California Resources Reports Second Quarter 2024 Financial and Operating Results
Increasing quarterly dividend by 25%, enhancing cash returns to shareholders
Targeting $235 million in Aera merger synergies
New EPA Class VI permit application to expand Company's carbon platform, doubling Central California CO2 potential storage capacity
LONG BEACH, California, August 6, 2024 - California Resources Corporation (NYSE: CRC) today reported financial and operating results for the second quarter of 2024. The Company plans to host a conference call and webcast at 1 p.m. ET (10 a.m. PT) on Wednesday, August 7, 2024. Participation details can be found within this release. In addition, supplemental slides have been posted to CRC’s website at www.crc.com.
Highlights:
Aera Merger
•Successfully closed the merger with Aera Energy on July 1, 2024. Complementary assets grow Company's core base, expected to double cash flow, and adds quality assets to carbon business platform
•Increased Aera merger targeted synergies to $235 million which includes a reduction of $60 million1 in annual interest expense and $25 million in additional operational synergies
CRC
•Enhanced cash returns to shareholders through 25% increase in quarterly dividend; declared quarterly dividend of $0.3875/share to be paid in the third quarter of 2024
•Generated $97 million of net cash provided by operating activities, net cash provided by operating activities before changes in operating assets and liabilities2 of $108 million and $63 million of free cash flow2
•Returned 142% of year-to-date free cash flow2, or $136 million, to shareholders including $93 million in share repurchases and $43 million in dividends
•Generated $8 million of net income, $42 million of adjusted net income2 and adjusted EBITDAX2 of $139 million
•Delivered second quarter average net production of 76 MBoe/d and average net oil production of 47 thousand barrels of oil per day (MBo/d). Gross production averaged
93 MBoe/d
•Exceeded first half 2024 production expectations through lower-than-expected natural field declines and in-line capital investments; entry-to-exit gross production declined by 2%, or 2 thousand barrels of oil equivalent per day (MBoe/d) on drilling and workover capital investments of $51 million
•Submitted a 102 million metric ton (MMT) Class VI permit application to the EPA for the Carbon TerraVault VI (CTV VI) CO2 reservoir in Central California bringing CTV's total
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potential storage capacity with Class VI permits submitted to the EPA to ~320 MMT. See CTV's Second Quarter 2024 Update for additional information
"These are exciting times for CRC as we successfully closed the merger with Aera Energy in early July," said Francisco Leon, CRC's President and Chief Executive Officer. "I am pleased with the CRC team's execution in the second quarter and we are working diligently with our new Aera colleagues on executing a comprehensive integration plan. We continue to identify additional avenues to further enhance shareholder value and accelerate momentum across our E&P and carbon management businesses. We are committed to improving CRC’s cash flows and remain vigilant in our environmental stewardship. With the addition of Aera, we believe we are extremely well positioned in the years ahead to provide substantial value to CRC shareholders and stakeholders."
Second Quarter 2024 Financial and Operating Summary
CRC reported net income of $8 million, or $0.11 per fully diluted share of common stock, and adjusted net income2 of $42 million, or $0.60 per fully diluted share. Net cash provided by operating activities was $97 million.
Gross production averaged 93 MBoe/d and net production averaged 76 MBoe/d, including net oil production of 47 MBo/d. Second quarter net production was negatively impacted by approximately 3 Mboe/d due to both scheduled maintenance and unplanned downtime at CRC's Elk Hills power plant. Average realized oil prices were 98% of Brent.
Operating costs declined 11% quarter-over-quarter to $156 million. The decrease was primarily related to lower activity and natural gas prices, as well as vendor cost savings.
Capital investments totaled $34 million, below guidance, primarily due to a $14 million change from capital to expense related to the Elk Hills power plant turnaround which began in the first quarter of 2024 and continued into the second quarter of 2024.
Second Quarter 2024 Financial Results
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| Selected Production, Price Information and Results of Operations | 2nd Quarter | 1st Quarter | ||||||||||||||||||
| ($ in millions) | 2024 | 2024 | ||||||||||||||||||
| Average net oil production per day (MBbl/d) | 47 | 48 | ||||||||||||||||||
| Realized oil price with derivative settlements ($ per Bbl) | $ | 81.29 | $ | 77.17 | ||||||||||||||||
| Average net NGL production per day (MBbl/d) | 10 | 11 | ||||||||||||||||||
| Realized NGL price ($ per Bbl) | $ | 46.96 | $ | 50.5 | ||||||||||||||||
| Average net natural gas production per day (Mmcf/d) | 114 | 105 | ||||||||||||||||||
| Realized natural gas price with derivative settlements ($ per Mcf) | $ | 1.78 | $ | 3.9 | ||||||||||||||||
| Average net total production per day (MBoe/d) | 76 | 76 | ||||||||||||||||||
Margin from marketing of purchased commodities4 ($ millions) | $ | 8 | $ | 20 | ||||||||||||||||
Margin from electricity sales5 ($ millions) | $ | 22 | $ | 7 | ||||||||||||||||
| Net gain (loss) from oil commodity derivatives ($ millions) | $ | 5 | $ | (71) | ||||||||||||||||
| Selected Financial Statement Data and non-GAAP measures: | 2nd Quarter | 1st Quarter | ||||||||||||||||||
| ($ and shares in millions, except per share amounts) | 2024 | 2024 | ||||||||||||||||||
| Statements of Operations: | ||||||||||||||||||||
| Revenues | ||||||||||||||||||||
| Total operating revenues | $ | 514 | $ | 454 | ||||||||||||||||
| Selected Expenses | ||||||||||||||||||||
| Operating costs | $ | 156 | $ | 176 | ||||||||||||||||
| General and administrative expenses | $ | 63 | $ | 57 | ||||||||||||||||
Adjusted general and administrative expenses2 | $ | 56 | $ | 49 | ||||||||||||||||
| Taxes other than on income | $ | 39 | $ | 38 | ||||||||||||||||
| Transportation costs | $ | 17 | $ | 20 | ||||||||||||||||
| Operating Income (loss) | $ | 38 | $ | (4) | ||||||||||||||||
| Interest and debt expense | $ | (17) | $ | (13) | ||||||||||||||||
| Income tax benefit (provision) | $ | (3) | $ | 9 | ||||||||||||||||
| Net (loss) Income | $ | 8 | $ | (10) | ||||||||||||||||
| EPS, Non-GAAP Measures and Select Balance Sheet Data | ||||||||||||||||||||
Adjusted net income2 | $ | 42 | $ | 54 | ||||||||||||||||
| Weighted-average common shares outstanding - diluted | 70.0 | 69.0 | ||||||||||||||||||
| Net loss (income) per share - diluted | $ | 0.11 | $ | (0.14) | ||||||||||||||||
Adjusted net income2 per share - diluted | $ | 0.60 | $ | 0.75 | ||||||||||||||||
Adjusted EBITDAX2 | $ | 139 | $ | 149 | ||||||||||||||||
| Net cash provided by operating activities | $ | 97 | $ | 87 | ||||||||||||||||
Net cash provided by operating activities before changes in operating assets and liabilities, net2 | $ | 108 | $ | 92 | ||||||||||||||||
| Capital investments | $ | 34 | $ | 54 | ||||||||||||||||
Free cash flow2 | $ | 63 | $ | 33 | ||||||||||||||||
| Cash and cash equivalents | $ | 1,031 | 403 | |||||||||||||||||
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Guidance
The following tables reflect guidance for key third quarter and second half 2024 financial and operating results. Guidance for the second half of 2024 includes approximately $30 million in targeted Aera merger synergies and reflects $60 million of interest savings achieved at merger close. In the second half of 2024, CRC expects to run a one rig program under its existing permits. See Attachment 2 for more information on CRC's third quarter and second half 2024 guidance.
CRC GUIDANCE3 | Total 3Q24E | ||||
| Net Production (MBoe/d) | 141 - 145 | ||||
| Oil Production (%) | ~79% | ||||
| Capital ($ millions) | $90 - $110 | ||||
Adjusted EBITDAX2 ($ millions) | $375 - $415 | ||||
CRC GUIDANCE3 | Total 2H24E | ||||
| Net Production (MBoe/d) | 140 - 146 | ||||
| Oil Production (%) | ~79% | ||||
| Capital ($ millions) | $170 - $210 | ||||
Adjusted EBITDAX2 | $720 - $760 | ||||
Shareholder Returns
CRC is committed to returning cash to shareholders through dividends and repurchases of common stock.
During the second quarter of 2024, CRC repurchased 0.7 million shares for $35 million at an average price of $49.71 per share. Since the inception of the Share Repurchase Program in May 2021 through June 30, 2024, 16.6 million shares have been repurchased for $697 million at an average price of $41.74 per share.
On August 2, 2024, CRC's Board of Directors amended the cash dividend policy to increase the total annual dividend to $1.55 per share of common stock, payable to shareholders in quarterly increments of $0.3875 per share. This represents a 25% increase to the prior dividend policy.
On August 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 August 30, 2024 and will be paid on September 16, 2024.
From October 2020 through June 30, 2024, CRC has returned $949 million of cash to its stakeholders, including $697 million in share repurchases, $55 million in principal of its 2026 Senior Notes repurchases and $197 million of dividends.
Balance Sheet and Liquidity
On June 5, 2024, CRC completed an offering of $600 million in an aggregate principal amount of 8.25% senior notes due 2029 (2029 Senior Notes). The net proceeds from this offering plus available cash were used to repay all Aera’s outstanding debt at the close of the Aera merger on July 1, 2024. This reduced the combined companies annual interest payments by $60 million.
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As of June 30, 2024, CRC had liquidity of $1.5 billion, which consisted of $1.0 billion in available cash and cash equivalents plus $600 million of available borrowing capacity under its Revolving Credit Facility, which is after $30 million outstanding on the Revolving Credit Facility, less $130 million of outstanding letters of credit.
On July 1, 2024, CRC amended its Revolving Credit Facility which increased the aggregate commitment to $1.1 billion from $630 million and increased its borrowing base to $1.5 billion from $1.2 billion. CRC had $1,005 million of liquidity at the close of the Aera merger. There were no amounts drawn on the Revolving Credit Facility as of August 2, 2024.
Upcoming Investor Conference Participation
CRC plans to participate in the following events in September 2024:
•2024 Barclays CEO Energy-Power Conference on September 3 to 5 in New York, NY
•NYSE Energy Virtual Investor Access Day on September 10
•Pickering Energy Partners Energy Conference 2024 on September 16 to 18 in Austin, TX
•2024 Goldman Sachs Global Sustainability Forum on September 26 in New York, NY
CRC’s presentation materials will be available the day of the events on the Events and Presentations page in 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, August 7, 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/10189857/fcb0ff718c. 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.
1As of June 30, 2024. When accounting for estimated cash interest income, CRC’s net interest savings were ~$36 million.
2 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 3Q24 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 2.
3 2H24 guidance assumes Brent price of $83.29 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $2.86 per mcf. 3Q24 guidance assumes Brent price of $84.23 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $2.61 per mcf. CRC's share of production under PSC contracts decreases when commodity prices rise and increases when prices fall.
4 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
5 Electricity Margin is calculated as the difference between Electricity Sales and Electricity Generation Expenses
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
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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, Ukraine and Yemen and the Red Sea;
•the ability to successfully integrate Aera's business;
•regulatory actions and changes that affect the oil and gas industry generally and CRC in particular, including (1) the availability or timing of, or conditions imposed on, 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 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;
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•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 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.
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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 | Richard Venn (Media) 818-661-6014 | ||||
| Attachment 1 | ||||||||||||||||||||||||||||||||
| SUMMARY OF RESULTS | ||||||||||||||||||||||||||||||||
| 2nd Quarter | 1st Quarter | 2nd Quarter | Six Months | Six Months | ||||||||||||||||||||||||||||
| ($ and shares in millions, except per share amounts) | 2024 | 2024 | 2023 | 2024 | 2023 | |||||||||||||||||||||||||||
| Statements of Operations: | ||||||||||||||||||||||||||||||||
| Revenues | ||||||||||||||||||||||||||||||||
| Oil, natural gas and NGL sales | $ | 412 | $ | 429 | $ | 447 | $ | 841 | $ | 1,162 | ||||||||||||||||||||||
| Net gain (loss) from commodity derivatives | 5 | (71) | 31 | (66) | 73 | |||||||||||||||||||||||||||
| Revenue from marketing of purchased commodities | 51 | 74 | 72 | 125 | 259 | |||||||||||||||||||||||||||
| Electricity sales | 36 | 15 | 34 | 51 | 102 | |||||||||||||||||||||||||||
| Other revenue | 10 | 7 | 7 | 17 | 19 | |||||||||||||||||||||||||||
| Total operating revenues | 514 | 454 | 591 | 968 | 1,615 | |||||||||||||||||||||||||||
| Operating Expenses | ||||||||||||||||||||||||||||||||
| Operating costs | 156 | 176 | 186 | 332 | 440 | |||||||||||||||||||||||||||
| General and administrative expenses | 63 | 57 | 71 | 120 | 136 | |||||||||||||||||||||||||||
| Depreciation, depletion and amortization | 53 | 53 | 56 | 106 | 114 | |||||||||||||||||||||||||||
| Asset impairment | 13 | — | — | 13 | 3 | |||||||||||||||||||||||||||
| Taxes other than on income | 39 | 38 | 42 | 77 | 84 | |||||||||||||||||||||||||||
| Exploration expense | — | 1 | 1 | 1 | 2 | |||||||||||||||||||||||||||
| Costs related to marketing of purchased commodities | 43 | 54 | 27 | 97 | 151 | |||||||||||||||||||||||||||
| Electricity generation expenses | 14 | 8 | 13 | 22 | 62 | |||||||||||||||||||||||||||
| Transportation costs | 17 | 20 | 16 | 37 | 33 | |||||||||||||||||||||||||||
| Accretion expense | 13 | 12 | 11 | 25 | 23 | |||||||||||||||||||||||||||
| Carbon management business expenses | 15 | 8 | 8 | 23 | 13 | |||||||||||||||||||||||||||
| Other operating expenses, net | 51 | 37 | 13 | 88 | 21 | |||||||||||||||||||||||||||
| Total operating expenses | 477 | 464 | 444 | 941 | 1,082 | |||||||||||||||||||||||||||
| Net gain on asset divestitures | 1 | 6 | — | 7 | 7 | |||||||||||||||||||||||||||
| Operating Income (Loss) | 38 | (4) | 147 | 34 | 540 | |||||||||||||||||||||||||||
| Non-Operating (Expenses) Income | ||||||||||||||||||||||||||||||||
| Interest and debt expense | (17) | (13) | (14) | (30) | (28) | |||||||||||||||||||||||||||
| Loss from investment in unconsolidated subsidiary | (4) | (3) | (1) | (7) | (3) | |||||||||||||||||||||||||||
| Other non-operating (loss) income, net | (6) | 1 | 3 | (5) | 2 | |||||||||||||||||||||||||||
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| Income Before Income Taxes | 11 | (19) | 135 | (8) | 511 | |||||||||||||||||||||||||||
| Income tax (provision) benefit | (3) | 9 | (38) | 6 | (113) | |||||||||||||||||||||||||||
| Net Income | $ | 8 | $ | (10) | $ | 97 | $ | (2) | $ | 398 | ||||||||||||||||||||||
| Net income (loss) per share - basic | $ | 0.12 | $ | (0.14) | $ | 1.39 | $ | (0.03) | $ | 5.65 | ||||||||||||||||||||||
| Net income (loss) per share - diluted | $ | 0.11 | $ | (0.14) | $ | 1.35 | $ | (0.03) | $ | 5.47 | ||||||||||||||||||||||
| Adjusted net income | $ | 42 | $ | 54 | $ | 38 | $ | 96 | $ | 231 | ||||||||||||||||||||||
| Adjusted net income per share - basic | $ | 0.62 | $ | 0.78 | $ | 0.55 | $ | 1.40 | $ | 3.28 | ||||||||||||||||||||||
| Adjusted net income per share - diluted | $ | 0.60 | $ | 0.75 | $ | 0.53 | $ | 1.35 | $ | 3.18 | ||||||||||||||||||||||
| Weighted-average common shares outstanding - basic | 68.1 | 69.0 | 69.7 | 68.6 | 70.5 | |||||||||||||||||||||||||||
| Weighted-average common shares outstanding - diluted | 70.0 | 69.0 | 71.9 | 68.6 | 72.7 | |||||||||||||||||||||||||||
| Adjusted EBITDAX | $ | 139 | $ | 149 | $ | 138 | $ | 288 | $ | 496 | ||||||||||||||||||||||
| Effective tax rate | 27 | % | 45 | % | 28 | % | 75 | % | 22 | % | ||||||||||||||||||||||
| 2nd Quarter | 1st Quarter | 2nd Quarter | YTD June | YTD June | ||||||||||||||||||||||||||||
| ($ in millions) | 2024 | 2024 | 2023 | 2024 | 2023 | |||||||||||||||||||||||||||
| Cash Flow Data: | ||||||||||||||||||||||||||||||||
| Net cash provided by operating activities | $ | 97 | $ | 87 | $ | 108 | $ | 184 | $ | 418 | ||||||||||||||||||||||
| Net cash used in investing activities | $ | (33) | $ | (49) | $ | (44) | $ | (82) | $ | (105) | ||||||||||||||||||||||
| Net cash provided (used) in financing activities | $ | 564 | $ | (131) | $ | (93) | $ | 433 | $ | (172) | ||||||||||||||||||||||
| June 30 , | December 31, | |||||||||||||||||||||||||||||||
| ($ in millions) | 2024 | 2023 | ||||||||||||||||||||||||||||||
| Selected Balance Sheet Data: | ||||||||||||||||||||||||||||||||
| Total current assets | $ | 1,439 | $ | 929 | ||||||||||||||||||||||||||||
| Property, plant and equipment, net | $ | 2,773 | $ | 2,770 | ||||||||||||||||||||||||||||
| Deferred tax asset | $ | 139 | $ | 132 | ||||||||||||||||||||||||||||
| Total current liabilities | $ | 593 | $ | 616 | ||||||||||||||||||||||||||||
| Long-term debt, net | $ | 1,161 | $ | 540 | ||||||||||||||||||||||||||||
| Noncurrent asset retirement obligations | $ | 436 | $ | 422 | ||||||||||||||||||||||||||||
| Stockholders' Equity | $ | 2,052 | $ | 2,219 | ||||||||||||||||||||||||||||
| GAINS AND LOSSES FROM COMMODITY DERIVATIVES | ||||||||||||||||||||||||||
| 2nd Quarter | 1st Quarter | 2nd Quarter | YTD June | YTD June | ||||||||||||||||||||||
| ($ millions) | 2024 | 2024 | 2023 | 2024 | 2023 | |||||||||||||||||||||
| Non-cash derivative gain (loss) | $ | 11 | $ | (59) | $ | 94 | $ | (48) | $ | 201 | ||||||||||||||||
| Net payments on settled commodity derivatives | (6) | (12) | (63) | (18) | (128) | |||||||||||||||||||||
| Net gain (loss) from commodity derivatives | $ | 5 | $ | (71) | $ | 31 | $ | (66) | $ | 73 | ||||||||||||||||
| 1st Quarter | 1st Quarter | 4th Quarter | 4th Quarter | 4th Quarter | |||||||||||||||||||||||||||||||||||||
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| CAPITAL INVESTMENTS | |||||||||||||||||||||||||||||
| 2nd Quarter | 1st Quarter | 2nd Quarter | YTD June | YTD June | |||||||||||||||||||||||||
| ($ millions) | 2024 | 2024 | 2023 | 2024 | 2023 | ||||||||||||||||||||||||
Facilities (1) | $ | 17 | $ | 14 | $ | 11 | $ | 31 | $ | 20 | |||||||||||||||||||
| Drilling | 18 | 15 | 13 | 33 | 38 | ||||||||||||||||||||||||
| Workovers | 11 | 7 | 11 | 18 | 17 | ||||||||||||||||||||||||
| Total E&P capital | 46 | 36 | 35 | 82 | 75 | ||||||||||||||||||||||||
CMB (1) | (2) | 4 | — | 2 | 1 | ||||||||||||||||||||||||
| Corporate and other | (10) | 14 | 4 | 4 | 10 | ||||||||||||||||||||||||
| Total capital program | $ | 34 | $ | 54 | $ | 39 | $ | 88 | $ | 86 | |||||||||||||||||||
(1) Facilities capital includes $0, $0 and $1 million in the second and first quarter of 2024 and second quarter of 2023, respectively, and $0 and $2 million for the six months 2024 and 2023, respectively, 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 $14 million. | |||||||||||||||||||||||||||||
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| Attachment 2 | |||||||||||||||||
| CRC GUIDANCE | Total 2H24E | CMB 2H24E | E&P, Corp. & Other 2H24E | ||||||||||||||
| Net Production (MBoe/d) | 140 - 146 | 140 - 146 | |||||||||||||||
| Oil Production (%) | ~79% | ~79% | |||||||||||||||
| CMB Expenses & Operating Costs ($ millions) | $675 - $720 | $35 - $40 | $640 - $680 | ||||||||||||||
| General and Administrative Expenses ($ millions) | $190 - $210 | $3 - $5 | $187 - $205 | ||||||||||||||
| Adjusted General and Administrative Expenses ($ millions) | $165 - $185 | $2 - $4 | $163 - $181 | ||||||||||||||
| Capital ($ millions) | $170 - $210 | $10 - $15 | $160 - $195 | ||||||||||||||
| Drilling & completions, workover ($ millions) | $85 - $105 | ||||||||||||||||
| Facilities ($ millions) | $70 - $80 | ||||||||||||||||
| Carbon management business ($ millions) | $10- $15 | ||||||||||||||||
| Corporate & other ($ millions) | $5 - $10 | ||||||||||||||||
| Adjusted EBITDAX ($ millions) | $720 - $760 | ||||||||||||||||
Margin from Marketing of Purchased Commodities ($ millions) (1) | $24 - $30 | $24 - $30 | |||||||||||||||
Electricity Margin ($ millions) (2) | $65 - $80 | $65 - $80 | |||||||||||||||
Other Operating Revenue & Expenses, net ($ millions)(3) | ($100) - ($105) | ($100) - ($105) | |||||||||||||||
| Transportation Costs ($ millions) | $40 - $50 | $40 - $50 | |||||||||||||||
| Taxes Other Than on Income ($ millions) | $150 - $160 | $150 - $160 | |||||||||||||||
| Interest and Debt Expense ($ millions) | $53 - $59 | $53 - $59 | |||||||||||||||
| Commodity Assumptions: | |||||||||||||||||
| Brent ($/Bbl) | $83.29 | $83.29 | |||||||||||||||
| NYMEX ($/Mcf) | $2.86 | $2.86 | |||||||||||||||
| Oil - % of Brent: | 94% to 98% | 94% to 98% | |||||||||||||||
| NGL - % of Brent: | 52% to 58% | 52% to 58% | |||||||||||||||
| Natural Gas - % of NYMEX: | 110% to 131% | 110% to 131% | |||||||||||||||
Page 11
| CRC GUIDANCE | Total 3Q24E | CMB 3Q24E | E&P, Corp. & Other 3Q24E | ||||||||||||||
| Net Production (MBoe/d) | 141 - 145 | 141 - 145 | |||||||||||||||
| Oil Production (%) | ~79% | ~79% | |||||||||||||||
| CMB Expenses & Operating Costs ($ millions) | $325 - $355 | $15 - $20 | $310 - $335 | ||||||||||||||
| General and Administrative Expenses ($ millions) | $100 - $120 | $2 - $4 | $98 - $116 | ||||||||||||||
| Adjusted General and Administrative Expenses ($ millions) | $80 - $99 | $1 - $2 | $79 - $97 | ||||||||||||||
| Capital ($ millions) | $90 - $110 | $5 - $10 | $85 - $100 | ||||||||||||||
| Drilling & completions, workover ($ millions) | $46 - $55 | ||||||||||||||||
| Facilities ($ millions) | $37 - $42 | ||||||||||||||||
| Carbon management business ($ millions) | $5- $9 | ||||||||||||||||
| Corporate & other ($ millions) | $2 - $4 | ||||||||||||||||
| Adjusted EBITDAX ($ millions) | $375 - $415 | ||||||||||||||||
Margin from Marketing of Purchased Commodities ($ millions) (1) | $10 - $16 | $10 - $16 | |||||||||||||||
Electricity Margin ($ millions) (2) | $45 - $65 | $45 - $65 | |||||||||||||||
Other Operating Revenue & Expenses, net ($ millions)(3) | ($100) - ($112) | ($100) - ($112) | |||||||||||||||
| Transportation Costs ($ millions) | $20 - $25 | $20 - $25 | |||||||||||||||
| Taxes Other Than on Income ($ millions) | $75 - $85 | $75 - $85 | |||||||||||||||
| Interest and Debt Expense ($ millions) | $25 - $30 | $25 - $30 | |||||||||||||||
| Commodity Assumptions: | |||||||||||||||||
| Brent ($/Bbl) | $84.23 | $84.23 | |||||||||||||||
| NYMEX ($/Mcf) | $2.61 | $2.61 | |||||||||||||||
| Oil - % of Brent: | 94% - 98% | 94% - 98% | |||||||||||||||
| NGL - % of Brent: | 46% - 54% | 46% - 54% | |||||||||||||||
| Natural Gas - % of NYMEX: | 100% - 114% | 100% - 114% | |||||||||||||||
(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. Includes Aera merger and integration costs paid in 3Q24 and $60 million of costs to achieve that we expect to be paid in 4Q24.
See Attachment 3 for management's disclosure of its use of these non-GAAP measures and how these measures provide useful information to investors about CRC's results of operations and financial condition.
ESTIMATED ADJUSTED GENERAL AND ADMINISTRATIVE EXPENSES RECONCILIATION
| 2H24 Estimated | |||||||||||||||||||||||||||||||||||
| Consolidated | CMB | E&P, Corporate & Other | |||||||||||||||||||||||||||||||||
| ($ millions) | Low | High | Low | High | Low | High | |||||||||||||||||||||||||||||
| General and administrative expenses | $ | 190 | $ | 210 | $ | 3 | $ | 5 | $ | 187 | $ | 205 | |||||||||||||||||||||||
| Equity-settled stock-based compensation | (23) | (23) | (1) | (1) | (22) | (22) | |||||||||||||||||||||||||||||
| Other | (2) | (2) | (2) | (2) | |||||||||||||||||||||||||||||||
| Estimated adjusted general and administrative expenses | $ | 165 | $ | 185 | $ | 2 | $ | 4 | $ | 163 | $ | 181 | |||||||||||||||||||||||
| 3Q24 Estimated | |||||||||||||||||||||||||||||||||||
| Consolidated | CMB | E&P, Corporate & Other | |||||||||||||||||||||||||||||||||
| ($ millions) | Low | High | Low | High | Low | High | |||||||||||||||||||||||||||||
| General and administrative expenses | $ | 100 | $ | 120 | $ | 2 | $ | 4 | $ | 98 | $ | 116 | |||||||||||||||||||||||
| Equity-settled stock-based compensation | (19) | (20) | (1) | (2) | (18) | (18) | |||||||||||||||||||||||||||||
| Other | (1) | (1) | (1) | (1) | |||||||||||||||||||||||||||||||
| Estimated adjusted general and administrative expenses | $ | 80 | $ | 99 | $ | 1 | $ | 2 | $ | 79 | $ | 97 | |||||||||||||||||||||||
| -3 | |||||||||||||||||||||||||||||||||||
Page 12
ESTIMATED ADJUSTED EBITDAX RECONCILIATION
| 2H24E | |||||||||||||||||||||||||||||||||||||||||
| ($ millions) | Low | High | |||||||||||||||||||||||||||||||||||||||
| Net income | $ | 152 | $ | 162 | |||||||||||||||||||||||||||||||||||||
| Interest and debt expense, net | 53 | 58 | |||||||||||||||||||||||||||||||||||||||
| Depreciation, depletion and amortization | 310 | 315 | |||||||||||||||||||||||||||||||||||||||
| Income taxes | 55 | 62 | |||||||||||||||||||||||||||||||||||||||
| Unusual, infrequent and other items | 83 | 88 | |||||||||||||||||||||||||||||||||||||||
| Other non-cash items | |||||||||||||||||||||||||||||||||||||||||
| Accretion expense | 54 | 58 | |||||||||||||||||||||||||||||||||||||||
| Stock-settled compensation | 10 | 14 | |||||||||||||||||||||||||||||||||||||||
| Post-retirement medical and pension | 3 | 3 | |||||||||||||||||||||||||||||||||||||||
| Estimated adjusted EBITDAX | $ | 720 | $ | 760 | |||||||||||||||||||||||||||||||||||||
| Net cash provided by operating activities | $ | 480 | $ | 500 | |||||||||||||||||||||||||||||||||||||
| Cash interest | 48 | 54 | |||||||||||||||||||||||||||||||||||||||
| Cash income taxes | 58 | 66 | |||||||||||||||||||||||||||||||||||||||
| Working capital changes | 134 | 140 | |||||||||||||||||||||||||||||||||||||||
| Estimated adjusted EBITDAX | $ | 720 | $ | 760 | |||||||||||||||||||||||||||||||||||||
| 3Q24E | |||||||||||||||||||||||||||||||||||||||||
| ($ millions) | Low | High | |||||||||||||||||||||||||||||||||||||||
| Net income | $ | 45 | $ | 65 | |||||||||||||||||||||||||||||||||||||
| Interest and debt expense, net | 25 | 29 | |||||||||||||||||||||||||||||||||||||||
| Depreciation, depletion and amortization | 156 | 160 | |||||||||||||||||||||||||||||||||||||||
| Income taxes | 16 | 20 | |||||||||||||||||||||||||||||||||||||||
| Unusual, infrequent and other items | 102 | 106 | |||||||||||||||||||||||||||||||||||||||
| Other non-cash items | |||||||||||||||||||||||||||||||||||||||||
| Accretion expense | 26 | 28 | |||||||||||||||||||||||||||||||||||||||
| Stock-settled compensation | 5 | 7 | |||||||||||||||||||||||||||||||||||||||
| Post-retirement medical and pension | 0 | 0 | |||||||||||||||||||||||||||||||||||||||
| Estimated adjusted EBITDAX | $ | 375 | $ | 415 | |||||||||||||||||||||||||||||||||||||
| Net cash provided by operating activities | $ | 270 | $ | 290 | |||||||||||||||||||||||||||||||||||||
| Cash interest | 19 | 23 | |||||||||||||||||||||||||||||||||||||||
| Cash income taxes | 27 | 31 | |||||||||||||||||||||||||||||||||||||||
| Working capital changes | 59 | 71 | |||||||||||||||||||||||||||||||||||||||
| Estimated adjusted EBITDAX | $ | 375 | $ | 415 | |||||||||||||||||||||||||||||||||||||
Page 13
| 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. | ||||||||||||||||||||||||||||||||
| 2nd Quarter | 1st Quarter | 2nd Quarter | YTD June | YTD June | ||||||||||||||||||||||||||||
| ($ millions, except per share amounts) | 2024 | 2024 | 2023 | 2024 | 2023 | |||||||||||||||||||||||||||
| Net income (loss) | $ | 8 | $ | (10) | $ | 97 | $ | (2) | $ | 398 | ||||||||||||||||||||||
| Unusual, infrequent and other items: | ||||||||||||||||||||||||||||||||
| Non-cash derivative (gain) loss | (11) | 59 | (94) | 48 | (201) | |||||||||||||||||||||||||||
| Asset impairment | 13 | — | — | 13 | 3 | |||||||||||||||||||||||||||
| Severance and termination costs | 1 | — | 2 | 1 | 3 | |||||||||||||||||||||||||||
| Aera merger transaction fees | 5 | 10 | — | 15 | — | |||||||||||||||||||||||||||
| Aera merger integration fees | 8 | 3 | — | 11 | — | |||||||||||||||||||||||||||
| Increased power and fuel costs due to power plant shutdown | 15 | 21 | — | 36 | — | |||||||||||||||||||||||||||
| Net gain on asset divestitures | (1) | (6) | — | (7) | (7) | |||||||||||||||||||||||||||
| Other, net | 17 | 2 | 10 | 19 | 13 | |||||||||||||||||||||||||||
| Total unusual, infrequent and other items | 47 | 89 | (82) | 136 | (189) | |||||||||||||||||||||||||||
| Income tax (benefit) provision of adjustments at effective tax rate | (13) | (25) | 23 | (38) | 53 | |||||||||||||||||||||||||||
| Income tax (benefit) provision - out of period | — | — | — | — | (31) | |||||||||||||||||||||||||||
| Adjusted net income | $ | 42 | $ | 54 | $ | 38 | $ | 96 | $ | 231 | ||||||||||||||||||||||
| Net income (loss) per share - basic | $ | 0.12 | $ | (0.14) | $ | 1.39 | $ | (0.03) | $ | 5.65 | ||||||||||||||||||||||
| Net income (loss) per share - diluted | $ | 0.11 | $ | (0.14) | $ | 1.35 | $ | (0.03) | $ | 5.47 | ||||||||||||||||||||||
| Adjusted net income per share - basic | $ | 0.62 | $ | 0.78 | $ | 0.55 | $ | 1.40 | $ | 3.28 | ||||||||||||||||||||||
| Adjusted net income per share - diluted | $ | 0.60 | $ | 0.75 | $ | 0.53 | $ | 1.35 | $ | 3.18 | ||||||||||||||||||||||
Page 14
| 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). | |||||||||||||||||||||||||||||||||||
| 2nd Quarter | 1st Quarter | 2nd Quarter | YTD June | YTD June | |||||||||||||||||||||||||||||||
| ($ millions, except per BOE amounts) | 2024 | 2024 | 2023 | 2024 | 2023 | ||||||||||||||||||||||||||||||
| Net income (loss) | $ | 8 | $ | (10) | $ | 97 | $ | (2) | $ | 398 | |||||||||||||||||||||||||
| Interest and debt expense | 17 | 13 | 14 | 30 | 28 | ||||||||||||||||||||||||||||||
| Depreciation, depletion and amortization | 53 | 53 | 56 | 106 | 114 | ||||||||||||||||||||||||||||||
| Income tax provision (benefit) | 3 | (9) | 38 | (6) | 113 | ||||||||||||||||||||||||||||||
| Exploration expense | — | 1 | 1 | 1 | 2 | ||||||||||||||||||||||||||||||
| Interest income | (8) | (6) | (5) | (14) | (9) | ||||||||||||||||||||||||||||||
Unusual, infrequent and other items (1) | 47 | 89 | (82) | 136 | (189) | ||||||||||||||||||||||||||||||
| Non-cash items | |||||||||||||||||||||||||||||||||||
| Accretion expense | 13 | 12 | 11 | 25 | 23 | ||||||||||||||||||||||||||||||
| Stock-based compensation | 6 | 5 | 8 | 11 | 15 | ||||||||||||||||||||||||||||||
| Post-retirement medical and pension | — | 1 | — | 1 | 1 | ||||||||||||||||||||||||||||||
| Adjusted EBITDAX | $ | 139 | $ | 149 | $ | 138 | $ | 288 | $ | 496 | |||||||||||||||||||||||||
| Net cash provided by operating activities | $ | 97 | $ | 87 | $ | 108 | $ | 184 | $ | 418 | |||||||||||||||||||||||||
| Cash interest payments | 1 | 21 | 2 | 22 | 25 | ||||||||||||||||||||||||||||||
| Cash interest received | (8) | (6) | (5) | (14) | (9) | ||||||||||||||||||||||||||||||
| Cash income taxes | 4 | 22 | 51 | 26 | 51 | ||||||||||||||||||||||||||||||
| Exploration expenditures | — | 1 | 1 | 1 | 2 | ||||||||||||||||||||||||||||||
| Adjustments to working capital changes | 45 | 24 | (19) | 69 | 9 | ||||||||||||||||||||||||||||||
| Adjusted EBITDAX | $ | 139 | $ | 149 | $ | 138 | $ | 288 | $ | 496 | |||||||||||||||||||||||||
| E&P, Corporate & Other Adjusted EBITDAX | $ | 160 | $ | 162 | $ | 151 | $ | 322 | $ | 518 | |||||||||||||||||||||||||
| CMB Adjusted EBITDAX | $ | (21) | $ | (13) | $ | (13) | $ | (34) | $ | (22) | |||||||||||||||||||||||||
| Adjusted EBITDAX per Boe | $ | 20.23 | $ | 21.47 | $ | 17.59 | $ | 20.86 | $ | 31.23 | |||||||||||||||||||||||||
(1) See Adjusted Net Income (Loss) reconciliation. | |||||||||||||||||||||||||||||||||||
Page 15
| 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. | ||||||||||||||||||||||||||||||||
| 2nd Quarter | 1st Quarter | 2nd Quarter | YTD June | YTD June | ||||||||||||||||||||||||||||
| ($ millions) | 2024 | 2024 | 2023 | 2024 | 2023 | |||||||||||||||||||||||||||
| Net cash provided by operating activities before working capital changes | $ | 108 | $ | 92 | $ | 98 | $ | 200 | $ | 414 | ||||||||||||||||||||||
| Working capital changes | (11) | (5) | 10 | (16) | 4 | |||||||||||||||||||||||||||
| Net cash provided by operating activities | 97 | 87 | 108 | 184 | 418 | |||||||||||||||||||||||||||
| Capital investments | (34) | (54) | (39) | (88) | (86) | |||||||||||||||||||||||||||
| Free cash flow | $ | 63 | $ | 33 | $ | 69 | $ | 96 | $ | 332 | ||||||||||||||||||||||
| Add: Aera transaction and integration costs | 13 | 13 | — | 26 | — | |||||||||||||||||||||||||||
| $ | 76 | $ | 46 | $ | 69 | $ | 122 | $ | 332 | |||||||||||||||||||||||
E&P, Corporate and Other (1) | $ | 95 | $ | 53 | $ | 78 | $ | 148 | $ | 348 | ||||||||||||||||||||||
CMB (1) | $ | (19) | $ | (7) | $ | (9) | $ | (26) | $ | (16) | ||||||||||||||||||||||
| Adjustments to capital investments: | ||||||||||||||||||||||||||||||||
Replacement water facilities(2) | $ | — | $ | — | $ | 1 | $ | — | $ | 2 | ||||||||||||||||||||||
| Adjusted capital investments: | ||||||||||||||||||||||||||||||||
| E&P, Corporate and Other | $ | 36 | $ | 50 | $ | 38 | $ | 86 | $ | 83 | ||||||||||||||||||||||
| CMB | $ | (2) | $ | 4 | $ | 1 | $ | 2 | $ | 3 | ||||||||||||||||||||||
| Adjusted free cash flow: | ||||||||||||||||||||||||||||||||
| E&P, Corporate and Other | $ | 95 | $ | 53 | $ | 79 | $ | 148 | $ | 350 | ||||||||||||||||||||||
| CMB | $ | (19) | $ | (7) | $ | (10) | $ | (26) | $ | (18) | ||||||||||||||||||||||
(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. We define 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 $0, $1 million and $1 million in the first quarter of 2024 and fourth and first quarter of 2023, respectively, to build replacement water injection facilities which will allow CRC to divert produced water away from a depleted oil and natural gas reservoir held by the Carbon TerraVault JV. Construction of these facilities supports the advancement of CRC’s carbon management business and CRC reported these amounts as part of adjusted CMB capital in this press release. Where adjusted CMB capital is presented, CRC removed the amounts from facilities capital and presented adjusted E&P, Corporate and Other capital. | ||||||||||||||||||||||||||||||||
Page 16
| ADJUSTED GENERAL & ADMINISTRATIVE EXPENSES | |||||||||||||||||||||||||||||||||||
Management uses a measure called adjusted general and administrative (G&A) expenses to provide useful information to investors interested in comparing CRC's costs between periods and performance to our peers. CRC supplemented its non-GAAP measure of adjusted general and administrative expenses with adjusted general and administrative expenses of its exploration and production and corporate items (adjusted general & administrative expenses for E&P, Corporate & Other) which it believes is a useful measure for investors to understand the results or CRC's core oil and gas business. CRC defines adjusted general & administrative Expenses for E&P, Corporate & Other as consolidated adjusted general and administrative expenses less results attributable to its carbon management business (CMB). | |||||||||||||||||||||||||||||||||||
| 2nd Quarter | 1st Quarter | 2nd Quarter | YTD June | YTD June | |||||||||||||||||||||||||||||||
| ($ millions) | 2024 | 2024 | 2023 | 2024 | 2023 | ||||||||||||||||||||||||||||||
| General and administrative expenses | $ | 63 | $ | 57 | $ | 71 | $ | 120 | $ | 136 | |||||||||||||||||||||||||
| Stock-based compensation | (6) | (5) | (8) | (11) | (15) | ||||||||||||||||||||||||||||||
| Information technology infrastructure | (1) | (2) | (6) | (3) | (9) | ||||||||||||||||||||||||||||||
| Other | — | (1) | — | (1) | — | ||||||||||||||||||||||||||||||
| Adjusted G&A expenses | $ | 56 | $ | 49 | $ | 57 | $ | 105 | $ | 112 | |||||||||||||||||||||||||
| E&P, Corporate and Other adjusted G&A expenses | $ | 53 | $ | 47 | $ | 54 | $ | 100 | $ | 106 | |||||||||||||||||||||||||
| CMB adjusted G&A expenses | $ | 3 | $ | 2 | $ | 3 | $ | 5 | $ | 6 | |||||||||||||||||||||||||
| 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. | |||||||||||||||||||||||||||||||||||
| 2nd Quarter | 1st Quarter | 2nd Quarter | YTD June | YTD June | |||||||||||||||||||||||||||||||
| ($ per BOE) | 2024 | 2024 | 2023 | 2024 | 2023 | ||||||||||||||||||||||||||||||
Energy operating costs (1) | $ | 6.40 | $ | 8.07 | $ | 7.39 | $ | 7.24 | $ | 11.52 | |||||||||||||||||||||||||
Gas processing costs (2) | 0.44 | 0.58 | 0.64 | 0.51 | 0.63 | ||||||||||||||||||||||||||||||
| Non-energy operating costs | 16.30 | 17.15 | 15.68 | 16.73 | 15.56 | ||||||||||||||||||||||||||||||
| Operating costs | $ | 23.14 | $ | 25.80 | $ | 23.71 | $ | 24.48 | $ | 27.71 | |||||||||||||||||||||||||
| Costs attributable to PSCs | |||||||||||||||||||||||||||||||||||
| Excess energy operating costs attributable to PSCs | $ | (0.94) | $ | (0.99) | $ | (0.91) | $ | (0.97) | $ | (0.98) | |||||||||||||||||||||||||
| Excess non-energy operating costs attributable to PSCs | (1.62) | (1.55) | (1.24) | (1.58) | (1.21) | ||||||||||||||||||||||||||||||
| Excess costs attributable to PSCs | $ | (2.56) | $ | (2.54) | $ | (2.15) | $ | (2.55) | $ | (2.19) | |||||||||||||||||||||||||
Energy operating costs, excluding effect of PSCs (1) | $ | 5.46 | $ | 7.08 | $ | 6.48 | $ | 6.27 | $ | 10.54 | |||||||||||||||||||||||||
Gas processing costs, excluding effect of PSCs (2) | 0.44 | 0.58 | 0.64 | 0.51 | 0.63 | ||||||||||||||||||||||||||||||
| Non-energy operating costs, excluding effect of PSCs | 14.68 | 15.60 | 14.44 | 15.15 | 14.35 | ||||||||||||||||||||||||||||||
| Operating costs, excluding effects of PSCs | $ | 20.58 | $ | 23.26 | $ | 21.56 | $ | 21.93 | $ | 25.52 | |||||||||||||||||||||||||
(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. | |||||||||||||||||||||||||||||||||||
Page 17
| Attachment 4 | |||||||||||||||||||||||||||||||||||
| PRODUCTION STATISTICS | |||||||||||||||||||||||||||||||||||
| 2nd Quarter | 1st Quarter | 2nd Quarter | YTD June | YTD June | |||||||||||||||||||||||||||||||
| Net Production Per Day | 2024 | 2024 | 2023 | 2024 | 2023 | ||||||||||||||||||||||||||||||
| Oil (MBbl/d) | |||||||||||||||||||||||||||||||||||
| San Joaquin Basin | 30 | 30 | 34 | 30 | 35 | ||||||||||||||||||||||||||||||
| Los Angeles Basin | 17 | 18 | 19 | 17 | 19 | ||||||||||||||||||||||||||||||
| Total | 47 | 48 | 53 | 47 | 54 | ||||||||||||||||||||||||||||||
| NGLs (MBbl/d) | |||||||||||||||||||||||||||||||||||
| San Joaquin Basin | 10 | 11 | 11 | 11 | 11 | ||||||||||||||||||||||||||||||
| Total | 10 | 11 | 11 | 11 | 11 | ||||||||||||||||||||||||||||||
| Natural Gas (MMcf/d) | |||||||||||||||||||||||||||||||||||
| San Joaquin Basin | 99 | 90 | 119 | 94 | 119 | ||||||||||||||||||||||||||||||
| Los Angeles Basin | 1 | 1 | 1 | 1 | 1 | ||||||||||||||||||||||||||||||
| Sacramento Basin | 14 | 14 | 15 | 14 | 16 | ||||||||||||||||||||||||||||||
| Total | 114 | 105 | 135 | 109 | 136 | ||||||||||||||||||||||||||||||
| Total Production (MBoe/d) | 76 | 76 | 86 | 76 | 88 | ||||||||||||||||||||||||||||||
| Gross Operated and Net Non-Operated | 2nd Quarter | 1st Quarter | 2nd Quarter | YTD June | YTD June | ||||||||||||||||||||||||||||||
| Production Per Day | 2024 | 2024 | 2023 | 2024 | 2023 | ||||||||||||||||||||||||||||||
| Oil (MBbl/d) | |||||||||||||||||||||||||||||||||||
| San Joaquin Basin | 33 | 34 | 38 | 33 | 39 | ||||||||||||||||||||||||||||||
| Los Angeles Basin | 24 | 24 | 25 | 24 | 25 | ||||||||||||||||||||||||||||||
| Total | 57 | 58 | 63 | 57 | 64 | ||||||||||||||||||||||||||||||
| NGLs (MBbl/d) | |||||||||||||||||||||||||||||||||||
| San Joaquin Basin | 11 | 11 | 12 | 11 | 12 | ||||||||||||||||||||||||||||||
| Total | 11 | 11 | 12 | 11 | 12 | ||||||||||||||||||||||||||||||
| Natural Gas (MMcf/d) | |||||||||||||||||||||||||||||||||||
| San Joaquin Basin | 125 | 128 | 136 | 127 | 135 | ||||||||||||||||||||||||||||||
| Los Angeles Basin | 7 | 7 | 7 | 7 | 7 | ||||||||||||||||||||||||||||||
| Sacramento Basin | 17 | 17 | 19 | 17 | 20 | ||||||||||||||||||||||||||||||
| Total | 149 | 152 | 162 | 151 | 162 | ||||||||||||||||||||||||||||||
| Total Production (MBoe/d) | 93 | 94 | 103 | 93 | 103 | ||||||||||||||||||||||||||||||
Page 18
| Attachment 5 | Attachment 5 | |||||||||||||||||||||||||||||||||||||
| PRICE STATISTICS | ||||||||||||||||||||||||||||||||||||||
| 2nd Quarter | 1st Quarter | 2nd Quarter | YTD June | YTD June | ||||||||||||||||||||||||||||||||||
| 2024 | 2024 | 2023 | 2024 | 2023 | ||||||||||||||||||||||||||||||||||
| Oil ($ per Bbl) | ||||||||||||||||||||||||||||||||||||||
| Realized price with derivative settlements | $ | 81.29 | $ | 77.17 | $ | 63.66 | $ | 79.20 | $ | 63.35 | ||||||||||||||||||||||||||||
| Realized price without derivative settlements | $ | 83.14 | $ | 80.16 | $ | 75.77 | $ | 81.63 | $ | 77.25 | ||||||||||||||||||||||||||||
| NGLs ($/Bbl) | $ | 46.96 | $ | 50.50 | $ | 42.48 | $ | 48.76 | $ | 50.88 | ||||||||||||||||||||||||||||
| Natural gas ($/Mcf) | ||||||||||||||||||||||||||||||||||||||
| Realized price with derivative settlements | $ | 1.78 | $ | 3.90 | $ | 3.46 | $ | 2.81 | $ | 12.44 | ||||||||||||||||||||||||||||
| Realized price without derivative settlements | $ | 1.78 | $ | 3.90 | $ | 3.46 | $ | 2.81 | $ | 12.44 | ||||||||||||||||||||||||||||
| Index Prices | ||||||||||||||||||||||||||||||||||||||
| Brent oil ($/Bbl) | $ | 85.00 | $ | 81.84 | $ | 78.01 | $ | 83.42 | $ | 80.12 | ||||||||||||||||||||||||||||
| WTI oil ($/Bbl) | $ | 80.57 | $ | 76.96 | $ | 73.78 | $ | 78.77 | $ | 74.95 | ||||||||||||||||||||||||||||
| NYMEX average monthly settled price ($/MMBtu) | $ | 1.89 | $ | 2.24 | $ | 2.10 | $ | 2.07 | $ | 2.76 | ||||||||||||||||||||||||||||
| Realized Prices as Percentage of Index Prices | ||||||||||||||||||||||||||||||||||||||
| Oil with derivative settlements as a percentage of Brent | 96 | % | 94 | % | 82 | % | 95 | % | 79 | % | ||||||||||||||||||||||||||||
| Oil without derivative settlements as a percentage of Brent | 98 | % | 98 | % | 97 | % | 98 | % | 96 | % | ||||||||||||||||||||||||||||
| Oil with derivative settlements as a percentage of WTI | 101 | % | 100 | % | 86 | % | 101 | % | 85 | % | ||||||||||||||||||||||||||||
| Oil without derivative settlements as a percentage of WTI | 103 | % | 104 | % | 103 | % | 104 | % | 103 | % | ||||||||||||||||||||||||||||
| NGLs as a percentage of Brent | 55 | % | 62 | % | 54 | % | 58 | % | 64 | % | ||||||||||||||||||||||||||||
| NGLs as a percentage of WTI | 58 | % | 66 | % | 58 | % | 62 | % | 68 | % | ||||||||||||||||||||||||||||
| Natural gas with derivative settlements as a percentage of NYMEX contract month average | 94 | % | 174 | % | 165 | % | 136 | % | 451 | % | ||||||||||||||||||||||||||||
| Natural gas without derivative settlements as a percentage of NYMEX contract month average | 94 | % | 174 | % | 165 | % | 136 | % | 451 | % | ||||||||||||||||||||||||||||
Page 19
| Attachment 6 | |||||||||||||||||||||||||||||
| SECOND QUARTER 2024 DRILLING ACTIVITY | |||||||||||||||||||||||||||||
| San Joaquin | Los Angeles | Ventura | Sacramento | ||||||||||||||||||||||||||
| Wells Drilled | Basin | Basin | Basin | Basin | Total | ||||||||||||||||||||||||
| Development Wells | |||||||||||||||||||||||||||||
| Primary | 3 | — | — | — | 3 | ||||||||||||||||||||||||
| Waterflood | — | — | — | — | — | ||||||||||||||||||||||||
| Steamflood | — | — | — | — | — | ||||||||||||||||||||||||
Total (1) | 3 | — | — | — | 3 | ||||||||||||||||||||||||
| SIX MONTHS 2024 DRILLING ACTIVITY | |||||||||||||||||||||||||||||
| San Joaquin | Los Angeles | Ventura | Sacramento | ||||||||||||||||||||||||||
| Wells Drilled | Basin | Basin | Basin | Basin | Total | ||||||||||||||||||||||||
| Development Wells | |||||||||||||||||||||||||||||
| Primary | 5 | — | — | — | 5 | ||||||||||||||||||||||||
| Waterflood | — | — | — | — | — | ||||||||||||||||||||||||
| Steamflood | — | — | — | — | — | ||||||||||||||||||||||||
Total (1) | 5 | — | — | — | 5 | ||||||||||||||||||||||||
(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 JUNE 30, 2024 | |||||||||||||||||||||||||||||||||||
| Q3 2024 | Q4 2024 | Q1 2025 | Q2 2025 | 2H 2025 | |||||||||||||||||||||||||||||||
| Sold Calls | |||||||||||||||||||||||||||||||||||
| Barrels per day | 30,000 | 29,000 | 30,000 | 30,000 | 29,500 | ||||||||||||||||||||||||||||||
| Weighted-average Brent price per barrel | $90.07 | $90.07 | $87.08 | $87.08 | $87.11 | ||||||||||||||||||||||||||||||
| Swaps | |||||||||||||||||||||||||||||||||||
| Barrels per day | 8,875 | 8,875 | 5,250 | 3,500 | 3,250 | ||||||||||||||||||||||||||||||
| Weighted-average Brent price per barrel | $80.10 | $79.94 | $76.27 | $72.50 | $72.50 | ||||||||||||||||||||||||||||||
| Purchased Puts | |||||||||||||||||||||||||||||||||||
| Barrels per day | 30,000 | 29,000 | 30,000 | 30,000 | 29,500 | ||||||||||||||||||||||||||||||
| Weighted-average Brent price per barrel | $65.17 | $65.17 | $61.67 | $61.67 | $61.69 | ||||||||||||||||||||||||||||||
Page 20