California Resources Reports Third Quarter 2024 Financial and Operating Results
Source: GlobeNewswireLONG BEACH, Calif., Nov. 05, 2024 (GLOBE NEWSWIRE) -- California Resources Corporation (NYSE: CRC) today reported financial and operating results for the third quarter of 2024. The Company plans to host a conference call and webcast at 1 p.m. ET (10 a.m. PT) on Wednesday, November 6, 2024. Participation details can be found within this release. In addition, supplemental slides are available on CRC’s website at www.crc.com.
Highlights
- Generated $345 million of net income, $137 million of adjusted net income1 and $402 million of adjusted EBITDAX1
- Generated $220 million of net cash provided by operating activities, $249 million of net cash provided by operating activities before changes in operating assets and liabilities1 and $141 million of free cash flow1
- Strong third quarter 2024 average net production sold of 145 thousand barrels of oil equivalent per day (MBoe/d) and average net oil production sold of 113 thousand barrels of oil per day (MBo/d). Drilling and workover capital investments were $38 million
- On-track to deliver approximately $235 million in targeted Aera merger-related synergies by the third quarter of 2025 with $135 million of synergies actioned to date including a reduction of $60 million2 in annual interest expense
- Returned 54% of quarterly free cash flow1, or $76 million, to shareholders including $42 million in share repurchases and $34 million in dividends
- Optimized capital structure and extended maturities through recent $300 million follow-on offering of 8.250% senior notes due 2029 (2029 Senior Notes) and subsequent tender of $300 million 7.125% senior notes due 2026 (2026 Senior Notes)
- Exited the quarter with $213 million in cash and cash equivalents and $1,138 million of liquidity3
- Received California's first conditional use permits for Carbon TerraVault I CCS project in Kern County and signed a memorandum of understanding4 (MOU) to develop carbon capture and storage (CCS) solutions with Hull Street Energy LLC, a leading California power partner. See Carbon TerraVault's Third Quarter 2024 Update for additional information
"Our performance this year has been strong and we have positioned CRC for long term value creation into the future," said Francisco Leon, CRC's President and Chief Executive Officer. "Today, CRC is bigger, stronger, and more sustainable. We continue to demonstrate that we are a different kind of energy company. I am really proud of our teams and the Aera integration. We are capturing meaningful synergies, enhancing operating efficiencies and advancing new growth opportunities. The Kern County Board of Supervisors’ approval of the conditional use permits for our CTV I project and a recent MOU with a leading power partner are a testament to our team's relentless pursuit of growing our carbon business. As we look to 2025, our hedge positions underpin near-term cash flows and will allow for continued debt reduction and cash returns to shareholders."
Third Quarter 2024 Financial and Operating Summary
CRC reported net income of $345 million, or $3.78 per fully diluted share of common stock, and adjusted net income1 of $137 million, or $1.50 per fully diluted share. Net cash provided by operating activities was $220 million.
Transaction and integration costs related to the Aera merger decreased third quarter 2024 cash flow from operations by $57 million. Employee severance and related costs during the three months ended September 30, 2024 were $27 million. CRC expects 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.
Gross production averaged 165 MBoe/d and net production sold averaged 145 MBoe/d, including net oil production sold of 113 MBo/d. Net oil production was positively impacted by approximately 1 MBo/d, as compared to the second quarter of 2024, a result CRC's production-sharing contracts (PSCs). Average realized oil prices were 98% of Brent.
Operating costs of $311 million reflected reduced activity levels, lower natural gas prices and the early realization of Aera merger-related synergies.
Capital investments of $79 million were lower than guidance primarily due to high-grading of workover capital.
| Selected Production, Price Information and Results of Operations | 3rd Quarter | 2nd Quarter | |||||||||
| ($ in millions) | 2024 | 2024 | |||||||||
| Net oil production sold per day (MBbl/d) | 113 | 47 | |||||||||
| Realized oil price with derivative settlements ($ per Bbl) | $ | 75.38 | $ | 81.29 | |||||||
| Net NGL production sold per day (MBbl/d) | 11 | 10 | |||||||||
| Realized NGL price ($ per Bbl) | $ | 45.77 | $ | 46.96 | |||||||
| Net natural gas production sold per day (Mmcf/d) | 126 | 114 | |||||||||
| Realized natural gas price with derivative settlements ($ per Mcf) | $ | 2.68 | $ | 1.78 | |||||||
| Net total production sold per day (MBoe/d) | 145 | 76 | |||||||||
| Margin from marketing of purchased commodities5 ($ millions) | $ | 8 | $ | 8 | |||||||
| Margin from electricity sales6 ($ millions) | $ | 60 | $ | 22 | |||||||
| Net gain from commodity derivatives ($ millions) | $ | 356 | $ | 5 | |||||||
| Selected Financial Statement Data and non-GAAP measures: | 3rd Quarter | 2nd Quarter | |||||||||
| ($ and shares in millions, except per share amounts) | 2024 | 2024 | |||||||||
| Statements of Operations: | |||||||||||
| Revenues | |||||||||||
| Total operating revenues | $ | 1,353 | $ | 514 | |||||||
| Selected Expenses | |||||||||||
| Operating costs | $ | 311 | $ | 156 | |||||||
| General and administrative expenses | $ | 106 | $ | 63 | |||||||
| Adjusted general and administrative expenses1 | $ | 89 | $ | 56 | |||||||
| Taxes other than on income | $ | 85 | $ | 39 | |||||||
| Transportation costs | $ | 23 | $ | 17 | |||||||
| Operating Income (loss) | $ | 518 | $ | 38 | |||||||
| Interest and debt expense | $ | (29) | $ | (17) | |||||||
| Income tax benefit (provision) | $ | (138) | $ | (3) | |||||||
| Net (loss) Income | $ | 345 | $ | 8 | |||||||
| EPS, Non-GAAP Measures and Select Balance Sheet Data | |||||||||||
| Adjusted net income1 | $ | 137 | $ | 42 | |||||||
| Weighted-average common shares outstanding - diluted | 91.2 | 70.0 | |||||||||
| Net loss (income) per share - diluted | $ | 3.78 | $ | 0.11 | |||||||
| Adjusted net income1 per share - diluted | $ | 1.50 | $ | 0.60 | |||||||
| Adjusted EBITDAX1 | $ | 402 | $ | 139 | |||||||
| Net cash provided by operating activities | $ | 220 | $ | 97 | |||||||
| Net cash provided by operating activities before changes in operating assets and liabilities, net1 | $ | 249 | $ | 108 | |||||||
| Capital investments | $ | 79 | $ | 34 | |||||||
| Free cash flow1 | $ | 141 | $ | 63 | |||||||
| Cash and cash equivalents | $ | 241 | $ | 1,031 | |||||||
Guidance
The following table provides guidance for key fourth quarter financial and operating metrics. For the balance of 2024, CRC expects to run a one-rig program.
CRC has actioned $135 million in Aera merger related synergies during the second half of 2024 and remains on-track to deliver approximately $235 million in estimated synergies by the third quarter of 2025. A reduction of $60 million2 in annual interest expense was achieved in the second quarter of 2024 and third quarter results reflect approximately $8 million of run rate savings. Looking forward, fourth quarter guidance includes $22 million of actioned synergies and the next $45 million of actioned Aera merger synergies are expected to be gradually reflected throughout 2025.
CRC plans to implement the final $100 million of projected operational and general and administrative Aera merger related synergies next year, with the benefits expected to be realized throughout 2025 and 2026. Projected operational synergies are expected to reduce operating costs, ARO, and capital. CRC plans to provide additional details of these operations synergies with its full year 2025 guidance during its fourth quarter 2024 earnings call. See Attachment 2 for additional information.
| CRC Guidance7 | Total 4Q24E |
| Net Production Sold (MBoe/d) | 140 - 144 |
| Oil Production Sold (%) | ~79% |
| Capital ($ millions) | $85 - $105 |
| Adjusted EBITDAX1 ($ millions) | $260 - $300 |
Shareholder Returns
CRC is committed to returning cash to shareholders through dividends and repurchases of common stock. During the third quarter of 2024, CRC repurchased 0.835 million shares for $42 million at an average price of $50.23 per share.
On November 5, 2024, CRC's Board of Directors declared a quarterly cash dividend of $0.3875 per share of common stock. The dividend is payable to shareholders of record on December 2, 2024 and will be paid on December 16, 2024.
Since May 2021, CRC has returned approximately $1,022 million of cash to its stakeholders, including $736 million8 in share repurchases, $231 million in dividends and redemption of $55 million in principal of its 2026 Senior Notes which reduced overall leverage.
In October 2020, CRC reserved an aggregate 4.384 million shares of its common stock for warrants, which were exercisable at $36 per share through October 28, 2024.
Since the issuance date of the warrants in October 2020, 3.857 million shares have been issued upon the exercise of warrants and, 0.469 million 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.
Balance Sheet and Liquidity
On August 22, 2024, CRC completed a follow-on offering of $300 million in aggregate principal amount of 2029 Senior Notes. The net proceeds of $298 million from the issuance, which included $3 million of premium and $5 million of issuance costs, were used to repurchase $300 million of CRC's 2026 Senior Notes in a tender offer.
As of September 30, 2024, CRC had liquidity of $1,138 million3, which consisted of $213 million in available cash and cash equivalents3 plus $925 million of availability under the Revolving Credit Facility which reflects $1,100 million of borrowing capacity, less $175 million of outstanding letters of credit.
On November 1, 2024, CRC reaffirmed its $1.5 billion borrowing base and amended its existing Revolving Credit Facility. The amendments included extending the maturity date of the facility to March 16, 2029, amending the springing maturity to permit its 2026 Senior Notes to remain outstanding past October 31, 2025 under certain circumstances, increasing the amount of elected commitments by $50 million, and other technical amendments.
Upcoming Investor Conference Participation
CRC plans to participate in the following events in November and December 2024:
- Bank of America Global Energy Conference 2024 on November 12 to 13 in Houston, TX
- TD Securities Energy Conference on November 19 to 20 in New York, NY
- Wolfe Research Inaugural Oil & Gas Conference on November 21, Virtual
- 2024 Stephens Annual Investment Conference on November 22 in Nashville, TN
- Mizuho Power, Energy & Infrastructure Conference 2024 on December 9 in New York, NY
- 23rd Annual Wells Fargo Midstream, Energy & Utilities Symposium on December 10 in New York, NY
- Capital One Securities Energy Conference on December 10 in Houston, TX
CRC’s presentation materials will be available on the day of the event on its website. See the Events and Presentations page under the Investor Relations section on www.crc.com.
Conference Call Details
A conference call is scheduled for 1 p.m. ET (10 a.m. PT) on Wednesday, November 6, 2024. To participate in the call, dial (877) 328-5505 (International calls please dial +1 (412) 317-5421) or access via webcast at www.crc.com. Participants may also pre-register for the conference call at https://dpregister.com/sreg/10192326/fd6685ad6e. A digital replay of the conference call will be archived for approximately 90 days and supplemental slides will be available online in the Investor Relations section of www.crc.com.
1 See Attachment 3 for the non-GAAP financial measures of operating costs per BOE (excluding effects of PSCs), adjusted net income (loss), adjusted net income (loss) per share - basic and diluted, net cash provided by operating activities before changes in operating assets and liabilities, net, adjusted EBITDAX, free cash flow and adjusted general and administrative expenses, including reconciliations to their most directly comparable GAAP measure, where applicable. For the 4Q24 estimates of the non-GAAP measures of adjusted EBITDAX and adjusted general and administrative expenses, including reconciliations to its most directly comparable GAAP measure, see Attachment 3.
2 As of June 30, 2024. When accounting for estimated cash interest income, CRC’s net interest savings were ~$36 million.
3 Excludes restricted cash of $28 million.
4 The MOU is non-binding and subject to negotiation of definitive agreements.
5 Margin from Marketing of Purchased Commodities is calculated as the difference between Revenue from Marketing of Purchased Commodities and Costs Related to Marketing of Purchased Commodities
6 Electricity Margin is calculated as the difference between Electricity Sales and Electricity Generation Expenses
7 4Q24 guidance assumes Brent price of $71.48 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $2.95 per mcf. CRC's share of production under PSC contracts decreases when commodity prices rise and increases when prices fall.
8 The total value of shares purchased excludes approximately $3 million related to excise taxes and commissions paid on share repurchases.
About California Resources Corporation
California Resources Corporation (CRC) is an independent energy and carbon management company committed to energy transition. CRC is committed to environmental stewardship while safely providing local, responsibly sourced energy. CRC is also focused on maximizing the value of its land, mineral ownership, and energy expertise for decarbonization by developing carbon capture and storage (CCS) and other emissions-reducing projects. For more information about CRC, please visit www.crc.com.
About Carbon TerraVault
Carbon TerraVault Holdings, LLC (CTV), a subsidiary of CRC, is developing services that include the capture, transport and storage of carbon dioxide for its customers. Through its subsidiaries, CTV is developing a series of proposed CCS projects to inject CO2 captured from industrial sources into depleted underground reservoirs for permanent storage deep underground. For more information about CTV, please visit www.carbonterravault.com.
Forward-Looking Statements
This document contains statements that CRC believes 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 CRC's 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” or “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 CRC believes the expectations and forecasts reflected in its 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 its 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 CRC's actual results to be materially different than those expressed in its forward-looking statements include:
- fluctuations in commodity prices, including supply and demand considerations for CRC's 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, Yemen and the Red Sea;
- the ability to successfully execute integration efforts in connection with CRC's 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 CRC 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 its 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 CRC's products;
- the efforts of activists to delay or prevent oil and gas activities or the development of CRC's 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 CRC's capital plan;
- lower-than-expected production or higher-than-expected production decline rates;
- changes to CRC's estimates of reserves and related future cash flows, including changes arising from its 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 CRC operates;
- CRC's 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 CRC's counterparties, including financial institutions, operating partners, CCS project participants and other parties;
- reorganization or restructuring of CRC's operations;
- CRC's ability to claim and utilize tax credits or other incentives in connection with its CCS projects;
- CRC's ability to realize the benefits contemplated by its energy transition strategies and initiatives, including CCS projects and other renewable energy efforts;
- CRC's 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 its ability to convert its CDMAs and MOUs to definitive agreements and enter into other offtake agreements;
- CRC's ability to maximize the value of its carbon management business and operate it on a stand alone basis;
- CRC's ability to successfully develop infrastructure projects and enter into third party contracts on contemplated terms;
- uncertainty around the accounting of emissions and its ability to successfully gather and verify emissions data and other environmental impacts;
- changes to CRC's dividend policy and share repurchase program, and its ability to declare future dividends or repurchase shares under its debt agreements;
- limitations on CRC's financial flexibility due to existing and future debt;
- insufficient cash flow to fund CRC's capital plan and other planned investments and return capital to shareholders;
- changes in interest rates;
- CRC's access to and the terms of credit in commercial banking and capital markets, including its ability to refinance its debt or obtain separate financing for its carbon management business;
- changes in state, federal or international tax rates, including CRC's ability to utilize its net operating loss carryforwards to reduce its income tax obligations;
- effects of hedging transactions;
- the effect of CRC's 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 CRC's 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 CRC's Annual Report on Form 10-K and its other SEC filings available at www.crc.com.
CRC cautions you not to place undue reliance on forward-looking statements contained in this document, which speak only as of the filing date, and it undertakes 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 CRC has not independently verified them and does not warrant the accuracy or completeness of such third-party information.
Contacts:
| Joanna Park (Investor Relations) 818-661-3731 Joanna.Park@crc.com | Richard Venn (Media) 818-661-6014 Richard.Venn@crc.com |
| Attachment 1 | |||||||||||||||||||||
| SUMMARY OF RESULTS | |||||||||||||||||||||
| 3rd Quarter | 2nd Quarter | 3rd Quarter | Nine Months | Nine Months | |||||||||||||||||
| ($ and shares in millions, except per share amounts) | 2024 | 2024 | 2023 | 2024 | 2023 | ||||||||||||||||
| Statements of Operations: | |||||||||||||||||||||
| Revenues | |||||||||||||||||||||
| Oil, natural gas and NGL sales | $ | 870 | $ | 412 | $ | 510 | $ | 1,711 | $ | 1,672 | |||||||||||
| Net gain (loss) from commodity derivatives | 356 | 5 | (204) | 290 | (131) | ||||||||||||||||
| Revenue from marketing of purchased commodities | 51 | 51 | 77 | 176 | 336 | ||||||||||||||||
| Electricity sales | 69 | 36 | 67 | 120 | 169 | ||||||||||||||||
| Other revenue | 7 | 10 | 10 | 24 | 29 | ||||||||||||||||
| Total operating revenues | 1,353 | 514 | 460 | 2,321 | 2,075 | ||||||||||||||||
| Operating Expenses | |||||||||||||||||||||
| Operating costs | 311 | 156 | 196 | 643 | 636 | ||||||||||||||||
| General and administrative expenses | 106 | 63 | 65 | 226 | 201 | ||||||||||||||||
| Depreciation, depletion and amortization | 140 | 53 | 56 | 246 | 170 | ||||||||||||||||
| Asset impairment | — | 13 | — | 13 | 3 | ||||||||||||||||
| Taxes other than on income | 85 | 39 | 48 | 162 | 132 | ||||||||||||||||
| Exploration expense | 1 | — | — | 2 | 2 | ||||||||||||||||
| Costs related to marketing of purchased commodities | 43 | 43 | 31 | 140 | 182 | ||||||||||||||||
| Electricity generation expenses | 9 | 14 | 23 | 31 | 85 | ||||||||||||||||
| Transportation costs | 23 | 17 | 16 | 60 | 49 | ||||||||||||||||
| Accretion expense | 31 | 13 | 12 | 56 | 35 | ||||||||||||||||
| Carbon management business expenses | 13 | 15 | 7 | 36 | 20 | ||||||||||||||||
| Other operating expenses, net | 73 | 51 | 21 | 161 | 42 | ||||||||||||||||
| Total operating expenses | 835 | 477 | 475 | 1,776 | 1,557 | ||||||||||||||||
| Net gain on asset divestitures | — | 1 | — | 7 | 7 | ||||||||||||||||
| Operating Income (Loss) | 518 | 38 | (15) | 552 | 525 | ||||||||||||||||
| Non-Operating (Expenses) Income | |||||||||||||||||||||
| Interest and debt expense | (29) | (17) | (15) | (59) | (43) | ||||||||||||||||
| Loss from investment in unconsolidated subsidiary | (2) | (4) | (3) | (9) | (6) | ||||||||||||||||
| Net loss on early extinguishment of debt | (5) | — | — | (5) | — | ||||||||||||||||
| Other non-operating income (loss), net | 1 | (6) | 3 | (4) | 5 | ||||||||||||||||
| Income Before Income Taxes | 483 | 11 | (30) | 475 | 481 | ||||||||||||||||
| Income tax (provision) benefit | (138) | (3) | 8 | (132) | (105) | ||||||||||||||||
| Net Income | $ | 345 | $ | 8 | $ | (22) | $ | 343 | $ | 376 | |||||||||||
| Net income (loss) per share - basic | $ | 3.86 | $ | 0.12 | $ | (0.32) | $ | 4.54 | $ | 5.38 | |||||||||||
| Net income (loss) per share - diluted | $ | 3.78 | $ | 0.11 | $ | (0.32) | $ | 4.42 | $ | 5.18 | |||||||||||
| Adjusted net income | $ | 137 | $ | 42 | $ | 74 | $ | 233 | $ | 305 | |||||||||||
| Adjusted net income per share - basic | $ | 1.53 | $ | 0.62 | $ | 1.08 | $ | 3.09 | $ | 4.36 | |||||||||||
| Adjusted net income per share - diluted | $ | 1.50 | $ | 0.60 | $ | 1.02 | $ | 3.00 | $ | 4.20 | |||||||||||
| Weighted-average common shares outstanding - basic | 89.4 | 68.1 | 68.7 | 75.5 | 69.9 | ||||||||||||||||
| Weighted-average common shares outstanding - diluted | 91.2 | 70.0 | 68.7 | 77.6 | 72.6 | ||||||||||||||||
| Adjusted EBITDAX | $ | 402 | $ | 139 | $ | 187 | $ | 690 | $ | 683 | |||||||||||
| Effective tax rate | 29% | 27% | 27% | 28% | 22% | ||||||||||||||||
| 3rd Quarter | 2nd Quarter | 3rd Quarter | Nine Months | Nine Months | |||||||||||||||||
| ($ in millions) | 2024 | 2024 | 2023 | 2024 | 2023 | ||||||||||||||||
| Cash Flow Data: | |||||||||||||||||||||
| Net cash provided by operating activities | $ | 220 | $ | 97 | $ | 104 | $ | 404 | $ | 522 | |||||||||||
| Net cash used in investing activities | $ | (928) | $ | (33) | $ | (28) | $ | (1,010) | $ | (133) | |||||||||||
| Net cash (used) provided by financing activities | $ | (82) | $ | 564 | $ | (45) | $ | 351 | $ | (217) | |||||||||||
| September 30, | December 31, | ||||||||||||||||||||
| ($ in millions) | 2024 | 2023 | |||||||||||||||||||
| Selected Balance Sheet Data: | |||||||||||||||||||||
| Total current assets | $ | 872 | $ | 929 | |||||||||||||||||
| Property, plant and equipment, net | $ | 5,836 | $ | 2,770 | |||||||||||||||||
| Deferred tax asset | $ | 50 | $ | 132 | |||||||||||||||||
| Total current liabilities | $ | 897 | $ | 616 | |||||||||||||||||
| Long-term debt, net | $ | 1,131 | $ | 540 | |||||||||||||||||
| Noncurrent asset retirement obligations | $ | 1,083 | $ | 422 | |||||||||||||||||
| Deferred tax liability | $ | 124 | $ | — | |||||||||||||||||
| Total stockholders' equity | $ | 3,501 | $ | 2,219 | |||||||||||||||||
| GAINS AND LOSSES FROM COMMODITY DERIVATIVES | |||||||||||||||||||
| 3rd Quarter | 2nd Quarter | 3rd Quarter | Nine Months | Nine Months | |||||||||||||||
| ($ millions) | 2024 | 2024 | 2023 | 2024 | 2023 | ||||||||||||||
| Non-cash derivative gain (loss) | $ | 373 | $ | 11 | $ | (109) | $ | 325 | $ | 92 | |||||||||
| Net payments on settled commodity derivatives | (17) | (6) | (95) | (35) | (223) | ||||||||||||||
| Net gain (loss) from commodity derivatives | $ | 356 | $ | 5 | $ | (204) | $ | 290 | $ | (131) | |||||||||
| CAPITAL INVESTMENTS | |||||||||||||||
| 3rd Quarter | 2nd Quarter | 3rd Quarter | Nine Months | Nine Months | |||||||||||
| ($ millions) | 2024 | 2024 | 2023 | 2024 | 2023 | ||||||||||
| Facilities (1) | $ | 36 | $ | 17 | $ | 7 | $ | 67 | $ | 27 | |||||
| Drilling | 19 | 18 | 13 | 52 | 51 | ||||||||||
| Workovers | 19 | 11 | 11 | 37 | 28 | ||||||||||
| Total E&P capital | 74 | 46 | 31 | 156 | 106 | ||||||||||
| CMB (1) | 4 | (2) | — | 6 | 1 | ||||||||||
| Corporate and other | 1 | (10) | 2 | 5 | 12 | ||||||||||
| Total capital program | $ | 79 | $ | 34 | $ | 33 | $ | 167 | $ | 119 | |||||
| (1) Facilities capital includes $1 million in the third quarter of 2023, and $3 million for the nine months 2023, to build replacement water injection facilities which will allow CRC to divert produced water away from a depleted oil and natural gas reservoir held by the Carbon TerraVault JV. Construction of these facilities supports the advancement of CRC’s carbon management business and CRC reported these amounts as part of adjusted CMB capital in this Earnings Release. Where adjusted CMB capital is presented, CRC removed the amounts from facilities capital and presented adjusted E&P, Corporate and Other capital. Capital for the three months ended June 30, 2024 reflects a $3 million reclassification from capital (PP&E) to expense for engineering costs incurred during the two prior quarters. Before this reclassification, CMB capital was $1 million for the three months ended June 30, 2024. Capital for Corporate and other for the three months ended June 30, 2024 reflects a reclassification of $10 million from capital (PP&E) to expense for planned major maintenance in the first quarter of 2024. Before the reclassifications, Corporate and other capital for the three months would have been $14 million. | |||||||||||||||
| Attachment 2 | |||||||
| CRC GUIDANCE | Total 4Q24E | CMB 4Q24E | E&P, Corp. & Other 4Q24E | ||||
| Net Production Sold (MBoe/d) | 140 - 144 | 140 - 144 | |||||
| Oil Production Sold (%) | ~79% | ~79% | |||||
| CMB Expenses & Operating Costs ($ millions) | $340 - $365 | $15 - $25 | $325 - $340 | ||||
| General and Administrative Expenses ($ millions) | $90 - $100 | $2 - $4 | $88 - $96 | ||||
| Adjusted General and Administrative Expenses ($ millions) | $80 - $90 | $1 - $3 | $79 - $87 | ||||
| Capital ($ millions) | $85 - $105 | $5 - $10 | $80 - $95 | ||||
| Drilling & completions, workover ($ millions) | $37 - $45 | ||||||
| Facilities ($ millions) | $40 - $45 | ||||||
| Carbon management business ($ millions) | $5 - $10 | ||||||
| Corporate & other ($ millions) | $3 - $5 | ||||||
| Adjusted EBITDAX ($ millions) | $260 - $300 | ||||||
| Margin from Marketing of Purchased Commodities ($ millions) (1) | $5 - $10 | $5 - $10 | |||||
| Electricity Margin ($ millions) (2) | $15 - $20 | $15 - $20 | |||||
| Other Operating Revenue & Expenses, net ($ millions)(3) | ($10) - ($20) | ($10) - ($20) | |||||
| Transportation Costs ($ millions) | $20 - $25 | $20 - $25 | |||||
| Taxes Other Than on Income ($ millions) | $75 - $86 | $75 - $86 | |||||
| Interest and Debt Expense ($ millions) | $25 - $30 | $25 - $30 | |||||
| Commodity Assumptions: | |||||||
| Brent ($/Bbl) | $71.48 | $71.48 | |||||
| NYMEX ($/Mcf) | $2.95 | $2.95 | |||||
| Oil - % of Brent: | 95% to 99% | 95% to 99% | |||||
| NGL - % of Brent: | 65% to 69% | 65% to 69% | |||||
| Natural Gas - % of NYMEX: | 128% to 138% | 128% to 138% | |||||
(1) Margin from Marketing of Purchased Commodities is calculated as the difference between Revenue from Marketing of Purchased Commodities and Costs Related to Marketing of Purchased Commodities.
(2) Electricity Margin is calculated as the difference between Electricity Sales and Electricity Generation Expenses.
(3) Other Operating Revenue & Expenses, net is calculated as the difference between Other Revenue and Other Operating Expenses, net.
See Attachment 3 for management's disclosure of its use of these non-GAAP measures and how these measures provide useful information to investors about CRC's results of operations and financial condition.
ESTIMATED ADJUSTED GENERAL AND ADMINISTRATIVE EXPENSES RECONCILIATION
| 4Q24 Estimated | |||||||||||||||||||||||
| Consolidated | CMB | E&P, Corporate & Other | |||||||||||||||||||||
| ($ millions) | Low | High | Low | High | Low | High | |||||||||||||||||
| General and administrative expenses | $ | 90 | $ | 100 | $ | 2 | $ | 4 | $ | 88 | $ | 96 | |||||||||||
| Equity-settled stock-based compensation | (9) | (9) | (1) | (1) | (8) | (8) | |||||||||||||||||
| Other | (1) | (1) | (1) | (1) | |||||||||||||||||||
| Estimated adjusted general and administrative expenses | $ | 80 | $ | 90 | $ | 1 | $ | 3 | $ | 79 | $ | 87 | |||||||||||
ESTIMATED ADJUSTED EBITDAX RECONCILIATION
| 4Q24E | |||||||||||||||
| ($ millions) | Low | High | |||||||||||||
| Net income | $ | 22 | $ | 32 | |||||||||||
| Interest and debt expense, net | 25 | 30 | |||||||||||||
| Depreciation, depletion and amortization | 135 | 141 | |||||||||||||
| Income taxes | 8 | 14 | |||||||||||||
| Unusual, infrequent and other items | 15 | 24 | |||||||||||||
| Other non-cash items | |||||||||||||||
| Accretion expense | 30 | 32 | |||||||||||||
| Stock-settled compensation | 5 | 7 | |||||||||||||
| Post-retirement medical and pension | 0 | 0 | |||||||||||||
| Estimated adjusted EBITDAX | $ | 240 | $ | 280 | |||||||||||
| Net cash provided by operating activities | $ | 158 | $ | 178 | |||||||||||
| Cash interest | 37 | 43 | |||||||||||||
| Cash income taxes | 45 | 51 | |||||||||||||
| Working capital changes | 0 | 8 | |||||||||||||
| Estimated adjusted EBITDAX | $ | 240 | $ | 280 | |||||||||||
| Attachment 3 | ||||||||
| NON-GAAP FINANCIAL MEASURES AND RECONCILIATIONS | ||||||||
| To supplement the presentation of its financial results prepared in accordance with U.S generally accepted accounting principles (GAAP), management uses certain non-GAAP measures to assess its financial condition, results of operations and cash flows. The non-GAAP measures include adjusted net income (loss), adjusted EBITDAX, E&P, Corporate & Other adjusted EBITDAX, CMB adjusted EBITDAX, net cash provided by operating activities before changes in operating assets and liabilities, net, free cash flow, E&P, Corporate & Other free cash flow, CMB free cash flow, adjusted general and administrative expenses, operating costs per BOE, and adjusted total capital among others. These measures are also widely used by the industry, the investment community and CRC's lenders. Although these are non-GAAP measures, the amounts included in the calculations were computed in accordance with GAAP. Certain items excluded from these non-GAAP measures are significant components in understanding and assessing CRC's financial performance, such as CRC's cost of capital and tax structure, as well as the effect of acquisition and development costs of CRC's assets. Management believes that the non-GAAP measures presented, when viewed in combination with CRC's financial and operating results prepared in accordance with GAAP, provide a more complete understanding of the factors and trends affecting the Company's performance. The non-GAAP measures presented herein may not be comparable to other similarly titled measures of other companies. Below are additional disclosures regarding each of the non-GAAP measures reported in this earnings release, including reconciliations to their most directly comparable GAAP measure where applicable. | ||||||||
| ADJUSTED NET INCOME (LOSS) | ||||||||||||||||||||
| Adjusted net income (loss) and adjusted net income (loss) per share are non-GAAP measures. CRC defines adjusted net income as net income excluding the effects of significant transactions and events that affect earnings but vary widely and unpredictably in nature, timing and amount. These events may recur, even across successive reporting periods. Management believes these non-GAAP measures provide useful information to the industry and the investment community interested in comparing CRC's financial performance between periods. Reported earnings are considered representative of management's performance over the long term. Adjusted net income (loss) is not considered to be an alternative to net income (loss) reported in accordance with GAAP. The following table presents a reconciliation of the GAAP financial measure of net income and net income attributable to common stock per share to the non-GAAP financial measure of adjusted net income and adjusted net income per share. | ||||||||||||||||||||
| 3rd Quarter | 2nd Quarter | 3rd Quarter | Nine Months | Nine Months | ||||||||||||||||
| ($ millions, except per share amounts) | 2024 | 2024 | 2023 | 2024 | 2023 | |||||||||||||||
| Net income (loss) | $ | 345 | $ | 8 | $ | (22) | $ | 343 | $ | 376 | ||||||||||
| Unusual, infrequent and other items: | ||||||||||||||||||||
| Non-cash derivative (gain) loss | (373) | (11) | 109 | (325) | (92) | |||||||||||||||
| Asset impairment | — | 13 | — | 13 | 3 | |||||||||||||||
| Severance and termination costs | 27 | 1 | 7 | 28 | 10 | |||||||||||||||
| Aera merger transaction / integration fees | 30 | 13 | — | 56 | — | |||||||||||||||
| Increased power and fuel costs due to power plant shutdown | 8 | 15 | — | 44 | — | |||||||||||||||
| Net gain (loss) on asset divestitures | — | (1) | — | (7) | (7) | |||||||||||||||
| Loss on early extinguishment of debt | 5 | — | — | 5 | — | |||||||||||||||
| Other, net | 6 | 17 | 17 | 25 | 30 | |||||||||||||||
| Total unusual, infrequent and other items | (297) | 47 | 133 | (161) | (56) | |||||||||||||||
| Income tax provision (benefit) of adjustments at effective tax rate | 89 | (13) | (37) | 51 | 16 | |||||||||||||||
| Income tax benefit - out of period | — | — | — | — | (31) | |||||||||||||||
| Adjusted net income | $ | 137 | $ | 42 | $ | 74 | $ | 233 | $ | 305 | ||||||||||
| Net income (loss) per share - basic | $ | 3.86 | $ | 0.12 | $ | (0.32) | $ | 4.54 | $ | 5.38 | ||||||||||
| Net income (loss) per share - diluted | $ | 3.78 | $ | 0.11 | $ | (0.32) | $ | 4.42 | $ | 5.18 | ||||||||||
| Adjusted net income per share - basic | $ | 1.53 | $ | 0.62 | $ | 1.08 | $ | 3.09 | $ | 4.36 | ||||||||||
| Adjusted net income per share - diluted | $ | 1.50 | $ | 0.60 | $ | 1.02 | $ | 3.00 | $ | 4.20 | ||||||||||
| ADJUSTED EBITDAX | |||||||||||||||||||||
| CRC defines Adjusted EBITDAX as earnings before interest expense; income taxes; depreciation, depletion and amortization; exploration expense; other unusual, infrequent and out-of-period items; and other non-cash items. CRC believes this measure provides useful information in assessing its financial condition, results of operations and cash flows and is widely used by the industry, the investment community and its lenders. Although this is a non-GAAP measure, the amounts included in the calculation were computed in accordance with GAAP. Certain items excluded from this non-GAAP measure are significant components in understanding and assessing CRC’s financial performance, such as its cost of capital and tax structure, as well as depreciation, depletion and amortization of CRC's assets. This measure should be read in conjunction with the information contained in CRC’s financial statements prepared in accordance with GAAP. A version of Adjusted EBITDAX is a material component of certain of its financial covenants under CRC's Revolving Credit Facility and is provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP. The following table represents a reconciliation of the GAAP financial measures of net income and net cash provided by operating activities to the non-GAAP financial measure of adjusted EBITDAX. CRC has supplemented its non-GAAP measures of consolidated adjusted EBITDAX with adjusted EBITDAX for its exploration and production and corporate items (Adjusted EBITDAX for E&P, Corporate & Other) which management believes is a useful measure for investors to understand the results of the core oil and gas business. CRC defines adjusted EBITDAX for E&P, Corporate & Other as consolidated adjusted EBITDAX less results attributable to its carbon management business (CMB). | |||||||||||||||||||||
| 3rd Quarter | 2nd Quarter | 3rd Quarter | Nine Months | Nine Months | |||||||||||||||||
| ($ millions, except per BOE amounts) | 2024 | 2024 | 2023 | 2024 | 2023 | ||||||||||||||||
| Net income (loss) | $ | 345 | $ | 8 | $ | (22) | $ | 343 | $ | 376 | |||||||||||
| Interest and debt expense | 29 | 17 | 15 | 59 | 43 | ||||||||||||||||
| Depreciation, depletion and amortization | 140 | 53 | 56 | 246 | 170 | ||||||||||||||||
| Income tax provision (benefit) | 138 | 3 | (8) | 132 | 105 | ||||||||||||||||
| Exploration expense | 1 | — | — | 2 | 2 | ||||||||||||||||
| Interest income | (1) | (8) | (5) | (15) | (14) | ||||||||||||||||
| Unusual, infrequent and other items (1) | (297) | 47 | 133 | (161) | (56) | ||||||||||||||||
| Non-cash items | |||||||||||||||||||||
| Accretion expense | 31 | 13 | 12 | 56 | 35 | ||||||||||||||||
| Stock-based compensation | 6 | 6 | 6 | 17 | 21 | ||||||||||||||||
| Taxes related to acquisition accounting | 10 | — | — | 10 | — | ||||||||||||||||
| Post-retirement medical and pension | — | — | — | 1 | 1 | ||||||||||||||||
| Adjusted EBITDAX | $ | 402 | $ | 139 | $ | 187 | $ | 690 | $ | 683 | |||||||||||
| Net cash provided by operating activities | $ | 220 | $ | 97 | $ | 104 | $ | 404 | $ | 522 | |||||||||||
| Cash interest payments | 24 | 1 | 23 | 46 | 48 | ||||||||||||||||
| Cash interest received | (1) | (8) | (5) | (15) | (14) | ||||||||||||||||
| Cash income taxes | 29 | 4 | 29 | 55 | 80 | ||||||||||||||||
| Exploration expenditures | 1 | — | — | 2 | 2 | ||||||||||||||||
| Adjustments to working capital changes | 129 | 45 | 36 | 198 | 45 | ||||||||||||||||
| Adjusted EBITDAX | $ | 402 | $ | 139 | $ | 187 | $ | 690 | $ | 683 | |||||||||||
| E&P, Corporate & Other Adjusted EBITDAX | $ | 417 | $ | 160 | $ | 199 | $ | 739 | $ | 717 | |||||||||||
| CMB Adjusted EBITDAX | $ | (15) | $ | (21) | $ | (12) | $ | (49) | $ | (34) | |||||||||||
| Adjusted EBITDAX per Boe | $ | 30.19 | $ | 20.23 | $ | 23.81 | $ | 25.44 | $ | 28.78 | |||||||||||
| (1) See Adjusted Net Income (Loss) reconciliation. | |||||||||||||||||||||
| FREE CASH FLOW AND SUPPLEMENTAL CASH FLOW MEASURES | ||||||||||||||||||||
| Management uses free cash flow, which is defined by CRC as net cash provided by operating activities less capital investments, as a measure of liquidity. The following table presents a reconciliation of CRC's net cash provided by operating activities to free cash flow. CRC supplemented its non-GAAP measure of free cash flow with (i) net cash provided by operating activities before changes in operating assets and liabilities, net, (ii) adjusted free cash flow, and (iii) adjusted free cash flow of exploration and production, and corporate and other items (Free Cash Flow for E&P, Corporate & Other), which it believes is a useful measure for investors to understand the results of CRC's core oil and gas business. CRC defines Free Cash Flow for E&P, Corporate & Other as consolidated free cash flow less results attributable to its carbon management business (CMB). CRC defines adjusted free cash flow as free cash flow before transaction and integration costs from the Aera Merger. | ||||||||||||||||||||
| 3rd Quarter | 2nd Quarter | 3rd Quarter | Nine Months | Nine Months | ||||||||||||||||
| ($ millions) | 2024 | 2024 | 2023 | 2024 | 2023 | |||||||||||||||
| Net cash provided by operating activities before working capital changes | $ | 249 | $ | 108 | $ | 129 | $ | 449 | $ | 543 | ||||||||||
| Working capital changes | (29) | (11) | (25) | (45) | (21) | |||||||||||||||
| Net cash provided by operating activities | 220 | 97 | 104 | 404 | 522 | |||||||||||||||
| Capital investments | (79) | (34) | (33) | (167) | (119) | |||||||||||||||
| Free cash flow | $ | 141 | $ | 63 | $ | 71 | $ | 237 | $ | 403 | ||||||||||
| Add: Aera transaction and integration costs | 30 | 13 | — | 56 | — | |||||||||||||||
| Free cash flow after special items | $ | 171 | $ | 76 | $ | 71 | $ | 293 | $ | 403 | ||||||||||
| E&P, Corporate and Other (1) | $ | 186 | $ | 95 | $ | 79 | $ | 334 | $ | 427 | ||||||||||
| CMB (1) | $ | (15) | $ | (19) | $ | (8) | $ | (41) | $ | (24) | ||||||||||
| Adjustments to capital investments: | ||||||||||||||||||||
| Replacement water facilities(2) | $ | — | $ | — | $ | 1 | $ | — | $ | 3 | ||||||||||
| Adjusted capital investments: | ||||||||||||||||||||
| E&P, Corporate and Other | $ | 75 | $ | 36 | $ | 32 | $ | 161 | $ | 115 | ||||||||||
| CMB | $ | 4 | $ | (2) | $ | 1 | $ | 6 | $ | 4 | ||||||||||
| Adjusted free cash flow: | ||||||||||||||||||||
| E&P, Corporate and Other | $ | 186 | $ | 95 | $ | 80 | $ | 334 | $ | 430 | ||||||||||
| CMB | $ | (15) | $ | (19) | $ | (9) | $ | (41) | $ | (27 | ) | |||||||||
| (1) CMB free cash flow previously reported for the first three months of 2024 was $(17) million and was corrected to $(7) million to account for noncash add backs related to leases. CRC defines free cash flow for E&P, Corporate & Other as consolidated free cash flow less results attributable to the carbon management business. Accordingly, this change impacted our previously reported E&P, Corporate & Other free cash flow from $63 million to $53 million for the first three months of 2024. | ||||||||||||||||||||
| (2) Facilities capital includes $1 million in the third quarter of 2023 to build replacement water injection facilities which will allow CRC to divert produced water away from a depleted oil and natural gas reservoir held by the Carbon TerraVault JV. Construction of these facilities supports the advancement of CRC’s carbon management business and CRC reported these amounts as part of adjusted CMB capital in this press release. Where adjusted CMB capital is presented, CRC removed the amounts from facilities capital and presented adjusted E&P, Corporate and Other capital. | ||||||||||||||||||||
| ADJUSTED GENERAL & ADMINISTRATIVE EXPENSES | |||||||||||||||||||||
| Management uses a measure called adjusted general and administrative (G&A) expenses to provide useful information to investors interested in comparing CRC's costs between periods and performance to our peers. CRC supplemented its non-GAAP measure of adjusted general and administrative expenses with adjusted general and administrative expenses of its exploration and production and corporate items (adjusted general & administrative expenses for E&P, Corporate & Other) which it believes is a useful measure for investors to understand the results or CRC's core oil and gas business. CRC defines adjusted general & administrative Expenses for E&P, Corporate & Other as consolidated adjusted general and administrative expenses less results attributable to its carbon management business (CMB). | |||||||||||||||||||||
| 3rd Quarter | 2nd Quarter | 3rd Quarter | Nine Months | Nine Months | |||||||||||||||||
| ($ millions) | 2024 | 2024 | 2023 | 2024 | 2023 | ||||||||||||||||
| General and administrative expenses | $ | 106 | $ | 63 | $ | 65 | $ | 226 | $ | 201 | |||||||||||
| Stock-based compensation | (6) | (6) | (6) | (17) | (21) | ||||||||||||||||
| Information technology infrastructure | — | (1) | (6) | (3) | (13) | ||||||||||||||||
| Accelerated vesting | (9) | — | — | (9) | — | ||||||||||||||||
| Retention awards | (2) | — | — | (2) | — | ||||||||||||||||
| Other | — | — | (2) | (1) | (4) | ||||||||||||||||
| Adjusted G&A expenses | $ | 89 | $ | 56 | $ | 51 | $ | 194 | $ | 163 | |||||||||||
| E&P, Corporate and Other adjusted G&A expenses | $ | 87 | $ | 53 | $ | 47 | $ | 187 | $ | 153 | |||||||||||
| CMB adjusted G&A expenses | $ | 2 | $ | 3 | $ | 4 | $ | 7 | $ | 10 | |||||||||||
| Adjusted G&A per BOE | $ | 6.68 | $ | 8.15 | $ | 6.49 | $ | 7.15 | $ | 6.87 | |||||||||||
| OPERATING COSTS PER BOE | |||||||||||||||||||||
| The reporting of PSC-type contracts creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only CRC's net share, inflating the per barrel operating costs. The following table presents operating costs after adjusting for the excess costs attributable to PSCs. | |||||||||||||||||||||
| 3rd Quarter | 2nd Quarter | 3rd Quarter | Nine Months | Nine Months | |||||||||||||||||
| ($ per BOE) | 2024 | 2024 | 2023 | 2024 | 2023 | ||||||||||||||||
| Energy operating costs (1) | $ | 7.29 | $ | 6.40 | $ | 9.42 | $ | 7.26 | $ | 10.87 | |||||||||||
| Gas processing costs (2) | 0.38 | 0.44 | 0.64 | 0.44 | 0.59 | ||||||||||||||||
| Non-energy operating costs | 16.06 | 16.30 | 14.90 | 16.41 | 15.34 | ||||||||||||||||
| Operating costs | $ | 23.73 | $ | 23.14 | $ | 24.96 | $ | 24.11 | $ | 26.80 | |||||||||||
| Costs attributable to PSCs | |||||||||||||||||||||
| Excess energy operating costs attributable to PSCs | $ | (0.75) | $ | (0.94) | $ | (1.09) | $ | (0.70) | $ | (1.01) | |||||||||||
| Excess non-energy operating costs attributable to PSCs | (0.48) | (1.62) | (1.30) | (1.18) | (1.25) | ||||||||||||||||
| Excess costs attributable to PSCs | $ | (1.23) | $ | (2.56) | $ | (2.39) | $ | (1.88) | $ | (2.26) | |||||||||||
| Energy operating costs, excluding effect of PSCs (1) | $ | 6.54 | $ | 5.46 | $ | 8.33 | $ | 6.56 | $ | 9.86 | |||||||||||
| Gas processing costs, excluding effect of PSCs (2) | 0.38 | 0.44 | 0.64 | 0.44 | 0.59 | ||||||||||||||||
| Non-energy operating costs, excluding effect of PSCs | 15.58 | 14.68 | 13.60 | 15.23 | 14.09 | ||||||||||||||||
| Operating costs, excluding effects of PSCs | $ | 22.50 | $ | 20.58 | $ | 22.57 | $ | 22.23 | $ | 24.54 | |||||||||||
| (1) Energy operating costs consist of purchased natural gas used to generate electricity for operations and steamfloods, purchased electricity and internal costs to generate electricity used in CRC's operations. | |||||||||||||||||||||
| (2) Gas processing costs include costs associated with compression, maintenance and other activities needed to run CRC's gas processing facilities at Elk Hills. | |||||||||||||||||||||
| Attachment 4 | |||||||||||
| PRODUCTION STATISTICS | |||||||||||
| The tables below present production information on the basis of gross production, net production and production sold. The difference between gross production and net production primarily reflects the reduction for volumes attributable to working interest and royalty owners and volumes associated with PSC-type contracts to arrive at CRC's net share. The difference between net production and net production sold reflects (i) the reduction for natural gas that CRC produces that is used in its oil and gas operations, including steam in its steamflood operations, and (ii) marketing activities reflecting the storage of volumes that CRC produces and are sold at a later time. | |||||||||||
| Volumes Sold | 3rd Quarter | 2nd Quarter | 3rd Quarter | Nine Months | Nine Months | ||||||
| Net Production Per Day | 2024 | 2024 | 2023 | 2024 | 2023 | ||||||
| Oil (MBbl/d) | |||||||||||
| San Joaquin Basin | 90 | 30 | 33 | 50 | 34 | ||||||
| Los Angeles Basin | 17 | 17 | 18 | 17 | 19 | ||||||
| Ventura Basin | 6 | — | — | 2 | — | ||||||
| Total | 113 | 47 | 51 | 69 | 53 | ||||||
| NGLs (MBbl/d) | |||||||||||
| San Joaquin Basin | 11 | 10 | 11 | 11 | 11 | ||||||
| Total | 11 | 10 | 11 | 11 | 11 | ||||||
| Natural Gas (MMcf/d) | |||||||||||
| San Joaquin Basin | 111 | 99 | 122 | 99 | 120 | ||||||
| Los Angeles Basin | 1 | 1 | 1 | 1 | 1 | ||||||
| Ventura Basin | 1 | — | — | — | — | ||||||
| Sacramento Basin | 13 | 14 | 15 | 14 | 15 | ||||||
| Total | 126 | 114 | 138 | 114 | 136 | ||||||
| Total Production (MBoe/d) | 145 | 76 | 85 | 99 | 87 | ||||||
| Volumes Produced | 3rd Quarter | 2nd Quarter | 3rd Quarter | Nine Months | Nine Months | ||||||
| Net Production Per Day | 2024 | 2024 | 2023 | 2024 | 2023 | ||||||
| Oil (MBbl/d) | |||||||||||
| San Joaquin Basin | 90 | 30 | 33 | 51 | 34 | ||||||
| Los Angeles Basin | 17 | 16 | 18 | 17 | 19 | ||||||
| Ventura Basin | 6 | — | — | 2 | — | ||||||
| Total | 113 | 46 | 51 | 70 | 53 | ||||||
| NGLs (MBbl/d) | |||||||||||
| San Joaquin Basin | 11 | 11 | 12 | 10 | 11 | ||||||
| Total | 11 | 11 | 12 | 10 | 11 | ||||||
| Natural Gas (MMcf/d) | |||||||||||
| San Joaquin Basin | 130 | 118 | 128 | 123 | 127 | ||||||
| Los Angeles Basin | 1 | 1 | 1 | 1 | 1 | ||||||
| Ventura Basin | 3 | — | — | 1 | — | ||||||
| Sacramento Basin | 13 | 14 | 15 | 14 | 16 | ||||||
| Total | 147 | 133 | 144 | 139 | 144 | ||||||
| Total Production (MBoe/d) | 149 | 79 | 87 | 103 | 88 | ||||||
| Attachment 4 | |||||||||||
| PRODUCTION STATISTICS | |||||||||||
| Gross Operated and Net Non-Operated | 3rd Quarter | 2nd Quarter | 3rd Quarter | Nine Months | Nine Months | ||||||
| Production Per Day | 2024 | 2024 | 2023 | 2024 | 2023 | ||||||
| Oil (MBbl/d) | |||||||||||
| San Joaquin Basin | 96 | 33 | 36 | 54 | 38 | ||||||
| Los Angeles Basin | 23 | 24 | 25 | 24 | 25 | ||||||
| Ventura Basin | 8 | — | — | 3 | — | ||||||
| Total | 127 | 57 | 61 | 81 | 63 | ||||||
| NGLs (MBbl/d) | |||||||||||
| San Joaquin Basin | 11 | 11 | 13 | 11 | 12 | ||||||
| Total | 11 | 11 | 13 | 11 | 12 | ||||||
| Natural Gas (MMcf/d) | |||||||||||
| San Joaquin Basin | 137 | 125 | 135 | 130 | 135 | ||||||
| Los Angeles Basin | 7 | 7 | 8 | 7 | 7 | ||||||
| Ventura Basin | 3 | — | — | 1 | — | ||||||
| Sacramento Basin | 16 | 17 | 18 | 17 | 20 | ||||||
| Total | 163 | 149 | 161 | 155 | 162 | ||||||
| Total Production (MBoe/d) | 165 | 93 | 101 | 118 | 102 | ||||||
| Attachment 5 | ||||||||||||||||||||||
| PRICE STATISTICS | ||||||||||||||||||||||
| 3rd Quarter | 2nd Quarter | 3rd Quarter | Nine Months | Nine Months | ||||||||||||||||||
| 2024 | 2024 | 2023 | 2024 | 2023 | ||||||||||||||||||
| Oil ($ per Bbl) | ||||||||||||||||||||||
| Realized price with derivative settlements | $ | 75.38 | $ | 81.29 | $ | 66.12 | $ | 77.10 | $ | 64.25 | ||||||||||||
| Realized price without derivative settlements | $ | 77.10 | $ | 83.14 | $ | 85.36 | $ | 79.15 | $ | 79.90 | ||||||||||||
| NGLs ($/Bbl) | $ | 45.77 | $ | 46.96 | $ | 44.95 | $ | 47.77 | $ | 48.89 | ||||||||||||
| Natural gas ($/Mcf) | ||||||||||||||||||||||
| Realized price with derivative settlements | $ | 2.68 | $ | 1.78 | $ | 4.83 | $ | 2.76 | $ | 9.85 | ||||||||||||
| Realized price without derivative settlements | $ | 2.68 | $ | 1.78 | $ | 4.83 | $ | 2.76 | $ | 9.85 | ||||||||||||
| Index Prices | ||||||||||||||||||||||
| Brent oil ($/Bbl) | $ | 78.54 | $ | 85.00 | $ | 85.95 | $ | 81.79 | $ | 82.06 | ||||||||||||
| WTI oil ($/Bbl) | $ | 75.09 | $ | 80.57 | $ | 82.26 | $ | 77.54 | $ | 77.39 | ||||||||||||
| NYMEX average monthly settled price ($/MMBtu) | $ | 2.16 | $ | 1.89 | $ | 2.55 | $ | 2.10 | $ | 2.69 | ||||||||||||
| Realized Prices as Percentage of Index Prices | ||||||||||||||||||||||
| Oil with derivative settlements as a percentage of Brent | 96% | 96% | 77% | 94% | 78% | |||||||||||||||||
| Oil without derivative settlements as a percentage of Brent | 98% | 98% | 99% | 97% | 97% | |||||||||||||||||
| Oil with derivative settlements as a percentage of WTI | 100% | 101% | 80% | 99% | 83% | |||||||||||||||||
| Oil without derivative settlements as a percentage of WTI | 103% | 103% | 104% | 102% | 103% | |||||||||||||||||
| NGLs as a percentage of Brent | 58% | 55% | 52% | 58% | 60% | |||||||||||||||||
| NGLs as a percentage of WTI | 61% | 58% | 55% | 62% | 63% | |||||||||||||||||
| Natural gas with derivative settlements as a percentage of NYMEX contract month average | 124% | 94% | 189% | 131% | 366% | |||||||||||||||||
| Natural gas without derivative settlements as a percentage of NYMEX contract month average | 124% | 94% | 189% | 131% | 366% | |||||||||||||||||
| Attachment 6 | |||||||||
| THIRD QUARTER 2024 DRILLING ACTIVITY | |||||||||
| San Joaquin | Los Angeles | Ventura | Sacramento | ||||||
| Wells Drilled | Basin | Basin | Basin | Basin | Total | ||||
| Development Wells | |||||||||
| Primary | 1 | — | — | — | 1 | ||||
| Waterflood | — | — | — | — | — | ||||
| Steamflood | — | — | — | — | — | ||||
| Total (1) | 1 | — | — | — | 1 | ||||
| NINE MONTHS 2024 DRILLING ACTIVITY | |||||||||
| San Joaquin | Los Angeles | Ventura | Sacramento | ||||||
| Wells Drilled | Basin | Basin | Basin | Basin | Total | ||||
| Development Wells | |||||||||
| Primary | 6 | — | — | — | 6 | ||||
| Waterflood | — | — | — | — | — | ||||
| Steamflood | — | — | — | — | — | ||||
| Total (1) | 6 | — | — | — | 6 | ||||
| (1) Includes steam injectors and drilled but uncompleted wells, which are not included in the SEC definition of wells drilled. | |||||||||
| Attachment 7 | |||||||||||||||||||||||||
| OIL HEDGES AS OF SEPTEMBER 30, 2024 | |||||||||||||||||||||||||
| Q4 2024 | Q1 2025 | Q2 2025 | Q3 2025 | Q4 2025 | 2026 | 2027 | 2028 | ||||||||||||||||||
| Sold Calls | |||||||||||||||||||||||||
| Barrels per day | 29,000 | 30,000 | 30,000 | 30,000 | 29,000 | 5,000 | — | — | |||||||||||||||||
| Weighted-average Brent price per barrel | $90.07 | $87.08 | $87.08 | $87.08 | $87.13 | $85.00 | $— | $— | |||||||||||||||||
| Swaps | |||||||||||||||||||||||||
| Barrels per day | 59,014 | 52,837 | 45,631 | 44,126 | 42,626 | 30,449 | 13,882 | 10,353 | |||||||||||||||||
| Weighted-average Brent price per barrel | $74.90 | $72.48 | $71.31 | $70.62 | $69.94 | $67.95 | $65.53 | $65.00 | |||||||||||||||||
| Purchased Puts | |||||||||||||||||||||||||
| Barrels per day | 29,000 | 30,000 | 30,000 | 30,000 | 29,000 | 5,000 | — | — | |||||||||||||||||
| Weighted-average Brent price per barrel | $65.17 | $61.67 | $61.67 | $61.67 | $61.72 | $60.00 | $— | $— | |||||||||||||||||
| Attachment 7 | ||||||||||||||||||||||||||
| NATURAL GAS HEDGES AS OF SEPTEMBER 30, 2024 | ||||||||||||||||||||||||||
| Q4 2024 | Q1 2025 | Q2 2025 | Q3 2025 | Q4 2025 | 2026 | 2027 | 2028 | |||||||||||||||||||
| SoCal Border | ||||||||||||||||||||||||||
| MMBtu per day | 20,000 | 10,000 | 29,074 | 25,750 | 22,408 | — | — | — | ||||||||||||||||||
| Weighted-average price per MMBtu | $5.49 | $6.02 | $3.44 | $3.48 | $3.53 | $— | $— | $— | ||||||||||||||||||
| Northwest Pipeline (NWPL) Rockies | ||||||||||||||||||||||||||
| MMBtu per day | 50,999 | 50,999 | 51,750 | 51,750 | 51,750 | 35,336 | 12,616 | 9,613 | ||||||||||||||||||
| Weighted-average price per MMBtu | $4.67 | $5.48 | $2.95 | $2.95 | $4.22 | $4.04 | $4.34 | $3.95 | ||||||||||||||||||
| PG&E Citygate | ||||||||||||||||||||||||||
| MMBtu per day | 14,000 | 14,000 | — | — | — | — | — | — | ||||||||||||||||||
| Weighted-average price per MMBtu | $5.60 | $6.10 | $— | $— | $— | $— | $— | $— | ||||||||||||||||||
This press release was published by a CLEAR® Verified individual.
