARO estimates which can be material to our financial position.
For the year ended December 31, 2017, we recorded $47 million of accretion expense in our consolidated statements of operations. A 10% increase in our ARO estimate as of December 31, 2017 would have impacted net loss by approximately $4 million. See Item 8. Financial Statements and Supplementary Data - Note 9. Asset Retirement Obligations.
Purchase Price Allocations and Resulting Goodwill
Description We occasionally acquire assets and assume liabilities in transactions accounted for as business combinations, such as the Clayton Williams Energy Acquisition in 2017 and 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.
Goodwill is not amortized to earnings but is assessed, at least annually, for impairment at the reporting unit level. A “reporting unit” is the level of reporting at which goodwill is tested for impairment. A reporting unit is an operating segment or one level below an operating segment. Our policy is to conduct a qualitative goodwill impairment assessment by examining relevant events and circumstances which could have a negative impact on our goodwill, such as: macroeconomic conditions; industry and market conditions, including commodity prices; cost factors; overall financial performance; reporting unit dispositions and acquisitions; and other relevant entity-specific events.
If, after assessing the totality of events or circumstances described above, we determine that it is more likely than not that the fair value of our Texas reporting unit is less than its carrying amount, the two-step goodwill test is performed. The two-step goodwill impairment test is also performed whenever events or changes in circumstances indicate that the carrying value may not be recoverable. If, after performing the two-step goodwill test, it is determined that the carrying value of goodwill is impaired, the amount of goodwill is reduced and a corresponding charge is made to earnings in the period in which the goodwill is determined to be impaired.
The two-step impairment test is used to identify potential goodwill impairment and measure the amount of a goodwill impairment loss to be recognized. The first step of the goodwill impairment test, used to identify potential impairment, compares the fair value of a reporting unit with its carrying amount, including goodwill. If the fair value of the reporting unit exceeds its carrying amount, goodwill is not considered to be impaired, and the second step of the test is not required. If necessary, the second step of the impairment test, used to measure the amount of impairment loss, compares the implied fair value of reporting unit goodwill with the carrying amount of that goodwill. If the carrying amount of reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess.
Judgment and Uncertainties Preparing a purchase price allocation requires estimating the fair values of assets acquired and liabilities assumed in a business combination, and we must 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 prepare estimates of such properties based on the fair value of associated crude oil, natural gas and NGL reserves utilizing the income approach.
The primary assumptions used to arrive at estimates of future net cash flows are reserves quantities, commodity prices, and capital and operating costs. 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.
Resulting goodwill from a purchase price allocation must be assessed for impairment. We perform our annual goodwill impairment test at the end of the third quarter of each year unless events or circumstances trigger the need for an interim impairment test.
The first step of the impairment test requires management to make estimates regarding the fair value of the reporting unit to which goodwill has been assigned. If it is necessary to determine the fair value of the Texas reporting unit, we use a combination of the income approach and the market approach.
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Income Approach Under the income approach, the fair value of the Texas reporting unit is estimated based on the present value of expected future cash flows. The income approach is dependent on a number of factors, including estimates of forecasted revenue and operating costs and proved reserves, as well as the success of future exploration for and development of unproved reserves, discount rates and other variables. Negative revisions of estimated reserves quantities, increases in future cost estimates, divestiture of a significant component of the reporting unit, or sustained decreases in crude oil or natural gas prices could lead to a reduction in expected future cash flows and possibly an impairment of all or a portion of goodwill in future periods. Key assumptions used in the discounted cash flow model described above include estimated quantities of crude oil, natural gas and NGL reserves, including both proved reserves and risk-adjusted unproved reserves; estimates of market prices considering forward commodity price curves as of the measurement date; and estimates of operating, administrative and capital costs adjusted for inflation. We discount the resulting future cash flows using a peer group based weighted average cost of capital.
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Market Approach Under the market approach, we estimate the fair value of the Texas reporting unit by comparison to similar businesses whose securities are actively traded in the public market The market approach requires management to make certain judgments about the selection of comparable companies and/or comparable recent company and asset transactions and transaction premiums, thereby creating a group of guideline public companies or transactions, or a peer group, that are engaged in similar operations with comparable risks and returns as our reporting unit.
We use the peer group multiple method for the market approach. Market multiples represent market estimates of fair value based on selected financial metrics. We use earnings before interest, taxes, DD&A and exploration expense (also known as EBITDAX) as our financial metric as we believe it more accurately compares companies using successful efforts and full cost accounting methods, both of which are in our peer group. Determination of fair value under the income approach and the market approach is subject to a high degree of estimation uncertainty as it requires us to make assumptions and apply judgment to various parameters that are sensitive to industry, market and economic conditions. The change in these factors in the future may have a negative impact on estimated future cash flows and the enterprise value of our reporting unit, which could result in future goodwill impairment.
Effect if Actual Results Differ from Assumptions The resulting estimated fair values assigned to assets acquired and liabilities assumed in a purchase price allocation 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. Clayton Williams Energy Acquisition and Item 8. Financial Statements and Supplementary Data - Note 4. Acquisitions, Divestitures and Merger.
As of December 31, 2017, our consolidated balance sheet includes goodwill of $1.3 billion, resulting from the Clayton Williams Energy Acquisition in second quarter 2017. All of our recorded goodwill is assigned to the Texas reporting unit.
We conducted a qualitative and quantitative goodwill impairment assessment as of September 30, 2017 and based on the results of our goodwill impairment test, we concluded that our goodwill at September 30, 2017 was not impaired as the fair value of our Texas reporting unit was in excess of its respective net book value, including goodwill. While not required under Accounting Standards Codification (“ASC”) 350 “Intangibles - Goodwill and Other", we also performed a reconciliation of the determined enterprise fair value as compared to our total company market capitalization. From this additional analysis, we have concluded that the determination of the enterprise fair value closely aligns with our market capitalization.
The estimates used in our goodwill impairment test do not constitute forecasts or projections of future results of operations, but are rather estimates and assumptions based on historical results and assessments of macroeconomic factors affecting the Texas reporting unit as of the valuation date. We believe that our estimates and assumptions are reasonable, but they are subject to change from period to period. Actual results of operations and other factors will likely differ from the estimates used in our discounted cash flow valuation and it is possible that differences could be material. Although we base the fair value estimate of the Texas reporting unit on assumptions we believe to be reasonable, those assumptions are inherently unpredictable and uncertain and actual results could differ from the estimate. In the event of a prolonged industry downturn, commodity prices again become depressed or decline, thereby causing the fair value of the Texas reporting unit to decline, which could result in an impairment of goodwill.
If, in the future, we dispose of a reporting unit or a portion of a reporting unit that constitutes a business, we will include goodwill associated with that business in the carrying amount of the business in order to determine the gain or loss on disposal. The amount of goodwill allocated to the carrying amount of a business can significantly impact the amount of gain or loss recognized on the sale of that business. The amount of goodwill to be included in that carrying amount will be based on the relative fair value of the business to be disposed of and the portion of the reporting unit that will be retained. See Item 8. Financial Statements and Supplementary Data - Note 3. Clayton Williams Energy Acquisition.
Exit Costs
Description We account for exit costs in accordance with ASC 420 - Exit or Disposal Cost Obligations, which requires that a liability for a cost associated with an exit or disposal activity be recognized at fair value in the period in which the liability is incurred. Further, a liability for costs that will continue to be incurred under a contract for its remaining term without economic benefit to the entity shall be recognized at the “cease-use date,” which is defined as the date the entity ceases using the right conveyed by the contract, for example, the right to use a leased property or to receive future goods or services.
During second quarter 2017, in connection with our Marcellus Shale upstream divestiture, we accrued a liability of $41 million, discounted, for exit costs related to our commitment under a retained firm transportation contract and charged the amount to loss on Marcellus Shale upstream divestiture in our consolidated statements of operations.
In addition, we have retained other Marcellus Shale firm transportation contracts, relating to pipeline projects that either were recently placed in service in late 2017/early 2018 or are not yet commercially available to us. These projects that are not yet available will undergo construction and, as these projects become commercially available to us, we will assess, based upon the facts and circumstances, the recognition of any potential exit cost liabilities. If we determine that we will not utilize a portion, or all, of the contracted pipeline capacity, we will accrue a liability, at fair value, for the amount of the estimated remaining financial commitment and include the related expense in operating expense in our consolidated statements of operations.
Any additional exit cost liability will be initially recorded at fair value, and, in periods subsequent to initial measurement, changes to the liability, including changes resulting from revisions to either the timing or the amount of estimated cash flows over the future contract period, will be recognized as an adjustment to the liability in the period of the change.
Judgment and Uncertainties We are required to make significant judgments and estimates regarding the timing and amount of recognition of any additional exit cost liabilities, taking into consideration our commercialization activities and/or the potential occurrence of a cease-use date. We must consider, among other factors, the following:
•
the status of negotiations with counterparties regarding partial or permanent release of our contract commitments;
•
the status of FERC approval of prospective pipeline projects;
•
the timing of commercial availability of approved pipelines upon completion of construction; and
•
the likelihood of capacity utilization through purchase of third party gas, which would reduce unutilized volume commitments.
Additionally, any subsequent changes in interest rates and/or credit risk will affect the discount rate used to calculate the present value of expected future cash flows associated with our existing contract commitments.
There are inherent uncertainties surrounding the recording of exit cost liabilities, and in future periods, a number of factors could significantly change our estimate of such obligations or result in recognition of additional liability
Effect if Actual Results Differ from Assumptions As of December 31, 2017 our financial commitment associated with Marcellus Shale firm transportation contracts was approximately $1.4 billion, undiscounted. We are currently engaged in actions to commercialize and address these remaining commitments, which would reduce our undiscounted financial commitment. We cannot guarantee our commercialization efforts will be successful, and we may recognize substantial future liabilities, at fair value, for the net amount of the estimated remaining commitments under these contracts, with the offsetting charge reducing our earnings. See Item 8. Financial Statements and Supplementary Data - Note 17. Commitments and Contingencies.
Income Tax Expense and Deferred Tax Assets
Description We are subject to income and other taxes in numerous taxing jurisdictions worldwide. For financial reporting purposes, we provide taxes at rates applicable for the appropriate tax jurisdictions. Estimates of amounts of income tax to be recorded involve interpretation of complex tax laws, including the recently enacted Tax Cuts and Jobs Act, as well as assessment of the effects of foreign taxes on domestic taxes, and estimates regarding the timing and amounts of future repatriation of earnings from controlled foreign corporations.
Our consolidated balance sheets include deferred tax assets. Deferred tax assets arise when expenses are recognized in the financial statements before they are recognized in the tax returns or when income items are recognized in the tax returns before they are recognized in the financial statements. Deferred tax assets also arise when operating losses or tax credits are available to offset tax payments due in future years. Ultimately, realization of a deferred tax asset depends on the existence of sufficient taxable income within the future periods to absorb future deductible temporary differences, loss carryforwards or credits.
In assessing the realizability of deferred tax assets, management must consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized.
Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment, and judgment is required in considering the relative weight of negative and positive evidence. We continue to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits and other deferred tax assets will be utilized prior to their expiration. As a result, we may determine, and we have determined in the past, that a deferred tax asset valuation allowance should be established.
Judgment and Uncertainties In assessing facts and circumstances surrounding realizability of our deferred tax assets we are required to apply judgment to determine the weight of both positive and negative evidence in order to conclude whether the valuation allowance is necessary relative to net operating loss carryforwards and other deferred tax assets.
In determining whether a valuation allowance is required for our deferred tax asset balances, we consider, among other factors, current financial position, results of operations, projected future taxable income, tax planning strategies and new tax legislation. Significant judgment is involved in this determination as we are required to make assumptions about future commodity prices, projected production, development activities, profitability of future business strategies and forecasted economics in the oil and gas industry. Additionally changes in the effective tax rate resulting from changes in tax law and our level of earnings may limit utilization of deferred tax assets and will affect valuation of deferred tax balances in the future.
Effect if Actual Results Differ from Assumptions As of December 31, 2017, our US federal income tax net operating loss carryforwards totaled approximately $3.2 billion and foreign net operating loss carryforwards were $662 million. The deferred tax asset associated with our federal and foreign net operating loss carryforwards was approximately $672 million and $187 million, respectively, classified, net, in our consolidated balance sheet within noncurrent deferred income tax liability balance. We currently have a valuation allowance on the deferred tax assets associated with foreign loss carryforwards and foreign tax credits. The valuation allowance on foreign loss carryforwards totaled $183 million in 2017 and $242 million in 2016. The changes to the valuation allowance for the loss carryforwards between periods was attributable to the offset of the valuation allowance against the NOL in a jurisdiction in which we are no longer active. Deemed foreign tax credits of $164 million were recognized along with the additional taxable income associated with the transition tax. A full valuation allowance of $366 million has been recorded against all foreign tax credits based on current interpretation of US Tax Reform law and the expected future utilization of net operating loss carryforwards. Any increase or decrease in a deferred tax asset valuation allowance would impact net income through offsetting changes in income tax expense, which could have a negative impact on our financial position and results of operations. See Item 8. Financial Statements and Supplementary Data - Note 11. Income Taxes.

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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. Due to commodity price volatility, we may use derivative instruments as a means of managing our exposure to price changes.
At December 31, 2017, 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, 2017 with a fair value of $71 million. Based on the December 31, 2017 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 $146 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 $5 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 2018 revenues and results of operations could be adversely affected if commodity prices were to decline. See Item 1A. Risk Factors - Commodity hedging transactions may limit our potential gains or fail to protect us from declines in commodity prices 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, 2017, 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, 2017, 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, 2017 which is included herein.
Noble Energy, Inc.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders
Noble Energy, Inc.:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Noble Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2017 and 2016, 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, 2017, and the related notes (collectively, the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2017, 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) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 20, 2018 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
Basis for Opinion
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 are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ KPMG LLP
We have served as the Company’s auditor since 2002.
Houston, Texas
February 20, 2018
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders
Noble Energy, Inc.:
Opinion on Internal Control Over Financial Reporting
We have audited Noble Energy, Inc.’s and subsidiaries’ (the “Company”) internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of the Company as of December 31, 2017 and 2016, 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, 2017, and the related notes (collectively, the “consolidated financial statements”), and our report dated February 20, 2018 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Company’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 controls over financial reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. 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 of internal control over financial reporting 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.
Definition and Limitations of Internal Control Over Financial Reporting
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.
/s/ KPMG LLP
Houston, Texas
February 20, 2018
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 historical operating areas include: US onshore, primarily the DJ Basin, Delaware Basin, Eagle Ford Shale and Marcellus Shale (until June 2017); US offshore Gulf of Mexico; Eastern Mediterranean; and West Africa. Our Midstream segment owns, operates, develops and acquires domestic midstream infrastructure assets with current focus areas being the DJ and Delaware Basins.
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. 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 revenues in our consolidated statements of operations.
We carry equity method investments at our share of net assets of the equity investees plus loans and advances, and include the investments in other noncurrent assets in our consolidated balance sheets. 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. 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. 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. 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 16. Additional Shareholders' Equity Information.
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 variable interest entity (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 Annual Report 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, exit costs and asset retirement obligations (AROs), 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. Declines in
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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).
Reclassifications
In Note 14. Segment Information, we report a new Midstream segment, established second quarter 2017, and present prior period amounts on a comparable basis. Certain other prior-period amounts have been reclassified to conform to the current period presentation.
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.
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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. Costs related to repair and maintenance activities 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.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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 2017, 2016 and 2015 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 resulting from acquisitions. We assess individually significant unproved properties for impairment on a quarterly basis and recognize a loss at the time of impairment by providing an impairment allowance. In determining whether a significant unproved property is impaired we consider numerous factors including, but not limited to, current exploration plans, favorable or unfavorable exploration activity on the property being evaluated and/or adjacent properties, our geologists' evaluation of the property, and the remaining months in the lease term for the property.
When we have allocated fair value to an unproved property as the result of a transaction accounted for as a business combination, we use a future cash flow analysis to assess the unproved property for impairment. Cash flows used in the impairment analysis are determined based on management’s estimates of crude oil, natural gas and NGL reserves, future commodity prices and future costs to produce the reserves. Cash flow estimates related to probable and possible reserves are reduced by additional risk-weighting factors. Other individually insignificant unproved properties are amortized on a composite method over an average holding period.
We recorded undeveloped leasehold impairment expense in 2017. It is possible that unproved oil and gas properties, including undeveloped leases, could become impaired in the future if commodity prices decline or if there are changes in exploration plans or the timing and extent of development activities. 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 oil and gas properties for sale. At the end of each reporting period, we evaluate 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 4. 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 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 three to thirty years. Other
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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 $49 million in 2017, $84 million in 2016, and $144 million in 2015.
Asset Retirement Obligations AROs consist of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. We recognize the fair value of a liability for an ARO in the period in which it is incurred when we have an existing legal obligation associated with the retirement of our oil and gas properties that can reasonably be estimated, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and gas asset. The asset retirement cost is recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at our credit-adjusted risk-free rate. After initial recording, the liability is increased for the passage of time, with the increase being reflected as accretion expense and included in DD&A expense in the consolidated statements 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
2017 Goodwill As of December 31, 2017, our consolidated balance sheet includes goodwill of $1.3 billion. This goodwill resulted from the acquisition (Clayton Williams Energy Acquisition) of Clayton Williams Energy, Inc. (Clayton Williams Energy) completed on April 24, 2017, and represents the excess of the consideration paid for Clayton Williams Energy over the net amounts assigned to identifiable assets acquired and liabilities assumed. All of our recorded goodwill is assigned to the Texas reporting unit, a component of our US reportable and operating segment. See Note 3. Clayton Williams Energy Acquisition.
Goodwill is not amortized to earnings but is qualitatively assessed for impairment. We assess goodwill for impairment annually during the third quarter, or more frequently as circumstances require, at the reporting unit level. If, based on our qualitative procedures, it is more likely than not that the fair value of the reporting unit is less than its carrying amount, we perform the two-step goodwill impairment test. The two-step goodwill impairment test is also performed whenever events or changes in circumstances indicate that the carrying value may not be recoverable. It is possible that goodwill could become impaired in the future if commodity prices or other economic factors decline. See Recently Issued Accounting Standards - Intangibles - Goodwill and Other: Simplifying the Test for Goodwill Impairment, below, for recently issued accounting guidance regarding future goodwill impairment testing.
We conducted a qualitative goodwill impairment assessment as of September 30, 2017 by examining relevant events and circumstances which could have a negative impact on our goodwill such as: macroeconomic conditions as pertinent to current and expected regulations, industry and market conditions, including overall global and regional supply and demand and impact of such on commodity prices; as well as microeconomic factors relevant to the enterprise such as cost factors that have a negative effect on earnings and cash flows, overall financial performance, reporting unit dispositions, acquisitions, portfolio restructuring and other decisions / circumstances specific to the entity and the reporting unit containing goodwill.
Certain negative indicators as of September 30 2017 included the current onshore service cost inflation resulting in pressure on operating margins impacting our financial results associated with the Texas reporting unit and our stock price. However, we in turn also noted positive indicators such as the current commodity price environment, our current and future drilling and development plans for the Texas assets and synergies we expect from the Clayton Williams Energy Acquisition driven by our unconventional expertise and position in the adjacent properties, which further increase opportunities to drill longer lateral wells on our combined acreage positions, which would contribute to profitability.
Furthermore, we see value creation to be derived from expected midstream build-out opportunities for the gathering, processing and servicing of future production in the Delaware Basin. Having assessed the totality of such events and circumstances described above, we determined that, while there existed certain negative factors, the overall qualitative assessment did not indicate that it is more likely than not that the fair value of the reporting unit is less than its carrying value. However, regardless of the outcome of the qualitative review, we decided to proceed with Step 1 of the impairment test as part of our annual review.
As such, we performed Step 1 of the goodwill impairment test, used to identify potential impairment. The result of the Step 1 test indicated that the fair value of the Texas reporting unit exceeded its carrying value, including goodwill, and therefore, the Texas reporting unit goodwill was not considered to be impaired as of September 30, 2017.
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Notes to Consolidated Financial Statements
If, in the future, we dispose of a reporting unit or a portion of a reporting unit that constitutes a business, we will include goodwill associated with that business in the carrying amount of the business in order to determine the gain or loss on disposal. The amount of goodwill allocated to the carrying amount of a business can significantly impact the amount of gain or loss recognized on the sale of that business. The amount of goodwill to be included in that carrying amount will be based on the relative fair value of the business to be disposed of and the portion of the reporting unit that will be retained.
2015 Goodwill At December 31, 2015, we reviewed our goodwill balance of $779 million 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 goodwill could have fallen below its book value. We determined that the goodwill was fully impaired and recognized a loss of $779 million. This goodwill related primarily to the excess purchase price over amounts assigned to assets acquired and liabilities assumed in the merger of Rosetta Resources Inc. (Rosetta) into a subsidiary of Noble Energy (Rosetta Merger) in 2015 and the Patina Merger in 2005 and was associated with our US reporting unit. During 2015, prior to the impairment, goodwill increased $163 million due to the Rosetta Merger and decreased $4 million due to allocations of goodwill to US onshore properties sold.
For purposes of determining the 2015 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.
Exit Costs We recognize the fair value of a liability for an exit cost in the period in which a liability is incurred. Accrued exit costs at December 31, 2017 relate primarily to estimated costs associated with retained Marcellus Shale firm transportation contracts.
The recognition and fair value estimation of an exit cost liability require that management take into account certain estimates and assumptions such as: the determination of whether a cease-use date has occurred (defined as the date the entity ceases using the right conveyed by the contract, for example, the right to use a leased property or to receive future goods or services); the amount, if any, of economic benefit that is expected to be obtained from a contract through partial use or release; and our estimate of costs that will continue to be incurred under the contract. We record the liability at estimated fair value, based on expected future cash outflows required to satisfy the obligation, net of estimated recoveries, and discounted. Exit costs, and associated accretion expense, are included in operating expense in our consolidated statements of operations. See Note 17. Commitments and Contingencies.
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 include the non-cash portion of gain and loss on commodity derivative instruments, which represents 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 agreement 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 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 restoration and other postretirement benefit plans in the consolidated balance sheets, with a corresponding adjustment to accumulated other comprehensive loss (AOCL), net of tax. The amount remaining in AOCL at December 31, 2017 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
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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 and Impact of Tax Reform Legislation Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized when items of income and expense are recognized in the financial statements in different periods than when recognized in the applicable tax return. Deferred tax assets arise when expenses are recognized in the financial statements before the tax return or when income items are recognized in the tax return prior to the financial statements. Deferred tax assets also arise when operating losses or tax credits are available to offset tax payments due in future years. Deferred tax liabilities arise when income items are recognized in the financial statements before the tax returns or when expenses are recognized in the tax return prior to the financial statements. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date when the change in the tax rate was enacted.
On December 22, 2017, the US Congress enacted the Tax Cuts and Jobs Act (Tax Reform Legislation), which made significant changes to US federal income tax law affecting us. 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.
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 17. Commitments and Contingencies.
We self-insure the medical and dental coverage provided to certain employees, and the deductibles for workers’ compensation, automobile liability and general liability coverage. Liabilities are accrued for self-insured claims, or when estimated losses exceed coverage limits, and when sufficient information is available to reasonably estimate the amount of the loss.
Foreign Currency The US dollar is considered the functional currency for each of our international operations. Transactions that are completed in foreign currencies are remeasured into US dollars and recorded in the financial statements at prevailing foreign exchange rates. Transaction gains or losses are included in other non-operating (income) expense, net in the consolidated statements of operations.
Segment Information Accounting policies for geographical segments are the same as those described above. Transfers between segments are accounted for at market value. We do not consider interest income and expense or income tax benefit or expense in our evaluation of the performance of geographical segments. See Note 14. Segment Information.
Revolving Credit Facilities In accordance with our accounting policy, we net intra-quarter revolving credit facility activity to zero for purposes of consolidated statements of cash flows disclosure.
Recently Issued Accounting Standards
Revenue Recognition In May 2014, the Financial Accounting Standards Board (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.
We continue to evaluate the impact of ASU 2014-09 on our accounting policies, internal controls, and consolidated financial statements and related disclosures. We are performing a review of contracts for each of our revenue streams and developing accounting policies to address the provisions of ASU 2014-09. ASU 2014-09 also includes provisions regarding future revenues and expenses under a gross-versus-net presentation. We are evaluating the impact, if any, on the presentation of future revenues and expenses under this gross-versus-net presentation guidance. Based upon assessments performed to date, we do not expect
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ASU 2014-09 to have an effect on the timing of revenue recognition or our financial position. In addition, we expect the impact regarding gross-versus-net presentation to involve certain presentation changes specifically related to domestic natural gas processing revenues and expenses. The impact of such presentation changes will not impact our net income. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. We will adopt the new standard on January 1, 2018, using the modified retrospective approach.
Compensation - Stock Compensation (Topic 718): Scope of Modification Accounting In May 2017, the FASB issued Accounting Standards Update No. 2017-09 (ASU 2017-09) Compensation - Stock Compensation (Topic 718). The purpose of this update is to provide clarity as to which modifications of awards require modification accounting under Topic 718, whereas previously issued guidance frequently resulted in varying interpretations and a diversity of practice. An entity should employ modification accounting unless the following are met: (1) the fair value of the award is the same immediately before and after the award is modified; (2) the vesting conditions are the same under both the modified award and the original award; and (3) the classification of the modified award is the same as the original award, either equity or liability. Regardless of whether modification accounting is utilized, award disclosure requirements under Topic 718 remain unchanged. ASU 2017-09 will be effective for annual or any interim periods beginning after December 15, 2017. We will adopt the new standard on the effective date of January 1, 2018 and do not believe adoption will have a material impact on our financial statements.
Business Combinations - Clarifying the Definition of a Business In January 2017, the FASB issued Accounting Standards Update No. 2017-01 (ASU 2017-01): Business Combinations - Clarifying the Definition of a Business, that assists in determining whether certain transactions should be accounted for as acquisitions or dispositions of assets or businesses. The amendment provides a screen to be applied to the fair value of an acquisition or disposal to evaluate whether the assets in question are simply assets or if they are a business. If the screen is not met, no further evaluation is needed. If the screen is met, certain steps are subsequently taken to make the determination. ASU 2017-01 is designed to reduce the number of transactions accounted for as business transactions, which take more time and cost more to analyze than asset transactions. ASU 2017-01 is effective for annual and interim periods beginning after December 15, 2017 and is required to be applied prospectively. Our recent Clayton Williams Energy Acquisition was not impacted by this guidance, which we will apply to applicable and qualifying transactions after adoption on January 1, 2018.
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. ASU 2016-18 will be effective for annual and interim periods beginning after December 15, 2017, with earlier application permitted. We will adopt the new standard on the effective date of January 1, 2018 and do not believe adoption will have a material impact on our consolidated statements 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 and Cash Payments, to clarify how eight specific cash receipt and cash payment transactions should be presented in the statement of cash flows. ASU 2016-15 will be effective for annual and interim periods beginning after December 15, 2017, with earlier application permitted. We will adopt the new standard on the effective date of January 1, 2018 and do not believe adoption will have a material impact on our consolidated statements of cash flows and related disclosures as this update pertains to classification of items and is not a change in accounting principle.
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. ASU 2016-02 also requires disclosures designed to give financial statement users information on the 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 will adopt the new standard on the effective date of January 1, 2019. At this time, we cannot reasonably estimate the impact ASU 2016-02 will have on our consolidated financial statements; however, we believe adoption and implementation of ASU 2016-02 will have a material impact on our consolidated balance sheet resulting from an increase in both assets and liabilities relating to leasing activities. As part of our assessment to date, we have formed an implementation work team, prepared educational and training materials pertinent to ASU 2016-02 and have begun contract review and documentation.
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Intangibles - Goodwill and Other - Simplifying the Test for Goodwill Impairment In January 2017, the FASB issued Accounting Standards Update No. 2017-04 (ASU 2017-04): Intangibles - Goodwill and Other - Simplifying the Test for Goodwill Impairment, to simplify how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. Under the new guidance, an entity will perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount, with an impairment charge being recognized for the amount by which the carrying amount exceeds the reporting unit’s fair value. ASU 2017-04 will be effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019, with early adoption permitted. We are currently evaluating the provisions of ASU 2017-04 and have not yet determined if we will early adopt.
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 will adopt the new standard on the effective date of January 1, 2020 and are currently evaluating the effect, if any, that the guidance will have on our consolidated financial statements and related disclosures.
SAB 118 On December 22, 2017, the SEC staff issued Staff Accounting Bulletin No. 118 (SAB 118) to address the application of US GAAP in situations when a registrant does not have the necessary information available, prepared, or analyzed (including computations) in reasonable detail to complete the accounting for certain income tax effects relating to the Tax Reform Legislation. SAB 118 provides guidance for registrants under three scenarios:
1) if measurement of certain income tax effects is complete, registrants must reflect the tax effects of the Tax Reform Legislation for which the accounting is complete;
2) if measurement of certain income tax effects can be reasonably estimated, registrants must report provisional amounts for those specific income tax effects of the Tax Reform Legislation for which the accounting is incomplete but a reasonable estimate can be determined. Provisional amounts or adjustments to provisional amounts identified in the measurement period, as defined, should be included as an adjustment to tax expense or benefit from continuing operations in the period the amounts are determined; and
3) if measurement of certain income tax effects cannot be reasonably estimated, registrants are not required to report provisional amounts for any specific income tax effects of the Tax Reform Legislation for which a reasonable estimate cannot be determined, and would continue to apply ASC 740 - Income Taxes based on the provisions of the tax laws that were in effect immediately prior to the enactment of the Tax Reform Legislation. Registrants would report the provisional amounts of the tax effects of the Tax Reform Legislation in the first reporting period in which a reasonable estimate can be determined.
The SEC staff believes that in no circumstances should the measurement period extend beyond December 22, 2018, one year from the enactment of the Tax Reform Legislation. See Note 11. Income Taxes.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 2. Additional Financial Statement Information
Additional statements of operations information is as follows:
(1)
Certain of our gathering and processing expenses were historically presented as components of other operating expense, net, in our consolidated statement of operations. Beginning in 2017, we changed our presentation to reflect these as components of production expense. These costs are now included within gathering, transportation and processing expense. For the years ended December 31, 2016 and 2015, these costs totaled $17 million and $17 million, respectively, and have been reclassified from other operating expense, net to conform to current presentation.
(2)
See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
(3)
Expense relates to unutilized commitments associated with Marcellus Shale firm transportation contracts. See Note 17. Commitments and Contingencies.
(4)
Amount includes costs for legal and advisory services and employee severance charges.
(5)
Expense relates to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments.
(6)
See Note 3. Clayton Williams Energy Acquisition.
(7)
Expenses are associated with corporate organizational activities.
(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 4. Acquisitions, Divestitures and Merger.
(10)
See Note 9. Asset Retirement Obligations.
(11)
Amount relates to the termination of a rig contract offshore Falkland Islands as a result of a supplier's non-performance.
(12)
See Note 4. Acquisitions, Divestitures and Merger.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Additional balance sheet information is as follows:
(1)
Proceeds relate to the farm-out of a 35% interest in Block 12 offshore Cyprus and were received in January 2017. See Note 4. Acquisitions, Divestitures and Merger.
(2) Assets held for sale at December 31, 2017 include assets in the Greeley Crescent area of the DJ Basin, a 7.5% interest in the Tamar and Dalit fields, offshore Israel, certain non-strategic assets acquired in the Clayton Williams Energy Acquisition and the CONE investments. Assets held for sale at December 31, 2016 include assets in the Greeley Crescent area of the DJ Basin. See Note 4. Acquisitions, Divestitures and Merger.
(3) Balance at December 31, 2017 represents amount held in escrow for the purchase of a midstream entity. Balance at December 31, 2016 represents amount held in escrow for the purchase of certain Delaware Basin properties. See Note 4. Acquisitions, Divestitures and Merger.
(4)
Relates to unutilized commitments associated with Marcellus Shale firm transportation contracts. See Note 4. Acquisitions, Divestitures
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and Merger.
Supplemental statements of cash flow information is as follows:
Note 3. Clayton Williams Energy Acquisition
In January 2017, we announced the Clayton Williams Energy Acquisition, which was approved by Clayton Williams Energy stockholders and closed on April 24, 2017. Acquired assets include 71,000 highly contiguous net acres in the core of the Delaware Basin adjacent to our Reeves County holdings in Texas, and an additional 100,000 net acres in other areas of the United States. In total, the acquisition increased our Delaware Basin position to approximately 117,000 net acres.
See Supplemental Oil and Gas Information (Unaudited), below for discussion of proved reserves acquired. In addition, upon closing of the acquisition, approximately 64,000 net acres in Reeves County, Texas were dedicated to Noble Midstream Partners for infield crude oil, natural gas and produced water gathering.
The acquisition was effected through the issuance of approximately 56 million shares of Noble Energy common stock with a fair value of approximately $1.9 billion and cash consideration of $637 million, for total consideration of approximately $2.5 billion, in exchange for all outstanding Clayton Williams Energy shares, including stock options, restricted stock awards and warrants. The closing price of our stock on the New York Stock Exchange (NYSE) was $34.17 on April 24, 2017. In connection with the transaction, we borrowed $1.3 billion under our Revolving Credit Facility (defined below) to fund the cash portion of the acquisition consideration, redeem outstanding Clayton Williams Energy debt, pay associated make-whole premiums and pay related fees and expenses. See Note 10. Long-Term Debt.
In connection with the Clayton Williams Energy Acquisition, we have incurred acquisition-related costs of $100 million to date, including $64 million of severance, consulting, investment, advisory, legal and other merger-related fees and $36 million of noncash share-based compensation expense, all of which were expensed and are included in other operating expense, net in our consolidated statements of operations. In addition, we received approximately 720,000 shares of common stock from Clayton Williams Energy shareholders for the payment of withholding taxes due on the vesting of their restricted stock and options pursuant to the purchase and sale agreement, resulting in a $25 million increase in our treasury stock balance.
Purchase Price Allocation The transaction has been accounted for as a business combination, using the acquisition method. The following table represents the preliminary allocation of the total purchase price of Clayton Williams Energy to the assets acquired and the liabilities assumed based on the fair value at the acquisition date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill.
Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, analysis of the underlying tax basis of Clayton Williams Energy's assets and liabilities, and final appraisals of assets acquired and liabilities assumed. We expect to complete the purchase price allocation during the 12-month period following the acquisition date, during which time the value of the assets and liabilities, including any goodwill, may be revised as appropriate.
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The following table sets forth our preliminary purchase price allocation:
The fair values of Clayton Williams Energy's identifiable assets are as follows:
In connection with the acquisition, we assumed, and then subsequently retired, all of Clayton Williams Energy's long-term debt at a cost to us of $595 million. The fair value measurements of long-term debt were estimated based on the early redemption prices and represent Level 1 inputs.
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 expected future cash flows to a single discounted amount. Significant inputs to the valuation of crude oil and natural gas properties included estimates of: (i) proved, possible and probable reserves; (ii) production rates and related development timing; (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.
Based upon the preliminary purchase price allocation, we have recognized $1.3 billion of goodwill, all of which is assigned to the Texas reporting unit. As a result of the acquisition, we expect to realize certain synergies which may result from our control of the combined assets as well as future midstream opportunities. The oil-rich geology of these assets, coupled with our unconventional expertise and position in the adjacent properties, significantly enhances our crude oil focus and growth outlook. The acquisition provides for synergies related to administrative and capital efficiencies, and increased opportunities to drill longer lateral wells on our combined acreage positions, enhances our crude oil production base and future crude oil growth potential. It also adds to our midstream assets and provides future midstream build-out opportunities for the gathering, processing and servicing of future production in the basin.
Results of Operations The results of operations attributable to Clayton Williams Energy are included in our consolidated statements of operations beginning on April 24, 2017. We generated revenues of $99 million and a pre-tax loss of $19 million from the Clayton Williams Energy assets during the period April 24, 2017 to December 31, 2017.
Pro Forma Financial Information The following pro forma condensed combined financial information was derived from the historical financial statements of Noble Energy and Clayton Williams Energy and gives effect to the acquisition as if it had occurred on January 1, 2016. The information below 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 Clayton Williams Energy's outstanding shares of common stock and equity awards and conversion of warrants as of the closing
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date of the acquisition, (ii) depletion of Clayton Williams Energy's fair-valued proved crude oil and natural gas properties, and (iii) the estimated tax impacts of the pro forma adjustments.
Additionally, pro forma earnings for the year ended December 31, 2017 were adjusted to exclude acquisition-related costs of $100 million incurred by Noble Energy and $23 million incurred by Clayton Williams Energy. The pro forma results of operations do not include any cost savings or other synergies that we expect to realize from the Clayton Williams Energy Acquisition or any estimated costs that have been or will be incurred by us to integrate the Clayton Williams Energy 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 Clayton Williams Energy Acquisition taken place on January 1, 2016; furthermore, the financial information is not intended to be a projection of future results.
Note 4. Acquisitions, Divestitures and Merger
We maintain an ongoing portfolio management program and have engaged in various transactions over recent years.
Year Ended December 31, 2017
Marcellus Shale Upstream Divestiture On June 28, 2017, we closed the sale of all of our Marcellus Shale upstream assets, which were primarily natural gas properties. The sales price totaled $1.2 billion, and we received $1.0 billion of net cash proceeds, after consideration of customary adjustments, at closing. The sales price includes additional contingent consideration of up to $100 million structured as three separate payments of $33.3 million each. The contingent payments are in effect should the average annual price of the Appalachia Dominion, South Point index exceed $3.30 per MMBtu in the individual annual periods from 2018 through 2020. To date, conditions for the recognition of the contingent consideration are not probable and, therefore, no amounts have been accrued related to the contingent consideration. Proceeds from the transaction were used to repay borrowings resulting from the Clayton Williams Energy Acquisition. See Note 10. Long-Term Debt.
For the year ended December 31, 2017, we recognized a total loss of $2.4 billion, or $1.5 billion after-tax, on this divestiture. The aggregate net book value of the properties sold was approximately $3.4 billion, which included approximately $883 million of undeveloped leasehold cost.
As part of the loss, we accrued non-cash exit costs of $41 million, discounted, relating to a retained transportation contract that is currently in service; however, we no longer have production to satisfy this commitment and do not plan to utilize this capacity in the future. In addition, we recorded a $52 million accrual, discounted, relating to future commitments to a third party who assumed a portion of our retained capacity relating to other pipeline projects. Both charges are included in loss on Marcellus Shale upstream divestiture in our consolidated statements of operations in accordance with accounting for exit or disposal activities under ASC 420 - Exit or Disposal Cost Obligations.
Other retained Marcellus Shale firm transportation contracts relate to pipeline projects that are not yet commercially available to us. These projects that are not yet available will undergo construction and, as these projects become commercially available to us, we will assess, based upon the facts and circumstances, the recognition of any potential exit cost liabilities. It is likely we will incur additional firm transportation costs associated with this exit activity in the future. See Note 2. Additional Financial Statement Information and Note 17. Commitments and Contingencies.
Production from the Marcellus Shale upstream assets represented 204 MMcfe/d of total consolidated sales volumes for the year ended December 31, 2017. See Supplemental Oil and Gas Information (Unaudited), below for discussion of reserves divested.
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Notes to Consolidated Financial Statements
Divestiture of 7.5% Interest in Tamar and Dalit Fields The terms of the Israel Natural Gas Framework (Framework) require us to reduce our current ownership interest in the Tamar and Dalit fields from 32.5% to 25% by year-end 2021. On January 29, 2018, we signed a definitive agreement to divest a 7.5% working interest in each of the fields to Tamar Petroleum Ltd. (TASE: TMRP) (Tamar Petroleum) for cash proceeds of approximately $560 million and 38.5 million shares of Tamar Petroleum. Closing of the transaction is expected by the end of first quarter 2018, subject to satisfactory conclusion of Tamar Petroleum's debt financing and customary approvals, terms and conditions. As of December 31, 2017, the net book value of the 7.5% interest, $293 million, was included in assets held for sale.
Divestiture of Southwest Royalties In January 2018, we signed an agreement to sell our interest in Southwest Royalties, Inc. (Southwest Royalties), a subsidiary of Clayton Williams Energy, and acquired as part of Clayton Williams Energy Acquisition. We received proceeds of $60 million on sale of these assets. As of December 31, 2017, the asset value of these properties of $102 million and associated asset retirement obligation of $42 million were included in assets and liabilities held for sale.
Other US Onshore Transactions We conducted the following additional transactions in 2017:
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US Onshore Divestitures During 2017, we received total proceeds of $671 million resulting from the sale of certain US onshore properties, including $568 million related to divestment of non-core acreage in the DJ Basin. Proceeds were applied to reduce field basis with no recognition of gain or loss. A subsequent closing for certain non-core DJ Basin operated properties, in the amount of approximately $40 million, is expected to occur in mid-2018.
•
Sale of Mineral and Royalty Assets We received $335 million and recognized a gain of $334 million on the sale of mineral and royalty assets covering approximately 140,000 net mineral acres concentrated primarily in Texas, Oklahoma and North Dakota.
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Delaware Basin Acquisition In January 2017, we completed the acquisition of Delaware Basin properties, including seven producing wells, thus increasing our contiguous acreage position in the Reeves County area. Consideration totaled $301 million, approximately $246 million of which was allocated to undeveloped leasehold cost. Initial consideration of $30 million was paid into an escrow account in fourth quarter 2016 and reflected as a restricted asset in our consolidated balance sheet as of December 31, 2016.
Marcellus Shale CONE Gathering Divestiture In December 2017, we signed an agreement to sell our 50% interest in CONE Gathering LLC (CONE Gathering) to CNX Resources Corporation. CONE Gathering owns the general partner of CONE Midstream Partners LP (CONE Midstream), which constructs, owns and operates natural gas gathering and other midstream energy assets in the Marcellus Shale. At December 31, 2017, our total investment of $181 million in the CONE entities was included in assets held for sale. We closed the sale in January 2018, receiving proceeds of $308 million in cash and utilized proceeds to pay down borrowings under the Revolving Credit Facility. We now hold 21.7 million common units representing a 33.5% limited partner interests in CNX Midstream Partners LP (NYSE: CNXM). As of December 31, 2017, the net book value of the limited partner interests was approximately $70 million.
Noble Midstream Partners Asset Contribution On June 26, 2017, Noble Midstream Partners acquired an additional 15% limited partner interest in Blanco River DevCo LP (Blanco River DevCo), increasing its ownership to 40% of the Blanco River DevCo LP, and acquired the remaining 20% limited partner interest in Colorado River DevCo LP (Colorado River DevCo) from us for $270 million.
Blanco River DevCo holds Noble Midstream Partners’ Delaware Basin in-field gathering dedications for crude oil and produced water gathering services on approximately 111,000 net acres, with substantially all of the acreage also dedicated for natural gas gathering. Colorado River DevCo provides services across our development areas in the DJ Basin, including crude oil and natural gas gathering and water services in the Wells Ranch area and crude oil gathering in the East Pony area.
The $270 million consideration consisted of $245 million in cash and 562,430 common units representing limited partner interests in Noble Midstream Partners. Noble Midstream Partners funded the cash consideration with approximately $138 million of net proceeds from a concurrent private placement of common units and $90 million of borrowings under the Noble Midstream Services Revolving Credit Facility (defined below) and the remainder from cash on hand.
Noble Midstream Partners Advantage Joint Venture On April 3, 2017, Noble Midstream Partners and Plains Pipeline, L.P., a wholly owned subsidiary of Plains All American Pipeline, L.P., acquired Advantage Pipeline, L.L.C. (Advantage Pipeline) for $133 million through a newly formed 50/50 joint venture (Advantage Joint Venture). Noble Midstream Partners contributed approximately $67 million of cash to the Advantage Joint Venture, funded by available cash on hand and the Noble Midstream Services Revolving Credit Facility. The Advantage Joint Venture is accounted for under the equity method and is included within our Midstream segment. See Note 7. Equity Method Investments.
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Noble Midstream Partners serves as operator of the Advantage Pipeline System, which includes a 70-mile crude oil pipeline in the Delaware Basin from Reeves County, Texas to Crane County, Texas with 150 MBbls per day of shipping capacity and 490 MBbls of storage capacity.
Noble Midstream Partners Black Diamond Gathering In December 2017, Noble Midstream Partners and Greenfield Midstream, LLC, a portfolio company of EnCap Flatrock Midstream Gathering, formed an entity, Black Diamond Gathering, LLC (Black Diamond Gathering). Black Diamond Gathering subsequently entered into definitive agreements to acquire Saddle Butte Rockies Midstream, LLC and affiliates (collectively, Saddle Butte). The Saddle Butte purchase closed on January 31, 2018, for total cash consideration of approximately $638.5 million. Noble Midstream Partners funded its share of the purchase price with proceeds from its December 2017 common unit offering, cash on hand and borrowings under its unsecured revolving credit facility. See Note 10. Long-Term Debt.
Noble Midstream partners received a 54.4% ownership interest in Black Diamond. Noble Midstream Partners fully consolidates the assets and liabilities of Black Diamond Gathering.
Noble Midstream Partners will serve as operator of Saddle Butte assets which include a large-scale integrated crude oil gathering system in the DJ Basin, consisting of approximately 160 miles of pipeline in operation, 300 MBbls per day of delivery capacity and approximately 210 MBbls of crude oil storage capacity. Saddle Butte has approximately 141,000 dedicated acres from six customers under fixed fee arrangements.
Subsequent Event - Gulf of Mexico Divestiture On February 15, 2018, we announced the Company signed a definitive agreement to sell its assets in the Gulf of Mexico for cash consideration of $480 million. As part of the transaction, the buyer will assume all abandonment obligations associated with the properties which we estimate to approximate $230 million as of December 31, 2017. The net book value of the Gulf of Mexico assets as of December 31, 2017 was approximately $750 million. We expect to incur a charge in early 2018, subject to customary closing adjustments. The transaction is expected to close during second quarter 2018, contingent upon the buyer’s successful implementation of its contemplated restructuring, and will be effective as of January 1, 2018.
Year Ended December 31, 2016
Termination of Marcellus Shale JDA In fourth quarter 2016, we and CONSOL Energy Inc. (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. 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.
DJ Basin 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.
2016 Divestitures During 2016, we engaged in the following sales transactions:
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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, with the remainder of the sale closing in 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 US onshore 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;
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sold our 47% interest in the Alon A and Alon C licenses, which included the Karish and Tanin fields, offshore Israel, 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;
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sold a 3.5% working interest in the Tamar and Dalit fields, offshore Israel, in compliance with the terms of the Framework, which requires us to reduce our ownership interest in the fields 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 fields basis and resulted in the recognition of a $261 million gain; and
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received proceeds of $131 million related to the farm-out of a 35% interest in Block 12, which includes the Aphrodite natural gas discovery, offshore Cyprus. 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.
Year Ended December 31, 2015
2015 Divestitures In 2015, we sold certain non-strategic US onshore properties, receiving proceeds of $151 million, with no gain or loss recorded.
Rosetta Merger On July 20, 2015, Noble Energy completed the Rosetta Merger. 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 US onshore shale positions to our portfolio including approximately 50,000 net acres in the Eagle Ford Shale and 54,000 net acres in the Delaware 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 allocation of the total purchase price of Rosetta to the assets acquired and the liabilities assumed was based on the fair values at the merger date, with the excess of the purchase price over the fair values of the identifiable net assets acquired recorded as goodwill.
Results of Operations The results of operations attributable to Rosetta are included in our consolidated statements 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 of $120 million, inclusive of a $163 million goodwill impairment, from Rosetta were generated from July 21, 2015 to December 31, 2015.
See Supplemental Oil and Gas Information (Unaudited), below, for discussion of proved reserves added or divested in connection with the above transactions.
Note 5. Asset Impairments
Pre-tax (non-cash) asset impairment charges were as follows:
2017 Asset Impairments During 2017, we recorded a non-cash property impairment charge related to our decision not to pursue development of the Troubadour natural gas discovery in the Gulf of Mexico.
2016 Asset Impairments While the Leviathan natural gas development project, offshore Israel, was not formally sanctioned at December 31, 2016, in fourth quarter 2016, we selected the initial development concept for the first phase of development and wrote off $88 million associated with certain development concepts that were not selected.
2015 Asset Impairments During 2015, certain properties were written down to their estimated fair values using a discounted cash flow model. The cash flow model included management’s estimates of future crude oil and natural gas production, commodity prices based on forward commodity price curves or contract prices as of the date of the estimate, operating and development costs, and discount rates. Impairment charges of $481 million resulted from reductions in the forward crude oil prices as of December 31, 2015.
We also recorded impairment charges of approximately $47 million primarily related to revisions in expected field abandonment and other costs for properties in the 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.
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Notes to Consolidated Financial Statements
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. In addition, wells costs associated with a discovery may be charged to impairment expense if we choose not to pursue development activities.
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 the farm-down of a 35% interest in Block 12 offshore Cyprus to a new partner.
(2) The 2017 amount relates to the approval and sanction of the first phase of development of the Leviathan field, offshore Israel.
The 2015 amount relates primarily to US onshore exploration activity.
(3) Capitalized exploratory well costs charged to expense are included within exploration or impairment expense in our consolidated statements of operations.
The 2017 amount relates primarily to the write-off of costs associated with the Troubadour natural gas discovery, Gulf of Mexico, for which we chose not to pursue development activities. See Note 5. Asset Impairments.
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 the Silvergate exploratory well in the Gulf of Mexico. The well did not encounter commercial hydrocarbons and was plugged and abandoned.
The 2015 amount relates primarily to a property in northeast Nevada. After assessing its commercial viability in the current commodity price environment, we elected to discontinue exploration efforts.
The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced, and the number of projects that have been capitalized for a period greater than one year:
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The following table provides a further aging of those exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling as of December 31, 2017:
Undeveloped Leasehold Costs We reclassify undeveloped leasehold costs to proved property costs when proved reserves, including PUDs, become attributable to the property as a result of our exploration and development activities. On the other
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hand, if, based upon a change in exploration plans, timing and extent of development activities, 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 impairment expense related to the respective leases or licenses.
As of December 31, 2017, we had remaining undeveloped leasehold costs, to which proved reserves had not been attributed, of$2.8 billion, including $1.6 billion related to Delaware Basin assets acquired in the Clayton Williams Energy Acquisition in 2017, and $1.1 billion and $149 million attributable to Delaware Basin and Eagle Ford Shale assets, respectively, acquired in the Rosetta Merger in 2015. Undeveloped leasehold costs were derived from allocated fair values as a result of business combinations or other purchases of unproved properties and are subject to impairment testing.
The remaining balance of undeveloped leasehold costs as of December 31, 2017 included $44 million related to Gulf of Mexico unproved properties and $53 million related to international unproved properties. These costs pertain to acquired leases or licenses that are subject to expiration over the next several years unless production is established on units containing the acreage. These costs are evaluated as part of our periodic impairment review.
During 2017, we completed geological evaluations of certain Gulf of Mexico leases and licenses and leases and licenses associated with other international unproved properties. We determined that several leases and licenses should be relinquished or exited. As a result, we recognized undeveloped leasehold impairment expense of $62 million primarily attributable to Gulf of Mexico leases. We recorded leasehold impairment expense of $93 million in 2016 and $21 million in 2015. This expense is included in exploration expense in the consolidated statements of operations.
Note 7. Equity Method Investments
Equity Method Investments Investments accounted for under the equity method consist primarily of the following:
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50% interest in Advantage Pipeline, which owns and operates a 70-mile crude oil pipeline in Texas (See Note 4 - Acquisitions, Divestitures and Merger);
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50% interest in CONE Gathering, which owns and operates natural gas gathering facilities servicing the Marcellus Shale (See Note 4 - Acquisitions, Divestitures and Merger);
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34% interest in CONE Midstream, a public master limited partnership, which constructs, owns and operates natural gas gathering and other midstream energy assets in the Marcellus Shale;
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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 (LPG) processing plant in Equatorial Guinea.
CONE Midstream Dropdown Transaction In fourth quarter 2016, CONE Midstream completed an acquisition of midstream assets (dropdown) from CONE Gathering. CONE Gathering subsequently distributed $70 million cash and additional CONE Midstream common units to us.
Equity method investments are as follows:
(1)
CONE Investments include CONE Midstream and CONE Gathering. The investments are included in assets held for sale at December 31, 2017.
Other At December 31, 2017, consolidated retained earnings included $90 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, 2017. 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, 2017.
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.
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.
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Notes to Consolidated Financial Statements
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, 2017, we had entered into the following crude oil derivative instruments:
(1)
We have entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma. The weighted average differential represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes covered by the basis swap contracts.
As of December 31, 2017, we had entered into the following natural gas derivative instruments:
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Fair Value Amounts and Gains and Losses on Derivative Instruments The fair values of derivative instruments in our consolidated balance sheets were as follows:
(1) See Note 1. Summary of Significant Accounting Policies - Derivative Instruments and Hedging Activities for a discussion of our netting policy.
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.
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Notes to Consolidated Financial Statements
Note 9. Asset Retirement Obligations
Asset retirement obligations (AROs) consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. Changes in AROs were as follows:
Year Ended December 31, 2017 Liabilities incurred include $63 million related to the Clayton Williams Energy Acquisition and $31 million primarily for other US onshore wells and midstream facilities placed into service.
Liabilities settled include $43 million related to abandonment of US onshore properties, $19 million related to properties sold in the Greeley Crescent (DJ Basin) acreage divestiture, $12 million related to properties sold in the Marcellus Shale upstream divestiture and $8 million related to other offshore domestic and international properties.
Revisions of estimates include a $42 million decrease related to changes in cost and timing associated with the North Sea abandonment project and a $38 million decrease for US onshore and Gulf of Mexico properties, partially offset by an increase of $15 million for West Africa.
In 2017, we also transferred $42 million and $12 million of ARO liabilities associated with Southwest Royalties and Tamar field, offshore Israel, respectively, to liabilities associated with assets held for sale. Refer to Item 8. Financial Statements and Supplementary Data - Note 4. Acquisitions, Divestitures and Merger.
Year Ended December 31, 2016 Liabilities incurred were due to new wells and facilities placed into service for US onshore, 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 Gulf of Mexico properties, $49 million related to US onshore properties abandoned or sold, $5 million related to offshore Israel properties and $1 million related to the North Sea.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 10. Long-Term Debt
Our debt consists of the following:
(1)
In fourth quarter 2017, we repaid $550 million of borrowings under the Term Loan Facility and $18 million of our outstanding Senior Notes due June 1, 2022.
(2)
In third quarter 2017, we redeemed all of our Senior Notes due March 1, 2019 and issued Senior Notes due January 15, 2028 and August 15, 2047.
(3)
Includes $8 million of Senior Notes due June 1, 2024 and $84 million of Senior Debentures due August 1, 2097. The weighted average interest rate for these instruments is 7.13%.
(4)
The reduction from 2016 includes $41 million related to other obligations for drilling commitments assumed by the acquirer of the Marcellus Shale upstream assets and $60 million of capital lease principal payments.
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 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.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
The Revolving Credit Facility requires that our total debt to capitalization ratio (as defined in the Revolving Credit Facility), 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, 2017, we were in compliance with our debt covenants.
The Revolving Credit Facility is available for general corporate purposes. Certain lenders that are a party to the Revolving Credit Facility 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 (Noble Midstream Services), a subsidiary of Noble Midstream Partners, entered into a credit agreement for a $350 million revolving credit facility (Noble Midstream Services Revolving Credit Facility). The Noble Midstream Services 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 Services 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 Services 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 London interbank offered rate (LIBOR) for an interest period of one month plus 1.00%; or
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in the case of LIBOR borrowings, the offered rate per annum for deposits of dollars for the applicable interest period.
The Noble Midstream Services 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 Services Revolving Credit Facility). All obligations of Noble Midstream Services, as the borrower under the Noble Midstream Services 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.
On January 31, 2018, in connection with the acquisition of Saddle Butte, Noble Midstream Partners drew an additional $300 million under the Noble Midstream Services Revolving Credit Facility and partially exercised the accordion feature, increasing the commitments under the credit agreement to $530 million.
Senior Notes Issuance and Completed Tender Offer On August 15, 2017, we issued $600 million of 3.85% senior unsecured notes that will mature on January 15, 2028 and $500 million of 4.95% senior unsecured notes that will mature on August 15, 2047. Interest on the 3.85% senior notes and 4.95% senior notes is payable semi-annually beginning January 15, 2018 and February 15, 2018, respectively. We may redeem some or all of the senior notes at any time at the applicable redemption price, plus accrued interest, if any. The senior notes were issued at a discount of $4 million and debt issuance costs incurred totaled $11 million, both of which are reflected as a reduction of long-term debt and are amortized over the life of the notes. Proceeds of $1 billion from the issuance of senior notes were used solely to fund the tender offer and the redemption of $1 billion of our 8.25% senior notes due March 1, 2019. As a result, we paid a premium of $96 million to the holders of the 8.25% senior notes and recognized a loss of $98 million in third quarter 2017, which is reflected in other non-operating (income) expense in our consolidated statements of operations.
Leviathan Term Loan Facility On February 24, 2017, Noble Energy Mediterranean Ltd. (NEML), a wholly-owned subsidiary of Noble Energy, entered into a facility agreement (Leviathan Term Loan Facility) which provides for a limited recourse secured term loan facility with an aggregate principal borrowing amount of up to $1.0 billion, of which $625 million is initially committed. Any amounts borrowed under the Leviathan Term Loan Facility will be available to fund a portion of our share of costs for the initial phase of development of the Leviathan field offshore Israel.
Any amounts borrowed will be subject to repayment on a quarterly basis following production startup for the first phase of development, which is targeted for the end of 2019. Repayment will be in accordance with an amortization schedule set forth in the facility agreement, with a final balloon payment of no more than 35% of the loans outstanding. The Leviathan Term Loan Facility matures on February 23, 2025 and we can prepay borrowings at any time, in whole or in part, without penalty. The Leviathan Term Loan Facility contains customary representations and warranties, affirmative and negative covenants, and
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events of default and also includes a prepayment mechanism that reduces the final balloon amount if cash flows exceed certain defined coverage ratios.
Any amounts borrowed will accrue interest at LIBOR, plus a margin of 3.50% per annum prior to production startup, 3.25% during the period following production startup until the last two years of maturity, and 3.75% during the last two years until the maturity date. We are also required to pay a commitment fee equal to 1.00% per annum on the unused and available commitments under the Leviathan Term Loan Facility until the beginning of the repayment period.
The Leviathan Term Loan Facility is secured by a first priority security interest in substantially all of NEML's interests in the Leviathan field and its marketing subsidiary, and in assets related to the initial phase of the project. All of NEML’s revenues from the first phase of Leviathan development will be deposited in collateral accounts, and we will be required to maintain a debt service reserve account for the benefit of the lenders under the Leviathan Term Loan Facility. Once servicing accounts are replenished and debt service made, all remaining cash will be available to us and our subsidiaries.
Term Loan Facility and Completed Tender Offers On January 6, 2016, we entered into a term loan agreement (Term Loan Facility), which provided for a three-year term loan facility for a principal amount of $1.4 billion. Provisions of the Term Loan Facility were consistent with those in the Revolving Credit Facility. Borrowings under the Term Loan Facility could be prepaid prior to maturity without premium. The Term Loan Facility accrued 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 ranged from 10 basis points to 75 basis points depending upon our credit rating, or (b) a LIBOR, plus a margin that ranged from 100 basis points to 175 basis points depending upon our credit rating.
Borrowings under the Term Loan Facility were used solely to fund tender offers for approximately $1.38 billion of notes assumed in the Rosetta Merger in 2015. As a result of the tender offers, we recognized a gain of $80 million in first quarter 2016 which is reflected in other non-operating (income) expense in our consolidated statements of operations. In fourth quarter 2016, we prepaid $850 million of the amount outstanding under the Term Loan Facility from cash on hand. In fourth quarter 2017, we repaid the remaining outstanding balance of $550 million under this facility using proceeds received from the sale of non-core Greeley Crescent and Bronco acreage in the DJ Basin.
Fair Value of Debt See Note 13. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of debt.
Capital Lease and Other Obligations The amount of the capital lease obligation is based on the discounted present value of future minimum lease payments, and therefore does not reflect future cash lease payments. Amounts due within one year equal the amount by which the capital lease obligation is expected to be reduced during the next 12 months. See Note 17. Commitments and Contingencies for future capital lease payments.
Annual Debt Maturities Annual maturities of outstanding debt, excluding capital lease payments, as of December 31, 2017 are as follows:
Note 11. Income Taxes
Recent Changes in US Tax Law On December 22, 2017, the US Congress enacted the Tax Reform Legislation, which made significant changes to US federal income tax law, including a reduction in the federal corporate tax rate to 21% effective January 1, 2018. Under US GAAP, we are required to recognize the effect of a rate change on deferred tax assets and liabilities in the period in which the tax rate change is enacted. Therefore, the rate change enacted by the Tax Reform Legislation resulted in the recognition of a deferred tax benefit of $500 million at December 31, 2017.
Further, the Tax Reform Legislation provides for a transition tax (toll tax) on a one-time “deemed repatriation” of accumulated foreign earnings for the year ended December 31, 2017. Based on current interpretations of the law, we have recognized additional taxable income of $767 million associated with the transition tax, which is fully offset by current year net operating
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Notes to Consolidated Financial Statements
losses and have recorded corresponding deemed foreign tax credits of $164 million, against which we have recorded a full valuation allowance.
The Tax Reform Legislation also repealed corporate alternative minimum tax (AMT) for tax years beginning January 1, 2018, and provides that existing AMT credit carryovers are refundable beginning in 2018. We have approximately $3 million of AMT credit carryovers that are expected to be fully refunded by 2022.
In addition, the Tax Reform Legislation preserves deductibility of intangible drilling costs and provides for 100% bonus depreciation on tangible personal property expenditures through 2022. The bonus depreciation percentage is phased down from 100% beginning in 2023 to 0% for years after 2026.
The Tax Reform Legislation is a comprehensive bill containing other provisions, such as limitations on the deductibility of interest expense and certain executive compensation, that are not expected to materially affect us. The ultimate impact of the Tax Reform Legislation may differ from our estimates due to changes in interpretations and assumptions made by us, as well as additional regulatory guidance that may be issued. In particular, our estimate of the impact of the toll tax is a provisional amount, based on current legal interpretations. This amount may be adjusted in future periods, as an adjustment to income tax expense or benefit, in the period in which the final amounts are determined.
Income Tax Disclosures
Components of income (loss) from operations before income taxes are as follows:
The income tax provision (benefit) consists of the following:
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Notes to Consolidated Financial Statements
A reconciliation of the federal statutory tax rate to the effective tax rate is as follows:
(1) See Recent Changes in US Tax Law, above. Rate will decrease to 21.0% for fiscal year 2018. In addition, see discussion regarding accumulated undistributed foreign earnings above.
Deferred tax assets and liabilities resulted from the following:
(1) At December 31, 2017, we reversed the deferred tax liability associated with the removal of the assertion of indefinitely reinvested earnings, resulting in recognition of a deferred tax benefit of $240 million.
Net deferred tax assets and liabilities were classified in the consolidated balance sheets as follows:
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Deferred Tax Assets Our estimated US federal income tax net operating loss (NOL) carryforwards totaled approximately $3.2 billion at December 31, 2017. Included in the resulting deferred tax assets are acquired NOLs associated with the Clayton Williams Energy Acquisition in 2017 and the Rosetta Merger in 2015.
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, current financial position, results of operations, projected future taxable income and tax planning strategies as well as current and forecasted business economics in the oil and gas industry. Based on the level of historical taxable income and projections for future taxable income, we believe it is more likely than not that we will realize the benefits of these NOL carryforwards. However, 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.
We currently have a valuation allowance on the deferred tax assets associated with foreign loss carryforwards and foreign tax credits. The valuation allowance on foreign loss carryforwards totaled $183 million in 2017 and $242 million in 2016. The changes to the valuation allowance for the loss carryforwards between periods was attributable to the offset of the valuation allowance against the NOL in a jurisdiction in which we are no longer active. Deemed foreign tax credits of $164 million were recognized along with the additional taxable income associated with the transition tax. A full valuation allowance of $366 million has been recorded against all foreign tax credits based on current interpretation of the Tax Reform Legislation and the expected future utilization of NOL carryforwards.
Clayton Williams Energy Acquisition On April 24, 2017, we completed the Clayton Williams Energy Acquisition. For federal income tax purposes, the transaction qualified as a tax free merger and we acquired carryover tax basis in Clayton Williams Energy's assets and liabilities. After the fair market valuation, we have currently recorded an opening balance sheet deferred tax liability of $307 million, adjusted for the new US statutory tax rate, which includes a deferred tax asset for federal pre-tax net operating losses of approximately $450 million. The merger resulted in a change of control for federal income tax purposes, and the NOL usage will be subject to an annual limitation in part based on Clayton Williams Energy's value at the date of the merger. We anticipate full utilization of the total NOL prior to expiration.
Accumulated Undistributed Earnings of Foreign Subsidiaries 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.
During 2016, we reviewed capital requirements and foreign cash positions, and reduced the deferred tax liability associated with unremitted earnings, net of foreign tax credits, to $240 million as of December 31, 2016.
In 2017, as a result of Tax Reform Legislation, which establishes a new territorial tax regime, the deferred tax liability recorded as of December 31, 2016 was reversed, resulting in a deferred tax benefit of $240 million for the year ended December 31, 2017. We do not expect a withholding tax impact upon actual distribution of earnings and as such have not recorded any additional tax associated with the unremitted earnings.
Effective Tax Rate Our effective tax rate increased in 2017 as compared with 2016 primarily due to the recognition of a deferred tax benefit related to the Tax Reform Legislation. The deferred tax benefit resulted from the revaluation of the ending deferred tax liability at the reduced future tax rate and the transition to the new territorial tax regime.
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, and the 2015 impact of foreign dividend repatriation and goodwill impairment.
Israeli Tax Law Effective December 21, 2016, the Israeli government decreased the corporate income tax rate from 25% to 24% for 2017 and announced a further rate decrease from 24% to 23% effective January 2018. The change decreased the deferred tax expense for 2017 by $12 million.
Furthermore, our Israeli operations are subject to the Natural Resources Profits Taxation Law, 2011 (the Law), which imposes a separate additional tax on profits from oil and gas activities (Profits Tax). The Profits Tax is calculated by dividing net accumulated revenue generated by each separate project by its cumulative investments as defined within the Law. Once the revenue factor (R Factor) reaches 1.5, a tax rate of 20% is imposed; as the ratio increases to a maximum of 2.3, the Profits Tax increases progressively up to a maximum rate of 50%. The Profits Tax provides for a corporate tax rate adjustment based on the corporate income tax rate, which is currently 23%. To the extent the corporate income tax rate exceeds 18%, a reduction in the Profits Tax rate is calculated. At the current corporate tax rate, the Profits Tax rate is 46.8%. The Profits Tax is deductible for corporate Israeli tax purposes. Our Tamar and Leviathan projects are both subject to the Profits Tax and are expected to pay at the maximum rate.
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Notes to Consolidated Financial Statements
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 - 2014, Israel - 2015 and Equatorial Guinea - 2012.
Our policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense.
A reconciliation of our beginning and ending amounts of unrecognized tax benefits follows:
The changes to our unrecognized tax benefits during 2017 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 2017, we recognized and accrued a de minimis amount of interest and no penalties.
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.
2017 Long-Term Incentive Plan On April 25, 2017, our stockholders approved the Noble Energy, Inc. 2017 Long-Term Incentive Plan (the 2017 Plan). Upon stockholder approval, the 2017 Plan superceded and replaced the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan, as amended (the 1992 Plan) which was frozen so that no future grants would be made under the 1992 Plan. The 1992 Plan continues to govern awards that were outstanding as of the date of its suspension, which remain in effect pursuant to their terms. Under the 2017 Plan, the Compensation, Benefits and Stock Option Committee of the Board of Directors (the Committee) may grant stock options, stock appreciation rights, restricted stock, restricted stock units, performance awards, stock awards and other incentive awards to our officers or other employees and those of our subsidiaries. The maximum number of shares that may be granted under the 2017 Plan is 29 million shares of common stock. At December 31, 2017, 28,987,609 shares of our common stock were reserved for issuance, including 28,972,832 shares available for future grants and awards, under the 2017 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 2017 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 2017 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. Performance share awards 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.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
2015 Stock Plan for Non-Employee Directors The 2015 Stock Plan for Non-Employee Directors of Noble Energy, Inc., as amended (the 2015 Plan) provides for grants of stock options and awards of restricted stock to our non-employee directors. The 2015 Plan superseded and replaced the 2005 Stock Plan for Non-Employee Directors of Noble Energy, Inc. The total number of shares of our common stock that may be issued under the 2015 Plan is 708,996. At December 31, 2017, 674,025 shares of our common stock were reserved for issuance, including 463,096 shares available for future grants and awards, under the 2015 Plan.
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.
•
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 $4 million in 2017, $10 million in 2016 and $7 million in 2015. As of December 31, 2017, $21 million of compensation cost related to unvested stock options granted under the Plans remained to be recognized. The cost is expected to be recognized over a weighted-average period of 1.3 years. We issue new shares of our common stock to settle option exercises. Dividends are not paid on unexercised options.
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Notes to Consolidated Financial Statements
Restricted Stock Awards Awards of time-vested restricted stock (shares subject to service conditions) are valued at the price of our common stock at the date of award. The fair 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 US 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:
(1)
During 2017, we awarded approximately 1.9 million shares of restricted stock for the conversion of Clayton Williams Energy shares into Noble Energy shares as part of the Clayton Williams Energy Acquisition. All awards subsequently vested during 2017. These awards are included in the above table. See Note 3. Clayton Williams Energy Acquisition.
The total fair value of restricted stock that vested was $34 million in 2017, $24 million in 2016, and $62 million in 2015.
The weighted average award-date fair value of restricted stock awarded was $35.45 per share in 2017, $29.99 per share in 2016, and $35.53 per share in 2015.
As of December 31, 2017, $41 million of compensation cost related to all of our unvested restricted stock awarded under the Plans remained to be recognized. The cost is expected to be recognized over a weighted-average period of 1.4 years. Common stock dividends accrue on restricted stock awards and are paid upon vesting. We issue new shares of our common stock when awarding restricted stock.
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 and assumed 500,000 simulations, 38% expected volatility and a risk-free rate of 0.9%.
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, 2017, we had accrued a liability of $10 million related to the phantom units. No phantom units were awarded in 2017.
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Notes to Consolidated Financial Statements
Phantom unit activity was as follows:
As of December 31, 2017, $6 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 1.1 years. The total fair value of phantom units that vested in 2017 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 $31 million in 2017, $32 million in 2016, and $35 million in 2015.
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.
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 400,000 shares, or 85%, of our common stock held in respect of one nonqualified deferred compensation plan at December 31, 2017 were attributable to a member of our Board of Directors. The shares are being distributed in equal installments over the next two years. Distributions of 200,000 shares were made in each of 2017, 2016 and 2015. In addition, plan participants sold 1,238 shares of our common stock in 2017, 1,009 shares in 2016, and 1,009 shares in 2015. Proceeds were invested in mutual funds and/or distributed to plan participants. Distributions to plan participants were valued at $21 million in 2017, $22 million in 2016 and $18 million in 2015.
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 $9 million in 2017, $11 million in 2016 and $(12) million in 2015.
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Notes to Consolidated Financial Statements
We also maintain other nonqualified deferred compensation plans for the benefit of certain of our employees. Deferred compensation liabilities of $116 million and $121 million were outstanding at December 31, 2017 and 2016, 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 sheets. The following methods and assumptions were used to estimate the fair values:
Cash, Cash Equivalents, Accounts Receivable and Accounts Payable The carrying amounts approximate fair value due to the short-term nature or maturity of the instruments.
Mutual Fund Investments Our mutual fund investments 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, enhanced swaps and basis swaps. We estimate the fair values of these instruments using published forward commodity price curves as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. In addition, for collars, we estimate the option values of the put options sold and the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract terms. See Note 8. Derivative Instruments and Hedging Activities.
Deferred Compensation Liability The value is dependent upon the fair values of mutual fund investments and shares of our common stock held in a rabbi trust. See Mutual Fund Investments above.
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.
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 2017, 2016, and 2015, 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.
Marcellus Shale Firm Transportation Liability As of December 31, 2017, we had recorded a $90 million liability representing the discounted present value of our remaining obligation under firm transportation contracts. See Note 17 - Commitments and Contingencies.
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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 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 commodities 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. Costs associated with abandoned properties were completely written off. 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.
At December 31, 2017, our variable-rate, non-public debt included the Revolving Credit Facility and the Noble Midstream Services Revolving Credit Facility. The fair value is estimated based on significant other observable inputs. As such, we consider the fair value of these facilities to be a Level 2 measurement on the fair value hierarchy. See Note 10. Long-Term Debt.
Fair value information regarding our debt is as follows:
(1)
Excludes unamortized discount, premium, debt issuance costs and capital lease obligations.
Note 14. Segment Information
During second quarter 2017, as a result of the strategic changes in our US onshore portfolio, we established our Midstream business as a new reportable segment. The Midstream segment, which includes the consolidated accounts of Noble Midstream Partners, additional US onshore midstream assets and US onshore equity method investments, was previously reported within the United States reportable segment. As a result, we now have the following reportable segments: United States (US onshore and Gulf of Mexico); Eastern Mediterranean (Israel and Cyprus); West Africa (Equatorial Guinea, Cameroon and Gabon); Other International (Newfoundland (Canada), Suriname, Falkland Islands and new ventures); and Midstream.
The geographical reportable segments are in the business of crude oil and natural gas exploration, development, production, and acquisition (Oil and Gas Exploration and Production or E&P). The Midstream reportable segment owns, operates, develops and acquires domestic midstream infrastructure assets with current focus areas being the DJ and Delaware Basins. Expenses related to debt, headquarters depreciation and corporate general and administrative expenses are recorded at the corporate level. Prior
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Notes to Consolidated Financial Statements
period amounts are presented on a comparable basis.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
(1)
Intersegment eliminations related to (loss) income before income taxes are the result of Midstream expenditures. These costs are presented as property, plant and equipment within the E&P business on an unconsolidated basis, in accordance with the successful efforts method of accounting, and are eliminated upon consolidation.
(2) Revenues from third parties for all foreign countries, in total, were $904 million in 2017, $973 million in 2016, and $1.1 billion in 2015.
(3) The midstream segment includes revenues of $19 million from third party customers.
(4) Goodwill is associated with the Texas reporting unit. See Note 1. Summary of Significant Accounting Policies.
(5) Long-lived assets located in all foreign countries, in total, were $2.8 billion, $3.0 billion, and $3.9 billion at December 31, 2017, 2016, and 2015, respectively.
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Notes to Consolidated Financial Statements
Note 15. Concentration of Risk
Concentration of Market Risk The largest single non-affiliated purchasers of our production were as follows:
(1) Includes sales to BP North American Funding Company, BP Company Commercial and/or BP Company.
(2) 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, NGL and natural gas 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 or remote international locations, 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 counterparty credit risk, especially during periods of falling commodity prices. We conduct our hedging activities with a diverse group of investment grade major banks and market participants. We monitor the creditworthiness of our hedge counterparties, and our internal hedge policies provide for mark-to-market exposure limits. We use master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be “net settled” at the time of election.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 16. Additional Shareholders’ Equity Information
Common Stock and Treasury Stock Activity in shares of our common stock and treasury stock was as follows:
(1)
The 2017 amount includes approximately 1.9 million shares of restricted stock awarded to former holders of Clayton Williams Energy outstanding stock awards as part of the Clayton Williams Energy Acquisition. See Note 3. Clayton Williams Energy Acquisition.
(2)
The 2017 amount includes approximately 720,000 shares of common stock from Clayton Williams Energy shareholders for the payment of withholding taxes due on the vesting of Clayton Williams Energy restricted shares and options pursuant to the purchase and sale agreement.
(3)
For the years ended December 31, 2017 and 2016, 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.
Issuance of Noble Midstream Partners Common Units On December 15, 2017, Noble Midstream Partners closed an offering of 3,680,000 common units, generating net proceeds of approximately $174 million, net of offering costs. On June 26, 2017, Noble Midstream Partners engaged in a private placement offering of 3,525,000 common units, generating proceeds of approximately $138 million, net of offering costs.
In third quarter 2016, Noble Midstream Partners completed its initial public offering of 14,375,000 common units, generating proceeds of $299 million, net of offering costs.
Subsequent Event - Share Repurchase Program On February 15, 2018, we announced the Company's Board of Directors authorized a share repurchase program of $750 million which expires December 31, 2020. All purchases will be made in accordance with applicable securities laws from time to time in open market or private transactions, depending on market conditions, and may be discontinued at any time.
Accumulated Other Comprehensive Loss (AOCL) AOCL in the shareholders’ equity section of the balance sheet included:
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Notes to Consolidated Financial Statements
All amounts in the table above are reported net of tax, using an effective income tax rate of 35%.
AOCL at December 31, 2017 included deferred losses of $20 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.
Note 17. Commitments and Contingencies
Legal Proceedings We are involved in various legal proceedings in the ordinary course of business. These proceedings are subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters and we believe that the ultimate disposition of such proceedings will not have a material adverse effect on our financial position, results of operations or cash flows.
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 crude oil and natural gas operations within the Non-Attainment Area of the DJ Basin. The Consent Decree was entered by the US District Court for the District 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 and 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. Over the last three years, 2015 through 2017, we spent approximately $72.0 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 Water Quality Control Division Matter In January 2017, we received a Notice of Violation/Cease and Desist Order (NOV/CDO) advising us of alleged violations of the Colorado Water Quality Control Act (Act) and its implementing regulations as it relates to our Colorado Discharge Permit System General Permit for construction activities associated with oil and gas exploration and/or production within our Wells Ranch Drilling and Production field located in Weld County, Colorado
Noble Energy, Inc.
Notes to Consolidated Financial Statements
(Permit). The NOV/CDO further orders us to cease and desist from all violations of the Act, the regulations and the Permit and to undertake certain corrective actions. Given the uncertainty associated with administrative actions of this nature, we are unable to predict the ultimate outcome of this action at this time but believe that the resolution of this action will not have a material adverse effect on our financial position, results of operations or cash flows.
Colorado Oil & Gas Conservation Commission Administrative Order on Consent In November 2017, we received a proposed Administrative Order on Consent (AOC) from the COGCC to resolve allegations of noncompliance associated with site preparation and stabilization at an oil and gas location in Weld County, Colorado. The AOC, which provides for an opportunity to further discuss the offer of settlement, has not yet been executed. Given the uncertainty associated with administrative actions of this nature, we are unable to predict the ultimate outcome of this action at this time but believe that the resolution of this action will not have a material adverse effect on our financial position, results of operations or cash flows.
Colorado Air Compliance Order on Consent In April 2017, we received a proposed Compliance Order on Consent (COC) from the Colorado Department of Public Health and Environment’s Air Pollution Control Division (APCD) to resolve allegations of noncompliance associated with compliance testing of certain engines subject to various General Permit 02 conditions and/or individual permit conditions. In May 2017, we reached a final resolution with the APCD and executed the COC, which requires payment of a civil penalty of $24,710 and an expenditure of no less than $98,840 on an approved SEP(s). 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 As part of our Marcellus Shale upstream divestiture, we retained certain 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 two to 16 years, is approximately $1.4 billion, undiscounted. The agreements for firm transportation primarily relate to services on certain pipelines which were recently placed into service in late 2017/early 2018 or for services on new pipeline projects to be constructed by, and connecting to, existing and new interstate pipeline systems with estimated in-service dates in late 2018. The associated commitments are included in the table below. See Note 1. Summary of Significant Accounting Policies - Exit Costs.
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 11 years, is approximately $781 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 $69 million in 2017, $76 million in 2016, and $84 million in 2015.
Minimum commitments as of December 31, 2017 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, NGL and natural gas reserves and exploration and production activities. In 2017 we established our Midstream business as a new reportable segment. The results of operations, costs incurred and capitalized costs associated with our Midstream reportable segment are not included in this disclosure. Prior period amounts are presented on a comparable basis.
Reserves There are numerous uncertainties inherent in estimating quantities of proved crude oil, NGL and natural gas reserves and 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, NGL and natural gas that are ultimately recovered.
Economic producibility of reserves is dependent on the crude oil, NGL and natural gas prices used in the reserves estimate. We based our December 31, 2017, 2016, and 2015 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, NGL and natural gas 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 Estimates of our proved reserves and associated future net cash flows are made solely by our engineers and are the responsibility of 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, 2017. 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 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 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)
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; partially offset by positive revisions of 14 MMBbls due to producing well performance and optimized lateral lengths in the Delaware 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, Delaware Basin and 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.
The 2017 US revisions associated with positive performance totaled 17 MMBbls, of which 14 were primarily attributable to the Delaware Basin due to continued optimization of well development and improved producing well performance. Revisions also included positive price revisions of 12 MMBbls.
(2)
The 2015 increase in US reserves was attributable to DJ Basin development.
The 2016 increase in US reserves included 38 MMBbls in the DJ Basin and 28 MMBbls in the Delaware Basin and Eagle Ford Shale, and was associated with increased performance from our horizontal drilling programs.
The 2017 increase in US reserves included additions of 59 MMBbls in the Delaware Basin, 42 MMBbls in the DJ Basin and 3 MMBbls in the Eagle Ford Shale primarily due to the addition of planned new locations and activity.
(3)
The 2015 increase was attributable to reserves acquired in the Rosetta Merger.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
The 2017 increase was attributable to the reserves acquired in the Clayton Williams Energy Acquisition.
(4)
In 2017, we sold the Marcellus Shale upstream assets and other non-strategic US onshore assets.
(5)
Equatorial Guinea production included sales from Alba Plant of approximately 1 MMBbl in 2017 and 3 MMBbl in each of the years 2016 and 2015.
See Items 1. and 2. Business and Properties - Proved Reserves Disclosures, Note 3. Clayton Williams Energy Acquisition and Note 4. 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; partially 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.
The 2017 US revisions associated with positive performance revisions totaled 25 MMBbls, including 11 MMBbls in the Delaware Basin, 8 MMBbls in the Eagle Ford Shale and 6 MMBbls in the DJ Basin, due to continued optimization of well development and improved producing well performance. Revisions also included positive price revisions of 6 MMBbls.
(2)
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 Delaware Basin and Eagle Ford shale due to improved well performance and/or decreases in development or operating costs.
The 2017 additions in US reserves included 19 MMBbls in the DJ Basin, 9 MMBbls in the Delaware Basin and 4 MMBbls in the Eagle Ford Shale primarily due to the addition of planned new locations and activity.
(3) The 2015 increase was attributable to reserves acquired in the Rosetta Merger.
The 2017 increase was attributable to the reserves acquired in the Clayton Williams Energy Acquisition.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
(4) Equatorial Guinea production represented sales from the Alba Plant.
(5) In 2017, we sold the Marcellus Shale upstream assets and other non-strategic US onshore assets.
See Items 1. and 2. Business and Properties - Proved Reserves Disclosures, Note 3. Clayton Williams Energy Acquisition and Note 4. 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 Framework, we are required to reduce our ownership in the Tamar and Dalit fields from 36% to 25% by year-end 2021. During 2016, we reduced our ownership to 32.5% through the sale of a 3.5% interest. At December 31, 2017, an additional 7.5% interest is included in assets held for sale. Proved reserves associated with the interest currently held for sale total approximately 502 Bcf, including 89 Bcf of PUDs, at December 31, 2017 and are included in the table above. In January 2018, we entered into an agreement to divest the 7.5% interest. See Note 4. Acquisitions, Divestitures and Merger.
(2)
The 2015 US revisions were 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 were associated with positive performance revisions to the Alba field. Israel revisions were 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 were associated with positive performance revisions of 58 Bcf at the Alba field, partially offset by negative commodity price revisions of 20 Bcf.
The 2017 US revisions were associated primarily with positive well performance and an increase in commodity prices. Net performance revisions of 66 Bcf primarily included 81 Bcf in the Eagle Ford Shale and 31 Bcf in the Delaware Basin, partially offset by negative performance revisions of 49 Bcf in the DJ Basin primarily associated vertical well locations. The 2017 Israel performance revisions of
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
292 Bcf were associated with the integration of the Tamar 8 well results into our geologic modeling across the reservoir. Positive price revisions were approximately 71 Bcf.
(3)
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 Delaware Basin and Eagle Ford Shale.
The 2017 increase in US reserves included additions of 224 Bcf in the DJ Basin, 53 Bcf in the Delaware Basin and 22 Bcf in the Eagle Ford Shale primarily due to the addition of planned new locations and activity. The 2017 increase in Israel reserves represented sanction of the first phase of development of the Leviathan natural gas project.
(4)
The 2015 increase was attributable to reserves acquired in the Rosetta Merger.
The 2017 increase was attributable to the reserves acquired in the Clayton Williams Energy Acquisition.
(5)
In 2016, we sold US onshore 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.
In 2017, we sold the Marcellus Shale upstream assets and other non-strategic US onshore assets.
See Items 1. and 2. Business and Properties - Proved Reserves Disclosures, Note 3. Clayton Williams Energy Acquisition and Note 4. Acquisitions, Divestitures and Merger.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Results of Operations for Oil and Gas Producing Activities (Unaudited) Results of operations for crude oil and natural gas producing activities within the E&P reporting segments are as follows:
(1)
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.
(2)
See Note 4. Acquisitions, Divestitures and Merger.
(3)
2017 asset impairments relate primarily to the Gulf of Mexico Troubadour well.
2016 asset impairments relate to certain Leviathan development concept costs.
2015 asset impairments related to reductions in the forward crude oil prices as of December 31, 2015 and revisions in expected field abandonment and other costs for offshore properties.
See Note 5. Asset Impairments.
(4)
Income tax expense is based upon respective corporate statutory tax rates. During 2017, 2016, and 2015, 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.
(5)
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.
(6)
Equatorial Guinea exploration expense includes amounts related to the write off of costs associated with certain discoveries. See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities (Unaudited)
Costs incurred include both capitalized costs and costs charged to expense when incurred for oil and gas property acquisition, exploration, and development activities associated with the E&P reporting segments. Costs incurred also include new AROs established in the current year, as well as changes to AROs resulting from changes to cost estimates during the year. Exploration costs presented below include the costs of drilling and equipping successful and unsuccessful exploration wells during the year, geological and geophysical expenses, and the costs of retaining undeveloped leaseholds. Development costs include the costs of drilling and equipping development wells. Costs associated with activities of our Midstream business and other corporate activities are not included.
(1)
Other International includes Newfoundland, Suriname, Falkland Islands, other new ventures and previous North Sea operations, which are in the process of being decommissioned.
(2)
2017 proved and unproved property acquisition costs include amounts allocated from the Clayton Williams Energy Acquisition (See Note 3. Clayton Williams Energy Acquisition) and the Delaware Basin Acquisition (See Note 4. Acquisitions, Divestitures and Merger).
2016 unproved property acquisition costs relate to the termination of the Marcellus Shale joint development agreement. See Note 4. Acquisitions, Divestitures and Merger.
2015 proved and unproved property acquisition costs include amounts allocated from the Rosetta Merger. See Note 4. Acquisitions, Divestitures and Merger.
(3)
2017 exploration costs include primarily capitalized interest on Gulf of Mexico projects, and $7 million dry hole cost related to the Araku-1 exploration well, offshore Suriname. The remainder relates to seismic expense and drilling costs.
2016 exploration costs include drilling and completion of $44 million in the Gulf of Mexico.
2015 exploration costs include drilling and completion of $22 million in the Gulf of Mexico.
(4)
Worldwide development costs include amounts spent to develop PUDs of approximately $1.2 billion in 2017, $656 million in 2016, and $1.5 billion in 2015.
Israel development costs include $416 million related to initial development of the Leviathan field and $63 million related to the Tamar 8 development well in 2017. Amounts incurred in 2016 and 2015 related primarily to development of the Tamar discovery.
Equatorial Guinea development costs primarily relate to the Alba field unitization project in 2017 and drilling and well completion and installation and construction of a compression platform in the Alba field in 2016 and 2015.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
US development costs include a decrease of $17 million in asset retirement obligations due to downward revisions and increases of $20 million in 2016 and $194 million in 2015.
Israel development costs include increases in asset retirement obligations of $4 million in 2017 and $46 million in 2015.
Equatorial Guinea development costs include increases (decreases) in asset retirement obligations of $14 million in 2017 and $(10) million in 2015.
Other International development costs include increases (decreases) in asset retirement obligations of $(40) million in 2017 mainly associated with the North Sea abandonment project and $2 million in 2015.
Capitalized Costs Relating to Oil and Gas Producing Activities (Unaudited) Aggregate capitalized costs relating to crude oil and natural gas producing activities within the E&P reporting segments are as follows:
(1)
Unproved oil and gas property cost at December 31, 2017 include previous acquisition costs of $1.6 billion related to the Clayton Williams Energy Acquisition, and $1.1 billion and $149 million related to the Delaware Basin and Eagle Ford Shale properties.
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 Delaware Basin properties and $758 million related to Marcellus Shale properties.
(2)
Proved oil and gas properties at December 31, 2017 include asset retirement costs of $941 million and assets held for sale of $448 million.
Proved oil and gas properties at December 31, 2016 include asset retirement costs of $884 million and $18 million of assets held for sale.
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 Framework, we are required to reduce our ownership in the Tamar and Dalit fields from 36% to 25% by year-end 2021. During 2016, we reduced our ownership to 32.5% through the sale of a 3.5% interest. Therefore, amounts at December 31, 2017 and 2016 reflect a 32.5% working interest, while 2015 amounts reflect a 36% working interest. At December 31, 2017, 7.5% of our 32.5% interest is included in assets held for sale. The portion of the standardized measure of discounted future net cash flows included in the table above, and associated with the interest currently held for sale, totals approximately $650 million at December 31, 2017. See Note 4. Acquisitions, Divestitures and Merger. The 2017 increase in the standardized measure of discounted future net cash inflows relates primarily to the sanction of the first phase of development of the Leviathan field.
(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. As of December 31, 2017, US future income tax expense includes the expected impact of the recent Tax Reform Legislation. As of December 31, 2017, 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, unless contractual arrangements designate the price to be used. 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 and NGLs from the 12-month average price for 2017 would reduce the discounted future net cash flows before income taxes by approximately $1.2 billion and $0.3 billion, respectively. We estimate that a 10% per Mcf reduction in the average price of natural gas from the 12-month average price for 2017 would reduce the discounted future net cash flows before income taxes by approximately $1 billion.
Future production and development costs, which include dismantlement and restoration expense, are computed by estimating the expenditures to be incurred in developing and producing the proved crude oil, natural gas and NGL reserves at the end of the year, based on year-end costs, and assuming continuation of existing economic conditions.
Future development costs include amounts that we expect to spend to develop PUDs of approximately $1.7 billion in 2018, $1.9 billion in 2019 and $1.4 billion in 2020.
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.
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 increase in 2017 and the decrease in 2015 were driven primarily by higher and lower, respectively, 12-month average commodity prices.
(2)
Purchase of minerals in 2017 relates to reserves acquired in the Clayton Williams Energy Acquisition.
Purchase of minerals in 2015 relates to reserves acquired in the Rosetta Merger.
(3)
The increase in 2017 future income tax expense relates primarily to the increase in profit and levy taxes in Israel, partially offset by the decrease in future corporate income tax rate in Israel. The increase in profits tax is driven by a significant increase in future cash flows related to the Leviathan project sanctioning in 2017. The increase in US tax expense due to the increase in future taxable income was offset by the decrease in tax expense associated with utilization of future net operating losses and decrease in applicable tax rate from 35% to 21% due to the changes in the US Tax Law effective January 1, 2018. 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.
Noble Energy, Inc.
Supplemental Quarterly Financial Information
(Unaudited)
Supplemental quarterly financial information is as follows:
(1) First quarter 2017 included the following:
•
No unusual or infrequent activity.
Second quarter 2017 included the following:
•
$2.4 billion loss on Marcellus Shale upstream divestiture (See Note 4. Acquisitions, Divestitures and Merger).
Third quarter 2017 included the following:
•
$98 million loss on extinguishment of debt (See Note 10. Long-Term Debt).
Fourth quarter 2017 included the following:
•
$270 million deferred tax benefit, net, related to recent changes in federal income tax regulations; and
•
$334 million gain on sale of mineral and royalty assets (See Note 4. Acquisitions, Divestitures and Merger).
(2) First quarter 2016 included the following:
•
$80 million gain on extinguishment of debt.
Second quarter 2016 included the following:
•
$25 million purchase price allocation adjustment related to Rosetta Merger (See Note 4. Acquisitions, Divestitures and Merger).
Third quarter 2016 included the following:
•
$81 million undeveloped leasehold impairment expense (See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs).
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); and
•
$92 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 (loss) as each quarterly computation is based on the earnings (loss) 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, 2017. 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 2018 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2017.

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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 2018 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2017.

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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 2018 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2017.

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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 2018 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2017.

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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 2018 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2017.
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:
(1)
Financial Statements: The consolidated financial statements and related notes, together with the reports of KPMG LLP, Independent Registered Public Accounting Firm, appear in Part II, Item 8, Financial Statements and Supplementary Data, of this Form 10-K.
(2)
Financial Statement Schedules: All schedules for which provision is made in the applicable accounting regulations of the SEC are not required under the related instruction or are inapplicable and, therefore, have been omitted.
(3)
Exhibits: The exhibits listed below on the Index to Exhibits are filed or incorporated by reference as part of this Form 10-K.
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.
†
Confidential treatment granted under Rule 24b-2 as to certain portions of this exhibit, which are omitted and filed separately with the Commission.
Item 16. Form 10-K Summary
See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Executive Summary.
GLOSSARY
In this report, the following abbreviations are used:
Bbl
Barrel
BBoe
Billion barrels oil equivalent
Bcf
Billion cubic feet
Bcf/d
Billion cubic feet per day
BCM
Billion cubic meters
BOE
Barrels oil equivalent. Natural gas is converted on the basis of six Mcf of gas per one barrel of crude oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given commodity price disparities, the price for a barrel of crude oil equivalent for natural gas is significantly less than the price for a barrel of crude oil. The price for a barrel of NGL is also less than the price for a barrel of crude oil.
Boe/d
Barrels oil equivalent per day
Btu
British thermal unit
FPSO
Floating production, storage and offloading vessel
GHG
Greenhouse gas emissions
GSPA
Gas Sales Purchase Agreement
HH
Henry Hub index
IDP
Integrated Development Plan
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
NGLs
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
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 20, 2018
By: /s/ David L. Stover
David L. Stover,
Chairman of the Board, President and Chief Executive Officer
Date:
February 20, 2018
By: /s/ Kenneth M. Fisher
Kenneth M. Fisher,
Executive Vice President, Chief Financial Officer
Date:
February 20, 2018
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 20, 2018
David L. Stover
(Principal Executive Officer)
/s/ Kenneth M. Fisher
Executive Vice President, Chief Financial Officer
February 20, 2018
Kenneth M. Fisher
(Principal Financial Officer)
/s/ Dustin A. Hatley
Vice President, Chief Accounting Officer and Controller
February 20, 2018
Dustin A. Hatley
(Principal Accounting Officer)
/s/ Jeffrey L. Berenson
Director
February 20, 2018
Jeffrey L. Berenson
/s/ Michael A. Cawley
Director
February 20, 2018
Michael A. Cawley
/s/ Edward F. Cox
Director
February 20, 2018
Edward F. Cox
/s/ James E. Craddock
Director
February 20, 2018
James E. Craddock
/s/ Thomas J. Edelman
Director
February 20, 2018
Thomas J. Edelman
/s/ Kirby L. Hedrick
Director
February 20, 2018
Kirby L. Hedrick
/s/ Holli C. Ladhani
Director
February 20, 2018
Holli C. Ladhani
/s/ Scott D. Urban
Director
February 20, 2018
Scott D. Urban
/s/ William T. Van Kleef
Director
February 20, 2018
William T. Van Kleef
/s/ Molly K. Williamson
Director
February 20, 2018
Molly K. Williamson

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Stock Performance Metrics:
Return: 0.1080669760704041
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