EOG Resources, Inc. and its subsidiaries (collectively referred to as EOG) are one of the largest independent (non-integrated) crude oil and natural gas companies in the United States, with proven reserves in the United States and Trinidad. EOG operates under a consistent business and operational strategy, focusing on maximizing the return on capital investment by controlling operating and capital costs and maximizing the reserve recovery rate. According to this strategy, each expected drilling location is evaluated according to its estimated rate of return. The strategy aims to increase the cash flow and income generation of each production unit in a cost-effective manner, enabling EOG to achieve long-term growth in shareholder value and maintain a strong balance sheet. EOG implements its strategy mainly by emphasizing the prospects generated inside drilling to find and develop low-cost reserves. Maintaining the lowest possible operating cost structure, coupled with efficient and safe operations, and sound environmental management practices and performance are an indispensable part of the implementation of the EOG strategy.

Recent developments. In 2020, the COVID-19 pandemic and measures taken to address and limit the spread of the virus have adversely affected the world economy and financial markets. The economic recession that began in early 2020 has had a negative impact on global crude oil demand and prices. Oil separation, natural gas liquids (NGL) and natural gas. In response, OPEC (Organization of Petroleum Exporting Countries) and certain non-OPEC global producers (Russia, Kazakhstan and other countries) formed a consortium OPEC agreed to voluntarily cut crude oil supply starting in April 2020, and plans to restore some crude oil supplies. These production cuts will continue until April 2021. Certain other non-OPEC countries have also reduced production and/or reduced investment in existing and new crude oil projects. This reaction started the process of balancing supply and demand.

In 2021, the impact of global COVID-19 mitigation measures, including extensive global fiscal stimulus and vaccine supply, will be affected by new COVID-19 variant strains and corresponding containment measures in certain regions of the world, resulting in severe damage to certain regions of the world. The overall demand for crude oil and condensate, NGL and natural gas has increased. Please refer to Item 1A, Risk Factors, of our Annual Report on Form 10-K for the fiscal year ending December 31, 2020, which we submitted on February 25, 2021, for the fiscal year ending December 31, 2020, for further discussion. During 2021, OPEC continues to revise their timetable to respond to the expected increase in demand for crude oil and gradually resume all production cuts in 2022.

The improvement or stabilization of certain economies and financial market conditions in the world has led to the continuous rebalancing of crude oil supply and demand. Together with the continuous actions taken by OPEC, it has had a positive impact on crude oil prices in the first nine months of 2021. Crude oil, condensate and oil NGL prices returned to pre-pandemic levels in the first quarter of 2021, while natural gas prices rebounded in early 2021.

We will continue to monitor and evaluate the COVID-19 pandemic and its impact on crude oil demand, OPEC’s actions and their impact on crude oil supply, and any executive orders or legislative or regulatory actions that may affect oil and gas industries to determine Influence our business and operations, and take appropriate action when necessary. For related discussions, please refer to Item 1, Business-Supervision, Item 1A, Risk Factors and Item 7, Management Discussion and Analysis of Financial Status and Operation Results-Overview in our annual report.

Commodity price. The prices of crude oil and condensate, NGL and natural gas have always been volatile. Due to many uncertain factors such as the world's political and economic environment, the global supply and demand of crude oil, NGL, and natural gas, the availability of other energy supplies, and the relative competition between the two countries, this fluctuation is expected to continue. Various energy sources taking into account consumers and other factors.

The market prices of crude oil and condensate, NGL and natural gas affect the amount of cash generated by EOG's operating activities, which in turn affects EOG's financial status and operating performance.

In the first nine months of 2021, the average prices of crude oil and natural gas on the New York Mercantile Exchange (NYMEX) were US$64.85 per barrel and US$3.18 per million British thermal units (MMBtu), both up 69% from the same period last year. The average price on the New York Mercantile Exchange during the same period in 2020. The market price of NGL is affected by the extracted components (including ethane, propane and butane, natural gasoline, etc.) and the respective market prices of each component. In February 2021, due to the interruption caused by winter storm Uri across the United States, EOG delivered natural gas on certain days to achieve above-average daily prices.

America. Facts have proved that EOG's efforts to identify areas with huge reserve potential have proven successful. EOG continues to drill multiple wells in large-scale production areas, and these wells have generally made significant contributions to EOG's crude oil and condensate, NGL and natural gas production, and are expected to continue to make significant contributions. EOG attaches great importance to applying its horizontal drilling and completion expertise to unconventional crude oil, and to a lesser extent, to liquid-rich natural gas areas.

In the first nine months of 2021, EOG continues to focus on improving the drilling, completion, and operational efficiency gained in previous years. This efficiency, combined with new innovations, reduces drilling and completion costs. Winter storm Uri had a negative impact on leasing and drilling, transportation and collection and processing costs in the first quarter of 2021. In addition, EOG continues to evaluate certain potential crude oil and condensate, NGL and natural gas exploration and development prospects, and looks for opportunities to increase drilling inventory through lease acquisitions, transfers, exchanges or tactical acquisitions. Calculated by volume, based on the ratio of 1.0 barrel of crude oil and condensate or NGL to 6000 cubic feet of natural gas, the output of crude oil, condensate, and NGL accounted for approximately 75% and 76% of the US production during the EOG period, respectively. The first nine months of 2020. In the first nine months of 2021, EOG's drilling and completion activities mainly occurred in the Delaware Basin, Eagle Ford and Rocky Mountains. The main production areas of EOG in the United States are in New Mexico and Texas. Due to the impact of the winter storm Uri in the first quarter of 2021 on the entire United States, EOG's sales in certain markets are facing disruptions.

Trinidad. In Trinidad, EOG continues to provide natural gas under existing supply contracts. Several oil fields in the South East Coast Consortium Block, Modified U(a) Block, Block 4(a), Modified U(b) Block, Banyan Field and Sercan Area have been developed and are producing natural gas, and are sold to Trinidad and Tobago National Gas Company Limited and its subsidiaries, and crude oil and condensate sold to Heritage Petroleum Company Limited (Heritage).

In March 2021, EOG and Heritage signed a farm agreement that allows EOG to obtain a 65% working interest in a part of the contract area (EOG area) governed by the Trinidad Northern Territory License. The EOG area is located offshore on the southwest coast of Trinidad. EOG is currently planning and preparing to drill a net exploratory well in the first half of 2022. EOG continues to make progress in the design and manufacturing of the platform and related facilities for its previously announced findings in the revised U(a) block.

Other international. In the Sultanate of Oman, a royal decree was promulgated on March 9, 2021, and EOG became a participant in the 49 block exploration and production sharing agreement, holding a 50% working interest. EOG's partner in Block 49 completed the drilling and testing of a general exploratory well in the first quarter of 2021. The results are currently being evaluated. In Block 36 where EOG has 100% working interest, an exploratory well has been drilled in the third quarter of 2021. EOG plans to drill another exploratory well in Block 36 by the end of 2021.

In Australia, a subsidiary of EOG signed a sale and purchase agreement in April 2021 to acquire a 100% interest in the WA-488-P block offshore Western Australia. The sale and purchase agreement must comply with customary closing conditions and is expected to be completed in the fourth quarter of 2021.

In the Sichuan Basin, Sichuan Province, China, EOG and its partner PetroChina ensure uninterrupted production in accordance with production sharing contracts and other related agreements. All natural gas produced in the Baijiaochang gas field is sold to PetroChina under long-term contracts.

In May 2021, EOG completed the sale of its subsidiary holding all assets in China. The net production of natural gas is approximately 25 million cubic feet per day (MMcfd). EOG no longer owns any business or assets in China.

EOG continues to evaluate other select crude oil and natural gas opportunities outside the United States, mainly by seeking extraction opportunities in countries that have established domestic crude oil and natural gas reserves.

Capital and operating plan for 2021. Total capital expenditures in 2021 are estimated to be between approximately US$3.8 billion and US$4 billion, including facilities and collection, processing and other expenditures, excluding acquisitions and non-cash transactions. EOG plans to continue to concentrate most of its exploration and development expenditures in major producing areas in the United States. In particular, EOG will continue to focus on its U.S. crude oil drilling activities in the Delaware Basin, Eagle Ford and Rocky Mountain regions, generating the highest rates of return in these regions. In order to further improve the economics of these businesses, EOG expects to continue to improve oil well performance and reduce drilling and completion costs through improved efficiency, new innovations, and measures to manage procurement and service costs. In addition, EOG has and expects to continue to use a portion of its capital expenditure in 2021 for leased area and assess new prospects.

It is expected that the total crude oil production in 2021 will remain at the level of the fourth quarter of 2020. In addition, EOG is expected to continue to focus on reducing operating costs by improving efficiency in 2021.

Management continues to believe that EOG has one of the strongest prospective inventories in EOG's history. When it is in line with EOG's strategy, EOG will make acquisitions to support existing drilling programs or provide incremental exploration and/or production opportunities.

Capital Structure. A key management strategy is to maintain a strong balance sheet, which is consistently lower than the average debt-to-total capitalization ratio compared to EOG's peers. EOG's debt to total capitalization ratio was 19% on September 30, 2021, and 22% on December 31, 2020. In this calculation, total capitalization represents the sum of total current and long-term debt and total shareholder equity.

On February 1, 2021, EOG repaid the total principal amount of US$750 million of the 4.100% senior notes due in 2021 at maturity.

As of September 30, 2021, EOG maintained a strong financial and liquidity position, including US$4.3 billion in cash and cash equivalents on hand and US$2 billion available under its advanced unsecured revolving credit facility.

EOG has great flexibility in financing options, including borrowings under its commercial paper program, bank borrowings, borrowings under its advanced unsecured revolving credit arrangements, joint development agreements and similar agreements, and equity and debt issuance.

Dividend statement and share repurchase authorization. On November 4, 2021, the EOG Board of Directors (i) increased the quarterly cash dividend for common stock from the previous US$0.4125 per share to US$0.75 per share, effective from the dividend payment to shareholders of record on January 28, 2022 On January 14, 2022, (ii) Announced a special cash dividend of US$2.00 per share on common stock, paid on December 30, 2021 to shareholders of record as of December 15, 2021, (iii) Established a new share buyback The authorization allowed EOG to repurchase up to $5 billion in common stock, and (iv) revoked and terminated the stock repurchase authorization established by the board of directors in September 2001. See Part Two, Item 2, Unregistered Equity Securities Sales and Use of Earnings Reported in the Quarter, Form 10-Q for further discussion.

The following review of operations for the three months ending September 30, 2021 and 2020 should be read in conjunction with EOG's condensed consolidated financial statements and their notes, which are included in this quarterly report on Form 10-Q.

The three months ending September 30, 2021 and the three months ending September 30, 2020

Operating income and others. In the third quarter of 2021, operating income increased from US$2.246 billion in the same period in 2020 to US$4.765 billion, an increase of US$2.519 billion, or 112%. And natural gas, in the third quarter of 2021, an increase of US$2.281 billion, or 129%, from US$1.764 billion in the same period in 2020, to US$4.045 billion. EOG confirmed a net loss of US$494 million in financial commodity derivative contracts at market value. The net loss in the third quarter of 2021 was US$4 million, and the collection, processing and marketing revenue in the third quarter of 2021 increased from US$539 million in the same period. 647 million U.S. dollars, or 120%, increased to 1.186 billion U.S. dollars in 2020. The net gain on asset disposal in the third quarter of 2021 was US$1 million, while the net loss for the same period in 2020 was US$71 million.

The statistics on the quantity and price of wellheads for the three months ending September 30, 2021 and September 30, 2020 are as follows:

Average crude oil and condensate prices ($/Bbl) (3) United States

(1) Thousand barrels/day or million cubic feet/day, if applicable. (2) Other international companies include EOG's operations in China and Canada. The China business was sold in the second quarter of 2021. (3) USD per barrel or per thousand cubic feet (if applicable). Excluding the impact of financial commodity derivatives (see Note 12 to the condensed consolidated financial statements). (4) Thousand barrels of oil equivalent/day or million barrels of oil equivalent, if applicable; including crude oil and condensate, NGL and natural gas. The crude oil equivalent volume is determined using the ratio of 1.0 barrel of crude oil and condensate or NGL to 6000 cubic feet of natural gas. MMBoe is calculated by multiplying the amount of MBoed by the number of days in the period, and then dividing the amount by one thousand.

Revenues from wellhead crude oil and condensate in the third quarter of 2021 increased by US$1.534 billion, or 110%, from US$1.395 billion in the same period in 2020, reaching US$2.929 billion. This increase was due to the combined average price increase ($1.266 billion) and an increase of 71.9 MBbld, or 19%, for wellhead crude oil and condensate production ($268 million). The increased production is mainly in the Permian Basin and Eagle Ford. EOG's composite wellhead crude oil and condensate prices rose 76% in the third quarter of 2021 to US$70.85 per barrel, compared to US$40.15 per barrel in the same period in 2020.

NGL revenue in the third quarter of 2021 increased by US$363 million, or 196%, from US$185 million in the same period in 2020, reaching US$548 million, due to the higher comprehensive average price (US$340 million) and an increase of 17.8 MBbld. That is 13%, in NGL delivery (23 million USD). The increase in production mainly occurred in the Permian Basin. EOG's compound NGL price in the third quarter of 2021 rose by 163% to US$37.72 per barrel, compared to US$14.34 per barrel in the same period in 2020.

In the third quarter of 2021, wellhead natural gas revenue increased from US$184 million in the same period in 2020 to US$568 million, an increase of US$384 million or 209%. Natural gas transportation ($37 million). Compared with the same period in 2020, the delivery of natural gas in the third quarter of 2021 increased by 232 MMcfd, or 19%, mainly due to the increase in associated gas production in the Permian Basin and the increase in natural gas production in Trinidad. The low natural gas production was offset by the reduction in the amount of natural gas related to the disposal of Marcellus shale assets in the third quarter of 2020, the reduction in deliveries in South Texas, and the reduction in the amount of natural gas related to the disposal of Chinese assets in the second quarter of 2021. EOG's integrated wellhead natural gas price increased by 158% in the third quarter of 2021 to US$4.34 per thousand square feet, compared to US$1.68 per thousand square feet in the same period in 2020.

In the third quarter of 2021, EOG confirmed that the market value net loss of financial commodity derivatives contracts was US$494 million, while the net loss for the same period in 2020 was US$4 million. In the third quarter of 2021, net cash paid for the same period in 2020, the net cash received for settlement of financial commodity derivatives contracts was US$293 million, and the net cash received for settlement of financial commodity derivatives contracts was US$275 million.

The collection, processing and marketing revenues are the sales revenues from third-party crude oil, NGL and natural gas, as well as the costs associated with the collection of third-party natural gas and the sales revenue from sand owned by EOG. The procurement and sales of third-party crude oil and natural gas can be used to balance the stable production capacity of third-party facilities with production in certain regions, and to take advantage of the excess capacity of facilities owned by EOG. EOG sells sand to balance the determination of the purchase agreement and the time to complete the work. Marketing costs refer to the cost of purchasing third-party crude oil, natural gas, and sand and related transportation costs, as well as the costs associated with the sale of sand owned by EOG to third parties.

Compared with the same period in 2020, the collection, processing and marketing revenue minus marketing costs in the third quarter of 2021 decreased by US$14 million. This was mainly due to the lower profit margin of crude oil marketing activities, which was partially affected by the profit margins of natural gas marketing activities. The higher is offset.

(1) The total excludes exploration costs, dry well costs, impairment, marketing costs and taxes other than revenue.

Compared with the same period in 2020, the main factors affecting the cost composition, transportation cost, collection and processing cost, DD&A, G&A, and net interest expense for the three months ended September 30, 2021 are as follows . For a discussion of wellhead capacity, see "Operating Revenue and Others" above.

Lease and oil well fees include the cost of assets operated by EOG and the fees charged to EOG by other operators whose EOG is not an asset operator. Leasing and oil well expenses can be divided into the following categories: operating and maintaining crude oil and natural gas wells, workover and leasing costs, and oil well management expenses. Operation and maintenance costs include pumping services, brine treatment, equipment repairs and maintenance, compression costs, lease maintenance, and fuel and electricity. Workover operations are to restore or maintain the production of existing wells.

As EOG tries to maintain and increase production while maintaining efficient, safe, and environmentally responsible operations, each of these cost categories fluctuates from time to time. EOG continues to increase its operational activities by drilling new wells in existing and new areas. Operation and maintenance costs in these existing and new regions, as well as the service costs that suppliers charge EOG, will fluctuate over time.

Leasing and oil well expenses in the third quarter of 2021 were US$270 million, an increase of US$43 million from the US$227 million in the same period of the previous year. This was mainly due to the increase in U.S. operating and maintenance costs (US$19 million) and the increase in U.S. workover costs (US$15 million) and increased leasing and well management expenses in the United States (US$7 million). The increase in the cost of leasing and oil wells in the United States was mainly due to the increase in production due to the increase in operating activities.

Transportation costs represent the costs associated with the delivery of hydrocarbon products from the aggregation point on the lease or EOG collection system to the downstream point of sale. Transportation costs include transportation fees, storage and terminal fees, compression costs (the cost of compressing natural gas to meet pipeline pressure requirements), dehydration costs (the cost associated with removing water from natural gas to meet pipeline requirements), collection fees, and fuel costs.

The transportation cost in the third quarter of 2021 was US$219 million, an increase of US$39 million from the US$180 million in the same period last year. This was mainly due to the relationship between the Permian Basin (US$29 million) and the Rocky Mountains (US$10 million). Production-related transportation costs increase.

Collection and processing costs refer to the operating and maintenance costs and management costs associated with operating EOG's collection 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 most of its natural gas production to extract NGL.

Collection and processing costs in the third quarter of 2021 increased by US$30 million to US$145 million, compared to US$115 million in the same period last year, mainly due to collection and processing costs (US$14 million) and operating and maintenance costs (US$8 million) ) Increased, both are related to production from the Permian Basin.

The DD&A of proven oil and gas asset costs is calculated using the production unit method. EOG's DD&A rates and fees are calculated by many individual DD&A groups. There are several factors that affect the comprehensive DD&A rate and cost of EOG, such as oil field production profile, drilling or acquisition of new wells, existing well disposal and reserve correction (up or down), mainly related to oil well performance, economic factors and impairment. Changes in these factors may cause EOG's compound DD&A rates and fees to fluctuate in different periods. The DD&A of other real estate, plant and equipment costs are generally calculated using the straight-line depreciation method during the life of the asset.

DD&A expenses in the third quarter of 2021 increased by 104 million U.S. dollars to 927 million U.S. dollars from 823 million U.S. dollars in the same period last year. DD&A expenses related to oil and gas assets in the third quarter of 2021 were $100 million higher than the same period last year. The main reason for the increase was the increase in production in the United States ($137 million) and Trinidad ($5 million), partially offset by the lower unit rate in the United States ($39 million). The decline in the unit rate in the United States is mainly due to increased efficiency and increased reserves at a lower cost.

G&A expenses in the third quarter of 2021 were US$142 million, an increase of US$17 million from the US$125 million in the same period last year. This was mainly due to increased employee-related costs (US$20 million) and joint ventures that were deemed unrecoverable. Interest bills (US$5 million), partly reduced by idle equipment and termination fees (US$13 million).

The net interest expense in the third quarter of 2021 was US$48 million, a decrease of US$5 million compared to the same period last year. This was mainly due to the repayment of US$750 million in February 2021 for the 4.100% senior notes due in 2021. The total principal amount ($8 million) was partially offset by the interest payment ($3 million) of late royalties on the Oklahoma property.

Exploration costs in the third quarter of 2021 were US$44 million, an increase of US$6 million from US$38 million in the same period last year. This was mainly due to the increase in U.S. geological and geophysical expenditures.

Impairment includes: amortization of the cost of unproven oil and gas assets and impairment of proven oil and gas assets; other real estate, plant and equipment; and other assets. Unconfirmed assets with insignificant acquisition costs are aggregated, and the portion estimated to be non-productive costs is amortized during the remaining lease period. Unproven properties with individually significant acquisition costs will be individually reviewed for impairment. When circumstances indicate that the certified property may be impaired, EOG compares the expected undiscounted future cash flows at the DD&A group level with the unamortized capitalized cost of the asset. If based on EOG’s estimates (and assumptions) of future crude oil, NGL and natural gas prices, operating costs, development expenditures, expected production of proven reserves, and other relevant data, the expected undiscounted future cash flow is lower than the unamortized capitalized cost, The capitalized cost is written down to fair value. The fair value is usually calculated using the income method described in the fair value measurement subject compiled by the Financial Accounting Standards Board Accounting Standards. In some cases, EOG uses quotations accepted by third-party purchasers as the basis for determining fair value.

Taxes other than income include severance payment/production tax, ad valorem tax/property tax, payroll tax, franchise tax and other miscellaneous taxes. Severance payment/production tax is usually determined based on wellhead income, and ad valorem tax/property tax is usually determined based on the valuation of related assets.

Taxes other than revenue in the third quarter of 2021 increased by US$151 million to US$277 million (6.8% of wellhead revenue) from US$126 million in the same period last year (7.2% of wellhead revenue). The increase in taxes other than income is mainly due to the increase in severance/production taxes ($142 million) and ad valorem taxes/property taxes ($5 million) in the United States.

EOG confirmed that the income tax provision for the third quarter of 2021 was US$334 million, and the income tax income for the third quarter of 2020 was US$11 million, which was mainly due to the increase in pre-tax income. The net effective tax rate in the third quarter of 2021 increased from 19% in the third quarter of 2020 to 23%, mainly due to the shortcomings of the stock compensation tax, which led to an increase in the effective tax rate of pre-tax income in the third quarter of 2021 and a decrease in the third quarter of 2020. The effective tax rate for quarterly pre-tax losses.

The nine months ending September 30, 2021 and the nine months ending September 30, 2020

Operating income. In the first nine months of 2021, operating income increased from US$8.067 billion in the same period in 2020 to US$12.598 billion, an increase of US$4.531 billion, or 56%. The total wellhead revenue in the first nine months of 2021 increased by US$5.656 billion, or 112%, from US$5.049 billion in the same period in 2020 to US$10.705 billion. In the first nine months of 2021, EOG confirmed that the net loss of financial commodity derivative contracts at market value was US$1.288 billion, while the net income for the same period was US$1.075 billion in 2020. The collection, processing and marketing revenue in the first nine months of 2021 increased by US$1.116 billion, or 58%, from US$1.940 billion in the same period in 2020, reaching US$3.056 billion. The net gain on asset disposal in the first nine months was US$46 million. The net loss in 2021 was US$41 million, while the net loss for the same period in 2020 was US$41 million.

The statistics on the quantity and price of wellheads as of September 30, 2021 and September 2020 are as follows:

Average crude oil and condensate prices ($/Bbl) (1) United States

(1) Excluding the impact of financial product derivatives (see Note 12 to the condensed consolidated financial statements).

Revenue from wellhead crude oil and condensate for the first nine months of 2021 increased by US$3.804 billion, or 93%, from US$4.075 billion in the same period in 2020, or 93%, due to the higher comprehensive average price (US$3.348 billion) and the increase of 45.8 MBbld, or 12%, in the production of wellhead crude oil and condensate (US$456 million). The increase in production was mainly in the Permian Basin, partially offset by the decline in Eagle Ford's production. In the first nine months of EOG 2021, the price of composite wellhead crude oil and condensate rose 74% to US$65.14 per barrel, compared to US$37.44 per barrel in the same period in 2020.

NGL revenue for the first nine months of 2021 increased by US$790 million, or 180%, to US$1.229 million from US$439 million in the same period in 2020, due to the higher combined average price (US$772 million) and the growth of 6.2 MBbld, or 5% , In the delivery of NGL ($18 million). The increase in production mainly occurred in the Permian Basin and Rocky Mountains, and was partially offset by the decrease in the production of the Barnett Shale and Eagle Ford in the Fort Worth Basin. EOG's comprehensive NGL price for the first nine months of 2021 increased by 168% to US$32.07 per barrel, compared to US$11.95 per barrel in the same period in 2020.

Wellhead natural gas revenue in the first nine months of 2021 increased from 535 million US dollars in the same period in 2020 to 1.597 billion US dollars, an increase of 1.062 billion US dollars or 199%. This increase was due to the integrated wellhead natural gas price (US$992 million) and the increase in natural gas supply (US$70 million). Compared with the same period in 2020, the delivery of natural gas in the first nine months of 2021 increased by 165 MMcfd, or 13%, mainly due to the increase in associated gas production in the Permian Basin and the increase in natural gas production in Trinidad, which was partially Lower natural gas production offsets. The amount of natural gas associated with the disposal of Marcellus shale assets in the third quarter of 2020 and the reduction in deliveries in South Texas. EOG's composite wellhead natural gas price in the first nine months of 2021 rose 164% to US$4.17 per thousand cubic feet, compared to US$1.58 per thousand cubic feet in the same period in 2020.

In the first nine months of 2021, EOG confirmed that the net loss of financial commodity derivatives contracts was 1.288 billion U.S. dollars, while the net income for the same period in 2020 was 1.075 billion U.S. dollars. In the first nine months of 2021, the net loss for cash paid for settlement of financial commodity derivatives contracts was US$516 million, while the net cash received from settlement of financial commodity derivatives contracts for the same period in 2020 was US$999 million.

Compared with the same period in 2020, the collection, processing and marketing revenue in the first nine months of 2021 minus marketing costs increased by US$180 million. This is offset by the decline in the rate. The profit margin of crude oil marketing activities in the first nine months of 2020 was negatively affected by the decline in the price of inventory crude oil waiting to be delivered to customers and EOG's decision to reduce commodity price fluctuations by selling in May and June at the beginning of the second quarter of 2020. Arrange delivery at a fixed price.

Operating and other expenses. Operating expenses for the first nine months of 2021 were US$9.024 billion, a decrease of US$75 million from the US$9.099 billion incurred in the same period in 2020. The following table lists the cost per barrel of oil equivalent for the nine-month period ending September 30, 2021 and 2020:

(1) The total excludes exploration costs, dry well costs, impairment, marketing costs and taxes other than revenue.

Compared with the same period in 2020, the main factors of the cost composition, transportation cost, collection and processing cost, DD&A and net interest expense for the nine months ended September 30, 2021 are set as follows: . For a discussion of wellhead capacity, see "Operating Revenue" above.

Lease and drilling expenses for the first nine months of 2021 were US$810 million, an increase of US$8 million from the US$802 million in the same period last year. This was mainly due to the increase in U.S. workover expenditures (US$12 million) and Trinidad operations. The increase in maintenance and maintenance costs (US$4 million) was partially offset by lower operating and maintenance costs in Canada (US$6 million) and the United States (US$3 million).

The transportation cost for the first nine months of 2021 was US$635 million, an increase of US$95 million from the US$540 million in the same period last year. The increase in transportation costs related to the production of Eagle Ford partially offset the decrease in transportation costs related to the production of Eagle Ford (US$7 million).

The cost of collection and processing in the first nine months of 2021 was US$412 million, an increase of US$72 million compared to the same period last year, mainly due to the Permian Basin (US$31 million) and Rocky Mountains (US$12) The production-related collection and processing costs have increased. Million), increased operating and maintenance costs related to production in the Permian Basin (US$13 million) and Rocky Mountain region (US$7 million), and increased general and administrative costs for collection and processing in the United States (US$11 million) ).

The DD&A expenses for the first nine months of 2021 increased from US$2.530 billion in the same period last year to US$2.741 billion. DD&A expenses related to oil and gas assets in the first nine months of 2021 were US$199 million higher than the same period last year. The increase was mainly due to the increase in production in the United States ($239 million) and Trinidad ($11 million) and the increase in unit price in Trinidad ($12 million), partially offset by the decline in unit price in the United States ($55 million) . The decline in the unit rate in the United States is mainly due to increased efficiency and increased reserves at a lower cost. In the first nine months of 2021, DD&A expenses related to other real estate, plant and equipment increased by 11 million U.S. dollars over the same period last year, mainly due to increased expenses related to storage assets.

The net interest expense for the first nine months of 2021 was US$140 million, a decrease of US$12 million compared to the same period last year. This was mainly due to the repayment of US$750 million in February 2021 of 4.100% senior notes due in 2021. The total principal (US$21 million) will be repaid in June 2020. The total principal of 4.40% of the senior bonds due in 2020 will be US$500 million (US$9 million). In April 2020, 2.45% of the principal will be repaid in 2020. A total of US$500 million (US$3 million), partially offsetting the issuance of 4.950% senior bonds due in 2050 (US$11 million) with a total principal of US$750 million in April 2020, and the principal issuance in April 2020 4.375% senior bonds (US$10 million) maturing in 2030 totaling US$750 million.

Exploration costs for the first nine months of 2021 were US$112 million, an increase of US$7 million from US$105 million in the same period last year, mainly due to an increase in geological and geophysical expenditures (US$9 million), partly reduced by general and administrative expenses (5 million U.S. dollars) offset, all in the United States.

The following table represents the impairment (in millions) for the period ending September 30, 2021 and September 2020:

Proved asset impairment in the first nine months of 2020 is mainly due to the decline in commodity prices, mainly related to the fair value write-down of traditional and non-core natural gas, crude oil and combined assets in the United States. Unproven impairment of oil and natural gas assets Includes $252 million in expenses for the first nine months of 2020 to cover certain lease costs that are not expected to be developed before maturity. The impairment of other assets in the first nine months of 2020 was mainly due to the write-down of the fair value of the crude oil assets of Sand and Railway and the write-down of other assets related to commodity prices. The firm commitment to contract impairment for the first nine months of 2020 was due to the decision to withdraw from Canada’s Horn River Basin.

Taxes other than revenue for the first nine months of 2021 increased by US$367 million to US$731 million (6.8% of wellhead revenue) from US$364 million in the same period last year (7.2% of wellhead revenue). The increase in taxes other than income is mainly due to the increased severance payment/production tax in the United States (US$347 million) and the reduced state severance payment rebate (US$13 million) and the increase in severance payment/production tax in Trinidad (US$5 million) ).

The net other income in the first nine months of 2021 decreased by US$17 million compared to the same period last year, mainly due to the increase in deferred compensation expenses (US$18 million) and the decrease in interest income (US$8 million). Equity income is offset by the ammonia plant in Trinidad ($11 million).

EOG confirmed that the income tax reserve for the first nine months of 2021 was US$755 million, and the income tax income for the first nine months of 2020 was US$225 million, which was mainly due to the increase in pre-tax income. The net effective tax rate for the first nine months of 2021 will increase from 19% in the first nine months of 2020 to 22%. The higher effective tax rate is mainly due to the taxation of EOG's overseas business.

cash flow. During the nine-month period ending September 30, 2021, EOG's main source of cash is operating capital and asset sales revenue. The main uses of cash are funds for operations; exploration and development expenditures; payment of dividends to shareholders; long-term debt repayment; net cash paid for settlement of commodity derivatives contracts and other real property, plant and equipment expenditures. In the first nine months of 2021, EOG's cash balance increased from USD 3.329 billion on December 31, 2020 to USD 964 million to USD 4.293 billion.

The net cash provided by operating activities in the first nine months of 2021 was US$5.625 billion, an increase of US$1.738 billion compared with the same period in 2020. This was mainly due to the increase in wellhead revenue (US$5.656 billion) and the deduction of collection, processing and marketing income. Increased cost of marketing revenue (US$180 million), part of the net cash paid for settlement of financial commodity derivatives contracts (US$1.515 billion), net cash used for working capital in the first nine months of 2021 (US$897 million) and 2020 Unfavorable changes in working capital (US$467 million), net cash paid for income tax (US$1.038 billion) in the first nine months, and an increase in cash operating expenses (US$529 million).

The net cash used for investment activities in the first nine months of 2021 was US$2.582 billion, a decrease of US$129 million compared with the same period in 2020. This was due to the net cash provided by working capital related to investment activities in the first nine months of 2021. The amount (US$100 million) compared to the net cash (US$276 million) used for working capital related to investment activities in the first nine months of 2020 and the increase in other real estate, plant and equipment (US$18 million), partly The increase in assets ($230 million) and the decrease in proceeds from asset sales ($35 million) were offset by the increase in oil and gas.

Net cash used for financing activities in the first nine months of 2021 was US$2.079 billion, including payment of cash dividends (US$1.278 billion), repayment of long-term debt (US$750 million), and purchase of treasury stocks related to stock compensation plans (US$33 million) ) And repayment of financing lease liabilities (US$27 million). Net cash used for financing activities in the first nine months of 2020 was US$140 million, including repayment of long-term debt (US$1 billion) and cash dividend payments (US$601 million), partially offset by net proceeds from long-term debt issuance (1.484 billion US dollars) Dollar).

total expenses. For 2021, the latest budget for EOG's exploration and development and other real estate, plant and equipment expenditures is estimated to be between approximately US$3.8 billion and US$4 billion, excluding acquisitions and non-cash transactions. The following table lists the total expenditure composition (in millions) as of September 30, 2021 and September 2020:

Total exploration and development expenditure 2,897 2,768 Other real estate, plant and equipment(3)

Exploration and development expenditures in the first nine months of 2021 were US$2.841 billion, an increase of US$142 million over the same period in 2020, mainly due to the increase in exploration and development drilling expenditures in the United States (US$47 million) and other countries (US$21 million). Facilities expenditures ($39 million), increased leasehold asset acquisitions ($31 million), and property acquisitions ($25 million) were partially offset by a decrease in Trinidad’s exploration and development expenditures ($44 million). Exploration and development expenditures for the first nine months of 2021 were US$2.841 billion, including US$2.299 billion in development drilling and facilities, US$419 million in exploration, US$99 million in property acquisitions, and US$24 million in capitalized interest. Exploration and development expenditures for the first nine months of 2020 are US$2.699 billion, including US$2.236 billion of development drilling and facilities, US$365 million of exploration, US$74 million of property acquisitions, and US$24 million of capitalized interest.

The level of exploration and development expenditures (including acquisitions) in the future will vary according to energy market conditions and other economic factors. EOG believes that it has significant flexibility and availability in terms of financing alternatives and the ability to adjust exploration and development expenditure budgets as the situation requires. Although EOG has certain ongoing commitments related to its operations-related expenditure plans, these commitments are not expected to be important when considering the total financial capabilities of EOG.

Commodity derivative transactions. As discussed more fully in Note 12 to the consolidated financial statements included in the EOG's annual report on Form 10-K for the year ended December 31, 2020, submitted on February 25, 2021, EOG engages in price risk management activities from time to time. These activities are designed to manage EOG's risk exposure to fluctuations in crude oil, NGL and natural gas commodity prices. EOG uses financial commodity derivatives, mainly price swaps, options, swaps, collars and basic swap contracts, as a means to manage this price risk. EOG does not designate any of its financial product derivative contracts as an accounting hedge. Therefore, it uses the market value accounting method to account for financial product derivative contracts. Under this accounting method, changes in the fair value of outstanding financial instruments are recognized as gains or losses during the period of change, and are included in gains (losses) (losses) and comprehensive income (losses) (losses) and comprehensive income ( loss). The impact of the relevant cash flow is reflected in the cash flow of operating activities in the condensed consolidated cash flow statement.

The total fair value of EOG commodity derivatives contracts is reflected in the condensed consolidated balance sheet on September 30, 2021 as net liabilities of US$301 million.

Commodity derivative contracts. The following is a comprehensive summary of EOG financial commodity derivatives contracts as of October 29, 2021. The quantity of crude oil and NGL is expressed in MBbld, and the price is expressed in USD/Bbl. The amount of natural gas is expressed in MMBtu per day (MMBtud), and the price is expressed in USD/MMBtu ($/MMBtu).

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