SEC Form 10-K Filing Report

Company: NOBLE ENERGY INC
CIK: 72207
SIC Code: 1311
Filing Date: 2020-02-12 00:00:00
Market Capitalization: 9320722.08054161

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ITEM 1. BUSINESS

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

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

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ITEM 2. PROPERTIES

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ITEM 3. LEGAL PROCEEDINGS
Item 3. Legal Proceedings
We are involved in various legal proceedings in the ordinary course of business. These proceedings are subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters and we believe that the
ultimate disposition of such proceedings will not have a material adverse effect on our financial position, results of operations or cash flows. See Item 8. Financial Statements and Supplementary Data - Note 12. Commitments and Contingencies.

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

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Common Stock On December 16, 2019, acting pursuant to authorization from our Board of Directors, we provided notice to the New York Stock Exchange (NYSE) of our intent to voluntarily withdraw the principal listing of our common stock, par value $0.01 per share, from the NYSE and transfer the listing to Nasdaq. Our common stock was voluntarily delisted on the NYSE effective as of the close of trading on December 27, 2019, and trading commenced on Nasdaq at market open on December 30, 2019. Our stock continues to trade under the stock symbol “NBL.”
Dividends 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.
On January 27, 2020, our Board of Directors declared a quarterly cash dividend of $0.12 per common share. The dividend will be paid February 24, 2020, to shareholders of record on February 10, 2020. 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 4, 2020, the number of holders of record of our common stock was 522.
Stock Repurchases The following table summarizes repurchases of our common stock occurring in fourth quarter 2019:
(1)
Shares repurchased 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 2019, we did not repurchase any shares under 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 On January 28, 2019, the Compensation, Benefits and Stock Option Committee of the Board of Directors (the Committee) made changes to our compensation peer group to accurately reflect, in the judgment of the Committee, companies with which we compete for investment capital and market recognition. Criteria used to determine this new group included similarity of long-term business strategy, multi-basin operations, commodity mix and international presence. After the change in companies, the new peer group consisted of the following:
Anadarko Petroleum Corp. (1)
Devon Energy Corp.
Murphy Oil Corp.
Apache Corp.
Ovintiv Inc. (formerly known as Encana Corp.)
Noble Energy, Inc.
Chesapeake Energy Corp.
EOG Resources, Inc.
WPX Energy, Inc.
Cimarex Energy Co.
Hess Corp.
Continental Resources, Inc.
Marathon Oil Corp.
(1)
Anadarko Petroleum Corp. is excluded from all periods in the graph below due to its acquisition by Occidental Petroleum Corp. in 2019.
Compared to our 2018 peers, the new 2019 peer group includes Cimarex Energy Co., Encana Corp. and WPX Energy, Inc., and excludes Cabot Oil & Gas Corp., Pioneer Natural Resource Co., Range Resources Corp. and Southwestern Energy Co.
This graph shows our cumulative total shareholder return over the five-year period from December 31, 2014 to December 31, 2019. The graph also shows the cumulative total returns for the same five-year period of the S&P 500 Index, the previous peer group used in 2018, and the new 2019 peer group. The cumulative total return of the common stock of our 2018 and 2019 peer groups includes the cumulative total return of our common stock.
The comparison assumes $100 was invested on December 31, 2014 in our common stock, in the S&P 500 Index and in our 2019 and 2018 peer groups and assumes that all of the dividends were reinvested. In addition, each peer group investment is weighted based upon the market capitalization of each individual company within the applicable peer group.
Copyright© 2020 Standard & Poor's, a division of S&P Global. All rights reserved.

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. Selected Financial Data
(1)
See Item 8. Financial Statements and Supplementary Data - Note 10. Impairments.
(2)
See Item 8. Financial Statements and Supplementary Data - Note 4. Acquisitions and Divestitures.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide a narrative about our business from the perspective of our management. Our MD&A is presented in the following sections:
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Executive Overview;
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Operating Outlook;
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Results of Operations - E&P;
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Results of Operations - Midstream;
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Results of Operations - Corporate;
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Liquidity and Capital Resources; and
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Critical Accounting Policies and Estimates.
The accompanying consolidated financial statements, including the notes thereto, contain detailed information that should be read in conjunction with our MD&A.
For discussion related to changes in financial condition and results of operations for 2018 as compared with 2017, refer to Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2018 Form 10-K, which was filed with the SEC on February 19, 2019.
EXECUTIVE OVERVIEW
Industry Outlook
Commodity Prices The global oil and gas industry is cyclical, and commodity prices can be volatile. Global crude oil prices are driven by crude oil supply, which includes Organization of Petroleum Exporting Countries (OPEC) and non-OPEC producers, and global crude oil demand. The outlook for 2020 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. Production cuts by OPEC and geopolitical factors in critical oil producing regions remain constructive for global crude oil prices. However, a weakening of crude oil demand amid signs of a potential softening in the global economy could result in lower prices. In addition, US and China trade tensions threaten further damage to global trade and economic growth and, consequently, crude oil demand.
The US domestic natural gas market remains oversupplied as production has continued to grow due to drilling efficiencies, higher incremental volumes of associated gas from oil wells and de-bottlenecking of transportation infrastructure. Despite record domestic LNG exports and high natural gas fired electric generation, natural gas inventories are projected to remain at or slightly above historical five-year averages. As a result, natural gas prices traded within a narrow range in 2019, with an expectation to continue as such in 2020. Natural gas price differentials increased in the DJ Basin, while differentials in the Delaware Basin continue to be wide despite additional pipeline capacity from the Delaware Basin to Corpus Christi, Texas. Additional Delaware Basin natural gas pipeline expansions are targeted for in-service in late 2020, which are expected to decrease these differentials.
US NGL prices are also suppressed amid increased production, high inventory levels, and downstream fractionation and export bottlenecks. As new processing and export facilities are brought online, NGL prices should benefit. During 2019, we added NGL commodity price hedges to our hedge portfolio.
The chart below shows the historical trends in benchmark prices for WTI crude oil, Brent crude oil, Mont Belvieu composite NGLs, and US Henry Hub natural gas.
Our Eastern Mediterranean GSPAs generally provide for an initial base price subject to price indexation over the life of the contract and have a contractual floor, which provides some protection from price volatility.
2019 Operating Focus
During 2019, our activities were focused on positioning the Company for sustainable, long-term cash flows through the following initiatives:
Improving Cost Structure We focused on strong operational execution and cost control to improve our cost structure for current and future operations. We reduced capital spend, focusing on high-margin, high-return opportunities while emphasizing safety and protection of the environment. Capital efficiencies resulted in significantly lower well costs, driving overall capital spend nearly $240 million lower than expected for the year. Unit production expenses were also driven lower than expected, primarily due to US onshore cost initiatives.
Improving US Onshore Takeaway Capacity We successfully leveraged significant pipeline expansion projects for increased flow assurance and improved crude oil netback prices. In the DJ Basin, we entered into a strategic relationship with Saddlehorn, acquiring additional capacity of long-term takeaway at lower cost. In the Delaware Basin, we exercised options to acquire ownership interests in EPIC Y-Grade and EPIC Crude Holdings, and partnered in the formation of the Delaware Crossing joint venture. Through these investments, we gained access to Gulf Coast pricing for certain of our Delaware Basin
production when the EPIC Y-Grade Pipeline began interim crude oil service. We continue to negotiate other pipeline contracts for lower cost arrangements.
Leviathan Phase I Development Having commenced production from the Leviathan field on December 31, 2019, we are now ready for significant regional exports to begin. We expect Leviathan production and regional sales will result in a significant impact to our sustainable production profile, with material increases in sales volumes and cash flows in 2020.
Progressing Natural Gas Monetization Offshore West Africa We continue to focus on progressing natural gas monetization opportunities through development of a regional natural gas hub offshore West Africa. During the year, we sanctioned the Alen Gas Monetization project, which will result in low-cost access to additional reserves and our entry into the global LNG markets in 2021.
Advancing Exploration Opportunities Although we have modified our exploration activity in the low commodity price environment, we continue to pursue opportunities that have low capital commitments, but which we perceive to have potentially high impact. During the year, we farmed-in a significant new opportunity offshore Colombia and progressed various exploration activities in support of future drilling efforts in both US onshore and international locations.
Completing Midstream Strategic Review We conducted a strategic review of our Midstream segment and elected to retain and increase our ownership in Noble Midstream Partners. We concluded the review with the sale of substantially all of our remaining US onshore midstream interests and assets and our incentive distribution rights to Noble Midstream Partners for total consideration of $1.6 billion, including $670 million of cash and 38.5 million of newly issued Noble Midstream Partners common units.
Maintaining Strong Balance Sheet We focused on maintaining our strong balance sheet and financial liquidity, which totaled almost $4.5 billion at December 31, 2019. During the year, we early redeemed certain senior notes, extending the average maturity of our total debt portfolio, which is approximately 16 years. We maintained our investment grade rating across all agencies while returning capital to investors through debt repayments and dividends.
Advancing Environmental, Social and Governance (ESG) Initiatives We continued our focus on ESG initiatives by identifying opportunities to reduce environmental impact, improve safety, support the communities in which we operate through social investment, increase transparency, and the diversity of our Board of Directors. We also finished 2019 with a record-low total recordable incident rate in the US onshore.
OPERATING OUTLOOK
Growing Long-Term Value We believe the following guiding principles will contribute to growing long-term value:
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Execution of a disciplined capital allocation process by:
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designing a flexible investment program aligned with the current commodity price environment.
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Leveraging the benefits of our well-positioned and diversified portfolio, including:
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exercising investment optionality and flexibility afforded by our assets, certain of which are held by production; and
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continuing portfolio optimization actions to maximize strategic value.
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Enhancing capital efficiencies by:
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utilizing our technical competencies and applying historical learnings from unconventional US shale plays to reduce US onshore exploration and development costs.
•
Capitalizing on a currently low-cost offshore environment with execution of high-quality, long-cycle development projects, such as:
◦
continuing development offshore Israel and monetizing natural gas offshore West Africa.
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Maintaining financial strength through:
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focusing operational activities on high-margin, high-return assets; and
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improving overall corporate returns.
•
Commitment to people and communities in which we operate by:
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being a safe and reliable operator;
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complying with applicable air quality rules and environmental regulations; and
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advancing ESG initiatives.
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, combined with Leviathan natural gas sales and efforts towards Alen Gas Monetization, will position us for sustainable free cash flow generation in the future. However, if commodity prices are suppressed for an extended period of time, 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 investment program or dividends, asset sales or actions to support our financial position. Our production, cash flows, and our stock price could decline as a result of these potential developments. See Item 1A. Risk Factors - Crude oil, NGL and natural gas price
volatility, including a substantial or extended decline in the price of these commodities, could have a material adverse effect on our results of operations, cash flows, liquidity, and the price of our common stock.
2020 Organic Capital Investment Program Our 2020 organic capital investment program, which excludes Noble Midstream Partners and acquisition capital, is designed to deliver near and long-term value and is flexible in the current commodity price environment. The 2020 organic capital investment program is in the range of $1.6 to $1.8 billion. The 2020 organic capital investment program is approximately 25% below our 2019 organic capital expenditures, which reflects lower spend on the Leviathan field offshore Israel. Approximately 75% of the 2020 organic capital budget is allocated to US onshore development, primarily in the DJ and Delaware Basins, with the remainder allocated to progressing the Alen Gas Monetization in West Africa, expanding gas deliverability in Israel and costs for drilling an exploratory well offshore Colombia.
We plan to fund our capital investment program with 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.
Our 2020 production target is in the range of 385 MBoe/d to 405 MBoe/d. In our US onshore business, we expect relatively flat production compared to 2019, with an increase in DJ and Delaware Basin production offset by reductions in the Eagle Ford Shale. We expect to have higher oil volumes in 2020 compared to 2019.
Potential for Future Impairments We have had in the past, and may incur in the future, impairments of proved and unproved properties. Our impairment assessment as of December 31, 2019 indicated that the carrying amounts of our DJ Basin and Delaware Basin properties were not impaired. However, we believe our Delaware Basin properties, in particular, may be at risk for future impairment. Our Delaware Basin properties have significant book value associated with proved reserves and unproved resources, which were acquired primarily through corporate acquisitions. Through acquisition accounting, acquired asset values are recorded at their estimated fair market values at the time of closing. In 2017, commodity prices, specifically those for domestic NGLs and natural gas, were significantly higher when compared to the current environment.
We believe that it is reasonably likely an impairment could be triggered if there is a decrease in forward commodity price assumptions, a widening of basis differentials, material changes to development plans or an increase in operating or abandonment costs, among other factors. The variable which generates the most significant change in undiscounted future net cash flows is generally the forward commodity price outlook. For purposes of impairment assessment, where contractual pricing is not applicable, our current assumption is based on a five-year strip price for crude oil and natural gas, with prices subsequent to the fifth year held constant. Should our assumptions regarding forward commodity prices decline 5% or more beyond that used as of December 31, 2019, with all other assumptions unchanged, our Delaware Basin properties would be at risk for impairment. As of December 31, 2019, the carrying amount of our Delaware Basin properties was $5.5 billion, of which $3.6 billion was attributable to proved properties, including related Midstream segment assets, with $1.9 billion attributable to unproved properties.
In addition, an extended commodity price downturn could result in the impairment of other proved or unproved properties or long-lived assets, including equity method investments, intangible assets, goodwill and/or right-of-use assets. A future impairment of property or other long-lived asset could have a significant impact on our deferred tax asset and liability balance, and potentially cause us to establish valuation allowances for our deferred tax assets associated with domestic net operating loss carryforwards, which would result in a corresponding increase in income tax expense.
See Item 1A. Risk Factors - Crude oil, NGL and natural gas price volatility, including a substantial or extended decline in the price of these commodities, could have a material adverse effect on our results of operations, cash flows, liquidity, and the price of our common stock.
RESULTS OF OPERATIONS - E&P
2019 Significant E&P Highlights:
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increased total average consolidated sales volumes by 3% to 355 MBoe/d, net;
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increased average daily sales volumes for US onshore crude oil by 10% to 120 MBbl/d, net;
•
reduced total production expense per BOE by 3% as compared to 2018;
•
exceeded 2 Tcf, gross, of natural gas produced from the Tamar field since commencement of operations;
•
commenced production from the Leviathan field in December 2019;
•
invested in the EMG Pipeline, through our affiliate, EMED Pipeline B.V., enabling future flow of natural gas production from offshore Israel to customers in Egypt;
•
reduced capital expenditures, excluding acquisitions, by $571 million as compared with 2018;
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drilled the Aseng 6P well, offshore Equatorial Guinea, and commenced production in fourth quarter 2019; and
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sanctioned the Alen Gas Monetization project, offshore Equatorial Guinea.
Following is a summarized statement of operations for our E&P business:
(1)
See Item 8. Financial Statements and Supplementary Data - Note 4. Acquisitions and Divestitures.
(2)
See Item 8. Financial Statements and Supplementary Data - Note 10. Impairments.
Average Oil, NGL and Gas Sales Volumes and Prices Average daily sales volumes from our share of production and average realized sales prices were as follows:
(1)
Natural gas from the Alba field is sold under contract for $0.25 per MMBtu to a methanol plant, an LPG plant, an LNG plant and a power generation plant. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method. See Items 1. and 2. Business and Properties - Delivery Commitments - West Africa Agreements.
(2)
Volumes represent sales of condensate and LPG from the LPG plant in Equatorial Guinea. See Income from Equity Method Investments and Other.
(3)
Includes 7 MBoe/d for 2018 related to Gulf of Mexico assets sold in second quarter 2018. See Item 8. Financial Statements and Supplementary Data - Note 4. Acquisitions and Divestitures.
An analysis of revenues from sales of crude oil, NGLs and natural gas is as follows:
(1)
Changes exclude impacts of commodity derivative instruments. See Item 8. Financial Statements and Supplementary Data - Note 14. Derivative Instruments and Hedging Activities.
Crude Oil and Condensate Sales Revenues Revenues from crude oil and condensate sales decreased in 2019 as compared with 2018 due to the following:
•
9% decrease in average realized prices (see factors impacting global pricing at Executive Overview - Industry Outlook);
•
reduction in sales volumes of 5 MBbl/d due to the sale of our Gulf of Mexico assets in second quarter 2018; and
•
lower offshore West Africa sales volumes of 3 MBbl/d due to timing of liftings and natural field decline;
partially offset by:
•
higher US onshore sales volumes of 11 MBbl/d primarily due to an increase in development activity in the DJ and Delaware Basins.
NGL Sales Revenues Revenues from NGL sales decreased in 2019 as compared with 2018 due to the following:
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43% decrease in average realized prices (see factors impacting global pricing at Executive Overview - Industry Outlook); and
•
lower Eagle Ford Shale sales volumes of 6 MBbl/d due to reduced activity and natural field decline;
partially offset by:
•
higher sales volumes of 12 MBbl/d in the DJ and Delaware Basins due to an increase in development activities.
Natural Gas Sales Revenues Revenues from natural gas sales decreased in 2019 as compared with 2018 due to the following:
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13% decrease in average realized prices (see factors impacting global pricing at Executive Overview - Industry Outlook);
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lower Eagle Ford Shale sales volumes of 41 MMcf/d due to reduced activity and natural field decline;
•
lower West Africa sales volumes of 28 MMcf/d due to natural field decline and planned maintenance at onshore facilities during first quarter 2019, which required shut-in for a portion of the period; and
•
lower Israel sales volumes of 14 MMcf/d primarily due to the sale of a 7.5% interest in the Tamar field in March 2018;
partially offset by:
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higher sales volumes of 91 MMcf/d in the DJ and Delaware Basins due to an increase in development activity.
Sales and Cost of Purchased Oil and Gas Sales and cost of purchased oil and gas increased in 2019 as compared with 2018 as we engaged in a full year of third-party sales and purchases of crude oil in the DJ Basin in 2019 compared with only fourth quarter sales and purchases in 2018. We enter into these arrangements for flow assurance on pipelines used to deliver our production to market and to cover shortfalls in equity production.
Income from Equity Method Investments and Other Our share of operations of equity method investments were as follows:
Income from equity method investments decreased for 2019 as compared with 2018 due to the following:
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decrease in net income from AMPCO and affiliates primarily due to lower realized methanol prices; and
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decrease in net income from Alba Plant primarily due to lower realized LPG prices.
Production Expense Components of production expense were as follows:
(1)
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investments.
(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.
Production expense decreased in 2019 as compared with 2018 primarily due to the following:
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decrease in US lease operating expense primarily due to the sale of our Gulf of Mexico assets and cost reduction efforts, notably workover reductions and compression optimization, in the US onshore basins; and
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decrease in other royalty expense due to lower commodity prices;
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decrease in West Africa lease operating expense due to cost reduction efforts across all assets; and
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decrease in production and ad valorem taxes due to production tax refunds;
partially offset by:
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increase in US gathering, transportation and processing (GTP) expense primarily due to increased development activity in the DJ Basin and higher-cost Delaware Basin; and
•
increase in Eastern Mediterranean lease operating expense due to planned maintenance activities.
The decrease in the unit rate per BOE for 2019 compared to 2018 is primarily due to cost reduction efforts in US onshore basins and West Africa, partially offset by an increase in GTP expense and an increase in volumes from higher-cost areas within US onshore.
Exploration Expense The increase in exploration expense for 2019 is primarily due to the write-off of $100 million of Leviathan Deep exploratory well costs. This increase was partially offset by reductions in lease rentals and staff expense as compared with 2018. See Item 8. Financial Statements and Supplementary Data - Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
Depreciation, Depletion and Amortization (DD&A) Expense DD&A expense was as follows:
(1)
DD&A expense includes accretion of discount on asset retirement obligations (AROs) of $43 million in 2019 and $33 million in 2018.
(2)
Consolidated rates exclude sales volumes and expenses attributable to equity method investments.
Total DD&A expense increased in 2019 as compared with 2018 primarily due to the following:
•
capital investment and development activities in the DJ and Delaware Basins resulting in higher sales volumes; and
•
increase in Eastern Mediterranean primarily due to the retirement of certain capital assets resulting in accelerated depreciation;
partially offset by:
•
decrease resulting from the sale of our Gulf of Mexico assets in second quarter 2018; and
•
reduced sales volumes in West Africa, as noted above, from natural field decline.
The unit rate per BOE for 2019 increased as compared with 2018 due to increased development activity in the higher cost oil-rich Delaware Basin and the 2018 sale of lower-cost Tamar reserves, which increased the overall unit rate per BOE. The increase in unit rate is partially offset by the sale of higher-cost production from the Gulf of Mexico assets in second quarter 2018.
Loss (Gain) on Commodity Derivative Instruments Commodity derivative activity was as follows:
For 2019, the loss on commodity derivative instruments was due to the following:
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net cash receipt of $32 million; and
•
net non-cash decrease of $175 million in the fair value of our net commodity derivative liability, primarily driven by increases in the forward commodity price curve for crude oil.
For 2018, gain on commodity derivative instruments included:
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net cash payment of $161 million; and
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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.
See Item 8. Financial Statements and Supplementary Data - Note 14. Derivative Instruments and Hedging Activities.
RESULTS OF OPERATIONS - MIDSTREAM
2019 Significant Midstream Highlights:
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sold substantially all of our US onshore midstream interests and assets and our incentive distribution rights to Noble Midstream Partners for total consideration of $1.6 billion;
•
expanded our long-haul business by developing strategic relationships in the Delaware Basin, exercising investment options in EPIC Y-Grade and EPIC Crude Holdings, and forming the Delaware Crossing crude oil pipeline joint venture, with total equity contributions of approximately $590 million; and
•
secured long-term takeaway at a lower cost in the DJ Basin through a strategic relationship with Saddlehorn.
Following is a summarized statement of operations for the Midstream segment:
Midstream Services Revenues - Third Party 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 dedicated acreage for our E&P business and to third-party customers. These volumes are affected by the level of drilling and completion activity 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.
Midstream segment services revenues for 2019 increased $16 million as compared with 2018 primarily due to increases in crude oil, natural gas and produced water gathering services and fresh water delivery. The increases were due primarily to higher Delaware Basin throughput volumes, a full year of services in the Mustang IDP and a full year of services related to the Black Diamond System, which was acquired in first quarter 2018.
Sales and Cost of Purchased Oil and Gas Sales and cost of purchased oil and gas for 2019 increased $48 million as compared with 2018 due to an increase in throughput volumes driven by additional well connections.
(Loss) Income from Equity Method Investments The 2019 amount decreased as compared to 2018 due to operating costs incurred by Noble Midstream Partners' equity method investments prior to commencement of full service operations, as well as a decrease in income of $24 million due to the sale of our investments in CONE Gathering LLC and CNX Midstream Partners LP (NYSE: CNXM) in 2018.
Operating Costs and Expenses Total expense for 2019 increased by $22 million as compared with 2018 due to an increase in gathering systems operating expense associated with the Delaware Basin CGFs that were completed in 2018, additional expenses associated with the Black Diamond System and expenses associated with the commencement of gathering services in the Mustang IDP in 2018.
DD&A Expense DD&A expense for 2019 increased by $17 million as compared with 2018 primarily due to certain assets being placed in service throughout 2018, including the Mustang IDP gathering system, the Delaware Basin CGFs, and additional Black Diamond assets. In addition, DD&A expense includes a full year of amortization related to intangible assets acquired in the Saddle Butte acquisition.
Gain on Divestitures, Net See Item 8. Financial Statements and Supplementary Data - Note 4. Acquisitions and Divestitures.
Asset Impairments See Item 8. Financial Statements and Supplementary Data - Note 10. Impairments.
RESULTS OF OPERATIONS - CORPORATE
Interest expenses and other debt-related costs, headquarters depreciation, corporate G&A expenses, exit costs and certain other costs associated with mitigating the effects of our retained Marcellus Shale transportation agreements are recorded at the Corporate level.
Transportation Exit Cost Revenues and expenses associated with retained Marcellus Shale firm transportation contracts were as follows:
(1)
Relates to third-party mitigation activities we engage in to utilize a portion of our Marcellus Shale transportation commitments. Cost of purchased gas includes utilized and unutilized transportation expense.
(2)
Includes exit costs related to future commitments to a third-party resulting from a permanent capacity assignment.
See Item 8. Financial Statements and Supplementary Data - Note 11. Exit Cost - Transportation Commitments.
General and Administrative Expense G&A expense was as follows:
(1)
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investments.
The 2019 increase to G&A is primarily due to incentive compensation awards, which reflected strong operating performance and major project execution. The increase in the unit rate per BOE for 2019 as compared with 2018 was due to the increase in G&A expense, partially offset by the increase in total sales volumes.
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 $59 million in 2019 and $54 million in 2018. See Item 8. Financial Statements and Supplementary Data - Note 16. Stock-Based and Other Compensation Plans.
Loss on Extinguishment of Debt or Facility See Item 8. Financial Statements and Supplementary Data - Note 8. Long-Term Debt.
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 investments.
Interest expense for 2019 increased slightly as compared with 2018. See Item 8. Financial Statements and Supplementary Data - Note 8. Long-Term Debt. Capitalized interest for 2019 increased as compared with 2018 primarily due to higher work in progress amounts related to Leviathan development and additions to our Midstream segment equity method investments engaged in construction activities.
The unit rate per BOE for 2019 decreased as compared with 2018, primarily due to the reduction in net interest expense and the increase in total sales volumes.
Income Taxes See Item 8. Financial Statements and Supplementary Data - Note 13. Income Taxes.
LIQUIDITY AND CAPITAL RESOURCES
Capital Structure/Financing Strategy
In seeking to effectively fund development 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. 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. Our sources of liquidity are primarily cash flows from operations, cash on hand, proceeds from divestitures of properties and other investments, commercial paper borrowings and available borrowing capacity under our Revolving Credit Facilities (defined below). We occasionally access the capital markets to ensure adequate liquidity exists in the form of unutilized capacity under our Revolving Credit Facilities or to refinance scheduled debt maturities.
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 repurchases, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors.
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. Additionally, we enter into commodity 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.
In 2019, we funded our capital investment program with cash flows from operations, cash on hand, commercial paper borrowings, proceeds from divestments of non-strategic assets, proceeds from the Midstream segment asset divestiture to Noble Midstream Partners, and other sources of funding. During the year, we did not repurchase any shares of Noble Energy common stock under the Board of Directors-authorized $750 million share repurchase program. As a result of our financing activities, we ended 2019 with almost $4.5 billion in liquidity, including $4.0 billion of availability under our Noble Energy Revolving Credit Facility.
2019 Significant Financing Highlights
•
initiated a commercial paper program;
•
issued and redeemed notes, lowering interest expense and extending debt maturities;
•
established a new Noble Midstream Partners term loan;
•
increased the Noble Midstream Services Revolving Credit Facility capacity to almost $1.2 billion;
•
secured a $200 million preferred equity commitment at Noble Midstream Partners; and
•
completed our midstream asset sale and simplification to Noble Midstream Partners.
Available Liquidity
Our operating cash flows are a significant source of liquidity. Additional sources of funding were available through debt financing activities, as described above. Overall, we expect to support our 2020 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 Facilities, 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 2020. 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)
Total cash includes $3 million of restricted cash at December 31, 2018.
(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 excludes unamortized debt discount/premium and debt issuance costs. See Item 8. Financial Statements and Supplementary Data - Note 8. Long-Term Debt
(4)
We define our ratio of debt-to-book capital as total debt divided by the sum of total debt plus Noble Energy's share of equity.
Cash and Cash Equivalents We had approximately $484 million in cash and cash equivalents at December 31, 2019, $383 million of which is attributable to our foreign subsidiaries.
Revolving Credit Facilities Noble Energy's $4.0 billion unsecured revolving credit facility (Revolving Credit Facility) and Noble Midstream Services' revolving credit facility (Noble Midstream Services Revolving Credit Facility), which was increased from $800 million to almost $1.2 billion in fourth quarter 2019, 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, 2019, no amounts were outstanding under Noble Energy's Revolving Credit Facility, and no commercial paper borrowings were outstanding, leaving the entire $4.0 billion available for borrowing. At December 31, 2019, $595 million was outstanding under the Noble Midstream Services Revolving Credit Facility, leaving $555 million of remaining availability. See Item 8. Financial Statements and Supplementary Data - Note 8. Long-Term Debt.
Commercial Paper Program Supported by our investment grade credit rating, in 2019 we established a commercial paper program to provide for short-term funding needs. The program allows for Noble to issue a maximum of $4.0 billion of unsecured commercial paper notes, supported by Noble Energy’s Revolving Credit Facility. The commercial paper program was a significant source of liquidity during 2019. All amounts outstanding were repaid prior to December 31, 2019. See Item 8. Financial Statements and Supplementary Data - Note 8. Long-Term Debt.
Senior Note Issuance and Redemption In October 2019, we issued $500 million of 3.25% senior notes due October 15, 2029 and $500 million of 4.20% senior notes due October 15, 2049. Proceeds from the issuance were used to fund the early tender offer and redemption of our $1.0 billion 4.15% notes due December 15, 2021. As a result, we paid a premium of $44 million on the extinguishment of debt and recognized a loss in fourth quarter 2019. The transactions resulted in reduced future interest costs and extended debt maturity dates. See Item 8. Financial Statements and Supplementary Data - Note 8. Long-Term Debt.
Noble Midstream Services 2019 Term Loan Credit Facility In August 2019, Noble Midstream Services entered into a term loan agreement, which provides for a three-year senior unsecured term loan credit facility, due August 23, 2022 (2019 Noble Midstream Services Term Loan Credit Facility), that permits aggregate borrowings of up to $400 million. Proceeds from the term loan were primarily used to repay a portion of the outstanding borrowings under the Noble Midstream Services Revolving Credit Facility. See Item 8. Financial Statements and Supplementary Data - Note 8. Long-Term Debt.
Noble Midstream Services 2018 Term Loan Credit Facility In July 2018, Noble Midstream Services entered into a term loan agreement, which provides for a three-year senior unsecured term loan credit facility, due July 31, 2021 (2018 Noble Midstream Services Term Loan Credit Facility), that permits aggregate borrowings of up to $500 million. As of December 31, 2019, $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 8. Long-Term Debt.
Mezzanine Equity Commitment In March 2019, Noble Midstream Partners obtained a $200 million preferred equity commitment. $100 million of the commitment funded immediately and the remaining $100 million is available for funding until March 2020, subject to certain conditions precedent. See Item 8. Financial Statements and Supplementary Data - Note 1. Summary of Significant Accounting Policies.
Asset Sale to Noble Midstream Partners We received approximately $1.6 billion in consideration from the sale of substantially all of our remaining midstream interests and assets to Noble Midstream Partners. Consideration included approximately $670 million in cash, of which $420 million was funded by the Noble Midstream Services Revolving Credit Facility and approximately $250 million was funded by a private placement of Noble Midstream Partners common units. See Note 4. Acquisitions and Divestitures.
Dividends We funded a 9% dividend increase in 2019. See Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Cash Flows
The following table summarizes our net cash flows from operating, investing and financing activities:
Operating Activities The decrease in cash provided by operating activities in 2019 compared with 2018 was primarily driven by a decrease in revenues resulting from lower commodity prices, partially offset by increases in sales volumes and lower production costs attributable to cost saving initiatives. In addition, we received cash settlements of commodity derivative instruments for $32 million in 2019, compared with cash payments of $161 million in 2018 and we made cash interest payments related to outstanding debt of $310 million in 2019 compared with $343 million in 2018.
Investing Activities Increases in cash used in investing activities primarily related to funding of new equity method investments of $799 million in 2019 compared with zero in 2018 and reduced divestiture activity resulting in proceeds from divestitures of $173 million in 2019 compared with $2.0 billion in 2018. These amounts were partially offset by cash used in acquisitions of $653 million in 2018, compared to none in 2019, as well as a $755 million decrease in spending on property, plant and equipment driven by our focus on improving cost structure and capital efficiencies during 2019, lower investment in
midstream infrastructure, and the timing of Leviathan field development costs, which were lower in 2019 than the peak year of capital investment in 2018. See Item 8. Financial Statements and Supplementary Data - Note 4. Acquisitions and Divestitures and Item 8. Financial Statements and Supplementary Data - Note 5. Equity Method Investments.
Financing Activities Increases in cash provided by financing activities include net borrowings of $535 million in 2019 on the Noble Midstream Services Revolving Credit Facility, compared with net repayments of $25 million in 2018, and having no net repayments under the Revolving Credit Facility in 2019 compared with $230 million in 2018. Additionally, repayments of senior notes, net of proceeds from senior note issuances, was $53 million in 2019 compared with $384 million of repayments in 2018. In 2019, Noble Midstream Partners received net proceeds of $243 million from the issuance of Noble Midstream Partners common units, which was used to fund Noble Midstream Partners' acquisition of our remaining midstream assets. We did not repurchase shares under our share repurchase program in 2019, compared with spending of $295 million in 2018. In 2019, we received contributions from noncontrolling interest owners of $37 million compared with $353 million in 2018.
See Item 8. Financial Statements and Supplementary Data - Note 4. Acquisitions and Divestitures, Item 8. Financial Statements and Supplementary Data - Note 8. Long-Term Debt and Item 8. Financial Statements and Supplementary Data - Consolidated Statements of Cash Flows.
Acquisition and Capital Expenditures
Our expenditures (on an accrual basis) were as follows:
(1)
Amounts relate to US onshore undeveloped leasehold activity.
(2)
Amounts include capitalized interest that will be amortized into earnings over the useful life of the related assets.
Development costs decreased in 2019 as compared with 2018 due to our focus on US onshore capital efficiencies and near-term completion of the Leviathan development activities. Costs include approximately $1.6 billion for US onshore and $482 million for Eastern Mediterranean, primarily related to Leviathan.
Midstream costs incurred in 2018 primarily relate to constructing the Mustang IDP gathering system and Delaware Basin CGFs and were higher than 2019 costs which included expansion of existing infrastructure. In addition, midstream expenditures for 2018 included $206 million related to the Saddle Butte acquisition.
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, 2019, material off-balance sheet arrangements and transactions that we have entered into included transportation and gathering agreements, undrawn letters of credit and guarantees, 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, 2019 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 excludes unamortized discounts, premiums, debt issuance costs and finance lease obligations.
(3)
Interest payments and commitment fees are based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2019.
(4)
Annual lease payments exclude regular maintenance and operational costs.
(5)
Amount includes firm transportation exit cost accruals resulting from certain permanent capacity assignments.
(6)
Purchase and service obligations represent contractual agreements to purchase goods or services that are enforceable, 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.
(7)
The table excludes deferred compensation liabilities of $133 million as specific payment dates are unknown. See Item 8. Financial Statements and Supplementary Data - Note 16. Stock-Based and Other Compensation Plans.
(8)
AROs are discounted.
(9)
Amount represents commodity derivative instruments that were in a net payable position with the counterparty at December 31, 2019.
Additional contractual commitments are as follows:
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 Delaware Basin properties are held through continuous development obligations. Therefore, we are contractually obligated to fund a level of development activity in these areas which could be substantial, or exercise options with land owners to extend leases. Failure to meet these obligations may result in the loss of leases.
Mezzanine Equity Commitment Preferred equity is perpetual and has a 6.5% annual dividend rate. The preferred equity partner can request redemption at a pre-determined base return following the later of the sixth anniversary of the preferred equity closing in March 2019 or the fifth anniversary of the completion date of the EPIC Crude Oil Pipeline.
OIL Contingency As of December 31, 2019, approximately $22 million was accrued as a theoretical withdrawal premium associated with 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 and the potential termination fee is calculated annually based on OIL’s past losses.
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 $132 million at December 31, 2019.
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.
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 2019, a 10% reduction in estimates of proved reserves across all properties would have increased DD&A expense by approximately $229 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 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 DD&A expense. We assess our oil and gas properties for possible impairment whenever events or circumstances indicate that the carrying value of the asset may not be recoverable. Our assessment involves a high degree of estimation uncertainty as it requires us to make assumptions and apply judgment to estimate future net undiscounted cash flows related to proved reserves. Such assumptions include commodity prices, capital spending, production and abandonment costs and reservoir data. In cases where unproved reserve cash flows are utilized to assess properties for impairment, we apply the same pricing, cost and future production assumptions. We also apply significant judgment in assessing entity-specific assumptions and assumptions relating, but not limited to, potential impacts of the political and regulatory climate on future development activity, 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 lease term of the property. Negative revisions in estimates of reserves quantities, expectations of decreasing commodity prices, or rising
operating or development costs could result in a reduction in undiscounted future cash flows, potentially indicating an impairment.
An impairment is indicated if, as a result of the assessment, an asset's carrying value exceeds its future net undiscounted cash flows. Once an impairment is indicated, we estimate the asset's fair value as the carrying value of the asset may not be recoverable. In the absence of comparable market data, fair value is estimated using a discounted net cash flow model. Cash flows are discounted using a risk-adjusted rate and compared to the carrying value in determining the amount of impairment expense to record. Estimated future cash flows are based on management’s expectations for the future and include estimates of crude oil, natural gas and NGL reserves and future commodity prices, revenues and operating and development costs.
For the purpose of impairment assessment as of December 31, 2019, the undiscounted future net cash flows included 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 designated the price to be used. Capital and operating costs were estimated assuming 0% escalation. As a result of the assessment, an impairment of our Eagle Ford Shale assets was indicated. We then estimated the fair value of the assets and reduced the carrying value of the assets to fair value, resulting in impairment expense of $1.2 billion. See Item 8. Financial Statements and Supplementary Data - Note 10. Impairments.
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 6. 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.
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 reduces 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, 2019, we have a significant remaining financial commitment associated with Marcellus Shale retained 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 11. Exit Cost - Transportation Commitments.
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 13. Income Taxes.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
We are exposed to market risk in the normal course of business operations, and the volatility of commodity 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, 2019, we had various open commodity derivative instruments. Changes in the fair value of commodity derivative instruments are reported in earnings in the period in which they occur. Our open commodity derivative instruments were in a net liability position with a fair value of $22 million. Based on the December 31, 2019 published commodity futures price curves for the underlying commodities, a hypothetical price increase of 10% per Bbl for both crude oil and NGLs and 10% per MMBtu for natural gas would increase the fair value of our net commodity derivative liability by approximately $121 million.
Even with certain hedging arrangements in place to mitigate the effect of commodity price volatility, our 2020 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 fully protect us from declines in commodity prices and

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. Financial Statements and Supplementary Data
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate “internal control over financial reporting,” 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, 2019, 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, 2019, 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, 2019 which is included herein.
Noble Energy, Inc.
Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors
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, 2019 and 2018, the related consolidated statements of operations and comprehensive (loss) income, cash flows, and shareholders’ equity for each of the years in the three-year period ended December 31, 2019, 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, 2019 and 2018, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2019, 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, 2019, 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 12, 2020 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
Change in Accounting Principle
As discussed in Note 1 to the consolidated financial statements, the Company has changed its method of accounting for leases as of January 1, 2019 due to the adoption of Accounting Standards Update No. 2016-02, Leases.
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.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Assessment of the impact of estimated proved oil and gas reserves on depletion expense related to producing oil and gas properties
As discussed in Note 1 to the consolidated financial statements, the Company calculates depletion expense related to producing oil and gas properties using the unit-of-production method. Under this method, capitalized costs of producing oil and gas properties, along with support equipment and facilities, are depleted to expense over proved oil and gas reserves. For the year ended December 31, 2019, the Company recorded depreciation, depletion and amortization expense of $2,197 million. The estimation of proved oil and gas reserves requires the expertise of professional petroleum reserve engineers who take into consideration forecasted production. The Company’s internal reserve engineers prepare an estimate of the proved oil and gas reserves. The Company engages external reserve engineers to independently evaluate the proved oil and gas reserves estimated by the Company.
We identified the assessment of the impact of estimated proved oil and gas reserves on depletion expense related to producing oil and gas properties as a critical audit matter. Complex auditor judgment was required in evaluating the Company’s estimate of proved oil and gas reserves, which was an input to the depletion expense calculation. Specifically, auditor judgment was required to evaluate the forecasted production of proved oil and gas reserves.
The primary procedures we performed to address this critical audit matter included the following. We tested certain internal controls over the Company’s depletion process, including controls related to the forecasted production of proved oil and gas reserves. We analyzed and recalculated the depletion expense for compliance with industry and regulatory standards. We assessed the methodology used by the Company’s internal reserve engineers to estimate proved oil and gas reserves. We assessed the competence, capabilities, and objectivity of the Company’s internal reserve engineers, who estimated the proved oil and gas reserves, and the external reserve engineers engaged by the Company. We compared the forecasted production used by the Company to historical production rates. We read the findings of the Company’s external reserve engineers in order to understand the method and assumptions used by the engineers in connection with our evaluation of the Company’s reserve estimates.
Assessment of recoverability of oil and gas properties in the Eagle Ford Shale and in the Delaware Basin
As discussed in Note 1 and 10 to the consolidated financial statements, the Company routinely assesses its oil and gas properties for impairment indicators. If an impairment indicator is identified in relation to one or more oil and gas properties, an undiscounted cash flow analysis is required to quantitatively evaluate recoverability. The Company estimates future net cash flows expected in connection with the oil and gas property and compares such future net cash flows to the carrying amount of the oil and gas property to determine if the carrying amount is recoverable. When the carrying amount of an oil and gas property exceeds its estimated undiscounted future net cash flows, the carrying amount is reduced to estimated fair value. Estimated future net cash flows used to estimate fair value are based on the Company’s forecasted production of oil and gas reserves, commodity prices based on published forward price curves or contract prices as of the date of the estimate, operating and development costs, and a discount rate. The Company recorded an impairment of $1.2 billion related to the Eagle Ford Shale proved properties and did not record any impairment related to the Delaware Basin oil and gas properties.
We identified the assessment of recoverability of oil and gas properties in the Eagle Ford Shale and in the Delaware Basin as a critical audit matter. There was a high degree of subjective auditor judgment in evaluating the key assumptions used to estimate the undiscounted future net cash flows of oil and gas properties in the Delaware Basin and the discounted future net cash flows of oil and gas properties in the Eagle Ford Shale. The key assumptions were the estimated future commodity prices, including relevant market differentials, forecasted production of oil and gas reserves, risk adjustment factors associated with oil and gas reserves, estimated future operating and development costs, and a discount rate applied to the cash flows.
The primary procedures we performed to address this critical audit matter included the following. We tested certain internal controls over the Company’s oil and gas property impairment process, including controls related to the key assumptions. We compared forecasted commodity prices to publicly available market information. We evaluated the Company’s undiscounted future net cash flows by comparing the Company’s forecasted production of oil and gas reserves, development costs, and operating costs to historical results. We evaluated risk adjustment factors against supporting information used by the Company and guideline ranges by reserve class from published industry surveys. We evaluated the competence, capabilities, and objectivity of the Company’s internal reserve engineers, who estimated the reserves, including the applicable risk adjustment factors. In addition, we involved a valuation professional with specialized skills and knowledge, who assisted in evaluating the discount rate used in the valuation, by comparing it against a discount rate range that was independently developed using publicly available market data for comparable entities.
/s/ KPMG LLP
We have served as the Company’s auditor since 2002.
Houston, Texas
February 12, 2020
Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors
Noble Energy, Inc.:
Opinion on Internal Control Over Financial Reporting
We have audited Noble Energy, Inc. and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2019, 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, 2019, 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, 2019 and 2018, the related consolidated statements of operations and comprehensive (loss) income, cash flows, and shareholders’ equity for each of the years in the three-year period ended December 31, 2019, and the related notes (collectively, the consolidated financial statements), and our report dated February 12, 2020 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 12, 2020
Noble Energy, Inc.
Consolidated Statements of Operations and Comprehensive (Loss) Income
(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
Nature of Operations 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.
Note 1. Summary of Significant Accounting Policies
Basis of Presentation and Consolidation We use accounting policies that conform to US GAAP. Our consolidated accounts include our accounts and the accounts of our wholly-owned subsidiaries. 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. Certain prior-period amounts have been reclassified to conform to the current period presentation.
Segment Information Accounting policies are consistent across geographical segments. Transfers between segments are accounted for at market value. See Note 3. Segment Information.
Noble Midstream Partners Noble Energy has determined that the partners with equity at risk in Noble Midstream Partners LP (Noble Midstream Partners, Nasdaq: NBLX) lack the authority, through voting rights or similar rights, to direct the activities that most significantly impact Noble Midstream Partners' economic performance; therefore, Noble Midstream Partners is considered a variable interest entity (VIE). Through Noble Energy's ownership interest in Noble Midstream GP LLC (the General Partner to Noble Midstream Partners), Noble Energy has the authority to direct the activities that most significantly affect economic performance and the obligation to absorb losses or the right to receive benefits that could be potentially significant to Noble Midstream Partners. Therefore, Noble Energy is considered the primary beneficiary and consolidates Noble Midstream Partners.
Noncontrolling Interests Our consolidated financial statements include both noncontrolling interests and a redeemable noncontrolling interest. The noncontrolling interests represent the public's ownership in Noble Midstream Partners and third-party ownership in Noble Midstream Partners' consolidated non-wholly owned subsidiaries.
The redeemable noncontrolling interest represents third-party preferred equity secured by Noble Midstream Partners in March 2019. The entire equity commitment totals $200 million, of which $100 million was funded and the remaining $100 million is available for a one year period, subject to certain conditions precedent. The preferred equity is perpetual and has a 6.5% annual dividend rate. Noble Midstream Partners can redeem the preferred equity in whole or in part at any time for cash at a predetermined redemption price. The preferred equity partner can request redemption at a pre-determined base return following the later of the sixth anniversary of the preferred equity closing or the fifth anniversary of the completion date of the EPIC Crude Oil Pipeline (defined below). As the preferred equity partner’s redemption right is outside of Noble Midstream Partners’ control, the preferred equity is not considered to be a component of shareholders' equity and, therefore, is reported as mezzanine equity. In addition, because the preferred equity is held by a third-party, it is considered a redeemable noncontrolling interest. We accrete changes in the preferred equity redemption value from the issuance date to the earliest redemption date and offset the accretion against additional paid in capital. See Note 4. 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. For certain entities, we serve as the operator and exert significant influence over the day-to-day operations. For other entities, we do not serve as the operator; however, our voting position on management committees or the board of directors allows us to exert significant influence over decisions regarding capital investments, budgets, turnarounds, maintenance, monetization decisions and other project matters. 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 upstream operations. In order to reflect the economics associated with our integrated upstream value chain, we include income from equity method investments as a component of revenues in our consolidated statements of operations. See Note 5. Equity Method Investments.
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. See Supplemental Oil and Gas Information (Unaudited). Other items subject to estimates and assumptions include the carrying amounts of inventory, property, plant and equipment, equity method investments, goodwill, intangible assets, exit cost liabilities and AROs, valuation
Noble Energy, Inc.
Notes to Consolidated Financial Statements
allowances for receivables and deferred income tax assets, valuation of derivative instruments, and fair values, 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, or other events, could result in a reduction in our fair value estimates and cause us to perform analyses to determine if our oil and gas properties, or other long-lived assets, are impaired. As future commodity prices cannot be determined accurately, actual results could differ significantly from our estimates.
Fair Value Measurements Certain assets and liabilities are measured at fair value on a recurring basis on our consolidated balance sheets. Other assets and liabilities are measured at fair value on a nonrecurring basis. 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:
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Level 1 measurements are fair value measurements which use quoted market prices (unadjusted) in active markets for identical assets or liabilities.
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Level 2 measurements are fair value measurements which use inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly.
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Level 3 measurements are fair value measurements which use unobservable inputs.
The fair value hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. We use Level 1 inputs when available, as Level 1 inputs generally provide the most reliable evidence of fair value. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term nature or maturity of the instruments.
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 Expected Credit Losses Our accounts receivable result primarily 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 reflects broad national and international customer base, which limits our exposure to concentrations of credit risk. We continually monitor the creditworthiness of the counterparties and have obtained credit enhancements from some parties in the form of parental guarantees or letters of credit.
At the end of each reporting period, we assess the recoverability of all material receivables using historical data, current market conditions, and reasonable and supportable forecasts of future economic conditions to determine their expected collectibility. The loss given default method is used when, based on management's judgment, an allowance for expected credit losses should be accrued on a material receivable to reflect the net amount expected to be collected. See “Recently Adopted Accounting Standards” below for discussion on our early adoption of Accounting Standards Update No. 2016-13 (ASU 2016-13): Financial Instruments - Credit Losses. 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 depleted using 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 accumulated DD&A is eliminated and we either adjust the basis of the respective asset or recognize a gain or loss. Costs related to repair and maintenance activities are expensed as incurred.
Proved Property Impairment For our proved properties, we routinely assess whether impairment indicators exist 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. We conduct an impairment test in the event impairment indicators exist. 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.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
When the carrying amount of the proved property exceeds its estimated undiscounted future net cash flows, an impairment is indicated and the fair value of the asset is then estimated. Fair value inputs, which are level 3 on the fair value hierarchy, 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 net 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. In the event of an impairment, the carrying amount of the proved property is reduced to estimated fair value. See Note 10. Impairments.
Unproved Property Our unproved properties consist of leasehold costs and allocated value to probable and possible reserves resulting from acquisitions. 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.
We assess individually significant unproved properties for impairment on a quarterly basis and recognize a loss at the time of impairment. 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 net 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. Reserves volumes are reduced by risk adjustments applied to probable and possible reserves. See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
Properties Acquired in Business Combinations When sufficient market data is not available, we determine the fair values of proved and unproved 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 At the end of each reporting period, we evaluate properties being marketed for sale to determine whether any should be reclassified as held for sale. If the held-for-sale criteria are met, the property is reclassified as held for sale on our consolidated balance sheets and valued at the lower of net book value or anticipated sales proceeds less costs to sell. Impairment expense is 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 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 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
Property, Plant and Equipment, Other Other property includes automobiles, trucks, an airplane, 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, term loan credit facilities and Senior
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Notes. Capitalized interest is included in the cost of oil and gas assets and is amortized with other costs on a unit-of-production basis.
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 7. Asset Retirement Obligations.
Intangible Assets Intangible assets consist of customer contracts and relationships that were recorded 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, 2019, the net book value of our intangible assets was $278 million, net of accumulated amortization of $62 million. Intangible assets with finite useful lives are reviewed for impairment when events or changes in circumstances indicate that the carrying amounts of such assets may not be recoverable. See Note 4. Acquisitions and Divestitures.
Exit Costs 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. Fair value estimates are based on expected future discounted cash outflows required to satisfy the obligation, net of estimated recoveries. In periods subsequent to initial measurement, 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, are recognized as an adjustment to the liability in the period of the change. Exit costs, and associated accretion expense, are included in other operating expense, net in our consolidated statements of operations. See Note 11. Exit Cost - Transportation Commitments.
Derivative Instruments and Hedging Activities All derivative instruments 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.
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 14. 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. See Note 16. Stock-Based and Other Compensation Plans.
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 12. Commitments and Contingencies.
Income Taxes 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 and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date when the change in the tax rate was enacted.
In 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. The
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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. See Note 13. 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 Our revenues are derived primarily from the sale of crude oil, NGL and natural gas production to crude oil refining companies, midstream marketing companies, marketers, industrial companies, electric utility companies, independent power producers and cogeneration facilities, among others. We recognize revenues based on the amount of product sold to a customer when control transfers to the customer. Our revenue arrangements include the following:
Crude Oil Sale Arrangements - US We sell our share of crude oil production under both short-term and long-term contracts at market-based prices, adjusted for location, quality and transportation charges. Revenue is measured based on the index-based contract price, and may include adjustments for market differentials and downstream costs incurred by the customer, including gathering, transportation, and fuel costs.
Crude Oil Sale Arrangements - West Africa We sell our share of crude oil and condensate at market-based prices and recognize revenue at the time a crude oil cargo is loaded onto the tanker.
Natural Gas and NGLs Sale Arrangements - US We evaluate these arrangements to determine whether the processor is a service provider or a customer. In arrangements where we determine that the processor is a customer, we record revenue when the processor takes control 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 arrangements, we receive natural gas and NGL products “in-kind” after processing at the tailgate of the plant. In these arrangements, where we determine that the processor is a service provider, we record revenue 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 Sale Arrangements - West Africa We sell our share of natural gas production 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 - Eastern Mediterranean We sell our share of natural gas production primarily based on long-term contracts with fixed volume commitments. Performance obligations 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 these sales contracts contain take-or-pay provisions whereby the customers are required to purchase a contractual minimum over varying time periods. We record revenues related to the volumes delivered at the contract price at the time of delivery.
The following table provides estimated future revenues for remaining performance obligations under fixed volume natural gas sales agreements using the contractual fixed base or floor price provision in effect. Actual future sales volumes under these agreements may exceed future minimum volume commitments. In addition, future sales revenues will vary due to components of variable consideration above the contractual base or floor provision, such as index-based escalations and market price changes. Certain of these contracts contain embedded derivatives for which we have elected the normal purchases and normal sales scope exception, which excludes the derivatives from mark-to-market accounting.
Estimated future revenues related to remaining performance obligations were as follows as of December 31, 2019:
(1)
Includes amounts related to the Tamar and Leviathan fields, offshore Israel.
Oil and Gas Purchase and Sale Arrangements We enter into separate third-party purchase and sale transactions at prevailing market prices to mitigate unutilized pipeline transportation commitments. We recognize associated revenues and expenses 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. We also enter into crude oil buy/sell arrangements that effect a change in location and/or grade with required repurchase of crude oil at a delivery point. We account for these transactions on a net basis and record the residual transportation fee within gathering, transportation and processing expense in the consolidated statements of operations.
Midstream Services Arrangements Third-party Midstream services revenues relate to fixed fee arrangements for gathering, transportation and storage services. Our performance obligations for the provision of such services are satisfied over time using volumes delivered as the measure of progress.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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 Adopted Accounting Standards
Leases Effective January 1, 2019, we adopted Accounting Standards Update No. 2016-02 (ASU 2016-02), which created Topic 842 - Leases (ASC 842). The standard requires lessees to recognize a right-of-use (ROU) asset and lease liability on the balance sheet for the rights and obligations created by leases. This standard does not apply to leases to explore for or use minerals, oil, natural gas or similar nonregenerative resources, including the intangible right to explore for those resources and rights to use the land in which those natural resources are contained.
Upon adoption, we elected the following optional practical expedients:
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transition “practical expedients,” permitting us not to reassess our prior conclusions about lease identification, lease classification and initial direct costs;
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the practical expedient pertaining to land easements, allowing us to account for existing land easements under our previous accounting policy; and
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the practical expedient to not separate lease and non-lease components for the majority of our leases (elected by asset class).
We adopted ASC 842 using the modified retrospective method and recorded ROU assets and lease liabilities of $282 million and $287 million, respectively, primarily related to operating leases. ROU assets and corresponding liabilities are based on the present value of the minimum lease payments. Our accounting for finance leases remains substantially unchanged. Adoption of ASC 842 did not materially impact our consolidated statement of operations and comprehensive income and had no impact on our consolidated statement of cash flows.
Additional information related to our accounting policies for leases is as follows:
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Most of our leases do not provide implicit borrowing rates; therefore, using the portfolio approach, we determine the present value of lease payments using hypothetical secured borrowing rates based on information available at lease commencement.
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Leases with an initial term of 12 months or less are not recorded on the balance sheet and we recognize lease expense for these leases on a straight-line basis over the lease term. Most leases include one or more options to renew, with renewal terms that can extend the lease term from one month to one year or more. Additionally, some of our leases include an option for early termination. We include renewal periods and exclude termination periods from our lease term if, at commencement, it is reasonably likely that we will exercise the option.
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Certain of our lease agreements include rental payments that are adjusted periodically for inflation or passage of time. These step payments are included within our present value calculation as they are known adjustments at commencement. Variable payments related to lease agreements are not material.
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We have lease agreements that include lease and non-lease components, such as equipment maintenance, that are generally accounted for as a single lease component. For these leases, lease payments include all fixed payments stated within the contract. For other leases, such as office space, lease and non-lease components are accounted for separately. While some lease agreements include residual value guarantees, there are no material guarantees that impact our lease payments.
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ROU assets are reviewed for impairment when events or changes in circumstances indicate that the carrying amounts of such assets may not be recoverable.
See Note 9. Leases.
Financial Instruments: Credit Losses In June 2016, the FASB issued ASU 2016-13, which replaces the incurred loss impairment methodology with an expected credit loss methodology for financial instruments, including financial assets measured at amortized cost, such as trade and joint interest billing receivables, and off-balance sheet credit exposures not accounted for as insurance, such as financial guarantees and other unfunded loan commitments. The amended standard is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. We early adopted this ASU in fourth quarter 2019. This adoption did not have a material impact on our financial statements.
Income Taxes In December 2019, the FASB released Accounting Standards Update No. 2019-12 (ASU 2019-12): Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes, which removes certain exceptions for recognizing deferred taxes for investments, performing intraperiod allocation and calculating income taxes in interim periods. The ASU also adds
Noble Energy, Inc.
Notes to Consolidated Financial Statements
guidance to reduce complexity in certain areas, including recognizing deferred taxes for tax goodwill and allocating taxes to members of a consolidated group. The amended standard is effective for fiscal years beginning after December 15, 2020, with early adoption permitted. We early adopted this ASU in fourth quarter 2019. This adoption did not have a material impact on our financial statements.
Recently Issued Accounting Standards
None that are expected to have a material impact on our financial statements.
Note 2. Additional Financial Statement Information
Statements of Operations Information Other statements of operations information is as follows:
(1)
See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
(2)
See Note 11. Exit Cost - Transportation Commitments.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Balance Sheet Information Other balance sheet information is as follows:
(1)
Amounts relate to divestitures of non-core assets and acreage in Reeves County, Texas. See Note 4. Acquisitions and Divestitures.
(2)
See Note 5. Equity Method Investments.
(3)
Amounts relate to assets and liabilities recorded as a result of ASC 842 adoption. See Note 9. Leases.
(4)
See Note 11. Exit Cost - Transportation Commitments.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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 at certain times is 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.
Supplemental Cash Flow Information Supplemental statements of cash flow information is as follows:
(1)
Interest capitalized totaled $102 million in 2019, $73 million in 2018 and $49 million in 2017.
See Note 9. Leases for supplemental cash flow information related to leases.
Significant Purchasers Non-affiliated purchasers who accounted for 10% or more of our commodity sales were as follows:
(1)
Includes sales to Shell Energy North America and Shell Trading (US) Company (collectively, Shell).
(2)
Includes sales to BP America Production, BP Energy Co and BP Products North America, Inc (collectively, BP).
Both Shell and BP purchased crude oil and condensate domestically from our US onshore operations. No other single purchaser accounted for 10% or more of our commodity sales in 2019. We routinely monitor the credit worthiness of our purchasers. While we maintain credit insurance associated with certain purchasers, we do not carry credit insurance for all purchasers. We believe that the loss of any one significant purchaser would not have a material adverse effect on our financial position or results of operations as there are numerous potential purchasers of our US onshore production and generally production is sold under short-term contracts.
Note 3. Segment Information
We have the following reportable segments: United States (US onshore (Marcellus Shale until July 2017) and Gulf of Mexico (until April 2018)); Eastern Mediterranean (Israel and Cyprus); West Africa (Equatorial Guinea, Cameroon and Gabon); Other International (Suriname (until November 2018), Falkland Islands (until December 2018), Canada, Colombia and New Ventures); and Midstream. The Midstream segment includes the consolidated accounts of Noble Midstream Partners.
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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. The chief operating decision maker analyzes income (loss) before income taxes to assess the performance of Noble Energy's reportable segments as management believes this measure provides useful information in assessing the Company's operating and financial performance across periods.
Expenses related to debt, such as interest and other debt-related costs, 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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(1)
Intersegment eliminations related to income (loss) before income taxes are the result of Midstream expenditures. Certain of these expenditures 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. Other expenditures are presented as production expense. Intercompany revenues and expenses are eliminated upon consolidation.
Note 4. Acquisitions and Divestitures
Year Ended December 31, 2019
Divestiture of Reeves County Assets In February 2019, we sold approximately 13,000 net proved and unproved non-core acres in the Reeves County, Texas area of the Delaware Basin. We received cash consideration of approximately $131 million, recognizing no gain or loss on the sale.
Asset Sale to Noble Midstream Partners In November 2019, we sold substantially all of our remaining midstream interests and assets to Noble Midstream Partners. The value of the transaction, which also included the sale of our incentive distribution rights, totaled approximately $1.6 billion, comprised of $670 million of cash and 38.5 million of newly issued Noble Midstream Partners common units, valued at approximately $930 million. Noble Midstream Partners funded the cash portion of the consideration through $420 million of borrowings on the Noble Midstream Services Revolving Credit Facility (defined below) and approximately $250 million in gross proceeds from a private placement of approximately 12 million common units. At closing, we owned approximately 56.5 million common units, or 63%, of the outstanding units of Noble Midstream Partners. We are subject to a post-closing 180-day lock-up period applicable to the common units received. Sales proceeds were used to repay amounts outstanding under our commercial paper program. As we continue to consolidate Noble Midstream Partners, the activities related to these assets will continue to be reflected within our Midstream segment.
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Year Ended December 31, 2018
Divestiture of Gulf of Mexico Assets We sold substantially all of our Gulf of Mexico assets, including interests in producing properties and undeveloped acreage, for cash consideration of $480 million, along with the assumption, by the purchaser, of abandonment obligations associated with the properties sold. We recorded impairment expense of $168 million during first quarter 2018. We received net proceeds of approximately $384 million and recorded a loss of $24 million upon close.
Divestiture of 7.5% Interest in Tamar Field In first quarter 2018, we sold 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 of $484 million and 38.5 million of Tamar Petroleum shares that had a publicly traded value of $224 million. 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% less 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 the Tamar Petroleum shares in over the counter transactions for pre-tax proceeds of $163 million, net of transaction expenses.
Divestiture of Southwest Royalties In January 2018, we sold our investment in Southwest Royalties, Inc., which we acquired in the 2017 acquisition of Clayton Williams Energy (Clayton Williams Energy Acquisition). We received proceeds of $60 million, resulting in no gain or loss recognition on the sale of these assets.
Divestiture of Greeley Crescent Assets In September 2018, we sold 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 sold certain non-core acreage in the Delaware Basin, receiving proceeds of $63 million, resulting in a pre-tax loss of $16 million.
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 In January 2018, Noble Midstream Partners and its partner formed Black Diamond Gathering LLC (Black Diamond) to acquire Saddle Butte Rockies Midstream, LLC and affiliates, which own a large-scale integrated gathering system located in the DJ Basin. Consideration for the acquisition totaled $681 million, which included $663 million of cash and assumption of $18 million of liabilities. Our partner funded approximately $343 million of the purchase price, which is reflected as a contribution from noncontrolling interest within our consolidated statement of shareholders' equity, and Noble Midstream Partners funded the remainder.
We accounted for the transaction as a business combination using the acquisition method and allocated the total purchase price to assets acquired and liabilities assumed based on the fair values at the acquisition date. Allocated fair values included: $206 million to property, plant and equipment; $340 million to customer-related intangible assets (acquired customer contracts); and $110 million to implied goodwill.
We own a 54.4% interest in Black Diamond and consolidate the entity as a VIE, reflecting the third-party ownership within noncontrolling interests in our consolidated statements of shareholders' equity.
Year Ended December 31, 2017
Clayton Williams Energy Acquisition We completed the Clayton Williams Energy Acquisition on April 24, 2017. Total consideration of $2.5 billion included cash consideration of $637 million and proceeds from the issuance of approximately 56 million shares of Noble Energy common stock with a fair value of approximately $1.9 billion. In exchange, we received all outstanding Clayton Williams Energy shares, including stock options, restricted stock awards and warrants.
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.
The transaction was accounted for as a business combination using the acquisition method. The allocation of the total purchase price of Clayton Williams Energy to the assets acquired and the liabilities assumed was based on the fair values at the
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acquisition date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill. The $1.3 billion of goodwill recorded as part of the transaction was fully impaired in fourth quarter 2018.
The results of operations attributable to Clayton Williams Energy are included in our consolidated statements of operations for 2019 and 2018. Revenues of $99 million and pre-tax net loss of $19 million were generated from Clayton Williams Energy assets during the period April 24, 2017 to December 31, 2017.
Marcellus Shale Upstream Divestiture In 2017, we sold 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 for each annual period through 2020, should certain conditions be met. 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.
We recognized a loss on divestiture of $2.3 billion, or $1.5 billion after-tax, and recorded exit costs for retained financial commitments of $93 million, discounted. The aggregate net book value of the properties sold was approximately $3.4 billion, which included approximately $883 million of undeveloped leasehold cost.
After the property sale, we retained certain firm transportation commitments to flow Marcellus Shale natural gas production. See Note 11. Exit Cost - Transportation Commitments.
Other US Onshore Transactions We conducted the following additional transactions in 2017:
•
sold certain US onshore properties receiving total proceeds of $671 million, 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.
•
acquired Delaware Basin properties, including seven producing wells, increasing our contiguous acreage position in the Reeves County, Texas area. Consideration totaled $301 million, approximately $246 million of which was allocated to undeveloped leasehold cost.
Asset Sale to Noble Midstream Partners In June 2017, we sold interests in certain midstream assets to Noble Midstream Partners for $270 million, which consisted of $245 million in cash and 562,430 Noble Midstream Partners common units. Noble Midstream Partners funded the cash consideration with approximately $138 million of net proceeds from a concurrent private placement of common units, $90 million of borrowings under the Noble Midstream Services Revolving Credit Facility and the remainder from cash on hand.
See Supplemental Oil and Gas Information (Unaudited) for discussion of proved reserves acquired or divested in connection with the above transactions.
Note 5. Equity Method Investments
The carrying values of our equity method investments, including the respective segments, are as follows:
(1)
Atlantic Methanol Production Company, LLC (AMPCO) owns and operates a methanol plant and related facilities in Equatorial Guinea.
(2)
Alba Plant LLC owns and operates a LPG processing plant in Equatorial Guinea.
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(3)
At December 31, 2019, total carrying values were $42 million higher than the underlying net assets of the investments, primarily due to capitalized interest which is amortized into earnings over the useful life of the related assets.
At December 31, 2019, consolidated retained earnings included $73 million related to the undistributed earnings of equity method investments.
Acquisitions and Divestitures
Year Ended December 31, 2019
EMED Pipeline B.V. During third quarter 2019, we acquired a 25% equity interest in Eastern Mediterranean Pipeline B.V. (EMED Pipeline B.V.). In fourth quarter 2019, EMED Pipeline B.V. acquired an approximate 39% equity interest in East Mediterranean Gas Company S.A.E. (EMG), which owns the EMG Pipeline. Upon closing of EMED Pipeline B.V.'s equity acquisition of EMG, we own an effective, indirect interest of approximately 10%, net, in EMG. The EMG Pipeline provides connection from the Israel pipeline network to Egyptian customers and supports delivery of natural gas from our producing fields offshore Israel into Egypt. During 2019, we made capital contributions of $189 million in EMED Pipeline B.V., primarily to fund the EMG equity acquisition.
EPIC Pipelines In first quarter 2019, Noble Midstream Partners exercised and closed options with EPIC Midstream Holdings, LP (EPIC) to acquire a 15% equity interest in EPIC Y-Grade, LP (EPIC Y-Grade), which constructed the EPIC Y-Grade Pipeline, and a 30% equity interest in EPIC Crude Holdings, which is constructing the EPIC Crude Oil Pipeline. The pipelines support transportation of production from the Delaware Basin to Corpus Christi, Texas. Noble Midstream Partners made capital contributions of $169 million and $351 million in EPIC Y-Grade and EPIC Crude Holdings, respectively, in 2019.
Delaware Crossing Joint Venture In February 2019, Noble Midstream Partners formed a 50/50 joint venture with Salt Creek Midstream LLC. The joint venture, Delaware Crossing LLC, is constructing a crude oil pipeline system in the Delaware Basin. Noble Midstream Partners made capital contributions of $70 million for its share of pipeline construction costs in 2019.
Year Ended December 31, 2018
Divestiture of Marcellus Shale CONE Gathering In January 2018, we sold 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.
Year Ended December 31, 2017
Noble Midstream Partners Advantage Joint Venture In April 2017, Noble Midstream Partners acquired a 50% interest in Advantage Pipeline, L.L.C. (Advantage Pipeline) for $67 million. Advantage Pipeline owns a crude oil pipeline system in the southern Delaware Basin from Reeves County, Texas to Crane County, Texas, for which we serve as operator.
Combined Financial Information
Summarized, 100% combined balance sheet information for equity method investments was as follows:
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Summarized, 100% combined statements of operations for equity method investments was as follows:
Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs
Capitalized Exploratory Well Costs We capitalize exploratory well costs until a determination is made that the well has found proved reserves or is deemed noncommercial. These costs are included in Oil and Gas Properties on our consolidated balance sheets. 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 relates to the second quarter 2018 sale of our Gulf of Mexico assets.
(2)
The 2017 amount relates to the approval and sanction of the first phase of development of the Leviathan field.
(3)
In fourth quarter 2019, we recorded exploration expense of $100 million related to the Leviathan Deep prospect, offshore Israel, which was initially drilled in 2012 but did not reach the target interval. Throughout this time, we have evaluated seismic information and nearby discoveries in the region. Upon concluding we would not move forward with the project, we wrote off the entire amount of capitalized exploratory well costs associated with this prospect. The 2017 amount relates to a write-off of costs for a natural gas discovery in the Gulf of Mexico. See Note 10. Impairments.
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, 2019:
Undeveloped Leasehold Costs Changes in undeveloped leasehold costs, which are recorded in oil and gas properties on our consolidated balance sheets, were as follows:
(1)
Transfers primarily relate to development of Delaware Basin assets.
(2)
Amounts primarily relate to Delaware Basin assets sold. See Note 4. Acquisitions and Divestitures.
As of December 31, 2019, undeveloped leasehold costs included $1.9 billion, $100 million, $79 million, and $58 million attributable to the Delaware Basin, Eagle Ford Shale, other US onshore properties, and international properties, respectively. Certain of 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. Other costs pertain to acreage that is being held by production.
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Note 7. Asset Retirement Obligations
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, 2019 Liabilities incurred included $43 million in Israel, primarily related to costs associated with the Leviathan field, and $20 million in US onshore, primarily related to the DJ and Delaware Basins. The majority of liabilities settled relate to abandonment of properties in the DJ Basin where we have engaged in a program to plug and abandon older vertical wells. Costs associated with these abandonment activities will be incurred over several years. Revisions of estimates include a decrease of $72 million in the DJ Basin as a result of improved cycle times and cost reductions for vertical wells.
Year Ended December 31, 2018 Liabilities settled 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, as discussed above.
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.
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Note 8. Long-Term Debt
Our debt consists of the following:
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. As of December 31, 2019, we were in compliance with our debt covenants and no amounts were outstanding under our Revolving Credit Facility.
Commercial Paper Program Our commercial paper program provides for short-term funding needs. The program allows Noble Energy to issue a maximum of $4.0 billion of unsecured commercial paper notes and is supported by Noble Energy’s $4.0 billion Revolving Credit Facility. Our commercial paper notes, which generally have a maturity of less than 30 days, are sold under customary terms in the commercial paper market and are generally issued at a discounted price relative to the principal face value. Such discount prices are dependent on market conditions and ratings assigned to the commercial paper program by credit rating agencies at the time of commercial paper issuance. As of December 31, 2019, we had no outstanding commercial paper borrowings.
Senior Notes Issuance and Completed Tender Offer On October 1, 2019, we issued $500 million of 3.25% senior notes due
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October 15, 2029 and $500 million of 4.20% senior notes due October 15, 2049. Interest on the notes is payable semi-annually beginning April 15, 2020. We may redeem some or all of the notes at any time at the applicable redemption price, plus accrued interest, if any. Proceeds from the issuance of the notes were used to fund the tender offer and redemption of our $1.0 billion 4.15% notes due December 15, 2021. In connection with the tender and redemption, in fourth quarter 2019, we recorded early debt extinguishment cost of approximately $44 million in our consolidated statements of operations.
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. In fourth quarter 2019, the capacity of the facility was increased from $800 million to almost $1.2 billion. As of December 31, 2019, $555 million was available for borrowing under 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. Noble Midstream Services was in compliance with the debt covenants for this facility as of December 31, 2019.
Noble Midstream Services 2019 Term Loan Credit Facility On August 23, 2019, Noble Midstream Services entered into a term loan agreement (Noble Midstream Services 2019 Term Credit Agreement), which provides for a three-year senior unsecured term loan credit facility due August 23, 2022 (2019 Term Loan Credit Facility) with permitted aggregate borrowings of up to $400 million. Proceeds from the 2019 Term Loan Credit Facility were primarily used to repay a portion of the outstanding borrowings under the Noble Midstream Services Revolving Credit Facility. Noble Midstream Services was in compliance with the debt covenants for this facility as of December 31, 2019.
Noble Midstream Services 2018 Term Loan Credit Facility In 2018, Noble Midstream Services entered into a term loan agreement (Noble Midstream Services 2018 Term Credit Agreement), which provides for a three-year senior unsecured term loan credit facility due July 31, 2021 (2018 Term Loan Credit Facility) with permitted aggregate borrowings of up to $500 million. Proceeds from the 2018 Term Loan Credit Facility were primarily used to repay a portion of the outstanding borrowings under the Noble Midstream Services Revolving Credit Facility. Noble Midstream Services was in compliance with the debt covenants for this facility as of December 31, 2019.
Fair Value of Debt The fair value of fixed-rate, public debt is estimated based on the published market prices. As such, we consider the fair value of this debt to be a Level 1 measurement on the fair value hierarchy. Our non-public debt, including our Revolving Credit Facility, commercial paper borrowings, Noble Midstream Services Revolving Credit Facility and Noble Midstream Services term loans are subject to variable interest rates. The fair value is estimated based on significant other observable inputs; thus, we consider the fair value to be a Level 2 measurement on the fair value hierarchy. Fair value information regarding our debt is as follows:
Annual Debt Maturities As of December 31, 2019, annual maturities of outstanding debt, excluding finance lease obligations, were as follows:
Finance Lease Obligations See Note 9. Leases.
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Note 9. Leases
In the normal course of business, we enter into operating and finance lease agreements to support our operations. Operating leases primarily include office space for our corporate and field locations, US onshore compressors and drilling rigs, vessels and helicopters for offshore operations, storage facilities, and other miscellaneous assets. Finance leases include corporate office space, a trunkline in the DJ Basin, a floating production, storage and offloading vessel (FPSO) in West Africa, and vehicles. Our leasing activity is recorded and presented on a gross basis, with the exception of the FPSO which is recorded net to our interest.
Balance Sheet Information ROU assets and lease liabilities are as follows:
(1)
Operating lease ROU assets include compressors of $89 million and office space of $80 million.
(2)
Finance lease ROU assets include office space of $90 million and a trunkline of $28 million, both net of accumulated amortization.
Statement of Operations Information The components of lease cost are as follows:
(1)
Cost classifications vary depending on the leased asset. Costs are primarily included within production expense and general and administrative expense. In addition, in accordance with the successful efforts method of accounting, certain lease costs may be capitalized when incurred and therefore, are included as part of oil and gas properties on our consolidated balance sheets.
(2)
Costs primarily relate to hydraulic fracturing services, well-to-well drilling rig contracts and other miscellaneous lease agreements. Amount excludes costs for leases with an initial term of one month or less.
Cash Flow Information Supplemental cash flow information is as follows:
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(1)
Amounts exclude the impact of adopting ASC 842 on January 1, 2019. See Note 1. Summary of Significant Accounting Policies.
Annual Lease Maturities As of December 31, 2019, maturities of lease liabilities were as follows:
(1)
Includes the current portions of $88 million and $42 million for operating and finance leases, respectively.
Lease Commitments See Note 12. Commitments and Contingencies for lease commitments as of December 31, 2019.
Other Information As of December 31, 2019, other information related to our leases is as follows:
Note 10. Impairments
2019 Impairments In fourth quarter 2019, we determined that the continued depressed commodity price environment and performance of certain of our US onshore basins indicated possible impairment of our proved oil and gas properties in our US onshore business. Following our impairment analysis, we recorded impairment expense of $1.2 billion to our Eagle Ford Shale proved properties, primarily as a result of significant decreases in NGL and natural gas prices, partially offset by lower capital and operating costs. The fair value of approximately $600 million was estimated using the income approach, utilizing a discounted cash flow model. The cash flow model included management's estimates of future production, commodity prices based on published forward commodity price curves, operating and development costs, and a risk-adjusted discount rate. As of December 31, 2019, we had $100 million of undeveloped leasehold costs related to our Eagle Ford Shale unproved properties that were not impaired and for which we believe future development scenarios exist to recover these costs.
2018 Impairments 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.
In fourth quarter 2018, we considered changes to facts and circumstances, particularly the decline in WTI strip pricing, increases in operating and capital costs, as well as our development plans, and concluded that it was more likely than not that the fair value of our Texas reporting unit was less than its carrying amount. As a result, we recognized a goodwill impairment of $1.3 billion.
2017 Impairments In 2017, we recorded impairment expense of $70 million primarily related to our decision not to pursue development of the Troubadour natural gas discovery in the Gulf of Mexico.
Note 11. Exit Cost - Transportation Commitments
In connection with the divestiture of Marcellus Shale upstream assets in 2017, we retained certain long-term financial commitments to pay transportation fees on certain pipelines in the Marcellus Basin. As of December 31, 2019, our undiscounted financial commitment for the remaining obligations under these agreements, which have remaining terms of three to fourteen years, was approximately $1.0 billion, which excludes the impact of ongoing mitigation activities to reduce and offset this cost. See Note 4. Acquisitions and Divestitures and Note 12. Commitments and Contingencies.
Our efforts to mitigate and thereby reduce these obligations primarily include permanent assignment of capacity, negotiation of capacity releases and utilization of capacity through purchase and transport of third-party natural gas. Revenues and expenses associated with mitigation activities are recorded in sales of purchased oil and gas and cost of purchased oil and gas, respectively, in our consolidated statements of operations. In the event we execute a permanent assignment of capacity, we no
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longer have a contractual obligation to the pipeline company and, as such, our gross financial 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 financial 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 a result of our mitigation activities, we reduced and offset our financial obligations by approximately $38 million and $8 million in 2019 and 2018, respectively.
Leach Xpress and Rayne Xpress Permanent Assignment In January 2019, we executed agreements on the Leach Xpress and Rayne Xpress pipelines to permanently assign the remaining capacity to a third-party effective January 1, 2021, extending through the remainder of the contract. The permanent assignment reduced our total financial commitment by approximately $350 million, undiscounted. As a result of the assignment, we recorded firm transportation exit cost at a fair value $92 million, representing the discounted, present value of our remaining obligation to the third-party. We will continue efforts to mitigate the impact of these transportation agreements through 2020.
Exit Costs Reconciliation of accrued exit costs at December 31, 2019 is as follows:
(1)
Amount includes $92 million exit cost for the permanent assigned discussed above, offset by a gain of $4 million.
Revenues and expenses associated with these long-term financial commitments, including mitigation activities discussed above, were as follows:
Note 12. 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. Costs associated with the settlement consist of $5 million in civil penalties which were paid in 2015. Mitigation costs of $4 million and supplemental environmental project costs of $4 million are being expended in accordance with schedules established in the Consent Decree. Costs associated with the injunctive relief, including plugging and abandonment of certain wells and facilities, are also being expended in accordance with schedules established in the Consent Decree.
We have concluded that the penalties, injunctive relief 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 7. Asset Retirement Obligations.
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Colorado Water Quality Control Division Matter In October 2019, we resolved by Compliance Order on Consent (COC) with the Colorado Department of Public Health & Environment allegations of noncompliance with the Colorado Water Quality Act relating 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. The COC required us to pay a penalty of $57 thousand and to contribute $126 thousand toward a State-managed supplemental environmental project. 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. In April 2019, we met with the DOJ and Environmental Protection Agency enforcement personnel to discuss potential settlement of the alleged violations. Given the ongoing status of settlement discussions, we are currently unable to predict the ultimate outcome of this action, but believe the resolution 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 obligations to flow Marcellus Shale natural gas production to various markets. See Note 11. Exit Cost - Transportation Commitments.
Other Gathering and Transportation Obligations As part of our normal course of business, we enter into agreements to transport minimum volumes in the US onshore and Eastern Mediterranean. In the US onshore, primarily in the DJ Basin, certain of these contracts require us to make payments for any shortfalls in delivering or transporting minimum volumes under the commitments. As properties are undergoing development activities, we may experience temporary shortfalls until production volumes increase to meet or exceed the minimum volume commitments and will incur expense related to volume deficiencies and/or unutilized commitments. 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. In the Eastern Mediterranean, regional export contracts contain minimum transportation commitments. For US onshore and Eastern Mediterranean agreements, which have remaining terms of one to 12 years, our total financial commitment is approximately $921 million, undiscounted. The commitments are included in the table below.
Mezzanine Equity Commitment In March 2019, Noble Midstream Partners obtained a $200 million preferred equity commitment. $100 million of the commitment funded immediately and the remaining $100 million is available for funding until March 2020, subject to certain conditions precedent. See Note 1. Summary of Significant Accounting Policies and Note 4. Acquisitions and Divestitures.
Minimum Commitments Minimum commitments as of December 31, 2019 consist of the following:
(1)
Amount includes exit cost obligations resulting from permanent capacity assignments. See Note 11. Exit Cost - Transportation Commitments.
(2)
Amount includes US onshore and Eastern Mediterranean transportation obligations of $921 million, undiscounted, and Noble Midstream Partners obligations of $221 million, undiscounted.
(3)
See Note 9. Leases.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 13. Income Taxes
Components of (loss) income from operations before income taxes are as follows:
Income Tax Provision The income tax (benefit) provision consists of the following:
The 2019 deferred income tax benefit relates to the asset impairment recorded in fourth quarter 2019. See Note 10. Impairments. The 2018 income tax provision is primarily due to current income tax expense for foreign taxes on the gain recognized for the 2018 divestiture of a 7.5% working interest in the Tamar field, partially offset by a deferred income tax benefit. The 2017 income tax benefit is due to the significant deferred tax benefit associated with the revaluation of the US deferred tax liability as a result of the reduction in the federal corporate tax rate to 21%.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Effective Tax Rate (ETR) A reconciliation of the federal statutory tax rate to the ETR is as follows:
There were no material items impacting our 2019 ETR as compared to the federal statutory rate of 21%. Our 2018 ETR included a significant deferred tax benefit, discussed below, recorded as a result of the intent of the US Department of the Treasury (Treasury) and Internal Revenue Service (IRS) to issue additional regulatory guidance associated with the Tax Cuts and Jobs Act (Tax Reform Legislation) and the transition tax. In addition, the 2018 ETR was impacted by low earnings, goodwill impairment with no tax benefit, deferred tax expense of $34 million related to GILTI, discussed below, and a deferred tax benefit of $50 million associated with a write-off of foreign exploration losses. Our 2017 ETR was driven by the deferred tax benefit related to the Tax Reform Legislation, as we revalued the ending deferred tax liability at the reduced future tax rate.
Deferred Tax Assets and Liabilities Deferred tax assets and liabilities resulted from the following:
(1)
At December 31, 2019, $459 million related to domestic tax (state and federal) and $197 million related to foreign tax.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Net deferred tax assets and liabilities were classified in the consolidated balance sheets as follows:
Our estimated pre-tax net operating loss (NOL) carryforwards totaled approximately $2.7 billion at December 31, 2019, of which US federal income tax NOL carryforwards totaled approximately $2.0 billion and foreign NOL carryforwards totaled $691 million.
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 $192 million and $187 million in 2019 and 2018, respectively. The valuation allowance on foreign tax credits totaled $133 million and $132 million in 2019 and 2018, respectively.
Accumulated Undistributed Earnings of Foreign Subsidiaries As of December 31, 2019, 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.
Tax Reform Legislation Updates Since the enactment of Tax Reform Legislation by the US Congress in December 2017, Treasury and the IRS have periodically issued guidance regarding various aspects of the new law.
Global Intangible Low-Taxed Income (GILTI) Tax Reform Legislation introduced a new tax on 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, for 2019 and 2018, we recognized tax expense of $14 million and $34 million, respectively, of GILTI associated with FORI from investments in Equatorial Guinea and Israel.
In June 2019, Treasury and the IRS released new proposed regulations pertaining to GILTI, which include an election that would apply an elective high-tax exception to GILTI when the tax imposed on a tentative net tested income item exceeds an 18.5% corporate tax rate. The applicability of the high-tax exception would be tested at the level of a single qualified business unit (QBU) and would apply to all foreign corporations controlled by the same domestic shareholders. This regulation is applicable to taxable years beginning on or after the date that final regulations are published in the Federal Register. For us, this high tax exception would have the effect of reclassifying all GILTI into another classification of income, thus eliminating the GILTI/NOL offset item described above. We will continue to monitor the development of this proposed regulation.
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. In April 2018, 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. This notice 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 NOLs. 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 payable in installments over eight years beginning in 2018.
Other Provisions Tax Reform Legislation broadened the former Section 163(j) applying a net interest expense limitation equal to 30% of earnings before interest, taxes, depreciation, and amortization (EBITDA) for tax years beginning after December 31, 2017, and before January 1, 2022, after which the net interest expense limitation will be calculated as 30% of earnings before interest and taxes (EBIT). Disallowed interest may be carried forward indefinitely. In November 2018, Treasury and the IRS released proposed regulations pertaining to section 163(j) which state that any amount normally incurred as deductible DD&A, but included in a taxpayer’s cost of goods sold calculation pursuant to section 263A, is not a deduction for DD&A for purposes of determining Adjusted Taxable Income for years beginning prior to January 1, 2022. We have modified our 163(j) limitation calculation to comply and will continue to monitor the development of this proposed regulation.
Israeli Tax Law 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 accumulated revenue generated by each separate project by its cumulative investments as defined within the
Noble Energy, Inc.
Notes to Consolidated Financial Statements
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.
Clayton Williams Energy Acquisition In April 2017, we completed the Clayton Williams Energy Acquisition, which qualified as a tax free merger, and acquired carryover tax basis in Clayton Williams Energy's assets and liabilities. As part of our purchase price allocation 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.
Unrecognized Tax Benefits We file a consolidated income tax return in the US federal jurisdiction, and we file income tax returns in various states and foreign jurisdictions. Our income tax returns are routinely audited by the applicable revenue authorities, and provisions are made in the financial statements for differences between positions taken in tax returns and amounts recognized in the financial statements in anticipation of audit results.
In our major tax jurisdictions, the earliest years remaining open to examination are: US - 2014, Israel - 2015 (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, 2019 and 2018, we had de minimis unrecognized tax benefits.
Note 14. Derivative Instruments and Hedging Activities
Objective and Strategies for Using Derivative Instruments We enter into 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 production. The derivative instruments we use may include variable to fixed price commodity swaps, enhanced swaps, collars and three-way collars, sold calls and sold puts, 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 difference 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.
Sold calls are entered into to receive premiums for establishing a maximum price that would be settled for the notional volumes covered by the respective contracts. Sold puts are entered into to receive premiums for establishing a minimum price that would be settled for the notional volumes covered by basis swap contracts.
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. Additionally, 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.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Unsettled Commodity Derivative Instruments As of December 31, 2019, we had entered into the following crude oil derivative instruments:
(1)
We have entered into crude oil basis swap contracts in order to establish a fixed amount for 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, 2019, we had entered into the following NGL derivative instruments:
As of December 31, 2019, we had entered into the following natural gas derivative instruments:
(1)
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 (CIG) and Waha Hub versus NYMEX Henry Hub (HH). The weighted average differential represents the amount of reduction to NYMEX HH prices for the notional volumes covered by the basis swap contracts.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Fair Value Amounts and Gains and Losses on Derivative Instruments The fair values of derivative instruments on our consolidated balance sheets were as follows (in millions):
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 London Inter-bank Offered Rate (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. Amounts include the impact of netting clauses within our master agreements that allow us to net cash settle asset and liability positions with the same counterparty.
The effect of derivative instruments on our consolidated statements of operations was as follows:
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 15. Additional Shareholders’ Equity Information
Common Stock and Treasury Stock Activity in shares of our common stock and treasury stock was as follows:
(1)
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. In 2019, no shares were repurchased and retired. In 2018, shares were repurchased and retired at an average price of $29.49 per share.
(2)
For the years ended December 31, 2019 and 2018, 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.
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, 2019 included deferred losses of $22 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.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 16. Stock-Based and Other Compensation Plans
We recognized total stock-based compensation expense as follows:
(1)
2019 amount excludes $8 million capitalized to property, plant and equipment.
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 44 million shares of common stock. At December 31, 2019, 39,693,735 shares of our common stock were reserved for issuance, including 28,407,839 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. 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, 2019, 485,062 shares of our common stock were reserved for issuance, including 306,243 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 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 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.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
•
Risk-free rate Represents 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 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:
There were no options exercised in 2019. The total intrinsic value of options exercised was $5 million in 2018 and $4 million in 2017. As of December 31, 2019, $5 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:
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Restricted stock activity was as follows:
The total fair value of restricted stock that vested was $20 million in 2019, $29 million in 2018, and $34 million in 2017. The weighted average award-date fair value per share of restricted stock awarded was $19.54 in 2019, $27.96 in 2018, and $35.45 in 2017.
As of December 31, 2019, $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 1.4 years. Common stock dividends accrue on restricted stock awards and are paid upon vesting. We issue new shares of our common stock when awarding restricted stock.
Cash-Settled Awards Periodically, we issue cash-settled awards (so called phantom units, the nomenclature used in accounting literature) to certain employees in lieu of a portion of restricted stock and stock options. These phantom units represented a hypothetical interest in the Company and, once vested, are settled in cash. Common stock dividends accrue on phantom units and are paid upon vesting.
On February 1, 2016, we issued one million phantom units under the 1992 Plan, a portion of which were subject to the Company's achievement of certain levels of total shareholder return relative to a pre-determined industry peer group. The phantom units vested during 2019 at $31.65 per share which was equal to the grant date fair value. 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 awards vested at 0% as performance was not achieved.
On February 19, 2019, we issued 803,606 phantom units under the 2017 Plan. The units had a grant date fair value of $22.39 and vest ratably over three years. The value at vesting will equal the fair market value of a share of common stock of the Company as of the vesting date.
Phantom unit activity was as follows:
As of December 31, 2019, $11 million of compensation cost related to phantom units remained to be recognized. The cost is expected to be recognized over a weighted-average period of 2.1 years. The total fair value of phantom units that vested in 2019 was $10 million. We accrued a liability of $5 million in 2019 related to the phantom units.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Other Compensation Plans
401(k) Plan We sponsor a 401(k) savings plan. All regular employees are eligible to participate. We make contributions to match employee contributions up to the first 6% of compensation deferred into the plan, and certain profit sharing contributions for employees hired on or after May 1, 2006, based upon their ages and salaries. We made cash contributions of $32 million in 2019, $31 million in 2018 and $31 million in 2017.
Deferred Compensation Plans We have a non-qualified deferred compensation plan for which participant-directed investments are held in a rabbi trust and are available to satisfy the claims of our creditors in the event of bankruptcy or insolvency. Participants may elect to receive distributions in either cash or shares of our common stock. Assets within the rabbi trust primarily consist of mutual fund investments, which include various publicly-traded mutual funds that, in turn, include investments ranging from equities to money market instruments and totaled $27 million at December 31, 2019. The fair values are based on quoted market prices for identical assets.
The liability associated with the deferred compensation plan, which is dependent upon the fair values of the mutual fund investments and common stock held in the rabbi trust, was $29 million and $43 million at December 31, 2019 and 2018, respectively. The rabbi trust included 64,729 and 267,792 shares of our common stock at December 31, 2019 and 2018, respectively, which are accounted for as treasury stock. Distributions of 200,000 shares were made in each of 2019, 2018 and 2017 and were valued at $23 million in 2019, $18 million in 2018 and $21 million in 2017.
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 $9 million in 2019, $2 million in 2018 and $9 million in 2017.
We also maintain other nonqualified deferred compensation plans for the benefit of certain of our employees. Deferred compensation liabilities under these plans were $99 million and $104 million at December 31, 2019 and 2018, respectively.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
In accordance with US GAAP for disclosures about oil and gas producing activities, and Securities and Exchange Commission (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 reserves and reserves engineering is a subjective process of estimating underground accumulations of crude oil, NGLs 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, NGLs and natural gas that are ultimately recovered.
Economic producibility of reserves is dependent on the commodity prices used in the reserves estimate. We based our 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. In accordance with US GAAP, we disclose a standardized measure of discounted future net cash flows related to our proved reserves. In order to standardize the measure, all companies are required to use a 10% discount rate and SEC pricing rules. This prescribed calculation can result in some proved undeveloped reserves (PUDs) having negative present worth, meaning that while these PUDs have positive cash flows, the rate of return is lower than 10%. As of December 31, 2019, we had 4 MMBoe of PUDs, or less than 1% of PUDs, with a negative present worth when discounted at 10%. 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, 2019. 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 reserves are those quantities of oil, NGLs and natural 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 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 sets forth the changes in estimated quantities of proved crude oil reserves:
Non-Price Revisions
•
2017 revisions were primarily attributable to the Delaware Basin due to continued optimization of well development and improved producing well performance.
•
2018 revisions included 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 plans in the Eagle Ford Shale and DJ Basin.
•
2019 revisions included a 41 MMBbls revision (29 MMBbls of PUDs and 12 MMBbls of proved developed) in the Delaware Basin for changes in development plans and performance.
Extensions, Discoveries and Other Additions
•
2017 included additions of 59 MMBbls and 42 MMBbls in the Delaware and DJ Basins, respectively, primarily due to the addition of planned new locations and activity.
•
2018 extensions relate to drilling plans for new wells and primarily include 55 MMBbls and 38 MMBbls in the Delaware and DJ Basins, respectively.
•
2019 additions of 52 MMBbls and 22 MMBbls in the DJ Basin and Delaware Basin, respectively, related to drilling plans for new wells.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Purchase of Minerals in Place The 2017 purchase was attributable to the reserves acquired in the Clayton Williams Energy Acquisition.
Sale of Minerals in Place
•
2017 sales included 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 Note 4. Acquisitions and Divestitures.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Proved NGL Reserves (Unaudited) The following reserves schedule sets forth the changes in estimated quantities of proved NGL reserves:
Non-Price Revisions
•
2017 US revisions included 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 revisions included positive revisions of 35 MMBbls in the DJ Basin primarily due to ASC 606 adoption, offset by negative revisions of 19 MMBbls, primarily in the Eagle Ford Shale due to changes in the previously adopted development plan.
Extensions, Discoveries and Other Additions
•
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 related to the addition of planned new locations and activity, of which 25 MMBbls, 15 MMBbls and 8 MMBbls related to the DJ Basin, Delaware Basin and Eagle Ford Shale, respectively.
•
2019 extensions included additions of 40 MMBbls in the DJ Basin due to drilling plans for new wells.
Sale of Minerals in Place
•
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 Note 4. Acquisitions and Divestitures.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Proved Gas Reserves (Unaudited) The following reserves schedule sets forth the changes in estimated quantities of proved natural gas reserves:
Non-Price Revisions
•
2017 US revisions included 81 Bcf in the Eagle Ford Shale and 31 Bcf in the Delaware Basin, partially offset by negative performance revisions of 49 Bcf in the DJ Basin primarily associated vertical well locations. The Israel revision was associated with the integration of the Tamar 8 well results in our geologic modeling across the reservoir.
•
2018 US revisions included 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.
•
2019 revisions in US onshore included a 41 Bcf negative revision in the Eagle Ford Shale due to performance, partially offset by positive revisions due to performance in the DJ Basin. In Israel, revisions to our Tamar field included positive revisions to developed reserves of 460 Bcf, partially offset by revisions to PUD reserves of 241 Bcf. The Tamar field PUDs were reclassified to developed reserves based on our determination the reserves are accessible with limited further development. Equatorial Guinea revisions relate to the sanction of the Alen Gas Monetization project, which extends the life of the Alba field as certain natural gas volumes are now economic to produce.
Extensions, Discoveries and Other Additions
•
2017 extensions in US reserves included additions of 224 Bcf in the DJ Basin, 53 Bcf in the Delaware Basin and 22 Bcf in
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
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 related to drilling plans for new wells. Increases in the US included 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 related to the Tamar field.
•
2019 extensions in US onshore included additions of 345 Bcf in the DJ Basin due to drilling plans for new wells. Israel additions relate to the Leviathan field and are due to closing of the EMG Pipeline transaction and signing of amendments to our natural gas sales agreements with Egyptian customers, which significantly increase our firm sales commitments in the region. Additions in Equatorial Guinea relate to sanction of the Alen Gas Monetization project in second quarter 2019.
Sale of Minerals in Place
•
2017 sales included 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 Note 4. 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, NGLs 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)
Amount for Israel includes $100 million for the write-off of the Leviathan Deep prospect.
(3)
See Note 10. Impairments.
(4)
Income tax (benefit) expense is based upon respective corporate statutory tax rates. During all periods presented, we incurred exploration expense in currently non-commercial other international locations; therefore, no tax benefit was included in income tax expense for 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, exit costs and certain costs associated with mitigating the effects of our retained Marcellus Shale firm transportation agreements, and overhead and interest costs.
(6)
See Note 4. Acquisitions and Divestitures.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities (Unaudited) Costs incurred include both capitalized costs and costs charged to expense when incurred for oil and gas property acquisition, exploration, and development activities associated with the E&P reporting segments. Costs incurred also include new AROs established in the current year, as well as changes to AROs resulting from changes to cost estimates during the year. Exploration costs presented below include the costs of drilling and equipping successful and unsuccessful exploration wells during the year, geological and geophysical expenses, and the costs of retaining undeveloped leaseholds. Development costs include the costs of drilling and equipping development wells. Costs associated with activities of our Midstream segment and other corporate activities are excluded.
(1)
2019 and 2018 unproved property acquisition costs include US onshore undeveloped leasehold activity during the year.
2017 proved and unproved property acquisition costs primarily include amounts allocated from the Clayton Williams Energy Acquisition. See Note 4. Acquisitions and Divestitures.
(2)
2019 and 2018 exploration costs primarily relate to lease rentals, seismic and staffing expense. 2019 costs exclude $100 million of dry hole expense related to the Leviathan Deep prospect as the associated unproved capital costs were incurred in prior years.
2017 exploration costs primarily include capitalized interest on Gulf of Mexico projects, $7 million dry hole cost related to the Araku-1 exploration well, offshore Suriname, and seismic expense and drilling costs.
(3)
2019 costs to develop our PUDs totaled $1.5 billion. Of this amount, $1.1 billion, $399 million and $48 million related to the conversion of year end 2018 PUDs to proved developed reserves in US onshore, the Leviathan field and the Aseng crude oil well, respectively. In addition, we spent $131 million to convert unproved reserves to proved developed reserves in US onshore and $24 million progressing PUDs that have not yet been converted to proved developed reserves. Development costs also included a decrease of $9 million in ARO, consisting of downward revisions of $57 million in US onshore partially offset by additions of $40 million in Israel related to Leviathan.
2018 costs to develop our PUDs totaled $1.7 billion. Of this amount, $1.0 billion and $646 million were spent in US onshore and Leviathan field, respectively. In addition, we spent $355 million to convert unproved reserves to proved developed reserves in US onshore. Development costs also included $315 million due to upward revisions of ARO costs, $302 million of which was in US onshore.
2017 costs to develop our PUDs totaled $1.7 billion. Of this amount, $1.2 billion and $479 million were spent in US onshore and Leviathan field offshore Israel, respectively. Development costs also included downward revisions in ARO of $13 million. Other International costs include decreases in ARO of $40 million primarily associated with the North Sea abandonment project.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
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)
See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
(2)
At December 31, 2019, includes asset retirement costs of $954 million and assets held for sale of $14 million.
At December 31, 2018, includes asset retirement costs of $966 million and assets held for sale of $133 million.
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)
During 2018, we reduced our ownership in the Tamar field, offshore Israel, to 25% through the sale of a 7.5% interest. Amounts at December 31, 2019 and December 31, 2018 reflect a 25% interest while amounts at December 31, 2017 reflect a 32.5% working interest. See Note 4. Acquisitions and Divestitures. In 2017, we sanctioned the first phase of development of the Leviathan field.
(2)
Other International represents changes in North Sea abandonment costs.
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)
(3)
Excludes 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 7. 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. Future income tax expense for Israel includes the effect of estimated future profit levy taxes and changes to corporate income tax rates.
Prices and Other Assumptions in Discounted Future Net Cash Flows (Unaudited) Future cash inflows are computed by applying a 12-month average commodity price, adjusted for location and quality differentials on a field-by-field basis, to year end quantities of proved reserves, except in those instances where fixed and determinable price changes are provided by contractual arrangements at year end. The discounted future cash flow estimates do not include the effects of derivative instruments. Average prices per region are as follows:
(1)
Natural gas from the Alba field is sold for $0.25 per MMBtu and is adjusted for energy content. In 2019, we recorded natural gas PUDs associated with the Alen Gas Monetization project with future cash inflows from LNG sales estimated based upon pricing linked principally to the ICE Brent index.
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 2019 would reduce the discounted future net cash flows before income taxes by approximately $1.2 billion and $192 million, respectively. We estimate that a 10% per Mcf reduction in the average price of natural gas from the 12-month average price for 2019 would reduce the discounted future net cash flows before income taxes by approximately $1.0 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 $1.2 billion in 2020, $920 million in 2021 and $1.0 billion in 2022.
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 decrease in 2019 and increases in 2018 and 2017 were driven primarily by 12-month average commodity prices.
(2)
The decrease in 2019 relates to primarily to capital efficiencies in our US onshore program and changes in development plans in the Delaware Basin.
(3)
Purchase of minerals in 2017 relates to reserves acquired in the Clayton Williams Energy Acquisition.
(4)
See Note 4. Acquisitions and Divestitures.
(5)
2019 increase in future income tax expense relates primarily to higher future cash flows from the Leviathan and Tamar fields and from cash flows attributable to Alen Gas Monetization, partially offset by a decrease in US income tax expense due to lower future taxable income.
2018 increase in future income tax expense relates primarily to higher 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.
2017 increase in future income tax expense relates primarily to the increase in profit and levy taxes in Israel, partially offset by the decrease in the 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% in the US effective January 1, 2018.
Noble Energy, Inc.
Supplemental Quarterly Financial Information
(Unaudited)
Supplemental quarterly financial information is as follows:
(1) First quarter 2019 included a $92 million firm transportation exit cost. See Note 11. Exit Cost - Transportation Commitments.
Second and third quarters 2019 did not have any unusual or infrequently occurring items.
Fourth quarter 2019 included the following:
•
Proved property impairment charge of $1.2 billion in the Eagle Ford Shale. See Note 10. Impairments; and
•
$100 million dry hole cost. See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
(2) First quarter 2018 included the following:
•
$572 million pre-tax gain on divestitures. See Note 4. Acquisitions and Divestitures;
•
$168 million impairment expense related to Gulf of Mexico asset divestiture. See Note 4. Acquisitions and Divestitures; and
•
$145 million discrete tax benefit, net, related to changes in federal income tax regulations. See Note 13. Income Taxes.
Second quarter 2018 included a $109 million gain on divestiture. See Note 4. Acquisitions and Divestitures.
Third quarter 2018 included a $198 million gain on divestiture See Note 4. Acquisitions and Divestitures.
Fourth quarter 2018 included a $1.3 billion goodwill impairment charge and $38 million asset impairment expense. See Note 10. Impairments.
(3) The sum of the individual quarterly income (loss) may not agree with year-to-date income (loss) as each quarterly computation is based on the income (loss) for the individual quarter as reported with rounding applied.

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

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
We maintain “disclosure controls and procedures,” 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, 2019.
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.

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

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ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS
Item 10. Directors, Executive Officers and Corporate Governance
The information required by this item is incorporated herein by reference to the 2020 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2019.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation
The information required by this item is incorporated herein by reference to the 2020 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2019.

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ITEM 12. SECURITY OWNERSHIP
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required by this item is incorporated herein by reference to the 2020 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2019.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this item is incorporated herein by reference to the 2020 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2019.

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ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Item 14. Principal Accounting Fees and Services
The information required by this item is incorporated herein by reference to the 2020 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2019.
PART IV

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ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibits, Financial Statement Schedules
(a)
The following documents are filed as a part of this report:
(1)
Financial Statements: The consolidated financial statements and related notes, together with the reports of KPMG LLP, Independent Registered Public Accounting Firm, appear in Part II, Item 8, Financial Statements and Supplementary Data, of this Form 10-K.
(2)
Financial Statement Schedules: All schedules for which provision is made in the applicable accounting regulations of the SEC are not required under the related instruction or are inapplicable and, therefore, have been omitted.
(3)
Exhibits: The exhibits listed below on the Index to Exhibits are filed or incorporated by reference as part of this Form 10-K.
INDEX TO EXHIBITS
*
Management contract or compensatory plan or arrangement required to be filed as an exhibit hereto.
Item 16. Form 10-K Summary
None.
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
Mt
Metric ton
Mt/d
Metric tons per day
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 12, 2020
By: /s/ David L. Stover
David L. Stover,
Chairman of the Board and Chief Executive Officer
Date:
February 12, 2020
By: /s/ Kenneth M. Fisher
Kenneth M. Fisher,
Executive Vice President, Chief Financial Officer
Date:
February 12, 2020
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 12, 2020
David L. Stover
(Principal Executive Officer)
/s/ Kenneth M. Fisher
Executive Vice President, Chief Financial Officer
February 12, 2020
Kenneth M. Fisher
(Principal Financial Officer)
/s/ Dustin A. Hatley
Vice President, Chief Accounting Officer and Controller
February 12, 2020
Dustin A. Hatley
(Principal Accounting Officer)
/s/ Jeffrey L. Berenson
Director
February 12, 2020
Jeffrey L. Berenson
/s/ Michael A. Cawley
Director
February 12, 2020
Michael A. Cawley
/s/ James E. Craddock
Director
February 12, 2020
James E. Craddock
/s/ Barbara J. Duganier
Director
February 12, 2020
Barbara J. Duganier
/s/ Thomas J. Edelman
Director
February 12, 2020
Thomas J. Edelman
/s/ Holli C. Ladhani
Director
February 12, 2020
Holli C. Ladhani
/s/ Scott D. Urban
Director
February 12, 2020
Scott D. Urban
/s/ William T. Van Kleef
Director
February 12, 2020
William T. Van Kleef
/s/ Martha B. Wyrsch
Director
February 12, 2020
Martha B. Wyrsch

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Stock Performance Metrics:
Return: -0.0206030085682869
1-Day Return: $1_day_return
3-Day Return: $3_day_return
5-Day Return: $5_day_return
10-Day Return: $10_day_return
20-Day Return: $20_day_return
40-Day Return: $40_day_return
60-Day Return: $60_day_return
80-Day Return: $80_day_return
100-Day Return: $100_day_return
150-Day Return: $150_day_return
252-Day Return: $252_day_return