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. 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, natural gas liquids (NGLs) and natural gas. In response, OPEC+, a
consortium of OPEC (Organization of Petroleum Exporting Countries) and certain
non-OPEC global producers (Russia, Kazakhstan and others), agreed to voluntarily
curtail crude oil supplies beginning in April 2020 with a schedule to bring back
some of these curtailments through April 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, 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. During 2021, OPEC+
has continued amending 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+, have had a
positive impact on crude oil prices in the first nine 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 nine months of 2021, the average U.S. New York Mercantile Exchange
(NYMEX) crude oil and natural gas prices were $64.85 per barrel and $3.18 per
million British thermal units (MMBtu), respectively, representing increases of
69% for both 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 nine 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 nine months of 2021 and 2020, respectively. During
the first nine 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 first half of 2022. 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 in the
first quarter of 2021. The results are currently being evaluated. In Block 36,
where EOG holds a 100% working interest, drilling commenced on one exploratory
well in the third quarter of 2021. EOG plans to drill one additional exploratory
well in Block 36 by the end of 2021.
In Australia, a subsidiary of EOG entered into a purchase and sale agreement in
April 2021 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 fourth quarter 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.
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EOG continues to evaluate other select crude oil and natural gas opportunities
outside the United States, primarily by pursuing exploitation opportunities in
countries where indigenous crude oil and natural gas reserves have been
identified.
2021 Capital and Operating Plan. Total 2021 capital expenditures are estimated
to range from approximately $3.8 billion to $4.0 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 continue to 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 has spent, and expects to continue to spend, a portion of its 2021
capital expenditures on leasing acreage and evaluating new prospects.
Full-year 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 19% at September 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 September 30, 2021, EOG maintained a strong financial and liquidity position,
including $4.3 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.
Dividend Declarations and Share Repurchase Authorization. On November 4, 2021,
EOG's Board (i) 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 to be paid on January 28, 2022, to stockholders of record as of January
14, 2022, (ii) declared a special cash dividend on the common stock of $2.00 per
share, payable on December 30, 2021, to stockholders of record as of December
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 in
September 2001. See Part II, Item 2, Unregistered Sales of Equity Securities and
Use of Proceeds, of this Quarterly Report on Form 10-Q for additional
discussion.
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Results of Operations
The following review of operations for the three months ended September 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 September 30, 2021 vs. Three Months Ended September 30, 2020
Operating Revenues and Other. During the third quarter of 2021, operating
revenues increased $2,519 million, or 112%, to $4,765 million from $2,246
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 third quarter of 2021 increased $2,281 million, or 129%, to
$4,045 million from $1,764 million for the same period of 2020. EOG recognized
net losses on the mark-to-market of financial commodity derivative contracts of
$494 million for the third quarter of 2021 compared to net losses of $4 million
for the same period of 2020. Gathering, processing and marketing revenues for
the third quarter of 2021 increased $647 million, or 120%, to $1,186 million
from $539 million for the same period of 2020. Net gains on asset dispositions
were $1 million for the third quarter of 2021 compared to net losses of $71
million for the same period of 2020.
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Wellhead volume and price statistics for the three-month periods ended September
30, 2021 and 2020 were as follows:
Three Months Ended
September 30,
2021 2020
Crude Oil and Condensate Volumes (MBbld) (1)
United States 448.3 376.6
Trinidad 1.2 1.0
Other International (2) - -
Total 449.5 377.6
Average Crude Oil and Condensate Prices ($/Bbl) (3)
United States
$ 70.88 $ 40.19
Trinidad 60.19 25.41
Other International (2) - 25.29
Composite 70.85 40.15
Natural Gas Liquids Volumes (MBbld) (1)
United States 157.9 140.1
Total 157.9 140.1
Average Natural Gas Liquids Prices ($/Bbl) (3)
United States $ 37.72 $ 14.34
Composite 37.72 14.34
Natural Gas Volumes (MMcfd) (1)
United States 1,210 1,008
Trinidad 212 151
Other International (2) - 31
Total 1,422 1,190
Average Natural Gas Prices ($/Mcf) (3)
United States $ 4.50 $ 1.49
Trinidad 3.39 2.35
Other International (2) - 4.73
Composite 4.34 1.68
Crude Oil Equivalent Volumes (MBoed) (4)
United States 807.9 684.7
Trinidad 36.5 26.2
Other International (2) - 5.1
Total 844.4 716.0
Total MMBoe (4) 77.7 65.9
(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 third quarter of 2021
increased $1,534 million, or 110%, to $2,929 million from $1,395 million for the
same period of 2020. The increase was due to a higher composite average price
($1,266 million) and an increase of 71.9 MBbld, or 19%, in wellhead crude oil
and condensate production ($268 million). Increased production was primarily in
the Permian Basin and the Eagle Ford. EOG's composite wellhead crude oil and
condensate price for the third quarter of 2021 increased 76% to $70.85 per
barrel compared to $40.15 per barrel for the same period of 2020.
NGL revenues for the third quarter of 2021 increased $363 million, or 196%, to
$548 million from $185 million for the same period of 2020 due to a higher
composite average price ($340 million) and an increase of 17.8 MBbld, or 13%, in
NGL deliveries ($23 million). Increased production was primarily in the Permian
Basin. EOG's composite NGL price for the third quarter of 2021 increased 163% to
$37.72 per barrel compared to $14.34 per barrel for the same period of 2020.
Wellhead natural gas revenues for the third quarter of 2021 increased $384
million, or 209%, to $568 million from $184 million for the same period of 2020.
The increase was due to a higher average composite price ($347 million) and an
increase in natural gas deliveries ($37 million). Natural gas deliveries for the
third quarter of 2021 increased 232 MMcfd, or 19%, 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, partially offset by
lower natural gas volumes associated with the disposition of the Marcellus Shale
assets in the third quarter of 2020, lower deliveries in South Texas and lower
natural gas volumes associated with the disposition of the China assets in the
second quarter of 2021. EOG's composite wellhead natural gas price for the third
quarter of 2021 increased 158% to $4.34 per Mcf compared to $1.68 per Mcf for
the same period of 2020.
During the third quarter of 2021, EOG recognized net losses on the
mark-to-market of financial commodity derivative contracts of $494 million
compared to net losses of $4 million for the same period of 2020. During the
third quarter of 2021, net cash paid for settlements of financial commodity
derivative contracts was $293 million compared to net cash received from
settlements of financial commodity derivative contracts of $275 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 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 for the third
quarter of 2021 decreased $14 million as compared to the same period of 2020
primarily due to lower margins on crude oil marketing activities, partially
offset by higher margins on natural gas marketing activities.
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Operating and Other Expenses. For the third quarter of 2021, operating expenses
of $3,294 million were $1,045 million higher than the $2,249 million incurred
during the third quarter of 2020. The following table presents the costs per
barrel of oil equivalent (Boe) for the three-month periods ended September 30,
2021 and 2020:
Three Months Ended
September 30,
2021 2020
Lease and Well $ 3.48 $ 3.45
Transportation Costs 2.82 2.74
Gathering and Processing Costs 1.87 1.74
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties 11.47 12.00
Other Property, Plant and Equipment 0.46 0.49
General and Administrative (G&A) 1.83 1.89
Interest Expense, Net 0.62 0.81
Total (1) $ 22.55 $ 23.12
(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 September 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 third quarter of 2021 increased
$43 million from $227 million for the same prior year period primarily due to
increased operating and maintenance costs in the United States ($19 million),
increased workovers expenditures in the United States ($15 million) and
increased lease and well administrative expenses in the United States ($7
million). 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 $219 million for the third quarter of 2021 increased $39
million from $180 million for the same prior year period primarily due to
increased transportation costs related to production from the Permian Basin ($29
million) and the Rocky Mountain area ($10 million).
Gathering and processing costs represent operating and maintenance expenses and
administrative expenses associated with operating EOG's gathering and processing
assets as well as natural gas processing fees and certain 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 $30 million to $145 million for the
third quarter of 2021 compared to $115 million for the same prior year period
primarily due to increased gathering and processing fees ($14 million) and
operating and maintenance expense ($8 million), both related to production from
the Permian Basin.
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 third quarter of 2021 increased $104 million to $927
million from $823 million for the same prior year period. DD&A expenses
associated with oil and gas properties for the third quarter of 2021 were $100
million higher than the same prior year period. The increase primarily reflects
increased production in the United States ($137 million) and in Trinidad ($5
million), partially offset by lower unit rates in the United States ($39
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 $142 million for the third quarter of 2021 increased $17 million
from $125 million for the same prior year period primarily due to increased
employee-related costs ($20 million) and joint interest billings deemed
uncollectible ($5 million), partially offset by decreased idle equipment and
termination fees ($13 million).
Interest expense, net of $48 million for the third quarter of 2021 decreased $5
million compared to the same prior year period primarily due to the repayment in
February 2021 of the $750 million aggregate principal amount of 4.100% Senior
Notes due 2021 ($8 million), partially offset by interest payments for late
royalty payments on Oklahoma properties ($3 million).
Exploration costs of $44 million for the third quarter of 2021 increased $6
million from $38 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 third quarter of 2021 and
2020 (in millions):
Three Months Ended
September 30,
2021 2020
Proved properties $ 13 $ 26
Unproved properties 69 52
Other assets - 1
Firm commitment contracts - -
Total $ 82 $ 79Taxes 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 third quarter of 2021 increased $151 million to
$277 million (6.8% of wellhead revenues) from $126 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 ($142 million)
and increased ad valorem/property taxes ($5 million), all in the United States.
EOG recognized an income tax provision of $334 million for the third quarter of
2021 compared to an income tax benefit of $11 million for the third quarter of
2020, primarily due to increased pretax income. The net effective tax rate for
the third quarter of 2021 increased to 23% from 19% for the third quarter of
2020, mostly due to stock-based compensation tax deficiencies increasing the
effective tax rate on pretax income in the third quarter of 2021 and decreasing
the effective tax rate on pretax loss in the third quarter of 2020.
Nine Months Ended September 30, 2021 vs. Nine Months Ended September 30, 2020
Operating Revenues. During the first nine months of 2021, operating revenues
increased $4,531 million, or 56%, to $12,598 million from $8,067 million for the
same period of 2020. Total wellhead revenues for the first nine months of 2021
increased $5,656 million, or 112%, to $10,705 million from $5,049 million for
the same period of 2020. During the first nine months of 2021, EOG recognized
net losses on the mark-to-market of financial commodity derivative contracts of
$1,288 million compared to net gains of $1,075 million for the same period of
2020. Gathering, processing and marketing revenues for the first nine months of
2021 increased $1,116 million, or 58%, to $3,056 million from $1,940 million for
the same period of 2020. Net gains on asset dispositions were $46 million for
the first nine months of 2021 compared to net losses of $41 million for the same
period of 2020.
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Wellhead volume and price statistics for the nine-month periods ended September
30, 2021 and 2020 were as follows:
Nine Months Ended
September 30,
2021 2020
Crude Oil and Condensate Volumes (MBbld)
United States 441.3 396.6
Trinidad 1.7 0.5
Other International 0.1 0.2
Total 443.1 397.3
Average Crude Oil and Condensate Prices ($/Bbl) (1)
United States
$ 65.18 $ 37.45
Trinidad 54.33 26.35
Other International 42.36 45.09
Composite 65.14 37.44
Natural Gas Liquids Volumes (MBbld)
United States 140.4 134.2
Total 140.4 134.2
Average Natural Gas Liquids Prices ($/Bbl) (1)
United States $ 32.07 $ 11.95
Composite 32.07 11.95
Natural Gas Volumes (MMcfd)
United States 1,170 1,029
Trinidad 221 175
Other International 12 34
Total 1,403 1,238
Average Natural Gas Prices ($/Mcf) (1)
United States $ 4.30 $ 1.38
Trinidad 3.38 2.20
Other International 5.67 4.45
Composite 4.17 1.58
Crude Oil Equivalent Volumes (MBoed)
United States 776.8 702.3
Trinidad 38.5 29.8
Other International 2.0 5.7
Total 817.3 737.8
Total MMBoe 223.1 202.2
(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 nine months of 2021
increased $3,804 million, or 93%, to $7,879 million from $4,075 million for the
same period of 2020 due to a higher composite average price ($3,348 million) and
an increase of 45.8 MBbld, or 12%, in wellhead crude oil and condensate
production ($456 million). Increased production was primarily in the Permian
Basin, partially offset by decreased production in the Eagle Ford. EOG's
composite wellhead crude oil and condensate price for the first nine months of
2021 increased 74% to $65.14 per barrel compared to $37.44 per barrel for the
same period of 2020.
NGL revenues for the first nine months of 2021 increased $790 million, or 180%,
to $1,229 million from $439 million for the same period of 2020 due to a higher
composite average price ($772 million) and an increase of 6.2 MBbld, or 5%, in
NGL deliveries ($18 million). Increased production was primarily in the Permian
Basin and the Rocky Mountain area, partially offset by decreased production in
the Fort Worth Basin Barnett Shale and the Eagle Ford. EOG's composite NGL price
for the first nine months of 2021 increased 168% to $32.07 per barrel compared
to $11.95 per barrel for the same period of 2020.
Wellhead natural gas revenues for the first nine months of 2021 increased $1,062
million, or 199%, to $1,597 million from $535 million for the same period of
2020. The increase was due to a higher composite wellhead natural gas price
($992 million) and an increase in natural gas deliveries ($70 million). Natural
gas deliveries for the first nine months of 2021 increased 165 MMcfd, or 13%,
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, 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 nine months of 2021 increased 164% to $4.17 per Mcf compared to $1.58 per
Mcf for the same period of 2020.
During the first nine months of 2021, EOG recognized net losses on the
mark-to-market of financial commodity derivative contracts of $1,288 million
compared to net gains of $1,075 million for the same period of 2020. During the
first nine months of 2021, net cash paid for settlements of financial commodity
derivative contracts was $516 million compared to net cash received from
settlements of financial commodity derivative contracts of $999 million for the
same period of 2020.
Gathering, processing and marketing revenues less marketing costs for the first
nine months of 2021 increased $180 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 nine 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 nine months of 2021, operating
expenses of $9,024 million were $75 million lower than the $9,099 million
incurred during the same period of 2020. The following table presents the costs
per Boe for the nine-month periods ended September 30, 2021 and 2020:
Nine Months Ended
September 30,
2021 2020
Lease and Well $ 3.63 $ 3.97
Transportation Costs 2.85 2.67
Gathering and Processing Costs 1.85 1.68
DD&A -
Oil and Gas Properties 11.79 12.02
Other Property, Plant and Equipment 0.49 0.49
G&A 1.67 1.83
Interest Expense, Net 0.63 0.75
Total (1) $ 22.91 $ 23.41(1)Total excludes exploration costs, dry hole costs, impairments, marketing
costs and taxes other than income.
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The primary factors impacting the cost components of per-unit rates of lease and
well, transportation costs, gathering and processing costs, DD&A, and net
interest expense for the nine months ended September 30, 2021, compared to the
same period of 2020 are set forth below. See "Operating Revenues" above for a
discussion of wellhead volumes.
Lease and well expenses of $810 million for the first nine months of 2021
increased $8 million from $802 million for the same prior year period primarily
due to increased workovers expenditures in the United States ($12 million) and
increased operating and maintenance costs in Trinidad ($4 million), partially
offset by decreased operating and maintenance costs in Canada ($6 million) and
the United States ($3 million).
Transportation costs of $635 million for the first nine months of 2021 increased
$95 million from $540 million for the same prior year period primarily due to
increased transportation costs related to production from the Permian Basin ($91
million) and the Rocky Mountain area ($17 million), partially offset by
decreased transportation costs related to production from the Eagle Ford ($7
million).
Gathering and processing costs of $412 million for the first nine months of 2021
increased $72 million compared to the same prior year period primarily due to
increased gathering and processing fees related to production from the Permian
Basin ($31 million) and the Rocky Mountain area ($12 million), increased
operating and maintenance expenses related to production from the Permian Basin
($13 million) and the Rocky Mountain area ($7 million) and increased gathering
and processing general and administrative costs in the United States ($11
million).
DD&A expenses for the first nine months of 2021 increased $211 million to $2,741
million from $2,530 million for the same prior year period. DD&A expenses
associated with oil and gas properties for the first nine months of 2021 were
$199 million higher than the same prior year period. The increase primarily
reflects increased production in the United States ($239 million) and in
Trinidad ($11 million) and higher unit rates in Trinidad ($12 million),
partially offset by lower unit rates in the United States ($55 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 nine months of 2021 were $11 million
higher than the same prior year period primarily due to an increase in expense
related to storage assets.
Interest expense, net of $140 million for the first nine months of 2021
decreased $12 million compared to the same prior year period primarily due to
the repayment in February 2021 of the $750 million aggregate principal amount of
4.100% Senior Notes due 2021 ($21 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).
Exploration costs of $112 million for the first nine months of 2021 increased $7
million from $105 million for the same prior year period due primarily to
increased geological and geophysical expenditures ($9 million), partially offset
by decreased general and administrative expenditures ($5 million), all in the
United States.
The following table represents impairments for the nine-month periods ended
September 30, 2021 and 2020 (in millions):
Nine Months Ended
September 30,
2021 2020
Proved properties $ 13 $ 1,185
Unproved properties 155 421
Other assets - 291
Firm commitment contracts 2 60
Total $ 170 $ 1,957
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Impairments of proved properties in the first nine 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 unproved oil and gas properties
included charges of $252 million in the first nine months of 2020 for certain
leasehold costs that are no longer expected to be developed before expiration.
Impairments of other assets in the first nine 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 nine months of 2020 were a result of the decision to exit
the Horn River Basin in Canada.
Taxes other than income for the first nine months of 2021 increased $367 million
to $731 million (6.8% of wellhead revenues) from $364 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 ($347 million)
and decreased state severance tax refunds ($13 million), all in the United
States, and increased severance/production taxes in Trinidad ($5 million).
Other income, net for the first nine months of 2021 decreased $17 million
compared to the same prior year period primarily due to an increase in deferred
compensation expense ($18 million) and decreased interest income ($8 million),
partially offset by higher equity income from ammonia plants in Trinidad ($11
million).
EOG recognized an income tax provision of $755 million for the first nine months
of 2021 compared to an income tax benefit of $225 million for the first nine
months of 2020, primarily due to increased pretax income. The net effective tax
rate for the first nine months of 2021 increased to 22% from 19% in the first
nine months of 2020. The higher effective tax rate is mostly due to taxes
attributable to EOG's foreign operations.
Capital Resources and Liquidity
Cash Flow. The primary sources of cash for EOG during the nine months ended
September 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; dividend payments to stockholders; long-term debt
repayments; net cash paid for settlements of commodity derivative contracts and
other property, plant and equipment expenditures. During the first nine months
of 2021, EOG's cash balance increased $964 million to $4,293 million from $3,329
million at December 31, 2020.
Net cash provided by operating activities of $5,625 million for the first nine
months of 2021 increased $1,738 million compared to the same period of 2020
primarily due to an increase in wellhead revenues ($5,656 million) and an
increase in gathering, processing and marketing revenues less marketing costs
($180 million), partially offset by an increase in net cash paid for settlements
of financial commodity derivative contracts ($1,515 million), net cash used in
working capital in the first nine months of 2021 ($897 million) compared to net
cash provided by working capital in the first nine months of 2020 ($467
million), an unfavorable change in net cash paid for income taxes ($1,038
million) and an increase in cash operating expenses ($529 million).
Net cash used in investing activities of $2,582 million for the first nine
months of 2021 decreased $129 million compared to the same period of 2020 due to
net cash provided by working capital associated with investing activities in the
first nine months of 2021 ($100 million) compared to net cash used in working
capital associated with investing activities in the first nine months of 2020
($276 million) and a decrease in additions to other property, plant and
equipment ($18 million), partially offset by an increase in additions to oil and
gas properties ($230 million) and a decrease in proceeds from the sale of assets
($35 million).
Net cash used in financing activities of $2,079 million for the first nine
months of 2021 included cash dividend payments ($1,278 million), repayments of
long-term debt ($750 million), purchases of treasury stock in connection with
stock compensation plans ($33 million) and repayment of finance lease
liabilities ($27 million). Net cash used in financing activities of $140 million
for the first nine months of 2020 included repayments of long-term debt ($1,000
million) and cash dividend payments ($601 million), partially offset by net
proceeds from the issuance of long-term debt ($1,484 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 $3.8 billion to $4.0 billion, excluding acquisitions
and non-cash transactions. The table below sets out components of total
expenditures for the nine-month periods ended September 30, 2021 and 2020 (in
millions):
Nine Months Ended
September 30,
2021 2020
Expenditure Category
Capital
Exploration and Development Drilling $ 2,097 $ 2,072
Facilities 287 248
Leasehold Acquisitions (1) 194 163
Property Acquisitions (2) 99 74
Capitalized Interest 24 24
Subtotal 2,701 2,581
Exploration Costs 112 105
Dry Hole Costs 28 13
Exploration and Development Expenditures 2,841 2,699
Asset Retirement Costs 56 69
Total Exploration and Development Expenditures 2,897 2,768
Other Property, Plant and Equipment (3)
221 238
Total Expenditures $ 3,118 $ 3,006
(1) Leasehold acquisitions included $37 million and $128 million for the
nine-month periods ended September 30, 2021 and 2020, respectively, related to
non-cash property exchanges.
(2) Property acquisitions included $4 million and $7 million for the nine-month
periods ended September 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 nine-month periods ended September 30, 2021 and 2020,
respectively, primarily related to finance lease transactions for storage
facilities.
Exploration and development expenditures of $2,841 million for the first nine
months of 2021 were $142 million higher than the same period of 2020 primarily
due to increased exploration and development drilling expenditures in the United
States ($47 million) and Other International ($21 million), increased facilities
expenditures ($39 million), increased leasehold acquisitions ($31 million) and
increased property acquisitions ($25 million), partially offset by decreased
exploration and development expenditures in Trinidad ($44 million). Exploration
and development expenditures for the first nine months of 2021 of $2,841 million
consisted of $2,299 million in development drilling and facilities, $419 million
in exploration, $99 million in property acquisitions and $24 million in
capitalized interest. Exploration and development expenditures for the first
nine months of 2020 of $2,699 million consisted of $2,236 million in development
drilling and facilities, $365 million in exploration, $74 million in property
acquisitions and $24 million in capitalized interest.
The level of exploration and development expenditures, including acquisitions,
will vary in future periods depending on energy market conditions and other
economic factors. EOG believes it has significant flexibility and availability
with respect to financing alternatives and the ability to adjust its exploration
and development expenditure budget as circumstances warrant. While EOG has
certain continuing commitments associated with expenditure plans related to its
operations, such commitments are not expected to be material when considered in
relation to the total financial capacity of EOG.
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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 September 30, 2021, as a net
liability of $301 million.
Commodity Derivative Contracts. Presented below is a comprehensive summary of
EOG's financial commodity derivative contracts as of October 29, 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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