crcboamlrevisedpresentat

Global Energy Conference Bank of America Merrill Lynch Todd Stevens| President & CEO| Miami, FL| November 16-17, 2016

BOAML 2016 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 specifically include our expectations as to our future financial position, drilling and workover program, joint ventures, production, projected costs, future operations, hedging activities, future transactions, planned capital investments and other guidance (including VCI calculations). Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. For any such forward-looking statement that includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that, while we believe such assumptions or bases to be reasonable and make them in good faith, assumed facts or bases almost always vary from actual results, sometimes materially. Factors (but not necessarily all the factors) that could cause results to differ include: assumptions underlying our expectations for meeting our guidance and projections, including any effect on reserves values of monetizations of infrastructure; commodity price fluctuations; the ability of our lenders to limit our borrowing capacity; other liquidity constraints; the effect of our debt on our financial flexibility; limitations on our ability to enter efficient hedging transactions; insufficiency of our operating cash flow to fund planned capital expenditures; steeper than expected production decline rates; inability to implement our capital investment program; inability to replace reserves; inability to obtain government permits and approvals; inability to monetize selected assets; restrictions and changes in restrictions imposed by regulations including those related to our ability to obtain, use, manage or dispose of water or use advanced well stimulation techniques like hydraulic fracturing; risks of drilling; tax law changes; competition with larger, better funded competitors for and costs of oilfield equipment, services, qualified personnel and acquisitions; the subjective nature of estimates of proved reserves and recoverable quantities from resources not classified as proved, and related future net cash flows; risks related to our disposition and acquisition activities; restriction of operations to, and concentration of exposure to events such as industrial accidents, natural disasters and labor difficulties in, California; the recoverability of resources; 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; effects of litigation; cyber attacks; operational issues that restrict market access; and uncertainties related to the Spin-off and the agreements related thereto. Material risks are further discussed in “Risk Factors” in our Annual Report on Form 10-K and subsequent 10-Qs 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 CRC 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. Some of the data in this presentation is from external sources as noted. While we believe it is accurate, we have not independently verified the data and do not represent or warrant that it is accurate, complete or reliable. This presentation includes financial measures that are not in accordance with United States generally accepted accounting principles (“GAAP”), including adjusted net income (loss), PV-10, adjusted EPS 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 such measures to the nearest comparable measure in accordance with GAAP, please see the Appendix. 2

BOAML 2016 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, 2015 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 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 “oil-in-place” and “inventory” 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. 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. Unproved inventory comprises risked probable and possible reserves and may include contingent and prospective resources. Contingent and prospective resources consist of volumes identified through life-of-field planning efforts to date that have not been risked by reference to analogy or other methods used to estimate the chance of success from drilling. For information on the determination of locations, please consult our Form 10-K. Ultimate recoveries will be dependent upon numerous factors including those noted above. 3

BOAML 2016 • CRC Opportunity Defined • Priorities and Accomplishments • Value Creation Focus – Doubles Inventory • Capital Allocation – Inflection Point 4

BOAML 2016 Reserve Value1 Well in Excess of EV 5 1,2,3,4,5 See End Notes in the Appendix. PDP Value Proved Value $0 $2,000 $4,000 $6,000 $8,000 $10,000 $12,000 $14,000 $16,000 $18,000 Strip Price 8/23 $65 Brent $75 Brent ($MM ) Current EV of $5.7 Bn5 Infrastructure2 Surface & Minerals3 Unproved4

BOAML 2016 Project Inventory Drives Organic Deleveraging 6 Surface & Minerals3 0.0x 2.0x 4.0x 6.0x 8.0x 10.0x 12.0x 2016E 2017E 2018E 2019E 2020E To ta l D eb t/ LTM E B IT D A X Leverage Ratios Strip 10/10 $65 $75 Note: All cases are self-funding. Capital program in all cases assumes discretionary cash flow is reinvested. Assumes lease operating costs on an absolute basis escalate ~5% per year from 2016 levels for the mid-point case of the range of portfolio planning scenario outcomes.

BOAML 2016 NY00813G / 589203_1.WOR Sacramento Basin 14 MMBoe Proved Reserves 6 MBoe/d production San Joaquin Basin 451 MMBoe Proved Reserves 98 MBoe/d production Ventura Basin 47 MMBoe Proved Reserves 7 MBoe/d production Los Angeles Basin 132 MMBoe Proved Reserves 31 MBoe/d production World-Class Resource Base  Operate in 4 of 12 largest fields in the continental U.S.  644 MMBoe proved reserves  142 MBoe/d production, 77% liquids  2.4 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 Reserves as of 12/31/15; Production figures reflect average 3Q YTD 2016 rates. 7

BOAML 2016 Largest California Producer with Deep Regional Insight 8 Surface & Minerals3 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 erat ed M b o e/ d Source: DOGGR, IHS, Wood Mackenzie, Company Estimates $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') Avg. 2016 OPEX $/BOE Largest 3-D Seismic Position in California

BOAML 2016 California Stacked Reservoirs: Multiple opportunity sets with large accumulations 9 Surface & Minerals3 Source: Information based on internal observed data and external published reports. 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 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

BOAML 2016 Benefits of the Spin: Focus Led to Improvements 10 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

BOAML 2016 • CRC Opportunity Defined • Priorities and Accomplishments • Value Creation Focus – Doubles Inventory • Capital Allocation – Inflection Point 11

BOAML 2016 12 6,765(1) 5,247 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 3Q16 To ta l D e b t ($ MM ) (2) Strengthen the Balance Sheet Significant Debt Reduction From Post-Spin Peak Chose options to maximize deleveraging and minimize recurring cost to the income statement and on a per share basis Cumulative Debt Reduction Total Total Net Principal Reduction $535 million $110 million $80 million $625 million $168 million $1,518 million Annual Income Statement Effect (Annualized Interest) +$22 million -$6 million -$5 million +$27 million -$5 million $33 million 1 Represents mid-second quarter peak debt. 2 CRC reduced an additional $21mm of principal amount in October 2016 in exchange for 1.26mm shares of common stock.

BOAML 2016 Protect the Base Low Decline Asset Base Requires Low Levels of D&C* Capital Rich asset portfolio and thoughtful capital allocation deliver high margin production and operational flexibility through the price cycle • Conventional assets with long production life and relatively low decline rates • Large inventory of conventional, repeatable, development projects with low technical risk Application of modern technologies/margin improvement/growth opportunities • Deferring many high-return project opportunities until prices rise • Identifying investments that meet our VCI threshold through commodity price cycles • Sophisticated well surveillance 13 FY 2014 FY 2015 FY 2016E MB o e/ d Production By Stream (MBoe/d) Oil NGL Gas Guidance 99 MB/d 104 MB/d Down ~12-14% With Only ~$50MM D&C + Workover Capital Investment Up ~5% With Only <$200MM D&C + Workover Capital Investment 160 MBoe/d 159 MBoe/d *D&C = Drilling and Completion

BOAML 2016 $- $2.00 $4.00 $6.00 $8.00 $10.00 $12.00 $14.00 $16.00 $18.00 $20.00 2014 2015 2016 YTD P ro d u ct io n C o st s ($/Boe ) Steam Injectant Gas Plant Expense Energy Supports and Other Downhole Maintenance Workovers/Well Enhancement Surface Operations and Maintenance Pipeline/Transportation 14 Defend Margins Continued Operating Cost Reductions and Efficiencies 3Q YTD 2016 Avg: $15.01 2015 Avg: $16.30 Down $1.29/Boe Or ~8% decrease 2014 Avg: $18.23

BOAML 2016 15 Reduced Well Costs 2016 program has ~23% 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:  Rig costs – Rig optimization and day work rate reduction  Cementing – Slurry redesign, volume optimization  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

BOAML 2016 16 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 rilling and W or k o ve r Capital ( $ MM ) Brent Marker Price ($/BBL) VCI > 1.0 VCI > 1.3 Focus on Life of Field Plans Doubled project inventory at $55 Brent Actionable Economic Project Inventory

BOAML 2016 • CRC Opportunity Defined • Priorities and Accomplishments • Value Creation Focus – Doubles Inventory • Capital Allocation – Inflection Point 17

BOAML 2016 Value Chain Progress: Building Inventory Across 135 Fields 18 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

BOAML 2016 Updated Inventory by Project Type 19 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 / $4 Mcf Dri lli n g Ca p it a l ($ M M ) Workovers Waterflood Unconventional Steamflood Primary

BOAML 2016 Steamflood Primary- Conventional Waterflood Primary- Unconventional Primary-Gas 35-50+% Per Pattern 30-90+% Per Well 30-100+% Per Pattern 15-40+% Per Well 12-30+% Per Well 20 Robust Returns Across Multiple Drive Mechanisms Oxnard Oakridge Wilmington Asphalto Rio Vista Midway Sunset Montalvo Huntington Beach Railroad Gap Thompkins Hill McDonald Anticline Rio Viejo San Miguelito BV Nose Willows McKittrick Pleito Ranch Mt. Poso Shale 29R Grimes Lost Hills Wheeler Ridge Rincon Buena Vista Kettleman Kern Front Saticoy S. Mountain N. Shafter Bardsdale Buena Vista Rose Paloma Paloma Gunslinger WSOZ WSOZ EH Stevens ESOZ ESOZ Kettleman EH Stevens EH Stevens Kettleman Kettleman All economics are pre-tax and assume $65/bbl Brent & $3.50/MMBTU NYMEX. Range is determined by low & high EUR boundaries

BOAML 2016 Elk Hills Adjacent Field: Buena Vista Field Development 21 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 ~10,000 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 $50.94 $20.31 $19.78 $13.54 $11.48 $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 42% reduction post spin

BOAML 2016 Elk Hills Analog: Kettleman North Dome 22 • 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

BOAML 2016 Steamfloods 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 • Up to 70% 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

BOAML 2016 Waterfloods 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 20 – 40% 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 S H A LL O W D EE P ETCHEGOIN SANDS # of S ta ck ed Reser voi rs Targeted Zones Characteristics

BOAML 2016 • CRC Opportunity Defined • Priorities and Accomplishments • Value Creation Focus – Doubles Inventory • Capital Allocation – Inflection Point 25

BOAML 2016 • Investment balanced against deleveraging opportunities with goal of high single-digit production growth • Existing Core Areas • Focus on 2-3 Growth Areas  Elk Hills Analogs  Elk Hills Adjacent Areas  Heavy Oil • Joint Venture opportunities • Double-digit growth possible if supported by price outlook, while sustaining balance sheet objectives • Core Areas + Growth Areas • 3+ High Impact Growth Areas Identified • Joint Venture opportunities • Exploration Capital Allocation Strategies with Improving Strip 26 Base Case Pricing* Steamfloods & Waterfloods Conventional Upside Pricing* Steamfloods and Waterfloods Conventional Unconventional and Other Capital Investments Capital Investments * Base Case Pricing assumes $65 Brent and Upside Case Pricing assumes $75+ Brent oil price.

BOAML 2016 Portfolio Flexibility Provides Range of Crude Oil Scenarios 27 80 90 100 110 120 130 2016E 2017E 2018E 2019E 2020E O il P ro d u ct io n MB/ d Crude Oil Production Outcomes Portfolio Planning Scenarios 0 300 600 900 1200 Ca p it al ( $MM ) Estimated Capital Invested Note: Assumes $60 Brent in 2017 and $65 Brent thereafter. 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. Top end of range of planning scenario outcomes includes geologic, development and permitting risks. All free cash flow reinvested in business for each outcome.

BOAML 2016 Double-Digit EBITDAX Growth 28 400 600 800 1000 1200 1400 1600 1800 2016E 2017E 2018E 2019E 2020E $M M Range of EBITDAX Outcomes Portfolio Planning Scenarios Note: See comments on previous slide.

BOAML 2016 NY00813G / 589203_1.WOR Sacramento Basin 14 MMBoe Proved Reserves 6 MBoe/d production San Joaquin Basin 451 MMBoe Proved Reserves 98 MBoe/d production Ventura Basin 47 MMBoe Proved Reserves 7 MBoe/d production Los Angeles Basin 132 MMBoe Proved Reserves 31 MBoe/d production  World-Class Resource Base: Large inventory of assets across basins and drive mechanisms that provide strong returns through the commodity price cycle  Exceptional Operating Control: High level of operating 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 Take Advantage of a Commodity Price Recovery Reserves as of 12/31/15; Production figures reflect average 3Q YTD 2016 rates. 29

BOAML 2016 California Resources Corporation Appendix 30

BOAML 2016 Capitalization as of 9/30/16 ($MM) $18 $449 $193 $149 $1,000 $2,250 212 $0 $500 $1,000 $1,500 $2,000 $2,500 Jan-1 6 Ju l-1 6 Jan-1 7 Ju l-1 7 Jan-1 8 Ju l-1 8 Jan-1 9 Ju l-1 9 Jan-2 0 Ju l-2 0 Jan-2 1 Ju l-2 1 Jan-2 2 Ju l-2 2 Jan-2 3 Ju l-2 3 Jan-2 4 Ju l-2 4 Term Loan Debt Maturities ($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 • $625 million net debt reduction from cash tender for bonds • Exchanged equity for $101 million of 5.5% and 6% bonds 1 As of September 30, 2016, we had approximately $506MM of available borrowing capacity under our revolving credit facility. 2 See Appendix for reconciliation to GAAP. 3 PV-10 as of 12/31/15 based on SEC five-year rule applied to PUDs using SEC price deck. See Appendix for reconciliation to GAAP. 4 Reserves as of 12/31/15. 5 Production in 3Q16. 1st Lien Secured RCF1 772 1st Lien Secured Term Loan (1L) 671 1st Lien Second Out Term Loan (1LSO) 1,000 Senior 2nd Lien Notes 2,250 Senior Unsecured Notes 554 Total Debt 5,247 Less cash (10) Total Net Debt 5,237 Equity (493) Total Net Capitalization 4,744 Total Net Debt / Total Net Capitalization 110% Total Net Debt / LTM Adjusted EBITDAX2 7.8x LTM Adjusted EBITDAX / LTM Interest Expense 2.1x PV-103 / Total Net Debt 1.0x Total Net Debt / Proved Reserves4 ($/Boe) $8.13 Total Net Debt / PD Reserves4 ($/Boe) $10.89 Total Net Debt / Production5 ($/Boepd) $37,949 * As of 9/30/16 31

BOAML 2016 Living within Cash Flow Plus Additional Liquidity 32 Based on our current capital program and at current price levels, we believe that we will have sufficient liquidity for the rest of this year, all of 2017 and well into 2018. Consensus2 EBITDA Consensus2 EBITDA Revolver Availability 1 Revolver Availability 1 Annual Cash Interest Annual Cash Interest Term Loan Amortization Term Loan Amortization HSE Capital Investment Credit Amendment CapEx 2 $0 $200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600 2016E 2016E 2017E 2017E ($MM ) 2 HSE & Capital Investment 1 Effective November 1, 2016, the borrowing base under our Credit Facilities was reaffirmed at $2.3 billion. As of September 30, we had approximately $506MM of available borrowing capacity under our revolving credit facility. 2 As of 11/09/16. 3 CRC’s investment budget for 2017 is currently limited by our credit facility up to $200 million plus carry-over of unspent 2016 investment and an additional potential $50 million on meeting a liquidity test in June 2017. CRC has not set a 2017 budget at this time; the Capital Investment reflects current maximum level in CRC’s Reserves-Based Credit Agreement. 1 1 3 2

BOAML 2016 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 Q4 2016 Q1 2017 Q2 2017 Q3 2017 Q4 2017 1Q 2018 2Q 2018 3Q 2018 4Q 2018 Calls Barrels per Day 25,000 12,100 5,000 10,000 15,000 15,600 15,000 15,000 15,000 Wtd Avg Ceiling Price per Barrel $53.62 $56.37 $55.05 $56.15 $56.12 $58.77 $58.83 $58.83 $58.83 Puts Barrels per Day 3,000 22,100 15,000 10,000 10,000 Wtd Avg Floor Price per Barrel $50.00 $49.10 $48.67 $48.00 $48.00 Swap Barrels per Day 39,000 20,0002 20,0002 20,0002 20,0002 Wtd Avg Price per Barrel $49.71 53.98 53.98 53.98 53.98 33 1 Prices are based on Brent. Positions as of November 11, 2016. 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.

BOAML 2016 2015 Net Proved Reserves (MMBoe) 644 2015 % Oil – Net Proved1 72% Pre-Tax Proved PV-10 ($ billion)2 5.1 2015 Avg. Net Production (MBoe/d) 160 2015 % Oil Production 65% 2015 Net Acreage (million acres) 1 2.4 2015 Identified Gross Locations1 23,450 1 As of 12/31/15. Drilling locations exclude 6,400 gross prospective locations. 2 See Appendix for reconciliation to GAAP. Figures shown are full year 2015, unless otherwise noted. San Joaquin Basin Los Angeles Basin Ventura Basin Sacramento Basin 2015 Net Proved Reserves (MMBoe) 451 132 47 14 2015 % Proved Developed 72% 80% 77% 100% 2015 % Liquids – Net Proved 1 78% 98% 89% 0% 2015 Avg. Net Production (MBoe/d) 110 34 9 7 2015 % Oil Production 58% 100% 67% 0% 2015 Net Acreage (million acres) 1 1.6 <0.1 0.3 0.5 2015 Identified Gross Drilling Locations 1 19,150 1,650 1,500 1,150 Diverse Assets with Flexible Development Opportunities • Diversity of basins, drive mechanisms • Predictable production, low decline rates • Multiple stacked reservoirs • Development targets include repeatable projects with low technical risk 34

BOAML 2016 35 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 Thompkins 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 mechanism and a combination of conventional and unconventional drilling targets.

BOAML 2016 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 • 3Q YTD 2016 average net production of 98 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

BOAML 2016 0 20 40 60 80 100 120 140 1998 2000 2002 2004 2006 2008 2010 2012 2014 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 • 3Q YTD 2016 avg. net production of 56 MBoe/d (40% of total production) • 540 MMcf/d processing capacity through 3 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

BOAML 2016 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 • 3Q YTD 2016 average net production of 31 MBoe/d (98% 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.

BOAML 2016 - 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) • 3Q YTD 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

BOAML 2016 Ventura Basin • Estimated ~3.5 billion barrels OOIP in CRC fields1 • Operate 29 fields (about 40% of basin) • ~300,000 net acres • Multiple source rocks: Miocene (Monterey and Rincon Formations), Eocene (Anita and Cozy Dell Formations) • 3Q YTD 2016 average net production of 7 MBoe/d (69% 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

BOAML 2016 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) • 3Q YTD 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

Shale Geological Overview Major U.S. Shale Plays Play Thickness (feet) Porosity (%) Permeability (mD) TOC (%) Maturity (%Ro) P (PSI/Ft) Monterey 200 – 3,500 5 - 30 0.0001 - 1.0 1 – 12 0.7 – 1.0 0.5 – 0.8 Kreyenhagen 250 – 1,000 5 - 12 0.001 – 0.1 2 – 18 0.7 – 1.2 0.5 – 0.8 Moreno 200 – 500 5 - 12 0.001 – 0.1 1 – 6 0.7 – 1.3 0.5 – 0.8 Bakken 6 – 145 2 - 12 0.01 – 1.0 8 – 21 0.8 – 1.0 0.5 – 0.8 Barnett 100 – 500 4 – 9 0.0001 – 0.1 4 – 8 0.8 – 2.0 0.5 – 0.6 Eagle Ford 100 – 250 3 – 14 0.001 – 0.1 2 - 9 1.0 – 1.4 0.4 – 0.6 California 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 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.

BOAML 2016 Recovery Factors for Discovered Fields¹ 9 40 0 5 10 15 20 25 30 35 40 45 Cum Recovered to Date Remaining 3P + Contingent RF + 10% RF + 15% RF + 20% Original in Place Billion Boe 1 Does not include undiscovered unconventional resource potential. • In place volumes of ~40 billion Boe at low recovery factor (22%) to date • Conventional “value chain” approach to life of field development • Unconventional success with attractive upside positioning • Untapped opportunities to apply technology advances to California • Good return projects that can withstand a variety of price environments Large in Place Volumes with Significant Upside for CRC 43

BOAML 2016 A Net Water Supplier • CRC’s delivery of reclaimed produced water to agriculture in 2015 exceeded the amount of fresh water we purchased by nearly 1 billion gallons • We expedited the North Kern Drought Relief project in 2015, achieving a 30% increase in our water supply to agriculture • We recycled approximately 77% of our produced water in improved or enhanced recovery operations in 2015 • We reduced our purchased fresh water volume by over 11% in 2015 94% 3% 3% WATER MANAGED IN CRC’s OPERATIONS Produced Water Fresh Water Non-Fresh Water In 2015, CRC’s steamflood operations supplied more than 2.6 billion gallons – over 8,100 acre-feet – of water for irrigation This preserves fresh water for other beneficial uses, equivalent to the needs of approximately 17,800 families per year 44 CRC’s operations in Long Beach use recycled water for 99.5% of their total water use

BOAML 2016 Diverse Resource Base • Interests in 4 of the 12 largest fields in the lower 48 states • 644 MMBoe proved reserves (12/31/2015) • 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 • 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 45

BOAML 2016 End Notes: 46 1 Reflects CRC estimate of reserves value as of August 23, 2016 applying a 15% tax rate. Includes $125 MM of annual, non-field level G&A. 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 may include contingent and prospective resources. Contingent and prospective resources consist of volumes identified through life-of-field planning efforts to date. 5 Calculated using September 30, 2016 debt at par and market cap as of October 31, 2016.

BOAML 2016 Non-GAAP Reconciliation for Adjusted EBITDAX 47 Third Quarter Nine Months ($ in millions) 2016 2015 2016 2015 Net Income (loss) $546 ($104) $356 ($272) Interest and debt expense 95 82 243 244 Income tax benefit - (50) (78) (165) Depreciation, depletion and amortization 137 253 422 757 Exploration expense 3 5 13 29 Adjusted income items before interest and taxes (a) (629) 12 (548) 45 Other non-cash items 12 14 40 42 Adjusted EBITDAX $164 $212 $448 $680 Net cash provided by operating activities $101 $180 $145 $412 Cash interest 64 99 244 248 Exploration expenditures 3 3 13 20 Other changes in operating assets and liabilities (9) (73) 32 (6) Plant turnaround, outage and other costs 5 3 14 6 Adjusted EBITDAX $164 $212 $448 $680 (a) See slide 48 for a table reconciling net income (loss) to adjusted net income (loss).

BOAML 2016 Non-GAAP Reconciliation for Adjusted Net Loss and Adjusted EPS 48 Third Quarter Nine Months ($ in millions) 2016 2015 2016 2015 Net Income (loss) $546 ($104) $356 ($272) Non-cash, unusual and infrequent items Non-cash derivative losses (gains) 25 (53) 243 (33) Severance and early retirement costs 1 62 19 72 Plant turnaround, outage and other costs 5 3 14 6 Net gain on early extinguishment of debt (660) - (793) - Gain from asset divestitures - - (31) - Adjusted income items before interest and taxes (629) 12 (548) 45 Deferred debt issuance costs write-off 12 - 12 - Valuation allowance for deferred tax assets (a) - - (63) - Tax effects of these items - 6 - (7) Total (617) 18 (599) 38 Adjusted net loss ($71) ($86) ($243) ($234) Net income (loss) per diluted share $13.06 ($2.72) $8.79 ($7.10) Adjusted net loss per diluted share ($1.75) ($2.25) ($6.12) ($6.11) Weighted average diluted shares outstanding 41.8 38.3 40.5 38.3 (a) Amount represents the out-of-period portion of the valuation allowance reversal.

BOAML 2016 Non-GAAP Reconciliation for PV-10 ($ in millions) At December 31, 2015 PV-10 of Proved Reserves $5,059 Present value of future income taxes discounted at 10% (1,035) Standardized Measure of Discounted Future Net Cash Flows $4,024 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. 49