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Item 2. Management’s Discussion and Analysis

2024-08-07 compared with 2024-05-08 · 346 added, 179 removed, 242 unchanged (68% of the section changed)

Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations

We are an independent oil and natural gas exploration and production and carbon management company operating properties exclusively within California.

We are committed to energy transition and have some of the lowest carbon intensity production in the United States.

We are in the early stages of permitting several carbon capture and storage (CCS) projects in California.

Our carbon management business, which we refer to as Carbon TerraVault, is expected to build, install, operate and maintain CO 2 capture equipment, transportation assets and storage facilities in California.

In August 2022, we entered into a joint venture with BGTF Sierra Aggregator LLC (Brookfield) to pursue carbon management and storage activities (Carbon TerraVault JV) .

For more information about the risks involved in our carbon capture projects, see Part I, Item 1A – Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2023 (2023 Annual Report) and for more information on the Carbon TerraVault JV, see Part I, Item 1 – Financial Statements, Note 3 Investment in Unconsolidated Subsidiary and Related Party Transactions.

Except when the context otherwise requires or where otherwise indicated, all references to ‘‘CRC,’’ the ‘‘Company,’’ ‘‘we,’’ ‘‘us’’ and ‘‘our’’ refer to California Resources Corporation and its consolidated subsidiaries.

Pending Aera Merger

On February 7, 2024, we entered into a definitive agreement and plan of merger (Merger Agreement) to combine with Aera Energy, LLC (Aera) in an all-stock transaction (Aera Merger) with an effective date of January 1, 2024.

Aera is a leading operator of mature fields in California, primarily in the San Joaquin and Ventura basins, with high oil-weighted production.

Pursuant to the Merger Agreement, we have agreed to issue 21,170,357 shares of common stock (subject to customary adjustments in the event of stock splits, dividend paid in stock and similar items) plus an additional number of shares determined by reference to the dividends declared by us having a record date between the effective date and closing as more fully described in the Merger Agreement.

Upon closing, Aera's $950 million outstanding long-term debt will become due as a result of a change in control provision within their legacy debt agreement.

We expect to repay a significant portion of this indebtedness with cash on hand and borrowings under our Revolving Credit Facility.

We intend to refinance the balance through one or more debt capital markets transactions and, only to the extent necessary, borrowings under a bridge loan facility provided by Citigroup Global Markets, Inc.

Under the terms of our debt commitment letter with the Bank, it has committed, subject to satisfaction of customary conditions, to provide us with an unsecured 364-day bridge loan facility in an aggregate principal amount of $500 million (Bridge Loan Facility).

Closing of the Aera Merger is subject to certain conditions, including, among others, approval of the stock issuance by our stockholders, expiration of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (HSR Act), prior authorization by the Federal Energy Regulatory Commission under Section 203 of the Federal Power Act and other customary closing conditions.

The required waiting period under the HSR Act expired on March 25, 2024.

Upon completion of the transaction, we currently expect our existing stockholders to own approximately 77% of the combined company and the existing Aera owners to own approximately 23% of the combined company, on a fully diluted basis.

The Aera Merger is expected to close around mid-year 2024.

Post closing of the Aera Merger, and subject to Board approval, we expect to increase our quarterly dividend.

In the three months ended March 31, 2024, we incurred $13 million of transaction and integration costs related to the Aera Merger included in other operating expenses, net on our condensed consolidated statement of operations.

We also incurred $8 million in financing fees, which is included in other current assets, net on our condensed consolidated balance sheet as of March 31, 2024.

We are an independent energy and carbon management company committed to energy transition.

We are committed to environmental stewardship while safely providing local, responsibly sourced energy.

We are also focused on maximizing the value of our land, mineral ownership, and energy expertise for decarbonization by developing carbon capture and storage (CCS) and other emissions-reducing projects.

On July 1, 2024, we closed on the transactions contemplated by the definitive agreement and plan of merger (Merger Agreement) to obtain all of the ownership interests in Aera Energy, LLC (Aera) with an effective date of January 1, 2024 (Aera Merger).

In connection with the closing of the Aera Merger, we issued 21,315,707 shares of common stock to the Aera owners and paid $990 million in connection with the extinguishment of Aera's outstanding indebtedness using the proceeds from the issuance of the 2029 Senior Notes and cash on hand.

For more information on the 2029 Senior Notes, refer to Part I, Item 1 – Financial Statements, Note 3 Debt.

As of July 1, 2024, immediately following closing of the Aera Merger, our existing stockholders prior to the Aera Merger owned approximately 76% of CRC and the previous owners of Aera owned approximately 24% of CRC.

In the three and six months ended June 30, 2024, we recognized $13 million and $26 million, respectively, of transaction and integration costs related to the Aera Merger which are included in other operating expenses, net on our condensed consolidated statement of operations.

In July 2024, we recognized additional transaction costs of $27 million which were conditioned upon closing.

Recent Debt Transactions

2029 Senior Notes

On June 5, 2024, we completed an offering of $600 million in aggregate principal amount of 8.25% senior notes due 2029 (2029 Senior Notes).

The terms of the 2029 Senior Notes are governed by the Indenture, dated as of June 5, 2024, by and among us, the guarantors and Wilmington Trust, National Association, as trustee (2029 Senior Notes Indenture).

The net proceeds of $590 million, after $10 million of debt discount and issuance costs, were used along with available cash to repay all of Aera's outstanding debt at closing of the Aera Merger.

For more information on the 2029 Senior Notes, refer to Part I, Item 1 – Financial Statements, Note 3 Debt.

Fourth Amendment to the Revolving Credit Facility

On July 1, 2024, we entered into a fourth amendment to our Revolving Credit Facility.

This amendment increased the aggregate revolving commitments available under the Revolving Credit Facility from $630 million to $1.1 billion.

Our ability to borrow under our Revolving Credit Facility is limited to the amount of these commitments.

This amendment also increased the borrowing base from $1.2 billion to $1.5 billion, among other matters.

Business Environment and Industry Outlook

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The following table presents the average daily benchmark prices for oil and natural gas during the periods presented:

Three months ended

March 31, 2024 December 31, 2023

Three months ended Six months ended

June 30, 2024 March 31, 2024 June 30, 2024 June 30, 2023

Brent oil ($/Bbl) $ 85.00 $ 81.84 $ 83.42 $ 80.12

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Regulatory Updates

Setbacks and Senate Bill No.

California Senate Bill No.

1137 establishes 3,200 feet as the minimum distance between new oil and natural gas production wells and certain sensitive receptors such as homes, schools and businesses open to the public and separately imposing a number of potential impact analysis and mitigation and reporting requirements.

The implementation of Senate Bill No.

1137 was stayed pending the outcome of a voter referendum to repeal the bill on the November 2024 ballot.

However, this referendum was withdrawn on June 27, 2024 and the requirements of Senate Bill No.

1137 are no longer stayed.

The majority of our production is in rural areas in the San Joaquin basin and is not affected by Senate Bill No.

In addition to the write-down of reserves previously recorded in 2023, we continue to evaluate the location of projects near setback zones and believe any further reductions to the net present value of our proved undeveloped reserves as a result of the withdrawal of the voter referendum and the implementation of Senate Bill No.

1137 would be less than $14 million based on 2023 SEC prices (with an insignificant impact on our overall proved reserves).

Well Permitting Status

CalGEM remains in the process of developing standard operating procedures for reviewing well permit applications that it commenced in the second half of 2023.

Significant permitting delays continue pending CalGEM’s completion of this process.

An increase in permits approvals for workovers has continued through the first quarter of 2024, and substantially increased in April 2024.

As of May 6, 2024, we have received 73 permits for workovers since the beginning of the year.

As of May 6, 2024, we have also received 8 permits for deepenings and 1 permit for a sidetrack for wells in our Wilmington field.

With only a few exceptions, there continues to be no new drill permits issued in the state.

Kern County EIR Litigation

On March 7, 2024, the California Court of Appeals, Fifth Appellate District (Court of Appeals), issued its ruling on the six challenges to Kern County’s Supplemental Recirculated Environmental Impact Report (SREIR) for Kern County Zoning Ordinance G-8992 (Ordinance).

In its disposition, the Court of Appeals ordered the Trial Court to enter a modified judgement and fourth preemptory writ directing Kern County (i) to set aside approval of the Ordinance, SREIR and related findings of facts and statements of overriding considerations;

and (ii) not to present a revised Ordinance for approval until Kern County has (a) prepared a revised SREIR that corrects CEQA violations relating to the (1) rejection of agricultural conservation easements as a form of partial mitigation for the conversion of agricultural land, (2) assessment of cancer risks associated with the drilling of multiple wells near sensitive receptors and (3) analysis of water supply impacts;

and (b) circulated the revised SREIR for public review and comment, prepared responses to comments, and certified the revised SREIR.

On March 22, 2024, Kern County released a notice of preparation of the Second Supplemental Revised Environmental Impact Report (SSREIR).

We expect that Kern County will prepare a draft SSREIR, circulate it for public comments and thereafter certify the SSREIR and approve the Ordinance.

After that, the Trial Court would then consider whether to lift the stay.

If that occurs, well permitting could resume assuming no further challenges to the SSREIR.

As a result of the ruling of the Court of Appeals in the Kern County EIR litigation and current lack of permits with respect to our Kern County properties, we currently plan to operate one drilling rig within Kern County in 2024.

We have sufficient permits in hand to keep that rig active through the end of 2025.

CCS Project Permitting

In December 2023, Kern County released a draft EIR prepared in connection with our application for conditional use permits for our CTV I CCS project.

The project was originally scheduled to be considered by the Kern County Planning Commission on March 28th;

however, based on comments received the Planning Commission required further environmental review before it can consider the project and the draft EIR.

The Planning Commission recommended that the consideration of applicable changes to the zoning ordinance and certification of the EIR be continued to the August 22, 2024 Planning Commission hearing, at which the Planning Commission will decide whether to recommend the adoption of the changes to the zoning ordinance and certification of the EIR to the Board of Supervisors.

The Board of Supervisors meeting is expected to occur in or around September or October.

Low Carbon Fuel Standard

On February 14, 2024, the California Air Resources Board (CARB) announced that it was postponing the previously scheduled March 21, 2024, public hearing regarding the proposed amendments to the LCFS Regulation released on December 19, 2023.

Due to continuous substantial public feedback on the proposed amendments, CARB intends to release revised proposed amendments for public review and comment, to be followed by a public hearing.

The release of the revised proposed amendments is pending.

These revisions may impact the eligibility of certain of our CCS projects for LCFS credits.

An increase in approvals for workovers has continued in the course of the first half of 2024.

As of June 30, 2024, we have received 364 permits for workovers (including permits received by Aera) since the beginning of the year.

In July 2024, following discussions with CalGEM and further internal review of our development portfolio, we relinquished eight permits for deepenings that we had received in April and May 2024.

In May and June 2024, CalGEM issued a number of new well permits to other operators in the state.

These permits were issued outside of Kern County or in reliance on an environmental impact analysis other than the Kern County EIR to comply with CEQA.

We are pursuing a similar strategy of seeking conditional use permits with respect to our Elk Hills, Buena Vista and Kern Front fields that would allow us to comply with CEQA requirements separate from the Kern County EIR.

However, our ability to obtain these conditional use permits is uncertain and we may not be successful in obtaining such permits in a timely manner or at all.

Following the withdrawal of the voter referendum regarding Senate Bill 1137 discussed above, CalGEM returned to operators all pending permit applications to be resubmitted with the information required under that law.

CRC and Aera resubmitted substantially all permit applications in accordance with the requirements of this law, excluding permit applications for approximately 150 workovers and approximately 40 deepenings and sidetracks located in setback zones.

The resubmission of these permit applications may result in further delays with CalGEM, including with respect to permit applications for wells not located in setback zones.

CCS Project Permitting Status

On June 4, 2024, Kern County released a Draft Recirculated Environmental Impact Report (DREIR) in connection with our application for conditional use permits for our CTV I CCS project.

As expected, the public comment period closed on July 18, 2024 and the project is scheduled for consideration by the Kern County Planning Commission on August 22, 2024, at which time the Planning Commission will decide whether to recommend the adoption of changes to the zoning ordinance and certification of the DREIR to the Board of Supervisors.

The Board of Supervisors is scheduled to meet to consider this matter later this year.

Water Injection

Our operations in the Wilmington Oil Field utilize injection wells to reinject produced water pursuant to waterflooding plans.

These operations are subject to oversight by the City of Long Beach and CalGEM.

Following discussions with the City of Long Beach and CalGEM with respect to the level of injection well pressure gradient needed to comply with CalGEM’s requirements for the protection of underground aquifers, while at the same time mitigating subsidence risks, CalGEM provided a directive to reduce the injection well pressure in a gradual manner.

In response to this directive, we were required to implement a five-year injection reduction work plan.

The first phase of reduction commenced July 1, 2024, and focuses on reducing pressure gradients in the zones at higher starting pressure.

We continue to evaluate the work plan with CalGEM, including any subsidence risk, and the work plan may be adjusted further in the future.

Given this uncertainty, it is difficult to predict with certainty the impact to production and reserves.

However, assuming no adjustments to the current work plan, we currently estimate on a preliminary basis that the net present value of our proved developed reserves would be negatively impacted by less than 1%.

We also estimate on a preliminary basis, a negative impact on production of approximately 1 MBoe/d at the end of the 5-year work plan.

These estimates are preliminary and could change materially pending the results of our year-end reserve process and technical audits.

Opposition toward oil and gas drilling and development activity has been growing over time.

Companies in the oil and gas industry are often the target of efforts to delay or prevent oil and gas development by non-governmental organizations and individuals.

This opposition also extends to our carbon management business as certain activists oppose carbon capture and sequestration efforts by the oil and gas industry.

These activists use a variety of tactics that primarily rely on allegations regarding safety, environmental compliance and business practices.

At both the state and federal level, these tactics include seeking changes to laws, pressuring governmental agencies to promulgate regulations or engage in rulemaking, or pursuing litigation.

For example, we are currently a named real party in interest in Center for Biological Diversity v.

City of Long Beach, Long Beach City Council, California State Lands Commission, et al.

, a lawsuit brought by an environmental non-governmental organization that seeks the shut down of the Long Beach Unit on the basis of a purported CEQA violation by certain governmental entities.

While we believe that the defendants will prevail in this matter and do not otherwise expect its disposition will result in a material adverse effect on our business or operations, we cannot predict the outcome of any litigation with certainty.

Results of Oil and Gas Operations

The following table sets forth our average net production of oil, NGLs and natural gas per day in each of the California oil and natural gas basins in which we operated for the periods presented.

Three months ended

March 31, 2024 December 31, 2023

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June 30, 2024 March 31, 2024 June 30, 2024 June 30, 2023

San Joaquin Basin 30 30 30 35

Los Angeles Basin 17 18 17 19

Total 47 48 47 54

NGLs (MBbl/d)

San Joaquin Basin 10 11 11 11

Total 10 11 11 11

Natural gas (MMcf/d)

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Total Net Production (MBoe/d) 76 76 76 88

Total daily net production for the three months ended March 31, 2024 compared to the three months ended December 31, 2023 decreased by 7 MBoe/d predominately due to scheduled plant downtime during the first quarter of 2024.

The decrease in production also reflects natural production decline as well as the divestiture of our share of a non-operated field in December 2023.

Our production-sharing contracts (PSCs), which are described below, did not have a significant impact on our net oil production in the three months ended March 31, 2024 compared to the three months ended December 31, 2023.

Total daily net production for the three months ended June 30, 2024 remained flat compared to the three months ended March 31, 2024.

Total daily net production for the three months ended March 31, 2024 was negatively impacted by 3 Mboe/d due to scheduled maintenance at our Elk Hills power plant.

Total daily net production for the three months ended June 30, 2024 was also negatively impacted by approximately 3 Mboe/d as a result of scheduled maintenance and unplanned downtime at our Elk Hills power plant.

Our PSCs, which are described below, did not have a significant impact on our net oil production in the three months ended June 30, 2024 compared to the three months ended March 31, 2024.

Total daily net production decreased by 12 Mboe/d from 88 MBoe/d during the six months ended June 30, 2023 to 76 Mboe/d during the six months ended June 30, 2024 primarily due to natural production decline, downtime at our Elk Hills power plant as well as the divestiture of our share of a non-operated field in December 2023.

Our PSCs, which are described below, negatively impacted our net oil production by 1 MBoe/d in the six months ended June 30, 2024 compared to the six months ended June 30, 2023.

The following table reconciles our average net production to our average gross production (which includes production from the fields we operate and our share of production from fields operated by others) for the periods presented:

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March 31, 2024 December 31, 2023

Three months ended Six months ended

June 30, 2024 March 31, 2024 June 30, 2024 June 30, 2023

Total Net Production 76 76 76 88

Partners' share under PSC-type contracts 7 7

Partners' share under PSCs

Working interest and royalty holders' share 7 7 6 8

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Production-Sharing Contracts (PSCs)

Our share of production and reserves from operations in the Wilmington field in the Los Angeles basin is subject to contractual arrangements similar to production-sharing contracts (PSCs) that are in effect through the economic life of the assets.

The reporting of our PSC-type contracts creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs.

Operating costs, excluding effects of PSC-type contracts is a non-GAAP measure which adjusts for excess costs attributable to PSC-type contracts for the periods presented in the tables below:

Our share of production and reserves from operations in the Wilmington field in the Los Angeles basin is subject to contractual arrangements similar to production-sharing contracts that are in effect through the economic life of the assets.

The reporting of our PSCs creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs.

Operating costs, excluding effects of PSCs, is a non-GAAP measure which adjusts for excess costs attributable to PSCs for the periods presented in the tables below:

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March 31, 2024 December 31, 2023

June 30, 2024 March 31, 2024

(in millions) ($ per Boe) (in millions) ($ per Boe)

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$ 159 $ 23.14 $ 179 $ 25.80

Excess costs attributable to PSC-type contracts (18) (2.54) (17) (2.22)

Operating costs, excluding effects of PSC-type contracts $ 161 $ 23.26 $ 169 $ 22.27

Excess costs attributable to PSCs

(17) (2.48) (18) (2.54)

Operating costs, excluding effects of PSCs

$ 142 $ 20.66 $ 161 $ 23.26

(a) Operating costs related to our exploration and production activities and are presented before elimination entries.

Six months ended

June 30, 2024 June 30, 2023

(in millions) ($ per Boe) (in millions) ($ per Boe)

Operating costs (a)

$ 338 $ 24.48 $ 440 $ 27.71

Excess costs attributable to PSCs

(35) (2.51) (35) (2.19)

Operating costs, excluding effects of PSCs

$ 303 $ 21.97 $ 405 $ 25.52

(a) Operating costs related to our exploration and production activities and are presented before elimination entries.

For further information on our production-sharing contracts, see Part I, Item 1 & 2 Business and Properties, Oil and Natural Gas Operations, Production, Price and Cost History in our 2023 Annual Report.

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March 31, 2024 December 31, 2023

June 30, 2024 March 31, 2024

Price Realization Price Realization

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Realized price ($/Mcf) $ 1.78 94% $ 3.90 174%

Six months ended

June 30, 2024 June 30, 2023

Price Realization Price Realization

Oil ($ per Bbl)

Brent $ 83.42 $ 80.12

Realized price without derivative settlements $ 81.63 98% $ 77.25 96%

Derivative settlements (2.43) (13.90)

Realized price with derivative settlements $ 79.20 95% $ 63.35 79%

WTI $ 78.77 $ 74.95

Realized price without derivative settlements $ 81.63 104% $ 77.25 103%

Realized price with derivative settlements $ 79.20 101% $ 63.35 85%

NGLs ($ per Bbl)

Realized price (% of Brent) $ 48.76 58% $ 50.88 64%

Realized price (% of WTI) $ 48.76 62% $ 50.88 68%

NYMEX Henry Hub ($/MMBtu) - Average Monthly Settled Price $ 2.07 $ 2.76

Realized price ($/Mcf)

$ 2.81 136% $ 12.44 451%

Oil — Brent prices were relatively flat for the three months ended March 31, 2024 compared to the three months ended December 31, 2023.

The slight decline in Brent prices is attributable to general market factors, including developing concern over the strength of China’s economy.

NGLs — NGL prices for the three months ended March 31, 2024 increased compared to the three months ended December 31, 2023 due to slightly stronger butane demand and development of alternative markets for our natural gasoline.

California remained a premium market compared to other North American locations.

Natural Gas — Natural gas prices decreased for the three months ended March 31, 2024 compared to the three months ended December 31, 2023 driven by growing natural gas production nationally and a surplus of natural gas in storage both nationally as well as in California.

Oil — Brent prices were higher for the three months ended June 30, 2024 compared to the three months ended March 31, 2024.

The increase in Brent prices is attributable to heightened geopolitical tensions as well as the OPEC+ decision to continue with voluntary production cuts of 2.2 million barrels per day.

Brent prices were higher for the six months ended June 30, 2024 compared to the six months ended June 30, 2023 due to global supply and demand factors signaling a continuing supply deficit in 2024 given OPEC+ resolve.

NGLs — NGL prices for the three months ended June 30, 2024 decreased compared to the three months ended March 31, 2024 reflecting traditional seasonality between quarters for NGL pricing.

NGL prices for the six months ended June 30, 2024 decreased compared to the six months ended June 30, 2023 primarily as a result of the ongoing supply and demand imbalance as a result of a generally mild North American winter in 2024.

Natural Gas — Natural gas prices decreased for the three months ended June 30, 2024 compared to the three months ended March 31, 2024 driven by seasonality between quarters and an abundance of natural gas in storage exiting winter.

Natural gas prices decreased for the six months ended June 30, 2024 compared to the six months ended June 30, 2023.

In California, specifically, these results reflect record-setting prices for the period in 2023 versus near-record levels of gas in storage across the same period in 2024.

Statements of Operations Analysis

The following table includes key operating data for our oil and gas operations, excluding certain corporate expenses and intercompany eliminations, for the three months ended March 31, 2024 and December 31, 2023.

All metrics are shown on a per Boe basis except as otherwise stated.

Energy operating costs consist of purchased natural gas used to generate electricity for our operations and steam for our steamfloods, purchased electricity and internal costs to generate electricity used in our operations.

1 unchanged sentence

Non-energy operating costs equal total operating costs less energy operating costs and gas processing costs.

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June 30, 2024 March 31, 2024 June 30, 2024 June 30, 2023

($ per Boe, except as otherwise stated)

Total net production (MBoe/d)

Total oil, natural gas and NGL sales (in millions)

$ 416 $ 435 $ 851 $ 1,162

Energy operating costs

1 unchanged sentence

Gas processing costs

0.44 0.58 0.51 0.63

Non-energy operating costs

16.30 17.15 16.73 15.56

Operating costs

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(b) Excludes depreciation, depletion and amortization related to our corporate assets and our Elk Hills power plant.

Energy operating costs were lower on a per Boe basis during the three months ended March 31, 2024 compared to the three months ended December 31, 2023 where the benefit of lower electricity and natural gas prices was predominately offset by lower production volumes between periods.

Non-energy operating costs were higher on a per Boe basis between the three months ended March 31, 2024 compared to the three months ended December 31, 2023 due to lower production volumes between periods.

Energy operating costs were lower on a per Boe basis during the three months ended June 30, 2024 compared to the three months ended March 31, 2024 as well as during the six months ended June 30, 2024 compared to the six months ended June 30, 2023.

The decreases between periods were predominantly a result of lower natural gas prices, partially offset by lower production volumes between periods.

Non-energy operating costs were lower on a per Boe basis during the three months ended June 30, 2024 compared to the three months ended March 31, 2024 due to less downhole maintenance activity.

Non-energy operating costs were lower during the six months ended June 30, 2024 compared to the six months ended June 30, 2023 due to reduced downhole maintenance and surface maintenance activity in 2024.

Non-energy operating costs were higher on a per Boe basis during the six months ended June 30, 2024 compared to the six months ended June 30, 2023 as a result of lower production volumes.

Consolidated Results of Operations

For financial information related to our subsidiaries designated as Unrestricted Subsidiaries under the Senior Notes Indenture, see Part I, Item 1 – Financial Statements, Note 13 Condensed Consolidated Financial Information.

For financial information related to our subsidiaries designated as Unrestricted Subsidiaries under the 2026 Senior Notes Indenture and 2029 Senior Notes Indenture, see Part I, Item 1 – Financial Statements, Note 12 Condensed Consolidated Financial Information.

We closed the Aera Merger on July 1, 2024 and the Results of Operations do not contain the results of Aera for the periods presented.

For more information on the Aera Merger, see Part I, Item 1 – Financial Statements, Note 13 Subsequent Events.

Certain prior period balances related to NGL marketing activities have been reclassified to conform to our 2024 presentation.

For the three months ended December 31, 2023, we reclassified $4 million related to NGL storage activities from other revenue to revenue from marketing of purchased commodities on our condensed consolidated statement of operations.

We also reclassified $3 million of NGL processing fees from other operating expenses, net to costs related to marketing of purchased commodities.

Three months ended March 31, 2024 compared to December 31, 2023

The following table presents our consolidated operating revenues for the three months ended March 31, 2024 and December 31, 2023:

For the six months ended June 30, 2023, we reclassified $3 million related to NGL storage activities from other revenue to revenue from marketing of purchased commodities on our condensed consolidated statement of operations.

Three months ended June 30, 2024 compared to March 31, 2024

The following table presents our consolidated operating revenues for the three months ended June 30, 2024 and March 31, 2024:

Three months ended

March 31, 2024 December 31, 2023

June 30, 2024 March 31, 2024

(in millions)

Oil, natural gas and NGL sales $ 412 $ 429

Net (loss) gain from commodity derivatives

Net gain (loss) from commodity derivatives

Revenue from marketing of purchased commodities

2 unchanged sentences

Total operating revenues $ 514 $ 454

Oil, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the effects of cash settlements on our commodity derivative contracts, were $429 million for the three months ended March 31, 2024, which is a decrease of $54 million compared to $483 million for the three months ended December 31, 2023.

This decrease was primarily due to lower production volumes and lower realized prices for the first quarter of 2024 as shown in the table below.

The effect of cash settlements on our commodity derivative contracts is not included in the table below.

Oil NGLs Natural Gas Total

Oil, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the effects of cash settlements on our commodity derivative contracts, were $412 million for the three months ended June 30, 2024, which is a decrease of $17 million compared to $429 million for the three months ended March 31, 2024.

The components of the decrease in the second quarter of 2024 are shown in the table below.

The effect of cash settlements on our commodity derivative contracts and the elimination of intercompany sales related to natural gas sold to our power plant are not included in the table below.

Oil NGLs Natural Gas Total Operations

(in millions)

Three months ended December 31, 2023 $ 380 $ 47 $ 56 $ 483

Three months ended March 31, 2024 (a)

$ 348 $ 49 $ 38 $ 435

Change in realized prices

2 unchanged sentences

(9) (1) 1 (9)

Change in intercompany sales of natural gas

Three months ended March 31, 2024 $ 348 $ 49 $ 32 $ 429

Three months ended June 30, 2024 (b)

$ 353 $ 45 $ 18 $ 416

See Production for volumes by commodity type and Prices and Realizations for index and realized prices for comparative periods.

Net (loss) gain from commodity derivatives — Net loss from commodity derivatives was $71 million for the three months ended March 31, 2024 compared to net gain of $119 million for the three months ended December 31, 2023.

The net loss from commodity derivatives primarily resulted from changes in the fair value of our outstanding commodity derivatives from the positions held as well as the relationship between contract prices and the associated forward curves at the end of each measurement period.

Payments on commodity derivatives were $12 million for the three months ended March 31, 2024 compared to $49 million for the three months ended December 31, 2023.

Including the effect of settlement payments for commodity derivatives, the realized prices received for our oil, natural gas and NGL sales decreased by $17 million compared to the three months ended December 31, 2023.

(a) Excludes a $6 million intercompany elimination related to natural gas sold to our Elk Hills power plant.

(b) Excludes a $4 million intercompany elimination related to natural gas sold to our Elk Hills power plant.

Net gain (loss) from commodity derivatives — Net gain from commodity derivatives was $5 million for the three months ended June 30, 2024 compared to net loss of $71 million for the three months ended March 31, 2024.

The net gain (loss) from commodity derivatives primarily resulted from changes in the fair value of our outstanding commodity derivatives from the positions held as well as the relationship between contract prices and the associated forward curves at the end of each measurement period.

Payments on commodity derivatives were $6 million for the three months ended June 30, 2024 compared to $12 million for the three months ended March 31, 2024.

Including the effect of settlement payments for commodity derivatives, the realized prices received for our oil, natural gas and NGL sales decreased by $11 million compared to the three months ended March 31, 2024.

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March 31, 2024 December 31, 2023

June 30, 2024 March 31, 2024

(in millions)

Non-cash commodity derivative (loss) gain

Non-cash commodity derivative gain (loss)

Settlements and premiums

Net (loss) gain from commodity derivatives

Electricity sales — Electricity sales decreased by $27 million to $15 million for the three months ended March 31, 2024 compared to $42 million for the three months ended December 31, 2023 due to downtime at our Elk Hills power plant for planned maintenance and lower electricity prices in the first quarter of 2024.

The following table presents our consolidated operating and non-operating expenses and income for the three months ended March 31, 2024 and December 31, 2023:

Net gain (loss) from commodity derivatives

Revenue from marketing of purchased commodities — Revenue from marketing of purchased commodities decreased $23 million to $51 million in the three months ended June 30, 2024 from $74 million in the three months ended March 31, 2024.

The decrease was predominantly due to lower natural gas prices in the second quarter compared to the first quarter of 2024.

Revenue from marketing of purchased commodities net of costs related to marketing of purchased commodities was $8 million for the three months ended June 30, 2024 compared to $20 million for the three months ended March 31, 2024.

Electricity sales — Electricity sales increased by $21 million to $36 million for the three months ended June 30, 2024 compared to $15 million for the three months ended March 31, 2024 due to fewer days of downtime at our Elk Hills power plant for maintenance in the second quarter of 2024 and higher revenue from capacity agreements coming into the summer months.

The following table presents our consolidated operating and non-operating expenses and income for the three months ended June 30, 2024 and March 31, 2024:

Three months ended

March 31, 2024 December 31, 2023

June 30, 2024 March 31, 2024

(in millions)

5 unchanged sentences

Depreciation, depletion and amortization 53 53

Asset impairment 13 —

Taxes other than on income 39 38

8 unchanged sentences

Gain on asset divestitures 1 6

Operating (loss) income

Operating income (loss)

Non-operating (expenses) income

Interest and debt expense (17) (13)

Loss on early extinguishment of debt

Loss from investment in unconsolidated subsidiary (4) (3)

Other non-operating (expenses) income

Income (loss) before income taxes

Income tax (provision) benefit

Net income (loss)

Energy operating costs — Energy operating costs for the three months ended June 30, 2024 were $41 million, which was a decrease of $12 million from $53 million for the three months ended March 31, 2024.

This decrease was primarily the result of lower natural gas prices in the three months ended June 30, 2024.

For more information on natural gas market prices, see Prices and Realizations above.

Asset impairments — During the three months ended June 30, 2024 we recognized a $13 million impairment for excess and obsolete materials and supplies related to our oilfield operations.

We did not recognize an asset impairment for the three months ended March 31, 2024.

Costs related to marketing of purchased commodities — Costs related to marketing of purchased commodities were $43 million for the three months ended June 30, 2024 compared to $54 million for the three months ended March 31, 2024.

The decrease of $11 million was primarily due to lower natural gas prices in the three months ended June 30, 2024 compared to the three months ended March 31, 2024.

This decrease was partially offset by higher volumes of purchased third-party crude oil in the three months ended June 30, 2024.

Other operating expenses, net — Other operating expenses, net increased $14 million to $51 million for the three months ended June 30, 2024 compared to $37 million for the three months ended March 31, 2024.

The increase was predominantly due to expenses related to transaction and integration costs related to the Aera Merger.

Six months ended June 30, 2024 compared to June 30, 2023

The following table presents our operating revenues for the six months ended June 30, 2024 and June 30, 2023:

Six months ended

June 30, 2024 June 30, 2023

(in millions)

Oil, natural gas and NGL sales $ 841 $ 1,162

Net (loss) gain from commodity derivatives

Revenue from marketing of purchased commodities 125 259

Electricity sales 51 102

Other revenue 17 19

Total operating revenues $ 968 $ 1,615

Oil, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the effects of cash settlements on our commodity derivative contracts, were $841 million for the six months ended June 30, 2024, which is a decrease of $321 million compared to $1,162 million for the six months ended June 30, 2023.

This decrease was primarily due to changes in realized prices as shown in the table below, including lower realized prices for natural gas and NGLs, partially offset by higher realized prices for oil.

Oil, natural gas and NGL sales were also impacted by lower production volumes across all commodities.

The effect of cash settlements on our commodity derivative contracts and the elimination of intercompany sales related to natural gas sold to our power plant are not included in the table below.

Oil NGLs Natural Gas Total Operations

(in millions)

Six months ended June 30, 2023 $ 752 $ 104 $ 306 $ 1,162

Change in realized prices 43 (4) (237) (198)

Change in production (94) (6) (13) (113)

Six months ended June 30, 2024 (a)

$ 701 $ 94 $ 56 $ 851

See Production for volumes by commodity type and Prices and Realizations for index and realized prices for comparative periods.

(a) Excludes a $10 million intercompany elimination related to natural gas sold to our Elk Hills power plant.

Net (loss) gain from commodity derivatives — Net loss from commodity derivatives was $66 million for the six months ended June 30, 2024 compared to a net gain of $73 million for the six months ended June 30, 2023.

The net (loss) gain from commodity derivatives primarily resulted from changes in the fair value of our outstanding commodity derivatives from the positions held as well as the relationship between contract prices and the associated forward curves at the end of each measurement period.

Payments on commodity derivatives were $18 million for the six months ended June 30, 2024 compared to payments of $128 million for the six months ended June 30, 2023.

Payments on commodity derivatives for the six months ended June 30, 2023 included settlements for hedges that were entered into at a lower commodity price due to the requirements of our Revolving Credit Facility at that time.

Including the effect of settlement payments for commodity derivatives, our oil, natural gas and NGL sales decreased by $211 million compared to the six months ended June 30, 2023.

Six months ended

June 30, 2024 June 30, 2023

(in millions)

Non-cash commodity derivative (loss) gain

Net cash payments on settled commodity derivatives (18) (128)

Net (loss) gain from commodity derivatives

Revenue from marketing of purchased commodities — Revenue from marketing of purchased commodities was $125 million for the six months ended June 30, 2024, which was a decrease of $134 million from $259 million during the six months ended June 30, 2023.

The decrease was primarily the result of lower natural gas prices in 2024 compared to 2023.

This decrease was partially offset by higher sales of purchased crude oil in 2024.

Revenue from marketing of purchased commodities net of costs related to marketing of purchased commodities was $28 million for the six months ended June 30, 2024 compared to $108 million for the six months ended June 30, 2023.

Electricity sales — Electricity sales decreased by $51 million to $51 million for the six months ended June 30, 2024 compared to $102 million for the six months ended June 30, 2023 due to scheduled maintenance and unplanned downtime at our Elk Hills power plant in the six months ended June 30, 2024.

This decrease was partially offset by higher revenues from capacity agreements due to higher prices in six months ended June 30, 2024 as compared to the prior comparative period.

The following table presents our operating and non-operating expenses and income for the six months ended June 30, 2024 and 2023:

Six months ended

June 30, 2024 June 30, 2023

(in millions)

Operating expenses

Energy operating costs $ 94 $ 183

Gas processing costs 7 10

Non-energy operating costs 231 247

General and administrative expenses 120 136

Depreciation, depletion and amortization 106 114

Asset impairment 13 3

Taxes other than on income 77 84

Exploration expense 1 2

Purchased natural gas marketing expense

Electricity generation expenses 22 62

Transportation costs 37 33

Accretion expense 25 23

Carbon management business expenses

Other operating expenses, net 88 21

Total operating expenses 941 1,082

Gain on asset divestitures

Operating income 34 540

Non-operating (expenses) income

Interest and debt expense (30) (28)

Loss from investment in unconsolidated subsidiary (7) (3)

Other non-operating income

2 unchanged sentences

Net (loss) income

Energy operating costs — Energy operating costs for the three months ended March 31, 2024 were $53 million, which was a decrease of $12 million from $65 million for the three months ended December 31, 2023.

This decrease was primarily the result of lower electricity and natural gas prices in the first quarter of 2024.

For more information on natural gas market prices, see Prices and Realizations above.

General and administrative expenses — General and administrative (G&A) expenses were $57 million for the three months ended March 31, 2024, which was a decrease of $9 million from $66 million for the three months ended December 31, 2023.

The decrease in G&A expenses was primarily attributable to a reduction in compensation-related expenses.

Stock-based compensation awards are granted under our stock-based compensation plans to executives, non-executive employees and non-employee directors that are either settled with shares of our common stock or cash.

Energy operating costs — Energy operating costs for the six months ended June 30, 2024 were $94 million, which was a decrease of $89 million from $183 million for the six months ended June 30, 2023.

This decrease was a result of lower natural gas prices in the six months of 2024 compared to the same prior year period.

For more information on our natural gas market prices, see Prices and Realizations above.

Non-energy operating costs — Non-energy operating costs were $231 million for the six months ended June 30, 2024, which was a decrease of $16 million from $247 million for the six months ended June 30, 2023.

The decrease was primarily due to lower downhole and surface maintenance activities combined with more favorable vendor pricing for certain items in 2024 as a result of cost savings initiatives undertaken during 2023.

General and administrative expenses — General and administrative (G&A) expenses were $120 million for the six months ended June 30, 2024, which was a decrease of $16 million from $136 million for the six months ended June 30, 2023.

The decrease in G&A expenses was primarily attributable to lower compensation-related expenses.

G&A expenses were also lower in the six months ended June 30, 2024 compared to the same prior year period as a result in reduced spending on information technology infrastructure.

Stock-based compensation awards are discussed further below.

The table below shows G&A expenses for our exploration and production business (in addition to unallocated corporate overhead and other) separately from our carbon management business.

The amounts shown for our carbon management business do not include expenses borne by the Carbon TerraVault JV.

Six months ended

June 30, 2024 June 30, 2023

(in millions)

Exploration and production, corporate and other

Carbon management business

Total general and administrative expenses $ 120 $ 136

Awards are granted under our stock-based compensation plans to executives, non-executive employees and non-employee directors that are either settled with shares of our common stock or cash.

Our equity-settled awards granted to executives include performance stock units and restricted stock units that either cliff vest at the end of a two- or three-year period or vest ratably over a two- or three-year period.

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Stock-based compensation included in G&A expense is shown in the table below:

Three months ended

March 31, 2024 December 31, 2023

Six months ended

June 30, 2024 June 30, 2023

(in millions)

2 unchanged sentences

Total included in general and administrative expenses $ 17 $ 22

Costs related to marketing of purchased commodities — Costs related to marketing of purchased commodities were $54 million for the three months ended March 31, 2024 compared to $42 million for the three months ended December 31, 2023.

The increase of $12 million was primarily due to higher purchases of third-party crude oil.

Electricity generation expenses — Electricity generation expenses for the three months ended March 31, 2024 were $8 million, which was a decrease of $10 million from $18 million for the three months ended December 31, 2023.

This decrease was primarily due to lower variable operating costs due to downtime resulting from scheduled maintenance of our Elk Hills power plant in the first quarter of 2024.

Other operating expenses, net — Other operating expenses, net increased $16 million to $37 million for the three months ended March 31, 2024 compared to $21 million for the three months ended December 31, 2023.

The increase was predominately due to additional expenses related to electricity purchased during the scheduled maintenance at our Elk Hills power plant as well as transaction and integration costs related to the Aera Merger.

Income taxes — The income tax benefit for the three months ended March 31, 2024 was $9 million (representing an effective tax rate of 47%), compared to a provision of $79 million (representing an effective tax rate of 30%) for the three months ended December 31, 2023.

We recognized an excess tax benefit as a discrete adjustment in the first quarter of 2024 related to the settlement of certain equity-settled stock-based compensation awards.

See Part I, Item 1 – Financial Statements, Note 7 Income Taxes for additional information on our effective tax rate.

Asset impairments — Asset impairments increased $10 million to $13 million for the six months ended June 30, 2024 from $3 million for the six months ended June 30, 2023.

In the six months ended June 30, 2024, our asset impairment related to the write-down of excess and obsolete materials and supplies inventory related to our oilfield operations.

In the six months ended June 30, 2023, our asset impairment related to the write-down of a property to fair value when it was classified as held for sale.

Taxes other than on income — Taxes other than on income were $77 million for the six months ended June 30, 2024, which was a decrease of $7 million from $84 million for the six months ended June 30, 2023.

The decrease was primarily related to lower greenhouse gas expense in 2024.

This decrease was partially offset by higher ad valorem taxes in the six months ended June 30, 2024 compared to the same prior year period.

Costs related to marketing of purchased commodities — Costs related to marketing of purchased commodities were $97 million for the six months ended June 30, 2024, which was a decrease of $54 million from $151 million for the six months ended June 30, 2023.

The decrease primarily related to lower natural gas prices in 2024 compared to 2023.

Electricity generation expense — Electricity generation expenses for the six months ended June 30, 2024 were $22 million, which was a decrease of $40 million from $62 million for the same prior year period.

This decrease was primarily due to lower prices for natural gas as well as downtime at our Elk Hills power plant for maintenance.

Carbon management business expenses — Carbon management business expenses increased by $10 million to $23 million for the six months ended June 30, 2024 from $13 million for the six months ended June 30, 2023.

The increase in carbon management business expenses was predominantly due to higher easement expense and compensation-related expenses.

Other operating expenses, net — Other operating expenses, net increased $67 million to $88 million for the six months ended June 30, 2024 compared to $21 million for the six months ended June 30, 2023.

The increase was primarily related to transaction and integration costs for the Aera Merger as well as additional expenses related to electricity purchased during the ongoing maintenance at our Elk Hills power plant.

Income taxes – The income tax benefit for the six months ended June 30, 2024 was $6 million (representing an effective tax rate of 75%), compared to a provision of $113 million (representing an effective tax rate of 22%) for the six months ended June 30, 2023.

We recognized an excess tax benefit as a discrete adjustment in the six months ended June 30, 2024 related to the settlement of certain equity-settled stock-based compensation awards.

See Part I, Item 1 – Financial Statements, Note 6 Income Taxes for more information on our effective tax rate.

Liquidity and Capital Resources

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We consider our low leverage and ability to control costs to be a core strength and strategic advantage, which we are focused on maintaining.

Our primary uses of operating cash flow for the three months ended March 31, 2024 were for capital investments, repurchases of our common stock and dividends.

Our primary uses of operating cash flow for the three months ended June 30, 2024 were for capital investments, repurchases of our common stock and dividends.

The following table summarizes our liquidity:

March 31, 2024

June 30, 2024

(in millions)

Cash and cash equivalents $ 403

Available cash and cash equivalents (a)

Revolving Credit Facility:

Borrowing capacity

Revolver balance drawn

Outstanding letters of credit (130)

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Liquidity $ 1,500

We amended our Revolving Credit Facility during the first quarter of 2024 as described in Part I, Item 1 – Financial Statements, Note 4 Debt and continue to evaluate refinancing options for our Senior Notes.

In March 2024, we obtained commitments from our existing lenders and certain new lenders to amend our Revolving Credit Facility upon closing of the Aera Merger.

These commitments include increasing our borrowing base from $1.2 billion to $1.5 billion, increasing the aggregate commitment amount from $630 million to $1.1 billion and other matters.

These commitments are subject to certain conditions prior to becoming effective, including the closing of the Aera Merger.

We intend to undertake certain financing transactions in connection with the Aera Merger.

See Part I, Item 1 – Financial Statements, Note 2 Pending Aera Merger.

(a) Excludes an insignificant amount of restricted cash.

At the time of the closing of the Aera Merger, we had available cash of $1.1 billion, which included $100 million of available cash at Aera.

We used this cash to pay $990 million in connection with the extinguishment of Aera's outstanding indebtedness, and transaction costs and financing fees for the combined entity of $75 million, of which $9 million was accrued as of June 30, 2024.

We amended our Revolving Credit Facility during the first quarter of 2024 which increased the aggregate commitment amount and our borrowing base as described in Part I, Item 1 – Financial Statements, Note 3 Debt and continue to evaluate refinancing options for our 2026 Senior Notes.

We also intend to pursue financing options for our carbon management business that are separate from the rest of our business.

At current commodity prices and based upon our planned 2024 capital program described below, we expect to generate operating cash flow to support and invest in our core assets and preserve financial flexibility.

We regularly review our financial position and evaluate whether to (i) adjust our drilling program, (ii) return available cash to shareholders through dividends or stock buybacks to the extent permitted under our Revolving Credit Facility and Senior Notes indenture, (iii) repurchase outstanding indebtedness, (iv) advance carbon management activities, or (v) maintain cash and cash equivalents on our balance sheet.

We regularly review our financial position and evaluate whether to (i) adjust our drilling program, (ii) return available cash to shareholders through dividends or stock buybacks to the extent permitted under our Revolving Credit Facility and the indentures for our 2026 Senior Notes and our 2029 Senior Notes, (iii) reduce outstanding indebtedness, (iv) advance carbon management activities, or (v) maintain cash and cash equivalents on our balance sheet.

We believe we have sufficient sources of liquidity to meet our obligations for the next twelve months.

Cash Flow Analysis

Cash flows from operating activities — For the three months ended March 31, 2024, our operating cash flow decreased $223 million to $87 million from $310 million in the same period in 2023.

This decrease in operating cash flow was primarily driven by lower natural gas prices in California markets during the first quarter of 2024 compared to 2023.

Our average natural gas prices decreased $17.66 per Mcf from $21.56 per MMcf in the three months ended March 31, 2024 to $3.90 per Mcf during the three months ended March 31, 2024.

Further, our natural gas production decreased by 31 MMcf/d from 136 MMcf/d in the three months ended March 31, 2023 to 105 MMcf/d in the three months ended March 31, 2024, also contributing to the decrease.

While our realized oil price with derivative settlements increased by $14.13 per barrel to $77.17 in the three months ended March 31, 2024 from $63.04 in the same prior year period, our net oil production volumes decreased 7 MBbl/d from 55 MBbl/d in the three months ended March 31, 2023 to 48 MBbl/d in the three months ended March 31, 2024.

Our total net production volumes decreased by 13 MBoe/d from 89 MBoe/d in the three months ended March 31, 2023 to 76 MBoe/d for the three months ended March 31, 2024 primarily due to scheduled plant downtime during the first quarter of 2024, natural production decline and the divestiture of our share of a non-operated field in December 2023.

Our PSCs also negatively impacted our net oil production by 1 MBoe/d in the three months ended March 31, 2024 compared to the same prior year period.

Cash flows from operating activities — For the six months ended June 30, 2024, our operating cash flow decreased $234 million to $184 million from $418 million in the same period in 2023.

This decrease in operating cash flow was primarily driven by lower natural gas prices in California markets during the six months ended June 30, 2024 compared to the same prior year period.

Our average natural gas prices decreased $9.63 per Mcf from $12.44 per MMcf in the six months ended June 30, 2023 to $2.81 per Mcf during the six months ended June 30, 2024.

Further, our natural gas production decreased by 27 MMcf/d from 136 MMcf/d in the six months ended June 30, 2023 to 109 MMcf/d in the six months ended June 30, 2024, also contributing to the decrease.

While our realized oil price with derivative settlements increased by $15.85 per barrel to $79.20 in the six months ended June 30, 2024 from $63.35 in the same prior year period, our net oil production volumes decreased 7 MBbl/d from 54 MBbl/d in the six months ended June 30, 2023 to 47 MBbl/d in the six months ended June 30, 2024.

Our total net production volumes decreased by 12 MBoe/d from 88 MBoe/d in the six months ended June 30, 2023 to 76 MBoe/d for the six months ended June 30, 2024 primarily due to plant downtime during the first quarter of 2024, natural production decline and the divestiture of our share of a non-operated field in December 2023.

Our PSCs also negatively impacted our net oil production by 1 MBoe/d in the six months ended June 30, 2024 compared to the same prior year period.

Cash flows used in investing activities — The following table provides a comparative summary of net cash used in investing activities:

Three months ended

Six months ended

(in millions)

2 unchanged sentences

Proceeds from divestitures, net 12 —

Acquisitions (6) (1)

Other, net (2) (3)

Net cash used in investing activities $ (82) $ (105)

In March 2024, we sold our 0.9-acre Fort Apache real estate property in Huntington Beach, California.

In March 2024, we sold our 0.9-acre Fort Apache real estate property in Huntington Beach, California for $10 million.

For more information on our divestiture in the three months ended March 31, 2024, see Part I, Item 1 – Financial Statements, Note 7 Divestitures and Acquisitions.

Cash flows used in financing activities — The following table provides a comparative summary of net cash used in financing activities:

Three months ended

Six months ended

(in millions)

Proceeds from Revolving Credit Facility

Proceeds from 2029 Senior Notes, net

Repurchases of common stock (a)

$ (58) $ (59)

Common stock dividends (43) (40)

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Issuance of common stock 3 1

Bridge loan commitment and debt amendment costs

Bridge loan commitment costs

Debt amendment costs

Shares cancelled for taxes (42) (2)

Net cash used in financing activities $ (131) $ (79)

(a) The total value of shares purchased includes approximately $1 million in both the three months ended March 31, 2024 and 2023 related to excise taxes on share repurchases, which was effective beginning on January 1, 2023.

Net cash provided by (used in) financing activities

$ 433 $ (172)

(a) The total value of shares purchased includes approximately $1 million in both the six months ended June 30, 2024 and 2023 related to excise taxes on share repurchases, which was effective beginning on January 1, 2023.

Commissions paid on share repurchases were not significant in all periods presented.

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In addition to the $21 million of dividends paid in the first quarter of 2024, we paid $4 million of dividend equivalents accrued on these stock-based compensation awards.

For more information on the terms of our stock-based compensation awards, refer to Part II, Item 8 – Financial Statements and Supplementary Data, Note 9 Stock-Based Compensation in our 2023 Annual Report.

2024 Capital Program

Our capital program is dynamic in response to commodity price volatility while focusing on oil production and maximizing our free cash flow.

Following the Court of Appeals decision in the Kern County EIR matter, we expect our 2024 capital program to range between $200 million and $240 million under current permitting conditions.

Of this amount, $165 million to $185 million is related to oil and natural gas development (including $20 million to $25 million for maintenance at one of our gas processing facilities at our Elk Hills field), $20 million to $25 million is for carbon management projects and $15 million to $30 million is for corporate and other (including $10 million to $15 million related to scheduled maintenance at our Elk Hills power plant).

We expect to run a one rig program for 2024 executing projects using existing permits.

Refer to Regulatory Updates above for more information.

The amounts in the table below reflect components of our capital investment for the periods indicated, excluding changes in capital investment accruals:

Three months ended March 31, 2024

(in millions)

Oil and natural gas operations (a)

Carbon management business 4

Corporate and other (b)

Total Capital $ 54

(a) During the three months ended March 31, 2024, we incurred an insignificant amount of costs related to planned maintenance at one of our gas processing facilities at our Elk Hills field.

(b) During the three months ended March 31, 2024, we incurred approximately $13 million related to planned maintenance at our Elk Hills power plant.

Our capital program is dynamic in response to commodity price volatility and permit availability while focusing on oil production and maximizing our free cash flow.

Our capital investment for the six months ended June 30, 2024 was $88 million.

For the combined business after completion of the Aera Merger, we expect our capital program for the second half of 2024 to range between $170 million and $210 million under current permitting conditions.

Of this amount, $155 million to $185 million is related to oil and natural gas development, $10 million to $15 million is for carbon management projects and $5 million to $10 million is for corporate and other.

We expect to run a one rig program for the remainder of 2024 executing projects using existing permits.

Refer to Regulatory Updates above for more information on permitting.

Significant changes in oil and natural gas prices may have a material impact on our liquidity.

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Unless otherwise indicated, we use the term “hedge” to describe derivative instruments that are designed to achieve our hedging requirements and program goals, even though they are not accounted for as cash-flow or fair-value hedges.

We did not have any commodity derivatives designated as accounting hedges as of and during the three months ended March 31, 2024.

See Part I, Item 1 – Financial Statements, Note 6 Derivatives for further information on our derivatives and a summary of our open derivative contracts as of March 31, 2024 and Part II, Item 8 – Financial Statements and Supplementary Data, Note 4 Debt in our 2023 Annual Report for information on the hedging requirements included in our Revolving Credit Facility.

We did not have any commodity derivatives designated as accounting hedges as of and during the six months ended June 30, 2024.

See Part I, Item 1 – Financial Statements, Note 5 Derivatives for further information on our derivatives and a summary of our open derivative contracts as of June 30, 2024 and Part II, Item 8 – Financial Statements and Supplementary Data, Note 4 Debt in our 2023 Annual Report for information on the hedging requirements included in our Revolving Credit Facility.

On August 2, 2024, our Board of Directors increased the cash dividend policy to anticipate a total annual dividend of $1.55 , payable to shareholders in quarterly increments of $0.3875 per share of common stock.

The actual declaration of future cash dividends, and the establishment of record and payment dates, is subject to final determination by our Board of Directors each quarter after reviewing our financial performance and position.

On August 5, 2024 , our Board of Directors declared a quarterly cash dividend of $0.3875 per share of common stock.

The dividend is payable to shareholders of record at the close of business on August 30, 2024 and is expected to be paid on September 16, 2024 .

Our Board of Directors declared the following cash dividends in each of the periods presented.

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Three months ended March 31, 2024 $ 21 $ 0.31

Three months ended June 30, 2024 22 $ 0.31

Six months ended June 30, 2024 $ 43

Three months ended March 31, 2023 $ 20 $ 0.2825

$ 20 $ 0.2825

In addition to dividends declared, we paid $4 million of dividend equivalents related to stock-based compensation awards which were settled in the three months ended March 31, 2024.

Three months ended June 30, 2023 20 $ 0.2825

Six months ended June 30, 2023 $ 40

In addition to dividends declared, we paid $4 million of dividend equivalents related to stock-based compensation awards which were settled in the six months ended June 30, 2024.

The declaration of future cash dividends, and the establishment of record and payment dates, is subject to final determination by our Board of Directors each quarter after reviewing our financial performance and position.

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Our Board of Directors has authorized a Share Repurchase Program to acquire up to $1.35 billion of our common stock through December 31, 2025.

The aggregate value of shares that may yet be purchased under the Share Repurchase Program totaled $691 million, excluding commissions and excise taxes on repurchases, as of March 31, 2024.

The aggregate value of shares that may yet be purchased under the Share Repurchase Program totaled $656 million, excluding commissions and excise taxes on repurchases, as of June 30, 2024.

The repurchases may be effected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, derivative contracts or otherwise in compliance with Rule 10b-18, subject to market conditions and contractual limitations in our debt agreements.

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(number of shares) (in millions) ($ per share)

Three months ended March 31, 2023 1,423,764 $ 59 $ 41.25

Three months ended March 31, 2024 1,065,764 $ 58 $ 53.26

Inception of Program (May 2021) through March 31, 2024 15,929,679 $ 662 $ 41.39

The total value of shares purchased includes approximately $1 million in both the three months ended March 31, 2024 and 2023 related to excise taxes on share repurchases, which was effective beginning on January 1, 2023.

Three months ended June 30, 2023 1,618,746 $ 64 $ 39.12

Three months ended June 30, 2024 703,839 $ 35 $ 49.71

Six months ended June 30, 2023 3,042,510 $ 123 $ 40.12

Six months ended June 30, 2024 1,769,603 $ 93 $ 51.85

Inception of Program (May 2021) through June 30, 2024 16,633,518 $ 697 $ 41.74

The total value of shares purchased includes approximately $1 million in both the six months ended June 30, 2024 and 2023 related to excise taxes on share repurchases, which was effective beginning on January 1, 2023.

Commissions paid on share repurchases were not significant in all periods presented.

Divestitures and Acquisitions

See Part I, Item 1 – Financial Statements, Note 7 Divestitures and Acquisitions for information on our transactions during the three months ended March 31, 2024 and 2023.

Divestitures, Acquisitions and Assets Held for Sale

See Part I, Item 1 – Financial Statements, Note 7 Divestitures, Acquisitions and Assets Held for Sale for information on our divestitures and acquisitions during the three months ended June 30, 2024 and 2023.

Lawsuits, Claims, Commitments and Contingencies

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We accrue reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated.

Reserve balances at March 31, 2024 and December 31, 2023 were not material to our condensed consolidated balance sheets as of such dates.

Reserve balances at June 30, 2024 and December 31, 2023 were not material to our condensed consolidated balance sheets as of such dates.

We also evaluate the amount of reasonably possible losses that we could incur as a result of these matters.

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Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements.

Additionally, the information in this report contains forward-looking statements related to the pending Aera Merger.

Although we believe the expectations and forecasts reflected in our forward-looking statements are reasonable, they are inherently subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control.

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Particular uncertainties that could cause our actual results to be materially different than those expressed in our forward-looking statements include:

• fluctuations in commodity prices, including supply and demand considerations for our products and services;

• fluctuations in commodity prices, including supply and demand considerations for our products and services, and the impact of such fluctuations on revenues and operating expenses;

• decisions as to production levels and/or pricing by OPEC or U.S.

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• government policy, war and political conditions and events, including the military conflicts in Israel, Ukraine and Yemen and the Red Sea;

• the ability to successfully integrate the business of Aera once the Aera merger is completed;

• the timing, receipt and terms and conditions of any required governmental and regulatory approvals of the Aera merger that could reduce anticipated benefits or cause the parties to abandon the Aera merger;

• the occurrence of any event, change or other circumstances that could give rise to the termination of the Merger Agreement;

• the possibility that the stockholders of CRC may not approve the issuance of new shares of common stock in the Aera merger;

• the ability to obtain the required debt financing pursuant to our commitment letters and, if obtained, the potential impact of additional debt on our business and the financial impacts and restrictions due to the additional debt;

• regulatory actions and changes that affect the oil and gas industry generally and us in particular, including (1) the availability or timing of, or conditions imposed on, permits and approvals necessary for drilling or development activities or our carbon management business, (2) the management of energy, water, land, greenhouse gases (GHGs) or other emissions, (3) the protection of health, safety and the environment or (4)

the transportation, marketing and sale of our products;

• the ability to successfully integrate Aera's business;

(2) the management of energy, water, land, greenhouse gases (GHGs) or other emissions, (3) the protection of health, safety and the environment, or (4) the transportation, marketing and sale of our products;

• the impact of inflation on future expenses and changes generally in the prices of goods and services;

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• reorganization or restructuring of our operations;

• our ability to claim and utilize tax credits or other incentives in connection with our CCS projects and clean energy projects;

• Our ability to claim and utilize tax credits or other incentives in connection with our CCS projects;

• Our ability to realize the benefits contemplated by our energy transition strategies and initiatives, including CCS projects and other renewable energy efforts;

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-Q

Item 2. Management’s Discussion and Analysis