Slides
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Third Quarter 2026 Results November 2, 2026
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Strengthening California’s Leading Energy Infrastructure Platform 3Q26 Results Highlights 152MBoe/d Total Net Production ~80% Oil $341MM Adj. EBITDAX * $158MM Total Capital $155MM E&P $66MM Total Shareholder Returns 4 $300MM Cash Flow Before W/C * Enhancing Our California Core • Strong reservoir performance driving ~2% sequential net production growth • Announced an agreement to divest Uinta Basin assets • Closed all - cash acquisition of Crimson which includes key rights - of - way that help build a foundation for a potential statewide CO 2 pipeline system 1 2 Commitment to Shareholder Returns • $66MM returned to shareholders in 3Q26 including $30MM in share repurchases and $36MM in dividends; ~45% of quarterly free cash flow *, 4 • ~4% increase in quarterly dividend to $0.42 per share; ~3.0% annual dividend yield vs. peer average of ~1.8% 4, 5 Expanding Our Leading Carbon Management Business • Signed MOU 2 with Bloom Energy for development of 1GW or more of clean power and storage of up to 3MMTPA of CO 2 emissions • Submitted new EPA Class VI permit application for ~57MMT of CO 2 emissions bringing total submitted EPA Class VI permit volumes to ~409MMT 3 BLOOM 1GW or More and 3MMTPA MOU 2 ~57MMT New EPA Class VI Permit Submitted 3 Note: “Before WC Changes” means “Before Net Changes in Operating Assets and Liabilities”. See slide 24 for “Assumptions, Estimates and Endnotes”. ~4% Quarterly Dividend Increase 4
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California Focused 3 • ~2,000 - mile Crimson diversified midstream system and storage to link Central California production to 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 • Acquisition includes land rights that help build a foundation for the long - term development of a potential CO 2 pipeline system 3 • Targeting the re - opening of S an Pablo Bay Pipeline in 1Q27 Accretive Attractively Priced ~$63MM Cash 2 Industrial Logic 4.4x EV/27E Adj. EBITDA *, 1 Strong Asset Fit Closed Crimson Acquisition • Accretive sale to cost structure and capital : Capital reallocation toward shareholder returns and other corporate purposes • ~0.5% estimated improvement to corporate Brent - linked oil realizations • Initial purchase price to be adjusted based on an economic effective date of July 1, 2026 (other than for certain items) and other transaction and closing costs 5 • Closing expected by year - end 2026, subject to customary closing conditions Unlocking Capital Reallocated Uinta 2026E D&C Capital 6 Strategic Sale Attractively Priced ~$90MM Cash 5 CRC Focus Unconventional Asset California ~$35MM ~$90MM Initial Purchase Price 5 Potential Unlocked Funds Announced the Divestiture of Non - Core Uinta Basin 4 Net Mineral Acres : ~100,000 acres 1H26 Oil Realization : ~79% of WTI Net Revenue Interest : ~61% 1H26 Operating Cost/Boe : ~$26/Boe Total ARO Liability: ~$32MM See slide 24 for “Assumptions, Estimates and Endnotes”.
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Building Momentum Through Year - End 2026 4 $0 $300 $600 $900 $1,200 2023 2024 2025 2026E $0 $500 $1,000 $1,500 2023 2024 2025 2026E (MBoe/d) Total Net Production ($MM) Adj. EBITDAX * ($MM) Operating Cash Flow Before W/C * Added Production in Lower Price Environments $50 $60 $70 $80 $90 $100 0 40 80 120 160 2023 2024 2025 2026E Brent ($/Bbl) Driving a ~15% Earnings CAGR Robust Cash Flow Growth $0 $500 $1,000 $1,500 $2,000 2023 2024 2025 2026E ($MM) Cumulative Shareholder Returns 2 Commitment to Shareholder Returns Note: “Before WC Changes” means “Before Net Changes in Operating Assets and Liabilities”. See slide 24 for “Assumptions, Estimates and Endnotes”. 2026E 1 2026E 1 2026E 1 2026E 1
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CRC CRC Aera BRY $200 $300 $400 $500 $600 2023 2026E CRC CRC Aera BRY $600 $1,000 $1,400 $1,800 $2,200 2023 2026E Significant Improvement Since 2023 5 Brent ($/Bbl) Headcount (#) ($MM) Operating Costs ($MM) G&A Expense $82.22 $92.26 ~2,275 3 >3,000 Reduced Operating Costs and G&A Expense by >$740MM Since 2023 Through Timely M&A Activity 1 Improvement In Operating Cost Structure ~28% Improvement In G&A Cost Structure ~30% See slide 24 for “Assumptions, Estimates and Endnotes”. 2026E 2 2026E 2 2023 1 2023 1
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6 ($600) ($500) ($400) ($300) ($200) ($100) $0 2023 2024 2025 2026 2027E – 28E 2027E – 28E 108% 1 of Berry target captured 6 months early 6 See slide 25 for “Assumptions, Estimates and Endnotes”. Cumulative Implemented Synergies and Structural Cost Reductions ($MM) G&A Operating Costs Other (Capital and Other) M&A Driven (2023 – 26) Organically Driven (2027 – 28) The Next Phase : Organic Cost Reductions Lower controllable cost structure while maintaining safe, reliable operations and our ability to grow Streamline Our Foundation Standardize core systems and connect enterprise data Simplify How We Work Align how work gets done across the business, removing duplication remaining after the mergers Apply AI and Digital Tools Move faster, reduce manual work, and improve productivity Unlocking the Value of Our Assets: The Next Chapter of CRC From Integration Synergies to Organic Efficiencies Cost reduction targets to be shared with our 2027 plan
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100 110 120 130 140 150 160 1Q26 2Q26 3Q26 4Q26E Oil NGLs NG 7 SoCal Border ($/MMBtu) $3.05 $1.22 $3.13 $3.62 Net Production (MBoe/d) Energy Operating Costs ($/Boe) Strong Production Performance Energy Costs Dependent on Fuel Prices • Net oil production rose sequentially by ~1% to 121 MBo/d, primarily related to sale of crude oil inventory, and drilling and workover activity • First CCS project enabled stronger than previously anticipated NGL yields and added ~1 MBoe/d in 3Q26 • Stronger electricity prices drove higher EHPP utilization and higher natural gas sales • Uinta net production contributed ~4 MBoe/d to 3Q26 results Brent ($/Bbl) $77.90 $96.87 $91.36 $102.90 • Higher - than - anticipated natural gas prices drove an increase in energy operating costs for internal field operations • All - time high diesel cracks led to high energy operating costs for drilling rig operations • Disciplined hedge strategy mitigates fuel energy volatility with ~58% of 4Q26E natural gas consumption at an average price of $4.23/MMBtu; ~58% of 2027E natural gas consumption hedged at an average price of $3.98/MMBtu 2 3Q26 Commentary See slide 25 for “Assumptions, Estimates and Endnotes”. $0.00 $2.00 $4.00 $6.00 $8.00 $10.00 1Q26 2Q26 3Q26 4Q26E 4Q26E 1 4Q26E 1
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First CCS Project Drives Incremental NGL Yields 8 • First CCS project cleans inlet gas to CRC’s Elk Hills cryogenic gas plant, supporting incremental gas processing capacity and subsequently increased NGL yields • Connection from Belridge production field to Elk Hills cryogenic gas plant supplies additional natural gas for processing • Established infrastructure to support natural gas development and future infrastructure integration opportunities in the area Benefits of Our Integrated Strategy in Action See slide 25 for “Assumptions, Estimates and Endnotes”. 9 10 11 12 13 Jan Feb Mar Apr May Jun Jul Aug Sep 2026 Gross NGL Production (MBoe/d) NGL Yield Increase from Belridge Connection Connection Between Belridge and Elk Hills Fields Supports Natural Gas Optimization ~6MMcf/d Incremental Net Gas Production ~1MBoe/d Increase in Net NGLs Production ~$20MM 1 Est. Annual Revenue Benefit Belridge Elk Hills
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9 Bloom MOU 1 to Advance Clean Power Solutions in California X See slide 25 for “Assumptions, Estimates and Endnotes”. CTV and Bloom Energy to jointly evaluate and target the potential development of solid - oxide fuel cell power generation paired with CCS across California • Identifying and developing new commercial pathways with potential power offtake customers • Initially contemplating FTM and BTM power opportunities: 1. FTM Clean Energy Projects – targeting multiple projects with potential connection to CTV’s vast California storage portfolio and utility offtake 2. BTM Clean Energy Opportunities – additional contemplated projects across CRC’s Central Valley footprint, designed for industries seeking on - site, clean and reliable power Central California ~12.3MMTPA EPA Class VI Permit Volumes Northern California ~5.6MMTPA EPA Class VI Permit Volumes Collaboration with Leading Clean Power Producer Power Generation of 1GW or More Up to 3MMTPA of CO 2 Emissions Developing Potential FTM & BTM Clean Power Solutions in CA CTV EPA Class VI Permit Volumes 2 (MMTPA) MOU 1 leverages the combined strengths of both companies to develop baseload clean power solutions in California • CRC’s proven track record of developing projects from permitting to execution • CTV’s leading CCS storage platform in California • Bloom’s clean, non - combustion fuel cells with a high - concentration CO₂ stream improving the efficiency of CCS Carbon TerraVault • Premier CO 2 Storage Platform • California Permitting Experience • Access to Natural Gas Resources Bloom Energy • Non - Combustion Technology • High CO 2 Concentration • Proven Supplier at Scale Carbon TerraVault x Bloom Energy
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0 2 4 6 8 10 12 - 5 10 15 20 25 30 Tenaska ExxonMobil Occidental CRC Chevron River Parish Tallgrass BKV Minnkota Power OnStream CO2 • California’s first CCS project operational • Submitted a new EPA Class VI permit (CTV VIII) for ~57MMT 2 of storage • Anticipating the receipt of one or more additional draft EPA Class VI permits by year - end 2026 2 10 Total Reservoir Injection Capacity Submitted for Permits (MMTPA) Total CO 2 Storage Projects (#) 36% EPA Class VI Wells (US) 2 Largest individual share of wells under EPA lead agency review CTV Others 88% California Class VI Wells 2 Dominant share of the emerging California CCS market CTV Others See slide 25 for “Assumptions, Estimates and Endnotes”. CTV: 4 th Largest Carbon Management Platform in the U.S. 1 California’s Leading CO 2 Storage Portfolio
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0% 1% 2% 3% S&P 500 S&P 400 S&P 600 XOP ETF CRC $35 $45 $55 $65 $- $50 $100 $150 $200 $250 $300 1Q24 2Q24 3Q24 4Q24 1Q25 2Q25 3Q25 4Q25 1Q26 2Q26 3Q26 Dividends Share Repurchases Average CRC Share Price $0.00 $0.10 $0.20 $0.30 $0.40 $0.50 $0 $40 $80 $120 $160 Dividends Paid Quarterly DPS (Year-End) 2021 2022 2023 2024 2025 2026E 11 See slide 25 for “Assumptions, Estimates and Endnotes”. Commitment to Long - Term Dividend Growth ($MM) Dividends Paid 1 Opportunistic Share Repurchases Create Value CRC Share Price ($/Share) Quarterly Dividend per Share ($/Share) Dividend Yield 2 ($MM) Quarterly Shareholder Returns 1 $1,721MM of cumulative shareholder returns since 2021 ~4% Increase in Quarterly Dividend ~20% Dividend per Share CAGR 2021 – 2026E
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$80 $90 $100 $110 1Q26 2Q26 3Q26 4Q26E Crimson Est. Annual Performance-Based Compensation $210 $235 $260 $285 $310 1Q26 2Q26 3Q26 4Q26E 12 3Q26 Results Commodity 3Q26A Oil Realizations (% of Brent) ~91% NGL Realizations (% of Brent) ~53% Natural Gas Realizations (% of NYMEX) ~119% Operational and Financial Net Production (MBoe/d) 152 Net Oil Production (MBo/d) 121 Operating Costs ($MM) $386 G&A Expenses ($MM) $89 Adj. G&A Expenses * ($MM) $79 Taxes Other Than on Income ($MM) $81 Transportation Costs ($MM) $31 Other Operating Expenses Net of Other Revenue *, 2 $35 Total Capital ($MM) $158 Adj. EBITDAX * ($MM) $341 Operating Cash Flow Before WC Changes * $300 Free Cash Flow Before WC Changes * $142 Other Items Margin from Purchased Commodities *, 3 $15 Electricity Revenue Net of Electricity Generation Expenses *, 4 $35 Total Return of Cash to Shareholders 5 ($MM) Share Repurchases ($MM) $30 Dividends Paid ($MM) $36 Total Shareholder Returns ($MM) $66 Note: “Before WC Changes” means “Before Net Changes in Operating Assets and Liabilities”. See slide 25 for “Assumptions, Estimates and Endnotes”. ($MM) Operating Cash Flow Before WC Changes * ($MM) G&A Expense Improving the Core Cost Structure to Grow Long - Term Cash Flow ~$6MM for Est. Annual Performance - Based Compensation ~$4MM for Crimson 4Q26E 1 4Q26E 1
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Southern California Northern California 13 California’s Leading Energy Infrastructure Platform Carbon Capture & Storage Low Carbon Intensity Oil & Gas Production Midstream Infrastructure Geothermal Opportunities Power Generation Solar Opportunities 3 rd Party Power Opportunities ~147MBoe/d 3 2026E CA Net Production (~80% Oil) ❑ 4 th Largest Economy in the World and 2 nd Largest Consumer of Energy in the U.S. 1 ❑ Historical Increase in Reliance on Energy Imports, While Local Production has Declined ❑ Unique Supply and Demand Dynamics Drive Premium Energy Price Environment CRC’s California Energy Portfolio ~18MMTPA 4 EPA Class VI CO 2 Permit Volumes Submitted ~1.9MM Mineral Acres ~23 Years 2 2P Reserve Life Index ~1GW Power Generation Capacity Nearly CCS Project Operating CA’s First CCS Project ~400Mbo/d Crude Oil Transportation Capacity ~350MMcf/d Natural Gas Transportation Capacity >5MMBbls Total Liquids Storage Capacity Integrated Assets Across the Energy Value Chain Active Up to See slide 26 for “Assumptions, Estimates and Endnotes”. Central California
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Guidance & Capital Structure 14
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15 CRC Guidance (as of November 2, 2026) 4Q26E Consolidated Oil and Natural Gas Carbon Management Net Production (MBoe/d) ~79% Oil 150 – 152 Margin from Purchased Commodities *, 1 ($MM) $11 – $15 Electricity Revenue Net of Electricity Generation Expenses ($MM) 2 $5 – $11 Operating Costs ($MM) $370 – $390 $370 – $390 G&A ($MM) $95 – $99 $12 – $16 $0 – $2 Adjusted G&A * ($MM) $83 – $93 $12 – $16 $0 – $2 Depreciation, Depletion and Amortization ($MM) $ 128 – $140 $120 – $130 Other Operating Expenses Net of Other Revenue *, 3 ($MM) $ 20 – $30 $4 – $12 Transportation Expense ($MM) $ 30 – $35 $20 – $24 Taxes Other Than on Income ($MM) $68 – $78 $60 – $66 Interest and Debt Expense, Net ($MM) $28 – $32 Capital ($MM) $ 110 – $130 $110 – $125 $0 – $2 Adj. EBITDAX * ($MM) $340 – $380 Other Assumptions 4Q26E Brent ($/ Bbl ) $102.90 NYMEX ($/Mcf) $3.25 Oil – % of Brent 91% – 93% NGL – % of Brent 55% – 62% Natural Gas – % of NYMEX 110% – 116 % Current Income Tax Provision 4 ($ MM) ($2) – $2 Effective Tax Rate 27% – 31% 4Q26 Outlook (inclusive of Uinta) See slide 26 for “Assumptions, Estimates and Endnotes”. Early 2027 Thoughts ~6 Rigs $ 450 - $ 475 MM 2027E D&C and Workover Capital * Flat Entry to Exit Gross Production Annual Cadence • Targeting restart of the SPBP in 1Q27 • Expect return to normalized oil realization levels Est. QoQ impact due to PSC effects ~1MBoe/d Est. impact to G&A due to annual performance - based compensation and Crimson ~$10MM 4Q26 Commentary Of capital to support 2027 development readiness ~$8MM
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$750 $550 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 16 16 ▪ S&P upgraded corporate rating to BB - ▪ Borrowing base reaffirmed at $1.5B in October 2026 ▪ Extended maturity of revolving credit facility to March 2030 Strong Balance Sheet and Financial Flexibility Long - Dated Debt Maturities Support Strategic Growth Recent Highlights Liquidity Snapshot See slide 27 for “Assumptions, Estimates and Endnotes”. Net Debt * as of September 30, 2026 ($MM) Revolving Credit Facility (RCF) $ – 7.000% 2034 Senior Notes 750 7.250% 2035 Senior Notes 550 Face Value of Total Debt $ 1,300 Less: Available Cash & Cash Equivalents 1 (35) Net Debt * $ 1,265 Liquidity *, 2 $ 1,315 3Q26 Net Leverage *, 3 1.0x 3Q26 Interest Coverage *, 4 11.0x Unsecured Senior Notes ($MM) No Debt Maturities Until 2034
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Appendix 17
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Sustainability is Embedded in Our Operations 18 Near - Term Ambition Reduction in Average Carbon Intensity of Oil & Gas Operations ≥20% by 2035 from 2020 Baseline Long - Term Goal Responsible Net Zero by 2045 from 2020 Baseline Reduction in Scope 1 & 2 Emissions ≥80% Goal to Reduce Absolute Scope 1 & 2 Emissions, and Neutralize Remaining Emissions 1 Climate ~25% Reduction in Scope 1 and 2 emissions vs 2020 baseline 2 Stewardship “Grade A” MiQ certification rating for the majority of operations 3 Carbon ~409MMT CO 2 emission permit volumes submitted to the EPA 4 Water ~4.6B Gal Treated, reclaimed water delivered to California; ~3x internal consumption Community >$2.0MM Charitable donations to support local communities Governance ~30% Executive compensation tied to ESG - related goals 2025 Sustainability Update See slide 27 for “Assumptions, Estimates and Endnotes”.
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~60 ~30 California’s Premier Carbon Management Provider 19 ▪ In May 2026, started sequestering CO 2 at California’s first CCS project at CRC’s Elk Hills cryogenic gas plant ▪ Anticipating the receipt of one or more Class VI draft permits for additional reservoirs in 2026 1 Annual Regional CO 2 Emissions (MMTPA) Target Addressable Market by Region 3 Vault / Reservoir Targeted EPA Class VI Permit Decision 1 Est. Annual Injection Rate 1 (MMTPA) Permit Volumes 1 (MMT) Draft Permit Final Permit EPA Class VI Permit 20 Years 40 Years CTV I 26R Permit Received ~1.5 2 ~1.9 ~1.0 ~38 CTV I A1 - A2 2026 2026 ~0.8 ~0.4 ~0.2 ~8 Carbon Frontier 2026 2027 ~3.3 ~1.6 ~0.8 ~32 CTV VI 2027 2027 ~3.4 ~5.1 ~2.5 ~102 CTV VII - - ~1.4 ~1.4 ~0.7 ~27 CTV VIII NEW - - ~1.9 ~2.9 ~1.4 ~57 Central California ~12.3 ~13.3 ~6.6 ~264 CTV II 2027 2027 ~1.0 ~1.2 ~0.6 ~23 CTV III 2026 2027 ~2.5 ~3.6 ~1.8 ~71 CTV IV 2027 2027 ~1.4 ~1.7 ~0.9 ~34 CTV V 2027 2027 ~0.7 ~0.8 ~0.4 ~17 Northern California ~5.6 ~7.3 ~3.7 ~145 Total - Combined ~17.9 ~20.6 ~10.3 ~409 See slide 27 for “Assumptions, Estimates and Endnotes”.
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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 20 Approximately 12% of CRC’s gross oil production is subject to PSC 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 27 for “Assumptions, Estimates and Endnotes”.
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21 CRC’s hedging strategy is designed to meet our business objectives should market prices decline and participate in upside should market prices increase STRATEGY ~ 65 % of remaining 2026E net oil production hedged at an average Brent floor price of ~$65/ Bbl 1 EXECUTION ~58% of remaining 2026E internal fuel consumption hedged at an average n atural gas price of ~$4.23/MMBtu 1 OPERATIONS Hedge Portfolio (as of September 30, 2026) See slide 27 for “Assumptions, Estimates and Endnotes”. Oil Production Units 4Q26E 1Q27E 2Q27E 3Q27E 4Q27E 2028E Calls (Short) – Brent Bbl/d 36,000 1,250 5,250 500 2,862 35,434 $/Bbl $83.51 $70.47 $72.07 $69.30 $69.79 $84.29 Swaps (Short) – Brent Bbl/d 41,703 80,811 65,014 68,047 64,761 7,285 $/Bbl $67.98 $66.04 $65.54 $65.57 $65.56 $66.98 Puts (Long) 2 – Brent Bbl/d 36,000 1,250 5,250 500 2,862 53,734 $/Bbl $61.11 $60.00 $61.90 $60.00 $60.00 $60.89 Natural Gas Consumption Units 4Q26E 1Q27E 2Q27E 3Q27E 4Q27E 2028E Swap (Long) – SoCal Border MMBtu/d 9,908 14,044 - - - - $/MMBtu $4.84 $4.77 - - - - Swap (Long) – NWPL Rockies 3 MMBtu/d 91,750 94,336 94,170 92,000 91,326 62,725 $/MMBtu $4.17 $4.18 $3.78 $3.88 $3.95 $3.59 Combined Portfolio Units 4Q26E 1Q27E 2Q27E 3Q27E 4Q27E 2028E Est. Hedge Contract Settlements 4 $MM ($159) ($179) ($142) ($117) ($93) ($68)
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Commodity Price Realizations 22 Note: 5 largest contributors to domestic GDP . Source: BEA, preliminary data for 2Q26; EIA ▪ Crude: 3Q26 Brent crude oil prices were volatile as a result of the conflict in the Middle East, the conflict between Russia and Ukraine, and shifting expectations for cessation of hostilities or further escalation in each. California price realizations are expected to have troughed as alternative pathways to market are being actioned. ▪ NGLs: 3Q26 natural gas liquids prices pulled back slightly Q/Q on slightly higher realizations, while Y/Y, liquids prices have increased but have failed to keep pace with crude oil prices. California NGLs maintain a meaningful premium to the broader North American market. ▪ Natural Gas: Broadly, 3Q26 natural gas prices remained rangebound. California natural gas prices increased Q/Q as transportation alternatives out of key North American production basins came online requiring California to compete for out - of - state supplies. Market area storage remains elevated. $64.27 $69.37 $76.43 $72.46 4Q25 1Q26 2Q26 3Q26 $3.91 $3.56 $1.84 $3.52 4Q25 1Q26 2Q26 3Q26 CALIFORNIA IS AN OIL ISLAND AND THE LARGEST U.S. GDP CONTRIBUTOR (amounts shown as % of U.S. domestic GDP) Oil w/ Hedges ($/BBL) NGLs ($/BBL) Natural Gas ($/MCF) Average Benchmark Prices 1 $63.08 $77.90 $96.87 $91.36 $63.08 $77.90 $96.87 $91.36 $3.55 $5.04 $2.90 $2.96 % of Benchmark 1 97% 96% 95% 91% 68% 58% 51% 53% 110% 71% 63% 119% Hedge Settlements $3.13 ($5.16) ($15.12) ($10.96) - - - - - - - - Average Realized Prices 2 $64.27 $69.37 $76.43 $72.46 $42.86 $44.98 $49.62 $48.57 $3.91 $3.56 $1.84 $3.52 $42.86 $44.98 $49.62 $48.57 4Q25 1Q26 2Q26 3Q26 See slide 27 for “Assumptions, Estimates and Endnotes”. 13.9% 9.6% 5.9% 8.1% 4.0% California Commodity Pricing Generally 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 23 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 24 Slide 2 : 1) Development of a CO 2 pipeline system is subject to further acquisition of all necessary land rights, permitting, engineering, construction and significant capital expenditures over a multi - year period . No assurance can be given that any such development will occur . 2) MOUs are non - binding agreements . The projects and transactions described in an MOU are subject to certain conditions precedent, typically including the negotiation of definitive documents, a final investment decision by the parties and receipt of EPA Class VI permits and other regulatory approvals . 3) Permit volumes refers to carbon storage shown in EPA Class VI permits that CTV has received or submitted . The actual volumes that CTV may ultimately store may differ from the permit volumes as additional technical and commercial data is acquired and evaluated . Injection rates are average rates based on estimated maximum permit volumes over the assumed life of project . Actual volumes and the injection period may vary over time . 4) 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 . 5) Source : FactSet as of October 30 , 2026 . Peers include APA, BKV, CHRD, CRK, CRGY, GPOR, KOS, MGY, MTDR, MUR, NOG, RRC, SOC, SM, TALO and VET . Slide 3 : 1) Estimated 2027 adjusted EBITDA is based on CRC’s projections for Crimson and : (i) 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 ), (ii) assumes transportation rates consistent with existing tariffs (including contemplated increases, a portion of which are interim until rate case settlement), (iii) includes payments made by CRC as a shipper on certain of the acquired pipelines, and (iv) 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 . 2) Initial purchase price excludes $ 7 million of preliminary purchase price adjustments . The final purchase price remains subject to certain adjustments . 3) Development of a CO 2 pipeline system is subject to further acquisition of all necessary land rights, permitting, engineering, construction and significant capital expenditures over a multi - year period . No assurance can be given that any such development will occur . 4) The transaction has an effective date of July 1 , 2026 , is subject to receipt of certain third - party consents and customary closing conditions, and is expected to close by year - end 2026 . Following the closing of the transaction, CRC expects to provide additional financial and operating guidance . 5) Before transaction costs and customary purchase price adjustments . CRC bears the following post - effective date cost of approximately $ 4 MM in drilling and completions capital, and other customary purchase price adjustments . 6) Reallocated capital represents $ 46 MM of 2026 budgeted capital reduced by $ 11 MM in actual amounts spent . Slide 4 : 1) Total year 2026 E estimates assume a 4 Q 26 E Brent price of $ 102 . 90 per barrel of oil, NGL realizations consistent with prior years and an average daily NYMEX gas price of $ 3 . 25 per mcf . Generally, CRC’s share of production under PSCs decreases when commodity prices rise and increases when prices decline . See slide 15 for 4 Q 26 E guidance . 2) 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 5 : 1) 2023 information represents the combined costs for legacy CRC, legacy BRY and legacy Aera, and excludes presentation adjustments, transaction adjustments and financing adjustments . Operating costs for Aera have been restated using CRC’s accounting classification . 2) Total year 2026 E estimates assume a 4 Q 26 E Brent price of $ 102 . 90 per barrel of oil, NGL realizations consistent with prior years and an average daily NYMEX gas price of $ 3 . 25 per mcf . Generally, CRC’s share of production under PSCs decreases when commodity prices rise and increases when prices decline . See slide 15 for 4 Q 26 E guidance . 3) Includes approximately 600 employees in the C&J Well Services business .
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Assumptions, Estimates and Endnotes 25 Slide 6 : 1) Information relative to the midpoint of the Berry merger synergy target of $ 90 MM - $ 100 MM . Slide 7 : 1) Total year 2026 E estimates assume a 4 Q 26 E Brent price of $ 102 . 90 per barrel of oil, NGL realizations consistent with prior years and an average daily NYMEX gas price of $ 3 . 25 per mcf . Generally, CRC’s share of production under PSCs decreases when commodity prices rise and increases when prices decline . See slide 15 for 4 Q 26 E guidance . 2) Subject to commodity prices and market factors . Slide 8 : 1) Estimate assumes a Brent price of $ 93 . 28 per barrel of oil, NGL realizations consistent with prior years and an average daily NYMEX gas price of $ 3 . 05 per Mcf . Slide 9 : 1) MOUs are non - binding agreements . The projects and transactions described in an MOU are subject to certain conditions precedent, typically including the negotiation of definitive documents, a final investment decision by the parties and receipt of EPA Class VI permits and other regulatory approvals . 2) Permit volumes refers to carbon storage shown in EPA Class VI permits that CTV has received or submitted . The actual volumes that CTV may ultimately store may differ from the permit volumes as additional technical and commercial data is acquired and evaluated . Injection rates are average rates based on estimated maximum permit volumes over the assumed life of project . Actual volumes and the injection period may vary over time . Slide 10 : 1) Source : Enverus (October 2026 ) and internal estimates . 2) Source : EPA as of October 23 , 2026 , www . epa . gov/uic/class - vi - wells - permitted - epa . Permit volumes refers to carbon storage shown in EPA Class VI permits that CTV has received or submitted . The actual volumes that CTV may ultimately store may differ from the permit volumes as additional technical and commercial data is acquired and evaluated . Injection rates are average rates based on estimated maximum permit volumes over the assumed life of project . Actual volumes and the injection period may vary over time . Slide 11 : 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 : FactSet as of October 30 , 2026 . Represents CRC’s current annual dividend policy of $ 1 . 68 per share divided by CRC’s share price as of October 30 , 2026 . Slide 12 : 1) Total year 2026 E estimates assume a 4 Q 26 E Brent price of $ 102 . 90 per barrel of oil, NGL realizations consistent with prior years and an average daily NYMEX gas price of $ 3 . 25 per mcf . Generally, CRC’s share of production under PSCs decreases when commodity prices rise and increases when prices decline . See slide 15 for 4 Q 26 E guidance . 2) 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 . 3) 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 . 4) Electricity revenue net of electricity generation expenses is calculated as the difference between electricity sales and electricity generation expenses . 5) 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 .
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Assumptions, Estimates and Endnotes 26 Slide 13 : 1) Source : EIA, total energy consumption estimates 2024 . 2) Data reflect reserves and annual production volumes as of December 31 , 2025 using SEC Prices of $ 69 . 38 per barrel for oil and $ 3 . 39 per MMBtu for natural gas . CRC’s production volumes include Berry Corporation’s volumes for 14 days following the transaction close . Production amounts used are reported results and are not presented on a pro forma basis . Information includes Uinta assets that were owned as of year - end 2025 and that CRC expects to divest by year - end 2026 . • Proved Reserves : Proved developed (PD) reserves include proved developed producing (PDP) and proved developed non - producing (PDNP) reserves . • Probable Reserves : Probable reserves are those reserves that are less certain to be recovered than proved reserves but, when aggregated with proved reserves, are as likely as not to be recovered . Probable reserves are subject to greater uncertainty regarding recoverability and economic viability and may not ultimately be recovered . Estimates of probable reserves have not been prepared in accordance with SEC definitions applicable to proved reserves and should not be construed as equivalent thereto . CRC’s probable reserves are internally prepared estimates, are not independently audited, and are not subject to the same internal control framework applicable to proved reserves . A reserve adjustment factor has not been applied to PV - 10 , a non - GAAP measure . • CRC’s proved reserves totaled 654 MMBOE and probable reserves totaled 526 MMBOE at 2025 SEC pricing (after adjustments for price realizations) . • Reserve estimates are inherently uncertain and constitute forward - looking statements based on assumptions regarding commodity prices, costs, development timing, and reservoir performance ; actual results may differ materially . Estimates of future net revenues should not be construed as fair market value . Categories of proved and probable reserves have been established to reflect the level of these uncertainties and to provide an indication of the probability of recovery . The estimation and classification of reserves require the application of professional judgment and geological and engineering knowledge to assess whether specific classification criteria have been satisfied . CRC’s estimates of proved and probable reserves are presented herein because management believes it is useful information that is widely used by the investment community in the valuation, comparison and analysis of companies . However, we note that the SEC prohibits companies from aggregating proved and probable reserves in filings with the SEC due to the different levels of certainty associated with each reserve category . 3) Total year 2026 E estimates assume a 4 Q 26 E Brent price of $ 102 . 90 per barrel of oil, NGL realizations consistent with prior years and an average daily NYMEX gas price of $ 3 . 25 per mcf . Generally, CRC’s share of production under PSCs decreases when commodity prices rise and increases when prices decline . See slide 15 for 4 Q 26 E guidance . 4) Permit volumes refers to carbon storage shown in EPA Class VI permits that CTV has received or submitted . The actual volumes that CTV may ultimately store may differ from the permit volumes as additional technical and commercial data is acquired and evaluated . Injection rates are average rates based on estimated maximum permit volumes over the assumed life of project . Actual volumes and the injection period may vary over time . Slide 15 : 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 .
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Assumptions, Estimates and Endnotes 27 Slide 16 : 1) Available cash and cash equivalents excludes $ 13 MM of restricted cash . 2) Liquidity on September 30 , 2026 is calculated as $ 35 MM of cash and cash equivalents (excluding $ 13 MM of restricted cash) plus $ 1 , 460 MM of borrowing capacity on CRC’s revolving credit facility less $ 180 MM in outstanding letters of credit . 3) Net leverage is calculated as 3 Q 26 net debt of $ 1 , 265 MM (excluding restricted cash of $ 13 MM) divided by LTM adjusted EBITDAX of $ 1 , 234 MM . 4) Interest coverage is calculated as LTM adjusted EBITDAX of $ 1 , 234 MM divided by LTM interest expense of $ 112 MM . Slide 18 : 1) Planned use of either carbon offsets generated and claimed internally or carbon offsets purchased and claimed through the third - party carbon market (including California’s Cap - and - Invest Program) for Scope 1 GHG emissions, and use of contractual instruments such as renewable energy certificates or carbon offsets for Scope 2 GHG emissions . 2) Excludes sustainability metrics related to Berry which merged with CRC on December 18 , 2025 , unless otherwise expressly noted . 3) MiQ certification covers production operations in the San Joaquin, Ventura and Los Angeles basins . 4) Permit volumes refers to carbon storage shown in EPA Class VI permits that CTV has received or submitted . The actual volumes that CTV may ultimately store may differ from the permit volumes as additional technical and commercial data is acquired and evaluated . Injection rates are average rates based on estimated maximum permit volumes over the assumed life of project . Actual volumes and the injection period may vary over time . Slide 19 : 1) Source : EPA as of October 23 , 2026 , www . epa . gov/uic/class - vi - wells - permitted - epa . Permit volumes refers to carbon storage shown in EPA Class VI permits that CTV has received or submitted . The actual volumes that CTV may ultimately store may differ from the permit volumes as additional technical and commercial data is acquired and evaluated . Injection rates are average rates based on estimated maximum permit volumes over the assumed life of project . Actual volumes and the injection period may vary over time . 2) 26 R injection volumes as per the EPA permit is ~ 38 MMT . Assuming the maximum expected injection rate of 1 . 46 MMTPA, the reservoir would reach permitted volumes 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 . 3) Source : CARB 2020 . Slide 20 : 1) Net Production from Wilmington field only . Includes the effects of a development program in the Los Angeles basin . Slide 21 : 1) Subject to commodity prices and market factors . 2) Purchased and sold puts with the same strike price have been netted together . 3) NWPL volumes require transportation to where the gas is consumed . These costs are reflected in our 4 Q 26 E transportation guidance . See slide 15 for 4 Q 26 E guidance . 4) Represents estimated net cash settlement payments inclusive of premiums for derivative contracts and forward commodity prices as of September 30 , 2026 . Slide 22 : 1) Benchmark prices are based on Brent for oil and NGLs, and NYMEX average monthly settled 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 28 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, OPEC+ or U . S . producers ; government policy, war and political conditions and events ; changes in price realizations ; integration efforts and projected synergies and other benefits in connection with the Berry Merger, Crimson acquisition and other acquisitions ; divestitures and joint ventures, including the Uinta divestiture ; regulatory actions and changes that affect the oil and gas industry generally and CRC 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 its 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 and improve capital efficiencies ; 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, transportation and storage projects, power projects and other renewable energy efforts, including those contemplated by the Bloom MOU ; changes in transportation costs and CRC's ability to develop midstream opportunities ; delays from government approvals and otherwise that could affect the timing of project s ; 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 document, 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 29 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, Operating Cash Flow Before WC Changes, Adjusted G&A Expense, Other Operating Expenses Net of Other Revenue, Margin from Purchased Commodities, Electricity Revenue Net of Electricity Generation Expenses, PV - 10 , Net Debt, Liquidity, Free Cash Flow, Free Cash Flow Before WC Changes, Net Leverage and Interest Coverage . 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