Business Wire | Aug 5, 2021 04:18PM EDT

California Resources Corporation Reports Second Quarter 2021 Results, Increases Free Cash Flow Guidance, Raises Share Repurchase Program to $250 Million and Announces Strategic A&D Transactions

Aug. 05, 2021

SANTA CLARITA, Calif.--(BUSINESS WIRE)--Aug. 05, 2021--California Resources Corporation (NYSE: CRC), an independent oil and natural gas company committed to energy transition in the sector, today reported second quarter 2021 operational and financial results.

"CRC continued to deliver on its strategy with strong second quarter results driven by robust financial and operational performance, resulting in an increase in 2021 free cash flow1 guidance to $400 to $500 million. Given our financial strength and low stock valuation relative to fundamentals, we are increasing our Share Repurchase Program from $150 million to $250 million," said Mac McFarland, President and Chief Executive Officer. "I am also pleased to announce an acquisition of the 90% working interest in the joint venture wells held by our partner as well as a planned divestiture of our non-core Ventura operations. These strategic A&D transactions will simplify our business model, lower our overall operating costs and provide positive net cash proceeds."

Mr. McFarland continued, "We continued to make strides on our ESG strategy and are pleased to announce we have identified approximately one billion metric tons of CO2 permanent storage capacity as well as up to 1,000 megawatts (MW) of front-of-the-meter solar opportunities which will help contribute to the decarbonization of California. As a first step, we are submitting permits for an ~40 million metric ton permanent storage CCS project, Carbon TerraVault I. Further, we are advancing arrangements with SunPower for an initial 12 MW and up to 45 MW of behind-the-meter solar projects.

"I'm also excited to announce the appointment of Nicole Neeman Brady to our Board and look forward to her contributions, particularly on the Sustainability Committee."

Second Quarter 2021 Highlights

Financial

* Reported a net loss attributable to common stock of $111 million, or $1.34 per diluted share. Adjusted net income1 was $78 million, or $0.94 per diluted share * Generated net cash provided by operating activities of $127 million, adjusted EBITDAX1 of $169 million and free cash flow1 of $77 million * Closed the quarter with $151 million of cash on hand, an undrawn credit facility and $518 million of liquidity2 * Sustained non-energy operating costs and general and administrative (G&A) expense improvements achieved earlier in 2021

Operational

* Produced an average of 101,000 net barrels of oil equivalent (BOE) per day, including 61,000 barrels per day of oil, with quarterly capital expenditures of $50 million * Operated two drilling rigs in the San Joaquin Basin and drilled 21 wells (21 online in 2Q21) * Operated 35 maintenance rigs * Completed 48 capital workovers

Transactional

* Signed agreements to divest operations in the Ventura basin for total cash consideration of up to $102 million plus additional earn-out consideration that is linked to future commodity prices * Post quarter end, acquired the working interest in the joint venture wells held by Macquarie Infrastructure and Real Assets, Inc. ("MIRA") for $53 million * Post quarter end, filing permits for an ~40 MMT CO2 permanent storage CCS project, Carbon TerraVault I * Advancing a 12 MW behind-the-meter solar project with SunPower for CRC's Mt. Poso field which is expected to be Low Carbon Fuel Standard ("LCFS") eligible; construction is expected to begin in early 2022

Guidance

* Raised 2021 free cash flow1 guidance to $400 to $500 million * Optimized CRC investment dollars by shifting an additional $20 million from drilling and completions to downhole maintenance projects which provide efficiencies and faster payouts * Raised the Share Repurchase Program ("SRP") to $250 million from $150 million; repurchased 1.4 million shares for $45 million in 2Q21

2021 Guidance & Capital Program

Given the strength of the second quarter results, CRC has raised its full year 2021 free cash flow1 guidance to $400 to $500 million from $250 to $350 million, adjusted EBITDAX1 guidance to $725 to $825 million from $625 to $725 million and production guidance to 97 to 100 MBOE per day from 96 to 99 MBOE per day. Recognizing capital efficiency improvements and faster payouts on downhole maintenance projects, CRC revised its full year 2021 operating cost and capital guidance by shifting an additional $20 million of drilling capital to these opportunities. In addition to this shift from capital to operating costs, an increase in natural gas prices further raises expected operating costs by approximately $35 million, which is more than offset by increased natural gas revenues as CRC is net long natural gas on the whole. These two items result in revised full year 2021 capital guidance of $170 to $190 million from $185 to $210 million and revised full year 2021 operating cost guidance of $670 to $695 million from $615 to $630 million.

CRC made $77 million of capital investments in the first half of 2021. The current capital program anticipates that CRC will maintain a consistent level of investment throughout the remainder of the year. If commodity prices decline significantly from current levels. CRC may need to decrease the size of its capital program in response to market conditions. 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 Total Year 2021E 2021E



Total Production (Mboe/d) 96 - 99 97 - 100

Oil Production (Mbbl/d) 60 - 62 60 - 62

Operating Costs ($ millions) $615 - $630 $670 - $695

General and administrative expenses ($ $180 - $190 $180 - $190millions)

Capital ($ millions) $185 - $210 $170 - $190

Adj. EBITDAX^1 ($ millions) $625 - $725 $725 - $825

Free cash flow^1 ($ millions) $250 - $350 $400 - $500

Increasing the Share Repurchase Program

In August 2021, CRC's Board of Directors increased the Share Repurchase Program by $100 million to $250 million through March 31, 2022.

Acquisitions and Divestitures

In the second quarter of 2021, CRC entered into agreements to sell its Ventura basin operations for expected cash consideration of up to $102 million plus additional earn-out consideration that is linked to future commodity prices. The consideration includes $82 million of cash to be paid at closing and up to $20 million of potential additional consideration if the buyer does not perform certain abandonment obligations with respect to the divested properties. These transactions will simplify CRC's business model, lower its overall operating costs and decrease its asset retirement obligations. For the three months ending June 30, 2021, CRC's Ventura basin operations were producing 3,600 BOE per day (~65% oil). The closing of the transaction is subject to customary closing conditions, including satisfaction of land and environmental due diligence and third-party consents.

In August 2021, CRC continued to demonstrate its focus on core areas by acquiring the 90% working interest in the joint venture wells held by MIRA for $53 million, before transaction costs. The acquisition of MIRA's working interest would have added oil production of 1,600 BOE per day (~100% oil) for the first half of 2021 with minimal integration costs and underground risk.

CRC's full year guidance will be updated upon the closing of the Ventura basin transactions which are expected in the second half of 2021.

Sustainability Update

According to internal and third party estimates, CRC has some of the lowest carbon intensity production in the U.S. CRC aims to build upon this position through investment in decarbonization projects and other emissions reducing projects to help advance energy transition in California. As part of an initial review, CRC has the potential to permanently store up to 1 billion metric tons of CO2 in its oil and gas reservoirs as well as the opportunity to generate 300 to 1,000 MW of front-of-the-meter solar power for the grid by utilizing CRC's vast surface land footprint. In addition to these opportunities, CRC has the potential for up to 45 MW of behind-the-meter solar development projects with its partner SunPower.

Building on CRC's carbon capture opportunity, CRC is applying for Class VI EPA permits for a project with a capability of up to 40 million metric tons of permanent CO2 storage, referred to as Carbon TerraVault I. Injection for this project could begin in the 2025 time frame with the injection of approximately 1 million metric tons per year, equivalent to the annual emissions of approximately 200,000 passenger vehicles. CRC is proud to be a first mover of CCS operations in California and to help the state make progress on its carbon neutrality goals.

CRC has a dedicated Sustainability Committee chaired by William B. Roby, with members Nicole Neeman Brady and Andrew B. Bremner along with a dedicated corporate function under the executive leadership of Chris Gould as EVP and Chief Sustainability Officer.

Board Enhancement

On August 5, 2021, CRC's Board of Directors elected one new Board member, Nicole Neeman Brady.

Ms. Neeman Brady has over 20 years of experience as an entrepreneur, executive, investor and community leader with global water, energy, and agricultural expertise. She serves as the Chief Executive Officer and a director of Sustainable Development Acquisition Corp. since December 2020. She also served as Principal and Chief Operating Officer at Renewable Resources Group LLC, as well as a member of the Investment Committee and a board member of several of its portfolio companies. Her experience also includes a deep understanding of and passion for the public sector, including board service on the Colorado River Board of California and currently, as a Commissioner on the Los Angeles Department of Water and Power, a Board member of Blue Ocean Mariculture and a Board member of the Library Foundation of Los Angeles. Please see www.crc.com for more details.

Fresh Start Accounting and Predecessor and Successor Periods

CRC qualified 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.

Second Quarter 2021 Results

Successor Predecessor

2nd 2nd Quarter Quarter

($ and shares in millions, except per share amounts) 2021 2020



Statements of Operations:

Revenues

Total revenues $ 304 $ 276



Costs

Total costs 394 391

Operating Loss $ (90 ) $ (115 )

Net Loss Attributable to Common Stock $ (111 ) $ (271 )



Net loss attributable to common stock per share - $ (1.34 ) $ (5.47 )basic and diluted

Adjusted net income (loss) $ 78 $ (202 )

Adjusted net income (loss) per share - basic $ 0.94 $ (4.08 )

Weighted-average common shares outstanding - basic 83.1 49.5

Adjusted EBITDAX $ 169 $ 19

Successor

Predecessor

2nd Quarter

2nd Quarter

($ in millions)

2021

2020

Cash Flow Data:

Net cash provided by operating activities

$

127

$

(135

)

Net cash used in investing activities

$

(43

)

$

(15

)

Net cash (used in) provided by financing activities

$

(63

)

$

199

Six-Month 2021 Results

Successor Predecessor

2nd Quarter 2nd Quarter

($ in millions) 2021 2020

Cash Flow Data:

Net cash provided by operating activities $ 127 $ (135 )

Net cash used in investing activities $ (43 ) $ (15 )

Net cash (used in) provided by financing activities $ (63 ) $ 199

Six-Month 2021 Results

Successor Predecessor

Six Six Months Months

($ and shares in millions, except per share amounts) 2021 2020



Statements of Operations:

Revenues

Total revenues $ 667 $ 849



Costs

Total costs 830 2,613

Operating Loss $ (163 ) $ (1,764 )

Net Loss Attributable to Common Stock $ (205 ) $ (2,067 )



Net loss attributable to common stock per share - $ (2.46 ) $ (41.84 )basic and diluted

Adjusted net income (loss) $ 180 $ (210 )

Adjusted net income (loss) per share - basic $ 2.16 $ (4.25 )

Weighted-average common shares outstanding - basic 83.2 49.4

Adjusted EBITDAX $ 358 $ 270

Successor

Predecessor

Six Months

Six Months

($ in millions)

2021

2020

Cash Flow Data:

Net cash provided by operating activities

$

274

$

93

Net cash used by investing activities

$

(63

)

$

(27

)

Net cash (used) provided by financing activities

$

(88

)

$

43

Review of Operating and Financial Results

Total daily net production volumes decreased 10% from 112,000 BOE per day for the second quarter of 2020 to 101,000 BOE per day for the second quarter of 2021. The decrease from the same period in 2020 was primarily due to limited drilling activity and capital investment during the prior twelve months and natural decline rates. Total daily net production volumes decreased 15% from 117,000 BOE per day for the six months ended June 30, 2020 to 100,000 BOE per day for the same period in 2021. Production sharing type contracts (PSC-type) at CRC's Long Beach assets negatively impacted oil production by approximately 5,000 and 4,000 barrels per day in the three and six months ended June 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 $23.28 per barrel from $30.82 per barrel in the second quarter of 2020 to $54.10 per barrel in the second quarter of 2021. For the six months ended June 30, 2021, realized oil prices, including the effect of settled hedges, increased by $10.15 to $53.91 from $43.76 in the same period of 2020. Realized oil prices were higher in the second quarter of 2021 compared to the same prior-year period as oil demand recovered from its COVID-19 driven lows. See Attachment 4 for further information on prices.

Adjusted EBITDAX1 for the second quarter of 2021 was $169 million and net cash provided by operating activities was $127 million. Internally funded capital invested during the second quarter of 2021 was $50 million. Free cash flow1 was $77 million. Adjusted EBITDAX1 for the six months ended June 30, 2021 was $358 million and net cash provided by operating activities was $274 million. For the first half of 2021, internally funded capital invested was $77 million. Free cash flow1 was $197 million.

Successor Predecessor

Six Months Six Months

($ in millions) 2021 2020

Cash Flow Data:

Net cash provided by operating activities $ 274 $ 93

Net cash used by investing activities $ (63 ) $ (27 )

Net cash (used) provided by financing activities $ (88 ) $ 43

Review of Operating and Financial Results

Total daily net production volumes decreased 10% from 112,000 BOE per day for the second quarter of 2020 to 101,000 BOE per day for the second quarter of 2021. The decrease from the same period in 2020 was primarily due to limited drilling activity and capital investment during the prior twelve months and natural decline rates. Total daily net production volumes decreased 15% from 117,000 BOE per day for the six months ended June 30, 2020 to 100,000 BOE per day for the same period in 2021. Production sharing type contracts (PSC-type) at CRC's Long Beach assets negatively impacted oil production by approximately 5,000 and 4,000 barrels per day in the three and six months ended June 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 $23.28 per barrel from $30.82 per barrel in the second quarter of 2020 to $54.10 per barrel in the second quarter of 2021. For the six months ended June 30, 2021, realized oil prices, including the effect of settled hedges, increased by $10.15 to $53.91 from $43.76 in the same period of 2020. Realized oil prices were higher in the second quarter of 2021 compared to the same prior-year period as oil demand recovered from its COVID-19 driven lows. See Attachment 4 for further information on prices.

Adjusted EBITDAX1 for the second quarter of 2021 was $169 million and net cash provided by operating activities was $127 million. Internally funded capital invested during the second quarter of 2021 was $50 million. Free cash flow1 was $77 million. Adjusted EBITDAX1 for the six months ended June 30, 2021 was $358 million and net cash provided by operating activities was $274 million. For the first half of 2021, internally funded capital invested was $77 million. Free cash flow1 was $197 million.

FREE CASH FLOW



Management uses free cash flow, which is defined by us as net cash provided byoperating activities less capital investments, as a measure of liquidity. Thefollowing table presents a reconciliation of our net cash provided by operatingactivities to free cash flow. We have excluded one-time costs for bankruptcyrelated fees during 2021 and 2020 as a supplemental measure of free cash flow.



Successor Predecessor Successor Predecessor

2nd 2nd Quarter Six Six Months Quarter Months

($ millions) 2021 2020 2021 2020



Net cash provided by $ 127 $ (135 ) $ 274 $ 93 operating activities

Capital investments (50 ) (3 ) (77 ) (33 )

Free cash flow 77 (138 ) 197 60

One-time bankruptcy related 2 42 4 47 fees

Free cash flow, after $ 79 $ (96 ) $ 201 $ 107 special items

Operating costs for the second quarter of 2021 were $169 million compared to $127 million for the second quarter of 2020. Operating costs for the six months ended June 30, 2021 were $333 million compared to $319 million for the same period in 2020. The increase was primarily attributable to higher downhole maintenance activity in 2021 which was deferred in 2020 as CRC shut-in wells. Additionally, operating costs increased in 2021 due to higher energy costs and natural gas prices as compared to 2020. Partially offsetting these increases were lower compensation-related costs from streamlining CRC's operations, which included headcount reductions in late 2020 and early 2021. CRC's second quarter 2020 reflect cost savings for reduced work hours and reduced management salaries in response to the industry downturn and the COVID-19 pandemic. Although higher natural gas and electricity prices in 2021 increased CRC's operating costs, higher prices have a net positive effect on operating results due to higher revenue from sales of these commodities which CRC also produces.

Operating costs per BOE are presented below:

OPERATING COSTS PER BOE



The reporting of our PSC-type contracts creates a difference between reportedoperating costs, which are for the full field, and reported volumes, which areonly our net share, inflating the per barrel operating costs. The followingtable presents operating costs after adjusting for the excess costsattributable to PSC-type contracts.



Successor Predecessor Successor Predecessor

2nd 2nd Quarter Six Six Months Quarter Months

($ per Boe) 2021 2020 2021 2020

Energy operating $ 4.70 $ 3.51 $ 4.70 $ 3.61 costs ^(a)

Gas processing costs 0.66 0.46 0.60 $ 0.57

Non-energy operating 13.12 8.45 13.10 10.81 costs ^(b)

Operating costs $ 18.48 $ 12.42 $ 18.40 $ 14.99

Excess costsattributable to (1.73 ) (0.42 ) (1.66 ) (0.66 )PSC-type contracts

Operating costs,excluding effects of $ 16.75 $ 12.00 $ 16.74 $ 14.33 PSC-type contracts

(a) Energy operating costs include purchases of fuel gas used to generate electricity, purchased electricity and internal costs to produce electricity used in our operations.

(b) 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.

G&A expenses were $48 million for the second quarter of 2021, compared to $69 million in the same prior-year period. For the six months ended June 30, 2021, G&A expenses were $96 million compared to $129 million in the same prior-year period. The decrease in G&A expenses reflects lower compensation-related costs primarily due to 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. CRC's second quarter 2020 results include savings from reduced work hours and reduced management salaries in response to the industry downturn and the COVID-19 pandemic. 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 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 June 30, 2021. The borrowing base for the Revolving Credit Facility is redetermined around April and October of each year and was most recently set at $1.2 billion in May 2021. The amount CRC is able to borrow under the Revolving Credit Facility is limited to the amount of the commitment described above.

In May 2021, CRC amended its Revolving Credit Facility to provide further strategic flexibility with respect to CRC's minimum and maximum hedging restrictions and to increase CRC's capacity to make certain restricted payments, including paying dividends on its common stock and repurchasing its common stock.

As of June 30, 2021, CRC had liquidity of $518 million, which consisted of $151 million in unrestricted cash and $367 million of available borrowing capacity under its Revolving Credit Facility after accounting for $125 million in outstanding letters of credit.

CRC anticipates the preferred interest in a development joint venture held by Benefit Street Partners ("BSP") could be automatically redeemed in the second half of 2021. We anticipate the remaining distributions to BSP will approximate $20 million.

CRC may begin paying income taxes in early 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, the amount and type of CRC's capital spend, cost structure and activity levels. Potential legislation could also limit tax incentives for fossil fuels.

Operational Update

During the second quarter of 2021, CRC operated an average of two drilling rigs in the San Joaquin Basin, drilled 21 net wells, 19 of which were brought online in addition to the two that were brought online from the first quarter totaling 21 online wells. The San Joaquin basin produced 74,500 net BOE per day. The Los Angeles basin produced 19,200 net BOE per day, the Ventura basin produced 3,600 net BOE per day and the Sacramento basin produced 3,300 net BOE per day.

September 2021 Investor Conferences

CRC's executives will be participating in the Barclays CEO Energy-Power Conference on September 8-10. Mac McFarland, President and CEO, and Francisco Leon, EVP and CFO, will also be presenting on September 10th at 10:55 a.m. ET.

CRC's presentation materials will be available the day of the event on the Earnings and Presentations page in the Investor Relations section on www.crc.com.

Conference Call Details

To participate in the conference call scheduled for later today at 5:00 p.m. Eastern Time, please dial (877) 328-5505 (International calls please dial +1 (412) 317-5421) or access via webcast at www.crc.com 15 minutes prior to the scheduled start time to register. Participants may also pre-register for the conference call at https://dpregister.com/sreg/10157220/e9185e9690. 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) 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 $151 million of cash plus $492 million of capacity on CRC's Revolving Credit Facility less $125 million in outstanding letters of credit.

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 U.S. and we are focused on maximizing the value of our land, mineral and technical resources for decarbonization by developing Carbon Capture and Sequestration (CCS) and other emissions reducing projects. For more information about CRC, please visit www.crc.com.

Forward-Looking Statements

The information included herein contains forward-looking statements that involve risks and uncertainties that could materially affect CRC's expected results of operations, liquidity, cash flows and business prospects. Such statements include those regarding CRC's expectations as to its future:

* 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 * energy transition initiatives

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 make them in good faith, they almost always vary from actual results, sometimes materially. CRC also believes third-party statements it cites are accurate but have not independently verified them and do not warrant their accuracy or completeness. Factors (but not necessarily all the factors) that could cause results to differ include:

* CRC's ability to execute its business plan post-emergence * 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 CRC's 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 * 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 CRC products * 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 * production-sharing contracts' effects on production and unit operating costs * 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 * 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 * CRC's ability to recognize the benefits of business strategies and initiatives related to energy transition, including carbon capture and sequestration projects and other renewable energy efforts * factors discussed in Item 1A, Risk Factors in CRC's Annual Report on Form 10-K 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 we undertake 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.

(a) Energy operating costs include purchases of fuel gas used to generateelectricity, purchased electricity and internal costs to produce electricityused in our operations.

(b) Non-energy operating costs equal total operating costs less energyoperating costs and gas processing costs. Purchases of fuel gas to generatesteam which is then used in our steamfloods is included in non-energy operatingcosts.

G&A expenses were $48 million for the second quarter of 2021, compared to $69 million in the same prior-year period. For the six months ended June 30, 2021, G&A expenses were $96 million compared to $129 million in the same prior-year period. The decrease in G&A expenses reflects lower compensation-related costs primarily due to 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. CRC's second quarter 2020 results include savings from reduced work hours and reduced management salaries in response to the industry downturn and the COVID-19 pandemic. 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 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 June 30, 2021. The borrowing base for the Revolving Credit Facility is redetermined around April and October of each year and was most recently set at $1.2 billion in May 2021. The amount CRC is able to borrow under the Revolving Credit Facility is limited to the amount of the commitment described above.

In May 2021, CRC amended its Revolving Credit Facility to provide further strategic flexibility with respect to CRC's minimum and maximum hedging restrictions and to increase CRC's capacity to make certain restricted payments, including paying dividends on its common stock and repurchasing its common stock.

As of June 30, 2021, CRC had liquidity of $518 million, which consisted of $151 million in unrestricted cash and $367 million of available borrowing capacity under its Revolving Credit Facility after accounting for $125 million in outstanding letters of credit.

CRC anticipates the preferred interest in a development joint venture held by Benefit Street Partners ("BSP") could be automatically redeemed in the second half of 2021. We anticipate the remaining distributions to BSP will approximate $20 million.

CRC may begin paying income taxes in early 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, the amount and type of CRC's capital spend, cost structure and activity levels. Potential legislation could also limit tax incentives for fossil fuels.

Operational Update

During the second quarter of 2021, CRC operated an average of two drilling rigs in the San Joaquin Basin, drilled 21 net wells, 19 of which were brought online in addition to the two that were brought online from the first quarter totaling 21 online wells. The San Joaquin basin produced 74,500 net BOE per day. The Los Angeles basin produced 19,200 net BOE per day, the Ventura basin produced 3,600 net BOE per day and the Sacramento basin produced 3,300 net BOE per day.

September 2021 Investor Conferences

CRC's executives will be participating in the Barclays CEO Energy-Power Conference on September 8-10. Mac McFarland, President and CEO, and Francisco Leon, EVP and CFO, will also be presenting on September 10th at 10:55 a.m. ET.

CRC's presentation materials will be available the day of the event on the Earnings and Presentations page in the Investor Relations section on www.crc.com.

Conference Call Details

To participate in the conference call scheduled for later today at 5:00 p.m. Eastern Time, please dial (877) 328-5505 (International calls please dial +1 (412) 317-5421) or access via webcast at www.crc.com 15 minutes prior to the scheduled start time to register. Participants may also pre-register for the conference call at https://dpregister.com/sreg/10157220/e9185e9690. 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) 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 $151 million of cash plus $492 million of capacity on CRC's Revolving Credit Facility less $125 million in outstanding letters of credit.

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 U.S. and we are focused on maximizing the value of our land, mineral and technical resources for decarbonization by developing Carbon Capture and Sequestration (CCS) and other emissions reducing projects. For more information about CRC, please visit www.crc.com.

Forward-Looking Statements

The information included herein contains forward-looking statements that involve risks and uncertainties that could materially affect CRC's expected results of operations, liquidity, cash flows and business prospects. Such statements include those regarding CRC's expectations as to its future:

* 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 * energy transition initiatives

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 make them in good faith, they almost always vary from actual results, sometimes materially. CRC also believes third-party statements it cites are accurate but have not independently verified them and do not warrant their accuracy or completeness. Factors (but not necessarily all the factors) that could cause results to differ include:

* CRC's ability to execute its business plan post-emergence * 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 CRC's 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 * 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 CRC products * 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 * production-sharing contracts' effects on production and unit operating costs * 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 * 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 * CRC's ability to recognize the benefits of business strategies and initiatives related to energy transition, including carbon capture and sequestration projects and other renewable energy efforts * factors discussed in Item 1A, Risk Factors in CRC's Annual Report on Form 10-K 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 we undertake 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.

Attachment 1

SUMMARY OF RESULTS



Successor Predecessor Successor Predecessor

2nd 2nd Quarter Six Six Months Quarter Months

($ and shares inmillions, except per 2021 2020 2021 2020share amounts)



Statements of Operations:

Revenues

Oil, natural gas and $ 478 $ 245 $ 910 $ 675 NGL sales

Net derivative (loss)gain from commodity (265 ) (4 ) (478 ) 75 contracts

Other revenue

Trading revenue 48 14 146 59

Electricity sales 33 19 66 32

Other 10 2 23 8

Total revenues 304 276 667 849



Costs

Operating costs 169 127 333 319

General andadministrative 48 69 96 129 expenses

Depreciation,depletion and 54 88 106 207 amortization

Asset impairments - - 3 1,736

Taxes other than on 37 38 77 79 income

Exploration expense 2 2 4 7

Other expenses, net

Trading costs 30 8 91 32

Electricity cost of 17 14 41 30 sales

Transportation costs 14 8 26 21

Other 23 37 53 53

Total costs 394 391 830 2,613



Operating Loss (90 ) (115 ) (163 ) (1,764 )



Non-Operating (Loss) Income

Reorganization items, (2 ) - (4 ) - net

Interest and debt (13 ) (85 ) (26 ) (172 )expense, net

Net (loss) gain onextinguishment of - - (2 ) 5 debt

Other non-operating (2 ) (47 ) (1 ) (61 )expenses



Loss Before Income (107 ) (247 ) (196 ) (1,992 )Taxes

Income tax provision - - - -

Net Loss (107 ) (247 ) (196 ) (1,992 )

Net incomeattributable to (4 ) (24 ) (9 ) (75 )noncontrolling interests

Net Loss Attributable $ (111 ) $ (271 ) $ (205 ) $ (2,067 )to Common Stock



Net loss attributableto common stock per $ (1.34 ) $ (5.47 ) $ (2.46 ) $ (41.84 )share - basic and diluted



Adjusted net income $ 78 $ (202 ) $ 180 $ (210 )(loss)

Adjusted net income(loss) per share - $ 0.94 $ (4.08 ) $ 2.16 $ (4.25 )basic

Adjusted net income(loss) per share - $ 0.94 $ (4.08 ) $ 2.15 $ (4.25 )diluted



Weighted-averagecommon shares 83.1 49.5 83.2 49.4 outstanding - basic

Weighted-averagecommon shares 83.4 49.5 83.7 49.4 outstanding - diluted



Adjusted EBITDAX $ 169 $ 19 $ 358 $ 270

Effective tax rate 0 % 0 % 0 % 0 %

Successor

Predecessor

Successor

Predecessor

2nd Qtr.

2nd Qtr.

Six Months

Six Months

($ in millions)

2021

2020

2021

2020

Cash Flow Data:

Net cash provided (used) by operating activities

$

127

$

(135

)

$

274

$

93

Net cash used by investing activities

$

(43

)

$

(15

)

$

(63

)

$

(27

)

Net cash (used) provided by financing activities

$

(63

)

$

199

$

(88

)

$

43

Successor Predecessor Successor Predecessor

2nd Qtr. 2nd Qtr. Six Six Months Months

($ in millions) 2021 2020 2021 2020

Cash Flow Data:

Net cash provided (used) $ 127 $ (135 ) $ 274 $ 93 by operating activities

Net cash used by $ (43 ) $ (15 ) $ (63 ) $ (27 )investing activities

Net cash (used) provided $ (63 ) $ 199 $ (88 ) $ 43 by financing activities

June 30,

December 31,

($ and shares in millions)

2021

2020

Selected Balance Sheet Data:

Total current assets

$

577

$

329

Property, plant and equipment, net

$

2,573

$

2,655

Total current liabilities

$

886

$

473

Long-term debt, net

$

589

$

597

Other long-term liabilities

$

850

$

822

Stockholder's Equity

$

915

$

1,182

Outstanding shares

81.9

83.3

June 30, December 31,

($ and shares in millions) 2021 2020



Selected Balance Sheet Data:

Total current assets $ 577 $ 329

Property, plant and equipment, net $ 2,573 $ 2,655

Total current liabilities $ 886 $ 473

Long-term debt, net $ 589 $ 597

Other long-term liabilities $ 850 $ 822

Stockholder's Equity $ 915 $ 1,182



Outstanding shares 81.9 83.3

DERIVATIVE GAINS AND LOSSES ON COMMODITY CONTRACTS

Successor

Predecessor

Successor

Predecessor

2nd Qtr.

2nd Qtr.

Six Months

Six Months

($ millions)

2021

2020

2021

2020

Non-cash derivative loss - excluding noncontrolling interest

$

(183

)

$

-

$

(357

)

$

(35

)

Non-cash derivative (loss) gain - noncontrolling interest

-

(9

)

-

7

Total non-cash changes

(183

)

(9

)

(357

)

(28

)

Net (payments) proceeds on settled commodity derivatives

(82

)

5

(121

)

40

Net proceeds on sale of commodity derivatives

-

-

-

63

Net derivative (loss) gain from commodity contracts

$

(265

)

$

(4

)

$

(478

)

$

75

DERIVATIVE GAINS AND LOSSES ON COMMODITY CONTRACTS



Successor Predecessor Successor Predecessor

2nd Qtr. 2nd Qtr. Six Months Six Months

($ millions) 2021 2020 2021 2020



Non-cash derivativeloss - excluding $ (183 ) $ - $ (357 ) $ (35 )noncontrolling interest

Non-cash derivative(loss) gain - - (9 ) - 7 noncontrolling interest

Total non-cash (183 ) (9 ) (357 ) (28 )changes

Net (payments)proceeds on settled (82 ) 5 (121 ) 40 commodity derivatives

Net proceeds on saleof commodity - - - 63 derivatives

Net derivative (loss)gain from commodity $ (265 ) $ (4 ) $ (478 ) $ 75 contracts



CAPITAL INVESTMENTS

Successor

Predecessor

Successor

Predecessor

2nd Qtr.

2nd Qtr.

Six Months

Six Months

($ millions)

2021

2020

2021

2020

Internally funded capital

$

50

$

3

$

77

$

33

Capital investments not included on our financial statements:

MIRA funded capital

-

(1

)

-

1

Alpine funded capital

-

8

-

97

Total capital program

$

50

$

10

$

77

$

131

CAPITAL INVESTMENTS



Successor Predecessor Successor Predecessor

2nd Qtr. 2nd Qtr. Six Six Months Months

($ millions) 2021 2020 2021 2020



Internally funded $ 50 $ 3 $ 77 $ 33capital

Capital investmentsnot included on our financial statements:

MIRA funded capital - (1 ) - 1

Alpine funded capital - 8 - 97

Total capital program $ 50 $ 10 $ 77 $ 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 our 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.

Attachment 2

NON-GAAP FINANCIAL MEASURES AND RECONCILIATIONS



To supplement the presentation of its financial results prepared in accordancewith U.S generally accepted accounting principles (GAAP), management usescertain non-GAAP measures to assess our financial condition, results ofoperations 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 arealso widely used by the industry, the investment community and our lenders.Although these are non-GAAP measures, the amounts included in the calculationswere computed in accordance with GAAP. Certain items excluded from thesenon-GAAP measures are significant components in understanding and assessing ourfinancial performance, such as our cost of capital and tax structure, as wellas the effect of acquisition and development costs of our assets. Managementbelieves that the non-GAAP measures presented, when viewed in combination withits financial and operating results prepared in accordance with GAAP, provide amore complete understanding of the factors and trends affecting the Company'sperformance. The non-GAAP measures presented herein may not be comparable toother similarly titled measures of other companies. Below are additionaldisclosures regarding each of the non-GAAP measures reported in this pressrelease, including reconciliations to their most directly comparable GAAPmeasure 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

2nd Qtr.

2nd Qtr.

Six Months

Six Months

($ millions, except per share amounts)

2021

2020

2021

2020

Net loss

$

(107

)

$

(247

)

$

(196

)

$

(1,992

)

Net income attributable to noncontrolling interests

(4

)

(24

)

(9

)

(75

)

Net loss attributable to common stock

(111

)

(271

)

(205

)

(2,067

)

Unusual, infrequent and other items:

Non-cash derivative loss from commodities, excluding noncontrolling interest

183

-

357

35

Asset impairments

-

-

3

1,736

Reorganization items, net

2

-

4

-

Chapter 11 transaction costs

-

49

-

49

Severance and termination costs

1

-

15

-

Net loss (gain) on extinguishment of debt

-

-

2

(5

)

Deficiency payment on pipeline delivery contract

-

20

-

20

Power plant maintenance

-

-

-

7

Incentive and retention award modification

-

4

-

4

Gains on asset divestitures

-

-

(2

)

Rig termination expenses

1

2

2

2

Other, net

2

(6

)

4

9

Total unusual, infrequent and other items

189

69

385

1,857

Adjusted net income (loss) attributable to common stock

$

78

$

(202

)

$

180

$

(210

)

Net loss attributable to common stock per share - diluted

$

(1.34

)

$

(5.47

)

$

(2.46

)

$

(41.84

)

Adjusted net income (loss) per share - basic

$

0.94

$

(4.08

)

$

2.16

$

(4.25

)

Adjusted net income (loss) per share - diluted

$

0.94

$

(4.08

)

$

2.15

$

(4.25

)

ADJUSTED NET INCOME (LOSS)



Adjusted net income (loss) and adjusted net income (loss) per share arenon-GAAP measures. We define adjusted net income as net income excluding theeffects of significant transactions and events that affect earnings but varywidely and unpredictably in nature, timing and amount. These events may recur,even across successive reporting periods. Management believes these non-GAAPmeasures provide useful information to the industry and the investmentcommunity interested in comparing our financial performance between periods.Reported earnings are considered representative of management's performanceover the long term. Adjusted net income (loss) is not considered to be analternative to net income (loss) reported in accordance with GAAP. Thefollowing table presents a reconciliation of the GAAP financial measure of netincome (loss) and net income (loss) attributable to common stock per share tothe non-GAAP financial measure of adjusted net income (loss) and adjusted netincome (loss) per share.



Successor Predecessor Successor Predecessor

2nd Qtr. 2nd Qtr. Six Six Months Months

($ millions, except 2021 2020 2021 2020per share amounts)

Net loss $ (107 ) $ (247 ) $ (196 ) $ (1,992 )

Net incomeattributable to (4 ) (24 ) (9 ) (75 )noncontrolling interests

Net loss attributable (111 ) (271 ) (205 ) (2,067 )to common stock

Unusual, infrequent and other items:

Non-cash derivativeloss fromcommodities, 183 - 357 35 excluding noncontrollinginterest

Asset impairments - - 3 1,736

Reorganization items, 2 - 4 - net

Chapter 11 - 49 - 49 transaction costs

Severance and 1 - 15 - termination costs

Net loss (gain) onextinguishment of - - 2 (5 )debt

Deficiency payment onpipeline delivery - 20 - 20 contract

Power plant - - - 7 maintenance

Incentive andretention award - 4 - 4 modification

Gains on asset - - (2 ) divestitures

Rig termination 1 2 2 2 expenses

Other, net 2 (6 ) 4 9

Total unusual,infrequent and other 189 69 385 1,857 items



Adjusted net income(loss) attributable $ 78 $ (202 ) $ 180 $ (210 )to common stock



Net loss attributableto common stock per $ (1.34 ) $ (5.47 ) $ (2.46 ) $ (41.84 )share - diluted

Adjusted net income(loss) per share - $ 0.94 $ (4.08 ) $ 2.16 $ (4.25 )basic

Adjusted net income(loss) per share - $ 0.94 $ (4.08 ) $ 2.15 $ (4.25 )diluted



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

2nd Quarter

2nd Quarter

Six Months

Six Months

($ millions)

2021

2020

2021

2020

Net cash provided (used) by operating activities

$

127

$

(135

)

$

274

$

93

Capital investments

(50

)

(3

)

(77

)

(33

)

Free cash flow

77

(138

)

197

60

One-time bankruptcy related fees

2

42

4

47

Free cash flow, after special items

$

79

$

(96

)

$

201

$

107

FREE CASH FLOW



Management uses free cash flow, which is defined by us as net cash provided byoperating activities less capital investments, as a measure of liquidity. Thefollowing table presents a reconciliation of our net cash provided by operatingactivities to free cash flow. We have excluded one-time costs for bankruptcyrelated fees during 2021 and 2020 as a supplemental measure of our free cashflow.



Successor Predecessor Successor Predecessor

2nd 2nd Quarter Six Six Months Quarter Months

($ millions) 2021 2020 2021 2020



Net cash provided(used) by operating $ 127 $ (135 ) $ 274 $ 93 activities

Capital investments (50 ) (3 ) (77 ) (33 )

Free cash flow 77 (138 ) 197 60

One-time bankruptcy 2 42 4 47 related fees

Free cash flow, after $ 79 $ (96 ) $ 201 $ 107 special items



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

2nd Qtr.

2nd Qtr.

Six Months

Six Months

($ millions, except per BOE amounts)

2021

2020

2021

2020

Net loss

$

(107

)

$

(247

)

$

(196

)

$

(1,992

)

Interest and debt expense, net

13

85

26

172

Depreciation, depletion and amortization

54

88

106

207

Exploration expense

2

2

4

7

Unusual, infrequent and other items (a)

189

69

385

1,857

Non-cash items

Accretion expense

13

10

26

20

Stock-settled compensation

4

2

5

4

Post-retirement medical and pension

1

1

2

2

Other non-cash items

-

9

-

(7

)

Adjusted EBITDAX

$

169

$

19

$

358

$

270

Net cash provided (used) by operating activities

$

127

$

(135

)

$

274

$

93

Cash interest

2

10

5

59

Exploration expenditures

2

2

4

7

Working capital changes

38

142

75

111

Adjusted EBITDAX

$

169

$

19

$

358

$

270

Adjusted EBITDAX per Boe

$

18.48

$

1.86

$

19.78

$

12.69

(a) See Adjusted Net Income (Loss) reconciliation.

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 thismeasure provides useful information in assessing our financial condition,results of operations and cash flows and is widely used by the industry, theinvestment community and our lenders. Although this is a non-GAAP measure, theamounts included in the calculation were computed in accordance with GAAP.Certain items excluded from this non-GAAP measure are significant components inunderstanding and assessing our financial performance, such as our cost ofcapital and tax structure, as well as depreciation, depletion and amortizationof our assets. This measure should be read in conjunction with the informationcontained in our financial statements prepared in accordance with GAAP. Aversion of Adjusted EBITDAX is a material component of certain of our financialcovenants under our Revolving Credit Facility and is provided in addition to,and not as an alternative for, income and liquidity measures calculated inaccordance with GAAP.



Successor Predecessor Successor Predecessor

2nd Qtr. 2nd Qtr. Six Months Six Months

($ millions, except 2021 2020 2021 2020per BOE amounts)

Net loss $ (107 ) $ (247 ) $ (196 ) $ (1,992 )

Interest and debt 13 85 26 172 expense, net

Depreciation,depletion and 54 88 106 207 amortization

Exploration expense 2 2 4 7

Unusual, infrequent 189 69 385 1,857 and other items ^(a)

Non-cash items

Accretion expense 13 10 26 20

Stock-settled 4 2 5 4 compensation

Post-retirement 1 1 2 2 medical and pension

Other non-cash items - 9 - (7 )

Adjusted EBITDAX $ 169 $ 19 $ 358 $ 270



Net cash provided(used) by operating $ 127 $ (135 ) $ 274 $ 93 activities

Cash interest 2 10 5 59

Exploration 2 2 4 7 expenditures

Working capital 38 142 75 111 changes

Adjusted EBITDAX $ 169 $ 19 $ 358 $ 270



Adjusted EBITDAX per $ 18.48 $ 1.86 $ 19.78 $ 12.69 Boe



(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 and cash interest, 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

2nd Quarter

2nd Quarter

Six Months

Six Months

($ millions)

2021

2020

2021

2020

Adjusted EBITDAX

$

169

$

19

$

358

$

270

Cash interest

(2

)

(10

)

(5

)

(59

)

Distributions paid to noncontrolling interest holders:

BSP

(17

)

(5

)

(31

)

(29

)

Ares

-

(19

)

-

(39

)

Asset retirement obligations and idle well testing

(12

)

(2

)

(24

)

(6

)

Discretionary cash flow

$

138

$

(17

)

$

298

$

137

DISCRETIONARY CASH FLOW



We define discretionary cash flow as the cash available after distributions tononcontrolling interest holders and cash interest, excluding the effect ofworking capital changes but before our internal capital investment. Managementuses discretionary cash flow as a measure of the availability of cash to reducedebt or fund investments.



Successor Predecessor Successor Predecessor

2nd 2nd Quarter Six Six Months Quarter Months

($ millions) 2021 2020 2021 2020

Adjusted EBITDAX $ 169 $ 19 $ 358 $ 270

Cash interest (2 ) (10 ) (5 ) (59 )

Distributions paid tononcontrolling interest holders:

BSP (17 ) (5 ) (31 ) (29 )

Ares - (19 ) - (39 )

Asset retirementobligations and idle (12 ) (2 ) (24 ) (6 )well testing



Discretionary cash $ 138 $ (17 ) $ 298 $ 137 flow



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

Six Months

4th Quarter

($ millions)

2021

2020

2021

2020

Total revenues

$

304

$

276

$

667

$

849

Non-cash derivative loss

183

9

357

28

Revenues, excluding non-cash derivative gains and losses

$

487

$

285

$

1,024

$

877

Adjusted EBITDAX margin

35

%

7

%

35

%

31

%

ADJUSTED EBITDAX MARGIN



Management uses adjusted EBITDAX margin as a measure of profitability betweenperiods and this measure is generally used by analysts for comparative purposeswithin the industry. Adjusted EBITDAX margin is calculated as adjusted EBITDAXdivided by Revenues, excluding non-cash derivative gains and losses.



Successor Predecessor Successor Predecessor

2nd 2nd Quarter Six 4th Quarter Quarter Months

($ millions) 2021 2020 2021 2020

Total revenues $ 304 $ 276 $ 667 $ 849

Non-cash derivative 183 9 357 28 loss

Revenues, excludingnon-cash derivative $ 487 $ 285 $ 1,024 $ 877 gains and losses

Adjusted EBITDAX 35 % 7 % 35 % 31 %margin



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

2nd Quarter

2nd Quarter

Six Months

Six Months

($ per Boe)

2021

2020

2021

2020

Energy operating costs (a)

$

4.70

$

3.51

$

4.70

$

3.61

Gas processing costs

0.66

0.46

0.60

0.57

Non-energy operating costs (b)

13.12

8.45

13.10

10.81

Operating costs

$

18.48

$

12.42

$

18.40

$

14.99

Excess costs attributable to PSC-type contracts

(1.73

)

(0.42

)

(1.66

)

(0.66

)

Operating costs, excluding effects of PSC-type contracts

$

16.75

$

12.00

$

16.74

$

14.33

(a) - Energy operating costs include purchases of fuel gas and electricity used in our operations and internal costs to produce electricity used in our fields.

(b) - Non-energy operating costs equal total operating costs less energy operating costs and gas processing costs.

OPERATING COSTS PER BOE



The reporting of our PSC-type contracts creates a difference between reportedoperating costs, which are for the full field, and reported volumes, which areonly our net share, inflating the per barrel operating costs. The followingtable presents operating costs after adjusting for the excess costsattributable to PSC-type contracts.



Successor Predecessor Successor Predecessor

2nd 2nd Quarter Six Six Months Quarter Months

($ per Boe) 2021 2020 2021 2020

Energy operating $ 4.70 $ 3.51 $ 4.70 $ 3.61 costs ^(a)

Gas processing costs 0.66 0.46 0.60 0.57

Non-energy operating 13.12 8.45 13.10 10.81 costs ^(b)

Operating costs $ 18.48 $ 12.42 $ 18.40 $ 14.99

Excess costsattributable to (1.73 ) (0.42 ) (1.66 ) (0.66 )PSC-type contracts

Operating costs,excluding effects of $ 16.75 $ 12.00 $ 16.74 $ 14.33 PSC-type contracts



(a) - Energy operating costs include purchases of fuel gas and electricity usedin our operations and internal costs to produce electricity used in our fields.

(b) - Non-energy operating costs equal total operating costs less energyoperating costs and gas processing costs.

Attachment 3

PRODUCTION STATISTICS

Successor

Predecessor

Successor

Predecessor

Net

2nd Quarter

2nd Quarter

Six Months

Six Months

Oil, NGLs and Natural Gas Production Per Day

2021

2020

2021

2020

Oil (MBbl/d)

San Joaquin Basin

39

41

38

44

Los Angeles Basin

19

27

20

26

Ventura Basin

3

2

2

3

Total

61

70

60

73

NGLs (MBbl/d)

San Joaquin Basin

13

13

12

14

Ventura Basin

-

-

1

-

Total

13

13

13

14

Natural Gas (MMcf/d)

San Joaquin Basin

135

148

135

151

Los Angeles Basin

1

2

1

2

Ventura Basin

5

3

5

4

Sacramento Basin

20

21

20

22

Total

161

174

161

179

Total Production (MBoe/d)

101

112

100

117

Successor

Predecessor

Successor

Predecessor

Gross Operated and Net Non-Operated

2nd Quarter

2nd Quarter

Six Months

Six Months

Oil, NGLs and Natural Gas Production Per Day

2021

2020

2021

2020

Oil (MBbl/d)

San Joaquin Basin

45

48

45

51

Los Angeles Basin

27

30

27

31

Ventura Basin

3

2

3

3

Total

75

80

75

85

NGLs (MBbl/d)

San Joaquin Basin

14

14

12

14

Ventura Basin

-

-

1

-

Total

14

14

13

14

Natural Gas (MMcf/d)

San Joaquin Basin

144

158

144

160

Los Angeles Basin

8

9

8

9

Ventura Basin

5

3

5

5

Sacramento Basin

24

26

24

28

Total

181

196

181

202

Total Production (MBoe/d)

119

127

118

133

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 3

PRODUCTION STATISTICS

Successor Predecessor Successor Predecessor

Net 2nd 2nd Quarter Six Six Months Quarter Months

Oil, NGLs and Natural Gas 2021 2020 2021 2020Production Per Day

Oil (MBbl/d)

San Joaquin Basin 39 41 38 44

Los Angeles Basin 19 27 20 26

Ventura Basin 3 2 2 3

Total 61 70 60 73



NGLs (MBbl/d)

San Joaquin Basin 13 13 12 14

Ventura Basin - - 1 -

Total 13 13 13 14



Natural Gas (MMcf/d)

San Joaquin Basin 135 148 135 151

Los Angeles Basin 1 2 1 2

Ventura Basin 5 3 5 4

Sacramento Basin 20 21 20 22

Total 161 174 161 179



Total Production (MBoe/d) 101 112 100 117



Successor Predecessor Successor Predecessor

Gross Operated and Net 2nd 2nd Quarter Six Six MonthsNon-Operated Quarter Months

Oil, NGLs and Natural Gas 2021 2020 2021 2020Production Per Day

Oil (MBbl/d)

San Joaquin Basin 45 48 45 51

Los Angeles Basin 27 30 27 31

Ventura Basin 3 2 3 3

Total 75 80 75 85



NGLs (MBbl/d)

San Joaquin Basin 14 14 12 14

Ventura Basin - - 1 -

Total 14 14 13 14



Natural Gas (MMcf/d)

San Joaquin Basin 144 158 144 160

Los Angeles Basin 8 9 8 9

Ventura Basin 5 3 5 5

Sacramento Basin 24 26 24 28

Total 181 196 181 202



Total Production (MBoe/d) 119 127 118 133



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

2nd 2nd Quarter Six Six Months Quarter Months

2021 2020 2021 2020

Realized Prices

Oil with hedge ($/Bbl) $ 54.10 $ 30.82 $ 53.91 $ 43.76

Oil without hedge ($/ $ 68.94 $ 30.27 $ 64.89 $ 41.02 Bbl)



NGLs ($/Bbl) $ 44.90 $ 21.05 $ 46.75 $ 25.18



Natural gas ($/Mcf) $ 3.04 $ 1.65 $ 3.17 $ 1.96



Index Prices

Brent oil ($/Bbl) $ 69.02 $ 33.27 $ 65.06 $ 42.12

WTI oil ($/Bbl) $ 66.07 $ 27.85 $ 61.96 $ 37.01

NYMEX gas ($/MMBtu) $ 2.76 $ 1.77 $ 2.74 $ 1.91



Realized Prices asPercentage of Index Prices

Oil with hedge as a 78 % 93 % 83 % 104 %percentage of Brent

Oil without hedge as a 100 % 91 % 100 % 97 %percentage of Brent



Oil with hedge as a 82 % 111 % 87 % 118 %percentage of WTI

Oil without hedge as a 104 % 109 % 105 % 111 %percentage of WTI



NGLs as a percentage of 65 % 63 % 72 % 60 %Brent

NGLs as a percentage of 68 % 76 % 75 % 68 %WTI



Natural gas as a 110 % 93 % 116 % 103 %percentage of NYMEX



Attachment 5

2ND QUARTER 2021 DRILLING ACTIVITY

San Joaquin

Los Angeles

Ventura

Sacramento

Wells Drilled

Basin

Basin

Basin

Basin

Total

Development Wells

Primary

11

-

-

-

11

Waterflood

10

-

-

-

10

Total (1)

21

-

-

-

21

SIX MONTHS 2021 DRILLING ACTIVITY

San Joaquin

Los Angeles

Ventura

Sacramento

Wells Drilled

Basin

Basin

Basin

Basin

Total

Development Wells

Primary

28

-

-

-

28

Waterflood

10

-

-

-

10

Total (1)

38

-

-

-

38

(1) Includes steam injectors and drilled but uncompleted wells, which would not be included in the SEC definition of wells drilled.

Attachment 5

2ND QUARTER 2021 DRILLING ACTIVITY

San Los Ventura Sacramento Joaquin Angeles

Wells Drilled Basin Basin Basin Basin Total



Development Wells

Primary 11 - - - 11

Waterflood 10 - - - 10

Total^ (1) 21 - - - 21





SIX MONTHS 2021 DRILLING ACTIVITY

San Los Ventura Sacramento Joaquin Angeles

Wells Drilled Basin Basin Basin Basin Total



Development Wells

Primary 28 - - - 28

Waterflood 10 - - - 10

Total^ (1) 38 - - - 38



^(1) Includes steam injectors and drilled but uncompleted wells, which would not be included in the SEC definition of wells drilled.

Attachment 6

CRUDE OIL HEDGES AS OF JUNE 30, 2021

Q3 2021

Q4 2021

1Q 2022

2Q 2022

2H 2022

FY 2023

Sold Calls:

Barrels per day

36,688

37,037

35,347

35,343

28,773

14,790

Weighted-average Brent price per barrel

$50.47

$60.75

$60.37

$60.63

$59.07

$58.01

Purchased Puts:

Barrels per day

36,943

35,820

35,347

35,343

28,773

14,790

Weighted-average Brent price per barrel

$40.18

$40.19

$40.57

$41.13

$40.70

$40.00

Sold Puts:

Barrels per day

14,647

14,193

6,869

-

2,674

-

Weighted-average Brent price per barrel

$30.00

$32.00

$32.00

-

$32.00

-

Swaps:

Barrels per day

11,063

11,922

10,869

8,669

8,386

6,930

Weighted-average Brent price per barrel

$51.02

$52.61

$52.62

$51.31

$51.22

$52.15

Attachment 6

CRUDE OIL HEDGES AS OF JUNE 30, 2021



Q3 Q4 1Q 2Q 2H FY 2021 2021 2022 2022 2022 2023



Sold Calls:

Barrels per day 36,688 37,037 35,347 35,343 28,773 14,790

Weighted-average Brent $50.47 $60.75 $60.37 $60.63 $59.07 $58.01price per barrel



Purchased Puts:

Barrels per day 36,943 35,820 35,347 35,343 28,773 14,790

Weighted-average Brent $40.18 $40.19 $40.57 $41.13 $40.70 $40.00price per barrel



Sold Puts:

Barrels per day 14,647 14,193 6,869 - 2,674 -

Weighted-average Brent $30.00 $32.00 $32.00 - $32.00 -price per barrel



Swaps:

Barrels per day 11,063 11,922 10,869 8,669 8,386 6,930

Weighted-average Brent $51.02 $52.61 $52.62 $51.31 $51.22 $52.15price per barrel



Attachment 7

2021E TOTAL YEAR GUIDANCE

Total Year 2021E

Total Production (Mboe/d)

97 - 100

Oil Production (Mbbl/d)

60 - 62

Operating Costs ($ millions)

$670 - $695

General and administrative expenses ($ millions)

$180 - $190

Capital ($ millions)

$170 - $190

Adjusted EBITDAX ($ millions)

$725 - $825

Free cash flow ($ millions)

$400 - $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. For FY 2021E guidance, management is not providing guidance on income taxes or any unusual or infrequent events at this time.

Attachment 7

2021E TOTAL YEAR GUIDANCE

Total Year 2021E





Total Production (Mboe/d) 97 - 100

Oil Production (Mbbl/d) 60 - 62

Operating Costs ($ millions) $670 - $695

General and administrative expenses ($ millions) $180 - $190

Capital ($ millions) $170 - $190

Adjusted EBITDAX ($ millions) $725 - $825

Free cash flow ($ millions) $400 - $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. 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 $ 590 $ 670

Capital investments (190 ) (170 )

Estimated free cash flow $ 400 $ 500

FY 2021 Estimated

($ millions)

Low

High

Net income

$

195

$

240

Interest and debt expense, net

50

55

Depreciation, depletion and amortization

190

225

Exploration expense

5

10

Unusual, infrequent and other items

220

220

Other non-cash items

Accretion expense

50

55

Stock-settled compensation

10

15

Post-retirement medical and pension

5

5

Estimated adjusted EBITDAX

$

725

$

825

Net cash provided by operating activities

$

590

$

670

Cash interest

30

35

Exploration expenditures

5

10

Working capital changes

100

110

Estimated adjusted EBITDAX

$

725

$

825

View source version on businesswire.com: https://www.businesswire.com/news/home/20210805006123/en/

CONTACT: Joanna Park (Investor Relations) 818-661-3731 Joanna.Park@crc.com

CONTACT: Richard Venn (Media) 818-661-6014 Richard.Venn@crc.com