Mark Smith| Sr. EVP & CFO| Orlando, FL| March 6 th- 8th, 2017 38th Annual Institutional Investors Conference RAYMOND JAMES & ASSOCIATES

Raymond James & Associates 20172 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. Such statements include those regarding our expectations as to our future: Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. While we believe assumptions or bases underlying our expectations are reasonable and make them in good faith, they almost always vary from actual results, sometimes materially. We also believe third-party statements we cite are accurate but have not independently verified them and do not warrant their accuracy or completeness. Factors (but not necessarily all the factors) that could cause results to differ include: Words such as "anticipate," "believe," "continue," "could," "estimate," "expect," "goal," "intend," "likely," "may," "might," "plan," "potential," "project," "seek," "should," "target, "will" or "would" and similar words that reflect the prospective nature of events or outcomes typically identify forward-looking statements. Any forward-looking statement speaks only as of the date on which such statement is made and we undertake no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. • financial position, liquidity, cash flows, and results of operations • business prospects • transactions and projects • operating costs • operations and operational results including production, hedging, capital investment and expected VCI • budgets and maintenance capital requirements • reserves • commodity price changes • debt limitations on our financial flexibility • insufficient cash flow to fund planned investment • inability to enter desirable transactions including asset sales and joint ventures • legislative or regulatory changes, including those related to drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, managing energy, water, land, greenhouse gases or other emissions, protection of health, safety and the environment, or transportation, marketing and sale of our products • unexpected geologic conditions • changes in business strategy • inability to replace reserves • insufficient capital, including as a result of lender restrictions, unavailability of capital markets or inability to attract potential investors • inability to enter efficient hedges • equipment, service or labor price inflation or unavailability • availability or timing of, or conditions imposed on, permits and approvals • lower-than-expected production, reserves or resources from development projects or acquisitions or higher-than-expected decline rates • disruptions due to accidents, mechanical failures, transportation constraints, natural disasters, labor difficulties, cyber attacks or other catastrophic events • factors discussed in “Risk Factors” in our Annual Report on Form 10-K available on our website at crc.com.

Raymond James & Associates 20173 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, 2016 in this presentation, with each category of reserves estimated in accordance with Securities and Exchange Commission (“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 and workover 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 “unproved resources” in this presentation to describe estimates of potentially recoverable hydrocarbons remaining in the applicable reservoir. These resources are not proved reserves in accordance with SEC regulations and 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 and the actual geologic characteristics of the reservoirs. Ultimate recoveries will be dependent upon numerous factors including those noted above. Terms in this presentation such as “oil-in-place” and “expected ultimate recovery (EUR)” describe our estimates of hydrocarbons that may be recoverable from a reservoir. SEC guidelines restrict us from including these measures in SEC filings. Our estimates are not reviewed by independent engineers and may include shale resources which are not considered in most older, publicly available estimates. Recovery of these hydrocarbons is inherently more speculative than recovery of estimated proved reserves and depends on many factors including underlying geology, commodity prices, availability of capital and success of development programs. 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.

Raymond James & Associates 2017 • CRC Opportunity Defined • Priorities and Accomplishments • Value Creation Focus – Doubled Inventory • Capital Allocation – Inflection Point 4

Raymond James & Associates 2017 Reserves Value1 in Excess of EV 5 1-5 See End Notes in the Appendix. PDP Value Proved Value Unproved4 $0 $2 $4 $6 $8 $10 $12 $14 $16 $18 $20 $22 $24 $55 Brent $65 Brent $75 Brent ($ B n ) Current EV of $6.1 Bn5 Infrastructure2 Surface & Minerals3

Raymond James & Associates 2017 Portfolio Flexibility Provides Range of Crude Oil Scenarios 6 40 60 80 100 120 140 160 2016 2017E 2018E 2019E 2020E Oi l P ro d uction M B /d Estimated Crude Oil Production Outcomes 0 300 600 900 1,200 Capi ta l ($ M M ) Estimated Capital Invested Note: Assumes $60 Brent in 2017 and $65 Brent and $3.35 Henry Hub gas price thereafter based on consensus estimates as of October 14, 2016. Assumes lease operating costs on an absolute basis escalate ~5% per year from 2016 levels for the mid-point of the range of planning scenario outcomes. Ranges of portfolio planning scenario outcomes assume development of a variety of combinations of steamflood, waterflood, conventional and unconventional projects in our inventory and reflect estimates of geologic, development and permitting risk. All discretionary cash flow reinvested in business for each outcome. 400 800 1,200 1,600 2016 2017E 2018E 2019E 2020E $ M M Estimated Range of EBITDAX Outcomes Combined with improving and stabilizing commodity prices, we are positioned for growth in: • Cash flow • Production • Reserves on a debt-adjusted per share basis Capital focused on oil projects that provide High Margins Low Decline Rates Compounding Cash Flow+ = Portfolio Planning Scenarios Portfolio Planning Scenarios

Raymond James & Associates 2017 Project Execution Drives Organic Deleveraging 7 0.0x 2.0x 4.0x 6.0x 8.0x 10.0x 2016 2017E 2018E 2019E 2020E To ta l D eb t/ LTM E B IT D A X Estimated Leverage Ratios $55 $65 $75 Note: All cases are self-funding. Capital program in all cases assumes discretionary cash flow is reinvested. Lease operating costs escalate ~5% per year from 2016 levels. Assumes midpoint case from range of portfolio planning scenarios.

Raymond James & Associates 2017 NY00813G / 589203_1.WOR Sacramento Basin 11 MMBoe Proved Reserves 6 MBoe/d production San Joaquin Basin 429 MMBoe Proved Reserves 97 MBoe/d production Ventura Basin 29 MMBoe Proved Reserves 7 MBoe/d production Los Angeles Basin 99 MMBoe Proved Reserves 30 MBoe/d production World-Class Resource Base  Operate in 4 of 12 largest fields in the continental U.S.  568 MMBoe proved reserves  140 MBoe/d production, 76% liquids  2.3 million net acres with significant mineral interest  Low, flattening decline rate Positioned to Grow as Prices Increase  Internally funded capital program designed to live within cash flow and drive growth  Operating flexibility across basins and drive mechanisms to optimize growth through commodity price cycles  Increasing crude oil mix improves margins  Deep inventory of high return projects CRC’s Large Resource Base with Advantaged Infrastructure 8 Reserves and net acres as of 12/31/16; Production figures reflect average FY 2016 rates.

Raymond James & Associates 2017 Largest California Producer with Deep Regional Insight 9 Top California Producers in 2015* 196 161 134 35 34 - 20 40 60 80 100 120 140 160 180 200 CRC Chevron USA Aera Energy Freeport McMoRan LINN Energy G ro ss O p era te d MB O E/ d Source: DOGGR, IHS, Wood Mackenzie, Company Estimates * For non-CRC Companies, estimated 2016 OPEX $/BOE $16 $23 $22 $29 $29 $0 $5 $10 $15 $20 $25 $30 $35 0% 25% 50% 75% 100% CRC Chevron USA Aera Energy Freeport McMoran LINN Energy Majority of CA production is shallow Shallow Deep (>5,000') FY 2016 OPEX $/BOE* Largest 3-D Seismic Position in California

Raymond James & Associates 2017 California Stacked Reservoirs: Multiple opportunity sets with large accumulations 10 Source: Information based on internal observed data and external published reports. MONTEREY SANDS AND SHALES TEMBLOR SANDS EOCENE SANDS AND SHALES UPPER CRETACEOUS SANDS AND SHALES 1 ,0 0 0 ’ P A Y TULARE SANDS 20 50 100 20 30 50 SH A LL O W D EE P Primary Oil Primary Shale Primary Dry Gas SteamFlood WaterFlood Type Wells • OOIP: 2 BBO • Estimated Recovery Factor: 25 % • Heavy Oil Trend • OOIP: 5 BBO • Estimated Recovery Factor : 20% • OOIP: 50 BBO • Estimated Recovery Factor : 8% • Heavy Oil Trend • Source Rock • Conventional and Unconventional Primary Oil and Gas Zones • OOIP: 10 BBO • Estimated Recovery Factor: 35% • OOIP: 6 BBO • OGIP: 20 TCF • Estimated Recovery Factor : 10% • OGIP: 20 TCF • Estimated Recovery Factor : 40% >5,000’ + ETCHEGOIN SANDS <5,000’ 15,000’ # of S ta ck ed R e se rv oi rs

Raymond James & Associates 2017 • CRC Opportunity Defined • Priorities and Accomplishments • Value Creation Focus – Doubles Inventory • Capital Allocation – Inflection Point 11

Raymond James & Associates 2017 Benefits of the Spin: Focus Led to Improvements 12 Sac Valley Thermal PV10 pre-tax cash flows PV10 of investments VCI = Value Creation Index One CRC • Entrepreneurial culture • Disciplined capital allocation through portfolio management • Three principal drivers: o Maximize long-term value – VCI > 1.3 o Value focused growth o Financial discipline – self-funding business Elk Hills THUMS Vintage

Raymond James & Associates 2017 Focus on Base Production – Production declined 10% Y-o-Y1, excluding PSC effects Generated Free Cash Flow –$49MM of free cash flow2 Reduced Debt – Decreased debt $900 million in 2016 and cumulatively reduced nearly $1.5 billion from peak levels. Defend Margins – Lowered production costs by 16% Y-o-Y3 Enhanced Economics – Achieved a 3.0x recycle ratio4 and organic F&D cost of $3.42 per BOE5, excluding price-related revisions Increased Inventory – Doubled the capital we could deploy to drillable and actionable investment opportunities that meet our 1.3 VCI hurdle at $55 Brent 13 2016 Accomplishments – CRC Delivered on Controllables 1 Fourth quarter production rate 2 After working capital for the year, see appendix for reconciliation 3 On an absolute dollar basis 4,5 See Appendix for calculation

Raymond James & Associates 201714 Chose options to maximize deleveraging and minimize recurring cost to the income statement and on a per share basis 6,765(1) 5,268 4,000 5,000 6,000 7,000 2Q15 Debt Exchange for 2L Open Market Repurchases Equity for Debt Exchange Cash Tender for Unsecureds Operating Cash Flow 4Q16 To ta l D e b t ($ MM ) Significant Debt Reduction From Post-Spin Peak Cumulative Debt Reduction Total Total Net Principal Reduction $535 million $116 million $102 million $625 million $119 million $1,497 million Annual Income Statement Effect (Annualized Interest) +$22 million -$7 million -$6 million +$27 million -$5 million $31 million 1 Represents mid-second quarter 2015 peak debt.

Raymond James & Associates 2017 Resilient Resource Base – Low Decline with Limited Capital 0 100 200 300 400 500 600 0 20 40 60 80 100 120 140 160 180 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 FY 2014 FY 2015 FY 2016 $ M M M B O E /d Production By Stream (MBOE/d) Oil NGL Gas Capital 159 MBOE/d Average Oil Production Average Total Production 160 MBOE/d 99 MBbl/d 104 MBbl/d 15 140 MBOE/d 91 MBbl/d $2.1BN $401MM $75MMTotal Capital:

Raymond James & Associates 201716 Defending Margins Through Operating Cost Reductions and Efficiencies - 5 10 15 20 25 30 35 FY 2014 FY 2015 FY 2016 Ca sh C o st s ($/BOE ) Adj. G&A Production Costs Taxes (non income) Exploration ~17% Decrease2014 Avg : $27.37 2015 Avg : $24.24 2016 Avg : $22.77

Raymond James & Associates 201717 Reduced Well Costs 2016 program had ~21% lower well costs compared to prior similar wells 0 300 600 900 1,200 1,500 1,800 Long Beach Horizontal Elk Hills ESOZ Mt. Poso Lost Hill Injector Kern Front Lost Hills Producer $ M Last Drilled (2014/2015) 2016 • Efficiency drivers: o Rig costs – Rig optimization and day work rate reduction o Cementing – Slurry redesign, volume optimization o Back to Basics – Cost reduction workshops covering spud through online well scope, logging and completion methods Includes drilling, completion and hook-up costs 40% 15% 13% 9% 7% 6% 6% 4% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 2016 Dri l l ing Savings Logging Casing Materials Cementing Services Fluid Hauling Contr Rig Supervisor Rental Service Equip. Rig Costs s

Raymond James & Associates 2017 CRC Drives California Rig Count Activity 18 0 5 10 15 20 25 30 35 40 45 50 Jan-14 Apr-14 Jul-14 Oct-14 Jan-15 Apr-15 Jul-15 Oct-15 Jan-16 Apr-16 Jul-16 Oct-16 Jan-17 Ri g C o u n t Total CA Rig Count CRC Rig Count Source: Baker Hughes Rotary Rig Count (includes offshore and onshore) California rig count has averaged ~30 rigs over the past decade of which CRC assets have accounted for approximately half of the activity.

Raymond James & Associates 2017 • CRC Opportunity Defined • Priorities and Accomplishments • Value Creation Focus – Doubles Inventory • Capital Allocation – Inflection Point 19

Raymond James & Associates 201720 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 2015 2016 2015 2016 2015 2016 $55 $65 $75 D rilli n g an d W o rk o ve r C ap it al ($ M M ) Brent Marker Price ($/BBL) VCI > 1.0 VCI > 1.3 More Actionable Inventory From Enhanced Life of Field Plans Actionable Economic Project Inventory

Raymond James & Associates 2017 Value Chain Progress: Building Inventory Across 135 Fields 21 Legacy Field Review - Paloma • Technical reevaluation doubled OOIP estimate • Analog field performance • Applying new technology and thinking to generate new opportunities Delineation - Pleito • Grew production since acquisition • Applying reservoir learnings • Targeting additional zones Development – Kern Front • Production ramp drives cash flows • Repeatability of operations & techniques • Low base decline 0 20 40 60 80 100 0 750 1,500 2,250 3,000 3,750 4,500 A ct iv e P ro d u ce r Co u n t G ro ss A vg M o n th ly R at e (B o e/ d ) Pleito Production Boepd Well Count 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 G ro ss P ro d u ct io n R at e (B /d ) Steamflood Example: Kern Front Kern Front Paloma Pleito

Raymond James & Associates 2017 Updated Inventory by Project Type 22 Actionable projects >1.3 VCI Table indicates the years of inventory available at each price deck and continuous activity level (active rig counts per year) Rigs/Year Years of Inventory 4 29 35 47 6 19 24 31 8 14 18 24 10 12 14 19 12 10 12 16 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 $55 Brent / $3 Mcf $65 Brent / $3.5 Mcf $75 Brent / $4 Mcf D ri lli n g a n d W o rk o v e r Cap ita l ($ M M ) Workovers Waterflood Unconventional Steamflood Primary

Raymond James & Associates 2017 Steamfloods – Low Risk and Stable/Low Decline 23 AVG. DEPTH (True Vertical) 2,000 AVG. GROSS THICKNESS (feet) 1,000 # OF SECTIONS 20 Avg. OOIP/OGIP per Section (MMBOE) 40 Avg. EUR (MBOE) 270 AVG. SPACING (acres) 5 # OF LOCATIONS 2,560 % OF SECTIONS COVERED BY 3D SEISMIC 50% STEAM GENERATOR COST $4mm PATTERNS PER STEAM GENERATOR 5 • Analog fields have had success with horizontal wells – up to 10x productivity for 2x the cost • Multi-zone development • Strong cash flow generation and asset preservation by lowering base decline Steam injection contributes to over 1.2mm bopd worldwide Thermal techniques account for over 40% of US EOR production, 95% of these are in California Approximately 75% of the oil-in-place can be recovered through steam injection Characterized by low risk and stable/low decline Low capital intensity and robust margins make it attractive investment at low prices TEMBLOR SANDS EOCENE SANDS AND SHALES UPPER CRETACEOUS SANDS AND SHALES MONTEREY SANDS AND SHALES 1 ,0 0 0 ’ P A Y TULARE SANDS 20 50 100 20 30 50 SH A LL O W D EE P ETCHEGOIN SANDS # of S ta ck ed Reser voi rs Targeted Zones Characteristics Portfolio Contribution Untapped Potential

Raymond James & Associates 2017 Waterfloods – Low Capital Intensity and Robust Margins 24 AVG. DEPTH (True Vertical) 5,000 AVG. GROSS THICKNESS (feet) 1,000 # OF SECTIONS 50 Avg. OOIP/OGIP per Section (MMBOE) 20 Avg. EUR (MBOE) 200 AVG. SPACING (acres) 10 # OF LOCATIONS 3,200 % OF SECTIONS COVERED BY 3D SEISMIC 80% • Potential to convert several primary fields to waterfloods • Strong cash flow generation and asset preservation by protecting oil production Water-flooding techniques are the most commonly used EOR production methods Up to approximately 20% of the oil-in-place can be recovered The oil rate decline for a waterflood is generally 1/3 less vs. unconventional wells Low capital intensity and robust margins make it attractive investment at low prices Portfolio Contribution Untapped Potential TEMBLOR SANDS EOCENE SANDS AND SHALES UPPER CRETACEOUS SANDS AND SHALES MONTEREY SANDS AND SHALES 1 ,0 0 0 ’ P A Y TULARE SANDS 20 50 100 20 30 50 SH A LL O W D EE P ETCHEGOIN SANDS # of S ta ck ed Reser voi rs Targeted Zones Characteristics

Raymond James & Associates 2017 Leveraging Infrastructure: Buena Vista Field Development 25 2500 TVD 2750 3000 3250 3750 4000 4250 3500 B V S ha le B V W at e rf loo d Effective Production Management • Current net production of ~9,000 Boe/d (no rigs since 2014) • Surveillance with modern tools • Daily exception reports/weekly pattern reviews • Bi-annual update of life of field plan Operational Efficiencies/Cost Reduction • Using produced water from shale wells as injection water in waterflood (WF) • Switched to Elk Hills power resulting in 60% reduction in yearly energy cost Development Opportunities • 250 unconventional unproven drilling locations and 180 WF patterns in development inventory* • Potential to more than double field production from 10,000 boepd with full field development • Exploration discovery in 2012 - average IP for 5 wells 500 Bbl/d $43.54 $21.16 $22.67 $13.54 $11.33 $0.00 $15.00 $30.00 $45.00 $60.00 2012 2013 2014 2015 2016 Opex/Boe Other Opex $/Boe Energy - $/Boe Total OPEX - $/Boe 50% reduction post spin * Please see “Item 2 - Properties - Our Reserves and Production Information” in our 2016 Form 10-K for more information on the processes and criteria we use to identify drilling locations P LEIS TO CE N E

Raymond James & Associates 2017 Tackling Underdeveloped Opportunities: Kettleman North Dome 26 • OOIP of 4 billion barrels, 14,000 Acres (2 mi. wide, 15 mi. long) • 1000’s of feet of stacked pay • Light oil – API > 36o • WI=100% and NRI=80% in KNDU • Modern formation evaluation, new wells, and workovers • Advancing the understanding and development potential • 7 stacked pay reservoirs • >5000 feet thick • Limited current production • Initial technical appraisal complete • Acquired 200 mi2 3D seismic survey in 2015 • Reinterpreted reservoirs and structure • Pilots that validated understanding • Implement development plan Bakersfield Elk Hills Lost Hills Relatively Steep SE Flank -4000 -6000 -8000 -10000 -12000 Temblor McA ams Upper Lower Zone I Zone II Zone III Zone IV Zone V SW NE Vaqueros Upper McAdams Gas Original Oil Band Temblor Primary Gas Caps Kreyenhagen Shale Prior Kr Wells 2014 Kr Well Rio Lobo seismic survey KNDU Field Boundary

Raymond James & Associates 2017 • CRC Opportunity Defined • Priorities and Accomplishments • Value Creation Focus – Doubles Inventory • Capital Allocation – Inflection Point 27

Raymond James & Associates 2017 Drilling $150 50% Workover $50 17% Development Facilities $50 17% Exploration $25 8% Other $25 8% 2017E Drilling Capital – By Drive Commentary 2017E Total Capital Plan • 2017 capital plan of $300 million will be directed to oil weighted projects in our core fields: Elk Hills, Wilmington, Kern Front, Buena Vista and the delineation of Kettleman North Dome • We have a dynamic plan which can be scaled up or down depending on the price environment • Plans can be reduced below $100 million or increase as high as $500 million based on conditions during the year and Board approval Self-Funded Capital Investment Program 28 2017E Drilling Capital – By Basin Total: $300 million Conventional $63 42% Exploration $7 5% Waterfloods $47 31% Steamfloods $12 8% Unconventional $21 14% San Joaquin $112 75% Ventura $17 11% Los Angeles $21 14% 1Other includes maintenance and occupational health, safety and environmental projects, seismic and other investments.

Raymond James & Associates 2017 Primary Objective San Joaquin Basin Map Highlights • Up to $250 MM over ~2 years • Initial $50 MM tranche o Focus will start in San Joaquin Basin • CRC’s discretion on which assets to develop1 • Enhances CRC project value • Investor funds 100% of the project capital • Investor NPI interest reverts after target IRR • CRC operates all wells Joint Venture with Benefit Street Partners 29 Kern Front -Legend- Oxy Land Oil Fields Gas Fields Buena Vista Pleito Ranch Elk Hills Kettleman Lost Hills Mt Poso CRC Land • Enhances CRC value • Accelerates cash flow • Highlights CRC’s inventory value 1 With Partner approval across development fields

Raymond James & Associates 2017 NY00813G / 589203_1.WOR Sacramento Basin 11 MMBOE Proved Reserves 6 MBOE/d production San Joaquin Basin 429 MMBOE Proved Reserves 97 MBOE/d production Ventura Basin 29 MMBOE Proved Reserves 7 MBOE/d production Los Angeles Basin 99 MMBOE Proved Reserves 30 MBOE/d production 30  World-Class Resource Base: Large inventory of assets across basins and drive mechanisms that provide strong returns through the commodity price cycle  Exceptional Operating Flexibility: High level of operating leverage and control favorably positions CRC to capitalize on a strengthening commodity market  Stable Base: Diverse and stable assets enable a predictable production profile with low base declines  Focused and Experienced Management Team: Proactive executive team that swiftly executes strategic objectives Poised to Grow Reserves as of 12/31/16; Production figures reflect average FY 2016 rates.

Raymond James & Associates 2017 California Resources Corporation Appendix 31

Raymond James & Associates 2017 Capitalization as of 12/31/16 ($MM) $25 $375 $193 $135 $1,000 $2,250 193 $0 $500 $1,000 $1,500 $2,000 $2,500 Ja n -1 6 Ju l-1 6 Ja n -1 7 Ju l-1 7 Ja n -1 8 Ju l-1 8 Ja n -1 9 Ju l-1 9 Ja n -2 0 Ju l-2 0 Ja n -2 1 Ju l-2 1 Ja n -2 2 Ju l-2 2 Ja n -2 3 Ju l-2 3 Ja n -2 4 Ju l-2 4 Term Loan Debt Maturities ($MM)* Strengthening the Balance Sheet • Deleveraging is a priority; ~$1.5 billion decrease to date from post-spin peak • Utilized cash flow to make amortization payments on term loan in 2016 • $625 million net reduction from cash tender for bonds • Exchanged equity for ~$100 million of 5.5% and 6% bonds 1 As of January 31, 2017 we had approximately $486MM of available borrowing capacity under our revolving credit facility, subject to minimum liquidity requirement. 2 See Appendix for reconciliation to GAAP. 3 PV-10 as of 12/31/16 based on SEC five-year rule applied to PUDs using SEC price deck. See Appendix for reconciliation to GAAP. 4 Reserves as of 12/31/16. 5 Production as of FY 2016. 1st Lien Secured RCF1 847 1st Lien Secured Term Loan (1L) 650 1st Lien Second Out Term Loan (1LSO) 1,000 Senior 2nd Lien Notes 2,250 Senior Unsecured Notes 521 Total Debt 5,268 Less cash (12) Total Net Debt 5,256 Equity (557) Total Net Capitalization 4,699 Total Net Debt / Total Net Capitalization 112% Total Net Debt / LTM Adjusted EBITDAX2 8.5x LTM Adjusted EBITDAX / LTM Interest Expense 1.9x PV-103 / Total Net Debt 0.5x Total Net Debt / Proved Reserv s4 ($/Boe) $9.25 Total Net Debt / PD Reserves4 ($/Boe) $12.95 Total Net Debt / Production5 ($/Boepd) $37,543 * As of 12/31/16; The 1LSO and 2LSO both have springing maturities which are detailed in our 10-K. 32

Raymond James & Associates 2017 Opportunistically Built Oil Hedge Portfolio1 • Hedge book started at zero post spin; we target hedges on 50% of production • Strategy focuses on protecting cash flow for capital investments and covenant compliance Q1 2017 Q2 2017 Q3 2017 Q4 2017 1Q 2018 2Q 2018 3Q 2018 4Q 2018 Calls Barrels per Day 12,100 5,000 10,000 15,000 15,600 15,000 15,000 15,000 Wtd Avg Ceiling Price per Barrel $56.37 $55.05 $56.15 $56.12 $58.77 $58.83 $58.83 $58.83 Puts Barrels per Day 22,100 20,000 17,000 10,000 Wtd Avg Floor Price per Barrel $49.10 $50.25 $50.88 $48.00 Swap Barrels per Day 20,000 20,0002 25,0003 25,0003 Wtd Avg Price per Barrel 53.98 53.98 54.99 54.99 33 1 Prices are based on Brent. Positions as of February 23, 2017. 2 Includes a quarterly counterparty option to increase volumes by up to 10,000 barrels per day for that quarter at a weighted-average Brent price of $55.46. 3 Includes a quarterly counterparty option to increase volumes by up to 10,000 barrels per day for that quarter at a weighted-average Brent price of $55.46 and a counterparty option to increase 2H 2017 volumes by an additional 10,000 barrels per day at a weighted-average Brent price of $60.24.

Raymond James & Associates 2017 Diverse Assets with Flexible Development Opportunities 34 • Diversity of basins and drive mechanisms • Predictable production and low decline rates • Multiple stacked reservoirs • Development targets include repeatable projects with low technical risk • Achieved a 2016 organic recycle(2) margin of 3.0x 2016 Net Proved Reserves (MMBOE) 568 2016 % Oil-Net Proved1 72% Standardized Measure of Discounted Future Net Cash Flows 2.67 Pre-Tax Proved PV-10 ($ billion)2 2.85 2016 Avg. Net Production (MBOE/d) 140 2016 % Oil Production 65% 2016 Net Acreage (million acres) 1 2.3 2016 Identified Gross Locations1 30,900 San Joaquin Basin Los Angles Basin Ventura Basin Sacramento Basin 2016 Net Proved Reserves (MMBOE) 429 99 29 11 2016 % Proved Developed 67% 84% 86% 100% 2016 % Liquids – Net Proved 79% 99% 90% 0% 2016 Avg. Net Production (MBOE/d) 97 30 7 6 2016 % Oil Production 58% 100% 67% 0% 2016 Net Acreage (million acres) 1.5 <0.1 0.3 0.5 2016 Identified Gross Drill Locations 23,900 2,150 2,950 1,900 1 As of 12/31/16. Drilling locations exclude 6,400 gross prospective locations. 2 See Appendix. Figures shown are for full year 2016, unless otherwise noted.

Raymond James & Associates 201735 Key CRC Fields by Drive Mechanism Oakridge Wilmington Montalvo Huntington Beach Rio Viejo San Miguelito Asphalto Pleito Ranch Mt. Poso Railroad Gap Wheeler Ridge Rincon BV Nose Saticoy S. Mountain Shale 29R Oxnard Bardsdale Buena Vista Buena Vista Midway Sunset Paloma Paloma N. Shafter Rio Vista McDonald Anticline WSOZ WSOZ Rose Tompkins Hill McKittrick ESOZ ESOZ Gunslinger Willows Lost Hills EH Stevens EH Stevens EH Stevens Grimes Kern Front Kettleman Kettleman Kettleman Kettleman Steamflood Primary- Conventional Waterflood Primary- Unconventional Primary-Gas Fields in green have multiple recovery/drive mechanisms and a combination of conventional and unconventional drilling targets.

Raymond James & Associates 2017 San Joaquin Basin • Oil and gas discovered in the late 1800s • Accounts for ~69% of CRC production • ~25 billion barrels OOIP in CRC fields1 • Cretaceous to Pleistocene sedimentary section (>25,000 feet) • Source rocks are organic rich shales from Moreno, Kreyenhagen, Tumey, and Monterey Formations • Thermal techniques applied since 1960s • FY 2016 average net production of 97 MBoe/d (59% oil) • Elk Hills is the flagship asset (~58% of CRC San Joaquin production) • Two core steamfloods - Kern Front and Lost Hills • Early stage waterfloods at Buena Vista and Mount Poso Overview Key Assets Basin Map -Legend- Oxy Land Oil Fields Gas Fields Buena Vista Pleito Ranch Elk Hills Kettleman Lost Hills Mt Poso CRC Land Kern Front 1 Information based on CRC internal estimates; includes shales which are not considered in most older, publicly available estimates. 36

Raymond James & Associates 2017 0 20 40 60 80 100 120 140 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 N et MB o e/ d • CRC’s flagship asset, a 100-year old field with exploration opportunities • Large fee property with multiple stacked reservoirs • Light oil from conventional and unconventional production • Largest gas and NGL producing field in CA, one of the largest fields in the continental U.S.1, >3,000 producing wells • 7.8 billion barrels OOIP2 and cumulative production of over 2.5 billion Boe • FY 2016 avg. net production of 56 MBoe/d (40% of total production) • 590 MMcf/d processing capacity through 4 gas plants (including California’s largest) • 2 CO2 removal plants • Over 4,200 miles of gathering lines • 45 MW cogeneration plant • 550 MW power plant Overview Comprehensive Infrastructure Field Map Production History 1 DOGGR data and U.S. Energy Information Administration. Elk Hills Buena Vista RR Gap Elk Hills Area - Overview 2 Information based on CRC internal estimates; includes shales which are not considered in most older, publicly available estimates. 37

Raymond James & Associates 2017 Los Angeles Basin • Large, world-class basin with thick deposits • Kitchen is the entire basin, hydrocarbons did not migrate laterally; basin depth (>30,000 ft) • ~10 billion barrels OOIP in CRC fields1 • Most significant discoveries date to the 1920s – past exploration focused on seeps & surface expressions • Very few deep wells (> 10,000 ft) ever drilled • Focus on urban, mature waterfloods, with generally low technical risk and proven repeatable technology across huge OOIP fields • FY 2016 average net production of 30 MBoe/d (97% oil) • Over 20,000 net acres • Major properties are world class coastal developments of Wilmington and Huntington Beach Overview Key Assets Basin Map 38 1 Information based on CRC internal estimates; includes shales which are not considered in most older, publicly available estimates.

Raymond James & Associates 2017 - 50 100 150 200 250 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 M M B o e Net Proved Reserves Production to Date Overview Field Map Proved Reserves & Cumulative Production Structure Map & Acquisition History * • CRC’s flagship coastal asset: acquired in 2000 • Field discovered in 1932; 3rd largest field in the U.S. • Over 7 billion barrels OOIP (34% recovered to date)1 • Depths 2,000’ – 10,000’ (TVDSS) • FY 2016 avg. production of 33 MBoe/d (gross) • Over 8,000 wells drilled to date • PSC (Working Interest and NRI vary by contract) • CRC partnering with State and City of Long Beach *Proved reserves prior to 2009 represent previously effective SEC methodology. Proved reserves for 2009 – 2015 are based on current SEC reserve methodology and SEC pricing. 1 Information based on CRC internal estimates; includes shales which are not considered in most older, publicly available estimates. Tidelands Acquired: 2006 Belmont Offshore Acquired: 2003 Long Beach Unit Acquired: 2000 Pico Properties Acquired: 2008 Wilmington Field - Overview 39

Raymond James & Associates 2017 Ventura Basin • Estimated ~3.5 billion barrels OOIP in CRC fields1 • Operate 28 fields (about 40% of basin) • ~300,000 net acres • Multiple source rocks: Miocene (Monterey and Rincon Formations), Eocene (Anita and Cozy Dell Formations) • FY 2016 average net production of 7 MBoe/d (71% oil) • In 2013, shot 10 mi2 of 3D Seismic > First 3D seismic acquired by any company in the basin Overview Key Assets Basin Map • CRC has four early stage waterfloods • Ventura Avenue Field analog has >30% RF • CRC fields have 3.5 Bn Boe in place at 14% RF Waterflood Potential2 1 Information based on CRC internal estimates; includes shales which are not considered in most older, publicly available estimates 2 Source: USGS 40

Raymond James & Associates 2017 Sacramento Basin • Exploration started in 1918 and focused on seeps and topographic highs. In the 1970s the use of multifold 2D seismic led to largest discoveries • Cretaceous Starkey, Winters, Forbes, Kione, and the Eocene Domengine sands • Most current production is less than 10,000 feet • 3D seismic surveys in mid 1990s helped define trapping mechanisms and reservoir geometries • CRC has 53 active fields (consolidated into 35 operating areas where we have facilities) • FY 2016 average net production of 6 MBoe/d (100% dry gas) • Produce 85% of basin gas with synergies of scale • Price and volume opportunity Overview Key Assets Basin Map 41

Raymond James & Associates 2017 Shale Geological Overview 42 Major U.S. Shale PlaysCalifornia Unconventional Potential 0 GR 150 0 GR 150 0 GR 150 0 GR 150 0 GR 150 0 GR 150 3,000 2,000 1,000 Kreyenhagen Productive interval Target interval Moreno Bakken Barnett Eagle Ford N A B C D PG • Successful in upper Monterey using precise development approach • Expanding efforts into lower Monterey and other shales Play Depth (ft) Thickness (gross ft) Porosity (%) Permeability (mD) Total Organic Carbon (%) Upper Monterey(1) 3,500' – 12,000' 250' – 3,500' 5 – 30 <0.0001 – 2 1 – 12 Lower Monterey(1) 9,000' – 16,000' 200' – 500' 5 – 12 <0.001 – 0.05 2 – 18 Kreyenhagen(1) 8,000' – 16,000' 200' – 350' 5 – 15 <0.001 – 0.1 1 – 6 Moreno(1) 8,000' – 16,000' 200' – 300' 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 CRC Current Production CRC Areas of Future Development 1 Reservoir 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.

Raymond James & Associates 2017 A NET WATER SUPPLIER • CRC’s delivery of reclaimed produced water to agriculture in 2016 exceeded our fresh water purchases by 2.5 billion gallons • We recycled approximately 78% of our produced water in improved or enhanced recovery operations in 2016 • We reduced our purchased fresh water volume by 8% in 2016 • In 2016, we purchased a record volume of reclaimed municipal wastewater to reduce our use of municipal fresh water supplies and groundwater wells 94% 3% 3% WATER MANAGED IN CRC’s OPERATIONS Produced Water Fresh Water Non-Fresh Water In 2016, CRC’s steamflood operations supplied nearly 4 billion gallons – over 12,100 acre-feet – of reclaimed water for irrigation or recharge. CRC nearly doubled our 2014 water supply to agriculture, and exceeded our 2015 volume by 50%, preserving farmland and jobs. 43 CRC’s operations in Long Beach use recycled or non-fresh water sources for 99.5% of their total water use.

Raymond James & Associates 2017 Diverse Resource Base • Interests in 4 of the 12 largest fields in the lower 48 states • 568 MMBoe proved reserves (12/31/2016) • 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 California Focus • Operations exclusively in California • Assembled largest privately-held land position in California • Operator of choice in sensitive environments Portfolio of Lower-Risk, Lower- Decline Opportunities • Oil-weighted reserves • Broad exploration and development inventory Shareholder Value Focus • Internally funded capital investment program • Optimized capital allocation 44

Raymond James & Associates 2017 Non-GAAP Reconciliation for Adjusted EBITDAX 45 Full Year ($ in millions) 2016 Net (loss) Income $ 279 Interest and debt expense 328 Income tax benefit (78) Depreciation, depletion and amortization 559 Exploration expense 23 Adjusted income items before interest and taxes (545) Other non-cash items 50 Adjusted EBITDAX $ 616 Net cash provided by operating activities $ 130 Cash interest 384 Exploration expenditures 20 Other changes in operating assets and liabilities 95 Other (13) Adjusted EBITDAX $ 616

Raymond James & Associates 2017 Free Cash Flow ($ millions) Full Year 2016 Operating cash flow $130 Capital investment (75) Changes in capital accruals (6) Free cash flow (after working capital) $49 46

Raymond James & Associates 2017 Non-GAAP Reconciliation for PV-10 ($ in millions) At December 31, 2016 PV-10 of Proved Reserves $2,848 Present value of future income taxes discounted at 10% (181) Standardized Measure of Discounted Future Net Cash Flows $2,667 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 reserves bases and the reserves 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. 47

Raymond James & Associates 2017 Organic Recycle Ratio ($/BOE) Full Year 2016 Oil and gas revenues $33.17 Production Costs (15.61) Taxes other than on income (Oil and Gas Operations) (2.36) Total CRC general and administrative expenses (4.84) Margin $10.36 Organic Finding and Development $3.42 Organic Recycle Ratio 3.0x (1) We calculate organic finding and development costs by dividing the costs incurred for the year from the capital program (including development costs (as well as asset retirement obligations) and exploration costs, but excluding acquisitions) by the amount of oil-equivalent proved reserves added in the same year from improved recovery, extensions and discoveries and performance-related revisions (excluding acquisitions and price-related revisions). We believe that reporting our finding and development costs can aid investors in their evaluation of our ability to add proved reserves at a reasonable cost but is not a substitute for 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. In addition, part of the 2016 costs were incurred to convert proved undeveloped reserves from prior years to proved developed reserves. Our calculations of finding and development costs may not be comparable to similar measures provided by other companies. We have not estimated future costs expected for the reserves added or removed costs related to reserves added in prior periods. (2) Includes development and exploration costs, as well as asset retirement obligations. (3) Includes performance revisions. 48 Organic Finding and Development Costs(1) 2016 Organic costs incurred – in millions (A) $123(2) Proved Reserves Added – MMBOE (B) 36(3) Organic Finding and Development Costs - $/BOE (A)/(B) $3.42

Raymond James & Associates 2017 End Notes 49 1 Current CRC estimate of reserves value as of December 31, 2016. Includes field level operating expenses and G&A. Assumes $3.30/Mcf Henry Hub. 2 Reflects the value of facilities and midstream assets at 50% of estimated replacement value. This discount is estimated to exceed the burden on reserves that would be incurred if assets were monetized. 3 Surface & Minerals reflect the estimated value of undeveloped surface and fee interests. 4 Unproved inventory comprises risked probable and possible reserves and contingent and prospective resources. Contingent and prospective resources consist of volumes identified through life-of-field planning efforts to date. 5 Calculated using December 31, 2016 debt at par and market cap as of January 31, 2017.