EOG RESOURCES, INC. Overview
EOG Resources, Inc. , together with its subsidiaries (collectively, EOG), is one of the largest independent (non-integrated) crude oil and natural gas companies inthe United States with proved reserves inthe United States ,Trinidad andChina . EOG operates under a consistent business and operational strategy that focuses predominantly on maximizing the rate of return on investment of capital by controlling operating and capital costs and maximizing reserve recoveries. Pursuant to this strategy, each prospective drilling location is evaluated by its estimated rate of return. This strategy is intended to enhance the generation of cash flow and earnings from each unit of production on a cost-effective basis, allowing EOG to deliver long-term growth in shareholder value and maintain a strong balance sheet. EOG implements its strategy primarily by emphasizing the drilling of internally generated prospects in order to find and develop low-cost reserves. Maintaining the lowest possible operating cost structure, coupled with efficient and safe operations and robust environmental stewardship practices and performance, is integral in the implementation of EOG's strategy. EOG realized a net loss of$605 million during 2020 as compared to net income of$2,735 million for 2019. AtDecember 31, 2020 , EOG's total estimated net proved reserves were 3,220 million barrels of oil equivalent (MMBoe), a decrease of 109 MMBoe fromDecember 31, 2019 . During 2020, net proved crude oil and condensate and natural gas liquids (NGLs) reserves decreased by 108 million barrels (MMBbl), and net proved natural gas reserves decreased by 9 billion cubic feet or 1 MMBoe, in each case fromDecember 31, 2019 .
Recent Developments
Commodity Prices. The COVID-19 pandemic and the measures being taken to address and limit the spread of the virus have adversely affected the economies and financial markets of the world, resulting in an economic downturn that has negatively impacted, and may continue to negatively impact, global demand and prices for crude oil and condensate, NGLs and natural gas. See ITEM 1A, Risk Factors for further discussion. In earlyMarch 2020 , due to the failure of the members of theOrganization of the Petroleum Exporting Countries andRussia (OPEC+) to reach an agreement on individual crude oil production limits,Saudi Arabia unilaterally reduced the sales price of its crude oil and announced that it would increase its crude oil production. The combination of these actions, and the effects of the COVID-19 pandemic on crude oil demand, resulted in significantly lower commodity prices in March andApril 2020 . InApril 2020 , the members of OPEC+ reached an agreement to cut crude oil production beginning inMay 2020 and extending throughApril 2022 with the quantity of the production cuts decreasing over time. Subsequent indications of conformity with these agreed-upon production cuts by OPEC+, combined with the evolving impacts of COVID-19 on crude oil demand, have resulted in gradually-improving market conditions. In the second half of 2020, crude oil prices increased, but remain significantly below average prices in 2019, as a result of the continuing rebalancing of crude oil supply resulting from the actions of OPEC+ and the continuing effect of the COVID-19 pandemic on global demand. In addition, NGL and natural gas prices have recovered to pre-pandemic levels. In response to the commodity price environment in 2020, EOG reduced activity across its operating areas and decreased its total capital expenditures. EOG also elected to reduce crude oil production, by delaying initial production from new wells and shutting-in or otherwise curtailing existing production. In early 2021, the members of OPEC+ met and agreed to taper off certain of their production curtailments (agreed to inApril 2020 ) throughMarch 2021 . Subsequent to the meeting,Saudi Arabia announced that it would unilaterally cut its production by an additional one million barrels per day inFebruary 2021 andMarch 2021 . These announcements have had a positive impact on crude oil prices. As a result of the many uncertainties associated with (i) the world economic environment, (ii) the COVID-19 pandemic and its continuing effect on the economies and financial markets of the world and (iii) any future actions by the members of OPEC+, and the effect of these uncertainties on worldwide supplies of, and demand for, crude oil and condensate, NGLs and natural gas, EOG is unable to predict what changes may occur in crude oil and condensate, NGLs and natural gas prices in the future. However, prices for crude oil and condensate, NGLs and natural gas have historically been volatile, and this volatility is expected to continue. For related discussion, see ITEM 1A, Risk Factors.
EOG will continue to monitor future market conditions and adjust its capital allocation strategy and production outlook accordingly in order to maximize shareholder value while maintaining its strong financial position.
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2020 Election. In November 2020 , Joseph R. Biden Jr . was elected President of
the United States . On January 27, 2021 , President Biden issued Executive Order
14008 entitled "Tackling the Climate Crisis at Home and Abroad," directing the
Secretary of the Interior, to the extent consistent with applicable law and in
consultation with other agencies and stakeholders, to (i) pause approval of new
oil and natural gas leases on federal lands or in offshore waters pending
completion of a comprehensive review and reconsideration of federal oil and gas
permitting and leasing practices and (ii) consider whether to adjust royalties
associated with oil and gas resources extracted from federal lands and offshore
waters to account for corresponding climate costs. In addition, new or revised
rules, regulations and policies may be issued, and new legislation may be
proposed, during the current administration that could impact the oil and gas
exploration and production industry. Such rules, regulations, policies and
legislation may affect, among other things, (i) permitting for oil and gas
drilling on federal lands, (ii) the leasing of federal lands for oil and gas
development, (iii) the regulation of greenhouse gas emissions and/or other
climate change-related matters associated with oil and gas operations, (iv) the
use of hydraulic fracturing on federal lands, (v) the calculation of royalty
payments in respect of oil and gas production from federal lands and (vi) U.S.
federal income tax laws applicable to oil and gas exploration and production
companies. See "Regulation" in ITEM 1, Business and ITEM 1A, Risk Factors for
further discussion.
EOG will continue to monitor and assess any actions that could impact the oil
and gas industry, to determine the impact on its business and operations, and
take appropriate actions where necessary.
Operations
Several important developments have occurred since
United States . EOG's efforts to identify plays with large reserve potential have proven to be successful. EOG continues to drill numerous wells in large acreage plays, which in the aggregate have contributed substantially to, and are expected to continue to contribute substantially to, EOG's crude oil and condensate, NGLs and natural gas production. EOG has placed an emphasis on applying its horizontal drilling and completion expertise to unconventional crude oil and liquids-rich reservoirs. During 2020, EOG continued to focus on increasing drilling, completion and operating efficiencies gained in prior years. Such efficiencies, combined with new innovation and decreased service costs, resulted in lower operating, drilling and completion costs in 2020. In addition, EOG continued to evaluate certain potential crude oil and condensate, NGLs and natural gas exploration and development prospects and to look for opportunities to add drilling inventory through leasehold acquisitions, farm-ins, exchanges or tactical acquisitions. On a volumetric basis, as calculated using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas, crude oil and condensate and NGLs production accounted for approximately 76% and 77% ofUnited States production during 2020 and 2019, respectively. During 2020, drilling and completion activities occurred primarily in theDelaware Basin play,Eagle Ford play andRocky Mountain area. EOG's major producing areas inthe United States are inNew Mexico andTexas . In the second quarter of 2020, EOG delayed initial production from most newly-completed wells and shut in some existing production. During the third quarter of 2020, EOG resumed the process of initiating production from completed wells, and the legacy wells that were shut-in were largely brought back on-line. See ITEM 1, Business - Exploration and Production for further discussion.Trinidad . InTrinidad , EOG continues to deliver natural gas under existing supply contracts. Several fields in the South East Coast Consortium Block, Modified U(a) Block, Block 4(a), Modified U(b) Block, the Banyan Field and the Sercan Area have been developed and are producing natural gas, which is sold to theNational Gas Company ofTrinidad and Tobago Limited and its subsidiary, and crude oil and condensate which is sold toHeritage Petroleum Company Limited .
In 2020, EOG drilled three net wells and completed two net wells in
Other International. In theSichuan Basin ,Sichuan Province ,China , EOG continues to work with its partner, PetroChina, under the Production Sharing Contract and other related agreements, to ensure uninterrupted production. All natural gas produced from the Baijaochang Field is sold under a long-term contract to PetroChina. In 2020, EOG entered into two agreements related to exploration and production rights in the Sultanate ofOman (Oman ). One agreement resulted in EOG acquiring exploration and production rights to Block 36 withinOman . The second agreement was a farm-in agreement allowing EOG to share in exploration and production rights within Block 49. Pursuant to that agreement, EOG participated in the drilling of one gross exploratory well which was in progress as ofDecember 31, 2020 .
In
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EOG continues to evaluate other select crude oil and natural gas opportunities
outside the United States , primarily by pursuing exploitation opportunities in
countries where indigenous crude oil and natural gas reserves have been
identified.
Capital Structure
One of management's key strategies is to maintain a strong balance sheet with a consistently below average debt-to-total capitalization ratio as compared to those in EOG's peer group. EOG's debt-to-total capitalization ratio was 22% atDecember 31, 2020 and 19% atDecember 31, 2019 . As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.
On
OnApril 14, 2020 , EOG closed on its offering of$750 million aggregate principal amount of its 4.375% Senior Notes due 2030 and$750 million aggregate principal amount of its 4.950% Senior Notes due 2050 (together, the Notes). EOG received net proceeds of$1.48 billion from the issuance of the Notes, which were used to repay the 4.40% Senior Notes due 2020 when they matured onJune 1, 2020 (see below), and for general corporate purposes, including the funding of capital expenditures.
On
On
During 2020, EOG funded$4.0 billion ($386 million of which was non-cash) in exploration and development and other property, plant and equipment expenditures (excluding asset retirement obligations), repaid$1.0 billion aggregate principal amount of long-term debt and paid$821 million in dividends to common stockholders, primarily by utilizing net cash provided from its operating activities, net proceeds of$1.48 billion from the issuance of the Notes and net proceeds of$192 million from the sale of assets. Total anticipated 2021 capital expenditures are estimated to range from approximately$3.7 billion to$4.1 billion , excluding acquisitions and non-cash transactions. The majority of 2021 expenditures will be focused onUnited States crude oil drilling activities. EOG has significant flexibility with respect to financing alternatives, including borrowings under its commercial paper program, bank borrowings, borrowings under its senior unsecured revolving credit facility, joint development agreements and similar agreements and equity and debt offerings.
Management continues to believe EOG has one of the strongest prospect inventories in EOG's history. When it fits EOG's strategy, EOG will make acquisitions that bolster existing drilling programs or offer incremental exploration and/or production opportunities.
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--------------------------------------------------------------------------------Results of Operations
The following review of operations for each of the three years in the period endedDecember 31, 2020 , should be read in conjunction with the consolidated financial statements of EOG and notes thereto beginning on page F-1.
Operating Revenues and Other
During 2020, operating revenues decreased$6,348 million , or 37%, to$11,032 million from$17,380 million in 2019. Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, NGLs and natural gas, decreased$4,291 , or 37%, to$7,290 million in 2020 from$11,581 million in 2019. Revenues from the sales of crude oil and condensate and NGLs in 2020 were approximately 89% of total wellhead revenues compared to 90% in 2019. During 2020, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of$1,145 million compared to net gains of$180 million in 2019. Gathering, processing and marketing revenues decreased$2,777 million during 2020, to$2,583 million from$5,360 million in 2019. Net losses on asset dispositions of$47 million in 2020 were primarily due to the sales of proved properties and non-cash property exchanges of unproved leasehold inTexas andNew Mexico and the disposition of theMarcellus Shale assets compared to net gains on asset dispositions of$124 million in 2019. 36 -------------------------------------------------------------------------------- Wellhead volume and price statistics for the years endedDecember 31, 2020 , 2019 and 2018 were as follows: Year Ended December 31 2020 2019 2018 Crude Oil and Condensate Volumes (MBbld) (1) United States 408.1 455.5 394.8 Trinidad 1.0 0.6 0.8 Other International (2) 0.1 0.1 4.3 Total 409.2 456.2 399.9 Average Crude Oil and Condensate Prices ($/Bbl) (3) United States$ 38.65 $ 57.74 $ 65.16 Trinidad 30.20 47.16 57.26 Other International (2) 43.08 57.40 71.45 Composite 38.63 57.72 65.21 Natural Gas Liquids Volumes (MBbld) (1) United States 136.0 134.1 116.1 Other International (2) - - - Total 136.0 134.1 116.1 Average Natural Gas Liquids Prices ($/Bbl) (3) United States$ 13.41 $ 16.03 $ 26.60 Other International (2) - - - Composite 13.41 16.03 26.60 Natural Gas Volumes (MMcfd) (1) United States 1,040 1,069 923 Trinidad 180 260 266 Other International (2) 32 37 30 Total 1,252 1,366 1,219 Average Natural Gas Prices ($/Mcf) (3) United States$ 1.61 $ 2.22 $ 2.88 Trinidad 2.57 2.72 2.94 Other International (2) 4.66 4.44 4.08 Composite 1.83 2.38 2.92 Crude Oil Equivalent Volumes (MBoed) (4) United States 717.5 767.8 664.7 Trinidad 30.9 44.0 45.1 Other International (2) 5.4 6.2 9.4 Total 753.8 818.0 719.2 Total MMBoe (4) 275.9 298.6 262.5 (1) Thousand barrels per day or million cubic feet per day, as applicable. (2)Other International includes EOG'sUnited Kingdom ,China andCanada operations. TheUnited Kingdom operations were sold in the fourth quarter of 2018.(3)Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments (see Note 12 to Consolidated Financial Statements). (4)Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand. 37 -------------------------------------------------------------------------------- 2020 compared to 2019. Wellhead crude oil and condensate revenues in 2020 decreased$3,827 million , or 40%, to$5,786 million from$9,613 million in 2019, due primarily to a lower composite average wellhead crude oil and condensate price ($2,860 million ) and a decrease in production ($967 million ). EOG's composite wellhead crude oil and condensate price for 2020 decreased 33% to$38.63 per barrel compared to$57.72 per barrel in 2019. Wellhead crude oil and condensate production in 2020 decreased 10% to 409 MBbld as compared to 456 MBbld in 2019. The decreased production was primarily in the Eagle Ford and theRocky Mountain area, partially offset by increased production in thePermian Basin . NGLs revenues in 2020 decreased$116 million , or 15%, to$668 million from$784 million in 2019 primarily due to a lower composite average wellhead NGLs price ($130 million ), partially offset by an increase in production ($13 million ). EOG's composite average wellhead NGLs price decreased 16% to$13.41 per barrel in 2020 compared to$16.03 per barrel in 2019. NGL production in 2020 increased 1% to 136 MBbld as compared to 134 MBbld in 2019. The increased production was primarily in thePermian Basin , partially offset by decreased production in the Eagle Ford. Wellhead natural gas revenues in 2020 decreased$347 million , or 29%, to$837 million from$1,184 million in 2019, primarily due to a lower composite wellhead natural gas price ($251 million ) and a decrease in natural gas deliveries ($96 million ). EOG's composite average wellhead natural gas price decreased 23% to$1.83 per Mcf in 2020 compared to$2.38 per Mcf in 2019. Natural gas deliveries in 2020 decreased 8% to 1,252 MMcfd as compared to 1,366 MMcfd in 2019. The decrease in production was primarily due to lower natural gas volumes inTrinidad , theMarcellus Shale and theRocky Mountain area, partially offset by increased production of associated natural gas from thePermian Basin . During 2020, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of$1,145 million , which included net cash received for settlements of crude oil, NGL and natural gas financial derivative contracts of$1,071 million . During 2019, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of$180 million , which included net cash received for settlements of crude oil and natural gas financial derivative contracts of$231 million . Gathering, processing and marketing revenues are revenues generated from sales of third-party crude oil, NGLs and natural gas, as well as fees associated with gathering third-party natural gas and revenues from sales of EOG-owned sand. Purchases and sales of third-party crude oil and natural gas may be utilized in order to balance firm transportation capacity with production in certain areas and to utilize excess capacity at EOG-owned facilities. EOG sells sand in order to balance the timing of firm purchase agreements with completion operations and to utilize excess capacity at EOG-owned facilities. Marketing costs represent the costs to purchase third-party crude oil, natural gas and sand and the associated transportation costs, as well as costs associated with EOG-owned sand sold to third parties. Gathering, processing and marketing revenues less marketing costs in 2020 decreased$124 million compared to 2019, primarily due to lower margins on crude oil and condensate marketing activities. The margin on crude oil marketing activities in 2020 was negatively impacted by the price decline for crude oil in inventory awaiting delivery to customers and EOG's decision early in the second quarter of 2020 to reduce commodity price volatility by selling May andJune 2020 deliveries under fixed price arrangements. 2019 compared to 2018. Wellhead crude oil and condensate revenues in 2019 increased$96 million , or 1%, to$9,613 million from$9,517 million in 2018, due primarily to an increase in production ($1,351 million ); partially offset by a lower composite average wellhead crude oil and condensate price ($1,255 million ). EOG's composite wellhead crude oil and condensate price for 2019 decreased 11% to$57.72 per barrel compared to$65.21 per barrel in 2018. Wellhead crude oil and condensate production in 2019 increased 14% to 456 MBbld as compared to 400 MBbld in 2018. The increased production was primarily in thePermian Basin and the Eagle Ford. NGLs revenues in 2019 decreased$343 million , or 30%, to$784 million from$1,127 million in 2018 primarily due to a lower composite average wellhead NGLs price ($518 million ), partially offset by an increase in production ($175 million ). EOG's composite average wellhead NGLs price decreased 40% to$16.03 per barrel in 2019 compared to$26.60 per barrel in 2018. NGL production in 2019 increased 16% to 134 MBbld as compared to 116 MBbld in 2018. The increased production was primarily in thePermian Basin . Wellhead natural gas revenues in 2019 decreased$118 million , or 9%, to$1,184 million from$1,302 million in 2018, primarily due to a lower composite wellhead natural gas price ($280 million ), partially offset by an increase in natural gas deliveries ($162 million ). EOG's composite average wellhead natural gas price decreased 18% to$2.38 per Mcf in 2019 compared to$2.92 per Mcf in 2018. Natural gas deliveries in 2019 increased 12% to 1,366 MMcfd as compared to 1,219 MMcfd in 2018. The increase in production was primarily due to higher deliveries inthe United States resulting from increased production of associated natural gas from thePermian Basin and higher natural gas volumes inSouth Texas . 38 -------------------------------------------------------------------------------- During 2019, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of$180 million , which included net cash received for settlements of crude oil and natural gas financial derivative contracts of$231 million . During 2018, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of$166 million , which included net cash paid for settlements of crude oil and natural gas financial derivative contracts of$259 million . Gathering, processing and marketing revenues less marketing costs in 2019 decreased$18 million compared to 2018, primarily due to lower margins on crude oil and condensate marketing activities, partially offset by higher margins on natural gas marketing activities.
Operating and Other Expenses
2020 compared to 2019. During 2020, operating expenses of$11,576 million were$2,105 million lower than the$13,681 million incurred during 2019. The following table presents the costs per barrel of oil equivalent (Boe) for the years endedDecember 31, 2020 and 2019: 2020 2019 Lease and Well$ 3.85 $ 4.58 Transportation Costs 2.66 2.54 Depreciation, Depletion and Amortization (DD&A) - Oil and Gas Properties 11.85 12.25 Other Property, Plant and Equipment 0.47 0.31 General and Administrative (G&A) 1.75 1.64 Net Interest Expense 0.74 0.62 Total (1)$ 21.32 $ 21.94
(1)Total excludes gathering and processing costs, exploration costs, dry hole costs, impairments, marketing costs and taxes other than income.
The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A, G &A and net interest expense for 2020 compared to 2019 are set forth below. See "Operating Revenues and Other" above for a discussion of production volumes. Lease and well expenses include expenses for EOG-operated properties, as well as expenses billed to EOG from other operators where EOG is not the operator of a property. Lease and well expenses can be divided into the following categories: costs to operate and maintain crude oil and natural gas wells, the cost of workovers and lease and well administrative expenses. Operating and maintenance costs include, among other things, pumping services, salt water disposal, equipment repair and maintenance, compression expense, lease upkeep and fuel and power. Workovers are operations to restore or maintain production from existing wells. Each of these categories of costs individually fluctuates from time to time as EOG attempts to maintain and increase production while maintaining efficient, safe and environmentally responsible operations. EOG continues to increase its operating activities by drilling new wells in existing and new areas. Operating and maintenance costs within these existing and new areas, as well as the costs of services charged to EOG by vendors, fluctuate over time. Lease and well expenses of$1,063 million in 2020 decreased$304 million from$1,367 million in 2019 primarily due to lower operating and maintenance costs inthe United States ($157 million ) and inCanada ($25 million ), lower workovers expenditures inthe United States ($103 million ) and lower lease and well administrative expenses inthe United States ($12 million ). Lease and well expenses decreased inthe United States primarily due to decreased operating activities resulting from decreased production, efficiency improvements and service cost reductions. Transportation costs represent costs associated with the delivery of hydrocarbon products from the lease or an aggregation point on EOG's gathering system to a downstream point of sale. Transportation costs include transportation fees, the cost of compression (the cost of compressing natural gas to meet pipeline pressure requirements), the cost of dehydration (the cost associated with removing water from natural gas to meet pipeline requirements), gathering fees and fuel costs. 39 -------------------------------------------------------------------------------- Transportation costs of$735 million in 2020 decreased$23 million from$758 million in 2019 primarily due to decreased transportation costs in theFort Worth Basin Barnett Shale ($27 million ), theRocky Mountain area ($24 million ) and the Eagle Ford ($20 million ), partially offset by increased transportation costs in thePermian Basin ($56 million ). DD&A of the cost of proved oil and gas properties is calculated using the unit-of-production method. EOG's DD&A rate and expense are the composite of numerous individual DD&A group calculations. There are several factors that can impact EOG's composite DD&A rate and expense, such as field production profiles, drilling or acquisition of new wells, disposition of existing wells and reserve revisions (upward or downward) primarily related to well performance, economic factors and impairments. Changes to these factors may cause EOG's composite DD&A rate and expense to fluctuate from period to period. DD&A of the cost of other property, plant and equipment is generally calculated using the straight-line depreciation method over the useful lives of the assets. DD&A expenses in 2020 decreased$350 million to$3,400 million from$3,750 million in 2019. DD&A expenses associated with oil and gas properties in 2020 were$390 million lower than in 2019 primarily due to a decrease in production inthe United States ($222 million ) andTrinidad ($22 million ) and lower unit rates inthe United States ($150 million ). Unit rates inthe United States decreased primarily due to upward reserve revisions and reserves added at lower costs as a result of increased efficiencies. DD&A expenses associated with other property, plant and equipment in 2020 were$40 million higher than in 2019 primarily due to an increase in expense related to gathering and storage assets and equipment. G&A expenses of$484 million in 2020 decreased$5 million from$489 million in 2019 primarily due to decreased employee-related expenses ($43 million ) and professional and other services ($7 million ), partially offset by idle equipment and termination fees ($46 million ). Net interest expense of$205 million in 2020 was$20 million higher than 2019 primarily due to the issuance of the Notes inApril 2020 ($51 million ) and lower capitalized interest ($7 million ), partially offset by repayment inJune 2019 of the$900 million aggregate principal amount of 5.625% Senior Notes due 2019 ($21 million ), repayment inJune 2020 of the$500 million aggregate principal amount of 4.40% Senior Notes due 2020 ($13 million ) and repayment inApril 2020 of the$500 million aggregate principal amount of 2.45% Senior Notes due 2020 ($10 million ). Gathering and processing costs represent operating and maintenance expenses and administrative expenses associated with operating EOG's gathering and processing assets as well as natural gas processing fees and certain NGLs fractionation fees paid to third parties. EOG pays third parties to process the majority of its natural gas production to extract NGLs. Gathering and processing costs decreased$20 million to$459 million in 2020 compared to$479 million in 2019 primarily due to decreased operating costs in the Eagle Ford ($16 million ) and decreased gathering and processing fees in the Eagle Ford ($9 million ) and theFort Worth Basin Barnett Shale ($5 million ); partially offset by increased gathering and processing fees in thePermian Basin ($15 million ). Exploration costs of$146 million in 2020 increased$6 million from$140 million in 2019 primarily due to increased geological and geophysical expenditures inthe United States ($15 million ), partially offset by decreased general and administrative expenses inthe United States ($8 million ). Impairments include: amortization of unproved oil and gas property costs as well as impairments of proved oil and gas properties; other property, plant and equipment; and other assets. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. Unproved properties with individually significant acquisition costs are reviewed individually for impairment. When circumstances indicate that a proved property may be impaired, EOG compares expected undiscounted future cash flows at a DD&A group level to the unamortized capitalized cost of the asset. If the expected undiscounted future cash flows, based on EOG's estimates of (and assumptions regarding) future crude oil, NGLs and natural gas prices, operating costs, development expenditures, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated by using the Income Approach described in the Fair Value Measurement Topic of theFinancial Accounting Standards Board's Accounting Standards Codification (ASC). In certain instances, EOG utilizes accepted offers from third-party purchasers as the basis for determining fair value. 40 -------------------------------------------------------------------------------- The following table represents impairments for the years endedDecember 31, 2020 and 2019 (in millions): 2020 2019 Proved properties$ 1,268 $ 207 Unproved properties 472 220 Other assets 300 91 Firm commitment contracts 60 - Total$ 2,100 $ 518 Impairments of proved properties were primarily due to the write-down to fair value of legacy and non-core natural gas and crude oil and combo plays in 2020 and legacy natural gas assets in 2019. Taxes other than income include severance/production taxes, ad valorem/property taxes, payroll taxes, franchise taxes and other miscellaneous taxes. Severance/production taxes are generally determined based on wellhead revenues, and ad valorem/property taxes are generally determined based on the valuation of the underlying assets. Taxes other than income in 2020 decreased$322 million to$478 million (6.6% of wellhead revenues) from$800 million (6.9% of wellhead revenues) in 2019. The decrease in taxes other than income was primarily due to decreased severance/production taxes inthe United States ($232 million ), decreased ad valorem/property taxes inthe United States ($51 million ) and a state severance tax refund ($27 million ).
Other income, net, was
In response to the economic impacts of the COVID-19 pandemic, the President ofthe United States signed the Coronavirus Aid, Relief, and Economic Security Act (the CARES Act) into law onMarch 27, 2020 . The CARES Act provides economic support to individuals and businesses through enhanced loan programs, expanded unemployment benefits, and certain payroll and income tax relief, among other provisions. The primary tax benefit of the CARES Act for EOG was the acceleration of approximately$150 million of additional refundable alternative minimum tax (AMT) credits into tax year 2019. These credits originated from AMT paid by EOG in years prior to 2018 and were reflected as a deferred tax asset and a non-current receivable as ofDecember 31, 2019 since they had been expected to either offset future current tax liabilities or be refunded on a declining balance schedule through 2021. The$150 million of additional refundable AMT credits was received inJuly 2020 . Further pandemic relief was contained in the Consolidated Appropriations Act of 2021 (the CA Act) which was signed into law by the President ofthe United States onDecember 27, 2020 . In addition, the CA Act provided government funding and limited corporate income tax relief primarily related to making permanent or extending certain tax provisions, none of which were a material benefit for EOG. EOG recognized an income tax benefit of$135 million in 2020 compared to an income tax provision of$810 million in 2019, primarily due to decreased pretax income. The net effective tax rate for 2020 decreased to 18% from 23% in 2019. The lower effective tax rate is mostly due to taxes attributable to EOG's foreign operations and increased stock-based compensation tax deficiencies. 41 -------------------------------------------------------------------------------- 2019 compared to 2018. During 2019, operating expenses of$13,681 million were$875 million higher than the$12,806 million incurred during 2018. The following table presents the costs per Boe for the years endedDecember 31, 2019 and 2018: 2019 2018 Lease and Well$ 4.58 $ 4.89 Transportation Costs 2.54 2.85 Depreciation, Depletion and Amortization (DD&A) - Oil and Gas Properties 12.25 12.65 Other Property, Plant and Equipment 0.31 0.44 General and Administrative (G&A) 1.64 1.63 Net Interest Expense 0.62 0.93 Total (1)$ 21.94 $ 23.39
(1)Total excludes gathering and processing costs, exploration costs, dry hole costs, impairments, marketing costs and taxes other than income.
The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A, G &A and net interest expense for 2019 compared to 2018 are set forth below. See "Operating Revenues and Other" above for a discussion of production volumes. Lease and well expenses of$1,367 million in 2019 increased$84 million from$1,283 million in 2018 primarily due to higher operating and maintenance costs ($76 million ) and higher lease and well administrative expenses ($29 million ) inthe United States , partially offset by lower operating and maintenance costs in theUnited Kingdom ($15 million ) due to the sale of operations in the fourth quarter of 2018 and inCanada ($11 million ). Lease and well expenses increased inthe United States primarily due to increased operating activities resulting in increased production. Transportation costs of$758 million in 2019 increased$11 million from$747 million in 2018 primarily due to increased transportation costs in thePermian Basin ($91 million ) andSouth Texas ($11 million ), partially offset by decreased transportation costs in the Eagle Ford ($77 million ) and theFort Worth Basin Barnett Shale ($13 million ). DD&A expenses in 2019 increased$315 million to$3,750 million from$3,435 million in 2018. DD&A expenses associated with oil and gas properties in 2019 were$337 million higher than in 2018 primarily due to an increase in production inthe United States ($489 million ), partially offset by lower unit rates inthe United States ($119 million ) and the sale of theUnited Kingdom operations in the fourth quarter of 2018 ($33 million ). Unit rates inthe United States decreased primarily due to upward reserve revisions and reserves added at lower costs as a result of increased efficiencies.
G&A expenses of
Net interest expense of$185 million in 2019 was$60 million lower than 2018 primarily due to repayment of the$900 million aggregate principal amount of 5.625% Senior Notes due 2019 inJune 2019 ($30 million ) and the$350 million aggregate principal amount of 6.875% Senior Notes due 2018 inOctober 2018 ($18 million ) and an increase in capitalized interest ($14 million ). Gathering and processing costs increased$42 million to$479 million in 2019 compared to$437 million in 2018 primarily due to increased operating costs and fees in thePermian Basin ($52 million ), theRocky Mountain area ($13 million ) andSouth Texas ($5 million ); partially offset by decreased operating costs in theUnited Kingdom ($33 million ) due to the sale of operations in the fourth quarter of 2018. Exploration costs of$140 million in 2019 decreased$9 million from$149 million in 2018 primarily due to decreased geological and geophysical expenditures in theTrinidad ($17 million ), partially offset by increased general and administrative expenses inthe United States ($7 million ). 42 -------------------------------------------------------------------------------- The following table represents impairments for the years endedDecember 31, 2019 and 2018 (in millions): 2019 2018 Proved properties$ 207 $ 121 Unproved properties 220 173 Other assets 91 49 Inventories - 4 Total$ 518 $ 347
Impairments of proved properties were primarily due to the write-down to fair value of legacy natural gas assets in 2019 and 2018.
Taxes other than income in 2019 increased$28 million to$800 million (6.9% of wellhead revenues) from$772 million (6.5% of wellhead revenues) in 2018. The increase in taxes other than income was primarily due to an increase in ad valorem/property taxes ($53 million ), partially offset by an increase in credits available to EOG in 2019 for state incentive severance tax rate reductions ($12 million ) and a decrease in severance/production taxes ($12 million ) primarily as a result of decreased wellhead revenues, all inthe United States . Other income, net, was$31 million in 2019 compared to other income, net, of$17 million in 2018. The increase of$14 million in 2019 was primarily due to an increase in interest income ($14 million ) and an increase in foreign currency transaction gains ($9 million ), partially offset by an increase in deferred compensation expense ($4 million ). EOG recognized an income tax provision of$810 million in 2019 compared to an income tax provision of$822 million in 2018, primarily due to decreased pretax income, partially offset by the absence of tax benefits from certain tax reform measurement-period adjustments. The net effective tax rate for 2019 increased to 23% from 19% in the prior year, primarily due to the absence of tax benefits from certain tax reform measurement-period adjustments.
Capital Resources and Liquidity
Cash Flow
The primary sources of cash for EOG during the three-year period endedDecember 31, 2020 , were funds generated from operations, net proceeds from the issuance of long-term debt, net cash received from settlements of commodity derivative contracts and proceeds from asset sales. The primary uses of cash were funds used in operations; exploration and development expenditures; repayments of debt; dividend payments to stockholders and other property, plant and equipment expenditures. 2020 compared to 2019. Net cash provided by operating activities of$5,008 million in 2020 decreased$3,155 million from$8,163 million in 2019 primarily due to a decrease in wellhead revenues ($4,291 million ); unfavorable changes in working capital and other assets and liabilities ($166 million ); a decrease in gathering, processing and marketing revenues less marketing costs ($124 million ) and an increase in net cash paid for income taxes ($86 million ); partially offset by an increase in cash received for settlements of commodity derivative contracts ($840 million ) and a decrease in cash operating expenses ($641 million ). Net cash used in investing activities of$3,348 million in 2020 decreased by$2,829 million from$6,177 million in 2019 primarily due to a decrease in additions to oil and gas properties ($2,908 million ); an increase in proceeds from the sale of assets ($52 million ); a decrease in additions to other property, plant and equipment ($49 million ); and a decrease in other investing activities ($10 million ); partially offset by an unfavorable change in working capital associated with investing activities ($190 million ). Net cash used in financing activities of$359 million in 2020 included repayments of long-term debt ($1,000 million ), cash dividend payments ($821 million ), repayment of finance lease liabilities ($19 million ) and purchases of treasury stock in connection with stock compensation plans ($16 million ). Cash provided by financing activities in 2020 included long-term debt borrowings ($1,484 million ) and proceeds from stock options exercised and employee stock purchase plan activity ($16 million ). 43 -------------------------------------------------------------------------------- 2019 compared to 2018. Net cash provided by operating activities of$8,163 million in 2019 increased$394 million from$7,769 million in 2018 primarily reflecting an increase in cash received for settlements of commodity derivative contracts ($490 million ), a decrease in net cash paid for income taxes ($367 million ) and favorable changes in working capital and other assets and liabilities ($122 million ); partially offset by a decrease in wellhead revenues ($365 million ) and an increase in cash operating expenses ($202 million ). Net cash used in investing activities of$6,177 million in 2019 increased by$7 million from$6,170 million in 2018 primarily due to an increase in additions to oil and gas properties ($313 million ), a decrease in proceeds from the sale of assets ($87 million ) and an increase in additions to other property, plant and equipment ($33 million ); partially offset by favorable changes in working capital associated with investing activities ($416 million ) and a decrease in other investing activities ($10 million ). Net cash used in financing activities of$1,513 million in 2019 included repayments of long-term debt ($900 million ), cash dividend payments ($588 million ) and purchases of treasury stock in connection with stock compensation plans ($25 million ). Cash provided by financing activities in 2019 included proceeds from stock options exercised and employee stock purchase plan activity ($18 million ). Total Expenditures
The table below sets out components of total expenditures for the years ended
2020 2019 2018
Expenditure Category Capital Exploration and Development Drilling$ 2,664 $ 4,951 $ 4,935 Facilities 347 629 625 Leasehold Acquisitions (1) 265 276 488 Property Acquisitions (2) 135 380 124 Capitalized Interest 31 38 24 Subtotal 3,442 6,274 6,196 Exploration Costs 146 140 149 Dry Hole Costs 13 28 5 Exploration and Development Expenditures 3,601 6,442
6,350
Asset Retirement Costs 117 186
70
Total Exploration and Development Expenditures 3,718 6,628
6,420
Other Property, Plant and Equipment (3) 395 272 286 Total Expenditures$ 4,113 $ 6,900 $ 6,706 (1)Leasehold acquisitions included$197 million ,$98 million and$291 million related to non-cash property exchanges in 2020, 2019 and 2018, respectively. (2)Property acquisitions included$15 million ,$52 million and$71 million related to non-cash property exchanges in 2020, 2019 and 2018, respectively. (3)Other property, plant and equipment included non-cash additions of$174 million , primarily related to finance lease transactions for storage facilities, and$49 million , primarily related to a finance lease transaction in thePermian Basin , in 2020 and 2018, respectively. 44 -------------------------------------------------------------------------------- Exploration and development expenditures of$3,601 million for 2020 were$2,841 million lower than the prior year. The decrease was primarily due to decreased exploration and development drilling expenditures inthe United States ($2,309 million ), decreased facilities expenditures ($282 million ) and decreased property acquisitions ($245 million ), partially offset by increased exploration and development drilling expenditures inTrinidad ($27 million ). The 2020 exploration and development expenditures of$3,601 million included$2,905 million in development drilling and facilities,$530 million in exploration,$135 million in property acquisitions and$31 million in capitalized interest. The 2019 exploration and development expenditures of$6,442 million included$5,513 million in development drilling and facilities,$511 million in exploration,$380 million in property acquisitions and$38 million in capitalized interest. The 2018 exploration and development expenditures of$6,350 million included$5,546 million in development drilling and facilities,$656 million in exploration,$124 million in property acquisitions and$24 million in capitalized interest. The level of exploration and development expenditures, including acquisitions, will vary in future periods depending on energy market conditions and other economic factors. EOG believes it has significant flexibility and availability with respect to financing alternatives and the ability to adjust its exploration and development expenditure budget as circumstances warrant. While EOG has certain continuing commitments associated with expenditure plans related to its operations, such commitments are not expected to be material when considered in relation to the total financial capacity of EOG.
Commodity Derivative Transactions
Crude Oil Derivative Contracts. Prices received by EOG for its crude oil production generally vary fromU.S. New York Mercantile Exchange (NYMEX) West Texas Intermediate (WTI) prices due to adjustments for delivery location (basis) and other factors. EOG has entered into crude oil basis swap contracts in order to fix the differential between Intercontinental Exchange (ICE) Brent pricing and pricing inCushing, Oklahoma (ICE Brent Differential). Presented below is a comprehensive summary of EOG's ICE Brent Differential basis swap contracts throughFebruary 18, 2021 . The weighted average price differential expressed in $/Bbl represents the amount of addition toCushing, Oklahoma , prices for the notional volumes expressed in Bbld covered by the basis swap contracts. ICE Brent Differential Basis Swap Contracts Weighted Average Price Differential Volume (Bbld) ($/Bbl) 2020 May 2020 (closed) 10,000 $ 4.92 EOG has also entered into crude oil basis swap contracts in order to fix the differential between pricing inHouston, Texas , andCushing, Oklahoma (Houston Differential). Presented below is a comprehensive summary of EOG'sHouston Differential basis swap contracts throughFebruary 18, 2021 . The weighted average price differential expressed in $/Bbl represents the amount of addition toCushing, Oklahoma , prices for the notional volumes expressed in Bbld covered by the basis swap contracts. Houston Differential Basis Swap Contracts Weighted Average Price Differential Volume (Bbld) ($/Bbl) 2020 May 2020 (closed) 10,000 $ 1.55 45
-------------------------------------------------------------------------------- EOG has also entered into crude oil swaps in order to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month (Roll Differential). Presented below is a comprehensive summary of EOG's Roll Differential basis swap contracts throughFebruary 18, 2021 . The weighted average price differential expressed in $/Bbl represents the amount of net addition (reduction) to delivery month prices for the notional volumes expressed in Bbld covered by the swap contracts. Roll Differential Basis Swap Contracts Weighted Average Price Differential Volume (Bbld) ($/Bbl) 2020 February 1, 2020 through June 30, 2020 (closed) 10,000 $ 0.70 July 1, 2020 through September 30, 2020 (closed) 88,000 (1.16) October 1, 2020 through December 31, 2020 (closed) 66,000 (1.16) 2021 February 2021 (closed) 30,000 $ 0.11 March 1, 2021 through December 31, 2021 125,000 0.17
2022
January 1, 2022 through December 31, 2022 125,000 $ 0.15 InMay 2020 , EOG entered into crude oil Roll Differential basis swap contracts for the period fromJuly 1, 2020 throughSeptember 30, 2020 , with notional volumes of 22,000 Bbld at a weighted average price differential of$(0.43) per Bbl, and for the period fromOctober 1, 2020 throughDecember 31, 2020 , with notional volumes of 44,000 Bbld at a weighted average price differential of$(0.73) per Bbl. These contracts partially offset certain outstanding Roll Differential basis swap contracts for the same time periods and volumes at a weighted average price differential of$(1.16) per Bbl. EOG paid net cash of$3.2 million for the settlement of these contracts. The offsetting contracts were excluded from the above table. Presented below is a comprehensive summary of EOG's crude oil NYMEX WTI price swap contracts throughFebruary 18, 2021 , with notional volumes expressed in Bbld and prices expressed in $/Bbl. Crude Oil NYMEX WTI Price Swap Contracts Weighted Average Volume (Bbld) Price ($/Bbl) 2020 January 1, 2020 through March 31, 2020 (closed) 200,000$ 59.33 April 1, 2020 through May 31, 2020 (closed) 265,000 51.36 2021 January 2021 (closed) 151,000$ 50.06 February 1, 2021 through March 31, 2021 201,000 51.29 April 1, 2021 through June 30, 2021 150,000 51.68 July 1, 2021 through September 30, 2021 150,000 52.71 46
-------------------------------------------------------------------------------- In April andMay 2020 , EOG entered into crude oil NYMEX WTI price swap contracts for the period fromJune 1, 2020 throughJune 30, 2020 , with notional volumes of 265,000 Bbld at a weighted average price of$33.80 per Bbl, for the period fromJuly 1, 2020 throughJuly 31, 2020 , with notional volumes of 254,000 Bbld at a weighted average price of$33.75 per Bbl, for the period fromAugust 1, 2020 throughSeptember 30, 2020 , with notional volumes of 154,000 Bbld at a weighted average price of$34.18 per Bbl and for the period fromOctober 1, 2020 throughDecember 31, 2020 , with notional volumes of 47,000 Bbld at a weighted average price of$30.04 per Bbl. These contracts offset the remaining crude oil NYMEX WTI price swap contracts for the same time periods and volumes at a weighted average price of$51.36 per Bbl for the period fromJune 1, 2020 throughJune 30, 2020 ,$42.36 per Bbl for the period fromJuly 1, 2020 throughJuly 31, 2020 ,$50.42 per Bbl for the period fromAugust 1, 2020 throughSeptember 30, 2020 and$31.00 per Bbl for the period fromOctober 1, 2020 throughDecember 31, 2020 . EOG received net cash of$364.0 million for the settlement of these contracts. The offsetting contracts were excluded from the above table. Presented below is a comprehensive summary of EOG's crude oil ICE Brent price swap contracts throughFebruary 18, 2021 , with notional volumes expressed in Bbld and prices expressed in $/Bbl. Crude Oil ICE Brent Price Swap Contracts Volume (Bbld) Weighted Average Price ($/Bbl) 2020 April 2020 (closed) 75,000 $ 25.66 May 2020 (closed) 35,000 26.53 NGLs Derivative Contracts. Presented below is a comprehensive summary of EOG'sMont Belvieu propane (non-TET) price swap contracts throughFebruary 18, 2021 , with notional volumes expressed in Bbld and prices expressed in $/Bbl. Mont Belvieu Propane Price Swap Contracts Weighted Average Volume (Bbld) Price ($/Bbl) 2020 January 1, 2020 through February 29, 2020 (closed) 4,000$ 21.34 March 1, 2020 through April 30, 2020 (closed) 25,000 17.92 2021 January 2021 (closed) 15,000$ 29.44 February 1, 2021 through December 31, 2021 15,000 29.44 In April andMay 2020 , EOG entered intoMont Belvieu propane price swap contracts for the period fromMay 1, 2020 throughDecember 31, 2020 , with notional volumes of 25,000 Bbld at a weighted average price of$16.41 per Bbl. These contracts offset the remainingMont Belvieu propane price swap contracts for the same time period with notional volumes of 25,000 Bbld at a weighted average price of$17.92 per Bbl. EOG received net cash of$9.2 million for the settlement of these contracts. The offsetting contracts were excluded from the above table. 47
-------------------------------------------------------------------------------- Natural Gas Derivative Contracts. Presented below is a comprehensive summary of EOG's natural gas NYMEX Henry Hub price swap contracts throughFebruary 18, 2021 , with notional volumes sold (purchased) expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu). InJanuary 2021 , EOG executed the early termination provision granting EOG the right to terminate certain 2022 natural gas NYMEX Henry Hub price swap contracts with notional volumes of 20,000 MMBtud at a weighted average price of$2.75 per MMBtu for the period fromJanuary 1, 2022 throughDecember 31, 2022 . EOG received net cash of$0.6 million for the settlement of these contracts. Natural Gas NYMEX Henry Hub Price Swap Contracts Weighted Average Volume (MMBtud) Price ($/MMBtu) 2021 April 1, 2021 through September 30, 2021 (70,000) $ 2.64
2022
January 1, 2022 through December 31, 2022 (closed) 20,000 $ 2.75 InDecember 2020 andJanuary 2021 , EOG entered into natural gas NYMEX Henry Hub price swap contracts for the period fromJanuary 1, 2021 throughMarch 31, 2021 , with notional volumes of 500,000 MMBtud at a weighted average price of$2.43 per MMBtu and for the period fromApril 1, 2021 throughDecember 31, 2021 , with notional volumes of 500,000 MMBtud at a weighted average price of$2.83 per MMBtu. These contracts offset the remaining natural gas NYMEX Henry Hub price swap contracts for the same time periods with notional volumes of 500,000 MMBtud at a weighted average price of$2.99 per MMBtu. EOG received net cash of$16.5 million throughFebruary 18, 2021 , for the settlement of certain of these contracts, and expects to receive net cash of$30.3 million during the remainder of 2021 for the settlement of the remaining contracts. The offsetting contracts were excluded from the above table.
Presented below is a comprehensive summary of EOG's natural gas Japan Korea
Marker (JKM) price swap contracts through
Natural Gas JKM Price Swap Contracts
Weighted Average
Volume (MMBtud) Price ($/MMBtu)
2021
April 1, 2021 through September 30, 2021 70,000 $ 6.65
48-------------------------------------------------------------------------------- EOG has entered into natural gas collar contracts, which establish ceiling and floor prices for the sale of notional volumes of natural gas as specified in the collar contracts. The collars require that EOG pay the difference between the ceiling price and the Henry Hub Index Price in the event the Henry Hub Index Price is above the ceiling price. The collars grant EOG the right to receive the difference between the floor price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the floor price. InMarch 2020 , EOG executed the early termination provision granting EOG the right to terminate certain 2020 natural gas collar contracts with notional volumes of 250,000 MMBtud at a weighted average ceiling price of$2.50 per MMBtu and a weighted average floor price of$2.00 per MMBtu for the period fromApril 1, 2020 throughJuly 31, 2020 . EOG received net cash of$7.8 million for the settlement of these contracts. Presented below is a comprehensive summary of EOG's natural gas collar contracts throughFebruary 18, 2021 , with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. Natural Gas Collar
Contracts
Weighted Average Price ($/MMBtu)
Volume (MMBtud) Ceiling Price Floor Price
2020
April 1, 2020 through July 31, 2020 (closed) 250,000 $ 2.50 $ 2.00
In April 2020 , EOG entered into natural gas collar contracts for the period from
August 1, 2020 through October 31, 2020 , with notional volumes of 250,000 MMBtud
at a ceiling price of $2.50 per MMBtu and a floor price of $2.00 per MMBtu.
These contracts offset the remaining natural gas collar contracts for the same
time period with notional volumes of 250,000 MMBtud at a ceiling price of $2.50
per MMBtu and a floor price of $2.00 per MMBtu. EOG received net cash of $1.1
million for the settlement of these contracts. The offsetting contracts were
excluded from the above table.
Prices received by EOG for its natural gas production generally vary from NYMEX
Henry Hub prices due to adjustments for delivery location (basis) and other
factors. EOG has entered into natural gas basis swap contracts in order to fix
the differential between pricing in the Rocky Mountain area and NYMEX Henry Hub
prices (Rockies Differential). Presented below is a comprehensive summary of
EOG's Rockies Differential basis swap contracts through February 18, 2021 . The
weighted average price differential expressed in $/MMBtu represents the amount
of reduction to NYMEX Henry Hub prices for the notional volumes expressed in
MMBtud covered by the basis swap contracts.
Rockies Differential Basis Swap Contracts
Weighted Average
Price Differential
Volume (MMBtud) ($/MMBtu)
2020
January 1, 2020 through December 31, 2020 (closed) 30,000 $ 0.55
49-------------------------------------------------------------------------------- EOG has also entered into natural gas basis swap contracts in order to fix the differential between pricing at the Houston Ship Channel (HSC) and NYMEX Henry Hub prices (HSC Differential). InMarch 2020 , EOG executed the early termination provision granting EOG the right to terminate certain 2020 HSC Differential basis swaps with notional volumes of 60,000 MMBtud at a weighted average price differential of$0.05 per MMBtu for the period fromApril 1, 2020 throughDecember 31, 2020 . EOG paid net cash of$0.4 million for the settlement of these contracts. Presented below is a comprehensive summary of EOG's HSC Differential basis swap contracts throughFebruary 18, 2021 . The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEXHenry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts. HSC Differential Basis Swap Contracts Weighted Average Price Differential Volume (MMBtud) ($/MMBtu) 2020 January 1, 2020 through December 31, 2020 (closed) 60,000 $ 0.05 EOG has also entered into natural gas basis swap contracts in order to fix the differential between pricing at the Waha Hub inWest Texas and NYMEX Henry Hub prices (Waha Differential). Presented below is a comprehensive summary of EOG's Waha Differential basis swap contracts throughFebruary 18, 2021 . The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts. Waha Differential Basis Swap Contracts Weighted Average Price Differential Volume (MMBtud) ($/MMBtu) 2020 January 1, 2020 through April 30, 2020 (closed) 50,000 $ 1.40 InApril 2020 , EOG entered into Waha Differential basis swap contracts for the period fromMay 1, 2020 throughDecember 31, 2020 , with notional volumes of 50,000 MMBtud at a weighted average price differential of$0.43 per MMBtu. These contracts offset the remaining Waha Differential basis swap contracts for the same time period with notional volumes of 50,000 MMBtud at a weighted average price differential of$1.40 per MMBtu. EOG paid net cash of$11.9 million for the settlement of these contracts. The offsetting contracts were excluded from the above table. Financing EOG's debt-to-total capitalization ratio was 22% atDecember 31, 2020 , compared to 19% atDecember 31, 2019 . As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity. AtDecember 31, 2020 and 2019, respectively, EOG had outstanding$5,640 million and$5,140 million aggregate principal amount of senior notes which had estimated fair values of$6,505 million and$5,452 million , respectively. The estimated fair value of debt was based upon quoted market prices and, where such prices were not available, other observable inputs regarding interest rates available to EOG at year-end. EOG's debt is at fixed interest rates. While changes in interest rates affect the fair value of EOG's senior notes, such changes do not expose EOG to material fluctuations in earnings or cash flow. During 2020, EOG funded its capital program and operations primarily by utilizing cash provided by operating activities, issuance of the Notes and proceeds from asset sales. While EOG maintains a$2.0 billion revolving credit facility to back its commercial paper program, there were no borrowings outstanding at any time during 2020 and the amount outstanding at year-end was zero. EOG considers the availability of its$2.0 billion senior unsecured revolving credit facility, as described in Note 2 to Consolidated Financial Statements, to be sufficient to meet its ongoing operating needs. 50 -------------------------------------------------------------------------------- 51 --------------------------------------------------------------------------------
Contractual Obligations
The following table summarizes EOG's contractual obligations atDecember 31, 2020 (in millions): Contractual Obligations (1) Total 2021 2022-2023 2024-2025 2026 & Beyond Current and Long-Term Debt$ 5,640 $ 750
2,297 207 366 309 1,415
Finance Leases (2) 239 36 60 56 87
Operating Leases (2) 1,039 323 344 166 206
Leases Effective, Not Commenced (2) 100 14 28 22 36
Transportation and Storage Service
Commitments (3) 6,665 964 1,830 1,296 2,575
Purchase and Service Obligations 1,258 429 497 143 189
Total Contractual Obligations $ 17,238 $ 2,723 $ 4,375 $ 2,492 $ 7,648
(1)This table does not include the liability for unrecognized tax benefits,
EOG's pension or postretirement benefit obligations or liability for
dismantlement, abandonment and asset retirement obligations (see Notes 6, 7 and
15, respectively, to Consolidated Financial Statements). These amounts are
excluded because they are subject to estimates and the timing of settlement is
unknown.
(2)For more information on contracts that meet the definition of a lease under
ASU 2016-02, see Note 18 to Consolidated Financial Statements.
(3)Amounts exclude transportation and storage service commitments that meet the
definition of a lease. Amounts shown are based on current transportation and
storage rates and the foreign currency exchange rates used to convert Canadian
dollars into United States dollars at December 31, 2020 . Management does not
believe that any future changes in these rates before the expiration dates of
these commitments will have a material adverse effect on the financial condition
or results of operations of EOG.
Off-Balance Sheet Arrangements
EOG does not participate in financial transactions that generate relationships with unconsolidated entities or financial partnerships. Such entities or partnerships, often referred to as variable interest entities (VIE) or special purpose entities (SPE), are generally established for the purpose of facilitating off-balance sheet arrangements or other limited purposes. EOG was not involved in any unconsolidated VIE or SPE financial transactions or any other "off-balance sheet arrangement" (as defined in Item 303(a)(4)(ii) of Regulation S-K) during any of the periods covered by this report and currently has no intention of participating in any such transaction or arrangement in the foreseeable future.
Foreign Currency Exchange Rate Risk
During 2020, EOG was exposed to foreign currency exchange rate risk inherent in its operations in foreign countries, includingTrinidad ,China andCanada . EOG continues to monitor the foreign currency exchange rates of countries in which it is currently conducting business and may implement measures to protect against foreign currency exchange rate risk. 52 --------------------------------------------------------------------------------
Outlook
Pricing. Crude oil, NGLs and natural gas prices have been volatile, and this volatility is expected to continue. As a result of the many uncertainties associated with the world political environment, worldwide supplies of, and demand for, crude oil and condensate, NGLs and natural gas, the availabilities of other worldwide energy supplies and the relative competitive relationships of the various energy sources in the view of consumers, EOG is unable to predict what changes may occur in crude oil and condensate, NGLs, natural gas, ammonia and methanol prices in the future. The market price of crude oil and condensate, NGLs and natural gas in 2021 will impact the amount of cash generated from EOG's operating activities, which will in turn impact EOG's financial position. As ofFebruary 18, 2021 , the average 2021 NYMEX crude oil and natural gas prices were$57.51 per barrel and$2.98 per MMBtu, respectively, representing an increase of 46% for crude oil and an increase of 43% for natural gas from the average NYMEX prices in 2020. See ITEM 1A, Risk Factors. Including the impact of EOG's crude oil and NGL derivative contracts (exclusive of basis swaps) and based on EOG's tax position, EOG's price sensitivity in 2021 for each$1.00 per barrel increase or decrease in wellhead crude oil and condensate price, combined with the estimated change in NGL price, is approximately$99 million for net income and$127 million for pretax cash flows from operating activities. Including the impact of EOG's natural gas derivative contracts and based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 2021 for which prices have not been determined under long-term marketing contracts, EOG's price sensitivity for each$0.10 per Mcf increase or decrease in wellhead natural gas price is approximately$31 million for net income and$40 million for pretax cash flows from operating activities. For information regarding EOG's crude oil, NGLs and natural gas financial commodity derivative contracts throughFebruary 18, 2021 , see "Commodity Derivative Transactions" above. Capital. EOG plans to continue to focus a substantial portion of its exploration and development expenditures in its major producing areas inthe United States . In particular, EOG will be focused onUnited States crude oil drilling activity in itsDelaware Basin ,Eagle Ford andRocky Mountain area where it generates its highest rates-of-return. To further enhance the economics of these plays, EOG expects to continue to improve well performance and lower drilling and completion costs through efficiency gains and lower service costs. In addition, EOG expects to spend a portion of its anticipated 2021 capital expenditures on leasing acreage and evaluating new prospects. The total anticipated 2021 capital expenditures of approximately$3.7 billion to$4.1 billion , excluding acquisitions and non-cash transactions, is structured to maintain EOG's strategy of capital discipline by funding its exploration, development and exploitation activities primarily from available internally generated cash flows and cash on hand. EOG has significant flexibility with respect to financing alternatives, including borrowings under its commercial paper program, bank borrowings, borrowings under its$2.0 billion senior unsecured revolving credit facility and equity and debt offerings.
Operations. In 2021, total crude oil production is expected to remain at fourth quarter 2020 levels. In 2021, EOG expects to continue to focus on reducing operating costs through efficiency improvements.
53
--------------------------------------------------------------------------------Summary of Critical Accounting Policies
EOG prepares its financial statements and the accompanying notes in conformity with accounting principles generally accepted inthe United States , which require management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes. EOG identifies certain accounting policies as critical based on, among other things, their impact on EOG's financial condition, results of operations or liquidity, and the degree of difficulty, subjectivity and complexity in their application. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management routinely discusses the development, selection and disclosure of each of the critical accounting policies. Following is a discussion of EOG's most critical accounting policies: Proved Oil and Gas Reserves EOG's engineers estimate proved oil and gas reserves in accordance withUnited States Securities and Exchange Commission (SEC) regulations, which directly impact financial accounting estimates, including depreciation, depletion and amortization and impairments of proved properties and related assets. Proved reserves represent estimated quantities of crude oil and condensate, NGLs and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. The process of estimating quantities of proved oil and gas reserves is complex, requiring significant subjective decisions in the evaluation of available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. For related discussion, see ITEM 1A, Risk Factors, and "Supplemental Information to Consolidated Financial Statements."
Oil and Gas Exploration and Development Costs
EOG accounts for its crude oil and natural gas exploration and production activities under the successful efforts method of accounting. Oil and gas exploration costs, other than the costs of drilling exploratory wells, are expensed as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether EOG has discovered commercial quantities of proved reserves. If commercial quantities of proved reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether commercial quantities of proved reserves have been discovered when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the estimated reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized.
Depreciation, Depletion and Amortization for
The quantities of estimated proved oil and gas reserves are a significant component of EOG's calculation of depreciation, depletion and amortization expense, and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserves are revised upward or downward, earnings will increase or decrease, respectively. Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method. The reserve base used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account.
Oil and gas properties are grouped in accordance with the provisions of the
Depreciation, depletion and amortization rates are updated quarterly to reflect the addition of capital costs, reserve revisions (upwards or downwards) and additions, property acquisitions and/or property dispositions and impairments.
54
--------------------------------------------------------------------------------Depreciation and amortization of other property, plant and equipment is calculated on a straight-line basis over the estimated useful life of the asset.
Impairments
Oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. Unproved properties with individually significant acquisition costs are reviewed individually for impairment. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred. When circumstances indicate that proved oil and gas properties may be impaired, EOG compares expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the unamortized capitalized cost of the asset. If the expected undiscounted future cash flows, based on EOG's estimates of (and assumptions regarding) future crude oil and natural gas prices, operating costs, development expenditures, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach described in the Fair Value Measurement Topic of the ASC. In certain instances, EOG utilizes accepted offers from third-party purchasers as the basis for determining fair value. Estimates of undiscounted future cash flows require significant judgment, and the assumptions used in preparing such estimates are inherently uncertain. In addition, such assumptions and estimates are reasonably likely to change in the future. Crude oil, NGLs and natural gas prices have exhibited significant volatility in the past, and EOG expects that volatility to continue in the future. During the five years endedDecember 31, 2020 , WTI crude oil spot prices have fluctuated from approximately$(36.98) per barrel to$77.41 per barrel, andHenry Hub natural gas spot prices have ranged from approximately$1.33 per MMBtu to$6.24 per MMBtu. Market prices for NGLs are influenced by the components extracted, including ethane, propane, butane and natural gasoline, among others, and the respective market pricing for each component. EOG uses the five-year NYMEX futures strip for WTI crude oil andHenry Hub natural gas and the five-year Oil Price Information Services futures strip for NGLs components (in each case as of the applicable balance sheet date) as a basis to estimate future crude oil, NGLs and natural gas prices. EOG's proved reserves estimates, including the timing of future production, are also subject to significant assumptions and judgment, and are frequently revised (upwards and downwards) as more information becomes available. Proved reserves are estimated using a trailing 12-month average price, in accordance withSEC rules. In the future, if any combination of crude oil prices, NGLs prices, natural gas prices, actual production or operating costs diverge negatively from EOG's current estimates, impairment charges and downward adjustments to our estimated proved reserves may be necessary. Income Taxes Income taxes are accounted for using the asset and liability approach. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis. EOG assesses the realizability of deferred tax assets and recognizes valuation allowances as appropriate. Significant assumptions used in estimating future taxable income include future crude oil, NGLs and natural gas prices and levels of capital reinvestment. Changes in such assumptions or changes in tax laws and regulations could materially affect the recognized amounts of valuation allowances.
Stock-Based Compensation
In accounting for stock-based compensation, judgments and estimates are made
regarding, among other things, the appropriate valuation methodology to follow
in valuing stock compensation awards and the related inputs required by those
valuation methodologies. Assumptions regarding expected volatility of EOG's
common stock, the level of risk-free interest rates, expected dividend yields on
EOG's common stock, the expected term of the awards, expected volatility in the
price of shares and composition of EOG's peer companies and other valuation
inputs are subject to change. Any such changes could result in different
valuations and thus impact the amount of stock-based compensation expense
recognized on the Consolidated Statements of Income and Comprehensive Income.
55
--------------------------------------------------------------------------------Information Regarding Forward-Looking Statements
This Annual Report on Form 10-K includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, goals, returns and rates of return, budgets, reserves, levels of production, capital expenditures, costs and asset sales, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forwardlooking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "aims," "goal," "may," "will," "focused on," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forwardlooking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness, or pay and/or increase dividends are forwardlooking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others: •the timing, extent and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids, natural gas and related commodities; •the extent to which EOG is successful in its efforts to acquire or discover additional reserves; •the extent to which EOG is successful in its efforts to (i) economically develop its acreage in, (ii) produce reserves and achieve anticipated production levels and rates of return from, (iii) decrease or otherwise control its drilling, completion, operating and capital costs related to, and (iv) maximize reserve recovery from, its existing and future crude oil and natural gas exploration and development projects and associated potential and existing drilling locations; •the extent to which EOG is successful in its efforts to market its production of crude oil and condensate, natural gas liquids, and natural gas; •security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems, physical breaches of our facilities and other infrastructure or breaches of the information technology systems, facilities and infrastructure of third parties with which we transact business; •the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, storage, transportation, refining, and export facilities; •the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses and leases and governmental and other permits and rights-of-way, and EOG's ability to retain mineral licenses and leases; •the impact of, and changes in, government policies, laws and regulations, including any changes or other actions which may result from the recentU.S. elections and change inU.S. administration and including tax laws and regulations; climate change and other environmental, health and safety laws and regulations relating to air emissions, disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations affecting the leasing of acreage and permitting for oil and gas drilling and the calculation of royalty payments in respect of oil and gas production; laws and regulations imposing additional permitting and disclosure requirements, additional operating restrictions and conditions or restrictions on drilling and completion operations and on the transportation of crude oil and natural gas; laws and regulations with respect to derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities; •EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and drilling, completing and operating costs with respect to such properties; •the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully and economically; •competition in the oil and gas exploration and production industry for the acquisition of licenses, leases and properties, employees and other personnel, facilities, equipment, materials and services; •the availability and cost of employees and other personnel, facilities, equipment, materials (such as water and tubulars) and services; •the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise; 56
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•weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, compression, storage, transportation, and export facilities; •the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG; •EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements; •the extent to which EOG is successful in its completion of planned asset dispositions; •the extent and effect of any hedging activities engaged in by EOG; •the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions; •the duration and economic and financial impact of epidemics, pandemics or other public health issues, including the COVID-19 pandemic; •geopolitical factors and political conditions and developments around the world (such as the imposition of tariffs or trade or other economic sanctions, political instability and armed conflict), including in the areas in which EOG operates; •the use of competing energy sources and the development of alternative energy sources; •the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage; •acts of war and terrorism and responses to these acts; and •the other factors described under ITEM 1A, Risk Factors of this Annual Report on Form 10-K and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K. In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration or extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.
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