NEWS RELEASE
California Resources Corporation Reports Strong Third Quarter 2022 Results, Announces 66% Increase in Quarterly Dividend and $200 Million Increase in Share Repurchase Program
Long Beach, November 3, 2022 - California Resources Corporation (NYSE: CRC), an independent oil and natural gas company committed to energy transition in the sector, today reported third quarter 2022 operational and financial results.
"CRC's strong financial performance, coupled with our consistent operational execution, allowed us to increase our fixed dividend by 66% and our Share Repurchase Program by an additional $200 million. Our disciplined capital allocation and shareholder return strategy demonstrate our continued commitment to our stakeholders. With these changes, CRC is on track to deliver nearly $1 billion in cumulative shareholder returns by year end 2023," said Mac McFarland, CRC’s President and Chief Executive Officer.
McFarland continued, "On the carbon management side, we continue to work with emitters, advance our permits, progress our Carbon TerraVault JV partnership and remain optimistic on our carbon management goals. CRC's carbon management strategy and energy transition efforts continue to be a unique differentiator and support our corporate objectives while delivering on our financial goals and sustainability targets."
Primary Highlights
•Declared a quarterly dividend of $0.2825 per share of common stock, totaling ~$20 million payable on December 16, 2022 to shareholders of record on December 1, 2022, with subsequent quarterly dividends subject to final determination and Board approval
•Increased the Share Repurchase Program by $200 million to $850 million from $650 million and extended the term of the program through December 31, 2023
•Repurchased 1,921,181 common shares for $80 million during the third quarter of 2022; repurchased an aggregate 10,617,862 shares for $424 million since the inception of the Share Repurchase Program through October 31, 2022
•Returned $286 million to shareholders throughout the first three quarters of 2022, ~5% more than the free cash flow1 generated during the same period
•Presented three new reservoirs to Carbon TerraVault JV
•Favorable ruling in Kern County EIR Litigation
•Shifted a rig to the Huntington Beach field for a 6 to 8 well program prioritizing available permits on hand
Third Quarter 2022 Highlights
Financial
•Reported net income of $426 million, or $5.58 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 $111 million, or $1.45 per diluted share
•Generated net cash provided by operating activities of $235 million, adjusted EBITDAX1 of $234 million and free cash flow1 of $128 million
•Ended the quarter with $358 million of cash on hand, an undrawn credit facility and $819 million of liquidity2
•Increased available credit under our Reserve Based Lending Credit Facility by $50 million in the quarter and $110 million year to date, bringing our aggregate commitments to over $600 million
Operations
•Produced an average of 92,000 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 $100 million during the quarter
•Operated three drilling rigs in the San Joaquin Basin and two drilling rigs in the Los Angeles Basin; drilled 36 wells (42 online in 3Q22)
•Operated 33 maintenance rigs
2022 Guidance and Capital Program Update3
CRC's capital program is dynamic in response to oil market volatility while focusing on oil production and strong liquidity and maximizing free cash flow. During the third quarter of 2022, CRC successfully managed the current market inflationary pressures and is narrowing its 2022 total capital program to the range of $380 to $400 million. CRC entered the fourth quarter of 2022 with four drilling rigs and expects to average three drilling rigs for the remainder of the year in its Elk Hills, Buena Vista, Wilmington and Huntington Beach fields as CRC repositions for its 2023 program.
This level of expected spending is consistent with CRC's strategy of investing up to 50% of its operating cash flow back into CRC's oil and gas operations. Following entry into the Carbon TerraVault JV with Brookfield, CRC anticipates that a portion of the operating cash flow previously designated for advancing decarbonization and other emission reducing projects may become available for other corporate purposes, such as shareholder returns and other strategic opportunities (see the summary of our Business Strategy in Part I, Item 1 & 2 – Business and Properties in CRC's 2021 Annual Report and see Part I, Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Carbon TerraVault Joint Venture in the Form 10-Q for the quarter ended September 30, 2022 for additional details on Carbon TerraVault JV).
The delay in the Kern County EIR litigation (see Part I, Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Regulatory Update in the Form 10-Q for the quarter ended September 30, 2022 for additional details on Kern County EIR) led to a change in CRC's drilling program which favors a higher natural gas to oil ratio. Therefore, CRC's 2022 oil production guidance is expected to be negatively impacted by approximately 1 MBo/d from this change. CRC's 2022 total production guidance remains consistent with previous expectations in the range of 91 to 94 MBoe/d.
CRC is raising its operating cost guidance to $760 to $790 million from $725 to $755 million primarily due to higher natural gas and electricity prices as well as some inflation and the change in well mix.
| | | | | | | | | | | | | | | | | |
| | | | | |
CRC GUIDANCE3 | Total
2022E | | CMB
2022E | | E&P, Corp. & Other 2022E |
| Net Total Production (MBoe/d) | 94 - 91 | | | | 94 - 91 |
| Net Oil Production (MBbl/d) | 58 - 53 | | | | 58 - 53 |
| Operating Costs ($ millions) | $760 - $790 | | | | $760 - $790 |
CMB Expenses4 ($ millions) | $10 - $20 | | $10 - $20 | | |
Adjusted General and Administrative Expenses1 ($ millions) | $195 - $210 | | $10 - $15 | | $185 - $195 |
| Total Capital ($ millions) | $380 - $400 | | $20 - $30 | | $360 - $370 |
| Drilling & Completions | $232 - $235 | | | | $232 - $235 |
Workovers | $36 - $38 | | | | $36 - $38 |
Facilities | $63 - $65 | | | | $63 - $65 |
Corporate & Other | $29 - $32 | | | | $29 - $32 |
CMB | $20 - $30 | | $20 - $30 | | |
Adjusted EBITDAX1 ($ millions) | $835 - $890 | | ($20) - ($35) | | $870 -- $910 |
Free Cash Flow1 ($ millions) | $325 - $370 | | ($40) - ($65) | | $390 - $410 |
Supply Chain and Cost Inflation
Operating and capital costs in the oil and natural gas industry are heavily influenced by commodity prices which are typically cyclical in nature. Typically, suppliers will negotiate increases for drilling and completion, oilfield services, equipment and materials as prices for energy-related commodities and raw materials (such as steel, metals and chemicals) increase. Recent worldwide and U.S. supply chain issues, together with rising commodity prices and tight labor markets in the U.S., have created cost inflation during 2022. Cost inflation may continue into 2023 if rising energy prices result in factory constraints, placing certain items such as directional drilling components and materials that have a high energy input intensity in short supply. CRC has taken measures to limit the effects of the inflationary market by entering into contracts for materials and services with terms of one to three years. CRC has also taken steps to build its on-hand supply stock for items frequently used in its operations to address possible supply chain disruptions. Despite these efforts, CRC has experienced significant increased costs thus far in 2022 and anticipates additional increases in the cost of goods and services and wages in the company's operations during the remainder of 2022. These increases will factor into CRC's operating and capital costs and could also negatively impact its results of operations and cash flows in 2023 and beyond.
Third Quarter 2022 E&P Operational Results
In November 2020, the SEC amended Regulation S-K to, among other things, provide companies with the option to discuss material changes to results of operations between the current and immediately preceding quarter. CRC has elected to discuss its results of operations on a sequential-quarter basis. CRC believes this approach provides more meaningful and useful information to measure its performance from the immediately preceding quarter. In accordance with this final rule, CRC is not required to include a comparison of the current quarter and the same prior-year quarter.
Total daily net production for the three months ended September 30, 2022, compared to the three months ended June 30, 2022 increased by approximately 1 MBoe/d, or 1%. This increase is predominately a result of CRC's production-sharing contracts (PSCs), which positively impacted its net oil production in the three months ended September 30, 2022 by approximately 2 MBoe/d, compared to the three months ended June 30, 2022. This increase was partially offset by natural decline.
During the third quarter of 2022, CRC operated an average of three drilling rigs in the San Joaquin Basin and two drilling rigs in the Los Angeles Basin. During the quarter, CRC drilled 36 net wells and brought online 42 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.
Third Quarter 2022 Financial Results
| | | | | | | | | | | | | | | | | | | | |
| 3rd Quarter | | | 2nd Quarter | | | | | | |
| ($ and shares in millions, except per share amounts) | 2022 | | | 2022 | | | | | | |
| | | | | | | | | | |
| Statements of Operations: | | | | | | | | | | |
| Revenues | | | | | | | | | | |
| Total operating revenues | $ | 1,125 | | | | $ | 747 | | | | | | | |
| | | | | | | | | | |
| Operating Expenses | | | | | | | | | | |
| Total operating expenses | 536 | | | | 473 | | | | | | | |
| Gain on asset divestitures | 2 | | | | 4 | | | | | | | |
| Operating Income | $ | 591 | | | | $ | 278 | | | | | | | |
| Net Income | $ | 426 | | | | $ | 190 | | | | | | | |
| | | | | | | | | | |
| Net income per share - basic | $ | 5.75 | | | | $ | 2.48 | | | | | | | |
| Net income per share - diluted | $ | 5.58 | | | | $ | 2.41 | | | | | | | |
Adjusted net income1 | $ | 111 | | | | $ | 89 | | | | | | | |
Adjusted net income1 per share - diluted | $ | 1.45 | | | | $ | 1.13 | | | | | | | |
| Weighted-average common shares outstanding - basic | 74.1 | | | | 76.7 | | | | | | | |
| Weighted-average common shares outstanding - diluted | 76.3 | | | | 78.8 | | | | | | | |
Adjusted EBITDAX1 | $ | 234 | | | | $ | 204 | | | | | | | |
Review of Third Quarter 2022 Financial Results
Realized oil prices, excluding the effects of cash settlements on CRC's commodity derivative contracts, decreased by $14.36 per barrel from $112.32 per barrel in the second quarter of 2022 to $97.96 per barrel in the third quarter of 2022. Realized oil prices were lower in the third quarter of 2022 compared to the second quarter of 2022 due to slowing global economic activity and ongoing releases from the U.S. Strategic Petroleum Reserve.
Realized oil prices, including the effects of cash settlements on CRC's commodity derivative contracts, decreased by $0.72 from $63.17 in the second quarter of 2022 to $62.45 in the third quarter of 2022. See Attachment 4 for further information on prices.
Adjusted EBITDAX1 for the third quarter of 2022 was $234 million. See table below for the Company's net cash provided by operating activities, capital investments and free cash flow1 during the same periods.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
FREE CASH FLOW1 | | | | | | | | | | |
| | | | | | | | | | |
| Management uses free cash flow, which is defined by us as net cash provided by operating activities less capital investments, as a measure of liquidity. The following table presents a reconciliation of our net cash provided by operating activities to free cash flow. We supplemented our non-GAAP measure of free cash flow with free cash flow of our exploration and production and corporate items (Free Cash Flow for E&P, Corporate & Other) which we believe is a useful measure for investors to understand the results of our core oil and gas business. We define Free Cash Flow for E&P, Corporate & Other as consolidated free cash flow less results attributable to our carbon management business (CMB). |
| | | | | | | | | | |
| | | | | | | 3rd Quarter | | | 2nd Quarter |
| ($ millions) | | 2022 | | | 2022 |
| | | | |
| Net cash provided by operating activities | $ | 235 | | | | $ | 181 | |
| Capital investments | (107) | | | | (98) | |
Free cash flow1 | $ | 128 | | | | $ | 83 | |
| | | | |
E&P, corporate & other free cash flow1 | $ | 139 | | | | $ | 98 | |
CMB free cash flow1 | $ | (11) | | | | $ | (15) | |
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. 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.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| OPERATING COSTS PER BOE |
| | | | | | | | | | |
| The reporting of our PSCs creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs. The following table presents operating costs after adjusting for the excess costs attributable to PSCs. |
| | | | |
| | 3rd Quarter | | | 2nd Quarter |
| ($ per Boe) | | | | | | | 2022 | | | 2022 |
| Energy operating costs | $ | 10.96 | | | | 9.33 | |
| Gas processing costs | | | | | | | 0.49 | | | | 0.54 | |
| Non-energy operating costs | 13.82 | | | | 13.05 | |
| Operating costs | | | | | | | $ | 25.27 | | | | $ | 22.92 | |
| Excess costs attributable to PSCs | (2.16) | | | | (2.58) | |
Operating costs, excluding effects of PSCs (a) | | | | | | | $ | 23.11 | | | | $ | 20.34 | |
| | | | |
| (a) Operating costs, excluding effects of PSCs is a non-GAAP measure. |
Energy operating costs for the third quarter of 2022 were $93 million, or $10.96 per Boe, which was an increase of $16 million or 21% from $77 million, or $9.33 per Boe, for the second quarter of 2022. This increase was primarily a result of higher electricity and natural gas prices.
Non-energy operating costs for the third quarter of 2022 were $117 million, or $13.82 per Boe, which was an increase of $8 million or 7% from $109 million, or $13.05 per Boe, for the second quarter of 2022. This increase was primarily a result of increased downhole maintenance activity.
Kern County Environmental Impact Report
CalGEM is California's primary regulator of the oil and natural gas industry on private and state lands, with additional oversight from the State Lands Commission’s administration of state surface and mineral interests. CalGEM currently requires an operator to identify the manner in which the California Environmental Quality Act (CEQA) has been satisfied prior to issuing various state permits, typically through either an environmental review or an exemption by a state or local agency. In Kern County, this requirement has typically been satisfied by complying with the local oil and gas ordinance which was supported by an Environmental Impact Report (EIR) certified by the Kern County Board of Supervisors in 2015.
A group of petitioners challenged the EIR and on February 25, 2020, a California Appellate Court (the Court) issued a ruling that required Kern County to decertify the EIR and set aside the amended Zoning Ordinance. In response, Kern County prepared, circulated and certified a supplementary recirculated EIR (Supplemental EIR) to address the ruling from the Court and, in April 2021, resumed issuing local permits relying on the Supplemental EIR. However, on October 22, 2021, Kern County was ordered to cease reviewing and approving oil and gas permits until the trial court determined that the Zoning Ordinance complies with CEQA requirements. On May 26, 2022, a hearing was held in Kern County and the Court ruled that Kern County’s local permitting system must cease until the trial court verified that the noted deficiencies had been remedied and that the remedies satisfied the concerns raised by the Court. In October 2022, the trial court ruled that the Supplemental EIR was not decertified but ordered Kern County to address four discrete issues before suspension of the local permitting could be lifted, which, once resolved, would bring the Supplemental EIR into compliance with applicable laws. The four discrete issues included requirements for the removal of offsite legacy equipment to mitigate agricultural land use impacts, revising emission reduction requirements to address particulate matter, the establishment of a drinking water grant fund for disadvantaged communities in Kern County, and updating the local oil and gas ordinance to reflect these requirements. The Kern County Board of Supervisors approved these changes in August 2022. On October 12, 2022, Kern County submitted notice with the trial court of these changes and on November 2, 2022 the trial court lifted the order preventing reliance on the local permitting system. This ruling is subject to further appeal by the petitioners and there is still some potential for future disruptions to obtaining permits in Kern County until any such appeals are resolved.
Sustainability Update
In August 2022, CRC published its 2021 Sustainability Report. The report provides an overview of CRC’s continuous progress on its sustainability efforts in environmental, social and governance (ESG) performance as the company advances its commitment to the energy transition and decarbonization of local economies. Building off its 2020 Sustainability Update and 2021 Leadership Level Ranking of A- by CDP, CRC's 2021 Sustainability Report references Sustainability Accounting Standards Board (SASB), Global Reporting Initiative (GRI) and International Petroleum Industry Environmental Conservation Association (IPIECA) standards.
Highlights and achievements from CRC’s 2021 Sustainability Report include:
•Announced 2045 Full-Scope Net Zero Goal and updated and expanded ESG goals on methane emissions, freshwater usage, community giving, diversity in leadership and linked ESG performance to executive pay
•Hired first Chief Sustainability Officer
•Established Project Management Office of Asset Retirement Obligations (ARO)
•Advanced CRC's Carbon Management Business including its Carbon TerraVault carbon capture and storage (CCS) projects, and CalCapture CCS+ project
•Continued to be a net supplier of both fresh water and electricity
•Continued to rank among the safest companies in the United States; workforce achieved a better safety performance rating than many non-industrial sectors in 2021
•Earned 26 National Safety Achievement Awards in each of its operating areas and company wide in 2021 for its performance
For more information about CRC’s sustainability efforts and to download the full length and summary versions of the 2021 Sustainability Report, please visit crc.com/esg.
Balance Sheet and Liquidity Update
CRC's aggregate commitment under the Revolving Credit Facility was $602 million as of September 30, 2022. The borrowing base for the Revolving Credit Facility is redetermined semi-annually and was reaffirmed at $1.2 billion on October 25, 2022.
As of September 30, 2022, CRC had liquidity of $819 million, which consisted of $358 million in unrestricted cash and $461 million of available borrowing capacity under its Revolving Credit Facility which is net of $141 million of letters of credit.
Acquisitions and Divestitures
During the three and nine months ended September 30, 2022, CRC recorded a net gain of $2 million and $60 million, respectively, related to the sale of certain Ventura basin assets and its Lost Hills transaction. The amount recognized in the three and nine months ended September 30, 2022 included $2 million and $6 million, respectively, of additional earn-out consideration on Ventura basin divestitures that occurred in the second half of 2021 and the first half of 2022. In addition, CRC also received $2 million to secure the performance of well abandonment obligations on divested properties which it expects to return to the purchaser once the work has been completed. As a result, CRC recorded a liability of $2 million included as accrued liabilities on its condensed consolidated balance sheet as of September 30, 2022. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Divestitures and Acquisitions in CRC's 2021 Annual Report for additional information on the Ventura basin transactions.
The closing of the sale of CRC's remaining assets in the Ventura basin is subject to final approval from the State Lands Commission, which CRC expects to receive prior to the end of the first quarter of 2023. These remaining assets, consisting of property, plant and equipment and associated asset retirement obligations, are classified as held for sale on CRC's condensed consolidated balance sheet as of September 30, 2022.
Shareholder Return Strategy
CRC continues to prioritize shareholder returns and dedicates a portion of its operating cash flow to shareholders. In light of this strategy, CRC's Board of Directors has increased its Share Repurchase Program by $200 million to $850 million and extended the program through December 31, 2023. Adjusting for this increase, there was approximately $426 million of capacity under CRC's Share Repurchase Program as of October 31, 2022.
During the third quarter of 2022, CRC repurchased 1.9 million shares of its common stock for $80 million. Since the inception of Share Repurchase Program through October 31, 2022, CRC has repurchased 10.6 million shares for $424 million at an average price of $39.89 per share, resulting in the repurchase of approximately 13% of the shares that CRC had at its emergence from bankruptcy.
On November 2, 2022, 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 December 1, 2022, and will be paid on December 16, 2022.
Through October 31, 2022, CRC has returned $476 million of cash to shareholders, including $52 million through quarterly dividends and $424 million through share repurchases.
Upcoming Investor Conference Participation
CRC's executives will be participating in the following events in November and December of 2022:
•Furey Research Hidden Gems Conference on November 7 - 8, 2022, Virtual
•Bank of America Securities Global Energy Conference on November 16 - 17 in Miami, FL
•Goldman Sachs Carbonomics Conference on November 29 in London, UK
•Capital One Securities Energy Conference on December 7 in Houston, TX
•StoneX Financial Natural Resources Day on December 8 in New York, NY
CRC’s presentation materials will be available the day of the events on the Events and Presentations page in the Investor Relations section on www.crc.com.
Conference Call Details
To participate in the conference call scheduled for November 3, 2022, 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 to https://dpregister.com/sreg/10171364/f48809c260. 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 and free cash flow, after special items including reconciliations to their most directly comparable GAAP measure, where applicable. For the full year 2022 estimates of the non-GAAP measures of adjusted EBITDAX and free cash flow, including reconciliations to their most directly comparable GAAP measure, see Attachment 7.
2 Calculated as $358 million of available cash plus $602 million of capacity on CRC's Revolving Credit Facility less $141 million in outstanding letters of credit.
3 Current guidance assumes a 2022 Brent price of $99.75 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $6.47 per mcf. CRC's share of production under PSC contracts decreases when commodity prices rise and increases when prices fall.
4 CMB Expenses include start-up expenditures.
About California Resources Corporation
California Resources Corporation (CRC) is an independent oil and natural gas company committed to energy transition in the sector. CRC has some of the lowest carbon intensity production in the US and CRC is focused on maximizing the value of our 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. Nothing herein is intended to imply or
create a legal partnership between Brookfield Global Transition Fund, California Resources Corporation, or any of their respective subsidiaries and affiliates.
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 CRC's 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 CRC's forward-looking statements include:
•fluctuations in commodity prices and the potential for sustained low oil, natural gas and natural gas liquids prices;
•equipment, service or labor price inflation or unavailability;
•legislative or regulatory changes, including those related to (i) the location, drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, (ii) the management of energy, water, land, greenhouse gases (GHGs) or other emissions, (iii) the protection of health, safety and the environment, (iv) CRC's ability to claim and utilize tax credits or other incentives, or (v) the transportation, marketing and sale of CRC's products and CO2;
•availability or timing of, or conditions imposed on, permits and approvals necessary for drilling or development activities and carbon management projects;
•changes in business strategy and CRC's capital plan;
•lower-than-expected production, reserves or resources from development projects or acquisitions, or higher-than-expected decline rates;
•incorrect estimates of reserves and related future cash flows and the inability to replace reserves;
•the recoverability of resources and unexpected geologic conditions;
•CRC's ability to successfully execute on the construction and other aspects of the infrastructure projects and enter into third party contracts on contemplated terms;
•CRC's ability to realize the benefits contemplated by the business strategies and initiatives related to energy transition, including carbon capture and storage 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;
•global geopolitical, socio-demographic and economic trends and technological innovations;
•changes in CRC's dividend policy and its ability to declare future dividends under its debt agreements;
•changes in CRC's share repurchase program and its ability to repurchase shares under its debt agreements;
•production-sharing contracts' effects on production and operating costs;
•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, stock repurchases and dividends;
•insufficient capital or lack of liquidity in the capital markets or inability to attract potential investors;
•limitations on transportation or storage capacity and the need to shut-in wells;
•inability to enter into desirable transactions, including acquisitions, asset sales and joint ventures;
•CRC's ability to achieve expected synergies from joint ventures and acquisitions;
•CRC's ability to utilize its net operating loss carryforwards to reduce its income tax obligations;
•CRC's ability to successfully gather and verify data regarding emissions, its environmental impacts and other initiatives;
•the compliance of various third parties with CRC's policies and procedures and legal requirements as well as contracts it enters into in connection with CRC's climate-related initiatives;
•the effect of CRC's stock price on costs associated with incentive compensation;
•changes in the intensity of competition in the oil and gas industry;
•effects of hedging transactions;
•climate-related conditions and weather events;
•disruptions due to accidents, mechanical failures, power outages, transportation or storage constraints, natural disasters, labor difficulties, cyber-attacks or other catastrophic events;
•pandemics, epidemics, outbreaks, or other public health events, such as the COVID-19; and
•other factors discussed in Part I, Item 1A – Risk Factors in CRC's Annual Report on Form 10-K and its other SEC filings available at www.crc.com.
CRC cautions you not to place undue reliance on forward-looking statements contained in this document, which speak only as of the filing date, and CRC undertakes no obligation to update this information. This document may also contain information from third party sources. This data may involve a number of assumptions and limitations, and CRC has not independently verified them and do not warrant the accuracy or completeness of such third-party information.
Contacts:
| | | | | |
Joanna Park (Investor Relations) 818-661-3731
Joanna.Park@crc.com | Richard Venn (Media) 818-661-6014 Richard.Venn@crc.com |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Attachment 1 |
| SUMMARY OF RESULTS | | | | | | | | | | |
| | | | | | | | | | |
| 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | | Nine Months | | Nine Months |
| ($ and shares in millions, except per share amounts) | 2022 | | 2022 | | 2021 | | | 2022 | | 2021 |
| | | | | | | | | | |
| Statements of Operations: | | | | | | | | | | |
| Revenues | | | | | | | | | | |
| Oil, natural gas and NGL sales | $ | 680 | | | $ | 718 | | | $ | 549 | | | | $ | 2,026 | | | $ | 1,459 | |
| Net gain (loss) from commodity derivatives | 243 | | | (100) | | | (125) | | | | (419) | | | (603) | |
| Sales of purchased natural gas | 113 | | | 75 | | | 95 | | | | 220 | | | 241 | |
| Electricity sales | 88 | | | 49 | | | 65 | | | | 171 | | | 131 | |
| Other revenue | 1 | | | 5 | | | 4 | | | | 27 | | | 27 | |
| Total operating revenues | 1,125 | | | 747 | | | 588 | | | | 2,025 | | | 1,255 | |
| | | | | | | | | | |
| Operating Expenses | | | | | | | | | | |
| Operating costs | 214 | | | 190 | | | 190 | | | | 586 | | | 523 | |
| General and administrative expenses | 59 | | | 56 | | | 51 | | | | 163 | | | 147 | |
| Depreciation, depletion and amortization | 50 | | | 50 | | | 54 | | | | 149 | | | 160 | |
| Asset impairments | — | | | 2 | | | 25 | | | | 2 | | | 28 | |
| Taxes other than on income | 44 | | | 42 | | | 36 | | | | 120 | | | 113 | |
| Exploration expense | 1 | | | 1 | | | 2 | | | | 3 | | | 6 | |
| Purchased natural gas expense | 98 | | | 67 | | | 53 | | | | 186 | | | 144 | |
| Electricity generation expenses | 42 | | | 33 | | | 29 | | | | 99 | | | 70 | |
| Transportation costs | 13 | | | 12 | | | 11 | | | | 37 | | | 37 | |
| Accretion expense | 10 | | | 11 | | | 13 | | | | 32 | | | 39 | |
| Other operating expenses, net | 5 | | | 9 | | | 4 | | | | 28 | | | 31 | |
| Total operating expenses | 536 | | | 473 | | | 468 | | | | 1,405 | | | 1,298 | |
| Net gain on asset divestitures | 2 | | | 4 | | | 2 | | | | 60 | | | 4 | |
| Operating Income (Loss) | 591 | | | 278 | | | 122 | | | | 680 | | | (39) | |
| | | | | | | | | | |
| Non-Operating (Expenses) Income | | | | | | | | | | |
| Reorganization items, net | — | | | — | | | (1) | | | | — | | | (5) | |
| Interest and debt expense, net | (13) | | | (13) | | | (14) | | | | (39) | | | (40) | |
| Net loss on early extinguishment of debt | — | | | — | | | — | | | | — | | | (2) | |
| Other non-operating expenses, net | 1 | | | 1 | | | — | | | | 3 | | | (3) | |
| | | | | | | | | | |
| Net Income (Loss) Before Income Taxes | 579 | | | 266 | | | 107 | | | | 644 | | | (89) | |
| Income tax provision | (153) | | | (76) | | | — | | | | (203) | | | — | |
| Net income (loss) | 426 | | | 190 | | | 107 | | | | 441 | | | (89) | |
| Net income attributable to noncontrolling interests | — | | | — | | | (4) | | | | — | | | (13) | |
| Net Income (Loss) Attributable to Common Stock | $ | 426 | | | $ | 190 | | | $ | 103 | | | | $ | 441 | | | $ | (102) | |
| | | | | | | | | | |
| Net income (loss) attributable to common stock per share - basic | $ | 5.75 | | | $ | 2.48 | | | $ | 1.26 | | | | $ | 5.77 | | | $ | (1.23) | |
| Net income (loss) attributable to common stock per share - diluted | $ | 5.58 | | | $ | 2.41 | | | $ | 1.25 | | | | $ | 5.62 | | | $ | (1.23) | |
| | | | | | | | | | |
| Adjusted net income | $ | 111 | | | $ | 89 | | | $ | 151 | | | | $ | 291 | | | $ | 331 | |
| Adjusted net income per share - basic | $ | 1.50 | | | $ | 1.16 | | | $ | 1.85 | | | | $ | 3.81 | | | $ | 4.01 | |
| Adjusted net income per share - diluted | $ | 1.45 | | | $ | 1.13 | | | $ | 1.83 | | | | $ | 3.71 | | | $ | 3.97 | |
| | | | | | | | | | |
| Weighted-average common shares outstanding - basic | 74.1 | | | 76.7 | | | 81.6 | | | | 76.4 | | | 82.6 | |
| Weighted-average common shares outstanding - diluted | 76.3 | | | 78.8 | | | 82.4 | | | | 78.5 | | | 82.6 | |
| | | | | | | | | | |
| Adjusted EBITDAX | $ | 234 | | | $ | 204 | | | $ | 242 | | | | $ | 644 | | | $ | 600 | |
| Effective tax rate | 26 | % | | 29 | % | | 0% | | | 32 | % | | 0% |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| GAINS AND LOSSES FROM COMMODITY DERIVATIVES | | | | |
| | | | | | | | | | |
|
| 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | | Nine Months | | Nine Months |
| ($ millions) | 2022 | | 2022 | | 2021 | | | 2022 | | 2021 |
| | | | | | | | | | |
| Non-cash derivative gain (loss) | $ | 425 | | | $ | 141 | | | $ | (26) | | | | $ | 185 | | | $ | (383) | |
| | | | | | | | | | |
| | | | | | | | | | |
| Cash payments on settled commodity derivatives | (182) | | | (241) | | | (99) | | | | (604) | | | (220) | |
| Net gain (loss) from commodity derivatives | $ | 243 | | | $ | (100) | | | $ | (125) | | | | $ | (419) | | | $ | (603) | |
| | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | 1st Quarter | | | 1st Quarter | | 4th Quarter | | 4th Quarter | | | 4th Quarter | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| CAPITAL INVESTMENTS | | | | |
| | | | | | | | | | |
|
| 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | | Nine Months | | Nine Months |
| ($ millions) | 2022 | | 2022 | | 2021 | | | 2022 | | 2021 |
| | | | | | | | | | |
| Facilities | $ | 20 | | | $ | 15 | | | $ | 11 | | | | $ | 52 | | | $ | 29 | |
| Drilling | 73 | | | 62 | | | 32 | | | | 194 | | | 73 | |
| Workovers | 7 | | | 9 | | | 8 | | | | 22 | | | 25 | |
| Total E&P capital | 100 | | | 86 | | | 51 | | | | 268 | | | 127 | |
| CMB | 6 | | | 10 | | | — | | | | 17 | | | — | |
| Corporate and other | 1 | | | 2 | | | — | | | | 19 | | | 1 | |
| Total capital program | $ | 107 | | | $ | 98 | | | $ | 51 | | | | $ | 304 | | | $ | 128 | |
| | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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, adjusted EBITDAX margin, discretionary cash flow, free cash flow and operating costs per BOE, 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. We define 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 (loss) and adjusted net income (loss) per share. | |
| | | | | |
| | 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | Nine Months | | Nine Months | |
| ($ millions, except per share amounts) | | 2022 | | 2022 | | 2021 | | 2022 | | 2021 | |
| Net income (loss) | | $ | 426 | | | $ | 190 | | | $ | 107 | | | $ | 441 | | | $ | (89) | | |
| Net income attributable to noncontrolling interests | | — | | | — | | | (4) | | | — | | | (13) | | |
| Net income (loss) attributable to common stock | | 426 | | | 190 | | | 103 | | | 441 | | | (102) | | |
| Unusual, infrequent and other items: | | | | | | | | | | | |
| Non-cash (income) loss from commodity derivatives | | (425) | | | (141) | | | 26 | | | (185) | | | 383 | | |
| Asset impairments | | — | | | 2 | | | 25 | | | 2 | | | 28 | | |
| Reorganization items, net | | — | | | — | | | 1 | | | — | | | 5 | | |
| | | | | | | | | | | |
| Severance and termination costs | | — | | | — | | | — | | | — | | | 15 | | |
| Net loss on early extinguishment of debt | | — | | | — | | | — | | | — | | | 2 | | |
| Net gain on asset divestitures | | (2) | | | (4) | | | (2) | | | (60) | | | (4) | | |
| Rig termination expenses | | — | | | — | | | — | | | — | | | 2 | | |
| Other, net | | 4 | | | 2 | | | (2) | | | 7 | | | 2 | | |
| Total unusual, infrequent and other items | | (423) | | | (141) | | | 48 | | | (236) | | | 433 | | |
| Income tax provision of adjustments at effective tax rate | | 120 | | | 40 | | | — | | | 67 | | | — | | |
| Income tax (benefit) provision - out of period | | (12) | | | — | | | — | | | 19 | | | — | | |
| | | | | | | | | | | |
| Adjusted net income attributable to common stock | | $ | 111 | | | $ | 89 | | | $ | 151 | | | $ | 291 | | | $ | 331 | | |
| | | | | | | | | | | |
| Net income (loss) attributable to common stock per share - basic | | $ | 5.75 | | | $ | 2.48 | | | $ | 1.26 | | | $ | 5.77 | | | $ | (1.23) | | |
| Net income (loss) attributable to common stock per share - diluted | | $ | 5.58 | | | $ | 2.41 | | | $ | 1.25 | | | $ | 5.62 | | | $ | (1.23) | | |
| Adjusted net income per share - basic | | $ | 1.50 | | | $ | 1.16 | | | $ | 1.85 | | | $ | 3.81 | | | $ | 4.01 | | |
| Adjusted net income per share - diluted | | $ | 1.45 | | | $ | 1.13 | | | $ | 1.83 | | | $ | 3.71 | | | $ | 3.97 | | |
| | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| FREE CASH FLOW | | | | | | | | | | | | |
| | | | | | | | | | | | |
Management uses free cash flow, which is defined by us as net cash provided by operating activities less capital investments, as a measure of liquidity. The following table presents a reconciliation of our net cash provided by operating activities to free cash flow. We supplemented our non-GAAP measure of free cash flow with free cash flow of our exploration and production and corporate items (Free Cash Flow for E&P, Corporate & Other) which we believe is a useful measure for investors to understand the results of our core oil and gas business. We define Free Cash Flow for E&P, Corporate & Other as consolidated free cash flow less results attributable to our carbon management business (CMB).
We have excluded one-time costs for bankruptcy related fees during 2021 as a supplemental measure of our free cash flow. |
| | | | | | | | | | | | |
| | 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | Nine Months | | | Nine Months | |
| ($ millions) | | 2022 | | 2022 | | 2021 | | 2022 | | | 2021 | |
| | | | | | | | | | | | |
| Net cash provided by operating activities | | $ | 235 | | | $ | 181 | | | $ | 182 | | | $ | 576 | | | | $ | 456 | | |
| Capital investments | | (107) | | | (98) | | | (51) | | | (304) | | | | (128) | | |
| Free cash flow | | 128 | | | 83 | | | 131 | | | 272 | | | | 328 | | |
| One-time bankruptcy related fees | | — | | | — | | | 1 | | | — | | | | 5 | | |
| Free cash flow, after special items | | $ | 128 | | | $ | 83 | | | $ | 132 | | | $ | 272 | | | | $ | 333 | | |
| | | | | | | | | | | | |
| E&P, Corporate and Other Free Cash Flow | | $ | 139 | | | $ | 98 | | | $ | 132 | | | $ | 301 | | | | $ | 333 | | |
| CMB Free Cash Flow | | $ | (11) | | | $ | (15) | | | $ | — | | | $ | (29) | | | | $ | — | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| ADJUSTED EBITDAX | | | | | | | | | |
|
We define 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. We believe this measure provides useful information in assessing our financial condition, results of operations and cash flows and is widely used by the industry, the investment community and our 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 our financial performance, such as our cost of capital and tax structure, as well as depreciation, depletion and amortization of our assets. This measure should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP. A version of Adjusted EBITDAX is a material component of certain of our financial covenants under our 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. We have supplemented our non-GAAP measures of consolidated adjusted EBITDAX with adjusted EBITDAX for our exploration and production and corporate items (Adjusted EBITDAX for E&P, Corporate & Other) which we believe is a useful measure for investors to understand the results of our core oil and gas business.. We define adjusted EBITDAX for E&P, Corporate & Other as consolidated adjusted EBITDAX less results attributable to our carbon management business (CMB). | |
| | | | | | |
| | 3rd Quarter | | 2nd Quarter | | | 3rd Quarter | | Nine Months | | | Nine Months | |
| ($ millions, except per BOE amounts) | | 2022 | | 2022 | | | 2021 | | 2022 | | | 2021 | |
| Net income (loss) | | $ | 426 | | | $ | 190 | | | | $ | 107 | | | $ | 441 | | | | $ | (89) | | |
| Interest and debt expense, net | | 13 | | | 13 | | | | 14 | | | 39 | | | | 40 | | |
| Depreciation, depletion and amortization | | 50 | | | 50 | | | | 54 | | | 149 | | | | 160 | | |
| Income tax provision | | 153 | | | 76 | | | | — | | | 203 | | | | — | | |
| Exploration expense | | 1 | | | 1 | | | | 2 | | | 3 | | | | 6 | | |
| Interest income | | (1) | | | — | | | | — | | | (1) | | | | — | | |
Unusual, infrequent and other items (a) | | (423) | | | (141) | | | | 48 | | | (236) | | | | 433 | | |
| Non-cash items | | | | | | | | | | | | | |
| Accretion expense | | 10 | | | 11 | | | | 13 | | | 32 | | | | 39 | | |
| Stock-based compensation | | 5 | | | 4 | | | | 4 | | | 13 | | | | 10 | | |
| Post-retirement medical and pension | | — | | | — | | | | — | | | 1 | | | | 1 | | |
| | | | | | | | | | | | | |
| Adjusted EBITDAX | | $ | 234 | | | $ | 204 | | | | $ | 242 | | | $ | 644 | | | | $ | 600 | | |
| | | | | | | | | | | | | |
| Net cash used by operating activities | | $ | 235 | | | $ | 181 | | | | $ | 182 | | | $ | 576 | | | | $ | 456 | | |
| Cash interest | | 23 | | | 2 | | | | 24 | | | 48 | | | | 29 | | |
| Cash income taxes | | — | | | 20 | | | | — | | | 20 | | | | — | | |
| Exploration expenditures | | 1 | | | 1 | | | | 2 | | | 3 | | | | 6 | | |
| Working capital changes | | (25) | | | — | | | | 34 | | | (3) | | | | 109 | | |
| | | | | | | | | | | | | |
| Adjusted EBITDAX | | $ | 234 | | | $ | 204 | | | | $ | 242 | | | $ | 644 | | | | $ | 600 | | |
| | | | | | | | | | | | | |
| E&P, Corporate & Other Adjusted EBITDAX | | $ | 239 | | | $ | 209 | | | | $ | 242 | | | $ | 656 | | | | $ | 600 | | |
| CMB Adjusted EBITDAX | | $ | (5) | | | $ | (5) | | | | $ | — | | | $ | (12) | | | | $ | — | | |
| | | | | | | | | | | | | |
| Adjusted EBITDAX per Boe | | $ | 27.63 | | | $ | 24.61 | | | | $ | 25.83 | | | $ | 26.06 | | | | $ | 21.85 | | |
| | | | | | | | | | | | | |
| (a) See Adjusted Net Income (Loss) reconciliation. | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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. We supplemented our non-GAAP measure of adjusted general and administrative expenses with adjusted general and administrative expenses of our exploration and production and corporate items (Adjusted General & Administrative Expenses for E&P, Corporate & Other) which we believe is a useful measure for investors to understand the results or our core oil and gas business. We define Adjusted General & Administrative Expenses for E&P, Corporate & Other as consolidated adjusted general and administrative expenses less results attributable to our carbon management business (CMB). | |
| | | | | | | | | | | |
| | 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | Nine Months | | Nine Months | |
| ($ millions) | | 2022 | | 2022 | | 2021 | | 2022 | | 2021 | |
| General and administrative expenses | | $ | 59 | | | $ | 56 | | | $ | 51 | | | $ | 163 | | | $ | 147 | | |
| Stock-based compensation | | (5) | | | (4) | | | (4) | | | (13) | | | (10) | | |
| Other | | (1) | | | (1) | | | — | | | (2) | | | — | | |
| Adjusted G&A expenses | | $ | 53 | | | $ | 51 | | $ | — | | $ | 47 | | | $ | 148 | | | $ | 137 | | |
| | | | | | | | | | | |
| E&P, Corporate and Other Adjusted G&A expenses | | $ | 48 | | 43 | $ | 47 | | | $ | 47 | | | $ | 138 | | | $ | 137 | | |
| CMB Adjusted G&A expenses | | $ | 5 | | | $ | 4 | | | $ | — | | | $ | 10 | | | $ | — | | |
| | | | | | | | | | | |
| OPERATING COSTS PER BOE | |
| | | | | | | | | | | |
| The reporting of our PSC-type contracts creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs.The following table presents operating costs after adjusting for the excess costs attributable to PSCs. | |
| | | | | | | | | | | |
| | 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | Nine Months | | Nine Months | |
| ($ per BOE) | | 2022 | | 2022 | | 2021 | | 2022 | | 2021 | |
Energy operating costs (1) | | $ | 10.96 | | | $ | 9.33 | | | $ | 7.87 | | | $ | 9.83 | | | $ | 6.68 | | |
Gas processing costs (2) | | 0.49 | | | 0.54 | | | 0.56 | | | 0.53 | | | 0.59 | | |
Non-energy operating costs (3) | | 13.82 | | | 13.05 | | | 11.85 | | | 13.35 | | | 11.77 | | |
| Operating costs | | $ | 25.27 | | | $ | 22.92 | | | $ | 20.28 | | | $ | 23.71 | | | $ | 19.04 | | |
| | | | | | | | | | | |
| Costs attributable to PSCs | | | | | | | | | | | |
| Excess energy operating costs attributable to PSCs | | $ | (0.97) | | | $ | (1.03) | | | $ | (0.69) | | | $ | (0.98) | | | $ | (0.63) | | |
| Excess non-energy operating costs attributable to PSCs | | (1.19) | | | (1.55) | | | (1.15) | | | (1.37) | | | (1.09) | | |
| Excess costs attributable to PSCs | | $ | (2.16) | | | $ | (2.58) | | | $ | (1.84) | | | $ | (2.35) | | | $ | (1.72) | | |
| | | | | | | | | | | |
Energy operating costs, excluding effect of PSCs (1) | | $ | 9.99 | | | $ | 8.30 | | | $ | 7.18 | | | $ | 8.85 | | | $ | 6.05 | | |
Gas processing costs, excluding effect of PSCs (2) | | 0.49 | | | 0.54 | | | 0.56 | | | 0.53 | | | 0.59 | | |
Non-energy operating costs, excluding effect of PSCs (3) | | 12.63 | | | 11.50 | | | 10.70 | | | 11.98 | | | 10.68 | | |
| Operating costs, excluding effects of PSCs | | $ | 23.11 | | | $ | 20.34 | | | $ | 18.44 | | | $ | 21.36 | | | $ | 17.32 | | |
| | | | | | | | | | | |
| (1) Energy operating costs consist of purchases of natural gas to generate electricity, purchased electricity and internal costs to produce electricity used in our operations. | |
| (2) Gas processing costs include costs associated with compression, maintenance and other activities needed to run our gas processing facilities at Elk Hills. | |
| (3) Non-energy operating costs equal total operating costs less energy and gas processing costs. Purchased natural gas used to generate steam in our 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 | | | | | | | | | | | |
| Net | | 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | Nine Months | | Nine Months | |
| Oil, NGLs and Natural Gas Production Per Day | | 2022 | | 2022 | | 2021 | | 2022 | | 2021 | |
| | | | | | | | | | | |
| Oil (MBbl/d) | | | | | | | | | | | |
| San Joaquin Basin | | 36 | | | 38 | | | 40 | | | 37 | | | 39 | | |
| Los Angeles Basin | | 19 | | | 16 | | | 19 | | | 18 | | | 19 | | |
| Ventura Basin | | — | | | — | | | 3 | | | — | | | 3 | | |
| Total | | 55 | | | 54 | | | 62 | | | 55 | | | 61 | | |
| | | | | | | | | | | |
| NGLs (MBbl/d) | | | | | | | | | | | |
| San Joaquin Basin | | 12 | | | 12 | | | 13 | | | 11 | | | 13 | | |
| Ventura Basin | | — | | | — | | | — | | | — | | | — | | |
| Total | | 12 | | | 12 | | | 13 | | | 11 | | | 13 | | |
| | | | | | | | | | | |
| Natural Gas (MMcf/d) | | | | | | | | | | | |
| San Joaquin Basin | | 131 | | | 132 | | | 135 | | | 128 | | | 135 | | |
| Los Angeles Basin | | 1 | | | 1 | | | 1 | | | 1 | | | 1 | | |
| Ventura Basin | | — | | | — | | | 5 | | | — | | | 5 | | |
| Sacramento Basin | | 17 | | | 18 | | | 19 | | | 18 | | | 19 | | |
| Total | | 149 | | | 151 | | | 160 | | | 147 | | | 160 | | |
| | | | | | | | | | | |
| Total Production (MBoe/d) | | 92 | | | 91 | | | 102 | | | 91 | | | 101 | | |
| | | | | | | | | | | |
| Gross Operated and Net Non-Operated | | 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | Nine Months | | Nine Months | |
| Oil, NGLs and Natural Gas Production Per Day | | 2022 | | 2022 | | 2021 | | 2022 | | 2021 | |
| | | | | | | | | | | |
| Oil (MBbl/d) | | | | | | | | | | | |
| San Joaquin Basin | | 40 | | | 42 | | | 45 | | | 41 | | | 44 | | |
| Los Angeles Basin | | 26 | | | 25 | | | 26 | | | 26 | | | 27 | | |
| Ventura Basin | | — | | | — | | | 3 | | | — | | | 3 | | |
| Total | | 66 | | | 67 | | | 74 | | | 67 | | | 74 | | |
| | | | | | | | | | | |
| NGLs (MBbl/d) | | | | | | | | | | | |
| San Joaquin Basin | | 13 | | | 13 | | | 14 | | | 12 | | | 13 | | |
| Ventura Basin | | — | | | — | | | — | | | — | | | 1 | | |
| Total | | 13 | | | 13 | | | 14 | | | 12 | | | 14 | | |
| | | | | | | | | | | |
| Natural Gas (MMcf/d) | | | | | | | | | | | |
| San Joaquin Basin | | 140 | | | 141 | | | 144 | | | 137 | | | 143 | | |
| Los Angeles Basin | | 7 | | | 7 | | | 8 | | | 7 | | | 8 | | |
| Ventura Basin | | — | | | — | | | 5 | | | — | | | 5 | | |
| Sacramento Basin | | 21 | | | 22 | | | 23 | | | 22 | | | 24 | | |
| Total | | 168 | | | 170 | | | 180 | | | 166 | | | 180 | | |
| | | | | | | | | | | |
| Total Production (MBoe/d) | | 107 | | | 108 | | | 118 | | | 107 | | | 118 | | |
| | | | | | | | | | | |
| 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 | | | | | | | | | | | | | |
| 3rd Quarter | | 2nd Quarter | | | 3rd Quarter | | Nine Months | | Nine Months | | | |
| | 2022 | | 2022 | | | 2021 | | 2022 | | 2021 | | | |
| Oil ($ per Bbl) | | | | | | | | | | | | | |
| Realized price with derivative settlements | $ | 62.45 | | | $ | 63.17 | | | | $ | 55.42 | | | $ | 61.96 | | | $ | 54.43 | | | | |
| Realized price without derivative settlements | $ | 97.96 | | | $ | 112.32 | | | | $ | 72.89 | | | $ | 102.01 | | | $ | 67.62 | | | | |
| | | | | | | | | | | | | |
| NGLs ($/Bbl) | $ | 57.68 | | | $ | 68.29 | | | | $ | 53.74 | | | $ | 66.98 | | | $ | 49.20 | | | | |
| | | | | | | | | | | | | |
| Natural gas ($/Mcf) | | | | | | | | | | | | | |
| Realized price with derivative settlements | $ | 8.58 | | | $ | 6.72 | | | | $ | 4.64 | | | $ | 7.21 | | | $ | 3.64 | | | | |
| Realized price without derivative settlements | $ | 8.80 | | | $ | 6.85 | | | | $ | 4.66 | | | $ | 7.33 | | | $ | 3.67 | | | | |
| | | | | | | | | | | | | |
| Index Prices | | | | | | | | | | | | | |
| Brent oil ($/Bbl) | $ | 97.81 | | | $ | 111.79 | | | | $ | 73.23 | | | $ | 102.33 | | | $ | 67.78 | | | | |
| WTI oil ($/Bbl) | $ | 91.56 | | | $ | 108.41 | | | | $ | 70.56 | | | $ | 98.09 | | | $ | 64.82 | | | | |
| NYMEX Henry Hub contract month average ($/MMBtu) | $ | 7.85 | | | $ | 6.62 | | | | $ | 3.71 | | | $ | 6.22 | | | $ | 3.06 | | | | |
| NYMEX Henry Hub average monthly settled price ($/MMBtu) | $ | 8.20 | | | $ | 7.17 | | | | $ | 4.01 | | | $ | 6.77 | | | $ | 3.18 | | | | |
| | | | | | | | | | | | | |
| Realized Prices as Percentage of Index Prices | | | | | | | | | | | | | |
| Oil with derivative settlements as a percentage of Brent | 64 | % | | 57 | % | | | 76 | % | | 61 | % | | 80 | % | | | |
| Oil without derivative settlements as a percentage of Brent | 100 | % | | 100 | % | | | 100 | % | | 100 | % | | 100 | % | | | |
| | | | | | | | | | | | | |
| Oil with derivative settlements as a percentage of WTI | 68 | % | | 58 | % | | | 79 | % | | 63 | % | | 84 | % | | | |
| Oil without derivative settlements as a percentage of WTI | 107 | % | | 104 | % | | | 103 | % | | 104 | % | | 104 | % | | | |
| | | | | | | | | | | | | |
| NGLs as a percentage of Brent | 59 | % | | 61 | % | | | 73 | % | | 65 | % | | 73 | % | | | |
| NGLs as a percentage of WTI | 63 | % | | 63 | % | | | 76 | % | | 68 | % | | 76 | % | | | |
| | | | | | | | | | | | | |
| Natural gas with derivative settlements as a percentage of NYMEX contract month average | 109 | % | | 102 | % | | | 125 | % | | 116 | % | | 119 | % | | | |
| Natural gas with derivative settlements as a percentage of NYMEX average monthly settled price | 105 | % | | 94 | % | | | 116 | % | | 106 | % | | 114 | % | | | |
| | | | | | | | | | | | | |
| Natural gas without derivative settlements as a percentage of NYMEX contract month average | 112 | % | | 103 | % | | | 126 | % | | 118 | % | | 120 | % | | | |
| Natural gas without derivative settlements as a percentage of NYMEX average monthly settled price | 107 | % | | 96 | % | | | 116 | % | | 108 | % | | 115 | % | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | Attachment 5 |
| THIRD QUARTER 2022 DRILLING ACTIVITY | | | | | | | | | | |
| | | San Joaquin | | Los Angeles | | Ventura | | Sacramento | | |
| Wells Drilled | | Basin | | Basin | | Basin | | Basin | | Total |
| | | | | | | | | | |
| Development Wells | | | | | | | | | | |
| Primary | | 9 | | — | | — | | — | | 9 |
| Waterflood | | — | | 11 | | — | | — | | 11 |
| Steamflood | | 16 | | — | | — | | — | | 16 |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Total (1) | | 25 | | 11 | | — | | — | | 36 |
| | | | | | | | | | |
| | | | | | | | | | |
| NINE MONTH 2022 DRILLING ACTIVITY | | | | | | | | | | |
| | | San Joaquin | | Los Angeles | | Ventura | | Sacramento | | |
| Wells Drilled | | Basin | | Basin | | Basin | | Basin | | Total |
| | | | | | | | | | |
| Development Wells | | | | | | | | | | |
| Primary | | 17 | | — | | — | | — | | 17 |
| Waterflood | | 27 | | 25 | | — | | — | | 52 |
| Steamflood | | 55 | | — | | — | | — | | 55 |
Total (1) | | 99 | | 25 | | — | | — | | 124 |
| | | | | | | | | | |
(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 SEPTEMBER 30, 2022 | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | Q4 2022 | | Q1 2023 | | Q2 2023 | | Q3 2023 | | Q4 2023 | | 2024 |
| | | | | | | | | | | | | |
| Sold Calls | | | | | | | | | | | | | |
| Barrels per day | | | 25,167 | | 18,322 | | 17,837 | | 17,363 | | 5,747 | | — |
| Weighted-average Brent price per barrel | | | $57.82 | | $57.28 | | $60.00 | | $57.06 | | $57.06 | | — |
| | | | | | | | | | | | | |
| Swaps | | | | | | | | | | | | | |
| Barrels per day | | | 17,263 | | 14,620 | | 14,475 | | 14,697 | | 26,094 | | 1,492 |
| Weighted-average Brent price per barrel | | | $58.79 | | $67.36 | | $66.36 | | $66.27 | | $69.14 | | $79.06 |
| | | | | | | | | | | | | |
Net Purchased Puts 1 | | | | | | | | | | | | | |
| Barrels per day | | | 25,167 | | 18,322 | | 17,837 | | 17,363 | | 5,747 | | 1,724 |
| Weighted-average Brent price per barrel | | | $64.47 | | $76.25 | | $76.25 | | $76.25 | | $76.25 | | $75.00 |
| | | | | | | | | | | | | |
| Sold Puts | | | | | | | | | | | | | |
| Barrels per day | | | 1,348 | | — | | — | | — | | — | | — |
| Weighted-average Brent price per barrel | | | $32.00 | | — | | — | | — | | — | | — |
| | | | | | | | | | | | | |
1 Purchased and sold puts with the same strike price have been presented on a net basis. |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | Attachment 7 |
| | | | | |
| 2022 Estimated |
TOTAL CRC GUIDANCE1 | Consolidated | | CMB | | E&P, Corporate & Other |
| Net Total Production (MBoe/d) | 94 - 91 | | | | 94 - 91 |
| Net Oil Production (MBbl/d) | 58 - 53 | | | | 58 - 53 |
| Operating Costs ($ millions) | $760 - $790 | | | | $760 - $790 |
CMB Expenses2 ($ millions) | $10 - $20 | | $10 - $20 | | |
| Adjusted General and Administrative Expenses ($ millions) | $195 - $210 | | $10 - $15 | | $185 - $195 |
| Capital ($ millions) | $380 - $400 | | $20 - $30 | | $360 - $370 |
| Adjusted EBITDAX ($ millions) | $835 - $890 | | ($20) - ($35) | | $870 -- $910 |
| Free Cash Flow ($ millions) | $325 - $370 | | ($40) - ($65) | | $390 - $410 |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
See Attachment 2 for management's disclosure of its use of these non-GAAP measures and how these measures provide useful information to investors about CRC's results of operations and financial condition. CRC has supplemented its non-GAAP measures of consolidated adjusted EBITDAX and consolidated free cash flow with adjusted EBITDAX for its exploration and production and corporate items (Adjusted EBITDAX for E&P, Corporate & Other) and free cash flow from our exploration and production and corporate items (free cash flow from E&P, Corporate & Other) which CRC believes are useful measures for investors to understand the results of its core oil and gas business. CRC defines adjusted EBITDAX for E&P, Corporate & Other as consolidated adjusted EBITDAX less results attributable to its carbon management business (CMB). CRC defines free cash flow from E&P, Corporate & Other as consolidated free cash flow less results attributable to CMB.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2022 Estimated |
| Consolidated | | CMB | | E&P, Corporate & Other |
| ($ millions) | Low | | High | | Low | | High | | Low | | High |
| Net cash provided (used) by operating activities | $ | 725 | | | $ | 750 | | | $ | (35) | | | $ | (20) | | | $ | 760 | | | $ | 770 | |
| Capital investments | (400) | | | (380) | | | (30) | | | (20) | | | (370) | | | (360) | |
| Estimated free cash flow | $ | 325 | | | $ | 370 | | | $ | (65) | | | $ | (40) | | | $ | 390 | | | $ | 410 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2022 Estimated |
| Consolidated | | CMB | | E&P, Corporate & Other |
| ($ millions) | Low | | High | | Low | | High | | Low | | High |
| Net income | $ | 612 | | | $ | 650 | | | $ | (35) | | | $ | (20) | | | $ | 647 | | | $ | 670 | |
| Interest and debt expense, net | 51 | | 52 | | | | | | 51 | | 52 |
| Depreciation, depletion and amortization | 200 | | 202 | | | | | | 200 | | 202 |
| Exploration expense | 5 | | 10 | | | | | | 5 | | 10 |
| Income taxes | 273 | | 277 | | | | | | 273 | | 277 |
| Unusual, infrequent and other items | | | | | | | | | | | |
| Non-cash derivative gain | (318) | | | (315) | | | | | | | (318) | | | (315) | |
| Gain on asset divestitures | (60) | | | (60) | | | | | | | (60) | | | (60) | |
| Other | 10 | | | 10 | | | | | | | 10 | | | 10 | |
| Other non-cash items | | | | | | | | | | | |
| Accretion expense | 43 | | 44 | | | | | | 43 | | 44 |
| Stock-based compensation | 17 | | 18 | | | | | | 17 | | 18 |
| Post-retirement medical and pension | 2 | | 2 | | | | | | 2 | | 2 |
| Estimated adjusted EBITDAX | $ | 835 | | | $ | 890 | | | $ | (35) | | | $ | (20) | | | $ | 870 | | | $ | 910 | |
| | | | | | | | | | | |
| Net cash provided (used) by operating activities | $ | 725 | | | $ | 750 | | | $ | (35) | | | $ | (20) | | | $ | 760 | | | $ | 770 | |
| Cash interest | 50 | | 52 | | | | | | 50 | | 52 |
| Cash income taxes | 30 | | 36 | | | | | | 30 | | 36 |
| Exploration expenditures | 5 | | 10 | | | | | | 5 | | 10 |
| Working capital changes | 25 | | 42 | | | | | | 25 | | 42 |
| Estimated adjusted EBITDAX | $ | 835 | | | $ | 890 | | | $ | (35) | | | $ | (20) | | | $ | 870 | | | $ | 910 | |
| | | | | | | | | | | |
| 2022 Estimated |
| Consolidated | | CMB | | E&P, Corporate & Other |
| ($ millions) | Low | | High | | Low | | High | | Low | | High |
| General and administrative expenses | $ | 220 | | | $ | 230 | | | $ | 10 | | | $ | 15 | | | $ | 210 | | | $ | 215 | |
| Equity-settled stock-based compensation | (20) | | | (15) | | | | | | | (20) | | | (15) | |
| Other | (5) | | | (5) | | | | | | | (5) | | | (5) | |
| Adjusted general and administrative expenses | $ | 195 | | | $ | 210 | | | $ | 10 | | | $ | 15 | | | $ | 185 | | | $ | 195 | |
| | | | | | | | | | | |
1 Current guidance assumes a 2022 Brent price of $99.75 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $6.47 per mcf. CRC's share of production under PSC contracts decreases when commodity prices rise and increases when prices fall. |
2 CMB Expenses include start-up expenditures. |
|
