NEWS RELEASE
California Resources Corporation Reports Strong Second Quarter 2023 Financial Results and Provides Updates on Carbon Management Business
Long Beach, July 31, 2023 - California Resources Corporation (NYSE: CRC), an independent energy and carbon management company committed to energy transition, today reported second quarter 2023 operational and financial results.
"CRC’s focus on execution drove solid operational and financial performance in the second quarter," said Francisco Leon, CRC President and Chief Executive Officer. "We returned nearly $84 million to our shareholders in the second quarter, bringing the total shareholder return program to nearly $700 million since its inception in 2021. We have accomplished this while growing our cash flow per share along with developing our carbon management business. Cash flow, carbon and California remain our core strengths as we continue to deliver meaningful value to our shareholders and provide low carbon intensity oil and gas that California needs."
Primary Highlights
•Declared a quarterly dividend of $0.2825 per share of common stock, totaling ~$20 million payable on September 15, 2023 to shareholders of record on September 1, 2023
•Repurchased 1,618,746 common shares for $64 million at an average share price of $39.12 per share during the second quarter of 2023
•Repurchased a cumulative 14,498,770 shares for $584 million at an average price of $40.18 per share since the inception of the Share Repurchase Program in May 2021 through June 30, 2023
•Submitted a Class VI permit to the EPA for 17 million metric tons (MMT) for CTV V CO2 reservoir in the Sacramento Basin, bringing CRC's total storage capacity with Class VI permits submitted the EPA to 191 MMT
•Signed a new storage-only carbon dioxide management agreement (CDMA) with Verde Clean Fuels Inc. for 100 thousand metric tons per annum (KMTPA) of CO2 injection
•Expanded the previously announced Lone Cypress Energy Service, LLC, blue hydrogen project to an estimated 205 KMTPA of CO2 injection
Financial Highlights
•Reported net income of $97 million, or $1.35 per diluted share. When adjusted for items analysts typically exclude from estimates including mark-to-market adjustments and one-time costs, the Company’s adjusted net income1 was $38 million, or $0.53 per diluted share
•Generated net cash provided by operating activities of $108 million, adjusted EBITDAX1 of $138 million and free cash flow1 of $69 million
•Ended the quarter with $448 million of cash and cash equivalents and an undrawn Revolving Credit Facility, (excluding $148 million of letters of credit) with $479 million of availability representing $927 million of total liquidity2
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Operational Highlights
•Reservoirs performed in line with expectations; total daily gross production of 103,000 gross barrels of oil equivalent per day (Boe/d) for the second quarter of 2023, which was flat compared to the first quarter of 2023
•Produced an average of 86 net MBoe/d, including 53,000 net barrels of oil per day (Bo/d), with E&P capital expenditures of $35 million during the quarter
•Total daily net production for the three months ended June 30, 2023, includes 2 net MBoe/d of combined negative effects; including 1 net MBoe/d related to CRC's production-sharing contracts (PSCs) and approximately 1 net MBoe/d due to changes in NGL storage volumes
•Operated 1 drilling rig in LA Basin; drilled 6 wells and brought 7 wells online in 2Q23
•Operated 35 maintenance rigs in the first quarter
Total Year 2023 Guidance and Capital Program3
CRC estimates average net total production between 85 and 91 MBoe/d3 (~61% oil) for the total year 2023. CRC is reaffirming its total year 2023 total capital which is expected to range between $200 and $245 million with heavier weighting in the second half of the year due to timing of projects and higher expected workover activity and facilities projects. The program includes an expected $185 to $220 million of adjusted E&P, corporate and other adjusted capital1 and $15 to $25 million of adjusted CMB capital1 for carbon management projects4. CRC is also narrowing its total year 2023 free cash flow1 guidance range to $380 to $460 million from $360 to $470 million.
The Company plans to execute a 1 to 1.5 rig development program on average for 2023. Activity will focus on drilling new locations where CRC has permits and high return workovers. The capital plan also includes procuring long-lead time items for planned maintenance of our facilities in 2024.
CRC is lowering the top end of the range for its operating cost guidance from $815 to $865 million to $815 to $850 million as a result of lower natural gas prices expected in the second half of 2023. Natural gas marketing margin was increased from a range of $80 to $110 million to $135 to $150 million to reflect the Company's performance in the first half of the year. Similarly, CRC's 2023 estimated commodity realizations were adjusted to reflect the Company's results.
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CRC GUIDANCE3 | Total 2023E | CMB 2023E | E&P, Corp. & Other 2023E | ||||||||||||||
| Net Total Production (MBoe/d) | 85 - 91 | 85 - 91 | |||||||||||||||
| Net Oil Production (MBbl/d) | 51 - 55 | 51 - 55 | |||||||||||||||
| Operating Costs ($ millions) | $815 - $850 | $815 - $850 | |||||||||||||||
CMB Expenses5 ($ millions) | $25 - $35 | $25 - $35 | |||||||||||||||
Adjusted General and Administrative Expenses1 ($ millions) | $195 - $225 | $10 - $15 | $185 - $210 | ||||||||||||||
Adjusted Total Capital1,4 ($ millions) | $200 - $245 | $15 - $25 | $185 - $220 | ||||||||||||||
| Drilling & Completions | $67 - $77 | $66 - $76 | |||||||||||||||
Workovers | $44 - $54 | $44 - $54 | |||||||||||||||
Adjusted Facilities | $44 - $54 | $44 - $54 | |||||||||||||||
Corporate & Other | $30 - $35 | $30 - $35 | |||||||||||||||
| Adjusted CMB | $15 - $25 | $15 - $25 | |||||||||||||||
Free Cash Flow1 ($ millions) | $380 - $460 | ||||||||||||||||
Adjusted Free Cash Flow1 ($ millions) | ($60) - ($80) | $460 - $520 | |||||||||||||||
| Natural Gas Marketing Margin ($ millions) | $135 - $150 | $135 - $150 | |||||||||||||||
| Electricity Margin ($ millions) | $70 - $110 | $70 - $110 | |||||||||||||||
| Transportation Expense ($ millions) | $50 - $70 | $50 - $70 | |||||||||||||||
| ARO Settlement Payments* ($ millions) | $55 - $60 | $55 - $60 | |||||||||||||||
| Taxes Other Than on Income* ($ millions) | $175 - $185 | $175 - $185 | |||||||||||||||
| Interest and Debt Expense* ($ millions) | $55 - $60 | $5 - $6 | $50 - $54 | ||||||||||||||
| Cash Income Taxes* ($ millions) | $100 - $120 | $100 - $120 | |||||||||||||||
| Commodity Realizations: | |||||||||||||||||
| Oil - % of Brent: | 94% - 97% | 94% - 97% | |||||||||||||||
| NGL - % of Brent: | 54% - 58% | 54% - 58% | |||||||||||||||
| Natural Gas - % of NYMEX: | 275% - 325% | 275% - 325% | |||||||||||||||
*Notes: •2023E ARO Settlement Payments: ~25% of estimated annual amount is paid every quarter •2023E Taxes Other Than on Income: ~30% of estimated annual amount is paid in each 1Q, 2Q and 4Q •2023E Interest Expense: ~46% of estimated annual amount is paid in cash in each 1Q and 3Q •Cash Income Taxes aren’t paid evenly throughout 2023 | |||||||||||||||||
Third Quarter 2023 Guidance and Capital Program3
CRC expects its third quarter 2023 total capital to range between $52 million and $67 million under current operating conditions. This includes $1 to $2 million of adjusted CMB capital1.
At this level of spending, CRC expects average net total production between 86 and 88 net MBoe/d3 (~61% oil) in the third quarter of 2023, running a 1 drilling rig program in the Los Angeles basin where it has permits.
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CRC GUIDANCE3 | Total 3Q23E | CMB 3Q23E | E&P, Corp. & Other 3Q23E | ||||||||||||||
| Net Total Production (MBoe/d) | 86 - 88 | 86 - 88 | |||||||||||||||
| Net Oil Production (MBbl/d) | 52 - 54 | 52 - 54 | |||||||||||||||
| Operating Costs ($ millions) | $185 - $205 | $185 - $205 | |||||||||||||||
CMB Expenses5 ($ millions) | $5 - $10 | $5 - $10 | |||||||||||||||
Adjusted General and Administrative Expenses1 ($ millions) | $52 - $60 | $2 - $5 | $50 - $55 | ||||||||||||||
Adjusted Total Capital1,4 ($ millions) | $52 - $67 | $1 - $2 | $50 - $65 | ||||||||||||||
Free Cash Flow1 ($ millions) | $30 - $50 | ||||||||||||||||
Adjusted Free Cash Flow1 ($ millions) | ($10) - ($15) | $45 - $60 | |||||||||||||||
| Natural Gas Marketing Margin ($ millions) | $20 - $25 | $20 - $25 | |||||||||||||||
| Electricity Margin ($ millions) | $40 - $50 | $40 - $50 | |||||||||||||||
| Transportation Expense ($ millions) | $13 - $18 | $13 - $18 | |||||||||||||||
| Cash Income Taxes ($ millions) | $25 - $35 | $25 - $35 | |||||||||||||||
| Commodity Realizations: | |||||||||||||||||
| Oil - % of Brent: | 96% - 99% | 96% - 99% | |||||||||||||||
| NGL - % of Brent: | 45% - 50% | 45% - 50% | |||||||||||||||
| Natural Gas - % of NYMEX: | 140% - 160% | 140% - 160% | |||||||||||||||
Second Quarter 2023 E&P Operational Results
Total daily net production for the three months ended June 30, 2023, compared to the three months ended March 31, 2023 decreased by approximately 3 MBoe/d largely due to natural decline and changes in NGL storage volumes. This decrease was partially offset by increased production from drilling and workover activity. CRC's PSCs negatively impacted net oil production by 1 MBoe/d in the three months ended June 30, 2023 compared to the three months ended March 31, 2023.
During the second quarter of 2023, CRC operated an average of 1 drilling rig in the Los Angeles basin, drilled 6 wells and brought online 7 wells. See Attachment 3 for further information on CRC's production results by basin and Attachment 5 for additional information on CRC's drilling activity.
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Second Quarter Financial Results
| 2nd Quarter | 1st Quarter | |||||||||||||
| ($ and shares in millions, except per share amounts) | 2023 | 2023 | ||||||||||||
| Statements of Operations: | ||||||||||||||
| Revenues | ||||||||||||||
| Total operating revenues | $ | 591 | $ | 1,024 | ||||||||||
| Operating Expenses | ||||||||||||||
| Total operating expenses | 444 | 638 | ||||||||||||
| Gain on asset divestitures | — | 7 | ||||||||||||
| Operating Income | $ | 147 | $ | 393 | ||||||||||
| Net Income Attributable to Common Stock | $ | 97 | $ | 301 | ||||||||||
| Net income attributable to common stock per share - basic | $ | 1.39 | $ | 4.22 | ||||||||||
| Net income attributable to common stock per share - diluted | $ | 1.35 | $ | 4.09 | ||||||||||
Adjusted net income1 | $ | 38 | $ | 193 | ||||||||||
Adjusted net income1 per share - diluted | $ | 0.53 | $ | 2.63 | ||||||||||
| Weighted-average common shares outstanding - basic | 69.7 | 71.3 | ||||||||||||
| Weighted-average common shares outstanding - diluted | 71.9 | 73.5 | ||||||||||||
Adjusted EBITDAX1 | $ | 138 | $ | 358 | ||||||||||
Review of Second Quarter 2023 Financial Results
Realized oil prices, excluding the effects of cash settlements on CRC's commodity derivative contracts, decreased by $2.91 per barrel from $78.68 per barrel in the first quarter of 2023 to $75.77 per barrel in the second quarter of 2023. Prices decreased slightly as global demand for crude remained generally flat.
Realized oil prices, including the effects of cash settlements on CRC's commodity derivative contracts, increased by $0.62 from $63.04 in the first quarter of 2023 to $63.66 in the second quarter of 2023.
Adjusted EBITDAX1 for the second quarter of 2023 was $138 million. See table below for the Company's net cash provided by operating activities, capital investments and free cash flow1 during the same periods.
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| FREE CASH FLOW | ||||||||||||||
| Management uses free cash flow, which is defined by CRC as net cash provided by operating activities less capital investments, as a measure of liquidity. The following table presents a reconciliation of CRC's net cash provided by operating activities to free cash flow. CRC supplemented its non-GAAP measure of free cash flow with free cash flow of CRC's exploration and production and corporate items (Free Cash Flow for E&P, Corporate & Other) which it believes is a useful measure for investors to understand the results of its core oil and gas business. CRC defines Free Cash Flow for E&P, Corporate & Other as consolidated free cash flow less results attributable to its carbon management business (CMB). | ||||||||||||||
| 2nd Quarter | 1st Quarter | |||||||||||||
| ($ millions) | 2023 | 2023 | ||||||||||||
| Net cash provided by operating activities | $ | 108 | $ | 310 | ||||||||||
| Capital investments | (39) | (47) | ||||||||||||
Free cash flow1 | 69 | 263 | ||||||||||||
E&P, corporate & other free cash flow1 | $ | 78 | $ | 270 | ||||||||||
CMB free cash flow1 | $ | (9) | $ | (7) | ||||||||||
The following table presents key operating data for CRC's oil and gas operations, on a per BOE basis, for the periods presented below. Energy operating costs consist of purchased natural gas used to generate electricity for CRC's operations and steam for its steamfloods, purchased electricity and internal costs to generate electricity used in CRC's operations. Gas processing costs include costs associated with compression, maintenance and other activities needed to run CRC's gas processing facilities at Elk Hills. Non-energy operating costs equal total operating costs less energy operating costs and gas processing costs.
| OPERATING COSTS PER BOE | ||||||||||||||
| The reporting of PSCs 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 | |||||||||||||
| ($ per Boe) | 2023 | 2023 | ||||||||||||
| Energy operating costs | $ | 7.39 | $ | 15.56 | ||||||||||
| Gas processing costs | 0.64 | 0.62 | ||||||||||||
| Non-energy operating costs | 15.68 | 15.43 | ||||||||||||
| Operating costs | $ | 23.71 | $ | 31.61 | ||||||||||
| Excess costs attributable to PSCs | $ | (2.15) | $ | (2.23) | ||||||||||
Operating costs, excluding effects of PSCs 1 | $ | 21.56 | $ | 29.38 | ||||||||||
Operating costs decreased during the three months ended June 30, 2023 compared to the three months ended March 31, 2023 primarily due to lower energy operating costs as natural gas prices in California markets declined between quarters.
Carbon Management Business Update
In July 2023, CRC applied for a Class VI permit for 17 MMT of permanent CO2 storage at a new storage vault in the Sacramento basin, CTV V. With this new permit, CRC has six Class VI permits on-file with the EPA, bringing CTV's total potential permitted carbon storage to 191 MMT. As of June 30, 2023, the Class VI application for CTV IV was determined to be administratively complete.
In July 2023, CTV entered into a new storage-only CDMA for 100 KMTPA of CO2 injection with Verde Clean Fuels Inc., at CRC's Net Zero Industrial Park at Elk Hills field in Kern County,
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California. Additionally, CTV expanded its Lone Cypress Energy Service, LLC, (Lone Cypress) blue hydrogen project to 205 KMTPA from 100 KMTPA of associated CO2 that could be permanently sequestered at CTV I. See CTV's 2Q23 Press Release for further information on these projects.
The CDMA frames the contractual terms between parties by outlining the material economics and terms of the project and includes conditions precedent to close. The CDMA provides a path for the parties to reach final definitive documents and FID.
Balance Sheet and Liquidity Update
The aggregate commitment under CRC's Revolving Credit Facility was $627 million as of June 30, 2023, which includes a net $25 million increase that occurred during the second quarter of 2023. The borrowing base for the Revolving Credit Facility was reaffirmed at $1.2 billion on April 26, 2023 as part of CRC's semi-annual redetermination.
As of June 30, 2023, CRC had liquidity of $927 million, which consisted of $448 million in cash and cash equivalents plus $479 million of available borrowing capacity under its Revolving Credit Facility (which is net of $148 million of issued letters of credit).
Shareholder Return Strategy
CRC continues to prioritize shareholder returns and therefore dedicates a significant portion of its free cash flow to shareholders in the form of dividends and share repurchases.
On July 28, 2023, CRC's Board of Directors declared a quarterly cash dividend of $0.2825 per share of common stock. The dividend is payable to shareholders of record on September 1, 2023 and will be paid on September 15, 2023.
During the second quarter of 2023, CRC repurchased 1.6 million shares for $64 million at an average price of $39.12 per share. Since the inception of the Share Repurchase Program in May 2021 through June 30, 2023, 14,498,770 shares have been repurchased for $584 million at an average price of $40.18 per share. These total repurchases represent 17% of CRC’s shares outstanding at emergence from bankruptcy.
Through June 30, 2023, CRC has returned approximately $700 million of cash to its shareholders, including approximately $600 million in share repurchases and approximately $100 million of dividends since May 2021. These figures exclude the $20 million second quarter dividend declared and payable in September 2023.
Upcoming Investor Conference Participation
CRC's executives will be participating in the following events in September of 2023:
•Barclays CEO Energy-Power Conference on September 5 to 7 in New York City, NY
•Pickering Energy Partners TE&M Fest Conference on September 20 to 22 in Austin, TX
•Goldman Sachs Sustainability Forum on September 27 in New York City, 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
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To participate in the conference call scheduled for August 1, 2023, at 1:00 p.m. Eastern Time, please dial (877) 328-5505 (International calls please dial +1 (412) 317-5421) or access via webcast at www.crc.com 15 minutes prior to the scheduled start time to register. Participants may also pre-register for the conference call at https://dpregister.com/sreg/10179237/f985ba358a. A digital replay of the conference call will be archived for approximately 90 days and supplemental slides for the conference call will be available online in the Investor Relations section of www.crc.com.
1 See Attachment 2 for the non-GAAP financial measures of adjusted EBITDAX, operating costs per BOE (excluding effects of PSCs), adjusted net income (loss), adjusted net income (loss) per share - basic and diluted, free cash flow, adjusted free cash flow, adjusted G&A and adjusted total capital, including reconciliations to their most directly comparable GAAP measure, where applicable. For the full year 2023 and 3Q23 estimates of the non-GAAP measure of free cash flow, adjusted free cash flow, adjusted G&A and adjusted capital, including reconciliations to their most directly comparable GAAP measure, see Attachment 7.
2 Calculated as $448 million of available cash plus $627 million of capacity on CRC's Revolving Credit Facility less $148 million in outstanding letters of credit.
3 Current guidance assumes a 2023 Brent price of $77.54 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $2.87 per mcf and a 3Q23 Brent price of $75.25 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $2.73 per mcf. CRC's share of production under PSC contracts decreases when commodity prices rise and increases when prices fall.
4 Adjusted E&P Capital and Adjusted CMB Capital are Non-GAAP measures. These measures reflect the reclassification of certain E&P, Corporate & Other Capital to CMB Capital related to the investment in facilities to advance carbon sequestration activities. For the full year 2023 and 3Q23 estimates of the non-GAAP measure of free cash flow, including reconciliations to their most directly comparable GAAP measure, see Attachment 7.
5 CMB Expenses includes lease cost for sequestration easements, advocacy, and other startup related costs.
About Carbon TerraVault
Carbon TerraVault Holdings, LLC (CTV), a subsidiary of CRC, provides services that include the capture, transport and storage of carbon dioxide for its customers. CTV is engaged in a series of CCS projects that inject CO2 captured from industrial sources into depleted underground reservoirs and permanently store CO2 deep underground. For more information about CTV, please visit www.carbonterravault.com.
About California Resources Corporation
California Resources Corporation (CRC) is an independent energy and carbon management company committed to energy transition. CRC produces some of the lowest carbon intensity oil in the US and is focused on maximizing the value of its land, mineral and technical resources for decarbonization efforts. For more information about CRC, please visit www.crc.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 CRC's 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:
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•fluctuations in commodity prices, including supply and demand considerations for CRC's products and services;
•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 war in Ukraine and oil sanctions on Russia, Iran and others;
•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 CRC's 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 CRC's 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;
•CRC's ability to convert it's 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 CRC's ability to successfully gather and verify emissions data and other environmental impacts;
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•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, and 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 CRC 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 do not warrant the accuracy or completeness of such third-party information.
Contacts:
| Joanna Park (Investor Relations) 818-661-3731 [email protected] | Richard Venn (Media) 818-661-6014 | ||||
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| Attachment 1 | ||||||||||||||||||||||||||||||||
| SUMMARY OF RESULTS | ||||||||||||||||||||||||||||||||
| 2nd Quarter | 1st Quarter | 2nd Quarter | Six Months | Six Months | ||||||||||||||||||||||||||||
| ($ and shares in millions, except per share amounts) | 2023 | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||||||||||
| Statements of Operations: | ||||||||||||||||||||||||||||||||
| Revenues | ||||||||||||||||||||||||||||||||
| Oil, natural gas and NGL sales | $ | 447 | $ | 715 | $ | 718 | $ | 1,162 | $ | 1,346 | ||||||||||||||||||||||
| Net gain (loss) from commodity derivatives | 31 | 42 | (100) | 73 | (662) | |||||||||||||||||||||||||||
| Sales of purchased natural gas | 72 | 184 | 75 | 256 | 107 | |||||||||||||||||||||||||||
| Electricity sales | 34 | 68 | 49 | 102 | 83 | |||||||||||||||||||||||||||
| Other revenue | 7 | 15 | 5 | 22 | 26 | |||||||||||||||||||||||||||
| Total operating revenues | 591 | 1,024 | 747 | 1,615 | 900 | |||||||||||||||||||||||||||
| Operating Expenses | ||||||||||||||||||||||||||||||||
| Operating costs | 186 | 254 | 190 | 440 | 372 | |||||||||||||||||||||||||||
General and administrative expenses(1) | 71 | 65 | 56 | 136 | 104 | |||||||||||||||||||||||||||
| Depreciation, depletion and amortization | 56 | 58 | 50 | 114 | 99 | |||||||||||||||||||||||||||
| Asset impairment | — | 3 | 2 | 3 | 2 | |||||||||||||||||||||||||||
| Taxes other than on income | 42 | 42 | 42 | 84 | 76 | |||||||||||||||||||||||||||
| Exploration expense | 1 | 1 | 1 | 2 | 2 | |||||||||||||||||||||||||||
| Purchased natural gas expense | 27 | 124 | 67 | 151 | 88 | |||||||||||||||||||||||||||
| Electricity generation expenses | 13 | 49 | 33 | 62 | 57 | |||||||||||||||||||||||||||
| Transportation costs | 16 | 17 | 12 | 33 | 24 | |||||||||||||||||||||||||||
| Accretion expense | 11 | 12 | 11 | 23 | 22 | |||||||||||||||||||||||||||
| Other operating expenses, net | 21 | 13 | 9 | 34 | 23 | |||||||||||||||||||||||||||
| Total operating expenses | 444 | 638 | 473 | 1,082 | 869 | |||||||||||||||||||||||||||
| Net gain on asset divestitures | — | 7 | 4 | 7 | 58 | |||||||||||||||||||||||||||
| Operating Income | 147 | 393 | 278 | 540 | 89 | |||||||||||||||||||||||||||
| Non-Operating (Expenses) Income | ||||||||||||||||||||||||||||||||
| Interest and debt expense | (14) | (14) | (13) | (28) | (26) | |||||||||||||||||||||||||||
| Loss from investment in unconsolidated subsidiary | (1) | (2) | — | (3) | — | |||||||||||||||||||||||||||
| Other non-operating income (expense), net | 3 | (1) | 1 | 2 | 2 | |||||||||||||||||||||||||||
| Income Before Income Taxes | 135 | 376 | 266 | 511 | 65 | |||||||||||||||||||||||||||
| Income tax provision | (38) | (75) | (76) | (113) | (50) | |||||||||||||||||||||||||||
| Net income | $ | 97 | $ | 301 | $ | 190 | $ | 398 | $ | 15 | ||||||||||||||||||||||
| Net income attributable to common stock per share - basic | $ | 1.39 | $ | 4.22 | $ | 2.48 | $ | 5.65 | $ | 0.19 | ||||||||||||||||||||||
| Net income attributable to common stock per share - diluted | $ | 1.35 | $ | 4.09 | $ | 2.41 | $ | 5.47 | $ | 0.19 | ||||||||||||||||||||||
| Adjusted net income | $ | 38 | $ | 193 | $ | 89 | $ | 231 | $ | 180 | ||||||||||||||||||||||
| Adjusted net income per share - basic | $ | 0.55 | $ | 2.71 | $ | 1.16 | $ | 3.28 | $ | 2.32 | ||||||||||||||||||||||
| Adjusted net income per share - diluted | $ | 0.53 | $ | 2.63 | $ | 1.13 | $ | 3.18 | $ | 2.26 | ||||||||||||||||||||||
| Weighted-average common shares outstanding - basic | 69.7 | 71.3 | 76.7 | 70.5 | 77.6 | |||||||||||||||||||||||||||
| Weighted-average common shares outstanding - diluted | 71.9 | 73.5 | 78.8 | 72.7 | 79.6 | |||||||||||||||||||||||||||
| Adjusted EBITDAX | $ | 138 | $ | 358 | $ | 204 | $ | 496 | $ | 410 | ||||||||||||||||||||||
| Effective tax rate | 28 | % | 20 | % | 29 | % | 22 | % | 78 | % | ||||||||||||||||||||||
| (1) General and administrative expenses included $13 million, $9 million and $6 million of non-cash stock based compensation expense for the second quarter of 2023, first quarter of 2023 and second quarter of 2022, respectively. General and administrative expenses included $22 million and $12 million of non-cash stock based compensation expense for the six months ended June 30, 2023 and 2022, respectively. General and administrative expenses also included $3 million and $5 million in the first and second quarters of 2023, respectively, related to information technology infrastructure. | ||||||||||||||||||||||||||||||||
Page 11
| 2nd Quarter | 1st Quarter | 2nd Quarter | Six Months | Six Months | ||||||||||||||||||||||||||||
| ($ in millions) | 2023 | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||||||||||
| Cash Flow Data: | ||||||||||||||||||||||||||||||||
| Net cash provided by operating activities | $ | 108 | $ | 310 | $ | 181 | $ | 418 | $ | 341 | ||||||||||||||||||||||
| Net cash used in investing activities | $ | (44) | $ | (61) | $ | (76) | $ | (105) | $ | (129) | ||||||||||||||||||||||
| Net cash used in financing activities | $ | (93) | $ | (79) | $ | (109) | $ | (172) | $ | (193) | ||||||||||||||||||||||
| June 30, | December 31, | |||||||||||||||||||||||||||||||
| ($ in millions) | 2023 | 2022 | ||||||||||||||||||||||||||||||
| Selected Balance Sheet Data: | ||||||||||||||||||||||||||||||||
| Total current assets | $ | 867 | $ | 864 | ||||||||||||||||||||||||||||
| Property, plant and equipment, net | $ | 2,745 | $ | 2,786 | ||||||||||||||||||||||||||||
| Deferred tax asset | $ | 108 | $ | 164 | ||||||||||||||||||||||||||||
| Total current liabilities | $ | 582 | $ | 894 | ||||||||||||||||||||||||||||
| Long-term debt, net | $ | 593 | $ | 592 | ||||||||||||||||||||||||||||
| Noncurrent asset retirement obligations | $ | 411 | $ | 432 | ||||||||||||||||||||||||||||
| Stockholders' Equity | $ | 2,110 | $ | 1,864 | ||||||||||||||||||||||||||||
Page 12
| GAINS AND LOSSES FROM COMMODITY DERIVATIVES | ||||||||||||||||||||||||||
| 2nd Quarter | 1st Quarter | 2nd Quarter | Six Months | Six Months | ||||||||||||||||||||||
| ($ millions) | 2023 | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||||
| Non-cash derivative gain (loss) | $ | 94 | $ | 107 | $ | 141 | $ | 201 | $ | (240) | ||||||||||||||||
| Net payments on settled commodity derivatives | (63) | (65) | (241) | (128) | (422) | |||||||||||||||||||||
| Net gain (loss) from commodity derivatives | $ | 31 | $ | 42 | $ | (100) | $ | 73 | $ | (662) | ||||||||||||||||
| 1st Quarter | 1st Quarter | 4th Quarter | 4th Quarter | 4th Quarter | |||||||||||||||||||||||||||||||||||||
| CAPITAL INVESTMENTS | |||||||||||||||||||||||||||||
| 2nd Quarter | 1st Quarter | 2nd Quarter | Six Months | Six Months | |||||||||||||||||||||||||
| ($ millions) | 2023 | 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||||||
Facilities (1) | $ | 11 | $ | 9 | $ | 15 | $ | 20 | $ | 32 | |||||||||||||||||||
| Drilling | 13 | 25 | 62 | 38 | 121 | ||||||||||||||||||||||||
| Workovers | 11 | 6 | 9 | 17 | 15 | ||||||||||||||||||||||||
| Total E&P capital | 35 | 40 | 86 | 75 | 168 | ||||||||||||||||||||||||
CMB (1) | — | 1 | 10 | 1 | 11 | ||||||||||||||||||||||||
| Corporate and other | 4 | 6 | 2 | 10 | 18 | ||||||||||||||||||||||||
| Total capital program | $ | 39 | $ | 47 | $ | 98 | $ | 86 | $ | 197 | |||||||||||||||||||
(1) Facilities capital includes $1 million, $1 million and $3 million in the second and first quarter of 2023 and second quarter of 2022, 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. | |||||||||||||||||||||||||||||
Page 13
| Attachment 2 | ||||||||||||||||||||||||||
| 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, 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 | Six Months | Six Months | |||||||||||||||||||||||||
| ($ millions, except per share amounts) | 2023 | 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||||||
| Net income | $ | 97 | $ | 301 | $ | 190 | $ | 398 | $ | 15 | |||||||||||||||||||
| Unusual, infrequent and other items: | |||||||||||||||||||||||||||||
| Non-cash derivative (gain) loss | (94) | (107) | (141) | (201) | 240 | ||||||||||||||||||||||||
| Asset impairment | — | 3 | 2 | 3 | 2 | ||||||||||||||||||||||||
| Severance and termination costs | 2 | 1 | — | 3 | — | ||||||||||||||||||||||||
| Net (gain) loss on asset divestitures | — | (7) | (4) | (7) | (58) | ||||||||||||||||||||||||
| Other, net | 10 | 3 | 2 | 13 | 3 | ||||||||||||||||||||||||
| Total unusual, infrequent and other items | (82) | (107) | (141) | (189) | 187 | ||||||||||||||||||||||||
| Income tax provision (benefit) of adjustments at effective tax rate | 23 | 30 | 40 | 53 | (53) | ||||||||||||||||||||||||
| Income tax (benefit) provision - out of period | — | (31) | — | (31) | 31 | ||||||||||||||||||||||||
| Adjusted net income attributable to common stock | $ | 38 | $ | 193 | $ | 89 | $ | 231 | $ | 180 | |||||||||||||||||||
| Net income attributable to common stock per share - basic | $ | 1.39 | $ | 4.22 | $ | 2.48 | $ | 5.65 | $ | 0.19 | |||||||||||||||||||
| Net income attributable to common stock per share - diluted | $ | 1.35 | $ | 4.09 | $ | 2.41 | $ | 5.47 | $ | 0.19 | |||||||||||||||||||
| Adjusted net income per share - basic | $ | 0.55 | $ | 2.71 | $ | 1.16 | $ | 3.28 | $ | 2.32 | |||||||||||||||||||
| Adjusted net income per share - diluted | $ | 0.53 | $ | 2.63 | $ | 1.13 | $ | 3.18 | $ | 2.26 | |||||||||||||||||||
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 | Six Months | Six Months | ||||||||||||||||||||||||||||
| ($ millions, except per BOE amounts) | 2023 | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||||||||||
| Net income | $ | 97 | $ | 301 | $ | 190 | $ | 398 | $ | 15 | ||||||||||||||||||||||
| Interest and debt expense | 14 | 14 | 13 | 28 | 26 | |||||||||||||||||||||||||||
| Depreciation, depletion and amortization | 56 | 58 | 50 | 114 | 99 | |||||||||||||||||||||||||||
| Income tax provision (benefit) | 38 | 75 | 76 | 113 | 50 | |||||||||||||||||||||||||||
| Exploration expense | 1 | 1 | 1 | 2 | 2 | |||||||||||||||||||||||||||
| Interest income | (5) | (4) | — | (9) | — | |||||||||||||||||||||||||||
Unusual, infrequent and other items (1) | (82) | (107) | (141) | (189) | 187 | |||||||||||||||||||||||||||
| Non-cash items | ||||||||||||||||||||||||||||||||
| Accretion expense | 11 | 12 | 11 | 23 | 22 | |||||||||||||||||||||||||||
| Stock-based compensation | 8 | 7 | 4 | 15 | 8 | |||||||||||||||||||||||||||
| Post-retirement medical and pension | — | 1 | — | 1 | 1 | |||||||||||||||||||||||||||
| Adjusted EBITDAX | $ | 138 | $ | 358 | $ | 204 | $ | 496 | $ | 410 | ||||||||||||||||||||||
| Net cash provided by operating activities | $ | 108 | $ | 310 | $ | 181 | $ | 418 | $ | 341 | ||||||||||||||||||||||
| Cash interest payments | 2 | 23 | 2 | 25 | 25 | |||||||||||||||||||||||||||
| Cash interest received | (5) | (4) | — | (9) | — | |||||||||||||||||||||||||||
| Cash income taxes | 51 | — | 20 | 51 | 20 | |||||||||||||||||||||||||||
| Exploration expenditures | 1 | 1 | 1 | 2 | 2 | |||||||||||||||||||||||||||
| Working capital changes | (19) | 28 | — | 9 | 22 | |||||||||||||||||||||||||||
| Adjusted EBITDAX | $ | 138 | $ | 358 | $ | 204 | $ | 496 | $ | 410 | ||||||||||||||||||||||
| E&P, Corporate & Other Adjusted EBITDAX | $ | 151 | $ | 367 | $ | 209 | $ | 518 | $ | 417 | ||||||||||||||||||||||
| CMB Adjusted EBITDAX | $ | (13) | $ | (9) | $ | (5) | $ | (22) | $ | (7) | ||||||||||||||||||||||
| Adjusted EBITDAX per Boe | $ | 17.59 | $ | 44.55 | $ | 24.61 | $ | 31.23 | $ | 25.24 | ||||||||||||||||||||||
(1) See Adjusted Net Income (Loss) reconciliation. | ||||||||||||||||||||||||||||||||
Page 15
| FREE CASH FLOW | |||||||||||||||||||||||||||||
| 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 free cash flow of its exploration and production and corporate 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). | |||||||||||||||||||||||||||||
| 2nd Quarter | 1st Quarter | 2nd Quarter | Six Months | Six Months | |||||||||||||||||||||||||
| ($ millions) | 2023 | 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||||||
| Net cash provided by operating activities | $ | 108 | $ | 310 | $ | 181 | $ | 418 | $ | 341 | |||||||||||||||||||
| Capital investments | (39) | (47) | (98) | (86) | (197) | ||||||||||||||||||||||||
| Free cash flow | $ | 69 | $ | 263 | $ | 83 | $ | 332 | $ | 144 | |||||||||||||||||||
| E&P, Corporate and Other | $ | 78 | $ | 270 | $ | 98 | $ | 348 | $ | 162 | |||||||||||||||||||
| CMB | $ | (9) | $ | (7) | $ | (15) | $ | (16) | $ | (18) | |||||||||||||||||||
| Adjustments to capital investments: | |||||||||||||||||||||||||||||
Replacement water facilities(1) | $ | 1 | $ | 1 | $ | 3 | $ | 2 | $ | 5 | |||||||||||||||||||
| Adjusted capital investments: | |||||||||||||||||||||||||||||
| E&P, Corporate and Other | $ | 38 | $ | 45 | $ | 85 | $ | 83 | $ | 181 | |||||||||||||||||||
| CMB | $ | 1 | $ | 2 | $ | 13 | $ | 3 | $ | 16 | |||||||||||||||||||
Adjusted free cash flow(2): | |||||||||||||||||||||||||||||
| E&P, Corporate and Other | $ | 79 | $ | 271 | $ | 101 | $ | 350 | $ | 167 | |||||||||||||||||||
| CMB | $ | (10) | $ | (8) | $ | (18) | $ | (18) | $ | (23) | |||||||||||||||||||
(1) Facilities capital includes $1 million, $1 million and $3 million in the first and second quarter of 2023 and second quarter of 2022, respectively, to build replacement water injection facilities which will allow CRC to divert produced water away from a depleted oil and natural gas reservoir held by the Carbon TerraVault JV. Construction of these facilities supports the advancement of CRC’s carbon management business and CRC reported these amounts as part of adjusted CMB capital in this press release. Where adjusted CMB capital is presented, CRC removed the amounts from facilities capital and presented adjusted E&P, Corporate and Other capital. | |||||||||||||||||||||||||||||
(2) Adjusted free cash flow is defined as net cash provided by operating activities less adjusted capital investments. | |||||||||||||||||||||||||||||
Page 16
| ADJUSTED GENERAL & ADMINISTRATIVE EXPENSES | |||||||||||||||||||||||||||||
Management uses a measure called adjusted general and administrative (G&A) expenses to provide useful information to investors interested in comparing CRC's costs between periods and performance to our peers. CRC supplemented its non-GAAP measure of adjusted general and administrative expenses with adjusted general and administrative expenses of its exploration and production and corporate items (adjusted general & administrative expenses for E&P, Corporate & Other) which it believes is a useful measure for investors to understand the results or CRC's core oil and gas business. CRC defines adjusted general & administrative Expenses for E&P, Corporate & Other as consolidated adjusted general and administrative expenses less results attributable to its carbon management business (CMB). | |||||||||||||||||||||||||||||
| 2nd Quarter | 1st Quarter | 2nd Quarter | Six Months | Six Months | |||||||||||||||||||||||||
| ($ millions) | 2023 | 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||||||
| General and administrative expenses | $ | 71 | $ | 65 | $ | 56 | $ | 136 | $ | 104 | |||||||||||||||||||
| Stock-based compensation | (8) | (7) | (4) | (15) | (8) | ||||||||||||||||||||||||
| Other | (6) | (3) | (1) | (9) | (1) | ||||||||||||||||||||||||
| Adjusted G&A expenses | $ | 57 | $ | 55 | $ | 51 | $ | 112 | $ | 95 | |||||||||||||||||||
| E&P, Corporate and Other adjusted G&A expenses | $ | 54 | $ | 52 | $ | 47 | $ | 106 | $ | 90 | |||||||||||||||||||
| CMB adjusted G&A expenses | $ | 3 | $ | 3 | $ | 4 | $ | 6 | $ | 5 | |||||||||||||||||||
| 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 | Six Months | Six Months | |||||||||||||||||||||||||
| ($ per BOE) | 2023 | 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||||||
Energy operating costs (1) | $ | 7.39 | $ | 15.56 | $ | 6.88 | $ | 11.52 | $ | 6.78 | |||||||||||||||||||
Gas processing costs (2) | 0.64 | 0.62 | 0.54 | 0.63 | 0.55 | ||||||||||||||||||||||||
Non-energy operating costs (3) | 15.68 | 15.43 | 15.50 | 15.56 | 15.57 | ||||||||||||||||||||||||
| Operating costs | $ | 23.71 | $ | 31.61 | $ | 22.92 | $ | 27.71 | $ | 22.90 | |||||||||||||||||||
| Costs attributable to PSCs | |||||||||||||||||||||||||||||
| Excess energy operating costs attributable to PSCs | $ | (0.91) | $ | (1.19) | $ | (1.03) | $ | (0.98) | $ | (0.96) | |||||||||||||||||||
| Excess non-energy operating costs attributable to PSCs | (1.24) | (1.04) | (1.55) | (1.21) | (1.49) | ||||||||||||||||||||||||
| Excess costs attributable to PSCs | $ | (2.15) | $ | (2.23) | $ | (2.58) | $ | (2.19) | $ | (2.45) | |||||||||||||||||||
Energy operating costs, excluding effect of PSCs (1) | $ | 6.48 | $ | 14.37 | $ | 5.85 | $ | 10.54 | $ | 5.82 | |||||||||||||||||||
Gas processing costs, excluding effect of PSCs (2) | 0.64 | 0.62 | 0.54 | 0.63 | 0.55 | ||||||||||||||||||||||||
Non-energy operating costs, excluding effect of PSCs (3) | 14.44 | 14.39 | 13.95 | 14.35 | 14.08 | ||||||||||||||||||||||||
| Operating costs, excluding effects of PSCs | $ | 21.56 | $ | 29.38 | $ | 20.34 | $ | 25.52 | $ | 20.45 | |||||||||||||||||||
(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. | |||||||||||||||||||||||||||||
(3) Non-energy operating costs equal total operating costs less energy operating costs and gas processing costs. Purchased natural gas used to generate steam in CRC's steamfloods was reclassified from non-energy operating costs to energy operating costs beginning in the third quarter of 2022. All prior periods have been updated to conform to this presentation. | |||||||||||||||||||||||||||||
Page 17
| Attachment 3 | |||||||||||||||||||||||||||||
| PRODUCTION STATISTICS | |||||||||||||||||||||||||||||
| 2nd Quarter | 1st Quarter | 2nd Quarter | Six Months | Six Months | |||||||||||||||||||||||||
| Net Production Per Day | 2023 | 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||||||
| Oil (MBbl/d) | |||||||||||||||||||||||||||||
| San Joaquin Basin | 34 | 35 | 38 | 35 | 38 | ||||||||||||||||||||||||
| Los Angeles Basin | 19 | 20 | 16 | 19 | 17 | ||||||||||||||||||||||||
| Total | 53 | 55 | 54 | 54 | 55 | ||||||||||||||||||||||||
| NGLs (MBbl/d) | |||||||||||||||||||||||||||||
| San Joaquin Basin | 11 | 11 | 12 | 11 | 11 | ||||||||||||||||||||||||
| Total | 11 | 11 | 12 | 11 | 11 | ||||||||||||||||||||||||
| Natural Gas (MMcf/d) | |||||||||||||||||||||||||||||
| San Joaquin Basin | 119 | 119 | 132 | 119 | 127 | ||||||||||||||||||||||||
| Los Angeles Basin | 1 | 1 | 1 | 1 | 1 | ||||||||||||||||||||||||
| Sacramento Basin | 15 | 16 | 18 | 16 | 18 | ||||||||||||||||||||||||
| Total | 135 | 136 | 151 | 136 | 146 | ||||||||||||||||||||||||
| Total Production (MBoe/d) | 86 | 89 | 91 | 88 | 90 | ||||||||||||||||||||||||
| Gross Operated and Net Non-Operated | 2nd Quarter | 1st Quarter | 2nd Quarter | Six Months | Six Months | ||||||||||||||||||||||||
| Production Per Day | 2023 | 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||||||
| Oil (MBbl/d) | |||||||||||||||||||||||||||||
| San Joaquin Basin | 38 | 39 | 42 | 39 | 42 | ||||||||||||||||||||||||
| Los Angeles Basin | 25 | 26 | 25 | 25 | 26 | ||||||||||||||||||||||||
| Total | 63 | 65 | 67 | 64 | 68 | ||||||||||||||||||||||||
| NGLs (MBbl/d) | |||||||||||||||||||||||||||||
| San Joaquin Basin | 12 | 12 | 13 | 12 | 11 | ||||||||||||||||||||||||
| Total | 12 | 12 | 13 | 12 | 11 | ||||||||||||||||||||||||
| Natural Gas (MMcf/d) | |||||||||||||||||||||||||||||
| San Joaquin Basin | 136 | 135 | 141 | 135 | 135 | ||||||||||||||||||||||||
| Los Angeles Basin | 7 | 7 | 7 | 7 | 7 | ||||||||||||||||||||||||
| Sacramento Basin | 19 | 20 | 22 | 20 | 23 | ||||||||||||||||||||||||
| Total | 162 | 162 | 170 | 162 | 165 | ||||||||||||||||||||||||
| Total Production (MBoe/d) | 103 | 103 | 108 | 103 | 106 | ||||||||||||||||||||||||
| Note: MBbl/d refers to thousands of barrels per day; MMcf/d refers to millions of cubic feet per day; MBoe/d refers to thousands of barrels of oil equivalent (Boe) per day. Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet of natural gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence. | |||||||||||||||||||||||||||||
Page 18
| Attachment 4 | ||||||||||||||||||||||||||||||||||||||
| PRICE STATISTICS | ||||||||||||||||||||||||||||||||||||||
| 2nd Quarter | 1st Quarter | 2nd Quarter | Six Months | Six Months | ||||||||||||||||||||||||||||||||||
| 2023 | 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||||||||||||||||
| Oil ($ per Bbl) | ||||||||||||||||||||||||||||||||||||||
| Realized price with derivative settlements | $ | 63.66 | $ | 63.04 | $ | 63.17 | $ | 63.35 | $ | 61.71 | ||||||||||||||||||||||||||||
| Realized price without derivative settlements | $ | 75.77 | $ | 78.68 | $ | 112.32 | $ | 77.25 | $ | 104.07 | ||||||||||||||||||||||||||||
| NGLs ($/Bbl) | $ | 42.48 | $ | 58.88 | $ | 68.29 | $ | 50.88 | $ | 72.57 | ||||||||||||||||||||||||||||
| Natural gas ($/Mcf) | ||||||||||||||||||||||||||||||||||||||
| Realized price with derivative settlements | $ | 3.46 | $ | 21.56 | $ | 6.72 | $ | 12.44 | $ | 6.51 | ||||||||||||||||||||||||||||
| Realized price without derivative settlements | $ | 3.46 | $ | 21.56 | $ | 6.85 | $ | 12.44 | $ | 6.58 | ||||||||||||||||||||||||||||
| Index Prices | ||||||||||||||||||||||||||||||||||||||
| Brent oil ($/Bbl) | $ | 78.01 | $ | 82.22 | $ | 111.79 | $ | 80.12 | $ | 104.59 | ||||||||||||||||||||||||||||
| WTI oil ($/Bbl) | $ | 73.78 | $ | 76.13 | $ | 108.41 | $ | 74.95 | $ | 101.35 | ||||||||||||||||||||||||||||
| NYMEX average monthly settled price ($/MMBtu) | $ | 2.10 | $ | 3.42 | $ | 7.17 | $ | 2.76 | $ | 6.06 | ||||||||||||||||||||||||||||
| Realized Prices as Percentage of Index Prices | ||||||||||||||||||||||||||||||||||||||
| Oil with derivative settlements as a percentage of Brent | 82 | % | 77 | % | 57 | % | 79 | % | 59 | % | ||||||||||||||||||||||||||||
| Oil without derivative settlements as a percentage of Brent | 97 | % | 96 | % | 100 | % | 96 | % | 100 | % | ||||||||||||||||||||||||||||
| Oil with derivative settlements as a percentage of WTI | 86 | % | 83 | % | 58 | % | 85 | % | 61 | % | ||||||||||||||||||||||||||||
| Oil without derivative settlements as a percentage of WTI | 103 | % | 103 | % | 104 | % | 103 | % | 103 | % | ||||||||||||||||||||||||||||
| NGLs as a percentage of Brent | 54 | % | 72 | % | 61 | % | 64 | % | 69 | % | ||||||||||||||||||||||||||||
| NGLs as a percentage of WTI | 58 | % | 77 | % | 63 | % | 68 | % | 72 | % | ||||||||||||||||||||||||||||
| Natural gas with derivative settlements as a percentage of NYMEX contract month average | 165 | % | 630 | % | 94 | % | 451 | % | 107 | % | ||||||||||||||||||||||||||||
| Natural gas without derivative settlements as a percentage of NYMEX contract month average | 165 | % | 630 | % | 96 | % | 451 | % | 109 | % | ||||||||||||||||||||||||||||
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| Attachment 5 | |||||||||||||||||||||||||||||
| SECOND QUARTER 2023 DRILLING ACTIVITY | |||||||||||||||||||||||||||||
| San Joaquin | Los Angeles | Ventura | Sacramento | ||||||||||||||||||||||||||
| Wells Drilled | Basin | Basin | Basin | Basin | Total | ||||||||||||||||||||||||
| Development Wells | |||||||||||||||||||||||||||||
| Primary | — | — | — | — | — | ||||||||||||||||||||||||
| Waterflood | — | 6 | — | — | 6 | ||||||||||||||||||||||||
| Steamflood | — | — | — | — | — | ||||||||||||||||||||||||
Total (1) | — | 6 | — | — | 6 | ||||||||||||||||||||||||
| SIX MONTHS 2023 DRILLING ACTIVITY | |||||||||||||||||||||||||||||
| San Joaquin | Los Angeles | Ventura | Sacramento | ||||||||||||||||||||||||||
| Wells Drilled | Basin | Basin | Basin | Basin | Total | ||||||||||||||||||||||||
| Development Wells | |||||||||||||||||||||||||||||
| Primary | 2 | — | — | — | 2 | ||||||||||||||||||||||||
| Waterflood | 1 | 12 | — | — | 13 | ||||||||||||||||||||||||
| Steamflood | — | — | — | — | — | ||||||||||||||||||||||||
Total (1) | 3 | 12 | — | — | 15 | ||||||||||||||||||||||||
(1) Includes steam injectors and drilled but uncompleted wells, which are not included in the SEC definition of wells drilled. | |||||||||||||||||||||||||||||
Page 20
| Attachment 6 | ||||||||||||||||||||||||||||||||||||||
| OIL HEDGES AS OF JUNE 30, 2023 | ||||||||||||||||||||||||||||||||||||||
| Q3 2023 | Q4 2023 | Q1 2024 | Q2 2024 | 2H 2024 | 2025 | |||||||||||||||||||||||||||||||||
| Sold Calls | ||||||||||||||||||||||||||||||||||||||
| Barrels per day | 17,363 | 5,747 | 7,750 | 10,500 | 10,375 | 14,811 | ||||||||||||||||||||||||||||||||
| Weighted-average Brent price per barrel | $57.06 | $57.06 | $90.00 | $90.20 | $90.20 | $85.83 | ||||||||||||||||||||||||||||||||
| Swaps | ||||||||||||||||||||||||||||||||||||||
| Barrels per day | 19,697 | 27,094 | 6,000 | 1,000 | 1,000 | 1,687 | ||||||||||||||||||||||||||||||||
| Weighted-average Brent price per barrel | $70.73 | $70.73 | $79.06 | $77.20 | $77.20 | $70.32 | ||||||||||||||||||||||||||||||||
Net Purchased Puts (1) | ||||||||||||||||||||||||||||||||||||||
| Barrels per day | 17,363 | 5,747 | 14,684 | 10,500 | 10,375 | 14,811 | ||||||||||||||||||||||||||||||||
| Weighted-average Brent price per barrel | $76.25 | $76.25 | $69.72 | $65.48 | $65.48 | $60.00 | ||||||||||||||||||||||||||||||||
(1) Purchased puts and sold puts with the same strike price have been presented on a net basis. | ||||||||||||||||||||||||||||||||||||||
Page 21
| Attachment 7 | |||||||||||||||||
| 2023 Estimated | |||||||||||||||||
TOTAL CRC GUIDANCE1 | Consolidated | CMB | E&P, Corporate & Other | ||||||||||||||
| Net Total Production (MBoe/d) | 85 - 91 | 85 - 91 | |||||||||||||||
| Net Oil Production (MBbl/d) | 51 - 55 | 51 - 55 | |||||||||||||||
| Operating Costs ($ millions) | $815 - $850 | $815 - $850 | |||||||||||||||
CMB Expenses2 ($ millions) | $25 - $35 | $25 - $35 | |||||||||||||||
Adjusted General and Administrative Expenses1 ($ millions) | $195 - $225 | $10 - $15 | $185 - $210 | ||||||||||||||
Adjusted Total Capital3 ($ millions) | $200 - $245 | $15 - $25 | $185 - $220 | ||||||||||||||
Free Cash Flow3 ($ millions) | $380 - $460 | ||||||||||||||||
Adjusted Free Cash Flow3 ($ millions) | ($60) - ($80) | $460 - $520 | |||||||||||||||
| Natural Gas Marketing Margin ($ millions) | $135 - $150 | $135 - $150 | |||||||||||||||
| Electricity Margin ($ millions) | $70 - $110 | $70 - $110 | |||||||||||||||
| Transportation Expense ($ millions) | $50 - $70 | $50 - $70 | |||||||||||||||
| ARO Settlement Payments* ($ millions) | $55 - $60 | $55 - $60 | |||||||||||||||
| Taxes Other Than on Income* ($ millions) | $175 - $185 | $175 - $185 | |||||||||||||||
| Interest and Debt Expense* ($ millions) | $55 - $60 | $5 - $6 | $50 - $54 | ||||||||||||||
| Cash Income Taxes* ($ millions) | $100 - $120 | $100 - $120 | |||||||||||||||
| Commodity Realizations: | |||||||||||||||||
| Oil - % of Brent: | 94% - 97% | 94% - 97% | |||||||||||||||
| NGL - % of Brent: | 54% - 58% | 54% - 58% | |||||||||||||||
| Natural Gas - % of NYMEX*: | 275% - 325% | 275% - 325% | |||||||||||||||
*Notes: •2023E ARO Settlement Payments: ~25% of estimated annual amount is paid every quarter •2023E Taxes Other Than on Income: ~30% of estimated annual amount is paid in 1Q, 2Q and 4Q •2023E Interest Expense: ~46% of estimated annual amount is paid in cash in 1Q and 3Q •Cash Income Taxes aren’t paid evenly throughout 2023 | |||||||||||||||||
Page 22
CRC GUIDANCE3 | Total 3Q23E | CMB 3Q23E | E&P, Corp. & Other 3Q23E | ||||||||||||||
| Net Total Production (MBoe/d) | 86 - 88 | 86 - 88 | |||||||||||||||
| Net Oil Production (MBbl/d) | 52 - 54 | 52 - 54 | |||||||||||||||
| Operating Costs ($ millions) | $185 - $205 | $185 - $205 | |||||||||||||||
CMB Expenses2 ($ millions) | $5 - $10 | $5 - $10 | |||||||||||||||
Adjusted General and Administrative Expenses1 ($ millions) | $52 - $60 | $2 - $5 | $50 - $55 | ||||||||||||||
Adjusted Total Capital3 ($ millions) | $52 - $67 | $1 - $2 | $50 - $65 | ||||||||||||||
Free Cash Flow3 ($ millions) | $30 - $50 | ||||||||||||||||
Adjusted Free Cash Flow3 ($ millions) | ($10) - ($15) | $45 - $60 | |||||||||||||||
| Natural Gas Marketing Margin ($ millions) | $20 - $25 | $20 - $25 | |||||||||||||||
| Electricity Margin ($ millions) | $40 - $50 | $40 - $50 | |||||||||||||||
| Transportation Expense ($ millions) | $13 - $18 | $13 - $18 | |||||||||||||||
| Cash Income Taxes ($ millions) | $25 - $35 | $25 - $35 | |||||||||||||||
| Commodity Realizations: | |||||||||||||||||
| Oil - % of Brent: | 96% - 99% | 96% - 99% | |||||||||||||||
| NGL - % of Brent: | 45% - 50% | 45% - 50% | |||||||||||||||
| Natural Gas - % of NYMEX: | 140% - 160% | 140% - 160% | |||||||||||||||
See Attachment 2 for management's disclosure of its use of these non-GAAP measures and how these measures provide useful information to investors about CRC's results of operations and financial condition. CRC has supplemented its non-GAAP measures of consolidated free cash flow with free cash flow from CRC's exploration and production and corporate items (free cash flow from E&P, Corporate & Other) which CRC believes is a useful measure for investors to understand the results of its core oil and gas business. CRC defines free cash flow from E&P, Corporate & Other as consolidated free cash flow less free cash flow attributable to CMB.
ESTIMATED FREE CASH FLOW RECONCILIATION
| 2023 Estimated | |||||||||||||||||||||||||||||||||||
| Consolidated | CMB | E&P, Corporate & Other | |||||||||||||||||||||||||||||||||
| ($ millions) | Low | High | Low | High | Low | High | |||||||||||||||||||||||||||||
| Net cash provided (used) by operating activities | $ | 625 | $ | 660 | $ | (55) | $ | (45) | $ | 680 | $ | 705 | |||||||||||||||||||||||
| Capital investments | (245) | (200) | (15) | (5) | (230) | (195) | |||||||||||||||||||||||||||||
| Estimated free cash flow | $ | 380 | $ | 460 | $ | (70) | $ | (50) | $ | 450 | $ | 510 | |||||||||||||||||||||||
| Adjustments to capital investments: | |||||||||||||||||||||||||||||||||||
| Replacement water facilities | (10) | (10) | 10 | 10 | |||||||||||||||||||||||||||||||
Adjusted capital investments(3) | $(25) | $(15) | $(220) | $(185) | |||||||||||||||||||||||||||||||
| Net cash provided (used) by operating activities | $ | (55) | $ | (45) | $ | 680 | $ | 705 | |||||||||||||||||||||||||||
| Adjusted capital investments | (25) | (15) | (220) | (185) | |||||||||||||||||||||||||||||||
| Estimated adjusted free cash flow | $ | (80) | $ | (60) | $ | 460 | $ | 520 | |||||||||||||||||||||||||||
Page 23
| 3Q23 Estimated | |||||||||||||||||||||||||||||||||||
| Consolidated | CMB | E&P, Corporate & Other | |||||||||||||||||||||||||||||||||
| ($ millions) | Low | High | Low | High | Low | High | |||||||||||||||||||||||||||||
| Net cash provided (used) by operating activities | $ | 92 | $ | 96 | $ | (13) | $ | (9) | $ | 105 | $ | 105 | |||||||||||||||||||||||
| Capital investments | (62) | (46) | (1) | — | (61) | (46) | |||||||||||||||||||||||||||||
| Estimated free cash flow | $ | 30 | $ | 50 | $ | (14) | $ | (9) | $ | 44 | $ | 59 | |||||||||||||||||||||||
| Adjustments to capital investments: | |||||||||||||||||||||||||||||||||||
| Replacement water facilities | (1) | (1) | 1 | 1 | |||||||||||||||||||||||||||||||
Adjusted capital investments(3) | $(2) | $(1) | $(60) | $(45) | |||||||||||||||||||||||||||||||
| Net cash provided (used) by operating activities | $ | (13) | $ | (9) | $ | 105 | $ | 105 | |||||||||||||||||||||||||||
| Adjusted capital investments | (2) | (1) | (60) | (45) | |||||||||||||||||||||||||||||||
| Estimated adjusted free cash flow | $ | (15) | $ | (10) | $ | 45 | $ | 60 | |||||||||||||||||||||||||||
ESTIMATED ADJUSTED GENERAL AND ADMINISTRATIVE EXPENSES RECONCILIATION
| 2023 Estimated | |||||||||||||||||||||||||||||||||||
| Consolidated | CMB | E&P, Corporate & Other | |||||||||||||||||||||||||||||||||
| ($ millions) | Low | High | Low | High | Low | High | |||||||||||||||||||||||||||||
| General and administrative expenses | $ | 235 | $ | 250 | $ | 10 | $ | 15 | $ | 225 | $ | 235 | |||||||||||||||||||||||
| Equity-settled stock-based compensation | (25) | (15) | (25) | (15) | |||||||||||||||||||||||||||||||
| Other | (15) | (10) | (15) | (10) | |||||||||||||||||||||||||||||||
| Estimated adjusted general and administrative expenses | $ | 195 | $ | 225 | $ | 10 | $ | 15 | $ | 185 | $ | 210 | |||||||||||||||||||||||
| 3Q23 Estimated | |||||||||||||||||||||||||||||||||||
| Consolidated | CMB | E&P, Corporate & Other | |||||||||||||||||||||||||||||||||
| ($ millions) | Low | High | Low | High | Low | High | |||||||||||||||||||||||||||||
| General and administrative expenses | $ | 67 | $ | 72 | $ | 2 | $ | 5 | $ | 65 | $ | 67 | |||||||||||||||||||||||
| Equity-settled stock-based compensation | (8) | (6) | (8) | (6) | |||||||||||||||||||||||||||||||
| Other | (7) | (6) | (7) | (6) | |||||||||||||||||||||||||||||||
| Estimated adjusted general and administrative expenses | $ | 52 | $ | 60 | $ | 2 | $ | 5 | $ | 50 | $ | 55 | |||||||||||||||||||||||
(1) Current guidance assumes a 2023 Brent price of $77.54 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $2.87 per mcf and a 3Q23 Brent price of $75.25 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $2.73 per mcf. CRC's share of production under PSC contracts decreases when commodity prices rise and increases when prices fall. | |||||||||||||||||||||||||||||||||||
(2) CMB Expenses includes lease cost for sequestration easements, advocacy, and other startup related costs. | |||||||||||||||||||||||||||||||||||
(3) Adjusted E&P capital investments and Adjusted CMB capital investments are non-GAAP measures. These measures reflect E&P facilities capital for replacement water injection facilities (which will allow CRC's oil and gas operations to divert produced water away from a depleted oil and natural gas reservoir held by the Carbon TerraVault JV) as Adjusted CMB capital investment. Construction of these facilities supports the advancement of CRC’s carbon management business (CMB). CRC has supplemented its non-GAAP financial measure of free cash flow with adjusted free cash flow calculated using adjusted capital investments for its E&P, Corporate & Other. Management believes this is a useful measure for investors to understand the results of the core oil and gas business. CRC defines adjusted free cash flow for E&P, Corporate & Other as consolidated free cash flow less results attributable to its carbon management business. | |||||||||||||||||||||||||||||||||||
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