Item 2. Management’s Discussion and Analysis
Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
We are an independent energy and carbon management company committed to energy transition. We are committed to environmental stewardship while safely providing local, responsibly sourced energy. We are also focused on maximizing the value of our land, mineral ownership, and energy expertise for decarbonization by developing carbon capture and storage (CCS) and other emissions-reducing projects.
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.
Aera Merger
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 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 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.
34
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 $5 million in face value of our 2026 Senior Notes at par resulting in an insignificant extinguishment loss for the write-off of unamortized debt issuance costs.
Fifth Amendment to Revolving Credit Facility
On November 1, 2024, we entered into a fifth amendment to our Revolving Credit Facility. For more information on recent amendments to our Revolving Credit Facility, see Part I, Item 1 – Financial Statements, Note 4 Debt and Note 15 Subsequent Events.
Business Environment and Industry Outlook
Commodity Prices
Our operating results, and those of the oil and natural gas industry as a whole, are heavily influenced by commodity prices. Oil and natural gas prices and differentials may fluctuate significantly as a result of numerous market-related variables. These and other factors make it impossible to predict realized prices reliably. We may respond to economic conditions by adjusting the amount and allocation of our capital program while continuing to identify efficiencies and cost savings. Volatility in oil prices may materially affect the quantities of oil and natural gas reserves we can economically produce over the longer term. Refer to Prices and Realizations below for information on our realized prices.
The following table presents the average daily benchmark prices for oil and natural gas during the periods presented:
Three months ended Nine months ended
September 30, 2024 June 30, 2024 September 30, 2024 September 30, 2023
Brent oil ($/Bbl) $ 78.54 $ 85.00 $ 81.79 $ 82.06
WTI oil ($/Bbl) $ 75.09 $ 80.57 $ 77.54 $ 77.39
NYMEX Henry Hub ($/MMBtu) Average Monthly Settled Price $ 2.16 $ 1.89 $ 2.10 $ 2.69
Marketing Arrangements
Crude Oil
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.
35
Natural Gas
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.
NGLs
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
Oil (MMBbl)
12 34 28 21 3
NGL (MMBbl)
1 1 — — —
Natural gas (Bcf)
11 4 — — —
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.
36
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. 1137
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 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, 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. No. 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. 1137. 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).
37
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 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.
38
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
Oil (MBbl/d)
San Joaquin Basin 90 30 50 34
Los Angeles Basin 17 17 17 19
Ventura Basin 6 — 2 —
Total 113 47 69 53
NGLs (MBbl/d)
San Joaquin Basin 10 10 11 11
Ventura Basin 1 — — —
Total 11 10 11 11
Natural gas (MMcf/d)
San Joaquin Basin 111 99 99 120
Los Angeles Basin 1 1 1 1
Ventura Basin 1 — — —
Sacramento Basin 13 14 14 15
Total 126 114 114 136
Total Net Production Sold (MBoe/d)
145 76 99 87
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.
39
Net Produced
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
Oil (MBbl/d)
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
(MBoe/d)
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
6 7 7 6
Working interest and royalty holders' share 10 7 8 8
Total Gross Production 165 93 118 102
40
Production-Sharing Contracts (PSCs)
Our share of production and reserves from operations in the Wilmington field in the Los Angeles basin is subject to contractual arrangements similar to production-sharing contracts that are in effect through the economic life of the assets. The reporting of our PSCs creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs. Operating costs, excluding effects of PSCs, is a non-GAAP measure which adjusts for excess costs attributable to PSCs for the periods presented in the tables below:
Three months ended
September 30, 2024 June 30, 2024
(in millions) ($ per Boe) (in millions) ($ per Boe)
Operating costs (a)
$ 316 $ 23.73 $ 159 $ 23.14
Excess costs attributable to PSCs
(16) (1.23) (17) (2.48)
Operating costs, excluding effects of PSCs
$ 300 $ 22.50 $ 142 $ 20.66
(a) Operating costs related to our exploration and production activities and are presented before elimination entries.
Nine months ended
September 30, 2024 September 30, 2023
(in millions) ($ per Boe) (in millions) ($ per Boe)
Operating costs (a)
$ 654 $ 24.11 $ 636 $ 26.80
Excess costs attributable to PSCs
(51) (1.88) (54) (2.26)
Operating costs, excluding effects of PSCs
$ 603 $ 22.23 $ 582 $ 24.54
(a) Operating costs related to our exploration and production activities and are presented before elimination entries.
For further information on our production-sharing contracts, see Part I, Item 1 & 2 Business and Properties, Oil and Natural Gas Operations, Production, Price and Cost History in our 2023 Annual Report.
41
Prices and Realizations
The following tables set forth the average realized prices and price realizations as a percentage of average Brent, WTI and NYMEX indexes for our oil and natural gas operations for the periods presented:
Three months ended
September 30, 2024 June 30, 2024
Price Realization Price Realization
Oil ($ per Bbl)
Brent $ 78.54 $ 85.00
Realized price without derivative settlements $ 77.10 98% $ 83.14 98%
Derivative settlements (1.72) (1.85)
Realized price with derivative settlements $ 75.38 96% $ 81.29 96%
WTI $ 75.09 $ 80.57
Realized price without derivative settlements $ 77.10 103% $ 83.14 103%
Realized price with derivative settlements $ 75.38 100% $ 81.29 101%
NGLs ($ per Bbl)
Realized price (% of Brent) $ 45.77 58% $ 46.96 55%
Realized price (% of WTI) $ 45.77 61% $ 46.96 58%
Natural gas
NYMEX Henry Hub ($/MMBtu) - Average Monthly Settled Price $ 2.16 $ 1.89
Realized price ($/Mcf) $ 2.68 124% $ 1.78 94%
42
Nine months ended
September 30, 2024 September 30, 2023
Price Realization Price Realization
Oil ($ per Bbl)
Brent $ 81.79 $ 82.06
Realized price without derivative settlements $ 79.15 97% $ 79.90 97%
Derivative settlements (2.05) (15.65)
Realized price with derivative settlements $ 77.10 94% $ 64.25 78%
WTI $ 77.54 $ 77.39
Realized price without derivative settlements $ 79.15 102% $ 79.90 103%
Realized price with derivative settlements $ 77.10 99% $ 64.25 83%
NGLs ($ per Bbl)
Realized price (% of Brent) $ 47.77 58% $ 48.89 60%
Realized price (% of WTI) $ 47.77 62% $ 48.89 63%
Natural gas
NYMEX Henry Hub ($/MMBtu) - Average Monthly Settled Price $ 2.10 $ 2.69
Realized price ($/Mcf)
$ 2.76 131% $ 9.85 366%
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.
43
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 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. Gas processing costs include costs associated with compression, maintenance and other activities needed to run our gas processing facilities at Elk Hills. Non-energy operating costs equal total operating costs less energy operating costs and gas processing costs.
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 sold (MBoe/d)
145 76 99 87
Total oil, natural gas and NGL sales (in millions)
$ 878 $ 416 $ 1,729 $ 1,672
Energy operating costs
$ 7.29 $ 6.40 $ 7.26 $ 10.87
Gas processing costs
0.38 0.44 0.44 0.59
Non-energy operating costs
16.06 16.30 16.41 15.34
Operating costs
$ 23.73 $ 23.14 $ 24.11 $ 26.80
Field general and administrative expenses (a)
$ 4.06 $ 1.31 $ 2.65 $ 1.39
Field depreciation, depletion and amortization (b)
$ 10.21 $ 6.84 $ 8.55 $ 6.62
Field taxes other than on income $ 5.41 $ 4.80 $ 5.05 $ 3.92
(a) Excludes unallocated general and administrative expenses.
(b) Excludes depreciation, depletion and amortization related to our corporate assets and our Elk Hills power plant.
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.
Certain prior period balances related to NGL marketing activities have been reclassified to conform to our 2024 presentation. 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.
44
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
September 30, 2024 June 30, 2024
(in millions)
Oil, natural gas and NGL sales $ 870 $ 412
Net gain from commodity derivatives
356 5
Revenue from marketing of purchased commodities
51 51
Electricity sales 69 36
Other revenue 7 10
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 $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 June 30, 2024
$ 353 $ 45 $ 18 $ 416
Change in realized prices
(26) (1) 9 (18)
Change in production
477 — 3 480
Three months ended September 30, 2024
$ 804 $ 44 $ 30 $ 878
Note: See Production for volumes by commodity type and Prices and Realizations for index and realized prices for comparative periods.
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
September 30, 2024 June 30, 2024
(in millions)
Non-cash commodity derivative gain
$ 373 $ 11
Settlements and premiums
(17) (6)
Net gain from commodity derivatives
$ 356 $ 5
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.
45
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
September 30, 2024 June 30, 2024
(in millions)
Operating expenses
Energy operating costs $ 92 $ 41
Gas processing costs 5 3
Non-energy operating costs 214 112
General and administrative expenses 106 63
Depreciation, depletion and amortization 140 53
Asset impairment — 13
Taxes other than on income 85 39
Exploration expense 1 —
Costs related to marketing of purchased commodities
43 43
Electricity generation expenses 9 14
Transportation costs 23 17
Accretion expense 31 13
Carbon management business expenses
13 15
Other operating expenses, net 73 51
Total operating expenses 835 477
Gain on asset divestitures — 1
Operating income
518 38
Non-operating (expenses) income
Interest and debt expense (29) (17)
Loss on early extinguishment of debt
(5) —
Loss from investment in unconsolidated subsidiary (2) (4)
Other non-operating (expenses) income
1 (6)
Income before income taxes
483 11
Income tax provision
(138) (3)
Net income (loss)
$ 345 $ 8
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.
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.
46
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
$ 104 $ 60
Carbon management business
2 3
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.
47
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 gain (loss) from commodity derivatives
290 (131)
Revenue from marketing of purchased commodities 176 336
Electricity sales 120 169
Other revenue 24 29
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 $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)
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
Nine months ended September 30, 2024
$ 1,505 $ 138 $ 86 $ 1,729
Note: See Production for volumes by commodity type and Prices and Realizations for index and realized prices for comparative periods.
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. 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 $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 gain
$ 325 $ 92
Net cash payments on settled commodity derivatives (35) (223)
Net gain (loss) from commodity derivatives
$ 290 $ (131)
48
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 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)
Operating expenses
Energy operating costs $ 186 $ 258
Gas processing costs 12 14
Non-energy operating costs 445 364
General and administrative expenses 226 201
Depreciation, depletion and amortization 246 170
Asset impairment 13 3
Taxes other than on income 162 132
Exploration expense 2 2
Purchased natural gas marketing expense
140 182
Electricity generation expenses 31 85
Transportation costs 60 49
Accretion expense 56 35
Carbon management business expenses
36 20
Other operating expenses, net 161 42
Total operating expenses 1,776 1,557
Gain on asset divestitures
7 7
Operating income 552 525
Non-operating (expenses) income
Interest and debt expense (59) (43)
Loss on early extinguishment of debt
(5) —
Loss from investment in unconsolidated subsidiary (9) (6)
Other non-operating (expense) income
(4) 5
Income before income taxes
475 481
Income tax provision
(132) (105)
Net income
$ 343 $ 376
49
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 $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.
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.
Nine months ended
September 30, 2024 September 30, 2023
(in millions)
Exploration and production, corporate and other
$ 219 $ 191
Carbon management business
7 10
Total general and administrative expenses $ 226 $ 201
Awards are granted under our stock-based compensation plans to executives, non-executive employees and non-employee directors that are either settled with shares of our common stock or cash. Our equity-settled awards granted to executives include performance stock units and restricted stock units that either cliff vest at the end of a two- or three-year period or vest ratably over a two- or three-year period. Our equity-settled awards granted to non-employee directors are restricted stock units that vest ratably over a three-year period. Our cash-settled awards granted to non-executive employees vest ratably over a three-year period.
Changes in our stock price introduce volatility in our results of operations because we pay half of our cash-settled awards based on our stock price performance and we adjust our obligation for unvested cash-settled awards at the end of each reporting period. Equity-settled awards are not similarly adjusted for changes in our stock price.
50
Stock-based compensation included in G&A expense is shown in the table below:
Nine months ended
September 30, 2024 September 30, 2023
(in millions)
Cash-settled awards
$ 8 $ 11
Stock-settled awards
17 21
Total included in general and administrative expenses $ 25 $ 32
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 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.
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.
51
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. 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.
Liquidity and Capital Resources
Liquidity
Our primary sources of liquidity and capital resources are cash flows from operations, cash and cash equivalents and available borrowing capacity under our Revolving Credit Facility. 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 September 30, 2024 were for capital investments, repurchases of our common stock and dividends.
The following table summarizes our liquidity:
September 30, 2024
(in millions)
Available cash and cash equivalents (a)
$ 213
Revolving Credit Facility:
Borrowing capacity
1,100
Outstanding letters of credit (175)
Availability $ 925
Liquidity $ 1,138
(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.
At current commodity prices and based upon our planned 2024 capital program described below, we expect to generate operating cash flow to support and invest in our core assets and preserve financial flexibility. We regularly review our financial position and evaluate whether to (i) adjust our drilling program, (ii) return available cash to shareholders through dividends or stock buybacks to the extent permitted under our Revolving Credit Facility and the indentures for our 2026 Senior Notes and our 2029 Senior Notes, (iii) reduce outstanding indebtedness, (iv) advance carbon management activities, or (v) maintain cash and cash equivalents on our balance sheet. We believe we have sufficient sources of liquidity to meet our obligations for the next twelve months.
52
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; and
• 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 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.
53
Cash flows used in investing activities — The following table provides a comparative summary of net cash used in investing activities:
Nine months ended
September 30,
2024 2023
(in millions)
Capital investments $ (167) $ (119)
Changes in accrued capital investments 8 (10)
Proceeds from divestitures, net 12 —
Purchase of a business, net of cash acquired
(853) —
Acquisitions (6) (1)
Other, net (4) (3)
Net cash used in investing activities $ (1,010) $ (133)
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 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:
Nine months ended
September 30,
2024 2023
(in millions)
Proceeds from Revolving Credit Facility
$ 30 $ —
Repayments of Revolving Credit Facility
(30) —
Proceeds from 2029 Senior Notes, net
888 —
Repurchases of common stock (a)
(135) (143)
Common stock dividends (77) (59)
Payments on equity-settled awards
(4) —
Issuance of common stock 2 1
Bridge loan commitment costs
(5) —
Debt repurchases
(303) (5)
Debt amendment costs
(10) (8)
Stock warrants exercised
37 —
Shares cancelled for taxes (42) (3)
Net cash provided by (used in) financing activities
$ 351 $ (217)
(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.
A significant number of stock-based compensation awards were settled in the first quarter of 2024. These awards were primarily granted in January 2021 following our emergence from bankruptcy. We withheld shares of common stock to satisfy the tax withholding obligations (shares cancelled for taxes). 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.
54
2024 Capital Program
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 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. We expect to run a one rig program for the remainder of 2024 executing projects using existing permits. Refer to Regulatory Updates above for more information on permitting.
Derivatives
Significant changes in oil and natural gas prices may have a material impact on our liquidity. Declining commodity prices negatively affect our operating cash flow, and the inverse applies during periods of rising commodity prices. Our hedging strategy seeks to mitigate our exposure to commodity price volatility and ensure our financial strength and liquidity by protecting our cash flows. We will continue to evaluate our hedging strategy based on prevailing market prices and conditions.
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 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:
Common Stock
Balance at December 31, 2023
68,693,885
Issued as part of the Aera Merger
21,315,707
Shares repurchased
(2,604,922)
Shares issued for exercised warrants
1,139,163
Other shares issued, net
917,840
Balance at September 30, 2024
89,461,673
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.
55
Dividends
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 November 5, 2024 , our Board of Directors declared a quarterly cash dividend of $0.3875 per share of common stock. The dividend is payable to shareholders of record at the close of business on December 2, 2024 and is expected to be paid on December 16, 2024 .
Our Board of Directors declared the following cash dividends in each of the periods presented.
Total Dividend
Rate Per Share
(in millions)
($ per share)
2024
Three months ended March 31, 2024 $ 21 $ 0.31
Three months ended June 30, 2024 22 $ 0.31
Three months ended September 30, 2024 34 $ 0.3875
Nine months ended September 30, 2024 $ 77
2023
Three months ended March 31, 2023 $ 20 $ 0.2825
Three months ended June 30, 2023 20 $ 0.2825
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 $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.
56
Share Repurchase Program
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 $614 million, excluding commissions and excise taxes on repurchases, as of September 30, 2024. The repurchases may be effected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, derivative contracts or otherwise in compliance with Rule 10b-18, subject to market conditions and contractual limitations in our debt agreements. The Share Repurchase Program does not obligate us to repurchase any dollar amount or number of shares and our Board of Directors may modify, suspend or discontinue authorization of the program at any time. The following is a summary of our share repurchases, which are held as treasury stock, for the periods presented:
Total Number of Shares Purchased Total Value of Shares Purchased Average Price Paid per Share
(number of shares) (in millions) ($ per share)
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
Note: 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.
Warrants
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 and nine months ended September 30, 2024 and 2023.
Lawsuits, Claims, Commitments and Contingencies
We are involved, in the normal course of business, in lawsuits, environmental and other claims and other contingencies that seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, civil penalties or injunctive or declaratory relief.
57
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 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. We believe that reasonably possible losses that we could incur in excess of reserves cannot be accurately determined.
See Part I, Item 1 – Financial Statements, Note 5 Lawsuits, Claims, Commitments and Contingencies for further information.
Critical Accounting Estimates and Significant Accounting and Disclosure Changes
There have been no changes to our critical accounting estimates, which are summarized in Part II, Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Estimates of our 2023 Annual Report.
58
Forward-Looking Statements
This document contains statements that we believe to be “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than historical facts are forward-looking statements, and include statements regarding our future financial position, business strategy, projected revenues, earnings, costs, capital expenditures and plans and objectives of management for the future. Words such as "expect," “could,” “may,” "anticipate," "intend," "plan," “ability,” "believe," "seek," "see," "will," "would," “estimate,” “forecast,” "target," “guidance,” “outlook,” “opportunity,” “strategy” or similar expressions are generally intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements.
Although we believe the expectations and forecasts reflected in our forward-looking statements are reasonable, they are inherently subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. No assurance can be given that such forward-looking statements will be correct or achieved or that the assumptions are accurate or will not change over time. Particular uncertainties that could cause our actual results to be materially different than those expressed in our forward-looking statements include:
• fluctuations in commodity prices, including supply and demand considerations for our products and services, and the impact of such fluctuations on revenues and operating expenses;
• decisions as to production levels and/or pricing by OPEC or U.S. producers in future periods;
• 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;
• changes in business strategy and our capital plan;
• lower-than-expected production or higher-than-expected production decline rates;
• changes to our estimates of reserves and related future cash flows, including changes arising from our inability to develop such reserves in a timely manner, and any inability to replace such reserves;
• the recoverability of resources and unexpected geologic conditions;
• general economic conditions and trends, including conditions in the worldwide financial, trade and credit markets;
• production-sharing contracts' effects on production and operating costs;
• the lack of available equipment, service or labor price inflation;
• limitations on transportation or storage capacity and the need to shut-in wells;
• any failure of risk management;
• results from operations and competition in the industries in which we operate;
• Our ability to realize the anticipated benefits from prior or future efforts to reduce costs;
• environmental risks and liability under federal, regional, state, provincial, tribal, local and international environmental laws and regulations (including remedial actions);
• the creditworthiness and performance of our counterparties, including financial institutions, operating partners, CCS project participants and other parties;
• reorganization or restructuring of our operations;
• Our ability to claim and utilize tax credits or other incentives in connection with our CCS projects;
• Our ability to realize the benefits contemplated by our energy transition strategies and initiatives, including CCS projects and other renewable energy efforts;
59
• Our ability to successfully identify, develop and finance carbon capture and storage projects and other renewable energy efforts, including those in connection with the Carbon TerraVault JV, and our ability to convert our CDMAs to definitive agreements and enter into other offtake agreements;
• Our ability to maximize the value of our carbon management business and operate it on a stand alone basis;
• Our ability to successfully develop infrastructure projects and enter into third party contracts on contemplated terms;
• uncertainty around the accounting of emissions and our ability to successfully gather and verify emissions data and other environmental impacts;
• changes to our dividend policy and share repurchase program, and our ability to declare future dividends or repurchase shares under our debt agreements;
• limitations on our financial flexibility due to existing and future debt;
• insufficient cash flow to fund our capital plan and other planned investments and return capital to shareholders;
• 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;
• changes in state, federal or international tax rates, including our ability to utilize our net operating loss carryforwards to reduce our income tax obligations;
• effects of hedging transactions;
• the effect of our stock price on costs associated with incentive compensation;
• inability to enter into desirable transactions, including joint ventures, divestitures of oil and natural gas properties and real estate, and acquisitions, and our ability to achieve any expected synergies;
• disruptions due to earthquakes, forest fires, floods, extreme weather events or other natural occurrences, accidents, mechanical failures, power outages, transportation or storage constraints, labor difficulties, cybersecurity breaches or attacks or other catastrophic events;
• pandemics, epidemics, outbreaks, or other public health events, such as the COVID-19 pandemic; and
• other factors discussed in Part I, Item 1A – Risk Factors in our 2023 Annual Report .
We caution you not to place undue reliance on forward-looking statements contained in this document, which speak only as of the filing date, and we undertake no obligation to update this information. This document may also contain information from third party sources. This data may involve a number of assumptions and limitations, and we have not independently verified them and do not warrant the accuracy or completeness of such third-party information.
60
Text extracted from the filing as submitted to EDGAR. Formatting, tables and exhibits are simplified for reading; the original document is authoritative for anything you rely on.