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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_____________________
FORM 8-K
_____________________
CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Date of report (Date of earliest event reported): November 1, 2023
_____________________
California Resources Corporation
(Exact Name of Registrant as Specified in its Charter)
| | | | | | | | | | | |
| Delaware | 001-36478 | 46-5670947 |
(State or Other Jurisdiction of
Incorporation) | (Commission
File Number) | (IRS Employer
Identification No.) |
| | | |
| 1 World Trade Center | |
| Suite 1500 | |
| Long Beach | |
| California | 90831 |
| (Address of Principal Executive Offices) | (Zip Code) |
Registrant’s Telephone Number, Including Area Code: (888) 848-4754
_____________________
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
☐ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
☐ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
☐ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
☐ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))
Securities registered pursuant to Section 12(b) of the Act:
| | | | | | | | |
| Title of each class | Trading Symbol(s) | Name of each exchange on which registered |
| Common Stock | CRC | New York Stock Exchange |
Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (17 CFR §230.405) or Rule 12b-2 of the Securities Exchange Act of 1934 (17 CFR §240.12b-2).
Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Item 2.02 Results of Operations and Financial Condition.
On November 1, 2023, California Resources Corporation (the “Company”) issued a press release announcing its financial condition and results of operations for the three and nine months ended September 30, 2023. A copy of the press release is furnished as Exhibit 99.1 to this report on Form 8-K, and is incorporated herein by reference.
The information contained in this report and the exhibits hereto shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and shall not be incorporated by reference into any filings made by the Company under the Securities Act of 1933, as amended, or the Exchange Act, except as may be expressly set forth by specific reference in such filing.
Item 9.01 Financial Statements and Exhibits.
(d) Exhibits
| | | | | | | | |
| Exhibit No. | | Description |
| 99.1 | | |
| 104 | | Cover Page Interactive Data File (embedded within the Inline XBRL document). |
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
| | | | | | | | | | | |
| California Resources Corporation |
| | | |
| | | |
| | | |
| /s/ Michael L. Preston | |
| Name: | Michael L. Preston |
| Title: | Executive Vice President, Chief Strategy Officer and General Counsel |
DATED: November 1, 2023
California Resources Corporation Reports Strong Third Quarter 2023 Financial Results, Announces 10% Increase in Quarterly Dividend and Meaningfully Advances its Carbon Management Business
Long Beach, November 1, 2023 - California Resources Corporation (NYSE: CRC), an independent energy and carbon management company committed to energy transition, today reported third quarter 2023 operational and financial results.
"CRC's strong third-quarter performance demonstrates the hard work of our team and the flexibility of the Company's business strategy to create value for shareholders across various fronts. Foundational to this success has been CRC's ability to generate significant free cash flow, meaningfully advance the Company's carbon management business and demonstrate our California advantage," said Francisco Leon, CRC President and Chief Executive Officer. "We are raising our dividend for the third year in a row and have bought back $604 million of stock since the inception of our share repurchase program, and have repurchased $35 million of senior notes year to date. We see a number of new and exciting developments for CRC as we continue to build a different kind of energy company."
Primary Highlights
•Generated net cash provided by operating activities of $104 million or $129 million of net cash provided by operating activities before changes in operating assets and liabilities, net1, and delivered $71 million of free cash flow1 during the third quarter
•Generated net cash provided by operating activities of $522 million and delivered $403 million of free cash flow1 year to date
•Returned approximately 52% or $207 million of its free cash flow1 generated year to date to CRC's stakeholders, including $143 million in share repurchases, $5 million in debt repurchases (excluding an additional $30 million of post 3Q repurchases) and $59 million in dividends
•Increased CRC's quarterly dividend by 10% to $0.31 per share payable on December 15, 2023, to shareholders of record on December 1, 2023
•On path to achieve at least $55 million in annual run rate reductions to operating and overhead costs from CRC's business transformation initiative
•Announcing CTV's first capture to storage project at one of the CRC's gas processing plants, Elk Hills cryogenic gas plant, in Kern County, California. This new project is expected to begin to remove and permanently store 100,000 metric tons per annum (MTPA) of CO2 in the CTV I reservoir by year end 2025
•Signed a storage-only Carbon Dioxide Management Agreement (CDMA)2 with NLC Energy LLC (NLCE) with a minimum volume commitment of 150,000 MTPA of CO2 injection at CTV I reservoir. See CTV's 3Q23 Update for additional information on CMB projects
Quarterly Financial Highlights
•Reported a net loss of $22 million, or $0.32 per diluted share. When adjusted for items analysts typically exclude from estimates (including mark-to-market adjustments of $109 million, and one-time costs of $24 million and adjusting for taxes of $37 million), the Company’s adjusted net income1 was $74 million, or $1.02 per diluted share
•Generated adjusted EBITDAX1 of $187 million
•Ended the quarter with $479 million of cash and cash equivalents, an undrawn Revolving Credit Facility and $958 million of total liquidity3
Quarterly Operational Highlights
•Reservoirs performed in line with expectations; total daily gross production of 101,000 gross barrels of oil equivalent per day (Boe/d) during the third quarter
•Produced an average of 85,000 net Boe/d, including 51,000 net barrels of oil per day (MBo/d), with $24 million of drilling and workover capital during the third quarter
•Third quarter average daily net oil production includes a negative impact of 1 net MBo/d related to CRC's production-sharing contracts (PSCs) at the Wilmington field
•Quarter over quarter, operating costs of $24.96 per Boe increased $1.25 per Boe primarily due to higher energy operating costs as electricity and natural gas prices in California markets increased between quarters
•Operated 1 drilling rig in the LA Basin; drilled 9 wells and brought 8 wells online during the third quarter
•Operated 31 maintenance rigs in the third quarter
Total Year 2023 Guidance and Capital Program4
CRC is narrowing its guidance range for average daily total net production from 85 to 91 Mboe/d4 to 85 and 87 MBoe/d4 (~60 % oil) for the full year 2023 to reflect the previously announced and anticipated 5% to 7% entry to exit decline in production.
The Company is lowering its guidance range for the 2023 capital program from $200 to $245 million to $185 to $210 million due to the timing of projects and the availability of permits. The program includes $180 to $200 million of adjusted E&P, corporate and other adjusted capital5 and $5 to $10 million of adjusted CMB capital5 for carbon management projects. On average for 2023, CRC plans to execute a 1 to 1.5 rig development program. Activity will focus on drilling new locations where CRC has permits and high return workovers. The capital plan also includes procuring critical components for planned maintenance of power and gas processing facilities in 2024 as well as incremental spending to advance CRC's carbon management business.
CRC increased its guidance for natural gas marketing margin for the full year 2023 from $135 to $150 million to $155 to $185 million range to reflect the Company's performance through the first three quarters of the year. The Company also narrowed its 2023 guidance for net electricity margin to $80 to $110 million and narrowed the range for taxes other than on income to $170 to $180 million. CRC's transportation expense guidance increased $10 million to a range of $60 to $80 million. Similarly, CRC's 2023 commodity realizations guidance were adjusted to reflect the Company's expected results.
CRC anticipates additional investment for subsurface land easements during the fourth quarter of 2023 to expand its carbon management business and has increased its guidance for CMB adjusted free cash flow1 for the full year 2023 from ($60) to ($80) million to ($70) to ($90) million. Additionally, CRC's E&P, Corporate and Other free cash flow1 guidance was narrowed from $460 to $520 million to $470 to $510 million. As a result, CRC narrowed its total 2023 free cash flow1 guidance from $380 to $460 million to $380 to $440 million. See Attachment 2 for further information on CRC's total year 2023 guidance.
Fourth Quarter 2023 Guidance and Capital Program4
CRC expects its fourth quarter 2023 total capital to range between $70 to $76 million under current operating conditions. This includes $5 to $10 million of adjusted CMB capital5 as well as procuring critical components for planned maintenance at a power plant and a gas processing facility at Elk Hills in 2024.
At this level of spending, CRC expects average net total production between 82 and 85 net MBoe/d4 (~60% oil) in the fourth quarter of 2023, running a 1 drilling rig program in the Los Angeles basin. See Attachment 2 for further information on CRC's 4Q23 guidance.
During the fourth quarter of 2023, CRC expects to invest approximately $10 to $20 million for additional land easements to expand its carbon management business.
Third Quarter Financial Results
| | | | | | | | | | | | | | | | | | | | |
| Selected Production, Price Information and Results of Operations | 3rd Quarter | | | 2nd Quarter | | | | | | |
| ($ in millions) | 2023 | | | 2023 | | | | | | |
| | | | | | | | | | |
| Average net oil production per day (MBbl/d) | 85 | | | | 86 | | | | | | | |
| Realized oil price with derivative settlements ($ per Bbl) | $ | 66.12 | | | | $ | 63.66 | | | | | | | |
| Average net NGL production per day (MBbl/d) | 11 | | | | 11 | | | | | | | |
| Realized NGL price ($ per Bbl) | $ | 44.95 | | | | $ | 42.48 | | | | | | | |
| Average net natural gas production per day (Mmcf/d) | 138 | | | | 135 | | | | | | | |
| Realized natural gas price with derivative settlements ($ per Mcf) | $ | 4.83 | | | | $ | 3.46 | | | | | | | |
| Average net total production per day (MBoe/d) | 85 | | | | 86 | | | | | | | |
| | | | | | | | | | |
| Margin from marketing purchased natural gas ($ millions) | $ | 47 | | | | $ | 45 | | | | | | | |
| Margin from electricity sales ($ millions) | $ | 44 | | | | $ | 21 | | | | | | | |
| Net (loss) gain from commodity derivatives ($ millions) | $ | (204) | | | | $ | 31 | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| Selected Financial Statement Data and non-GAAP measures: | 3rd Quarter | | | 2nd Quarter | | | | | | |
| ($ and shares in millions, except per share amounts) | 2023 | | | 2023 | | | | | | |
| | | | | | | | | | |
| Statements of Operations: | | | | | | | | | | |
| Revenues | | | | | | | | | | |
| Total operating revenues | $ | 460 | | | | $ | 591 | | | | | | | |
| | | | | | | | | | |
| Selected Expenses | | | | | | | | | | |
| Operating costs | $ | 196 | | | | $ | 186 | | | | | | | |
General and administrative expenses1 | $ | 65 | | | | $ | 71 | | | | | | | |
Adjusted general and administrative expenses1 | $ | 51 | | | | $ | 57 | | | | | | | |
| Taxes other than on income | $ | 48 | | | | $ | 42 | | | | | | | |
| Transportation costs | $ | 16 | | | | $ | 16 | | | | | | | |
| Exploration expense | $ | — | | | | $ | 1 | | | | | | | |
| Operating (loss) Income | $ | (15) | | | | $ | 147 | | | | | | | |
| Interest and debt expense | $ | (15) | | | | $ | (14) | | | | | | | |
| Income tax (benefit) provision | $ | 8 | | | | $ | (38) | | | | | | | |
| Deferred income tax (benefit) provision | $ | (40) | | | | $ | 9 | | | | | | | |
| Net (loss) Income | $ | (22) | | | | $ | 97 | | | | | | | |
| | | | | | | | | | |
Adjusted net income1 | $ | 74 | | | | $ | 38 | | | | | | | |
| Weighted-average common shares outstanding - diluted | 68.7 | | | | 71.9 | | | | | | | |
| Net (loss) income per share - diluted | $ | (0.32) | | | | $ | 1.35 | | | | | | | |
Adjusted net income1 per share - diluted | $ | 1.02 | | | | $ | 0.53 | | | | | | | |
Adjusted EBITDAX1 | $ | 187 | | | | $ | 138 | | | | | | | |
Net cash provided by operating activities before changes in operating assets and liabilities, net1 | $ | 129 | | | | $ | 98 | | | | | | | |
| Net cash provided by operating activities | $ | 104 | | | | $ | 108 | | | | | | | |
| Capital investments | $ | 33 | | | | $ | 39 | | | | | | | |
Free cash flow1 | $ | 71 | | | | $ | 69 | | | | | | | |
| Cash and cash equivalents | $ | 479 | | | | $ | 448 | | | | | | | |
Balance Sheet and Liquidity Update
The aggregate commitment under CRC's Revolving Credit Facility was $627 million as of September 30, 2023. On October 30, 2023, the borrowing base for the Revolving Credit Facility was reaffirmed at $1.2 billion as part of CRC's semi-annual redetermination and the aggregate commitment amount increased to $630 million.
As of September 30, 2023, CRC had liquidity of $958 million, which consisted of $479 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).
Reorganization
In August 2023, CRC implemented organizational changes that resulted in a headcount reduction of 75 employees. These actions were taken to better align CRC's resources to its strategic priorities and improve its operational efficiency. As a result, CRC recognized a charge of $7 million in other operating expenses, net for the three months ended September 30, 2023, primarily related to severance benefits. For the nine months ended September 30, 2023, CRC recognized a severance charge of $10 million. CRC expects these actions, along with other initiatives taken to streamline its operations, to result in at least $55 million of savings in operating and overhead costs on an annualized basis.
Shareholder Return and Deleveraging 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, share repurchases and debt repurchases.
On November 1, 2023, CRC's Board of Directors declared a quarterly cash dividend of $0.31 per share of common stock. The dividend is payable to shareholders of record at the close of business on December 1, 2023 and is expected to be paid on December 15, 2023.
During the third quarter of 2023, CRC repurchased 0.4 million shares for approximately $20 million at an average price of $54.75 per share. Since the inception of the Share Repurchase Program in May 2021 through September 30, 2023, 14,863,915 shares have been repurchased for $604 million at an average price of $40.53 per share, including commissions and excise taxes. These total repurchases represent ~18% of CRC’s shares outstanding since December 31, 2020.
CRC repurchased $5 million in face value of its senior notes at par in the third quarter and an additional $30 million of its senior notes at an average price of 100.50% of par in October 2023. After these repurchases, the remaining principal amount of CRC’s senior notes is $565 million due February 1, 2026.
CRC has returned $739 million of cash to its stakeholders, including $604 million in share repurchases, $5 million in debt repurchases and $132 million of dividends since December 31st, 2020, through September 30, 2023. These figures exclude $30 million of senior notes repurchased subsequent to quarter end and $21 million of dividends expected to be paid on December 15, 2023.
Upcoming Investor Conference Participation
CRC's executives will be participating in the following events:
•Bank of America Energy Conference on November 14 and 15 in Houston, TX
•Mizuho Energy & Infrastructure Conference on November 27 to 29 in New York City, NY
•Stone X Natural Resource Day on December 7 in New York City, NY
•Goldman Sachs Global Energy and Clean Tech Conference on January 3 to 5 in Miami, FL
•UBS Global Energy and Utilities Conference on January 8 to 10 in Park City, UT
•TD Global Energy Conference on January 8 to 10 in London, UK
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
To participate in the conference call scheduled for November 2, 2023, at 1:00 p.m. Eastern Time, please dial (877) 315-5411 (International calls please dial +1 (412) 902-6739) 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/10182061/fa45058ce0. 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 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, free cash flow, adjusted free cash flow, adjusted G&A and adjusted 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 3.
2 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.
3 Calculated as $479 million of available cash plus $627 million of capacity on CRC's Revolving Credit Facility less $148 million in outstanding letters of credit.
4 Current guidance assumes a 2023 Brent price of $84.16 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $2.77 per mcf and a 4Q23 Brent price of $90.46 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $3.00 per mcf. CRC's share of production under PSC contracts decreases when commodity prices rise and increases when prices fall.
5 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 4Q23 estimates of the non-GAAP measure of free cash flow, including reconciliations to their most directly comparable GAAP measure, see Attachment 2.
6 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:
•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 wars in Ukraine and Israel 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;
•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 Joanna.Park@crc.com | Richard Venn (Media) 818-661-6014 Richard.Venn@crc.com |
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| Attachment 1 |
| SUMMARY OF RESULTS | | | | | | | | | | |
| | | | | | | | | | |
| 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | | Nine Months | | Nine Months |
| ($ and shares in millions, except per share amounts) | 2023 | | 2023 | | 2022 | | | 2023 | | 2022 |
| | | | | | | | | | |
| Statements of Operations: | | | | | | | | | | |
| Revenues | | | | | | | | | | |
| Oil, natural gas and NGL sales | $ | 510 | | | $ | 447 | | | $ | 680 | | | | $ | 1,672 | | | $ | 2,026 | |
| Net (loss) gain from commodity derivatives | (204) | | | 31 | | | 243 | | | | (131) | | | (419) | |
| Marketing of purchased natural gas | 78 | | | 72 | | | 113 | | | | 334 | | | 220 | |
| Electricity sales | 67 | | | 34 | | | 88 | | | | 169 | | | 171 | |
| Other revenue | 9 | | | 7 | | | 1 | | | | 31 | | | 27 | |
| Total operating revenues | 460 | | | 591 | | | 1,125 | | | | 2,075 | | | 2,025 | |
| | | | | | | | | | |
| Operating Expenses | | | | | | | | | | |
| Operating costs | 196 | | | 186 | | | 214 | | | | 636 | | | 586 | |
| General and administrative expenses | 65 | | | 71 | | | 59 | | | | 201 | | | 163 | |
| Depreciation, depletion and amortization | 56 | | | 56 | | | 50 | | | | 170 | | | 149 | |
| Asset impairment | — | | | — | | | — | | | | 3 | | | 2 | |
| Taxes other than on income | 48 | | | 42 | | | 44 | | | | 132 | | | 120 | |
| Exploration expense | — | | | 1 | | | 1 | | | | 2 | | | 3 | |
| Purchased natural gas marketing expense | 31 | | | 27 | | | 98 | | | | 182 | | | 186 | |
| Electricity generation expenses | 23 | | | 13 | | | 42 | | | | 85 | | | 99 | |
| Transportation costs | 16 | | | 16 | | | 13 | | | | 49 | | | 37 | |
| Accretion expense | 12 | | | 11 | | | 10 | | | | 35 | | | 32 | |
| Other operating expenses, net | 28 | | | 21 | | | 5 | | | | 62 | | | 28 | |
| Total operating expenses | 475 | | | 444 | | | 536 | | | | 1,557 | | | 1,405 | |
| Net gain on asset divestitures | — | | | — | | | 2 | | | | 7 | | | 60 | |
| Operating (Loss) Income | (15) | | | 147 | | | 591 | | | | 525 | | | 680 | |
| | | | | | | | | | |
| Non-Operating (Expenses) Income | | | | | | | | | | |
| | | | | | | | | | |
| Interest and debt expense | (15) | | | (14) | | | (13) | | | | (43) | | | (39) | |
| Loss from investment in unconsolidated subsidiary | (3) | | | (1) | | | — | | | | (6) | | | — | |
| | | | | | | | | | |
| Other non-operating income, net | 3 | | | 3 | | | 1 | | | | 5 | | | 3 | |
| | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (Loss) Income Before Income Taxes | (30) | | | 135 | | | 579 | | | | 481 | | | 644 | |
| Income tax benefit (provision) | 8 | | | (38) | | | (153) | | | | (105) | | | (203) | |
| Net (Loss) income | $ | (22) | | | $ | 97 | | | $ | 426 | | | | $ | 376 | | | $ | 441 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| Net (loss) income per share - basic | $ | (0.32) | | | $ | 1.39 | | | $ | 5.75 | | | | $ | 5.38 | | | $ | 5.77 | |
| Net (loss) income per share - diluted | $ | (0.32) | | | $ | 1.35 | | | $ | 5.58 | | | | $ | 5.18 | | | $ | 5.62 | |
| | | | | | | | | | |
| Adjusted net income | $ | 74 | | | $ | 38 | | | $ | 111 | | | | $ | 305 | | | $ | 291 | |
| Adjusted net income per share - basic | $ | 1.08 | | | $ | 0.55 | | | $ | 1.50 | | | | $ | 4.36 | | | $ | 3.81 | |
| Adjusted net income per share - diluted | $ | 1.02 | | | $ | 0.53 | | | $ | 1.45 | | | | $ | 4.20 | | | $ | 3.71 | |
| | | | | | | | | | |
| Weighted-average common shares outstanding - basic | 68.7 | | | 69.7 | | | 74.1 | | | | 69.9 | | | 76.4 | |
| Weighted-average common shares outstanding - diluted | 68.7 | | | 71.9 | | | 76.3 | | | | 72.6 | | | 78.5 | |
| | | | | | | | | | |
| Adjusted EBITDAX | $ | 187 | | | $ | 138 | | | $ | 234 | | | | $ | 683 | | | $ | 644 | |
| Effective tax rate | 27 | % | | 28 | % | | 26 | % | | | 22 | % | | 32 | % |
| | | | | | | | | | |
| | | | | | | | | | |
|
| 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | | Nine Months | | Nine Months |
| ($ in millions) | 2023 | | 2023 | | 2022 | | | 2023 | | 2022 |
| Cash Flow Data: | | | | | | | | | | |
| Net cash provided by operating activities | $ | 104 | | | $ | 108 | | | $ | 235 | | | | $ | 522 | | | $ | 576 | |
| Net cash used in investing activities | $ | (28) | | | $ | (44) | | | $ | (109) | | | | $ | (133) | | | $ | (238) | |
| Net cash used in financing activities | $ | (45) | | | $ | (93) | | | $ | (92) | | | | $ | (217) | | | $ | (285) | |
| | | | | | | | | | |
| Sept. 30, | | December 31, | | | | | | | |
| ($ in millions) | 2023 | | 2022 | | | | | | | |
| Selected Balance Sheet Data: | | | | | | | | | | |
| Total current assets | $ | 929 | | | $ | 864 | | | | | | | | |
| Property, plant and equipment, net | $ | 2,722 | | | $ | 2,786 | | | | | | | | |
| Deferred tax asset | $ | 150 | | | $ | 164 | | | | | | | | |
| Total current liabilities | $ | 694 | | | $ | 894 | | | | | | | | |
| Long-term debt, net | $ | 589 | | | $ | 592 | | | | | | | | |
| Noncurrent asset retirement obligations | $ | 388 | | | $ | 432 | | | | | | | | |
| Stockholders' Equity | $ | 2,050 | | | $ | 1,864 | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| GAINS AND LOSSES FROM COMMODITY DERIVATIVES | | |
| | | | | | | | |
|
| 3rd Quarter | | 2nd Quarter | | 3rd Quarter | Nine Months | | Nine Months |
| ($ millions) | 2023 | | 2023 | | 2022 | 2023 | | 2022 |
| | | | | | | | |
| Non-cash derivative (loss) gain | $ | (109) | | | $ | 94 | | | $ | 425 | | $ | 92 | | | $ | 185 | |
| | | | | | | | |
| | | | | | | | |
| Net payments on settled commodity derivatives | (95) | | | (63) | | | (182) | | (223) | | | (604) | |
| Net gain (loss) from commodity derivatives | $ | (204) | | | $ | 31 | | | $ | 243 | | $ | (131) | | | $ | (419) | |
| | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | 1st Quarter | | | 1st Quarter | | 4th Quarter | | 4th Quarter | | | 4th Quarter | |
| | | | | | | | | | | | | |
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| | | | | | | | | | | | | |
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| CAPITAL INVESTMENTS | | | | |
| | | | | | | | | |
|
| 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | Nine Months | | Nine Months |
| ($ millions) | 2023 | | 2023 | | 2022 | | 2023 | | 2022 |
| | | | | | | | | |
Facilities (1) | $ | 7 | | | $ | 11 | | | $ | 20 | | | $ | 27 | | | $ | 52 | |
| Drilling | 13 | | | 13 | | | 73 | | | 51 | | | 194 | |
| Workovers | 11 | | | 11 | | | 7 | | | 28 | | | 22 | |
| Total E&P capital | 31 | | | 35 | | | 100 | | | 106 | | | 268 | |
CMB (1) | — | | | — | | | 6 | | | 1 | | | 17 | |
| Corporate and other | 2 | | | 4 | | | 1 | | | 12 | | | 19 | |
| Total capital program | $ | 33 | | | $ | 39 | | | $ | 107 | | | $ | 119 | | | $ | 304 | |
| | | | | | | | | |
(1) Facilities capital includes $1 million, $1 million and $4 million in the third and second quarter of 2023 and third quarter of 2022, respectively, to build replacement water injection facilities which will allow CRC to divert produced water away from a depleted oil and natural gas reservoir held by the Carbon TerraVault JV. Construction of these facilities supports the advancement of CRC’s carbon management business and CRC reported these amounts as part of adjusted CMB capital in this Earnings Release. Where adjusted CMB capital is presented, CRC removed the amounts from facilities capital and presented adjusted E&P, Corporate and Other capital. |
|
| | | | | | | | | | | | | | | | | |
| | | | | Attachment 2 |
| 2023 Estimated |
TOTAL CRC GUIDANCE1 | Consolidated | | CMB | | E&P, Corporate & Other |
| Net Total Production (MBoe/d) | 85 - 87 | | | | 85 - 87 |
| Net Oil Production (MBbl/d) | 51 - 53 | | | | 51 - 53 |
| Operating Costs ($ millions) | $815 - $850 | | | | $815 - $850 |
CMB Expenses2 ($ millions) | $40 - $50 | | $40 - $50 | | |
Adjusted General and Administrative Expenses1 ($ millions) | $195 - $225 | | $10 - $15 | | $185 - $210 |
| | | | | |
| Capital ($ millions) | $185 - $210 | | $1 - $6 | | $184 - $204 |
Adjusted Capital3 ($ millions) | | | $5 - $10 | | $180 - $200 |
Free Cash Flow3 ($ millions) | $380 - $440 | | ($66) - ($86) | | $466 - $506 |
Adjusted Free Cash Flow3 ($ millions) | | | ($70) - ($90) | | $470 - $510 |
| | | | | |
| Natural Gas Marketing Margin ($ millions) | $155 - $185 | | | | $155 - $185 |
| Electricity Margin ($ millions) | $80 - $110 | | | | $80 - $110 |
| Transportation Expense ($ millions) | $60 - $80 | | | | $60 - $80 |
| ARO Settlement Payments ($ millions) | $55 - $60 | | | | $55 - $60 |
| Taxes Other Than on Income ($ millions) | $170 - $180 | | | | $170 - $180 |
| Interest and Debt Expense ($ millions) | $55 - $60 | | $5 - $6 | | $50 - $54 |
| Cash Income Taxes ($ millions) | $100 - $120 | | | | $100 - $120 |
| | | | | |
| Commodity Realizations: | | | | | |
| Oil - % of Brent: | 94% - 97% | | | | 94% - 97% |
| NGL - % of Brent: | 56% - 60% | | | | 56% - 60% |
| Natural Gas - % of NYMEX*: | 275% - 325% | | | | 275% - 325% |
|
| | | | | | | | | | | | | | | | | |
| | | | | |
CRC GUIDANCE3 | Total
4Q23E | | CMB
4Q23E | | E&P, Corp. & Other 4Q23E |
| Net Total Production (MBoe/d) | 82 - 85 | | | | 82 - 85 |
| Net Oil Production (MBbl/d) | 49 - 51 | | | | 49 - 51 |
| Operating Costs ($ millions) | $185 - $195 | | | | $185 - $195 |
CMB Expenses2 ($ millions) | $10 - $20 | | $10 - $20 | | |
Adjusted General and Administrative Expenses1 ($ millions) | $51 - $58 | | $1 - $2 | | $50 - $56 |
| Capital ($ millions) | $65 - $81 | | $4 - $9 | | $61 - $72 |
Adjusted Capital3 ($ millions) | | | $5 - $10 | | $60 - $71 |
Free Cash Flow3 ($ millions) | ($5) - $30 | | ($44) - ($54) | | $49 - $74 |
Adjusted Free Cash Flow3 ($ millions) | | | ($45) - ($55) | | $50 - $75 |
| | | | | |
| Natural Gas Marketing Margin ($ millions) | $20 - $30 | | | | $20 - $30 |
| Electricity Margin ($ millions) | $10 - $15 | | | | $10 - $15 |
| Transportation Expense ($ millions) | $15 - $19 | | | | $15 - $19 |
| Cash Income Taxes ($ millions) | $25 - $35 | | | | $25 - $35 |
| | | | | |
| Commodity Realizations: | | | | | |
| Oil - % of Brent: | 96% - 99% | | | | 96% - 99% |
| NGL - % of Brent: | 50% - 60% | | | | 50% - 60% |
| Natural Gas - % of NYMEX: | 165% - 185% | | | | 165% - 185% |
See Attachment 3 for management's disclosure of its use of these non-GAAP measures and how these measures provide useful information to investors about CRC's results of operations and financial condition. CRC has supplemented its non-GAAP measures of consolidated free cash flow with free cash flow from CRC's exploration and production and corporate items (free cash flow from E&P, Corporate & Other) which CRC believes is a useful measure for investors to understand the results of its core oil and gas business. CRC defines free cash flow from E&P, Corporate & Other as consolidated free cash flow less free cash flow attributable to CMB.
ESTIMATED FREE CASH FLOW RECONCILIATION
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2023 Estimated |
| Consolidated | | CMB | | E&P, Corporate & Other |
| ($ millions) | Low | | High | | Low | | High | | Low | | High |
| Net cash provided (used) by operating activities | $ | 590 | | | $ | 625 | | | $ | (80) | | | $ | (65) | | | $ | 670 | | | $ | 690 | |
| Capital investments | (210) | | | (185) | | | (6) | | | (1) | | | (204) | | | (184) | |
| Estimated free cash flow | $ | 380 | | | $ | 440 | | | $ | (86) | | | $ | (66) | | | $ | 466 | | | $ | 506 | |
| | | | | | | | | | | |
| Adjustments to capital investments: | | | | | | | | | | | |
| Replacement water facilities | | | | | (4) | | (4) | | 4 | | 4 |
Adjusted capital investments(3) | | | | | $(10) | | $(5) | | $(200) | | $(180) |
| | | | | | | | | | | |
| Net cash provided (used) by operating activities | | | | | $ | (80) | | | $ | (65) | | | $ | 670 | | | $ | 690 | |
| Adjusted capital investments | | | | | (10) | | | (5) | | | (200) | | | (180) | |
| Estimated adjusted free cash flow | | | | | $ | (90) | | | $ | (70) | | | $ | 470 | | | $ | 510 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 4Q23 Estimated |
| Consolidated | | CMB | | E&P, Corporate & Other |
| ($ millions) | Low | | High | | Low | | High | | Low | | High |
| Net cash provided (used) by operating activities | $ | 76 | | | $ | 95 | | | $ | (45) | | | $ | (40) | | | $ | 121 | | | $ | 135 | |
| Capital investments | (81) | | | (65) | | | (9) | | | (4) | | | (72) | | | (61) | |
| Estimated free cash flow | $ | (5) | | | $ | 30 | | | $ | (54) | | | $ | (44) | | | $ | 49 | | | $ | 74 | |
| | | | | | | | | | | |
| Adjustments to capital investments: | | | | | | | | | | | |
| Replacement water facilities | | | | | (1) | | (1) | | 1 | | 1 |
Adjusted capital investments(3) | | | | | $(10) | | $(5) | | $(71) | | $(60) |
| | | | | | | | | | | |
| Net cash provided (used) by operating activities | | | | | $ | (45) | | | $ | (40) | | | $ | 121 | | | $ | 135 | |
| Adjusted capital investments | | | | | (10) | | | (5) | | | (71) | | | (60) | |
| Estimated adjusted free cash flow | | | | | $ | (55) | | | $ | (45) | | | $ | 50 | | | $ | 75 | |
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 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| 4Q23 Estimated |
| Consolidated | | CMB | | E&P, Corporate & Other |
| ($ millions) | Low | | High | | Low | | High | | Low | | High |
| General and administrative expenses | $ | 64 | | | $ | 72 | | | $ | 1 | | | $ | 2 | | | $ | 63 | | | $ | 70 | |
| Equity-settled stock-based compensation | (8) | | | (6) | | | | | | | (8) | | | (6) | |
| Other | (5) | | | (8) | | | | | | | (5) | | | (8) | |
| Estimated adjusted general and administrative expenses | $ | 51 | | | $ | 58 | | | $ | 1 | | | $ | 2 | | | $ | 50 | | | $ | 56 | |
| | | | | | | | | | | |
(1) Current guidance assumes a 2023 Brent price of $84.16 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $2.77 per mcf and a 4Q23 Brent price of $90.46 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $3.00 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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| 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. | |
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| ADJUSTED NET INCOME (LOSS) | | | | | | | | | | | |
|
| Adjusted net income (loss) and adjusted net income (loss) per share are non-GAAP measures. CRC defines adjusted net income as net income excluding the effects of significant transactions and events that affect earnings but vary widely and unpredictably in nature, timing and amount. These events may recur, even across successive reporting periods. Management believes these non-GAAP measures provide useful information to the industry and the investment community interested in comparing CRC's financial performance between periods. Reported earnings are considered representative of management's performance over the long term. Adjusted net income (loss) is not considered to be an alternative to net income (loss) reported in accordance with GAAP. The following table presents a reconciliation of the GAAP financial measure of net income and net income attributable to common stock per share to the non-GAAP financial measure of adjusted net income and adjusted net income per share. | |
| | | | | |
| | 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | Nine Months | | Nine Months | |
| ($ millions, except per share amounts) | | 2023 | | 2023 | | 2022 | | 2023 | | 2022 | |
| Net (loss) income | | $ | (22) | | | $ | 97 | | | $ | 426 | | | $ | 376 | | | $ | 441 | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Unusual, infrequent and other items: | | | | | | | | | | | |
| Non-cash derivative loss (gain) | | 109 | | | (94) | | | (425) | | | (92) | | | (185) | | |
| Asset impairment | | — | | | — | | | — | | | 3 | | | 2 | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Severance and termination costs | | 7 | | | 2 | | | — | | | 10 | | | — | | |
| | | | | | | | | | | |
| Net gain on asset divestitures | | — | | | — | | | (2) | | | (7) | | | (60) | | |
| | | | | | | | | | | |
| Other, net | | 17 | | | 10 | | | 4 | | | 30 | | | 7 | | |
| Total unusual, infrequent and other items | | 133 | | | (82) | | | (423) | | | (56) | | | (236) | | |
| Income tax (benefit) provision of adjustments at effective tax rate | | (37) | | | 23 | | | 120 | | | 16 | | | 67 | | |
| Income tax (benefit) provision - out of period | | — | | | — | | | (12) | | | (31) | | | 19 | | |
| | | | | | | | | | | |
| Adjusted net income attributable to common stock | | $ | 74 | | | $ | 38 | | | $ | 111 | | | $ | 305 | | | $ | 291 | | |
| | | | | | | | | | | |
| Net (loss) income per share - basic | | $ | (0.32) | | | $ | 1.39 | | | $ | 5.75 | | | $ | 5.38 | | | $ | 5.77 | | |
| Net (loss) income per share - diluted | | $ | (0.32) | | | $ | 1.35 | | | $ | 5.58 | | | $ | 5.18 | | | $ | 5.62 | | |
| Adjusted net income per share - basic | | $ | 1.08 | | | $ | 0.55 | | | $ | 1.50 | | | $ | 4.36 | | | $ | 3.81 | | |
| Adjusted net income per share - diluted | | $ | 1.02 | | | $ | 0.53 | | | $ | 1.45 | | | $ | 4.20 | | | $ | 3.71 | | |
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| ADJUSTED EBITDAX | | | | | | | | | |
|
CRC defines Adjusted EBITDAX as earnings before interest expense; income taxes; depreciation, depletion and amortization; exploration expense; other unusual, infrequent and out-of-period items; and other non-cash items. CRC believes this measure provides useful information in assessing its financial condition, results of operations and cash flows and is widely used by the industry, the investment community and its lenders. Although this is a non-GAAP measure, the amounts included in the calculation were computed in accordance with GAAP. Certain items excluded from this non-GAAP measure are significant components in understanding and assessing CRC’s financial performance, such as its cost of capital and tax structure, as well as depreciation, depletion and amortization of CRC's assets. This measure should be read in conjunction with the information contained in CRC’s financial statements prepared in accordance with GAAP. A version of Adjusted EBITDAX is a material component of certain of its financial covenants under CRC's Revolving Credit Facility and is provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP.
The following table represents a reconciliation of the GAAP financial measures of net income and net cash provided by operating activities to the non-GAAP financial measure of adjusted EBITDAX. CRC has supplemented its non-GAAP measures of consolidated adjusted EBITDAX with adjusted EBITDAX for its exploration and production and corporate items (Adjusted EBITDAX for E&P, Corporate & Other) which management believes is a useful measure for investors to understand the results of the core oil and gas business. CRC defines adjusted EBITDAX for E&P, Corporate & Other as consolidated adjusted EBITDAX less results attributable to its carbon management business (CMB).
| |
| | | | | | |
| | 3rd Quarter | | 2nd Quarter | | | 3rd Quarter | | Nine Months | | | Nine Months | |
| ($ millions, except per BOE amounts) | | 2023 | | 2023 | | | 2022 | | 2023 | | | 2022 | |
| Net (loss) income | | $ | (22) | | | $ | 97 | | | | $ | 426 | | | $ | 376 | | | | $ | 441 | | |
| Interest and debt expense | | 15 | | | 14 | | | | 13 | | | 43 | | | | 39 | | |
| Depreciation, depletion and amortization | | 56 | | | 56 | | | | 50 | | | 170 | | | | 149 | | |
| Income tax (benefit) provision | | (8) | | | 38 | | | | 153 | | | 105 | | | | 203 | | |
| Exploration expense | | — | | | 1 | | | | 1 | | | 2 | | | | 3 | | |
| Interest income | | (5) | | | (5) | | | | (1) | | | (14) | | | | (1) | | |
Unusual, infrequent and other items (1) | | 133 | | | (82) | | | | (423) | | | (56) | | | | (236) | | |
| Non-cash items | | | | | | | | | | | | | |
| Accretion expense | | 12 | | | 11 | | | | 10 | | | 35 | | | | 32 | | |
| Stock-based compensation | | 6 | | | 8 | | | | 5 | | | 21 | | | | 13 | | |
| Post-retirement medical and pension | | — | | | — | | | | — | | | 1 | | | | 1 | | |
| | | | | | | | | | | | | |
| Adjusted EBITDAX | | $ | 187 | | | $ | 138 | | | | $ | 234 | | | $ | 683 | | | | $ | 644 | | |
| | | | | | | | | | | | | |
| Net cash provided by operating activities | | $ | 104 | | | $ | 108 | | | | $ | 235 | | | $ | 522 | | | | $ | 576 | | |
| Cash interest payments | | 23 | | | 2 | | | | 23 | | | 48 | | | | 48 | | |
| Cash interest received | | (5) | | | (5) | | | | (1) | | | (14) | | | | (1) | | |
| Cash income taxes | | 29 | | | 51 | | | | — | | | 80 | | | | 20 | | |
| Exploration expenditures | | — | | | 1 | | | | 1 | | | 2 | | | | 3 | | |
| Adjustments to changes in operating assets and liabilities | | 36 | | | (19) | | | | (24) | | | 45 | | | | (2) | | |
| | | | | | | | | | | | | |
| Adjusted EBITDAX | | $ | 187 | | | $ | 138 | | | | $ | 234 | | | $ | 683 | | | | $ | 644 | | |
| | | | | | | | | | | | | |
| E&P, Corporate & Other Adjusted EBITDAX | | $ | 199 | | | $ | 151 | | | | $ | 239 | | | $ | 717 | | | | $ | 656 | | |
| CMB Adjusted EBITDAX | | $ | (12) | | | $ | (13) | | | | $ | (5) | | | $ | (34) | | | | $ | (12) | | |
| | | | | | | | | | | | | |
| Adjusted EBITDAX per Boe | | $ | 23.81 | | | $ | 17.59 | | | | $ | 27.63 | | | $ | 28.78 | | | | $ | 26.06 | | |
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(1) See Adjusted Net Income (Loss) reconciliation. | | | | | | | | | | |
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| FREE CASH FLOW AND SUPPLEMENTAL FREE 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) 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 net cash provided by operating activities less adjusted capital investments. |
| | | | | | | | | | |
| | 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | Nine Months | | Nine Months |
| ($ millions) | | 2023 | | 2023 | | 2022 | | 2023 | | 2022 |
| | | | | | | | | | |
| Net cash provided by operating activities before changes in operating assets and liabilities, net | | $ | 129 | | | $ | 98 | | | $ | 201 | | | $ | 543 | | | $ | 555 | |
| Changes in operating assets and liabilities, net | | (25) | | | 10 | | | 34 | | | (21) | | | 21 | |
| Net cash provided by operating activities | | 104 | | | 108 | | | 235 | | | 522 | | | 576 | |
| Capital investments | | (33) | | | (39) | | | (107) | | | (119) | | | (304) | |
| Free cash flow | | $ | 71 | | | $ | 69 | | | $ | 128 | | | $ | 403 | | | $ | 272 | |
| | | | | | | | | | |
| E&P, Corporate and Other | | $ | 79 | | | $ | 78 | | | $ | 139 | | | $ | 427 | | | $ | 301 | |
| CMB | | $ | (8) | | | $ | (9) | | | $ | (11) | | | $ | (24) | | | $ | (29) | |
| | | | | | | | | | |
| Adjustments to capital investments: | | | | | | | | | | |
Replacement water facilities(1) | | $ | 1 | | | $ | 1 | | | $ | 4 | | | $ | 3 | | | $ | 9 | |
| Adjusted capital investments: | | | | | | | | | | |
| E&P, Corporate and Other | | $ | 32 | | | $ | 38 | | | $ | 97 | | | $ | 115 | | | $ | 278 | |
| CMB | | $ | 1 | | | $ | 1 | | | $ | 10 | | | $ | 4 | | | $ | 26 | |
| | | | | | | | | | |
| Adjusted free cash flow: | | | | | | | | | | |
|
| E&P, Corporate and Other | | $ | 80 | | | $ | 79 | | | $ | 143 | | | $ | 430 | | | $ | 310 | |
| CMB | | $ | (9) | | | $ | (10) | | | $ | (15) | | | $ | (27) | | | $ | (38) | |
| | | | | | | | | | |
(1) Facilities capital includes $1 million, $1 million and $4 million in the third and second quarter of 2023 and third quarter of 2022, respectively, to build replacement water injection facilities which will allow CRC to divert produced water away from a depleted oil and natural gas reservoir held by the Carbon TerraVault JV. Construction of these facilities supports the advancement of CRC’s carbon management business and CRC reported these amounts as part of adjusted CMB capital in this press release. Where adjusted CMB capital is presented, CRC removed the amounts from facilities capital and presented adjusted E&P, Corporate and Other capital.
|
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| ADJUSTED GENERAL & ADMINISTRATIVE EXPENSES | |
| | | | | | | | | | | |
Management uses a measure called adjusted general and administrative (G&A) expenses to provide useful information to investors interested in comparing CRC's costs between periods and performance to our peers. CRC supplemented its non-GAAP measure of adjusted general and administrative expenses with adjusted general and administrative expenses of its exploration and production and corporate items (adjusted general & administrative expenses for E&P, Corporate & Other) which it believes is a useful measure for investors to understand the results or CRC's core oil and gas business. CRC defines adjusted general & administrative Expenses for E&P, Corporate & Other as consolidated adjusted general and administrative expenses less results attributable to its carbon management business (CMB). | |
| | | | | | | | | | | |
| | 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | Nine Months | | Nine Months | |
| ($ millions) | | 2023 | | 2023 | | 2022 | | 2023 | | 2022 | |
| General and administrative expenses | | $ | 65 | | | $ | 71 | | | $ | 59 | | | $ | 201 | | | $ | 163 | | |
| Stock-based compensation | | (6) | | | (8) | | | (5) | | | (21) | | | (13) | | |
| Information technology infrastructure | | (6) | | | (5) | | | (1) | | | (13) | | | (2) | | |
| Other | | (2) | | | (1) | | | — | | | (4) | | | — | | |
| Adjusted G&A expenses | | $ | 51 | | | $ | 57 | | | $ | 53 | | | $ | 163 | | | $ | 148 | | |
| | | | | | | | | | | |
| E&P, Corporate and Other adjusted G&A expenses | | $ | 47 | | | $ | 54 | | | $ | 48 | | | $ | 153 | | | $ | 138 | | |
| CMB adjusted G&A expenses | | $ | 4 | | | $ | 3 | | | $ | 5 | | | $ | 10 | | | $ | 10 | | |
| | | | | | | | | | | |
| OPERATING COSTS PER BOE | |
| | | | | | | | | | | |
| The reporting of PSC-type contracts creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only CRC's net share, inflating the per barrel operating costs. The following table presents operating costs after adjusting for the excess costs attributable to PSCs. | |
| | | | | | | | | | | |
| | 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | Nine Months | | Nine Months | |
| ($ per BOE) | | 2023 | | 2023 | | 2022 | | 2023 | | 2022 | |
Energy operating costs (1) | | $ | 9.42 | | | $ | 7.39 | | | $ | 10.96 | | | $ | 10.87 | | | $ | 9.83 | | |
Gas processing costs (2) | | 0.64 | | | 0.64 | | | 0.49 | | | 0.59 | | | 0.53 | | |
| Non-energy operating costs | | 14.90 | | | 15.68 | | | 13.82 | | | 15.34 | | | 13.35 | | |
| Operating costs | | $ | 24.96 | | | $ | 23.71 | | | $ | 25.27 | | | $ | 26.80 | | | $ | 23.71 | | |
| | | | | | | | | | | |
| Costs attributable to PSCs | | | | | | | | | | | |
| Excess energy operating costs attributable to PSCs | | $ | (1.09) | | | $ | (0.91) | | | $ | (0.97) | | | $ | (1.01) | | | $ | (0.98) | | |
| Excess non-energy operating costs attributable to PSCs | | (1.30) | | | (1.24) | | | (1.19) | | | (1.25) | | | (1.37) | | |
| Excess costs attributable to PSCs | | $ | (2.39) | | | $ | (2.15) | | | $ | (2.16) | | | $ | (2.26) | | | $ | (2.35) | | |
| | | | | | | | | | | |
Energy operating costs, excluding effect of PSCs (1) | | $ | 8.33 | | | $ | 6.48 | | | $ | 9.99 | | | $ | 9.86 | | | $ | 8.85 | | |
Gas processing costs, excluding effect of PSCs (2) | | 0.64 | | | 0.64 | | | 0.49 | | | 0.59 | | | 0.53 | | |
| Non-energy operating costs, excluding effect of PSCs | | 13.60 | | | 14.44 | | | 12.63 | | | 14.09 | | | 11.98 | | |
| Operating costs, excluding effects of PSCs | | $ | 22.57 | | | $ | 21.56 | | | $ | 23.11 | | | $ | 24.54 | | | $ | 21.36 | | |
| | | | | | | | | | | |
(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. | |
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| Attachment 4 |
| PRODUCTION STATISTICS | | | | | | | | | | | |
| | 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | Nine Months | | Nine Months | |
| Net Production Per Day | | 2023 | | 2023 | | 2022 | | 2023 | | 2022 | |
| | | | | | | | | | | |
| Oil (MBbl/d) | | | | | | | | | | | |
| San Joaquin Basin | | 33 | | | 34 | | | 36 | | | 34 | | | 37 | | |
| Los Angeles Basin | | 18 | | | 19 | | | 19 | | | 19 | | | 18 | | |
| | | | | | | | | | | |
| Total | | 51 | | | 53 | | | 55 | | | 53 | | | 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 | | 122 | | | 119 | | | 131 | | | 120 | | | 128 | | |
| Los Angeles Basin | | 1 | | | 1 | | | 1 | | | 1 | | | 1 | | |
| | | | | | | | | | | |
| Sacramento Basin | | 15 | | | 15 | | | 17 | | | 15 | | | 18 | | |
| Total | | 138 | | | 135 | | | 149 | | | 136 | | | 147 | | |
| | | | | | | | | | | |
| Total Production (MBoe/d) | | 85 | | | 86 | | | 92 | | | 87 | | | 91 | | |
| | | | | | | | | | | |
| Gross Operated and Net Non-Operated | | 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | Nine Months | | Nine Months | |
| Production Per Day | | 2023 | | 2023 | | 2022 | | 2023 | | 2022 | |
| | | | | | | | | | | |
| Oil (MBbl/d) | | | | | | | | | | | |
| San Joaquin Basin | | 36 | | | 38 | | | 40 | | | 38 | | | 41 | | |
| Los Angeles Basin | | 25 | | | 25 | | | 26 | | | 25 | | | 26 | | |
| | | | | | | | | | | |
| Total | | 61 | | | 63 | | | 66 | | | 63 | | | 67 | | |
| | | | | | | | | | | |
| NGLs (MBbl/d) | | | | | | | | | | | |
| San Joaquin Basin | | 13 | | | 12 | | | 13 | | | 12 | | | 12 | | |
| Total | | 13 | | | 12 | | | 13 | | | 12 | | | 12 | | |
| | | | | | | | | | | |
| Natural Gas (MMcf/d) | | | | | | | | | | | |
| San Joaquin Basin | | 135 | | | 136 | | | 140 | | | 135 | | | 137 | | |
| Los Angeles Basin | | 8 | | | 7 | | | 7 | | | 7 | | | 7 | | |
| | | | | | | | | | | |
| Sacramento Basin | | 18 | | | 19 | | | 21 | | | 20 | | | 22 | | |
| Total | | 161 | | | 162 | | | 168 | | | 162 | | | 166 | | |
| | | | | | | | | | | |
| Total Production (MBoe/d) | | 101 | | | 103 | | | 107 | | | 102 | | | 107 | | |
| | | | | | | | | | | |
| |
| | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | Attachment 5 | | | |
| PRICE STATISTICS | | | | | | | | | | | | | |
| 3rd Quarter | | 2nd Quarter | | | 3rd Quarter | | Nine Months | | Nine Months | | | |
| | 2023 | | 2023 | | | 2022 | | 2023 | | 2022 | | | |
| Oil ($ per Bbl) | | | | | | | | | | | | | |
| Realized price with derivative settlements | $ | 66.12 | | | $ | 63.66 | | | | $ | 62.45 | | | $ | 64.25 | | | $ | 61.96 | | | | |
| Realized price without derivative settlements | $ | 85.36 | | | $ | 75.77 | | | | $ | 97.96 | | | $ | 79.90 | | | $ | 102.01 | | | | |
| | | | | | | | | | | | | |
| NGLs ($/Bbl) | $ | 44.95 | | | $ | 42.48 | | | | $ | 57.68 | | | $ | 48.89 | | | $ | 66.98 | | | | |
| | | | | | | | | | | | | |
| Natural gas ($/Mcf) | | | | | | | | | | | | | |
| Realized price with derivative settlements | $ | 4.83 | | | $ | 3.46 | | | | $ | 8.58 | | | $ | 9.85 | | | $ | 7.21 | | | | |
| Realized price without derivative settlements | $ | 4.83 | | | $ | 3.46 | | | | $ | 8.80 | | | $ | 9.85 | | | $ | 7.33 | | | | |
| | | | | | | | | | | | | |
| Index Prices | | | | | | | | | | | | | |
| Brent oil ($/Bbl) | $ | 85.95 | | | $ | 78.01 | | | | $ | 97.81 | | | $ | 82.06 | | | $ | 102.33 | | | | |
| WTI oil ($/Bbl) | $ | 82.26 | | | $ | 73.78 | | | | $ | 91.56 | | | $ | 77.39 | | | $ | 98.09 | | | | |
| NYMEX average monthly settled price ($/MMBtu) | $ | 2.55 | | | $ | 2.10 | | | | $ | 8.20 | | | $ | 2.69 | | | $ | 6.77 | | | | |
| | | | | | | | | | | | | |
| Realized Prices as Percentage of Index Prices | | | | | | | | | | | | | |
| Oil with derivative settlements as a percentage of Brent | 77 | % | | 82 | % | | | 64 | % | | 78 | % | | 61 | % | | | |
| Oil without derivative settlements as a percentage of Brent | 99 | % | | 97 | % | | | 100 | % | | 97 | % | | 100 | % | | | |
| | | | | | | | | | | | | |
| Oil with derivative settlements as a percentage of WTI | 80 | % | | 86 | % | | | 68 | % | | 83 | % | | 63 | % | | | |
| Oil without derivative settlements as a percentage of WTI | 104 | % | | 103 | % | | | 107 | % | | 103 | % | | 104 | % | | | |
| | | | | | | | | | | | | |
| NGLs as a percentage of Brent | 52 | % | | 54 | % | | | 59 | % | | 60 | % | | 65 | % | | | |
| NGLs as a percentage of WTI | 55 | % | | 58 | % | | | 63 | % | | 63 | % | | 68 | % | | | |
| | | | | | | | | | | | | |
| Natural gas with derivative settlements as a percentage of NYMEX contract month average | 189 | % | | 165 | % | | | 105 | % | | 366 | % | | 106 | % | | | |
| | | | | | | | | | | | | |
| Natural gas without derivative settlements as a percentage of NYMEX contract month average | 189 | % | | 165 | % | | | 107 | % | | 366 | % | | 108 | % | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | Attachment 6 |
| THIRD QUARTER 2023 DRILLING ACTIVITY | | | | | | | | | | |
| | | San Joaquin | | Los Angeles | | Ventura | | Sacramento | | |
| Wells Drilled | | Basin | | Basin | | Basin | | Basin | | Total |
| | | | | | | | | | |
| Development Wells | | | | | | | | | | |
| Primary | | — | | — | | — | | — | | — |
| Waterflood | | — | | 9 | | — | | — | | 9 |
| Steamflood | | — | | — | | — | | — | | — |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Total (1) | | — | | 9 | | — | | — | | 9 |
| | | | | | | | | | |
| | | | | | | | | | |
| NINE MONTHS 2023 DRILLING ACTIVITY | | | | | | | | | | |
| | | San Joaquin | | Los Angeles | | Ventura | | Sacramento | | |
| Wells Drilled | | Basin | | Basin | | Basin | | Basin | | Total |
| | | | | | | | | | |
| Development Wells | | | | | | | | | | |
| Primary | | 2 | | — | | — | | — | | 2 |
| Waterflood | | 1 | | 21 | | — | | — | | 22 |
| Steamflood | | — | | — | | — | | — | | — |
Total (1) | | 3 | | 21 | | — | | — | | 24 |
| | | | | | | | | | |
(1) Includes steam injectors and drilled but uncompleted wells, which are not included in the SEC definition of wells drilled. | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Attachment 7 |
| OIL HEDGES AS OF SEPTEMBER 30, 2023 | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | Q4 2023 | | Q1 2024 | | Q2 2024 | | Q3 2024 | | Q4 2024 | | 2025 |
| | | | | | | | | | | | | |
| Sold Calls | | | | | | | | | | | | | |
| Barrels per day | | | 5,747 | | 23,650 | | 30,000 | | 30,000 | | 29,000 | | 19,748 |
| Weighted-average Brent price per barrel | | | $57.06 | | $90.00 | | $90.07 | | $90.07 | | $90.07 | | $85.83 |
| | | | | | | | | | | | | |
| Swaps | | | | | | | | | | | | | |
| Barrels per day | | | 27,094 | | 9,000 | | 7,750 | | 7,750 | | 5,500 | | 3,374 |
| Weighted-average Brent price per barrel | | | $70.73 | | $79.37 | | $79.65 | | $79.64 | | $77.45 | | $72.66 |
| | | | | | | | | | | | | |
Net Purchased Puts (1) | | | | | | | | | | | | | |
| Barrels per day | | | 5,747 | | 30,584 | | 30,000 | | 30,000 | | 29,000 | | 19,748 |
| Weighted-average Brent price per barrel | | | $76.25 | | $67.27 | | $65.17 | | $65.17 | | $65.17 | | $60.00 |
| | | | | | | | | | | | | |
(1) Purchased puts and sold puts with the same strike price have been presented on a net basis. |
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California Resources (NYSE:CRC)
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