Bakersfield ANALYST DAY & SITE TOUR October 14, 2015

Analyst Presentation – Day 2 FORWARD-LOOKING / CAUTIONARY STATEMENTS This presentation contains forward-looking statements that involve risks and uncertainties that could materially affect our expected results of operations, liquidity, cash flows and business prospects, and reported results should not be considered an indication of future performance. Such statements specifically include our expectations as to our future financial position, drilling program, production, projected costs, future operations, hedging activities, capital investments and other guidance included in this presentation. Factors (but not necessarily all the factors) that could cause results to differ include: commodity price fluctuations; the effect of our debt on the impact of economic downturns and adverse business developments; sufficiency of our operating cash flow to fund planned capital investments; the ability to obtain government permits and approvals; effectiveness of our capital investments; restrictions and changes in restrictions imposed by regulations including those related to our ability to obtain, use, manage or dispose of water; risks of drilling; tax law changes; the subjective nature of estimates of proved reserves and related future net cash flows; restriction of operations to, and concentration of exposure to events such as industrial accidents, refinery shutdowns, natural disasters and labor difficulties in, California; concerns about climate change and air quality issues; lower-than-expected production from development projects or acquisitions; catastrophic events for which we may be uninsured or underinsured; cyber attacks; operational issues that restrict market access; and uncertainties related to the spin-off, the agreements related thereto and the anticipated effects of restructuring or reorganizing our business. Material risks are further discussed in “Risk Factors” in our Annual Report on Form 10-K available on our website at crc.com. Words such as "aim," "anticipate," "believe," "budget," "continue," "could," "effort," "estimate," "expect," "forecast," "goal," "guidance," "intend," "likely," "may," "might," "objective," "outlook," "plan," "potential," "predict," "project," "seek," "should," "target, "will" or "would" “or similar expressions that convey the prospective nature of events or outcomes generally indicate forward-looking statements. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. This presentation includes financial measures that are not in accordance with United States generally accepted accounting principles (“GAAP”), including PV-10 and Adjusted EBITDAX. While management believes that such measures are useful for investors, they should not be used as a replacement for financial measures that are in accordance with GAAP. For a reconciliation of Adjusted EBITDAX to the nearest comparable measure in accordance with GAAP, please see the Appendix. 1

Analyst Presentation – Day 2 CAUTIONARY STATEMENTS REGARDING HYDROCARBON QUANTITIES We have provided internally generated estimates for proved reserves and aggregated proved, probable and possible reserves (“3P Reserves”) as of December 31, 2014 in this presentation, with each category of reserves estimated in accordance with SEC guidelines and definitions, though we have not reported all such estimates to the SEC. As used in this presentation: • Probable reserves. We use deterministic methods to estimate probable reserve quantities, and when deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. • Possible reserves. We use deterministic methods to estimate possible reserve quantities, and when deterministic methods are used to estimate possible reserve quantities, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. The SEC prohibits companies from aggregating proved, probable and possible reserves estimated using deterministic estimation methods in filings with the SEC due to the different levels of certainty associated with each reserve category. Actual quantities that may be ultimately recovered from our interests may differ substantially from the estimates in this presentation. Factors affecting ultimate recovery include the scope of our ongoing drilling program, which will be directly affected by commodity prices, the availability of capital, regulatory approvals, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints and other factors; actual drilling results, which may be affected by geological, mechanical and other factors that determine recovery rates; and budgets based upon our future evaluation of risk, returns and the availability of capital. We use the term “oil-in-place”, “net unrisked 3P resources”, “net unrisked prospective resources” and “estimated ultimate recovery” in this presentation to describe estimates of potentially recoverable hydrocarbons remaining in the applicable reservoir. SEC guidelines restrict us from including these measures in filings with the SEC. These have been estimated internally without review by independent engineers and may include shale resources which are not considered in most older, publicly available estimates. Actual recovery of these potential resource volumes is inherently more speculative than recovery of estimated reserves and any such recovery will be dependent upon future design and implementation of a successful development plan. Management’s estimate of original hydrocarbons in place includes historical production plus estimates of proved, probable and possible reserves and a gross resource estimate that has not been reduced by appropriate factors for potential recovery and as a result differs significantly from estimates of hydrocarbons that can potentially be recovered. Ultimate recoveries will be dependent upon numerous factors including those noted above. In addition, we discuss “PUD-like” reserves by which we mean reserves for which our technical evaluation indicates that we would book the reserves as proved undeveloped reserves except that we do not expect to develop them within five years. These are not proved reserves in accordance with SEC regulations. 2

Analyst Presentation – Day 2 3 • Day One  Strategic Overview of CRC – Todd Stevens, President & CEO  Marketing Overview – Carlos Contreras, VP Marketing  Regulatory Overview – Charlie Weiss, EVP – Public Affairs  Waterflood Primer – Jerry Foster, Manager IOR/EOR  Los Angeles and Ventura Basins – Frank Komin, EVP – Southern Operations  THUMS Island Tour • Day Two  Exploration Overview – Darren Williams, EVP – Exploration  Northern Operations Overview– Bob Barnes, EVP – Northern Operations  Steamflood Primer  Dr. Vic Ziegler, Director- Corporate Development  Jeff Hatlen – Chief Reservoir Engineer Thermal Operations  Elk Hills Site Tour CRC AGENDA

Analyst Presentation – Day 2 World Class Resource Base • Interests in 4 of the 12 largest fields in the lower 48 states • 768 MMBoe proved reserves (12/31/2014) • Largest producer in California on a gross operated basis with significant exploration and development potential California Heritage • Strong track record of operations since 1950s • Longstanding community and state relationships • Actively involved in communities with CRC operations Management Expertise • Successful operations exclusively in California • Assembled largest privately-held land position in California • Operator of choice in sensitive environments Portfolio of Lower-Risk, High- Growth Opportunities • Oil weighted reserves • Broad exploration and development program • 30%-100%+ rates of return on individual projects Shareholder Value Focus • Internally funded capital expenditure program • Optimized capital allocation • Unlocking under-exploited resource potential utilizing modern technology

EXPLORATION OVERVIEW Darren Williams | EVP – Exploration | October 14, 2015

Analyst Presentation – Day 2 6 EXPLORATION KEY TAKEAWAYS Sacramento Basin Dry gas & shale San Joaquin Basin Heavy oil, light oil, dry gas & shale Ventura Basin Heavy oil, light oil, dry gas & shale LA Basin Heavy oil, light oil & shale • Material growth portfolio in an underexplored, world-class hydrocarbon province • Proven value creation through exploration success • Unparalleled portfolio of conventional exploration assets • Significant prospective shale resources with reservoir properties comparable to US resource plays • Rigorous portfolio management process focused on value creation drives exploration program

Analyst Presentation – Day 2 7 • Multiple 1 Bn Boe+ discoveries from 1880s to 1940s based upon surface information  Established California as a world class hydrocarbon province • Limited exploration activity 1970 thru 2000s  Industry focused on development and EOR • Late 2000s CRC reestablished focused exploration program • Portfolio of high-graded exploration opportunities delivering renewed success CALIFORNIA EXPLORATION HISTORY 0 5 10 15 20 25 30 35 40 0.0 1.0 2.0 3.0 4.0 1 8 6 0 1 8 7 0 1 8 8 0 1 8 9 0 1 9 0 0 1 9 1 0 1 9 2 0 1 9 3 0 1 9 4 0 1 9 5 0 1 9 6 0 1 9 7 0 1 9 8 0 1 9 9 0 2 0 0 0 2 0 1 0 A n n u a lD is c o v e ri e s B n B o e Discovery Year C u m .D is c o v e rie s B n B o e 35 35 36 36 37 37 0 50 100 150 200 250 1 9 6 0 1 9 6 5 1 9 7 0 1 9 7 5 1 9 8 0 1 9 8 5 1 9 9 0 1 9 9 5 2 0 0 0 2 0 0 5 2 0 1 0 A n n u a lD is c o v e ri e s M M B o e Discovery Year C u m .D is c o v e rie s B n B o e CRC RENEWED EXPLORATION SUCCESS CALIFORNIA EXPLORATION HISTORY Drill Oil and Gas Seeps Drill Surface Features 2D Seismic Small Discoveries CRC Discoveries Source : California Division of Oil, Gas & Geothermal Resources.

Analyst Presentation – Day 2 8 DEMONSTRATED VALUE CREATION THRU EXPLORATION • 2007-2014 exploration program • Activity: 130 wells • Geologic success rate: ~70% • Net 3P Reserves Adds: 218 MMBoe • 3P Finding cost: $3.55 / Boe • 2014 production: ~18,000 Boe/d • Key discoveries:  2009: Gunslinger  2012: Buena Vista Nose  2013 & 2014: Pleito Ranch extensions  2015 : >750 BOPD exploration success Source: Information based on CRC internal estimates. EXPLORATION DRIVEN PRODUCTION GROWTH CUMULATIVE 3P RESERVE ADDS

Analyst Presentation – Day 2 9 DRIVERS FOR SUCCESS • Largest land position in State • Proprietary data sets provides competitive advantage • 4,250 square miles of 3D seismic, ~90% of 3D available in state • Proprietary geologic models integrating well, seismic, outcrop and analog data to identify accumulations missed by previous operators • Highly experienced team • Culture of innovation Shallow 4-way - Existing fields Deep 4-way – exploration SAN JOAQUIN LAND & SEISMIC MAP EXPLORATION TEAM EXPERIENCE PROPRIETARY GEOLOGIC MODELS

Analyst Presentation – Day 2 10 • Unparalleled portfolio of onshore US conventional exploration assets • Significant value creation opportunity from deep inventory of near-field exploration prospects • Analogous to producing assets & recent key exploration discoveries • Multiple, stacked reservoirs in proven play trends • Conventional and unconventional reservoirs in structural and stratigraphic plays • Diverse, multi-basin portfolio provides optionality in different price environments CONVENTIONAL EXPLORATION ASSETS SAN JOAQUIN BASIN FIELDS & PLAY TYPES

Analyst Presentation – Day 2 11 • Unparalleled exploration assets • Material, low risk conventional onshore US exploration portfolio  125+ independent oil and gas prospects  10 key play trends across three world- class hydrocarbon basins  1+Bn BOE net, unrisked resource potential • Exploration program driven by rigorous portfolio management process focused on value creation CONVENTIONAL EXPLORATION PORTFOLIO *Industry Average = Average commercial discovery size (65MMBOE) from 2003 – 2012 & average industry commercial success rate (20%) from 2004 - 2013 Sources : WoodMac Annual Exploration Benchmarking Study, September 2014 & WoodMac Exploration Trends – Global Exploration Benchmarking Study, January 2014 EXPLORATION PORTFOLIO RISK vs RESOURCE VALUE FOCUS : VCI vs F&D

Analyst Presentation – Day 2 12 • Conventional reservoir in structural trap within CRC Operated field area • Multiple, stacked deepwater sand reservoirs • Reservoir interval #1 (deepest zone)  58’ gross hydrocarbon bearing sand  Peak daily flow rates > 200 BOPD • Reservoir interval #2  148’ gross hydrocarbon bearing sand  Natural flow >750 BOPD & 1.5MMCFD • Additional uphole pay in development reservoirs  350’+ gross hydrocarbon bearing sand  Offset well ~ ½ mile to east flowed > 600 BOPD from these reservoirs • Repeatability & running room  Underexplored < 5 wells test exploration reservoirs  20+ mile play trend, 10 prospects  Remaining potential to drill deeper  > 200MMBOE net unrisked resource potential RECENT >750 BOPD EXPLORATION SUCCESS Fault scarp with oil seeps from exposed reservoir rocks, Ventura Basin

Analyst Presentation – Day 2 13 • Multiple, regionally extensive organic-rich shale reservoirs • Exploration targets in Lower Monterey, Whepley, Kreyenhagen and Moreno shales  Individual shale reservoirs range in thickness from 200 to 1000’+  Depths to targets from 8,000 – 20,000’  TOC > 4% observed, source rocks for main fields  Multiple potential horizontal well landing zones in each shale reservoir • Exploration portfolio  2Bn BOE net unrisked, prospective resource  ~650,000 acre gross play trend  5,300+ net prospective drill locations  Potential 80 acre horizontal development well spacing SHALE RESOURCES LOWER MONTEREY WHEPLEY KREYENHAGEN MORENO UPPER MONTEREY - 6,000’ - 8,000’ - 4,000’ Producing Shale Exploration 8,000’ 4 1 , 00’ 4 12, 00’ - 4,000’14, 00’ >2,500’ EXPLORATION SHALE RESERVOIR POTENTIAL

Analyst Presentation – Day 2 14 SHALE RESOURCES Major U.S. Shale PlaysCalifornia Unconventional Potential • Successful in upper Monterey using precise development approach • Expanding efforts into lower Monterey and other shales CRC Current Production CRC Areas of Future Development 1Reservoir characteristics were internally generated based on regional 2D seismic data, 3D seismic data, open hole and mud log data, cores and other reservoir engineering data. Play Depth (ft) Thickness (gross ft) Porosity (%) Permeability (mD) Total Organic Carbon (%) Upper Monterey1 3,500' – 12,000' 250' – 3,500' 5 – 30 <0.0001 – 2 1 – 12 Lower Monterey1 9,000' – 16,000' 200' – 500' 5 – 12 <0.001 – 0.05 2 – 18 Kreyenhagen1 8,000' – 20,000' 500' – 1000' 5 – 15 <0.001 – 0.1 2 – 8 Moreno1 8,000' – 20,000' 500' – 1000' 5 – 10 <0.001 – 0.1 2 – 6 Bakken 3,000' – 11,000' 6' – 145' 2 – 12 0.05 8 – 21 Barnett 5,400' – 9,500' 100' – 500' 4.0 – 9.6 <0.0001 – 0.1 4 – 8 Eagle Ford 5,000' – 12,000' 100' – 250' 3.4 – 14.6 0.13 2 – 9 Monterey

Analyst Presentation – Day 2 15 KREYENHAGEN RESERVOIR • Type IIs organic black shale deposited in a restricted marine basin • Extensive, consistent reservoir mapped using log & 3D seismic data  500-1000’ gross thickness • Multiple, stacked high TOC (2-8%) intervals observed in log, core, cuttings & outcrop • Calibrated geological models define oil, condensate & gas maturity fairways DlogR TOCVclay KREYENHAGEN TYPE LOG CORE TOC 6% CORE TOC 2% CORE TOC 4% CORE TOC 4% CORE TOC 2% Vaqueros McAdams K r. U p p er K r. M id d le K r. Lo w er 0’ 100’ 200’ 300’ 400’ 500’ 600’ 700’ 800’ HYDROCARBON MATURITY & TOC MAP

Analyst Presentation – Day 2 16 KREYENHAGEN RESERVOIR PROPERTIES • Reservoir properties key to storage capacity, completion effectiveness & well drainage • Average porosity > 10% • High quartz content  50-80% by volume • Multiple quartz-rich, brittle zones > 100’ thick • High fracture density observed on image logs and core data  > 10 fractures/foot  Multiple fracture types & orientations • Rock type similar to Marcellus, Barnett, Fayetteville & Haynesville shale reservoirs Fracture Swarm Through- going fractures Bed-limited fractures C O R E IN TE R V A L

Analyst Presentation – Day 2 17 PROVEN KREYENHAGEN RESERVOIR PRODUCTION • Production in ~20 vertical wells from Kreyenhagen reservoir  30 Day IP’s: 10-300+ BOPD • CRC implementing deliberate & cost effective approach to assessing expected reservoir performance  Utilizing workovers in existing wellbore  Zonal completions to evaluate horizontal landing zones  Production established from multiple zones • Overpressured reservoirs DlogRVclay Proven producing reservoir intervals ORIGINAL OIL IN PLACE & VERTICAL PRODUCERS MAP KREYENHAGEN TYPE LOG Vaqueros McAdams K r. U p p er K r. M id d le K r. Lo w er 0’ 100’ 200’ 300’ 400’ 500’ 600’ 700’ 800’

Analyst Presentation – Day 2 18 KEY ELEMENTS OF SUCCESSFUL RESOURCE PLAYS TOC & Thermal Maturity Reservoir Presence & Extent Brittleness & Fractures Overpressure Productive Hydrocarbons in Place Hydrocarbon generation potential & type Resource potential, sweet spot identification Hydrocarbon storage & repeatability Drainage area, completion effectiveness Reservoir energy, well productivity Capacity to flow hydrocarbons Lease Position Running room, operational efficiencies      CA SHALES   CA SHALES

Analyst Presentation – Day 2 19 EXPLORATION SUMMARY Sacramento Basin Dry gas & shale San Joaquin Basin Heavy oil, light oil, dry gas & shale Ventura Basin Heavy oil, light oil, dry gas & shale LA Basin Heavy oil, light oil & shale • Material growth portfolio in an underexplored, world-class hydrocarbon province • Proven value creation through exploration success • Unparalleled portfolio of conventional exploration assets • Significant prospective shale resources with reservoir properties comparable to US resource plays • Rigorous portfolio management process focused on value creation drives exploration program

NORTHERN OPERATIONS Robert Barnes | EVP – Northern Operations | October 14, 2015

Analyst Presentation – Day 2 21 • World-Class Assets – Great Reservoirs • Base production surveillance is generating results • Cost reduction with minimal impact on production • Sustainable reduced costs and a culture of low cost operating • Expansive, integrated infrastructure with world-class reliability • Deep inventory with the ability to execute • Driven operations and technical professionals • CRC operates a portfolio of diverse assets in a safe and environmentally sound manner CRC NORTH KEY TAKEAWAYS

Analyst Presentation – Day 2 22 Net Production - Q2 2015  67.0 MBOPD  17.0 MBPD NGL  224 MMCFD  121 MBOEPD  1,311 MBWPD water CRC NORTH OPERATIONS AT GLANCE 8,098 active wells • 6,919 producers • 1,025 injection/disposal wells • 79% production by beam pump Infrastructure • Consolidated Control Facility • 3 gas plants (CGP1, LTS1, LTS2) • 520 MMCFD processing capacity • 195 units; 330K HP compression • 44 major fluid processing facilities • 50 Steam generators • 218 MBSPD capacity • 27 LACT sales points • 550 MW Elk Hills Power Plant • 292 tank settings • 8,370 miles of oil and gas gathering lines 2 drilling rigs 30 workover/well servicing rigs Consolidated Control Facility As of 2Q 2015

Analyst Presentation – Day 2 CRC - NORTHERN OPERATIONS ACTIVE WELL COUNT REPORT TOTAL PROD/INJ 7,944 Jun-2015 5,454 184 958 188 79 56 1,025 Beam ESP Flowing Prog Cavity Hydraulic Gas Lift Injection CRC NORTH WELL COUNT 23 BEAM ESP FLOWING GAS LIFT PCP HYDRAULIC INJECTION OTHER TOTAL NORTH 5,454 184 958 56 188 79 1,025 154 8,098 OIL PROD GAS PROD WATER INJ GAS INJ STEAM INJ WATER INJ OTHER TOTAL NORTH 6,050 854 356 82 364 223 169 8,098 Source: Weatherford, Company data

Analyst Presentation – Day 2 24 CRC NORTH PERFORMANCE METRICS 2014Q4 2015Q1 2015Q2 Total Hours (MM) 3.0 1.7 1.5 Net Production (MBOEPD) 123.4 121.4 120.2 Oil (MBD) 66.7 66.5 66.0 Capital ($MM) 372 90 50 Cash OPEX ($MM) 163 153 144 Realized Price ($/BOE) 50.97 34.61 39.44 Cash OPEX ($/BOE) 14.37 14.03 13.20 Cash Margin from Ops ($/BOE) 36.60 20.58 26.24 Downtime (Ave BOEPD) 3,867 3,010 2,530 • Energy Costs and Conservation • Steam Costs and Optimization • Artificial Lift Optimization • Infrastructure Reliability • Job Consolidation and Contractor Reduction

Analyst Presentation – Day 2 25 DEFENDING MARGINS BY MANAGING COSTS ~28% Decrease $- $5.00 $10.00 $15.00 $20.00 $25.00 2012 2013 2014 1H 2015 $ /B O E CRC NORTH COST TRENDS Surface Operations and Maintenance Downhole Maintenance Workovers/Well Enhancement Supports and Other Energy Gas Plant Expense Steam Injectant

Analyst Presentation – Day 2 WELL SERVICING SCORECARD 0 5 10 15 20 25 30 35 40 45 0 5 10 15 20 25 30 35 40 45 1Q2014 2Q2014 3Q2014 4Q2014 1Q2015 2Q2015 $ M p er jo b H o u rs p e r jo b Job Efficiency Hours per job Cost per job 26 0 200 400 600 800 1,000 1,200 1,400 1Q2014 2Q2014 3Q2014 4Q2014 1Q2015 2Q2015 b o e p d Waiting on Hoist 0 2,000 4,000 6,000 8,000 10,000 12,000 1Q2014 2Q2014 3Q2014 4Q2014 1Q2015 2Q2015 R ig H o u rs Maintenance Rig Hours Linear (Series1) 0 500 1,000 1,500 2,000 2,500 1Q2014 2Q2014 3Q2014 4Q2014 1Q2015 2Q2015 b o e p d Downtime Trendline

Analyst Presentation – Day 2 WORLD-CLASS UPTIME WELLS, PLANTS AND INFRASTRUCTURE 27 90% 91% 92% 93% 94% 95% 96% 97% 98% 99% 100% 1Q2014 2Q2014 3Q2014 4Q2014 1Q2015 2Q2015 P ro u d ct io n U p ti m e

Analyst Presentation – Day 2 28 WORKOVERS – LOW CAPITAL, GREAT RETURNS Description CAPEX ($MM) Incremental Rate (BOPD) Incremental Rate (BOEPD) Payout (YRS) ROR (%) VCI 10 8 - Artificial Lift Upgrade 18 - Add Perfs $7.6 662 914 1.3 155 5.3 0 100 200 300 400 500 600 700 800 900 1000 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 CRC Workover Net Incremental Rate Net Oil BOPD Net Gas BOEPD Net NGL BPD N et In cr em en ta lR at e (B O EP D )

Analyst Presentation – Day 2 29 DEFEND CRC’S MARGINS Revenue - Cash Direct OPEX (Not including overhead, ad valorem tax, severance tax and GHG tax) 55% Oil 35% Oil 1% Oil 40% Oil 100% Oil 100% Oil 89% Oil 100% Oil 95% Oil 96% $- $10 $20 $30 $40 $50 $60 1 10 100 1000 Total CRC North Buena Vista Rio Vista Elk Hills Field Lost Hills Kern Front North Shafter Mount Poso Pleito Ranch Buena Vista Nose F ie ld O p e ra ti n g M a rg in ($ /B O E ) N e t R a te (M B O E /D ) CRC North Operated Areas H1 2015 Production and Operating Margins Net Rate (MBOE/D) Field Cash Margin ($/BOE)

Analyst Presentation – Day 2 ELK HILLS AREA AT A GLANCE 30 3,726 active wells • 3,319 producers • 407 injection/disposal wells • 89% production by beam pump Infrastructure • Consolidated Control Facility • 3 gas plants (CGP1, LTS1, LTS2) • 520 MMCFD processing capacity • 148 units; 300K HP compression • 3 major fluid processing facilities • Produced water treatment & injection • 45 MW Cogen • 550 MW Elk Hills Power Plant • 3 CO2 removal plants (CGP1 Amine, GTU2 and 14Z Amine) • 120 tank settings • Over 4,300 miles of gas gather lines 21 workover/well servicing rigs Net Production - Q2 2015  25.6 MBOPD  16.4 MBPD NGL  141.5 MMCFD  65.4 MBOEPD  500 MBWPD produced

Analyst Presentation – Day 2 31 MAJOR GAS & POWER FACILITIES • Largest gas plant complex in California  CGP1 (200 MMSCFD)  LTS1 (160 MMSCFD)  LTS2 (160 MMSCFD) – On Standby  CGP1 Amine, GTU2 & GTU3 (CO2) • Consolidated Control Facility (CCF) • 550 Megawatt Power Plant (EHPP) – Supplies power and steam to Elk Hills facilities and sells remaining power to grid • 45 MW Cogen – Supplies power and steam to Elk Hills facilities • 300K HP of compression • Gas sales pipelines connected to all major markets with multiple outlets

Analyst Presentation – Day 2 32 CGP1 BENEFITS • Cryogenic Gas Plant (CGP1) started up in mid-2012 • Added 3,000 bpd of NGL production due to improved recovery • Improved sales gas quality to consistently meet customer BTU and Dew Point specs • California’s largest natural gas and NGL plant - Processing 210 MMSCFD of wet gas  160 MMSCFD of residue gas  16 MBPD of NGLs • Plant reliability exceeds 99% - Best in Class • Operation is critical to reliable Oil, NGL, and Gas production • Pipeline delivery of gas and NGL products to sales outlets

Analyst Presentation – Day 2 33 SAN JOAQUIN BASIN WEST TO EAST SEISMIC CROSS-SECTION Belgian Anticline & Midway Sunset Elk Hills North Shafter Kern Front Etchegoin Upper Monterey Lower Monterey Temblor Deep Marine Turbidites Basement Shallow Marine San Andreas Fault System Faults SW NE Mount Poso Bowerbank Kreyenhagen Shale • Only California operator with basin wide seismic data set • Proprietary integration of seismic and petrophysical data yields proven results 5 miles

Analyst Presentation – Day 2 34 ELK HILLS MAJOR PRODUCING ZONES 6 Deep Expl.

Analyst Presentation – Day 2 35 BUILDING LIFE OF FIELD PLANS – ELK HILLS Multiple recovery mechanisms  Primary  Waterflood  Unconventional Improved base decline  ~15%/yr  Improved well uptime  Infrastructure Reliability Base Surveillance and Management Implementation of a diverse project inventory will continue to maximize value 0 20,000 40,000 60,000 80,000 100,000 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 N e t B O E P D ELK HILLS FIELD DEVELOPMENT In-Field Development Exploration Discoveries Base Decline ~15%

Analyst Presentation – Day 2 36 EFFECTIVE MANAGEMENT OF ELK HILLS OPERATING COSTS* *Transition from primary to secondary production in Elk Hills has been occurring during this period. The Wilmington Field has similarly experienced declines in Opex per well and Opex per Boe despite a significantly higher WOR (~39 in 2014). 10.0 10.5 11.0 11.5 12.0 12.5 13.0 13.5 14.0 14.5 15.0 2012 2014 1H 2015 W a te r - O il R a ti o (W O R ) Elk Hills Field Water-Oil Ratio (WOR) 136,00 0 94,000 68,000 - 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000 2012 2014 1H 2015 O p e ra ti n g C o st / W e ll, $ /w e ll Elk Hills Field - Opex per Well $16.46 $14.31 $10.94 2,000 2,500 3,000 3,500 4,000 4,500 5,000 $- $2.00 $4.00 $6.00 $8.00 $10.00 $12.00 $14.00 $16.00 $18.00 2012 2014 1H 2015 W e ll C o u n ts O p e ra ti n g C o st ,$ /b o e Elk Hills Field - Opex, $/boe Opex, $/boe Well Counts

Analyst Presentation – Day 2 GREATER ELK HILLS AREA RESERVOIRS 37

Analyst Presentation – Day 2 PROGRESSING INVENTORY TO VCI THRESHOLD 38 GEHA INVENTORY 2016 -2020 VCI >= 1.0 VCI >= 1.3 Plan Year 2016 to 2020 Plan Year 2016 to 2020 Recovery Mechanism Prod Drill Count Inj Drill Count WO Count Net Capex $MM Recovery Mechanism Prod Drill Count Inj Drill Count WO Count Net Capex $MM Conventional 176 0 38 103 Conventional 0 0 38 11 Unconventional 171 0 129 457 Unconventional 10 0 125 82 Waterflood 65 29 152 154 Waterflood 41 23 146 126 Grand Total 412 29 319 714 Grand Total 51 23 309 219 Recovery Mechanism Prod Drill Count Inj Drill Count WO Count Net Capex $MM Recovery Mechanism Prod Drill Count Inj Drill Count WO Count Net Capex $MM Conventional 176 0 38 103 Conventional 164 0 38 100 Unconventional 198 0 129 514 Unconventional 25 0 129 116 Waterflood 209 32 155 252 Waterflood 65 29 152 154 Grand Total 583 32 322 869 Grand Total 254 29 319 370 Recovery Mechanism Prod Drill Count Inj Drill Count WO Count Net Capex $MM Recovery Mechanism Prod Drill Count Inj Drill Count WO Count Net Capex $MM Conventional 443 0 39 386 Conventional 164 0 38 100 Unconventional 223 0 129 573 Unconventional 89 0 129 273 Waterflood 209 40 185 264 Waterflood 66 29 155 157 Grand Total 875 40 353 1,223 Grand Total 319 29 322 530 @ $50 Oil, $3.00 Gas ($3.50 Gas for >= 2017) @ $50 Oil, $3.00 Gas ($3.50 Gas for >= 2017) @ $60 Oil, $3.00 Gas ($3.50 Gas for >= 2017) @ $60 Oil, $3.00 Gas ($3.50 Gas for >= 2017) @ $70 Oil, $3.00 Gas ($3.50 Gas for >= 2017) @ $70 Oil, $3.00 Gas ($3.50 Gas for >= 2017)

Analyst Presentation – Day 2 39 MT POSO REDEVELOPMENT • Old steamfloods have hotplate heated Vedder generating drilling opportunities • Expanding waterflood development from North part to the South area of the field • 6 Recent wells (4 verticals and 2 horizontals) with good results • 400 bopd net at $3MM for a VCI10=3.5 and Payout: 7 months • 10 patterns ready for H2 2015 development • 6 new wells and 7 workovers ready for Q3, 2015 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 January-14 January-15 January-16 G ro ss M B O P D

Analyst Presentation – Day 2 40 • Discovery date: 1957 • CRC Drilled 36 wells to date • Formations: Santa Margarita and Chanac • Complex Upturn Play Trap • Depths: 9,000 – 15,100’ MD • WI = 100% and P1 NRI = 96% • In place: 250 MMBO / Cum. Prod: 12 MMBO / ~5% RF • Current production: 3,200 BOEPD (27 API) PLEITO RANCH CRC Acquired 2007 Production (Boepd)

Analyst Presentation – Day 2 IMPROVED WATERFLOOD - BUENA VISTA • 1,300 bopd and 60,000 bwpd • 80 active injectors, waterflood is 30% implemented • Prior Operator initiated disposal project on 5 acres • Current flood is responding with CRC 20 acre patterns (37 injectors in past two years) • Incremental Oil Recovery (improved sweep and balancing) • Optimizing with traditional surveillance methods and new FrontSim Model • Every extra 1% on the Recovery Factor would represent 7 MMBO net to CRC - 1,000 2,000 3,000 4,000 5,000 6,000 7,000 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 O il P ro d u ci to n R at e (B O P D ) WF Base WF Dev Wedge Risked Potential of ~6,000 BOPD Assumes Increm. RF ~7% 41

Analyst Presentation – Day 2 42 • World-Class Assets – Great Reservoirs • Base production surveillance is generating results • Cost reduction with minimal impact on production • Sustainable reduced costs and a culture of low cost operating • Expansive, integrated infrastructure with world-class reliability • Deep inventory with the ability to execute • Driven operations and technical professionals • CRC operates a portfolio of diverse assets in a safe and environmentally sound manner CRC NORTH SUMMARY

THERMAL EOR OVERVIEW Past, Present and Future Victor Ziegler, Ph.D. | Director – Corporate Development | October 14, 2015

Analyst Presentation – Day 2 44 THERMAL EOR OVERVIEW • Provide an overview and update on the status of thermal enhanced oil recovery (TEOR) • Discussion includes:  Thermal Process  Historical Overview  Economic Barometer  Future Opportunities

Analyst Presentation – Day 2 45 KEY THERMAL HIGHLIGHTS • Steam injection is the most successful EOR process • Up to 70% of the oil-in-place in a reservoir may be recovered by steamflooding • Application of new technologies has enhanced steamflooding even in mature areas such as the U.S. • TEOR operators focus on oil/gas price ratio, and water and heat management • Steamflood development in fractured reservoirs has the potential to significantly increase production • The size of the resource and long project lives make the future of thermal operations in California attractive with room for expansion

Analyst Presentation – Day 2 46 THERMAL EOR PROCESSES Cyclic steam injection • A three-step well stimulation process • Used as a precursor and supplement to steamflood Source: Department of Energy

Analyst Presentation – Day 2 47 THERMAL EOR PROCESSES Steamflood • Continuous steam injection into a pattern • Rapid heating of the pattern area; steam over-rides oil column STEAMFLOOD Source: Department of Energy

Analyst Presentation – Day 2 48 THERMAL EOR PROCESSES In situ combustion • Inject air, which reacts with the oil to generate high temperatures (~1,000 F) • Unstable process, which has poor reservoir sweep and oil recovery Source: Department of Energy

Analyst Presentation – Day 2 49 HEAVY OIL RECOVERY EFFICIENCY R e se rv e s Natural Depletion Low Med High L o w M e d H ig h Steam has larger target oil recovery Steamflood Cyclic Steam Combustion Cold Waterflood Hot Waterflood Investment

Analyst Presentation – Day 2 50 U.S. THERMAL EOR (TEOR) • Steam injection has been the most successful EOR process in the U.S. • High prices have kept production flat for the last 10 years Source: Oil and Gas Journal April 2014

Analyst Presentation – Day 2 51 TYPICAL STEAMFLOOD FIELD Kern Front

Analyst Presentation – Day 2 52 EFFECTIVE ENHANCED RECOVERY METHOD • Long history with initial projects begun in the 1930’s • Implementation of multi-pattern pilots, however, did not begin until the 1950’s • Success of steam pilots minimized the use of air injection • Price decline of 1986 forced changes in steamflood design and management

Analyst Presentation – Day 2 53 PRODUCTION REFLECTS PATTERN RESPONSE • 95% of U.S. steamfloods are in Kern County, CA • Typical steam pattern response stabilized plateau rate even though number of projects was decreasing

Analyst Presentation – Day 2 54 KEY IMPROVEMENTS IN THERMAL PRACTICES • Reservoir heat management  1986 price decline triggered advances in steamflood management  SFR = 2.5 bs/mcf; SOR ~ 5 bs/bo >>> steam fuel costs ~ $6/bo for $3/mcf • Multi-reservoir steamflood development  Accelerate oil recovery and utilize hotplate heating effects to minimize steam requirements • Use of horizontal wells  Better drilling practices and equipment >>> better well placement  Productivity ratio ~ 2x-to-10x as compared to a vertical well  Horizontal well costs ~1.5x-2.0x times vertical well cost • SAGD  Effective for tar sands • Low-cost slimhole injectors • Desktop thermal simulation

Analyst Presentation – Day 2 55 RESERVOIR HEAT MANAGEMENT • Steamfloods are different than waterfloods >> waterfloods require a constant injection rate • Reducing steam injection in mature patterns keeps steam in pattern area, minimizes steam production and provides steam for pattern expansions • This provides an effective method to manage costs without affecting the production trend

Analyst Presentation – Day 2 56 MULTI-RESERVOIR STEAMFLOOD DEVELOPMENT • Multiple zones may be developed either simultaneously or sequentially (bottoms-up order) • Vertically expanding a steamflood pattern to an overlying reservoir greatly extends the productive life of the project with minimal additional capital costs

Analyst Presentation – Day 2 57 MULTI-RESERVOIR STEAMFLOOD RATE PROFILE • 9-pattern project at Kern Front • Initial steamflood was into Etchegoin sand in 1991 • Vertical expansion steamfloods were begun in 2005 • Oil recovery per zone approaches 70% of oil in place by steamflood (versus ~30% by waterflood) Cyclic Steam Initial Steamflood Vertical Expansion Steamfloods

Analyst Presentation – Day 2 58 CALIFORNIA SERVES AS TRAINING GROUND • Thermal EOR accounts for ~1.2 Mmbopd of world-wide oil production • Venezuela and Canada are the two largest TEOR producers • The US is the third largest TEOR producer Source: Oil and Gas Journal April 2014

Analyst Presentation – Day 2 59 MAIN ECONOMIC BAROMETER 0.00 10.00 20.00 30.00 40.00 50.00 60.00 70.00 Brent / Henry Hub Ratio Ratio Economic Limit Source: Bloomberg • Even with recent price drop, TEOR remains attractive investment with oil/gas ratio >5x (currently ~15x) • TEOR patterns compete favorably for capital since reservoirs are shallow with low costs (<~$0.4MM per well) to drill and equip

Analyst Presentation – Day 2 60 REGULATORY FOCUS FOR THERMAL IN CA • Fresh water use, under drought conditions  CRC is a net supplier of water to agriculture  CRC provides more treated, reclaimed water from TEOR operations than the amount of fresh water we purchase statewide • State review of Underground Injection Control (UIC) wells  State seeks to replace water disposal with recycling or reclamation of produced water  State has appointed a panel to study agricultural use of reclaimed water • GHG and air emissions from steam generation  Air permits and emission credits  GHG allowances under California cap-and-trade program

Analyst Presentation – Day 2 61 STEAMFLOOD INNOVATIONS • Enclosed parabolic solar troughs to pre-heat feedwater or generate steam • Permanently buried seismic sources and receivers to provide daily images of the movement of a steam front Source: GlassPoint Source: IPTC 17407

Analyst Presentation – Day 2 62 FUTURE OPPORTUNITIES – NEW RESERVOIRS • Majority of known heavy oil sands are already developed • Carbonates, diatomite and siliceous shale reservoirs containing both light and heavy oils are the next targets Heavy oil sand

Analyst Presentation – Day 2 63 POTENTIAL RECOVERY MECHANISMS • Viscosity reduction is the primary recovery mechanism • In fractured reservoirs, low matrix permeability means heat transfer is primarily by conduction • Oil recovery will be aided by counter-current imbibition and thermal expansion of the matrix fluids Viscosity reduction Capillary imbibition Thermal expansion

Analyst Presentation – Day 2 64 KEY THERMAL HIGHLIGHTS • Steam injection contributes over 1 million bopd worldwide • Up to 70% of the oil-in-place in a reservoir may be recovered by steamflooding • Reservoir heat management and multi-zone development have enhanced steamflooding even in mature areas such as the US • Economic drivers are well understood • Steamflood development in fractured reservoirs has the potential to significantly increase production • The size of the resource and long project lives make the future of thermal operations in California attractive with room for expansion

THERMAL OPERATIONS - STEAMFLOODING Jeff Hatlen | Chief Reservoir Engineer – Thermal Operations | October 14, 2015

Analyst Presentation – Day 2 66 KEY STEAMFLOOD TAKE-AWAYS • Up-front Investment • Strong Margins • Stable/Long-Lived Declines • Strong Backside Cash Flow Creates Real Value

Analyst Presentation – Day 2 67 INTRODUCTION TO STEAMFLOODING • Steamfloods have a life cycle • Immature • High injection rate • Steam build-out • Breakthrough • Mature • Oil drainage • Heat cuts • Strong cash flow • Steamfloods follow a path • Primary production • Cyclic steam • Continuous steam injection Immature Mature Steam Oil

Analyst Presentation – Day 2 68 STEAMFLOOD TARGETS • Our reservoirs are like a layer cake of sandstone and clay • Each sandstone layer is important • To achieve the highest cash margins, we need to control each layer • Understanding how steam moves through these layers will drive success  Common Conceptual Model  Observation wells  Surface data  Operations

Analyst Presentation – Day 2 69 STEAM MOVEMENT AND IMPACT Steam Injection Oil & Water Oil & Water Start of steam injection Heat management Effluent Steam Steam breakthrough

Analyst Presentation – Day 2 70 STEAMFLOODING: PATTERN DEVELOPMENTS OVER MULTIPLE YEARS Patterns are the Fundamental Building Blocks 5-spot Pattern • Typical 5 acres Injection well Production well Displacement Project • Common start-date • Contiguous patterns Field Development • Several Projects • Multi-year Drilling 2014 2016 2015

Analyst Presentation – Day 2 71 THERMAL PROCESS : PATTERN LIFE CYCLE Ramp-up Mature Stable Oil Decline Injection Reduction Facilities Established Maximize injection 6mo – 2+ yrs Steam Injection Rate Peak Maximum Oil Rate Steam Breakthrough

Analyst Presentation – Day 2 72 KERN FRONT – STACKED INTERVALS

Analyst Presentation – Day 2 73 STEAMFLOOD SURVEILLANCE

Analyst Presentation – Day 2 74 STEAM MANAGEMENT

Analyst Presentation – Day 2 75 STEAMFLOOD LEARNINGS Kern Front

Analyst Presentation – Day 2 76 LOST HILLS – ADDITIONAL OPPORTUNITIES Short Circuiting Layer Cold Oil Cold Oil Previous Operator Pattern Group

Analyst Presentation – Day 2 77 MULTI-YEAR OF INVENTORY OF PATTERNS Lost Hills Kern Front

Analyst Presentation – Day 2 78 DEEP INVENTORY FUELS THERMAL GROWTH 0 5,000 10,000 15,000 20,000 25,000 30,000 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 N e t B O E P D 2011-2020 Thermal Operations Production Kern Front Lost Hills Adv. Properties

Analyst Presentation – Day 2 79 ROBUST MARGINS DESPITE LOW PRICES 41% 43% 33% 49% 58% 58% 48% 44% $42 $47 $41 $47 $55 $57 $47 $42 $0 $10 $20 $30 $40 $50 $60 $70 0% 25% 50% 75% 100% Jan Feb Mar Apr May Jun Jul Aug O p e ra ti n g M a rg in a s % o f O il P ri ce 2015 Thermal Operations Op. Margin as % of Oil Price

Analyst Presentation – Day 2 80 STRONG BACKSIDE CASH FLOW CREATES REAL VALUE 0 Positive Cash Kern Front Field Example Representative example; based on CRC estimates.

Analyst Presentation – Day 2 81 KEY STEAMFLOOD TAKE-AWAYS • Up-front Investment • Strong Margins • Stable/Long-Lived Declines • Strong Backside Cash Flow Creates Real Value

Analyst Presentation – Day 2 82 CALIFORNIA RESOURCES CORPORATION APPENDIX

Analyst Presentation – Day 2 END NOTES: (1) The reserves replacement ratio is calculated for a specified period using the applicable proved oil-equivalent additions divided by oil-equivalent production. Company- wide 76% of 2014 additions were proved undeveloped. There is no guarantee that historical sources of reserves additions will continue as many factors fully or partially outside management’s control, including the underlying geology, commodity prices and availability of capital, affect reserves additions. Management uses this measure to gauge results of its capital allocation. The measure is limited in that reserves may be added and produced based on costs incurred in separate periods and other oil and gas producers may use different replacement ratios affecting comparability. (2) Finding and Development costs for the capital program are calculated by dividing the costs incurred from the capital program (development and exploration costs) by the amount of proved reserves added in the same year from improved recovery and extensions and discoveries (excluding acquisitions and revisions). Our management believes that reporting our finding and development costs can aid evaluation of our ability to add proved reserves at a reasonable cost and is not a substitute for our GAAP disclosures. Various factors, including timing differences and effects of commodity price changes, can cause finding and development costs to reflect costs associated with particular reserves imprecisely. For example, we will need to make more investments in order to develop the proved undeveloped reserves added during the year and any future revisions may change the actual measure from that presented above. Our calculations of finding and development costs may not be comparable to similar measures provided by other companies. (3) Our total production costs consist of variable costs that tend to vary depending on production levels, and fixed costs that do not vary with changes in production levels or well counts, especially in the short term. The substantial majority of our near-term fixed costs become variable over the longer term as they can be managed based on the field’s stage of life and operating characteristics. For example, portions of labor and material costs, energy, workovers and maintenance expenditures correlate to well count, production and activity levels. Portions of these same costs can be relatively fixed over the near term, however, they are managed down as fields mature in a manner that correlates to production and commodity price levels. While a certain amount of costs for facilities, surface support, surveillance and related maintenance can be regarded as fixed in the early phases of a program, as the production from a certain area matures, well count increases and daily per well production drops, such support costs can be reduced and consolidated over a larger number of wells, reducing costs per operating well. Further, many of our other costs, such as property taxes and oilfield services, are variable and will respond to activity levels and tend to correlate with commodity prices. Overall, we believe less than one-third of our operating costs are fixed over the life cycle of our fields. We actively manage our fields to optimize production and costs. If we see growth in a field we increase capacities, and similarly if a field is reaching the end of its economic life we would manage the costs while it remains economically viable to produce. 83

JRCO 0915Analyst Presentation – Day 2 Non-GAAP Reconciliation for Adjusted EBITDAX For the Second Quarter Ended June 30, For the Six Months Ended June 30, Full Year ($ in millions) 2015 2014 2015 2014 2014 Net Income/(loss) ($68) $246 ($168) $469 ($1,434) Interest expense 83 - 162 - 72 Income taxes expense/(benefit) (46) 162 (115) 313 (987) Depreciation, depletion and amortization 251 293 504 582 1,198 Exploration expense 7 15 24 46 139 Asset Impairments (a) - - - - 3,402 Other (b) 43 11 61 22 158 Adjusted EBITDAX $270 $727 $468 $1,432 $2,548 Net cash provided by operating activities $117 $496 $232 $1,236 $2,371 Interest expense 83 - 162 - 72 Cash income taxes - 135 - 135 165 Cash exploration expenses 6 7 17 13 38 Changes in operating assets and liabilities 49 118 50 47 (143) Other, net 15 (29) 7 1 45 Adjusted EBITDAX $270 $727 $468 $1,432 $2,548 a - For full year 2014, includes pre-tax impairment charges of $3.4 bn. b - Includes non-cash and unusual or infrequent charges. 84

JRCO 0915Analyst Presentation – Day 2 Non-GAAP Reconciliation for PV-10 ($ in millions) At December 31, 2014 PV-10 $16,091 Present value of future income taxes discounted at 10% (5,263) Standardized Measure of Discounted Future Net Cash Flows $10,828 PV-10 is a non-GAAP financial measure and represents the year-end present value of estimated future cash inflows from proved oil and natural gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows and using SEC prescribed pricing assumptions for the period. PV-10 differs from Standardized Measure because Standardized Measure includes the effects of future income taxes on future net cash flows. Neither PV-10 nor Standardized Measure should be construed as the fair value of our oil and natural gas reserves. PV-10 and Standardized Measure are used by the industry and by our management as an asset value measure to compare against our past reserve bases and the reserve bases of other business entities because the pricing, cost environment and discount assumptions are prescribed by the SEC and are comparable. PV-10 further facilitates the comparisons to other companies as it is not dependent on the tax paying status of the entity. 85