Slides
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Second Quarter 2026 Results August 10 , 2026 CALIFORNIA RESOURCES
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2 Strengthening CA’s Leading Energy Infrastructure Platform • Acquiring Crimson for ~$63MM in cash to secure direct E&P access to California’s highest - value markets 1 • Adding ~2,000 miles of strategic pipeline infrastructure, storage capacity and third - party throughput Strong Execution in California • Implemented ~$103MM in Berry - related synergies - 6 months ahead of schedule; Delivered ~25% improvement in 2Q26 drilling efficiencies 2 • Lowering 2026E D&C and workover capital * by $10MM; Maintaining total 2026E capital plan and ~1% entry - to - exit production growth 3 • Lowering long - term D&C and workover maintenance capital * by ~5% with six rigs Advancing Carbon & Power Platforms • Began CO₂ injection and achieved first revenue at California’s first commercial - scale CCS project • Partnered with Beacon Data Centers to advance a potential Golden Valley Technology Hub Executing Our Strategy 2Q26 Key Messages 2 See slide 22 for “Assumptions, Estimates and Endnotes”.
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• Purchased a 118 - mile, 60 MBbl /d crude pipeline system connecting key Central Valley production hubs (1Q26) • Added >1.0 MMBbl of oil storage capacity with integrated gathering, transportation and truck loading infrastructure 3 • ~2,000 - mile pipe system and storage to link Central California’s production to the highest - value markets and other growth opportunities • Deal includes: SoCal Pipeline Network, IVEC Line, San Pablo Bay Pipeline, KLM Pipeline and other strategic assets • Transaction includes any proceeds from pending rate cases Strengthening California’s Leading Energy Infrastructure Platform CTV VI CTV II CTV III CTV V CTV IV San Francisco Stockton Fresno San Jose Accretive Attractively Priced ~$63MM Cash 3 Industrial Logic 4.4x EV/27E Adj. EBITDA *,2 Strong Asset Fit CTV I A1/A2 CTV I 26R CTV VII Carbon Frontier Bakersfield Acquired an Integrated Central Valley Midstream Network - Line 100 (P66) • Improved operational reliability and commercial flexibility while c reating a more efficient and integrated Central Valley operating platform Agreement to Acquire Crimson, a Diversified Midstream Platform 1 See slide 22 for “Assumptions, Estimates and Endnotes”.
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($500) ($400) ($300) ($200) ($100) $0 2023 2024 2025 2026E 2027E-28E Structural Cost Reductions Driving Margin Expansion 4 Benefits of a Leaner CRC Targeted Cumulative Synergies and Structural Cost Reductions ($MM) ~$470MM Targeting Up To of Cumulative Synergies and Cost Reductions Through 2028 2026 Berry - Related Synergies ($MM) >100% Implementation of Synergies G&A Expense ~$48MM ~$103MM Operating Costs ~$35MM Interest Expense ~$20MM Months Ahead of Schedule ~6
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5 See slide 22 for “Assumptions, Estimates and Endnotes”. Improvement in Drilling New Wells / Sidetracks 2Q26 Planned 2Q26 Drilled New Wells / Sidetracks Workovers 77 108 124 96 # of California Drilled Wells ~25% Efficient Execution Strong California Reservoir Performance Net Gross 168 167 151 149 Holding Near Flat California Production with 5 Rigs Jan 2026 Brent $64.73/Bbl Dec 2026E Brent $79.26/Bbl Entry Production Est. Exit Production CRC California Production (MBoe/d) 1
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6 6 ~5 Rigs $370 - $390MM 2026E D&C and Workover Capital *, 1 ~1% Entry to Exit Gross Growth Annual Cadence Improvement in 2026E D&C and Workover Capital *, 1 $10MM Improving 2026E Capital Efficiency 156 155 Net Gross Dec 2026E Brent $ 79.26 /Bbl Jan 2026 Brent $64.73/Bbl 174 175 ▪ 1 Utah rig in 3Q26 and 5 California rigs in 2H26, expecting to enter 2027 with 6 rigs in California ▪ All 2026 drilling permits on hand , CRC continues to build its 2027 permit inventory Maintaining Production Outlook See slide 22 for “Assumptions, Estimates and Endnotes”. Est. Exit Production Entry Production CRC Production (MBoe/d) 1 Delivering Growth in 2026
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7 2026 Demonstrating Strong Execution Improved Long - Term Outlook Holding Nearly Flat Entry - to - Exit Gross Production With ~5 rigs Lowering LT D&C and Workover Maintenance Capital * to $450 - $475MM with 6 rigs • 24/7 rig mobilization, including safe nighttime moves • Continuous drilling campaigns with dedicated rig and crew continuity • Improved CRC – C&J coordination reducing idle time • Implementation of Berry - related synergies Lower Long - Term Maintenance Capital Efficiency Gains in California Enhance Long - Term Outlook Executing Our Strategy 5%
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Golden Valley Technology Hub | Uniquely Positioned 8 California’s ‘’Premier’’ Data Center Campus PARTNERSHIP WITH BEACON DATA CENTERS A LEADING NORTH AMERICAN CO - DEVELOPER GOLDEN VALLEY TECHNOLOGY HUB • UNPARALLELED LAND POSITION • EXISTING POWER PLANT • SOCIALLY - RESPONSIBLE DEVELOPMENT • STRONG PARTNER WITH EARLY DEVELOPMENT CAPITAL DEPLOYED PROVEN PERMITTING TEAM • HISTORICAL TRACK RECORD OF SUCCESS • CONDITIONAL USE PERMIT SUBMITTED • ENVIRONMENTAL IMPACT REPORT TO BE SUBMITTED IN 4Q26 TARGETED VALUE CAPTURE • HYPERSCALER COMMITMENT – LOI • CONTRACTED POWER – PPA • RECEIPT OF PERMITS • PROJECT FID • PROJECT ONLINE CTV I A1/A2 CTV I 26R Elk Hills Oil Field 275MW | INTERCONNECT WITH PG&E | GROWTH OPPORTUNITY ~550 MW CRC’s Elk Hills Power Plant 0 4 Miles Proposed ’’Premier’’ Data Center Campus Elk Hills Power Plant Proposed Data Center Location Site Note: See www.goldenvalleytechhub.com for additional information.
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9 Golden Valley Technology Hub | Community Focused Water • Closed - loop cooling — lowest - use category of any data center design • 600,000 - gal initial fill (~30 residential pools); Expect ~6,000 gal/yr recharge (<1/3 pool/yr) Power • Powered directly by CRC - owned Elk Hills Power Plant | ~275 MW available power capacity • Developer funds all project infrastructure; no rate impact or grid upgrades Noise • Sited on existing industrial land; nearest residence ~1 mile away • Noise profile comparable to a mid - sized office building Jobs • ~1,500 peak construction jobs; up to 250 permanent operating roles • First CA O&G company with a statewide Project Labor Agreement Tax Revenue • Recurring property tax on real & data - center personal property • CRC was the #1 taxpayer in Kern County in 2025 1 The project is expected to provide the following community benefits: Note: See www.goldenvalleytechhub.com for additional information. CRC internal estimates. See slide 22 for “Assumptions, Esti mat es and Endnotes”.
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0% 10% 20% 30% 40% 50% 60% 70% 80% CRC Peer Average Share Repurchases Dividends Paid 10 Balanced Capital Approach Robust Historical Shareholder Return Profile Organic Growth & Strategic Deals 2021 – 1H26 Cumulative Shareholder Returns 1 (% of Free Cash Flow * ) ~75% of Cumulative Free Cash Flow * Returned to Shareholders since 2021 See slide 22 for “Assumptions, Estimates and Endnotes”. Balance Sheet Strength Dividend Growth & Opportunistic Buybacks Balanced Capital Pillars 2
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11 Strong 2Q26 Commodity 2Q26A Oil Realizations (% of Brent) ~95% NGL Realizations (% of Brent) ~51% Natural Gas Realizations (% of NYMEX) ~63% Operational and Financial Net Production (MBoe/d) 149 Net Oil Production (MBo/d) 120 Operating Costs ($MM) $347 G&A Expenses ($MM) $97 Adj. G&A Expenses * ($MM) $89 Taxes Other Than on Income ($MM) $66 Transportation Costs ($MM) $30 Other Operating Expenses Net of Other Revenue *,3 $56 Total Capital ($MM) $149 Adj. EBITDAX * ($MM) $338 Operating Cash Flow Before WC Changes * $300 Free Cash Flow Before WC Changes * $151 Other Items Margin from Purchased Commodities *, 4 $11 Electricity Revenue Net of Electricity Generation Expenses *, 5 ($4) Total Return of Cash to Shareholders 6 ($MM) Share Repurchases ($MM) - Dividends Paid ($MM) $36 Total Shareholder Returns ($MM) $36 Note: “Before WC Changes” means “Before Net Changes in Operating Assets and Liabilities”. See slide 23 for “Assumptions, Estimates and Endnotes”. $106 $97 $80 $90 $100 $110 1Q26A 2Q26A 3Q26E 4Q26E Synergies Drive Lower G&A Outlook G&A Expenses 2 ($MM) Production and Financial Results 149 1.5 120 130 140 150 160 1Q26A 2Q26A Net Production Built Inventory Net Production 1 (MBoe/d) $300 $25 $160 $240 $320 1Q26A 2Q26A Impact from Stacked Production and Other Operating Cash Flow Before WC Changes* Operating Cash Flow Before WC Changes *,1 ($MM)
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Guidance & Capital Structure 12
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13 2026E Consolidated Oil and Natural Gas Carbon Management 150 – 155 $50 – $65 $20 – $40 $1,425 – $1,475 $1,425 – $1,475 $365 – $385 $51 – $63 $4 – $10 $335 – $350 $51 – $63 $4 – $10 $520 – $540 $500 – $510 $135 – $145 $20 – $30 $115 – $125 $75 – $85 $272 – $282 $240 – $246 $115 – $125 $520 – $560 $505 – $530 $10 – $18 $1,200 – $1,300 2026E $84.51 $3.55 92% – 96% 52% – 57% 80% – 85% ($2) – $2 33% – 37% 4 CRC Guidance (as of July 15, 2026) 3Q26E Consolidated Oil and Natural Gas Carbon Management Net Production (MBoe/d) ~80% Oil 151 – 154 Margin from Purchased Commodities *, 1 ($MM) $11 – $15 Electricity Revenue Net of Electricity Generation Expenses ($MM) 2 $ 18 – $24 Operating Costs ($MM) $360 – $380 $360 – $380 G&A ($MM) $ 82 – $92 $12 – $16 $0 – $2 Adjusted G&A * ($MM) $ 75 – $85 $12 – $16 $0 – $2 Depreciation, Depletion and Amortization ($MM) $ 126 – $138 $120 – $130 Other Operating Expenses Net of Other Revenue *, 3 ($MM) $ 20 – $32 $4 – $12 Transportation Expense ($MM) $ 30 – $35 $20 – $24 Taxes Other Than on Income ($MM) $ 70 – $80 $62 – $68 Interest and Debt Expense, Net ($MM) $27 – $31 Capital ($MM) $ 150 – $170 $150 – $165 $0 – $2 Adj. EBITDAX * ($MM) $ 285 – $325 Other Assumptions 3Q26E Brent ($/Bbl) $83.14 NYMEX ($/Mcf) $2.95 Oil – % of Brent 91% – 94% NGL – % of Brent 48% – 54 % Natural Gas – % of NYMEX 97% – 103 % Current Income Tax Provision 4 ($ MM) ($2) – $2 Effective Tax Rate 33% – 37% 2026 Outlook ~70% ~22% ~ 3% ~5% D&C and Workovers Facilities CMB Corporate and Other 5 2026E Capital $520 - $560 MM See slide 23 for “Assumptions, Estimates and Endnotes”. 2026 Commentary ~94% 2026E Oil - % of Brent CRC plans to update 2026E guidance once Crimson transaction is closed *
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14 14 Liquidity Net Debt * Snapshot as of June 30, 2026 ($MM) Revolving Credit Facility (RCF) $ - 7.000% 2034 Senior Notes 750 7.250% 2035 Senior Notes 550 Face Value of Debt $ 1,300 Less Available Cash & Cash Equivalents 1 (43) Net Debt * $ 1,257 Liquidity *, 2 $ 1,322 ($MM) RCF Borrowing Base $1,500 2Q26 Free Cash Flow * $114 2Q26 Net Debt * / LTM Adj. EBITDAX *, 3 1.0x LTM Adj. EBITDAX * / LTM Interest Expense *, 4 11.1x Strong Coverage Ratios ▪ Fitch upgraded corporate rating to BB - ▪ Issued $550MM in 7.250% 2035 Senior Notes at par ▪ Redeemed $550MM in 8.250% 2029 Senior Notes ▪ Borrowing base reaffirmed at $1.5B in April 2026 $750 $550 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 Capital Structure Provides Flexibility Long Dated Debt Maturity Profile Strong Balance Sheet and Ample Liquidity 2Q26 Highlights Unsecured Senior Notes ($MM) See slide 23 for “Assumptions, Estimates and Endnotes”.
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Appendix 15
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16 Leading Position Setting Industry Precedent 30% EPA Class VI Wells (US) 1 Largest individual share of wells under EPA lead agency review CTV Others 27% EPA CO₂ Injection Rate (US) 2 Over one - quarter of the injection rate EPA is evaluating CTV Others 86% California Class VI Wells 1 Dominant share of the emerging California CCS market CTV Others 1 Permitting & Operations ✓ First EPA Class VI permit in U.S. since ADM ✓ First Class VI injection operations in California ✓ First CO₂ sequestration in depleted hydrocarbon reservoir 2 Well Design & Construction ✓ First repurposed injection well ✓ First repurposed monitoring wells ✓ First 25Cr OCTG installation for Class VI 3 Monitoring & Technology ✓ First seismic monitoring for CCS in California ✓ First public, realtime monitoring via live website ✓ First CCS tech deployments: VAM® 21 CW, CorrosaLok ® Advancing the National CCS Industry CARBON TERRAVAULT | Major share of EPA’s active Class VI portfolio with first - of - a - kind technical and operational leadership See slide 23 for “Assumptions, Estimates and Endnotes”.
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Joined the Ranks of Global CCS Leaders 1 17 1 1 of only 2 U.S. oil & gas companies actively storing CO 2 underground through EPA Class VI geologic sequestration wells 2 1 of 6 commercial - scale CCS sequestration projects in the U.S. permanently injecting and storing CO₂ in dedicated geologic formations (EPA class VI) 3 1 of 15 commercial - scale CCS projects globally actively injecting and storing CO₂ (Non - EOR, Non - Acid Gas Injection) 4 California's first and only commercial - scale CCS project operational and injecting CO₂ in the state Amongst an Elite Global Sequestration Peer Group Positioned alongside some of the world's proven commercial - scale CCS operators CRC Elk Hills, California Chevron Gorgon, Australia ExxonMobil Strathcona, Canada Shell Quest, Canada Equinor Snøhvit , Norway Santos Moomba, Australia CO₂ Line to Injection Pad EPA CO 2 Sample Collection Capture Equipment See slide 23 for “Assumptions, Estimates and Endnotes”. Permanent Geologic Sequestration by Country — Non - EOR, Non - Acid Gas Injection (MMTPA) U.S.A. 4.5 6 projects Australia 2.8 2 projects Norway 2.3 3 project Qatar 2.1 1 project China 1.5 1 projects Canada 1.0 1 project Italy <0.1 1 project Verified actual (MTPA) CRC CA project (+0.10 MTPA) CARBON TERRAVAULT | A Differentiated Position in Global CCS
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0 5,000 10,000 15,000 20,000 $50 $55 $60 $65 $70 $75 $80 $85 $90 $95 $100 $105 $110 Brent ($/BBL) Cost Recovery Bbls Net Profit Bbls 45 - 49% of Gross Production Gross Production Net Production +/ - $1/Bbl - /+ ~ 70 Bo/ d at lower prices (low recovery) +/ - $1/Bbl - /+ ~ 60 Bo/d at higher prices +/ - $1/Bbl - /+ ~90 Bo/d at mid point ~ 2.2 Mb o/d increase in net production ~ 1.9 Mbo/ d decrease in net production CRC sees a difference of ~4.1 MBO/D in net oil production between $50/Bbl and $110/Bbl 1 Effect Of Oil Price On Net Production 1 Wilmington Field Production (Bo/d) Production Sharing Contracts (PSC) at Higher Prices 18 Approximatively 12% of CRC’s gross oil production is subject to PSCs Mechanics: ▪ CRC pays its partners’ share of operating and capital cost ▪ CRC recovers 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 “profit barrels” are recovered See slide 24 for “Assumptions, Estimates and Endnotes”.
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19 OIL PRODUCTION 3Q26E 4Q26E 1Q27E 2Q27E 2H27E 2028E SOLD CALLS Brent Barrels per Day 36,000 36,000 1,250 5,250 1,681 17,534 Weighted - Average Price $83.51 $83.51 $70.47 $72.07 $69.72 $81.28 SWAPS Brent Barrels per Day 42,869 41,703 80,811 65,014 66,404 7,285 Weighted - Average Price $68.20 $67.98 $66.04 $65.54 $65.56 $66.98 PURCHASED PUTS 1 Brent Barrels per Day 36,000 36,000 1,250 5,250 1,681 17,534 Weighted - Average Price $61.11 $61.11 $60.00 $61.90 $60.00 $62.74 NATURAL GAS CONSUMPTION 3Q26E 4Q26E 1Q27E 2Q27E 2H27E 2028E SWAPS SoCal Border MMBtu per Day 10,750 9,908 14,044 - - - Weighted - Average Price $4.83 $4.84 $4.77 - - - NWPL Rockies 2 MMBtu per Day 91,750 91,750 94,336 94,170 91,663 32,475 Weighted - Average Price $3.76 $4.17 $4.18 $3.78 $3.92 $3.45 EST. HEDGE CONTRACT SETTLEMENTS 3 3Q26E 4Q26E 1Q27E 2Q27E 2H27E 2028E Combined Hedge Portfolio ($MM) ($38) ($33) ($44) ($48) ($68) ($6) CRC’s hedging strategy is designed to meet our business objectives should market prices decline and participate in upside should market prices increase STRATEGY ~64% of remaining 2026E net oil production hedged at an average Brent floor price of ~$65/Bbl 4 EXECUTION ~ 59 % of remaining 2026E internal fuel consumption hedged at an average n atural gas price of ~$4.05/MMBtu 4 OPERATIONS Hedge Portfolio (as of June 30, 2026) See slide 24 for “Assumptions, Estimates and Endnotes”.
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Commodity Price Realizations 20 13.8% 8.0% 9.4 % 6.0 % 3.9 % Note: 5 largest contributors to domestic GDP . Source: BEA, preliminary data for 1Q26; EIA ▪ Crude: 2Q26 Brent crude prices rose sharply Q/Q and Y/Y as hostilities continued across the Middle East. California realizations came under limited pressure as incremental production and Jones Act waivers introduced additional crude into the California market. ▪ Natural Gas: 2Q26 North American natural gas prices were lower Q/Q and Y/Y as unseasonably cold weather was replaced by generally seasonal temperatures and growing natural gas production. California 2Q26 natural gas prices – as with prices across the Western US – were pressured by an absence of weather demand, out - of - state imports, and an abundance of gas in storage. ▪ NGLs: 2Q26 NGL prices were higher Q/Q on seasonally lower realizations as NGL prices moved in sympathy with crude prices. California NGLs continue to carry a material premium to the broader North American NGL market. $67.04 $64.27 $69.37 $76.43 3Q25 4Q25 1Q26 2Q26 $3.47 $3.91 $3.56 $1.84 3Q25 4Q25 1Q26 2Q26 CALIFORNIA IS AN OIL ISLAND AND THE LARGEST U.S. GDP CONTRIBUTOR (amounts shown as % of U.S. domestic GDP) Oil w/ Hedges ($/BBL) NGLs ($/BBL) Natural Gas ($/MCF) Average Benchmark Prices 1 $68.13 $63.08 $77.90 $96.87 $68.13 $63.08 $77.90 $96.87 $3.07 $3.55 $5.04 $2.90 % of Benchmark 1 97% 97% 96% 95% 60% 68% 58% 51% 113% 110% 71% 63% Hedge Settlements $0.72 $3.13 ($5.16) ($15.12) - - - - - - - - Average Realized Prices 2 $67.04 $64.27 $69.37 $76.43 $41.04 $42.86 $44.98 $49.62 $3.47 $3.91 $3.56 $1.84 $41.04 $42.86 $44.98 $49.62 3Q25 4Q25 1Q26 2Q26 See slide 24 for “Assumptions, Estimates and Endnotes”. CRC’s commodity realizations are historically above domestic averages
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Term Definition KMTPA Thousand Metric Tons Per Annum LCFS Low Carbon Fuel Standard LTM Last Twelve Months MMT Million Metric Tons MMTPA Million Metric Tons Per Annum MOIC Multiple on Invested Capital MOU Memorandum of Understanding MRV Monitoring, Reporting and Verification Plan MT Metric Tons MTPA Metric Tons Per Annum NG Natural Gas NGL Natural Gas Liquid NRI Net Revenue Interest OCF Operating Cash Flow PDP Proved Developed Producing PDNP Proved Developed Non - Producing PPA Power Purchase Agreement PUD Proved Undeveloped RA Resource Adequacy ROFL Right of First Look RSG Responsibly Sourced Gas R/P Reserves to Production Ratio RTC Round - the - Clock SEC United States Securities and Exchange Commission SFDR Sustainable Finance Disclosure Regulation SMOG Standardized Measure of Discounted Future Net Cash Flows SRP Share Repurchase Program SJV San Joaquin Valley TBA To Be Announced Tcf Trillion Cubic Feet WI Working Interest Glossary 21 Term Definition Bcf Billion Cubic Feet BMT Billion Metric Tons BTM Behind - the - Meter CARB California Air Resources Board CCS Carbon Capture and Storage CDMA Carbon Dioxide Management Agreement CEQA California Environmental Quality Act CGP Cryogenic Gas Plant CI Carbon Intensity CMB Carbon Management Business CO 2 Carbon Dioxide CTV Carbon TerraVault (a subsidiary of CRC) CUP Conditional Use Permit DAC Direct Air Capture D&C Drilling and Completions E&P Exploration and Production EBITDAX Earnings Before Interest, Taxes, Depreciation, Amortization and Exploration 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 FID Final Investment Decision FTM Front - of - the - Meter g/MJ Grams of CO 2 Equivalent per Megajoule of Energy Produced G&A General and Administrative GHG Greenhouse Gas IRR Internal Rate of Return JV Joint Venture
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Assumptions, Estimates and Endnotes 22 Slide 2 : 1) Subject to customary regulatory approvals, other closing conditions and is expected to close in the third quarter of 2026 . CRC plans to provide updated guidance following closing of the transaction . 2) Reflects the increase in wells drilled compared to initial plans described in CRC’s 1 Q 26 presentation . See slide 5 for additional information . 3) Total year 2026 E guidance assumes a 2026 E Brent price of $ 84 . 51 per barrel of oil, NGL realizations consistent with prior years and an average daily NYMEX gas price of $ 3 . 55 per mcf . Generally, CRC’s share of production under PSCs decreases when commodity prices rise and increases when prices decline . See slide 13 for 2026 E guidance . Slide 3 : 1) Subject to customary regulatory approvals, other closing conditions and is expected to close in the third quarter of 2026 . CRC plans to provide updated guidance following closing of the transaction . 2) Estimated 2027 adjusted EBITDA is based on CRC’s projections for Crimson and ( 1 ) assumes the acquired pipeline systems continue to operate at current levels (except for the San Pablo Bay pipeline where an increase in throughput is projected for 2027 ), ( 2 ) assumes transportation rates consistent with existing tariffs (including contemplated increases, a portion of which are interim until rate case settlement), ( 3 ) includes payments made by CRC as a shipper on certain of the acquired pipelines, and ( 4 ) does not include any material capital expenditures for that period . CRC has not included a reconciliation of this non - GAAP measure to its nearest GAAP equivalent because it cannot do so without unreasonable effort and any attempt to do so would be inherently imprecise . 3) Subject to certain customary adjustments . Slide 5 : 1) Total year 2026 E guidance assumes a 2026 E Brent price of $ 84 . 51 per barrel of oil, NGL realizations consistent with prior years and an average daily NYMEX gas price of $ 3 . 55 per mcf . Generally, CRC’s share of production under PSCs decreases when commodity prices rise and increases when prices decline . See slide 13 for 2026 E guidance . Slide 6 : 1) Total year 2026 E guidance assumes a 2026 E Brent price of $ 84 . 51 per barrel of oil, NGL realizations consistent with prior years and an average daily NYMEX gas price of $ 3 . 55 per mcf . Generally, CRC’s share of production under PSCs decreases when commodity prices rise and increases when prices decline . See slide 13 for 2026 E guidance . Slide 9 : 1) Source : Kern County Treasurer - Tax Collector . Slide 10 : 1) All CRC’s future quarterly dividends and share repurchases are subject to commodity prices, debt agreement covenants and Board of Directors approval . Excludes excise taxes and commissions paid on share repurchases . 2) Source : Bloomberg and company reports as of August 7 , 2026 . Peers include APA, BKV, CHRD, CRK, CRGY, GPOR, KOS, MGY, MTDR, MUR, NOG, RRC, SOC, SM, TALO and VET .
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Assumptions, Estimates and Endnotes 23 Slide 11 : 1) Built inventory represented approximately 1 . 5 MBo/d, and together with weaker differentials and higher transportation and operating costs associated with temporary takeaway constraints, reduced 2 Q 26 net cash provided by operating activities before net changes in operating assets and liabilities by approximately $ 25 million . 2) Total year 2026 E guidance assumes a 2026 E Brent price of $ 84 . 51 per barrel of oil, NGL realizations consistent with prior years and an average daily NYMEX gas price of $ 3 . 55 per mcf . Generally, CRC’s share of production under PSCs decreases when commodity prices rise and increases when prices decline . See slide 13 for 2026 E guidance . 3) Other operating expenses net of other revenue is calculated as the difference between other revenue and other operating expenses, net and includes exploration expense and CMB expenses . CMB expenses includes lease cost for sequestration easements, advocacy, and other startup related costs . We have updated this caption for better alignment to our condensed consolidated statements of operations . 4) Margin from purchased commodities is calculated as the difference between revenue from marketing of purchased commodities and costs related to marketing of purchased commodities, and excludes costs of transportation . 5) Electricity revenue net of electricity generation expenses is calculated as the difference between electricity sales and electricity generation expenses . 6) All CRC’s future quarterly dividends and share repurchases are subject to commodity prices, debt agreement covenants and Board of Directors’ approval . Excludes excise taxes and commissions paid on share repurchases . Slide 13 : 1) Margin from purchased commodities is calculated as the difference between revenue from marketing of purchased commodities and costs related to marketing of purchased commodities, and excludes costs of transportation . 2) Electricity revenue net of electricity generation expenses is calculated as the difference between electricity sales and electricity generation expenses . 3) Other operating expenses net of other revenue is calculated as the difference between other revenue and other operating expenses, net and includes exploration expense and CMB expenses . CMB expenses includes lease cost for sequestration easements, advocacy, and other startup related costs . 4) Current income tax composition is subject to variability and depends on a number of factors, including but not limited to, final taxable income determinations, the availability and utilization of net operating loss carryforwards (NOLs), applicable tax credits, and other differences between book and taxable income . Accordingly, the current provision may vary from period to period and should not be viewed as indicative of future tax obligations . 5) Corporate and other includes corporate, C&J Well Services and exploration capital . Slide 14 : 1) Available cash and cash equivalents excludes $ 13 MM of restricted cash . 2) Liquidity on June 30 , 2026 is calculated as $ 43 MM of cash and cash equivalents (excluding $ 13 MM of restricted cash) plus $ 1 , 279 MM of borrowing capacity on CRC’s revolving credit facility less $ 181 MM in outstanding letters of credit . 3) Net leverage is calculated as 2 Q 26 net debt of $ 1 , 257 MM (excluding restricted cash of $ 13 MM) divided by LTM adjusted EBITDAX of $ 1 , 231 MM . 4) Interest coverage is calculated as LTM adjusted EBITDAX of $ 1 , 231 MM and LTM interest expense of $ 111 MM . Slide 16 : 1) Source : EPA as of July 31 , 2026 , www . epa . gov/uic/class - vi - wells - permitted - epa . 2) Source : ccusmap . com Slide 17 : 1) Source : Enverus . Peers include projects operated by ADM, Basin Electric Power Cooperative, Gevo, Harvestone Group, Shell, Equinor, Santos, Chevron, Qatar Energy, ENI and Huaneng Group .
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Assumptions, Estimates and Endnotes 24 Slide 18 : 1) Net Production from Wilmington field only . Includes the effects of a development program in the Los Angeles basin . Slide 19 : 1) Purchased and sold puts with the same strike price have been netted together . 2) NPWL volumes require transportation to where the gas is consumed . These costs are reflected in our 2026 E transportation guidance . See slide 13 for 2026 E guidance . 3) Represents estimated net cash settlement payments inclusive of premiums for derivative contracts and forward commodity prices as of June 30 , 2026 . 4) Subject to commodity prices and market factors . Slide 20 : 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 .
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Forward - Looking / Cautionary Statements – Certain Terms 25 Forward - Looking Statements : Information set forth in this communication, including financial estimates and statements as to the effects of the Berry Merger and the Crimson acquisition, constitute “forward - looking statements” within the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 and other securities laws . All statements other than historical facts are forward - looking statements, and include statements regarding the benefits of the Berry Merger and the Crimson acquisition, CRC's future financial position, business strategy, projected revenues, earnings, costs, capital expenditures and plans and objectives and intentions 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 . These forward - looking statements are based upon the current beliefs and expectations of the management of CRC and are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, projected in, or implied by, such statements . Although CRC believes the expectations and forecasts reflected in its 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 its 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 CRC’s actual results to be materially different than those expressed in its forward - looking statements are described in its most recent Annual Report on Form 10 - K and its other periodic filings with the SEC . These factors include, but are not limited to : fluctuations in commodity prices ; production levels and/or pricing by OPEC+ or U . S . producers ; government policy, war and political conditions and events ; integration efforts and projected synergies and other benefits in connection with the Berry Merger, Crimson acquisition and other acquisitions ; divestitures and joint ventures ; regulatory actions and changes that affect the oil and gas industry generally and us in particular ; the efforts of activists to delay or prevent oil and gas activities or the development of CRC’s carbon management segment ; changes in business strategy and the ability and financial resources to execute our capital plan in a timely manner ; lower - than - expected production ; changes to estimates of reserves and related future cash flows ; the recoverability of resources and unexpected geologic conditions ; general economic conditions and trends ; results from operations and competition in the industries in which it operates ; CRC’s ability to realize the anticipated benefits from prior or future efforts to reduce costs ; environmental risks and liability ; the benefits contemplated by its energy transition strategies and initiatives ; CRC’s ability to successfully identify, develop and finance carbon capture and storage projects, power projects and other renewable energy efforts ; delays from government approvals and otherwise that could affect the timing of first injection of CO 2 ; future dividends and share repurchases and de - leveraging efforts ; and natural disasters, accidents, mechanical failures, power outages, labor difficulties, cybersecurity breaches or attacks or other catastrophic events . CRC cautions you not to place undue reliance on forward - looking statements contained in this communication, which speak only as of the date hereof, and CRC is under no obligation, and expressly disclaims any obligation to update, alter or otherwise revise any forward - looking statements, whether as a result of new information, future events or otherwise . This communication may also contain information from third - party sources . This data may involve a number of assumptions and limitations, and CRC has not independently verified them and does not warrant the accuracy or completeness of such third - party information .
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Forward - Looking / Cautionary Statements – Certain Terms 26 Non - GAAP Financial Measures : This presentation contains certain financial measures that are not prepared in accordance with generally accepted accounting principles (“GAAP”) . These measures are identified with an “*” and include but are not limited to Adjusted EBITDAX, Drilling, Completion and Workover Capital, Reserve Replacement Ratio, per Bbl Brent O&G Only Breakeven Price, Cash Flow from Operations before WC Changes, Adjusted G&A Expense, Other Operating Expenses Net of Other Revenue, Margin from Purchased Commodities, Electricity Margin, PV - 10 , Net Debt, Liquidity and Free Cash Flow . 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 . Additionally, this presentation includes forward - looking non - GAAP financial measures, including adjusted EBITDAX . CRC is unable to provide a reconciliation of such forward - looking non - GAAP measures to the most directly comparable forward - looking GAAP financial measures because certain information needed to reconcile these measures is dependent on future events, many of which are outside of CRC’s control and cannot be reasonably predicted at this time . These items include, but are not limited to, changes in working capital, the timing and amount of capital accruals, and other non - cash or unusual items . Accordingly, a quantitative reconciliation is not available without unreasonable efforts . Industry and Market Data : This presentation has been prepared by CRC and includes market data and other statistical information from sources it believes to be reliable, including independent industry publications, governmental publications or other published independent sources . Some data is also based on our good faith estimates, which are derived from CRC’s review of internal sources as well as the independent sources described above . Although CRC believes these sources are reliable, it has not independently verified the information and cannot guarantee its accuracy and completeness . CRC owns or has rights to various trademarks, service marks and trade names that it uses in connection with the operation of its business . This presentation also contains trademarks, service marks and trade names of third parties, which are the property of their respective owners . CRC’s use or display of third parties’ trademarks, service marks, trade names or products in this presentation is not intended to, and does not imply, a relationship with CRC or an endorsement or sponsorship by or of CRC .
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Daniel Juck Investor Relations 818 - 661 - 3700 CRC_IR@crc.com Hailey Bonus Media 714 - 874 - 7732 CRC.Communications@crc.com