California Resources Corporation Announces the Formation of a California Carbon Management Partnership with Brookfield Renewable, Reports Strong Second Quarter 2022 Results and Increases Full Year 2022 Free Cash Flow1 Guidance

California Resources Corporation (NYSE: CRC), an independent oil and natural gas company committed to energy transition in the sector, today announced the formation of a joint venture (the "JV") with Brookfield Renewable ("Brookfield"), creating a carbon management partnership focused on carbon capture and sequestration (“CCS”) development and reported second quarter 2022 operational and financial results.

Brookfield has committed an initial $500 million to invest in CCS projects that are jointly approved through the JV. The investment from Brookfield will be allocated through the Brookfield Global Transition Fund (“BGTF”), the world’s largest fund dedicated to facilitating the global transition to a net zero carbon economy. Brookfield, together with its institutional partners, will participate in the joint venture through BGTF. The first CCS project designated for development is CRC’s 26R reservoir in the Elk Hills Field which was contributed to the partnership at a value of $10 per metric ton, which will be paid in three installments with the last two installments subject to achievement of specific milestones. The initial Brookfield commitment provides CRC with additional capital to advance the Company's carbon management strategy, de-risks its CCS projects and aims to significantly progress the decarbonization of California. The JV is targeting the injection of 5 million metric tons per annum and 200 million metric tons of total carbon dioxide ("CO₂") storage development, aligned with CRC’s 2027 goals. Reaching this target would require an estimated $2.5 billion of total capital, and Brookfield could make additional investments of more than $1 billion in the strategic partnership assuming it fully participates in these CCS projects.

The strategic partnership will benefit substantially from CRC’s first mover advantage in gaining access to available storage assets in the state of California and Brookfield’s knowledge in global clean energy markets. California is a world-leading location for the development of CCS projects, driven by the state’s Low Carbon Fuel Standard and Cap-and-Trade programs, together with the federal 45Q tax credit of $50 per ton of CO₂ captured and permanently stored. CRC is currently progressing CO₂ storage project permit applications and represents four out of the five Class VI well project applications active in California.

"We are pleased to partner with Brookfield to develop industry leading CCS projects that support California's energy transition," said Mac McFarland, CRC’s President and Chief Executive Officer. "The Brookfield partnership aligns our carbon management strategy with a strong investment partner, bringing significant operational and development expertise to reinforce our efforts. Brookfield's capital commitment also accelerates our carbon management opportunities. It also enables CRC to maintain capital discipline and financial flexibility to achieve our corporate objectives including achieving our Full-Scope Net Zero 2045 goal."

“Transitioning our economy to net zero is a critical global challenge and that means rapidly scaling our available decarbonization technologies," said Connor Teskey, CEO of Brookfield Renewable. "Brookfield Renewable has been a leader in delivering clean energy for three decades and now we see significant potential in the rollout of carbon capture and sequestration technology. Partnering with CRC presents a great opportunity to continue the growth of our CCS business and expand the scope of decarbonization solutions we provide to our customers."

California Carbon Management Partnership Highlights

• CRC and Brookfield will jointly develop CCS projects in California through created JVs. The JVs will be owned 51% by CRC and 49% by BGTF

• The California Carbon Management Partnership with Brookfield is an important step in CRC’s Full-Scope Net Zero 2045 Goal and Carbon Management Strategy. It highlights the value of CRC's expansive CO₂ pore space portfolio while demonstrating the Company’s commitment to capital discipline and retaining flexibility for strategic corporate objectives including shareholder returns and investing in the business

• Strengthens CRC’s competitive position in CCS deployment with Brookfield’s infrastructure investment experience, operating knowledge, and capital allocation. CRC and Brookfield are targeting the injection of 5 million metric tons of CO₂ per annum over the first five years of the strategic partnership

• CRC is committing $2.5 million over the next three years to the Kern Community College District (Kern CCD) and California State University Bakersfield (CSUB) to promote innovation and implementation of energy transition in California

Second Quarter Operational and Financial Results

"During the second quarter of 2022, CRC continued to deliver strong operational results and shareholder returns," said Mac McFarland. "We expect to maintain our 2022 entry to exit net total production after taking into account asset divestitures. We are raising our full year EBITDAX¹ and free cash flow guidance¹ despite cost inflation and other macro pressures. With respect to our shareholder return strategy, CRC returned approximately 134% of its total generated free cash flow¹ back to its shareholders in the form of dividends and share repurchases. The combination of our strong financial results coupled with ongoing capital investment and shareholder return strategies demonstrate our balanced commitment to our stakeholders."

McFarland continued, "Given prevailing market conditions, we are raising our adjusted EBITDAX¹ and free cash flow¹ guidance, and expect to continue our robust shareholder returns despite inflationary cost pressures. Further, the strategic partnership with Brookfield advances our carbon management energy transition efforts and provides increased capital flexibility with which we expect to pursue our overall corporate objectives and deliver on our financial goals and sustainability targets."

Primary Highlights

• Raising full year 2022 adjusted EBITDAX¹ and free cash flow¹ guidance and reaffirming full year 2022 total production guidance of 91 to 94 thousand barrels of oil equivalent per day
• Investing approximately $13 million in natural gas assets located in the Sacramento Basin and the Buena Vista field to focus on quick and high impact workover opportunities
• In July 2022, CRC's fifth drilling rig began operations at the Wilmington Field
• Repurchased 2,255,445 common shares for $96 million during the second quarter of 2022; repurchased an aggregate 9,136,836 shares for $360 million since the inception of the Share Repurchase Program through July 31, 2022 for an average price of $39.34 per share
• Returned $193 million in total shareholder returns to investors throughout the first half of 2022, 34% more than the total free cash flow¹ generated during the same period
• Declared a quarterly dividend of $0.17 per share of common stock, totaling $13 million payable on September 16, 2022 to shareholders of record on September 1, 2022, with subsequent quarterly dividends subject to final determination and Board approval

Financial

• Reported net income of $190 million, or $2.41 per fully diluted share. When adjusted for items analysts typically exclude from estimates including mark-to-market adjustments and gains on asset divestitures, the Company’s adjusted net income¹ was $89 million, or $1.13 per fully diluted share
• Generated net cash provided by operating activities of $181 million, adjusted EBITDAX¹ of $204 million and free cash flow¹ of $83 million
• Ended the quarter with $324 million of cash on hand, an undrawn credit facility and $740 million of liquidity²

Operations

• Produced an average of 91,000 net barrels of oil equivalent per day (Boe/d), including 54,000 barrels of oil per day (Bo/d), with capital expenditures of $98 million during the quarter
• Operated three drilling rigs in the San Joaquin Basin and one drilling rig in the Los Angeles Basin; drilled 46 wells (42 online in 2Q22)
• Operated 33 maintenance rigs

Joint Venture Overview

The carbon management partnership will involve developing both infrastructure and storage assets required for CCS projects in California through newly created joint venture entities, Carbon TerraVault JV HoldCo, LLC ("HoldCo"), Carbon TerraVault JV Storage Company (“StorageCo”) and Carbon TerraVault JV Infrastructure Company, LLC (“InfraCo”).

StorageCo will build, install, operate, and maintain CO₂ storage facilities. CRC has contributed the storage rights in the 26R storage reservoir in the Elk Hills field to StorageCo. Brookfield has acquired an indirect 49% interest in StorageCo at an implied value of $10 per metric ton of permitted capacity, payable in three installments for a total consideration of $137 million. The first installment of $45.7 million was funded at close. The second and third installments are due upon completion of certain pre-agreed milestones related to the permitting process with the EPA and final investment decision. Future storage projects for Brookfield's initial commitment will be contributed on the same terms and milestones.

InfraCo will build, install, operate, maintain CO₂ capture equipment and transportation assets, and provide funding as projects develop. StorageCo and InfraCo are wholly owned by HoldCo.

2022 Production Guidance and Capital Program Update³

CRC's capital program is dynamic in response to oil market volatility and focused on maintaining oil production and strong liquidity and maximizing free cash flow. CRC is increasing its 2022 total capital program to a range of $380 to $410 million from $340 million to $385 million. CRC increased its 2022 capital program for inflation and these cost increases could also impact its capital program in 2023 and beyond. Additionally, in response to the continued strong commodity environment, CRC is adding to its workover program for natural gas assets located in the Sacramento Basin and the Buena Vista field. Finally, CRC has increased its capital program for its carbon management activities.

This level of expected spending is consistent with CRC's strategy of investing up to 50% of its operating cash flow back into CRC's oil and gas operations. Following the joint venture with Brookfield, CRC anticipates that a portion of the operating cash flow previously designated for advancing decarbonization and other emission reducing projects will now be available for other corporate purposes, such as shareholder returns and other strategic opportunities (see a summary of our Business Strategy in Part I, Item 1 & 2 – Business and Properties in CRC's 2021 Annual Report).

The delay in the Kern County EIR litigation (see Part I, Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Regulatory Update in the Form 10-Q for the quarter ended June 30, 2022 for additional details on Kern County EIR) led to a change in CRC's drilling program which favors a higher natural gas to oil ratio. Therefore, CRC's 2022 oil production guidance is expected to be negatively impacted by approximately 1,000 Bo/d from this change as well as for 1,200 Boe/d for PSC. CRC's 2022 total production guidance remains consistent with previous expectations in the range of 91 to 94 MBoe/d.

With this capital program, and when adjusted for asset divestitures, production-sharing contracts (PSC) effects and the previously discussed Kern County EIR driven change in well mix, CRC expects to modestly grow oil production from entry to exit and is maintaining its total net production guidance. During the second half of 2022, CRC plans to run five drilling rigs in the Elk Hills, Buena Vista and Wilmington fields. In July 2022, CRC's fifth drilling rig began operations at the Wilmington Field.

In addition, CRC is raising its free cash flow¹ and adjusted EBITDAX¹ guidance by 10% and 2% at the midpoint, respectively, to $365 to $450 million and $895 to $960 million.

CRC is also raising its operating cost guidance to $725 to $755 million from $680 to $720 million due to inflation, change in well mix and higher natural gas and electricity prices.

Adjusted G&A guidance increased by $15 million to $185 to $200 million due primarily to wage and cost inflation as well as increased headcount as we develop our carbon management business.

TOTAL CRC GUIDANCE3		2022E		CMB 2022E		E&P, Corp. & Other 2022E
Net Total Production (MBoe/d)		94 - 91				94 - 91
Net Oil Production (MBbl/d)		58 - 53				58 - 53
Operating Costs ($ millions)		$725 - $755				$725 - $755
CMB Expenses4 ($ millions)		$20 - $30		$20 - $30
Adjusted General and Administrative Expenses1 ($ millions)		$185 - $200		$10 - $15		$175 - $185
Total Capital ($ millions)		$380 - $410		$20 - $30		$360 - $380
Drilling & Completions		$260 - $265				$260 - $265
Workovers		$40 - $45				$40 - $45
Facilities		$55 - $60				$55 - $60
Corporate & Other		$5 - $10				$5 - $10
CMB		$20 - $30		$20 - $30
Adjusted EBITDAX1 ($ millions)		$895 - $960		($30) - ($45)		$940 - $990
Free Cash Flow1 ($ millions)		$365 - $450		($50) - ($75)		$440 - $500

Supporting Local Communities and Investing in the Energy Transition in California

Aligning with the strategic partnership, CRC will donate $2.5 million over the next three years to Kern Community College District (Kern CCD) and California State University Bakersfield (CSUB) to promote innovation and deployment of energy transition in California. This donation is expected to accelerate R&D efforts in decarbonization technologies in local academic research institutions located where CRC operates. CRC is dedicated to reducing emissions in California and is aligned with the state’s ambitious climate goals. As part of this pledge, CRC is also forming the CRC Carbon Management Institute at Kern CCD and is starting the CRC Energy Transition Lecture Series at CSUB.

Supply Chain and Cost Inflation

Operating and capital costs in the oil and natural gas industry are heavily influenced by commodity price environments which are cyclical in nature. Typically, suppliers will negotiate increases for drilling and completion, oilfield services, equipment and materials as prices for energy-related commodities and raw materials (such as steel, metals and chemicals) increase. Recent worldwide and U.S. supply chain issues, together with rising commodity prices and tight labor markets in the U.S., have created cost inflation during 2022 which may continue in future periods. CRC has taken proactive measures to limit the effects of the inflationary market by entering into contracts for materials and services with terms of one to three years. CRC has also taken steps to build its on-hand supply stock for items frequently used in its operations to address possible supply chain disruptions. Despite these efforts, CRC has experienced increased costs thus far in 2022 and CRC anticipates potential additional increases in the cost of goods and services and wages in its operations during the remainder of 2022. These increases have been factored into CRC's operating and capital costs guidance and could also negatively impact its results of operations and cash flows in 2023 and beyond.

Second Quarter 2022 E&P Operational Results

In November 2020, the SEC amended Regulation S-K to, among other things, provide companies with the option to discuss material changes to results of operations between the current and immediately preceding quarter. CRC has elected to discuss its results of operations on a sequential-quarter basis. CRC believes this approach provides more meaningful and useful information to measure its performance from the immediately preceding quarter. In accordance with this final rule, CRC is not required to include a comparison of the current quarter and the same prior-year quarter.

Total daily net production for the three months ended June 30, 2022, compared to the three months ended March 31, 2022 increased by approximately 3 MBoe/d, or 3%. This increase includes approximately 5 MBoe/d resulting from the return of production at one of CRC's cryogenic gas processing facilities, which had planned maintenance during the first quarter of 2022. These increases were partially offset by decreases resulting from natural decline, and the divestiture of CRC's remaining 50% working interest in certain zones in the Lost Hills field in February 2022. CRC's PSCs negatively impacted its net oil production in the three months ended June 30, 2022 by approximately 1 MBoe/d, compared to the three months ended March 31, 2022. The previously mentioned delays in the Kern County EIR litigation also negatively affected CRC's net oil production by 200 Bo/d for the three months ended June 30, 2022 due to the change in well mix.

During the second quarter of 2022, CRC operated an average of three drilling rigs in the San Joaquin Basin and one drilling rig in the Los Angeles Basin. During the quarter, CRC drilled 46 net wells and brought online 42 wells. See Attachment 3 for further information on CRC's production results by basin and Attachment 5 for further information on CRC's drilling activity.

Second Quarter 2022 Financial Results

	2nd Quarter				1st Quarter
($ and shares in millions, except per share amounts)	2022					2022
Statements of Operations:
Revenues
Total operating revenues	$	747			$	153
Operating Expenses
Total operating expenses		473				396
Gain on asset divestitures		4				54
Operating Income (Loss)	$	278			$	(189	)
Net Income (Loss) Attributable to Common Stock	$	190			$	(175	)
Net income (loss) per share - basic	$	2.48			$	(2.23	)
Net income (loss) per share - diluted	$	2.41			$	(2.23	)
Adjusted net income1	$	89			$	91
Adjusted net income1 per share - diluted	$	1.13			$	1.13
Weighted-average common shares outstanding - basic		76.7				78.5
Weighted-average common shares outstanding - diluted		78.8				78.5
Adjusted EBITDAX1	$	204			$	206

		2nd Quarter				1st Quarter
($ in millions)		2022					2022
Cash Flow Data:
Net cash provided by operating activities	$	181				$	160
Net cash used in investing activities	$	(76	)			$	(53	)
Net cash used in financing activities	$	(109	)			$	(84	)

Review of Second Quarter 2022 Financial Results

Realized oil prices, excluding the effects of cash settlements on CRC's commodity derivative contracts, increased by $16.19 per barrel from $96.13 per barrel in the first quarter of 2022 to $112.32 per barrel in the second quarter of 2022. Realized oil prices were higher in the second quarter of 2022 compared to the first quarter of 2022 as the effects of the COVID-19 pandemic have subsided leaving crude oil production and product inventories at historically low levels. As demand has rebounded, producers have generally maintained capital discipline, OPEC+ members have failed to produce at stepped-up quotas, and the conflict between Russia and Ukraine has created a disconnect between buyers and sellers of Russian produced crude oil.

Realized oil prices, including the effects of cash settlements on CRC's commodity derivative contracts, increased by $2.87 from $60.30 in the first quarter of 2022 to $63.17 in the second quarter of 2022. The increase is due to a higher commodity price environment in the second quarter of 2022 compared to the first quarter of 2022. See Attachment 4 for further information on prices.

Adjusted EBITDAX¹ for the second quarter of 2022 was $204 million. See table below for the Company's net cash provided by operating activities, capital investments and free cash flow¹ during the same periods.

FREE CASH FLOW1
Management uses free cash flow, which is defined by us as net cash provided by operating activities less capital investments, as a measure of liquidity. The following table presents a reconciliation of our net cash provided by operating activities to free cash flow. We supplemented our non-GAAP measure of free cash flow with free cash flow of our exploration and production and corporate items (Free Cash Flow for E&P, Corporate & Other) which we believe is a useful measure for investors to understand the results of our core oil and gas business. We define Free Cash Flow for E&P, Corporate & Other as consolidated free cash flow less results attributable to our carbon management business.
							2nd Quarter					1st Quarter
($ millions)								2022					2022
Net cash provided by operating activities							$	181				$	160
Capital investments								(98	)				(99	)
Free cash flow1							$	83				$	61
E&P, corporate & other free cash flow1							$	98				$	64
CMB free cash flow1							$	(15	)			$	(3	)

The following table presents key operating data for CRC's oil and gas operations, on a per BOE basis, for the periods presented below. Energy operating costs consist of 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 and gas processing costs. However, non-energy operating costs include the costs of purchasing natural gas from third parties that is used to generate steam for CRC's steamflood operations.

OPERATING COSTS PER BOE
The reporting of our PSCs creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs. The following table presents operating costs after adjusting for the excess costs attributable to PSCs.
							2nd Quarter					1st Quarter
($ per Boe)								2022					2022
Energy operating costs							$	6.88					6.68
Gas processing costs								0.54					0.56
Non-energy operating costs								15.50					15.63
Operating costs							$	22.92				$	22.87
Excess costs attributable to PSCs								(2.58	)				(2.30	)
Operating costs, excluding effects of PSCs (a)							$	20.34				$	20.57
(a) Operating costs, excluding effects of PSCs is a non-GAAP measure.

Energy operating costs for the second quarter of 2022 were $57 million, or $6.88 per Boe, which was an increase of $4 million or 8% from $53 million, or $6.68 per Boe, for the first quarter of 2022. These increases were primarily a result of higher prices for purchased natural gas, which CRC used to generate electricity for its operations, and for purchased electricity. Energy operating costs were also higher on a per Boe basis as a result of lower production volumes between periods.

Non-energy operating costs for the second quarter of 2022 were $129 million, or 15.50 per Boe, which was an increase of $5 million or 4% from $124 million, or $15.63 per Boe, for the first quarter of 2022. This increase was primarily a result of higher compensation-related expenses and increased downhole maintenance activity.

Balance Sheet and Liquidity Update

CRC's aggregate commitment under the Revolving Credit Facility was $552 million as of June 30, 2022. The borrowing base for the Revolving Credit Facility is redetermined semi-annually and was reaffirmed at $1.2 billion on April 29, 2022.

As of June 30, 2022, CRC had liquidity of $740 million, which consisted of $324 million in cash and $416 million of available borrowing capacity under its Revolving Credit Facility.

Acquisitions and Divestitures

During the three months ended June 30, 2022, CRC recorded a gain of $4 million related to the sale of certain Ventura basin assets. The amount recognized in the three months ended June 30, 2022 of $4 million related to additional earn-out consideration on closings that occurred in the second half of 2021 and the first half of 2022. In addition, CRC received $2 million to secure the performance of abandonment obligations which CRC expects to reimburse to the buyer once the abandonment obligations are met. As a result, CRC recorded a liability of $2 million as of June 30, 2022, and CRC did not recognize gain on asset divestitures for this portion of the transaction. CRC expects to divest of its remaining assets in the Ventura basin during the second half of 2022, pending final approval from the State Lands Commission.

In June 2022, CRC sold its commercial office building located in Bakersfield, California for net proceeds of $13 million. In May 2022, CRC recorded a $2 million impairment charge to write down the carrying value of the building to its fair value.

Shareholder Returns Strategy

CRC continues to prioritize shareholder returns and dedicate a portion of its operating cash flow to shareholders. In light of this strategy, CRC's Board of Directors has authorized a Share Repurchase Program of $650 million, of which $290 million remains available for future repurchases.

During the second quarter of 2022, CRC repurchased 2.3 million shares of its common stock for $96 million. During the first half of 2022, CRC repurchased approximately 3.9 million shares of its common stock for $167 million. Since the inception of Share Repurchase Program through July 31, 2022, CRC has repurchased 9.1 million shares for $360 million at an average price of $39.34 per share, resulting in the repurchase of approximately 11% of the shares that CRC had at its emergence from bankruptcy.

On August 3, 2022, CRC's Board of Directors declared a quarterly cash dividend of $0.17 per share of common stock. The dividend is payable to shareholders of record on September 1, 2022, and will be paid on September 16, 2022.

Upcoming Investor Conference Participation

CRC's executives will be participating in the following in-person events in September 2022:

• Barclays CEO Energy Power Conference on September 6 - 8, 2022, in New York, NY
• Pickering Energy Partners TE&MFest Conference on September 15 -16, 2022, in Austin, TX
• Credit Suisse 8th Annual Houston Oil & Gas Conference on September 20 - 21, 2022, in Houston, TX

CRC’s presentation materials will be available the day of the events on the Events and Presentations page in the Investor Relations section on www.crc.com.

Advisors

Guggenheim Securities, LLC acted as financial advisor, and Sullivan & Cromwell LLP and Vinson & Elkins LLP acted as legal advisors for California Resources Corporation on the California Carbon Management Partnership with Brookfield Renewable deal.

Conference Call Details

To participate in the conference call scheduled for August 4, 2022, at 12:00 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 to https://dpregister.com/sreg/10167707/f307b93bd1. A digital replay of the conference call will be archived for approximately 90 days and supplemental slides for the conference call will be available online in the Investor Relations section of www.crc.com.

¹ See Attachment 2 for the non-GAAP financial measures of adjusted EBITDAX, operating costs per BOE (excluding effects of PSCs), adjusted net income (loss), adjusted net income (loss) per share - basic and diluted), free cash flow and free cash flow, after special items including reconciliations to their most directly comparable GAAP measure, where applicable. For the full year 2022 estimates of the non-GAAP measures of adjusted EBITDAX and free cash flow, including reconciliations to their most directly comparable GAAP measure, see Attachment 7.
² Calculated as $324 million of cash plus $552 million of capacity on CRC's Revolving Credit Facility less $136 million in outstanding letters of credit.
³ 2022 guidance assumes a 2022 Brent price of $103.42 per barrel of oil, NGL realizations consistent with prior years and a NYMEX gas price of $5.62 per mcf. CRC's share of production under PSC contracts decreases when commodity prices rise and increases when prices fall.
⁴ CMB Expenses include start-up expenditures.

About California Resources Corporation

California Resources Corporation (CRC) is an independent oil and natural gas company committed to energy transition in the sector. CRC has some of the lowest carbon intensity production in the US and we are focused on maximizing the value of our land, mineral and technical resources for decarbonization by developing CCS and other emissions reducing projects. For more information about CRC, please visit www.crc.com. Nothing herein is intended to imply or create a legal partnership between Brookfield Global Transition Fund, California Resources Corporation, HoldCo or any of their respective subsidiaries and affiliates.

About Brookfield Renewable

Brookfield Renewable operates one of the world’s largest publicly traded, pure-play renewable power platforms. Its portfolio consists of hydroelectric, wind, solar and storage facilities in North America, South America, Europe and Asia, and totals approximately 21,000MW of installed capacity and an approximately 69,000MW development pipeline. Investors can access its portfolio either through Brookfield Renewable Partners L.P. (NYSE: BEP; TSX: BEP.UN), or Brookfield Renewable Corporation (NYSE, TSX: BEPC), a Canadian corporation. Brookfield Renewable is the flagship listed renewable power company of Brookfield Asset Management, a leading global alternative asset manager with approximately $725 billion of assets under management.

The Brookfield Global Transition Fund, co-led by Mark Carney, Brookfield Vice Chair and Head of Transition Investing, and Connor Teskey, CEO of Brookfield Renewable, is Brookfield’s inaugural impact fund focusing on investments that accelerate the global transition to a net-zero carbon economy, while delivering strong risk-adjusted returns to investors.

The Fund targets investment opportunities relating to reducing greenhouse gas emissions and energy consumption, as well as increasing low-carbon energy capacity and supporting sustainable solutions. Consistent with its dual objectives of earning strong risk-adjusted returns and generating a measurable positive environmental change, the Fund will report to investors on both its financial and environmental impact performance.

Forward-Looking Statements

This document contains statements that we believe to be “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than historical facts are forward-looking statements, and include statements regarding CRC's future financial position, business strategy, projected revenues, earnings, costs, capital expenditures and plans and objectives of management for the future. Words such as "expect," “could,” “may,” "anticipate," "intend," "plan," “ability,” "believe," "seek," "see," "will," "would," “estimate,” “forecast,” "target," “guidance,” “outlook,” “opportunity” or “strategy” or similar expressions are generally intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements.

Although we believe the expectations and forecasts reflected in CRC's forward-looking statements are reasonable, they are inherently subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond CRC's control. No assurance can be given that such forward-looking statements will be correct or achieved or that the assumptions are accurate or will not change over time. Particular uncertainties that could cause our actual results to be materially different than those expressed in CRC's forward-looking statements include:

• fluctuations in commodity prices and the potential for sustained low oil, natural gas and natural gas liquids prices;
• equipment, service or labor price inflation or unavailability;
• legislative or regulatory changes, including those related to (i) 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 or other incentives, or (v) transportation, marketing and sale of our products;
• availability or timing of, or conditions imposed on, permits and approvals necessary for drilling or development activities and carbon management projects;
• changes in business strategy and CRC's capital plan;
• lower-than-expected production, reserves or resources from development projects or acquisitions, or higher-than-expected decline rates;
• incorrect estimates of reserves and related future cash flows and the inability to replace reserves;
• the recoverability of resources and unexpected geologic conditions;
• CRC’s ability to utilize storage capacity of the 26R storage reservoir consistent with the Joint Venture and Investment Agreement through either storage only contracts or as part of an integrated project;
• CRC’s ability to identify and develop projects that are acceptable to the JV;
• CRC’s ability to successfully execute on the construction and other aspects of the infrastructure projects and enter into third party contracts on contemplated terms;
• CRC’s ability to realize all benefits contemplated by the strategic partnership and business strategies and initiatives related to energy transition, including CCS projects and other renewable energy efforts;
• CRC's ability to finance and implement its CCS projects, including the development of projects contemplated as part of the strategic partnership with Brookfield;
• global geopolitical, socio-demographic and economic trends and technological innovations;
• changes in our dividend policy and our ability to declare future dividends;
• production-sharing contracts' effects on production and operating costs;
• limitations on CRC's financial flexibility due to existing and future debt;
• insufficient cash flow to fund planned investments, interest payments on our debt, stock repurchases or changes to CRC's capital plan;
• insufficient capital or liquidity 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;
• joint ventures and acquisitions and CRC's ability to achieve expected synergies;
• CRC's ability to utilize its net operating loss carryforwards to reduce its income tax obligations;
• CRC's ability to successfully gather and verify data regarding emissions, its environmental impacts and other initiatives;
• the compliance of various third parties with CRC's policies and procedures and legal requirements as well as contracts CRC enters into in connection with its climate-related initiatives;
• the effect of CRC's stock price on costs associated with incentive compensation;
• changes in the intensity of competition in the oil and gas industry;
• effects of hedging transactions;
• climate-related conditions and weather events;
• disruptions due to accidents, mechanical failures, power outages, transportation or storage constraints, natural disasters, labor difficulties, cyber-attacks or other catastrophic events;
• pandemics, epidemics, outbreaks, or other public health events, such as the COVID-19; and
• other factors discussed in Part I, Item 1A – Risk Factors in CRC's Annual Report on Form 10-K and its other SEC filings available at www.crc.com.

CRC cautions you not to place undue reliance on forward-looking statements contained in this document, which speak only as of the filing date, and CRC undertakes no obligation to update this information. This document may also contain information from third party sources. This data may involve a number of assumptions and limitations, and we have not independently verified them and do not warrant the accuracy or completeness of such third-party information.

Attachment 1
SUMMARY OF RESULTS
	2nd Quarter				1st Quarter				2nd Quarter					Six Months				Six Months
($ and shares in millions, except per share amounts)		2022				2022				2021					2022				2021
Statements of Operations:
Revenues
Oil, natural gas and NGL sales	$	718			$	628			$	478				$	1,346			$	910
Net loss from commodity derivatives		(100	)			(562	)			(265	)				(662	)			(478	)
Sales of purchased natural gas		75				32				48					107				146
Electricity sales		49				34				33					83				66
Other revenue		5				21				10					26				23
Total operating revenues		747				153				304					900				667
Operating Expenses
Operating costs		190				182				169					372				333
General and administrative expenses		56				48				48					104				96
Depreciation, depletion and amortization		50				49				54					99				106
Asset impairments		2				—				—					2				3
Taxes other than on income		42				34				37					76				77
Exploration expense		1				1				2					2				4
Purchased natural gas expense		67				21				30					88				91
Electricity generation expenses		33				24				17					57				41
Transportation costs		12				12				14					24				26
Accretion expense		11				11				13					22				26
Other operating expenses, net		9				14				10					23				27
Total operating expenses		473				396				394					869				830
Net gain on asset divestitures		4				54				—					58				—
Operating Income (Loss)		278				(189	)			(90	)				89				(163	)
Non-Operating (Expenses) Income
Reorganization items, net		—				—				(2	)				—				(4	)
Interest and debt expense, net		(13	)			(13	)			(13	)				(26	)			(26	)
Net loss on early extinguishment of debt		—				—				—					—				(2	)
Other non-operating expenses, net		1				1				(2	)				2				(1	)
Net Income (Loss) Before Income Taxes		266				(201	)			(107	)				65				(196	)
Income tax (provision) benefit		(76	)			26				—					(50	)			—
Net income (loss)		190				(175	)			(107	)				15				(196	)
Net income attributable to noncontrolling interests		—				—				(4	)				—				(9	)
Net Income (Loss) Attributable to Common Stock	$	190			$	(175	)		$	(111	)			$	15			$	(205	)
Net income (loss) attributable to common stock per share - basic	$	2.48			$	(2.23	)		$	(1.34	)			$	0.19			$	(2.46	)
Net income (loss) attributable to common stock per share - diluted	$	2.41			$	(2.23	)		$	(1.34	)			$	0.19			$	(2.46	)
Adjusted net income	$	89			$	91			$	78				$	180			$	180
Adjusted net income per share - basic	$	1.16			$	1.16			$	0.94				$	2.32			$	2.16
Adjusted net income per share - diluted	$	1.13			$	1.13			$	0.94				$	2.26			$	2.15
Weighted-average common shares outstanding - basic		76.7				78.5				83.1					77.6				83.2
Weighted-average common shares outstanding - diluted		78.8				78.5				83.1					79.6				83.2
Adjusted EBITDAX	$	204			$	206			$	169				$	410			$	358
Effective tax rate		29	%			13	%			0	%				78	%			0	%

	2nd Quarter				1st Quarter				2nd Quarter				Six Months				Six Months
($ in millions)		2022				2022				2021				2022				2021
Cash Flow Data:
Net cash provided by operating activities	$	181			$	160			$	127			$	341			$	274
Net cash used in investing activities	$	(76	)		$	(53	)		$	(43	)		$	(129	)		$	(63	)
Net cash used by financing activities	$	(109	)		$	(84	)		$	(63	)		$	(193	)		$	(88	)

	June 30,			December 31,
($ and shares in millions)		2022			2021
Selected Balance Sheet Data:
Total current assets	$	851		$	753
Property, plant and equipment, net	$	2,675		$	2,599
Deferred tax asset	$	367		$	396
Total current liabilities	$	1,208		$	854
Long-term debt, net	$	591		$	589
Noncurrent asset retirement obligations	$	409		$	438
Stockholders' Equity	$	1,517		$	1,688
Outstanding shares		75.4			79.3

GAINS AND LOSSES FROM COMMODITY DERIVATIVES
	2nd Quarter				1st Quarter				2nd Quarter				Six Months				Six Months
($ millions)		2022				2022				2021				2022				2021
Non-cash derivative gain (loss)	$	141			$	(381	)		$	(183	)		$	(240	)		$	(357	)
Net payments on settled commodity derivatives		(241	)			(181	)			(82	)			(422	)			(121	)
Net loss from commodity derivatives	$	(100	)		$	(562	)		$	(265	)		$	(662	)		$	(478	)

CAPITAL INVESTMENTS
	2nd Quarter			1st Quarter			2nd Quarter			Six Months			Six Months
($ millions)	2022			2022			2021			2022			2021
Facilities	$	15		$	17		$	11		$	32		$	18
Drilling		62			59			28			121			41
Workovers		9			6			10			15			17
Total E&P capital		86			82			49			168			76
CMB		10			1			—			11			—
Other		2			16			1			18			1
Total capital program	$	98		$	99		$	50		$	197		$	77

Attachment 2
NON-GAAP FINANCIAL MEASURES AND RECONCILIATIONS
To supplement the presentation of its financial results prepared in accordance with U.S generally accepted accounting principles (GAAP), management uses certain non-GAAP measures to assess its financial condition, results of operations and cash flows. The non-GAAP measures include adjusted net income (loss), adjusted EBITDAX, adjusted EBITDAX margin, discretionary cash flow, free cash flow and operating costs per BOE, among others. These measures are also widely used by the industry, the investment community and our lenders. Although these are non-GAAP measures, the amounts included in the calculations were computed in accordance with GAAP. Certain items excluded from these non-GAAP measures are significant components in understanding and assessing our financial performance, such as our cost of capital and tax structure, as well as the effect of acquisition and development costs of our assets. Management believes that the non-GAAP measures presented, when viewed in combination with its financial and operating results prepared in accordance with GAAP, provide a more complete understanding of the factors and trends affecting the Company's performance. The non-GAAP measures presented herein may not be comparable to other similarly titled measures of other companies. Below are additional disclosures regarding each of the non-GAAP measures reported in this press release, including reconciliations to their most directly comparable GAAP measure where applicable.

ADJUSTED NET INCOME (LOSS)
Adjusted net income (loss) and adjusted net income (loss) per share are non-GAAP measures. We define adjusted net income as net income excluding the effects of significant transactions and events that affect earnings but vary widely and unpredictably in nature, timing and amount. These events may recur, even across successive reporting periods. Management believes these non-GAAP measures provide useful information to the industry and the investment community interested in comparing our financial performance between periods. Reported earnings are considered representative of management's performance over the long term. Adjusted net income (loss) is not considered to be an alternative to net income (loss) reported in accordance with GAAP. The following table presents a reconciliation of the GAAP financial measure of net income and net income attributable to common stock per share to the non-GAAP financial measure of adjusted net income (loss) and adjusted net income (loss) per share.
	2nd Quarter				1st Quarter				2nd Quarter				Six Months				Six Months
($ millions, except per share amounts)		2022				2022				2021				2022				2021
Net income (loss)	$	190			$	(175	)		$	(107	)		$	15			$	(196	)
Net income attributable to noncontrolling interests		—				—				(4	)			—				(9	)
Net income (loss) attributable to common stock		190				(175	)			(111	)			15				(205	)
Unusual, infrequent and other items:
Non-cash (income) loss from commodity derivatives		(141	)			381				183				240				357
Asset impairments		2				—				—				2				3
Reorganization items, net		—				—				2				—				4
Severance and termination costs		—				—				1				—				15
Net loss on early extinguishment of debt		—				—				—				—				2
Net gain on asset divestitures		(4	)			(54	)			—				(58	)			(2	)
Rig termination expenses		—				—				1				—				2
Other, net		2				1				2				3				4
Total unusual, infrequent and other items		(141	)			328				189				187				385
Income tax benefit (provision) of adjustments at effective tax rate		40				(93	)			—				(53	)			—
Valuation allowance		—				31				—				31				—
Adjusted net income attributable to common stock	$	89			$	91			$	78			$	180			$	180
Net income (loss) attributable to common stock per share - basic	$	2.48			$	(2.23	)		$	(1.34	)		$	0.19			$	(2.46	)
Net income (loss) attributable to common stock per share - diluted	$	2.41			$	(2.23	)		$	(1.34	)		$	0.19			$	(2.46	)
Adjusted net income per share - basic	$	1.16			$	1.16			$	0.94			$	2.32			$	2.16
Adjusted net income per share - diluted	$	1.13			$	1.13			$	0.94			$	2.26			$	2.15

FREE CASH FLOW
Management uses free cash flow, which is defined by us as net cash provided by operating activities less capital investments, as a measure of liquidity. The following table presents a reconciliation of our net cash provided by operating activities to free cash flow. We supplemented our non-GAAP measure of free cash flow with free cash flow of our exploration and production and corporate items (Free Cash Flow for E&P, Corporate & Other) which we believe is a useful measure for investors to understand the results of our core oil and gas business. We define Free Cash Flow for E&P, Corporate & Other as consolidated free cash flow less results attributable to our carbon management business.   We have excluded one-time costs for bankruptcy related fees during 2021 and 2020 as a supplemental measure of our free cash flow.
	2nd Quarter				1st Quarter				2nd Quarter				Six Months				Six Months
($ millions)		2022				2022				2021				2022				2021
Net cash provided by operating activities	$	181			$	160			$	127			$	341			$	274
Capital investments		(98	)			(99	)			(50	)			(197	)			(77	)
Free cash flow		83				61				77				144				197
One-time bankruptcy related fees		—				—				2				—				4
Free cash flow, after special items	$	83			$	61			$	79			$	144			$	201
E&P, Corporate and Other Free Cash Flow	$	98			$	64			$	79			$	162			$	201
CMB Free Cash Flow	$	(15	)		$	(3	)		$	—			$	(18	)		$	—

ADJUSTED EBITDAX
We define Adjusted EBITDAX as earnings before interest expense; income taxes; depreciation, depletion and amortization; exploration expense; other unusual, infrequent and out-of-period items; and other non-cash items. We believe this measure provides useful information in assessing our financial condition, results of operations and cash flows and is widely used by the industry, the investment community and our lenders. Although this is a non-GAAP measure, the amounts included in the calculation were computed in accordance with GAAP. Certain items excluded from this non-GAAP measure are significant components in understanding and assessing our financial performance, such as our cost of capital and tax structure, as well as depreciation, depletion and amortization of our assets. This measure should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP. A version of Adjusted EBITDAX is a material component of certain of our financial covenants under our Revolving Credit Facility and is provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP. The following table represents a reconciliation of the GAAP financial measures of net income and net cash provided by operating activities to the non-GAAP financial measure of adjusted EBITDAX. We have supplemented our non-GAAP measures of consolidated adjusted EBITDAX with adjusted EBITDAX for our exploration and production and corporate items (Adjusted EBITDAX for E&P, Corporate & Other) which we believe is a useful measure for investors to understand the results of our core oil and gas business.. We define adjusted EBITDAX for E&P, Corporate & Other as consolidated adjusted EBITDAX less results attributable to our carbon management business (CMB).
	2nd Quarter				1st Quarter					2nd Quarter				Six Months				Six Months
($ millions, except per BOE amounts)		2022				2022					2021				2022				2021
Net income (loss)	$	190			$	(175	)			$	(107	)		$	15			$	(196	)
Interest and debt expense, net		13				13					13				26				26
Depreciation, depletion and amortization		50				49					54				99				106
Income tax provision (benefit)		76				(26	)				—				50				—
Exploration expense		1				1					2				2				4
Unusual, infrequent and other items (a)		(141	)			328					189				187				385
Non-cash items
Accretion expense		11				11					13				22				26
Stock-based compensation		4				4					4				8				6
Post-retirement medical and pension		—				1					1				1				1
Other non-cash items		—				—					—				—				—
Adjusted EBITDAX	$	204			$	206				$	169			$	410			$	358
Net cash used by operating activities	$	181			$	160				$	127			$	341			$	274
Cash interest		2				23					2				25				5
Cash income taxes		20				—					—				20				—
Exploration expenditures		1				1					2				2				4
Working capital changes		—				22					38				22				75
Adjusted EBITDAX	$	204			$	206				$	169			$	410			$	358
E&P, Corporate & Other Adjusted EBITDAX	$	209			$	208				$	169			$	417			$	358
CMB Adjusted EBITDAX	$	(5	)		$	(2	)			$	—			$	(7	)		$	—
Adjusted EBITDAX per Boe	$	24.61			$	25.89				$	18.48			$	25.24			$	19.78
(a) See Adjusted Net Income (Loss) reconciliation.

ADJUSTED GENERAL & ADMINISTRATIVE EXPENSES
Management uses a measure called adjusted general and administrative (G&A) expenses to provide useful information to investors interested in comparing our costs between periods and performance to our peers. We supplemented our non-GAAP measure of adjusted general and administrative expenses with adjusted general and administrative expenses of our exploration and production and corporate items (Adjusted General & Administrative Expenses for E&P, Corporate & Other) which we believe is a useful measure for investors to understand the results or our core oil and gas business. We define Adjusted General & Administrative Expenses for E&P, Corporate & Other as consolidated adjusted general and administrative expenses less results attributable to our carbon management business
	2nd Quarter				1st Quarter					2nd Quarter				Six Months				Six Months
($ millions)		2022				2022					2021				2022				2021
General and administrative expenses	$	56			$	48				$	48			$	104			$	96
Stock-based compensation		(4	)			(4	)				(4	)			(8	)			(6	)
ERP implementation costs		(1	)			—					—				(1	)			—
Adjusted G&A expenses	$	51			$	44				$	44			$	95			$	90
E&P, Corporate and Other Adjusted G&A expenses	$	47			$	43				$	44			$	90			$	90
CMB Adjusted G&A expenses	$	4			$	1				$	—			$	5			$	—
OPERATING COSTS PER BOE
The reporting of our PSC-type contracts creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs. The following table presents operating costs after adjusting for the excess costs attributable to PSCs.
	2nd Quarter				1st Quarter					2nd Quarter				Six Months				Six Months
($ per BOE)		2022				2022					2021				2022				2021
Energy operating costs (1)	$	6.88			$	6.68				$	4.70			$	6.78			$	4.70
Gas processing costs		0.54				0.56					0.66				0.55				0.60
Non-energy operating costs (2)		15.50				15.63					13.12				15.57				13.10
Operating costs	$	22.92			$	22.87				$	18.48			$	22.90			$	18.40
Costs attributable to PSCs
Excess energy operating costs attributable to PSCs	$	(1.03	)		$	(0.90	)			$	(0.63	)		$	(0.96	)		$	(0.60	)
Excess non-energy operating costs attributable to PSCs		(1.55	)			(1.40	)				(1.10	)			(1.49	)			(1.06	)
Excess costs attributable to PSCs	$	(2.58	)		$	(2.30	)			$	(1.73	)		$	(2.45	)		$	(1.66	)
Energy operating costs, excluding effect of PSCs (1)	$	5.85			$	5.78				$	4.07			$	5.82			$	4.10
Gas processing costs, excluding effect of PSCs		0.54				0.56					0.66				0.55				0.60
Non-energy operating costs, excluding effect of PSCs (2)		13.95				14.23					12.02				14.08				12.04
Operating costs, excluding effects of PSCs	$	20.34			$	20.57				$	16.75			$	20.45			$	16.74
(1) Energy operating costs consist of purchases of natural gas to generate electricity, purchased electricity and internal costs to produce electricity used in our operations.
(2) Non-energy operating costs equal total operating costs less energy and gas processing costs. However, non-energy operating costs include the costs of purchasing natural gas used to generate steam for our steamfloods.

Attachment 3
PRODUCTION STATISTICS
Net	2nd Quarter		1st Quarter		2nd Quarter		Six Months		Six Months
Oil, NGLs and Natural Gas Production Per Day	2022		2022		2021		2022		2021
Oil (MBbl/d)
San Joaquin Basin	38		38		39		38		38
Los Angeles Basin	16		18		19		17		20
Ventura Basin	—		—		3		—		2
Total	54		56		61		55		60
NGLs (MBbl/d)
San Joaquin Basin	12		9		13		11		12
Ventura Basin	—		—		—		—		1
Total	12		9		13		11		13
Natural Gas (MMcf/d)
San Joaquin Basin	132		121		135		127		135
Los Angeles Basin	1		1		1		1		1
Ventura Basin	—		—		5		—		5
Sacramento Basin	18		19		20		18		20
Total	151		141		161		146		161
Total Production (MBoe/d)	91		88		101		90		100
Gross Operated and Net Non-Operated	2nd Quarter		1st Quarter		2nd Quarter		Six Months		Six Months
Oil, NGLs and Natural Gas Production Per Day	2022		2022		2021		2022		2021
Oil (MBbl/d)
San Joaquin Basin	42		43		45		42		45
Los Angeles Basin	25		26		27		26		27
Ventura Basin	—		—		3		—		3
Total	67		69		75		68		75
NGLs (MBbl/d)
San Joaquin Basin	13		9		14		11		12
Ventura Basin	—		—		—		—		1
Total	13		9		14		11		13
Natural Gas (MMcf/d)
San Joaquin Basin	141		129		144		135		144
Los Angeles Basin	7		8		8		7		8
Ventura Basin	—		—		5		—		5
Sacramento Basin	22		23		24		23		24
Total	170		160		181		165		181
Total Production (MBoe/d)	108		105		119		106		118
Note: MBbl/d refers to thousands of barrels per day; MMcf/d refers to millions of cubic feet per day; MBoe/d refers to thousands of barrels of oil equivalent (Boe) per day. Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet of natural gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.

														Attachment 4
PRICE STATISTICS
	2nd Quarter				1st Quarter					2nd Quarter				Six Months				Six Months
		2022				2022					2021				2022				2021
Oil ($ per Bbl)
Realized price with derivative settlements	$	63.17			$	60.30				$	54.10			$	61.71			$	53.91
Realized price without derivative settlements	$	112.32			$	96.13				$	68.94			$	104.07			$	64.89
NGLs ($/Bbl)	$	68.29			$	78.63				$	44.90			$	72.57			$	46.75
Natural gas ($/Mcf)
Realized price with derivative settlements	$	6.72			$	6.28				$	3.03			$	6.51			$	3.14
Realized price without derivative settlements	$	6.85			$	6.28				$	3.04			$	6.58			$	3.17
Index Prices
Brent oil ($/Bbl)	$	111.79			$	97.38				$	69.02			$	104.59			$	65.06
WTI oil ($/Bbl)	$	108.41			$	94.29				$	66.07			$	101.35			$	61.96
NYMEX Henry Hub average daily price ($/MMBtu)	$	6.62			$	4.19				$	2.76			$	5.40			$	2.74
NYMEX Henry Hub average monthly settled price ($/MMBtu)	$	7.17			$	4.95				$	2.83			$	6.06			$	2.76
Realized Prices as Percentage of Index Prices
Oil with derivative settlements as a percentage of Brent		57	%			62	%				78	%			59	%			83	%
Oil without derivative settlements as a percentage of Brent		100	%			99	%				100	%			100	%			100	%
Oil with derivative settlements as a percentage of WTI		58	%			64	%				82	%			61	%			87	%
Oil without derivative settlements as a percentage of WTI		104	%			102	%				104	%			103	%			105	%
NGLs as a percentage of Brent		61	%			81	%				65	%			69	%			72	%
NGLs as a percentage of WTI		63	%			83	%				68	%			72	%			75	%
Natural gas with derivative settlements as a percentage of NYMEX average daily price		102	%			150	%				110	%			121	%			115	%
Natural gas with derivative settlements as a percentage of NYMEX average monthly settled price		94	%			127	%				107	%			107	%			114	%
Natural gas without derivative settlements as a percentage of NYMEX average daily price		103	%			150	%				110	%			122	%			116	%
Natural gas without derivative settlements as a percentage of NYMEX average monthly settled price		96	%			127	%				107	%			109	%			115	%

							Attachment 5
SECOND QUARTER 2022 DRILLING ACTIVITY
	San Joaquin		Los Angeles		Ventura		Sacramento
Wells Drilled	Basin		Basin		Basin		Basin		Total
Development Wells
Primary	5		—		—		—		5
Waterflood	6		7		—		—		13
Steamflood	28		—		—		—		28
Total (1)	39		7		—		—		46
SIX MONTH 2022 DRILLING ACTIVITY
	San Joaquin		Los Angeles		Ventura		Sacramento
Wells Drilled	Basin		Basin		Basin		Basin		Total
Development Wells
Primary	8		—		—		—		8
Waterflood	27		14		—		—		41
Steamflood	39		—		—		—		39
Total (1)	74		14		—		—		88
(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 JUNE 30, 2022
		Q3 2022			Q4 2022			Q1 2023			Q2 2023			2H 2023			2024
Sold Calls
Barrels per day			34,380			25,167			18,322			17,837			11,555			—
Weighted-average Brent price per barrel		$	60.76		$	57.82		$	57.28		$	60.00		$	57.06			—
Swaps
Barrels per day			10,476			17,263			14,620			14,475			19,395			1,492
Weighted-average Brent price per barrel		$	53.97		$	58.79		$	67.36		$	66.36		$	68.05		$	79.06
Net Purchased Puts 1
Barrels per day			34,380			25,167			18,322			17,837			11,555			1,724
Weighted-average Brent price per barrel		$	65.02		$	64.47		$	76.25		$	76.25		$	76.25		$	75.00
Sold Puts
Barrels per day			4,000			1,348			—			—			—			—
Weighted-average Brent price per barrel		$	32.00		$	32.00			—			—			—			—
1 Purchased and sold puts with the same strike price have been netted together.

			Attachment 7
	2022 Estimated
TOTAL CRC GUIDANCE1	Consolidated		CMB		E&P, Corporate & Other
Net Total Production (MBoe/d)	91 - 94				91 - 94
Net Oil Production (MBbl/d)	53 - 58				53 - 58
Operating Costs ($ millions)	$725 - $755				$725 - $755
CMB Expenses2 ($ millions)	$20 - $30		$20 - $30
Adjusted General and Administrative Expenses ($ millions)	$185 - $200		$10 - $15		$175 - $185
Capital ($ millions)	$380 - $410		$20 - $30		$360 - $380
Adjusted EBITDAX ($ millions)	$895 - $960		($30) - ($45)		$940 - $990
Free Cash Flow ($ millions)	$365 - $450		($50) - ($75)		$440 - $500

See Attachment 2 for management's disclosure of its use of these non-GAAP measures and how these measures provide useful information to investors about CRC's results of operations and financial condition. CRC has supplemented its non-GAAP measures of consolidated adjusted EBITDAX and consolidated free cash flow with adjusted EBITDAX for its exploration and production and corporate items (Adjusted EBITDAX for E&P, Corporate & Other) and free cash flow from our exploration and production and corporate items (free cash flow from E&P, Corporate & Other) which CRC believes are useful measures for investors to understand the results of its core oil and gas business. CRC defines adjusted EBITDAX for E&P, Corporate & Other as consolidated adjusted EBITDAX less results attributable to its carbon management business (CMB). CRC defines free cash flow from E&P, Corporate & Other as consolidated free cash flow less results attributable to CMB.

	2022 Estimated
	Consolidated								CMB								E&P, Corporate & Other
($ millions)	Low				High				Low				High				Low				High
Net cash provided (used) by operating activities	$	775			$	830			$	(45	)		$	(30	)		$	820			$	860
Capital investments		(410	)			(380	)			(30	)			(20	)			(380	)			(360	)
Estimated free cash flow	$	365			$	450			$	(75	)		$	(50	)		$	440			$	500

	2022 Estimated
	Consolidated								CMB								E&P, Corporate & Other
($ millions)	Low				High				Low				High				Low				High
Net income	$	495			$	515			$	(45	)		$	(30	)		$	540			$	545
Interest and debt expense, net		50				56												50				56
Depreciation, depletion and amortization		200				210												200				210
Exploration expense		7				10												7				10
Income taxes		232				256												232				256
Unusual, infrequent and other items
Non-cash derivative gain		(90	)			(99	)											(90	)			(99	)
Gain on asset divestitures		(58	)			(58	)											(58	)			(58	)
Other		2				4												2				4
Other non-cash items
Accretion expense		40				46												40				46
Stock-based compensation		15				18												15				18
Post-retirement medical and pension		2				2												2				2
Estimated adjusted EBITDAX	$	895			$	960			$	(45	)		$	(30	)		$	940			$	990
Net cash provided (used) by operating activities	$	775			$	830			$	(45	)		$	(30	)		$	820			$	860
Cash interest		44				48												44				48
Cash income taxes		32				38												32				38
Exploration expenditures		7				7												7				7
Working capital changes		37				37												37				37
Estimated adjusted EBITDAX	$	895			$	960			$	(45	)		$	(30	)		$	940			$	990
	2022 Estimated
	Consolidated								CMB								E&P, Corporate & Other
($ millions)	Low				High				Low				High				Low				High
General and administrative expenses	$	215			$	225			$	10			$	15			$	205			$	210
Equity-settled stock-based compensation		(23	)			(18	)											(23	)			(18	)
ERP implementation Costs		(7	)			(7	)											(7	)			(7	)
Adjusted general and administrative expenses	$	185			$	200			$	10			$	15			$	175			$	185
1 Current guidance assumes a 2022 Brent price of $103.42 per barrel of oil, NGL realizations consistent with prior years and an average daily NYMEX gas price of $5.62 per mcf. CRC's share of production under PSCs decreases when commodity prices rise and increases when prices decline.
2 CMB Expenses include start-up expenditures.

 

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