Investor Slides December, 2014

Forward-Looking / Cautionary Statements This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical fact, included in this presentation that address activities, events or developments that California Resources Corporation (the “Company” or “CRC”) assumes, plans, expects, believes or anticipates will or may occur in the future are forward-looking statements. The words “believe,” “expect,” “may,” “estimate,” “will,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. However, the absence of these words does not mean that the statements are not forward-looking. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including as to the Company’s drilling program, production, hedging activities, capital expenditure levels and other guidance included in this presentation. These statements are based on certain assumptions made by the Company based on management’s expectations and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include, but are not limited to, commodity pricing; inability to reduce costs; compliance with regulations or changes in regulations and the ability to obtain government permits and approvals; vulnerability to economic downturns and adverse developments in our business due to our debt; insufficiency of our operating cash flow to fund planned capital investments; inability to implement our capital investment program profitably or at all; inability to drill identified locations when planned or at all; risks of drilling; regulatory initiatives relating to hydraulic fracturing and other well stimulation techniques; tax law changes; the subjective nature of estimates of proved reserves and related future net cash flows; concentration of operations in a single geographic area; any need to impair the value of our oil and natural gas properties; compliance with laws and regulations, including those pertaining to land use and environmental protection; restrictions on our ability to obtain, use, manage or dispose of water; concerns about climate change and air quality issues; catastrophic events for which we may be uninsured or underinsured; cyber attacks; operational issues that restrict production or market access. 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 generally accepted accounting principles (“GAAP”), including 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 EBITDAX to the nearest comparable measure in accordance with GAAP, please see the Appendix.

Cautionary Statements Regarding Hydrocarbon Quantities CRC has provided internally generated estimates for proved reserves and aggregated proved, probable and possible reserves (“3P Reserves”) as of December 31, 2013 in this presentation, with each category of reserves estimated in accordance with SEC guidelines and definitions, though it has 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 CRC’s interests may differ substantially from the estimates in this presentation. Factors affecting ultimate recovery include the scope of CRC’s 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, including geological and mechanical factors affecting recovery rates; and budgets based upon our future evaluation of risk, returns and the availability of capital. In this presentation, the Company may use the terms “oil-in-place” or descriptions of resource potential which the SEC guidelines restrict from being included in filings with the SEC. These have been estimated internally by the Company without review by independent engineers and include shales which are not considered in most older, publicly available estimates. The Company uses the term “oil-in-place” in this presentation to describe estimates of potentially recoverable hydrocarbons remaining in the applicable reservoir. Actual recovery of these resource potential 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, the Company’s production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases.

Key Credit Highlights World Class Resource Base Interests in 4 of the 12 largest fields in the lower 48 states 744 MMBoe proved reserves 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 Increased 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

Disciplined Capital Allocation Focused Business Strategy Grow NAV per share through exploration and development of under-exploited resources Self-funding capital program eliminates reliance on external capital Rigorously review projects to allocate capital most efficiently Drive down costs to enhance project returns and ROE Aggressively apply modern technologies to develop assets in a responsible manner Utilize legacy knowledge and data to accelerate successful exploration program Capitalize on management team’s local expertise with assets Proactive and Collaborative Approach to Safety, Environmental Protection and Community Relations Unlock Resource Potential Through Increased Exploration and Development Seek to benefit communities in which CRC operates Maintain frequent, constructive dialogue with local, regional and state representatives Be the operator of choice for California

The State of California is a World Class Oil Province 1 Produced volumes: California Division of Oil, Gas & Geothermal Resources (“DOGGR”). Over 35 billion Boe produced since 18761 Pico Canyon #4 was the first well with commercial production west of the Rockies and produced from 1876 to 1992 Rich marine oil and gas source rocks Underexplored with large undiscovered resources ~ 50 different active plays We have operated in California since the 1950s California's oil-in-place estimates have grown over many decades, and CRC expect to continue to expand its reserve base with the increasing application of proven, modern technologies San Francisco Los Angeles Bakersfield Sacramento CRC Fee/Lease CRC Fee/Lease 2 billion Boe 19 billion Boe 4 billion Boe 10 billion Boe

Overview of California Resources Corporation California Pure-Play Net Resource Overview CRC is an independent E&P company focused on high-return assets in California Largest privately-held acreage-holder with 2.3 million net acres (12/31/13) ~60% of total position is held in fee (12/31/13) Conventional and unconventional opportunities Primary production Waterfloods & gas injection Steam / EOR Substantial base of Proved Reserves (12/31/13) 744 MMBoe (69% PD, 72% oil, 81% liquids) PV-10 of $14 billion (SEC 5 year rule to PUDs) 3P Reserves1 1,098 MMBoe (83% liquids) PV-10 of $21 billion as of December 2013 San Joaquin Basin 69% 68% PD Los Angeles Basin 21% 70% PD Ventura Basin 7% 64% PD Sacramento Basin 3% 100% PD San Joaquin Basin 71% 57% Oil Los Angeles Basin 18% 99% Oil Ventura Basin 5% 68% Oil Sacramento Basin 6% 0% Oil 1Refer to Endnote reference 1 for detail on 3P Reserves. 217,691 locations in known formations as of 12/31/13. Does not include 6,400 prospective resource locations. Total proved reserves by basin (12/31/2013) Total identified gross drilling locations by basin2 17,691 total gross locations2 744 MMBoe, 69% PD, 72% oil 157 MBoe/d, 62% oil Total 3P Reserves by basin (12/31/2013) 1,098 MMBoe; 83% liquids 12,836 73% 1,537 9% 2,310 13% 1,008 5% San Joaquin Basin Los Angeles Basin Sacramento Basin Ventura Basin San Joaquin Basin Los Angeles Basin Sacramento Basin Ventura Basin 744, 68% 79% liquids 235, 21% 99% liquids 96, 9% 89% liquids 22, 2% 1% liquids Avg. net production by basin (YTD Q3’14)

CRC is the Leading Operator in California 85% of CA production from top 5 operators* Top California Producers in 2013* Growth of Top California Producers Aera Chevron CRC Top 25 Companies MBoe/d % of CA CRC 188.0 29% Chevron 166.2 25% Aera 147.1 22% PXP/Freeport 38.5 6% Berry/Linn 25.4 4% MacPherson 11.3 2% Seneca 10.4 2% Venoco 7.0 1% E&B 6.6 1% Pacific Coast Enrg 6.4 1% Warren 3.8 0.6% Breitburn 3.8 0.6% XOM 3.7 0.5% DCOR 3.3 0.5% Signal Hill 3.1 0.5% Greka 3.0 0.5% Crimson 2.7 0.4% ERG 2.2 0.3% Holmes 2.0 0.3% Termo 1.9 0.3% SJFM 1.6 0.2% TRC 1.5 0.2% Vaquero 1.3 0.2% Kern River Hldgs 1.3 0.2% JP Oil 1.1 0.2% Total – Top 25 642.8 97% Remaining 300 companies 22.2 3% *Gross operated production from DOGGR data for 2013 full year average. 0 50 100 150 200 250 300 Gross Operated MBoe/d 188 166 147 38 25 - 20 40 60 80 100 120 140 160 180 200 CRC Chevron USA Aera Energy Freeport McMoRan LINN Energy Gross Operated MBoe/d

Acquisitions Over the Years ~40M acres Elk Hills and Kern Front 1.2MM acres Acquisition of Vintage and CA EOG assets 2.3MM acres Leading privately held acreage position in the state 1998 2009 2013 Tidelands Thums 0 500,000 1,000,000 1,500,000 2,000,000 2,500,000 Acquisition Date San Joaquin and Sacramento Basin Minerals San Joaquin Minerals San Joaquin Basin Minerals and North Shafter SJV North SJV and Sac Stockdale SJV Central Huntington Beach Buen a Vista Hills Kettleman North Dome Lost Hills Elk Hills Vintage Merger Net Acres

Substantial Opportunity and Resource Rich Asset Base Total California 2013 Reserves Net Proved Reserves (MMBoe) 744 % Liquids – Net Proved 81% Pre-Tax Proved PV-10 ($ millions)1 $14,018 Net 3P Reserves MMBoe 1,098 % Liquids – Net 3P 83% Pre-Tax 3P PV-10 ($ millions) $20,995 YTD Q3’14 Avg. Net Production (MBoe/d) 157 % Oil 62% Net Acreage (‘000 acres) 2,296 Identified Gross Locations 17,691 Additional Potential Locations 6,400 Note: Reserves as of 12/31/13. 1 PV-10 shown as of 12/31/13 based on SEC five-year rule applied to PUDs using SEC price deck of WTI at $97.97/Bbl and $3.66/Mcf. 2 Basin-level PV-10s include $180MM associated with fuel gas, which is excluded from PV-10 of $14,018MM disclosed in Form 10 filing. 3 Refer to Endnote reference 2 for further information. San Joaquin Basin Los Angeles Basin Ventura Basin Sacramento Basin Net Proved Reserves (MMBoe) 511 159 55 19 % Liquids – Net Proved 78% 98% 89% 0% Pre-Tax Proved PV-10 ($ million)2 $10,130 $2,331 $1,631 $106 Net 3P Reserves MMBoe3 744 235 96 22 % Liquids – Net 3P3 79% 98% 89% 1% Pre-Tax 3P PV-10 ($ millions)3 $14,983 $3,343 $2,556 $113 YTD Q3’14 Avg. Net Production (MBoe/d) 111 28 9 9 % Oil 57% 100% 67% 0% Net Acreage (‘000 acres)(12/31/13) 1,485 21 257 533 Identified Gross Locations 12,836 1,537 2,310 1,008 Sacramento Basin San Joaquin Basin Ventura Basin Los Angeles Basin

Conventional Waterflood Steamflood Unconventional Total Net Proved Reserves (MMBoe) 112 238 178 216 744 % Liquids - Net Proved 68% 95% 100% 57% 81% Pre-Tax Proved PV-10 ($ millions) $959 $4,216 $4,917 $4,105 $14,1982 Net 3P Reserves (MMBoe)3 187 373 227 312 1,098 % Liquids - Net 3P3 77% 94% 100% 60% 83% Pre-Tax 3P PV-10 ($ millions)3 $2,719 $6,342 $5,906 $6,029 $20,995 YTD Q3’14 Avg. Net Production (MBoe/d) 33 37 30 57 157 % Oil 41% 94% 99% 34% 62% Identified Gross Locations 6,455 3,540 3,014 4,682 17,691 Additional Potential Locations - - - 6,400 6,400 Single Well/Pattern Economics by Drive Mechanism: Before Tax IRR1 Total California 2013 Reserves Note: Reserves as of 12/31/13. PV-10 shown as of 12/31/13 using SEC price deck of WTI at $97.97/Bbl and $3.66/Mcf. 1Assumes $100/Bbl and $4.50/Mcf. 2 Drive-mechanism-level PV-10s include PV-10 of $180MM associated with fuel gas excluded from PV-10 of $14,018MM disclosed in Form 10 filing. 3 Refer to Endnote reference 3 for further information. Robust Returns Across Multiple Drive Mechanisms Conventional Waterflood Steamflood Unconventional 50%+ per pattern 50%+ per pattern 80% - 100%+ per well 30% - 50% per well

Creating a Recovery Value Chain Conventional fields in various stages of development Base assets in place – advancing recovery with traditional means Moving recoveries from primary through EOR Primary (93 fields) Production with natural energy of reservoir or gravity drainage Waterflood (17 fields) Incremental recovery beyond primary with pressure support and displacement Steam / EOR (12 fields) Enhanced recovery from reservoirs using techniques such as steam, CO2, etc. Approximate current CRC RF% Development program is based on reservoir characteristics, reserves potential, and expected returns Typical Recoveries by Mechanism Type 0 10 20 30 40 50 60 70 80 Primary Waterflood Steam Recovery of Orig in Place; RF%

Large in Place Volumes with Significant Upside Recovery Factors for Discovered Fields¹ Billion Boe 1 Does not include undiscovered unconventional resource potential. Leading asset position to exploit In place volumes of ~40 Bn Boe at low recovery factor (22%) to date Conventional “value chain” approach to life of field development Unconventional success with great upside positioning Untapped opportunities to apply technology advances to California Good return projects that can withstand alternative price environments 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

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) YTD Q3’14 average net production of 9 MBoe/d (100% dry gas) Produce 85% of basin gas with synergies of scale Price and volume opportunity Overview Key Assets Basin Map

San Joaquin Basin Oil and gas discovered in the late 1800s Currently accounts for ~70% of CRC production 25 billion barrels OOIP in CRC fields 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 YTD Q3’14 avg. of 111 MBoe/d (57% oil) Elk Hills is the flagship asset (~57% 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 Buena Vista Pleito Ranch Elk Hills Kettleman Lost Hills Mt Poso CRC Land Kern Front

Elk Hills Field – Overview CRC’s flagship asset, a 103-year old field with exploration opportunities1 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 OOIP and cumulative production of 1.6 billion Boe1 In 2013, produced 68 MBoe/d (44% of total production), including 46 MBoe/d of unconventional production from the upper Monterey Shale 540 MMScf/d processing capacity 2 CO2 removal plants Over 4,200 miles of gathering lines 3 gas plants (including California’s largest) 45 MW cogeneration plant 550 MW power plant Overview Comprehensive Infrastructure Field Map Production History 1DOGGR data and U.S. Energy Information Administration. Elk Hills Buena Vista Asphalto RR Gap GS 0 20 40 60 80 100 120 140 1998 2000 2002 2004 2006 2008 2010 2012 2014 Net MBoe/d

Ventura Basin Estimated ~3.5 billion barrels OOIP in CRC fields1 Operate 25 fields (about 40% of basin) 257,500 net acres Multiple source rocks: Miocene (Monterey and Rincon Formations), Eocene (Anita and Cozy Dell Formations) YTD Q3’14 average net production of 9 MBoe/d 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. San Miguelito Oxnard Saticoy South Mountain Shiells Canyon Rincon CRC Waterflood Fields Aera Waterflood CRC Primary Production Fields Ventura

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 fields 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 YTD Q3’14 avg. net production of 28 MBoe/d Over 20,000 net acres Active coastal development program underway – seven rigs and 143 wells drilled year to date Major properties are world class coastal developments of Wilmington and Huntington Beach Overview Key Assets Basin Map

Wilmington Field – Overview 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) Q3’14 avg. production of 36.8 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 – 2013 are based on current SEC reserve methodology and SEC pricing. Tidelands Acquired: 2006 Belmont Offshore Acquired: 2003 Long Beach Unit Acquired: 2000 Pico Properties Acquired: 2008 - 50 100 150 200 250 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 MMBoe Net Proved Reserves Production to Date

CRC has a significant portfolio of conventional and unconventional opportunities to generate double-digit production growth over the longer-term. CRC has developed preliminary planning scenarios that indicate it may be able to grow crude oil production at a double-digit pace from operating cash flow in a mid- $70 oil price environment and maintain crude oil production relatively flat in a $60 oil price environment with operating cash flow, subject to certain cost-savings and other assumptions (including those noted on Slide 1). 10%+ Longer-term growth1 Value-additive Growth Living within Cash Flow 1 Based on 4Q’14 guidance for net production of 162 – 165 MBoe/d and 2014 capital budget of $2.1 billion, as disclosed in the Form 10, assuming commodity prices of $100/Bbl for crude oil and $4.50/Mcf for natural gas. 155 158 1 - - 50 100 150 200 250 1H'14 2014 2015 2016 Longer-term MBoe/d (Net) Oil NGLs Gas

Proven Track Record in Sensitive Environments Operator of choice in coastal environments Proven coexistence with sensitive environmental receptors Excellence in safety and mechanical integrity

CRC – Price Realizations NGL Price Realization - % of WTI Realization % of WTI 109% 110% 106 % 101% Realization % of NYMEX 105% 105 % 102 % 102% Oil Price Realization Gas Price Realization Since California imports a significant percentage of its crude oil requirements, California refiners typically purchase crude oil at international index-based prices for comparable grades $95.12 $94.21 $97.97 $99.61 $103.80 $104.02 $104.16 $100.94 $110.90 $111.70 $108.76 107.02 $80 $90 $100 $110 $120 2011 2012 2013 9 Months 2014 $/Bbl WTI Realizations Brent $4.11 $2.81 $3.66 $4.53 $4.31 $2.94 $3.73 $4.46 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 2011 2012 2013 9 Months 2014 $/ Mcf NYMEX Realizations 74% 56% 51% 52% 0% 10% 20% 30% 40% 50% 60% 70% 80% 2011 2012 2013 9 Months 2014 % of WTI

Financial Strength Provides Flexibility to Drive Growth Capital program: Invest within cash flow Growth strategy based on re-investment in opportunity rich portfolio of projects and disciplined allocation of capital Maintain strong liquidity profile Target debt / EBITDAX of 2.2x or less Funds from operations / debt: 30% - 40% Selective commodity hedging to support capital program or M&A Opportunistic M&A to increase asset base where attractive Corporate family and senior unsecured credit ratings of Ba1 and BB+ from Moody’s and S&P, respectively Est. Capitalization as of 10/1/14 ($MM) Debt Maturities ($MM) 1 CRC expected to borrow an additional $300 – 350 million, including (i) $200 million to repay a short-term loan from OXY used to fund the acquisition of oil and gas properties and (ii) $100 – 150 million concurrently with, or shortly after, the Spin-Off to fund working capital requirements as a stand-alone company. 2 PV-10 shown as of 12/31/13 based on SEC five-year rule applied to PUDs using SEC price deck. $2.0Bn Senior Unsecured RCF1 65 Senior Unsecured Term Loan 1,000 Senior Unsecured Notes 5,000 Total Debt 6,065 Equity 4,869 Total Capitalization $10,934 Total Debt / Capitalization 55% Total Debt / LTM EBITDAX 2.2x EBITDAX / Interest expense 9.0x PV-102 / Total Debt 2.3x Total Debt / Proved Reserves ($/Boe) $8.15 Total Debt / PD Reserves ($/Boe) $11.80 Total Debt / Production ($/Boepd) $38,631 $25 $625 $1,000 $1,750 $2,250 $0 $500 $1,000 $1,500 $2,000 $2,500 Jan-16 Jun-16 Nov-16 Apr-17 Sep-17 Feb-18 Jul-18 Dec-18 May-19 Oct-19 Mar-20 Aug-20 Jan-21 Jun-21 Nov-21 Apr-22 Sep-22 Feb-23 Jul-23 Dec-23 May-24 Oct-24 Term Loan Senior Notes Ter

Self-Funded Capital Investment Program Commentary 2014 Drilling Capital Budget – By Basin 2014 Total Capital Budget 2014 Capital Budget – By Drive 2014 capital budget of $2.1 billion is an increase of 24% from 2013 CRC plans to reinvest excess free cash flow that prior to spin was sent to Occidental Total: $2.1 billion Total: $1,390 million 1Other includes land, seismic, infrastructure and other investments. 1 Drilling ~$1,390 ~66% Dev. Facility ~$280 ~13% Workover ~$200 ~9% Exploration ~$95 ~5 % Other ~$145 ~7% San Joaquin $942 68% Los Angeles $384 28 % Ventura $56 4% Sacramento $8 1 % Primary $342 16% Unconventional $543 26% Waterflood $787 37% Steamflood $343 16% Exploration $95 5%

The CRC Investment Opportunity World Class Resource Base Portfolio of Lower-Risk, High-Growth Opportunities Management Expertise California Heritage Shareholder Value Focus

California Resources Corporation Q&A

Non-GAAP Reconciliation for EBITDAX For the Year Ended December 31, 9 Months Ended, Last Twelve Months Ended, ($ in millions) 2012 2013 9/30/2013 9/30/2014 9/30/2014 Net Income $699 $869 $657 $657 $869 Interest Expense - - - - - Provision for income taxes 482 578 438 444 584 Depreciation, depletion and amortization 926 1,144 853 886 1,177 Exploration expense 148 116 81 71 106 EBITDAX $2,255 $2,707 $2,029 $2,058 $2,736 Net cash provided by operating activities $2,223 $2,476 $1,903 $1,891 $2,464 Interest expense - - - - - Cash income taxes (121) 318 241 182 259 Cash exploration expenses 20 44 30 19 33 Changes in operating assets and liabilities 202 (102) (103) (12) (11) Asset impairments and related items (41) - - - - Other, net (28) (29) (42) (22) (9) EBITDAX $2,255 $2,707 $2,029 $2,058 $2,736

Endnotes As of 12/31/13, CRC’s probable reserves were 218 MMBoe (87% liquids) with a PV-10 of $4 billion and possible reserves were 136 MMBoe (83% liquids) with a PV-10 of $3 billion, each based on SEC pricing. As of 12/31/13, CRC’s probable reserves in the San Joaquin, Los Angeles, Ventura and Sacramento basins were 124 MMBoe (82% liquids), 65 MMBoe (95% liquids), 28 MMBoe (89% liquids) and 1 MMBoe (0% liquids), respectively, with a PV-10 of $2.5 billion, $0.9 billion, $0.6 billion and $0.0 billion, respectively, and CRC’s possible reserves were 109 MMBoe (82% liquids), 12 MMBoe (100% liquids), 14 MMBoe (86% liquids) and 1 MMBoe (0% liquids), respectively, with a PV-10 of $2.4 billion, $0.1 billion, $0.4 billion and $0.0 billion, respectively, each based on SEC pricing. As of 12/31/13, CRC’s probable reserves associated with conventional, waterflood, steamflood and unconventional drive mechanisms were 32 MMBoe (91% liquids), 101 MMBoe (94% liquids), 41 MMBoe (100% liquids) and 44 MMBoe (59% liquids), respectively, with a PV-10 of $0.8 billion, $1.6 billion, $0.9 billion and $0.6 billion, respectively, and CRC’s possible reserves were 42 MMBoe (90% liquids), 35 MMBoe (86% liquids), 8 MMBoe (100% liquids) and 51 MMBoe (75% liquids), respectively, with a PV-10 of $0.9 billion, $0.5 billion, $0.1 billion and $1.3 billion, respectively, each based on SEC pricing.

ROR Sensitivity – Pattern Waterflood Project Type Avg Pattern cost ($MM) $0.6 % Oil 100% DPI10 4.85 DPI15 4.45 Locations 180 Net F&D ($ / Boe)1 $8.92 WF EUR (Gross) MBoe Oil Prices (WTI $ / Bbl) 43 65 87 109 131 $100 102% 169% 238% 311% 388% $90 89% 147% 208% 272% 337% $80 75% 125% 178% 233% 289% Key Assumptions & Outputs Improving recovery from primary reservoirs Redeveloping existing asset base Wells already drilled Expand waterflood facilities Already understand reservoir characteristics from prior production performance Average Waterflood Pattern Production Response Type Curve Average Curve Boe/d Months 1 Refer to Endnote reference 2 in the Appendix for detail on the calculation of F&D costs. DPI - Discounted Profitability Index is a ratio of the net present value of the project over capital investment, used for ranking investments in our portfolio of assets. EUR – Estimated Ultimate Recovery 0 20 40 60 80 100 -6 0 6 12 18 24 2012 2013 2014

ROR Sensitivity 9 Spot Inv Pattern cost ($MM) $1.8 % Oil 100% DPI10 2.2 DPI15 1.9 Net F&D ($ / Boe)1 $10.50 Locations 100+ Fuel Gas Price, $ / MMBTU $4.50 EUR (Gross) MBoe Oil Prices (WTI $ / Bbl) 120 145 175 200 230 $100 30% 44% 57% 69% 82% $90 22% 35% 47% 58% 69% $80 13% 26% 37% 47% 57% Steamflood Projects Improving recovery from heavy oil reservoirs Add steam to make oil flow better Proven process Good quality reservoirs; high oil saturation Reliable execution Shallow reservoirs; inexpensive to drill High margins and good returns Key Assumptions & Outputs Example Kern Front Pattern 1 Refer to Endnote reference 2 in the Appendix for detail on the calculation of F&D costs. 0 20 40 60 80 100 120 140 1 2 3 4 5 6 7 8 9 10 11 Bopd Year

Shale Geological Overview Major U.S. Shale Plays California Unconventional Potential 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 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' – 16,000' 200' – 350' 5 – 15 <0.001 – 0.1 1 – 6 Moreno1 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. 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