CVXChevron Corporation

We note in the fourth quarter 2023, you recognized an after-tax loss of $1.9 billion related to abandonment and decommissioning obligations from previously sold oil and gas production assets in the U.S. Gulf of Mexico, as companies that purchased these assets have filed for protection under Chapter 11 of the U.S. Bankruptcy Code.

Rest of the question

You disclose it is now probable and estimable that a portion of these obligations will revert to the company and the cash outlays for these abandonment and decommissioning obligations are expected to take place over the next decade. Please address the following: Explain, in reasonable detail, the facts that resulted in the determination a $1.9 billion loss should be recorded in the fourth quarter 2023. Your explanation should address the assets that were sold, dates of each sale, and events that occurred between the time • 1. of sale and when it was determined an accrual should be recorded related to the abandonment and decommissioning obligations from the previously sold assets. Address any terms of your contractual agreements or requirements by government authorities which resulted in a portion of these obligations reverting to the company subsequent to the sale. • Tell us how you considered the application of ASC 450-20-50, Item 103 of Regulation S-K, Item 105 of Regulation S-K and Item 303 of Regulation S-K to those facts in the periods prior to the fourth quarter of 2023. As part of your response, address the requirement to describe any known trends, events or uncertainties that are reasonably likely to have a material impact on your liquidity, capital resources or results of operations. • From your disclosure, it appears you have not previously accrued expenses related to these obligations. Tell us how you considered FASB ASC 410-20 and ASC 450-2025 when determining a liability related to these obligations was not necessary in the periods prior to the fourth quarter 2023. • Provide your assessment for each period subsequent to the sale of the assets addressing whether there was a reasonable possibility of an exposure to loss in excess of the amount accrued and what the additional loss or range of loss might be. Please tell us how you considered the disclosure requirements of FASB ASC 450-20-50-1 through 50-4 and FASB ASC 275-10-50-6 through 50-15. • Tell us, in reasonable detail, the amounts expected to be recorded in future years related to the expected cash outlays for these abandonment and decommissioning obligations.

The Company has set forth the Staff’s bulleted comments below and addresses each one individually.

Executive Summary:

As detailed in the response below, substantially all of the $1.9 billion loss that was recognized during the fourth quarter of 2023 related to the bankruptcies of Cox Operating, LLC (“Cox”) and Fieldwood Energy LLC (“Fieldwood”), with approximately 80 percent attributable to Cox.

Rest of the answer

During the periods leading up to the fourth quarter of 2023, significant uncertainty existed as to whether, when and to what extent decommissioning obligations previously assumed by Cox and Fieldwood could revert to Chevron. When Cox declared bankruptcy in May 2023, multiple commercial alternatives other than the reversion of such obligations to Chevron were possible under the U.S. Bankruptcy Code, including potential sales of assets to third parties and the fact that numerous Cox assets were generating revenues through production of oil and natural gas. Chevron did not know which assets would be sold by Cox and which decommissioning obligations previously assumed by Cox would ultimately revert to Chevron. The Company also considered the asset retirement obligation balance derecognized in connection with the 2015 sale. As a result, in the second and third quarters of 2023, Chevron deemed the liability with respect to Cox-related decommissioning obligations as reasonably possible but not probable and estimable, and did not expect the amount could result in a material loss.

In December 2023, a subset of producible leases from the Cox Debtors’ estate was sold to a third party, but in a lesser amount than the Company had anticipated, potentially indicating more decommissioning obligations than anticipated reverting to the Company. Also, in December 2023, Cox and affiliated debtors sought court approval to abandon (i.e., relinquish from the debtors’ estate) certain properties and to reject associated leases/agreements that were a burden to the debtors’ estate (“Motion to Abandon”), including producible leases where Chevron was in the chain of title. As a result of this new information, Chevron then determined that it was probable that decommissioning obligations from leases within the Cox Debtors’ estate would revert to the Company due to its status as a predecessor in interest to the debtors and concluded that it had sufficient information to determine the potential loss related to the Cox assets was both probable and reasonably estimable. At that time, in accordance with ASC 450, the Company recorded a liability that represented the best estimate of future costs, given current facts and circumstances around the scope of liability, industry-wide cost estimates, and current attribution of Chevron’s share of the decommissioning costs.

Background Information:

As disclosed in its periodic reports with the SEC, the Company continually evaluates opportunities to dispose of assets that are not expected to provide sufficient long-term value and to acquire assets or operations complementary to its asset base to help augment the Company’s financial performance and value growth. For asset sales, commercial negotiations dictate whether liabilities related to assets, such as abandonment and decommissioning obligations, are retained by the Company or assumed by the buyer.

Chevron applies ASC 410 to account for asset retirement obligations (“ARO”) when Chevron owns assets. The ARO asset and liability are recorded when there is a legal obligation associated with the retirement of a long-lived asset and the amount can be reasonably estimated. If the asset is sold and the Company retains the decommissioning obligations, the associated decommissioning liabilities remain on the Company’s consolidated balance sheet. If the obligation to decommission the assets is assumed by the buyer, the Company derecognizes the decommissioning obligations from its balance sheet; any further recognition follows ASC 450 and a loss contingency is recorded by Chevron only when a loss is probable and can be reasonably estimated, and disclosure of the contingency is made when the loss is at least reasonably possible and material.

As disclosed in SEC filings, Chevron had total assets that averaged over $250 billion from 2021-2023, and before-tax income that averaged over $33 billion per year over the same period. Chevron considers these financial metrics and other quantitative and qualitative factors when assessing what disclosures are appropriate in its financial statements.

•Explain, in reasonable detail, the facts that resulted in the determination a $1.9 billion loss should be recorded in the fourth quarter 2023. Your explanation should address the assets that were sold, dates of each sale, and events that occurred between the time of sale and when it was determined an accrual should be recorded related to the abandonment and decommissioning obligations from the previously sold assets. Address any terms of your contractual agreements or requirements by government authorities which resulted in a portion of these obligations reverting to the company subsequent to the sale.

Company Response:

Assets on the Outer Continental Shelf in the Gulf of Mexico (“GOM”) are subject to regulatory oversight by the Department of the Interior through the Bureau of Ocean Energy Management (“BOEM”), which oversees ownership and maintenance of leases, including bonding for decommissioning, and the Bureau of Safety and Environmental Enforcement (“BSEE”), which oversees operation of leases, including management of decommissioning and estimation of decommissioning costs. Per federal regulations, all previous lease owners are jointly and severally liable for accrued1 decommissioning obligations. BSEE enforces accrued decommissioning obligations against predecessors in interest by issuance of a Decommissioning Order, which typically occurs after lease owner or operator default. Instances of default by a lease owner or operator can include failure to timely2 perform accrued decommissioning obligations, bankruptcy, lease relinquishment, or an affirmative statement to BSEE that the operator will not complete the required decommissioning.

1 As utilized in this response letter when referencing decommissioning obligations, the term “accrued” has the meaning prescribed in 30 C.F.R. § 250.1702.

2 30 C.F.R. § 250.1710 requires permanent abandonment of all wells on a lease within one year after the lease terminates.

After regularly selling assets over many years, the Company undertook a significant asset sale program in 2015 and 2016 whereby the Company sold most of its GOM shelf assets (generally 800 feet of water and shallower). Additionally, between 2000 and 2020, Chevron acquired companies that had similarly sold assets prior to acquisition, such as Texaco Corporation (“Texaco”), Unocal Corporation (“Unocal”), and Noble Energy, Inc. (“Noble”). From 2000 to 2018, Chevron, Texaco, Unocal, and Noble each sold assets to Cox and Fieldwood, subsidiaries or affiliates of Cox and Fieldwood, or to other companies that were subsequently purchased by Cox or Fieldwood. Following these sales, Cox and Fieldwood each filed for protection under Chapter 11 of the U.S. Bankruptcy Code, as detailed in the Appendix.

“Decommissioning Orders” are issued by BSEE in the ordinary course of administering regulations and outside of bankruptcy proceedings after decommissioning liability is defaulted upon by debtors. Although the Company’s regulatory liability is not determined or assigned by a bankruptcy court, Chevron monitored the progression of bankruptcy proceedings of both Cox and Fieldwood in order to evaluate whether developments were likely to result in BSEE issuing Decommissioning Orders to Chevron as predecessor in interest in assets then owned and/or operated by the named debtors. During bankruptcy proceedings, both Cox and Fieldwood defaulted on their regulatory decommissioning obligations with respect to assets purchased from the Company. Substantially all of the $1.9 billion loss that was recognized during the fourth quarter 2023 was related to the bankruptcies of Cox and Fieldwood, with approximately 80 percent attributable to Cox.

During the periods leading up to the fourth quarter 2023, significant uncertainty existed as to whether, when and to what extent decommissioning obligations previously assumed by Cox and Fieldwood could revert to Chevron. Multiple commercial outcomes were possible under the U.S. Bankruptcy Code including potential sales of assets (including assets where Chevron was in the chain of title) to third parties, numerous Cox assets were generating revenues through production of oil and natural gas, and Cox had not yet defaulted on its decommissioning obligations. In addition, the Company did not know which leases would be sold by Cox and which decommissioning obligations previously assumed by Cox would ultimately revert to the Company. The Company also considered the asset retirement obligation balance derecognized in connection with the 2015 sale. As a result, in the second and third quarters of 2023, Chevron deemed the liability with respect to Cox-related decommissioning obligations as reasonably possible but not probable and estimable, and did not expect the amount could result in a material loss. The Company provided qualitative disclosure on this possible exposure in the Management’s Discussion and Analysis (“MD&A”) sections of the Company’s second and third quarter 2023 Forms 10-Q.

In December 2023, a subset of producible leases from the bankruptcy estate of the Cox Debtors (as defined in the Appendix) was sold to a third party, but in a lesser amount than the Company had anticipated, potentially indicating more decommissioning obligations than anticipated reverting to the Company. Also, in December 2023, the Cox Debtors filed a Motion to Abandon, including producible leases. As a result of these events, and the related new information, the Company concluded it was now probable that decommissioning obligations from leases within the Cox Debtors’ estate would revert to the Company due to its status as a predecessor in interest to the Cox Debtors. The Company then recorded a liability that represented its best estimate of future costs, given current facts and circumstances around the scope, industry-wide cost estimates, and current attribution of Chevron’s share of the decommissioning costs. In future periods, as bankruptcy proceedings progress, the Company will continue to assess its obligations and adjust the liability as necessary and provide disclosures of any losses that may be incremental to what is accrued if the additional loss is reasonably possible and materially different from the amount accrued.

The Appendix outlines the relevant facts as they pertain to substantially all of the liability recognized by the Company in the fourth quarter of 2023.

•Tell us how you considered the application of ASC 450-20-50, Item 103 of Regulation S-K, Item 105 of Regulation S-K and Item 303 of Regulation S-K to those facts in the periods prior to the fourth quarter of 2023. As part of your response, address the requirement to describe any known trends, events or uncertainties that are reasonably likely to have a material impact on your liquidity, capital resources or results of operations.

Company Response:

As previously stated, Chevron applies ASC 450 when assessing loss contingencies related to previously sold assets, with the decommissioning obligations assumed by the buyer. As explained above and detailed in the Appendix, in the second and third quarters of 2023, significant uncertainty existed as to whether, when and to what extent decommissioning obligations previously assumed by Cox and Fieldwood could revert to Chevron, as there were multiple commercial outcomes available under the U.S. Bankruptcy Code, numerous Cox assets were generating revenues through production of oil and natural gas, and Cox had not yet defaulted on its decommissioning obligations. The Company also considered the asset retirement obligation balance derecognized at the time of the 2015 sale. Therefore, Chevron deemed the liability with respect to Cox-related decommissioning obligations as reasonably possible but not probable and estimable, and did not expect the amount could result in a material loss. In December 2023, a subset of producible leases from the Cox Debtors’ estate was sold to a third party, but in a lesser amount than the Company had anticipated, potentially indicating more decommissioning obligations than anticipated reverting to the Company. When the Cox bankruptcy proceedings advanced and the Cox Debtors filed a Motion to Abandon, including producible leases, Chevron determined that it was now probable that Cox would default on its decommissioning obligations and a loss was reasonably estimable, given current facts and circumstances around the scope of liability, industry-wide cost estimates, and current attribution of Chevron’s share of the decommissioning costs. At that time, the Company expanded its disclosure in the 2023 Form 10-K, Note 24 – Other Contingencies and Commitments as follows:

In addition, some assets are sold along with their related liabilities and in certain instances, such transferred obligations have reverted and may in the future revert to the company and result in losses that could be significant. In fourth quarter 2023, the company recognized an after-tax loss of $1,950 related to abandonment and decommissioning obligations from previously sold oil and gas production assets in the

U.S. Gulf of Mexico, as companies that purchased these assets have filed for protection under Chapter 11 of the U.S. Bankruptcy Code, and we believe it is now probable and estimable that a portion of these obligations will revert to the company.

In compliance with Item 103 of Regulation S-K, Chevron discloses material pending legal proceedings in its periodic reports filed with the SEC in the normal course. Chevron is not a party to a material pending legal proceeding associated with these decommissioning obligations and determined that no such disclosure was warranted.

When assessing whether disclosure is required under Item 105 of Regulation S-K, the Company assesses the material factors that make an investment in the Company speculative or risky. Our risk factors have evolved over time as new risks have arisen. Based on information known to us at the time, in 2015, following the sale of a significant package of GOM shelf assets to Cox, the Company expanded its risk factors in its 2015 Form 10-K to include the following disclosure:

In some cases, liabilities associated with divested assets may return to the company when an acquirer of those assets subsequently declares bankruptcy.

In 2021, the Company determined that the initial liability recognized in response to the Fieldwood bankruptcy did not have a material impact to the Company. As such, the Company did not update its risk factors in this respect.

In 2023, following the initial liability recognized in response to the Cox bankruptcy and the incremental liability recorded related to Fieldwood, the Company updated its risk factors to acknowledge that certain decommissioning obligations have returned to Chevron and may continue to do so in the future. The updated risk factor disclosure from the 2023 Form 10-K is as follows:

In some cases, transferred liabilities, including for abandonment and decommissioning of divested oil and gas assets, have returned and may continue to return to the company when an acquirer of those assets subsequently declares bankruptcy.

With respect to Item 303 of Regulation S-K, the Company considers known trends and uncertainties that may be material when determining which topics to address within the MD&A section of its Form 10-K and Form 10-Q filings. In the second quarter of 2021, following the 2020 Fieldwood bankruptcy and months of commercial negotiations with the Fieldwood Debtors (as defined in the Appendix), the Company recorded an immaterial reserve and determined that MD&A disclosure was not needed with respect to this matter at that time.

The energy industry’s financial performance is driven by commodity prices and is cyclical. During prior down-cycles, consolidation in the industry has occurred and the financial pressures led to higher probability of companies facing financial challenges. 2022 was a record year for the industry, with record earnings and cash flows common among many oil and gas companies. This is not the environment in which bankruptcies are common; however, shortly thereafter, in the second quarter of 2023, Cox declared bankruptcy. Since Chevron and its affiliates had sold many assets to Cox, the Company determined this uncertainty should be disclosed to investors even though, at that time, the Company did not expect the amount could result in a material loss, due to the multiple uncertainties that existed, as described above and in the Appendix. To that end, the following disclosure was added to the second quarter 2023 Form 10-Q MD&A:

In addition, some assets are sold along with their related liabilities, such as asset retirement obligations. In certain instances, such transferred obligations have and may in the future revert back to the company and result in losses that could be significant.

In the fourth quarter 2023, the scope of the potential loss became clearer due to commercial developments and court proceedings. Following certain Cox bankruptcy proceedings and Cox Debtors’ Motion to Abandon, the Company was able to develop an estimate for the cost to decommission applicable assets and determined it would be material. The MD&A disclosure was then updated to articulate the amounts recorded and when the related cash outflows were expected to occur. The MD&A disclosure from the 2023 Form 10-K is as follows:

In addition, some assets are sold along with their related liabilities, such as abandonment and decommissioning obligations. In certain instances, such transferred obligations have, and may in the future, revert to the company and result in losses that could be significant. In fourth quarter 2023, the company recognized an after-tax loss of $1.9 billion related to abandonment and decommissioning obligations from previously sold oil and gas production assets in the U.S. Gulf of Mexico, as companies that purchased these assets have filed for protection under Chapter 11 of the U.S. Bankruptcy Code, and the company believes it is now probable and estimable that a portion of these obligations will revert to the company. The cash outlays for these abandonment and decommissioning obligations are expected to take place over the next decade.

Additionally, rather than waiting for the filing of the fourth quarter earnings in late January 2024, on January 2, 2024, the Company proactively furnished a Form 8-K Item 2.02 that quantified this loss and informed investors of these upcoming non-cash charges that would be included in the fourth quarter 2023 results. That Form 8-K Item 2.02 disclosure is as follows:

Item 2.02 Results of Operations and Financial Condition

On January 2, 2024, Chevron Corporation announced that for fourth quarter 2023, the Company will be impairing a portion of its U.S. upstream assets, primarily in California, due to continuing regulatory challenges in the state that have resulted in lower anticipated future investment levels in its business plans. The Company expects to continue operating the impacted assets for many years to come. In addition, the Company will be recognizing a loss related to abandonment and decommissioning obligations from previously sold oil and gas production assets in the U.S. Gulf of Mexico, as companies that purchased these assets have filed for protection under Chapter 11 of the U.S. Bankruptcy Code, and we believe it is now probable and estimable that a portion of these obligations will revert to the Company. We expect to undertake the decommissioning activities on these assets over the next decade.

The Company is in the process of finalizing the financial impacts of these actions, which it expects to treat as special items and exclude from adjusted earnings. These actions in the aggregate are currently estimated to result in non-cash, after-tax charges of $3.5 billion to $4.0 billion in the Company’s fourth quarter 2023 results.

•From your disclosure, it appears you have not previously accrued expenses related to these obligations. Tell us how you considered FASB ASC 410-20 and ASC 450-20-25 when determining a liability related to these obligations was not necessary in the periods prior to the fourth quarter 2023.

Company Response:

As discussed above and in the Appendix, while not material at the time, the Company did retain a liability associated with the 2015 2 field sale to Fieldwood under ASC 410, as those decommissioning obligations were retained by the Company at the time of the sale. In the second quarter 2021, the Company also recorded an immaterial remediation charge related to previously sold assets following the execution of a commercial agreement made with Fieldwood after its bankruptcy the prior year. In the periods prior to the fourth quarter 2023, even though Cox had declared bankruptcy in the second quarter 2023, Cox had not yet defaulted on its decommissioning obligations, and significant uncertainty existed as there were multiple commercial outcomes possible, including potential sales of assets to third parties. The Company did not know which leases would be sold by Cox and which decommissioning obligations previously assumed by Cox would ultimately revert to the Company, or that the amount could be material. Only in the fourth quarter 2023, when the Cox bankruptcy proceedings advanced, the Cox Debtors’ estate sold fewer assets than the Company anticipated, and Cox Debtors filed a Motion to Abandon, including producible leases, was Chevron able to determine that it was probable that Cox would default on its decommissioning obligations, and the loss related to the Cox assets was reasonably estimable under ASC 450.

•Provide your assessment for each period subsequent to the sale of the assets addressing whether there was a reasonable possibility of an exposure to loss in excess of the amount accrued and what the additional loss or range of loss might be. Please tell us how you considered the disclosure requirements of FASB ASC 450-20-50-1 through 50-4 and FASB ASC 275-10-50-6 through 50-15.

Company Response:

See prior responses with respect to the facts and circumstances that existed at each relevant period subsequent to the sale of the assets. Only in the fourth quarter of 2023 was the Company able to determine that a loss contingency was probable and estimable under ASC 450.

With respect to ASC 275, when Cox declared bankruptcy in May 2023, there were multiple commercial alternatives that existed that could have significantly impacted the extent of the ultimate loss to Chevron. The Company also considered the asset retirement obligation balance derecognized at the time of the 2015 sale. During the second and third quarters of 2023, it was reasonably possible that Chevron could incur a loss following the Cox bankruptcy, however, the Company did not expect the amount could result in a material loss, as insufficient information was available at those times. It was not until the fourth quarter of 2023 that Chevron had enough information to assess the scope of the exposure and estimate the possible loss or range of loss. In the months following the initial Cox bankruptcy filing, the scope of the liabilities that would revert to

Chevron became clear due to subsequent court proceedings that included Cox entering into commercial agreements to sell fewer assets to third parties than the Company anticipated, and Cox Debtors’ Motion to Abandon, including producible leases. At this time, in late December 2023, the Company concluded that the share of the Cox Debtors’ decommissioning obligations that would revert to Chevron as a predecessor in interest was larger than originally anticipated and recognized a loss under ASC 450.

•Tell us, in reasonable detail, the amounts expected to be recorded in future years related to the expected cash outlays for these abandonment and decommissioning obligations.

Company Response:

The Company currently expects to spend approximately $400 million in fiscal year 2024 and approximately $250-300 million per year thereafter through 2033 on decommissioning obligations that reverted to Chevron following the Cox and Fieldwood bankruptcies. The work will be conducted pursuant to regulations administered by BSEE on an agreed schedule, with priority toward the satisfaction of decommissioning obligations resulting from the Fieldwood bankruptcy, with the decommissioning obligations resulting from the Cox bankruptcy to commence shortly thereafter. There are limited resources available and capable of safely performing this type of work, so it will be completed in a thoughtful and measured pace, in compliance with all BSEE requirements. In future periods, the Company will continue to assess its obligations and adjust the liability and disclosure, including any material revisions to estimates, as necessary.

If you wish to discuss or have any questions related to the information herein, please contact me or Mr. Amit Ghai, Assistant Controller, by telephone at (925) 842-1000.

Read in the reply ↗

Your response states that the decommissioning liabilities were transferred to each of the buyers and the asset retirement obligations were derecognized by the Company at the time of the respective sales. In addition to the assets sold to Cox in 2015 and Fieldwood in 2016, we note Cox and Fieldwood acquired additional assets previously owned by Chevron through subsequent acquisitions.

Rest of the question

Please quantify the amounts derecognized for each of the sales included in the appendix.

The Company derecognized $55 million in asset retirement obligations (“AROs”) associated with the 2004 sale to Anglo-Suisse Offshore Partners, LLC; $65 million, $63 million, and $111 million in AROs associated with the 2008, 2009, and 2011 sales to Hilcorp, respectively; and $378 million related to the 2015 sale to Cox.

The Company also derecognized $92 million in AROs associated with the 2015 sale to Fieldwood, as well as an additional $15 million in 2016. Prior to being acquired by Chevron, Noble Energy, Inc.

Rest of the answer

(“Noble”) disclosed that it had derecognized $216 million in AROs associated with its 2018 sale to Fieldwood and $45 million associated with its 2006 sale to Coldren Resources LP, which was subsequently acquired by Fieldwood.

Information related to the derecognition of AROs by Texaco Inc., Unocal Corp. and Noble in 2003 and earlier is not available.

Read in the reply ↗

Your response indicates that “In December 2023, a subset of producible leases from the Cox Debtors’ estate was sold to a third party, but in a lesser amount than the Company had anticipated, potentially indicating more decommissioning obligations than anticipated reverting to the Company.” Please address the following: • Describe for us the “subset” of producible leases from the Cox Debtors’ estate and how that

Rest of the question

“subset” related to the entire Cox Debtors’ estate; • Tell us the amount for which the “subset” of producible leases was sold and the sales amount that you had anticipated prior to the sale; • Tell us the amount or range of decommissioning obligations you had anticipated reverting to the company prior to the sale of the “subset” of producible leases; • Tell us when and how the amount or range of decommissioning obligations you had anticipated reverting to company was first estimated; and, • Tell us whether and when the amount or range of decommissioning obligations you had anticipated reverting to the company was communicated to the board of directors or a committee or subcommittee thereof.

At the time of its May 2023 bankruptcy filing, Cox represented that it had over 470 operating platforms and interests in over 400 leases. Chevron monitored assets in the Cox Debtors’ estate in which it was a predecessor in interest. As detailed in the table below, Chevron (or companies acquired by Chevron) was in the chain of title for 205 leases in the Cox Debtors’ estate, 134 of which had outstanding decommissioning obligations and included approximately 990 wells and 347 platforms.

Rest of the answer

Of the 134 leases that had outstanding decommissioning obligations, 33 leases were producing at the time of the bankruptcy filing, including approximately 430 wells and 190 platforms. Also, there were an indeterminate number of additional leases that were not producing but were capable of producing given the right economic conditions.

The “subset” in our initial response refers to 19 leases included in a Purchase and Sale Agreement between the Cox Debtors and W&T Offshore, Inc. (“W&T”) filed with the bankruptcy court in December 2023 (“W&T Agreement”), of which Chevron was in the chain of title for 11. This subset included approximately 37 wells and 21 platforms.

A summary of the leases, wells, and platforms is included in the following table:

Note - All lease, well, and platform counts are estimates

Leases Wells Platforms

Cox Debtors’ estate (May 2023) 400+ n/a 470+

Cox Debtors’ leases with Chevron in chain of title 205 990 347

Chevron in chain with no decommissioning obligation 71 n/a n/a

Chevron in chain with decommissioning obligation 134 990 347

Not currently producing 101 560 157

Producing (potential sale candidate) 33 430 190

Cox agreed to sell to W&T (December 2023) 19 n/a n/a

Of which Chevron in chain of title 11 37 21

•Tell us the amount for which the “subset” of producible leases was sold and the sales amount that you had anticipated prior to the sale;

Company Response:

W&T agreed to purchase 19 leases (the “subset” of producible leases) for $72 million pursuant to the W&T Agreement filed with the court in December 2023. Chevron had predecessor liability for 11 of the leases purchased by W&T. While the amount of sales proceeds was relevant to determining if Cox can reorganize, it did not fully inform the Company’s potential exposure, which is impacted by knowing which decommissioning obligations would revert to Chevron. On December 12, 2023, after failing to reach terms to sell other assets from its estate, Cox filed its Motion to Abandon certain properties and to reject associated leases/agreements that it deemed a burden to the Cox Debtors’ estate.

The Company had reasonably assumed that all of the 33 leases in the Cox Debtors’ estate where Chevron was a predecessor in interest and that were producing would be sale candidates. Hence, in the second quarter of 2023, the Company expected that decommissioning obligations for 560 wells and 157 platforms, which were not currently producing, could reasonably revert to the Company. After the W&T sale in the fourth quarter of 2023, however, the Company learned that decommissioning obligations for 953 wells and 326 platforms could ultimately revert to the Company.

•Tell us the amount or range of decommissioning obligations you had anticipated reverting to the company prior to the sale of the “subset” of producible leases;

Company Response:

In the second quarter of 2023, the Company estimated the potential range of exposure related to the Cox bankruptcy as zero to $1.4 billion. The estimate was based on publicly available estimates published by the

Bureau of Safety and Environmental Enforcement (“BSEE”) for nearly all federal leases in the Cox Debtors’ estate for which Chevron had predecessor liability and decommissioning obligations remained outstanding. BSEE estimates provide costs to plug and abandon wells, abandon pipelines, remove platforms, and perform site clearance, and were readily available. At the time of the Cox bankruptcy filing, the Company had access to financial security of approximately $170 million (as detailed below) associated with the assets previously sold to Cox, or to companies acquired by Cox. If the Company could liquidate all financial security, the cost estimate would reduce to $1.2 billion. On the other hand, the Company's exposure could be zero based on examples of other companies that have sold assets from debtors’ estates, where assets that are either producing or capable of producing can reasonably be sold through bankruptcy proceedings, and where debtors reorganize1 around these assets. The Company believed all of the producing assets in the Cox Debtors’ estate would be sold, without the reversion of associated decommissioning obligations to the Company, and therefore assumed the exposure would be lower than the high end of the estimated range, which the Company concluded was not material.

To provide additional context, there were approximately 134 leases with decommissioning obligations outstanding that were in the Cox Debtor’s estate where Chevron was in the chain of title, representing 990 wells and 347 platforms. Approximately 33 of the leases were producing, including approximately 430 wells and 190 platforms. If all of the producing leases were sold, decommissioning costs would not revert to the Company for approximately 43 percent of the wells and 55 percent of the platforms. In that case, the Company’s cost estimate would have been reduced by roughly the same percentage (for reference, 50 percent of our second quarter 2023 and fourth quarter 2023 estimates would have been $700 million and $1,040 million, respectively).

•Tell us when and how the amount or range of decommissioning obligations you had anticipated reverting to company was first estimated; and,

Company Response:

While the Company has been monitoring this risk of exposure since the sale in 2015, it was not until the second quarter of 2023, after the Cox bankruptcy filing, that the Company first estimated the possible range of decommissioning obligations that could revert from Cox. At this time, the Company relied on readily available

1 Examples of other companies in our industry that have recently reorganized from Chapter 11 bankruptcy, without decommissioning obligations reverting to predecessor companies, include the following:

•Ascent Resources Marcellus Holdings, LLC; Case No. 18-10265; Del.; filed 2/6/2018

•EV Energy Partners, L.P.; Case No. 18-10814; Del.; filed 4/2/2018

•Snachez Energy Corp.; Case No. 19-34508; S.D. Texas; filed 8/11/2019

•Whiting Petroleum Corporation, et al; Case No. 20-32021; S.D. Texas; filed 4/1/2020

•Ultra Petroleum Corp., et al; Case No. 20-32631; S.D. Texas; filed 5/14/2020

•Unit Corporation, et al; Case No. 20-32738; S.D. Texas; filed 5/22/2020

•Chesapeake Energy Corporation, et al; Case No. 20-33232; S.D. Texas; filed 6/28/2020

•California Resources Corporation, et. al; Case No. 20-336568, S.D. Texas; filed 7/15/2020

•Lonestar Resources, LP; Case No. 20-34805; S.D. Texas; filed 9/3/2020

•Remora Petroleum, LP; Case No. 20-34037; S.D. Texas; filed 8/12/2020

BSEE P90 decommissioning cost estimates to assess potential range of exposure as zero to $1.4 billion before tax. This estimate reflected nearly all federal leases sold by Chevron to the Cox Debtors and was created using BSEE P90 decommissioning cost estimates to plug and abandon wells, abandon pipelines, remove platforms, and perform site clearance, and was limited to the federal leases in the Cox bankruptcy that had decommissioning obligations outstanding (both producing and non-producing) and for which Chevron was a predecessor in interest.

During the third quarter of 2023, the Company started developing internal estimates, including the estimated time required for decommissioning activity and the possible extent of maintenance and monitoring that could be required. For context, it takes time for the Company to develop quality estimates for complex matters such as costs to decommission assets that were sold many years ago and geographically spread across a large area in the Gulf of Mexico, particularly when such estimate is used to support entries in the Company’s financial statements. In fact, Chevron’s recurring processes for comprehensive asset retirement obligation reviews for individual properties that are owned by the Company take up to six months to develop quality estimates before they are approved by management.

•Tell us whether and when the amount or range of decommissioning obligations you had anticipated reverting to the company was communicated to the board of directors or a committee or subcommittee thereof.

Company Response:

Management, including those responsible for financial reporting, notified the Company’s Board Audit Committee (“BAC”) of the possibility that decommissioning obligations could revert to the Company following the Cox bankruptcy. This notification occurred as management was reviewing the second quarter 2023 Form 10-Q, where it routinely discusses noteworthy topics and new or evolving disclosures. The possibility of the obligations reverting, along with management’s assessment that the obligation was not probable or reasonably possible to be material, was communicated at that time. During the review of the third quarter 2023 Form 10-Q with the BAC, management shared that it was continuing to monitor Cox bankruptcy proceedings and possible exposure, but there was no change to the initial assessment provided in the second quarter.

Because of Cox’s Motion to Abandon certain leases filed on December 12, 2023, the Company re-evaluated the likelihood and extent of its exposure and concluded, in late December 2023, that it was probable and estimable that decommissioning obligations previously assumed by Cox would revert to the Company. Chevron then completed its analysis and was able to finalize the estimate and obtain management concurrence with the amount. Upon these determinations, the Company shared this information with the Board of Directors.

Supplemental information regarding the increase to the estimate between 2Q23 and 4Q23

After Cox filed its Motion to Abandon, the Company reassessed its exposure based on the totality of the new information that was available at that time, including the listing of leases with outstanding decommissioning obligations that would revert to the Company in Cox’s Motion to Abandon, and the announced sale of certain leases to W&T. The Company was then reasonably able to anticipate the overall volume of decommissioning work and prepare a projected timeline for completion of such work. The Company concluded that the overall scope of work was expected to take approximately 10 or more years and the total cost estimate pertaining to the decommissioning obligations related to the Cox bankruptcy was $2.1 billion. The cost estimate developed in the fourth quarter of 2023 was largely based on updated BSEE P90 decommissioning estimates for federal leases, but also included costs associated with maintenance and monitoring as the locations and the anticipated logistical and oversight support costs to oversee the scope of the decommissioning obligations and anticipated duration of such work were now known. Further, because of the identification of the assets in the Motion to Abandon, the Company’s fourth quarter 2023 estimate also included projected costs to abandon rights-of-way, right-of-use easements and state properties that the Cox Debtors sought to abandon (as such estimates are not available in public databases), resulting in additional incremental costs. Estimates were then benchmarked against actual costs incurred from similar projects recently completed by Chevron including Genesis Spar and Neptune Spar decommissioning, following which the cost estimates were further increased. Lastly, leases that were originally included in the second quarter 2023 estimate but were later included in the announced sale to W&T were deducted from the Company’s estimate.

For the reasons described above, the following table summarizes the change in estimate between second quarter 2023 and fourth quarter 2023:

Read in the reply ↗

Regarding the Cox bankruptcy, your response highlights disclosure added to the 2nd quarter 2023 Form 10-Q MD&A after “the company determined that this uncertainty should be disclosed to investors.” Given your stated purpose for adding the disclosure, and in view of the fact that it was added specifically in response to the Cox bankruptcy, explain to us why you believe the added disclosure, which does not include any

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mention of the Cox bankruptcy or describe the specific details of the underlying matter, satisfies either your stated purpose for adding it or the requirements of Item 303 of Regulation S- K.

Item 303 of Regulation S-K requires, among other things, MD&A disclosure of any known trends or uncertainties, but only when those trends or uncertainties are “reasonably likely” to have a material impact on the registrant’s liquidity, capital resources or results of operations. In second quarter 2023, the Company did not believe that the exposure was reasonably likely to have a material effect on the Company’s results of operations or financial condition; however, the Cox bankruptcy filing was a trigger that had the potential to impact future results of operations.

Rest of the answer

As such, the Company determined it would be appropriate to foreshadow this evolving situation and added the referenced MD&A disclosure to identify a key uncertainty, even if not currently expected to be material, from which future losses could materialize that could be significant.

In general, the Company refrains from naming other companies in our public disclosures as some of our commercial agreements contain confidentiality clauses and, in some cases, require prior written consent to disclose certain information. Additionally, given the Company’s earlier experience with Fieldwood, whereby Fieldwood declared bankruptcy in 2018 with resolution that did not impact Chevron, the Company was reluctant to identify Cox by name when significant uncertainties existed regarding the Cox bankruptcy. This, along with the fact that management did not believe that it was reasonably likely that our exposure could be material, further reinforced the decision regarding the nature of the disclosure for the Company’s second quarter 2023 Form 10-Q.

Read in the reply ↗

As described in your response, the risk factor disclosure you provided regarding the potential return to you of liabilities associated with divested assets remained unchanged from 2015 until the filing of your 2023 Form 10-K. Please explain to us your basis for concluding that the unchanged risk factor was adequate and should not have been updated in periodic reports filed in 2023 after Cox declared bankruptcy.

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Refer to Item 105 of Regulation S-K and Part II, Item 1-A of Form 10-Q. In your response, you state that following the 2015 sale to Cox and the 2016 sale to Fieldwood, escrow accounts were established to receive payments from the purchasers (based on a percentage of monthly revenues) to fund future decommissioning activity on the leases. Please provide us with further details regarding the escrow accounts addressing the following points: • Explain why the establishment of escrow accounts to fund future decommissioning activity following the 2015 and 2016 sales was necessary and clarify if the establishment of these types of escrow accounts is common practice by you and your industry peers when entering into sales of oil and gas properties. 5. • Tell us how the percentage of monthly revenues was determined and negotiated between you and the purchasers, providing details sufficient to understand whether the negotiated percentage was based on an estimate of the underlying decommissioning liabilities. • Clarify your rights to the amounts accumulated in the escrow accounts and explain how a lapse of funding to the escrow accounts impact Chevron. To the extent there was a lapse in funding, tell us when this occurred and how it factored into your consideration of whether a loss was reasonably possible. • Tell us the balance of the escrow accounts as of the dates that Cox filed for relief under Chapter 11, and how the balances compared to your estimates of the decommissioning liabilities that you would assume at that time, if any. • Tell us how the escrow account balances were factored into your calculation of the $1.9 billion charge taken in December 2023.

The Company routinely evaluates the need to update risk factors in light of developments that occurred during the reporting period. This evaluation is conducted by a cross-functional team considering both qualitative and quantitative factors. As provided under Part II, Item 1A of Form 10-Q, Form 10-Q only requires material updates to risk factors disclosed in the preceding Form 10-K.

From 2015 until and including the second quarter of 2023, management had determined, based on its analysis at the time, that the exposure was not reasonably likely to be material and that there was significant

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uncertainty surrounding the range of possible exposure. This determination continued into the third quarter of 2023 as there were no material updates that would change this assessment. As a result, the Company determined that in the second and third quarter 2023 Forms 10-Q, no update was necessary to the risk factors regarding the potential return to us of liabilities associated with divested assets.

As explained above, following the Motion to Abandon in December 2023, management determined that the exposure was then probable and estimable and that the estimated amount was material. Accordingly, the

Company updated its risk factor in the 2023 Form 10-K to illustrate that the risk of transferred liabilities returning to the Company, including for abandonment and decommissioning obligations associated with previously sold assets, was no longer hypothetical but had been experienced by the Company.

Read in the reply ↗

You disclose that on October 19, 2023, the Hess board "revisited its prior discussion during its October 6, 2023 meeting concerning the potential benefits and risks of contacting other potential transaction counterparties, and confirmed its view that it would not be in the best interests of Hess and its stockholders to initiate any such outreach." Revise to clarify, if true, that Hess did not explore a business

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combination with any entity other than Chevron during 2023.

In response to the Staff’s comment, Amendment No. 1 has been revised on page 42. Read in the reply ↗

We note that in recommending the merger, the Hess board considered in detail "the opportunities and risks of various potential strategic alternatives available to Hess, including the transaction with Chevron [and] other potentially available strategic transactions...." Please identify any "potentially available strategic transactions" or counterparties which were considered as part of this detailed consideration.

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We also note you disclose that the Chevron merger offered "superior value ... compared with other potential alternative transactions, including the [board's belief], after analysis and discussion with its financial advisors and Hess management, that the limited number of counterparties who could acquire Hess were unlikely to be willing or able to offer more attractive value to Hess’ stockholders than Chevron...." Expand the discussion to clarify what basis the board had for this belief, including whether it specifically considered any other entities of similar or larger size than Chevron in reaching its conclusion that such potential counterparties would be unwilling to offer more attractive value.

In response to the Staff’s comment, Amendment No. 1 has been revised on page 51. Read in the reply ↗

Please provide updated disclosure regarding the status of the FTC review and the need for any approvals from any Guyanese governmental body, agency, or authority of competent jurisdiction.

In response to the

Staff’s comment, Amendment No. 1 has been revised on pages 19, 20, 79 and 107. Read in the reply ↗

Please provide updated disclosure in this section and, as appropriate, in the Risk Factors section, regarding any arbitration or litigation concerning the transaction. In that regard, we note the communication filed by Hess Corporation pursuant to Rule 425 on March 7, 2024 in which Hess discloses that ExxonMobil announced that it is filing for arbitration regarding the applicability of a right of first

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refusal/pre-emption provision in the Stabroek joint operating agreement.

In response to the Staff’s comment, Amendment No. 1 has been revised on pages 29, 32, 38, 81, 82, 83, 84 and 118. Read in the reply ↗

We note the Wachtell form of opinion filed as exhibit 8.1 states: "Because this opinion is required to be delivered in connection with the effectiveness of the Registration Statement, there can be no assurance that it will continue to be valid at the Effective Time." As the discussion of tax consequences in the prospectus relies on the Section 368(a) opinion and the receipt of the opinion appears to be a waivable

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condition, please have counsel revise its opinion to remove this disclaimer and file an executed opinion of counsel before effectiveness. Please also make clear that you will recirculate and resolicit if the condition is waived and the change in tax consequences is material. See Section III.D.3 of Staff Legal Bulletin No. 19 (Corp. Fin., October 14, 2011).

In response to the Staff’s comment, Amendment No. 1 has been revised on page 86 and Exhibit 8.1 to

Amendment No. 1 has also been revised. Read in the reply ↗

We note Hess Corporation's annual report on Form 10-K for the fiscal year ended December 31, 2023 is incorporated by reference. However, the Form 10-K incorporates information from its proxy statement which has not yet been filed.

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Prior to requesting acceleration of the effectiveness of this registration statement, please either amend the Form 10-K to include information required by Part III of Form 10-K or file the definitive proxy statement. Please refer to Question 123.01 of Securities Act Forms Compliance and Disclosure Interpretations for guidance.

The Registrant acknowledges the Staff’s comment and advises the Staff that Part III of Form 10-K will be included in Hess’ definitive proxy statement, which will be filed with the Commission on Schedule 14A prior to the Registrant submitting a request for acceleration of effectiveness of the

Registration Statement. Read in the reply ↗

Please update this section to incorporate by reference Hess Corporation's Form 8-K filed on March 8, 2024. For guidance, refer to Question 123.05 of the Securities Act Forms Compliance and Disclosure Interpretations.

In response to the Staff’s comment, Amendment No. 1 has been revised on page 153. Read in the reply ↗

We note Chevron Corporation's annual report on Form 10-K for the fiscal year ended December 31, 2023 is included as Annex D. However, the Form 10-K incorporates certain Part III information from its proxy statement which has not been filed. Please revise your registration statement to include all information required by Form S-4 and Part III of Form10-K, including Items 401, 402, and 404 of Regulation S-K.

The Registrant acknowledges the Staff’s comment and advises the Staff that Part III of Form 10-K will be included in the Registrant’s definitive proxy statement, which will be filed with the Commission on Schedule 14A prior to the Registrant submitting a request for acceleration of effectiveness of the Registration Statement. Such Part III information will be included as Annex E to the Registration Statement prior to submitting a request for acceleration of effectiveness of the Registration Statement. Read in the reply ↗

We note your new disclosure indicating that the filing of the arbitration relating to the Stabroek ROFR may delay the completion of the merger and that Hess seeks to complete the arbitration by the end of 2024. In light of this new disclosure, ensure that all related disclosures are updated and current.

In response to the Staff’s comment, the disclosures from pages 68 to 74 of Amendment No. 3 that are based on an anticipated closing date have been revised to assume December 31, 2024 as an illustrative closing date. The completion of the merger is subject to factors outside the parties’ control, and therefore this illustrative closing date is not necessarily indicative of the expected closing date of the transaction.

To the extent information set forth in the proxy/prospectus indicates an earlier illustrative closing date, the Registrant has revised the disclosures to expressly state that no

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material changes are expected from the date the information is so presented and the illustrative closing date of December 31, 2024.

Read in the reply ↗

The tax opinion which you filed as Exhibit 8.1 opines that the Merger will qualify as a “reorganization” within the meaning of Section 368(a) of the Code, but it does not constitute a short-form opinion with regard to the disclosure in this section.

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Counsel's opinion expressly states: "We express no opinion on any issue or matter relating to the tax consequences of the transactions contemplated by the Merger Agreement or the Registration Statement other than the opinion set forth above." If you elect to use a short-form opinion, the Exhibit 8 short-form opinion and the tax disclosure in the proxy statement / prospectus both must identify counsel, state clearly that the disclosure in this section is the opinion of the named counsel or accountant, and that disclosure must clearly identify and articulate the opinion being rendered. For reference, please see Staff Legal Bulletin No. 19 at Sections III.A.1 and III.B.2.

In response to the Staff’s comment, pages 86 and 87 and Exhibit 8.1 of Amendment No. 3 have been revised. Read in the reply ↗

We note you present the measure "capital and exploratory expenditures, including equity affiliates" in the table at page 68 and at page 45 in your discussion of liquidity and capital resources. Please tell us how you considered this measure as a non-GAAP measure and how its current presentation in the financial statements and in management's discussion and analysis complies with Item 10(e) of Regulation S-K.

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In this regard, we note that you apply the equity method of accounting to your equity affiliates and therefore own an interest in the investee as a whole rather than having a proportionate legal interest in each financial statement line item, like revenues or expenses. Reflecting these equity method investments using a proportionate consolidation method in a consolidated measure does not appear to be consistent with the guidance in Question 100.04 of the Non- GAAP Compliance and Disclosure Interpretations issued on May 17, 2016. In closing, we remind you that the company and its management are responsible for the accuracy and adequacy of their disclosures, notwithstanding any review, comments, action or absence of action by the staff.

We acknowledge the Staff’s comment and advise the Staff that we do not consider Capital and Exploratory Expenditures (“C&E”) to be a non-GAAP financial measure as defined in Item 10(e) of Regulation S-X; therefore, Question 100.04 of the Non-GAAP CDIs is not applicable. Rather, we consider Capital and Exploratory Expenditures, including equity affiliates (“Total C&E”), to be a key performance indicator (“KPI”).

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We believe the presentation of this KPI is consistent with the Commission Guidance on Management’s Discussion and Analysis (“MD&A”) of Financial Condition and Results of Operation, effective February 25, 2020, that provides guidance on disclosure of KPIs and metrics in MD&A. However, as discussed below, we propose to enhance our disclosure in MD&A. Total C&E is an important metric used by the Company’s management, board of directors, and other key stakeholders that follow us and our industry.

No direct GAAP measure

There is no direct GAAP measure that captures the Company’s total investment level. Total C&E includes additions to properties, plant and equipment and investment and advances made by the Company (included as investing cash outflows in the consolidated Statement of Cash Flows) and exploration expenditures (included as operating cash flows in the consolidated Statement of Cash Flows) for the Company. Exploration expenditures are a key measure for companies with upstream operations and include seismic and other costs incurred at the early stages of an exploration program. The Company also includes its share of similar expenditures made by non-consolidated equity affiliates (not directly reflected in the Company’s financial statements) in Total C&E. Given that there is no comparable GAAP measure that provides a comprehensive view of the Company’s total investment plans and performance, we do not consider this metric to be a non-GAAP measure.

Total C&E is a Key Performance Indicator

Chevron determines Total C&E on an annual basis as part of the Company’s business plan, which is approved by the board of directors. Total C&E for the Company represents its proportionate share of C&E for both its consolidated and equity affiliate companies, and represents total capital reinvested in the business.1 Chevron manages and allocates capital at the portfolio level, which includes both its consolidated subsidiaries and equity affiliates. Management has flexibility and may reallocate capital within the annual budget cycle across businesses (i.e., for both consolidated subsidiaries and its equity affiliates). Equity affiliate C&E has a direct impact on funding requirements for the Company and its affiliates, and it impacts the cash available for dividends from the affiliate to the Company.

For example, Chevron has a 50-percent interest in a non-consolidated equity affiliate that has undertaken a multi-year, major capital project with spend of approximately $45 billion. The affiliate is funding this project from internally generated cash flows and loans; as a result, the affiliate has less cash available to dividend to Chevron. Therefore, while the funding for this project is not in the form of direct capital contributions from the Company to the affiliate, it is impacting the Company’s overall investments and cash flows. As a point of reference, affiliate spending has averaged 29 percent of Total C&E for Chevron over the last three years.

Total C&E is relied on by investors, analysts and rating agencies

Chevron believes that Total C&E provides investors with decision-useful information on the Company’s total investment and capital allocation plans that they are unable to otherwise obtain from the Company’s financial statements. It is also a measure that investors, analysts, and credit rating agencies monitor to assess the Company’s capital intensity, capital discipline and delivery on its financial priorities. With this KPI, stakeholders may evaluate the Company’s total capital spending relative to other sources and uses of cash—including those anticipated to and from affiliates—and observe our flexibility in adjusting spending levels as market conditions

1 Non-controlling interest ("NCI") is inconsequential and is therefore not excluded from consolidated figures. For example, in 2021, NCI was less than $5 million relative to Total C&E of $11.7 billion.

evolve to preserve cash flows, as occurred during the beginning of the COVID-19 pandemic in 2020. Investors, analysts and credit rating agencies are interested in the Company’s Total C&E program, as well as individual asset C&E, as this metric is frequently discussed in investor calls and cited in third party reports.

Prospective Filings

We believe the presentation of “Capital and exploratory expenditures, including equity affiliates” provides decision-useful information for investors for the reasons described above. In connection with responding to the Staff’s comment, we reviewed our disclosure and presented below, for illustrative purposes, is proposed disclosure (using the Company’s 2021 Form 10-K). The Company will endeavor to provide similar levels of disclosure to the below proposed disclosure in its future filings, starting with its Form 10-Q for the quarter ending June 30, 2022.

We will modify the information in Note 3 of the financial statements to only present the components that make up “capital expenditures” as presented on the face of the Consolidated Statement of Cash Flows. This information will exclude exploration costs that are expensed, assets acquired through finance lease obligations, and equity affiliate expenditures. The presentation that we will use in the annual and interim financial statements is presented below in Table 1.

Table 1

Year ended December 31

Millions of Dollars 2021 2020 2019

Additions to properties, plant and equipment $ 7,515 $ 8,492 $ 13,839

Additions to investments 460 136 140

Current-year dry hole expenditures 83 327 124

Payments for other assets and liabilities, net (2) (33) 13

Capital expenditures $ 8,056 $ 8,922 $ 14,116

Management’s Discussion and Analysis

Additionally, we propose to expand our discussion of Total C&E in our Liquidity and Capital Resources section of MD&A, consistent with the Commission Guidance effective February 25, 2020, to include a definition and calculation of this metric and statements as to how it provides useful information to investors and how management uses it to manage and monitor the performance of our business. Our additional disclosure will be similar to the following:

“Capital and exploratory expenditures, including equity affiliates (Total C&E), is a key performance indicator for the Company and provides a comprehensive view of its share of investment levels. This metric includes additions to fixed asset or investment accounts, or to exploration expense, for consolidated companies and our share of these expenditures by equity affiliates. Management uses this metric to manage allocation of capital across its entire portfolio, funding requirements and ultimately shareholder distributions.”

We also propose to add a new table to show the calculation of Total C&E, as illustrated in Table 2, and modify the existing Capital and Exploratory expenditures by business segment table as illustrated in Table 3.

Table 2

Expensed exploration expenditures 431 500 598

Assets acquired through finance leases and other obligations 64 53 181

Payments for other assets and liabilities, net 2 42 (13)

Capital and exploratory expenditures, excluding equity affiliates 8,553 9,517 14,882

Company’s share of expenditures by equity affiliates 3,167 3,982 6,112

Capital and exploratory expenditures, including equity affiliates $ 11,720 $ 13,499 $ 20,994

Table 3

2021 2020 2019

Millions of dollars U.S. Int’l. Total U.S. Int’l. Total U.S. Int’l. Total

Upstream $ 4,698 $ 4,916 $ 9,614 $ 5,130 $ 5,784 $ 10,914 $ 8,197 $ 9,627 $ 17,824

Downstream 1,235 630 1,865 1,021 1,325 2,346 1,868 920 2,788

All Other 221 20 241 226 13 239 365 17 382

Total C&E $ 6,154 $ 5,566 $ 11,720 $ 6,377 $ 7,122 $ 13,499 $ 10,430 $ 10,564 $ 20,994

If you wish to discuss or have any questions related to the information herein, please contact me or Mr. Amit Ghai, Assistant Controller, by telephone at (925) 842-1000.

Read in the reply ↗

We have considered your response to our prior comment. We note your measure of capital and exploratory expenditures, including equity affiliates, and do not agree with your conclusion that the measure is not a non-GAAP financial measure.

Rest of the question

Further, we believe your presentation of this measure is contrary to Question 100.04 of our Non- GAAP Compliance and Disclosure Interpretations and therefore should not be disclosed. Please revise your disclosures to comply with the provisions of Item 10(e) of Regulation S-K and Question 100.04 of the Non-GAAP Compliance and Disclosure Interpretations.

The Company respectfully acknowledges the Staff’s comment and appreciates the opportunity to discuss with the Staff on September 14, 2022, the response previously provided by the Company in its letter dated June 24, 2022, with respect to the Staff’s prior comment. Consistent with such discussion, the Company agrees to no longer disclose the metric “Capital and Exploratory Expenditures, including equity affiliates” (formerly, “Total C&E”).

Chevron Corporation

6001 Bollinger Canyon Road, San Ramon, CA 94583-2324

Tel 925 842 3232

On a prospective basis, we will separately disclose the two

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key performance indicators (“KPIs”): “Capital and Exploratory Expenditures” (“C&E”), and “Equity affiliate Capital and Exploratory expenditures” (“Affiliate C&E”), which represents the Company’s share of expenditures by equity affiliates, in our Management’s Discussion and Analysis (“MD&A”) section.

Further to the above, we propose to expand our discussion of these KPIs in our Liquidity and Capital Resources section of MD&A in a manner substantially similar to the following:

Capital and exploratory expenditures (“C&E”) is a key performance indicator that provides the Company’s investment level in its consolidated companies. This metric includes additions to fixed asset and investment accounts along with exploration expense for its consolidated companies. Management uses this metric along with Affiliate C&E (as defined below) to manage allocation of capital across the company’s entire portfolio, funding requirements and ultimately shareholder distributions.

Equity affiliate capital and exploratory expenditures (“Affiliate C&E”) is a key performance indicator that provides the Company’s share of investments in its significant equity affiliate companies. This metric includes additions to fixed asset and investment accounts along with exploration expense in the equity affiliate companies’ financial statements. Management uses this metric to assess possible funding needs and/or shareholder distribution capacity of the company’s equity affiliate companies. Together with C&E, management also uses Affiliate C&E to manage allocation of capital across the company’s entire portfolio, funding requirements and ultimately shareholder distributions.

We also propose to present, on a prospective basis and in tabular format, the calculation of C&E, as illustrated in Table 1, and modify the existing Capital and Exploratory expenditures by business segment table, as illustrated in Table 2.

Table 1

Year ended December 31

Millions of Dollars 2021 2020 2019

Capital expenditures $ 8,056 $ 8,922 $ 14,116

Expensed exploration expenditures 431 500 598

Assets acquired through finance leases and other obligations 64 53 181

Payments for other assets and liabilities, net

2 42 (13)

Capital and exploratory expenditures (C&E)

$ 8,553 $ 9,517 $ 14,882

Affiliate capital and exploratory expenditures (Affiliate C&E)

$ 3,167 $ 3,982 $ 6,112

Table 2

Capital and Exploratory Expenditures:

2021 2020 2019

Millions of dollars U.S. Int’l. Total U.S. Int’l. Total U.S. Int’l. Total

Upstream $ 4,696 $ 2,512 $ 7,208 $ 5,130 $ 2,867 $ 7,997 $ 8,197 $ 4,446 $ 12,643

Downstream 870 234 1,104 697 584 1,281 1,501 357 1,858

All Other 221 20 241 226 13 239 364 17 381

C&E

$ 5,787 $ 2,766 $ 8,553 $ 6,053 $ 3,464 $ 9,517 $ 10,062 $ 4,820 $ 14,882

Affiliate Capital and Exploratory Expenditures:

Upstream $ 2 $ 2,404 $ 2,406 $ — $ 2,917 $ 2,917 $ — $ 5,181 $ 5,181

Downstream 365 396 761 324 741 1,065 367 563 930

All Other — — — — — — 1 — 1

Affiliate C&E

$ 367 $ 2,800 $ 3,167 $ 324 $ 3,658 $ 3,982 $ 368 $ 5,744 $ 6,112

If you wish to discuss or have any questions related to the information herein, please contact me or Mr. Amit Ghai, Assistant Controller, by telephone at (925) 842-1000.

Read in the reply ↗

Expand the discussion of the changes in the net quantities of your proved undeveloped reserves to include an appropriate narrative explanation relating to each of the items you identity, e.g. revisions, improved recovery, extensions and discoveries, transfers to proved developed, sales and acquisitions.

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To the extent that two or more unrelated factors are combined to arrive at the overall change for an item, your disclosure should separately identify and quantify each individual factor that contributed to a material change so that the change in net reserve quantities between periods is fully explained. The disclosure of revisions in the previous estimates of your proved undeveloped reserves in particular should identify the individual factors such as the changes caused by commodity prices, well performance, unsuccessful and/or uneconomic proved undeveloped locations or the removal of proved undeveloped locations due to changes in a previously adopted development plan. Refer to Item 1203(b) of Regulation S-K. This comment also applies to the narrative explanations provided relating to the changes that occurred in the net quantities of proved crude oil, condensate and synthetic oil; natural gas liquids; and natural gas reserves provided on pages 98 through 102 for each line item shown in the reconciliation, other than production, and for each of the periods presented. Refer to FASB ASC 932-235-50-5.

With respect to the discussion of changes in net quantities of total proved reserves (crude oil, condensate and synthetic oil, natural gas liquids, and natural gas reserves) for each annual period presented, we believe we have provided the disclosures required by FASB ASC 932-235-50-5. Our Form 10-K disclosure provides an explanation for all movements that we consider significant.

Additionally, we believe our disclosures for Proved Undeveloped Reserves (PUD) comply with Item 1203(b) of Regulation S-K when considering the totality of disclosures for both PUD and proved reserves on pages

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97-102 of our 2019 Form 10-K.

In future filings, we will provide a table of the annual PUD changes that occurred during the current year, a three-year version of which is illustrated below, together with expanded narrative regarding the factors that contributed to the material changes in the items identified as impacting proved undeveloped reserves (an example of which is provided under the table below). This is in addition to the existing disclosures for total proved reserves by category and product that are reflected on pages 98-102 of the 2019 Form 10-K.

Proved Undeveloped Reserves (MMboe)

2019

2018

2017

Quantity at January 1

4,647

4,330

3,609

Revisions

(685)

366

Improved Recovery

Extension & Discoveries

635

717

736

Acquisitions

Sales

(31)

(2)

(6)

Transfers to Proved Developed

(593)

(531)

(419)

Quantity at December 31

4,006

In 2019, revisions included (450) MMboe in the Midland and Delaware basins primarily attributed to the company optimizing its development plan targets away from reservoirs with higher gas-to-oil ratios and lower execution efficiencies and (331) MMboe in the Appalachian region associated with the decision to divest the acreage. These negative revisions were partially offset by 96 MMboe of net positive revisions in other operations.

Extensions and Discoveries in 2019 were primarily due to portfolio optimizations in the Midland and Delaware basins of 451 MMboe (where future drilling in various fields is being targeted toward liquids-rich reservoirs with higher execution efficiencies), and in the deepwater fields in the Gulf of Mexico of 125 MMboe. Other operations added 59 MMboe.

Transfers to proved developed in 2019 include (411) MMboe in the United States, primarily unconventional developments, and (182) MMboe in Nigeria, Canada, and other international locations. These transfers are the consequence of development expenditures on completing wells and facilities.

The changes associated with improved recovery, acquisitions and sales were not material in 2019.

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The combined change in the net quantities of proved crude oil, condensate and synthetic oil; natural gas liquids; and natural gas reserves attributed to extensions and discoveries appears to be significantly greater than the corresponding change in the net quantities of proved undeveloped reserves for each of the last three fiscal years presented.

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Expand the discussion of the changes in your total proved reserves attributed to extensions and discoveries to explain the reason(s) for this difference. Refer to FASB ASC 932-235-505.

With respect to the changes in net quantities of total proved crude oil, condensate and synthetic oil, natural gas liquids, and natural gas reserves attributed to extensions and discoveries, we believe we have provided the disclosures required by FASB ASC 932-235-50-5. Our Form 10-K disclosure provides an explanation for all movements that we consider significant.

The table below shows the impact of extensions and discoveries on proved and proved undeveloped reserves along with the differences over the past three years.

Rest of the answer

The differences are due to proved extensions and discoveries that were not recognized as PUDs in the prior periods but rather were recognized directly as proved developed. For 2017-2019, the majority of the differences in extensions and discoveries that were recognized directly as proved reserves (without passing through PUDs), relate to non-operated drilling activity in unconventional developments in the Midland and Delaware basins of the United States, for which proved reserves are recognized when more certainty exists regarding development plans and operational activities.

Extensions & Discoveries (MMboe)

Changes in Proved

774

865

816

Changes in Proved Undeveloped

Difference

139

148

As noted in our response to question 1 above, we will provide an expanded discussion of extensions and discoveries to differentiate the changes in both PUDs and total proved reserves in future filings.

Read in the reply ↗