2Q21 Earnings Presentation

Full text

(1)“Charting a new course”. 2Q21 Earnings Presentation August 5, 2021.

(2) Mac McFarland President & CEO. Francisco Leon EVP & CFO.

(3) Forward Looking / Cautionary Statements – Certain Terms The information included herein contains forward-looking statements that involve risks and uncertainties that could materially affect our expected results of operations, liquidity, cash flows and business prospects. Such statements include those regarding our expectations as to our future: • • • • •. financial position, liquidity, cash flows and results of operations business prospects transactions and projects operating costs 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 we believe assumptions or bases underlying our expectations are reasonable and make them in good faith, they almost always vary from actual results, sometimes materially. We also believe third-party statements we cite 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: • • • • • • • • • •. our ability to execute our 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 our recent emergence from bankruptcy on our business and relationships debt limitations on our financial flexibility insufficient cash flow to fund planned investments, interest payments on our debt, debt repurchases or changes to our 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 our ability to utilize our net operating loss carryforwards to reduce our 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 our products. • • • • • • • • • • •. • • •. joint ventures and acquisitions and our 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 our 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 our 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. See the Investor Relations page at www.crc.com for additional information about 3P reserves and other hydrocarbon resource quantities, PV-10 and standardized measure, finding and development (F&D) costs, recycle ratio calculations, reserve replacement ratios, debt-adjusted shares calculations, drilling locations and reconciliations of non-GAAP measures to the closest GAAP equivalent.. 3.

(4) 2Q21 Highlights 2Q21 SNAPSHOT Continued Strong Core Financial & Operational Performance Sacramento Basin ~3,300 BOE per day. Announcing Strategic A&D Transactions San Joaquin Basin ~74,500 BOE per day + Acquired 1,600 BOE per day (~100% Oil)1. Further Optimizing Operations & Raising FCF Guidance Increasing Share Repurchase Plan (SRP) to $250 MM. CCS Est. Up to 1B MT Storage Capacity2. The New Chapter: Low Carbon Opportunities Solar Est. Up to 45 MW BTM & 300 to 1,000 MW FTM2. Ventura Basin ~3,600 BOE per day PSAs signed – Planned Divestitures (~65% oil)1,3. Other Highlights. Los Angeles Basin ~19,200 BOE per day. Strengthened ESG Commitment. Increased 2021 guidance to reflect improved returns. Sustained Operational Excellence & Safety Record. Oil 60%. 13%. 27%. NGLs. Gas. (1) Average production for the three months ending June 30, 2021. (2) Source: internal estimates; BTM represents behind-the-meter and FTM represents front-of-the-meter (3) Subject August 5, 2021 to customary closing conditions, including satisfaction of land and environmental due diligence and third-party consents. See 2Q21 10Q for additional details.. 4.

(5) Executing On Our Strategy & Delivering on Our Priorities. 1. COST & OPERATIONAL EXCELLENCE. 2. DISCIPLINED INVESTING. 3. PORTFOLIO MANAGEMENT. Prudent Investment and Prioritization of Best Projects. Efficient Operating Model. Sustained G&A and Non-Energy Cost Structure Improvements. Responsible, Value-Focused Stewardship Strategic A&D Transactions & Leading ESG Platform. Stable Asset Performance & Disciplined Capital Allocation. Strong Financial Foundation $518 MM Liquidity1 | 0.5x-0.6x 2Q21 Net Debt/Est. 2021 Adj. EBITDAX2. Raising 2021 FCF2 Guidance to $400 - $500 MM August 5, 2021. Increasing SRP to $250 Million. (1) Calculated as cash of $151 million and $492 million capacity on CRC’s Revolving Credit Facility less $125 million in outstanding letters of credit. (2) Adj. EBITDAX, Net Debt and Free Cash Flow are non-GAAP measures. For all historical non-GAAP financial measures please see the Investor Relations page at www.crc.com for a reconciliation to the closest GAAP measure and other additional information. Reconciliations of 2021E Adj. EBITDAX, Net Debt and Free Cash Flow to their nearest GAAP equivalent can be found in the Supplemental Materials on slides 26 - 27.. 5.

(6) Positioning for the Future CO2. CARBON OPPORTUNITIES. Up to 1 BMT of Potential CO2 Permanent Storage Capacity for CRC Strategically Placed Infrastructure Across CA Opportunity to Participate in Full CCS Value Chain. Carbon TerraVault I: New ~40 MMT of Total Est. CO2 Permanent Storage Project1 Filed for up to 10 MMT Class VI EPA Well Permit for Sequestration in A1 & A2 Reservoir | Preparing to File for up to 30 MMT Class VI EPA Well Permit for Sequestration in 26R Reservoir | Started 45Q and LCFS3 Certification. SOLAR OPPORTUNITIES. 300 to 1,000 MW Solar Opportunity Front-of-the-Meter Solar for Grid Supply 3 Projects Identified | 5,000 Acres Suitable for Utility Scale Development Interconnection Request Submitted for 3 Sites to CAISO. Up to 45 MW Solar Photovoltaic2 Behind-the-Meter Solar Potential at Five Fields Located in San Joaquin and LA Basins Qualifying LCFS Pathway3 | SunPower as a Development Partner. Committed to ESG Advancement Sustainability Committee chaired by William B. Roby, with members Nicole Neeman Brady and Andrew B. Bremner Dedicated corporate division under the executive leadership of Chris Gould as EVP and Chief Sustainability Officer August 5, 2021. Source: Internal estimates Note: BMT represents billion metric tons and MMT represents million metric tons. (1) Injects 1 MMT of CO2/yr. sequestration for 40 years, assumes LCFS eligible emissions. (2) Represents identified opportunities with SunPower. (3) The “Low Carbon Fuel Standard” LCFS is designed to decrease the carbon intensity of California's transportation fuel pool.. 6.

(7) STEWARDING OUR RETURNS-FOCUSED BUSINESS MODEL.

(8) Continued Operational Excellence Second Quarter 2021. First Half 2021. PRODUCTION. PRODUCTION. 101 Mboe/d. 100 Mboe/d. 60% Oil. 60% Oil. OPERATIONS. OPERATIONS. 21 Drilled1 21 Online | 48 Workover Wells 2 Drilling | 35 Maintenance Rigs. 38 Drilled1 36 Online | 88 Workover Wells 2 Drilling | 33 Maintenance Rigs. HSE. HSE. 0.00 LTIR2 | 0.00 Employee IIR3. 0.00 LTIR2 | 0.00 Employee IIR3. No Major Incidents. No Major Incidents. (1) Please see Attachment 5 in the 2Q21 Earnings Release for additional details on CRC’s drilling activity. (2) LTIR: Lost Time Injury Rate applies to CRC employees only. (3) CRC’s employee IIR August 5, 2021 applies to CRC employees while working on our operations.. 8.

(9) Emphasizing CRC’s Asset Quality. 6-Month Program Highlights (avg. per well) Mount Poso. 2021 YTD DEVELOPMENT PERFORMANCE:. Wells Drilled & Completed. ▪ 2 rigs running in San Joaquin basin during Q2 ▪ Focused on shallow, high margin oil projects in the Mt. Poso, Elk Hills, and Buena Vista fields.. TMD (ft.). 22 2,630. Peak IP1(boepd) Estimated IRR2 (%). 90 146%. Elk Hills (ESOZ) Wells Drilled & Completed TMD (ft.). 1 4,790. Peak IP1 (boepd) Estimated IRR2 (%). 128 122%. Buena Vista Wells Drilled & Completed TMD (ft.). 13 5,895. Peak IP1 (boepd) Estimated. IRR2. (%). 47 97%. Third Rig Program Forecast (avg. per well)3 Long Beach Wells to be Drilled. ▪ CRC has invested in 88 capital workovers across multiple fields at an average cost of ~$180k per job, resulting in an average rate of ~20 boepd per workover and estimated returns >200%. TMD (ft.) Peak. IP1. 9 5,000. (boepd). 72. IRR2. 60%. Estimated. (%). Note: TMD represents total measured depth (1): Peak IP rate defined as highest production achieved during first 90 days of production (2): IRR calculated using actual prices YTD, $70 Brent for the remainder of 2021, $65 Brent for 2022 onward and $3.00 NYMEX (3): Drilling rig expected to start sometime in the fall of 2021. 9.

(10) CRC Price Realizations Remained Strong in CA’s Improving Market Dynamics ▪ Realized oil prices increased due to stronger Brent pricing and an almost full return to pre-COVID market conditions.. CALIFORNIA IS AN ENERGY ISLAND AND THE LARGEST U.S. GDP CONTRIBUTOR. ▪ Realized natural gas prices remained strong relative to NYMEX however they were weaker relative to Q1 due to milder weather and limited injection capacity at SoCalGas. 8.0% 4.1%. ▪ NGL realizations took their typical seasonal dip in 2Q from 1Q as gains in crude outpaced NGL’s and winter premiums rolled off pricing. 14.7%. Expecting NGLs pricing to strengthen on a relative basis through the 2H21. 5.2%. $53.73. 8.5%. $54.10 $48.77. $42.15. $44.39 $35.45. $30.82 $21.05. 2Q20. Note: 5 largest contributors to domestic GDP Source: BEA, Data from 1Q21; EIA. $44.90. 3Q20. 4Q20. 1Q21. 2Q21. 2Q20. $25.16. 3Q20. 4Q20. 1Q21. 2Q21. $1.65. $2.22. 2Q20. 3Q20. NGLs ($/Bbl). Oil w/ Hedges ($/Bbl). $3.03. $3.29. $3.04. 4Q20. 1Q21. 2Q21. Natural Gas ($/Mcf). Brent/NYMEX. $33.27. $43.37. $45.24. $61.10. $69.02. $33.27. $43.37. $45.24. $61.10. $69.02. $1.77. $1.93. $2.66. $2.72. $2.76. Differential. ($3.00). ($1.54). ($1.30). ($0.29). ($0.08). ($12.22). ($18.21). ($9.79). ($12.33). ($24.12). ($0.12). $0.29. $0.37. $0.57. $0.28. Hedge Impact. $0.55. $0.32. $0.45. ($7.08). ($14.84). -. -. -. -. -. -. -. -. -. -. Realized Prices. $30.82. $42.15. $44.39. $53.73. $54.10. $21.05. $25.16. $35.45. $48.77. $44.90. $1.65. $2.22. $3.03. $3.29. $3.04. August 5, 2021. 10.

(11) Second Quarter 2021 Highlights REDUCED MAINTENANCE SPENDING 2Q201 Predecessor. 1Q211 Successor. 2Q211 Successor. Energy operating costs2 ($/Boe). $3.51. $4.70. $4.70. Gas processing costs ($/Boe). $0.46. $0.53. $0.66. Non-energy operating costs2 ($/Boe). $8.45. $13.10. $13.12. $12.42. $18.33. $18.48. Energy operating costs, excluding effects of PSC-type contracts2,3 ($/Boe). $3.34. $4.14. $4.07. Gas processing costs ($/Boe). $0.46. $0.53. $0.66. Non-energy operating costs, excluding effects of PSC-type contracts2,3 ($/Boe). $8.20. $12.05. $12.02. Operating costs, excluding effects of PSC-type contracts3 ($/Boe). $12.00. $16.72. $16.75. G&A ($/boe). $6.75. $5.36. $5.25. Taxes other than on income ($/boe). $3.72. $4.47. $4.05. Interest expense, net ($/boe). $8.31. $1.45. $1.42. Transportation costs ($/boe). $0.78. $1.34. $1.53. RETAINING COST FOCUS TO ENABLE MARGIN EXPANSION. Costs ($/boe). $50. $54.10. $53.73. $50. $44.39. $40 $30. $60. $40 $30.95. $29.14. $30.73 $30. $20. $20. $10. $10. $0. 4Q20 Non-GAAP (Combined) 1 Full OPS Cost. 4. 1Q21 Successor G&A. 1. 2Q21 Successor 1 Interest. $0. Realized. Realized Oil Price w Hedge ($/bbl). $60. PRUDENT MAINTENANCE SPENDING. Operating costs ($/Boe). (1) Periods subsequent to October 31, 2020 (Successor period) and ending on or prior to October 31, 2020 (Predecessor period) are distinct reporting periods as a result of the adoption of fresh start accounting upon emergence from Chapter 11 bankruptcy and as such, 1Q21 and 2Q21 are not comparable to prior periods. For further information, consult the 2020 10K, Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Fresh Start Accounting. (2) Energy operating costs consist of purchases of fuel gas used to generate electricity, purchased electricity and internal costs to produce electricity used in our operations. 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. (3) Represent non-GAAP measures. For all historical non-GAAP financial measures, please see the Investor Relations page at www.crc.com for a reconciliation to the closest GAAP measure and other additional information. (4) Full OPS cost includes operating costs plus transportation costs, plus taxes other than on income. August 5, 2021. 11.

(12) Second Quarter 2021 Highlights (cont.). 1Q211 Successor. 2Q211 Successor. Net Oil Production (MBbl/d). 70. 60. 61. Total Net Production (MBoe/d). 112. 99. 101. Realized Oil Price w/ Hedge ($/Bbl). $30.82. $53.73. $54.10. Realized NGL Price ($/Bbl). $21.05. $48.77. $44.90. Realized Natural Gas Price ($/Mcf) 2. Adjusted Net (Loss) Income per Share – Diluted ($/share). $3.04. ($4.08). $1.22. $0.94. $19. $189. $169. ($135). $147. $127. $3. $27. $50. 40. 40. 20. 0. 0 4Q20 Exit Rate Non-GAAP (Combined) 1 Gas. 1Q21 Successor1. NGL. Oil. 2Q21 Successor 1. Wells Drilled 3. $120. $77. Strong 1H21 with ~ $200 MM in FCF 2 2Q21 FCF reflects increased CAPEX to more normalized rate and 1H21 property tax payments. $150. 35% 27%. 30%. $100 $50. 40%. 35%. $189. 20%. $169. $116. 10%. $0. Adj. EBITDAX Margin2. ($138). $200. Adj. EBITDAX2 ($MM). Cash (Used in) Provided by Operating Activities ($MM). Free Cash Flow2 ($MM). $3.29. 80. ASSET PERFORMANCE SUPPORTS EARNINGS POWER. Adjusted EBITDAX2 ($MM). Internally Funded Capital Investments ($MM). $1.65. 60. MBOEPD. 2Q201 Predecessor. 120. Wells Drilled. MAINTAINING PRODUCTION WITH LIMITED DRILLING ACTIVITY DUE TO STRONG MAINTENANCE OPPORTUNITIES. 0% 4Q20 Non-GAAP 1 (Combined) Adj. EBITDAX 2. 1Q21 1 Successor. 2Q21 1 Successor 2. Adj. EBITDAX Margin. (1) Periods subsequent to October 31, 2020 (Successor period) and ending on or prior to October 31, 2020 (Predecessor period) are distinct reporting periods as a result of the adoption of fresh start accounting upon emergence. August 5, 2021 from Chapter 11 bankruptcy and as such, 1Q21 and 2Q21 are not comparable to prior periods. For further information, consult the 2020 10K, Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Fresh Start Accounting. (2) Free Cash Flow, Adj. Net Income, Adj. EBITDAX and Adj. EBITDAX Margin are non-GAAP measures. For all historical non-GAAP financial measures, please see the Investor Relations page at www.crc.com for a reconciliation to the closest GAAP measure and other additional information. (3) No wells were drilled in 4Q20.. 12.

(13) Raising the Bar on Guidance & Improving Shareholder Returns CRC IS NET LONG IN NATURAL GAS. FY 2021E1. FY 2021E1. Total Production (Mboepd)2. 96 – 99. 97 - 100. Oil Production (Mbopd)2. 60 – 62. Reaffirmed. Operating Costs ($MM) Capital Spend ($MM) Operating and Capital Needs ($MM) G&A ($MM). $615 - $630. $670 - 695. $17.01 - $17.98 $/boe. $18.36 - $19.63 $/boe. $185 - $210. $170 - $190. $5.12 - $5.42 $/boe. $4.66 - $5.37 $/boe. $800 - $840. $840 - $885. $180 - $190. Reaffirmed. $4.98 - $5.42 $/boe. Adjusted EBITDAX3 ($MM). $625 - $725. $725 - $825. $17.84 - $20.06. $19.86 – $23.30 $/boe. Free Cash Flow 3 ($MM). $250 - $350. $400 - $500. Free Cash Flow Yield3,5. 11% - 15%. 17% - 22%. Bcf/year. 0. ADJUSTING $35 MM FOR INCREASE IN NATURAL GAS PRICES. SHIFTING $20 MM FROM CAPITAL TO OPEX FOR HIGHER IRR WELL WORK. 10. 20. 30. Internal Consumption. 40 4. 50. 60. Total Sales. $600. 25%. $500. 20%. $400. 15%. $300 10%. $200. 5%. $100 $0. 0% $60 Brent. $70 Brent. $80 Brent Free Cash Flow Yield. August 5, 2021. FREE CASH FLOW YIELD3,5 (%). REVISED GUIDANCE. FREE CASH FLOW3 ($MM). PRIOR GUIDANCE. 3,5. (1) 2021E prior guidance used $60 per barrel Brent pricing, $38.75 per barrel for NGLs and $2.75 per mcf NYMEX gas. Revised guidance assumes strip pricing as of June 30, 2021. (2) 2021E Production range subject to PSC effects. (3) Represent non-GAAP figures. Adj. EBITDAX and Free Cash Flow are non-GAAP measures. For all historical non-GAAP financial measures please see the Investor Relations page at www.crc.com for a reconciliation to the closest GAAP measure and other additional information. Reconciliations of 2021E Adj. EBITDAX and Free Cash Flow to their nearest GAAP equivalent can be found in the Supplemental Materials on slides 26 - 27. (4) Internal consumption doesn’t include Natural Gas used to generate and sell 13 merchant power at Elk Hills Power Plant (5) FCF Yield reflects FY 2021E Free Cash Flow divided by market capitalization as of July 29, 2021, calculated using 81.879 million shares..

(14) CRC’s Low Valuation Provides Equity Upside: Increasing SRP to $250MM CURRENT OIL PRICING OFFERS ROBUST UPSIDE. MULTIPLES COMPARED TO PEERS1 SHOW STRONG INVESTMENT OPPORTUNITY. 2021 FCF Yield3 (%). 30%. High FCF / Low Leverage. PV-10 Reserves Value3 and Metrics At SEC Price Deck and $60 Brent. High FCF / High Leverage. 25% CRC2. 20% 15%. $2,426 MM3,4. 10% 5% Low FCF / Low Leverage. 0% -0.5x. 0.0x. 0.5x. 3.0x. 3.5x. Consensus 2021 EV / EBITDA2,6,7. SEC 2020 Price Deck4 442 MMboe. 7.0x. Total Proved Reserves / 2020 Exit Production. 6.0x. ~10% PUD. ~96% of PV-101 from Core Fields6 ~90% PDP. Low FCF / High Leverage. 1.0x 1.5x 2.0x 2.5x Consensus 2021 ND/EBITDA3. $5,720 MM5. 5.0x. PV-103 ($MM). 4.0x. PV-103. / 2Q21 Net. Debt3. ($). $60 Brent5 509 MMboe. SEC Price Deck4. $60 Brent5. 11.8 years. 13.6 years. $2,426. $5,720. 5.4x. 12.7x. 3.0x. 2Q21 Net. $1.02. $0.88. 2.0x. EV7/Total Proved Reserves ($/boe). $6.27. $5.44. PV-101 /Total Proved Reserves ($/boe). $5.49. $11.24. 1.1x. 0.5x. 1.0x. 15. 14. CRC. 13. 12. 11. 10. 9. 8. 7. 6. 5. Avg.. 4. 3. 2. 1. 0.0x. Debt3. EV7/PV-101. ($). / Total Proved Reserves ($/boe). (1) Peers consist of AR, BRY, COG, CPE, CRK, KOS, MGY, MTDR, MUR, PDCE, RRC, SM, SWN, VET, XEC. Source FactSet as of July 29, 2021. (2) CRC 2021 estimated Free Cash Flow and Adj. EBITDAX are based on 2021 guidance. Net Debt is estimated as of December 31, 2021 and is prior to share repurchases in 2H21. Please see slides 16, 18, 26 and 27 for more details. (3) PV-10 is as of December 31, 2020. Reflects non-GAAP measures. For all historical non-GAAP financial measures please see the Investor Relations page at www.crc.com for a reconciliation to the closest GAAP measure and other additional information. Please see appendix slides 26 through 27 for information on 2021 estimated measures. Free Cash Flow Yield is calculated as FY 2021E Free Cash Flow over market capitalization as of July 29, 2021. CRC market capitalization is calculated using 81.879 million shares. (4) Represents FY2020 Reserves at SEC prices as of December 31, 2020 and reflects average realized pricing of $42.35 per barrel for oil, $26.42 per barrel for NGLs and $2.28 per Mcf for natural gas. (5) Index prices used to estimate our PV-10 of proved reserves were $60 per barrel for oil, $38.75 per barrel of NGLs and $2.50 per Mcf for natural gas. GAAP does not prescribe a standardized measure of reserves on a basis other than SEC pricing. As such, no standardized measure of our PV-10 of proved reserves using $60 per barrel for oil, $38.75 per barrel of NGLs and $2.50 per Mcf for natural gas has been provided (6) See Strategy Day presentation (slide 14) for core field description which is available at crc.com. (7) Enterprise Value estimated as of July 29, 2021. CRC’s EV reflects market capitalization using 81.879 million shares plus $449 million of Net Debt.. August 5, 2021. 14.

(15) Value Through Core A&D Transactions BOLT-OFF THROUGH VENTURA BASIN EXIT. BOLT-ON ACQUISITON IN OUR CORE ASSET. ▪ Signed PSAs for a full basin divestiture1. ▪ Purchase of MIRA’s2 Working Interest. ▪ Removes high-cost fields. ▪ Simplifies business model and high grades barrel produced. ▪ Simplifies CRC’s operations into three basins. ▪ Valuation reflects core location, minimal integration and execution risk. ▪ ▪ ▪. 3.6 mboepd (~65% oil)3 Highest cost barrels at CRC $102 MM total consideration1. ▪ ▪. 1.6 mboepd (~100% oil)3 Includes producing wells in Mount Poso, Kern Front and Pleito Ranch $53 MM Cash. ▪. Simplifies Business Model Streamlines Cost Structure Improves Operational Efficiencies Note: 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. (1) Subject to customary closing conditions, August 5, 2021 including satisfaction of land and environmental due diligence and third-party consents. See 2Q21 10Q for additional details. (2) Macquarie Infrastructure and Real Assets (3) Average production 15 for the three months ending June 30..

(16) Maintaining Balance Sheet Strength, Liquidity, and Financial Flexibility ESTIMATED LIQUIDITY ROLL FORWARD1. 6/30/21 DEBT SNAPSHOT. $1,000 ~$770 MM. ($ in millions). $ Millions. $800 $600. Revolving Credit Facility (RCF) ~$250 MM. $. 0. 7.125% Senior Notes. $518 MM. 600. Face Value of Debt. $. Less Available Cash. $400. 600 (151). Net Debt. $. 449. $200 $0. 6/30/21 Liquidity. 3Q21-4Q21E Increase in Available Cash. 12/31/2021 Estimated YE Liquidity. NO SIGNIFICANT MATURITIES UNTIL 2026. MULTIPLES DEMONSTRATE FLEXIBILITY. $ Millions. $800. ($ in millions). $600. Undrawn3. RCF Borrowing Base. $400 $200 $0. $. 2021E Free Cash Flow2. YE 2021E Net Debt1,2 / 2021E Adjusted EBITDAX2 6/30/21 Liquidity. 2022. 6/30/2021 Revolver Availability. 2023 Cash. 2024. 2025. Revolver Availability at Maturity. 2026. 2021E Adjusted. EBITDAX2. 1,200. $400 – $500. / 2021E Interest Expense. 0.2x – 0.3x 13.2x – 16.5x. Senior Notes. (1) Prior to share repurchases. Liquidity at 6/30/21 calculated as cash of $151 million and $492 million capacity on CRC’s Revolving Credit Facility less $125 million in outstanding letters of credit. Estimated YE 2021 liquidity is calculated using cash as of 6/30/21 plus the midpoint of Free Cash Flow guidance less 1H21 free cash flow of ~$200 million and $492 million capacity on CRC’s Revolving Credit Facility less $125 million in outstanding letters of credit. 3Q21 to 4Q21 estimated increase in available cash reflects revised Free Cash Flow guidance less 1H21 free cash flow of ~$200 million. (2) Adj. EBITDAX, Net Debt and Free Cash Flow are non-GAAP measures. For all historical non-GAAP financial measures please see the Investor Relations page at www.crc.com for a reconciliation to the closest GAAP measure and other additional information. Reconciliations of 2021E Adj. EBITDAX, Net Debt and Free Cash Flow to their nearest GAAP equivalent can be found in the Supplemental Materials on slides 26 - 27. (3) Undrawn revolver as of June 30, 2021.. August 5, 2021. 16.

(17) Hedging Program Protects Cash Flow OIL HEDGE PROTECTION1 as of June 30, 2021. SOLD CALLS. STRATEGY ▪ CRC hedging strategy typically utilizes a mixture of Puts, Collars and Swaps to protect cash flow and to ensure CRC’s ability to live within cash flow, and is also aligned with CRC’s RBL requirements. PURCHASED PUTS. SOLD PUTS. HEDGE CONTRACT SETTLEMENTS EXPECTED TO SIGNIFICANTLY DECREASE IN 2022 & 2023 Hedge Contract Settlements2 ($MM). 1Q21. 2Q21. 3Q21E. 4Q21E. 2021E. 1H22E. 2H22E. 2022E. 2023E. ($39). ($82). ($105). ($64). ($290). ($96). ($75). ($171). ($72). SWAPS. August 5, 2021. 3Q21. 4Q21. 1Q22. 2Q22. 2H22. FY23. Barrels per Day. 36,688. 37,037. 35,347. 35,343. 28,773. 14,790. WeightedAverage Price per Barrel. $50.47. $60.75. $60.37. $60.63. $59.07. $58.01. Barrels per Day. 36,943. 35,820. 35,347. 35,343. 28,773. 14,790. WeightedAverage Price per Barrel. $40.18. $40.19. $40.57. $41.13. $40.70. $40.00. Barrels per Day. 14,647. 14,193. 6,869. -. 2,674. -. WeightedAverage Price per Barrel. $30.00. $32.00. $32.00. -. $32.00. -. Barrels per Day. 11,063. 11,922. 10,869. 8,669. 8,386. 6,930. WeightedAverage Price per Barrel. $51.02. $52.61. $52.62. $51.31. $51.22. $52.15. (1) Hedges are based on weighted-average Brent prices per barrel. (2) Represents estimated net cash settlement payments for derivative contracts as of 6/30/2021, except 1Q21 & 2Q21 which are actuals for the three months ended March 31, 2021 and June 30, 2021, respectively.. 17.

(18) Hedging Program Changes Since April 30, 2021. 3Q 2021. 4Q 2021. 1Q 2022. 2Q 2022. 3Q 2022. 4Q 2022. FY 2023. August 5, 2021. Downside Protection (Swaps + Purchased Puts). Ceiling (Sold Calls). Barrels per Day. 1,326. 326. Weighted Avg. Price per Barrel. $67.91. $67.95. Barrels per Day. 1,337. 337. Weighted Avg. Price per Barrel. $66.68. $66.00. Barrels per Day. 3,000. 1,000. Weighted Avg. Price per Barrel. $65.07. $73.06. Barrels per Day. 4,000. 2,000. Weighted Avg. Price per Barrel. $63.26. $71.15. Barrels per Day. 3,000. 1,000. Weighted Avg. Price per Barrel. $65.51. $72.65. Barrels per Day. 3,000. 1,000. Weighted Avg. Price per Barrel. $63.57. $70.60. Barrels per Day. 2,000. -. Weighted Avg. Price per Barrel. $63.46. -. Note: as of June 30, 2021. 18.

(19) New Chapter : Low Carbon Opportunities. 19.

(20) Understanding California’s Full CCS Potential 5th LARGEST ECONOMY WORLDWIDE1 BIGGEST DOMESTIC GDP POWERHOUSE STATE ▪. 424 MMT of CO2 e in 20172. CCS TECHNOLOGY HAS THE POTENTIAL TO REDUCE ~ 15% OF THE CO2 EMISSIONS NEEDED FOR CA TO MEET ITS 2030 TARGET2. ~ 2 - 5 BMT3 of O&G GEOLOGICAL STORAGE POTENTIAL ACROSS CA CRC OWNS A MEANINGFUL PORTION OF THESE RESOURCES3. “ CCS enables production of low - and zero-carbon fuels, electricity, chemicals, materials, and products that transform captured carbon into economic value, sustaining and creating industries and high-paying jobs “ - Great Plains Institute, 2021. Note: BMT represents billion metric tons and MMT represents million metric tons. (1) Source: EIA (2) Source: An Action Plan for Carbon Capture and Storage in California: Opportunities, August 5, 2021 Challenges, and Solutions, a joint study by Energy Future Initiatives, Stanford Center for Carbon Storage , pg S-4 & 10; calculated as estimated CCS opportunities CO2 reductions over reductions 20 need to achieve California’s 2030 goal. (3) Source: Stanford Study, Natcarb, internal estimates.

(21) Defining CRC’s Strategic Decarbonization Advantage CA’S DEPLETED O&G RESERVOIRS PROVIDE ENORMOUS PERMANENT CARBON STORAGE POTENTIAL. ~2 – 5 BMT CO21. CRC Has Up. CALIFORNIA HAS THE MOST SUPPORTIVE REGULATORY ENVIRONMENT FOR DECARBONIZATION, INCLUDING FINANCIAL CCS INCENTIVES. to 1 BMT2 of. Estimated CO2 Storage Capacity Unparalleled Reservoir Characteristics ▪ Permanent solution in terms of depth, geological seal and reservoir characteristics ▪ Located in proximity to several longterm LCFS qualified CO2 sources. California Low Carbon Fuel Standard (LCFS). 45Q Tax Credit. Cap and Trade program. Total Potential Incentive3. ~$0-$40/MT ~$50/MT. ~$235 - $275 /MT. ~$185 /MT. CALIFORNIA INCENTIVE. FEDERAL INCENTIVE. NEEDED FOR CA’s DECARB GOAL. THE RIGHT ASSETS & THE RIGHT REGULATORY ENVIRONMENT Note: BMT represents billion metric tons and MMT represents million metric tons. (1) Source: An Action Plan for Carbon Capture and Storage in California: Opportunities, Challenges, and Solutions, a joint study by Energy. August 5, 2021 Future Initiatives, Stanford Center for Carbon Storage Natcarb, CARB – Achieving Carbon Neutrality in California page 80; internal estimates (2) internal estimates (3) LCFS - The California Air Resources Board – average pricing as of July 25, 2021; 45Q based on 2026 pricing per fas.org; Cap & Trade – Internal estimate, Cap and Trade program currently doesn’t cover CCS and could not materialize.. 21.

(22) Validating CRC’s New Chapter Est. CRC O&G RESERVOIR CCS STORAGE CAPACITY1 0. 200. Permitting & NearTerm Focus. 400. ▪. Filed for up to 10 MMT Class VI EPA well permit for sequestration in A1 & A2 reservoir. ▪. Started 45Q and LCFS certification. ▪. Preparing to file for up to 30 MMT Class VI EPA well permit for sequestration in 26R reservoir. ▪. Initiated conversations with emitters in close proximity to the project. ▪. Began engaging with regulatory agencies, investors and other important stakeholders. 600. 800. 1,000. Possible. Probable. Carbon TerraVault I: New ~40 MMT CCS Project1,2. August 5, 2021. MMT of CO2. Elk Hills CalCapture ~1.4 MMT/year CCUS Project1 ▪. FEED Study: Finalizing Owners Costs - DOE Report 3Q 2021. ▪. Preparing to file for a Class II expansion well permit. ▪. Full CO2 output 45Q eligible for EOR ($35/ton); ~1/3 eligible for LCFS. Note: BMT represents billion metric tons and MMT represents million metric tons. (1) Internal estimates (2) Internal estimates at 1.0 MMT /yr. CO 2 sequestration rate.. 22.

(23) Strengthening Solar Capability SELF SUPPLY | BEHIND THE METER: ▪. Advancing an agreement with SunPower for a 12 MW behind-the-meter solar project at Mt. Poso, expected to be LCFS eligible. ▪. Targeting up to 45 MW Solar PV installations in five fields located in San Joaquin and LA Basin with construction planned in 2022, all online estimated by 1Q-2023. ▪. Estimated cash power cost reduction by >35% at the five fields further driving margin enhancements Robust PPA, solar financing market Significant Cost Savings. Additional Cash Flow Stream. Carbon Footprint Reduction. Expecting to successfully surpass CRC’s 2030 renewables goal upon BTM project commission. Lower power costs. Reliability+ vs grid. GRID SUPPLY | FRONT OF THE METER:. Land & Ops Control. ▪. CRC has identified over 5,000 acres suitable for utility scale development presents future value for CRC and investors. ▪. Potential for 300 to 1,000 MW with core 3 projects identified. ▪. Potential to further reduce CO2 emissions while adding further commercial opportunity. August 5, 2021. Source: Internal estimates. 23.

(24) Introducing New Board Member. ▪ Appointed as a member of the Sustainability & Compensation Committees on August 5, 2021 ▪ Over 20 years of experience in strategic planning and sustainability roles. Nicole Neeman Brady Newly appointed Director Member of the Sustainability & Compensation Committees. ▪ Serves on the Boards of Directors of Sustainable Development Acquisition Corp, Blue Ocean Mariculture and the Library Foundation of Los Angeles, and is a Commissioner of the Los Angeles Department of Water and Power. “. “. ▪ Currently serves as the Chief Executive Officer and a Director of Sustainable Development Acquisition Corp.; previously served as Principal and Chief Operating Officer at Renewable Resources Group. I am excited to be joining CRC’s Board and look forward to providing oversight to its energy transition initiatives. I see great potential with CRC’s strategic position in California to further CRC’s sustainability efforts and help the state meet its decarbonization goals. – Nicole Neeman Brady, newly elected CRC BoD member. “. “. I am extremely pleased to welcome Nicole to the Board of CRC. Nicole brings extensive sustainability experience, strengthens our governance practices and further demonstrates CRC’s position as an ESG leader in the energy sector. – Tiffany (TJ) Thom Cepak, Chair of the Board. August 5, 2021. *For more information about Nicole Neeman Brady or other members of our Board of Directors, please see the Governance page on www.crc.com. 24.

(25) SUPPLEMENTAL MATERIALS.

(26) Adjusted EBITDAX Reconciliation 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.. ($ millions). Net income Interest and debt expense, net Depreciation, depletion and amortization Exploration expense Other non-cash items Estimated Adjusted EBITDAX. ($ millions). Net cash provided by operating activities Cash Interest Exploration expenditures Working capital changes Estimated Adjusted EBITDAX August 5, 2021. FY 2021 Estimated Low High $195 $240 50 55 190 225 5 10 285 295 $725 $825 FY 2021 Estimated Low High $590 $670 30 35 5 10 100 110 $725 $825. Note: Management is not providing guidance on income taxes, acquisitions or divestitures or any other unusual or infrequent events at this time.. 26.

(27) Leverage & Free Cash Flow Reconciliation Leverage and Net Debt We calculate the leverage ratio by dividing net debt by adjusted EBITDAX for the applicable period. We define net debt as the face value of our debt less available cash. We believe the leverage ratio is an important metric of the operational and financial health of our Company and is useful to investors as an indicator of our ability to incur additional debt and to service our existing debt. The following table presents a reconciliation of our leverage ratio. The leverage ratio is a supplemental measure of our performance that is not required by or presented in accordance with U.S. generally accepted accounting principles (“GAAP”).. 2Q 2021E Low. High. Face value of debt. $600. $600. Available cash. (151). (151). Net Debt as of June 30, 2021. $449. $449. 2021E Adjusted EBITDAX. $825. $725. 2Q21E Leverage Ratio. 0.5x. 0.6x. ($ in millions). FY 2021E ($ in millions). Face value of debt Estimated available. cash1. High. $600. $600. (450). (350). Estimated Net Debt as of December 31, 2021. $150. $250. 2021E Adjusted EBITDAX. $825. $725. 2021E Leverage Ratio. 0.2x. 0.3x. Free Cash Flow Management uses free cash flow, which is defined by us as net cash provided by operating activities after our internal capital investment, as a measure of liquidity. The table at right presents a reconciliation of net cash provided by operating activities to free cash flow.. Low. FY 2021E ($ in millions). Net cash provided by operating activities Capital Investment Estimated Free Cash Flow. Low $590 (190) $400. High $670 (170) $500. Note: Adj. EBITDAX and Net Debt are non-GAAP measures. For all historical non-GAAP financial measures please see the Investor Relations page at www.crc.com for a reconciliation to the closest August 5, 2021 GAAP measure and other additional information. (1) Prior to share repurchases in 2H 2021. Calculated as cash as of 6/30/21 plus revised Free Cash Flow guidance of $400 to $500 million less 27 1H21 Free Cash Flow of ~$200 million..

(28) Joanna Park (Investor Relations). Richard Venn (Media). 818-661-3731. 818-661-6014. [email protected]. [email protected].

(29)

No results found