What changed in this filing

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Item 2. Management’s Discussion and Analysis

2024-11-06 compared with 2024-08-07 · 385 added, 236 removed, 352 unchanged (64% of the section changed)

4 unchanged sentences

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 as of the date presented.

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.

On July 1, 2024, we closed on transactions pursuant to the definitive agreement and plan of merger (Merger Agreement) to obtain all of the ownership interests in Aera Energy, LLC (Aera) (Aera Merger).

In connection with the closing of the Aera Merger, we issued 21,315,707 shares of common stock to the former Aera owners (Sellers).

We also paid approximately $990 million in connection with the extinguishment of all of Aera's outstanding indebtedness using the proceeds from the issuance of our 2029 Senior Notes and cash on hand.

For more information on the 2029 Senior Notes, refer to Part I, Item 1 – Financial Statements, Note 4 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.

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

In the three and nine months ended September 30, 2024, we recognized $30 million and $56 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.

See Part I, Item 1 – Financial Statements, Note 4 Debt for information on financing costs related to the Aera Merger.

Reorganization

In August 2024, management committed to a reduction in force as part of the integration process following the Aera Merger, which, when complete, will result in a 12% reduction in our combined company's employee headcount.

We initiated this workforce reduction to align the size and composition of our workforce with expected future operating and capital plans and to capture synergies related to the Aera Merger.

As a result, we recognized a charge of $27 million and $28 million in other operating expenses, net on the consolidated statement of operations for the three and nine months ended September 30, 2024, respectively, primarily related to severance benefits.

See Part I, Item 1 – Financial Statements, Note 11 Pension and Postretirement Benefit Plans for information on amendments to Aera’s pension and postretirement benefit plans in August 2024.

We expect to pay severance costs of approximately $25 million in the fourth quarter of 2024 and the remaining amounts throughout 2025 as the workforce reduction will be achieved in stages due to transition periods.

See Part I, Item 1 – Financial Statements, Note 2 Aera Merger for information on the severance plan and Note 11 Pension and Postretirement Benefit Plans for information on amendments to Aera's pension and postretirement benefit plans.

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.

2029 Senior Notes Follow-On Offering

On August 22, 2024, we completed a follow-on offering of $300 million in aggregate principal amount of 8.25% senior notes due 2029 (2029 Senior Notes).

The net proceeds from this offering of $298 million, after $3 million of debt premium and $5 million of debt issuance costs, were used to repurchase a portion of our outstanding 7.125% senior notes due 2026 (2026 Senior Notes) as described below.

The 2029 Senior Notes issued on August 22, 2024 are governed by the same indenture as the $600 million of 2029 Senior Notes that were previously issued on June 5, 2024.

2026 Senior Note Repurchases

In the three and nine months ended September 30, 2024, we repurchased $300 million in face value of our 2026 Senior Notes for $303 million, resulting in a loss on early extinguishment of debt in the amount of $5 million which includes a $2 million write-off of unamortized debt issuance costs.

In the three and nine months ended September 30, 2023, we repurchased $5 million in face value of our 2026 Senior Notes at par resulting in an insignificant extinguishment loss for the write-off of unamortized debt issuance costs.

Fifth Amendment to Revolving Credit Facility

On November 1, 2024, we entered into a fifth amendment to our Revolving Credit Facility.

For more information on recent amendments to our Revolving Credit Facility, see Part I, Item 1 – Financial Statements, Note 4 Debt and Note 15 Subsequent Events.

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 Six months ended

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

Three months ended Nine months ended

September 30, 2024 June 30, 2024 September 30, 2024 September 30, 2023

Brent oil ($/Bbl) $ 78.54 $ 85.00 $ 81.79 $ 82.06

1 unchanged sentence

NYMEX Henry Hub ($/MMBtu) Average Monthly Settled Price $ 2.16 $ 1.89 $ 2.10 $ 2.69

Marketing Arrangements

We sell nearly all of our crude oil to California refiners.

A majority of our crude oil production is connected to third-party pipelines and California refining markets via our gathering systems.

We do not refine or process the crude oil we produce and do not have any significant long-term transportation arrangements.

The prices paid by California refiners are typically based on local postings that are closely tied to Brent prices.

International waterborne-based Brent prices are relevant because there is limited crude pipeline infrastructure available to transport crude over land from other parts of the United States into California.

We believe that these limitations will continue to contribute to higher realized prices in California than most other U.S.

oil markets for comparable grades.

In October 2024, Phillips 66 announced that it plans to close its Wilmington refinery in Los Angeles in late 2025.

For the three months ended September 30, 2024, following the Aera Merger, we sold approximately 8% of our production to this refinery.

Following the closure of this facility, there will be four remaining major (greater than 75,000 barrels per day) petroleum refineries in Southern California and three remaining major petroleum refineries in Northern California.

Due to the significant excess of refining capacity in California versus the quantity of crude oil produced locally, we do not expect the closure of this refinery to affect our ability to market our crude oil production, or to negatively impact our price realizations.

We sell all of our natural gas not used in our operations into the California market.

A majority of these sales are made at index-based prices.

Natural gas prices and differentials are strongly affected by local market fundamentals, such as storage capacity and the availability of transportation capacity between the market and producing areas.

Transportation capacity influences prices because California imports more than 90% of its natural gas from other states and from Canada.

As a result, we typically obtain higher realizations relative to out-of-state producers due to lower transportation costs on the delivery of our natural gas.

In addition to selling natural gas, we also purchase natural gas for production of steam at our steamfloods and for power generation.

As a result, the positive impact of higher natural gas prices is, absent impacts of gas cost hedging, largely offset by higher operating costs of our steamfloods and in our electricity generation expense, but higher prices have a net positive effect on our operating results when gas hedges are taken into account.

See Part I, Item 1 – Financial Statements, Note 6 Derivatives for more information on derivative contracts related to purchased natural gas .

Following the Aera Merger, we have transportation contracts for up to (i) 101,750 MMBtu/d of long-haul (Rockies to California) gas transportation through September 2031 and (ii) approximately 220,000 MMBtu/d of localized system natural gas transportation through September 2026.

These contracts to transport natural gas contain both fixed reservation fees and variable charges.

NGL prices vary by liquid type and realizations are closely correlated to the different commodity prices to which they relate.

Prices can also fluctuate due to the demand for certain chemical products (for which NGLs are used as feedstock) and due to infrastructure constraints and seasonality.

Finally, our results are also affected by the performance of our natural gas-processing plants.

We process our wet gas to extract NGLs and other natural gas byproducts.

We then deliver dry gas to pipelines and separately sell the remaining products as NGLs.

The efficiency with which we extract liquids from the wet gas stream affects our production volumes and operating results.

Our natural gas-processing plants also facilitate access to third-party delivery points near the Elk Hills field.

We currently have a ship-or-pay pipeline transportation contract for approximately 6,100 barrels per day of NGLs through March 2026.

Our contract to transport NGLs requires us to cash settle any shortfall between the contractual throughput minimums and volumes actually shipped.

We have met all our throughput minimums under this contract for the periods presented.

Delivery Commitments

We have commitments to certain refineries and other buyers to deliver oil, natural gas and NGLs, including additional delivery commitments obtained as part of the Aera Merger.

As of September 30, 2024, we had the following delivery commitments as shown in the table below.

2024 2025 2026 2027 2028

12 34 28 21 3

Natural gas (Bcf)

We expect to fulfill our delivery commitments predominantly from our production and to a lesser extent from third party volumes acquired in connection with our marketing activities.

We typically enter into index-based contracts with prices set at the time of delivery.

Regulatory Updates

Well Permitting Status

CalGEM remains in the process of developing standard operating procedures for reviewing well permit applications and significant permitting delays may continue pending CalGEM’s completion of this process.

An increase in approvals for workovers has continued through the third quarter of 2024.

As of September 30, 2024, we have received 581 permits for workovers and 89 permits for sidetracks (including permits received by Aera) since the beginning of the year.

During the second and third quarters of 2024, CalGEM issued 48 and 34 new well permits to other operators in the state, respectively.

These permits were issued outside of Kern County or in reliance on an environmental impact analysis other than the Kern County Environmental Impact Report (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 and Aera's Belridge field that would allow us to comply with CEQA requirements separate from the Kern County EIR.

As discussed in the 2023 Annual Report, the Kern County EIR was legally challenged in 2020 and the use of the Kern County EIR is currently stayed and has been stayed through most of the litigation.

For further information on the Kern County EIR, see Part I, Item IA – Risk Factors, We may face material delays related to our ability to timely obtain permits necessary for our operations or be unable to secure such permits on favorable terms or at all as a result of numerous California political, regulatory, and legal developments in our 2023 Annual Report.

As a result, 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.

CCS Project Permitting Status

On October 21, 2024, the Kern County Board of Supervisors approved the issuance of the conditional use permits and certified the Draft Recirculated Environmental Impact Report for our first carbon capture and storage project, Carbon TerraVault I.

This approval follows a recommendation from the Kern County Planning Commission (Planning Commission) on September 12, 2024 that the Kern County Board of Supervisors take these actions.

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.

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 imposes 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.

1137 was stayed pending the outcome of a voter referendum to repeal the bill on the November 2024 ballot, but the referendum was withdrawn on June 27, 2024.

However, on September 30, 2024, the Governor signed into law Assembly Bill No.

218, which extends the timeline for the implementation of certain initial and future monitoring and reporting requirements to July 1, 2026 and further delays compliance with certain other requirements of Senate Bill No.

1137 by up to three years.

Assembly Bill.

218 does not modify the 3,200-foot setback requirements applicable to new drills, sidetracks or workovers.

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.

In addition to the writedown 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 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.

Recent Legislation

On September 25, 2024, the following laws were enacted in the State of California:

Assembly Bill 1866

This law increases the annual fees operators must pay per idle well, depending on how long each well has been idle, and includes a new fee for those wells that have been idle for less than three years.

In lieu of the annual fees, operators can instead file an eight year plan with the state to provide for the management and elimination of its idle wells.

This law also increases the minimum percentages of idle wells that operators are required to eliminate each year.

The rate at which idle wells must be eliminated varies depending on the number of an operator’s idle wells.

Operators must prepare and submit a plan for the elimination of idle wells to CalGEM for approval.

We have robust programs for managing and eliminating idle wells that in most cases meet or exceed the requirements of the new law.

As a result, we do not expect this new law to have any meaningful impact on our current plans for eliminating idle wells or meaningfully increase fees associated with our idle wells.

Assembly Bill 2716

This law requires operators to plug “low production wells” located within the boundary of the Baldwin Hills Conservancy in Los Angeles within a certain timeframe or otherwise subjects operators to administrative penalties.

A “low-production well” is a well that produced fewer than 15 barrels of oil a day during the past 12 months.

We have limited operations and assets within the affected area.

As a result, we expect that this law will have an insignificant impact on both our total production and proved reserves.

Assembly Bill 3233 (AB 3233)

This law provides local governments with the authority to limit methods for, or even prohibit oil and gas operations or development within their jurisdiction, including with respect to existing operations.

Prior to the passage of this law, certain local governments in California had attempted to limit oil and gas operations within their jurisdictions and such actions had been challenged and struck down by California courts.

Monterey County previously sought to ban only new production and prohibit the use of wastewater injection as a production method.

The City and County of Los Angeles previously sought to both ban new wells and phaseout existing wells over a certain period of time.

Although both those local measures were struck down in court, following the adoption of AB 3233, certain legal challenges previously made to these local actions are no longer valid and it is possible that these or other local governments in California may attempt to pass new or similar restrictions.

For the three months ended September 30, 2024, approximately 12% of our gross production is located in Los Angeles County and approximately 3% is in Monterey County.

For the three months ended September 30, 2024, over 80% of our gross production is located in Kern County, and at this time we are not aware of any local governments within Kern County that are considering materially limiting or otherwise prohibiting oil and gas operations within their jurisdiction.

However, it is difficult to predict how local governments in California may choose to exercise their new authority under AB 3233.

There may be future legal challenges to AB 3233 and any local ordinances enacted thereunder and we cannot predict whether or not such challenges will be successful.

See Part II, Item 1A – Risk Factors – We may face increased local restrictions on oil and gas exploration and production operations or even be prohibited from operating in certain areas as a result of recently enacted California legislation .

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 Six months ended

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

The tables below present production information on the basis of gross production, net production and net production sold.

The difference between gross production and net production primarily reflects the reduction for (i) volumes attributable to working interest and royalty owners and (ii) volumes associated with PSC-type contracts to arrive at our net share.

The difference between net production and net production sold reflects (i) the reduction for natural gas that we produce that is used in our oil and gas operations, including steam in our steamflood operations, and (ii) marketing activities reflecting the storage of volumes that we produce and are sold at a later time.

The amounts in the production tables below include volumes produced from Aera's operated and non-operated fields during the period from July 1, 2024 through September 30, 2024 and volumes from CRC's operated and non-operated fields for each of the periods presented.

Net Production Sold

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

Three months ended Nine months ended

September 30, 2024 June 30, 2024 September 30, 2024 September 30, 2023

San Joaquin Basin 90 30 50 34

Los Angeles Basin 17 17 17 19

Ventura Basin 6 — 2 —

Total 113 47 69 53

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San Joaquin Basin 10 10 11 11

Ventura Basin 1 — — —

Total 11 10 11 11

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Los Angeles Basin 1 1 1 1

Ventura Basin 1 — — —

Sacramento Basin 13 14 14 15

Total 126 114 114 136

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

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:

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

Total Net Production Sold (MBoe/d)

Total daily net production sold increased by 69 Mboe/d from 76 Mboe/d for the three months ended June 30, 2024 to 145 Mboe/d during the three months ended September 30, 2024 primarily as a result of the Aera Merger.

Our natural gas production also increased during the three months ended September 30, 2024 as compared to the three months ended June 30, 2024 by 2 MBoe/d as a result of fewer days of downtime at our Elk Hills power plant.

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

Total daily net production sold increased by 12 Mboe/d from 87 MBoe/d during the nine months ended September 30, 2023 to 99 Mboe/d during the nine months ended September 30, 2024 primarily as a result of the Aera Merger.

This increase was partially offset by lower production during the nine months ended September 30, 2024 compared to the prior year period due to natural decline, additional days of scheduled maintenance and unplanned downtime at our Elk Hills power plant and 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 nine months ended September 30, 2024 compared to the nine months ended September 30, 2023.

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

Three months ended Nine months ended

September 30, 2024 June 30, 2024 September 30, 2024 September 30, 2023

San Joaquin Basin 90 30 51 34

Los Angeles Basin 17 16 17 19

Ventura Basin 6 — 2 —

Total 113 46 70 53

NGLs (MBbl/d)

San Joaquin Basin 11 11 10 11

Total 11 11 10 11

Natural gas (MMcf/d)

San Joaquin Basin 130 118 123 127

Los Angeles Basin 1 1 1 1

Ventura Basin 3 — 1 —

Sacramento Basin 13 14 14 16

Total 147 133 139 144

Total Net Produced (MBoe/d)

149 79 103 88

The following table reconciles our average net production sold and volumes produced 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:

Three months ended Nine months ended

September 30, 2024 June 30, 2024 September 30, 2024 September 30, 2023

Total Net Production Sold 145 76 99 87

Changes in NGL inventory and other 4 3 4 1

Total Net Produced

149 79 103 88

Partners' share under PSCs

Working interest and royalty holders' share 10 7 8 8

Changes in NGL inventory and other 3 4 4 1

Total Gross Production 165 93 118 102

4 unchanged sentences

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September 30, 2024 June 30, 2024

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

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

Six months ended

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Nine months ended

September 30, 2024 September 30, 2023

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

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Three months ended

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September 30, 2024 June 30, 2024

Price Realization Price Realization

12 unchanged sentences

Realized price ($/Mcf) $ 2.68 124% $ 1.78 94%

Six months ended

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Nine months ended

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Price Realization Price Realization

13 unchanged sentences

$ 2.76 131% $ 9.85 366%

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.

Oil — Brent prices were lower for the three months ended September 30, 2024 compared to the three months ended June 30, 2024.

The decrease in Brent prices is attributable to stagnating demand growth and increased production from non-OPEC+ sources.

Brent prices were largely unchanged for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023 as markets attempted to reconcile continued geopolitical conflict, OPEC+ compliance and discipline, and slowing growth in global demand.

NGLs — NGL prices for the three months ended September 30, 2024 decreased compared to the three months ended June 30, 2024 reflecting traditional seasonality and moved in tandem with crude oil prices.

NGL prices for the nine months ended September 30, 2024 decreased compared to the nine months ended September 30, 2023 as growing North American crude and associated gas production continue to provide an ample supply of wet gas for processing.

Natural Gas — Natural gas prices increased for the three months ended September 30, 2024 compared to the three months ended June 30, 2024 driven by a greater degree of producer discipline.

Natural gas prices decreased for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023.

In California, specifically, nine-month metrics continue to reflect record-setting prices in early 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 June 30, 2024 and March 31, 2024 and the six months ended June 30, 2024 and 2023.

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 September 30, 2024 and June 30, 2024 and the nine months ended September 30, 2024 and 2023.

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.

Three months ended Six months ended

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

Three months ended Nine months ended

September 30, 2024 June 30, 2024 September 30, 2024 September 30, 2023

($ per Boe, except as otherwise stated)

Total net production (MBoe/d)

Total net production sold (MBoe/d)

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

15 unchanged sentences

(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 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

Our consolidated results of operations include the results of Aera beginning July 1, 2024, the closing date of the Aera Merger.

For more information on the Aera Merger, see Part I, Item 1 – Financial Statements, Note 2 Aera Merger.

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 14 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 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:

For the nine months ended September 30, 2023, we reclassified $2 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 September 30, 2024 compared to June 30, 2024

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

Three months ended

June 30, 2024 March 31, 2024

September 30, 2024 June 30, 2024

(in millions)

Oil, natural gas and NGL sales $ 870 $ 412

Net gain (loss) from commodity derivatives

Net gain from commodity derivatives

Revenue from marketing of purchased commodities

2 unchanged sentences

Total operating revenues $ 1,353 $ 514

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, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the effects of cash settlements on our commodity derivative contracts, were $870 million for the three months ended September 30, 2024, which is an increase of $458 million compared to $412 million for the three months ended June 30, 2024.

This increase includes $475 million of oil, natural gas and NGL sales related to additional production from the Aera fields following the completion of the Aera Merger on July 1, 2024.

The effect of cash settlements on our commodity derivative contracts are excluded from the table below.

The table below includes sales of natural gas we produce which is used by our Elk Hills power plant.

Oil NGLs Natural Gas Total Operations

(in millions)

Three months ended March 31, 2024 (a)

Three months ended June 30, 2024

$ 353 $ 45 $ 18 $ 416

2 unchanged sentences

Change in production

(9) (1) 1 (9)

Three months ended June 30, 2024 (b)

Three months ended September 30, 2024

$ 804 $ 44 $ 30 $ 878

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

(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.

Net gain from commodity derivatives — Net gain from commodity derivatives was $356 million for the three months ended September 30, 2024 compared to net gain of $5 million for the three months ended June 30, 2024 as shown in the table below.

As of July 1, 2024, we recorded a liability of $336 million for Aera's outstanding Brent-based derivative contracts.

Due to a decline in forward oil prices between July 1, 2024 and September 30, 2024, we recognized a non-cash commodity derivative gain for these Aera hedges during the three months ended September 30, 2024.

The net 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.

Three months ended

June 30, 2024 March 31, 2024

September 30, 2024 June 30, 2024

(in millions)

Non-cash commodity derivative gain (loss)

Non-cash commodity derivative gain

Settlements and premiums

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:

Net gain from commodity derivatives

Electricity sales — Electricity sales increased by $33 million to $69 million for the three months ended September 30, 2024 compared to $36 million for the three months ended June 30, 2024.

The increase was primarily a result of higher resource adequacy revenue and sales from electricity delivered to the wholesale market during the three months ended September 30, 2024.

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

Three months ended

June 30, 2024 March 31, 2024

September 30, 2024 June 30, 2024

(in millions)

16 unchanged sentences

Gain on asset divestitures — 1

Operating income (loss)

Operating income

Non-operating (expenses) income

Interest and debt expense (29) (17)

Loss on early extinguishment of debt

Loss from investment in unconsolidated subsidiary (2) (4)

Other non-operating (expenses) income

Income (loss) before income taxes

Income tax (provision) benefit

Income before income taxes

Income tax provision

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.

Energy operating costs — Energy operating costs for the three months ended September 30, 2024 were $92 million, which was an increase of $51 million from $41 million for the three months ended June 30, 2024.

This increase was primarily due to additional energy costs and purchase injectant used in the operation of the Aera fields.

Our energy operating costs for the three months ended September 30, 2024 include $45 million related to Aera's fields following the completion of the Aera Merger on July 1, 2024.

Excluding Aera, energy operating costs for the three months ended September 30, 2024 were higher than the three months ended June 30, 2024 as the result of higher natural gas prices.

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

Non-energy operating costs — Non-energy operating costs for the three months ended September 30, 2024 were $214 million, which was an increase of $102 million from $112 million for the three months ended June 30, 2024.

The increase was predominately a result of the operation of the Aera fields after the Aera Merger.

Our non-energy operating costs for the three months ended September 30, 2024 include $99 million related to Aera's fields following the completion of the Aera Merger on July 1, 2024.

Excluding Aera, non-energy operating costs increased in the three months ended September 30, 2024 compared to the three months ended June 30, 2024 due to additional spending on downhole and surface maintenance.

General and administrative expenses — General and administrative (G&A) expenses were $106 million for the three months ended September 30, 2024 compared to $63 million for the three months ended June 30, 2024.

The increase was primarily a result of an additional $46 million related to Aera for the period from July 1, 2024 through September 30, 2024.

Excluding Aera, G&A costs were slightly lower in the three months ended September 30, 2024 compared to the three months ended June 30, 2024.

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.

Three months ended

September 30, 2024 June 30, 2024

(in millions)

Exploration and production, corporate and other

Carbon management business

Total general and administrative expenses $ 106 $ 63

Depreciation, depletion and amortization — Depreciation, depletion and amortization for the three months ended September 30, 2024 was $140 million compared to $53 million during the three months ended June 30, 2024.

The increase was the result of a higher carrying value of our property, plant and equipment after the Aera Merger.

Asset impairments — We did not recognize an asset impairment for the three months ended September 30, 2024.

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

Taxes other than on income — Taxes other than on income for the three months ended September 30, 2024 were $85 million, which is an increase of $46 million from $39 million for the three months ended June 30, 2024.

This increase was due to higher production taxes, ad valorem taxes and greenhouse gas expense related to acquiring Aera's operations.

Excluding Aera, taxes other than income for the three months ended September 30, 2024 increased from the three months ended June 30, 2024 primarily due to higher greenhouse gas expense, partially offset by lower ad valorem taxes.

Accretion expense — Accretion expense for the three months ended September 30, 2024 was $31 million compared to $13 million for the three months ended June 30, 2024.

The increase was primarily due to the addition of Aera's asset retirement liability assumed as of July 1, 2024 as part of the Aera Merger.

Other operating expenses, net — Other operating expenses, net increased $22 million to $73 million for the three months ended September 30, 2024 compared to $51 million for the three months ended June 30, 2024.

The increase was predominantly due to transaction costs, including success-based fees, related to the Aera Merger and severance expense in the three months ended September 30, 2024.

These increases were partially offset by lower costs related to energy purchased due to fewer days of Elk Hills power plant downtime during the three months ended September 30, 2024.

Income taxes – The income tax provision for the three months ended September 30, 2024 was $138 million (representing an effective tax rate of 29%), compared to a provision of $3 million (representing an effective tax rate of 27%) for the three months ended June 30, 2024.

Nine months ended September 30, 2024 compared to September 30, 2023

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

Nine months ended

September 30, 2024 September 30, 2023

(in millions)

Oil, natural gas and NGL sales $ 1,711 $ 1,672

Net (loss) gain from commodity derivatives

Net gain (loss) from commodity derivatives

Revenue from marketing of purchased commodities 176 336

2 unchanged sentences

Total operating revenues $ 2,321 $ 2,075

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, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the effects of cash settlements on our commodity derivative contracts, were $1,711 million for the nine months ended September 30, 2024, which is an increase of $39 million compared to $1,672 million for the nine months ended September 30, 2023.

This increase was predominately a result of additional sales of oil production from the Aera fields following completion of the Aera Merger on July 1, 2024.

The effect of cash settlements on our commodity derivative contracts are excluded from the table below.

The table below includes sales of natural gas we produce which is used by our Elk Hills power plant.

Oil NGLs Natural Gas Total Operations

(in millions)

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

Nine months ended September 30, 2023 $ 1,154 $ 151 $ 367 $ 1,672

Change in realized prices (11) (3) (265) (279)

Change in production 362 (10) (16) 336

Six months ended June 30, 2024 (a)

Nine months ended September 30, 2024

$ 1,505 $ 138 $ 86 $ 1,729

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

Net gain (loss) from commodity derivatives — Net gain from commodity derivatives was $290 million for the nine months ended September 30, 2024 compared to a net loss of $131 million for the nine months ended September 30, 2023.

As of July 1, 2024, we recorded a liability of $336 million for Aera's outstanding Brent-based derivative contracts.

Due to a decline in forward oil prices between July 1, 2024 and September 30, 2024, we recognized a non-cash commodity derivative gain for these Aera hedges during the nine months ended September 30, 2024.

Payments on commodity derivatives were $35 million for the nine months ended September 30, 2024 compared to payments of $223 million for the nine months ended September 30, 2023.

Payments on commodity derivatives for the nine months ended September 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.

Nine months ended

September 30, 2024 September 30, 2023

(in millions)

Non-cash commodity derivative (loss) gain

Non-cash commodity derivative gain

Net cash payments on settled commodity derivatives (35) (223)

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.

Net gain (loss) from commodity derivatives

$ 290 $ (131)

Revenue from marketing of purchased commodities — Revenue from marketing of purchased commodities was $176 million for the nine months ended September 30, 2024, which was a decrease of $160 million from $336 million during the nine months ended September 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

This decrease was partially offset by higher sales of purchased crude oil used in our marketing activities in 2024 as compared to 2023.

Revenue from marketing of purchased commodities net of costs related to marketing of purchased commodities was $36 million for the nine months ended September 30, 2024 compared to $154 million for the nine months ended September 30, 2023.

Electricity sales — Electricity sales decreased by $49 million to $120 million for the nine months ended September 30, 2024 compared to $169 million for the nine months ended September 30, 2023 due to lower prices in 2024 compared to the same prior year period.

The decrease was partially offset by higher resource adequacy revenues in the nine months ended September 30, 2024 as compared to the prior comparative period.

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

Nine months ended

September 30, 2024 September 30, 2023

(in millions)

19 unchanged sentences

Interest and debt expense (59) (43)

Loss on early extinguishment of debt

Loss from investment in unconsolidated subsidiary (9) (6)

Other non-operating income

(Loss) income before income taxes

Income tax benefit (provision)

Net (loss) income

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.

Other non-operating (expense) income

Income before income taxes

Income tax provision

Energy operating costs — Energy operating costs for the nine months ended September 30, 2024 were $186 million, which was a decrease of $72 million from $258 million for the nine months ended September 30, 2023.

This decrease was a result of lower natural gas prices in the nine months of 2024 compared to the same prior year period as well as lower costs related to the divestiture of our share of a non-operated field in December 2023.

This decrease was partially offset by higher energy costs in nine months ended September 30, 2024 of which $45 million related to energy and purchase injectant for the Aera fields following the completion of the Aera Merger.

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.

Non-energy operating costs — Non-energy operating costs were $445 million for the nine months ended September 30, 2024, which was an increase of $81 million from $364 million for the nine months ended September 30, 2023.

The increase was predominately a result of the additional fields acquired in the Aera Merger.

Non-energy operating costs for the nine months ended September 30, 2024 include $99 million related to Aera's operations.

Excluding Aera, non-energy operating costs for the nine months ended September 30, 2024 were lower than the prior year period as a result of lower costs for downhole and surface maintenance and lower costs from 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 $226 million for the nine months ended September 30, 2024, which was an increase of $25 million from $201 million for the nine months ended September 30, 2023.

The increase in G&A expenses was primarily attributable to the Aera Merger.

Excluding Aera, G&A expenses were lower in the nine months ended September 30, 2024 compared to the same prior year period as a result of reduced spending on information technology infrastructure and lower stock-based compensation expense.

Stock-based compensation awards are discussed further below.

1 unchanged sentence

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

Nine months ended

September 30, 2024 September 30, 2023

(in millions)

9 unchanged sentences

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

Six months ended

June 30, 2024 June 30, 2023

Nine months ended

September 30, 2024 September 30, 2023

(in millions)

2 unchanged sentences

Total included in general and administrative expenses $ 25 $ 32

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.

Depreciation, depletion and amortization — Depreciation, depletion and amortization for the nine months ended September 30, 2024 was $246 million compared to $170 million during the nine months ended September 30, 2023.

The increase was the result of a higher carrying value for our property, plant and equipment as a result of the Aera Merger.

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

In the nine months ended September 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 nine months ended September 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 $162 million for the nine months ended September 30, 2024, which was an increase of $30 million from $132 million for the nine months ended September 30, 2023.

This increase was due to higher production taxes, ad valorem taxes and greenhouse gas expense related to the Aera assets following the completion of the Aera Merger on July 1, 2024.

Excluding Aera, taxes other than on income was lower for the nine months ended September 30, 2024 compared to the same period in 2023 primarily due to lower greenhouse gas expense.

Costs related to marketing of purchased commodities — Costs related to marketing of purchased commodities were $140 million for the nine months ended September 30, 2024, which was a decrease of $42 million from $182 million for the nine months ended September 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.

Electricity generation expense — Electricity generation expenses for the nine months ended September 30, 2024 were $31 million, which was a decrease of $54 million from $85 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.

Transportation costs — Transportation costs for the nine months ended September 30, 2024 were $60 million which is an increase of $11 million from $49 million for the nine months ended September 30, 2023.

The increase in transportation costs was primarily a result of higher volumes transported as well as additional transportation contracts assumed in the Aera Merger.

Accretion expense — Accretion expense for the nine months ended September 30, 2024 was $56 million compared to $35 million for the nine months ended September 30, 2023.

The increase was primarily due to the addition of the Aera asset retirement liability assumed as of July 1, 2024 as part of the Aera Merger.

Carbon management business expenses — Carbon management business expenses increased by $16 million to $36 million for the nine months ended September 30, 2024 from $20 million for the nine months ended September 30, 2023.

The increase in carbon management business expenses was predominantly due to higher lease cost for easements and compensation-related expenses.

Other operating expenses, net — Other operating expenses, net increased $119 million to $161 million for the nine months ended September 30, 2024 compared to $42 million for the nine months ended September 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.

We also incurred higher severance costs in the nine months ended September 30, 2024 as a result of our headcount reduction compared to the same prior year period.

Interest and debt expense, net — Interest and debt expense, net was $59 million for the nine months ended September 30, 2024 compared to $43 million for the nine months ended September 30, 2023.

The increase was predominately a result from higher interest expense from the issuance of our 2029 Senior Notes.

In June 2024, we issued $600 million in aggregate principal amount of 8.25% senior notes due 2029 and in August 2024, we completed a follow-on offer of $300 million in aggregate principal amount for those notes.

Income taxes – The income tax benefit for the nine months ended September 30, 2024 was $132 million (representing an effective tax rate of 28%), compared to a provision of $105 million (representing an effective tax rate of 22%) for the nine months ended September 30, 2023.

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

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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 June 30, 2024 were for capital investments, repurchases of our common stock and dividends.

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

The following table summarizes our liquidity:

June 30, 2024

September 30, 2024

(in millions)

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Borrowing capacity

Revolver balance drawn

Outstanding letters of credit (175)

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Liquidity $ 1,138

(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.

(a) Excludes restricted cash of $28 million.

We recently amended our Revolving Credit Facility as described in Part I, Item 1 – Financial Statements, Note 4 Debt .

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

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

Revolving Credit Facility and Recent Amendment

The borrowing base under our Revolving Credit Facility is redetermined semi-annually and was reaffirmed at $1.5 billion on November 1, 2024.

The borrowing base takes into account the estimated value of our proved reserves, total indebtedness and other relevant factors consistent with customary reserves-based lending criteria.

The amount we are able to borrow under our Revolving Credit Facility is limited to the amount of the commitments from our lenders.

On November 1, 2024, we entered into a fifth amendment to our Revolving Credit Facility.

The amendments included, among other things:

• increasing the amount of the revolving commitments by $50 million to $1,150 million to reflect changes to our lender group;

• extending the maturity date of the facility from July 31, 2027 to March 16, 2029;

• amending the springing maturity to permit our 2026 Senior Notes to remain outstanding past October 31, 2025 so long as the aggregate availability (less the outstanding 2026 Senior Notes) is not less than 25% of the total revolving commitments;

• increasing our capacity to issue letters of credit from $250 million to $300 million;

• other technical amendments.

For more information regarding our Revolving Credit Facility and the recent amendments, see Part I, Item 1 – Financial Statements, Note 4 Debt and Note 15 Subsequent Events.

Cash Flow Analysis

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 from operating activities — For the nine months ended September 30, 2024, our operating cash flow decreased by $118 million to $404 million from $522 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 nine months ended September 30, 2024 compared to the same prior year period.

Our average natural gas prices decreased $7.09 per Mcf from $9.85 per MMcf in the nine months ended September 30, 2023 to $2.76 per Mcf during the nine months ended September 30, 2024.

Further, our natural gas production decreased by 22 MMcf/d from 136 MMcf/d in the nine months ended September 30, 2023 to 114 MMcf/d in the nine months ended September 30, 2024, also contributing to the decrease.

Partially offsetting the decrease related to natural as prices and volumes, our realized oil price with derivative settlements increased by $12.85 per barrel to $77.10 in the nine months ended September 30, 2024 from $64.25 in the same prior year period and our net oil production volumes increased 16 MBbl/d from 53 MBbl/d in the nine months ended September 30, 2023 to 69 MBbl/d in the nine months ended September 30, 2024 as a result of the addition of Aera in the third quarter of 2024.

Transaction and integration costs related to the Aera Merger decreased operating cash flow by $56 million in 2024.

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

Six months ended

Nine months ended

September 30,

(in millions)

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Proceeds from divestitures, net 12 —

Purchase of a business, net of cash acquired

Acquisitions (6) (1)

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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.

For more information on our divestitures, 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:

Six months ended

Nine months ended

September 30,

(in millions)

Proceeds from Revolving Credit Facility

Repayments of Revolving Credit Facility

Proceeds from 2029 Senior Notes, net

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Bridge loan commitment costs

Debt repurchases

Debt amendment costs

Stock warrants exercised

Shares cancelled for taxes (42) (3)

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$ 351 $ (217)

(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.

(a) The total value of shares purchased reported on our statement of cash flows includes approximately $1 million in both the nine months ended September 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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We withheld shares of common stock to satisfy the tax withholding obligations (shares cancelled for taxes).

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.

In addition to the $81 million of dividends paid in the nine months ended September 30, 2024, we paid $4 million of dividend equivalents accrued on our 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.

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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.

Our capital investment for the nine months ended September 30, 2024 was $167 million inclusive of $25 million for capital investment related to Aera's operations since the July 1, 2024 acquisition date.

We expect our capital program for the remainder of 2024 to range between $85 million and $105 million under current permitting conditions.

Of this amount, $77 million to $90 million is related to oil and natural gas development, $5 million to $10 million is for carbon management projects and $3 million to $5 million is for corporate and other.

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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 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.

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

Transactions Related to Our Common Stock

The following table is a summary of common stock issuances:

Balance at December 31, 2023

Issued as part of the Aera Merger

Shares repurchased

Shares issued for exercised warrants

Other shares issued, net

Balance at September 30, 2024

Common Stock Issued as Part of the Aera Merger

In connection with the Aera Merger, as described in Part I, Item 1 – Financial Statements, Note 2 Aera Merger, on July 1, 2024 we entered into a registration rights agreement (Registration Rights Agreement) with the Sellers.

In accordance with the Registration Rights Agreement, a total of 21,315,707 shares of common stock were registered pursuant to a registration statement on Form S-3 filed on August 5, 2024.

The Registration Rights Agreement contemplates that each Seller is subject to certain lock-up provisions whereby such Seller agreed not to transfer (1) any shares of common stock issued to such Seller to any non-affiliate until January 1, 2025;

(2) more than one-third of the shares of common stock issued to such Seller to any non-affiliate until July 1, 2025;

and (3) more than two-thirds of the shares of common stock issued to such Seller to any non-affiliate until January 1, 2026.

The lock up provisions are subject to certain exceptions as more particularly described in the Registration Rights Agreement, included as Exhibit 10.4 thereto.

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 .

On November 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 December 2, 2024 and is expected to be paid on December 16, 2024 .

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

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Three months ended June 30, 2024 22 $ 0.31

Six months ended June 30, 2024 $ 43

Three months ended September 30, 2024 34 $ 0.3875

Nine months ended September 30, 2024 $ 77

Three months ended March 31, 2023 $ 20 $ 0.2825

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.

Three months ended September 30, 2023 19 $ 0.2825

Nine months ended September 30, 2023 $ 59

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

Since the adoption of our dividend policy in 2021, we have returned $197 million to shareholders through dividends.

Since the adoption of our dividend policy in 2021, we have returned $231 million to shareholders through dividends (excluding dividend equivalents).

For information regarding past dividends paid, see Cash Flow Analysis, Cash Flow Used in Financing Activities above.

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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 $656 million, excluding commissions and excise taxes on repurchases, as of June 30, 2024.

The aggregate value of shares that may yet be purchased under the Share Repurchase Program totaled $614 million, excluding commissions and excise taxes on repurchases, as of September 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 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.

Three months ended September 30, 2023 365,145 $ 20 $ 54.75

Three months ended September 30, 2024 835,319 $ 42 $ 50.23

Nine months ended September 30, 2023 3,407,655 $ 143 $ 41.69

Nine months ended September 30, 2024 2,604,922 $ 135 $ 51.33

Inception of Program (May 2021) through September 30, 2024 17,468,837 $ 739 $ 42.14

The total value of shares purchased includes approximately $1 million in both the nine months ended September 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.

In October 2020, we reserved an aggregate 4,384,182 shares of our common stock for warrants for issuance upon the exercise of warrants, which were exercisable at $36 per share through October 28, 2024.

As of September 30, 2024, we had outstanding warrants exercisable into 2,812,754 shares of our common stock (subject to adjustments pursuant to the terms of the warrants).

During the three and nine months ended September 30, 2024, we issued 1,085,838 and 1,139,163 shares of our common stock in exchange for warrants, respectively.

During the three and nine months ended September 30, 2023, we issued 1,958 and 2,179 shares of our common stock in exchange for warrants, respectively.

During October 2024, we issued 2,630,540 shares of our common stock in connection with warrant exercises.

Since the issuance date of the warrants in October 2020, 3,856,833 shares have been issued upon the exercise of warrants and 469,429 shares were cancelled due to net settlement.

On October 28, 2024, any unexercised warrants expired in accordance with their terms and 57,920 shares underlying such warrants were never issued.

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.

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 and nine months ended September 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 June 30, 2024 and December 31, 2023 were not material to our condensed consolidated balance sheets as of such dates.

Reserve balances at September 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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producers in future periods;

• 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 Aera's business;

• 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;

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

• the ability to successfully execute integration efforts in connection with our merger with Aera Energy LLC, and achieve projected synergies and ensure that such synergies are sustainable;

• 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, EPA and other governmental 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 efforts of activists to delay prevent oil and gas activities or the development of our carbon management business through a variety of tactics, including litigation;

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

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• changes in interest rates;

• Our access to and the terms of credit in commercial banking and capital markets, including our ability to refinance our debt or obtain separate financing for our carbon management business;

• Our access to and the terms of credit in commercial banking and capital markets,

including our ability to refinance our debt or obtain separate financing for our carbon management business;

• changes in state, federal or international tax rates, including our ability to utilize our net operating loss carryforwards to reduce our income tax obligations;

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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