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 andTrinidad . 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 net income of$4,664 million during 2021 as compared to a net loss of$605 million for 2020. AtDecember 31, 2021 , EOG's total estimated net proved reserves were 3,747 million barrels of oil equivalent (MMBoe), an increase of 527 MMBoe fromDecember 31, 2020 . During 2021, net proved crude oil and condensate and natural gas liquids (NGLs) reserves increased by 50 million barrels (MMBbl), and net proved natural gas reserves increased by 2,862 billion cubic feet or 477 MMBoe, in each case fromDecember 31, 2020 .
Recent Developments
Commodity Prices. In 2020, the COVID-19 pandemic and the measures taken to address and limit the spread of the virus adversely affected the economies and financial markets of the world, resulting in an economic downturn beginning in early 2020 that negatively impacted global demand and prices for crude oil and condensate, NGLs and natural gas. In response, OPEC+, a consortium ofOPEC (Organization of Petroleum Exporting Countries ) and certain non-OPEC global producers (Russia ,Kazakhstan and others), agreed to voluntarily curtail crude oil supplies beginning inApril 2020 with a schedule to bring back some of these curtailments throughApril 2021 . Certain other non-OPEC+ countries also curtailed production and/or reduced investments in existing and new crude oil projects. This response started the process of balancing supply with demand. In 2021, the effects of global COVID-19 mitigation efforts, including extensive global fiscal stimulus and the availability of vaccines, tempered by new COVID-19 variant strains and corresponding containment measures in certain parts of the world, have resulted in overall increased demand for crude oil and condensate, NGLs and natural gas. See ITEM 1A, Risk Factors for discussion of risks related to the COVID-19 pandemic. During 2021 and into early 2022, OPEC+ continued their schedule of gradually returning all curtailed production through 2022 in response to expected increases in demand for crude oil. The continuing rebalancing of crude oil demand and supply resulting from improving or stabilizing conditions in certain economies and financial markets of the world, combined with the continuing actions taken by OPEC+, had a positive impact on crude oil prices in 2021. Prices for crude oil and condensate and NGLs returned to prepandemic levels in the first quarter of 2021, while natural gas prices returned to pre-pandemic levels at the beginning of 2021. As a result of the many uncertainties associated with (i) the world economic and political 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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Climate Change. For a discussion of climate change matters and related
regulatory matters, including potential developments related to climate change
and the potential impacts and risks of such developments on EOG, see ITEM 1A,
Risk Factors, and the related discussion in ITEM 1, Business - Regulation. EOG
will continue to monitor and assess any climate change-related developments that
could impact EOG and 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, to a lesser extent, liquids-rich natural gas plays. During 2021, EOG continued to focus on increasing drilling, completion and operating efficiencies gained in prior years. Such efficiencies resulted in lower operating, drilling and completion costs in 2021. 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 75% and 76% ofUnited States production during 2021 and 2020, respectively. During 2021, drilling and completion activities occurred primarily in theDelaware Basin play,Eagle Ford oil play andRocky Mountain area. EOG's major producing areas inthe United States are inTexas andNew Mexico . EOG faced interruptions to sales in certain markets due to disruptions throughoutthe United States from Winter Storm Uri in the first quarter of 2021. Winter Storm Uri also negatively impacted Lease and Well, Transportation and Gathering and Processing Costs in the first quarter of 2021. See ITEM 1, Business - Exploration and Production for further discussion regarding EOG's 2021 United States operations.Trinidad . In theRepublic of Trinidad and Tobago (Trinidad ), 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 (Heritage). InMarch 2021 , EOG signed a farmout agreement with Heritage, which allows EOG to earn a 65% working interest in a portion of the contract area (EOG Area) governed by the Trinidad Northern Area License. The EOG Area is located offshore the southwest coast ofTrinidad . EOG continues to make progress on the design and fabrication of a platform and related facilities for its previously announced discovery in the Modified U(a) Block.
In 2022, EOG expects to drill one net exploratory well in the EOG Area in addition to three development wells and one exploratory well in the Modified U(a) Block.
Other International. InAustralia , onApril 22, 2021 , a subsidiary of EOG entered into a purchase and sale agreement to acquire a 100% interest in the WA-488-P Block, located offshoreWestern Australia . The transaction was closed in the fourth quarter of 2021 including the transfer of the petroleum exploration permit for that block. In 2022, EOG will continue preparing for the drilling of an exploration well which is expected to commence in 2023. In the Sultanate ofOman (Oman ), a Royal Decree was issued onMarch 9, 2021 , and EOG became a participant in the Exploration and Production Sharing Agreement for Block 49, holding a 50% working interest. EOG's partner in Block 49 completed the drilling and testing of one net exploratory well, which was determined to be a dry hole. EOG notified its partner and theMinistry of Energy andMinerals of its intention to withdraw from Block 49. In Block 36, where EOG holds a 100% working interest, EOG drilled two net exploratory wells and completed one net exploratory well. There was a discovery of natural gas in Block 36, but the well results did not yield sufficient projected returns for EOG to move forward with the project. EOG recorded pretax impairment charges of$45 million and dry hole costs of$42 million in 2021. In 2022, EOG expects to exit Block 36. InMay 2021 , EOG closed the sale of its subsidiary which held all of its assets in theChina Sichuan Basin (China ). Net production was approximately 25 million cubic feet per day (MMcfd) of natural gas prior to the sale. EOG no longer has any operations or assets inChina . 35 -------------------------------------------------------------------------------- EOG continues to evaluate other select crude oil and natural gas opportunities outsidethe 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 19% atDecember 31, 2021 and 22% atDecember 31, 2020 . As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.
On
During 2021, EOG funded$4.1 billion ($124 million of which was non-cash) in exploration and development and other property, plant and equipment expenditures (excluding asset retirement obligations), paid$2,684 million in dividends to common stockholders and repaid the 2021 Notes, primarily by utilizing net cash provided from its operating activities and net proceeds of$231 million from the sale of assets. Total anticipated 2022 capital expenditures are estimated to range from approximately$4.3 billion to$4.7 billion , excluding acquisitions and non-cash transactions. The majority of 2022 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.
Dividend Declarations and Share Repurchase Authorization. OnFebruary 25, 2021 , EOG's Board increased the quarterly cash dividend on the common stock from the previous$0.375 per share to$0.4125 per share, effective beginning with the dividend paid onApril 30, 2021 , to stockholders of record as ofApril 16, 2021 . OnMay 6, 2021 , EOG's Board declared a special cash dividend on the common stock of$1.00 per share. The special cash dividend, which was in addition to the quarterly cash dividend, was paid onJuly 30, 2021 to stockholders of record as ofJuly 16, 2021 . OnNovember 4, 2021 , EOG's Board (i) further increased the quarterly cash dividend on the common stock from the previous$0.4125 per share to$0.75 per share, effective beginning with the dividend paid onJanuary 28, 2022 , to stockholders of record as ofJanuary 14, 2022 , (ii) declared a special cash dividend on the common stock of$2.00 per share, paid onDecember 30, 2021 , to stockholders of record as ofDecember 15, 2021 , (iii) established a new share repurchase authorization to allow for the repurchase by EOG of up to$5 billion of the common stock and (iv) revoked and terminated the share repurchase authorization established by the Board inSeptember 2001 . See ITEM 5, Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases ofEquity Securities for additional discussion. OnFebruary 24, 2022 , the Board declared a quarterly cash dividend on the common stock of$0.75 per share payableApril 29, 2022 , to stockholders of record as ofApril 15, 2022 . The Board also declared a special dividend of$1.00 per share payableMarch 29, 2022 , to stockholders of record as ofMarch 15, 2022 . 36 --------------------------------------------------------------------------------
Results of Operations
The following review of operations for each of the three years in the period endedDecember 31, 2021 , 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 2021, operating revenues increased$7,610 million , or 69%, to$18,642 million from$11,032 million in 2020. Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, NGLs and natural gas, increased$8,090 million , or 111%, to$15,381 million in 2021 from$7,291 million in 2020. Revenues from the sales of crude oil and condensate and NGLs in 2021 were approximately 84% of total wellhead revenues compared to 89% in 2020. During 2021, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of$1,152 million compared to net gains of$1,145 million in 2020. Gathering, processing and marketing revenues increased$1,705 million during 2021, to$4,288 million from$2,583 million in 2020. EOG recognized net gains on asset dispositions of$17 million in 2021 compared to net losses on asset dispositions of$47 million in 2020. 37 -------------------------------------------------------------------------------- Wellhead volume and price statistics for the years endedDecember 31, 2021 , 2020 and 2019 were as follows: Year Ended December 31 2021 2020 2019 Crude Oil and Condensate Volumes (MBbld) (1) United States 443.4 408.1 455.5 Trinidad 1.5 1.0 0.6 Other International (2) 0.1 0.1 0.1 Total 445.0 409.2 456.2 Average Crude Oil and Condensate Prices ($/Bbl) (3) United States$ 68.54 $ 38.65 $ 57.74 Trinidad 56.26 30.20 47.16 Other International (2) 42.36 43.08 57.40 Composite 68.50 38.63 57.72 Natural Gas Liquids Volumes (MBbld) (1) United States 144.5 136.0 134.1 Other International (2) - - - Total 144.5 136.0 134.1 Average Natural Gas Liquids Prices ($/Bbl) (3) United States$ 34.35 $ 13.41 $ 16.03 Other International (2) - - - Composite 34.35 13.41 16.03 Natural Gas Volumes (MMcfd) (1) United States 1,210 1,040 1,069 Trinidad 217 180 260 Other International (2) 9 32 37 Total 1,436 1,252 1,366 Average Natural Gas Prices ($/Mcf) (3) United States$ 4.88 $ 1.61 $ 2.22 Trinidad 3.40 2.57 2.72 Other International (2) 5.67 4.66 4.44 Composite 4.66 1.83 2.38 Crude Oil Equivalent Volumes (MBoed) (4) United States 789.6 717.5 767.8 Trinidad 37.7 30.9 44.0 Other International (2) 1.6 5.4 6.2 Total 828.9 753.8 818.0 Total MMBoe (4) 302.5 275.9 298.6 (1) Thousand barrels per day or million cubic feet per day, as applicable. (2)Other International includes EOG'sChina andCanada operations. TheChina operations were sold in the second quarter of 2021.(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. 38 -------------------------------------------------------------------------------- 2021 compared to 2020. Wellhead crude oil and condensate revenues in 2021 increased$5,339 million , or 92%, to$11,125 million from$5,786 million in 2020, due primarily to a higher composite average wellhead crude oil and condensate price ($4,852 million ) and an increase in production ($487 million ). EOG's composite wellhead crude oil and condensate price for 2021 increased 77% to$68.50 per barrel compared to$38.63 per barrel in 2020. Wellhead crude oil and condensate production in 2021 increased 9% to 445 MBbld as compared to 409 MBbld in 2020. The increased production was primarily in thePermian Basin , partially offset by decreased production in the Eagle Ford oil play. NGLs revenues in 2021 increased$1,144 million , or 171%, to$1,812 million from$668 million in 2020 primarily due to a higher composite average wellhead NGLs price ($1,104 million ) and an increase in production ($40 million ). EOG's composite average wellhead NGLs price increased 156% to$34.35 per barrel in 2021 compared to$13.41 per barrel in 2020. NGL production in 2021 increased 6% to 145 MBbld as compared to 136 MBbld in 2020. The increased production was primarily in thePermian Basin . Wellhead natural gas revenues in 2021 increased$1,607 million , or 192%, to$2,444 million from$837 million in 2020, primarily due to a higher composite wellhead natural gas price ($1,486 million ) and an increase in natural gas deliveries ($121 million ). EOG's composite average wellhead natural gas price increased 155% to$4.66 per Mcf in 2021 compared to$1.83 per Mcf in 2020. Natural gas deliveries in 2021 increased 15% to 1,436 MMcfd as compared to 1,252 MMcfd in 2020. The increase in production was primarily due to increased production of associated natural gas from thePermian Basin and higher natural gas volumes inTrinidad , partially offset by lower natural gas volumes associated with the dispositions of theMarcellus Shale assets in the third quarter of 2020 and theChina assets in the second quarter of 2021. During 2021, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of$1,152 million , which included net cash paid for settlements of crude oil, NGL and natural gas financial derivative contracts of$638 million . 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 from settlements of crude oil, NGL and natural gas financial derivative contracts of$1,071 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 capacity at third-party facilities 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. 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 2021
increased
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 oil play 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 of associated NGLs in the Eagle Ford oil play. 39 -------------------------------------------------------------------------------- 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 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.
Operating and Other Expenses
2021 compared to 2020. During 2021, operating expenses of$12,540 million were$964 million higher than the$11,576 million incurred during 2020. The following table presents the costs per barrel of oil equivalent (Boe) for the years endedDecember 31, 2021 and 2020: 2021 2020 Lease and Well$ 3.75 $ 3.85 Transportation Costs 2.85 2.66 Gathering and Processing Costs 1.85 1.66 Depreciation, Depletion and Amortization (DD&A) - Oil and Gas Properties 11.58 11.85 Other Property, Plant and Equipment 0.49 0.47 General and Administrative (G&A) 1.69 1.75 Net Interest Expense 0.59 0.74 Total (1)$ 22.80 $ 22.98
(1)Total excludes 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, gathering and processing costs, DD&A, G &A and net interest expense for 2021 compared to 2020 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. 40 -------------------------------------------------------------------------------- Lease and well expenses of$1,135 million in 2021 increased$72 million from$1,063 million in 2020 primarily due to higher operating and maintenance costs inthe United States ($33 million ) and inTrinidad ($5 million ), higher workovers expenditures inthe United States ($25 million ) and higher lease and well administrative expenses inthe United States ($12 million ); partially offset by lower operating and maintenance costs inCanada ($6 million ) and as a result of the disposition of all of theChina assets in the second quarter of 2021 ($5 million ). Lease and well expenses increased inthe United States primarily due to increased operating activities resulting from increased production. 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, storage and terminal 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. Transportation costs of$863 million in 2021 increased$128 million from$735 million in 2020 primarily due to increased transportation costs in thePermian Basin ($121 million ) and theRocky Mountain area ($22 million ), partially offset by decreased transportation costs in the Eagle Ford oil play ($13 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 increased$100 million to$559 million in 2021 compared to$459 million in 2020 primarily due to increased gathering and processing fees related to production from thePermian Basin ($51 million ) and theRocky Mountain area ($10 million ), increased operating costs in thePermian Basin ($26 million ) and theRocky Mountain area ($7 million ) and increased administrative expenses inthe United States ($15 million ); partially offset by decreased gathering and processing fees in the Eagle Ford oil play ($5 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 2021 increased$251 million to$3,651 million from$3,400 million in 2020. DD&A expenses associated with oil and gas properties in 2021 were$235 million higher than in 2020 primarily due to an increase in production inthe United States ($307 million ) andTrinidad ($12 million ) and higher unit rates inTrinidad ($14 million ), partially offset by lower unit rates inthe United States ($85 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 2021 were$15 million higher than in 2020 primarily due to an increase in expense related to storage assets. G&A expenses of$511 million in 2021 increased$27 million from$484 million in 2020 primarily due to a net increase in costs associated with corporate support activities, including employee-related expenses and increased information system costs ($54 million ); partially offset by a decrease in idle equipment and termination fees ($46 million ). Net interest expense of$178 million in 2021 was$27 million lower than 2020 primarily due to repayment inFebruary 2021 of the$750 million aggregate principal amount of 4.100% Senior Notes due 2021 ($29 million ), repayment inJune 2020 of the$500 million aggregate principal amount of 4.40% Senior Notes due 2020 ($9 million ), repayment inApril 2020 of the$500 million aggregate principal amount of 2.45% Senior Notes due 2020 ($3 million ) and lower interest payments for late royalty payments onOklahoma properties ($6 million ), partially offset by the issuance inApril 2020 of the$750 million aggregate principal amount of 4.950% Senior Notes due 2050 ($11 million ) and$750 million aggregate principal amount of 4.375% Senior Notes due 2030 ($10 million ). Exploration costs of$154 million in 2021 increased$8 million from$146 million in 2020 primarily due to increased geological and geophysical expenditures inthe United States . 41
-------------------------------------------------------------------------------- Impairments include: amortization of unproved oil and gas property costs as well as impairments of proved oil and gas properties; other property, plant and equipment; and other assets. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. Unproved properties with individually significant acquisition costs are reviewed individually for impairment. When circumstances indicate that a proved property may be impaired, EOG compares expected undiscounted future cash flows at a DD&A group level to the unamortized capitalized cost of the group. If the expected undiscounted future cash flows, based on EOG's estimates of (and assumptions regarding) future crude oil, NGLs and natural gas prices, operating costs, development expenditures, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated by using the Income Approach described in the Fair Value Measurement Topic of theFinancial Accounting Standards Board's Accounting Standards Codification (ASC). In certain instances, EOG utilizes accepted offers from third-party purchasers as the basis for determining fair value. The following table represents impairments for the years endedDecember 31, 2021 and 2020 (in millions): 2021 2020 Proved properties$ 20 $ 1,268 Unproved properties 310 472 Other assets 28 300 Inventories 13 - Firm commitment contracts 5 60 Total$ 376 $ 2,100 Impairments of proved properties in 2020 were primarily due to the decline in commodity prices and were primarily related to the write-down to fair value of legacy and non-core natural gas, crude oil and combo plays inthe United States . Impairments of unproved oil and gas properties included charges of$38 million in 2021 due to the decision in the fourth quarter of 2021 to exit Block 36 and Block 49 inOman and$252 million in 2020 for certain leasehold costs that are no longer expected to be developed before expiration. Impairments of other assets in 2020 were primarily for the write-down to fair value of sand and crude-by-rail assets and a commodity price-related write-down of other assets. Impairments of firm commitment contracts in 2020 were a result of the decision to exit theHorn River Basin inCanada . 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 2021 increased$569 million to$1,047 million (6.8% of wellhead revenues) from$478 million (6.6% of wellhead revenues) in 2020. The increase in taxes other than income was primarily due to increased severance/production taxes inthe United States ($522 million ), increased severance/production taxes inTrinidad ($7 million ) and decreased state severance tax refunds ($39 million ). EOG recognized an income tax provision of$1,269 million in 2021 compared to an income tax benefit of$134 million in 2020, primarily due to increased pretax income. The net effective tax rate for 2021 increased to 21% from 18% in 2020. The higher effective tax rate is mostly due to taxes attributable to EOG's foreign operations and stock-based compensation tax deficiencies increasing the effective tax rate on pretax income in 2021 and decreasing the effective tax rate on pretax loss in 2020. 42
-------------------------------------------------------------------------------- 2020 compared to 2019. During 2020, operating expenses of$11,576 million were$2,105 million lower than the$13,681 million incurred during 2019. The following table presents the costs per Boe for the years endedDecember 31, 2020 and 2019: 2020 2019 Lease and Well$ 3.85 $ 4.58 Transportation Costs 2.66 2.54 Gathering and Processing Costs 1.66 1.60 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)$ 22.98 $ 23.54
(1)Total excludes 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, gathering and processing 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 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 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 oil play ($20 million ), partially offset by increased transportation costs in thePermian Basin ($56 million ). 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 oil play ($9 million ) and theFort Worth Basin Barnett Shale ($5 million ); partially offset by increased gathering and processing fees in thePermian Basin ($15 million ). 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 ). 43 -------------------------------------------------------------------------------- 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 ($8 million ). The following table represents impairments for the years endedDecember 31, 2020 and 2019 (in millions): 2020 2019 Proved properties$ 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 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$134 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. 44 --------------------------------------------------------------------------------
Capital Resources and Liquidity
Cash Flow
The primary sources of cash for EOG during the three-year period endedDecember 31, 2021 , 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; dividend payments to stockholders; repayments of debt; net cash paid for settlements of commodity derivative contracts and other property, plant and equipment expenditures. 2021 compared to 2020. Net cash provided by operating activities of$8,791 million in 2021 increased$3,783 million from$5,008 million in 2020 primarily due to an increase in wellhead revenues ($8,090 million ) and an increase in gathering, processing and marketing revenues less marketing costs ($230 million ); partially offset by an increase in net cash paid for settlements of commodity derivative contracts ($1,709 million ); an increase in net cash paid for income taxes ($1,320 million ); net cash used in working capital in 2021 ($817 million ) compared to net cash provided by working capital in 2020 ($193 million ); and an increase in cash operating expenses ($882 million ). Net cash used in investing activities of$3,419 million in 2021 increased by$71 million from$3,348 million in 2020 primarily due to an increase in additions to oil and gas properties ($394 million ), partially offset by net cash provided by working capital associated with investing activities in 2021 ($200 million ) compared to net cash used in working capital associated with investing activities in 2020 ($75 million ); an increase in proceeds from the sales of assets ($39 million ); and a decrease in additions to other property, plant and equipment ($9 million ). Net cash used in financing activities of$3,493 million in 2021 included cash dividend payments ($2,684 million ), repayments of long-term debt ($750 million ), purchases of treasury stock in connection with stock compensation plans ($41 million ) and repayment of finance lease liabilities ($37 million ). Cash provided by financing activities in 2021 included proceeds from stock options exercised and employee stock purchase plan activity ($19 million ). 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 ($123 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 ($16 million ). 45 --------------------------------------------------------------------------------
Total Expenditures
The table below sets out components of total expenditures for the years ended
2021 2020 2019
Expenditure Category Capital Exploration and Development Drilling$ 2,864 $ 2,664 $ 4,951 Facilities 405 347 629 Leasehold Acquisitions (1) 215 265 276 Property Acquisitions (2) 100 135 380 Capitalized Interest 33 31 38 Subtotal 3,617 3,442 6,274 Exploration Costs 154 146 140 Dry Hole Costs 71 13 28 Exploration and Development Expenditures 3,842 3,601
6,442
Asset Retirement Costs 127 117
186
Total Exploration and Development Expenditures 3,969 3,718
6,628
Other Property, Plant and Equipment (3) 286 395 272 Total Expenditures$ 4,255 $ 4,113 $ 6,900 (1)Leasehold acquisitions included$45 million ,$197 million and$98 million related to non-cash property exchanges in 2021, 2020 and 2019, respectively. (2)Property acquisitions included$5 million ,$15 million and$52 million related to non-cash property exchanges in 2021, 2020 and 2019, respectively. (3)Other property, plant and equipment included non-cash additions of$74 million and$174 million , primarily related to finance lease transactions for storage facilities in 2021 and 2020, respectively. Exploration and development expenditures of$3,842 million for 2021 were$241 million higher than the prior year. The increase was primarily due to increased exploration and development drilling expenditures inthe United States ($267 million ) and increased facilities expenditures ($58 million ), partially offset by decreased exploration and development drilling expenditures inTrinidad ($61 million ), decreased leasehold acquisitions ($50 million ) and decreased property acquisitions ($35 million ). The 2021 exploration and development expenditures of$3,842 million included$3,172 million in development drilling and facilities,$537 million in exploration,$100 million in property acquisitions and$33 million in capitalized interest. 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 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. 46 --------------------------------------------------------------------------------
Commodity Derivative Transactions
Presented below is a comprehensive summary of EOG's financial commodity derivative contracts settled during the year endedDecember 31, 2021 (closed) and remaining for 2022 and thereafter, as ofFebruary 18, 2022 . Crude oil and NGL volumes are presented in MBbld and prices are presented in $/Bbl. Natural gas volumes are presented in MMBtu per day (MMBtud) and prices are presented in dollars per MMBtu ($/MMBtu). Crude Oil Financial Price Swap Contracts Contracts Sold Volume Weighted Average Price Period Settlement Index (MBbld) ($/Bbl) NYMEX West Texas Intermediate January 2021 (closed) (WTI) 151 $ 50.06 February -March 2021 (closed) NYMEX WTI 201 51.29 April - June 2021 (closed) NYMEX WTI 150 51.68 July -September 2021 (closed) NYMEX WTI 150 52.71 January 2022 (closed) NYMEX WTI 140 65.58 February - March 2022 NYMEX WTI 140 65.58 April - June 2022 NYMEX WTI 140 65.62 July - September 2022 NYMEX WTI 140 65.59 October - December 2022 NYMEX WTI 140 65.68 January - March 2023 NYMEX WTI 150 67.92 April - June 2023 NYMEX WTI 120 67.79 July - September 2023 NYMEX WTI 100 70.15 October - December 2023 NYMEX WTI 69 69.41 Crude Oil Basis Swap Contracts Contracts Sold Weighted Average Price Volume Differential Period Settlement Index (MBbld) ($/Bbl) NYMEX WTI Roll Differential February 2021 (closed) (1) 30 $ 0.11 March - December 2021 NYMEX WTI Roll Differential (closed) (1) 125 0.17 January - February 2022 NYMEX WTI Roll Differential (closed) (1) 125 0.15 NYMEX WTI Roll Differential March - December 2022 (1) 125 0.15
(1) This settlement index is used to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month.
47
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NGL Financial Price Swap Contracts
Contracts Sold
Volume Weighted Average Price
Period Settlement Index (MBbld) ($/Bbl)
January - December 2021
(closed) Mont Belvieu Propane (non-Tet) 15 $ 29.44
Natural GasFinancial Price Swap Contracts
Contracts Sold Contracts Purchased
Volume
(MMBtud in Weighted Average Volume (MMBtud in Weighted Average
Period Settlement Index thousands) Price ($/MMBtu) thousands) Price ($/MMBtu)
January - March 2021
(closed) NYMEX Henry Hub 500 $ 2.99 500 $ 2.43
April - September 2021
(closed) NYMEX Henry Hub 500 2.99 570 2.81
October - December 2021
(closed) NYMEX Henry Hub 500 2.99 500 2.83
January - December 2022
(closed) (1) NYMEX Henry Hub 20 2.75 - -
January - February 2022
(closed) NYMEX Henry Hub 725 3.57 - -
March - December 2022 NYMEX Henry Hub 725 3.57 - -
January - December 2023 NYMEX Henry Hub 725 3.18 - -
January - December 2024 NYMEX Henry Hub 725 3.07 - -
January - December 2025 NYMEX Henry Hub 725 3.07 - -
April - September 2021
(closed) Japan Korea Marker (JKM) 70 6.65 - -
(1) In January 2021 , EOG executed the early termination provision granting EOG
the right to terminate all of its 2022 natural gas price swap contracts which
were open at that time. EOG received net cash of $0.6 million for the settlement
of these contracts.
Natural Gas Basis Swap Contracts
Contracts Sold
Volume Weighted Average Price
Period Settlement Index (MMBtud in thousands) ($/MMBtu)
January - February 2022 NYMEX Henry Hub Houston Ship
(closed) Channel (HSC) Differential (1) 210 $ (0.01)
March - December 2022 NYMEX Henry Hub HSC
Differential (1) 210 (0.01)
January - December 2023 NYMEX Henry Hub HSC
Differential (1) 135 (0.01)
January - December 2024 NYMEX Henry Hub HSC
Differential (1) 10 0.00
January - December 2025 NYMEX Henry Hub HSC
Differential (1) 10 0.00
(1) This settlement index is used to fix the differential between pricing at the Houston Ship Channel and NYMEX Henry Hub prices.
48
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In connection with its financial commodity derivative contracts, EOG had $1.4
billion of collateral posted at February 18, 2022 . EOG expects this collateral
to be applied to the settlement of financial commodity derivative contracts if
market prices remain above contract prices or returned to EOG if market prices
decrease below contract prices.
Financing
EOG's debt-to-total capitalization ratio was 19% atDecember 31, 2021 , compared to 22% atDecember 31, 2020 . As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity. AtDecember 31, 2021 and 2020, respectively, EOG had outstanding$4,890 million and$5,640 million aggregate principal amount of senior notes which had estimated fair values of$5,577 million and$6,505 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 2021, EOG funded its capital program and operations primarily by utilizing cash provided by operating activities, cash on hand 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 2021 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.
Foreign Currency Exchange Rate Risk
During 2021, EOG was exposed to foreign currency exchange rate risk inherent in its operations in foreign countries, includingTrinidad ,Australia ,Oman ,Canada and, throughMay 2021 , inChina . 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.
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 economic and political environment, worldwide supplies of, and demand for, crude oil and condensate, NGLs and natural gas, the availabilities of other 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 2022 will impact the amount of cash generated from EOG's operating activities, which will in turn impact EOG's financial position. As ofFebruary 18, 2022 , the average 2022 NYMEX crude oil and natural gas prices were$84.45 per barrel and$4.61 per MMBtu, respectively, representing an increase of 24% for crude oil and an increase of 20% for natural gas from the average NYMEX prices in 2021. See ITEM 1A, Risk Factors for additional discussion of the impact of commodity prices (including fluctuations in commodity prices) on our financial condition, cash flows and results of operations. 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 2022 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$107 million for net income and$138 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 2022 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$15 million for net income and$19 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, 2022 , see "Commodity Derivative Transactions" above. 49 -------------------------------------------------------------------------------- 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 drilling activity in itsDelaware Basin ,Eagle Ford oil play,Rocky Mountain area and Dorado gas play 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 offset inflationary pressure through efficiency gains and by locking in certain service costs for drilling and completion activities. In addition, EOG expects to spend a portion of its anticipated 2022 capital expenditures on leasing acreage, evaluating new prospects, long-term transportation infrastructure and environmental projects. The total anticipated 2022 capital expenditures of approximately$4.3 billion to$4.7 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$2.0 billion senior unsecured revolving credit facility and equity and debt offerings. Operations. In 2022, total crude oil, NGLs and natural gas production is expected to return to prepandemic levels. In 2022, EOG expects to continue to focus on mitigating inflationary pressure on operating costs through efficiency improvements. Cash Requirements. Certain of EOG's capital expenditures and operating expenses are subject to contracts with minimum commitments, including those that meet the definition of a lease under ASU 2016-02. In 2022, EOG anticipates the following cash requirements under these commitments (in millions): Finance Leases (1)$ 42 Operating Leases (1) 262 Leases Effective, Not Commenced (1) 25
Transportation and Storage Service Commitments (2) (3) 961 Purchase and Service Obligations (3)
374
Total Cash Requirements $ 1,664
(1) For more information on contracts that meet the definition of a lease under
ASU 2016-02, see Note 18 to Consolidated Financial Statements.
(2) 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, 2021 . 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.
(3) For more information on transportation and storage service commitments and
purchase and service obligations, see Note 8 to Consolidated Financial
Statements.
In 2022, EOG has no senior notes maturing and expects to pay interest of $191
million on senior notes. For more information on EOG's current and long-term
debt, see Note 2 to Consolidated Financial Statements.
Cash requirements to settle the liability for unrecognized tax benefits, EOG's
pension and postretirement benefit obligations and the liability for
dismantlement, abandonment and asset retirement obligations (see Notes 6, 7, and
15, respectively, to Consolidated Financial Statements) are excluded because
they are subject to estimates and the timing of settlement is unknown.
EOG expects to fund its exploration, development and exploitation activities and
other cash requirements, both in 2022 and in future years, primarily from
internally generated cash flows and cash on hand. As discussed above, 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.
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Summary of Critical Accounting Policies and Estimates
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 and estimates 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 and estimates 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 and estimates. Following is a discussion of EOG's most critical accounting policies and estimates:
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. Proved reserves are estimated using a trailing 12-month average price, in accordance withSEC rules. Crude oil, NGLs and natural gas prices have exhibited significant volatility in the past, and EOG expects that volatility to continue in the future. 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.
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. 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. The concept of sufficient progress is subject to significant judgment and may require further operational actions or require additional approvals from government agencies or partners in oil and gas operations, among other factors, the timing of which may delay management's determinations. See Note 16 to Consolidated Financial Statements.
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.
51
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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.
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 group. 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, 2021 , WTI crude oil spot prices have fluctuated from approximately$(36.98) per barrel to$85.64 per barrel, andHenry Hub natural gas spot prices have ranged from approximately$1.33 per MMBtu to$23.86 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. In the future, if any combination of crude oil prices, NGLs prices, natural gas prices or estimated proved reserves diverge negatively from EOG's current estimates, impairment charges may be necessary.
See Notes 13 and 14 to Consolidated Financial Statements for further disclosures of impairments of oil and gas properties and other assets.
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. See Note 6 to Consolidated Financial
Statements.
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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," "ambition," "initiative,"
"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, achieve, reach or otherwise meet initiatives, plans,
goals, ambitions or targets with respect to emissions, other environmental
matters, safety matters or other ESG (environmental/social/governance) matters,
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 (NGLs), 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, NGLs 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 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 climate change-related regulations, policies and initiatives (for
example, with respect to air emissions); tax laws and regulations (including,
but not limited to, carbon tax legislation); environmental, health and safety
laws and regulations relating to 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;
•the impact of climate change-related policies and initiatives at the corporate
and/or investor community levels and other potential developments related to
climate change, such as (but not limited to) changes in consumer and
industrial/commercial behavior, preferences and attitudes with respect to the
generation and consumption of energy; increased availability of, and increased
consumer and industrial/commercial demand for, competing energy sources
(including alternative energy sources); technological advances with respect to
the generation, transmission, storage and consumption of energy; alternative
fuel requirements; energy conservation measures; decreased demand for, and
availability of, services and facilities related to the exploration for, and
production of, crude oil, NGLs and natural gas; and negative perceptions of the
oil and gas industry and, in turn, reputational risks associated with the
exploration for, and production of, crude oil, NGLs and natural gas;
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•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, economically and in compliance with applicable laws and regulations; •competition in the oil and gas exploration and production industry for the acquisition of licenses, leases and properties; •the availability and cost of, and competition in the oil and gas exploration and production industry for, 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; •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 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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