California Resources Corporation Reports Third Quarter 2021 Results, Declares Inaugural Quarterly Dividend and Announces 2045 Full-Scope Net Zero Goal

SANTA CLARITA, Calif.--(BUSINESS WIRE)--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.

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

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 - $720
General and administrative expenses^3 ($ millions)	$180 - $190	$190 - $200
Capital ($ millions)	$170 - $190	$180 - $200
Adj. EBITDAX^1 ($ millions)	$725 - $825	$840 - $900
Free cash flow^1 ($ millions)	$400 - $500	$460 - $510

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, 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 EBITDAX^1	$	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

	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 EBITDAX^1	$	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 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.

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 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 [phone] (International calls please dial [phone]) 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

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
• 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.

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				%

	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

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

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

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	)

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.

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		%

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.

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.

										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		%

					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.

											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

		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