SCOTIA HOWARD WEIL 46 TH ANNUAL ENERGY. CONFERENCE Todd Stevens President and CEO March 28, 2018

Transcription

1 SCOTIA HOWARD WEIL 46 TH ANNUAL ENERGY CONFERENCE Todd Stevens President and CEO March 28, 2018

2 Forward Looking / Cautionary Statements This presentation contains forward-looking statements that involve risks and uncertainties that could materially affect our expected results of operations, liquidity, cash flows and business prospects. Such statements include those regarding our expectations as to our future: financial position, liquidity, cash flows and results of operations business prospects transactions and projects operating costs Value Creation Index (VCI) metrics are based on certain estimates including future production rates, costs and commodity prices 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 thirdparty 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: 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 operations and operational results including production, hedging and capital investment budgets and maintenance capital requirements reserves type curves 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 or storage 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. 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. See the Investor Relations page at for important information about 3P reserves and other hydrocarbon resource quantities, finding and development costs, recycle ratio calculations, and drilling locations. Scotia Howard Weil 46 th Annual Energy Conference 2

3 Value Proposition Multiple Ways to Increase Valuation $MM Regaining Momentum Through Increased Investment Increasing CRC Investments and Deploying Rigs Disciplined Portfolio Management ,500 2,000 EBITDAX Growth* Joint Ventures Opportunistic Deleveraging Significant Operating Leverage to Crude Oil 1,500 1, E 2019E 2020E 2021E 2021E *See Slide 24 for additional information regarding EBITDAX Growth planning scenarios. Scotia Howard Weil 46 th Annual Energy Conference 3

4 CRC s Large Resource Base with Advantaged Infrastructure World-Class Resource Base Operate 4 of the largest fields in the continental U.S. Diversified, conventional portfolio with low base decline rate 618 MMBOE proved reserves 129 MBOE/d production, 64% oil 2.3 million net mineral acres Sacramento Basin 14 MMBOE Proved Reserves 6 MBOE/d production (100% dry gas) San Joaquin Basin 419 MMBOE Proved Reserves 90 MBOE/d production (58% oil) Positioned to Grow Internally funded capital program designed to live within cash flow and drive growth Development investment augmented by JV capital and increases flexibility 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 Ventura Basin 40 MMBOE Proved Reserves 6 MBOE/d production (67% oil) Los Angeles Basin 145 MMBOE Proved Reserves 27 MBOE/d production (100% oil) Reserves as of 12/31/17; Production figures reflect average FY 2017 rates. Scotia Howard Weil 46 th Annual Energy Conference 4

5 DEEP 15,000 1,000 PAY Production Mix OPEX $/Boe** Gross Operated MBoe/d SHALLOW <5,000 Largest California Producer with Deep Regional Insight Top California Producers in 2017* TULARE SANDS ETCHEGOIN SANDS Largest 3-D Seismic Position in California MONTEREY SANDS AND SHALES - CRC Chevron USA Aera Energy Sentinel Peak Berry 100% 75% 50% 25% 0% Majority of CA Production is Shallow* $29 $29 $24 $21 $19 CRC Chevron USA Aera Energy Sentinel Peak Berry Shallow Deeper (>5,000') FY OPEX $/BOE** $35 $30 $25 $20 $15 $10 $5 $0 TEMBLOR SANDS EOCENE SANDS AND SHALES UPPER CRETACEOUS SANDS AND SHALES *Source: DOGGR data (average production data for 2017) **Information for CRC, Chevron, and Aera is from 2017, data for Berry and Sentinel Peak are from most recent available information which is Source: Wood Mackenzie, Company Estimates. Scotia Howard Weil 46 th Annual Energy Conference 5

6 San Joaquin Basin An American Super Basin Gross Wells Drilled Avg. Rig Count Overview Oil and gas discovered in the late 1800s 70% of CRC production is from San Joaquin Basin Cretaceous to Pleistocene sedimentary section (>25,000 feet) Thermal recovery applied since early 1960s Currently running 7 drilling rigs Key Assets 2017 average net production of 90 MBOE/d (58% oil) with <8% YOY decline Elk Hills is the flagship asset (~59% of FY 2017 CRC San Joaquin production) Two core steamfloods - Kern Front and Lost Hills Early stage waterfloods at Buena Vista and Mount Poso Substantial, integrated infrastructure that supports Elk Hills Basin Map Legend CRC Land Oil Field Gas Field CRC Operated Steamflood Waterflood Primary Unconventional Avg. Rig Count Scotia Howard Weil 46 th Annual Energy Conference 6

7 Los Angeles Basin Kitchen is the Entire Basin Gross Wells Drilled Avg. Rig Count Overview World-class hydrocarbon-rich sedimentary basin with large quantities of stacked pay ~10 billion barrels OOIP in CRC fields Kitchen is the entire basin, hydrocarbons did not migrate laterally; basin depth (>30,000 ft) Very few penetrations >10,000 ft, leaving deep horizons underexplored Focus on mature waterfloods with generally low technical risk and proven repeatable technology across huge OOIP fields 2017 average net production of 27 MBOE/d (100% liquids) with a 10% YOY decline and an organic reserves replacement ratio of 330%* Over 30,000 net mineral acres Major properties are premier coastal development assets of Wilmington and Huntington Beach Wilmington Basin Map Legend CRC Land Oil Field Gas Field CRC Operated The Wilmington field is subject to contractual agreements similar to production-sharing contracts (PSCs). The contracts represented slightly less than 20% of our total 2017 production. Huntington Beach 50 Waterflood Avg. Rig Count Performed 26 Capital Workover projects in *Organic reserves replacement excludes the effect of price change on reserves volumes Scotia Howard Weil 46 th Annual Energy Conference 7

8 Ventura Basin Birthplace of the California Oil Industry Overview Prolific basin with a long history, including the first commercial oil well in California Field Map ~8 billion barrels OOIP in CRC fields Operate 28 fields (over half the fields in the basin) ~250,000 net mineral acres (75% undeveloped) 2017 average net production of 6 MBOE/d (67% oil) Portfolio of drive mechanisms: Primary, New & Redevelopment Waterfloods and Steamfloods Building off exploration success: recent exploration wells have flowed in excess and 1,000 BOE/d (80% oil) along Oak Ridge trend Incorporating 10 square miles of 3D seismic into drillable locations Legend Active CRC Field Idle CRC Field Significant upside: movable oil, low recovery factor, controlling acreage position and existing infrastructure California wildfires in Ventura County impacted December 2017 production by approximately 2,000 BOE/d and production remained affected by approximately 1,000 BOE/d in January 2018 OOIP (MMBO) CUM PROD (MMBO) RF 7, % High Growth Area: large OOIP, low recovery factor and potential for high-ip wells Scotia Howard Weil 46 th Annual Energy Conference 8

9 Sacramento Basin Significant Gas Optionality Overview 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 under 6,000 feet, deeper targets remain at less than 10,000 feet 3D seismic surveys in mid-1990s helped define trapping mechanisms and reservoir geometries 2017 average net production of 33 MMcf/d (100% dry gas) CRC produces 85% of basin gas with synergies from scale Includes the Rio Vista field, which has produced over 3.7 TCF of natural gas over its lifetime CRC has an active exploration program in the basin Legend CRC Land Oil Field Gas Field CRC Operated Basin Map California imports >90% of its natural gas requirements 0 20 Miles Scotia Howard Weil 46 th Annual Energy Conference 9

10 MMBoe Value Additive Inventory Growth Comprehensive technical review of 40% of CRC s fields. 2,250 3P Reserves Growth Since Spin 2017 proved reserves of 618 million BOE and 450 million BOE of probable reserves. 119% organic reserve replacement, excluding the effect of price adjustments. 2,000 1,750 1,500 >350% Growth 1,129 We added 34 million BOE of proved reserves from extension and discoveries and 22 million BOE from performance. We were also able to rebook 49 million BOE due to the increase in prices compared to prior years. 1,250 1, Organic F&D costs excluding price related revisions was $6.82 per BOE and produced a recycle ratio of 2.1x Over 95% of our total proved reserves have been audited by Ryder Scott in the last three years Spin-off Cummulative Production Revisions Due to Price Since 2014 Proven Unproven See the Investor Relations page at for important information about 3P reserves and other hydrocarbon quantities. Scotia Howard Weil 46 th Annual Energy Conference 10

11 Strategy at a Glance Short-Term Long-Term Value Directed Investments Enhancing Production Margin Expansion Through managing cost and increasing oil weighting of commodity mix Live within Cash Flow Value Focus Smart Growth (per share) Live within Cash Flow Targeting Balance Sheet Leverage 2x-3x (mid-cycle) Value Creation Index* VCI = PV10 pre-tax cash flows PV10 of investments *Please see end notes for further information on how we calculate VCI. Scotia Howard Weil 46 th Annual Energy Conference 11

12 History of Proactive Strategic Decisions Brent Crude Oil Price ($/Bbl)* CRC Drilling Rig Count Swift, decisive actions through the commodity downturn have positioned CRC for growth. Proactive discussions with lenders and solid asset base provide a path to recovery and an actionable inventory. $120 $100 1 Oil Price CRC Rig Count $80 $60 $40 $20 Under OXY SPIN-OFF $0 07/20/14 10/20/14 01/20/15 04/20/15 07/20/15 10/20/15 01/20/16 04/20/16 07/20/16 10/20/16 01/20/17 04/20/17 07/20/17 10/20/17 01/20/18 04/20/ Cut rig count/began hedging 4. Deleveraging Transactions 2. Cut 2015 Capital Budget 5. Increasing activity, invest within Cash Flow 3. Bank Amendments 6. JV Transactions Scotia Howard Weil 46 th Annual Energy Conference 12

13 Significant Reduction in Net Debt from Post-Spin Peak Total Net Debt ($ MM) Chose options to maximize deleveraging and minimize recurring cost to the income statement on a per share basis. Continue to seek opportunistic transactions that reduce overall debt. 7,000 6,000 5,000 6, ,000 4,502-3,000 2Q15 Debt Exchange for 2L Open Market Repurchases Equity for Debt Exchange Cash Tender for Unsecureds 2 Cash Flow Ares Transactions PF 4Q17 3 Total Total Net Debt Reduction $535 million $153 million $102 million $625 million $59 million $789 million $2,263 million 1 Represents mid-second quarter 2015 peak debt. 2 Includes operating cash flow, positive working capital and proceeds from asset sales in 1H 2017, net of restricted cash. 3 Pro Forma net debt at 4Q17 includes the payoff of the 12/31/2017 outstanding balance of $363 million on our RCF and $441 million of available cash after the completion of the Ares transactions. Scotia Howard Weil 46 th Annual Energy Conference 13

14 Strengthening the Balance Sheet - Improved Creditworthiness and Liquidity Availability ($MM) Pro Forma 1 Total Debt $4.9B Revolver Availability $850MM Available Cash 2 $441MM Pro-Forma 1 Debt Maturities ($MM)* Increased Liquidity $4,000 $1,400 $3,000 $1,200 $1,000 Cash $441 $2,000 $1,000 $ Term Loan 2nd Lien Notes 2016 Term Loan Unsecured Notes 2014 RCF $800 $600 $400 $200 $0 Cash $11 Revolver Availability $431 Revolver Availability $850 3Q17 PF 4Q17* 1 Pro forma debt reflects the payoff of the 12/31/17 outstanding balance of $363 million on our RCF after the completion of the Ares JV. 2 The $441 million of available cash includes (1) $15 million unrestricted cash as of 12/31/17 and (2) $426 million of available cash after the Ares transaction and pro forma repayment of the RCF. Scotia Howard Weil 46 th Annual Energy Conference 14

15 Development Joint Ventures: A Force Multiplier $550 Million Total Potential JV Capital Portfolio Flexibility and Optionality Kettleman North Dome $154 Million $260 MM Committed Enables High Margin Production Growth Lost Hills Kern Front Mt Poso ~ MBoe/d Gross Peak Production per $100 MM of development capital Accelerate Value -Legend- Elk Hills Buena Vista Pleito Ranch >12 MMBoe Potential Targeted Reserves per $100 MM of development capital Derisk Inventory CRC Oxy Land Oil Fields Gas Fields JVs are generally focused in the San Joaquin Basin JVs add production and cashflow, and help de-risk inventory to increase CRC s reserve base Scotia Howard Weil 46 th Annual Energy Conference 15

16 MBoe/d Capital ($MM) Resilient Resource Base ) Production By Stream (Mboe/d) Oil NGL Gas Total Capital* CRC Capital (Internally Funded) Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 FY 2015 *Total Capital reflected in the graph includes the capital investment of internal CRC capital as well as all JV partners which includes BSP and MIRA. Please note our consolidated financial statements include BSP s investment and exclude MIRA from CRC consolidated results based on the accounting treatment of each agreement. Total Capital FY 2016 FY 2017 $401MM $75MM $429MM MIRA: $58MM BSP: $96MM CRC (Internally Funded): $275MM Scotia Howard Weil 46 th Annual Energy Conference 16 0

17 2017 Investment Delivered Solid Returns VCI Moved from Defense to Offense 2017 Review CRC 2017 capital plan was directed to oil-weighted projects in our core fields: Elk Hills, Wilmington, Kern Front, Buena Vista, Mt. Poso, Pleito Ranch, Wheeler Ridge and the delineation of Kettleman North Dome JV capital was primarily focused in the San Joaquin Basin Exploration 2% 2017 Total Capital Invested Other1 1 6% Total: $429 million 3 Development Facilities 14% Drilling 24% Results of Fully-Burdened CRC Development Program 1.70 Total: ~$240 million 2.00 MIRA JV Capital 14% BSP JV Capital 22% Workover 18% ~30% IRR* ~45% IRR* $55 Brent Flat $3 NYMEX $55 Brent 2017, $65 Brent in & $3 NYMEX 1 Other includes maintenance and occupational health, safety and environmental projects, seismic and other investments. 2 Facility Costs and other non-return capital are apportioned to producing wells in the year they are drilled. 3 Includes capital funded by MIRA, which is not included in our consolidated results. *IRR estimate for the 2017 development program. For a description of how VCI is calculated please see the end notes. Scotia Howard Weil 46 th Annual Energy Conference 17

18 Oil Price $/BBL Investment Allocation through the Commodity Cycle Bull Market Invest to accelerate production growth and explore/pilot new resources Add facilities (steam and water handling) to support pace of growth Cash generation is high VCI 1.3 floor to reinvest for value Mid-Cycle Market Invest to grow cash flow Drill in high-graded portfolio (>1.5 VCI) Oil to gas ratio for steamfloods (>5:1). Selectively add steam generation EOR and IOR for long-term cash flow. Primary and shale for high IP impact Delineate future growth areas to unlock upside Bear Market Invest to protect base production Take advantage of existing facilities and prior capacity investments Steamfloods and waterfloods: drill to fill Workovers on existing wellbores is best investment Utilize excess equipment to reduce capital costs Engineering efforts focused on field surveillance to protect existing production Gas Price $/MCF Scotia Howard Weil 46 th Annual Energy Conference 18

19 2018 Capital Investment Program Living Within Cash Flow Production Enhancement Plans for 2018 CRC 2018 capital plan will be directed to oil-weighted projects in our core fields: Elk Hills, Wilmington, Kern Front, Huntington Beach, and continued delineation of Kettleman North Dome and Buena Vista JV capital will be focused in the San Joaquin Basin and Huntington Beach We have a dynamic plan that can be scaled up or down depending on the price environment and efficient deployment of joint venture proceeds The JV capital increases flexibility or provides for incremental deleveraging 2018E Total Capital Plan Approx. $425 to $450 million 2018E Drilling Capital By Drive Approx. $250 million 2018E Drilling Capital By Basin Approx. $250 million Exploration Other1 Unconventional Development Facilities Workover 12% 22% 4% 4% 30% 28% Drilling Steamfloods 6% 16% 30% 6% 42% Conventional San Joaquin 80% 10% 10% Ventura Los Angeles JV - Capital Waterfloods Exploration 1 Other includes maintenance and occupational health, safety and environmental projects, seismic and other investments. Scotia Howard Weil 46 th Annual Energy Conference 19

20 Development Capital ($B) Full Cycle Cost 2 ($/Boe) Deep Inventory of Actionable Projects at $65 Portfolio Spectrum Growth portfolio focus, fully burdened All projects meet a Value Creation Index (VCI) 1 threshold of 1.3 at $65 Brent and $3.00 NYMEX, and deliver robust cash flow Portfolio has large contributions from all recovery mechanisms and reserves types Many projects take advantage of existing infrastructure, while other newer projects may require infrastructure investment in facilities and sales points Steamflood Waterflood Primary Shale Gas Net Resources 3 (MMBoe) Net Resources 3 (MMBoe) 1 VCI is calculated by dividing the net present value of the project s expected pre-tax cash flow over its life by the net present value of the investments, each using a 10% discount rate. 2 Full cycle costs = operating costs + development costs + facility costs + field-level G&A + taxes other than on income. 3 See the Investor Relations page at for details regarding net resources. Scotia Howard Weil 46 th Annual Energy Conference 20

21 Strong Returns Through the Commodity Cycle Total LOF Actionable Near Term Growth 17,055 Total Net Producer Locations ~2,500 Total Near Term Growth Projects ~2,800 Additional Actionable Projects > 1.3 VCI Steamflood Waterflood Primary Shale Gas Focus on lower operating costs. Invest in steam floods above 5x Oil/Gas Ratio. Take advantage of dominant position in the basin. Invest in Sacramento Gas Projects. Oil Price Gas Price Oil Price Gas Price Oil Price Gas Price Oil Price Gas Price Oil Price Gas Price Optimum Investment Range Oil/Gas Price Ratio *Counts exclude prospective drilling and injector locations. Near term growth plan locations include inventory in the 5-year plan at $65 Brent CRC has a strong portfolio of actionable projects that can thrive in varying commodity price environments Scotia Howard Weil 46 th Annual Energy Conference 21

22 Midstream JV Provides Optionality to Create Maximum Value Invest in Resources Reduce Debt $750MM Mid-Stream Joint Venture Includes Elk Hills power plant, gas processing assets and related nonborrowing base infrastructure Scotia Howard Weil 46 th Annual Energy Conference 22

23 PROJECT VCI Example of Investment Alternatives for Asset Sale Proceeds PROJECT VS. SECOND LIEN (2L) NOTE REPURCHASE* INVEST If the VCI of an investment opportunity falls above the indifference curve, investing in the new project could be a better option Per the terms of the 2014 credit agreement on asset sales, 2L notes must be repurchased at a minimum 20% discount to par PURCHASE DEBT If the VCI of an investment opportunity falls below the indifference curve, repurchasing 2L notes could be a better option Indifference Curve 0.9 0% 10% 20% 30% 40% 50% DISCOUNT ON SECOND LIEN NOTES *CRC will continue to review all opportunistic debt reduction transactions. We utilize VCI to guide management in allocating capital and prioritizing investments. Please see end notes for how we calculate VCI. Scotia Howard Weil 46 th Annual Energy Conference 23

24 Portfolio Flexibility Provides Range of Crude Oil Scenarios Oil Production MB/d Capital ($MM) EBITDAX $MM Combined with mid-cycle commodity prices, we are positioned for growth in: Cash flow Production Estimated Crude Oil Production Outcomes E 2019E 2020E 2021E Portfolio Planning Scenarios Reserves on a debt-adjusted per share basis* Capital focused on oil projects that provide Increasing Margins Low Decline Rates + = Compounding Cash Flow 2,000 1,600 1, ,500 1, Estimated Range of EBITDAX Outcomes (Inclusive of Ares payment) E 2019E 2020E 2021E Estimated Ranges of Capital Investments E 2019E 2020E 2021E Note: Scenarios assume flat pricing from $55 to $75 Brent and $3.00 to $3.10 NYMEX gas, respectively. Assumes lease operating costs are equal to 2017 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 scenario. EBITDAX calculation for all estimated periods reflects a reduction from associated payments to Ares based on our JV agreement. Please note that beginning in 2018 these charges will be incorporated after our calculation for net income on our consolidated financial statement due to the accounting treatment of non-controlling interests. * See the Investor Relations page at for a description of the calculation of debt-adjusted per share and other important information. Portfolio Planning Scenarios Scotia Howard Weil 46 th Annual Energy Conference 24

25 Margin Expansion Driven by Liquid-Rich Resource Base % Oil Mix As we develop our reserves we anticipate the oil weight of production to trend from 64% produced in 2017 toward the 72% reflected in our 2017 Proved Reserves 75% The 2017 average blended realized price of $41 per BOE was 75% of the average Brent Crude index We have significant operating control of our properties which allows us to adjust our activity based on commodity price and market conditions 50% Oil NGL Gas Blended Realized Price* 25% 2017 Production Mix 64% 12% 24% $ Proved Reserves Mix *Includes effects of settled hedges 72% 9% 19% 0% FY 2015 FY 2016 FY Reserves Scotia Howard Weil 46 th Annual Energy Conference 25

26 ($Billion) 2017 Reserves Value 1 In Excess EV $20 $16 $12 Infrastructure 2 Surface & Minerals 3 $8 Unproved 4 $4 Proved Value Current EV of $5.1 Bn 5 PDP Value $0 $55 Brent $65 Brent $75 Brent 1-5 See endnotes in the Appendix. See the Investor Relations page at for important information about 3P reserves and other hydrocarbon quantities. Scotia Howard Weil 46 th Annual Energy Conference 26

27 Project Inventory Drives Organic Deleveraging Total Debt/LTM EBITDAX Estimated Leverage Ratios 10.0x 8.0x 6.0x 4.0x 2.0x 0.0x E 2019E 2020E 2021E $55 $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 are flat to 2017 levels for the mid-point case of the range of portfolio planning scenario outcomes. EBITDAX calculation for all estimated periods reflects a reduction from associated payments to Ares based on our JV agreement. Please note that beginning in 2018 these charges will be incorporated after our calculation for net income on our consolidated financial statement due to the accounting treatment of non-controlling interests. Scotia Howard Weil 46 th Annual Energy Conference 27

28 The Case for CRC: Investment Thesis Overview $MM Investment Case for CRC Competitive Advantages World-class assets with significant inventory Resilient model that preserves optionality and protects downside Focused on value and poised for growth Grow within cash flow Clear runway and available cash Industry leading decline rate Integrated and complementary infrastructure Why Own CRC Now Moved from defense to offense Disciplined portfolio management 2,500 Potential for EBITDAX growth* Maintain Production Production and Cash Flow Growth 2,000 1,500 1, E 2019E 2020E 2021E 2021E Production Innovation Deep Inventory *See Slide 24 for additional information regarding EBITDAX Growth planning scenarios. Scotia Howard Weil 46 th Annual Energy Conference 28

29 APPENDIX

30 Boe/d Boe/d Wilmington Field Production Sharing Contract Over 90% of CRC s Long Beach production is covered under Production Sharing Contracts (PSCs) with the State and the City of Long Beach 50,000 40,000 30,000 LBU PSC Base Incremental End of LBU Base CRC s net production decreases when prices rise and increases when prices decline Base rate/profit are defined in contracts State/City receive most of base profit CRC receives remainder Incremental rate/profit is everything greater than the Base Per the provisions of the contract, the Base of the LBU PSC ended in 4Q 2016 *Average profit split % 20,000 10,000-12,000 10,000 8,000 6,000 4,000 2,000 - Base Profit Split: 4% CRC / 96% State* Base Tidelands PSC Incremental First of 3 new PSC s executed Base Profit Split: 4% CRC / 96% State* Incremental Profit Split: 49% CRC / 51% State* Incremental Profit Split 49% CRC / 51% State & City* Scotia Howard Weil 46 th Annual Energy Conference 30

31 Wilmington PSC Illustration Mboepd $MM Total $ Brent Price Total $ Brent Price Gross Production Cost Recovery Barrels Variable with price NPI Barrel Revenue Variable with Price Net Profit Barrels 45% Share of Gross Production Cost Recovery Revenue Fixed revenue from cost recovery of the State & City of Long Beach share of costs $40 $45 $50 $55 $60 $65 $70 $75 $80 $85 $90 $95 $100 $Brent $40 $45 $50 $55 $60 $65 $70 $75 $80 $85 $90 $95 $100 $Brent CRC pays ~90% of gross costs (capital investments, OPEX, tax and overhead) up front and recovers our partners ~46% share (State/City of LB) of these costs in the form of offsetting Revenues Scotia Howard Weil 46 th Annual Energy Conference 31

32 CRC Price Realizations $/Bbl % of WTI & Brent $/Mcf Oil Price Realization (with Hedges) Gas Price Realization 70 Realization % of WTI WTI Realizations Brent $ $54.66 $56.92 $51.91 $50.92 $54.82 $53.64 $48.29 $52.18 $55.40 $ $45.04 $50.95 $50.02 $50.24 $47.98 $48.21 $49.19 $48.80 $ $ Q Q Q Q % 99% 104% 103% 101% 99% 101% Realization % of NYMEX NYMEX Realizations $3.26 $3.14 $2.95 $3.00 $3.09 $2.75 $2.42 $2.90 $2.56 $2.77 $2.66 $2.47 $2.28 $2.67 1Q Q Q Q % 79% 87% 92% 97% 94% 86% NGL Price Realization - % of WTI & Brent 100% WTI Brent 79% 72% 80% 66% 62% 70% 72% 60% 52% 65% 63% 66% 59% 40% 40% 50% 37% 20% 0% 1Q Q Q Q California refinery demand for native crude continues to be strong and reduction in heavy waterborne crude has positively influenced differentials. NGL prices have been supported by lower inventories and export markets. CRC believes near-term differentials will remain strong Scotia Howard Weil 46 th Annual Energy Conference 32

33 Debt Hierarchy Updated Capital Structure from Recent Transactions Improved Liquidity ($MM) Availability ($MM) 2014 Revolving Credit Facility Capacity - $1 billion $1,000 $750 Reduced Revolver Borrowing Added in November 2017 Term Loan - $1.3 billion 2016 Term Loan - $1 billion 2015 Second Lien - $2.25 billion Unsecured Notes - $0.393 billion $500 $250 $0 $1,400 $1,200 $1,000 $800 Drawn Revolver $837 3Q17 PF 4Q17* Increased Liquidity** Undrawn Revolver Cash $441 * Pro Forma for the Ares JV and $50mm private placement ** Subject to minimum liquidity requirement under 2014 Revolving Credit Facility. Includes unrestricted cash. $600 $400 $200 $0 Cash $11 Revolver Availability $431 Revolver Availability $850 3Q17 PF 4Q17* Scotia Howard Weil 46 th Annual Energy Conference 33

34 Strengthening the Balance Sheet - Improved Creditworthiness and Liquidity Sep-17 Dec-17 Mar-18 Jun-18 Sep-18 Dec-18 Mar-19 Jun-19 Sep-19 Dec-19 Mar-20 Jun-20 Sep-20 Dec-20 Mar-21 Jun-21 Sep-21 Dec-21 Mar-22 Jun-22 Sep-22 Dec-22 Mar-23 Jun-23 Sep-23 Dec-23 Mar-24 Jun-24 Sep-24 Dec-24 Pro-Forma 1 Capitalization ($MM) 1st Lien 2014 Revolving Credit Facility (RCF) - 1st Lien 2017 Term Loan 1,300 1st Lien 2016 Term Loan 1,000 2nd Lien Notes 2,250 Senior Unsecured Notes 393 Total Debt 4,943 Less cash 2 (441) Total Net Debt 4,502 Equity 3 (764) Total Net Capitalization 3,738 Total Net Debt / Total Net Capitalization 120% Total Net Debt / LTM Adjusted EBITDAX 4 5.9x LTM Adjusted EBITDAX 4 / LTM Interest Expense 2.2x PV-10 5 / Total Net Debt 1.0x Total Net Debt / Proved Reserves ($/Boe) $7.28 Total Net Debt / Proved Developed Reserves ($/Boe) $10.23 Total Net Debt / 2017 Production ($/Boepd) $34,899 1 Pro-forma capitalization table and debt maturities graph reflect the payoff of the 12/31/17 outstanding balance of $363 million on our RCF after the completion of the Ares JV and $50 million private placement. 2 The $441 million of available cash includes (1) $15 million unrestricted cash as of 12/31/17 and (2) $426 million of available cash after the Ares transaction and proforma repayment of the RCF. 3 Excludes noncontrolling interest at 12/31/17 and includes $50 million of equity from the Ares private placement. 4 See Investor Relations for a reconciliation to the closest GAAP measure and other important information. 5 PV-10 as of 12/31/17, see Attachment 2 of CRC s Fourth Quarter Earnings Release dated February 26, 2018 for details on this calculation. Pro forma net results from the Ares transactions which closed on February 7, 2018: $4,000 $3,500 $3,000 $2,500 $2,000 $1,500 $1,000 $500 $0 CRC received $797 million in net proceeds, $8mm of which is restricted cash The RCF was paid in full The RCF has approximately $850 million of available borrowing capacity, excluding $150 million minimum liquidity The recent amendment extends the maturity of the RCF to June 2021 and relaxes financial covenants 2014 RCF 2017 Term Loan 2016 Term Loan 2nd Lien Notes Unsecured Notes Pro-Forma 1 Debt Maturities ($MM)* Undrawn RCF $100 $1,000 $100 $0 $1,300 $2,250 $193 * Previously, the RCF, the 2017 Term Loan and the 2016 Term Loan were subject to springing maturities related to the 2020 and 2021 Notes. During the fourth quarter of 2017, CRC repurchased $65 million in principal amount of the 2020 Notes and $35 million in principal amount of the 2021 Notes, which eliminated those springing maturities. The 2017 Term Loan remains subject to a springing maturity related to the 2016 Term Loan. Scotia Howard Weil 46 th Annual Energy Conference 34

35 Opportunistically Built Oil Hedge Portfolio Strategy Protect cash flow for capital investments and covenant compliance 1Q Q Q Q Q 2019 Sold Calls Barrels per Day 9,000 6,200 16,100 16,100 1,100 Weighted Average Ceiling Price per Barrel $59.58 $60.24 $58.91 $58.91 $60.00 Purchased Calls Barrels per Day ,000 Weighted Average Ceiling Price per Barrel $71.00 Purchased Puts Barrels per Day 1,200 1,200 6,100 1,100 14,100 Weighted Average Floor Price per Barrel $45.82 $45.83 $61.48 $45.85 $58.93 Sold Puts Barrels per Day 29,000 29,000 24,000 19,000 10,000 Weighted Average Floor Price per Barrel $45.00 $45.00 $46.04 $45.00 $47.50 Swaps Barrels per Day 38,300 34,000 19,000 19,000 7,000 Weighted Average Price per Barrel Percentage of 4Q 2017 Oil Production Hedged* Certain of our counterparties have options to increase swap volumes at weighted average costs between $60 and $70 Brent. For potential volume changes and further details please see Attachment 10 of our Earnings Release. * As of 2/26/2018. Assumes counterparty options are not exercised. $60.03 $60.00 $60.13 $60.13 $ % 44% 31% 25% 26% We target hedges on 50% of crude oil production Scotia Howard Weil 46 th Annual Energy Conference 35

36 Elk Hills Area CRC s Flagship Asset Net MBOE/d Rig Count Overview CRC s flagship, a 100 year-old field with exploration opportunities Field Map Light oil from conventional and unconventional production Largest gas and NGL producing field in California, one of the largest fields in the continental U.S. 1, >3,000 producing wells 11 billion OOIP (BOE) and cumulative production of over 2.7 billion BOE 2017 average net production of 53 MBOE/d (~40% of total CRC production) Integrated Infrastructure 610 MMcf/d processing capacity through 4 gas plants Including California s largest 3 CO 2 removal plants Over 4,500 miles of gathering lines 45 MW cogeneration plant 550 MW power plant Production History Net MBOEPD Rig Count Large fee property position with integrated infrastructure 1 DOGGR data and U.S. Energy Information Administration Scotia Howard Weil 46 th Annual Energy Conference 36

37 Buena Vista Area Highly Prospective Area Drilling Cost $MM/well Drilling Cost $/Ft Drilling Time Days/well Overview Includes Buena Vista (BV) Hills and BV Nose JV capital applied to infill development program that led to improved operational efficiencies Organic capital deployed to expand the extent of the play BV Nose was discovered in 2012 as a step-out to BV Hills 10,000 average True Vertical Depth 32 API, 600 GOR Reduced capital costs with a new well design (two strings) LDMAP Conventional BV Nose Development Drilling Cost Average Drilling Days/Well BV Area development program delivers a 1.8 VCI at a $55 Brent price deck Drilling Cost/Well Drilling Cost $/Ft Growth potential near existing infrastructure Scotia Howard Weil 46 th Annual Energy Conference 37

38 Production (BOPD) Accelerating Production Decline in U.S. Onshore Lower 48 Development Wells 7,000,000 40% Normalized Decline Rates 6,000,000 30% 20% 5,000,000 10% 4,000,000 0% 3,000,000-10% 2,000,000-20% -30% 1,000,000-40% Pre Wells 2011 Wells 2012 Wells 2013 Wells 2014 Wells 2015 Wells -50% Year 1 Year 2 Year 3 Year 4 Year Wells 2011 Wells 2012 Wells 2013 Wells 2014 Wells 2015 Wells Recent wells in the onshore Lower 48 are showing steeper declines Source: Data from Wood Mackenzie, CRC analysis Scotia Howard Weil 46 th Annual Energy Conference 38

39 Best In Class Corporate Decline Rates 50% 1 Year Decline 80% 3 Year Decline 70% 40% 60% 30% Median: 29% 50% Median: 49% 40% 20% 30% 20% CRC 10% CRC 10% 0% 0% FY 2016 Production Percentage Liquids Less than 55% 55% - 75% Greater than 75% Peers included: CLR, COG, CPE, CXO, DNR, EGN, EOG, EPE, FANG, HK, LPI, MRO, MTDR, MUR, NFX, OAS, PDCE, PE, PXD, QEP,RRC, RSPP, SM, SN, WLL,WPX, and XEC. Source: Wood Mackenzie - Operated Production Data through 2016, CRC analysis. Scotia Howard Weil 46 th Annual Energy Conference 39

40 Core Principle of Living within Cash Flow Unlevered Free Cash Flow ($MM) CRC 1, Unlevered Free Cash Flow (500) Average: $(341.5)MM (1,000) (1,500) (2,000) (2,500) (3,000) Peers included: APA, APC, AR, BBG, CHK, CLR, COG, CPE, CRK, CRZO, CXO, DNR, DVN, ECR, EGN, EOG, EPE, EQT, FANG, GPOR, GST, HK, JONE, LPI, MRO, MTDR, MUR, NBL, NFX, OAS, PDCE, PE, PXD, QEP, REI, RICE, RRC, RSPP, SD, SGY, SM, SN, SWN, UNT, UPL, VNR, WLL, WPX, and XEC. Source: FactSet. Scotia Howard Weil 46 th Annual Energy Conference 40

41 Accelerating Value and Derisking Inventory through JVs Highlights: Up to $250MM over ~2 years Two tranches of $50MM Total of $100MM funded Investor funds 100% of project capital in exchange for a net profits interest (NPI) Investor NPI interest reverts to CRC after low teens target IRR CRC retains early termination options Current focus is in the San Joaquin Basin CRC operates all wells Highlights: Up to $300MM Initial commitment of $160MM DrillCo type structure where Investor funds 100% of project capital for 90% WI, with CRC carried on its 10% WI CRC interest reverts to 75% after target IRR is achieved CRC retains early termination options Focus on four fields within the San Joaquin Basin Kern Front, Mt. Poso, Pleito Ranch, Wheeler Ridge CRC operates all wells Scotia Howard Weil 46 th Annual Energy Conference 41

42 Typical Industry JV Structure Production Based on recent industry JV deals, a typical deal structure is o Partner pays % Capital o Receives % Working Interest o Typical hurdle rate: o 10% - 20% IRR o Partner s working interest once hurdle rate is achieved: o 5% - 25% 7, , , , , Hurdle Rate Reached 2, , Time JV Share Typical E&P 64 Share Scotia Howard Weil 46 th Annual Energy Conference 42

43 Strategic Partner Alignment Partner Affiliate of Ares Management (Ares) Summary of Deal Contributed Assets Elk Hills power plant, gas processing assets and related non-borrowing base infrastructure currently owned by CRC Midstream JV Capitalization Distribution to Partners Exit Provisions Class A common interests (voting) owned 50% by Ares and 50% by California Resources Elk Hills (CREH) Class B preferred interests ( Preferred ) owned 100% by Ares Class C common interests (distributing) owned 95.25% by CREH and 4.75% by Ares Preferred interests to receive distributions of 13.5% per annum on the $750 MM contributed amount 9.5% cash pay and 4.0% PIK to be deferred for the first three years Deferred distributions are interest bearing and repaid over two years following the deferral period Remaining cash after preferred distributions to be distributed pro rata to Class C interests Prior to end of 5 or 7.5 years, CRC may redeem Preferred at variable amounts that include make whole premiums At end of 5 years, CRC may elect to either redeem or extend to 7.5 years At 7.5 years, if not redeemed by CRC, Preferred can monetize the JV Board Board of Managers to consist of three CRC representatives and three representatives from Ares Scotia Howard Weil 46 th Annual Energy Conference 43

44 CRC Midstream JV Structure with Ares Benefits Strategic alignment with Ares Provides CRC paths for opportunistic deleveraging through cash flow growth or debt reduction Greatly enhances liquidity California Resources Elk Hills, LLC Retain ownership and operational control Defined exit criteria Power and Gas Processing Services Contributed Assets $750 MM gross proceeds Class A (50%) and Class C (95.25%) Common Interests Commercial Agreement Capacity Charges Elk Hills Power, LLC $750 MM gross proceeds Ares Management, L.P. Class B Preferred Interests, Class A and Class C Common Interests Scotia Howard Weil 46 th Annual Energy Conference 44

45 BOEPD BOEPD BOEPD Portfolio Mix Dynamic Portfolio Provides Flexibility Higher Oil to Gas Price Ratio Lower Oil to Gas Price Ratio 100% Gas 75% Unconventional 50% 25% 0% Primary Waterflood Steamflood Workover Gas Oil YEAR Gas Oil YEAR Gas Oil YEAR 5 EUR (MBOE per $10MM) 1,385 1,265 1,060 % Oil 81% 70% 53% Development Cost/BOE $7.20 $7.90 $9.40 Recycle Ratio 3.4x 2.9x 2.2x For illustration of portfolio optionality based on normalized results per $10MM of investment and not guidance. See endnote for details on type curves. Prices for recycle ratio are $65 Brent and $3.50 NYMEX. Scotia Howard Weil 46 th Annual Energy Conference 45

46 Greenfield Steamflood Type Pattern PARAMETERS PER PATTERN BOPD $ BRENT 100 Kern Front Actuals Composite Type Curve N. Antelope Lost Hills Hills McDonald Anticline McKittrick Midway Sunset Kern Front $NYMEX VCI $3.5 $3 $2.5 $ Oxnard $ CRC OPERATED FIELDS CRC STEAMFLOODS $ YEAR Operating Expense/bbl $10-20 Capital Cost * $2.8MM Total EUR (MBO) 270 Peak Rate (BOPD) 90 D&C (days) 15 Royalty 10% 300 Near Term Growth Plan Pattern Locations * Information is for a steamflood pattern assuming 3 producers per 1 injector and is fully burdened with new steam generator infrastructure costs of $900K per pattern. At low prices, new steam generation infrastructure is not added to the project. See endnotes for important information about our type curves. Scotia Howard Weil 46 th Annual Energy Conference 46

47 Waterflood New Pattern Composite Type Well PARAMETERS PER PATTERN BOEPD $ BRENT 60 Kettleman 45 Mount Poso Actuals Buena Vista Actuals Elk Hills Buena Vista Paloma Mount Poso 30 VCI EUR Composite Type Curve Rincon Saticoy South Mountain $ $ CRC OPERATED FIELDS CRC NEW & POTENTIAL WATERFLOODS $ YEAR Operating Expense Capital Cost* Total EUR (MBOE) Peak Rate (BOEPD) Drilling Time (days) Royalty $19/BOE $1.2MM % 350 Near Term Growth Plan Locations * Capital cost is fully burdened with facilities, injectors and tie-ins. Assumes 5-spot pattern with a 1:1 producer to injector ratio. See endnote for important information about our type curves. Scotia Howard Weil 46 th Annual Energy Conference 47

48 Waterflood Redevelopment Type Well BOEPD PARAMETERS $ BRENT Huntington Beach Actuals Elk Hills 80 East Wilmington Actuals Composite Type well VCI EUR 190 West Wilmington Actuals San Miguelito $ YEAR Elk Hills Actuals CRC OPERATED FIELDS CRC REDEVELOPMENT WATERFLOODS Wilmington Huntington Beach $ $ Operating Expense $19/BOE Capital Cost* $1.8MM Total EUR (MBOE) 165 Peak Rate (BOEPD) 120 Drilling Time (days) 14 Royalty PSC** 350 Near Term Growth Plan Locations * Capital cost is fully burdened with facilities, injectors and tie-ins. ** A majority of locations are subject to PSCs, which have a 49% NPI. For NPV calculation, this can be modeled as 49% WI/NRI. For Production Rate, Net/Gross ratio is typically 75% when including cost recovery barrels. See endnote for important information about our type curves. Scotia Howard Weil 46 th Annual Energy Conference 48

49 Primary Type Well Deeper Horizons PARAMETERS BOEPD $ BRENT 900 Kettleman BV Nose Actuals Bardsdale Actuals Elk Hills BV Nose Yowlumne Paloma Rio Viejo Pleito Ranch Wheeler Ridge VCI EUR Pleito Ranch Actuals Composite Type well Saticoy Bardsdale $ Montalvo South Mountain $ Wheeler Ridge Actuals 0YEAR CRC OPERATED FIELDS CRC PRIMARY $ Operating Expense $10/BOE Capital Cost* $5.0MM Total EUR (MBOE) 430 Peak Rate (BOEPD) 360 Drilling Time (days) 30 Royalty 12% 150 Near Term Growth Plan Locations * Capital cost includes drilling, completion, and tie-ins. Does not include 450 shallow (<5,000 ft) locations with costs under $1.5 MM/well and with similar economics. See endnote for important information about our type curves. Scotia Howard Weil 46 th Annual Energy Conference 49

50 California Shale Type Well BOEPD $ BRENT 500 Kettleman 400 Elk Hills ( ) Elk Hills Railroad Gap Rose N. Shafter 300 New Pool Type Curve Asphalto Buena Vista Gunslinger 200 Gunslinger Actuals Rose/N. Shafter Actuals VCI Infill New Pool $ Elk Hills Actuals Infill Shale Curve CRC OPERATED FIELDS CRC SHALE $ YEAR $ Operating Expense Capital Cost* Total EUR (MBOE) Peak Rate (BOEPD) Drilling Time (days) Average Royalty New Pool Infill $10/BOE $8/BOE $5.0MM $2.5MM % 13% 50 Near Term Growth Plan Locations (Split Evenly) *Capital cost includes drilling, completion and tie-ins. See endnote for important information about our type curves. Scotia Howard Weil 46 th Annual Energy Conference 50

51 A Net Water Supplier 4% 2% WATER MANAGED IN CRC s OPERATIONS Produced Water CRC set a new company record for water deliveries to agriculture in 2017, an 85% increase since 2015, preserving farmland and jobs. Fresh Water Non-Fresh Water CRC s operations in Long Beach use recycled or non-fresh water for 99.5% of their total water use. 94% In 2017, CRC supplied 4.9 billion gallons over 15,000 acre-feet of treated, reclaimed water for irrigation or recharge. For every gallon of fresh water CRC purchased in 2017, we delivered nearly 3 gallons of treated water to agriculture Recycled or reclaimed over 89% of our produced water in 2017, almost a 10% increase since 2015 Reduced our produced water disposal by over 40% since 2015 Reduced our potable water use by nearly 30% since 2015 Scotia Howard Weil 46 th Annual Energy Conference 51

52 End Notes 1 Current CRC estimate of reserves value as of December 31, Includes field-level operating expenses and G&A. Assumes $3.00/MMBTU NYMEX. 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. Excludes the value of the assets monetized in the Ares transaction. 3 Surface & Minerals reflect the estimated value of undeveloped surface and minerals held in fee. 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 Pro Forma debt post Ares transaction and market cap as of March 16, Type Curve Note: Each field-specific type well curve represents an average of the historical results of multiple projects over the prior four-year time period. Drive mechanism type curves are the weighted average of the field-specific curves related to the projects chosen for our near-term growth plan. Type curves represent management s estimates of future results and are subject to project selection and other variables. Our type well curves are prepared for purposes of modeling overall results of our near-term growth program and are not useful for purpose of benchmarking any individual well or pattern performance. Actual results are expected to vary depending on which projects are specifically developed. Value Creation Index (VCI) Note: VCI is calculated by dividing the net present value of the project s expected pre-tax cash flow over its life by the net present value of project investments, each using a 10% discount rate Scotia Howard Weil 46 th Annual Energy Conference 52