California Resources Corporation
11/12/2021 | Press release | Distributed by Public on 11/12/2021 08:01
California Resources Corporation Reports Third Quarter 2021 Results, Declares Inaugural Quarterly Dividend and Announces 2045 Full-Scope Net Zero Goal - Form 8-K
California Resources Corporation Reports Third Quarter 2021 Results, Declares Inaugural Quarterly Dividend and Announces 2045 Full-Scope Net Zero Goal
Santa Clarita, November 11, 2021 - California Resources Corporation (NYSE: CRC), an independent oil and natural gas company committed to energy transition in the sector, today reported third quarter 2021 operational and financial results.
"Third quarter results continued to reflect strong operational performance and represented our best quarter this year in terms of free cash flow generation. These financial results enabled CRC to further enhance our shareholder return strategy by initiating a quarterly cash dividend. Additionally, we tightened our full year free cash flow guidance toward the high end of the range to $460 to $510 million," said Mac McFarland, President and Chief Executive Officer. "Given the strength of our 2021 drilling program and the current commodity environment, we added a fourth rig in Buena Vista Shale in October. Additionally, we expect to have more than $325 million of cash on hand at year end after share repurchases and a cash dividend payment."
Mr. McFarland continued, "As we continue to make progress on our ESG strategy, we are excited to announce a 2045 Full-Scope Net Zero Goal which targets Scope 1, Scope 2 and Scope 3 emissions. As planned, we also submitted our second permit to the EPA for the 26R reservoir, which when combined with our initial permit for the A1/A2 reservoirs, makes up Carbon TerraVault I, an approximately 40 million metric ton storage capacity project. We are also happy to announce that we are progressing our partnership with SunPower on 24 MW of BTM solar projects at the Kern Front and North Shafter fields and continue to target projects in other fields to reduce our carbon footprint. With these efforts, CRC remains committed to maximize shareholder value while executing on our ESG strategy."
Primary Highlights
•Announced a 2045 Full-Scope Net Zero Goal for Scope 1, 2 and 3 emissions
•Adopted and declared a quarterly dividend of $0.17 per share of common stock, totaling approximately $14 million payable in the fourth quarter, with subsequent quarterly dividend payments subject to final determination and Board approval
•Repurchased 3.1 million shares for $104 million through November 5, 2021 under the share repurchase program (SRP) for an average share price of $33.99 per share
•Filed a Class VI permit for the 26R reservoir as part of the Carbon TerraVault I project which is targeting up to 40 million metric ton (MMT) CO2 permanent CCS storage
•After the quarter-end, closings for the sale of our Ventura basin operations occurred with respect to the majority of the basin's assets and subsequent closings are expected to occur in the following quarters.
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Third Quarter 2021 Highlights
Financial
•Reported net income attributable to common stock of $103 million, or $1.25 per diluted share. Adjusted net income1 was $151 million, or $1.83 per diluted share
•Generated net cash provided by operating activities of $182 million, adjusted EBITDAX1 of $242 million and free cash flow1 of $131 million
•Closed the quarter with $189 million of cash on hand, an undrawn credit facility and $548 million of liquidity2
Operations
•Produced an average of 102,000 net barrels of oil equivalent (BOE) per day, including 62,000 barrels per day of oil, with quarterly capital expenditures of $51 million
•Operated two drilling rigs in the San Joaquin Basin and added one drilling rig in the Los Angeles Basin in September; drilled 27 wells (22 online in 3Q21)
•Operated 35 maintenance rigs
•Completed 76 capital workovers
Transactions
•Completed the wind-up of CRC's development joint venture (JV) with Macquarie Infrastructure and Real Assets Inc. (MIRA) and the development joint venture with Benefit Street Partners (BSP)
•Progressing the partnership with SunPower on 24 MW of BTM solar projects at the Kern Front and North Shafter fields
Guidance
•Tightened 2021 free cash flow1 guidance to $460 to $510 million
•Raised 2021 adjusted EBITDAX1 guidance to $840 to $900 million
•Added a drilling rig in the fourth quarter of 2021 that was planned for 2022 due to success of the drilling program to date and continued strong commodity prices; raising 2021 capital guidance to $180 to $200 million
•Increased 2021 operating costs guidance to $700 to $720 million due to rising natural gas prices, which is more than offset by gas revenues due to CRC's net long natural gas position
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2021 Guidance & Capital Program
CRC tightened its full year 2021 free cash flow1 guidance to $460 to $510 million from $400 to $500 million, raised its adjusted EBITDAX1 guidance to $840 to $900 million from $725 to $825 million and raised its production guidance to 99 to 101 MBOE per day from 97 to 100 MBOE per day. Rising natural gas prices are putting upward pressure on operating costs and CRC increased operating guidance to a range of $700 to $720 million for the year, up from $670 to $695 million. Although higher natural gas and electricity prices in 2021 increased CRC's operating costs, higher prices have a net positive effect on its operating results due to higher revenue from sales of these commodities which CRC also produces.
CRC made $128 million of capital investments in the first nine months of 2021. Success of the drilling program to date, along with the rise in commodity prices, resulted in the addition of a drilling rig in the fourth quarter of 2021 that was planned for 2022. As a result, CRC expects its full year capital program to range from $180 to $200 million, up from $170 to $190 million. The Company's capital program will be dynamic in response to oil market volatility while focusing on maintaining its oil production, strong liquidity and maximizing its free cash flow.
| Prior | Revised | |
| 2021E TOTAL YEAR GUIDANCE | Total Year 2021E | Total Year 2021E |
| Net Total Production (Mboe/d) | 97 - 100 | 99 - 101 |
| Net Oil Production (Mbbl/d) | 60 - 62 | 60 - 62 |
| Operating Costs ($ millions) | $670 - $695 | $700 - $720 |
|
General and administrative expenses3 ($ millions)
|
$180 - $190 | $190 - $200 |
| Capital ($ millions) | $170 - $190 | $180 - $200 |
|
Adj. EBITDAX1 ($ millions)
|
$725 - $825 | $840 - $900 |
|
Free cash flow1 ($ millions)
|
$400 - $500 | $460 - $510 |
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Acquisitions and Divestitures
After the quarter-end, closings for the sale of our Ventura basin operations occurred with respect to the majority of the basin's assets and subsequent closings are expected to occur in the following quarters. With the divestitures closed to date, CRC realized $62 million of cash paid at closing (before purchase price adjustments) and its liability for related asset retirement obligations of approximately $100 million which were assumed by the buyer.
During the three months ended September 30, 2021, CRC sold unimproved land for $11 million in proceeds recognizing a $2 million gain.
In August 2021, CRC continued to demonstrate its focus on core areas by acquiring MIRA's 90% working interest share in the joint venture wells for $53 million, before purchase price adjustments and transaction costs. In September 2021, BSP's preferred interest in the BSP JV was automatically redeemed in full under the terms of the joint venture agreement. For the three and nine months ended September 30, 2021, CRC distributed $19 million and $50 million, respectively, to BSP.
CRC's full year guidance accounts for the closing of the sale of CRC's Ventura basin operations in the fourth quarter of 2021.
Sustainability Update
In October 2021, CRC published its 2020 Sustainability Update. The update provides CRC's key environmental, social and governance (ESG) performance metrics. Additionally, CRC has also published metrics following the guidance of the Sustainability Accounting Standards Board (SASB) and the American Petroleum Institute (API) to promote sector transparency.
CRC continues to make progress on its ESG initiatives and has announced a Full-Scope Net Zero Goal by 2045. CRC defines Net Zero as achieving permanent storage of captured or removed carbon emissions in a volume equal to all of its scope 1, 2, and 3 emissions by 2045. CRC intends to achieve this goal by prioritizing 50% of its free cash flow to invest in projects that reduce its direct and indirect emissions or achieve sequestration of carbon in volumes necessary to offset these emissions. The Company remains committed to advancing emissions reducing projects that are aligned with California's climate goals and CRC believes that its Full-Scope Net Zero Goal and its 50% cash flow prioritization are a significant ESG differentiator.
Continuing the Company's low carbon strategy efforts, CRC filed a Class VI permit for the 26R reservoir as part of the up to 40 million metric ton (MMT) CO2 permanent storage CCS project, Carbon TerraVault I, and are progressing the partnership with SunPower on 24 MW of BTM solar projects at the Kern Front and North Shafter fields. This is in addition to the previously announced 12 MW project at Mount Poso and advances projects on a total of 36 MW, of the up to previously announced 45 MW BTM target.
Fresh Start Accounting and Predecessor and Successor Periods
CRC qualified for and adopted fresh start accounting upon emergence from bankruptcy on October 27, 2020, at which point CRC became a new entity for financial reporting purposes. CRC adopted an accounting convenience date of October 31, 2020 for the application of fresh start accounting. As a result of the application of fresh start accounting and the effects of the implementation of the joint plan of reorganization, the financial statements after October 31,
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2020 may not be comparable to the financial statements prior to that date. Accordingly, "black-line" financial statements are presented to distinguish between the Predecessor and Successor companies. References to "Predecessor" refer to the Company for periods ended on or prior to October 31, 2020 and references to "Successor" refer to the Company for periods subsequent to October 31, 2020.
Third Quarter 2021 Results
| Successor | Predecessor | |||
| 3rd Quarter | 3rd Quarter | |||
| ($ and shares in millions, except per share amounts) | 2021 | 2020 | ||
| Statements of Operations: | ||||
| Revenues | ||||
| Total operating revenues | $ | 588 | $ | 409 |
| Operating Expenses | ||||
| Total operating expenses | 468 | 422 | ||
| Operating Income (Loss) | $ | 122 | $ | (13) |
| Net Income (Loss) Attributable to Common Stock | $ | 103 | $ | (29) |
| Net income (loss) attributable to common stock per share - basic | $ | 1.26 | $ | 2.20 |
| Net income (loss) attributable to common stock per share - diluted | $ | 1.25 | $ | 2.20 |
|
Adjusted net income (loss)1
|
$ | 151 | $ | (55) |
|
Adjusted net income (loss)1 per share - diluted
|
$ | 1.83 | $ | 1.68 |
| Weighted-average common shares outstanding - basic | 81.6 | 49.5 | ||
| Weighted-average common shares outstanding - diluted | 82.4 | 49.5 | ||
|
Adjusted EBITDAX1
|
$ | 242 | $ | 103 |
| Successor | Predecessor | |||
| 3rd Quarter | 3rd Quarter | |||
| ($ in millions) | 2021 | 2020 | ||
| Cash Flow Data: | ||||
| Net cash provided by operating activities | $ | 182 | $ | 48 |
| Net cash used in investing activities | $ | (88) | $ | (1) |
| Net cash used in financing activities | $ | (56) | $ | (51) |
Nine Month 2021 Results
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| Successor | Predecessor | |||
| Nine Months | Nine Months | |||
| ($ and shares in millions, except per share amounts) | 2021 | 2020 | ||
| Statements of Operations: | ||||
| Revenues | ||||
| Total operating revenues | $ | 1,255 | $ | 1,258 |
| Costs | ||||
| Total operating costs | 1,298 | 3,035 | ||
| Operating Loss | $ | (43) | $ | (1,777) |
| Net Loss Attributable to Common Stock | $ | (102) | $ | (2,096) |
| Net loss attributable to common stock per share - basic and diluted | $ | (1.23) | $ | (39.64) |
|
Adjusted net income (loss)1
|
$ | 331 | $ | (265) |
|
Adjusted net income (loss)1 per share - diluted
|
$ | 3.97 | $ | (2.57) |
| Weighted-average common shares outstanding - basic and diluted | 82.6 | 49.4 | ||
|
Adjusted EBITDAX1
|
$ | 600 | $ | 373 |
| Successor | Predecessor | |||
| Nine Months | Nine Months | |||
| ($ in millions) | 2021 | 2020 | ||
| Cash Flow Data: | ||||
| Net cash provided by operating activities | $ | 456 | $ | 141 |
| Net cash used by investing activities | $ | (151) | $ | (28) |
| Net cash used by financing activities | $ | (144) | $ | (8) |
Review of Operating and Financial Results
Total daily net production volumes decreased 4% from 106,000 BOE per day for the third quarter of 2020 to 102,000 BOE per day for the third quarter of 2021. Total daily net production volumes decreased 11% from 113,000 BOE per day for the nine months ended September 30, 2020 to 101,000 BOE per day for the same period in 2021. The decrease from the same period in 2020 was primarily due to limited drilling activity and capital investment during 2020 and natural decline rates. This decrease was partially offset by improved operational results from CRC's 2021 drilling program and its acquisition of the working interests in certain joint venture wells held by MIRA in the third quarter of 2021. Production sharing type contracts (PSC-type) at CRC's Long Beach assets negatively impacted oil production by approximately 1,000 and 3,000 barrels per day in the three and nine months ended September 30, 2021, respectively, compared to the same prior-year period. See Attachment 3 for further information on production.
Realized oil prices, including the effect of settled hedges, increased by $13.27 per barrel from $42.15 per barrel in the third quarter of 2020 to $55.42 per barrel in the third quarter of 2021. For the nine months ended September 30, 2021, realized oil prices, including the effect of settled hedges, increased by $11.16 to $54.43 from $43.27 in the same period of 2020. Realized oil prices were higher in the third quarter of 2021 compared to the same prior-year period as oil demand was bolstered by the re-opening of economies and the easing of mobility restrictions. See Attachment 4 for further information on prices.
Adjusted EBITDAX1 for the third quarter of 2021 was $242 million and net cash provided by operating activities was $182 million. Internally funded capital invested during the third quarter of 2021 was $51 million. Free cash flow1 was $131 million. Adjusted EBITDAX1 for the nine months
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ended September 30, 2021 was $600 million and net cash provided by operating activities was $456 million. For the first nine months of 2021, internally funded capital invested was $128 million. Free cash flow1 was $328 million.
| FREE CASH FLOW | ||||||||
| Management uses free cash flow, which is defined by us as net cash provided by operating activities less capital investments, as a measure of liquidity. The following table presents a reconciliation of our net cash provided by operating activities to free cash flow. We have excluded one-time costs for bankruptcy related fees during 2021 and 2020 as a supplemental measure of free cash flow. | ||||||||
| Successor | Predecessor | Successor | Predecessor | |||||
| 3rd Quarter | 3rd Quarter | Nine Months | Nine Months | |||||
| ($ millions) | 2021 | 2020 | 2021 | 2020 | ||||
| Net cash provided by operating activities | $ | 182 | $ | 48 | $ | 456 | $ | 141 |
| Capital investments | (51) | (4) | (128) | (37) | ||||
| Free cash flow | 131 | 44 | 328 | 104 | ||||
| One-time bankruptcy related fees | 1 | 27 | 5 | 74 | ||||
| Free cash flow, after special items | $ | 132 | $ | 71 | $ | 333 | $ | 178 |
The following table provides further detail of CRC's per BOE operating costs. Energy operating costs consist of purchases of natural gas used to generate electricity, purchased electricity and internal costs to generate electricity used in CRC's operations. Non-energy operating costs equal total operating costs less energy costs and gas processing costs. Purchases of natural gas to generate steam which is then used in CRC's steamfloods is included in non-energy operating costs:
| 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 PSC-type contracts. | ||||||||
| Successor | Predecessor | Successor | Predecessor | |||||
| 3rd Quarter | 3rd Quarter | Nine Months | Nine Months | |||||
| ($ per Boe) | 2021 | 2020 | 2021 | 2020 | ||||
| Energy operating costs | $ | 5.49 | $ | 4.25 | $ | 4.97 | $ | 3.81 |
| Gas processing costs | 0.56 | 0.46 | 0.59 | $ | 0.54 | |||
| Non-energy operating costs | 14.23 | 9.81 | 13.48 | 10.50 | ||||
| Operating costs | $ | 20.28 | $ | 14.52 | $ | 19.04 | $ | 14.85 |
| Excess costs attributable to PSC-type contracts | (1.84) | (1.15) | (1.72) | (0.82) | ||||
|
Operating costs, excluding effects of PSC-type contracts (a)
|
$ | 18.44 | $ | 13.37 | $ | 17.32 | $ | 14.03 |
|
(a) Operating costs, excluding effects of PSC-type contracts is a non-GAAP measure. 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. These amounts represent our operating costs after adjusting for this difference. |
Energy operating costs for the three months ended September 30, 2021 were $5.49 per BOE, which was an increase of $1.24 per BOE or 29% from $4.25 per BOE for the same period of 2020. Energy operating costs for the nine months ended September 30, 2021 were $4.97 per BOE, which was an increase of $1.16 per BOE or 30% from $3.81 per BOE for the same period of 2020. This increase was primarily a result of higher prices for purchased natural gas, which CRC used to generate electricity for its operations, and for purchased electricity.
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Non-energy operating costs for the three months ended September 30, 2021 were $14.23 per BOE, which was an increase of $4.42 per BOE or 45% from $9.81 per BOE for the same period of 2020. Non-energy operating costs for the nine months ended September 30, 2021 were $13.48 per BOE, which was an increase of $2.98 per BOE or 28% from $10.50 per BOE for the same period of 2020. This increase was primarily a result of higher downhole maintenance activity in 2021 which was deferred in 2020 as we shut-in wells and surface maintenance activity. Additionally, non-energy operating costs increased in 2021 due to higher prices for purchased natural gas which CRC uses to generate steam for its steamfloods. Partially offsetting these increases were lower compensation-related costs from headcount reductions in late 2020 and early 2021 and reduced employee benefits in the second quarter of 2021. CRC's third quarter 2020 results reflect cost savings for streamlining its operations in response to the industry downturn resulting from the COVID-19 pandemic. Although higher natural gas prices in 2021 increased CRC's operating costs, higher prices have a net positive effect on its operating results due to higher revenue from sales of this commodity which it also produces.
General and administrative (G&A) expenses were $51 million for the third quarter of 2021, compared to $64 million in the same prior-year period. For the nine months ended September 30, 2021, G&A expenses were $147 million compared to $193 million in the same prior-year period. The decrease in G&A expenses for the three and nine months ended September 30, 2021 reflects lower compensation-related costs as a result of workforce reductions that occurred in the second half of 2020 and the first quarter of 2021 as well as benefit reductions in the second quarter of 2021. The remaining decrease between comparative periods was primarily due to cost saving efforts which resulted in lower spend across a number of cost categories. The decrease was partially offset by non-cash stock-based compensation expense related to awards granted to executives and directors in 2021.
Balance Sheet and Liquidity Update
CRC's aggregate commitment under the Revolving Credit Facility was $492 million as of September 30, 2021. The borrowing base for the Revolving Credit Facility is redetermined semi-annually and was most recently reaffirmed at $1.2 billion in November 2021.
As of September 30, 2021, CRC had liquidity of $548 million, which consisted of $189 million in unrestricted cash and $359 million of available borrowing capacity under its Revolving Credit Facility after $133 million of outstanding letters of credit.
CRC expects to begin paying income taxes in 2022 if Brent prices remain at current levels for a sustained period. CRC's tax paying status depends on a number of factors, including but not limited to, commodity prices, the amount and type of CRC's capital spend, cost structure and activity levels. Potential legislation could change key provisions of the existing U.S. corporate income tax regime and it is uncertain whether some or all of the legislative proposals will be enacted. CRC doesn't currently expects the proposed modifications will materially impact its income tax liability. CRC believes it has sufficient sources of cash to meet its obligations for the next twelve months.
Operational Update
During the third quarter of 2021, CRC operated an average of two drilling rigs in the San Joaquin Basin and added one drilling rig in the Los Angeles Basin in September. During the
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quarter, CRC drilled 27 net wells and brought online 22 wells. The San Joaquin basin produced 75,700 net BOE per day. The Los Angeles basin produced 19,300 net BOE per day, the Ventura basin produced 3,600 net BOE per day and the Sacramento basin produced 3,100 net BOE per day.
Conference Call Details
To participate in the conference call scheduled for later today 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/10160036/ed00623af0.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 PSC-type contracts), adjusted net income (loss), adjusted net income (loss) per share - basic and diluted) and free cash flow, including reconciliations to their most directly comparable GAAP measure, where applicable. For the full year 2021 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 $189 million of cash plus $492 million of capacity on CRC's Revolving Credit Facility less $133 million in outstanding letters of credit
3 Includes approximately $13 million of non-cash stock-based compensation expense.
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 we are focused on maximizing the value of our land, mineral and technical resources for decarbonization by developing carbon capture and storage (CCS) and other emissions reducing projects. For more information about CRC, please visit www.crc.com.
Forward-Looking Statements
This release contains forward-looking statements, including statements relating to the manner in which CRC intends to conduct certain of its activities with respect to developing and implementing carbon capture and storage programs and related efforts based on management's current plans and expectations. These statements are not promises or guarantees of future conduct, performance or policy and involve risks and uncertainties that could materially affect CRC's expected results of operations, liquidity, cash flows and business prospects. Such forward-looking statements include those regarding CRC's expectations as to its future:
•energy transition initiatives
•financial position, liquidity, cash flows and results of operations
•business prospects
•transactions and projects
•operating costs and general and administrative expenses
•operations and operational results including production, hedging and capital investment
•budgets and maintenance capital requirements
•reserves and reservoir characteristics
•type curves
•expected synergies from acquisitions and joint ventures
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Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. While CRC believes assumptions or bases underlying its expectations are reasonable and makes them in good faith, they almost always vary from actual results, sometimes materially. Therefore, the actual conduct of its activities, including development, implementation, or continuation of any carbon capture and storage programs or other initiatives or efforts discussed or forecasted in this release or in the future in connection with updates issued regarding these programs, initiatives and efforts, may differ materially in the future. In addition, many of the assumptions and metrics used to create the forward-looking statements contained in this release and used in the process of creating this release continue to evolve and are highly likely to change over time. Moreover, some of the time frames used in the creation of these forward-looking statements are longer than those time frames customarily used in CRC's disclosures issued under required regimes. Given the inherent uncertainty of the assumptions, metrics and timelines contained in this release, the materiality of CRC's statements is inherently difficult to assess in advance, and it may not be able to anticipate whether or the degree to which it will be able to meet its plans, targets or goals in advance.
Factors (but not necessarily all the factors) that could cause results to differ include:
•CRC's ability to execute its business plan post-emergence, including its ability to finance and implement its carbon capture and storage program
•CRC's ability to recognize the benefits of business strategies and initiatives related to energy transition, including carbon capture and storage projects and other renewable energy efforts
•legislative or regulatory changes, including those related to (i) drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, (ii) managing energy, water, land, greenhouse gases (GHGs) or other emissions, (iii) protection of health, safety and the environment, (iv) tax credits, carbon credits or other incentives or (v) transportation, marketing and sale of its products
•global socio-demographic and economic trends and technological innovations
•the volatility of commodity prices and the potential for sustained low oil, natural gas and natural gas liquids prices
•impact of CRC's recent emergence from bankruptcy on its business and relationships
•debt limitations on CRC's financial flexibility
•insufficient cash flow to fund planned investments, interest payments on CRC's debt, debt repurchases or changes to its capital plan
•insufficient capital or liquidity, including as a result of lender restrictions, unavailability of 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 utilize its net operating loss carryforwards to reduce its income tax obligations
•joint ventures and acquisitions and CRC's ability to achieve expected synergies
•the recoverability of resources and unexpected geologic conditions
•incorrect estimates of reserves and related future cash flows and the inability to replace reserves
•changes in business strategy
•changes in CRC's dividend policy and its ability to declare future dividends in the amounts anticipated or at all
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•CRC's ability to achieve its Net Zero goals, including related initiatives and efforts, generally and under the expected time frames
•production-sharing contracts' effects on production and operating costs
•CRC's ability to successfully gather and verify data regarding its environmental impacts and 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 its climate-related initiatives
•the effect of CRC's stock price on costs associated with incentive compensation
•effects of hedging transactions
•equipment, service or labor price inflation or unavailability
•availability or timing of, or conditions imposed on, permits and approvals
•lower-than-expected production, reserves or resources from development projects, joint ventures or acquisitions, or higher-than-expected decline rates
•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
•other factors discussed in Item 1A, Risk Factors in CRC's Annual Report on Form 10-K and CRC's other SEC filings available at www.crc.com.
Words such as "anticipate," "believe," "continue," "could," "estimate," "expect," "goal," "intend," "likely," "may," "might," "plan," "potential," "project," "seek," "should," "target, "will" or "would" and similar words that reflect the prospective nature of events or outcomes typically identify forward-looking statements. Any forward-looking statement speaks only as of the date on which such statement is made, and CRC undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. You should not place undue reliance on any forward-looking statement, and should carefully review the risk considerations in this release and in CRC's other filings and disclosures.
While certain matters discussed in this release and in other climate-related disclosures may be significant, any significance should not be read as necessarily rising to the level of materiality used for the purposes of CRC's compliance with the U.S. federal securities laws and regulations, even if it uses the word "material" or "materiality." This release may also contain information from third-party sources. This data may involve a number of assumptions and limitations, and CRC has not independently verified them and does not warrant the accuracy or completeness of such third-party data.
Contacts:
|
Joanna Park (Investor Relations) 818-661-3731 [email protected] |
Richard Venn (Media)
818-661-6014
|
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| Attachment 1 | ||||||||
| SUMMARY OF RESULTS | ||||||||
| Successor | Predecessor | Successor | Predecessor | |||||
| 3rd Quarter | 3rd Quarter | Nine Months | Nine Months | |||||
| ($ and shares in millions, except per share amounts) | 2021 | 2020 | 2021 | 2020 | ||||
| Statements of Operations: | ||||||||
| Revenues | ||||||||
| Oil, natural gas and NGL sales | $ | 549 | $ | 312 | $ | 1,459 | $ | 987 |
| Net (loss) gain from commodity derivatives | (125) | - | (603) | 75 | ||||
| Sales of purchased natural gas | 95 | 50 | 241 | 109 | ||||
| Electricity sales | 65 | 43 | 131 | 75 | ||||
| Other revenue | 4 | 4 | 27 | 12 | ||||
| Total operating revenues | 588 | 409 | 1,255 | 1,258 | ||||
| Operating Expenses | ||||||||
| Operating costs | 190 | 141 | 523 | 460 | ||||
| General and administrative expenses | 51 | 64 | 147 | 193 | ||||
| Depreciation, depletion and amortization | 54 | 89 | 160 | 296 | ||||
| Asset impairments | 25 | - | 28 | 1,736 | ||||
| Taxes other than on income | 36 | 42 | 113 | 121 | ||||
| Exploration expense | 2 | 2 | 6 | 9 | ||||
| Purchased natural gas expense | 53 | 35 | 144 | 67 | ||||
| Electricity generation expenses | 29 | 17 | 70 | 47 | ||||
| Transportation costs | 11 | 10 | 37 | 31 | ||||
| Accretion expense | 13 | 10 | 39 | 30 | ||||
| Other operating expenses net | 4 | 12 | 31 | 45 | ||||
| Total operating expenses | 468 | 422 | 1,298 | 3,035 | ||||
| Gain on asset divestitures | (2) | - | (4) | - | ||||
| Operating Income (Loss) | 122 | (13) | (39) | (1,777) | ||||
| Non-Operating (Expenses) Income | ||||||||
| Reorganization items, net | (1) | 66 | (5) | 66 | ||||
| Interest and debt expense, net | (14) | (28) | (40) | (200) | ||||
| Net (loss) gain on early extinguishment of debt | - | - | (2) | 5 | ||||
| Other non-operating expenses, net | - | (32) | (3) | (93) | ||||
| Income (Loss) Before Income Taxes | 107 | (7) | (89) | (1,999) | ||||
| Income taxes | - | - | - | - | ||||
| Net Income (Loss) | 107 | (7) | (89) | (1,999) | ||||
| Net income attributable to noncontrolling interests | (4) | (22) | (13) | (97) | ||||
| Net Income (Loss) Attributable to Common Stock | $ | 103 | $ | (29) | $ | (102) | $ | (2,096) |
| Net loss attributable to common stock per share - basic | $ | 1.26 | $ | 2.20 | $ | (1.23) | $ | (39.64) |
| Net loss attributable to common stock per share - diluted | $ | 1.25 | $ | 2.20 | $ | (1.23) | $ | (39.64) |
| Adjusted net income (loss) | $ | 151 | $ | (55) | $ | 331 | $ | (265) |
| Weighted-average common shares outstanding - basic | 81.6 | 49.5 | 82.6 | 49.4 | ||||
| Weighted-average common shares outstanding - diluted | 82.4 | 49.5 | 82.6 | 49.4 | ||||
| Adjusted EBITDAX | $ | 242 | $ | 103 | $ | 600 | $ | 373 |
| Effective tax rate | 0% | 0% | 0% | 0% |
Page 13
| Successor | Predecessor | Successor | Predecessor | |||||
| 3rd Qtr. | 3rd Qtr. | Nine Months | Nine Months | |||||
| ($ in millions) | 2021 | 2020 | 2021 | 2020 | ||||
| Cash Flow Data: | ||||||||
| Net cash provided by operating activities | $ | 182 | $ | 48 | $ | 456 | $ | 141 |
| Net cash used in investing activities | $ | (88) | $ | (1) | $ | (151) | $ | (28) |
| Net cash used in financing activities | $ | (56) | $ | (51) | $ | (144) | $ | (8) |
| September 30, | December 31, | |||
| ($ and shares in millions) | 2021 | 2020 | ||
| Selected Balance Sheet Data: | ||||
| Total current assets | $ | 657 | $ | 329 |
| Property, plant and equipment, net | $ | 2,587 | $ | 2,655 |
| Total current liabilities | $ | 957 | $ | 473 |
| Long-term debt, net | $ | 589 | $ | 597 |
| Asset retirement obligations | $ | 428 | $ | 547 |
| Stockholders' Equity | $ | 1,052 | $ | 1,182 |
| Outstanding shares | 80.8 | 83.3 |
Page 14
| GAINS AND LOSSES FROM COMMODITY DERIVATIVES | ||||||||
| Successor | Predecessor | Successor | Predecessor | |||||
| 3rd Qtr. | 3rd Qtr. | Nine Months | Nine Months | |||||
| ($ millions) | 2021 | 2020 | 2021 | 2020 | ||||
| Non-cash derivative (loss) gain - excluding noncontrolling interest | $ | (26) | $ | 4 | $ | (383) | $ | (31) |
| Non-cash derivative (loss) gain - noncontrolling interest | - | (6) | - | 1 | ||||
| Total non-cash changes | (26) | (2) | (383) | (30) | ||||
| Net (payments) proceeds on settled commodity derivatives | (99) | 2 | (220) | 42 | ||||
| Net proceeds on sale of commodity derivatives | - | - | - | 63 | ||||
| Net (loss) gain from commodity derivatives | $ | (125) | $ | - | $ | (603) | $ | 75 |
| 1st Quarter | 1st Quarter | 4th Quarter | 4th Quarter | 4th Quarter |
| CAPITAL INVESTMENTS | ||||||||
| Successor | Predecessor | Successor | Predecessor | |||||
| 3rd Qtr. | 3rd Qtr. | Nine Months | Nine Months | |||||
| ($ millions) | 2021 | 2020 | 2021 | 2020 | ||||
| Internally funded capital | $ | 51 | $ | 4 | $ | 128 | $ | 37 |
| Capital investments not included on our financial statements: | ||||||||
| MIRA funded capital | - | - | - | 1 | ||||
| Alpine funded capital | - | (4) | - | 93 | ||||
| Total capital program | $ | 51 | $ | - | $ | 128 | $ | 131 |
Page 15
| 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 (loss) and net income (loss) attributable to common stock per share to the non-GAAP financial measure of adjusted net income (loss) and adjusted net income (loss) per share. | ||||||||
| Successor | Predecessor | Successor | Predecessor | |||||
| 3rd Qtr. | 3rd Qtr. | Nine Months | Nine Months | |||||
| ($ millions, except per share amounts) | 2021 | 2020 | 2021 | 2020 | ||||
| Net income (loss) | $ | 107 | $ | (7) | $ | (89) | $ | (1,999) |
| Net income attributable to noncontrolling interests | (4) | (22) | (13) | (97) | ||||
| Net income (loss) attributable to common stock | 103 | (29) | (102) | (2,096) | ||||
| Unusual, infrequent and other items: | ||||||||
| Non-cash loss (income) from commodity derivatives, excluding noncontrolling interest | 26 | (4) | 383 | 31 | ||||
| Asset impairments | 25 | - | 28 | 1,736 | ||||
| Reorganization items, net | 1 | (66) | 5 | (66) | ||||
| Chapter 11 transaction costs | - | 15 | - | 64 | ||||
| Severance and termination costs | - | 10 | 15 | 10 | ||||
| Net loss (gain) on early extinguishment of debt | - | - | 2 | (5) | ||||
| Deficiency payment on pipeline delivery contract | - | - | - | 20 | ||||
| Power plant maintenance | - | - | - | 7 | ||||
| Incentive and retention award modification | - | - | - | 4 | ||||
| Write-off deferred financing costs | - | 4 | - | 4 | ||||
| Gain on asset divestitures | (2) | - | (4) | - | ||||
| Rig termination expenses | - | 1 | 2 | 3 | ||||
| Other, net | (2) | 14 | 2 | 23 | ||||
| Total unusual, infrequent and other items | 48 | (26) | 433 | 1,831 | ||||
| Adjusted net income (loss) attributable to common stock | $ | 151 | $ | (55) | $ | 331 | $ | (265) |
| Net loss attributable to common stock per share - diluted | $ | 1.25 | $ | 2.20 | $ | (1.23) | $ | (39.64) |
| Adjusted net income (loss) per share - basic | $ | 1.85 | $ | 1.68 | $ | 4.01 | $ | (2.57) |
| Adjusted net income (loss) per share - diluted | $ | 1.83 | $ | 1.68 | $ | 3.97 | $ | (2.57) |
Page 16
| 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 have excluded one-time costs for bankruptcy related fees during 2021 and 2020 as a supplemental measure of our free cash flow. | ||||||||
| Successor | Predecessor | Successor | Predecessor | |||||
| 3rd Quarter | 3rd Quarter | Nine Months | Nine Months | |||||
| ($ millions) | 2021 | 2020 | 2021 | 2020 | ||||
| Net cash provided by operating activities | $ | 182 | $ | 48 | $ | 456 | $ | 141 |
| Capital investments | (51) | (4) | (128) | (37) | ||||
| Free cash flow | 131 | 44 | 328 | 104 | ||||
| One-time bankruptcy related fees | 1 | 27 | 5 | 74 | ||||
| Free cash flow, after special items | $ | 132 | $ | 71 | $ | 333 | $ | 178 |
| 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. | ||||||||
| Successor | Predecessor | Successor | Predecessor | |||||
| 3rd Qtr. | 3rd Qtr. | Nine Months | Nine Months | |||||
| ($ millions, except per BOE amounts) | 2021 | 2020 | 2021 | 2020 | ||||
| Net income (loss) | $ | 107 | $ | (7) | $ | (89) | $ | (1,999) |
| Interest and debt expense, net | 14 | 28 | 40 | 200 | ||||
| Depreciation, depletion and amortization | 54 | 89 | 160 | 296 | ||||
| Exploration expense | 2 | 2 | 6 | 9 | ||||
|
Unusual, infrequent and other items (a)
|
48 | (26) | 433 | 1,831 | ||||
| Non-cash items | ||||||||
| Accretion expense | 13 | 10 | 39 | 30 | ||||
| Stock-settled compensation | 4 | 1 | 9 | 4 | ||||
| Post-retirement medical and pension | - | 1 | 2 | 4 | ||||
| Other non-cash items | - | 5 | - | (2) | ||||
| Adjusted EBITDAX | $ | 242 | $ | 103 | $ | 600 | $ | 373 |
| Net cash provided by operating activities | $ | 182 | $ | 48 | $ | 456 | $ | 141 |
| Cash interest | 24 | 21 | 29 | 80 | ||||
| Exploration expenditures | 2 | 2 | 6 | 9 | ||||
| Working capital changes | 34 | 32 | 109 | 143 | ||||
| Adjusted EBITDAX | $ | 242 | $ | 103 | $ | 600 | $ | 373 |
| Adjusted EBITDAX per Boe | $ | 25.83 | $ | 10.61 | $ | 21.85 | $ | 12.04 |
| (a) See Adjusted Net Income (Loss) reconciliation. |
Page 17
| DISCRETIONARY CASH FLOW | ||||||||
| We define discretionary cash flow as the cash available after distributions to noncontrolling interest holders, cash interest and asset retirement obligation and idle well testing, excluding the effect of working capital changes but before our internal capital investment. Management uses discretionary cash flow as a measure of the availability of cash to reduce debt or fund investments. | ||||||||
| Successor | Predecessor | Successor | Predecessor | |||||
| 3rd Quarter | 3rd Quarter | Nine Months | Nine Months | |||||
| ($ millions) | 2021 | 2020 | 2021 | 2020 | ||||
| Adjusted EBITDAX | $ | 242 | $ | 103 | $ | 600 | $ | 373 |
| Cash interest | (24) | (21) | (29) | (80) | ||||
| Distributions paid to noncontrolling interest holders: | ||||||||
| BSP | (19) | (5) | (50) | (34) | ||||
| Ares | - | (22) | - | (61) | ||||
| Asset retirement obligations and idle well testing | (10) | (2) | (34) | (8) | ||||
| Discretionary cash flow | $ | 189 | $ | 53 | $ | 487 | $ | 190 |
| ADJUSTED EBITDAX MARGIN | ||||||||
| Management uses adjusted EBITDAX margin as a measure of profitability between periods and this measure is generally used by analysts for comparative purposes within the industry. Adjusted EBITDAX margin is calculated as adjusted EBITDAX divided by Revenues, excluding non-cash derivative gains and losses. | ||||||||
| Successor | Predecessor | Successor | Predecessor | |||||
| 2nd Quarter | 2nd Quarter | Nine Months | 4th Quarter | |||||
| ($ millions) | 2021 | 2020 | 2021 | 2020 | ||||
| Total revenues | $ | 588 | $ | 409 | $ | 1,255 | $ | 1,258 |
| Non-cash derivative loss | 26 | 2 | 383 | 30 | ||||
| Revenues, excluding non-cash derivative gains and losses | $ | 614 | $ | 411 | $ | 1,638 | $ | 1,288 |
| Adjusted EBITDAX margin | 39 | % | 25 | % | 37 | % | 29 | % |
Page 18
| 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. | ||||||||||
| Successor | Predecessor | Successor | Predecessor | |||||||
| 3rd Quarter | 3rd Quarter | Nine Months | Nine Months | |||||||
| ($ millions) | 2021 | 2020 | 2021 | 2020 | ||||||
| General and administrative expenses | $ | 51 | $ | 64 | $ | 147 | $ | 193 | ||
| Equity settled compensation | (4) | - | (10) | - | ||||||
| Incentive / retention award modification | - | - | - | (4) | ||||||
| Adjusted G&A Expenses | $ | 47 | $ | 64 | $ | - | $ | 137 | $ | 189 |
| 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 PSC-type contracts. | ||||||||||
| Successor | Predecessor | Successor | Predecessor | |||||||
| 3rd Quarter | 3rd Quarter | Nine Months | Nine Months | |||||||
| ($ per BOE) | 2021 | 2020 | 2021 | 2020 | ||||||
|
Energy operating costs (1)
|
$ | 5.49 | $ | 4.25 | $ | 4.97 | $ | 3.81 | ||
| Gas processing costs | 0.56 | 0.46 | 0.59 | 0.54 | ||||||
|
Non-energy operating costs (2)
|
14.23 | 9.81 | 13.48 | 10.50 | ||||||
| Operating costs | $ | 20.28 | $ | 14.52 | $ | 19.04 | $ | 14.85 | ||
| Costs attributable to PSC type contracts | ||||||||||
| Excess energy operating costs attributable to PSC-type contracts | $ | (0.69) | $ | (0.47) | $ | (0.63) | $ | (0.30) | ||
| Excess non-energy operating costs attributable to PSC-type contracts | (1.15) | (0.68) | (1.09) | (0.52) | ||||||
| Excess costs attributable to PSC-type contracts | $ | (1.84) | $ | (1.15) | $ | (1.72) | $ | (0.82) | ||
|
Energy operating costs, excluding effect of PSC-type contracts (1)
|
$ | 4.80 | $ | 3.78 | $ | 4.34 | $ | 3.51 | ||
| Gas processing costs, excluding effect of PSC-type contracts | 0.56 | 0.46 | 0.59 | 0.54 | ||||||
|
Non-energy operating costs, excluding effect of PSC-type contracts (2)
|
13.08 | 9.13 | 12.39 | 9.98 | ||||||
| Operating costs, excluding effects of PSC-type contracts | $ | 18.44 | $ | 13.37 | $ | 17.32 | $ | 14.03 | ||
| (1) Energy operating costs consist of purchases of fuel gas to generate electricity, purchased electricity and internal costs to produce electricity used in our operations. | ||||||||||
| (2) Non-energy operating costs equal total operating costs less energy operating costs and gas processing costs. Purchases of fuel gas to generate steam which is then used in our steamfloods is included in non-energy operating costs. |
Page 19
| Attachment 3 | ||||
| PRODUCTION STATISTICS | ||||
| Successor | Predecessor | Successor | Predecessor | |
| Net | 3rd Quarter | 3rd Quarter | Nine Months | Nine Months |
| Oil, NGLs and Natural Gas Production Per Day | 2021 | 2020 | 2021 | 2020 |
| Oil (MBbl/d) | ||||
| San Joaquin Basin | 40 | 40 | 39 | 42 |
| Los Angeles Basin | 19 | 22 | 19 | 25 |
| Ventura Basin | 3 | 2 | 3 | 3 |
| Total | 62 | 64 | 61 | 70 |
| NGLs (MBbl/d) | ||||
| San Joaquin Basin | 13 | 14 | 13 | 14 |
| Total | 13 | 14 | 13 | 14 |
| Natural Gas (MMcf/d) | ||||
| San Joaquin Basin | 135 | 142 | 135 | 148 |
| Los Angeles Basin | 1 | 2 | 1 | 2 |
| Ventura Basin | 5 | 4 | 5 | 4 |
| Sacramento Basin | 19 | 20 | 19 | 21 |
| Total | 160 | 168 | 160 | 175 |
| Total Production (MBoe/d) | 102 | 106 | 101 | 113 |
| Successor | Predecessor | Successor | Predecessor | |
| Gross Operated and Net Non-Operated | 3rd Quarter | 3rd Quarter | Nine Months | Nine Months |
| Oil, NGLs and Natural Gas Production Per Day | 2021 | 2020 | 2021 | 2020 |
| Oil (MBbl/d) | ||||
| San Joaquin Basin | 45 | 46 | 44 | 49 |
| Los Angeles Basin | 26 | 28 | 27 | 30 |
| Ventura Basin | 3 | 3 | 3 | 3 |
| Total | 74 | 77 | 74 | 82 |
| NGLs (MBbl/d) | ||||
| San Joaquin Basin | 14 | 14 | 13 | 14 |
| Ventura Basin | - | - | 1 | - |
| Total | 14 | 14 | 14 | 14 |
| Natural Gas (MMcf/d) | ||||
| San Joaquin Basin | 144 | 153 | 143 | 157 |
| Los Angeles Basin | 8 | 8 | 8 | 9 |
| Ventura Basin | 5 | 4 | 5 | 5 |
| Sacramento Basin | 23 | 25 | 24 | 27 |
| Total | 180 | 190 | 180 | 198 |
| Total Production (MBoe/d) | 118 | 123 | 118 | 130 |
Note: MBbl/d refers to thousands of barrels per day; MMcf/d refers to millions of cubic feet per day; MBoe/d refers to thousands of barrels of oil equivalent (Boe) per day. Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet of natural gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.
Page 20
| Attachment 4 | ||||||||
| PRICE STATISTICS | ||||||||
| Successor | Predecessor | Successor | Predecessor | |||||
| 3rd Quarter | 3rd Quarter | Nine Months | Nine Months | |||||
| 2021 | 2020 | 2021 | 2020 | |||||
| Oil ($ per Bbl) | ||||||||
| Realized price with derivative settlements | $ | 55.42 | $ | 42.15 | $ | 54.43 | $ | 43.27 |
| Realized price without derivative settlements | $ | 72.89 | $ | 41.83 | $ | 67.62 | $ | 41.27 |
| NGLs ($/Bbl) | $ | 53.74 | $ | 25.16 | $ | 49.20 | $ | 25.17 |
| Natural gas ($/Mcf) | $ | 4.66 | $ | 2.22 | $ | 3.67 | $ | 2.05 |
| Index Prices | ||||||||
| Brent oil ($/Bbl) | $ | 73.23 | $ | 43.37 | $ | 67.78 | $ | 42.53 |
| WTI oil ($/Bbl) | $ | 70.56 | $ | 40.93 | $ | 64.82 | $ | 38.32 |
| NYMEX gas ($/MMBtu) | $ | 3.71 | $ | 1.93 | $ | 3.06 | $ | 1.92 |
| Realized Prices as Percentage of Index Prices | ||||||||
| Oil with derivative settlements as a percentage of Brent | 76 | % | 97 | % | 80 | % | 102 | % |
| Oil without derivative settlements as a percentage of Brent | 100 | % | 96 | % | 100 | % | 97 | % |
| Oil with derivative settlements as a percentage of WTI | 79 | % | 103 | % | 84 | % | 113 | % |
| Oil without derivative settlements as a percentage of WTI | 103 | % | 102 | % | 104 | % | 108 | % |
| NGLs as a percentage of Brent | 73 | % | 58 | % | 73 | % | 59 | % |
| NGLs as a percentage of WTI | 76 | % | 61 | % | 76 | % | 66 | % |
| Natural gas as a percentage of NYMEX | 126 | % | 115 | % | 120 | % | 107 | % |
Page 21
| Attachment 5 | |||||
| THREE MONTHS 2021 DRILLING ACTIVITY | |||||
| San Joaquin | Los Angeles | Ventura | Sacramento | ||
| Wells Drilled | Basin | Basin | Basin | Basin | Total |
| Development Wells | |||||
| Primary | 2 | - | - | - | 2 |
| Waterflood | 12 | 1 | - | - | 13 |
| Steamflood | 12 | - | - | - | 12 |
|
Total (1)
|
26 | 1 | - | - | 27 |
| NINE MONTHS 2021 DRILLING ACTIVITY | |||||
| San Joaquin | Los Angeles | Ventura | Sacramento | ||
| Wells Drilled | Basin | Basin | Basin | Basin | Total |
| Development Wells | |||||
| Primary | 2 | - | - | - | 2 |
| Waterflood | 49 | 1 | - | - | 50 |
| Steamflood | 13 | - | - | - | 13 |
|
Total (1)
|
64 | 1 | - | - | 65 |
|
(1) Includes steam injectors and drilled but uncompleted wells, which are not included in the SEC definition of wells drilled.
|
Page 22
| Attachment 6 | ||||||
| OIL HEDGES AS OF SEPTEMBER 30, 2021 | ||||||
| Q4 2021 | Q1 2022 | Q2 2022 | Q3 2022 | Q4 2022 | FY 2023 | |
| Sold Calls: | ||||||
| Barrels per day | 37,037 | 35,347 | 35,343 | 34,380 | 25,167 | 14,790 |
| Weighted-average Brent price per barrel | $60.75 | $60.37 | $60.63 | $60.76 | $57.82 | $58.01 |
| Purchased Puts: | ||||||
| Barrels per day | 35,820 | 56,814 | 57,850 | 57,855 | 43,121 | 14,790 |
| Weighted-average Brent price per barrel | $40.19 | $48.29 | $48.98 | $49.48 | $50.05 | $40.00 |
| Sold Puts: | ||||||
| Barrels per day | 14,193 | 28,336 | 22,507 | 27,475 | 19,302 | - |
| Weighted-average Brent price per barrel | $32.00 | $38.00 | $40.00 | $38.84 | $39.44 | - |
| Swaps: | ||||||
| Barrels per day | 13,922 | 12,369 | 10,669 | 10,476 | 17,263 | 10,101 |
| Weighted-average Brent price per barrel | $54.86 | $54.38 | $54.12 | $53.97 | $58.79 | $55.69 |
Page 23
| Attachment 7 | ||
| 2021E TOTAL YEAR GUIDANCE | Prior | Revised |
| Total Year 2021E | Total Year 2021E | |
| Net Total Production (Mboe/d) | 97 - 100 | 99 - 101 |
| Net Oil Production (Mbbl/d) | 60 - 62 | 60 - 62 |
| Operating Costs ($ millions) | $670 - $695 | $700 - $720 |
| General and administrative expenses ($ millions) | $180 - $190 | $190 - $200 |
| Capital ($ millions) | $170 - $190 | $180 - $200 |
| Adjusted EBITDAX ($ millions) | $725 - $825 | $840 - $900 |
| Free cash flow ($ millions) | $400 - $500 | $460 - $510 |
See Attachment 2 for management's disclosure of its use of these non-GAAP measures and how these measures provide useful information to investors about CRC's results of operations and financial condition. For FY 2021E guidance, management is not providing guidance on income taxes or any unusual or infrequent events at this time.
| FY 2021 Estimated | ||||
| ($ millions) | Low | High | ||
| Net cash provided by operating activities | $ | 660 | $ | 690 |
| Capital investments | (200) | (180) | ||
| Estimated free cash flow | $ | 460 | $ | 510 |
| FY 2021 Estimated | ||||
| ($ millions) | Low | High | ||
| Net income | $ | 180 | $ | 200 |
| Interest and debt expense, net | 50 | 55 | ||
| Depreciation, depletion and amortization | 210 | 220 | ||
| Exploration expense | 5 | 10 | ||
| Unusual, infrequent and other items | 330 | 340 | ||
| Other non-cash items | ||||
| Accretion expense | 50 | 55 | ||
| Stock-settled compensation | 10 | 15 | ||
| Post-retirement medical and pension | 5 | 5 | ||
| Estimated adjusted EBITDAX | $ | 840 | $ | 900 |
| Net cash provided by operating activities | $ | 660 | $ | 690 |
| Cash interest | 30 | 35 | ||
| Exploration expenditures | 5 | 10 | ||
| Working capital changes | 145 | 165 | ||
| Estimated adjusted EBITDAX | $ | 840 | $ | 900 |
Page 24