January 2024 Investor Presentation
Table of Contents ON PACE FOR STRONG YEAR END 2023 RESULTS CARBON MANAGEMENT BUSINESS APPENDIX • CENTRAL CALIFORNIA • NORTHERN CALIFORNIA • DAC HUB
Expecting Strong Quarterly Results $40 – $60MM 4Q23E FCF1 82 – 84MBOE/D 4Q23E Total Production ~60% Oil $65 – $75MM 4Q23E Total Capital EXPECTING TO EXCEED QUARTERLY FCF1 AND TO BE IN LINE WITH PRODUCTION GUIDANCE2 ADVANCING CALIFORNIA’S LEADING CARBON MANAGEMENT BUSINESS Class VI Draft Permit EPA Released California’s First For 26R reservoir (part of CTV I storage vault) Midstream Infrastructure Carbon Capture & Storage Low Carbon Intensity Production BTM Solar Opportunities FTM/Grid Power Production Geothermal Opportunities LA Basin 1 ACTIVE DRILLING RIGS 21% 79% Announced TBA 5MMTPA YE27 CTV INJECTION RATE TARGET 200MMT YE27 CTV STORAGE CAPACITY TARGET Los Angeles Basin San Joaquin Basin Sacramento Basin Submitted to EPA TBA 191 MMT 9 MMT 3 38MMT of permitted injection capacity with an injection rate of up to ~1.5MMTPA3 ; both above type curve Started 90-day public comment period (1) Represents a non-GAAP measure. For all historical non-GAAP financial measures please see the Investor Relations page at www.crc.com for a reconciliation to the nearest GAAP equivalent and other additional information. Free cash flow is equal to net cash provided (used) by operating activities less capital investments. Reconciliation of 4Q23E non–GAAP measure to its nearest GAAP equivalent can be found on slide 52 of this deck. (2) See CRC’s 3Q23 earnings presentation for a FY23 and 4Q23 guidance. (3) See slide 12 for more information on CTV I (26R) reservoir. CRC is still preparing its reserve report for 2023, but does not currently expect to write down any reserves as a result of state regulatory or Kern County permitting matters
Preliminary 2024 E&P Business Outlook 4 CASHFLOW CALIFORNIA CARBON (1) Capacity revenue is a part of electricity revenue on CRC’s income statement. (2) Includes YE2023 reduction in non energy operating costs and Adj. E&P corporate and other G&A. (3) Internal estimates. EXPECTED INVENTORY OF SIDETRACKS, WORKOVERS, NATURAL GAS TO INCREASE ACTIVITY IN 2H24 EST. ELK HILLS PLANTS TURNAROUND IMPACT IN 1Q24 CONTRACTED CAPACITY REVENUE1 FROM EHPP TO INCREASE BY ~$45MM IN 2024 VS 2023E ON PATH TO ACHIEVE $55MM + IN TARGETED YE2023 RUN RATE REDUCTIONS2 IMPLIES ~$2/BOE REDUCTION TO CRC’S OPERATING COST3 20 MMCF/D CAPITAL $34MM LINE OF SIGHT TO WELL PERMITTING PROGRESSION IN 2024
Why California Resources Corporation? LEADING CARBON MANAGEMENT BUSINESS STRONG SHAREHOLDER RETURNS STRATEGY PREMIER BALANCE SHEET WITH STRONG FREE CASH FLOW GENERATION DISCIPLINED CAPITAL ALLOCATION
THE FOREFRONT OF CARBON MANAGEMENT
Carbon TerraVault – California’s Leading Carbon Management Platform 7 Positioned to Be California’s Premier Carbon Management Provider CALIFORNIA LEADING CARBON MANAGEMENT PLATFORM ▪ Identified up to 1BMT1 CO2 storage in California ▪ Technological expertise, large scale project management, and financial capability ▪ Largest number of Class VI CO2 sequestration permits submitted to the EPA (191 MMT submitted)2 TRUSTED AND RESPONSIBLE PARTNER TARGETING 5MMTPA OF INJECTION BY YE273 ▪ Direct path to sustainably and meaningfully advance California’s climate goals ▪ In discussions with >20 MMTPA of potential emissions and 6 CDMAs signed ▪ In partnership with Brookfield Renewable ▪ Scalable business model that drives value creation ▪ Total potential addressable California CCS market of 150 – 210 MMTPA1 ▪ Evaluating a potential standalone Carbon TerraVault entity DESIGNED FOR LONG TERM SUCCESS200MMT PERMITTED BY YE273 $250MM - $675MM IN CTV JV EBITDA4 BY YE28 GLOBAL TRANSITION FUND (“BGTF”) Note: please see slide 50 for details on the footnotes on this slide.
California Has the Largest Amount of Domestic Potential Incentives for CCS Growth CALIFORNIA LOW CARBON FUEL STANDARD (LCFS) FEDERAL 45Q TAX CREDIT Potential Economic Incentives (1) 45Q assumes wage and apprenticeship requirements are met. (2) Source: LCFS 2022 and 2023YTD average prices per MT of CO2 - The California Air Resources Board – average Type 1 transfer pricing as of August 24, 2023. 45Q assumes wage and apprenticeship requirements are met. (3) Source: CARB; California’s Cap and Trade program currently doesn’t cover CCS and requires regulatory changes to be implemented that may not materialize. Represents average auction prices for 2022 as of July 15, 2022. (4). There are currently no point source CCS projects generating CDR credits. CRC expects new CCS industry verification protocols to be available in 2024. (5) Source: Database of State Incentives for Renewables & Efficiency (DSIRE) from the N.C. Clean Energy Technology Center, 2022. $85 (2026) Value for Carbon Storage (per MT of CO2)1 $169 - $66 Trading Range for 2022 -2023 YTD (per MT of CO2)2 CALIFORNIA CAP & TRADE PROGRAM POTENTIAL Average trading price YTD is~$30 (per MT of CO2)3 Supportive Domestic Regulatory Policies5 200+ Policies or Incentives 101-200 Policies or Incentives 50-100 Policies or Incentives 50 or Less Policies or Incentives 8 VOLUNTARY CARBON MARKET POTENTIAL Engineered Carbon Dioxide Removal (CDR) credits market development4 in the most attractive market in the US with premium pricing for locational and quality differentiation. OR
Application Requirements Capture ▪ In proximity to emitters eligible for LCFS and 45Q/V credits; and are also attracting greenfield projects focused on emerging energy technologies ▪ Strong historical relationships with major petrochemical complexes in CA ▪ Access to capital markets and innovation hubs ▪ Understanding of the commercial and engineering CO2 capture market from CalCapture and DOE FEED study evaluation Transportation ▪ Proximity to CO2 sources ▪ Ability to leverage key infrastructure in place ▪ Access to supply chain distribution network ▪ Midstream experience ▪ Legal & regulatory structure is being developed by the state of CA Storage ▪ Experienced subsurface, reservoir and injection management capabilities ▪ Fully developed static and dynamic reservoir models ▪ Largest fee position in the state ▪ Experience with municipal, county, state & federal permitting agencies ▪ Identified up to 1BMT of potential storage capacity1 Use ▪ Proximity to CO2 sources and petrochemical complexes ▪ Presence in the large consumption market ▪ Access to vast transportation & aerospace network CCS Technology Can Enable a Lower Carbon Future and CTV is Well Positioned to Provide It California’s economy could see rapid near-term emission reduction benefits from CCS ▪ Immediate emissions reductions ▪ Clean, safe and affordable energy ▪ Low carbon baseload power ▪ Global technological leadership Note: (1) Source: Internal estimates. (2) CARB 2020. CRC has identified potential total CO2 storage opportunities of up to 2 9 ~1BMT1
California’s Brownfield Emitters California Marketplace Demand California Marketplace Demand California’s Brownfield Emitters New California Greenfield Emitters Largest Market Share Conventional Brownfield CCS Greenfield CCS Gray Emissions are displaced with Greenfield products through substitution “Virtual Pipeline” of CO2 created via reduced demand for gray product ▪ Brownfield emitters provide a decarbonized product by capturing the CO2 molecules used in the creation of their products and transporting CO2 for permanent storage ▪ This lowers the carbon intensity of their product and the brownfield takes the decarbonized product to market ▪ Decarbonization enabled by emissions which are transported by physical pipe ▪ Greenfield projects provide product with an inherently lower carbon intensity than gray products ▪ Greenfield decarbonized product acts as a substitute for gray product and captures market share ▪ Decarbonization occurs via products which displace higher CI products thus creating a “Virtual Pipeline” that takes lower CI products to market rather than taking the CO2 from gray products Multiples Paths to Decarbonize CRC can either help decarbonization efforts by taking CO2 emissions from gray products or by enabling newer green products to displace gray emissions by taking market share Increasing Market Share Fully Decarbonized product reaches the market Emissions injected into CO2 Storage Decreasing Market Share 10 Direct pipeline Emissions injected into CO2 Storage
Solidifying CTV Class VI Permitting Leadership 11 CTV Leads CA/Region 9 with EPA Class VI Permit Submissions (1) Subject to issuance of EPA class VI permits. (2) Source: EPA Tracker, https://www.epa.gov/uic/current-class-vi-projects-under-review-epa; one other project in Region 9 is under Completeness Review and another is are projected to receive Final Permit in October 2025 (3) Projected to complete preparation of final permit decision at the end of June ‘25 of Currently Submitted EPA Class VI Permits are From CTV1 ~10% U.S. EPA Regions 9 6 7 4 5 EPA released Class VI Draft Permit for 26R (CTV I) reservoir at Elk Hills 26R (CTV I) final permit approval would be first in California and first permit for storage into a depleted oil and gas reservoir Proactively engaging with the local communities to share information about the positive benefits of these projects in the local communities MC
145 MMT 46 MMT Vault CTV I CTV II CTV III CTV IV CTV V EPA Permit Application Administratively Complete Yes (26R) Yes (A1-A2) Yes Yes Yes In Progress Targeting Class VI Draft EPA Permit Receipt Released ~2024 ~2024 ~2024 ~2025 ~2025 California’s Basin SJ Basin Sacramento Basin Annual Regional CO2 Emissions2 (MMTPA) ~30 ~60 Est. Average Annual Injection Capacity4 (MMTPA) ~1.55 0.2 ~0.6 ~1.8 ~0.9 ~0.4 Potential Total Storage Capacity (MMT) 38 8 23 71 34 17 Remaining and Available CO2 Injection Capacity (%)6 45% 100% 100% ~77% 100% 100% EPA released Class VI Draft Permit for 26R (CTV I) reservoir Targeting first CO2 injection at CTV I by the end of 2025 Positioned to Be California’s Premier Carbon Management Provider 191MMT CTV Storage Capacity Submitted to EPA For Class VI Permits to Date ~1,065KMTPA of CDMAs Announced by CTV to Date3,5 ~5.3MMTPA Est. combined average annual CO2 injection capacity4,5 for CTV I - V reservoirs Numbers might not add up due to rounding. Note: please see slide 50 for details on the footnotes on this slide. 12
CENTRAL CALIFORNIA NORTHERN CALIFORNIA DAC HUB THE FOREFRONT OF CARBON MANAGEMENT
Leveraging CRC’s Flagship Elk Hills Asset with a CTV Clean Energy Park 14Note: The exact project location within CTV Clean Energy Park at Elk Hills is TBD. Elk Hills provides ideal conditions to attract greenfield projects, given ▪ Large 47,000 acres land position at Elk Hills for potential infrastructure development ▪ Proximity to ~46MMT under Class VI permit application; most advanced EPA permit applications in the queue in California (filed in 2021) ▪ Additional Elk Hills reservoirs are currently being evaluated for new EPA Class VI permit applications Highlights CRC’s strong energy transition commitment through the economic repurposing of legacy assets and employment creation ▪ Provides incremental pore space to support the CTV Clean Energy Park ▪ Converts decommissioning liability from depleted reservoirs into revenue generating assets ▪ Access to land and amenities incentivizes low carbon investments ▪ Access to skilled energy transition workforce for operations and construction By combining CRC’s Elk Hills surface acreage and world class CO2 sequestration reservoirs, CTV JV could potentially replicate greenfield opportunities such as the Lone Cypress Hydrogen Project multiple times over and continue to build out the CTV Clean Energy Park “We established ambitious and necessary goals to reduce carbon emission … We provided the tools industry needs to capture and store carbon before it hits the atmosphere … creating jobs that will support families across the state.” - G. Newsom, Governor of California, November 16, 2022
$0 $10 $20 $30 $40 $50 $60 $70 $80 $90 CRC Lone Cypress InEntec NLC Verde TBD On Path To First Injection at CTV I (26R) in 2025 15 ~$80MM Est. 26R reservoir’s EBITDA2 once fully subscribed U.S. EPA Released Draft Class VI Permit to CRC’s Carbon TerraVault 26R for CO2 Injection and Storage in California STORAGE ONLY BUSINESS MODEL UNDER CDMAS3 TOTAL 26R Est. CO2 Injection Rate per Year (KMTPA) ~6551 Up to 1,4604 Est. CTV JV EBITDA2 ($MM) ~$40 ~$80 CTV I’S 26R RESERVOIR – THE FIRST SEQUESTRATION TARGET1 (1) Actual results could differ materially. Presents estimated future EBITDA from the sequestration of CO2 related to (a) CRC’s decarbonization CCS project at Elk Hills gas plant where CRC intends to pay CTV JV a storage fee for its services, (b) projects subject to signed CDMA’s and (c) other projects that are not yet identified. Amounts shown are based on an estimated $55 of EBITDA per MT of CO2 storage for CRC’s decarbonization CCS project (assuming 100 KMTPA of injected CO2) and the minimum volume commitments under existing CDMAs. Our CDMAs frame the anticipated contractual terms between parties and provide a path to reaching final definitive agreements. The timing of yet to be identified CDMAs and other CO2 injection projects is uncertain. The 26R reservoir is owned by the CTV JV and CRC’s share is 51% of associated EBITDA. (2) EBITDA is a non-GAAP measure, and estimates include tax credits which may change based on further guidance from IRS and other factors and assumes that wage and apprenticeship requirements are met. (3) Includes CRC’s decarbonization CCS project at Elk Hills gas plant. (4) Total 26R injection capacity as per the draft EPA permit is 38MMT. Assuming the maximum expected injection rate of 1.46 MMTPA, the reservoir would reach capacity in 26 years. (5) See slide 43 for further details. STORAGE ONLY PROJECTS AT 26R VAULT (VARIETY OF CO2 STREAM CONCENTRATIONS) ▪ CTV JV is the off-taker of CO2 from the Clean Energy Park at the 26R storage site ▪ Expected capital requirements on lower end of type curve for storage projects only ▪ Co-location of projects at Clean Energy Park at Elk Hills will provide CTV JV oversight of the entire development while offering opportunities for synergies and organic growth ▪ Potential LCFS, Cap and Trade and/or Voluntary Carbon Credit Market expansion could provide further EBITDA2 potential ▪ CRC anticipates the majority of the 26R CCS development capital (net to CRC) to be covered by Brookfield’s payments for their 49% working interest5 in the project Est. CTV JV EBITDA2 ($MM) 2025 2026 2027 2028 2029 2030
Announcing CRC’s First Capture to Storage Project at Elk Hills Gas Plant 16 CTV’S FIRST CCS PROJECT TO CAPTURE AND STORE 100 KMTPA PROJECT DETAILS FOR CAPTURE TO STORAGE PROJECT AT ELK HILLS ▪ CTV to construct a pre-combustion project at the CTV Clean Energy Park at Elk Hills to remove CO2 from inlet gas, increasing operational efficiency of the cryogenic gas processing plant, improving propane recovery, and reducing the carbon intensity of the electricity generated from the Elk Hills Power Plant ▪ Expected to capture 100KMTPA of CO2 and to be stored at CTV I storage vault ▪ The capture project is targeting 45Q credit generation as well as the potential for LCFS qualification and Cap & Trade (C&T) avoidance, and anticipates paying CTV JV an injection fee for CO2 sequestration services ▪ Project provides the ability to control the full CCS value chain ▪ CTV JV storage only economics are in line with previously disclosed type curve2 ▪ Capture + storage economics net to CRC are in line with previously disclosed IRR range2 of 10% to 30% ▪ Project FID targeted in 1H243; commercial operations targeted in 2H25 DECARBONIZING CRC’S OPERATIONS & TARGETING ~6.5% REDUCTION1 IN EMISSIONS INTENSITY OF ELK HILLS POWER PLANT Note: please see slide 50 for details on the footnotes on this slide. Planned CO2 INJECTION RATE (KMTPA) 100 KMTPA PROJECT EST. CAPITAL REQUIREMENTS ($/MT) PROJECT EST. EBITDA4 ($/ MT) WITHIN OUR PREVIOUSLY DISCLOSED TYPE CURVE2 OF $50 TO $75 OF EBITDA4 PER MT OF CO2 FOR A STORAGE- ONLY SOLUTION WITHIN OUR PREVIOUSLY DISCLOSED TYPE CURVE2 OF $5 TO $15 OF CAPITAL PER MT OF CO2 FOR A STORAGE-ONLY SOLUTION Note: Due to CTV’s 51% ownership of the storage entity, CTV JV, the metrics above are shown on a storage-only basis for comparison purposes to previously announced projects.
▪ Lone Cypress Energy Services, LLC, (Lone Cypress) has executed projects on behalf of some of the majors and largest E&P/Midstream companies in the energy sector with a variety of well-established strategic partners and industry leaders ▪ Lone Cypress’ specialized projects span large midstream systems, RNG facilities, carbon capture and storage systems, hydrogen production and generation, waste to energy plant solutions and traditional oil and gas midstream facilities ▪ Headquartered in Tulsa, OK, Lone Cypress offers a full suite of technology-enabled solutions Lone Cypress Clean Hydrogen Facility 17 Note: The exact Clean Hydrogen facility’s location within Elk Hills is TBD. (1) Our CDMAs frame the anticipated contractual terms between parties and provide a path to reaching final definitive agreements. (2) This project would qualify for LCFS credits to the extent it sells the clean hydrogen to the mobility market (e.g.,hydrogen powered vehicles). (3) Earnings before interest, taxes, depreciation and amortization (EBITDA) is a non-GAAP measure. EBITDA estimates include 45Q tax credits which may change based on further guidance from IRS and other factors. (4) Assumes a 26-year project life. See slide 15 of this deck for the details on the CTV project economic type curve for the 26R reservoir. Planned CO2 INJECTION RATE (KMTPA) 205 KMTPA PROJECT EST. CAPITAL REQUIREMENTS ($/MT) PROJECT EST. EBITDA3 ($/ MT) WITHIN OUR PREVIOULSY DISCLOSED TYPE CURVE4 OF $50 TO $75 OF EBITDA3 PER MT OF CO2 FOR A STORAGE- ONLY SOLUTION ABOUT LONE CYPRESS CDMA DETAILS FOR LONE CYPRESS HYDROGEN FACILITY1 ▪ Lone Cypress to construct a 65 tons per day (TPD) clean hydrogen facility at the CTV Clean Energy Park at Elk Hills using its proprietary technology ▪ CTV JV will provide permanent sequestration for 205KMTPA using CTV I 26R storage vault, including the lease of land for the clean hydrogen facility ▪ Project FID targeted in 2024; commercial operations targeted in 2026 ▪ Combination of CTV I first storage project and Lone Cypress hydrogen facility could be eligible for 45Q or 45V tax credits as well as LCFS credits2 ▪ CTV JV and Lone Cypress are also discussing CRC’s potential financial participation in the clean hydrogen facility, including potentially a significant equity stake205 KMTPA STORAGE ONLY PROJECT WITHIN OUR PREVIOUSLY DISCLOSED TYPE CURVE4 OF $5 TO $15 OF CAPITAL PER MT OF CO2 FOR A STORAGE- ONLY SOLUTION
Today’s Waste, Tomorrow’s Clean Energy ▪ InEnTec Inc. (InEnTec) is an industry leader in proprietary gasification systems that economically and responsibly turn the world's waste into valuable green products, fuels, and energy ▪ Headquartered in Richland, WA, InEnTec has a strong team of highly-skilled engineers and experts in project development and management InEnTec Renewable Dimethyl Ether Facility 18 Note: The exact DME facility’s location within Elk Hills is TBD. (1) Our CDMAs frame the anticipated contractual terms between parties and provide a path to reaching final definitive agreements. (2) Earnings before interest, taxes, depreciation and amortization (EBITDA) is a non-GAAP measure. EBITDA estimates include 45Q tax credits which may change based on further guidance from IRS and other factors. (3) Assumes a 26-year project life. See slide 15 of this deck for the details on the CTV project economic type curve for the 26R reservoir. (4) Superior Plus Energy Services Inc. (Superior) is a U.S. operating subsidiary of Superior Plus Corp. (TSX: SPB). Planned CO2 INJECTION RATE (KMTPA) 100 KMTPA PROJECT EST. CAPITAL REQUIREMENTS ($/MT) PROJECT EST. EBITDA2 ($/ MT) WITHIN OUR PREVIOUSLY DISCLOSED TYPE CURVE3 OF $50 TO $75 OF EBITDA2 PER MT OF CO2 FOR A STORAGE- ONLY SOLUTION OFFTAKE INTEREST ABOUT INENTEC CDMA DETAILS FOR INENTEC DIMETHYL ETHER (DME) FACILITY1 ▪ InEnTec to construct a facility that will use proprietary gasification technology to produce 80 to 100 tons per day (TPD) renewable dimethyl ether (DME) from biomass and other waste feedstock at the CTV Clean Energy Park ▪ CTV will provide permanent sequestration initially for 100KMTPA of CO2 using CTV I storage vault, including the lease of land for the DME facility ▪ Project FID targeted in 2024; commercial operations targeted in 2026 ▪ CTV and InEnTec are also discussing CRC’s potential financial participation in the rDME facility, including potentially a significant equity stake INENTEC HAS ENTERED INTO A MASTER OFFTAKE AGREEMENT WITH SUPERIOR4 TO SUPPLY SUPERIOR WITH rDME 100 KMTPA STORAGE ONLY PROJECT WITHIN OUR PREVIOUSLY DISCLOSED TYPE CURVE3 OF $5 TO $15 OF CAPITAL PER MT OF CO2 FOR A STORAGE-ONLY SOLUTION
▪ NLC Energy LLC, (NLCE) designs, builds, owns, and operates RNG facilities that convert organic waste into useful commodities like clean Renewable Natural Gas (RNG) ▪ Low-carbon RNG replaces higher-carbon fossil fuels across the transportation, utilities, and manufacturing sectors ▪ The company is headquartered in Nashua, NH and has an operational RNG plant in Denmark, WI NLC Energy Greenfield Renewable Natural Gas (RNG) Facility 19 Planned CO2 INJECTION RATE (KMTPA) 150 KMTPA PROJECT EST. CAPITAL REQUIREMENTS ($/MT) PROJECT EST. EBITDA2 ($/ MT) WITHIN OUR PREVIOUSLY DISCLOSED TYPE CURVE3 OF $50 TO $75 OF EBITDA2 PER MT OF CO2 FOR A STORAGE-ONLY SOLUTION ABOUT NLC ENERGY CDMA DETAILS FOR NLCE GREENFIELD RNG FACILITY1 ▪ NLCE to construct a greenfield production facility at the CTV Clean Energy Park at Elk Hills that is expected to generate up to 7,000 MMBtu per day of RNG ▪ CTV JV will provide permanent sequestration for 150KMTPA of CO2 initially using CTV I storage vault, including the lease of land for the RNG facility ▪ Project FID targeted for late 2024; commercial operations targeted in 2027 ▪ CTV JV and NLC are also discussing CRC’s potential financial participation in the RNG facility 150 KMTPA STORAGE ONLY PROJECT RNG PRODUCTION OFFTAKE WITHIN THE CTV CLEAN ENERGY PARK AND CRC OPERATIONS COULD FURTHER REDUCE EXISTING AND FUTURE EMISSIONS OF FACILITIES OFFTAKE INTEREST (1) CRC’s CDMAs frame the anticipated contractual terms between parties and provide a path to reaching final definitive agreements. (2) Earnings before interest, taxes, depreciation and amortization (EBITDA) is a non-GAAP measure. EBITDA estimates include 45Q tax credits which may change based on further guidance from IRS and other factors. (3) Assumes a 26-year project life. See slide 15 of this deck for the details on the CTV project economic type curve for the 26R reservoir. WITHIN OUR PREVIOUSLY DISCLOSED TYPE CURVE3 OF $5 TO $15 OF CAPITAL PER MT OF CO2 FOR A STORAGE-ONLY SOLUTION
▪ Verde Clean Fuels, Inc. (Verde) focuses on supplying gasoline and other fuels derived from renewable feedstocks or natural gas ▪ Verde utilizes its proprietary process to convert synthesis gas derived from biomass feedstocks, such as yard waste, agricultural waste, and sorted municipal solid waste, as well as stranded or flared natural gas (including renewable natural gas) into commodity-grade gasoline ▪ Verde, headquartered in Houston, TX, has a fully operational demonstration plant in Hillsborough, NJ. Verde is listed on NASDAQ, trading under ticker symbol VGAS Verde Renewable Gasoline Facility 20 Planned CO2 INJECTION RATE (KMTPA) 100 KMTPA PROJECT EST. CAPITAL REQUIREMENTS ($/MT) PROJECT EST. EBITDA2 ($/ MT) WITHIN OUR PREVIOUSLY DISCLOSED TYPE CURVE3 OF $50 TO $75 OF EBITDA2 PER MT OF CO2 FOR A STORAGE- ONLY SOLUTION ABOUT VERDE CDMA DETAILS FOR VERDE RENEWABLE GASOLINE FACILITY1 ▪ Verde to construct a facility at the CTV Clean Energy Park at Elk Hills that will use proprietary gasification technology targeted to produce ~7.5 million gallons per year (GPY) of renewable gasoline from biomass and other agricultural waste feedstock ▪ CTV JV will provide permanent sequestration initially for 100KMTPA of CO2 using CTV I storage vault, including the lease of land for the RG facility ▪ Project FID targeted in 2025; commercial operations targeted in 2027 ▪ CTV JV and Verde are also discussing CRC’s potential financial participation in the renewable gasoline facility, including potentially a significant equity stake Note: The exact RG facility’s location within Elk Hills is TBD. (1) CRC’s CDMAs frame the anticipated contractual terms between parties and provide a path to reaching final definitive agreements. (2) Earnings before interest, taxes, depreciation and amortization (EBITDA) is a non-GAAP measure. EBITDA estimates include 45Q tax credits which may change based on further guidance from IRS and other factors. (3) Assumes a 26-year project life. See slide 15 of this deck for the details on the CTV project economic type curve for the 26R reservoir. 100 KMTPA STORAGE ONLY PROJECT WITHIN OUR PREVIOUSLY DISCLOSED TYPE CURVE3 OF $5 TO $15 OF CAPITAL PER MT OF CO2 FOR A STORAGE- ONLY SOLUTION
CENTRAL CALIFORNIA THE FOREFRONT OF CARBON MANAGEMENT DAC HUB NORTHERN CALIFORNIA
(1) Includes CTV II, III, IV and V. (2) Source: CARB 2020, represents legacy emissions within 100 miles of CTV III CO2 storage vault. (3) Source: Oakland Sea Port. (4) Source: City of Sacramento. (5) Source: Colliers. (6) Source: Port of Stockton. 22 CTV Storage Vaults in Northern California ▪ ~145MMT of CO2 storage capacity vaults1, or 3.7MMTPA expected injection rate, submitted by CRC to EPA for Class VI permits in Northern California ▪ Northern California has ~34% of California’s existing emissions2 with most of them from hard to abate industrial sectors ▪ Oakland is home to the ninth busiest container port in the United States where San Francisco Bay ranks among the four largest Pacific Coast ports for container cargo3 ▪ Agribusiness & Food Manufacturing represents a ~$3B industry in the Sacramento region4 with ~$1B of annual industrial dollar volume surrounding Sacramento5 ▪ Port of Stockton carries ~4MM tons of cargo every year and sits in the heart of the agricultural center of California6 CTV’s CO2 storage assets are located in close proximity to the majority of existing emission sources in Northern California as well as potential to serve an emerging new energy economy
Grannus Clean Ammonia Facility 23 Note: The exact Grannus Clean Ammonia and Hydrogen Project location within CTV III is TBD. Clean ammonia is ammonia produced with near zero, or minimal carbon emissions. (1) Our CDMAs frame the anticipated contractual terms between parties and provide a path to reaching final definitive agreements. (2) This project would qualify for LCFS credits to the extent it sells the clean ammonia/hydrogen to the mobility market (e.g. hydrogen powered vehicles). (3) Earnings before interest, taxes, depreciation and amortization (EBITDA) is a non-GAAP measure. EBITDA estimates include 45Q tax credits. (4) See slides 44 and 45 of this deck for the latest details on the CTV project economic type curve. (5) A binding offtake agreement with respect to the Grannus Clean Ammonia and Hydrogen Project related to CTV III is subject to finalization and approval by Grannus and CALAMCO. Planned CO2 INJECTION RATE (KMTPA) 370 KMTPA PROJECT EST. CAPITAL REQUIREMENTS ($/MT) PROJECT EST. EBITDA3 ($/ MT) WITHIN OUR PREVIOUSLY DISCLOSED TYPE CURVE4 OF $50 TO $75 OF EBITDA3 PER MT OF CO2 FOR A STORAGE-ONLY SOLUTION OFFTAKE INTEREST GRANNUS HAS ENTERED INTO A MASTER AMMONIA SALES AGREEMENT WITH CALAMCO IN AN AMOUNT UP TO ITS TOTAL AMMONIA REQUIREMENTS5 CDMA DETAILS FOR GRANNUS CLEAN AMMONIA FACILITY1 ▪ Grannus to construct a 150KMTPA clean ammonia & 10KMTPA hydrogen facility near the CTV III location using its patented process design with commercial operations targeted by the end of 2027 ▪ CTV will provide permanent storage for 370KMTPA using its CTV III storage vault, including the CO2 pipeline and the lease of land for the clean ammonia and hydrogen facility ▪ Combination of CTV III’s storage project and Grannus’ clean ammonia and hydrogen facility will be eligible for 45Q or 45V tax credits as well as LCFS credits2 ▪ CTV will have the right to take a majority stake in the total outstanding equity of the project company that holds the Grannus Clean Ammonia and Hydrogen Project ▪ CTV will have an option to purchase equity in Grannus as well as a right of first refusal (ROFR) to provide storage services for subsequent Grannus ammonia and hydrogen projects in California ▪ Grannus is an independent clean-tech company that is building a portfolio of clean ammonia and hydrogen production facilities to supply the agriculture, mobility and marine fuel markets ▪ Grannus is using patented technologies that produce effectively no emissions and exceed the conversion efficiencies of today’s best in class clean ammonia and hydrogen production facilities’ designs ▪ Headquartered in Tucson, AZ, Grannus offers a full suite of technology-enabled project development, project management and engineering solutions in the U.S. and North America ABOUT GRANNUS 370 KMTPA STORAGE ONLY PROJECT WITHIN OUR PREVIOUSLY DISCLOSED TYPE CURVE4 OF $5 TO $15 OF CAPITAL PER MT OF CO2 FOR A STORAGE-ONLY SOLUTION
Clean Ammonia Will Help Accelerate The Decarbonization of CA’s Agricultural Sector 24 Note: Clean ammonia is ammonia produced with near zero, or minimal carbon emissions. (1) Source: EIA based on 2020 data; Economic Research Service - U.S. Department of Agriculture; U.S. Geological Survey, Mineral Commodity Summaries, January 2022; CA Department of Food and Agriculture. (2) Source: “Ammonia’s Potential Role in a Low-Carbon Economy”, Congressional research service, December, 2022 (3) Source: CALAMCO (4) Source: KCRA, July, 2022. (5) Source: CALAMCO’s public website. (6) Source: CARB website as of 2020 ▪ U.S. is the world’s third largest producer of ammonia, consuming ~ 19.5MMTPA of ammonia which is mainly used in the agricultural sector1 (~88% of U.S. ammonia consumption was for fertilizer use2) ▪ CALAMCO represents the majority of agricultural ammonia demand in California3 where most of it is imported into Stockton, Sacramento4 and other entry points from other U.S. states and countries such as Trinidad and Tobago ▪ CALAMCO’s terminal at the Port of Stockton, the only ammonia marine import terminal in California, currently hosts 40,000 tons of ammonia storage tanks5 ▪ California produced low carbon clean ammonia can replace imported grey ammonia to create local employment, lower the carbon intensity of fertilizers used in the agricultural sector (~9% of CA’s 2020 total GHG emissions6) and further drive the technological evolution of the energy transition in California CLEAN AMMONIA – ENERGY TRANSITION MIX IN CALIFORNIA
▪ Yosemite to build and operate a 24 tons per day (TPD) hydrogen facility in the city of Oroville, California, using dual bed gasification technology with commercial operations targeted in 2026 ▪ CTV will provide truck offloading facility and permanent sequestration for the initial 40 KMTPA of CO2 emissions from this facility using CTV storage vaults ▪ Yosemite plans to deliver CO2 to CTV location via a fleet of low emissions trucks ▪ Combination of CTV’s storage project and Yosemite’s hydrogen facility will be eligible for 45Q or 45V tax credits as well as LCFS credits2 ▪ CTV has the right to participate in project for up to a majority equity stake ▪ Yosemite has plans for two additional green hydrogen facilities in California with up to an additional 160 KMTPA of CO2 emissions under consideration; CTV has the right of first negotiation to provide CO2 sequestration services to any hydrogen production facility constructed in California Yosemite Renewable Fuels Facility Planned Expansion Potential CO2 INJECTION RATE (KMTPA) 200 KMTPA PROJECT EST. CAPITAL REQUIREMENTS ($/MT) PROJECT EST. EBITDA3 ($/ MT) WITHIN OUR PREVIOUSLY DISCLOSED TYPE CURVE4 OF $50 TO $75 OF EBITDA3 PER MT OF CO2 FOR A STORAGE- ONLY SOLUTION OFFTAKE INTEREST YOSEMITE HAS ENTERED INTO A LETTER OF INTENT FOR A MASTER HYDROGEN OFF-TAKE AGREEMENT WITH GUNVOR USA ▪ Yosemite Clean Energy LLC (“Yosemite”) is a bioenergy development company that specializes in transforming farm and forest wood waste into carbon-negative hydrogen, providing renewable solutions to California’s transportation and broader energy sectors. ▪ Headquartered in Fresno, CA, Yosemite and its development partners have experience in forestry, agriculture, banking, law, energy, engineering, and marketing ABOUT YOSEMITE CLEAN ENERGY CDMA DETAILS FOR YOSEMITE’S RENEWABLE FUELS PROJECT1 (1) Our CDMAs frame the anticipated contractual terms between parties and provide a path to reaching final definitive agreements. (2) This project would qualify for LCFS credits to the extent it sells the hydrogen to the mobility market (e.g., hydrogen powered vehicles). (3) Earnings before interest, taxes, depreciation and amortization (EBITDA) is a non-GAAP measure. EBITDA estimates include 45Q tax credits which may change based on further guidance from IRS and other factors. (4) See slides 44 and 45 of this deck for the latest details on the CTV project economic type curve. 40 KMTPA STORAGE ONLY PROJECT 25 WITHIN OUR PREVIOUSLY DISCLOSED TYPE CURVE4 OF $5 TO $15 OF CAPITAL PER MT OF CO2 FOR A STORAGE-ONLY SOLUTION
NORTHERN CALIFORNIA CENTRAL CALIFORNIA THE FOREFRONT OF CARBON MANAGEMENT DAC HUB
Accelerating Climate Leadership and Energy Transition Through Direct Air Capture (DAC) ▪ WHAT IS DAC+S? Direct Air Capture plus Storage (DAC+S) is a technological solution that can remove and then permanently store decades-old atmospheric carbon in underground reservoirs using low carbon emission energy DAC+S reduces overall levels of CO2 in the atmosphere and therefore is carbon negative (1) CTV Direct is a wholly owned subsidiary of Carbon TerraVault focused on DAC. (2) Source: “Big Tech’s carbon removal scheme announces its first purchases”, Protocol, June 2022. (3) Source: EPA. (4) California’s leading goal for Carbon Direct Removal of 100 MTPA, of which ~66 MMTPA is projected to be from DAC per CARB Scoping Plan. Source: CARB. ▪ WHY FORM A DAC CONSORTIUM IN CALIFORNIA? California has ample access to sustainable Carbon Dioxide Removal (CDR) credits2, advanced technologies, world-leading research institutions, and supportive government-driven financial incentives CarbonTerraVault leads in EPA Class VI permit applications for CO2 non-EOR storage reservoirs in California3 that are supplemented by extensive existing infrastructure that can be repurposed to further advance DAC+S across California California has ambitious climate targets that require CDR for success4 ▪ WHY IS IT IMPORTANT? Acceleration of DAC+S in California can provide positive economic impacts, create high-paying jobs, successfully and sustainably reduce CO2 emissions, and help the state lead in the energy transition with long-lasting benefits for Californians and our communities Source: CARB Source: World Resources Institute MMT for DAC4~66 ▪ WHAT IS A CALIFORNIA DAC HUB? A newly formed consortium, led by CTV Direct1, EPRI and Kern Community College District (Kern CCD), seeks to bring together like-minded energy transition industry, technology, academia, national labs, community, government, and labor participants with the main goal to create and accelerate the development of the State’s first full scale DAC+S hub Carbon TerraVault has formed a DAC Hub consortium to accelerate a Direct Air Capture and storage solution (DAC+S) for California through its wholly owned subsidiary CTV Direct1 27
Under the U.S. Department of Energy (DOE) Regional DAC Hubs Initiative Development Vision ▪ HOW WILL IT BE DEVELOPED? The first DAC Hub is targeted for Kern County and is expected to store CO2 at the CTV I reservoir1. The hub is expected to expand to other locations across the state to store CO2 in non-EOR reservoirs while providing high-paying energy transition driven jobs and training programs for reskilling workers, and helping California reach its carbon removal goals ▪ HOW WILL THIS BE FUNDED? In August of 2023, DAC Hub has been selected to receive ~$12MM in funding from the U.S. DOE under its Regional DAC Hubs Initiative2 related to the proposed development of California’s first full-scale DAC plus storage (DAC+S) network of regional hubs. With successful selection for the DOE funding, the DAC Hub could also qualify for additional funding from the CEC in the amount of $3MM The full cost to perform FEED studies, community benefits and engagement in 2024/25 on the proposed DAC facilities in Kern County is expected to be ~$24MM where the remainder of this amount will be split between the California DAC Consortium members In 2025, California DAC Hub is expecting to submit a subsequent funding request to the DOE under its Regional DAC Hubs Initiative2 for a potential total amount of $500MM which will include a planned development and construction plans California Direct Air Capture HUB ~$500MM2 DAC Hub Permanently Store Atmospheric CO2 Using Low Carbon Energy Note: DOE = Department of Energy (1) CRC has applied for EPA Class VI permits and the environmental review has begun for two initial permanent carbon capture and storage (CCS) vaults at the Elk Hills Field – which are collectively referred to as Carbon TerraVault I. (2) DOE is establishing a program under which the Secretary of Energy shall provide funding (total funding amount of $3.5B) for eligible projects that contribute to the development of four regional direct air capture hubs. Potential total funding amount for California DAC Hub was estimated per the latest funding opportunity announcement to potential domestic hubs. Total funding amount might vary based on DOE grants. Source: DOE (https://www.energy.gov/oced/regional-direct-air-capture-hubs). (3). DOE. (4). Source: LCFS YTD2023 weighted average price of $76 per MT of CO2 - The California Air Resources Board. Potential total funding amount of 28 45Q $180 Value (per MT of CO2) for Carbon Storage3 LCFS CDR Credits ~$76 Est. Value (per MT of CO2)4 Voluntary CDR Credits Market
ACADEMIA Together We Can Achieve Bigger and “DAC” Things INDUSTRY NATIONAL LABS DAC TECHNOLOGY COMMUNITY GOVERNMENT LABOR Lead DOE Applicant Represents a Public-Private Partnership of Leading CA Community, Academic, DAC, and Carbon Storage Organizations 29
“California is pioneering new solutions to fight climate change. It’s not enough to cut emissions – we have to go further by actively removing carbon pollution from the atmosphere. This project will be the first of its kind in our state and will help us meet our world-leading climate goals” California Is Leading the Climate Charge - G. Newsom, Governor of California, August 2023 30
Appendix
32 Huntington Beach – Asset Optimization & Value Unlock ▪ 1810 Pacific Coast Highway, Huntington Beach, CA ▪ Completed the abandonment of six wells ▪ In the process of completing surface abandonment ▪ Targeting call for offers for ~1 acre parcel of land (Fort Apache) in 1Q24 ▪ Planning to provide additional details with 4Q23/YE23 results Over 1 mile of direct access to Pacific Coast Highway ▪ Continuing the re-zoning, re-entitlements and due diligence processes • Multi year process ▪ Developing strategy to optimize production and ARO schedule • Huntington Beach field 2022 gross production1 was ~3,000BOD • The field is connected to a producing offshore platform Emmy • Free cash flow2 generating asset ▪ Plugged and abandoned 20 wells year to date ▪ Targeting to P&A an additional 40 wells in 2024 Source: CRC. (1) Source: CalGEM (2) Represents a non-GAAP measure. For all historical non-GAAP financial measures please see the Investor Relations page at www.crc.com for a reconciliation to the nearest GAAP equivalent and other additional information. Free cash flow is equal to operating cash flow less total capital requirements. 1 ACRE PARCEL – FT APACHE ~90 ACRES PARCEL – HUNTINGTON BEACH Source: Newmark
Transforming the Way We Operate for a Long-Term Outlook ▪ Implement identified cost saving opportunities ▪ Integrate process improvements into operating model OPPORTUNITY IDENTIFICATION DEPLOYMENT & INTEGRATION LONG-TERM VISION ▪ Identified major cost saving opportunities ▪ Evaluating additional operational efficiencies ▪ Lock-in operational efficiencies and cost reductions ▪ Organizational alignment ▪ Transforming the way we operate to improve margins and drive higher cash flows ▪ Utilizing Alvarez & Marsal’s industry experience and proprietary PeerView E&P benchmarking and analytics $55MM + Targeted YE2023 run rate2 reduction NON ENERGY OPERATING COSTS ADJ. E&P CORP. & OTHER G&A1 FOCUS AREAS: 33 (1) Represents a non-GAAP measure. For all historical non-GAAP financial measures please see the Investor Relations page at www.crc.com for a reconciliation to the nearest GAAP equivalent and other additional information. (2) Current 2023 guidance doesn’t include targeted cost reduction initiatives. Excludes CTV from the scope of this initiative. Non Energy Operating Costs Adj. E&P Corp. & Other G&A 1 Est. YE2023 Split in Targeted Reductions Between Focus Areas (%) Actioned Savings In Process Progress on Focus Areas (%)
Sustainability Is In Our Business Model Please visit CRC.com/ESG to view CRC’s 2022 Sustainability Update. 34 Submitted 191MMT of CO2 Reservoirs to EPA for Class VI permits in five carbon vaults with many more in development; leading the nation in Class VI permit applications 2022 Sustainability Update Highlights ESG Milestones Announced a California DAC Hub with a purpose to permanently store atmospheric CO2 using low carbon emission energy and provide economic benefits to surrounding communities CO2 Removal Pledged $2.5MM to fund several Kern County initiatives to advance the energy transition Community Carbon Management Reduce Methane Emissions 30% from 2020 levels by 2030 Reduce or Offset Scope 1, 2 & 3 Emissions 100% by 2045 Reduced Scope 1 & 2 Emissions 9.5% from 2020 to 2022 Ta rg e ts P ro g re s s Reduced Methane Emissions 15.5% from 2020 to 2022 Investor-favored changes including the removal of Supermajority votes. Board exhibited diversity with 33% being gender diverse and 44% consisting of members from underrepresented communities. Governance
35 Differentiated and Diversified Asset Base Across California Note: The above pictures were taken by CRC and represent its current properties and assets. THUMS Islands Huntington Beach LA BASIN SACRAMENTO BASIN Midstream Infrastructure at Elk Hills SAN JOAQUIN BASIN San Joaquin Valley NG Processing Plant & 550MW Power Plant at Elk Hills Largest Natural Gas Producer in California CRC Holds ~1.9MM Net Mineral and ~ 100K Surface Acres
~13 Years ~86% 7.0 Long Durability, Low Decline & Low Carbon Intensity O&G Assets ~13 years of low carbon intensity multi year production runway2 13% 87% PUD PD $5.9B PV-10 OF 2022 PROVED RESERVES1 87% 13%San Joaquin Basin 85% 15% PDP PUD Los Angeles Basin 100%Sacramento Basin 9 0% ~13% 3 ~9 ~82% 9.3 107 ~99% ~7% 19 ~15 ~71% 5.6 287 ~62% ~12% 66 ~12 ~92% 7.5 MMBoe ($80 Brent)1 % Oil Est. Annual Decline 1H23 Average Net Production2 (MBOE/D) R/P2 NRI ($80 Brent)1 CI3 (Scope 1+2) (g CO2e/MJ) Multi-year Runway LONG DURABILITY 1P ASSETS We See a Long-Term Need in California for CRC’s Low Carbon Intensity Barrel & Carbon Management Strategy Sacramento Basin San Joaquin Basin Los Angeles Basin Note: please see slide 50 for details on the footnotes on this slide. 36
California Needs Low Carbon Intensity Domestic Natural Gas 37(1) EIA; excludes Vehicle Fuel which was less than 0.029 mcf/d from 2018 to 2022 (2) CARB Scoping Plan 2022 (3) Other includes pumped storage, shed DR, geothermal, nuclear, biomass, CHP and coal (4) CARB (5) Internal estimates 1.2 1.3 1.3 1.2 1.1 0.7 0.7 0.6 0.7 0.7 2.1 2.1 1.9 1.9 1.6 1.7 1.6 1.7 1.7 1.8 0.0 1.0 2.0 3.0 4.0 5.0 6.0 2018 2019 2020 2021 2022 Residential Commerical Industrial Electric Power POWER AND INDUSTRY CONSUME ~70% OF THE STATE’S NATURAL GAS1 EVEN IN 2045, NATURAL GAS POWER PLANTS PLAN TO CONTRIBUTE 12%2 California continues to need a consistent and reliable supply of electricity from natural gas power plants through 2045 California Will Continue to Receive a Premium to Henry Hub ▪ CRC expects natural gas to play a key role in supporting energy transition ▪ CA imports 90% of its gas needs. Lack of flexibility with the legacy natural gas infrastructure will continue to drive elevated prices and volatility in periods of high demand5 ▪ CRC expects relatively strong natural gas prices with the premium to Henry Hub to continue California’s Natural Gas Demand (Bcf/d) Total Capacity (Giga-watts) Source: Baringa. Note, listed volumes are maximum 2022 reported flows 0 50 100 150 200 250 300 2023 2035 2045 Solar - All Battery Storage Gas Wind - All Hydro - All Hydrogen CT Other 3 Canada / Rockies (~1.8 Bcf) Rockies (~0.6 Bcf) San Juan / Rockies (~0.8 Bcf) Permian (~1.4 Bcf) California imports ~4.6 Bcf/d or ~90% of its demand4 from regions that frac for natural gas
CRC’s Natural Gas Inventory Depth – 1Tcf1 Opportunity CRC’s Opportunity Set1 by Basin >250 Bcf >800 Bcf Sacramento Basin Opportunity Set1 ▪ ~110Bcf of actionable inventory ▪ Resource: ▪ >250 Bcf of dry gas ▪ ~300 locations Up to 220Bcf of near-term actionable inventory potentially starting in 2H244 San Joaquin Basin Opportunity Set1 ▪ ~700Bcf of actionable inventory ▪ Resource: ▪ >800 Bcf of associated gas ▪ ~1,100 locations CALIFORNIA’S NATURAL GAS FORWARD CURVES3 ($/Mcf) CRC is pursuing a Responsibly Sourced Gas2 (RSG) certification for the majority of its natural gas assets $- $2 $4 $6 $8 $10 $12 $14 2023 YTD 2024 2025 2026 2027 2028 2029 2030 2031 2032 NYMEX HH PG&E Citygate Socal Border Socal Citygate Avg. 2024 – 2032 Price NYMEX HH $3.85 PG&E City-gate $5.42 SoCal Bdr $4.93 SoCal City-gate $5.98 Note: please see slide 50 for details on the footnotes on this slide. 38
Exploring Technologies to Further Advance Net Zero Energy Pathways Source: ICE Thermal Harvesting, CRC Internal ▪ Partnered with ICE Thermal Harvesting (“ICE”), who was awarded a ~$2MM “Wells of Opportunity” grant from the DOE ▪ Provides an avenue for CRC to pilot a new zero-carbon energy technology ▪ Potential commercial benefits: field electrical cost reductions, decreased emissions, postponement of asset retirement obligations, increased reliability of power and improved economics ▪ Project kicked off in October 2022 and is expected to last 3 to 4 years with a potential for free zero-emissions electricity capable to power 6 wells ▪ Initial planned location at Elk Hills with prospects to expand this technology to other fields or to other applications: ▪ Areas of Elk Hills, Buena Vista, Yowlumne, Kern Front, and Kettleman are associated with geothermal opportunities Est. ~6MW of Geothermal Opportunities in SJB 39
Solar Developments on Track (1) Other includes sites across CRC’s asset base. (2) www.cpuc.ca.gov GRID SUPPLY | FRONT OF THE METER UPDATE: ▪ CRC has identified over 5,000 acres of surface potentially suitable for utility scale solar development that could present future value for CRC and investors ▪ Potential for 300 to 1,000 MW with 3 core projects preliminarily identified ▪ Evaluating further FTM opportunities in future Interconnection Cluster Studies ▪ Potential to further reduce CO2 emissions while adding further commercial opportunity SELF SUPPLY | BEHIND THE METER UPDATE : Progressing our solar developments: ▪ Mt. Poso & Kern Front: ▪ Projects are in the Net Energy Metering (NEM) 2.0 program2 ▪ Front-end engineering and design packages completed ▪ Kern Front grading permit submitted and construction start expected after permit issuance ▪ Received grading permit for Mount Poso; targeting construction in Q1 2024 ▪ Continue to advance additional 4MW of BTM projects across CRC’s operations BTM Development Field Capacity (MW) Est. Commercial Operation Est. Energy OPEX Reduction Mount Poso 12 2H24 15% - 25% Kern Front 22 1H25 15% - 25% Other1 4 TBD TBD ~ 38 MW of BTM projects in development 40
Expecting to Further Diversify CTV’s Portfolio of Emitters Across The Energy Spectrum in California Continuing to attract new emissions sources due to ideal conditions for greenfield and existing sources projects (Subsurface knowledge, technical expertise, assets’ location, access to capital, permitting process & etc.) Decarbonizing California and Building a CTV Driven Energy Transition Ecosystem Project Type1 Tech Greenfield Existing Sources Type of Emitter DAC Renewable Diesel/Gas Ammonia Hydrogen Ethanol Refiners, Cement, Steam Generators and Natural Gas Power Plants (incl. CalCapture) Cost of Capture ($/TCO2) Very High Medium Low Medium Low Medium to High Concentration of CO2 Very Low Medium High Medium High Low to Medium LCFS Eligible? Yes, plus Incremental Incentives Yes Depends on Use Depends on Use Yes Depends on Use Source: Internal estimates 41 Positioned to Be California’s Premier Carbon Management Provider 150 - 210 California’s Potential Addressable CCS Market Size by 2045 MMTPA or more
Strategic Partnership – A Structural Capital Advantage (1) Assumes the average capital needs for 5MMTPA of Carbon Sequestration from the CTV JV economic “Type Curve”. See slides 44 and 45 for detailed information on the previously disclosed Type Curve. Brookfield made an initial commitment of $500 million to invest in CCS projects that are jointly approved through the Carbon TerraVault JV. The partnership is targeting 5MMTPA of CO2 injection by YE 2027, aligned with CRC’s 2027 goals, thereby requiring an estimated ~$2.5B of capital. (2) ~$980MM assumes 200MMT of CO2 pore space for $10/MT of CO2 storage space and 49% Brookfield ownership which assumes Brookfield fully participates in CCS projects up to JV target of 5MMTPA of injection and 200MMT of CO2 storage. (3) Results subject to effects of taxes, timing, pace of project development and Brookfield further approval to fund capital. Illustrative 2027 CO2 Storage/Injection Goal Capital Funding Needs1 assumes Brookfield fully participates in 5MMTPA of CTV JV projects 50% 50% CRC Brookfield ~$637MM of Capital (5MMTPA of CO2 Injection by 2027) Est. $2.5B Capital Outlay1 ~50% Equity ~$1.25B ~50% Debt ~$1.25B 2 0 2 7 G O A L 51% 49% C R C ’s C a p it a l C o n tr ib u ti o n O w n e rs h ip ~$980MM for Pore Space2 200MMT of CO2 Pore Space $10/MT of CO2 Storage Space 51% 49% Est. Capital Required Est. Pore Space Contribution ~$613MM of Capital B ro o k fie ld ’s C a p ita l C o n trib u tio n Improves & Increases Flexibility of CRC’s Capital Allocation Framework ▪ Capitalizes first 5MMTPA of projects and provides potential funding for CRC’s development of 200MMT of CO2 storage by 2027 ▪ CRC’s equity commitments for the first 5MMTPA are more than 2x covered by Brookfield’s initial commitment for projects jointly approved through the CTV JV ▪ Allows CRC to increase flexibility for shareholder returns strategy and explore strategic alternatives for low CI E&P business expansion JV ~$980MM Est. Brookfield Pore Space Contribution ~$637MM Est. CRC’s Capital Contribution ~$343MM Available to fund CRC early stage CMB expenses and capital (represents approximately 5 years of spending and CMB 2023E Guidance of ~$70MM) Projected Excess Capital Available for Early Stage CMB Expenses and Capital3 – 42
~38MMT ~161MMT ~9 MMT Contributed ROFL Notice Delivered TBA CTV JV – Vault Dropping Mechanism Carbon TerraVault JV (“CTV JV”) JV A1-A2 CTV II Brookfield $46MM 26R1 Brookfield $46MM Brookfield: between $54 - $94MM2 Brookfield 49% Capital Call For Project Development Permit Public Comment Expiration FID Project Capital Call CRC's portion of capital calls can be satisfied with Brookfield's contribution retained by the CTV JV Milestone 3Milestone 2Initial Payment Reservoir Vault Dropdown YE2027 200MMT Storage CTV JV Target4 26R A1-A2 CTV II CTV … Future Potential Dropdowns CTV presented subsequent reservoirs to CTV JV with a combined capacity of 161MMT CTV … If Accepted • Brookfield to Pay Initial Payment ($10/Ton x Permitted Pore Space x 49% / 3) • Brookfield to Pay Milestone Payment at Permit Public Comment Expiration ($10/Ton x Permitted Pore Space x 49% / 3) • Brookfield to Pay Milestone Payment at FID ($10/Ton x Permitted Pore Space x 49% / 3) Brookfield Retains the Right to Defer the Approval Decision Through FID If Deferred, Projects to be Re-presented to Brookfield at FID • If Approved, Brookfield to Pay Lump Sum for Full Buy-in ($10/Ton x Permitted Pore Space x 49%) + % Carry3 to CRC • If Rejected, CRC is Free to Develop the Reservoir / Project Outside of the CTV JV1 Future Potential Dropdowns Note: CTV JV terms simplified for illustrative purposes. Source: Internal estimates. (1) As it pertains to a previously contributed reservoir, in the case Brookfield is not interested in jointly pursuing a specific opportunity, CRC retains the right to rent back up to 25% of the permitted pore space to pursue stated storage opportunity on its own accord. (2) Total Brookfield payments to CRC corresponding to their 49% interest in the 26R reservoir are expected to total up to ~$185 MM at FID. $46MM has been received to date, with two additional instalments expected at milestones 1) EPA Class VI Public Comment Expiration and 2) 26R Reservoir FID. The amount of the last milestone payment will be calculated in accordance with the final permit volumes adjusted for water injection. For illustrative purposes, the final payment amount is shown based on the volumes outlined in the draft EPA permit of 38MMT. (3) Calculated from date of initial ROFL presentation at certain milestone. (4) Assumes Brookfield fully participates in CCS projects up to JV target of 5MMTPA of injection and 200MMT of CO2 storage. 43
$0 $100 $200 $300 $400 $500 2023E 2026E 2028E M id p o in t o f E s t. C T V J V E B IT D A ($ M M ) Illustrative CTV JV Type Curve Demonstrates Potential Valuation Upside Note: Please see Slide 51 for important information regarding the assumptions used in the preparation of the information show on this slide. CTV JV economics are shared 51% to CRC and 49% to Brookfield. EBITDA is a non-GAAP measure. Unit Low High Notes/Incorporated Assumptions Total Incentive Potential (LCFS + 45Q ) $/MT $170 $205 45Q ($/MT): $85, LCFS ($/MT): $85 - $120, 100% LCFS eligibility Opex $/MT $10 $75 Range reflects costs associated with full range of business model possibilities and includes G&A of dedicated staff. Capex Avg $/MT $5 $20 Range of capital includes cost of capture facility and pipeline retrofit. Cost of capture facility depends on CO2 concentration at source. Pipeline costs depend on distance from source to sink and size of pipe. Pace of capex deployment is expected to be ~5% to ~10% of Total Project Capex in Year 1, ~10% to ~35% in Year 2 and ~55% to ~85% in Year 3. Depending on project structure and location, capex could be lower or higher than range represented. EXAMPLE CTV JV PROJECT ECONOMICS – “TYPE CURVE” (PER MT OF INJECTED CO2) First Full Year of Est. Impact 2026E 2028E Est. CO2 Injection Rate per Year 1MMTPA 5MMTPA Est. CTV JV EBITDA ($MM) $50 - $135 $250 - $675 44 Example Strategic Partnership Economics An average CTV project could generate on average $50 to $135 of EBITDA per metric ton injected per annum depending on project structure
$5 $10 $15 $20 $25 $30 $50 $60 $75 $90 $105 $120 $135 $150 $165 Not Likely Est. EBITDA1 ($/Ton) E s t. C A P E X ( $ / T o n ) Storage Only Low CO2 Concentration Large Opportunity Set With a Variety of Potential Emitters Note: Depicts illustrative examples of expected and estimated IRR, EBITDA and capital expenditure requirements based on internal estimates. Actual results could differ materially. (1) EBITDA is a non-GAAP measure. EBITDA estimates include 45Q tax credits which may change based on further guidance from IRS and other factors and assumes that 45Q wage and apprenticeship requirements are met. (2) CalCapture refers to CRC’s project at the Elk Hills Power Plant. STORAGE ONLY PROJECTS ▪ CTV JV is the off-taker of CO2 at storage site through Storage Co. ▪ Lower expected capital requirements for project development, including injection and monitoring wells, facilities and compression ILLUSTRATIVE EBITDA1 VS CAPEX REQUIREMENTS FOR VARIOUS CO2 PROJECTS MID - HIGH CO2 CONCENTRATION PROJECTS (≥15% CO2 STREAM CONCENTRATION) ▪ CTV JV controls the entire value chain (capture to storage) and majority of the incentives ▪ Capital requirements for capture systems, while still significant, are expected to be on the lower end of the capture cost curve due to higher CO2 concentration of stream ▪ Project financing more likely vs. storage only and provides opportunity to increase levered returns ▪ Potential LCFS expansion could provide further EBITDA potential LOW CO2 CONCENTRATION PROJECTS (<15% CO2 STREAM CONCENTRATION) ▪ CTV JV controls value chain and incentive but lower expected IRR due to higher costs of capture (Ex: Natural Gas Combined Cycle Power Plants) ▪ Inflation Reduction Act of 2022 expands potential project opportunities ▪ Advancements in capture technology to play key role in improving project economics ▪ CARB considering new incentive programs to unlock traditionally hard to decarbonize sectors (e.g. cement) ▪ CalCapture2 is an advantaged low CO2 concentration project given its proximity to storage (insignificant transport capital) Area of Focus Est. 10% - 30% Levered IRR Mid - High CO2 Concentration Target 45
$60 $65 $70 $75 $80 $85 $90 $95 $100 $105 $110 $115 $120 Brent ($/BBL) Wilmington Production Sharing Contracts (PSC) At Higher Commodity Prices Approximately 30% of CRC’s oil production is subject to PSCs Mechanics: ▪ As operator, CRC pays our partners’ share of the Operating and Capital Cost ▪ CRC recovers our partners’ share of operating and capital costs through production sharing, where CRC’s cost recovery is reported as revenue ▪ CRC receives 45-49% of the gross production as “Profit Barrels” after cost recovery ▪ CRC’s net share of production includes cost recovery and profit barrels As prices rise, fewer barrels are required to recover our partners’ portion of the cost Cost Recovery BBLs Net Profit BBLs 45-49% of Gross Production Net Production (BOD) CRC sees a difference of ~5.3MBOD in net oil production between $65/BBL and $115/BBL EFFECT OF OIL PRICE ON NET PRODUCTION2 For every $1/BBL increase/decrease in Brent price, we expect a ~90BOD decrease/increase in our net oil production related to PSCs1 (1) Based on Brent price of $90 per barrel of oil (2) Net Production from Wilmington field only. Includes the effects of a development program in LA Basin. -/+ $1/BBL +/- ~180 BOD -/+ $1/BBL +/- ~60 BOD -/+ $1/BBL +/- ~90 BOD ~3.4 MBOD increase in net production ~1.9 MBOD decrease in net production 46
▪ Crude: California crude prices continued move in tandem with the broader market with realizations for 3Q23 firming slightly from 2Q. For the balance of the year, local (permits, refining margins & outages) and geopolitical dynamics (OPEC+, central bank policies, Middle East tensions) remain key determinants as to where prices will trend in California ▪ NGLs: 3Q23 NGL prices across North America continued to weaken driven by seasonal trend and general over-supply. As reflected within 2Q23 realizations - and as projected for the balance of the year - California has been and should remain a premium-priced NGL marketplace ▪ Natural Gas: California 3Q23 natural gas prices increased relative to 2Q23 as storage inventories were replenished. A material increase in Aliso Canyon natural gas storage capacity stands to support prices this Fall while – along with an abundance of hydro generation capacity - limiting the potential for gas price run-ups this winter ▪ Power: As measured on year/year basis, 3Q power prices retreated on the back of record snowpack & hydro output, incremental on-peak solar output, and uncharacteristically mild weather $61.33 $63.04 $63.66 $66.12 4Q22 1Q23 2Q23 3Q23 $8.73 $21.56 $3.46 $4.83 4Q22 1Q23 2Q23 3Q23 14.4% 7.8% 9.5% 5.4% 3.9% Strong Price Realizations in CA’s Unique Market Dynamics CALIFORNIA IS AN OIL ISLAND AND THE LARGEST U.S. GDP CONTRIBUTOR (amounts shown as % of U.S. domestic GDP) Note: 5 largest contributors to domestic GDP. Source: BEA, Data from 1Q23; EIA Oil w/ Hedges ($/BBL) NGLs ($/BBL) Natural Gas ($/MCF) Average Benchmark Prices1 $88.60 $82.22 $78.01 $85.95 $88.60 $82.22 $78.01 $85.95 $6.76 $3.42 $2.10 $2.55 % of Benchmark1 98% 96% 97% 99% 64% 72% 54% 52% 129% 630% 165% 189% Hedge Settlements ($25.82) ($15.64) ($12.11) ($19.24) – - - - ($0.22) - - - Average Realized Prices2 $61.33 $63.04 $63.66 $66.12 $56.55 $58.88 $42.48 $44.95 $8.51 $21.56 $3.46 $4.83 (1) Benchmark prices are based on Brent for oil and NGLs, and NYMEX average daily price for natural gas. (2) Average realized prices include hedges on oil and natural gas. CRC’s commodity realizations continue to trend above domestic WTI averages $56.55 $58.88 $42.48 $45.06 4Q22 1Q23 2Q23 3Q23 47
CRC’s hedging strategy is designed to meet our business objectives should market prices decline and participate should market prices increase Hedging Program (1) Hedge position as of September 30, 2023. Includes deferred option premium payment. For the purposes of this example assumes CRC physical sales realize 100% of Brent price. (2) Hedges are based on weighted-average Brent prices per barrel. (3) Purchased and sold puts with the same strike price have been netted together. (4) Assumes forward commodity prices as of September 30, 2023 and assumes a 2023 Brent price of $84.16 per barrel of oil, NGL realizations consistent with prior years and an average daily NYMEX gas price of $2.77 per mcf. (5) Represents estimated net cash settlement payments for derivative contracts as of 9/30/2023, except 2021, 2022, 1Q23, 2Q23 and 3Q23 which are actuals for the year ended on December 31, 2021, the year ended December 31, 2022, the three months ended March 31, 2023, the three months ended June 30, 2023, and the three months ended September 30, 2023 respectively. Historical settlements include natural gas derivatives on production volumes. STRATEGY OIL HEDGES2 As of September 30, 2023 2021 2022 1Q23 2Q23 3Q23 4Q23E 2023E 2024E 2025E ($319) ($738) ($65) ($63) ($95) ($75) ($300) ($35) ($20) HEDGE CONTRACT SETTLEMENTS EXPECTED TO SIGNIFICANTLY DECREASE IN 4Q234 AND BEYOND 48 $40 $50 $60 $70 $80 $90 $100 $110 $120 Crude Rev Net Hedges No Hedges 2024 CRUDE REVENUE NET HEDGE SETTLEMENT SENSITIVITY TO BRENT PRICE 1 ($MM) Est. 2024 Brent Price (~$80/bbl) CRC Realized Price ($/bbl) $60 $63 $65 $71 $79 $88 $91 $94 $97 Actual & Estimated Hedge Contract Settlements5 ($MM) 4Q23 1Q24 2Q24 3Q24 4Q24 2025 SOLD CALLS Barrels per Day 5,747 23,650 30,000 30,000 29,000 19,748 Weighted- Average Price per Barrel $57.06 $90.00 $90.07 $90.07 $90.07 $85.63 SWAPS Barrels per Day 27,094 9,000 7,750 7,750 5,500 3,374 Weighted- Average Price per Barrel $70.73 $79.37 $79.65 $79.64 $77.45 $72.66 NET PURCHASED PUTS3 Barrels per Day 5,747 30,584 30,000 30,000 29,000 19,748 Weighted- Average Price per Barrel $76.25 $67.27 $65.17 $65.17 $65.17 $60.00 2 0 2 4 C R U D E R E V E N U E
Glossary Term Definition FID Final Investment Decision GHG Greenhouse Gas IRR Internal Rate of Return KMTPA Thousand Metric Tons Per Annum LCFS Low Carbon Fuel Standard MMT Million Metric Tons MMTPA Million Metric Tons Per Annum MRV Monitoring, Reporting and Verification Plan MT Metric Tons MTPA Metric Tons Per Annum OCF Operating Cash Flow PD Proved Developed PUD Proved Undeveloped RSG Responsibly Sourced Gas ROFL Right of First Look R/P Reserves to Production Ratio RTC Round-the-Clock SFDR Sustainable Finance Disclosure Regulation SRP Share Repurchase Program SJV San Joaquin Valley TBA To Be Announced Tcf Trillion Cubic Feet WI Working Interest Term Definition Bcf Billion Cubic Feet BMT Billion Metric Tons CARB California Air Resources Board CCS Carbon Capture and Storage CCS+ Carbon Capture and Storage + EOR CDMA Carbon Dioxide Management Agreement CEQA California Environmental Quality Act CGP Cryogenic Gas Plant CI Carbon Intensity CMB Carbon Management Business CO2 Carbon Dioxide CTV Carbon TerraVault (a subsidiary of CRC) DAC Direct Air Capture D&C Drilling and Completions E&P Exploration and Production EHPP Elk Hills Power Plant EIR Environmental Impact Report EOR Enhanced Oil Recovery EPA Environmental Protection Agency ESG Environmental, Social and Governance FCF Free Cash Flow FEED Front End Engineering and Design 49
Assumptions & Relevant Footnotes: Slide 7: ▪ (1) Source: Internal estimates. ▪ (2) EPA, source: www.epa.gov/uic/class-vi-wells-permitted-epa ▪ (3) The CTV JV partnership is targeting 5MMTPA of CO2 injection by YE 2027 which implies 200MMT of CO2 pore space under Class VI EPA permits. CTV JV is under 49% Brookfield ownership. ▪ (4) See slides 45 and 46 for the details on the CTV project economic type curve assumptions. Earnings before interest, taxes, depreciation and amortization (EBITDA) is a non-GAAP measure. EBITDA estimates include 45Q tax credits. Results subject to effects of taxes, timing, pace of project development and Brookfield further approval to fund capital. Slide 12: ▪ Source: Internal estimates. Numbers may not add up due to rounding. SJ Basin implies San Joaquin basin. ▪ (1) Our CDMAs frame the anticipated contractual terms between parties and provide a path to reaching final definitive agreements. ▪ (2) Source: CARB 2020. ▪ (3) Includes CRC’s decarbonization CCS project at Elk Hills gas plant planned to sequester 100KMPTA of CO2 which is not under CDMA. Assumes minimum voluntary commitment injection rate for each announced CTV I project. ▪ (4) Injection rates are average rates based on max permit volumes over life of project using a 40-year basis. Actual volumes and the injection period will vary over time. ▪ (5) 26R injection capacity as per the draft EPA permit is 38MMT. Assuming the maximum expected injection rate of 1.46 MMTPA, the reservoir would reach capacity in 26 years. Each CTV reservoir will have a unique set of operating, injection and life span parameters that will vary and will be reflected on the submitted permit. See slide 15 of this deck for the details on the CTV project economic type curve for the 26R reservoir. ▪ (6) Internal estimates as of October 2023. Represents remaining capacity after taking into account pore space attributable to signed CDMAs and CRC’s projects. Slide 16: ▪ (1) Internal estimates. ▪ (2) Earnings before interest, taxes, depreciation and amortization (EBITDA) is a non-GAAP measure. ▪ (3) Assumes a 12-year project life. See slide 15 of this deck for the details on the CTV project economic type curve and opex details for the 26R reservoir. ▪ (4) Earnings before interest, taxes, depreciation and amortization (EBITDA) is a non-GAAP measure. EBITDA estimates include 45Q tax credits, which may change based on further guidance from IRS and other factors, of $85 per metric ton of sequestered CO2; assumes $100 LCFS price for approximately 20% of sequestered CO2 ; anticipates 90% of the CO2 volume sequestered avoids cap and trade(C&T) costs assumed at $35 per metric ton. Slide 36: ▪ (1) Reserves estimated as of December 31, 2022 using $80.00 per barrel for oil, $54.17 per barrel of NGLs and $4.97 per Mcf for natural gas. PV-10 is a non-GAAP measure. GAAP does not prescribe a standardized measure of reserves on a basis other than SEC Prices. As such, a GAAP reconciliation for reserves estimated using $80.00 per barrel for oil, $54.17 per barrel of NGLs and $4.97 per Mcf for natural gas has not been provided. ▪ (2) Calculated using reserves estimated as of December 31, 2022, using $80.00 per barrel for oil described in footnote one and divided by annualized average 1H23 production. ▪ (3) Calculated using internal estimates of 2022 Scope 1 and Scope 2 emissions from our oil and gas operations divided by gross production. Excludes emissions from Elk Hills power plant related to power not used in our operations. Slide 38: ▪ (1) Internal estimates. The SEC prohibits oil and gas companies, in their filings with the SEC, from disclosing estimates of oil or gas resources other than “reserves,” as that term is defined by the SEC. This presentation includes estimates of quantities of oil and gas using certain terms, such as “opportunity set” or other descriptions of volumes of reserves, which terms include quantities of oil and gas that may not meet the SEC’s definitions of proved, probable and possible reserves, and which the SEC’s guidelines strictly prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being recovered. Readers are urged to consider closely the reserves and other disclosures in our periodic filings with the SEC. ▪ (2) CRC is pursuing a RSG certification for its natural gas assets. This certification depends on many factors which may or may not be achievable. ▪ (3) Source: ICE forward market price as of October 18, 2023. ▪ (4) Subject to availability of drilling permits and additional surface infrastructure which may be needed. 50
Assumptions & Relevant Footnotes (Cont.): Slide 44: The information on slide 44 is an example of project economics for the strategic partnership with Brookfield, which are shared 51% to CRC and 49% to Brookfield. The terms and availability of third-party sources of financing, if needed, could also affect returns and outcomes. The following assumptions were used: ▪ Assumes that projects are completed and online with no material delays or impediments to the issuance of necessary permits, government approvals, or third party third-party arrangements. ▪ Assumes development at the mid-point of the CTV JV economic “Type Curve”. ▪ Assumes 1MMT injected per year for 40-year project life unless specified otherwise. ▪ Assumes Brookfield fully participates in CCS projects up to JV target of 5MMTPA of injection and 200MMT of CO2 storage. ▪ EBITDA amounts that are shown as a range assume the top and bottom ranges of the EBITDA assumptions and are multiplied by 1MM and 5MM to represent 1MMTPA of projects and 5MMTPA of projects, respectively. The EBITDA range presented has been reduced by ~20% – 50% to reflect uncertainties related to project structure, financing and ownership. ▪ EBITDA estimates include 45Q tax credits which may change based on further guidance from IRS and other factors and assumes that 45Q wage and apprenticeship requirements are met. Based on incentives available under current regulatory framework. ▪ Assumes total incentive potential can be monetized through tax equity brokers and LCFS monetized in the LCFS trading marketplace and recorded as revenue. ▪ For simplicity, a 5-year accelerated straight line depreciation and amortization is assumed. Assumes no bonus depreciation. which may change based on further guidance from IRS and other factors. ▪ Assumes that a project is cash flow positive in year 4 with payback period of ~ 4 to 6 years and reflects the midpoint of range estimates. Payback period is defined as total CRC investment / annual cash flow and is specifically for CTV JV project level economics. ▪ High end of Opex range assumes end-to-end value chain business model and low-end assumes carbon storage business model, both described on slide 23 of CRC’s Carbon Storage Update on October 6, 2021. ▪ Capex range assumes project capital of between $200MM and $800MM for an end-to-end business model. Project/partnership structures where CRC provides storage only could result in capital ranges below stated ranges. 51
Free Cash Flow Reconciliation Management uses the non-GAAP measure of free cash flow, which is defined by us as net cash provided by operating activities less our capital investment, as a measure of liquidity. The table below presents a reconciliation of net cash provided by operating activities to free cash flow. Free Cash Flow 4Q23E ($MM) Low High Est. Net Cash Provided by Operating Activities $115 $125 Est. Capital Investment (75) (65) Est. Free Cash Flow $40 $60 Note: Free Cash Flow is a non-GAAP measure. For all historical non-GAAP financial measures please see the Investor Relations page at www.crc.com for a reconciliation to the nearest GAAP equivalent and other additional information. 52
• fluctuations in commodity prices, including supply and demand considerations for our products and services; • decisions as to production levels and/or pricing by OPEC or U.S. producers in future periods; • government policy, war and political conditions and events, including the war in Ukraine and Israel, and oil sanctions on Russia, Iran and others; • regulatory actions and changes that affect the oil and gas industry generally and us in particular, including (1) the availability or timing of, or conditions imposed on, permits and approvals necessary for drilling or development activities or our carbon management business; (2) the management of energy, water, land, greenhouse gases (GHGs) or other emissions, (3) the protection of health, safety and the environment, or (4) the transportation, marketing and sale of our products; • the impact of inflation on future expenses and changes generally in the prices of goods and services; • changes in business strategy and our capital plan; • lower-than-expected production or higher-than-expected production decline rates; • changes to our estimates of reserves and related future cash flows, including changes arising from our inability to develop such reserves in a timely manner, and any inability to replace such reserves; • the recoverability of resources and unexpected geologic conditions; • general economic conditions and trends, including conditions in the worldwide financial, trade and credit markets; • production-sharing contracts' effects on production and operating costs; • the lack of available equipment, service or labor price inflation; • limitations on transportation or storage capacity and the need to shut-in wells; • any failure of risk management; • results from operations and competition in the industries in which we operate; • our ability to realize the anticipated benefits from prior or future efforts to reduce costs; • environmental risks and liability under federal, regional, state, provincial, tribal, local and international environmental laws and regulations (including remedial actions); • the creditworthiness and performance of our counterparties, including financial institutions, operating partners, CCS project participants and other parties; • reorganization or restructuring of our operations; • our ability to claim and utilize tax credits or other incentives in connection with our CCS projects, • our ability to realize the benefits contemplated by our energy transition strategies and initiatives, including CCS projects and other renewable energy efforts; • our ability to successfully identify, develop and finance carbon capture and storage projects and other renewable energy efforts, including those in connection with the Carbon TerraVault JV, and our ability to convert our CDMAs to definitive agreements and enter into other offtake agreements; • our ability to maximize the value of our carbon management business and operate it on a stand alone basis; • our ability to successfully develop infrastructure projects and enter into third party contracts on contemplated terms; • uncertainty around the accounting of emissions and our ability to successfully gather and verify emissions data and other environmental impacts; • changes to our dividend policy and share repurchase program, and our ability to declare future dividends or repurchase shares under our debt agreements; • limitations on our financial flexibility due to existing and future debt; • insufficient cash flow to fund our capital plan and other planned investments and return capital to shareholders; • changes in interest rates; • our access to and the terms of credit in commercial banking and capital markets, including our ability to refinance our debt or obtain separate financing for our carbon management business; • changes in state, federal or international tax rates, including our ability to utilize our net operating loss carryforwards to reduce our income tax obligations; • effects of hedging transactions; • the effect of our stock price on costs associated with incentive compensation; • inability to enter into desirable transactions, including joint ventures, divestitures of oil and natural gas properties and real estate, and acquisitions, and our ability to achieve any expected synergies; • disruptions due to earthquakes, forest fires, floods, extreme weather events or other natural occurrences, accidents, mechanical failures, power outages, transportation or storage constraints, labor difficulties, cybersecurity breaches or attacks or other catastrophic events; • pandemics, epidemics, outbreaks, or other public health events, such as the COVID-19; and • other factors discussed in Part I, Item 1A – Risk Factors. This document contains statements that we believe to be “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than historical facts are forward-looking statements, and include statements regarding our future financial position, business strategy, projected revenues, earnings, costs, capital expenditures and plans and objectives of management for the future. Words such as “expect,” “could,” “may,” “anticipate,” “intend,” “plan,” “ability,” “believe,” “seek,” “see,” “will,” “would,” “estimate,” “forecast,” “target,” “guidance,” “outlook,” “opportunity” or “strategy” or similar expressions are generally intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements. Although we believe the expectations and forecasts reflected in our forward-looking statements are reasonable, they are inherently subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. No assurance can be given that such forward-looking statements will be correct or achieved or that the assumptions are accurate or will not change over time. Particular uncertainties that could cause our actual results to be materially different than those expressed in our forward-looking statements include: Forward Looking / Cautionary Statements – Certain Terms We caution you not to place undue reliance on forward-looking statements contained in this document, which speak only as of the filing date, and we undertake no obligation to update this information. This document may also contain information from third party sources. This data may involve a number of assumptions and limitations, and we have not independently verified them and do not warrant the accuracy or completeness of such third-party information. 53
Joanna Park (Investor Relations) 818-661-3731 Joanna.Park@crc.com Richard Venn (Media) 818-661-6014 Richard.Venn@crc.com