Document
California Resources Reports First Quarter 2024 Financial and Operating Results
CRC Committed to Shareholder Return Strategy; Returned Nearly $95 million Year to Date to Shareholders via Dividends and Share Repurchases
LONG BEACH, California, May 7, 2024 - California Resources Corporation (NYSE: CRC) today reported financial and operating results for the first quarter 2024. The Company plans to host a conference call and webcast on Wednesday, May 8th at 1:00 p.m. Eastern Time (10:00 a.m. Pacific Time). Participation details can be found within this release. In addition, supplemental slides are posted to CRC’s website at www.crc.com.
First Quarter 2024 Highlights:
•Returned $79 million to shareholders through share repurchases and dividends
•Reported $87 million of net cash from operating activities
•Net cash provided by operating activities before changes in operating assets and liabilities, net1 of $92 million includes $25 million of costs related to the Aera transaction and incremental energy costs due to scheduled power plant major maintenance
•Reported net loss of $10 million, or $0.14 per diluted share. When adjusted for items analysts typically exclude from estimates (including mark-to-market adjustments of $59 million, one-time costs for Aera Merger of $13 million and increased power and fuel costs due to power plant shutdown of $21 million all of which is before taxes), the Company's adjusted net income1 was $54 million, or $0.75 per diluted share
•Generated an adjusted EBITDAX1 of $149 million and $33 million of free cash flow1
•Flat entry to exit gross production of 94 thousand barrels of oil equivalent per day (MBoe/d) after investing drilling and workover capital of $22 million
•Delivered average quarterly net production of 76 MBoe/d and net oil production of 48 thousand barrels of oil per day (MBo/d)
•The Carbon TerraVault JV achieved the milestone for the second installment related to “CTV I – 26R” reservoir pore space contribution in the amount of $46 million. See CTV's First Quarter 2024 Update press release for additional information
•Announced the expiration of the required waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 with respect to the pending combination upon the completion of which Aera Energy, LLC (Aera) and its operating affiliate Aera Energy Services Company will be indirect wholly-owned subsidiaries of CRC (Aera Merger)
•Received “Grade A” certification through MiQ’s Methane Emissions Performance Standard for CRC's operating assets in Los Angeles and Orange Counties
"Our solid first quarter performance adds to CRC's historical track record of unwavering commitment to shareholder returns and effective cost management," said Francisco Leon, CRC's President and Chief Executive Officer. "CRC's improved cost structure demonstrates the fundamental improvements we’ve made to our business, reflecting our readiness to combine with Aera while driving a higher level of efficiency and effectiveness throughout the organization. I want to thank all of our employees as the foundation of CRC’s continued success comes from their ongoing diligent efforts and hard work”
"With company's operations successfully scaled to generate free cash flow, our advantaged balance sheet position has allowed us to accelerate the return of capital to shareholders and return more than double of our quarterly free cash flow1 back to investors," continued Leon. "Looking ahead to the remainder of the year, we remain focused on closing the Aera Merger, further expanding our carbon management business and continuing to provide innovative energy solutions to meet California's energy needs."
First Quarter 2024 Financial and Operating Summary
Net loss for the period was $10 million, or $0.14 per diluted share of common stock, and adjusted net income1 was $54 million, or $0.75 per diluted share. The Company reported first quarter net cash from operating activities of $87 million. Adjusted EBITDAX1 was $149 million. Net cash provided by operating activities before changes in operating assets and liabilities, net1, of $92 million includes Aera Merger expenses of $13 million and incremental energy costs due to the scheduled Elk Hills power plant major maintenance of $12 million. CRC generated $33 million of free cash flow1 during the quarter.
CRC’s gross production in the first quarter averaged 94 MBoe/d. Net production averaged 76 MBoe/d, including net oil production of 48 MBo/d. A longer than expected Elk Hills power plant major maintenance, challenging weather conditions and PSC effects adversely affected net production in the first quarter of 2024 by 1.5 MBoe/d from previously issued guidance. Average realized oil prices during the quarter were 98% of Brent.
Operating costs in the first quarter of 2024 were $176 million compared to $186 million in the fourth quarter of 2023 primarily due to lower electricity and natural gas prices.
Capital in the first quarter of 2024 was lower than previously issued guidance due to anticipated facility and workover spend, and totaled $54 million. CRC ran a one-rig program in the San Joaquin basin during the period.
First Quarter 2024 Financial Results
Certain prior period balances related to NGL marketing activities have been reclassified to conform to CRC's 2024 presentation. For the three months ended December 31, 2023, CRC reclassified $4 million related to NGL storage activities from other revenue to revenue from marketing of purchased commodities on the condensed consolidated statement of operations. CRC also reclassified $3 million of NGL processing fees from other operating expenses, net to costs related to marketing of purchased commodities.
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| Selected Production, Price Information and Results of Operations |
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1st Quarter |
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4th Quarter |
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| ($ in millions) |
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2024 |
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2023 |
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| Average net oil production per day (MBbl/d) |
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48 |
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50 |
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| Realized oil price with derivative settlements ($ per Bbl) |
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$ |
77.17 |
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$ |
71.34 |
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| Average net NGL production per day (MBbl/d) |
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11 |
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11 |
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| Realized NGL price ($ per Bbl) |
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$ |
50.50 |
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$ |
49.08 |
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| Average net natural gas production per day (Mmcf/d) |
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105 |
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130 |
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| Realized natural gas price with derivative settlements ($ per Mcf) |
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$ |
3.90 |
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$ |
4.66 |
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| Average net total production per day (MBoe/d) |
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76 |
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83 |
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| Margin from marketing of purchased commodities ($ millions) |
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$ |
20 |
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$ |
29 |
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| Margin from electricity sales ($ millions) |
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$ |
7 |
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$ |
24 |
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| Net gain (loss) from oil commodity derivatives ($ millions) |
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$ |
(71) |
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$ |
119 |
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| Selected Financial Statement Data and non-GAAP measures: |
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1st Quarter |
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4th Quarter |
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| ($ and shares in millions, except per share amounts) |
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2024 |
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2023 |
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| Statements of Operations: |
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| Revenues |
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| Total operating revenues |
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$ |
454 |
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$ |
726 |
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| Selected Expenses |
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| Operating costs |
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$ |
176 |
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$ |
186 |
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| General and administrative expenses |
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$ |
57 |
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$ |
66 |
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Adjusted general and administrative expenses1 |
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$ |
49 |
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$ |
55 |
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| Taxes other than on income |
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$ |
38 |
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$ |
33 |
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| Transportation costs |
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$ |
20 |
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$ |
18 |
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| Operating Income (loss) |
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$ |
(4) |
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$ |
283 |
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| Interest and debt expense |
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$ |
(13) |
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$ |
(13) |
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| Income tax benefit (provision) |
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$ |
9 |
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$ |
(79) |
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| Net (loss) Income |
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$ |
(10) |
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$ |
188 |
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| EPS, Non-GAAP Measures and Select Balance Sheet Data |
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Adjusted net income1 |
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$ |
54 |
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$ |
67 |
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| Weighted-average common shares outstanding - diluted |
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69.0 |
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72.3 |
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| Net loss (income) per share - diluted |
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$ |
(0.14) |
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$ |
2.60 |
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Adjusted net income1 per share - diluted |
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$ |
0.75 |
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$ |
0.93 |
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Adjusted EBITDAX1 |
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$ |
149 |
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$ |
179 |
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| Net cash provided by operating activities |
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$ |
87 |
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$ |
131 |
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Net cash provided by operating activities before changes in operating assets and liabilities, net1 |
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$ |
92 |
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$ |
104 |
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| Capital investments |
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$ |
54 |
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$ |
66 |
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Free cash flow1 |
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$ |
33 |
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$ |
65 |
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| Cash and cash equivalents |
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$ |
403 |
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$ |
496 |
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Pending Aera Merger
On February 7, 2024, CRC entered into a definitive agreement and plan of merger (Merger Agreement) to combine with Aera in an all-stock transaction with an effective date of January 1, 2024.
Aera is a leading operator of mature fields in California, primarily in the San Joaquin and Ventura basins, with high oil-weighted production. At closing, Aera's owners will receive 21.2 million shares of CRC's common stock plus an additional number of shares determined by reference to the dividends declared by CRC having a record date between the effective date and closing. CRC also agreed to assume Aera’s outstanding long-term indebtedness of $950 million. CRC expects to repay a significant portion of this indebtedness with cash on hand and borrowings under its revolving credit facility. CRC expects to refinance the balance through one or more debt capital markets transactions and, only to the extent necessary, borrowings under a bridge loan facility.
On March 26, 2024, CRC announced the expiration of the required waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 with respect to the pending Aera Merger.
On May 7, 2024, CRC filed the definitive proxy statement for the Aera Merger with the SEC. Closing of the Aera Merger is subject to certain closing conditions, including among others, regulatory approvals and CRC shareholder approval, and is expected to close around mid-year 2024.
For more information about this transaction please visit: https://www.crc.com/news/news-details/2024/California-Resources-Corporation-to-Combine-with-Aera-Energy/default.aspx
2024 Capital Outlook, Second Quarter 2024 Guidance and Capital Program2
CRC’s 2024 guidance estimates exclude the pending Aera Merger. The Company intends to update guidance after the transaction closes.
Following the March 2024 Court of Appeals decision in the Kern County Environmental Impact Report matter, CRC expects its 2024 capital program to range between $200 million and $240 million under current permitting conditions. Of this amount, $165 million to $185 million is related to oil and natural gas development (including $20 million to $25 million for maintenance at CRC’s Elk Hills gas processing plant), $20 million to $25 million is for carbon management projects and $15 million to $30 million is for corporate and other (including $10 million to $15 million related to maintenance at CRC’s Elk Hills power plant). In 2024, CRC expects to run a one rig program while executing projects using existing permits.
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2024 PRELIMINARY OUTLOOK2 |
TOTAL 2024E |
| Net Production (MBoe/d) |
75 - 79 |
| Oil Production (%) |
~61% |
| Capital ($ millions) |
$200 - $240 |
| Drilling & completions, workover ($ millions) |
$100 - $110 |
| Facilities ($ millions) |
$45 - $50 |
| Maintenance of gas processing and power plants at Elk Hills ($ millions) |
$30 - $40 |
| Carbon management business ($ millions) |
$20- $25 |
| Corporate & other ($ millions) |
$5 - $15 |
CRC expects its second quarter capital program to range between $50 million to $57 million. The program includes capital of $45 million to $49 million related to oil and natural gas development (including $4 million to $8 million related to maintenance at CRC’s Elk Hills gas processing plant), $3 million to $5 million related to carbon management projects and $2 million to $3 million related to corporate and other activities.
CRC expects to produce 74 to 78 MBoe/d (~61% oil) in the second quarter of 2024. The table below provides highlights of the Company's second quarter 2024 guidance. See Attachment 2 for complete information on CRC's second quarter 2024 guidance.
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CRC GUIDANCE2 |
Total
2Q24E
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CMB
2Q24E
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E&P, Corp. & Other 2Q24E |
| Net Production (MBoe/d) |
74 - 78 |
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74 - 78 |
| CMB Expenses and Operating Costs ($ millions) |
$170 - $183 |
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$10 - $13 |
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$160 - $170 |
| General and Administrative Expenses ($ millions) |
$56 - $64 |
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$1 - $3 |
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$55 - $61 |
Adjusted General and Administrative Expenses1 ($ millions) |
$49 - $57 |
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$1 - $3 |
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$48 - $54 |
| Capital ($ millions) |
$50 - $57 |
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$3 - $5 |
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$47 - $52 |
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Margin from Marketing of Purchased Commodities ($ millions) 3 |
$5 - $15 |
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$5 - $15 |
Electricity Margin ($ millions)4 |
$34 - $42 |
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$34 - $42 |
Shareholder Return
CRC is committed to returning significant cash to shareholders through dividends and repurchases of its common stock.
During the first quarter of 2024, CRC repurchased 1.1 million shares for $58 million or an average price of $53.26 per share. Post quarter end and through May 3, 2024, CRC repurchased an additional 0.3 million shares for $15 million or an average price of $54.80. Since the inception of the Share Repurchase Program in May 2021 through May 3, 2024, 16.2 million shares have been repurchased for $675 million at an average price of $41.61 per share. These total repurchases represent 19% of CRC’s shares outstanding at its bankruptcy emergence in October 2020.
In February 2024, CRC’s Board of Directors approved a $250 million increase of the Share Repurchase Program, bringing the aggregate program to $1.35 billion, and extended the program through December 31, 2025. Adjusting for this increase, CRC has approximately $675 million of capacity remaining under the repurchase program as of May 7, 2024.
On May 7, 2024, 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 on May 31, 2024 and will be paid on June 14, 2024. Post closing of the Aera Merger, and subject to Board approval, CRC expects to increase its quarterly dividend.
From October 2020 through May 7, 2024, CRC has returned $905 million of cash to its stakeholders, including $675 million in share repurchases, $175 million of dividends and $55 million in principal of its Senior Notes repurchases.
Balance Sheet and Liquidity Update
In connection with the Merger Agreement, on February 9, 2024, CRC entered into a second amendment to its Revolving Credit Facility to permit CRC to incur debt under a bridge loan facility that may be used in connection with closing the Aera Merger.
In March 2024, CRC entered into a third amendment to its Revolving Credit Facility. The amendment facilitated certain matters with respect to the Aera Merger, including the postponement of the regular spring borrowing base redetermination until the fall of 2024 and certain other amendments.
Additionally, CRC obtained commitments from its existing lenders and certain new lenders to amend CRC's Revolving Credit Facility upon closing of the Aera Merger. These commitments include increasing its borrowing base from $1.2 billion to $1.5 billion, increasing the aggregate commitment amount from $630 million to $1.1 billion, and other matters.
As of March 31, 2024, CRC had liquidity of $880 million, which consisted of $403 million in cash and cash equivalents plus $477 million of available borrowing capacity under its Revolving Credit Facility (which is after $153 million of outstanding letters of credit).
Acquisitions and Divestitures
In March 2024, CRC sold its 0.9-acre Fort Apache real estate property in Huntington Beach, California for a purchase price of $10 million and recognized a $6 million gain.
Sustainability
In April, 2024, CRC received a “Grade A” certification through MiQ’s Methane Emissions Performance Standard for CRC's operating assets in Los Angeles and Orange Counties. MiQ is an independent not-for-profit established to facilitate a rapid reduction in methane emissions from the oil and gas sector. This certification is the first “Grade A” independently certified gas (ICG) designation that MiQ has presented to oil and natural gas operating assets in California and the Rocky Mountain region. The achievement further demonstrates CRC’s dedication to its ESG goals and sustainability platform. CRC plans to continue to work with MiQ to expand its ICG certifications to operations in the San Joaquin and Sacramento basins.
Board Changes
On May 3, 2024, CRC's shareholders elected one new Board member, Christian S. Kendall.
Mr. Kendall is the former President and Chief Executive Officer of Denbury. Prior to joining Denbury in 2015, Mr. Kendall worked at Noble Energy, Inc., where he served as a member of Noble’s executive management and operations leadership team as Senior Vice President, Global Operations Services. Prior to that, Mr. Kendall served in several other executive and management roles of increasing responsibility with Noble beginning in 2001. Mr. Kendall’s career in the oil and natural gas industry began in 1989 at Mobil Oil Corporation. Mr. Kendall has served as the Chairman of the Board of the Dallas Division of the American Heart Association and is a member of National Petroleum Council. Mr. Kendall holds a Bachelor of Science degree in Engineering with a Civil Specialty from the Colorado School of Mines and has also completed the Advanced Management Program at the Harvard Business School. Please see www.crc.com for more details.
As previously disclosed, Julio M. Quintana, who has served as a member of CRC’s Board of Directors since October 2020, did not seek reelection as a Director at the 2024 Annual Meeting. CRC thanks Mr. Quintana for his outstanding leadership, knowledge, and contributions to the Company throughout his tenure on the Board of Directors and wish him all the best.
Upcoming Investor Conference Participation
CRC's executives will be participating in the following events in May through July 2024:
•Goldman Sachs Ninth Annual Leveraged Finance and Credit Conference on May 13 and 14 in Rancho Palos Verdes, CA
•2024 Citi Energy & Climate Technology Conference on May 14 to 15 in Boston, MA
•TD Cowen's 2nd Annual Sustainability Week on May 21 held virtually
•Stifel 2024 Cross Sector Insights Conference on June 3 in Boston, MA
•RBC Capital Markets Global Energy, Power & Infrastructure Conference on June 5 in New York, NY
•BofA Securities Energy Credit Conference on June 6 in New York, NY
•2024 JP Morgan Energy, Power & Renewables Conference on June 17 to 18 in New York, NY
•2024 TD Calgary Energy Conference on July 9 to 10 in Calgary, AB, Canada
CRC’s presentation materials will be available the day of the events on the Events and Presentations page in the Investor Relations section on www.crc.com.
Conference Call Details
A conference call is scheduled for Wednesday, May 8, 2024 at 1:00 p.m. Eastern Time (10:00 a.m. Pacific Time). To participate in the call, 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/10187009/fbc013eb9d. 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, adjusted EBITDAX, free cash flow and adjusted G&A, including reconciliations to their most directly comparable GAAP measure, where applicable. For the 2Q24 estimates of the non-GAAP measure of adjusted general and administrative expenses, including reconciliations to its most directly comparable GAAP measure, see Attachment 2.
2 2Q24 guidance assumes Brent price of $86.17 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $1.78 per mcf. CRC's share of production under PSC contracts decreases when commodity prices rise and increases when prices fall.
3 Margin from Marketing of Purchased Commodities is calculated as the difference between Revenue from Marketing of Purchased Commodities and Costs Related to Marketing of Purchased Commodities
4 Electricity Margin is calculated as the difference between Electricity Sales and Electricity Generation Expenses
About California Resources Corporation
California Resources Corporation (CRC) is an independent energy and carbon management company committed to energy transition. CRC produces some of the lowest carbon intensity production in the US and is focused on maximizing the value of its land, mineral and technical resources for decarbonization by developing CCS and other emissions reducing projects. For more information about CRC, please visit www.crc.com.
About Carbon TerraVault
Carbon TerraVault Holdings, LLC (CTV), a subsidiary of CRC, provides services that include the capture, transport and storage of carbon dioxide for its customers. CTV is engaged in a series of carbon capture and storage (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.
Additional Information and Where to Find It
This communication may be deemed to be solicitation material in respect of the transactions contemplated by the merger agreement pursuant to which California Resources Corporation (“CRC”) has agreed to combine with Aera Energy, LLC (“Aera”) (the “Merger Agreement”), including the proposed issuance of CRC’S common stock pursuant to the Merger Agreement. In connection with the transaction, CRC filed a proxy statement on Schedule 14A with the U.S. Securities and Exchange Commission (“SEC”), as well as other relevant materials. Following the filing of the definitive proxy statement, CRC mailed the definitive proxy statement and a proxy card to its stockholders. INVESTORS AND SECURITY HOLDERS OF CRC ARE URGED TO READ THE PROXY STATEMENT AND OTHER RELEVANT DOCUMENTS FILED OR TO BE FILED WITH THE SEC CAREFULLY WHEN THEY BECOME AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT CRC, AERA, THE TRANSACTION AND RELATED MATTERS. Investors and security holders will be able to obtain copies of the proxy statement (when available) as well as other filings containing information about CRC, Aera and the transaction, without charge, at the SEC’s website, www.sec.gov. Copies of documents filed with the SEC by CRC will be available, without charge, at CRC’s website, www.crc.com.
Participants in Solicitation
CRC and its directors and executive officers may be deemed to be participants in the solicitation of proxies in connection with the transaction. Information about the directors and executive officers of CRC is set forth in the proxy statement for CRC’s 2024 Annual Meeting of Stockholders, which was filed with the SEC on March 21, 2024. Investors may obtain additional information regarding the interest of such participants by reading the proxy statement regarding the transaction when it becomes available.
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 its 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. Additionally, the information in this report contains forward-looking statements related to the recently announced Aera Merger.
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 the company'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 military conflicts in Israel, Ukraine and Yemen and the Red Sea;
•the ability to successfully integrate the business of Aera once the Aera Merger is completed;
•the timing, receipt and terms and conditions of any required governmental and regulatory approvals of the Aera Merger that could reduce anticipated benefits or cause the parties to abandon the Aera Merger;
•the occurrence of any event, change or other circumstances that could give rise to the termination of the Merger Agreement;
•the possibility that the stockholders of CRC may not approve the issuance of new shares of common stock in the Aera Merger;
•the ability to obtain the required debt financing pursuant to CRC's commitment letters and, if obtained, the potential impact of additional debt on its business and the financial impacts and restrictions due to the additional debt;
•regulatory actions and changes that affect the oil and gas industry generally and CRC in particular, including (1) the availability or timing of, or conditions imposed on, permits and approvals necessary for drilling or development activities or its carbon management business; (2) the management of energy, water, land, greenhouse gases (GHGs) or other emissions, (3) the protection of health, safety and the environment, or (4) the transportation, marketing and sale of the company'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 the 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;
•the 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;
•the ability to claim and utilize tax credits or other incentives in connection with CRC's CCS projects;
•the ability to realize the benefits contemplated by CRC's energy transition strategies and initiatives, including CCS projects and other renewable energy efforts;
•the ability to successfully identify, develop and finance carbon capture and storage projects and other renewable energy efforts, including those in connection with the Carbon TerraVault JV, and the ability to convert CRC's CDMAs to definitive agreements and enter into other offtake agreements;
•the ability to maximize the value of CRC's carbon management business and operate it on a stand alone basis;
•the ability to successfully develop infrastructure projects and enter into third party contracts on contemplated terms;
•uncertainty around the accounting of emissions and the ability to successfully gather and verify emissions data and other environmental impacts;
•changes to CRC's dividend policy and share repurchase program, and the ability to declare future dividends or repurchase shares under its debt agreements;
•limitations on CRC's financial flexibility due to existing and future debt;
•insufficient cash flow to fund CRC's capital plan and other planned investments and return capital to shareholders;
•changes in interest rates;
•CRC's access to and the terms of credit in commercial banking and capital markets, including the ability to refinance its debt or obtain separate financing for its carbon management business;
•changes in state, federal or international tax rates, including the ability to utilize net operating loss carryforwards to reduce CRC's 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 the 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 2023 Annual Report.
CRC cautions you not to place undue reliance on forward-looking statements contained in this document, which speak only as of the filing date, and it undertakes no obligation to update this information. This document may also contain information from third party sources. This data may involve a number of assumptions and limitations, and CRC has not independently verified them and does not warrant the accuracy or completeness of such third-party information.
Contacts:
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Joanna Park (Investor Relations)
818-661-3731
Joanna.Park@crc.com
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Richard Venn (Media)
818-661-6014
Richard.Venn@crc.com
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| Attachment 1 |
| SUMMARY OF RESULTS |
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1st Quarter |
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4th Quarter |
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1st Quarter |
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| ($ and shares in millions, except per share amounts) |
2024 |
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2023 |
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2023 |
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| Statements of Operations: |
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| Revenues |
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| Oil, natural gas and NGL sales |
$ |
429 |
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$ |
483 |
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$ |
715 |
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| Net (loss) gain from commodity derivatives |
(71) |
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119 |
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42 |
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| Revenue from marketing of purchased commodities |
74 |
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71 |
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187 |
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| Electricity sales |
15 |
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42 |
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68 |
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| Other revenue |
7 |
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11 |
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12 |
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| Total operating revenues |
454 |
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726 |
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1,024 |
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| Operating Expenses |
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| Operating costs |
176 |
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186 |
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254 |
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| General and administrative expenses |
57 |
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66 |
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65 |
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| Depreciation, depletion and amortization |
53 |
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55 |
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58 |
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| Asset impairment |
— |
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— |
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3 |
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| Taxes other than on income |
38 |
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33 |
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42 |
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| Exploration expense |
1 |
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1 |
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1 |
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| Costs related to marketing of purchased commodities |
54 |
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42 |
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124 |
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| Electricity generation expenses |
8 |
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18 |
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49 |
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| Transportation costs |
20 |
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18 |
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17 |
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| Accretion expense |
12 |
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11 |
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12 |
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| Carbon management business expenses |
8 |
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17 |
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5 |
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| Other operating expenses, net |
37 |
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21 |
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8 |
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| Total operating expenses |
464 |
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468 |
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638 |
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| Net gain on asset divestitures |
6 |
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25 |
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7 |
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| Operating (Loss) Income |
(4) |
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283 |
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393 |
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| Non-Operating (Expenses) Income |
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| Interest and debt expense |
(13) |
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(13) |
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(14) |
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| Loss from investment in unconsolidated subsidiary |
(3) |
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(3) |
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(2) |
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| Net loss on early extinguishment of debt |
— |
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(1) |
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— |
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| Other non-operating income (loss), net |
1 |
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1 |
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(1) |
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| (Loss) Income Before Income Taxes |
(19) |
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267 |
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376 |
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| Income tax benefit (provision) |
9 |
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(79) |
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(75) |
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| Net (Loss) Income |
$ |
(10) |
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$ |
188 |
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$ |
301 |
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| Net (loss) income per share - basic |
$ |
(0.14) |
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$ |
2.74 |
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$ |
4.22 |
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| Net (loss) income per share - diluted |
$ |
(0.14) |
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$ |
2.60 |
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$ |
4.09 |
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| Adjusted net income |
$ |
54 |
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$ |
67 |
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$ |
193 |
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| Adjusted net income per share - basic |
$ |
0.78 |
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$ |
0.98 |
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$ |
2.71 |
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| Adjusted net income per share - diluted |
$ |
0.75 |
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$ |
0.93 |
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$ |
2.63 |
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| Weighted-average common shares outstanding - basic |
69.0 |
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68.7 |
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71.3 |
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| Weighted-average common shares outstanding - diluted |
69.0 |
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72.3 |
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73.5 |
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| Adjusted EBITDAX |
$ |
149 |
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$ |
179 |
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$ |
358 |
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| Effective tax rate |
45 |
% |
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30 |
% |
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20 |
% |
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1st Quarter |
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4th Quarter |
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1st Quarter |
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| ($ in millions) |
2024 |
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2023 |
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2023 |
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| Cash Flow Data: |
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| Net cash provided by operating activities |
$ |
87 |
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$ |
131 |
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$ |
310 |
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| Net cash used in investing activities |
$ |
(49) |
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$ |
(42) |
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$ |
(61) |
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| Net cash used in financing activities |
$ |
(131) |
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$ |
(72) |
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$ |
(79) |
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March 31, |
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December 31, |
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| ($ in millions) |
2024 |
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2023 |
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| Selected Balance Sheet Data: |
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| Total current assets |
$ |
839 |
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$ |
929 |
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| Property, plant and equipment, net |
$ |
2,793 |
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$ |
2,770 |
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| Deferred tax asset |
$ |
139 |
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$ |
132 |
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| Total current liabilities |
$ |
594 |
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$ |
616 |
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| Long-term debt, net |
$ |
541 |
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$ |
540 |
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| Noncurrent asset retirement obligations |
$ |
429 |
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$ |
422 |
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| Stockholders' Equity |
$ |
2,093 |
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$ |
2,219 |
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| GAINS AND LOSSES FROM COMMODITY DERIVATIVES |
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1st Quarter |
|
4th Quarter |
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1st Quarter |
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| ($ millions) |
2024 |
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2023 |
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2023 |
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| Non-cash derivative (loss) gain |
$ |
(59) |
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$ |
168 |
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$ |
107 |
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| Net payments on settled commodity derivatives |
(12) |
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(49) |
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(65) |
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| Net (loss) gain from commodity derivatives |
$ |
(71) |
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$ |
119 |
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$ |
42 |
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1st Quarter |
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1st Quarter |
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4th Quarter |
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4th Quarter |
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4th Quarter |
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| CAPITAL INVESTMENTS |
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|
1st Quarter |
|
4th Quarter |
|
1st Quarter |
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| ($ millions) |
2024 |
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2023 |
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2023 |
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Facilities (1) |
$ |
14 |
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$ |
20 |
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$ |
9 |
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| Drilling |
15 |
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16 |
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25 |
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| Workovers |
7 |
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11 |
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6 |
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| Total E&P capital |
36 |
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47 |
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|
40 |
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CMB (1) |
4 |
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4 |
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1 |
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| Corporate and other |
14 |
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|
15 |
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6 |
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| Total capital program |
$ |
54 |
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$ |
66 |
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$ |
47 |
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(1) Facilities capital includes $0, $1 million and $1 million in the first quarter of 2024 and fourth and first quarter of 2023, respectively, to build replacement water injection facilities which will allow CRC to divert produced water away from a depleted oil and natural gas reservoir held by the Carbon TerraVault JV. Construction of these facilities supports the advancement of CRC’s carbon management business and CRC reported these amounts as part of adjusted CMB capital in this Earnings Release. Where adjusted CMB capital is presented, CRC removed the amounts from facilities capital and presented adjusted E&P, Corporate and Other capital. |
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Attachment 2 |
| 2024 PRELIMINARY OUTLOOK |
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Total 2024E |
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| Net Production (MBoe/d) |
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75 - 79 |
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| Oil Production (%) |
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~61% |
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| Capital ($ millions) |
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$200 - $240 |
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| CRC GUIDANCE |
Total
2Q24E |
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CMB
2Q24E |
|
E&P, Corp. & Other 2Q24E |
| Net Production (MBoe/d) |
74 - 78 |
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74 - 78 |
| Oil Production (%) |
~61% |
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~61% |
| CMB Expenses & Operating Costs ($ millions) |
$170 - $183 |
|
$10 - $13 |
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$160 - $170 |
| General and Administrative Expenses ($ millions) |
$56 - $64 |
|
$1 - $3 |
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$55 - $61 |
| Adjusted General and Administrative Expenses ($ millions) |
$49 - $57 |
|
$1 - $3 |
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$48 - $54 |
| Capital ($ millions) |
$50 - $57 |
|
$3 - $5 |
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$47 - $52 |
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|
Margin from Marketing of Purchased Commodities ($ millions) (1) |
$5 - $15 |
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$5 - $15 |
Electricity Margin ($ millions) (2) |
$34 - $42 |
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$34 - $42 |
| Other Operating Revenue & Expenses, net ($ millions) |
$0 - $5 |
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$0 - $5 |
| Transportation Costs ($ millions) |
$14 - $17 |
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|
$14 - $17 |
Taxes Other Than on Income ($ millions) (3) |
$44 - $46 |
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|
$44 - $46 |
| Interest and Debt Expense ($ millions) |
$13 - $15 |
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$13 - $15 |
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| Commodity Assumptions: |
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| Brent ($/Bbl) |
$86.17 |
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|
$86.17 |
| NYMEX ($/Mcf) |
$1.78 |
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|
$1.78 |
| Oil - % of Brent: |
97% - 99% |
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|
97% - 99% |
| NGL - % of Brent: |
50% - 55% |
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|
50% - 55% |
| Natural Gas - % of NYMEX: |
89% - 93% |
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|
89% - 93% |
(1) Margin from Marketing of Purchased Commodities is calculated as the difference between Revenue from Marketing of Purchased Commodities and Costs Related to Marketing of Purchased Commodities.
(2) Electricity Margin is calculated as the difference between Electricity Sales and Electricity Generation Expenses.
(3) Other Operating Revenue & Expenses, net is calculated as the difference between Other Revenue and Other Operating Expenses, net. Current guidance does not include estimated Aera Merger and integration expenses of $30 - $40 million dependent on the timing of close.
See Attachment 3 for management's disclosure of its use of these non-GAAP measures and how these measures provide useful information to investors about CRC's results of operations and financial condition.
ESTIMATED ADJUSTED GENERAL AND ADMINISTRATIVE EXPENSES RECONCILIATION
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2Q24 Estimated |
|
Consolidated |
|
CMB |
|
E&P, Corporate & Other |
| ($ millions) |
Low |
|
High |
|
Low |
|
High |
|
Low |
|
High |
| General and administrative expenses |
$ |
56 |
|
|
$ |
64 |
|
|
$ |
1 |
|
|
$ |
3 |
|
|
$ |
55 |
|
|
$ |
61 |
|
| Equity-settled stock-based compensation |
(6) |
|
|
(5) |
|
|
|
|
|
|
(6) |
|
|
(5) |
|
| Other |
(1) |
|
|
(2) |
|
|
|
|
|
|
(1) |
|
|
(2) |
|
| Estimated adjusted general and administrative expenses |
$ |
49 |
|
|
$ |
57 |
|
|
$ |
1 |
|
|
$ |
3 |
|
|
$ |
48 |
|
|
$ |
54 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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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. |
|
|
|
|
|
|
|
|
|
1st Quarter |
|
4th Quarter |
|
1st Quarter |
|
|
|
|
|
| ($ millions, except per share amounts) |
|
2024 |
|
2023 |
|
2023 |
|
|
|
|
|
| Net (loss) income |
|
$ |
(10) |
|
|
$ |
188 |
|
|
$ |
301 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Unusual, infrequent and other items: |
|
|
|
|
|
|
|
|
|
|
|
| Non-cash derivative loss (gain) |
|
59 |
|
|
(160) |
|
|
(107) |
|
|
|
|
|
|
| Asset impairment |
|
— |
|
|
— |
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Severance and termination costs |
|
— |
|
|
— |
|
|
1 |
|
|
|
|
|
|
| Aera Merger transaction fees |
|
10 |
|
|
— |
|
|
— |
|
|
|
|
|
|
| Aera Merger integration fees |
|
3 |
|
|
— |
|
|
— |
|
|
|
|
|
|
| Increased power and fuel costs due to power plant shutdown |
|
21 |
|
|
— |
|
|
— |
|
|
|
|
|
|
| Net loss on early extinguishment of debt |
|
— |
|
|
1 |
|
|
— |
|
|
|
|
|
|
| Net gain on asset divestitures |
|
(6) |
|
|
(25) |
|
|
(7) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Other, net |
|
2 |
|
|
16 |
|
|
3 |
|
|
|
|
|
|
| Total unusual, infrequent and other items |
|
89 |
|
|
(168) |
|
|
(107) |
|
|
|
|
|
|
| Income tax (benefit) provision of adjustments at effective tax rate |
|
(25) |
|
|
47 |
|
|
30 |
|
|
|
|
|
|
| Income tax (benefit) provision - out of period |
|
— |
|
|
— |
|
|
(31) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Adjusted net income |
|
$ |
54 |
|
|
$ |
67 |
|
|
$ |
193 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Net (loss) income per share - basic |
|
$ |
(0.14) |
|
|
$ |
2.74 |
|
|
$ |
4.22 |
|
|
|
|
|
|
| Net (loss) income per share - diluted |
|
$ |
(0.14) |
|
|
$ |
2.60 |
|
|
$ |
4.09 |
|
|
|
|
|
|
| Adjusted net income per share - basic |
|
$ |
0.78 |
|
|
$ |
0.98 |
|
|
$ |
2.71 |
|
|
|
|
|
|
| Adjusted net income per share - diluted |
|
$ |
0.75 |
|
|
$ |
0.93 |
|
|
$ |
2.63 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 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).
|
|
|
|
|
|
|
|
|
|
|
1st Quarter |
|
4th Quarter |
|
|
1st Quarter |
|
|
|
|
|
|
| ($ millions, except per BOE amounts) |
|
2024 |
|
2023 |
|
|
2023 |
|
|
|
|
|
|
| Net (loss) income |
|
$ |
(10) |
|
|
$ |
188 |
|
|
|
$ |
301 |
|
|
|
|
|
|
|
| Interest and debt expense |
|
13 |
|
|
13 |
|
|
|
14 |
|
|
|
|
|
|
|
| Depreciation, depletion and amortization |
|
53 |
|
|
55 |
|
|
|
58 |
|
|
|
|
|
|
|
| Income tax (benefit) provision |
|
(9) |
|
|
79 |
|
|
|
75 |
|
|
|
|
|
|
|
| Exploration expense |
|
1 |
|
|
1 |
|
|
|
1 |
|
|
|
|
|
|
|
| Interest income |
|
(6) |
|
|
(7) |
|
|
|
(4) |
|
|
|
|
|
|
|
Unusual, infrequent and other items (1) |
|
89 |
|
|
(168) |
|
|
|
(107) |
|
|
|
|
|
|
|
| Non-cash items |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Accretion expense |
|
12 |
|
|
11 |
|
|
|
12 |
|
|
|
|
|
|
|
| Stock-based compensation |
|
5 |
|
|
6 |
|
|
|
7 |
|
|
|
|
|
|
|
| Post-retirement medical and pension |
|
1 |
|
|
1 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Adjusted EBITDAX |
|
$ |
149 |
|
|
$ |
179 |
|
|
|
$ |
358 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Net cash provided by operating activities |
|
$ |
87 |
|
|
$ |
131 |
|
|
|
$ |
310 |
|
|
|
|
|
|
|
| Cash interest payments |
|
21 |
|
|
1 |
|
|
|
23 |
|
|
|
|
|
|
|
| Cash interest received |
|
(6) |
|
|
(7) |
|
|
|
(4) |
|
|
|
|
|
|
|
| Cash income taxes |
|
22 |
|
|
41 |
|
|
|
— |
|
|
|
|
|
|
|
| Exploration expenditures |
|
1 |
|
|
1 |
|
|
|
1 |
|
|
|
|
|
|
|
| Adjustments to changes in operating assets and liabilities |
|
24 |
|
|
12 |
|
|
|
28 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Adjusted EBITDAX |
|
$ |
149 |
|
|
$ |
179 |
|
|
|
$ |
358 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| E&P, Corporate & Other Adjusted EBITDAX |
|
$ |
162 |
|
|
$ |
199 |
|
|
|
$ |
367 |
|
|
|
|
|
|
|
| CMB Adjusted EBITDAX |
|
$ |
(13) |
|
|
$ |
(20) |
|
|
|
$ |
(9) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Adjusted EBITDAX per Boe |
|
$ |
21.47 |
|
|
$ |
23.57 |
|
|
|
$ |
44.55 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) See Adjusted Net Income (Loss) reconciliation. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| FREE CASH FLOW AND SUPPLEMENTAL CASH FLOW MEASURES |
|
|
|
|
|
|
|
|
|
|
|
Management uses free cash flow, which is defined by CRC as net cash provided by operating activities less capital investments, as a measure of liquidity. The following table presents a reconciliation of CRC's net cash provided by operating activities to free cash flow. CRC supplemented its non-GAAP measure of free cash flow with (i) net cash provided by operating activities before changes in operating assets and liabilities, net, (ii) adjusted free cash flow, and (iii) 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. |
|
|
|
|
|
|
|
|
|
|
|
|
|
1st Quarter |
|
4th Quarter |
|
1st Quarter |
|
|
|
|
| ($ millions) |
|
2024 |
|
2023 |
|
2023 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Net cash provided by operating activities before changes in operating assets and liabilities, net |
|
$ |
92 |
|
|
$ |
104 |
|
|
$ |
316 |
|
|
|
|
|
| Changes in operating assets and liabilities, net |
|
(5) |
|
|
27 |
|
|
(6) |
|
|
|
|
|
| Net cash provided by operating activities |
|
87 |
|
|
131 |
|
|
310 |
|
|
|
|
|
| Capital investments |
|
(54) |
|
|
(66) |
|
|
(47) |
|
|
|
|
|
| Free cash flow |
|
$ |
33 |
|
|
$ |
65 |
|
|
$ |
263 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| E&P, Corporate and Other |
|
$ |
50 |
|
|
$ |
84 |
|
|
$ |
270 |
|
|
|
|
|
| CMB |
|
$ |
(17) |
|
|
$ |
(19) |
|
|
$ |
(7) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Adjustments to capital investments: |
|
|
|
|
|
|
|
|
|
|
Replacement water facilities(1) |
|
$ |
— |
|
|
$ |
1 |
|
|
$ |
1 |
|
|
|
|
|
| Adjusted capital investments: |
|
|
|
|
|
|
|
|
|
|
| E&P, Corporate and Other |
|
$ |
50 |
|
|
$ |
61 |
|
|
$ |
45 |
|
|
|
|
|
| CMB |
|
$ |
4 |
|
|
$ |
5 |
|
|
$ |
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Adjusted free cash flow: |
|
|
|
|
|
|
|
|
|
|
|
| E&P, Corporate and Other |
|
$ |
50 |
|
|
$ |
85 |
|
|
$ |
271 |
|
|
|
|
|
| CMB |
|
$ |
(17) |
|
|
$ |
(20) |
|
|
$ |
(8) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Facilities capital includes $0, $1 million and $1 million in the first quarter of 2024 and fourth and first quarter of 2023, respectively, to build replacement water injection facilities which will allow CRC to divert produced water away from a depleted oil and natural gas reservoir held by the Carbon TerraVault JV. Construction of these facilities supports the advancement of CRC’s carbon management business and CRC reported these amounts as part of adjusted CMB capital in this press release. Where adjusted CMB capital is presented, CRC removed the amounts from facilities capital and presented adjusted E&P, Corporate and Other capital.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ADJUSTED GENERAL & ADMINISTRATIVE EXPENSES |
|
|
|
|
|
|
|
|
|
|
|
|
|
Management uses a measure called adjusted general and administrative (G&A) expenses to provide useful information to investors interested in comparing CRC's costs between periods and performance to our peers. CRC supplemented its non-GAAP measure of adjusted general and administrative expenses with adjusted general and administrative expenses of its exploration and production and corporate items (adjusted general & administrative expenses for E&P, Corporate & Other) which it believes is a useful measure for investors to understand the results or CRC's core oil and gas business. CRC defines adjusted general & administrative Expenses for E&P, Corporate & Other as consolidated adjusted general and administrative expenses less results attributable to its carbon management business (CMB). |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1st Quarter |
|
4th Quarter |
|
1st Quarter |
|
|
|
|
|
| ($ millions) |
|
2024 |
|
2023 |
|
2023 |
|
|
|
|
|
| General and administrative expenses |
|
$ |
57 |
|
|
$ |
66 |
|
|
$ |
65 |
|
|
|
|
|
|
| Stock-based compensation |
|
(5) |
|
|
(6) |
|
|
(7) |
|
|
|
|
|
|
| Information technology infrastructure |
|
(2) |
|
|
(4) |
|
|
(3) |
|
|
|
|
|
|
| Other |
|
(1) |
|
|
(1) |
|
|
— |
|
|
|
|
|
|
| Adjusted G&A expenses |
|
$ |
49 |
|
|
$ |
55 |
|
|
$ |
55 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| E&P, Corporate and Other adjusted G&A expenses |
|
$ |
47 |
|
|
$ |
53 |
|
|
$ |
52 |
|
|
|
|
|
|
| CMB adjusted G&A expenses |
|
$ |
2 |
|
|
$ |
2 |
|
|
$ |
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 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. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1st Quarter |
|
4th Quarter |
|
1st Quarter |
|
|
|
|
|
| ($ per BOE) |
|
2024 |
|
2023 |
|
2023 |
|
|
|
|
|
Energy operating costs (1) |
|
$ |
8.07 |
|
|
$ |
8.65 |
|
|
$ |
15.56 |
|
|
|
|
|
|
Gas processing costs (2) |
|
0.58 |
|
|
0.60 |
|
|
0.62 |
|
|
|
|
|
|
| Non-energy operating costs |
|
17.15 |
|
|
15.24 |
|
|
15.43 |
|
|
|
|
|
|
| Operating costs |
|
$ |
25.80 |
|
|
$ |
24.49 |
|
|
$ |
31.61 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Costs attributable to PSCs |
|
|
|
|
|
|
|
|
|
|
|
| Excess energy operating costs attributable to PSCs |
|
$ |
(0.99) |
|
|
$ |
(1.01) |
|
|
$ |
(1.19) |
|
|
|
|
|
|
| Excess non-energy operating costs attributable to PSCs |
|
(1.55) |
|
|
(1.32) |
|
|
(1.04) |
|
|
|
|
|
|
| Excess costs attributable to PSCs |
|
$ |
(2.54) |
|
|
$ |
(2.33) |
|
|
$ |
(2.23) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy operating costs, excluding effect of PSCs (1) |
|
$ |
7.08 |
|
|
$ |
7.64 |
|
|
$ |
14.37 |
|
|
|
|
|
|
Gas processing costs, excluding effect of PSCs (2) |
|
0.58 |
|
|
0.60 |
|
|
0.62 |
|
|
|
|
|
|
| Non-energy operating costs, excluding effect of PSCs |
|
15.60 |
|
|
13.92 |
|
|
14.39 |
|
|
|
|
|
|
| Operating costs, excluding effects of PSCs |
|
$ |
23.26 |
|
|
$ |
22.16 |
|
|
$ |
29.38 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Energy operating costs consist of purchased natural gas used to generate electricity for operations and steamfloods, purchased electricity and internal costs to generate electricity used in CRC's operations. |
|
(2) Gas processing costs include costs associated with compression, maintenance and other activities needed to run CRC's gas processing facilities at Elk Hills. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Attachment 4 |
| PRODUCTION STATISTICS |
|
|
|
|
|
|
|
|
|
|
|
|
|
1st Quarter |
|
4th Quarter |
|
1st Quarter |
|
|
|
|
|
| Net Production Per Day |
|
2024 |
|
2023 |
|
2023 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Oil (MBbl/d) |
|
|
|
|
|
|
|
|
|
|
|
| San Joaquin Basin |
|
30 |
|
|
32 |
|
|
35 |
|
|
|
|
|
|
| Los Angeles Basin |
|
18 |
|
|
18 |
|
|
20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total |
|
48 |
|
|
50 |
|
|
55 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| NGLs (MBbl/d) |
|
|
|
|
|
|
|
|
|
|
|
| San Joaquin Basin |
|
11 |
|
|
11 |
|
|
11 |
|
|
|
|
|
|
| Total |
|
11 |
|
|
11 |
|
|
11 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Natural Gas (MMcf/d) |
|
|
|
|
|
|
|
|
|
|
|
| San Joaquin Basin |
|
90 |
|
|
114 |
|
|
119 |
|
|
|
|
|
|
| Los Angeles Basin |
|
1 |
|
|
1 |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Sacramento Basin |
|
14 |
|
|
15 |
|
|
16 |
|
|
|
|
|
|
| Total |
|
105 |
|
|
130 |
|
|
136 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Production (MBoe/d) |
|
76 |
|
|
83 |
|
|
89 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Gross Operated and Net Non-Operated |
|
1st Quarter |
|
4th Quarter |
|
1st Quarter |
|
|
|
|
|
| Production Per Day |
|
2024 |
|
2023 |
|
2023 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Oil (MBbl/d) |
|
|
|
|
|
|
|
|
|
|
|
| San Joaquin Basin |
|
34 |
|
|
36 |
|
|
39 |
|
|
|
|
|
|
| Los Angeles Basin |
|
24 |
|
|
25 |
|
|
26 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total |
|
58 |
|
|
61 |
|
|
65 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| NGLs (MBbl/d) |
|
|
|
|
|
|
|
|
|
|
|
| San Joaquin Basin |
|
11 |
|
|
11 |
|
|
12 |
|
|
|
|
|
|
| Total |
|
11 |
|
|
11 |
|
|
12 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Natural Gas (MMcf/d) |
|
|
|
|
|
|
|
|
|
|
|
| San Joaquin Basin |
|
128 |
|
|
129 |
|
|
135 |
|
|
|
|
|
|
| Los Angeles Basin |
|
7 |
|
|
8 |
|
|
7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Sacramento Basin |
|
17 |
|
|
18 |
|
|
20 |
|
|
|
|
|
|
| Total |
|
152 |
|
|
155 |
|
|
162 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Production (MBoe/d) |
|
94 |
|
|
98 |
|
|
103 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Attachment 5 |
|
|
|
|
|
|
|
| PRICE STATISTICS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1st Quarter |
|
4th Quarter |
|
|
1st Quarter |
|
|
|
|
|
|
|
| |
2024 |
|
2023 |
|
|
2023 |
|
|
|
|
|
|
|
| Oil ($ per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Realized price with derivative settlements |
$ |
77.17 |
|
|
$ |
71.34 |
|
|
|
$ |
63.04 |
|
|
|
|
|
|
|
|
| Realized price without derivative settlements |
$ |
80.16 |
|
|
$ |
82.00 |
|
|
|
$ |
78.68 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| NGLs ($/Bbl) |
$ |
50.50 |
|
|
$ |
49.08 |
|
|
|
$ |
58.88 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Natural gas ($/Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Realized price with derivative settlements |
$ |
3.90 |
|
|
$ |
4.66 |
|
|
|
$ |
21.56 |
|
|
|
|
|
|
|
|
| Realized price without derivative settlements |
$ |
3.90 |
|
|
$ |
4.66 |
|
|
|
$ |
21.56 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Index Prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Brent oil ($/Bbl) |
$ |
81.84 |
|
|
$ |
82.69 |
|
|
|
$ |
82.22 |
|
|
|
|
|
|
|
|
| WTI oil ($/Bbl) |
$ |
76.96 |
|
|
$ |
78.32 |
|
|
|
$ |
76.13 |
|
|
|
|
|
|
|
|
| NYMEX average monthly settled price ($/MMBtu) |
$ |
2.24 |
|
|
$ |
2.88 |
|
|
|
$ |
3.42 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Realized Prices as Percentage of Index Prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Oil with derivative settlements as a percentage of Brent |
94 |
% |
|
86 |
% |
|
|
77 |
% |
|
|
|
|
|
|
|
| Oil without derivative settlements as a percentage of Brent |
98 |
% |
|
99 |
% |
|
|
96 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Oil with derivative settlements as a percentage of WTI |
100 |
% |
|
91 |
% |
|
|
83 |
% |
|
|
|
|
|
|
|
| Oil without derivative settlements as a percentage of WTI |
104 |
% |
|
105 |
% |
|
|
103 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| NGLs as a percentage of Brent |
62 |
% |
|
59 |
% |
|
|
72 |
% |
|
|
|
|
|
|
|
| NGLs as a percentage of WTI |
66 |
% |
|
63 |
% |
|
|
77 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Natural gas with derivative settlements as a percentage of NYMEX contract month average |
174 |
% |
|
162 |
% |
|
|
630 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Natural gas without derivative settlements as a percentage of NYMEX contract month average |
174 |
% |
|
162 |
% |
|
|
630 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Attachment 6 |
| FIRST QUARTER 2024 DRILLING ACTIVITY |
|
|
|
|
|
|
|
|
|
|
| |
|
San Joaquin |
|
Los Angeles |
|
Ventura |
|
Sacramento |
|
|
| Wells Drilled |
|
Basin |
|
Basin |
|
Basin |
|
Basin |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
| Development Wells |
|
|
|
|
|
|
|
|
|
|
| Primary |
|
2 |
|
— |
|
— |
|
— |
|
2 |
| Waterflood |
|
— |
|
— |
|
— |
|
— |
|
— |
| Steamflood |
|
— |
|
— |
|
— |
|
— |
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (1) |
|
2 |
|
— |
|
— |
|
— |
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 MARCH 31, 2024 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q2 2024 |
|
Q3 2024 |
|
Q4 2024 |
|
1H 2025 |
|
2H 2025 |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Sold Calls |
|
|
|
|
|
|
|
|
|
|
|
|
| Barrels per day |
|
|
|
30,000 |
|
30,000 |
|
29,000 |
|
28,000 |
|
27,500 |
| Weighted-average Brent price per barrel |
|
|
|
$90.07 |
|
$90.07 |
|
$90.07 |
|
$86.88 |
|
$86.90 |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
| Barrels per day |
|
|
|
8,875 |
|
8,875 |
|
5,500 |
|
3,500 |
|
3,250 |
| Weighted-average Brent price per barrel |
|
|
|
$79.28 |
|
$80.10 |
|
$77.45 |
|
$72.81 |
|
$72.50 |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Purchased Puts |
|
|
|
|
|
|
|
|
|
|
|
|
| Barrels per day |
|
|
|
30,000 |
|
30,000 |
|
29,000 |
|
28,000 |
|
27,500 |
| Weighted-average Brent price per barrel |
|
|
|
$65.17 |
|
$65.17 |
|
$65.17 |
|
$61.43 |
|
$61.45 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
エドガーで原本を確認する
