NOBLE ENERGY, INC. 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: • Executive Overview ; • Operating Outlook ; • Results of Operations - E&P ; • Results of Operations - Midstream ; • Results of Operations - Corporate ; • Liquidity and Capital Resources ; and • Critical Accounting Policies and Estimates . The accompanying consolidated financial statements, including the notes thereto, contain detailed information that should be read in conjunction with our MD&A. 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 theSEC onFebruary 19, 2019 . 39
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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 includesOrganization 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 byOPEC 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 andChina 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 theDJ Basin , while differentials in theDelaware Basin continue to be wide despite additional pipeline capacity from theDelaware Basin toCorpus 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 USHenry Hub natural gas. [[Image Removed: a201910kindexprices.jpg]] 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 theDJ Basin , we entered into a strategic relationship with Saddlehorn, acquiring additional capacity of long-term takeaway at lower cost. In theDelaware Basin , we exercised options to acquire ownership interests inEPIC Y-Grade and EPIC Crude Holdings , and partnered in the formation of theDelaware Crossing joint venture. Through these investments, we gained access toGulf Coast pricing for certain of ourDelaware Basin 40
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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 onDecember 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 offshoreWest 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 offshoreColombia 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 inNoble 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 toNoble Midstream Partners for total consideration of$1.6 billion , including$670 million of cash and 38.5 million of newly issuedNoble 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 atDecember 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: • Execution of a disciplined capital allocation process by: • designing a flexible investment program aligned with the current commodity price environment.
• Leveraging the benefits of our well-positioned and diversified portfolio,
including:
• exercising investment optionality and flexibility afforded by our
assets, certain of which are held by production; and
• continuing portfolio optimization actions to maximize strategic value.
• Enhancing capital efficiencies by:
• 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 offshoreIsrael and monetizing natural gas offshoreWest Africa .
• Maintaining financial strength through:
• focusing operational activities on high-margin, high-return assets; and
• improving overall corporate returns.
• Commitment to people and communities in which we operate by:
• being a safe and reliable operator;
• complying with applicable air quality rules and environmental regulations; and
• 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
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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 excludesNoble 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 offshoreIsrael . 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 inWest Africa , expanding gas deliverability inIsrael and costs for drilling an exploratory well offshoreColombia . 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 andDelaware Basin production offset by reductions in theEagle 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 ofDecember 31, 2019 indicated that the carrying amounts of ourDJ Basin andDelaware Basin properties were not impaired. However, we believe ourDelaware Basin properties, in particular, may be at risk for future impairment. OurDelaware 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 ofDecember 31, 2019 , with all other assumptions unchanged, ourDelaware Basin properties would be at risk for impairment. As ofDecember 31, 2019 , the carrying amount of ourDelaware 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: • increased total average consolidated sales volumes by 3% to 355 MBoe/d, net; • 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
• invested in the EMG Pipeline, through our affiliate,EMED Pipeline B.V. , enabling future flow of natural gas production from offshoreIsrael to customers inEgypt ;
• reduced capital expenditures, excluding acquisitions, by
compared with 2018;
• drilled the Aseng 6P well, offshore
production in fourth quarter 2019; and
• sanctioned the Alen Gas Monetization project, offshore
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Following is a summarized statement of operations for our E&P business:
Year Ended December 31,
(millions) 2019 2018
Oil, NGL and Gas Sales to Third Parties
109 20
Income from Equity Method Investments and Other 69 132
Total Revenues 4,082 4,613
Production Expense 1,354 1,358
Exploration Expense 202 129
Depreciation, Depletion and Amortization 2,058 1,819
Gain on Divestitures, Net (1) - (340 )
Asset Impairments (2) 1,160 169
Goodwill Impairment (2) - 1,281
Cost of Purchased Oil and Gas 107 20
Loss (Gain) on Commodity Derivative Instruments 143 (63 )
(Loss) Income Before Income Taxes (1,093 ) 119
(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:
Average Sales Volumes Average Realized Sales Prices
Crude Oil & Crude Oil &
Condensate NGLs Natural Gas Total Condensate NGLs Natural Gas
(MBbl/d) (MBbl/d) (MMcf/d) (MBoe/d) (Per Bbl) (Per Bbl) (Per Mcf)
Year Ended December 31, 2019
United States 120 68 516 274 $ 55.68 $ 14.32 $ 1.83
Eastern
Mediterranean - - 223 37 - - 5.55
West Africa
(1) 13 - 186 44 61.03 - 0.27
Total
Consolidated
Operations 133 68 925 355 56.21 14.32 2.41
Equity
Investment
(2) 2 4 - 6 58.65 31.77 -
Total 135 72 925 361 $ 56.24 $ 15.40 $ 2.41
Year Ended December 31, 2018
United States
(3) 114 62 472 255 $ 61.12 $ 25.88 $ 2.53
Eastern
Mediterranean - - 237 40 - - 5.47
West Africa
(1) 16 - 213 51 68.53 - 0.27
Total
Consolidated
Operations 130 62 922 346 62.01 25.88 2.76
Equity
Investment
(2) 2 5 - 7 68.99 42.14 -
Total 132 67 922 353 $ 62.10 $ 27.18 $ 2.76 (1) Natural gas from the Alba field is sold under contract for
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
(3) Includes 7 MBoe/d for 2018 related to
quarter 2018. See Item 8. Financial Statements and Supplementary Data -
Note 4. Acquisitions and Divestitures.
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An analysis of revenues from sales of crude oil, NGLs and natural gas is as
follows:
Crude Oil & Natural
(millions) Condensate NGLs Gas Total
Year Ended December 31, 2018 $ 2,945 $ 587 $ 929 $ 4,461
Changes due to
Increase (Decrease) in Sales Volumes 68 48 (15 ) 101
Decrease in Sales Prices (1) (277 ) (281 ) (100 ) (658 )
Year Ended December 31, 2019 $ 2,736 $ 354 $ 814 $ 3,904 (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: • 43% decrease in average realized prices (see factors impacting global
pricing at Executive Overview - Industry Outlook ); and
• lower
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: • 13% decrease in average realized prices (see factors impacting global
pricing at Executive Overview - Industry Outlook );
• lower
and natural field decline;
• lower
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: • higher sales volumes of 91 MMcf/d in the DJ and Delaware Basins due to an
increase in development activity.
Sales and Cost ofPurchased 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 theDJ 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: Year Ended December 31, 2019 2018 Net Income (millions) AMPCO and Affiliates $ 23$ 64 Alba Plant 41 71 Dividends (millions) AMPCO and Affiliates $ 9$ 63 Alba Plant 42 93 Sales Volumes Methanol (Mt/d) 1,091 1,230 Condensate (MBbl/d) 2 2 LPG (MBbl/d) 4 5 Average Realized Prices 44
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Methanol (per Mt)$ 269.73 $ 379.62 Condensate (per Bbl) 58.65 68.99 LPG (per Bbl) 31.77 42.14 Income from equity method investments decreased for 2019 as compared with 2018 due to the following: • decrease in net income from AMPCO and affiliates primarily due to lower
realized methanol prices; and
• decrease in net income from
prices.
Production Expense Components of production expense were as follows: (millions, except unit Total per BOE
United Eastern
rate) (1)(2) Total States (2) Mediterranean West Africa Year Ended December 31, 2019 Lease Operating Expense$ 4.42 $ 573 $ 460 $ 37 $ 76 Production and Ad Valorem Taxes 1.30 169 169 - - Gathering, Transportation and Processing 4.62 599 598 1 - Other Royalty Expense 0.10 13 13 - - Total Production Expense$ 10.44 $ 1,354 $ 1,240 $ 38 $ 76 Total Production Expense per BOE$ 10.44 $ 12.41 $ 2.78$ 4.73 Year Ended December 31, 2018 Lease Operating Expense$ 4.78 $ 603 $ 480 $ 26 $ 97 Production and Ad Valorem Taxes 1.46 184 184 - - Gathering, Transportation and Processing 4.22 533 533 - - Other Royalty Expense 0.30 38 38 - - Total Production Expense$ 10.76 $ 1,358 $ 1,235 $ 26 $ 97 Total Production Expense per BOE$ 10.76 $ 13.28 $ 1.79$ 5.20
(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:
• 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
• decrease in other royalty expense due to lower commodity prices;
• decrease in
efforts across all assets; and
• decrease in production and ad valorem taxes due to production tax refunds;
partially offset by: • 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 andWest 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. 45
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Depreciation, Depletion and Amortization (DD&A) Expense DD&A expense was as follows:
Eastern
(millions, except unit rate) Total
$ 2,058 $ 1,907 $ 67 $ 83 $ 1
Unit Rate per BOE (2)
4.91$ 5.16 $ - Year EndedDecember 31, 2018 DD&A Expense (1)$ 1,819 $ 1,642 $ 60 $ 115 $ 2 Unit Rate per BOE (2)$ 14.42 $ 17.66 $ 4.13$ 6.17 $ -
(1) DD&A expense includes accretion of discount on asset retirement obligations
(AROs) of
(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
quarter 2018; and
• reduced sales volumes in
decline.
The unit rate per BOE for 2019 increased as compared with 2018 due to increased development activity in the higher cost oil-richDelaware 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 theGulf 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: • 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:
• net cash payment of
• net non-cash increase of
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:
• 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
venture, with total equity contributions of approximately
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:
Year Ended December 31,
(millions) 2019 2018
Midstream Services Revenues - Third Party
190 142
(Loss) Income from Equity Method Investments (18 ) 40
Intersegment Revenues 427 351
Total Revenues 693 611
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Operating Costs and Expenses 150 128
Depreciation, Depletion and Amortization 104 87 Gain on Divestiture, Net
- (503 )
Asset Impairments - 37
Cost of Purchased Oil and Gas 181 136
Total Expense (Income) 435 (115 )
Income Before Income Taxes $ 258 $ 726
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:
Year Ended December 31,
(millions) 2019 2018
Sales of Purchased Gas (1) $ 90 $ 113
Cost of Purchased Gas (1) 143 140
Firm Transportation Exit Cost (2) 88 -
(1) Relates to third-party mitigation activities we engage in to utilize a
portion of our
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.
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General and Administrative Expense G&A expense was as follows:
Year Ended December 31,
(millions, except unit rate) 2019 2018
G&A Expense $ 416 $ 385
Unit Rate per BOE (1) $ 3.21 $ 3.05 (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$54 million in 2018. See Item 8. Financial Statements and Supplementary Data - Note 16. Stock-Based and Other Compensation Plans. Loss on Extinguishment of Debt or Facility See Item 8. Financial Statements and Supplementary Data - Note 8. Long-Term Debt. Interest Expense and Capitalized Interest Interest expense and capitalized interest were as follows: Year Ended December 31, (millions, except unit rate) 2019 2018 Interest Expense$ 362 $ 355 Capitalized Interest (102 ) (73 ) Interest Expense, Net$ 260 $ 282 Unit Rate per BOE (1)$ 2.01 $ 2.23
(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.
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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 toNoble Midstream Partners , and other sources of funding. During the year, we did not repurchase any shares ofNoble 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
• increased the Noble Midstream Services Revolving Credit Facility capacity
to almost
• secured a
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.
December 31, 2019 December 31, 2018
Noble Energy Noble Energy
Excluding Excluding
(millions, except Noble Midstream Noble Midstream Noble Midstream Noble Midstream
percentages) Partners Partners Total Partners Partners Total
Total Cash (1) $ 471 $ 13 $ 484 $ 707 $ 12 $ 719
Amounts Available for
Borrowing (2) 4,000 - 4,000 4,000 - 4,000
Total Liquidity $ 4,471 $ 13 $ 4,484 $ 4,707 $ 12 $ 4,719
Total Debt (3) $ 6,089 $ 1,495 $ 7,584 $ 6,115 $ 560 $ 6,675
Noble Energy Share of
Equity $ 8,410 $ 9,426
Ratio of Debt-to-Book
Capital (4) 47 % 41 %
(1) Total cash includes
(2) Excludes amounts available to be borrowed under the
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
Cash and Cash Equivalents We had approximately$484 million in cash and cash equivalents atDecember 31, 2019 ,$383 million of which is attributable to our foreign subsidiaries. Revolving Credit FacilitiesNoble Energy's $4.0 billion unsecured revolving credit facility (Revolving Credit Facility) andNoble 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. AtDecember 31, 2019 , no amounts were outstanding underNoble Energy's Revolving Credit Facility, and no commercial paper borrowings were outstanding, leaving the entire$4.0 billion available for borrowing. AtDecember 31, 2019 ,$595 million was outstanding under theNoble Midstream Services Revolving Credit Facility, leaving$555 million of remaining availability. See Item 8. Financial Statements and Supplementary Data - Note
8. Long-Term Debt.
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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 byNoble Energy's Revolving Credit Facility. The commercial paper program was a significant source of liquidity during 2019. All amounts outstanding were repaid prior toDecember 31, 2019 . See Item 8. Financial Statements and Supplementary Data - Note 8. Long-Term Debt. Senior Note Issuance and Redemption InOctober 2019 , we issued$500 million of 3.25% senior notes dueOctober 15, 2029 and$500 million of 4.20% senior notes dueOctober 15, 2049 . Proceeds from the issuance were used to fund the early tender offer and redemption of our$1.0 billion 4.15% notes dueDecember 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 InAugust 2019 ,Noble Midstream Services entered into a term loan agreement, which provides for a three-year senior unsecured term loan credit facility, dueAugust 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 theNoble 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 InJuly 2018 ,Noble Midstream Services entered into a term loan agreement, which provides for a three-year senior unsecured term loan credit facility, dueJuly 31, 2021 (2018 Noble Midstream Services Term Loan Credit Facility), that permits aggregate borrowings of up to$500 million . As ofDecember 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 InMarch 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 toNoble 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$250 million was funded by a private placement ofNoble Midstream Partners common units. See Note 4. Acquisitions and Divestitures. Dividends We funded a 9% dividend increase in 2019. See Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases ofEquity Securities . Cash Flows The following table summarizes our net cash flows from operating, investing and financing activities: Year Ended December 31, (millions) 2019 2018 Total Cash Provided By (Used in) Operating Activities$ 1,998 $ 2,336 Investing Activities (3,138 ) (1,931 ) Financing Activities 905 (399 )
Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash
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 50
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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 ofNoble Midstream Partners common units, which was used to fundNoble 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: Year Ended December 31, (millions) 2019
2018
Unproved Property Acquisition (1) $ 37$ 41 Proved Property Acquisition 4 - Exploration 38 25 Development 2,074 2,658 Midstream 230 727 Corporate 66 60 Total$ 2,449 $ 3,511 Additions to Equity Method Investments(2) EMED Pipeline B.V.$ 189 $ - EPIC Y-Grade 174 - EPIC Crude Holdings 358 - Delaware Crossing 72 - Other 6 - Total Additions to Equity Method Investments$ 799 $
-
Increase in Finance Lease Obligations $ 7$ 14 (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 andDelaware 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 ofDecember 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. 51
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Contractual Obligations The following table summarizes certain contractual obligations as ofDecember 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. Note Reference 2021 and 2023 and 2025 and (millions) (1) 2020 2022 2024 beyond Total Note Long-Term Debt (2) 8 $ -$ 900 $ 1,345 $ 5,134 $ 7,379 Long-Term Debt Interest Payments and Revolving Credit Note Facility Commitment Fee (3) 8 342 661
580 4,458 6,041
Note
Operating Lease Obligations (4) 9 100 101 41 37 279
Note
Finance Lease Obligations (4) 9 52 65 44 86 247
Marcellus Shale Firm Note
Transportation Obligations (5) 11 143 187 175 675 1,180
Purchase and Service Note
Obligations (6) 12 135 42 32 72 281
Gathering, Transportation and Note
Processing Obligations 12 174 332 302 334 1,142
Other Liabilities (7)
Asset Retirement Obligations Note
(8) 7 85 170 34 525 814
Commodity Derivative Note
Instruments (9) 14 36 1 - - 37
Total Contractual Obligations $ 1,067 $ 2,459 $
2,553
(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
(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 topurchase 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 andSupplementary 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 .
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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 theSEC and theFinancial 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 53
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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 ofDecember 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 ourEagle 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 retainedMarcellus 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. 54
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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 ofDecember 31, 2019 , we have a significant remaining financial commitment associated withMarcellus 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. 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. AtDecember 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 theDecember 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 Item 8. Financial Statements and Supplementary Data - Note 14. Derivative Instruments and Hedging Activities. Interest Rate Risk Changes in interest rates affect the amount of interest we pay on certain of our borrowings. Borrowings under our commercial paper program, the Revolving Credit Facility, Noble Midstream Services Revolving Credit Facility andNoble Midstream Services Term Loan Credit Facilities, which as ofDecember 31, 2019 total$1.5 billion and have a weighted average interest rate of 2.92%, are subject to variable interest rates which expose us to the risk of earnings or cash flow loss due to potential increases in market interest rates. A change in the interest rate applicable to amounts, if any, related to these debt agreements would have has a de minimis impact on our consolidated net loss. See Item 8. Financial Statements and Supplementary Data - Note 8. Long-Term Debt. 55
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While we currently have no interest rate derivative instruments as ofDecember 31, 2019 , we may invest in such instruments in the future in order to mitigate interest rate risk. LIBOR Transition London Inter-bank Offered Rate (LIBOR) is a commonly used indicative measure of the average interest rate at which major global banks could borrow from one another. Certain of our commercial agreements use LIBOR as a "benchmark" or "reference rate" for various commercial terms. It is currently expected that the LIBOR benchmark will be discontinued after 2021. We are currently reviewing our contracts that extend past 2021 to determine their exposure to LIBOR, some of which contain an existing LIBOR alternative. Where there is not an alternative, we expect to replace the LIBOR benchmark with an alternative reference rate such as the Secured Overnight Financing Rate. We do not expect the transition to an alternative rate to have a significant impact on our business, operations or liquidity. Foreign Currency Risk The US dollar is considered the functional currency for each of our international operations. Substantially all of our international crude oil, NGL and natural gas production is sold pursuant to US dollar denominated contracts. Transactions, such as operating costs and administrative expenses that are paid in a foreign currency, are remeasured into US dollars and recorded in the financial statements at prevailing currency exchange rates. Certain monetary assets and liabilities, for example certain local working capital items, are denominated in a foreign currency and remeasured into US dollars. A reduction in the value of the US dollar against currencies of other countries in which we have material operations could result in the use of additional cash to settle operating, administrative and tax liabilities. Net transaction gains and losses were de minimis for 2019, 2018 and 2017. We currently have no foreign currency derivative instruments outstanding. However, we may enter into foreign currency derivative instruments in the future if we determine that it is necessary to invest in such instruments in order to mitigate our foreign currency exchange risk. 56
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