Company: NOBLE ENERGY INC
CIK: 72207
SIC: 1311
Filing Date: 2019-02-19 00:00:00

ITEM 1 - BUSINESS

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

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

ITEM 2 - PROPERTIES

ITEM 3 - LEGAL PROCEEDINGS
Item 3. Legal Proceedings
We are involved in various legal proceedings in the ordinary course of business. These proceedings are subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters and we believe that the ultimate disposition of such proceedings will not have a material adverse effect on our financial position, results of operations or cash flows. See Item 8. Financial Statements and Supplementary Data - Note 11. Commitments and Contingencies.

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

ITEM 5 - MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Common Stock Our common stock, $0.01 par value, is listed and traded on the NYSE under the symbol “NBL.” The declaration and payment of dividends are 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.
Dividends On January 29, 2019, our Board of Directors declared a quarterly cash dividend of $0.11 per common share. The dividend will be paid February 25, 2019, to shareholders of record on February 11, 2019. See Item 8. Financial Statements and Supplementary Data - Consolidated Statements of Shareholders' Equity.
Transfer Agent and Registrar The transfer agent and registrar for our common stock is Computershare Trust Company N.A., 250 Royall Street, Canton, MA, 02021.
Shareholders’ Profile Pursuant to the records of the transfer agent, as of February 7, 2019, the number of holders of record of our common stock was 541.
Stock Repurchases The following table summarizes repurchases of our common stock occurring in fourth quarter 2018:
(1) Includes stock repurchases of 69,216 shares during the period related to stock received by us from employees for the payment of withholding taxes due on shares of common stock issued under stock-based compensation plans.
(2) During fourth quarter 2018, we repurchased and retired 2,585,685 shares of common stock at an average purchase price of $24.19 per share pursuant to the $750 million share repurchase program, authorized by the Board of Directors and announced in February 2018, which expires on December 31, 2020.
Stock Performance Graph This graph shows our cumulative total shareholder return over the five-year period from December 31, 2013 to December 31, 2018. 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.
Devon Energy Corp.
Noble Energy, Inc.
Apache Corp.
EOG Resources, Inc.
Pioneer Natural Resources Co.
Cabot Oil & Gas Corp.
Hess Corp.
Range Resources Corp.
Chesapeake Energy Corp.
Marathon Oil Corp.
Southwestern Energy Co.
Continental Resources, Inc.
Murphy Oil Corp.
The comparison assumes $100 was invested on December 31, 2013 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.

ITEM 6 - SELECTED FINANCIAL DATA
Item 6. Selected Financial Data
(1)
See Item 8. Financial Statements and Supplementary Data - Note 5. Acquisitions and Divestitures.
(2)
See Item 8. Financial Statements and Supplementary Data - Note 6. Goodwill Impairment.

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:
•
Executive Summary;
•
Executive Overview;
•
Operating Outlook;
•
Results of Operations - E&P;
•
Results of Operations - Midstream;
•
Results of Operations - Corporate;
•
Liquidity and Capital Resources; and
•
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 (metrics should be reviewed in the context of additional information provided in the links below)
Items 1. and 2. Business and Properties - Sales Volumes, 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)
Item 8. Financial Statements and Supplementary Data - Note 5. Acquisitions and Divestitures
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 Volumes, 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. Building on the prior year's price recovery and higher demand, crude oil prices trended upward for most of 2018, with Brent and WTI crude oil prices reaching a four-year high, in excess of $80 and $70 per barrel, respectively. However, in November 2018, prices suddenly plunged, with Brent and WTI prices falling to nearly $50 and $40 per barrel, respectively, as traders focused on supply economics combined with concerns of slowing global growth.
The outlook for 2019 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. Even if OPEC cuts production, US shale supply is expected to continue to grow due to capital investment in anticipation of the addition of takeaway capacity easing recent bottlenecks, such as in the Delaware Basin. These factors, and the potential for slower global growth and increasing global uncertainty, could suppress crude oil prices. In addition, the spread between WTI and Brent prices has been widening, resulting in comparatively lower prices for US production. However, reductions in industry investment, particularly for conventional crude oil development, will, over time, contribute to production declines, potentially supporting higher prices.
Natural Gas The US domestic natural gas market remains oversupplied as domestic production has continued to grow due to drilling efficiencies, higher incremental volumes of associated gas from oil wells 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 2018, with an expectation to continue as such in 2019, with natural gas prices at or near current or recent trading levels.
Impact of Current Commodity Prices The chart below shows the historical trend in benchmark prices for WTI crude oil, Brent crude oil and US Henry Hub natural gas.
Development and Operating Costs As commodity prices strengthened, the demand for oilfield equipment, services and infrastructure, particularly in US onshore basins, began to rise, leading to cost inflation for the drilling, completion and operating of wells, and for the construction and/or access to necessary oil and gas infrastructure. As a result, during 2018 there was pressure on operating margins and capital efficiency in US onshore basins, including those in which we operate. With the recent crude oil price decline from mid-2018 highs, the development and operating cost structure has begun to shift downward, and we expect margin pressure will continue into 2019.
Takeaway Capacity With higher commodity prices and the resurgence of US onshore drilling activity, demand increased for access to gathering facilities, transportation and/or takeaway pipelines due to growing production volumes. In the Delaware Basin, midstream suppliers are working to construct new gathering, transportation and processing facilities or to repurpose existing infrastructure in an effort to proactively outpace expected production growth. In this regard, we have secured near-term flow assurance and long-term out-of-basin takeaway from the Delaware Basin to the Texas Gulf Coast, with access to export markets. See Items 1. and 2. Business and Properties - US Onshore.
Colorado Proposition #112 On November 6, 2018, a majority of Colorado voters voted against Proposition #112, which, if passed, would have significantly limited, or in some cases prevented, the future development of crude oil and natural gas and demand for our midstream services in areas where we currently conduct operations.
Initiatives have been underway in the State of Colorado to regulate, limit or ban hydraulic fracturing or other facets of crude oil and natural gas exploration, development or operations for some time. We are monitoring the work of the State of Colorado General Assembly to create a framework for future oil and gas development in the State.
Concurrently, we are engaged in extensive public education and outreach efforts, with the goal of engaging and educating the public and communities about the economic and environmental benefits of safe and responsible crude oil and natural gas development.
Impact of Tariffs During 2018, the US Administration imposed import tariffs of 25% on steel products and 10% on aluminum products, as well as quantitative restrictions on imports of steel and/or aluminum products from various countries. The US oil and gas industry relies on steel for drilling and completion of new wells, as well as for facility production at refineries, petrochemical plants and pipelines. Implementation of these tariffs will likely increase prices for specialty and other products used in our industry. Tariffs and quantitative restrictions may cause disruption in the energy industry’s supply chain, resulting in delay or cessation of drilling efforts or postponement or cancellation of new inter- or intra-state pipeline projects that the industry is relying on to transport its increasing onshore production to market, as well as endangering US LNG export projects resulting in negative impacts on natural gas pricing and production.
Recent Activities
During the period 2015-2018, we strategically repositioned our portfolio to focus capital investment primarily in US onshore plays, including the DJ and Delaware Basins and Eagle Ford Shale, and in our international offshore assets in the Eastern Mediterranean and West Africa. The focus of our capital programs in these areas is expected to positively impact our future cash flows and margins.
During 2018, we continued to enhance our portfolio, concentrated development capabilities on higher-impact opportunities that can drive substantial long-term value creation, focused on margin improvements and undertook shareholder value initiatives.
We believe implementation of our focused strategy has enhanced our future outlook. During 2018, we accomplished the following:
Portfolio Activities, Including:
•
sale of a 7.5% working interest in Tamar;
•
sale of our 50% interest in CONE Gathering LLC and our investment in CNX Midstream Partners common units;
•
sale of our Gulf of Mexico assets;
•
expansion of new venture portfolio in both US onshore and international offshore locations;
•
execution of numerous acreage exchanges and sales to secure more contiguous acreage positions within the DJ and Delaware Basins; and
•
completing the midstream Saddle Butte Acquisition, which expanded utilization of the Advantage Pipeline.
Operational Accomplishments, Including:
•
progressing Leviathan development to approximately 75% completion and remaining on budget and on schedule to flow first gas by the end of 2019;
•
achieved annual average record gross sales of over 1 Bcf/d in Israel;
•
advancing natural gas marketing and transportation optionality for the export of Tamar and Leviathan production to Egypt;
•
progressed the next phase of development offshore West Africa by entering a Heads of Agreement establishing the framework for monetization of natural gas from the Alen field;
•
increased total US onshore sales volumes by more than 18% from 2017, excluding the impact of the Marcellus Shale upstream divestiture, and continuing shift to an oilier production mix, with approximately 44% of our US onshore consolidated sales volumes attributable to crude oil;
•
securing near-term flow assurance and long-term out-of-basin takeaway capacity, including the EPIC firm transport agreement, from the Delaware Basin to the Texas Gulf Coast, with access to export markets;
•
expanded our midstream footprint capabilities through CGF constructions; and
•
received approval for the first large-scale CDP which will span our Mustang IDP area.
Financial Initiatives, Including:
•
Board of Directors authorization to implement a $750 million share repurchase program and subsequent repurchase of 10 million shares of Noble Energy common stock, for $295 million, during the year;
•
increase in dividends to 11 cents per Noble Energy common share for second, third and fourth quarters and paid dividends of $208 million during 2018;
•
repayment of $609 million of outstanding debt;
•
enhancement of financial flexibility via revolving credit facility maturity date extensions, a capacity increase and entry into a new term loan credit facility;
•
repatriation of $791 million from foreign operations with no US tax impact;
•
positive mitigation efforts for retained Marcellus Shale firm transportation contracts;
•
strong liquidity position including cash on hand and unused borrowing capacity; and
•
investment grade credit ratings and received improved outlooks from two agencies.
In summary, we believe 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 continue to drive efficiencies in our US onshore drilling and completions, while advancing our Eastern Mediterranean and West Africa regional natural gas developments. Financially, we continue to maintain our strong balance sheet and robust liquidity position while engaging in shareholder return initiatives.
OPERATING OUTLOOK
Growing Long-Term Value We believe the following guiding principles will contribute to growing long-term value:
•
Execution of a disciplined capital allocation process by:
◦
designing a flexible investment program aligned with the current commodity price environment; and
◦
maintaining a strong balance sheet and liquidity position.
•
Enhancing capital efficiencies by:
◦
utilizing our technical competencies and applying historical learnings from unconventional US shale plays to reduce US onshore finding and development costs.
•
Leveraging the benefits of our well-positioned and diversified portfolio, including:
◦
exercising investment optionality and flexibility afforded by our assets, certain of which are held by production; and
◦
continuing portfolio optimization actions to maximize strategic value.
•
Capitalizing on a currently low-cost offshore environment with execution of high-quality, long-cycle development projects, such as:
◦
progressing Leviathan Phase 1 field development and monetization of natural gas offshore West Africa.
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Maintaining financial strength through:
◦
focusing operational activities on high-margin, high-return assets; and
◦
improving overall corporate returns.
We currently expect that commodity price improvement will be limited in the first half of 2019 and that this factor, along with the timing of our capital expenditures for US onshore development, Leviathan completion and the Aseng development well, will result in the outspending of our operating cash flows. In the second half of the year, reduced capital spend, plus the positive impact from production growth, will result in improved operating cash flows relative to capital spending.
We believe our approach positions the Company for sustainability, operational efficiency, and long-term success throughout the oil and gas business cycle. Further, we expect our US onshore activity level, combined with Leviathan Phase 1 natural gas sales, expected to commence in late 2019, and our West Africa natural gas monetization strategy, which is expected to result in first gas processing in 2021, position us for robust cash flow growth in 2020-2021.
However, if commodity prices are suppressed for an extended period of time and/or operating cost inflation continues impacting operating margins, 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 crude oil, NGL and natural gas prices are volatile. A reduction in these prices could have a material adverse effect on our operations, our liquidity, and the price of our common stock.
Our 2019 production target is in the range of 345 MBoe/d to 365 MBoe/d.
2019 Capital Investment Program
Exploration and Production Program Our 2019 organic 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 and acquisition capital related to the EMG Pipeline, our 2019 organic capital program is in the range of $2.4 to $2.6 billion, with approximately 70% being allocated to US onshore development and approximately 20% to complete the Leviathan project in the Eastern Mediterranean. The remaining portion of the organic capital program is designated for Noble retained Midstream activities, drilling of a crude oil development well in West Africa, and other exploration and corporate activities.
2019 Budget Principles Our 2019 organic capital program anticipates a lower level of investment directed to our US onshore assets, as compared with 2018. We will continue to advance our US onshore program through investments in liquids-rich and high-return projects, improve execution efficiency, and enhance our midstream business value. In the Eastern Mediterranean, our 2019 organic capital program, excluding acquisition capital related to the EMG Pipeline, includes the investment needed to complete Leviathan Phase 1 development.
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:
•
commodity prices, including price realizations on specific crude oil, NGL and natural gas production;
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operating and development costs;
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production, drilling and delivery commitments, or other contractual obligations;
•
drilling results;
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cash flows from operations and 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;
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property acquisitions and divestitures;
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exploration activity; and
•
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 non-strategic assets, borrowings under our Revolving Credit Facility, and/or other sources of funding. See Liquidity and Capital Resources - Sources and Uses of Liquidity and Liquidity and Capital Resources - Contractual Obligations.
RESULTS OF OPERATIONS - E&P
Highlights for our E&P business were as follows:
2018 Significant E&P Operating Highlights Included:
•
total average consolidated sales volumes of 346 MBoe/d, net;
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average daily sales volumes for US onshore crude oil of 109 MBbl/d, net; and
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average daily sales volumes of approximately 1.0 Bcfe/d, gross, offshore Israel, primarily from the Tamar field.
2018 E&P Financial Results Included:
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average realized crude oil price increase of 25% as compared with 2017;
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average realized NGL price increase of 10% as compared with 2017;
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average realized natural gas price decrease of 8% as compared with 2017;
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goodwill impairment charge of $1.3 billion attributable to the Texas reporting unit (associated with the Clayton Williams Energy Acquisition);
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pre-tax income of $119 million, as compared with pre-tax loss of $1.8 billion for 2017; and
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capital expenditures, excluding acquisitions, of $2.8 billion, as compared with $2.4 billion for 2017.
Following is a summarized statement of operations for our E&P business:
(1)
The adoption of ASC 606 on January 1, 2018 had a de minimis impact on revenues and production expense for 2018. See Item 8. Financial Statements and Supplementary Data - Note 4. Revenue from Contracts with Customers.
(2)
See Item 8. Financial Statements and Supplementary Data - Note 5. Acquisitions and Divestitures.
(3)
See Item 8. Financial Statements and Supplementary Data - Note 6. Goodwill Impairment.
Average Oil, NGL and Gas Sales Volumes and Prices Average daily sales volumes and average realized sales prices were as follows:
(1)
The adoption of ASC 606 on January 1, 2018 had a de minimis impact on revenues and production expense for 2018. See Item 8. Financial Statements and Supplementary Data - Note 4. Revenue from Contracts with Customers. Specifically, this resulted in the following:
◦
increases in NGL revenues, and corresponding increase in production expense, of $7 million for 2018;
◦
decreases in natural gas revenues, and corresponding decreases in production expense, of $7 million for 2018;
◦
increases in NGL and natural gas sales volumes of 5 MBbl/d and 31MMcf/d, respectively, for 2018; and
◦
reductions in average realized NGL and natural gas sales prices of $1.76/Bbl and $0.12/Mcf, respectively, for 2018.
(2)
Includes 7 MBoe/d for 2018 related to Gulf of Mexico assets sold in April 2018. See Item 8. Financial Statements and Supplementary Data - Note 5. Acquisitions and Divestitures.
(3)
See Items 1. and 2. Business and Properties - Delivery Commitments - West Africa Agreements.
(4)
Volumes represent sales of condensate and LPG from the LPG plant in Equatorial Guinea. See Income from Equity Method Investees.
An analysis of revenues from sales of crude oil, NGLs and natural gas is as follows:
(1)
Changes exclude gains and losses related to commodity derivative instruments. See Item 8. Financial Statements and Supplementary Data - Note 13. Derivative Instruments and Hedging Activities.
Crude Oil and Condensate Sales Revenues Revenues from crude oil and condensate sales increased in 2018 as compared with 2017 due to the following:
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25% increase in average realized prices (see factors impacting global pricing at Executive Overview - Industry Outlook); and
•
higher US onshore sales volumes of 19 MBbl/d primarily driven by an increase in development activity in the Delaware and DJ Basins;
partially offset by:
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lower Gulf of Mexico sales volumes of 16 MBbl/d resulting from the sale of the Gulf of Mexico assets in second quarter 2018; and
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lower offshore West Africa sales volumes of 2 MBbl/d resulting from natural field decline.
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 (see factors impacting global pricing at Executive Overview - Industry Outlook);
•
higher US onshore sales volumes of 16 MBbl/d, including 5 MBbl/d contributed by 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:
•
lower sales volumes of 14 MBbl/d primarily due to natural field decline in the Gulf of Mexico and Equatorial Guinea.
NGL Sales Revenues Revenues from NGL sales increased in 2018 as compared with 2017 due to the following:
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higher US onshore sales volumes of 6 MBbl/d (exclusive of 5 MBbl/d from adoption of ASC 606) primarily attributable to development activities in the Delaware and DJ Basins;
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10% increase in average realized prices (see factors impacting global pricing at Executive Overview - Industry Outlook); and
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$7 million increase associated with the adoption of ASC 606;
partially offset by:
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lower sales volumes of 5 MBbl/d due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017.
Revenues from NGL sales increased in 2017 as compared with 2016 due to the following:
•
56% increase in average realized prices (see factors impacting global pricing at Executive Overview - Industry Outlook); and
•
higher US onshore sales volumes of 7 MBbl/d, including 1 MBbl/d contributed by Clayton Williams Energy assets, primarily attributable to increased development and enhanced well design and completion techniques;
partially offset by:
•
lower sales volumes of 4 MBbl/d due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017.
Natural Gas Sales Revenues Revenues from natural gas sales decreased in 2018 as compared with 2017 due to the following:
•
lower sales volumes of 174 MMcf/d due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017;
•
lower Gulf of Mexico sales volumes of 14 MMcf/d resulting from the sale of the Gulf of Mexico assets in second quarter 2018;
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lower Israel sales volumes of 35 MMcf/d due to the sale of a 7.5% interest in the Tamar field in second quarter 2018;
•
$7 million decrease associated with the adoption of ASC 606;
•
lower sales volumes of 26 MMcf/d from the Alba field, offshore Equatorial Guinea, resulting from natural field decline and timing of field maintenance; and
•
8% decrease in average realized prices primarily due to the impact of increased US onshore supply;
partially offset by:
•
higher US onshore sales volumes of 30 MMcf/d (exclusive of 31 MMcf/d from adoption of ASC 606) primarily attributable to development activities in the Delaware and DJ Basins; and
•
higher sales volumes related to our remaining working interest in Israel due to increased demand for power as well as conversion of facilities from use of coal to natural gas.
Revenues from natural gas sales decreased slightly in 2017 as compared with 2016 due to the following:
•
lower sales volumes of 312 MMcf/d due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017; and
•
lower sales volumes of 29 MMcf/d as a result of the sale of a 3.5% working interest in the Tamar field in December 2016, partially offset by higher gross sales volumes from the field;
partially offset by:
•
24% increase in average realized prices (see factors impacting global pricing at Executive Overview - Industry Outlook); and
•
higher US onshore sales volumes of 40 MMcf/d, including 6 MMcf/d contributed by Clayton Williams Energy assets.
Income from Equity Method Investees Our share of operations of equity method investees were as follows:
Changes for 2018 as compared with 2017 included the following:
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increase in net income from AMPCO and affiliates primarily due to higher realized methanol prices; and
•
increase in net income from Alba Plant primarily due to higher realized LPG prices.
Changes for 2017 as compared with 2016 included the following:
•
increase in net income from AMPCO and affiliates primarily due to higher realized methanol prices; and
•
increase in net income from Alba Plant primarily due to higher LPG sales volumes and realized prices.
Production Expense Components of production expense were as follows:
(1)
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.
(2)
US production expense includes charges from our midstream operations that are eliminated on a consolidated basis. See Item 8. Financial Statements and Supplementary Data - Note 3. Segment Information.
(3)
Lease operating expense includes oil and gas operating costs (labor, fuel, repairs, replacements, saltwater disposal and other related lifting costs) and workover expense.
(4)
The adoption of ASC 606 on January 1, 2018 had a de minimis impact on revenues and production expense for 2018. See Item 8. Financial Statements and Supplementary Data - Note 4. Revenue from Contracts with Customers.
Lease Operating Expense Lease operating expense increased in 2018 as compared with 2017 primarily due to the following:
•
increase of $93 million primarily due to increased development activities resulting in added production in the DJ and Delaware Basins; and
•
increase in costs in the Delaware Basin due to higher activity and demand for supplies and services, particularly water disposal;
partially offset by:
•
decrease of $84 million due to lower production in the Gulf of Mexico resulting from natural field decline and the subsequent sale of the assets in second quarter 2018; and
•
decrease of $13 million related to the divestiture of the Marcellus Shale upstream assets in second quarter 2017.
Lease operating expense increased in 2017 as compared with 2016 primarily due to the following:
•
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:
•
decrease of $19 million resulting from natural field decline in the Gulf of Mexico;
•
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 following the partial divestiture in December 2016.
Production and Ad Valorem Tax Expense Production and ad valorem taxes increased in 2018 as compared with 2017, primarily due to higher commodity prices.
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.
Gathering, Transportation and Processing Expense Gathering, transportation and processing expense decreased in 2018 as compared with 2017 primarily due to:
•
decrease of $17 million in the Gulf of Mexico due to lower production resulting from natural field decline and the subsequent sale of the assets in second quarter 2018; and
•
decrease of $88 million related to the divestiture of the Marcellus Shale upstream assets in second quarter 2017;
partially offset by:
•
increase of $63 million related to increased activity in Delaware and DJ Basins.
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.
Other Royalty Expense Other royalty expense increased in 2018 as compared with 2017, primarily due to higher commodity prices. Other royalty expense remained relatively flat in 2017 as compared with 2016.
Unit Rate Per BOE Production expense on a per BOE basis increased in 2018 as compared with 2017, primarily due to the decrease in total sales volumes driven by divestitures of the Marcellus Shale upstream assets in second quarter 2017 and Gulf of Mexico assets in second quarter 2018, which lowered our average production expense per BOE. These impacts were offset by an increase in volumes from the higher cost Delaware Basin.
Production expense on a per BOE basis increased in 2017 as compared with 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.
Exploration Expense Components of exploration expense were as follows:
(1)
See Item 8. Financial Statements and Supplementary Data - Note 7. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
(2)
Includes lease rental and other exploration expense.
Exploration expense for 2018 included:
•
staff expense incurred across our US onshore assets.
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.
Depreciation, Depletion and Amortization Expense Depreciation, Depletion and Amortization (DD&A) expense was as follows:
(1) DD&A expense includes accretion of discount on AROs of $33 million in 2018, $47 million in 2017, and $48 million in 2016.
Total DD&A expense decreased in 2018 as compared with 2017 primarily due to the following:
•
decrease of $223 million due to both lower sales volumes in the Gulf of Mexico resulting from natural field decline and classification of the assets as held for sale in first quarter 2018, resulting in the cessation of DD&A expense;
•
decrease of $15 million due to reclassification of a 7.5% working interest in the Tamar field as assets held for sale at December 31, 2017, resulting in cessation of DD&A expense; and
•
decrease of $90 million due to the Marcellus Shale upstream divestiture in second quarter 2017;
partially offset by:
•
higher sales volumes in the Delaware Basin, which almost doubled, due to increased development activities subsequent to the Clayton Williams Energy Acquisition in second quarter 2017.
The unit rate per BOE for 2018 was flat as compared with 2017, primarily due to the increased development activity in the Delaware Basin resulting in higher depletable basis and the sales of lower-cost production from our 7.5% interest in the Tamar field in first quarter 2018 and the Marcellus Shale upstream assets in second quarter 2017, offset by a decrease in total DD&A expense combined with the sale of higher-cost production from the Gulf of Mexico assets in second quarter 2018.
Total DD&A expense decreased in 2017 as compared with 2016 primarily 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;
•
lower sales volumes in the DJ Basin and the impact of certain property divestitures since the second quarter 2016;
•
decrease of $291 million due to the Marcellus Shale upstream divestiture in second quarter 2017;
•
decrease of $7 million due to the sale of a 3.5% working interest in the Tamar field in December 2016;
•
decrease of $37 million due to a reduction in depletable costs of $153 million due to the reallocation of common asset costs from the Alen field, offshore Equatorial Guinea, to the West Africa natural gas monetization development project in second quarter 2017; and
•
lower sales volumes in the Gulf of Mexico resulting from natural field decline and reduction in the depletable costs due to downward revisions in estimates of ARO costs;
partially offset by:
•
higher US onshore sales volumes of 29 MBoe/d, including 7 MBoe/d contributed by Clayton Williams Energy assets;
•
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 due to higher domestic demand.
The unit rate per BOE for 2017 decreased 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. 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.
Gain on Divestitures, Net See Item 8. Financial Statements and Supplementary Data - Note 5. Acquisitions and Divestitures.
Goodwill Impairment See Critical Accounting Policies and Estimates - Goodwill and Item 8. Financial Statements and Supplementary Data - Note 6. Goodwill Impairment.
(Gain) Loss on Commodity Derivative Instruments (Gain) loss on commodity derivative instruments includes (i) cash settlements paid/received relating to our crude oil and natural gas commodity derivative contracts; and (ii) non-cash decreases/increases in the fair values of our crude oil and natural gas commodity derivative contracts.
For 2018, gain on commodity derivative instruments included:
•
net cash settlement payment of $161 million; and
•
net non-cash increase of $224 million in the fair value of our net commodity derivative asset, primarily driven by decreases in the forward commodity price curve for crude oil.
For 2017, gain on commodity derivative instruments included:
•
net cash settlement receipt of $13 million; and
•
net non-cash increase of $50 million in the fair value of our net commodity derivative liability, primarily driven by changes in the forward commodity price curves for both crude oil and natural gas.
For 2016, loss on commodity derivative instruments included:
•
net cash settlement receipt of $569 million; and
•
net non-cash decrease of $708 million in the fair value of our net commodity derivative liability, primarily driven by changes in the forward commodity price curves for both crude oil and natural gas.
See Item 8. Financial Statements and Supplementary Data - Note 13. Derivative Instruments and Hedging Activities.
RESULTS OF OPERATIONS - MIDSTREAM
The Midstream segment develops, owns, operates and acquires domestic midstream infrastructure assets, or invests in other midstream entities, with current focus areas being the DJ and Delaware Basins.
Results of Operations
Highlights for the Midstream segment were as follows:
2018 Significant Midstream Operating Highlights Included:
•
completed the Saddle Butte Acquisition;
•
completed construction of the Coronado, Collier and Billy Miner Train II CGFs in the Delaware Basin;
•
completed construction of freshwater delivery infrastructure and commenced gathering services in the DJ Basin;
•
signed a non-binding letter of intent with Salt Creek for construction of a crude oil pipeline system in the Delaware Basin, for which definitive agreements with Salt Creek were executed in February 2019;
•
commenced natural gas compression in the Delaware Basin; and
•
in first quarter 2019, exercised options to acquire equity interests in the EPIC Y-Grade Pipeline and the EPIC Crude Oil Pipeline.
2018 Midstream Financial Results Included:
•
pre-tax income of $726 million, as compared with pre-tax income of $233 million for 2017;
•
net proceeds of approximately $696 million received, and gain of $503 million recognized, on the sale of our interest in CONE Gathering and sale of our investment in CNX Midstream Partners common units; and
•
capital expenditures, excluding acquisitions, of $521 million, as compared with $399 million for 2017.
Following is a summarized statement of operations for the Midstream segment:
Revenues The amount of revenue generated by the Midstream segment 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, NGLs and natural gas in the markets served directly or indirectly by our midstream assets.
Total revenues for 2018 increased from 2017 primarily due to an increase in crude oil, produced water and natural gas gathering services and fresh water delivery revenues due to the commencement of services in the Greeley Crescent IDP area of the DJ Basin and the Delaware Basin. In addition, in first quarter 2018, Noble Midstream Partners acquired an interest in Black Diamond which completed the Saddle Butte Acquisition of a large-scale integrated gathering system and associated third-party contracts which include transactions for the purchase and sale of crude oil with varying counterparties. The purchases and sales of crude oil are at the prevailing market prices.
Total revenues for 2017 increased from 2016 primarily 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.
Income from Equity Method Investees Midstream's share of operations of equity method investees was as follows:
(1)
Investments were sold in separate transactions in 2018. See Item 8. Financial Statements and Supplementary Data - Note 5. Acquisitions and Divestitures.
Operating Costs and Expenses
Total expense for 2018 increased by $38 million as compared with 2017 due to the following:
•
increase of $21 million due to the addition of expenses associated with the Black Diamond gathering system acquired in the Saddle Butte Acquisition in first quarter 2018;
•
increase of $12 million in gathering, transportation and processing expense associated with the new CGFs in the Delaware Basin and commencement of gathering services in the Mustang IDP area of the DJ Basin.
Total expense for 2017 increased by $33 million as compared with 2016 due to the following:
•
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;
•
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; and
•
increase of $7 million in general and administrative and other expenses, primarily related to increased third-party legal and advisory fees resulting from transactions.
DD&A Expense DD&A expense for 2018 increased by $57 million as compared with 2017 primarily due to tangible assets acquired in the Saddle Butte Acquisition, assets placed in service in 2018, specifically the CGFs in the Delaware Basin and gathering system in the DJ Basin, and an increase of $30 million related to amortization of customer-related intangible assets acquired in the Saddle Butte Acquisition.
DD&A expense for 2017 increased by $11 million as compared with 2016 primarily 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.
Gain on Divestitures, Net Gain on divestitures, net, includes the first quarter 2018 sale of our interest in CONE Gathering and second and third quarter 2018 sales of our investment in CNX Midstream Partners common units. See Item 8. Financial Statements and Supplementary Data - Note 5. Acquisitions and Divestitures.
Salt Creek Joint Venture In October 2018, Noble Midstream Partners entered into a non-binding letter of intent with Salt Creek to form a 50/50 joint venture to construct a 160 MBbl/d day crude oil pipeline system in the Delaware Basin. On February 7, 2019, Noble Midstream Partners executed definitive agreements and completed the formation of Delaware Crossing.
The 95-mile pipeline system will originate in Pecos County, Texas, with additional connections in Reeves County and Winkler County, Texas. The project footprint will be served by a combination of in-field crude oil gathering lines and a trunkline to a hub in Wink, Texas. The project is underpinned by approximately 192,000 dedicated gross acres and nearly 100 miles of gathering pipeline in Pecos, Reeves, Ward and Winkler Counties, Texas. The pipeline is expected to be operational in second quarter 2019.
RESULTS OF OPERATIONS - CORPORATE
Our Corporate costs include exit and certain costs associated with mitigating the effects of our retained Marcellus Shale firm transportation agreements and expenses related to debt, headquarters depreciation, and corporate general and administrative expenses.
Marcellus Shale Firm Transportation Contracts Revenues and expenses associated with retained Marcellus Shale firm transportation contracts were as follows:
(1)
Represents accrued non-cash exit costs related to certain retained Marcellus Shale firm transportation contracts.
See Item 8. Financial Statements and Supplementary Data - Note 10. Marcellus Shale Firm Transportation Contracts.
General and Administrative Expense General and administrative (G&A) expense was as follows:
(1)
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.
On a gross basis, G&A expense for 2018 increased as compared with 2017 primarily due to increased employee overhead related costs and campaign and government relations costs related to Colorado Proposition #112. On a net basis, G&A expense for 2018 decreased as compared with 2017 due to enhanced recovery of overhead costs. The unit rate per BOE was flat as compared with 2017.
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.
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 2018, $56 million in 2017 and $62 million in 2016. See Item 8. Financial Statements and Supplementary Data - Note 17. Stock-Based and Other Compensation Plans.
Loss (Gain) on Extinguishment of Facility or Debt See Item 8. Financial Statements and Supplementary Data - Note 9. Long-Term Debt.
Other Operating Expense, Net See Item 8. Financial Statements and Supplementary Data - Note 2. Additional Financial Statement Information.
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.
Interest expense for 2018 decreased as compared with 2017 primarily due to a decrease in the overall debt balance. In fourth quarter 2017, we repaid our former $550 million Term Loan Facility due January 6, 2019. In 2018, we repaid $379 million of Senior Notes due May 1, 2021 and $230 million, net, on our Revolving Credit Facility. In addition, in third quarter 2017, we conducted a tender offer and refinanced our 8.25% Senior Notes, resulting in a lower interest rate and lower interest expense, gross, for 2018 as compared with 2017. These financing activities were partially offset by an increase in Noble Midstream Partners debt of $475 million, which was primarily used to fund the first quarter 2018 Saddle Butte Acquisition.
Capitalized interest for 2018 increased as compared with 2017 primarily due to higher work in progress amounts related to Leviathan development.
Interest expense for 2017 decreased as compared with 2016 primarily due to the third quarter 2017 refinancing of our 8.25% senior notes and fourth quarter 2017 repayment of our Term Loan Facility due January 6, 2019.
Capitalized interest for 2017 decreased as compared with 2016 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, partially offset by a higher work in progress amount related to the Leviathan development project.
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 offshore West Africa and offshore Eastern Mediterranean. See Item 8. Financial Statements and Supplementary Data - Note 7. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
Income Taxes See Item 8. Financial Statements and Supplementary Data - Note 12. 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 commodity price cycles, 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 merger and acquisition opportunities. We endeavor to maintain a strong balance sheet and an investment grade debt rating in service of these objectives.
We strive to maintain a minimum liquidity level to address volatility and risk. Traditional sources of liquidity are cash flows from operations, cash on hand, proceeds from divestitures of properties and other investments, and available borrowing capacity under our $4.0 billion unsecured Revolving Credit Facility. We occasionally access the capital markets to ensure adequate liquidity exists in the form of unutilized capacity under our Revolving Credit Facility or to refinance scheduled debt
maturities. In 2019, we put in place a $4.0 billion commercial paper program to provide for short-term funding needs. We also evaluate potential strategic farm-out arrangements of our working interests for reimbursement of our capital spending. We periodically consider repatriations of foreign cash to increase our financial flexibility and fund our capital investment program. We also 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.
Our portfolio transformation strategy, primarily executed during 2017, continued into 2018, with the sales of Gulf of Mexico assets, a 7.5% working interest in Tamar, our 50% interest in CONE Gathering LLC, our investment in CNX Midstream Partners common units, and other US onshore assets. As a result, our divestitures generated cash proceeds of approximately $2.0 billion and $2.1 billion in 2018 and 2017, respectively, which were used to improve our capital structure, fund a portion of our capital program, strengthen our liquidity and return value to shareholders through the share repurchase program.
In 2018, we funded our capital program through organic cash flows, proceeds from divestitures and, when needed, borrowings under our Revolving Credit Facility. During the year, we borrowed and repaid amounts under our Revolving Credit Facility, resulting in no amounts outstanding as of December 31, 2018. As a result of our financing activities, we ended 2018 with over $4.7 billion in liquidity, including $4.0 billion of availability under our Revolving Credit Facility.
As of December 31, 2018, our outstanding long-term debt, net of unamortized discount and debt issuance costs and excluding capital lease obligations, totaled $6.4 billion. We may periodically seek to access the capital markets to refinance a portion of our outstanding indebtedness. In addition, we may from time to time seek to retire or purchase our outstanding senior notes 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.
Sources and Uses of Liquidity
Our operating cash flows are a significant source of liquidity. For most of 2018, we experienced strengthening crude oil and NGL prices and completed several divestitures which continued the transformation strategy started in 2017, repositioning our US portfolio to high margin onshore crude oil-rich assets. These activities 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. At the same time, we focused efforts on shareholder return initiatives, including share repurchases and dividends. Additionally, we redeemed $379 million in outstanding senior notes and repaid $230 million of outstanding 2017 borrowings on our Revolving Credit Facility.
Overall, we expect to support our 2019 capital investment program with cash flows from operations, cash on hand, proceeds from divestments of non-strategic assets, issuances of commercial paper, borrowings under our Revolving Credit Facility, and/or other sources of funding.
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 2019. A downgrade below our current investment grade rating could trigger requirements to post collateral as financial assurance of performance under certain contractual arrangements. See Item 1A. Risk Factors - Indebtedness may limit our liquidity and financial flexibility.
The table below summarizes our cash, debt balances and available liquidity:
(1)
As of December 31, 2018, total cash includes cash and cash equivalents of $11 million related to Noble Midstream Partners and $3 million of restricted cash related to amounts held for the divestiture of certain non-core acreage in the Delaware Basin and Noble Midstream Partners collateral on letters of credit. As of December 31, 2017, total cash includes $18 million cash of Noble Midstream Partners and $38 million of restricted cash related to the Saddle Butte Acquisition that closed first quarter 2018. As of December 31, 2016, total cash 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)
Excludes amounts available to be borrowed under the Noble Midstream Services Revolving Credit Facility, which is not available to Noble Energy for general corporate purposes.
(3)
Total debt includes capital lease obligations and excludes unamortized debt discount/premium and debt issuance costs. Additionally, it includes $560 million of Noble Midstream Partners debt as of December 31, 2018.
(4)
We define our ratio of debt-to-book capital as total debt (which includes long-term debt excluding unamortized discount/premium and issuance costs, the current portion of long-term debt, and short-term borrowings) divided by the sum of total debt plus Noble Energy's share of equity.
Cash and Cash Equivalents We had approximately $716 million in cash and cash equivalents at December 31, 2018, primarily denominated in US dollars and invested in money market funds and short-term deposits with major financial institutions. Approximately $456 million of this cash is attributable to our foreign subsidiaries. We do not expect to incur any significant US income tax expense with respect to future repatriation of foreign cash.
Revolving Credit Facilities Noble Energy's Revolving Credit Facility of $4.0 billion and the Noble Midstream Services Revolving Credit Facility of $800 million both mature in 2023. These facilities are used to fund capital investment programs and acquisitions and may periodically provide amounts for working capital purposes. At December 31, 2018, no amounts were outstanding under the Revolving Credit Facility and $60 million was outstanding under the Noble Midstream Services Revolving Credit Facility, leaving $4.0 billion and $740 million in remaining availability under the respective credit facilities. See Item 8. Financial Statements and Supplementary Data - Note 9. Long-Term Debt.
Commercial Paper Program In 2019, we established a commercial paper program, which allows for a maximum of $4.0 billion of unsecured commercial paper notes and is supported by Noble Energy’s Revolving Credit Facility, to provide for short-term funding needs. Commercial paper generally has a maturity of between 1 and 90 days, although it can have a maturity of up to 397 days. The commercial paper is sold under customary terms in the commercial paper market and notes either are issued at a discount price to their principal face value or will bear interest at varying interest rates on a fixed or floating basis. Such discounted prices or interest amounts are dependent on market conditions and ratings assigned to the commercial paper program by the credit agencies at the time of issuance of the commercial paper.
Noble Midstream Services Term Loan Credit Facility In July 2018, Noble Midstream Services entered into the Noble Midstream Services Term Loan Credit Facility that permits aggregate borrowings of up to $500 million. As of December 31, 2018, $500 million was outstanding under this facility, which was used to repay amounts outstanding under the Noble Midstream Services Revolving Credit Facility. See Item 8. Financial Statements and Supplementary Data - Note 9. Long-Term Debt.
Leviathan Term Loan Facility The facility, which provided for a limited recourse secured loan facility with an aggregate principal borrowing amount of up to $1.0 billion, of which $625 million was initially committed, was terminated in December 2018. No amounts were ever drawn on this facility.
Legacy Rosetta Note Redemption In May 2018, we redeemed $379 million of Senior Notes due May 1, 2021, that we had assumed in our acquisition of Rosetta Resources, for $395 million.
Cash Flows
The following table summarizes our net cash flows from operating, investing and financing activities:
Operating Activities In 2018, net cash provided by operating activities increased as compared with 2017, primarily resulting from an increase in net revenues due to rising crude oil and NGL commodity prices, partially offset by higher production costs attributable to increased operational activity and rising costs in US onshore, and a decrease in US natural gas sales volumes. In addition, we made cash settlements of $161 million for commodity derivatives, as compared with cash receipts of $13 million in the prior year and cash interest payments related to outstanding debt of $343 million as compared with $394 million in 2017.
Working capital changes resulted in a $47 million operating cash flow decrease in 2018 as compared with a $150 million operating cash flow decrease in 2017. The changes in working capital were primarily due to an increase in our trade payables for drilling and development costs and midstream capital expenditures and decrease in accounts receivable. The increase was partially offset by the increase in non-current assets, specifically the customer-related intangible asset recorded as part of the Saddle Butte Acquisition in first quarter 2018.
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 as a result of the Marcellus Shale upstream divestiture and lower settlements of commodity derivative instruments. The increase in cash flows from sales was offset by the decrease in settlement 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. In 2017, we made cash interest payments related to outstanding debt of $394 million as compared with $412 million in 2016.
Investing Activities In 2018, capital spending for additions to property, plant and equipment, excluding acquisitions, totaled $3.3 billion as compared with $2.6 billion in 2017. The increase was primarily due to increased development spending for the Delaware Basin, Leviathan Phase 1 and midstream infrastructure. This was partially offset by decreased development spending in the Eagle Ford Shale and on the Marcellus Shale upstream assets and Gulf of Mexico assets following their respective sales. In addition, $653 million was spent on acquisitions during 2018.
During 2018, we received net cash proceeds of $2.0 billion from divestitures. We utilized sales proceeds to support our development activities in core operational areas, redeem senior note balances and further strengthen our liquidity position. See Item 8. Financial Statements and Supplementary Data - Note 5. Acquisitions and Divestitures.
Capital expenditures in 2017 were $2.6 billion, or $1.1 billion higher than capital spent 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 of the increase was related to the initial Leviathan project development.
In 2016, capital spending for property, plant and equipment was $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 $1.2 billion of proceeds from asset divestitures, as compared with $151 million of proceeds from divestitures during 2015.
Financing Activities In 2018, our primary financing activities included a $230 million, net, Revolving Credit Facility repayment and a $25 million, net, Noble Midstream Services Revolving Credit Facility repayment, which included borrowings of $475 million primarily used to fund an acquisition, offset by a repayment of $500 million drawn under the Noble Midstream Services Term Loan Credit Facility. We also used $384 million of cash to redeem senior notes, for which payment of accrued interest of $11 million is reflected in operating activities.
In addition, we used cash of $295 million pursuant to our share repurchase program and paid $208 million of cash dividends to Noble Energy shareholders and $51 million of cash distributions to Noble Midstream Partners noncontrolling interest owners. We also received $353 million of contributions from noncontrolling interest owners. Other financing activities used net cash of $110 million.
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. We also used cash to pay dividends on our common stock of $172 million. See Item 8. Financial Statements and Supplementary Data - Note 9. Long-Term Debt.
See Item 8. Financial Statements and Supplementary Data - Consolidated Statements of Cash Flows.
Acquisition, Capital Expenditures and Other Exploration Expenditures
Our capital expenditures (on an accrual basis) were as follows:
(1)
2018 costs relate to US onshore undeveloped leasehold activity.
2017 costs include $1.6 billion related to the Clayton Williams Energy Acquisition and $246 million related to acquisitions in the Delaware Basin.
2016 costs relate to properties exchanged upon termination of the Marcellus Shale joint development agreement.
(2)
2017 costs include $722 million of proved properties and $63 million of ARO acquired in the Clayton Williams Energy Acquisition and $58 million of proved properties acquired in the Delaware Basin.
(3)
Midstream expenditures include those of Noble Midstream Partners.
2018 includes $206 million related to the Saddle Butte Acquisition.
2017 includes gathering and processing assets of $48 million related to the Clayton Williams Energy Acquisition.
(4)
2017 includes our contribution to the Advantage Pipeline joint venture, in which Noble Midstream Partners owns a 50% interest.
Exploration and development costs increased in 2018 as compared with 2017, primarily due to increased US onshore and Leviathan development activities. Exploration and development costs include approximately $2.0 billion for US onshore and approximately $676 million for Eastern Mediterranean activities primarily related to Leviathan. In addition, Midstream capital spending, exclusive of acquisitions, increased in 2018 due to the construction of gathering systems in the DJ and Delaware Basins.
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, 2018, 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 Contractual Obligations, below.
Contractual Obligations
The following table summarizes certain contractual obligations as of December 31, 2018 that are reflected in the consolidated balance sheets and/or disclosed in the accompanying notes. Unless otherwise noted, all amounts are undiscounted and are net to our interest.
(1)
References are to the Notes accompanying Item 8. Financial Statements and Supplementary Data.
(2)
Long-term debt includes our revolving credit facilities and fixed-rate debt and excludes unamortized discounts, premiums, debt issuance costs and capital lease obligations.
(3)
Interest payments are based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2018.
(4)
Annual capital lease payments exclude regular maintenance and operational costs.
(5)
Purchase and service obligations represent 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.
(6)
Amount includes exit cost obligations resulting from a permanent capacity assignment. In addition, we entered into a permanent capacity assignment in January 2019 which reduced the undiscounted financial commitment by approximately $350 million.
(7)
Operating lease obligations represent non-cancelable leases for office buildings, facilities and equipment used in our daily operations, such as drilling rigs, vessels and compressors. Annual lease payments exclude regular maintenance and operational costs.
(8)
The table excludes deferred compensation liabilities of $147 million as specific payment dates are unknown. See Item 8. Financial Statements and Supplementary Data - Note 17. Stock-Based and Other Compensation Plans.
(9)
AROs are discounted.
(10)
Amount represents commodity derivative instruments that were in a net payable position with the counterparty at December 31, 2018.
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 several years, and failure to conduct such exploration activities within the prescribed periods could lead to loss of leases or exploration rights and/or penalty payments.
Continuous Development Obligations Certain of our US onshore assets, such as our Eagle Ford Shale and Delaware Basin properties, are primarily held through continuous development obligations. Therefore, we are contractually obligated to fund a level of development activity in these areas which could be substantial, or exercise options with land owners to extend leases. Failure to meet these obligations may result in the loss of leases.
Leviathan Natural Gas Project The initial development of the Leviathan field requires substantial infrastructure and capital; therefore, we have executed major equipment and installation contracts in support of these activities. As of December 31, 2018, we had entered into approximately $176 million, net, of contracts to support the remaining development activities and bring first production online by the end of 2019.
OIL Contingency As of December 31, 2018, we accrued approximately $28 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, 2018.
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, including Noble Midstream Partners, totaled approximately $89 million at December 31, 2018.
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. See Item 1A. Risk Factors - Indebtedness may limit our liquidity and financial flexibility.
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 We estimate proved oil and gas reserves according to the definition of proved reserves provided by the SEC and the Financial Accounting Standards Board (FASB). Reserves estimates have a significant impact on our financial statements as they are used as an input in the calculation of DD&A expense and in impairment assessments for crude oil and natural gas properties and goodwill.
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, and production data and on historical 12-month average commodity 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, NGLs and natural gas 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, NGL and natural gas 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. For 2018, a 10% reduction in estimates of proved reserves across all properties would have increased DD&A expense by approximately $190 million.
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 or goodwill exceeds fair value and could result in an impairment charge, which would reduce earnings. See Item 8. Financial Statements and Supplementary Data - Supplemental Oil and Gas Information (Unaudited).
Oil and Gas Properties - Successful Efforts Method of Accounting
Description We account for crude oil and natural gas properties under the successful efforts method of accounting which 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.
The alternative method of accounting for crude oil and natural gas properties is the full cost method under which 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, 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 determining whether unproved crude oil and natural gas properties are impaired, we apply significant 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 both 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. For the purpose of impairment testing as of December 31, 2018, 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.
For capitalized exploratory well costs, significant judgment is required in order to determine whether sufficient progress has been made in assessing the reserves and the economic and operational viability of a project in order to continue capitalization of such costs. Such assessment requires consideration of the following factors: commitment of project personnel, costs incurred to assess reserves and potential development, progress of 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 the determination not to pursue certain projects, resulting in future write-offs of the capitalized exploratory well costs.
Calculation of unit-of-production rates for DD&A purposes 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 At year-end, the net book value of our unproved properties includes significant amounts allocated in previous business combinations or acquisitions. 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. Unfavorable changes in pricing and cost assumptions in the future may result in negative revisions to proved and/or unproved reserves and associated cash flows, causing us to record impairment of proved and/or unproved oil and gas properties. An impairment of a proved or unproved property could result in a significant decrease in earnings.
If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs would be charged to exploration expense in future periods, resulting in a decrease in earnings. See Item 8. Financial Statements and Supplementary Data - Note 7. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
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.
Purchase Price Allocations and Resulting Goodwill
Description We use the acquisition method to account for certain business combinations. This method requires us to allocate the acquisition cost to assets acquired and liabilities assumed based on fair values as of the acquisition date, with any difference recorded either as goodwill or gain on bargain purchase. 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. Any goodwill recognized is subsequently assessed for impairment through an initial qualitative assessment, followed by the application of the quantitative test.
Judgment and Uncertainties Estimation of the fair values of assets acquired and liabilities assumed in a business combination requires that we make various assumptions, the most significant of which 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, NGL and natural gas reserves utilizing the income approach. The primary assumptions used to arrive at estimates of future net cash flows used in the income approach include reserves quantities, future 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 risk 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 that, in management's judgment, are reasonable.
For other assets acquired in business combinations, we use judgment to determine the appropriate combination of available cost and market data and/or estimated cash flows to determine the fair values. 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.
The initial qualitative goodwill impairment assessment also involves significant judgment, as we are required to examine 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.
Management must make estimates regarding the fair value of the reporting unit to which goodwill has been assigned. We use a combination of the income and market approaches to determine the fair value of a reporting entity. These approaches result in fair values that are subject to a high degree of estimation uncertainty as they require us to make assumptions and apply judgment to various parameters that are sensitive to industry, market and economic conditions. Inputs for the income approach include estimates of both proved reserves and risk-adjusted unproved reserves; market prices considering forward commodity price curves as of the measurement date; and operating, administrative and capital costs adjusted for inflation. Inputs for the market approach include selection of comparable companies and/or comparable recent company and asset transactions and transaction premiums as well as selected company financial metrics, such as EBITDAX.
Effect if Actual Results Differ from Assumptions Although we based the fair value estimate of the US reporting unit on assumptions we believed to be reasonable, those assumptions were inherently unpredictable and uncertain. Changes in assumptions, such as an increase in commodity prices or a decrease in discount rates, could have resulted in a lesser amount of impairment or no goodwill impairment at all. For example, we conducted our annual goodwill impairment assessment, concluding that the goodwill allocated to the Texas reporting unit was fully impaired. See Item 8. Financial Statements and Supplementary Data - Note 6. Goodwill Impairment.
The estimated fair values assigned to assets acquired and liabilities assumed in a purchase price allocation can have a significant effect on future results of operations. For example, a higher fair value assigned to a property results in higher DD&A expense, which results in lower net income. In addition, 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 the estimates originally used to determine fair value, the resulting reductions in future cash flows could indicate that a property is impaired.
In addition, 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 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. In the event of a prolonged industry downturn, commodity prices could again become depressed or decline, thereby causing the fair values of our reporting units to decline, which could result in an impairment of goodwill. A property or goodwill 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.
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.
Exit Costs
Description Our consolidated balance sheets include accrued exit cost liabilities relating to retained Marcellus Shale natural gas firm transportation contracts.
Judgment and Uncertainties We are required to make significant judgments and estimates regarding the timing and amount of recognition of exit cost liabilities, taking into consideration current commercialization activities related to the retained firm transportation contracts and/or the potential occurrence of a cease-use date. We must consider, among other factors, the status of negotiations with counterparties regarding permanent assignment or capacity release of our contract commitments and the likelihood of capacity utilization through purchase of third-party natural 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 Although we based the initial fair value estimate of our accrued exit cost liabilities on assumptions we believed to be reasonable, those assumptions were inherently unpredictable and uncertain. Changes in assumptions, such as a reduced likelihood of capacity utilization through purchase of third-party natural gas, could have resulted in a higher exit cost accrual, higher current period expense, and lower future expense. For example, as of December 31, 2018, we have a significant remaining financial commitment associated with Marcellus Shale firm transportation contracts. We cannot guarantee that our current commercialization efforts for these contracts will be successful, and, in the
future, 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 10. Marcellus Shale Firm Transportation Contracts.
Income Tax Expense and Deferred Tax Assets
Description Our consolidated balance sheets include deferred tax assets and liabilities relating to temporary differences, operating losses, and tax-credit carryforwards. Valuation allowances may reduce the deferred tax assets if it is more likely than not that some portion or all of the deferred tax assets will not be realized.
Judgment and Uncertainties Estimates of amounts of income tax to be recorded involve interpretation of complex tax laws 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.
In determining whether a valuation allowance is required for our deferred tax asset balances, we consider all available evidence (both positive and negative) including, 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 rates, timing of development activities, profitability of future business strategies and forecasted economics in the oil and gas industry. Judgment is also required in considering the relative weight of negative and positive evidence. 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 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. Changes to our current financial position, results of operations, projected future taxable income, tax planning strategies and/or new tax legislation may be deemed significant enough to necessitate a change to our deferred tax asset valuation allowances in the future, in which case the increases or decreases could significantly impact net income through offsetting changes in income tax expense. See Item 8. Financial Statements and Supplementary Data - Note 12. Income Taxes.

ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
We are exposed to market risk in the normal course of business operations, and the volatility of crude oil and natural gas prices continues to impact the oil and gas industry.
Derivative Instruments Held for Non-Trading Purposes Due to commodity price volatility, we may use derivative instruments as a means of managing our exposure to price changes.
At December 31, 2018, we had various open commodity derivative instruments related to crude oil and 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 asset position with a fair value of $153 million. Based on the December 31, 2018 published commodity futures price curves for the underlying commodities, a hypothetical price increase of 10% per Bbl for crude oil and 10% per MMBtu for natural gas would decrease the fair value of our net commodity derivative asset by approximately $272 million.
Even with certain hedging arrangements in place to mitigate the effect of commodity price volatility, our 2019 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

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," as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. 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, 2018, 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, 2018, 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, 2018 which is included herein.
Noble Energy, Inc.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
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, 2018 and 2017, the related consolidated statements of operations and comprehensive income (loss), shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2018, 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, 2018 and 2017, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2018, 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, 2018, 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 19, 2019 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 19, 2019
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
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, 2018, 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, 2018, 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, 2018 and 2017, the related consolidated statements of operations and comprehensive income (loss), shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2018, and the related notes (collectively, the consolidated financial statements), and our report dated February 19, 2019 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 19, 2019
Noble Energy, Inc.
Consolidated Statements of Operations and Comprehensive Income (Loss)
(millions, except per share amounts)
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 (until April 2018); Eastern Mediterranean; and West Africa. Our Midstream segment develops, owns, operates and acquires domestic midstream infrastructure assets, or invests in other midstream entities, with current focus areas being the DJ and Delaware Basins.
Basis of Presentation and Consolidation We use accounting policies that 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. For the periods presented, net income or loss is materially consistent with comprehensive income or loss.
Segment Information Accounting policies are consistent across geographical segments. Transfers between segments are accounted for at market value. We do not consider interest income or expense and income tax benefit or expense in our evaluation of the performance of geographical segments. See Note 3. Segment Information.
Consolidated Variable Interest Entity (VIE) Noble Energy has determined that the partners with equity at risk in Noble Midstream Partners LP (Noble Midstream Partners) lack the authority, through voting rights or similar rights, to direct the activities that most significantly impact Noble Midstream Partners' economic performance; therefore, Noble Midstream Partners is considered a VIE. Through Noble Energy's ownership interest in Noble Midstream GP LLC (the General Partner to Noble Midstream Partners), Noble Energy has the authority to direct the activities that most significantly affect economic performance and the obligation to absorb losses or the right to receive benefits that could be potentially significant to Noble Midstream Partners. Therefore, Noble Energy is considered the primary beneficiary and consolidates Noble Midstream Partners.
Noncontrolling Interests In third quarter 2016, 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. We also present third-party ownership in Noble Midstream Partners' consolidated non-wholly owned subsidiaries as noncontrolling interests. See Note 5. Acquisitions and Divestitures.
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 on our consolidated balance sheets. Within our consolidated statements of cash flows, activity is reflected within cash flows provided by operating activities and cash flows 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 15. Equity Method Investments.
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.
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, NGL and natural gas reserves are the most significant of our estimates. All of 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, NGLs and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil, NGL and natural gas reserves. The accuracy of any reserves estimate is a function of the quality
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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, NGLs and natural gas that are ultimately recovered. Qualified petroleum engineers in our Houston and Denver offices prepare all reserves estimates for our different geographical regions. These reserves estimates are reviewed and approved by senior engineering staff and division management with final approval by the Senior Vice President - Corporate Development and certain members of senior management. See Supplemental Oil and Gas Information (Unaudited).
Other items subject to estimates and assumptions include the carrying amounts of inventory, property, plant and equipment, goodwill, exit costs and 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 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.
Reclassifications The revenues and expenses associated with mitigating Marcellus Shale retained firm transportation contracts, including costs associated with exiting certain of those contracts, were reclassified from our oil and gas exploration and production segment to Corporate as these items are not representative of retained upstream operations. See Note 3. Segment Information.
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.
•
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 14. 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.
Accounts Receivable and Allowance for Doubtful Accounts 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. The majority of these receivables have payment terms of 30 days or less. Our accounts receivable reflect a broad national and international customer base, which limits our exposure to concentrations of credit risk. We continually monitor the creditworthiness of the counterparties and we have obtained credit enhancements from some parties in the form of parental guarantees or letters of credit.
We routinely assess the recoverability of all material receivables to determine their collectibility. We accrue a reserve on a receivable when, based on management’s judgment, it is probable that a receivable will not be collected and the amount of such reserve may be reasonably estimated. See Note 2. Additional Financial Statement Information.
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 assets will be reduced to their fair value if the carrying amount exceeds net realizable value. The cost of crude oil inventory includes production costs and depreciation, depletion and amortization (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:
Oil and Gas Properties (Successful Efforts Method of Accounting) 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, NGL and natural gas reserves on a field-by-field basis, 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 ranging from three to thirty years. Upon sale or retirement of depreciable or depletable property, the cost and related
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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.
Proved 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. Under such test, 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. Other long-lived assets, such as our midstream assets, are evaluated in a manner consistent with our policy for proved property.
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.
We recorded impairment charges in 2018, 2017 and 2016 and it is possible that other assets could become impaired in the future. See Note 14. Fair Value Measurements and Disclosures.
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, NGL and natural gas reserves, future commodity prices and future costs to produce the reserves. Cash flow estimates related to probable and possible reserves are reduced by additional risk-weighting factors.
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 7. 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 oil and gas properties acquired in transactions accounted for as business combinations by preparing estimates of cash flows from the production of crude oil, NGL and natural gas reserves. We estimate future prices to apply to the estimated reserves quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net cash flows. For the fair value assigned to proved reserves, future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the business combination. When estimating and valuing unproved reserves, discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors.
For other assets acquired in business combinations, we use a combination of available cost and market data and/or estimated cash flows to determine the fair values.
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 on 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.
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 international projects, it may take us more than one year to evaluate the future potential of the exploratory well
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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, permits and approvals and we believe they will be obtained. We assess the status of suspended exploratory well costs on a quarterly basis. See Note 7. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
Property, Plant and Equipment, Other Other property includes automobiles, trucks, airplanes, office furniture, computer equipment, buildings, leasehold improvements and other fixed assets. These items are recorded at cost and are depreciated using the straight-line method based on expected lives of the individual assets or group of assets, ranging from three to thirty years. Other property also includes linefill, which is recorded at cost to produce into the production line. Linefill is not subject to depreciation but is reviewed for impairment.
Capitalization of Interest We capitalize interest costs associated with the development and construction of significant properties or projects to bring them to a condition and location necessary for their intended use, which for crude oil and natural gas assets is at first production from the field. Interest is capitalized using an interest rate equivalent to the weighted average interest rate we pay on long-term debt, including our unsecured revolving credit facilities and bonds. Capitalized interest is included in the cost of oil and gas assets and is amortized with other costs on a unit-of-production basis. Capitalized interest totaled $73 million in 2018, $49 million in 2017, and $84 million in 2016.
Asset Retirement Obligations 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 we have an existing legal obligation associated with the retirement that can reasonably be estimated. The associated asset retirement cost is capitalized as part of the carrying value of the oil and gas asset. The asset retirement cost is recorded at estimated fair value, measured by the expected future cash outflows required to satisfy the 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 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 8. Asset Retirement Obligations.
Goodwill Goodwill is not amortized to earnings but is assessed for impairment at the reporting unit level on an annual basis, or more frequently as circumstances require. We use qualitative and quantitative assessments to determine whether goodwill is impaired. If we conclude that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, an impairment charge is recognized for the amount by which the carrying amount exceeds the fair value.
We conducted our annual goodwill impairment assessment as of September 30, 2018. As of that date, our consolidated balance sheet included goodwill of $1.4 billion, of which $1.3 billion was allocated to our Texas reporting unit, included within our oil and gas exploration and production segment, and $110 million was allocated to our Midstream reporting unit. At that time, we concluded that goodwill was not impaired. During fourth quarter 2018, we considered changes to facts and circumstances, particularly the decline in WTI strip pricing, increase in operating and capital costs, as well as our development plan, and concluded that the goodwill allocated to the Texas reporting unit was fully impaired and recorded a charge of $1.3 billion. See Note 6. Goodwill Impairment.
Intangible Assets Intangible assets consist of customer contracts and relationships acquired by Noble Midstream Partners through Black Diamond in its acquisition of Saddle Butte Rockies Midstream, LLC and affiliates (collectively, Saddle Butte). We recorded the intangible assets at their estimated fair values at the date of acquisition. Amortization is calculated using the straight-line method, which reflects the pattern in which the estimated economic benefit is expected to be received over the estimated useful life of the intangible assets, which is currently over periods of seven to 13 years. As of December 31, 2018, the net book value of our intangible assets was $310 million. Amortization expense, which is equivalent to accumulated amortization for 2018, of $30 million is included in DD&A expense in our consolidated statements of operations and statements of cash flows. Intangible assets with finite useful lives are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. See Note 5. Acquisitions and Divestitures.
Exit Costs In accordance with Accounting Standards Codification (ASC) 420 - Exit or Disposal Cost Obligations, we recognize the fair value of a liability for an exit cost in the period in which a liability is incurred. The recognition and fair value estimation of an exit cost liability requires that management take into account certain estimates and assumptions including: 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 exit cost liabilities at estimated fair value, based on expected future cash outflows required to satisfy the obligation, net of estimated recoveries, and discounted. In periods subsequent to initial measurement,
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Notes to Consolidated Financial Statements
changes to an exit cost 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.
Exit cost liabilities are included in other current and other noncurrent liabilities on our consolidated balance sheets. Exit costs, and associated accretion expense, are included in other operating expense, net in our consolidated statements of operations.
Accrued exit costs at December 31, 2018 and 2017 relate primarily to estimated costs associated with Marcellus Shale contracts. See Note 10. Marcellus Shale Firm Transportation Commitments.
Derivative Instruments and Hedging Activities All derivative instruments (including certain derivative instruments embedded in other contracts) are recorded on our consolidated balance sheets as either an asset or liability and are 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 against 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. See Note 13. Derivative Instruments and Hedging Activities.
Stock-Based Compensation Restricted stock and stock options issued to employees and directors are recorded on grant-date at 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 ASC 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 17. Stock-Based and Other Compensation Plans.
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, 2018 represents unrecognized net actuarial loss and unrecognized prior service cost related to our restoration plan. These amounts are currently being recognized as net periodic benefit cost pursuant to our historical accounting policy for amortizing such amounts. Any actuarial gains and losses that arise during the plan year, but which are not required to be recognized as net periodic benefit cost in the same period, are recognized as a component of AOCL.
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 11. 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.
Income Taxes and Impact of Tax Reform Legislation 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.
We account for income taxes using 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.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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 12. 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 We recognize revenue at an amount that reflects the consideration to which we expect to be entitled in exchange for transferring goods or services to a customer, using a five-step process, in accordance with ASC 606 - Revenue from Contracts with Customers. See Note 4. Revenue from Contracts with Customers.
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. In the event of a net loss, we exclude the effect of outstanding common stock equivalents from the calculation of diluted EPS as the inclusion would be anti-dilutive.
Recently Issued Accounting Standards
Leases In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2016-02 (ASU 2016-02): Leases. The standard requires lessees to recognize a right of use asset (ROU asset) and lease liability on the balance sheet for the rights and obligations created by leases. 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. In July 2018, the FASB issued Accounting Standards Update No. 2018-11 (ASU 2018-11): Leases (Topic 842): Targeted Improvements, which provides for an alternative transition method by allowing entities to initially apply the new leases standard at the adoption date (January 1, 2019) and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption (comparative periods presented in the financial statements will continue to be in accordance with current GAAP (Topic 840, Leases)). The standard is 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, field services and well equipment, office space and other assets. We adopted the new standard on the effective date of January 1, 2019, using a modified retrospective approach as permitted under ASU 2018-11.
The new standard provides a number of optional practical expedients in transition. We expect to:
•
elect the package of 'practical expedients', which permits us not to reassess under the new standard our prior conclusions about lease identification, lease classification and initial direct costs;
•
elect the practical expedient pertaining to land easements and plan to account for existing land easements under our current accounting policy;
•
elect the short-term lease recognition exemption for all leases that qualify and, as such, no ROU asset or lease liability will be recorded on the balance sheet and no transition adjustment will be required for short-term leases; and
•
elect the practical expedient to not separate lease and non-lease components for all of our leases.
We do not expect to elect the hindsight practical expedient in determining the lease term and assessing impairment of ROU assets when transitioning to ASC 842.
We continue to execute a project plan, which includes contract review and assessment, data collection, and evaluation of our systems, processes and internal controls. In addition, we have implemented a new lease accounting software which will facilitate the adoption of this standard.
While we are finalizing our assessment of the effect of adoption, we do not expect the adoption and implementation of this standard will have a material effect on our financial statements. We estimate the most significant impact will relate to the recognition of new ROU assets and lease liabilities on our balance sheet for operating leases, as well as additional disclosures. Consequently, with adoption, we expect to recognize additional operating liabilities ranging between $200 million to $350 million with corresponding ROU assets of the same amount based on the present value of the remaining minimum rental payments under current leasing standards for existing operating leases.
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 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 standard is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. From evaluation of our current credit portfolio, which includes receivables for commodity sales,
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Notes to Consolidated Financial Statements
joint interest billings due from partners and other receivables, historical credit losses have been de minimis and we believe that our expected future credit losses would not be significant. As such, we do not believe adoption of the standard will have a material impact on our financial statements.
Derivatives and Hedging - Targeted Improvements to Accounting for Hedging Activities In August 2017, the FASB issued Accounting Standards Update No. 2017-12 (ASU 2017-12): Derivatives and Hedging - Targeted Improvements to Accounting for Hedging Activities. The update is intended to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition to that main objective, ASU 2017-12 makes certain targeted improvements to simplify the application of the hedge accounting guidance in current US GAAP. The amended standard is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. We are currently evaluating the provisions of ASU 2017-12.
Intangibles - Goodwill and Other - Internal-Use Software In August 2018, the FASB issued Accounting Standards Update No. 2018-15 (ASU 2018-15): Intangibles - Goodwill and Other - Internal-Use Software to align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The amended standard is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. We are currently evaluating the provisions of ASU 2018-15.
Recently Adopted Accounting Standards
Topic 606, Revenue from Contracts with Customers In May 2014, the FASB issued Accounting Standards Update No. 2014-09 (ASU 2014-09), which creates Topic 606, Revenue from Contracts with Customers (ASC 606). We adopted ASC 606 on January 1, 2018, using the modified retrospective method. See Note 4. Revenue from Contracts with Customers.
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. We adopted ASU 2016-18 in the first quarter of 2018, using the retrospective method. ASU 2016-18 requires that restricted cash and 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. There are no other impacts on our results of operations, financial condition or cash flows.
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 standard, we will perform our 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 early adopted this ASU in fourth quarter 2018. This adoption did not have a material impact on our financial statements.
Accumulated Other Comprehensive Income In February 2018, the FASB issued Accounting Standards Update No. 2018-02 (ASU 2018-02): Income Statement - Reporting Comprehensive Income to allow reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Reform Legislation. ASU 2018-02 is effective for annual and interim periods beginning after December 15, 2018, with early adoption permitted. We early adopted this ASU in fourth quarter 2018, reclassifying the tax effect of approximately $6 million stranded in accumulated other comprehensive income to retained earnings. This adoption did not have a material impact on our financial statements.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 2. Additional Financial Statement Information
Statements of Operations Information Other statements of operations information is as follows:
(1)
As part of the Saddle Butte Acquisition in first quarter 2018, we acquired certain contracts which include the purchase and sale of crude oil with third parties. In addition, we entered into certain transactions beginning in first quarter 2018 for the purchase of third-party natural gas and the subsequent sale of natural gas to other third parties. The natural gas is transported through firm transportation capacity we retained following the Marcellus Shale upstream divestiture in second quarter 2017 and is part of our mitigation efforts to utilize capacity and reduce our financial commitment. See Note 3. Segment Information and Note 10. Marcellus Shale Firm Transportation Commitments.
(2)
Amounts relate to shortfalls in transporting or processing minimum volumes under certain financial commitments primarily in the DJ Basin for 2018 and in the DJ Basin and Marcellus Shale for 2017 (prior to the Marcellus Shale upstream divestiture) and 2016.
(3)
Gains due to downward ARO revisions in locations where we have no remaining assets. See Note 8. Asset Retirement Obligations.
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Notes to Consolidated Financial Statements
Balance Sheet Information Other balance sheet information is as follows:
(1)
We bill partners for their share of expenses of joint venture projects for which we are the operator. These projects, especially those in deepwater or remote international locations, can be very capital cost intensive. Our receivables from joint interest billings decreased significantly in 2018 due to the second quarter 2018 sale of our Gulf of Mexico offshore assets.
(2)
Assets held for sale at December 31, 2018 include certain proved and unproved non-core acreage in Reeves County, Texas. 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 field, our investment in Southwest Royalties, Inc. acquired in the Clayton Williams Energy Acquisition, and the CONE investments, including
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Notes to Consolidated Financial Statements
CONE Midstream and CONE Gathering. Liabilities associated with assets held for sale primarily represent ARO and other liabilities to be assumed by the purchaser. See Note 5. Acquisitions and Divestitures.
(3)
Balance at December 31, 2018 represents amounts held for the divestiture of certain non-core acreage in the Delaware Basin and Noble Midstream Partners collateral on letters of credit. Balance at December 31, 2017 represents amount held in escrow pending closing of the Saddle Butte Acquisition. See Note 5. Acquisitions and Divestitures.
(4)
Amount relates to intangible assets acquired in the Saddle Butte Acquisition. See Note 5. Acquisitions and Divestitures.
Reconciliation of Total Cash We define total cash as cash, cash equivalents and restricted cash. The following table provides a reconciliation of total cash:
A significant portion of our cash is located in 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.
Supplemental statements of cash flow information are as follows:
Note 3. Segment Information
We have the following reportable segments: United States (US onshore and Gulf of Mexico (until April 2018)); Eastern Mediterranean (Israel and Cyprus); West Africa (Equatorial Guinea, Cameroon and Gabon); Other International (Suriname, Falkland Islands, Canada, and New Ventures); and Midstream. The Midstream segment includes the consolidated accounts of Noble Midstream Partners, US onshore equity method investments and other US onshore midstream assets.
The geographical reportable segments are in the business of crude oil and natural gas acquisition and exploration, development, and production (Oil and Gas Exploration and Production). The Midstream reportable segment develops, owns, and operates domestic midstream infrastructure assets, as well as invests in other financially attractive midstream projects, with current focus areas being the DJ and Delaware Basins. To assess the performance of Noble Energy's operating segments, the chief operating decision maker analyzes income (loss) before income taxes. Management believes income (loss) before income taxes provides information useful in assessing the Company's operating and financial performance across periods.
Expenses related to debt, headquarters depreciation, corporate general and administrative expenses, exit costs and certain costs associated with mitigating the effects of our retained Marcellus Shale firm transportation agreements, are recorded at the corporate level.
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Notes to Consolidated Financial Statements
Noble Energy, Inc.
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Noble Energy, Inc.
Notes to Consolidated Financial Statements
(1)
Intersegment eliminations related to income (loss) 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.
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.
Both BP and Shell purchased crude oil and condensate domestically from our US onshore operations and from our Gulf of Mexico operations prior to selling the Gulf of Mexico assets in second quarter 2018. No other single purchaser accounted for 10% or more of crude oil, NGL and natural gas sales in 2018. We maintain credit insurance associated with specific purchasers and believe that the loss of any one purchaser would not have a material effect on our financial position or results of operations as there are numerous potential purchasers of our production.
Note. 4. Revenue from Contracts with Customers
Our revenue is derived from the sale of crude oil, NGL and natural gas production, primarily to crude oil refining companies, midstream marketing companies, marketers, industrial companies, electric utility companies, independent power producers and cogeneration facilities, among others. We account for revenue in accordance with ASC 606, Revenue from Contracts with Customers (ASC 606), which we adopted on January 1, 2018 using the modified retrospective method. Under ASC 606, performance obligations are the unit of account and generally represent distinct goods or services that are promised to customers. For sales of crude oil, NGLs and natural gas, each unit sold is generally considered a distinct good and the related performance obligation is generally satisfied at a point in time. We recognize our sales revenues at a point in time and upon delivery to a customer at the contractually stated price and for the quantity of product delivered. In Israel, because our contracts are long-term arrangements, we recognize revenues from the sale of natural gas over the life of the contract based on the quantity of natural gas delivered.
ASC 606 provides additional clarification related to principal versus agent considerations. Under this guidance, we record revenue on a gross basis if we control a promised good or service before transferring it to a customer (acting as principal). For example, gathering, processing, transportation and fractionation costs incurred before transfer of control to the customer at the tailgate of a plant are accounted for as fulfillment costs and are presented as a component of gathering, transportation and processing expense in our consolidated statements of operations. On the other hand, we record revenue on a net basis if our role is to arrange for another entity to provide the goods or services (acting as agent). For example, costs incurred after control over the product has transferred to the customer, such as at the wellhead or inlet of a plant, are recorded as a reduction of the transaction price received within revenue.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Certain of our contracts for the sale of commodities contain embedded derivatives. We have elected the normal purchases and normal sales scope exception as provided by ASC 815, Derivatives and Hedging, and will account for such contracts in accordance with ASC 606.
In the US, we enter into marketing agreements with our non-operating partners to market and sell their share of production to third parties. We have determined that we act as an agent in such arrangements and account for such arrangements on a net basis.
ASC 606 adoption did not have an impact on the opening balance of retained earnings. The adoption impact on revenues and expenses for 2018 was less than $1 million and did not affect operating or net income or operating cash flows. The comparative information for the prior period has not been recast and continues to be reported under the accounting standards in effect for the period. Adoption of the new standard did not impact our financial position, and we do not expect that it will do so going forward. See Note 3. Segment Information for disaggregation of revenue by commodity and geographic location.
Changes to the presentation of commodity sales revenue and production expense resulted from our assessment of certain contractual arrangements under principal versus agent guidance and assessment of control under ASC 606. In particular, we have determined that the processor is our customer with regard to the sale of natural gas at the wellhead or the sale of NGLs at the tailgate. This is a change from previous conclusions reached under principal versus agent guidance per ASC 605, Revenue Recognition, where we previously determined that we retained control over our production until the sale to the end customer in the downstream markets. As such, effective January 1, 2018, revenues and expenses are presented on a net basis within revenues in our consolidated statements of operations at the time control over production is transferred to the processor under these arrangements.
Following the control model in ASC 606, we determined that we remain the principal in arrangements with end customers, such as when we take product in-kind at the tailgate and when we are directly responsible for the transportation and marketing of our production to downstream customers. In such arrangements, we record NGL and natural gas sales and production expense on a gross basis.
Our commodity sales contracts in the US are index-based and, thus, include variable consideration. In accordance with ASC 606, we allocate variable consideration (market price) to the distinct commodities transferred in the period, but not to the future obligations to deliver production. Such allocation represents the amount of consideration to which we are entitled for deliveries of our commodities to-date and represents the value of product delivered to the customer. Therefore, our revenue is recognized at the time of delivery and is the product of the volume delivered and the index-based price for the period.
The following is a summary of our types of revenue arrangements by commodity and geographic location.
Exploration and Production Revenue Arrangements
Crude Oil Sale Arrangements - US We sell the majority of our US crude oil production under short-term contracts at market-based prices, adjusted for location, quality and transportation charges. Market-based pricing is based on the price index applicable for the location of the sale.
We sell our crude oil production either at the lease location or to downstream customers. Crude oil production at the lease location is sold through netback arrangements, under which we sell crude oil net of transportation costs incurred by the purchaser. We record revenue, net, at the lease location when the customer receives delivery of the product.
When we move our crude oil production from the lease location to the downstream markets in the US, we incur gathering and transportation costs, which we consider contract fulfillment activities. Such costs are reported as expense within gathering, transportation and processing expense in the consolidated statements of operations. Revenue from the sale of crude oil to downstream customers is recognized upon delivery, as specified in the contract, when control of the product has transferred to the customer.
In second quarter 2018, we entered into a long-term contract to sell firm quantities of crude oil under index-based prices adjusted by applicable fees, including transportation, insurance, and marketing.
Crude Oil Buy/Sell Transactions - US We enter into buy/sell arrangements that effect a change in location and/or grade with required repurchase of crude oil at a delivery point. The sale and repurchase of crude oil is settled at the same contractually fixed price (before application of transportation and grade deductions) on a net basis. We account for these transactions on a net basis, in accordance with ASC 845, Nonmonetary Transactions. We record the residual transportation fee as transportation expense within gathering, transportation and processing expense in the consolidated statements of operations.
Crude Oil Sale Arrangements - West Africa Our share of crude oil and condensate from the Aseng, Alen and Alba fields is sold at market-based prices to Glencore Energy UK Ltd. (Glencore Energy). Crude oil is priced at a Dated Brent FOB net realized price achieved by Glencore Energy and is adjusted by applicable fees, including transportation, insurance, and marketing. We recognize revenue on the sale of crude oil to Glencore Energy at the time crude oil cargo is loaded onto the
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tanker and control transfers to Glencore Energy. We record revenue at the realized price received from Glencore Energy, net of applicable fees.
Natural Gas and NGLs Sale Arrangements - US Certain of our commodity contracts in the US are for the sale of natural gas to processors at prevailing market prices. We evaluate the contract terms of these arrangements to determine whether the processor is a service provider or a customer on a contract by contract basis. In arrangements where we determine that we sold our product to the processor, we treat the processor as a customer and record revenue when the processor takes physical possession of the natural gas and NGLs and in the amount of proceeds expected to be received, net of any fees or deductions charged by the processor.
In other natural gas processing arrangements, we receive natural gas and NGL products "in-kind" after processing at the tailgate of the plant. In these arrangements, we are responsible for the transportation, fractionation and marketing costs of our production. In such cases, where we have determined that the processor is a service provider, we record the sale of natural gas and NGLs and applicable gathering, processing, transportation and fractionation fees on a gross basis at the time the product is delivered to the end customer.
Natural Gas Purchase and Sale Arrangements - US We enter into purchase transactions and separate sale transactions with third parties at prevailing market prices to mitigate unutilized pipeline transportation commitments, primarily related to retained Marcellus Shale firm transportation contracts. Revenues and expenses from the sales and purchases are recorded on a gross basis, as we act as a principal in these transactions by assuming control of the purchased commodity before it is transferred to the customer.
Natural Gas Sale Arrangements - West Africa We sell our share of natural gas production from the Alba field under a long-term contract for $0.25 per MMBtu to a methanol plant, a liquefied petroleum gas (LPG) plant, a liquefied natural gas (LNG) plant and a power generation plant. We recognize revenue upon transfer of control of product to these processors.
Natural Gas Sale Arrangements - Israel Our natural gas sales in Israel are primarily based on long-term contracts with fixed volume commitments over the life of the arrangements. Our performance obligations for the sale of natural gas are satisfied over time using production output to measure progress. The nature of these contracts gives rise to several types of variable consideration, including index-based annual price escalations, commodity-based index pricing, tiered pricing and sales price discounts in periods of volume deficiencies. Additionally, the majority of our sales contracts contain take-or-pay provisions where the customers are required to purchase a contractual minimum over varying time periods. Where the variable consideration is related to market-based pricing or index-based escalations of a fixed base price, we have elected the variable consideration allocation exception pursuant to ASC 606. We record revenue related to the volumes delivered at the contract price at the time of delivery. To date, there have been no material impacts of variability in consideration due to tiered pricing, take-or-pay provisions and/or volume deficiency discounts. We believe that any variability due to future sales price adjustments associated with potential volume deficiencies will not have a significant impact on our financial position or results of operations.
Transaction Price Allocated to Remaining Performance Obligations - Israel Remaining performance obligations represent the transaction price of firm sales arrangements for which volumes have not been delivered. Pursuant to ASC 606, short and long-term interruptible contracts and long-term dedicated production agreements are excluded from the disclosure due to uncertainty associated with estimating future production volumes and future market prices. However, certain of our Tamar natural gas sales contracts in Israel have fixed annual sales volumes and fixed base pricing with annual index escalations. The following table includes estimated revenues based upon those certain agreements with fixed minimum take-or-pay sales volumes. Our actual future sales volumes under these agreements may exceed future minimum volume commitments.
(1)
The remaining performance obligations are estimated utilizing the contractual base or floor price provision in effect. Our future revenues from the sale of natural gas under these associated contracts will vary from the amounts presented above due to components of variable consideration above the contractual base or floor provision, such as index-based escalations and market price changes.
Midstream Revenue Arrangements
Service Arrangements Our Midstream segment revenues are derived from fixed fee contract arrangements for gathering, transportation and storage services. We have determined that our performance obligations for the provision of such services are satisfied over time using volumes delivered as the measure of progress. ASC 606 adoption did not have an impact on the recognition, measurement and presentation of our midstream revenues and expenses.
Crude Oil Purchase and Sale Arrangements In first quarter 2018, Noble Midstream Partners acquired an interest in Black Diamond which completed the Saddle Butte Acquisition of a large-scale integrated gathering system and associated third-party
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contracts which include transactions for the purchase and sale of crude oil with varying counterparties. Revenues and expenses from the sales and purchases are recorded on a gross basis as we act as a principal in these transactions by assuming control of the purchased commodity before it is transferred to the customer. The purchases and sales of crude oil are recorded at the prevailing market prices.
Note 5. Acquisitions and Divestitures
We maintain an ongoing portfolio management program and have engaged in various transactions over recent years.
Year Ended December 31, 2018
Divestiture of Gulf of Mexico Assets On February 15, 2018, we announced that we had signed a definitive agreement to sell our Gulf of Mexico assets, including all of our interests in producing properties and undeveloped acreage, for cash consideration of $480 million, along with the assumption, by the purchaser, of all abandonment obligations associated with the properties. As a result, we recorded impairment expense of $168 million during first quarter 2018.
In second quarter 2018, we closed the transaction with an effective date of January 1, 2018. After consideration of customary closing adjustments, to date we have received net proceeds of $384 million and recorded a loss of $24 million.
In addition, a cumulative contingent payment of up to $100 million is payable to us in the period after the closing of the transaction, beginning third quarter 2018, through the end of 2022, determined quarterly, at a rate of $2 per barrel produced by these assets when the average purchase price for Light Louisiana Sweet (LLS) crude oil exceeds $63 per barrel, and if produced crude oil volumes exceed certain minimum thresholds. As of December 31, 2018, $3 million has been accrued related to the contingent payment.
Divestiture of 7.5% Interest in Tamar Field On March 14, 2018, we closed the sale of a 7.5% working interest in the Tamar field to Tamar Petroleum Ltd. (Tamar Petroleum), a publicly traded entity on the Tel Aviv Stock Exchange (TASE: TMRP). Total consideration included cash and 38.5 million shares of Tamar Petroleum that had a publicly traded value of $224 million. The transaction had an effective date of January 1, 2018 and, after consideration of closing adjustments and before consideration of taxes, we received $484 million of cash. Total consideration received from the sale was applied to the field's basis and resulted in the recognition of a pre-tax gain of $376 million. We incurred tax expense of $86 million in connection with the transaction.
The Tamar Petroleum shares were subject to certain temporary lock-up provisions and had no voting rights. Due to the lock-up provisions associated with the Tamar Petroleum shares, we initially attributed $190 million of fair value to the shares, or 15% lower than the publicly traded value on the TASE. These shares were accounted for at fair value and we recorded decreases in fair value of $27 million and dividend income of $31 million during 2018. These amounts are included in other non-operating (income) expense, net, in our consolidated statements of operations.
In fourth quarter 2018, we sold 38.5 million shares of Tamar Petroleum in over the counter transactions for pre-tax proceeds of $163 million, net of transaction expenses. Upon sale, voting rights were restored and granted to the third parties. The sales of the 7.5% working interest in the Tamar field and of the Tamar Petroleum shares are in accordance with the terms of the Israel Natural Gas Framework (Framework) that requires us to reduce our ownership interest in the Tamar field from 32.5% to 25% by year-end 2021.
Divestiture of Southwest Royalties In January 2018, we closed the sale of our investment in Southwest Royalties, Inc. (Southwest Royalties), a subsidiary of Clayton Williams Energy, Inc. (Clayton Williams Energy), which we acquired in the acquisition of Clayton Williams Energy (Clayton Williams Energy Acquisition) in 2017. We received proceeds of $60 million, resulting in no gain or loss recognition on the sale of these assets.
Divestiture of Marcellus Shale CONE Gathering In January 2018, we closed the sale of our 50% interest in CONE Gathering LLC (CONE Gathering) to CNX Resources Corporation. CONE Gathering owns the general partner of CNX Midstream Partners LP (CNX Midstream Partners, NYSE: CNXM). We received proceeds of $309 million in cash and recognized a pre-tax gain of $196 million.
After the sale, we held 21.7 million common units, representing a 34.1% limited partner interest, in CNX Midstream Partners. During 2018, we sold our 21.7 million common units, receiving net proceeds of approximately $387 million, and recognized a gain of $307 million. The investment was previously accounted for under the equity method of accounting.
Divestiture of Greeley Crescent Assets In September 2018, we closed the sale of assets in the Greeley Crescent area of the DJ Basin and received proceeds of $68 million, resulting in no gain or loss recognition on the sale of these assets.
Divestiture of Non-Core Delaware Basin Acreage In December 2018, we closed the sale of certain non-core acreage in the Delaware Basin, receiving proceeds of $63 million, resulting in a pre-tax loss of $16 million.
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DJ Acreage Exchange We closed a cashless acreage exchange in the DJ Basin receiving approximately 12,900 net undeveloped acres within core areas of our Mustang and Wells Ranch positions in exchange for approximately 12,300 net undeveloped acres in non-core areas of Mustang and Wells Ranch. No gain or loss was recognized.
Noble Midstream Partners Saddle Butte Acquisition On January 31, 2018, Noble Midstream Partners acquired a 54.4% in Black Diamond Gathering LLC (Black Diamond), an entity formed by Black Diamond Gathering Holdings LLC, a wholly-owned subsidiary of Noble Midstream Partners, and Greenfield Midstream, LLC (Greenfield), which completed the acquisition of Saddle Butte from Saddle Butte Pipeline II, LLC (Saddle Butte Acquisition). Saddle Butte owned a large-scale integrated gathering system, located in the DJ Basin, which we subsequently renamed the Black Diamond gathering system.
Consideration totaled $681 million, which included $663 million of cash and assumption of $18 million of liabilities. Greenfield funded approximately $343 million of the purchase price, which is reflected as a contribution from noncontrolling interest within our consolidated statement of equity, and Noble Midstream Partners funded the remainder. We consolidate Black Diamond as a VIE and reflect the third-party ownership within noncontrolling interest within our consolidated statement of equity.
This transaction was accounted for as a business combination using the acquisition method. The total purchase price was allocated to assets acquired and liabilities assumed based on the fair value at the acquisition date. We have recognized goodwill for the amount of the purchase price exceeding the fair value of the assets acquired. Allocated fair value included: $206 million to property, plant and equipment; $340 million to customer-related intangible assets (acquired customer contracts); and $110 million to implied goodwill. Noble Midstream Partners has completed the purchase price allocation related to this acquisition.
Other Acquisitions and Divestitures During 2018, we closed on the acquisition of other smaller US onshore properties for total cash consideration of $3 million. We also closed the sale of certain other smaller US onshore proved and unproved properties and received total cash consideration of $81 million, recording a gain of $4 million.
Subsequent Events In first quarter 2019, we closed the sale of certain proved and unproved non-core acreage totaling approximately 13,000 net acres in Reeves County, Texas. We received cash consideration of $132 million, recognizing no gain or loss on the sale. As of December 31, 2018, the assets and related liabilities associated with this acreage were considered held for sale and were recorded within other current assets and other current liabilities on our consolidated balance sheets.
In first quarter 2019, Noble Midstream Partners exercised and closed an option with EPIC Midstream Holdings, LP (EPIC) to acquire a 15% equity interest in the EPIC Y-Grade Pipeline. It also exercised an option to acquire a 30% equity interest in the EPIC Crude Oil Pipeline, for which closing is anticipated to occur later in first quarter 2019, subject to certain conditions precedent.
Year Ended December 31, 2017
Clayton Williams Energy Acquisition On April 24, 2017, we completed the Clayton Williams Energy Acquisition. Clayton Williams Energy's results of operations since the acquisition date are included in our consolidated statement of operations. 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 9. Long-Term Debt.
The acquired assets included 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 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.
In connection with the acquisition, we incurred acquisition-related costs of $100 million, 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.
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Purchase Price Allocation The transaction was accounted for as a business combination using the acquisition method. The following table represents the 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.
The following table sets forth our purchase price allocation:
The fair values of Clayton Williams Energy's identifiable assets are as follows:
(1) The goodwill, which was associated with the Texas reporting unit included within our oil and gas exploration and production segment, was fully impaired as of December 31, 2018. See Note 6. Goodwill Impairment.
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 AROs 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 AROs 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.
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 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.
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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.
(1) No pro forma adjustments were made for the period as Clayton Williams Energy operations are included in our historical results.
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 closing adjustments. 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. 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 9. Long-Term Debt.
For the year ended December 31, 2017, we recognized a loss on divestiture of $2.3 billion, or $1.5 billion after-tax. The aggregate net book value of the properties sold was approximately $3.4 billion, which included approximately $883 million of undeveloped leasehold cost.
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).
After the property sale, we retained certain firm transportation commitments to flow Marcellus Shale natural gas production. See Note 10. Marcellus Shale Firm Transportation Commitments.
Other US Onshore Transactions We conducted the following additional transactions in 2017:
•
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.
•
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.
•
completed the acquisition of Delaware Basin properties, including seven producing wells, 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.
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
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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 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 15. Equity Method Investments.
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.
Other Acquisitions and Divestitures During 2017, we closed on the acquisition of other smaller US onshore properties for total cash consideration of $26 million. We also closed the sale of certain other smaller US onshore and international properties and received total cash consideration of $39 million, recording a loss of $6 million.
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:
•
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;
•
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;
•
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;
•
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
•
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.
Other Divestitures During 2016, we also closed the sale of certain smaller US onshore properties and received total cash consideration of $83 million, with no recognition of gain or loss.
See Supplemental Oil and Gas Information (Unaudited) for discussion of proved reserves added or divested in connection with the above transactions.
Note 6. Goodwill Impairment
As of December 31, 2017 and through September 30, 2018, our consolidated balance sheet included goodwill of $1.4 billion, of which $1.3 billion, resulting from the Clayton Williams Energy Acquisition, was allocated to our Texas reporting unit, included
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within our oil and gas exploration and production segment, and $110 million was allocated to our Midstream reporting unit. We conducted our annual goodwill impairment assessment as of September 30, 2018. At that time, we concluded that goodwill was not impaired.
In fourth quarter 2018, we considered changes to facts and circumstances, particularly the decline in WTI strip pricing, increase in operating and capital costs, as well as our development plan, and concluded that it was more likely than not that the fair value of our Texas reporting unit was less than its carrying amount. For purposes of determining the goodwill impairment, we estimated the implied fair value of the goodwill using a variety of valuation methods, including the income and market approaches. Our estimate of fair value required us to use significant unobservable inputs, representative of a Level 3 fair value measurement, including assumptions for future crude oil and natural gas production, commodity prices based on forward commodity price curves, operating and development costs and other factors. The analysis indicated that the implied fair value of our Texas reporting unit goodwill was zero and we recognized a loss of $1.3 billion.
Note 7. 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. On a quarterly basis, we review the status of suspended exploratory well costs and assess the development of these projects. If a well is deemed to be noncommercial, the well costs are charged to exploration expense as dry hole cost.
Changes in capitalized exploratory well costs, excluding amounts that were capitalized and subsequently expensed in the same period, are as follows:
(1) The 2018 amount represents costs primarily related to Gulf of Mexico assets sold during second quarter and 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.
(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. 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, Gulf of Mexico, which did not encounter commercial hydrocarbons and was subsequently plugged and abandoned.
The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced:
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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, 2018:
Undeveloped Leasehold Costs Undeveloped leasehold costs are derived from allocated fair values as a result of business combinations or other purchases of unproved properties and are subject to impairment testing. We reclassify undeveloped leasehold costs to proved property costs when, as a result of exploration and development activities, probable and possible resources are reclassified to proved reserves, including proved undeveloped reserves. On the other hand, if, based upon a
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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.
Changes in undeveloped leasehold costs were as follows:
(1)
2017 additions relate to the Clayton Williams Energy Acquisition and Delaware Basin asset acquisition.
(2)
2018 transfers relate primarily to Delaware Basin assets.
(3)
2017 sales relate primarily to the Marcellus Shale upstream divestiture.
(4)
2017 impairment expense was primarily attributable to Gulf of Mexico leases.
As of December 31, 2018, remaining undeveloped leasehold costs, to which proved reserves had not been attributed, totaled $2.4 billion, including $2.2 billion and $100 million attributable to Delaware Basin and Eagle Ford Shale, respectively.
The remaining balance of undeveloped leasehold costs as of December 31, 2018 included $53 million and $31 million related to international and domestic unproved properties, respectively. 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.
Note 8. Asset Retirement Obligations
ARO consists primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. Changes in ARO are as follows:
Year Ended December 31, 2018 Liabilities settled primarily included $216 million and $24 million of liabilities assumed by the purchasers of the Gulf of Mexico properties and Greeley Crescent assets, respectively, and $104 million related to abandonment of US onshore properties, primarily in the DJ Basin, where we have engaged in a program to plug and abandon older vertical wells. Costs associated with the DJ Basin abandonment activities will be incurred over several years.
Revisions of estimates were primarily related to increases in cost estimates and changes in timing estimates of $287 million for US onshore, primarily in the DJ Basin related to the abandonment activities noted above, $10 million for wells offshore Israel and $9 million for wells offshore Equatorial Guinea, partially offset by decreases in cost and timing estimates of $17 million associated with the North Sea abandonment project.
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.
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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 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, respectively, to liabilities associated with assets held for sale. See Note 5. Acquisitions and Divestitures.
Note 9. Long-Term Debt
Our debt consists of the following:
(1)
In second quarter 2018, we redeemed all of the Senior Notes due May 1, 2021, and expensed the associated premium. See Redemption of Notes, below.
(2)
Includes $8 million of 5.875% Senior Notes due June 1, 2024 and $84 million of 7.25% Senior Debentures due August 1, 2097.
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 Credit Agreement, as amended, provides for a $4.0 billion unsecured revolving credit facility (Revolving Credit Facility), which is available for general corporate purposes. The 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) 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, and (iii) includes sub-facilities for short-term loans and letters of credit up to an aggregate amount of $500 million under each sub-facility.
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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. We were in compliance with our debt covenants as of December 31, 2018.
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.
In the first quarter 2018, we extended the maturity date of the Revolving Credit Facility from August 2020 to March 2023. As of December 31, 2018, no borrowings were outstanding under the Revolving Credit Facility.
Noble Midstream Services Revolving Credit Facility Noble Midstream Services LLC (Noble Midstream Services), a subsidiary of Noble Midstream Partners, maintains a revolving credit facility (Noble Midstream Services Revolving Credit Facility), which is available to fund working capital and to finance acquisitions and other capital expenditures of Noble Midstream Partners.
Borrowings by Noble Midstream Partners under the Noble Midstream Services Revolving Credit Facility bear interest at a rate equal to an applicable margin plus, at Noble Midstream Partners' option, either (a) in the case of base rate borrowings, a rate equal to the highest of (1) the prime rate, (2) the greater of the federal funds rate or the overnight bank funding rate, plus 0.5% and (3) the LIBOR for an interest period of one month plus 1.00%; or (b) 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.
In first quarter 2018, the capacity was increased from $350 million to $800 million and the maturity date was extended from September 2021 to March 2023.
In third quarter 2018, we used $480 million proceeds from the issuance of a new term loan credit facility to repay a portion of the balance outstanding under the Noble Midstream Services Revolving Credit Facility. See Noble Midstream Services Term Loan Credit Facility, below. As of December 31, 2018, $60 million was outstanding under the Noble Midstream Services Revolving Credit Facility.
Noble Midstream Services Term Loan Credit Facility In third quarter 2018, Noble Midstream Services entered into a Term Credit Agreement (Noble Midstream Services Term Credit Agreement), which provides for a three year senior unsecured term loan credit facility (Noble Midstream Services Term Loan Credit Facility) and permits aggregate borrowings of up to $500 million. Proceeds from the Noble Midstream Services Term Loan Credit Facility were used to repay a portion of the outstanding borrowings under the Noble Midstream Services Revolving Credit Facility and to pay fees and expenses in connection with the Noble Midstream Services Term Loan Credit Facility.
Borrowings under the Noble Midstream Services Term Loan Credit Facility bear interest at a rate equal to, at Noble Midstream Partners' option, either (1) a base rate plus an applicable margin between 0.00% and 0.50% per annum or (2) a Eurodollar rate plus an applicable margin between 1.00% and 1.50% per annum. As of December 31, 2018, $500 million was outstanding under the Noble Midstream Services Term Loan Credit Facility.
The Noble Midstream Services Term Loan Credit Facility contains customary representations and warranties, affirmative and negative covenants, and events of default that are substantially the same as those contained in the Noble Midstream Services Revolving Credit Facility. Upon the occurrence and during the continuation of an event of default under the Noble Midstream Services Term Loan Credit Facility, the lenders may declare all amounts outstanding under the Noble Midstream Services Term Loan Credit Facility to be immediately due and payable and exercise other remedies as provided by applicable law.
Redemption of Senior Notes In May 2018, we redeemed $379 million of Senior Notes due May 1, 2021 that we assumed in the merger with Rosetta Resources, Inc. in 2015 for $395 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
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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 $1.1 billion from the issuance of senior notes were used solely to fund the tender offer and the redemption of $1.1 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 provided for a limited recourse secured term loan facility with an aggregate principal borrowing amount of up to $1.0 billion, of which $625 million was initially committed. Any amounts borrowed under the Leviathan Term Loan Facility would have been available to fund a portion of our share of costs for the initial phase of development of the Leviathan field. No amounts were ever drawn on the facility, which was terminated in December 2018.
Fair Value of Debt See Note 14. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of debt.
Capital Lease 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 11. Commitments and Contingencies for future capital lease payments.
Annual Debt Maturities Annual maturities of outstanding debt, excluding capital lease payments, as of December 31, 2018 are as follows:
Note 10. Marcellus Shale Firm Transportation Commitments
On June 28, 2017, we closed the sale of our Marcellus Shale upstream assets, which were primarily natural gas properties. In connection with the divestiture, we retained certain financial commitments on pipelines flowing natural gas production inside and outside of the Marcellus Basin. These financial commitments represent commitments to pay transportation fees; thus, we have no commitment to physically transport minimum volumes of natural gas.
Since closing, we have continued efforts to commercialize these firm transportation commitments including the permanent assignment of capacity, negotiation of capacity releases, utilization of capacity through purchase and transport of third-party natural gas, and other potential arrangements. In the event we execute a permanent assignment of capacity, we no longer have a contractual obligation to the pipeline company and, as such, our gross contractual commitment is reduced. In the event we execute a capacity release or utilize the capacity through the purchase and transport of third-party natural gas, we remain the primary obligor to the pipeline company. While our gross contractual commitment is not reduced, except through use under those arrangements, we would receive future cash payments from the third-parties with whom we negotiated a capacity release or from the sale of purchased natural gas to third-parties.
As of December 31, 2018, our gross retained firm transportation commitment for the remaining obligations under these agreements, which have remaining terms of approximately four to fifteen years, is approximately $1.5 billion, undiscounted. See Note 11. Commitments and Contingencies.
One of the retained contracts relates to the Texas Eastern Pipeline. This contract is being fully utilized through a capacity release agreement with the acquirer of the Marcellus Shale upstream assets. The financial commitment on this contract is being fully mitigated by a netback agreement with the purchaser.
One of the retained contracts relates to the Appalachian Gateway Project. In 2017, we recorded an exit cost of $41 million, discounted, related to this contract, as we no longer have production to satisfy the commitment and do not plan to utilize this capacity in the future.
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Additional retained contracts relate to the Leach Xpress and Rayne Xpress (Leach/Rayne Xpress) pipelines. In 2017, we permanently assigned a portion of the capacity, recording an exit cost of $52 million, discounted, related to future commitments to the third-party. Throughout 2018, we mitigated the impact of the remaining capacity through purchasing third-party natural gas and selling the natural gas to other third parties at prevailing market prices. Revenues and expenses associated with these activities are recorded on a gross basis, as we act as a principal in these arrangements by assuming control of the purchased commodity before it is transferred to the customer.
In addition to the retained firm transportation commitments, we also have the following accrued discounted liabilities associated with the exit cost activities described above:
Two additional retained contracts relate to the WB Xpress and NEXUS pipelines. In fourth quarter 2018, we entered into capacity release agreements with third parties extending through March and October 2020, respectively. Revenues and expenses associated with these agreements, as well as those associated with purchasing and selling third-party natural gas to mitigate Leach/Rayne Xpress capacity, are as follows:
(1)
Includes the net impact of the difference in the firm transportation contract rates and the rates agreed to in the capacity releases. Additionally, amount includes transportation expense associated with our transport of purchased natural gas on Leach/Rayne Xpress.
We expect to continue our commercialization actions, including utilizing pipeline capacity through purchases of third-party natural gas and sales to other third parties, to mitigate these firm transportation commitments. Some of our commercialization efforts may require pipeline and/or FERC approval to ultimately reduce the financial commitment associated with these contracts. 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. We cannot guarantee our commercialization efforts will be successful and we may recognize substantial future liabilities. See Note 5. Acquisitions and Divestitures.
Subsequent Event In January 2019, we executed agreements on Leach/Rayne Xpress to permanently assign the remaining capacity to a third-party effective January 1, 2021 extending through the remainder of the contract term. The permanent assignment reduces our total undiscounted financial commitment under the Marcellus Shale firm transportation contracts by approximately $350 million. In January 2019, we recorded exit costs of $92 million, discounted, related to future commitments to the third-party. We will continue efforts to mitigate the impact of these transportation agreements during 2019 and 2020.
Note 11. 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 (EPA), 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.
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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 corrective actions, to complete mitigation projects, to complete supplemental environmental projects (SEP), and to pay a civil penalty. Costs associated with the settlement consist of $5 million in civil penalties which were paid in 2015. Mitigation costs of $4 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. Since 2015, we have incurred approximately $84 million, of which $77 million was incurred to undertake corrective actions 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, plugging and abandonment activities, and mitigation expenditures that result from this settlement, based on currently available information will not have, a material adverse effect on our financial position, results of operations or cash flows. See Note 8. Asset Retirement Obligations.
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 (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. In October 2018, we met with enforcement staff at the Colorado Department of Public Health and Environment (CDPHE) to discuss a potential settlement of the alleged violations. Given the ongoing status of such settlement discussions, 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 and Gas Conservation Commission Administrative Order on Consent In July 2018, we resolved by Administrative Order on Consent (AOC) with the Colorado Oil and Gas Conservation Commission (COGCC) allegations of noncompliance associated with site preparation and stabilization at an oil and gas location in Weld County, Colorado. The AOC required us to pay an administrative penalty of $135 thousand ($41 thousand of which is deferred subject to a nine-month compliance schedule) and to complete certain corrective actions at five oil and gas locations in Weld County, Colorado. We have concluded that the resolution of this action did not have a material adverse effect on our financial position, results of operations or cash flows.
Colorado Mechanical Integrity Testing Matter In September 2018, we resolved by AOC with the COGCC administrative claims for allegations of noncompliance of State mechanical integrity testing rules at eight shut-in wells in Weld County, Colorado. The AOC includes an administrative penalty of $1.6 million, of which $1.4 million of the total penalty is to be offset by our commensurate contribution to two public projects and our requirement to repair or plug and abandon each of the eight wells and to submit to COGCC certain environmental data. We have concluded that the resolution of this action did not have a material adverse effect on our financial position, results of operations or cash flows.
Colorado Clean Water Act Referral Notice In September 2018, we received a letter from the US Department of Justice providing notification of referral from the EPA of alleged Clean Water Act violations at an upstream production facility and a midstream gathering facility in Weld County, Colorado. The letter requests an opportunity to discuss settlement of the alleged violations. Given the uncertainty associated with enforcement 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.
Marcellus Shale Firm Transportation 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. See Note 10. Marcellus Shale Firm Transportation Commitments.
Other Transportation and Gathering Obligations We have transportation and gathering obligations to flow US onshore production, primarily in the DJ Basin, to various markets. Certain of these contracts require us to make payments for any
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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. We expect to continue to incur expense related to deficiency and/or unutilized commitments in the near-term. These amounts are recorded as marketing expense in our consolidated statements of operations.
Our total financial commitment for these agreements, which have remaining terms of two to ten years, is approximately $612 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 $90 million in 2018, $69 million in 2017, and $76 million in 2016.
Minimum commitments as of December 31, 2018 consist of the following:
(1)
Amount includes exit cost obligations resulting from a permanent capacity assignment. See Note 10. Marcellus Shale Firm Transportation Commitments.
(2)
Annual lease payments, net to our interest, exclude regular maintenance and operational costs. See Note 9. Long-Term Debt.
Note 12. Income Taxes
Components of income (loss) from operations before income taxes are as follows:
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The income tax provision (benefit) consists of the following:
A reconciliation of the federal statutory tax rate to the effective tax rate is as follows:
(1) See Tax Reform Legislation and Accumulated Undistributed Earnings of Foreign Subsidiaries, below.
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Deferred tax assets and liabilities resulted from the following:
Net deferred tax assets and liabilities were classified in the consolidated balance sheets as follows:
Tax Reform Legislation On December 22, 2017, the US Congress enacted 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. The SEC staff issued SAB 118 which allowed registrants to report provisional amounts for the income tax effects specific to Tax Reform Legislation for which accounting was incomplete but a reasonable estimate could be determined. We reported certain provisional amounts in fourth quarter 2017, some of which were adjusted in 2018 based on changes in estimates, including changes based on further guidance provided by the Internal Revenue Service (IRS).
Provisional amounts recorded in 2017 and changes in estimates reported in 2018 are as follows:
Remeasurement of Deferred Taxes In accordance with US GAAP, we recognized the effect of the rate change on deferred tax assets and liabilities in the period in which the tax rate change was enacted, resulting in the recognition of a provisional deferred tax benefit of $500 million at December 31, 2017. Further remeasurements of these deferred taxes in 2018 were associated with the return to provision resulted in a $10 million deferred tax benefit.
Transition Tax (Toll Tax) Tax Reform Legislation provided for a toll tax on a one-time “deemed repatriation” of accumulated foreign earnings for the year ended December 31, 2017. Based on early interpretations of the law, we recognized additional taxable income in 2017 of $767 million associated with the toll tax, which was fully offset by net operating losses (NOLs), and recorded corresponding deemed foreign tax credits of $164 million, against which we recorded a full valuation allowance.
On April 2, 2018, the US Department of the Treasury and the IRS released Notice 2018-26, signaling intent to issue regulations related to the toll tax for the year ended December 31, 2017. Notice 2018-26 clarified that an Internal Revenue Code Section 965(n) election is available with respect to both current and prior year NOLs. As a result, we released $252 million of the valuation allowance recorded against foreign tax credits to be utilized against the estimated $268 million toll tax liability recorded as of December 31, 2017. This resulted in a $252 million tax benefit and a corresponding expense of $107 million for the tax rate change adjustment on the previously utilized NOL's. The impact on first quarter 2018 total tax expense, related to this additional guidance, was a net $145 million discrete tax benefit.
During fourth quarter 2018, the toll tax calculations were finalized in conjunction with filing of the US tax return, resulting in a $261 million toll tax against which $240 million of foreign tax credits were utilized. This resulted in a $21 million liability
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payable in installments over eight years beginning in 2018. The additional impact recorded during fourth quarter 2018 was a net $5 million tax expense.
Global Intangible Low-Taxed Income (GILTI) Tax Reform Legislation also introduced a new tax on global intangible low-taxed income (GILTI). Further analysis and legal interpretation has resulted in identifying certain foreign oil related income (FORI) activity as GILTI income which will be offset by NOL carryforwards rather than the 50% deduction and related foreign tax credits. As a result of utilizing our NOL to offset the GILTI inclusion, we recognized tax expense of $34 million for 2018 GILTI associated with FORI from investments in operating assets in Equatorial Guinea and operations in Israel. We are making an accounting policy election to not record deferred taxes related to GILTI.
Other Provisions Tax Reform Legislation is a comprehensive bill containing other provisions that do not materially affect us. The ultimate impact may differ from our estimates if additional regulatory guidance is issued. We are closely monitoring the provision which revised and broadened the former Section 163(j) interest expense limitation rules. In tax years subsequent to 2021 the basis of the limitation calculation will change to be roughly equivalent to EBIT at which time we expect to be subject to an interest expense limitation. The interest expense not deducted due to limitation has an indefinite carryover period.
Deferred Tax Assets Our estimated pre-tax NOL carryforwards totaled approximately $2.4 billion at December 31, 2018, of which US federal income tax NOL carryforwards totaled approximately $1.7 billion and foreign NOL carryforwards were $670 million.
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 $187 million and $183 million in 2018 and 2017, respectively. The valuation allowance on foreign tax credits totaled $132 million and $366 million in 2018 and 2017, respectively. As noted above, in first quarter 2018 we released $252 million of the valuation allowance recorded against the foreign tax credits and in fourth quarter 2018, we made further return to provision adjustments based on the tax return filing.
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. Our purchase price allocation is finalized and we recorded a deferred tax liability of $307 million, adjusted for the new US statutory rate, which includes a deferred tax asset for federal pre-tax NOLs 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.
Effective Tax Rate Our effective tax rate increased in 2018 as compared with 2017, primarily due to the fourth quarter 2018 goodwill impairment for which there is no tax benefit and the deferred tax expense of $34 million for GILTI. This increase was reduced by a deferred tax benefit of $145 million recorded discretely in the current year, as discussed above, and a deferred tax benefit of $50 million associated with a write-off of foreign exploration losses. The increase in current income tax expense during 2018 as compared with 2017 is primarily due to foreign taxes on the gain recognized with the first quarter 2018 divestiture of a 7.5% working interest in the Tamar field. The decrease in deferred income tax benefit during 2018 as compared to 2017 is due to the significant deferred tax benefit recorded in 2017 associated with the revaluation of the US deferred tax liability at the reduced future tax rate.
Accumulated Undistributed Earnings of Foreign Subsidiaries During 2016, we reduced the deferred tax liability associated with unremitted foreign earnings, net of foreign tax credits, to $240 million. In 2017, as a result of Tax Reform Legislation, which established a new territorial tax regime, we reversed the deferred tax liability recorded in 2016, resulting in a deferred tax benefit of $240 million. As of December 31, 2018, there is no expected withholding tax impact upon actual distribution of earnings and as such, we have not recorded any tax associated with unremitted earnings.
Israeli Tax Law Effective December 21, 2016, the Israeli government decreased the corporate income tax rate from 25% to 24% for 2017 and from 24% to 23% effective January 2018. The full impact of the rate reduction was recognized in 2017, decreasing deferred tax expense 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 (Oil Profits Tax). The Oil Profits Tax is calculated by dividing net
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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 Oil Profits Tax increases progressively up to a maximum rate of 50%. The Oil 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 Oil Profits Tax rate is calculated. At the current corporate tax rate, the Oil Profits Tax rate is 46.8%. The Oil Profits Tax is deductible for Israeli corporate tax purposes. Our Tamar and Leviathan projects are both subject to the Oil Profits Tax and are expected to pay at the maximum rate.
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 - 2015, Israel - 2015 (2013 with respect to Israel Oil Profits Tax) and Equatorial Guinea - 2013. Our policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense. As of December 31, 2018 and 2017, we had no unrecognized tax benefits.
Note 13. 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, collars and three-way collars, basis swaps, swaptions and/or put options.
The fixed price swap and 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 collar contract combined with a put option contract sold by us with a strike price below the floor price of the collar. We receive price protection at the purchased put option floor price of the 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.
A swaption gives counterparties the right, but not the obligation, to enter into swap agreements with us on the option expiration dates.
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 14. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of our derivative instruments.
Counterparty Credit Risk Derivative instruments expose us to counterparty credit risk, especially during periods of falling prices. Our commodity derivative instruments are currently with a diversified group of major banks or market participants. We monitor the creditworthiness of these counterparties and our internal hedge policies provide for exposure limits. 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. 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.
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Unsettled Derivative Instruments As of December 31, 2018, 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, 2018, we had entered into the following natural gas derivative instruments:
(1) We have entered into contracts for portions of 2019 resulting in the difference in hedged volumes for the full year.
(2) We have entered into natural gas basis swap contracts in order to establish a fixed amount for the differential between index pricing for Colorado Interstate Gas and NYMEX Henry Hub. The weighted average differential represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes covered by the basis swap contracts.
Fair Value Amounts and Gains and Losses on Derivative Instruments The fair values of derivative instruments on our consolidated balance sheets were as follows (1):
(1) See Note 1. Summary of Significant Accounting Policies - Derivative Instruments and Hedging Activities.
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The effect of derivative instruments on our consolidated statements of operations was as follows:
Note 14. 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 on 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 considers market volatility, market prices and contract terms. See Note 13. 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 17. Stock-Based and Other Compensation Plans.
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Measurement information for assets and liabilities that are measured at fair value on a recurring basis was as follows:
(1)
See Note 1. Summary of Significant Accounting Policies - Fair Value Measurements for a description of the fair value hierarchy.
(2)
Amount represents the impact of netting clauses within our master agreements that allow us to net cash settle asset and liability positions with the same counterparty.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Certain assets and liabilities are measured at fair value on a nonrecurring basis on our consolidated balance sheets. See Note 1. Summary of Significant Accounting Policies for the methods and assumptions used to estimate the fair values:
Asset Impairments Impairments are recorded when we determine that the carrying amounts of certain oil and gas properties or midstream facilities are not recoverable from future cash flows, and are calculated using significant unobservable (Level 3) inputs. In 2018, upon classification of the Gulf of Mexico properties as assets held for sale, we recognized impairment expense of $168 million. Additionally, in fourth quarter 2018, we recorded impairment expense of $38 million, $37 million of which related to changes in construction plans for certain midstream assets.
The 2017 impairment of $70 million primarily related to our decision not to pursue development of the Troubadour natural gas discovery in the Gulf of Mexico. The 2016 impairment of $92 million primarily related to a decision to write off certain development concepts associated with the Leviathan natural gas project that were not selected. The assets were reduced to their estimated fair values.
Inventory Impairment In 2016, we determined that the carrying amount of certain of our materials and supplies inventory was greater than its net realizable value, which was calculated using significant unobservable (Level 3) inputs. We recognized a $14 million impairment related to these assets.
Goodwill Impairment In fourth quarter 2018, we determined that the carrying amount of goodwill allocated to our Texas reporting unit was less than its estimated fair value, which was calculated using significant unobservable (Level 3) inputs. As a result, we recognized a goodwill impairment of $1.3 billion. See Note 6. Goodwill Impairment.
Marcellus Shale Firm Transportation Liability In 2017, we recorded liabilities totaling $93 million representing the discounted present value of our remaining obligation under certain firm transportation contracts. See Note 10. Marcellus Shale Firm Transportation Commitments.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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, 2018, our variable-rate, non-public debt included the Revolving Credit Facility, Noble Midstream Services Revolving Credit Facility and the Noble Midstream Services Term Loan 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 9. 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 15. Equity Method Investments
Equity Method Investments Investments accounted for under the equity method consist primarily of the following:
•
50% interest in Advantage Pipeline, which owns and operates a 70-mile crude oil pipeline in Texas (See Note 5. Acquisitions and Divestitures);
•
45% interest in Atlantic Methanol Production Company, LLC (AMPCO), which owns and operates a methanol plant and related facilities in Equatorial Guinea; and
•
28% interest in Alba Plant , which owns and operates a LPG processing plant in Equatorial Guinea.
We consider these equity method investments essential components of our business as well as necessary and integral elements of our value chain in support of ongoing operations in our Midstream and West Africa segments. For the Advantage Pipeline system, Noble Midstream Partners serves as operator and exerts significant influence over the day-to-day operations. The operating agreements for Advantage Pipeline empower the board to direct activities that most significantly affect long-term economic performance. With regard to AMPCO, we hold a voting position on AMPCO's leadership team through AMPCO's management committee, and our asset teams influence decisions regarding capital investments, budgets, turnarounds, maintenance and other project matters. For the Alba Plant, our Alba asset teams are fully engaged in operational and financial decisions and exert significant influence in the monetization of the Alba field and Alba Plant.
Equity method investments are as follows:
Additional Information At December 31, 2018, consolidated retained earnings included $68 million related to the undistributed earnings of equity method investees.
The carrying value of our AMPCO investment was $13 million higher than the underlying net assets of the investee at December 31, 2018. 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 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.
(2)
On February 15, 2018, we announced that the Company's Board of Directors had authorized a share repurchase program of $750 million which expires December 31, 2020. These shares were repurchased and retired at an average price of $29.49 per share.
(3)
The 2017 amount includes approximately 720,000 shares of common stock received 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.
(4)
For the years ended December 31, 2018 and 2017, 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.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Accumulated Other Comprehensive Loss (AOCL) AOCL in the shareholders’ equity section of the balance sheet included:
Items in AOCL were initially recorded net of tax, using an effective income tax rate of 35%. In fourth quarter 2018, we reclassified to retained earnings approximately $6 million representing the effect of the decrease in the income tax rate to 21%.
AOCL at December 31, 2018 included deferred losses of $24 million, net of tax, related to an interest rate derivative instrument. This amount is reclassified to earnings as an adjustment to interest expense over the term of our senior notes due March 2041.
Note 17. 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 shareholders approved the Noble Energy, Inc. 2017 Long-Term Incentive Plan (the 2017 Plan). Upon shareholder approval, the 2017 Plan superseded 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, 2018, 26,621,632 shares of our common stock were reserved for issuance, including 21,084,928 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 shareholder 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.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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.
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, 2018, 576,798 shares of our common stock were reserved for issuance, including 397,979 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:
Noble Energy, Inc.
Notes to Consolidated Financial Statements
The total intrinsic value of options exercised was $5 million in 2018, $4 million in 2017 and $10 million in 2016. As of December 31, 2018, $11 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 1.2 years. We issue new shares of our common stock to settle option exercises. Dividends are not paid on unexercised options.
Restricted Stock Awards Awards of time-vested restricted stock (shares subject to service conditions) are valued at the price of our common stock at the date of award. The fair 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:
The total fair value of restricted stock that vested was $29 million in 2018, $34 million in 2017, and $24 million in 2016.
The weighted average award-date fair value of restricted stock awarded was $27.96 per share in 2018, $35.45 per share in 2017, and $29.99 per share in 2016.
As of December 31, 2018, $74 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 1.5 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 (two-year cliff vesting for officers and three-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.
We accrued a liability of $8 million in 2018 related to the phantom units. No phantom units were awarded in 2018 or 2017.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Phantom unit activity was as follows:
As of December 31, 2018, compensation cost related to phantom units remained to be recognized was de minimis. The remaining cost is expected to be recognized in first quarter 2019. The total fair value of phantom units that vested in 2018 was de minimis. Common stock dividends accrue on phantom units and are 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 2018, $31 million in 2017, and $32 million in 2016.
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 14. 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 200,000 shares, or 75%, of our common stock held in respect of one nonqualified deferred compensation plan at December 31, 2018 were attributable to a member of our Board of Directors. The remaining shares will be distributed in 2019. Distributions of 200,000 shares were made in each of 2018, 2017 and 2016. In addition, plan participants sold 2,239 shares of our common stock in 2018, 1,238 shares in 2017, and 1,009 shares in 2016. Proceeds were invested in mutual funds and/or distributed to plan participants. Distributions to plan participants were valued at $18 million in 2018, $21 million in 2017 and $22 million in 2016.
All fluctuations in market value of the deferred compensation liability have been reflected in other non-operating (income) expense, net in the consolidated statements of operations. We recognized deferred compensation expense of $2 million in 2018, $9 million in 2017 and $11 million in 2016.
Noble Energy, Inc.
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 $104 million and $116 million were outstanding at December 31, 2018 and 2017, respectively, under those other plans.
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. The results of operations, costs incurred and capitalized costs associated with our Midstream reportable segment are not included in this disclosure.
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, 2018, 2017, and 2016 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. Alternatively, decreases in these costs could result in positive 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 - 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, 2018. 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 to 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:
Revisions of Previous Estimates Oil revisions included:
•
Price Revisions
◦
2016 positive price revisions included 19 MMBbls in the US and 4 MMBbls in Equatorial Guinea.
◦
2017 positive price revisions included 12 MMBbls in the US.
◦
2018 positive price revisions of 14 MMBbls included 10 MMBbls in the US and 4 MMBbls in Equatorial Guinea.
•
Non-Price Revisions
◦
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.
◦
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.
◦
2018 includes negative non-price revisions of 42 MMBbls, which primarily includes 30 MMBbls for changes in expected recoveries and increased operating and capital costs in the Delaware Basin, and 11 MMBbls for changes in the previously adopted development plan in the Eagle Ford Shale and DJ Basin.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Extensions, Discoveries and Other Additions Oil extensions, discoveries and other additions included:
•
2016 extensions 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.
•
2017 extensions 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.
•
2018 extensions relate to drilling plans for new wells and include 55 MMBbls, 38 MMBbls, 5 MMBbls and 3 MMBbls in the Delaware Basin, DJ Basin, Eagle Ford Shale and Equatorial Guinea, respectively.
Purchase of Minerals in Place The 2017 increase in oil was attributable to the reserves acquired in the Clayton Williams Energy Acquisition.
Sale of Minerals in Place Sales of oil minerals in place included:
•
2017 includes the sale of Marcellus Shale upstream assets and other non-strategic US onshore assets.
•
2018 sales included 16 MMBbls related to our Gulf of Mexico assets and 8 MMBbls related to other non-strategic US onshore assets.
See Items 1. and 2. Business and Properties - Proved Reserves Disclosures and Note 5. Acquisitions and Divestitures.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Proved NGL Reserves (Unaudited) The following reserves schedule was developed by our qualified petroleum engineers and sets forth the changes in estimated quantities of proved NGL reserves:
Revisions of Previous Estimates NGL revisions included:
•
Price Revisions
◦
2016 included negative price revisions of 4 MMBbls.
◦
2017 included positive price revisions of 6 MMBbls.
◦
2018 included include positive price revisions of 5 MMBbls in the US.
•
Non-Price Revisions
◦
2016 US revisions were primarily associated with positive performance revisions of 11 MMBbls in the Marcellus Shale and 9 MMBbls in the DJ Basin.
◦
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.
◦
2018 net positive non-price revisions of 16 MMBbls include positive revisions of 35 MMBbls in the DJ Basin primarily due to ASC 606 adoption, offset by negative revisions of 15 MMBbls in the Eagle Ford Shale due to changes in the previously adopted development plan and 4 MMBbls in the Delaware Basin for changes in expected recoveries and increased operating and capital costs.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Extensions, Discoveries and Other Additions NGL extensions, discoveries and other additions included:
•
2016 extensions 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.
•
2017 extensions 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.
•
2018 extensions relate to the addition of planned new locations and activity, of which 25 MMBbls, 15 MMBbls and 8 MMBbls relate to the DJ Basin, Delaware Basin and Eagle Ford Shale, respectively.
Sale of Minerals in Place Sales of NGL minerals in place included:
•
2017 sales included the Marcellus Shale upstream assets and other non-strategic US onshore assets.
•
2018 sales included 1 MMBbl from Gulf of Mexico assets and 6 MMBbls for certain non-core US onshore assets.
See Items 1. and 2. Business and Properties - Proved Reserves Disclosures and Note 5. Acquisitions and Divestitures.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Proved Gas Reserves (Unaudited) The following reserves schedule was developed by our qualified petroleum engineers and sets forth the changes in estimated quantities of proved natural gas reserves:
Revisions of Previous Estimates Gas revisions included:
•
Price Revisions
◦
2016 included negative commodity price revisions of 81 Bcf in the US and 20 Bcf in Equatorial Guinea.
◦
2017 included positive commodity price revisions of 53 Bcf in the US and 13 Bcf in Equatorial Guinea.
◦
2018 included positive price revisions of 44 Bcf in the US and 5 Bcf in Equatorial Guinea.
•
Non-Price Revisions
◦
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. Equatorial Guinea revisions were associated with positive performance revisions of 58 Bcf at the Alba field.
◦
2017 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.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
◦
2018 net negative revisions of 24 Bcf include negative performance revisions of 43 Bcf in the US, partially offset by positive revisions of 19 Bcf in Equatorial Guinea and Israel. US includes positive revisions of 70 Bcf in the DJ Basin primarily due to ASC 606 adoption, offset by negative revisions of 71 Bcf in the Eagle Ford Shale due to changes in the previously adopted development plan and 42 Bcf primarily in the Delaware Basin due to changes in expected recoveries and increased operating and capital costs. Additional reserves of 17 Bcf in Equatorial Guinea and 2 Bcf in Israel relate to improved recoveries on existing wells.
Extensions, Discoveries and Other Additions Gas extensions, discoveries and other additions included:
•
2016 extensions 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.
•
2017 extensions 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.
•
2018 extensions in reserves relate to drilling plans for new wells. Increases in the US include 254 Bcf, 77 Bcf and 42 Bcf in the DJ Basin, Delaware Basin and Eagle Ford Shale, respectively, and the increase in Israel of 68 Bcf relates to the Tamar field.
Sale of Minerals in Place Sales of gas minerals in place included:
•
2016 included the sale of non-strategic US onshore assets, an acreage exchange in the Marcellus Shale where we relinquished 185 Bcf, and we sold a 3.5% ownership interest in the Tamar field, offshore Israel.
•
2017 included the sale of our Marcellus Shale upstream assets and other non-strategic US onshore assets.
•
2018 sales included 20 Bcf for our Gulf of Mexico assets, 59 Bcf for other non-strategic US onshore assets and 502 Bcf for a 7.5% working interest in the Tamar field, offshore Israel.
See Items 1. and 2. Business and Properties - Proved Reserves Disclosures and Note 5. Acquisitions and Divestitures.
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, royalty expense, transportation and gathering expense, and general and administrative expense supporting oil and gas operations.
(2)
See Note 5. Acquisitions and Divestitures.
(3)
2018 asset impairments relate to the sale of our Gulf of Mexico assets.
2017 asset impairments relate primarily to the Gulf of Mexico Troubadour well.
2016 asset impairments relate to certain Leviathan development concept costs.
(4)
Income tax expense is based upon respective corporate statutory tax rates. During 2018, 2017, and 2016, 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 activities and overhead and interest costs. See Note 13. Derivative Instruments and Hedging Activities.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
(6)
Amount reflects reclassification of $93 million accrued exit costs for retained Marcellus Shale firm transportation commitments from our US oil and gas exploration and production reportable segment to our Corporate segment. See Note 1. Summary of Significant Accounting Policies, Note 3. Segment Information and Note 10. Marcellus Shale Firm Transportation Commitments.
(7)
Equatorial Guinea exploration expense includes amounts related to the write off of costs associated with certain discoveries. See Note 7. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
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 segment and other corporate activities are not included.
(1)
Other International includes Newfoundland, Suriname (until November 2018), Falkland Islands (until December 2018), other new ventures and previous North Sea operations, which are in the process of being decommissioned.
(2)
2018 unproved property acquisition costs include US onshore undeveloped leasehold activity during the year.
2017 proved and unproved property acquisition costs include amounts allocated from the Clayton Williams Energy Acquisition and the Delaware Basin Acquisition. See Note 5. Acquisitions and Divestitures.
2016 unproved property acquisition costs relate to the termination of the Marcellus Shale joint development agreement. See Note 5. Acquisitions and Divestitures.
(3)
2018 exploration costs relate primarily to seismic expense, drilling costs, and lease rentals.
2017 exploration costs primarily include 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 $44 million drilling and completion costs in the Gulf of Mexico.
(4)
Worldwide development costs include amounts spent to develop PUDs of approximately $1.0 billion in 2018, $1.2 billion in 2017, and $656 million in 2016.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
US development costs include an increase of $302 million in ARO due primarily to upward revisions in 2018, a decrease of $17 million in 2017 and an increase of $20 million in 2016.
Israel development costs for 2018 include $646 million related to initial development of the Leviathan field. Israel development costs for 2017 include $416 million related to initial development of the Leviathan field and $63 million related to the Tamar 8 development well.
Israel development costs for 2016 relate primarily to development of the Tamar discovery. Israel development costs include increases in ARO of $13 million in 2018 and $4 million in 2017.
Equatorial Guinea development costs are de minimis in 2018, 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. 2017 development costs include an increase in ARO of $14 million.
Other International development costs include decreases in ARO of $40 million in 2017 primarily associated with the North Sea abandonment project.
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 costs at December 31, 2018 include previous acquisition costs of $2.2 billion related to Delaware Basin properties and $100 million related to Eagle Ford Shale properties.
Unproved oil and gas property costs at December 31, 2017 include previous acquisition costs of $2.7 billion related to Delaware Basin properties and $149 million related to Eagle Ford Shale properties.
(2)
Proved oil and gas properties at December 31, 2018 include asset retirement costs of $966 million and assets held for sale of $133 million.
Proved oil and gas properties at December 31, 2017 include asset retirement costs of $941 million and assets held for sale of $448 million.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited) The following information is based on our best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows in accordance with US GAAP. The standards require the use of a 10% discount rate. This information is not the fair value, nor does it represent the expected present value of future cash flows of our proved oil and gas reserves.
(1)
In accordance with the Framework, we were 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. During 2018, we reduced our ownership to 25% through the sale of a 7.5% interest. Therefore, amounts at December 31, 2018 reflect a 25% interest while amounts at December 31, 2017 and 2016 reflect a 32.5% working interest. See Note 5. Acquisitions and Divestitures. 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 8. 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, 2018, 2017 and 2016, 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 2018 would reduce the discounted future net cash flows before income taxes by approximately $1.6 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 2018 would reduce the discounted future net cash flows before income taxes by approximately $0.9 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, NGL and natural gas reserves at the end of the year, based on year-end costs, and assuming continuation of existing economic conditions.
Future development costs include amounts that we expect to spend to develop PUDs of approximately $2.1 billion in 2019, $1.5 billion in 2020 and $1.1 billion in 2021.
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, NGL and natural gas reserves, less the tax bases of the properties involved. Future income tax expense gives effect to tax credits and allowances, but does not reflect the impact of general and administrative costs and exploration expenses of ongoing operations.
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, NGL and natural gas reserves are as follows:
(1)
The increases in 2018 and 2017 were driven primarily by higher 12-month average commodity prices.
(2)
Purchase of minerals in 2017 relates to reserves acquired in the Clayton Williams Energy Acquisition.
(3)
See Note 5. Acquisitions and Divestitures.
(4)
The increase in 2018 future income tax expense relates primarily to the increase in US tax expense due to higher future taxable income and a reduction of NOL carryforwards utilized to offset future taxable income from $3.2 billion as of December 31, 2017 to $1.7 billion as of December 31, 2018. The increase is partially offset by a decrease in future taxes in Israel driven by the sale of 7.5% working interest in Tamar.
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.
Noble Energy, Inc.
Supplemental Quarterly Financial Information
(Unaudited)
Supplemental quarterly financial information is as follows:
(1) First quarter 2018 included the following:
•
$376 million pre-tax gain on sale of 7.5% working interest in Tamar field. See Note 5. Acquisitions and Divestitures;
•
$196 million pre-tax gain on sale of our 50% interest in CONE Gathering. See Note 5. Acquisitions and Divestitures;
•
$168 million impairment expense related to Gulf of Mexico asset divestiture. See Note 5. Acquisitions and Divestitures;
•
$145 million discrete tax benefit, net, related to changes in federal income tax regulations. See Note 12. Income Taxes; and
•
$79 million loss on commodity derivative instruments, including non-cash portion of loss on commodity derivative instruments of $51 million. See Note 13. Derivative Instruments and Hedging Activities.
Second quarter 2018 included the following:
•
$249 million loss on commodity derivative instruments, including non-cash portion of loss on commodity derivative instrument of $184 million. See Note 13. Derivative Instruments and Hedging Activities; and
•
$109 million gain on sale of 7.5 million CNX Midstream Partners units. See Note 5. Acquisitions and Divestitures.
Third quarter 2018 included the following:
•
$198 million gain on sale of 14.2 million CNX Midstream Partners units. See Note 5. Acquisitions and Divestitures; and
•
$155 million loss on commodity derivative instruments, including non-cash portion of loss on commodity derivative instruments of $88 million. See Note 13. Derivative Instruments and Hedging Activities.
Fourth quarter 2018 included the following:
•
$1.3 billion goodwill impairment charge. See Note 6. Goodwill Impairment;
•
$546 million gain on commodity derivative instruments, including non-cash portion of gain on commodity derivative instruments of $547 million. See Note 13. Derivative Instruments and Hedging Activities; and
•
$38 million impairment expense primarily related to midstream assets. See Note 14. Fair Value Measurements and Disclosures.
(2) First quarter 2017 included the following:
•
No unusual or infrequent activity.
Second quarter 2017 included the following:
•
$2.3 billion loss on Marcellus Shale upstream divestiture. See Note 5. Acquisitions and Divestitures.
Third quarter 2017 included the following:
•
$98 million loss on extinguishment of debt. See Note 9. Long-Term Debt.
Fourth quarter 2017 included the following:
•
$270 million deferred tax benefit, net, related to changes in federal income tax regulations; and
•
$334 million gain on sale of mineral and royalty assets. See Note 5. Acquisitions and Divestitures.
(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.

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

ITEM 9A - CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
We maintain "disclosure controls and procedures," as such term is defined in Rule 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended, 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 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 as of December 31, 2018.
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
There were no changes in internal controls over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

ITEM 9B - OTHER INFORMATION
Item 9B. Other Information
Effective, February 15, 2019, the Board of Directors of Noble Energy, Inc. (the “Company”) approved the amendment and restatement of the Company’s By-Laws (“By-Laws”). The revision to the By-Laws included an amendment to Article III, Section 1(b) to allow for a Lead Independent Director, who attains the age of 72 as of the next annual meeting succeeding such person’s 72nd birthday, to be eligible to stand for election as a director for one additional year, but ineligible to be appointed as the lead independent director.
The foregoing description of the amendment to the By-Laws is qualified in its entirety by reference to the full text of the By-Laws, a copy of which is filed as Exhibit 3.2 to this Annual Report on Form 10-K and incorporated herein by reference.
PART III

ITEM 10 - DIRECTORS AND EXECUTIVE OFFICERS
Item 10. Directors, Executive Officers and Corporate Governance
The information required by this item is incorporated herein by reference to the 2019 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2018.

ITEM 11 - EXECUTIVE COMPENSATION
Item 11. Executive Compensation
The information required by this item is incorporated herein by reference to the 2019 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2018.

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 2019 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2018.

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 2019 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2018.

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 2019 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2018.
PART IV

ITEM 15 - EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibits, Financial Statement Schedules
(a)
The following documents are filed as a part of this report:
(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 19, 2019
By: /s/ David L. Stover
David L. Stover,
Chairman of the Board and Chief Executive Officer
Date:
February 19, 2019
By: /s/ Kenneth M. Fisher
Kenneth M. Fisher,
Executive Vice President, Chief Financial Officer
Date:
February 19, 2019
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 and Chief Executive Officer
February 19, 2019
David L. Stover
(Principal Executive Officer)
/s/ Kenneth M. Fisher
Executive Vice President, Chief Financial Officer
February 19, 2019
Kenneth M. Fisher
(Principal Financial Officer)
/s/ Dustin A. Hatley
Vice President, Chief Accounting Officer and Controller
February 19, 2019
Dustin A. Hatley
(Principal Accounting Officer)
/s/ Jeffrey L. Berenson
Director
February 19, 2019
Jeffrey L. Berenson
/s/ Michael A. Cawley
Director
February 19, 2019
Michael A. Cawley
/s/ Edward F. Cox
Director
February 19, 2019
Edward F. Cox
/s/ James E. Craddock
Director
February 19, 2019
James E. Craddock
/s/ Barbara J. Duganier
Director
February 19, 2019
Barbara J. Duganier
/s/ Thomas J. Edelman
Director
February 19, 2019
Thomas J. Edelman
/s/ Holli C. Ladhani
Director
February 19, 2019
Holli C. Ladhani
/s/ Scott D. Urban
Director
February 19, 2019
Scott D. Urban
/s/ William T. Van Kleef
Director
February 19, 2019
William T. Van Kleef

Market Capitalization: 11371236.666057587
1-Year Return: 0.04681985080242157
252-Day Return: $252_day_return