California Resources Corporation Reports Record First Quarter Financial Results, Provides an Update on the Progress of Business Repositioning and Further Expands Its Carbon Management Business
California Resources Corporation (NYSE: CRC), an independent energy and carbon management company committed to energy transition, today reported first quarter 2023 operational and financial results.
“We’re off to a great start this year with strong quarterly free cash flow driven by operational execution and natural gas markets in California, which underscores the quality of our asset portfolio and commodity diversification strategy,” said Francisco Leon, President and Chief Executive Officer. “We made good progress in advancing the plan to reposition our business, reduce our costs by $25 to $50 million on an annual run-rate basis and expand our carbon management business. Our focus remains on driving cash flow generation, increasing our financial flexibility and delivering meaningful value to our shareholders while providing the energy that California needs.”
Primary Highlights
- Named Manuela (Nelly) Molina as the new Executive Vice President and Chief Financial Officer, effective May 8, 2023 (see press release on May 1, 2023 for additional details around Nelly’s appointment)
- Achieved record quarterly financial results driven by natural gas realizations of 630% of NYMEX during the first quarter of 2023
- Increased 2023 free cash flow1 guidance to reflect strong first quarter performance by 8% and lowered 2023 operating costs guidance by 3% to reflect lower natural gas outlook, at midpoint of ranges respectively
- Engaged Alvarez & Marsal (A&M) to assist with the execution of cost savings initiatives targeting $25 million to $50 million of sustainable annual run rate savings by the end of 2023
- Successfully amended the RBL credit facility - extended its term to July 31, 2027, improved financial flexibility and reaffirmed the $1.2 billion borrowing base
- Declared a quarterly dividend of $0.2825 per share of common stock, totaling ~$20 million payable on June 16, 2023 to shareholders of record on June 1, 2023, with subsequent quarterly dividends subject to final determination and Board approval
- Repurchased 1,423,764 common shares for $59 million during the first quarter of 2023; repurchased an aggregate 12,880,024 shares for $519 million at an average price of $40.31 per share since the inception of the Share Repurchase Program in May 2021 through March 31, 2023
- Submitted a Class VI permit to the EPA for 34 million metric tons (MMT) for CTV IV CO2 reservoir
- Signed two new storage-only Carbon Dioxide Management Agreements (CDMAs) with Yosemite Clean Energy, LLC and InEnTec Inc. for 40,000 and 100,000 metric tons per annum (MTPA) of CO2 injection, respectively
Financial Highlights
- Reported net income of $301 million, or $4.09 per diluted share. When adjusted for items analysts typically exclude from estimates including mark-to-market adjustments and gains on asset divestitures, the Company’s adjusted net income1 was $193 million, or $2.63 per diluted share
- Generated net cash provided by operating activities of $310 million, adjusted EBITDAX1 of $358 million and free cash flow1 of $263 million
- Ended the quarter with $477 million of cash and cash equivalents and an undrawn $454 million Revolving Credit Facility, (net of $148 million of letters of credit), representing $931 million of total liquidity2
Operational Highlights
- Produced an average of 89,000 net barrels of oil equivalent per day (Boe/d), including 55,000 barrels of oil per day (Bo/d), with E&P capital expenditures of $40 million during the quarter
- Operated ~1.5 drilling rigs across CRC’s asset base; drilled 9 wells and brought 10 wells online in 1Q23
- Operated 35 maintenance rigs in the first quarter
Total Year 2023 Guidance and Capital Program3
CRC is reaffirming its total year 2023 capital program to a range between $200 and $245 million. The program includes $15 to $25 million of adjusted capital for carbon management projects4 and $185 to $220 million of E&P, Corporate and other adjusted capital, including procuring long-lead time items for planned maintenance at CRC's Elk Hills power plant in 2024. CRC's 2023 capital program related to oil and natural gas development to be focused primarily on executing projects using permits outside of Kern County.
CRC estimates average production between 85,000 and 91,000 Boe/d3 (~60% oil) for 2023. CRC expects to run a development program averaging 1.5 rigs for drilling locations where CRC has permits and plans to focus on workover and maintenance activity.
As a result of higher-than-expected natural gas market prices in the first quarter of 2023, CRC is raising its free cash flow1 and lowering its operating costs guidance by 8% (to a range of $360 to $470 million) and 3% (to a range of $815 to $865 million) at the midpoint, respectively.
|
|
|
|
|
|
CRC GUIDANCE3 |
Total 2023E |
|
CMB 2023E |
|
E&P, Corp. & Other 2023E |
Net Total Production (MBoe/d) |
85 - 91 |
|
|
|
85 - 91 |
Net Oil Production (MBbl/d) |
51 - 55 |
|
|
|
51 - 55 |
Operating Costs ($ millions) |
$815 - $865 |
|
|
|
$815 - $865 |
CMB Expenses5 ($ millions) |
$25 - $35 |
|
$25 - $35 |
|
|
Adjusted General and Administrative Expenses1 ($ millions) |
$195 - $225 |
|
$10 - $15 |
|
$185 - $210 |
Adjusted Total Capital1,4 ($ millions) |
$200 - $245 |
|
$15 - $25 |
|
$185 - $220 |
Drilling & Completions |
$67 - $77 |
|
|
|
$66 - $76 |
Workovers |
$44 - $54 |
|
|
|
$44 - $54 |
Adjusted Facilities |
$44 - $54 |
|
|
|
$44 - $54 |
Corporate & Other |
$30 - $35 |
|
|
|
$30 - $35 |
Adjusted CMB |
$15 - $25 |
|
$15 - $25 |
|
|
Free Cash Flow1 ($ millions) |
$360 - $470 |
|
|
|
|
Adjusted Free Cash Flow1 ($ millions) |
|
|
($60) - ($80) |
|
$440 - $530 |
|
|
|
|
|
|
Marketing & Trading, Net ($ millions) |
$80 - $110 |
|
|
|
$80 - $110 |
Net Electricity ($ millions) |
$70 - $110 |
|
|
|
$70 - $110 |
Transportation Expense ($ millions) |
$50 - $70 |
|
|
|
$50 - $70 |
ARO Settlement Payments* ($ millions) |
$55 - $60 |
|
|
|
$55 - $60 |
Taxes Other Than on Income* ($ millions) |
$175 - $185 |
|
|
|
$175 - $185 |
Interest and Debt Expense* ($ millions) |
$55 - $60 |
|
|
|
$55 - $60 |
Cash Income Taxes* ($ millions) |
$100 - $120 |
|
|
|
$100 - $120 |
|
|
|
|
|
|
Commodity Realizations: |
|
|
|
|
|
Oil - % of Brent: |
97% - 99% |
|
|
|
97% - 99% |
NGL - % of Brent: |
58% - 64% |
|
|
|
58% - 64% |
Natural Gas - % of NYMEX: |
150% - 250% |
|
|
|
150% - 250% |
*Notes:
|
|||||
Second Quarter 2023 Guidance and Capital Program3
CRC expects its second quarter 2023 total capital program to range between $46 and $62 million under current operating conditions. This includes $1 to $2 million of adjusted capital1 for carbon management projects.
At this level of spending, CRC expects to produce on average between 86,000 and 88,000 Boe/d3 (~61% oil) in the second quarter of 2023 and plans to run 1 drilling rig in the Los Angeles basin, where CRC plans to develop drilling locations for which it already has permits.
|
|
|
|
|
|
CRC GUIDANCE3 |
Total 2Q23E |
|
CMB 2Q23E |
|
E&P, Corp. & Other 2Q23E |
Net Total Production (MBoe/d) |
86 - 88 |
|
|
|
86 - 88 |
Net Oil Production (MBbl/d) |
54 - 52 |
|
|
|
54 - 52 |
Operating Costs ($ millions) |
$175 - $195 |
|
|
|
$175 - $195 |
CMB Expenses5 ($ millions) |
$5 - $10 |
|
$5 - $10 |
|
|
Adjusted General and Administrative Expenses1 ($ millions) |
$52 - $60 |
|
$2 - $5 |
|
$50 - $55 |
Adjusted Total Capital1,4 ($ millions) |
$46 - $62 |
|
$1 - $2 |
|
$45 - $60 |
Free Cash Flow1 ($ millions) |
$45 - $ 65 |
|
|
|
|
Adjusted Free Cash Flow1 ($ millions) |
|
|
($10) - ($15) |
|
$60 - $75 |
|
|
|
|
|
|
Marketing & Trading, Net ($ millions) |
$17 - $22 |
|
|
|
$17 - $22 |
Net Electricity ($ millions) |
$12 - $17 |
|
|
|
$12 - $17 |
Transportation Expense ($ millions) |
$10 - $15 |
|
|
|
$10 - $15 |
Cash Income Taxes ($ millions) |
$50 - $60 |
|
|
|
$50 - $60 |
|
|
|
|
|
|
Commodity Realizations: |
|
|
|
|
|
Oil - % of Brent: |
94% - 98% |
|
|
|
94% - 98% |
NGL - % of Brent: |
55% - 60% |
|
|
|
55% - 60% |
Natural Gas - % of NYMEX: |
150% - 160% |
|
|
|
150% - 160% |
First Quarter 2023 E&P Operational Results
Total daily net production for the three months ended March 31, 2023, compared to the three months ended December 31, 2022 decreased by approximately 2 MBoe/d, or 2% largely due to higher amounts of rain and colder seasonal temperatures than normal in California, resulting in increased downtime in CRC's operations. Production-sharing contracts (PSCs) did not have an impact on production for the three months ended March 31, 2023 compared to the three months ended December 31, 2022.
During the first quarter of 2023, CRC operated an average of ~1.5 drilling rigs in the Los Angeles basin, drilled 9 wells and brought online 10 wells. See Attachment 3 for further information on CRC's production results by basin and Attachment 5 for further information on CRC's drilling activity.
First Quarter Financial Results
|
1st Quarter |
|
|
4th Quarter |
|||
($ and shares in millions, except per share amounts) |
2023 |
|
|
2022 |
|||
|
|
|
|
|
|||
Statements of Operations: |
|
|
|
|
|||
Revenues |
|
|
|
|
|||
Total operating revenues |
$ |
1,024 |
|
|
$ |
682 |
|
|
|
|
|
|
|||
Operating Expenses |
|
|
|
|
|||
Total operating expenses |
|
638 |
|
|
|
549 |
|
Gain on asset divestitures |
|
7 |
|
|
|
(1 |
) |
Operating Income |
$ |
393 |
|
|
$ |
132 |
|
Net Income Attributable to Common Stock |
$ |
301 |
|
|
$ |
83 |
|
|
|
|
|
|
|||
Net income attributable to common stock per share - basic |
$ |
4.22 |
|
|
$ |
1.14 |
|
Net income attributable to common stock per share - diluted |
$ |
4.09 |
|
|
$ |
1.11 |
|
Adjusted net income1 |
$ |
193 |
|
|
$ |
93 |
|
Adjusted net income1 per share - diluted |
$ |
2.63 |
|
|
$ |
1.24 |
|
Weighted-average common shares outstanding - basic |
|
71.3 |
|
|
|
72.7 |
|
Weighted-average common shares outstanding - diluted |
|
73.5 |
|
|
|
75.0 |
|
Adjusted EBITDAX1 |
$ |
358 |
|
|
$ |
208 |
|
Review of First Quarter 2023 Financial Results
Realized oil prices, excluding the effects of cash settlements on CRC's commodity derivative contracts, decreased by $8.47 per barrel from $87.15 per barrel in the fourth quarter of 2022 to $78.68 per barrel in the first quarter of 2023. The decrease was primarily due to recession concerns across Western economies and disappointment at the pace and scale of the post-COVID-19 reopening in China.
Realized oil prices, including the effects of cash settlements on CRC's commodity derivative contracts, increased by $1.71 from $61.33 in the fourth quarter of 2022 to $63.04 in the first quarter of 2023.
Adjusted EBITDAX1 for the first quarter of 2023 was $358 million. See table below for the Company's net cash provided by operating activities, capital investments and free cash flow1 during the same periods.
FREE CASH FLOW |
|
|
|
|
||||
|
|
|
|
|
||||
Management uses free cash flow, which is defined by CRC as net cash provided by operating activities less capital investments, as a measure of liquidity. The following table presents a reconciliation of CRC's net cash provided by operating activities to free cash flow. CRC supplemented its non-GAAP measure of free cash flow with free cash flow of CRC's exploration and production and corporate items (Free Cash Flow for E&P, Corporate & Other) which it believes is a useful measure for investors to understand the results of its core oil and gas business. CRC defines Free Cash Flow for E&P, Corporate & Other as consolidated free cash flow less results attributable to its carbon management business (CMB). |
||||||||
|
|
|
|
|
||||
|
1st Quarter |
|
|
4th Quarter |
||||
($ millions) |
|
2023 |
|
|
|
|
2022 |
|
|
|
|
|
|
||||
Net cash provided by operating activities |
$ |
310 |
|
|
|
$ |
114 |
|
Capital investments |
|
(47 |
) |
|
|
|
(75 |
) |
Free cash flow1 |
|
263 |
|
|
|
|
39 |
|
|
|
|
|
|
||||
E&P, corporate & other free cash flow1 |
$ |
270 |
|
|
|
$ |
61 |
|
CMB free cash flow1 |
$ |
(7 |
) |
|
|
$ |
(22 |
) |
The following table presents key operating data for CRC's oil and gas operations, on a per BOE basis, for the periods presented below. Energy operating costs consist of purchased natural gas used to generate electricity for CRC's operations and steam for its steamfloods, purchased electricity and internal costs to generate electricity used in CRC's operations. Gas processing costs include costs associated with compression, maintenance and other activities needed to run CRC's gas processing facilities at Elk Hills. Non-energy operating costs equal total operating costs less energy operating costs and gas processing costs.
OPERATING COSTS PER BOE |
||||||||
|
|
|
|
|
||||
The reporting of PSCs creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only CRC's net share, inflating the per barrel operating costs. The following table presents operating costs after adjusting for the excess costs attributable to PSCs. |
||||||||
|
|
|
|
|
||||
|
1st Quarter |
|
|
4th Quarter |
||||
($ per Boe) |
|
2023 |
|
|
|
|
2022 |
|
Energy operating costs |
$ |
15.56 |
|
|
|
$ |
9.56 |
|
Gas processing costs |
|
0.62 |
|
|
|
|
0.48 |
|
Non-energy operating costs |
|
15.43 |
|
|
|
|
13.82 |
|
Operating costs |
$ |
31.61 |
|
|
|
$ |
23.86 |
|
Excess costs attributable to PSCs |
$ |
(2.23 |
) |
|
|
$ |
(1.90 |
) |
Operating costs, excluding effects of PSCs (1) |
$ |
29.38 |
|
|
|
$ |
21.96 |
|
Energy operating costs for the first quarter of 2023 were $125 million, or $15.56 per Boe, an increase of $45 million or 56% from $80 million, or $9.56 per Boe, for the fourth quarter of 2022. This increase includes $38 million for purchased electricity and purchased natural gas, which CRC uses to generate electricity for its operations, and $7 million for purchased natural gas used to generate steam for its steamfloods. Natural gas used in CRC's operations is purchased at first-of-the-month prices, which were higher than average daily prices during the period due to significant volatility in the natural gas market during the first quarter of 2023.
Non-energy operating costs for the first quarter of 2023 were $124 million, or $15.43 per Boe, which was an increase of $8 million or 7% from $116 million, or $13.82 per Boe, for the fourth quarter of 2022. This increase was primarily a result of increased downhole maintenance activity from the prior quarter.
Carbon Management Business Update
In April 2023, CRC applied for a Class VI permit for 34 MMT of permanent CO2 storage for a new CTV VI in the Sacramento basin, which, subject to approval, brings CTV's total potential permitted storage to 174 MMT.
Additionally, in April 2023, Carbon TerraVault Holdings, LLC (CTV), a subsidiary of CRC, reached new storage-only CDMAs for 40,000 and 100,000 MTPA of CO2 injection, at CTV carbon storage vaults from two new facilities to be constructed in Northern and Central California. See CTV's 1Q23 press release for further information on these CDMA's.
The CDMA frames the contractual terms between parties by outlining the material economics and terms of the project and includes conditions precedent to close. The CDMA provides a path for the parties to reach final definitive documents and FID.
Balance Sheet and Liquidity Update
On April 26, 2023, CRC amended its existing Revolving Credit Facility. The amended Revolving Credit Facility provides for an initial aggregate commitment of $592 million and a borrowing base of $1.2 billion. CRC's borrowing base for the Revolving Credit Facility was also reaffirmed at $1.2 billion on April 26, 2023. The amendments included, among other things:
- Extending the maturity date to July 31, 2027 (subject to a springing maturity to August 4, 2025 if any of our Senior Notes are outstanding on that date);
- Increasing CRC's ability to make certain restricted payments (such as dividends and share repurchases) and certain investments (including in its carbon management business);
- Releasing liens on certain assets securing the loans made under the Revolving Credit Facility, including CRC's Elk Hills power plant;
- Extending the period for which we can enter into hedges on our production from 48 months to 60 months; and
- Increasing CRC's capacity to issue letters of credit from $200 million to $250 million.
CRC also amended the interest rates and fees it pays under its Revolving Credit Facility. At CRC's election, borrowings under the amended Revolving Credit Facility may be alternate base rate (ABR) loans or term SOFR loans, plus an applicable margin. ABR loans bear interest at a rate equal to the highest of (i) the federal funds effective rate plus 0.50%, (ii) the administrative agent prime rate and (iii) the one-month SOFR rate plus 1%. Term SOFR loans bear interest at term SOFR, plus an additional 10 basis points per annum credit spread adjustment. The applicable margin is adjusted based on the commitment utilization percentage and will vary from (i) in the case of ABR loans, 1.50% to 2.50% and (ii) in the case of term SOFR loans, 2.50% to 3.50%. CRC also pays customary fees and expenses. Interest is payable quarterly for ABR loans and at the end of the applicable interest period for term SOFR loans, but not less than quarterly. We also pay a commitment fee on unused capacity ranging from 37.5 to 50 basis points per annum, depending on the percentage of the commitment utilized.
As of March 31, 2023, CRC had liquidity of $931 million, which consisted of $477 million in unrestricted cash and $454 million of available borrowing capacity under its Revolving Credit Facility which is net of $148 million of letters of credit.
Leadership Changes
On February 24, 2023, CRC announced that Francisco J. Leon, its current Executive Vice President and Chief Financial Officer, will succeed Mark A. (Mac) McFarland as its President and Chief Executive Officer, and joined CRC's Board of Directors. Mr. McFarland will continue to serve as a non-executive member of CRC's Board of Directors and Chair of the Board of its Carbon TerraVault subsidiary. Manuela (Nelly) Molina has been appointed Executive Vice President and Chief Financial Officer, effective May 8, 2023.
Shareholder Return Strategy
CRC continues to prioritize shareholder returns and therefore dedicates a significant portion of its free cash flow to shareholders in the form of dividends and share repurchases.
During the first quarter of 2023, CRC repurchased 1.4 million shares for $59 million or an average price of $41.25 per share. Since the inception of the Share Repurchase Program in May 2021 through March 31, 2023, 12,880,024 shares have been repurchased for $519 million at an average price of $40.31 per share. These total repurchases represent 15% of CRC’s shares outstanding at its bankruptcy emergence in October 2020.
On April 28, 2023, CRC's Board of Directors declared a quarterly cash dividend of $0.2825 per share of common stock. The dividend is payable to shareholders of record on June 1, 2023 and will be paid on June 16, 2023.
Through March 31, 2023, CRC has returned $612 million of cash to its shareholders, including $519 million in share repurchases and $93 million of dividends. These figures exclude share repurchases made after March 31, 2023 as well as the $20 million second quarter dividend declared and payable in June 2023.
Upcoming Investor Conference Participation
CRC's executives will be participating in the following events in May through July of 2023:
- 2023 Citi Energy & Climate Technology Conference on May 9 to 10 in Boston, MA
- Goldman Sachs Eighth Annual Leveraged Finance and Credit Conference on May 22 to 24 in Rancho Palos Verdes, CA
- MS Sustainable Finance Summit on May 24 in New York City, NY
- Stifel 2023 Cross Sector Insight Conference on June 6 in Boston, MA
- 2023 RBC Capital Markets Global Energy, Power & Infrastructure Conference on June 7 in New York City, NY
- 2023 BofA Securities Energy Credit Conference on June 8 in New York City, NY
- 2023 JP Morgan Energy, Power & Renewables Conference on June 21 to 22 in New York City, NY
- 2023 TD Calgary Energy Conference on July 11 to 12 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
To participate in the conference call scheduled for May 2, 2023, at 1:00 p.m. Eastern Time, please dial (877) 328-5505 (International calls please dial +1 (412) 317-5421) or access via webcast at www.crc.com 15 minutes prior to the scheduled start time to register. Participants may also pre-register for the conference call at https://dpregister.com/sreg/10177066/f8cf780338. A digital replay of the conference call will be archived for approximately 90 days and supplemental slides for the conference call will be available online in the Investor Relations section of www.crc.com.
(1) See Attachment 2 for the non-GAAP financial measures of adjusted EBITDAX, operating costs per BOE (excluding effects of PSCs), adjusted net income (loss), adjusted net income (loss) per share - basic and diluted, free cash flow, adjusted G&A and adjusted capital, including reconciliations to their most directly comparable GAAP measure, where applicable. For the full year 2023 and 2Q23 estimates of the non-GAAP measure of free cash flow, adjusted G&A and adjusted capital, including reconciliations to their most directly comparable GAAP measure, see Attachment 7. |
(2) Calculated as $477 million of available cash plus $602 million of capacity on CRC's Revolving Credit Facility less $148 million in outstanding letters of credit. |
(3) Current guidance assumes a 2023 Brent price of $79.54 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $2.92 per mcf and a 2Q23 Brent price of $79.69 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $2.22 per mcf. CRC's share of production under PSC contracts decreases when commodity prices rise and increases when prices fall. |
(4) Adjusted E&P Capital and Adjusted CMB Capital are Non-GAAP measures. These measures reflect the reclassification of certain E&P, Corporate & Other Capital to CMB Capital related to the investment in facilities to advance carbon sequestration activities. For the full year 2023 and 2Q23 estimates of the non-GAAP measure of free cash flow, including reconciliations to their most directly comparable GAAP measure, see Attachment 7. |
(5) CMB Expenses includes lease cost for sequestration easements, advocacy, and other startup related costs. |
About Carbon TerraVault
Carbon TerraVault Holdings, LLC (CTV), a subsidiary of CRC, provides services that include the capture, transport and storage of carbon dioxide for its customers. CTV is engaged in a series of CCS projects that inject CO2 captured from industrial sources into depleted underground reservoirs and permanently store CO2 deep underground. For more information about CTV, please visit www.carbonterravault.com.
About California Resources Corporation
California Resources Corporation (CRC) is an independent energy and carbon management company committed to energy transition. CRC produces some of the lowest carbon intensity oil in the US and is focused on maximizing the value of its land, mineral and technical resources for decarbonization efforts. For more information about CRC, please visit www.crc.com.
Forward-Looking Statements
This document contains statements that CRC believes to be “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than historical facts are forward-looking statements, and include statements regarding CRC's future financial position, business strategy, projected revenues, earnings, costs, capital expenditures and plans and objectives of management for the future. Words such as "expect," “could,” “may,” "anticipate," "intend," "plan," “ability,” "believe," "seek," "see," "will," "would," “estimate,” “forecast,” "target," “guidance,” “outlook,” “opportunity” or “strategy” or similar expressions are generally intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements.
Although CRC believes the expectations and forecasts reflected in its forward-looking statements are reasonable, they are inherently subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond CRC's control. No assurance can be given that such forward-looking statements will be correct or achieved or that the assumptions are accurate or will not change over time. Particular uncertainties that could cause CRC's actual results to be materially different than those expressed in its forward-looking statements include:
- fluctuations in commodity prices, including supply and demand considerations for CRC's products and services;
- decisions as to production levels and/or pricing by OPEC or U.S. producers in future periods;
- government policy, war and political conditions and events, including the war in Ukraine and oil sanctions on Russia, Iran and others;
- regulatory actions and changes that affect the oil and gas industry generally and CRC in particular, including (1) the availability or timing of, or conditions imposed on, permits and approvals necessary for drilling or development activities or CRC's carbon management business; (2) the management of energy, water, land, greenhouse gases (GHGs) or other emissions, (3) the protection of health, safety and the environment, or (4) the transportation, marketing and sale of CRC's products;
- the impact of inflation on future expenses and changes generally in the prices of goods and services;
- changes in business strategy and CRC's capital plan;
- lower-than-expected production or higher-than-expected production decline rates;
- changes to CRC's estimates of reserves and related future cash flows, including changes arising from CRC's inability to develop such reserves in a timely manner, and any inability to replace such reserves;
- the recoverability of resources and unexpected geologic conditions;
- general economic conditions and trends, including conditions in the worldwide financial, trade and credit markets;
- production-sharing contracts' effects on production and operating costs;
- the lack of available equipment, service or labor price inflation;
- limitations on transportation or storage capacity and the need to shut-in wells;
- any failure of risk management;
- results from operations and competition in the industries in which CRC operates;
- CRC's ability to realize the anticipated benefits from prior or future efforts to reduce costs;
- environmental risks and liability under federal, regional, state, provincial, tribal, local and international environmental laws and regulations (including remedial actions);
- the creditworthiness and performance of CRC's counterparties, including financial institutions, operating partners, CCS project participants and other parties;
- reorganization or restructuring of CRC's operations;
- CRC's ability to claim and utilize tax credits or other incentives in connection with its CCS projects;
- CRC's ability to realize the benefits contemplated by its energy transition strategies and initiatives, including CCS projects and other renewable energy efforts;
- CRC's ability to successfully identify, develop and finance carbon capture and storage projects and other renewable energy efforts, including those in connection with the Carbon TerraVault JV;
- CRC's ability to convert its CDMAs to definitive agreements and enter into other offtake agreements;
- CRC's ability to maximize the value of its carbon management business and operate it on a stand-alone basis;
- CRC's ability to successfully develop infrastructure projects and enter into third party contracts on contemplated terms;
- uncertainty around the accounting of emissions and 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.
Attachment 1 |
|||||||||||
SUMMARY OF RESULTS |
|
|
|
|
|
||||||
|
|
|
|
|
|
||||||
|
1st Quarter |
|
4th Quarter |
|
1st Quarter |
||||||
($ and shares in millions, except per share amounts) |
|
2023 |
|
|
|
2022 |
|
|
|
2022 |
|
|
|
|
|
|
|
||||||
Statements of Operations: |
|
|
|
|
|
||||||
Revenues |
|
|
|
|
|
||||||
Oil, natural gas and NGL sales |
$ |
715 |
|
|
$ |
617 |
|
|
$ |
628 |
|
Net gain (loss) from commodity derivatives |
|
42 |
|
|
|
(132 |
) |
|
|
(562 |
) |
Sales of purchased natural gas |
|
184 |
|
|
|
94 |
|
|
|
32 |
|
Electricity sales |
|
68 |
|
|
|
90 |
|
|
|
34 |
|
Other revenue |
|
15 |
|
|
|
13 |
|
|
|
21 |
|
Total operating revenues |
|
1,024 |
|
|
|
682 |
|
|
|
153 |
|
|
|
|
|
|
|
||||||
Operating Expenses |
|
|
|
|
|
||||||
Operating costs |
|
254 |
|
|
|
199 |
|
|
|
182 |
|
General and administrative expenses |
|
65 |
|
|
|
59 |
|
|
|
48 |
|
Depreciation, depletion and amortization |
|
58 |
|
|
|
49 |
|
|
|
49 |
|
Asset impairment |
|
3 |
|
|
|
— |
|
|
|
— |
|
Taxes other than on income |
|
42 |
|
|
|
42 |
|
|
|
34 |
|
Exploration expense |
|
1 |
|
|
|
1 |
|
|
|
1 |
|
Purchased natural gas expense |
|
124 |
|
|
|
87 |
|
|
|
21 |
|
Electricity generation expenses |
|
49 |
|
|
|
68 |
|
|
|
24 |
|
Transportation costs |
|
17 |
|
|
|
13 |
|
|
|
12 |
|
Accretion expense |
|
12 |
|
|
|
11 |
|
|
|
11 |
|
Other operating expenses, net |
|
13 |
|
|
|
20 |
|
|
|
14 |
|
Total operating expenses |
|
638 |
|
|
|
549 |
|
|
|
396 |
|
Net gain on asset divestitures |
|
7 |
|
|
|
(1 |
) |
|
|
54 |
|
Operating Income (Loss) |
|
393 |
|
|
|
132 |
|
|
|
(189 |
) |
|
|
|
|
|
|
||||||
Non-Operating (Expenses) Income |
|
|
|
|
|
||||||
Interest and debt expense |
|
(14 |
) |
|
|
(14 |
) |
|
|
(13 |
) |
Loss from investment in unconsolidated subsidiary |
|
(2 |
) |
|
|
(1 |
) |
|
|
— |
|
Other non-operating (expenses) income, net |
|
(1 |
) |
|
|
— |
|
|
|
1 |
|
|
|
|
|
|
|
||||||
Net Income (Loss) Before Income Taxes |
|
376 |
|
|
|
117 |
|
|
|
(201 |
) |
Income tax (provision) benefit |
|
(75 |
) |
|
|
(34 |
) |
|
|
26 |
|
Net income (Loss) |
$ |
301 |
|
|
$ |
83 |
|
|
$ |
(175 |
) |
|
|
|
|
|
|
||||||
Net income (loss) attributable to common stock per share - basic |
$ |
4.22 |
|
|
$ |
1.14 |
|
|
$ |
(2.23 |
) |
Net income (loss) attributable to common stock per share - diluted |
$ |
4.09 |
|
|
$ |
1.11 |
|
|
$ |
(2.23 |
) |
|
|
|
|
|
|
||||||
Adjusted net income |
$ |
193 |
|
|
$ |
93 |
|
|
$ |
91 |
|
Adjusted net income per share - basic |
$ |
2.71 |
|
|
$ |
1.28 |
|
|
$ |
1.16 |
|
Adjusted net income per share - diluted |
$ |
2.63 |
|
|
$ |
1.24 |
|
|
$ |
1.13 |
|
|
|
|
|
|
|
||||||
Weighted-average common shares outstanding - basic |
|
71.3 |
|
|
|
72.7 |
|
|
|
78.5 |
|
Weighted-average common shares outstanding - diluted |
|
73.5 |
|
|
|
75.0 |
|
|
|
78.5 |
|
|
|
|
|
|
|
||||||
Adjusted EBITDAX |
$ |
358 |
|
|
$ |
208 |
|
|
$ |
206 |
|
Effective tax rate |
|
20 |
% |
|
|
29 |
% |
|
|
13 |
% |
|
|
|
|
|
|
||||||
|
1st Quarter |
|
4th Quarter |
|
1st Quarter |
||||||
($ in millions) |
|
2023 |
|
|
|
2022 |
|
|
|
2022 |
|
Cash Flow Data: |
|
|
|
|
|
||||||
Net cash provided by operating activities |
$ |
310 |
|
|
$ |
114 |
|
|
$ |
160 |
|
Net cash used in investing activities |
$ |
(61 |
) |
|
$ |
(79 |
) |
|
$ |
(53 |
) |
Net cash used in financing activities |
$ |
(79 |
) |
|
$ |
(86 |
) |
|
$ |
(84 |
) |
|
|
|
|
|
|
||||||
|
March 31, |
|
December 31, |
|
|
||||||
($ in millions) |
|
2023 |
|
|
|
2022 |
|
|
|
||
Selected Balance Sheet Data: |
|
|
|
|
|
||||||
Total current assets |
$ |
972 |
|
|
$ |
864 |
|
|
|
||
Property, plant and equipment, net |
$ |
2,764 |
|
|
$ |
2,786 |
|
|
|
||
Deferred tax asset |
$ |
117 |
|
|
$ |
164 |
|
|
|
||
Total current liabilities |
$ |
717 |
|
|
$ |
894 |
|
|
|
||
Long-term debt, net |
$ |
592 |
|
|
$ |
592 |
|
|
|
||
Noncurrent asset retirement obligations |
$ |
424 |
|
|
$ |
432 |
|
|
|
||
Stockholders' Equity |
$ |
2,092 |
|
|
$ |
1,864 |
|
|
|
||
|
|
|
|
|
|
||||||
GAINS AND LOSSES FROM COMMODITY DERIVATIVES |
|
||||||||||
|
|
|
|
|
|
||||||
|
1st Quarter |
|
4th Quarter |
|
1st Quarter |
||||||
($ millions) |
|
2023 |
|
|
|
2022 |
|
|
|
2022 |
|
|
|
|
|
|
|
||||||
Non-cash derivative gain (loss) |
$ |
107 |
|
|
$ |
2 |
|
|
$ |
(381 |
) |
Net payments on settled commodity contracts |
|
(65 |
) |
|
|
(134 |
) |
|
|
(181 |
) |
Net gain (loss) from commodity derivatives |
$ |
42 |
|
|
$ |
(132 |
) |
|
$ |
(562 |
) |
|
|
|
|
|
|
||||||
| CAPITAL INVESTMENTS |
|
||||||||
|
|
|
|
|
|
||||
|
1st Quarter |
|
4th Quarter |
|
1st Quarter |
||||
($ millions) |
2023 |
|
2022 |
|
2022 |
||||
|
|
|
|
|
|
||||
Facilities (1) |
$ |
9 |
|
$ |
19 |
|
|
$ |
32 |
Drilling |
|
25 |
|
|
48 |
|
|
|
59 |
Workovers |
|
6 |
|
|
14 |
|
|
|
6 |
Total E&P capital |
|
40 |
|
|
81 |
|
|
|
97 |
CMB (1)(2) |
|
1 |
|
|
(13 |
) |
|
|
1 |
Corporate and other |
|
6 |
|
|
7 |
|
|
|
1 |
Total capital program |
$ |
47 |
|
$ |
75 |
|
|
$ |
99 |
|
|
|
|
|
|
||||
(1) Facilities capital includes $1 million, $3 million and $2 million in the first quarter of 2023, fourth quarter of 2022 and first quarter of 2022, respectively, to build replacement water injection facilities which will allow CRC to divert produced water away from a depleted oil and natural gas reservoir held by the Carbon TerraVault JV. Construction of these facilities supports the advancement of CRC’s carbon management business and CRC reported these amounts as part of adjusted CMB capital in this press release. Where adjusted CMB capital is presented, CRC removed the amounts from facilities capital and presented adjusted E&P, Corporate and Other capital. |
|||||||||
(2) In the fourth quarter of 2022, $14 million of capital investments was reclassified from PP&E to other noncurrent assets. |
|||||||||
Attachment 2 |
||||||||
NON-GAAP FINANCIAL MEASURES AND RECONCILIATIONS |
||||||||
|
||||||||
To supplement the presentation of its financial results prepared in accordance with U.S generally accepted accounting principles (GAAP), management uses certain non-GAAP measures to assess its financial condition, results of operations and cash flows. The non-GAAP measures include adjusted net income (loss), adjusted EBITDAX, E&P, Corporate & Other adjusted EBITDAX, CMB adjusted EBITDAX, free cash flow, E&P, Corporate & Other free cash flow, CMB free cash flow, adjusted general and administrative expenses, operating costs per BOE, and adjusted total capital among others. These measures are also widely used by the industry, the investment community and our 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 our financial performance, such as our cost of capital and tax structure, as well as the effect of acquisition and development costs of our assets. Management believes that the non-GAAP measures presented, when viewed in combination with its 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 press release, including reconciliations to their most directly comparable GAAP measure where applicable. |
||||||||
|
|
|
|
|
|
|
|
|
ADJUSTED NET INCOME (LOSS) |
|||||||||||
|
|||||||||||
Adjusted net income (loss) and adjusted net income (loss) per share are non-GAAP measures. CRC defines adjusted net income as net income excluding the effects of significant transactions and events that affect earnings but vary widely and unpredictably in nature, timing and amount. These events may recur, even across successive reporting periods. Management believes these non-GAAP measures provide useful information to the industry and the investment community interested in comparing our 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) |
|
2023 |
|
|
|
2022 |
|
|
|
2022 |
|
Net income (loss) |
$ |
301 |
|
|
$ |
83 |
|
|
$ |
(175 |
) |
Unusual, infrequent and other items: |
|
|
|
|
|
||||||
Non-cash derivative (gain) loss |
|
(107 |
) |
|
|
(2 |
) |
|
|
381 |
|
Asset impairment |
|
3 |
|
|
|
— |
|
|
|
— |
|
Severance and termination costs |
|
1 |
|
|
|
— |
|
|
|
— |
|
Net (gain) loss on asset divestitures |
|
(7 |
) |
|
|
1 |
|
|
|
(54 |
) |
Rig termination expenses |
|
1 |
|
|
|
2 |
|
|
|
— |
|
Other, net |
|
2 |
|
|
|
13 |
|
|
|
1 |
|
Total unusual, infrequent and other items |
|
(107 |
) |
|
|
14 |
|
|
|
328 |
|
Income tax provision (benefit) of adjustments at effective tax rate |
|
30 |
|
|
|
(4 |
) |
|
|
(93 |
) |
Income tax (benefit) provision - out of period |
|
(31 |
) |
|
|
— |
|
|
|
31 |
|
|
|
|
|
|
|
||||||
Adjusted net income attributable to common stock |
$ |
193 |
|
|
$ |
93 |
|
|
$ |
91 |
|
|
|
|
|
|
|
||||||
Net income (loss) attributable to common stock per share - basic |
$ |
4.22 |
|
|
$ |
1.14 |
|
|
$ |
(2.23 |
) |
Net income (loss) attributable to common stock per share - diluted |
$ |
4.09 |
|
|
$ |
1.11 |
|
|
$ |
(2.23 |
) |
Adjusted net income per share - basic |
$ |
2.71 |
|
|
$ |
1.28 |
|
|
$ |
1.16 |
|
Adjusted net income per share - diluted |
$ |
2.63 |
|
|
$ |
1.24 |
|
|
$ |
1.13 |
|
|
|
|
|
|
|
||||||
| 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) |
|
2023 |
|
|
|
2022 |
|
|
|
2022 |
|
Net income (loss) |
$ |
301 |
|
|
$ |
83 |
|
|
$ |
(175 |
) |
Interest and debt expense |
|
14 |
|
|
|
14 |
|
|
|
13 |
|
Depreciation, depletion and amortization |
|
58 |
|
|
|
49 |
|
|
|
49 |
|
Income tax provision (benefit) |
|
75 |
|
|
|
34 |
|
|
|
(26 |
) |
Exploration expense |
|
1 |
|
|
|
1 |
|
|
|
1 |
|
Interest income |
|
(4 |
) |
|
|
(3 |
) |
|
|
— |
|
Unusual, infrequent and other items (1) |
|
(107 |
) |
|
|
14 |
|
|
|
328 |
|
Non-cash items |
|
|
|
|
|
||||||
Accretion expense |
|
12 |
|
|
|
11 |
|
|
|
11 |
|
Stock-based compensation |
|
7 |
|
|
|
4 |
|
|
|
4 |
|
Post-retirement medical and pension |
|
1 |
|
|
|
1 |
|
|
|
1 |
|
Adjusted EBITDAX |
$ |
358 |
|
|
$ |
208 |
|
|
$ |
206 |
|
|
|
|
|
|
|
||||||
Net cash provided by operating activities |
$ |
310 |
|
|
$ |
114 |
|
|
$ |
160 |
|
Cash interest payments |
|
23 |
|
|
|
2 |
|
|
|
23 |
|
Cash interest received |
|
(4 |
) |
|
|
(3 |
) |
|
|
— |
|
Exploration expenditures |
|
1 |
|
|
|
1 |
|
|
|
1 |
|
Working capital changes |
|
28 |
|
|
|
94 |
|
|
|
22 |
|
Adjusted EBITDAX |
$ |
358 |
|
|
$ |
208 |
|
|
$ |
206 |
|
|
|
|
|
|
|
||||||
E&P, Corporate & Other Adjusted EBITDAX |
$ |
367 |
|
|
$ |
223 |
|
|
$ |
208 |
|
CMB Adjusted EBITDAX |
$ |
(9 |
) |
|
$ |
(15 |
) |
|
$ |
(2 |
) |
|
|
|
|
|
|
||||||
Adjusted EBITDAX per Boe |
$ |
44.55 |
|
|
$ |
24.94 |
|
|
$ |
25.89 |
|
|
|
|
|
|
|
||||||
(1) See Adjusted Net Income (Loss) reconciliation. |
|
|
|
|
|||||||
FREE CASH FLOW |
|||||||||||
|
|
|
|
|
|
||||||
Management uses free cash flow, which is defined by CRC as net cash provided by operating activities less capital investments, as a measure of liquidity. The following table presents a reconciliation of CRC's net cash provided by operating activities to free cash flow. CRC supplemented its non-GAAP measure of free cash flow with free cash flow of its exploration and production and corporate items (Free Cash Flow for E&P, Corporate & Other), which it believes is a useful measure for investors to understand the results of CRC's core oil and gas business. CRC defines Free Cash Flow for E&P, Corporate & Other as consolidated free cash flow less results attributable to its carbon management business (CMB). |
|||||||||||
|
|
|
|
|
|
||||||
|
1st Quarter |
|
4th Quarter |
|
1st Quarter |
||||||
($ millions) |
|
2023 |
|
|
|
2022 |
|
|
|
2022 |
|
|
|
|
|
|
|
||||||
Net cash provided by operating activities |
$ |
310 |
|
|
$ |
114 |
|
|
$ |
160 |
|
Capital investments |
|
(47 |
) |
|
|
(75 |
) |
|
|
(99 |
) |
Free cash flow |
$ |
263 |
|
|
$ |
39 |
|
|
$ |
61 |
|
|
|
|
|
|
|
||||||
E&P, Corporate and Other |
$ |
270 |
|
|
$ |
61 |
|
|
$ |
64 |
|
CMB |
$ |
(7 |
) |
|
$ |
(22 |
) |
|
$ |
(3 |
) |
|
|
|
|
|
|
||||||
Adjustments to capital investments: |
|
|
|
|
|
||||||
Replacement water facilities(2) |
$ |
1 |
|
|
$ |
3 |
|
|
$ |
2 |
|
Adjusted capital investments: |
|
|
|
|
|
||||||
E&P, Corporate and Other |
$ |
45 |
|
|
$ |
85 |
|
|
$ |
96 |
|
CMB |
$ |
2 |
|
|
$ |
(10 |
) |
|
$ |
3 |
|
|
|
|
|
|
|
||||||
Adjusted free cash flow(1): |
|
|
|
|
|
||||||
|
|||||||||||
E&P, Corporate and Other |
$ |
271 |
|
|
$ |
64 |
|
|
$ |
66 |
|
CMB |
$ |
(8 |
) |
|
$ |
(25 |
) |
|
$ |
(5 |
) |
|
|
|
|
|
|
||||||
(1)Adjusted free cash flow is defined as net cash provided by operating activities less adjusted capital investments. |
|||||||||||
(2) Facilities capital includes $1 million, $3 million and $2 million in the first quarter of 2023, fourth quarter of 2022 and first quarter of 2022, respectively, to build replacement water injection facilities which will allow CRC to divert produced water away from a depleted oil and natural gas reservoir held by the Carbon TerraVault JV. Construction of these facilities supports the advancement of CRC’s carbon management business and CRC reported these amounts as part of adjusted CMB capital in this press release. Where adjusted CMB capital is presented, CRC removed the amounts from facilities capital and presented adjusted E&P, Corporate and Other capital. |
|||||||||||
ADJUSTED GENERAL & ADMINISTRATIVE EXPENSES |
|||||||||||
|
|
|
|
|
|
||||||
Management uses a measure called adjusted general and administrative (G&A) expenses to provide useful information to investors interested in comparing our costs between periods and performance to our peers. CRC supplemented its non-GAAP measure of adjusted general and administrative expenses with adjusted general and administrative expenses of its exploration and production and corporate items (adjusted general & administrative expenses for E&P, Corporate & Other) which it believes is a useful measure for investors to understand the results or CRC's core oil and gas business. CRC defines adjusted general & administrative Expenses for E&P, Corporate & Other as consolidated adjusted general and administrative expenses less results attributable to its carbon management business (CMB). |
|||||||||||
|
|
|
|
|
|
||||||
|
1st Quarter |
|
4th Quarter |
|
1st Quarter |
||||||
($ millions) |
|
2023 |
|
|
|
2022 |
|
|
|
2022 |
|
General and administrative expenses |
$ |
65 |
|
|
$ |
59 |
|
|
$ |
48 |
|
Stock-based compensation |
|
(7 |
) |
|
|
(4 |
) |
|
|
(4 |
) |
Other |
|
(3 |
) |
|
|
(2 |
) |
|
|
— |
|
Adjusted G&A expenses |
$ |
55 |
|
|
$ |
53 |
|
|
$ |
44 |
|
|
|
|
|
|
|
||||||
E&P, Corporate and Other adjusted G&A expenses |
$ |
52 |
|
|
$ |
51 |
|
|
$ |
43 |
|
CMB adjusted G&A expenses |
$ |
3 |
|
|
$ |
2 |
|
|
$ |
1 |
|
|
|
|
|
|
|
||||||
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) |
|
2023 |
|
|
|
2022 |
|
|
|
2022 |
|
Energy operating costs (1) |
$ |
15.56 |
|
|
$ |
9.56 |
|
|
$ |
9.16 |
|
Gas processing costs (2) |
|
0.62 |
|
|
|
0.48 |
|
|
|
0.56 |
|
Non-energy operating costs (3) |
|
15.43 |
|
|
|
13.82 |
|
|
|
13.15 |
|
Operating costs |
$ |
31.61 |
|
|
$ |
23.86 |
|
|
$ |
22.87 |
|
|
|
|
|
|
|
||||||
Costs attributable to PSCs |
|
|
|
|
|
||||||
Excess energy operating costs attributable to PSCs |
$ |
(1.19 |
) |
|
$ |
(0.76 |
) |
|
$ |
(0.90 |
) |
Excess non-energy operating costs attributable to PSCs |
|
(1.04 |
) |
|
|
(1.14 |
) |
|
|
(1.40 |
) |
Excess costs attributable to PSCs |
$ |
(2.23 |
) |
|
$ |
(1.90 |
) |
|
$ |
(2.30 |
) |
|
|
|
|
|
|
||||||
Energy operating costs, excluding effect of PSCs (1) |
$ |
14.37 |
|
|
$ |
8.80 |
|
|
$ |
8.26 |
|
Gas processing costs, excluding effect of PSCs (2) |
|
0.62 |
|
|
|
0.48 |
|
|
|
0.56 |
|
Non-energy operating costs, excluding effect of PSCs (3) |
|
14.39 |
|
|
|
12.68 |
|
|
|
11.75 |
|
Operating costs, excluding effects of PSCs |
$ |
29.38 |
|
|
$ |
21.96 |
|
|
$ |
20.57 |
|
|
|
|
|
|
|
||||||
(1) Energy operating costs consist of purchased natural gas used to generate electricity for operations and steamfloods, purchased electricity and internal costs to generate electricity used in CRC's operations. |
|||||||||||
(2) Gas processing costs include costs associated with compression, maintenance and other activities needed to run CRC's gas processing facilities at Elk Hills. |
|||||||||||
(3) Non-energy operating costs equal total operating costs less energy operating costs and gas processing costs. Purchased natural gas used to generate steam in CRC's steamfloods was reclassified from non-energy operating costs to energy operating costs beginning in the third quarter of 2022. All prior periods have been updated to conform to this presentation. |
|||||||||||
Attachment 3 |
|||||
PRODUCTION STATISTICS |
|
|
|
|
|
|
1st Quarter |
|
4th Quarter |
|
1st Quarter |
Net Production Per Day |
2023 |
|
2022 |
|
2022 |
Oil (MBbl/d) |
|
|
|
|
|
San Joaquin Basin |
35 |
|
36 |
|
38 |
Los Angeles Basin |
20 |
|
19 |
|
18 |
Total |
55 |
|
55 |
|
56 |
|
|
|
|
|
|
NGLs (MBbl/d) |
|
|
|
|
|
San Joaquin Basin |
11 |
|
11 |
|
9 |
Total |
11 |
|
11 |
|
9 |
|
|
|
|
|
|
Natural Gas (MMcf/d) |
|
|
|
|
|
San Joaquin Basin |
119 |
|
129 |
|
121 |
Los Angeles Basin |
1 |
|
1 |
|
1 |
Sacramento Basin |
16 |
|
17 |
|
19 |
Total |
136 |
|
147 |
|
141 |
|
|
|
|
|
|
Total Production (MBoe/d) |
89 |
|
91 |
|
88 |
|
|
|
|
|
|
Gross Operated and Net Non-Operated |
1st Quarter |
|
4th Quarter |
|
1st Quarter |
Production Per Day |
2023 |
|
2022 |
|
2022 |
Oil (MBbl/d) |
|
|
|
|
|
San Joaquin Basin |
39 |
|
40 |
|
43 |
Los Angeles Basin |
26 |
|
25 |
|
26 |
Total |
65 |
|
65 |
|
69 |
|
|
|
|
|
|
NGLs (MBbl/d) |
|
|
|
|
|
San Joaquin Basin |
12 |
|
12 |
|
9 |
Total |
12 |
|
12 |
|
9 |
|
|
|
|
|
|
Natural Gas (MMcf/d) |
|
|
|
|
|
San Joaquin Basin |
135 |
|
136 |
|
129 |
Los Angeles Basin |
7 |
|
8 |
|
8 |
Sacramento Basin |
20 |
|
21 |
|
23 |
Total |
162 |
|
165 |
|
160 |
|
|
|
|
|
|
Total Production (MBoe/d) |
103 |
|
105 |
|
105 |
|
|
|
|
|
|
Note: MBbl/d refers to thousands of barrels per day; MMcf/d refers to millions of cubic feet per day; MBoe/d refers to thousands of barrels of oil equivalent (Boe) per day. Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet of natural gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence. |
|||||
Attachment 4 |
|||||||||||
PRICE STATISTICS |
|
|
|
|
|
||||||
|
1st Quarter |
|
4th Quarter |
|
1st Quarter |
||||||
|
|
2023 |
|
|
|
2022 |
|
|
|
2022 |
|
Oil ($ per Bbl) |
|
|
|
|
|
||||||
Realized price with derivative settlements |
$ |
63.04 |
|
|
$ |
61.33 |
|
|
$ |
60.30 |
|
Realized price without derivative settlements |
$ |
78.68 |
|
|
$ |
87.15 |
|
|
$ |
96.13 |
|
|
|
|
|
|
|
||||||
NGLs ($/Bbl) |
$ |
58.88 |
|
|
$ |
56.55 |
|
|
$ |
78.63 |
|
|
|
|
|
|
|
||||||
Natural gas ($/Mcf) |
|
|
|
|
|
||||||
Realized price with derivative settlements |
$ |
21.56 |
|
|
$ |
8.51 |
|
|
$ |
6.28 |
|
Realized price without derivative settlements |
$ |
21.56 |
|
|
$ |
8.73 |
|
|
$ |
6.28 |
|
|
|
|
|
|
|
||||||
Index Prices |
|
|
|
|
|
||||||
Brent oil ($/Bbl) |
$ |
82.22 |
|
|
$ |
88.60 |
|
|
$ |
97.38 |
|
WTI oil ($/Bbl) |
$ |
76.13 |
|
|
$ |
82.64 |
|
|
$ |
94.29 |
|
NYMEX average monthly settled price ($/MMBtu) |
$ |
3.42 |
|
|
$ |
6.26 |
|
|
$ |
4.95 |
|
|
|
|
|
|
|
||||||
Realized Prices as Percentage of Index Prices |
|
|
|
|
|
||||||
Oil with derivative settlements as a percentage of Brent |
|
77 |
% |
|
|
69 |
% |
|
|
62 |
% |
Oil without derivative settlements as a percentage of Brent |
|
96 |
% |
|
|
98 |
% |
|
|
99 |
% |
|
|
|
|
|
|
||||||
Oil with derivative settlements as a percentage of WTI |
|
83 |
% |
|
|
74 |
% |
|
|
64 |
% |
Oil without derivative settlements as a percentage of WTI |
|
103 |
% |
|
|
105 |
% |
|
|
102 |
% |
|
|
|
|
|
|
||||||
NGLs as a percentage of Brent |
|
72 |
% |
|
|
64 |
% |
|
|
81 |
% |
NGLs as a percentage of WTI |
|
77 |
% |
|
|
68 |
% |
|
|
83 |
% |
|
|
|
|
|
|
||||||
Natural gas with derivative settlements as a percentage of NYMEX contract month average |
|
630 |
% |
|
|
136 |
% |
|
|
127 |
% |
|
|
|
|
|
|
||||||
Natural gas without derivative settlements as a percentage of NYMEX contract month average |
|
630 |
% |
|
|
139 |
% |
|
|
127 |
% |
Attachment 5 |
|||||||||
FIRST QUARTER 2023 DRILLING ACTIVITY |
|
|
|
|
|
|
|
|
|
|
San Joaquin |
|
Los Angeles |
|
Ventura |
|
Sacramento |
|
|
Wells Drilled |
Basin |
|
Basin |
|
Basin |
|
Basin |
|
Total |
|
|
|
|
|
|
|
|
|
|
Development Wells |
|
|
|
|
|
|
|
|
|
Primary |
2 |
|
— |
|
— |
|
— |
|
2 |
Waterflood |
1 |
|
6 |
|
— |
|
— |
|
7 |
Steamflood |
— |
|
— |
|
— |
|
— |
|
— |
Total (1) |
3 |
|
6 |
|
— |
|
— |
|
9 |
|
|
|
|
|
|
|
|
|
|
(1) Includes steam injectors and drilled but uncompleted wells, which are not included in the SEC definition of wells drilled. |
|||||||||
Attachment 6 |
||||||||||
OIL HEDGES AS OF MARCH 31, 2023 |
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
Q2 2023 |
|
Q3 2023 |
|
Q4 2023 |
|
1H 2024 |
|
2H 2024 |
|
|
|
|
|
|
|
|
|
|
|
Sold Calls |
|
|
|
|
|
|
|
|
|
|
Barrels per day |
|
17,837 |
|
17,363 |
|
5,747 |
|
2,000 |
|
4,000 |
Weighted-average Brent price per barrel |
|
$60.00 |
|
$57.06 |
|
$57.06 |
|
$90.53 |
|
$90.53 |
|
|
|
|
|
|
|
|
|
|
|
Swaps |
|
|
|
|
|
|
|
|
|
|
Barrels per day |
|
16,475 |
|
17,697 |
|
27,094 |
|
3,500 |
|
1,000 |
Weighted-average Brent price per barrel |
|
$70.48 |
|
$69.27 |
|
$70.73 |
|
$78.79 |
|
$77.20 |
|
|
|
|
|
|
|
|
|
|
|
Net Purchased Puts (1) |
|
|
|
|
|
|
|
|
|
|
Barrels per day |
|
17,837 |
|
17,363 |
|
5,747 |
|
5,467 |
|
4,000 |
Weighted-average Brent price per barrel |
|
$76.25 |
|
$76.25 |
|
$76.25 |
|
$71.80 |
|
$66.25 |
|
|
|
|
|
|
|
|
|
|
|
(1) Purchased puts and sold puts with the same strike price have been presented on a net basis. |
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Attachment 7 |
|
2023 Estimated |
||||
TOTAL CRC GUIDANCE1 |
Consolidated |
|
CMB |
|
E&P, Corporate & Other |
Net Total Production (MBoe/d) |
85 - 91 |
|
|
|
85 - 91 |
Net Oil Production (MBbl/d) |
51 - 55 |
|
|
|
51 - 55 |
Operating Costs ($ millions) |
$815 - $865 |
|
|
|
$815 - $865 |
CMB Expenses2 ($ millions) |
$25 - $35 |
|
$25 - $35 |
|
|
Adjusted General and Administrative Expenses ($ millions) |
$195 - $225 |
|
$10 - $15 |
|
$185 - $210 |
Adjusted Total Capital3 ($ millions) |
$200 - $245 |
|
$15 - $25 |
|
$185 - $220 |
Free Cash Flow ($ millions) |
$360 - $470 |
|
|
|
|
Adjusted Free Cash Flow ($ millions) |
|
|
($60) - ($80) |
|
$440 - $530 |
|
|
|
|
|
|
Marketing & Trading, Net ($ millions) |
$80 - $110 |
|
|
|
$80 - $110 |
Net Electricity ($ millions) |
$70 - $110 |
|
|
|
$70 - $110 |
Transportation Expense ($ millions) |
$50 - $70 |
|
|
|
$50 - $70 |
ARO Settlement Payments* ($ millions) |
$55 - $60 |
|
|
|
$55 - $60 |
Taxes Other Than on Income* ($ millions) |
$175 - $185 |
|
|
|
$175 - $185 |
Interest and Debt Expense* ($ millions) |
$55 - $60 |
|
|
|
$55 - $60 |
Cash Income Taxes* ($ millions) |
$100 - $120 |
|
|
|
$100 - $120 |
|
|
|
|
|
|
Commodity Realizations: |
|
|
|
|
|
Oil - % of Brent: |
97% - 99% |
|
|
|
97% - 99% |
NGL - % of Brent: |
58% - 64% |
|
|
|
58% - 64% |
Natural Gas - % of NYMEX*: |
150% - 250% |
|
|
|
150% - 250% |
*Notes:
|
|||||
|
|
|
|
|
|
CRC GUIDANCE3 |
Total 2Q23E |
|
CMB 2Q23E |
|
E&P, Corp. & Other 2Q23E |
Net Total Production (MBoe/d) |
86 - 88 |
|
|
|
86 - 88 |
Net Oil Production (MBbl/d) |
54 - 52 |
|
|
|
54 - 52 |
Operating Costs ($ millions) |
$175 - $195 |
|
|
|
$175 - $195 |
CMB Expenses2 ($ millions) |
$5 - $10 |
|
$5 - $10 |
|
|
Adjusted General and Administrative Expenses1 ($ millions) |
$52 - $60 |
|
$2 - $5 |
|
$50 - $55 |
Adjusted Total Capital3 ($ millions) |
$46 - $62 |
|
$1 - $2 |
|
$45 - $60 |
Free Cash Flow1 ($ millions) |
$45 - $ 65 |
|
|
|
|
Adjusted Free Cash Flow ($ millions) |
|
|
($10) - ($15) |
|
$60 - $75 |
|
|
|
|
|
|
Marketing & Trading, Net ($ millions) |
$17 - $22 |
|
|
|
$17 - $22 |
Net Electricity ($ millions) |
$12 - $17 |
|
|
|
$12 - $17 |
Transportation Expense ($ millions) |
$10 - $15 |
|
|
|
$10 - $15 |
Cash Income Taxes ($ millions) |
$50 - $60 |
|
|
|
$50 - $60 |
|
|
|
|
|
|
Commodity Realizations: |
|
|
|
|
|
Oil - % of Brent: |
94% - 98% |
|
|
|
94% - 98% |
NGL - % of Brent: |
55% - 60% |
|
|
|
55% - 60% |
Natural Gas - % of NYMEX: |
150% - 160% |
|
|
|
150% - 160% |
See Attachment 2 for management's disclosure of its use of these non-GAAP measures and how these measures provide useful information to investors about CRC's results of operations and financial condition. CRC has supplemented its non-GAAP measures of consolidated free cash flow with free cash flow from our exploration and production and corporate items (free cash flow from E&P, Corporate & Other) which CRC believes is a useful measure for investors to understand the results of its core oil and gas business. CRC defines free cash flow from E&P, Corporate & Other as consolidated free cash flow less free cash flow attributable to CMB. |
|||||
ESTIMATED FREE CASH FLOW RECONCILIATION |
|||||||||||||||||||||||
|
2023 Estimated |
||||||||||||||||||||||
|
Consolidated |
|
CMB |
|
E&P, Corporate & Other |
||||||||||||||||||
($ millions) |
Low |
|
High |
|
Low |
|
High |
|
Low |
|
High |
||||||||||||
Net cash provided (used) by operating activities |
$ |
605 |
|
|
$ |
670 |
|
|
$ |
(55 |
) |
|
$ |
(45 |
) |
|
$ |
660 |
|
|
$ |
715 |
|
Capital investments |
|
(245 |
) |
|
|
(200 |
) |
|
|
(15 |
) |
|
|
(5 |
) |
|
|
(230 |
) |
|
|
(195 |
) |
Estimated free cash flow |
$ |
360 |
|
|
$ |
470 |
|
|
$ |
(70 |
) |
|
$ |
(50 |
) |
|
$ |
430 |
|
|
$ |
520 |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Adjustments to capital investments: |
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Replacement water facilities |
|
|
|
|
|
(10 |
) |
|
|
(10 |
) |
|
|
10 |
|
|
|
10 |
|
||||
Adjusted capital investments(3) |
|
|
|
|
$ |
(25 |
) |
|
$ |
(15 |
) |
|
$ |
(230 |
) |
|
$ |
(195 |
) |
||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net cash provided (used) by operating activities |
|
|
|
|
$ |
(55 |
) |
|
$ |
(45 |
) |
|
$ |
660 |
|
|
$ |
715 |
|
||||
Adjusted capital investments |
|
|
|
|
|
(25 |
) |
|
|
(15 |
) |
|
|
(220 |
) |
|
|
(185 |
) |
||||
Estimated adjusted free cash flow |
|
|
|
|
$ |
(80 |
) |
|
$ |
(60 |
) |
|
$ |
440 |
|
|
$ |
530 |
|
||||
|
2Q23 Estimated |
||||||||||||||||||||||
|
Consolidated |
|
CMB |
|
E&P, Corporate & Other |
||||||||||||||||||
($ millions) |
Low |
|
High |
|
Low |
|
High |
|
Low |
|
High |
||||||||||||
Net cash provided (used) by operating activities |
$ |
107 |
|
|
$ |
111 |
|
|
$ |
(13 |
) |
|
$ |
(9 |
) |
|
$ |
120 |
|
|
$ |
120 |
|
Capital investments |
|
(62 |
) |
|
|
(46 |
) |
|
|
(1 |
) |
|
|
— |
|
|
|
(61 |
) |
|
|
(46 |
) |
Estimated free cash flow |
$ |
45 |
|
|
$ |
65 |
|
|
$ |
(14 |
) |
|
$ |
(9 |
) |
|
$ |
59 |
|
|
$ |
74 |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Adjustments to capital investments: |
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Replacement water facilities |
|
|
|
|
|
(1 |
) |
|
|
(1 |
) |
|
|
1 |
|
|
|
1 |
|
||||
Adjusted capital investments(3) |
|
|
|
|
$ |
(2 |
) |
|
$ |
(1 |
) |
|
$ |
(60 |
) |
|
$ |
(45 |
) |
||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net cash provided (used) by operating activities |
|
|
|
|
$ |
(13 |
) |
|
$ |
(9 |
) |
|
$ |
120 |
|
|
$ |
120 |
|
||||
Adjusted capital investments |
|
|
|
|
|
(2 |
) |
|
|
(1 |
) |
|
|
(60 |
) |
|
|
(45 |
) |
||||
Estimated adjusted free cash flow |
|
|
|
|
$ |
(15 |
) |
|
$ |
(10 |
) |
|
$ |
60 |
|
|
$ |
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
2Q23 Estimated |
||||||||||||||||||||
|
Consolidated |
|
CMB |
|
E&P, Corporate & Other |
||||||||||||||||
($ millions) |
Low |
|
High |
|
Low |
|
High |
|
Low |
|
High |
||||||||||
General and administrative expenses |
$ |
67 |
|
|
$ |
72 |
|
|
$ |
2 |
|
$ |
5 |
|
$ |
65 |
|
|
$ |
67 |
|
Equity-settled stock-based compensation |
|
(8 |
) |
|
|
(6 |
) |
|
|
|
|
|
|
(8 |
) |
|
|
(6 |
) |
||
Other |
|
(7 |
) |
|
|
(6 |
) |
|
|
|
|
|
|
(7 |
) |
|
|
(6 |
) |
||
Estimated adjusted general and administrative expenses |
$ |
52 |
|
|
$ |
60 |
|
|
$ |
2 |
|
$ |
5 |
|
$ |
50 |
|
|
$ |
55 |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
(1) Current guidance assumes a 2023 Brent price of $79.54 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $2.92 per mcf and a 2Q23 Brent price of $79.69 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $2.22 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 our 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. |
|||||||||||||||||||||
View source version on businesswire.com: https://www.businesswire.com/news/home/20230501005705/en/
Latest directors dealings
- 1 day ago IntegraFin Holding
- 1 day ago Spirent Communications
- 1 day ago CRH (CDI)
- 1 day ago Bezant Resources
- 1 day ago EJF Investments Ltd NPV