Overview
EOG Resources, Inc., together with its subsidiaries (collectively, EOG), is one
of the largest independent (non-integrated) crude oil and natural gas companies
in the United States with proved reserves in the United States and Trinidad. 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.
Recent Developments. 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,
natural gas liquids (NGLs) and natural gas. The effects of COVID-19 mitigation
efforts, including the wide availability of vaccines, tempered by new
developments such as emerging COVID-19 variant strains, have resulted in overall
increased demand for crude oil and condensate. See ITEM 1A, Risk Factors, of our
Annual Report on Form 10-K for the fiscal year ended December 31, 2020, filed on
February 25, 2021 (Annual Report), for further discussion.
In early 2021, the members of the Organization of Petroleum Exporting Countries
and Russia (OPEC+) met and agreed to taper off certain of their production
curtailments (agreed to in April 2020) through March 2021. In subsequent
meetings, OPEC+ indicated it would continue to ease production curtailments,
incrementally adding supply (i) as the overall intensity of the COVID-19
pandemic subsides and containment measures are scaled back and (ii) in response
to expected increases in demand for crude oil production in the second half of
2021. OPEC+ indicated that it would return to its pre-pandemic production levels
by mid-to late-2022.
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 continuing actions taken by OPEC+, have had a
positive impact on crude oil prices in the first six months of 2021. Prices for
crude oil and condensate and NGLs returned to pre-pandemic levels in the first
quarter of 2021, while natural gas prices recovered at the beginning of 2021.
We will continue to monitor and assess the COVID-19 pandemic and its effect on
crude oil demand, the actions of OPEC+ and their effect on crude oil supply, as
well as any executive orders or legislative or regulatory actions that could
impact the oil and gas industry, to determine the impact on our business and
operations, and take appropriate actions where necessary. For related
discussion, see ITEM 1, Business - Regulation, ITEM 1A, Risk Factors and ITEM 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operations - Overview, of our Annual Report.
Commodity Prices. Prices for crude oil and condensate, NGLs and natural gas have
historically been volatile. This volatility is expected to continue due to the
many uncertainties associated with the world political and economic environment
and the global supply of, and demand for, crude oil, NGLs and natural gas and
the availability of other energy supplies, the relative competitive
relationships of the various energy sources in the view of consumers and other
factors.
The market prices of crude oil and condensate, NGLs and natural gas impact the
amount of cash generated from EOG's operating activities, which, in turn, impact
EOG's financial position and results of operations.
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For the first six months of 2021, the average U.S. New York Mercantile Exchange
(NYMEX) crude oil and natural gas prices were $61.95 per barrel and $2.76 per
million British thermal units (MMBtu), respectively, representing increases of
68% and 49%, respectively, from the average NYMEX prices for the same period
in 2020. Market prices for NGLs are influenced by the components extracted,
including ethane, propane and butane and natural gasoline, among others, and the
respective market pricing for each component. In February 2021, EOG realized
higher-than-average daily prices on certain days for deliveries of natural gas
volumes due to disruptions throughout the United States from Winter Storm Uri.
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 the first six months of 2021, EOG continued to focus on increasing
drilling, completion and operating efficiencies gained in prior years. Such
efficiencies, combined with new innovation, resulted in lower drilling and
completion costs. Winter Storm Uri negatively impacted Lease and Well,
Transportation and Gathering and Processing Costs in the first quarter of 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 the 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% of EOG's United States
production during the first six months of 2021 and 2020, respectively. During
the first six months of 2021, EOG's drilling and completion activities occurred
primarily in the Delaware Basin play, Eagle Ford play and Rocky Mountain area.
EOG's major producing areas in the United States are in New Mexico and Texas.
EOG faced interruptions to sales in certain markets due to disruptions
throughout the United States from Winter Storm Uri in the first quarter of 2021.
Trinidad. In 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
the National Gas Company of Trinidad and Tobago Limited and its subsidiary, and
crude oil and condensate which is sold to Heritage Petroleum Company Limited
(Heritage).
In March 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 of Trinidad. EOG is currently planning and preparing to
drill one net exploratory well in the second half of 2021. 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.
Other International. In the Sultanate of Oman, a Royal Decree was issued on
March 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 gross exploratory well. The
results are currently being evaluated. EOG expects to drill two net exploratory
wells in Block 36 in the second half of 2021.
In Australia, on April 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
offshore Western Australia. The purchase and sale agreement is subject to
customary closing conditions and is expected to close in the second half of
2021.
In the Sichuan Basin, Sichuan Province, China, EOG worked with its partner,
PetroChina, under a production sharing contract and other related agreements, to
ensure uninterrupted production. All natural gas produced from the Baijaochang
Field was sold under a long-term contract to PetroChina.
In May 2021, EOG closed the sale of its subsidiary which held all of its assets
in China. Net production was approximately 25 million cubic feet per day (MMcfd)
of natural gas. EOG no longer has any operations or assets in China.
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.
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2021 Capital and Operating Plan. Total anticipated 2021 capital expenditures are
estimated to range from approximately $3.7 billion to $4.1 billion, including
facilities and gathering, processing and other expenditures, and excluding
acquisitions and non-cash transactions. EOG plans to continue to focus a
substantial portion of its exploration and development expenditures in its major
producing areas in the United States. In particular, EOG will be focused on
United States crude oil drilling activity in its Delaware Basin play, Eagle Ford
play and Rocky 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, new innovation and initiatives to manage procurement and service costs.
In addition, EOG expects to spend a portion of its anticipated 2021 capital
expenditures on leasing acreage and evaluating new prospects.
In 2021, total crude oil production is expected to remain at fourth quarter 2020
levels. Further, EOG expects to continue to focus on reducing operating costs in
2021 through efficiency improvements.
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.
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 20% at June 30, 2021 and 22% at December 31, 2020. As
used in this calculation, total capitalization represents the sum of total
current and long-term debt and total stockholders' equity.
On February 1, 2021, EOG repaid upon maturity the $750 million aggregate
principal amount of its 4.100% Senior Notes due 2021.
At June 30, 2021, EOG maintained a strong financial and liquidity position,
including $3.9 billion of cash and cash equivalents on hand and $2.0 billion of
availability under its senior unsecured revolving credit facility.
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.
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Results of Operations
The following review of operations for the three months ended June 30, 2021 and
2020 should be read in conjunction with the Condensed Consolidated Financial
Statements of EOG and notes thereto included in this Quarterly Report on Form
10-Q.
Three Months Ended June 30, 2021 vs. Three Months Ended June 30, 2020
Operating Revenues and Other. During the second quarter of 2021, operating
revenues increased $3,036 million, or 275%, to $4,139 million from $1,103
million for the same period of 2020. Total wellhead revenues, which are revenues
generated from sales of EOG's production of crude oil and condensate, NGLs and
natural gas, for the second quarter of 2021 increased $2,621 million, or 309%,
to $3,470 million from $849 million for the same period of 2020. EOG recognized
net losses on the mark-to-market of financial commodity derivative contracts of
$427 million for the second quarter of 2021 compared to net losses of $127
million for the same period of 2020. Gathering, processing and marketing
revenues for the second quarter of 2021 increased $660 million, or 182%, to
$1,022 million from $362 million for the same period of 2020. Net gains on asset
dispositions were $51 million for the second quarter of 2021 compared to net
gains of $14 million for the same period of 2020.
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Wellhead volume and price statistics for the three-month periods ended June 30,
2021 and 2020 were as follows:
Three Months Ended
June 30,
2021 2020
Crude Oil and Condensate Volumes (MBbld) (1)
United States 446.9 330.9
Trinidad 1.7 0.1
Other International (2) - 0.1
Total 448.6 331.1
Average Crude Oil and Condensate Prices ($/Bbl) (3)
United States
$ 66.16 $ 20.40
Trinidad 56.26 0.60
Other International (2) 55.56 48.78
Composite 66.12 20.40
Natural Gas Liquids Volumes (MBbld) (1)
United States 138.5 101.2
Total 138.5 101.2
Average Natural Gas Liquids Prices ($/Bbl) (3)
United States $ 29.15 $ 10.20
Composite 29.15 10.20
Natural Gas Volumes (MMcfd) (1)
United States 1,199 939
Trinidad 233 174
Other International (2) 13 34
Total 1,445 1,147
Average Natural Gas Prices ($/Mcf) (3)
United States $ 2.99 $ 1.11
Trinidad 3.37 2.13
Other International (2) 5.69 4.36
Composite 3.07 1.36
Crude Oil Equivalent Volumes (MBoed) (4)
United States 785.2 588.5
Trinidad 40.6 29.2
Other International (2) 2.2 5.7
Total 828.0 623.4
Total MMBoe (4) 75.3 56.7
(1)Thousand barrels per day or million cubic feet per day, as applicable.
(2)Other International includes EOG's China and Canada operations. The China
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 the
Condensed 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.
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Wellhead crude oil and condensate revenues for the second quarter of 2021
increased $2,084 million, or 339%, to $2,699 million from $615 million for the
same period of 2020. The increase was due to a higher composite average price
($1,866 million) and an increase of 118 MBbld, or 35%, in wellhead crude oil and
condensate production ($218 million). Increased production was primarily due to
increases in the Permian Basin, the Rocky Mountain area and the Eagle Ford.
EOG's composite wellhead crude oil and condensate price for the second quarter
of 2021 increased 224% to $66.12 per barrel compared to $20.40 per barrel for
the same period of 2020.
NGL revenues for the second quarter of 2021 increased $274 million, or 295%, to
$367 million from $93 million for the same period of 2020 due to a higher
composite average price ($239 million) and an increase of 37 MBbld, or 37%, in
NGL deliveries ($35 million). Increased production was primarily due to
increases in the Permian Basin and the Rocky Mountain area. EOG's composite NGL
price for the second quarter of 2021 increased 186% to $29.15 per barrel
compared to $10.20 per barrel for the same period of 2020.
Wellhead natural gas revenues for the second quarter of 2021 increased $263
million, or 187%, to $404 million from $141 million for the same period of 2020.
The increase was due to a higher average composite price ($227 million) and an
increase in natural gas deliveries ($36 million). Natural gas deliveries for the
second quarter of 2021 increased 298 MMcfd, or 26%, compared to the same period
of 2020 due primarily to increased production of associated natural gas from the
Permian Basin and higher natural gas volumes in the Rocky Mountain area and
Trinidad, partially offset by lower natural gas volumes associated with the
disposition of the Marcellus Shale assets in the third quarter of 2020 and lower
deliveries in South Texas. EOG's composite wellhead natural gas price for the
second quarter of 2021 increased 126% to $3.07 per Mcf compared to $1.36 per Mcf
for the same period of 2020.
During the second quarter of 2021, EOG recognized net losses on the
mark-to-market of financial commodity derivative contracts of $427 million
compared to net losses of $127 million for the same period of 2020. During the
second quarter of 2021, net cash paid for settlements of financial commodity
derivative contracts was $193 million compared to net cash received from
settlements of financial commodity derivative contracts of $640 million for the
same period of 2020.
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 for the second
quarter of 2021 increased $113 million as compared to the same period of 2020
primarily due to higher margins on crude oil marketing activities. The margin on
crude oil marketing activities for the second quarter of 2020 was negatively
impacted by EOG's decision early in the second quarter of 2020 to reduce
commodity price volatility by selling May and June 2020 deliveries under fixed
price arrangements.
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Operating and Other Expenses. For the second quarter of 2021, operating
expenses of $2,968 million were $778 million higher than the $2,190 million
incurred during the second quarter of 2020. The following table presents the
costs per barrel of oil equivalent (Boe) for the three-month periods ended June
30, 2021 and 2020:
Three Months Ended
June 30,
2021 2020
Lease and Well $ 3.58 $ 4.32
Transportation Costs 2.84 2.67
Gathering and Processing Costs 1.70 1.71
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties 11.63 11.84
Other Property, Plant and Equipment 0.50 0.62
General and Administrative (G&A) 1.59 2.32
Interest Expense, Net 0.60 0.96
Total (1) $ 22.44 $ 24.44
(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 the three months ended June 30, 2021, compared to the same
period of 2020, are set forth below. See "Operating Revenues and Other" above
for a discussion of wellhead 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 $270 million for the second quarter of 2021 increased
$25 million from $245 million for the same prior year period primarily due to
increased workover expenditures ($18 million) and increased operating and
maintenance costs ($8 million), both in the United States. Lease and well
expenses increased in the United States primarily due to increased operating
activities resulting in 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 $214 million for the second quarter of 2021 increased
$62 million from $152 million for the same prior year period primarily due to
increased transportation costs related to production from the Permian Basin ($52
million) and the Rocky Mountain area ($9 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 NGL fractionation fees
paid to third parties. EOG pays third parties to process the majority of its
natural gas production to extract NGLs.
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Gathering and processing costs increased $31 million to $128 million for the
second quarter of 2021 compared to $97 million for the same prior year period
primarily due to increased gathering and processing fees related to production
from the Permian Basin ($14 million), the Rocky Mountain area ($8 million) and
the Eagle Ford ($4 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 for the second quarter of 2021 increased $207 million to $914
million from $707 million for the same prior year period. DD&A expenses
associated with oil and gas properties for the second quarter of 2021 were $205
million higher than the same prior year period. The increase primarily reflects
increased production in the United States ($215 million) and in Trinidad ($5
million) and higher unit rates in Trinidad ($8 million); partially offset by
lower unit rates in the United States ($20 million). Unit rates in the United
States decreased primarily due to reserves added at lower costs as a result of
increased efficiencies.
G&A expenses of $120 million for the second quarter of 2021 decreased $12
million from $132 million for the same prior year period primarily due to
decreased idle equipment and termination fees ($26 million), partially offset by
increased employee-related costs ($5 million) and professional and legal
services ($3 million).
Interest expense, net of $45 million for the second quarter of 2021 decreased $9
million compared to the same prior year period primarily due to repayment in
February 2021 of the $750 million aggregate principal amount of 4.100% Senior
Notes due 2021 ($8 million) and repayment in June 2020 of the $500 million
aggregate principal amount of 4.40% Senior Notes due 2020 ($4 million).
Exploration costs of $35 million for the second quarter of 2021 increased $8
million from $27 million for the same prior year period due primarily to
increased geological and geophysical expenditures in the United States.
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 the Financial
Accounting Standards Board's Accounting Standards Codification. In certain
instances, EOG utilizes accepted offers from third-party purchasers as the basis
for determining fair value.
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The following table represents impairments for the second quarter of 2021 and
2020 (in millions):
Three Months Ended
June 30,
2021 2020
Proved properties $ - $ 26
Unproved properties 43 60
Other assets - 219
Firm commitment contracts 1 -
Total $ 44 $ 305Impairments of other property, plant and equipment in the second quarter of 2020
were primarily related to the write-down to fair value of sand and crude-by-rail
assets in the United States.
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 for the second quarter of 2021 increased $158 million to
$239 million (6.9% of wellhead revenues) from $81 million (9.4% of wellhead
revenues) for the same prior year period. The increase in taxes other than
income was primarily due to increased severance/production taxes in the United
States.
EOG recognized an income tax provision of $217 million for the second quarter of
2021 compared to an income tax benefit of $235 million for the second quarter of
2020, primarily due to increased pretax income. The net effective tax rate for
the second quarter of 2021 decreased to 19% from 21% for the second quarter of
2020, mostly due to certain tax benefits related to EOG's exiting of its
Canadian operations.
Six Months Ended June 30, 2021 vs. Six Months Ended June 30, 2020
Operating Revenues. During the first six months of 2021, operating revenues
increased $2,012 million, or 35%, to $7,833 million from $5,821 million for the
same period of 2020. Total wellhead revenues for the first six months of 2021
increased $3,375 million, or 103%, to $6,660 million from $3,285 million for the
same period of 2020. During the first six months of 2021, EOG recognized net
losses on the mark-to-market of financial commodity derivative contracts of $794
million compared to net gains of $1,079 million for the same period of 2020.
Gathering, processing and marketing revenues for the first six months of 2021
increased $469 million, or 33%, to $1,870 million from $1,401 million for the
same period of 2020. Net gains on asset dispositions were $45 million for the
first six months of 2021 compared to net gains of $30 million for the same
period of 2020.
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Wellhead volume and price statistics for the six-month periods ended June 30,
2021 and 2020 were as follows:
Six Months Ended
June 30,
2021 2020
Crude Oil and Condensate Volumes (MBbld)
United States 437.8 406.8
Trinidad 2.0 0.3
Other International - 0.1
Total 439.8 407.2
Average Crude Oil and Condensate Prices ($/Bbl) (1)
United States
$ 62.22 $ 36.17
Trinidad 52.57 27.75
Other International 42.36 53.41
Composite 62.18 36.16
Natural Gas Liquids Volumes (MBbld)
United States 131.5 131.2
Total 131.5 131.2
Average Natural Gas Liquids Prices ($/Bbl) (1)
United States $ 28.62 $ 10.65
Composite 28.62 10.65
Natural Gas Volumes (MMcfd)
United States 1,150 1,039
Trinidad 225 188
Other International 19 35
Total 1,394 1,262
Average Natural Gas Prices ($/Mcf) (1)
United States $ 4.19 $ 1.32
Trinidad 3.37 2.15
Other International 5.67 4.34
Composite 4.08 1.53
Crude Oil Equivalent Volumes (MBoed)
United States 761.0 711.1
Trinidad 39.5 31.6
Other International 3.1 6.1
Total 803.6 748.8
Total MMBoe 145.4 136.3
(1) Excludes the impact of financial commodity derivative instruments (see Note
12 to the Condensed Consolidated Financial Statements).
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Wellhead crude oil and condensate revenues for the first six months of 2021
increased $2,270 million, or 85%, to $4,950 million from $2,680 million for the
same period of 2020 due to a higher composite average price ($2,071 million) and
an increase of 33 MBbld, or 8%, in wellhead crude oil and condensate production
($199 million). Increased production was primarily due to increases in the
Permian Basin and the Rocky Mountain area, partially offset by decreased
production in the Eagle Ford. EOG's composite wellhead crude oil and condensate
price for the first six months of 2021 increased 72% to $62.18 per barrel
compared to $36.16 per barrel for the same period of 2020.
NGL revenues for the first six months of 2021 increased $427 million, or 168%,
to $681 million from $254 million for the same period of 2020 due to a higher
composite average price. EOG's composite NGL price for the first six months of
2021 increased 169% to $28.62 per barrel compared to $10.65 per barrel for the
same period of 2020.
Wellhead natural gas revenues for the first six months of 2021 increased $678
million, or 193%, to $1,029 million from $351 million for the same period of
2020. The increase was due to a higher composite wellhead natural gas price
($644 million) and an increase in natural gas deliveries ($34 million). Natural
gas deliveries for the first six months of 2021 increased 132 MMcfd, or 10%,
compared to the same period of 2020 due primarily to increased production of
associated natural gas from the Permian Basin and higher natural gas volumes in
Trinidad and the Rocky Mountain area, partially offset by lower natural gas
volumes associated with the disposition of the Marcellus Shale assets in the
third quarter of 2020 and lower deliveries in South Texas. EOG's composite
wellhead natural gas price for the first six months of 2021 increased 167% to
$4.08 per Mcf compared to $1.53 per Mcf for the same period of 2020.
During the first six months of 2021, EOG recognized net losses on the
mark-to-market of financial commodity derivative contracts of $794 million
compared to net gains of $1,079 million for the same period of 2020. During the
first six months of 2021, net cash paid for settlements of financial commodity
derivative contracts was $223 million compared to net cash received from
settlements of financial commodity derivative contracts of $724 million for the
same period of 2020.
Gathering, processing and marketing revenues less marketing costs for the first
six months of 2021 increased $194 million as compared to the same period of 2020
primarily due to higher margins on crude oil marketing activities, partially
offset by lower margins on natural gas marketing activities. The margin on crude
oil marketing activities for the first six months of 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 and June 2020 deliveries under fixed
price arrangements.
Operating and Other Expenses. For the first six months of 2021, operating
expenses of $5,730 million were $1,120 million lower than the $6,850 million
incurred during the same period of 2020. The following table presents the costs
per Boe for the six-month periods ended June 30, 2021 and 2020:
Six Months Ended
June 30,
2021 2020
Lease and Well $ 3.71 $ 4.22
Transportation Costs 2.86 2.64
Gathering and Processing Costs 1.84 1.65
DD&A -
Oil and Gas Properties 11.96 12.03
Other Property, Plant and Equipment 0.51 0.49
G&A 1.58 1.81
Interest Expense, Net 0.63 0.73
Total (1) $ 23.09 $ 23.57(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 the six months ended June 30, 2021, compared to the same
period of 2020 are set forth below. See "Operating Revenues" above for a
discussion of wellhead volumes.
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Lease and well expenses of $540 million for the first six months of 2021
decreased $35 million from $575 million for the same prior year period primarily
due to decreased operating and maintenance costs in the United States ($22
million) and Canada ($5 million) and decreased lease and well administrative
expenses in the United States ($8 million).
Transportation costs of $416 million for the first six months of 2021 increased
$56 million from $360 million for the same prior year period primarily due to
increased transportation costs related to production from the Permian Basin ($62
million) and the Rocky Mountain area ($7 million), partially offset by decreased
transportation costs related to production from the Eagle Ford ($10 million).
Gathering and processing costs of $267 million for the first six months of 2021
increased $42 million compared to the same prior year period primarily due to
increased gathering and processing fees related to production from the Permian
Basin ($17 million) and the Rocky Mountain area ($10 million) and increased
operating and maintenance expenses related to production from the Rocky Mountain
area ($5 million) and the Permian Basin ($5 million).
DD&A expenses for the first six months of 2021 increased $107 million to $1,814
million from $1,707 million for the same prior year period. DD&A expenses
associated with oil and gas properties for the first six months of 2021 were $99
million higher than the same prior year period. The increase primarily reflects
increased production in the United States ($102 million) and in Trinidad ($7
million) and higher unit rates in Trinidad ($10 million), partially offset by
lower unit rates in the United States ($16 million). Unit rates in the United
States decreased primarily due to reserves added at lower costs as a result of
increased efficiencies. DD&A expenses associated with other property, plant and
equipment for the first six months of 2021 were $8 million higher than the same
prior year period primarily due to an increase in expense related to storage
assets.
G&A expenses of $230 million for the first six months of 2021 decreased $16
million from $246 million for the same prior year period primarily due to
decreased idle equipment and termination fees.
Interest expense, net of $92 million for the first six months of 2021 decreased
$7 million compared to the same prior year period primarily due to repayment in
February 2021 of the $750 million aggregate principal amount of 4.100% Senior
Notes due 2021 ($13 million), repayment in June 2020 of the $500 million
aggregate principal amount of 4.40% Senior Notes due 2020 ($9 million) and
repayment in April 2020 of the $500 million aggregate principal amount of 2.45%
Senior Notes due 2020 ($3 million), partially offset by the issuance in April
2020 of the $750 million aggregate principal amount of 4.950% Senior Notes due
2050 ($11 million) and issuance in April 2020 of the $750 million aggregate
principal amount of 4.375% Senior Notes due 2030 ($10 million).
The following table represents impairments for the six-month periods ended June
30, 2021 and 2020 (in millions):
Six Months Ended
June 30,
2021 2020
Proved properties $ - $ 1,411
Unproved properties 86 117
Other assets - 290
Firm commitment contracts 2 60
Total $ 88 $ 1,878Impairments of proved properties in the first six months of 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 in the United States. Impairments of other assets in the first six months
of 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 the first six months of 2020 were a
result of the decision to exit the Horn River Basin in Canada.
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Taxes other than income for the first six months of 2021 increased $216 million
to $454 million (6.8% of wellhead revenues) from $238 million (7.2% of wellhead
revenues) for the same prior year period. The increase in taxes other than
income was primarily due to increased severance/production taxes ($205 million)
and decreased state severance tax refunds ($12 million), all in the United
States.
Other income (expense), net for the first six months of 2021 increased $20
million compared to the same prior year period primarily due to an increase in
deferred compensation expense ($18 million) and decreased interest income ($7
million), partially offset by higher equity income from ammonia plants in
Trinidad ($5 million).
EOG recognized an income tax provision of $421 million for the first six months
of 2021 compared to an income tax benefit of $214 million for the first six
months of 2020, primarily due to increased pretax income. The net effective tax
rate for the first six months of 2021 increased to 21% from 19% in the first six
months of 2020. The higher effective tax rate is mostly due to taxes
attributable to EOG's foreign operations.
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Capital Resources and Liquidity
Cash Flow. The primary sources of cash for EOG during the six months ended June
30, 2021, were funds generated from operations and proceeds from sales of
assets. The primary uses of cash were funds used in operations; exploration and
development expenditures; long-term debt repayments; dividend payments to
stockholders; net cash paid for settlements of commodity derivative contracts
and other property, plant and equipment expenditures. During the first six
months of 2021, EOG's cash balance increased $551 million to $3,880 million from
$3,329 million at December 31, 2020.
Net cash provided by operating activities of $3,429 million for the first six
months of 2021 increased $756 million compared to the same period of 2020
primarily due to an increase in wellhead revenues ($3,375 million) and an
increase in gathering, processing and marketing revenues less marketing costs
($194 million), partially offset by net cash used in working capital in the
first six months of 2021 ($621 million) compared to net cash provided by working
capital in the first six months of 2020 ($552 million), an increase in net cash
paid for settlements of financial commodity derivative contracts ($947 million),
an unfavorable change in net cash paid for income taxes ($583 million) and an
increase in cash operating expenses ($265 million).
Net cash used in investing activities of $1,649 million for the first six months
of 2021 decreased $727 million compared to the same period of 2020 due to net
cash provided by working capital associated with investing activities in the
first six months of 2021 ($145 million) compared to net cash used in working
capital associated with investing activities in the first six months of 2020
($282 million), a decrease in additions to oil and gas properties ($147
million), an increase in proceeds from the sale of assets ($103 million) and a
decrease in additions to other property, plant and equipment ($50 million).
Net cash used in financing activities of $1,229 million for the first six months
of 2021 included repayments of long-term debt ($750 million), cash dividend
payments ($458 million) and repayment of finance lease liabilities ($18
million). Net cash provided by financing activities of $92 million for the first
six months of 2020 included net proceeds from the issuance of long-term debt
($1,484 million). Net cash used in financing activities for the first six months
of 2020 included repayments of long-term debt ($1,000 million) and cash dividend
payments ($384 million).
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Total Expenditures. For the year 2021, EOG's updated budget for exploration and
development and other property, plant and equipment expenditures is estimated to
range from approximately $3.7 billion to $4.1 billion, excluding acquisitions
and non-cash transactions. The table below sets out components of total
expenditures for the six-month periods ended June 30, 2021 and 2020 (in
millions):
Six Months Ended
June 30,
2021 2020
Expenditure Category
Capital
Exploration and Development Drilling $ 1,444 $ 1,694
Facilities 187 210
Leasehold Acquisitions (1) 104 75
Property Acquisitions (2) 95 51
Capitalized Interest 15 17
Subtotal 1,845 2,047
Exploration Costs 68 67
Dry Hole Costs 24 -
Exploration and Development Expenditures 1,937 2,114
Asset Retirement Costs 48 25
Total Exploration and Development Expenditures 1,985 2,139
Other Property, Plant and Equipment (3)
171 221
Total Expenditures $ 2,156 $ 2,360
(1) Leasehold acquisitions included $22 million and $48 million for the
six-month periods ended June 30, 2021 and 2020, respectively, related to
non-cash property exchanges.
(2) Property acquisitions included $3 million and $7 million for the six-month
periods ended June 30, 2021 and 2020, respectively, related to non-cash property
exchanges.
(3) Other property, plant and equipment included $74 million and $73 million of
non-cash additions for the six-month periods ended June 30, 2021 and 2020,
respectively, primarily related to finance lease transactions for storage
facilities.
Exploration and development expenditures of $1,937 million for the first six
months of 2021 were $177 million lower than the same period of 2020 primarily
due to decreased exploration and development drilling expenditures in the United
States ($242 million) and Trinidad ($16 million) and decreased facilities
expenditures ($23 million), partially offset by increased property acquisitions
($44 million), increased leasehold acquisitions ($29 million) and increased
exploration and development expenditures in Other International ($8 million).
Exploration and development expenditures for the first six months of 2021 of
$1,937 million consisted of $1,630 million in development drilling and
facilities, $197 million in exploration, $95 million in property acquisitions
and $15 million in capitalized interest. Exploration and development
expenditures for the first six months of 2020 of $2,114 million consisted of
$1,840 million in development drilling and facilities, $206 million in
exploration, $51 million in property acquisitions and $17 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.
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Commodity Derivative Transactions. As more fully discussed in Note 12 to the
Consolidated Financial Statements included in EOG's Annual Report on Form 10-K
for the year ended December 31, 2020, filed on February 25, 2021, EOG engages in
price risk management activities from time to time. These activities are
intended to manage EOG's exposure to fluctuations in commodity prices for crude
oil, NGLs and natural gas. EOG utilizes financial commodity derivative
instruments, primarily price swap, option, swaption, collar and basis swap
contracts, as a means to manage this price risk. EOG has not designated any of
its financial commodity derivative contracts as accounting hedges and,
accordingly, accounts for financial commodity derivative contracts using the
mark-to-market accounting method. Under this accounting method, changes in the
fair value of outstanding financial instruments are recognized as gains or
losses in the period of change and are recorded as Gains (Losses) on
Mark-to-Market Commodity Derivative Contracts on the Condensed Consolidated
Statements of Income (Loss) and Comprehensive Income (Loss). The related cash
flow impact is reflected in Cash Flows from Operating Activities on the
Condensed Consolidated Statements of Cash Flows.
The total fair value of EOG's commodity derivative contracts was reflected on
the Condensed Consolidated Balance Sheets at June 30, 2021, as a net liability
of $410 million.
Commodity Derivative Contracts. Presented below is a comprehensive summary of
EOG's financial commodity derivative contracts as of July 30, 2021. 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).
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