CRC Corporate Presentation April 2018 Forward Looking / Cautionary - - PowerPoint PPT Presentation

CRC Corporate Presentation

April 2018

CRC Corporate Presentation – April 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: Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. While we believe assumptions or bases underlying our expectations are reasonable and make them in good faith, they almost always vary from actual results, sometimes materially. We also believe third- party statements we cite are accurate but have not independently verified them and do not warrant their accuracy or completeness. Factors (but not necessarily all the factors) that could cause results to differ include: Words such as "anticipate," "believe," "continue," "could," "estimate," "expect," "goal," "intend," "likely," "may," "might," "plan," "potential," "project," "seek," "should," "target, "will" or "would" and similar words that reflect the prospective nature of events or outcomes typically identify forward-looking statements. Any forward-looking statement speaks only as of the date on which such statement is made and we undertake no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. See the Investor Relations page at www.crc.com for important information about 3P reserves and other hydrocarbon resource quantities, finding and development costs, recycle ratio calculations, and drilling locations.

• financial position, liquidity, cash flows and results of operations
• business prospects
• transactions and projects
• perating costs
• Value Creation Index (VCI) metrics are based on certain estimates

including future production rates, costs and commodity prices

• perations and operational results including production, hedging and capital

investment

• budgets and maintenance capital requirements
• reserves
• type curves
• 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

• ther emissions, protection of health, safety and the environment, or

transportation, marketing and sale of our products

• unexpected geologic conditions
• changes in business strategy
• inability to replace reserves
• insufficient capital, including as a result of lender restrictions, unavailability
• f 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.

CRC Corporate Presentation – April 2018 | 3

Value Proposition – Multiple Ways to Increase Valuation

Disciplined Portfolio Management EBITDAX Growth* Regaining Momentum Through Increased Investment

• Increasing CRC

Investments and Deploying Rigs

• Joint Ventures
• Opportunistic Deleveraging
• Significant Operating

Leverage to Crude Oil

*See Slide 24 for additional information regarding EBITDAX Growth planning scenarios.

400+

500 1,000 1,500 2,000 2,500 2017 2018E 2019E 2020E 2021E $MM

2017 2018E 2019E 2020E 2021E

CRC Corporate Presentation – April 2018 | 4

CRC’s Large Resource Base with Advantaged Infrastructure

Sacram amento ento Basin in 14 MMBOE Proved Reserves 6 MBOE/d production (100% dry gas) San Joaquin uin Basin in 419 MMBOE Proved Reserves 90 MBOE/d production (58% oil) Ventur ura a Basin in 40 MMBOE Proved Reserves 6 MBOE/d production (67% oil)

World rld-Cl Class ss Resou

• urce

ce 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

Positioned itioned to Gro row

• 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
• ptimize growth through commodity price cycles
• Increasing crude oil mix improves margins
• Deep inventory of high-return projects

Reserves as of 12/31/17; Production figures reflect average FY 2017 rates.

Los Angel eles Basin in 145 MMBOE Proved Reserves 27 MBOE/d production (100% oil)

CRC Corporate Presentation – April 2018 | 5

Largest California Producer with Deep Regional Insight

163 142 122 30 21

• 50

100 150 200

CRC Chevron USA Aera Energy Sentinel Peak Berry Gross Operated MBoe/d

*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 2016. Source: Wood Mackenzie, Company Estimates.

Largest 3-D Seismic Position in California

$19 $21 $24 $29 $29

$0 $5 $10 $15 $20 $25 $30 $35 0% 25% 50% 75% 100% CRC Chevron USA Aera Energy Sentinel Peak Berry

OPEX $/Boe** Production Mix

Shallow Deeper (>5,000') FY OPEX $/BOE**

MONTEREY SANDS AND SHALES TEMBLOR SANDS EOCENE SANDS AND SHALES UPPER CRETACEOUS SANDS AND SHALES 1,000’ PAY TULARE SANDS SHALLOW DEEP ETCHEGOIN SANDS <5,000’ 15,000’

Top California Producers in 2017* Majority of CA Production is Shallow*

CRC Corporate Presentation – April 2018 | 6

San Joaquin Basin – An American Super Basin

Ove Overvie view

• 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 y Asse sets

• 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 in Map

2 4 6 100 200 300 2015 2016 2017

• Avg. Rig Count

Gross Wells Drilled

Steamflood Waterflood Primary Unconventional

• Avg. Rig Count

Legend CRC Land Oil Field Gas Field CRC Operated

CRC Corporate Presentation – April 2018 | 7

Los Angeles Basin – Kitchen is the Entire Basin

Ove Overvie view

• 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

• 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.

Wilmington Huntington Beach

Basin in Map

*Organic reserves replacement excludes the effect of price change on reserves volumes

1 2 25 50 2015 2016 2017

• Avg. Rig Count

Gross Wells Drilled

Waterflood

• Avg. Rig Count

Performed 26 Capital Workover projects in 2017

Legend CRC Land Oil Field Gas Field CRC Operated

CRC Corporate Presentation – April 2018 | 8

Ventura Basin – Birthplace of the California Oil Industry

Over Overvie view

• Prolific basin with a long history, including the first commercial oil well

in California

• ~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
• 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

High Growth Area: large OOIP, low recovery factor and potential for high-IP wells

Fie ield ld Map

OOIP (MMBO) CUM PROD (MMBO) RF 7,843 813 10%

Legend

Active CRC Field Idle CRC Field

CRC Corporate Presentation – April 2018 | 9

Sacramento Basin – Significant Gas Optionality

Ove Overvie view

• 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 less than 6,000 feet deep, 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

California imports >90% of its natural gas requirements

Basin in Map

20 Miles

Legend CRC Land Oil Field Gas Field CRC Operated

CRC Corporate Presentation – April 2018 | 10

Value Additive Inventory Growth

• Comprehensive technical review of 40% of CRC’s

fields.

• 2017 proved reserves of 618 million BOE and 450

million BOE of probable reserves.

• 119% organic reserve replacement, excluding the

effect of price adjustments.

• 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.

• 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.

3P Rese serves s Gro rowth th Sinc nce Spin in

58 109 156 768 644 568 618 222 251 202 321 340 826 1,129 250 500 750 1,000 1,250 1,500 1,750 2,000 2,250 Spin-off 2015 2016 2017

MMBoe

Cummulative Production Proven Revisions Due to Price Since 2014 Unproven

>350% Growth

See the Investor Relations page at www.crc.com for important information about 3P reserves and other hydrocarbon quantities.

CRC Corporate Presentation – April 2018 | 11

Strategy at a Glance

Value Directed Investments Targeting Balance Sheet Leverage 2x-3x (mid-cycle)

Value ue Focus cus

Live within Cash Flow Smart Growth (per share)

PV10 pre-tax cash flows PV10 of investments VCI =

En Enhancin ancing Produc ducti tion

• n

Margin n Ex Expansi sion

• n

Through managing cost and increasing

• il weighting of commodity mix

Live e within hin Cash h Flow Long-Term rm Short-Term erm

*Please see end notes for further information on how we calculate VCI.

Value e Creati tion n Index* x*

CRC Corporate Presentation – April 2018 | 12

History of Proactive Strategic Decisions

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.

5 10 15 20 25 30

$0 $20 $40 $60 $80 $100 $120

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 04/20/18

CRC Drilling Rig Count Brent Crude Oil Price ($/Bbl)*

Oil Price CRC Rig Count

• 1. 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

2 1 5 3

Under OXY

6

SPIN-OFF

3 3 3 3 3 4 4 4 4 6 6 3

CRC Corporate Presentation – April 2018 | 13

Significant Reduction in Net Debt from Post-Spin Peak

6,7651 4,502 3,000 4,000 5,000 6,000 7,000

2Q15 Debt Exchange for 2L Open Market Repurchases Equity for Debt Exchange Cash Tender for Unsecureds Cash Flow Ares Transactions PF 4Q17

Total Net Debt ($ MM)

2

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.

• 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.

3

CRC Corporate Presentation – April 2018 | 14

Strengthening the Balance Sheet - Improved Creditworthiness and Liquidity

Pro ro-Forma ma1 Debt t Matur uriti ties es ($MM)* )*

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.

$0 $1,000 $2,000 $3,000 $4,000 2018 2019 2020 2021 2022 2023 2024

2017 Term Loan 2nd Lien Notes 2016 Term Loan Unsecured Notes 2014 RCF

Revolver Availability $431 Revolver Availability $850 Cash $11 Cash $441

$0 $200 $400 $600 $800 $1,000 $1,200 $1,400 3Q17 PF 4Q17* Availability ($MM)

Increased eased Liqui uidity dity

Pro Forma1 Total Debt

$4.9B

Revolver Availability

$850MM

Available Cash2

$441MM

CRC Corporate Presentation – April 2018 | 15

Development Joint Ventures: A Force Multiplier

$154 Million

$260 MM Committed

~3.5-4.0 MBoe/d

Gross Peak Production per $100 MM of development capital

>12 MMBoe

Potential Targeted Reserves per $100 MM of development capital

JVs are generally focused in the San Joaquin Basin

$550 Million

Total Potential JV Capital

Kern Front

• Legend-

Oxy Land Oil Fields Gas Fields

Buena Vista Pleito Ranch Elk Hills Kettleman North Dome Lost Hills Mt Poso

CRC Land

Portfolio Flexibility and Optionality Enables High Margin Production Growth Accelerate Value Derisk Inventory

JVs add production and cashflow, and help de-risk inventory to increase CRC’s reserve base

CRC Corporate Presentation – April 2018 | 16

Resilient Resource Base

25 50 75 100 125 150 175 200 20 40 60 80 100 120 140 160 180 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 FY 2015 FY 2016 FY 2017 Capita ital l ($MM) MBoe/d

)

Oil NGL Gas Total Capital* CRC Capital (Internally Funded)

Producti roduction

• n By St

Strea eam m (Mboe/d) boe/d)

MIRA: $58MM BSP: $96MM CRC (Internally Funded): $275MM Total Capital $401MM $75MM $429MM *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.

CRC Corporate Presentation – April 2018 | 17 Drilling 24% Workover 18% BSP JV Capital 22% MIRA JV Capital 14% Exploration 2% Other1 6% Development Facilities 14%

Moved ed from rom Defe fense se to Of Offen ense se – 2017 7 Revie view

• 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

2017 Investment Delivered Solid Returns

Total: $429 million3

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.

2017 Total

• tal Capita

tal In Inve vest sted ed

1.70 2.00

0.00 0.50 1.00 1.50 2.00 2.50 $55 Brent Flat $3 NYMEX $55 Brent 2017, $65 Brent in 2018+ & $3 NYMEX

VCI Results lts of Full lly-Burde urdened ed2 2017 CRC Deve velopm lopment ent Pro rogr gram am

Total: ~$240 million

Other1

~30% IRR* ~45% IRR*

*IRR estimate for the 2017 development program. For a description of how VCI is calculated please see the end notes.

CRC Corporate Presentation – April 2018 | 18

Investment Allocation through the Commodity Cycle

Oil Price $/BBL Gas Price $/MCF

• 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
• 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

Bull Market Mid-Cycle Market Bear 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

CRC Corporate Presentation – April 2018 | 19 Drilling JV - Capital Workover Development Facilities Exploration Other1 Other1 San Joaquin Ventura Los Angeles

Producti roduction

• n Enh

nhancemen ancement Plans ns 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

2018 Capital Investment Program – Living Within Cash Flow

• Approx. $425 to $450 million

1Other includes maintenance and occupational health, safety and

environmental projects, seismic and other investments.

2018E E Total al Capital tal Pla lan 2018E E Drillin illing g Capita tal l – By Driv ive

28% 30% 22% 12% 4% 4%4% 4% 10% 10%

Conventional Exploration Waterfloods Steamfloods Unconventional

42% 6% 6% 30% 16% 80%

The JV capital increases flexibility or provides for incremental deleveraging

• Approx. $250 million
• Approx. $250 million

6% 6%

2018E Dril illing ing Capita tal l – By Basin in

CRC Corporate Presentation – April 2018 | 20

Deep Inventory of Actionable Projects at $65

Portfolio Spectrum

• Growth portfolio focus, fully

ly burde dened ned

• 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

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 www.crc.com for details regarding net resources.

2 4 6 8 10 100 200 300 400 500 600 700 800 Development Capital ($B) Net Resources3 (MMBoe) 5 10 15 20 25 30 35 40 45 50 100 200 300 400 500 600 700 800 Full Cycle Cost2 ($/Boe) Net Resources3 (MMBoe)

Steamflood Waterflood Primary Shale Gas

CRC Corporate Presentation – April 2018 | 21

Strong Returns Through the Commodity Cycle

Gas

Take advantage of dominant position in the basin. Invest in Sacramento Gas Projects.

Primary Shale

*Counts exclude prospective drilling and injector locations. Near term growth plan locations include inventory in the 5-year plan at $65 Brent

17,055 Total Net Producer Locations ~2,500 Total Near Term Growth Projects ~2,800 Additional Actionable Projects > 1.3 VCI

Total LOF Actionable Near Term Growth

Focus on lower operating costs. Invest in steam floods above 5x Oil/Gas Ratio.

Steamflood Waterflood

Gas Price Oil Price Gas Price Oil Price Gas Price Oil Price Gas Price Oil Price

Oil/Gas Price Ratio Optimum Investment Range

CRC has a strong portfolio of actionable projects that can thrive in varying commodity price environments

Gas Price Oil Price

CRC Corporate Presentation – April 2018 | 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 non-

borrowing base infrastructure

CRC Corporate Presentation – April 2018 | 23

0.9 1.0 1.1 1.2 1.3 1.4 1.5 1.6 1.7 0% 10% 20% 30% 40% 50%

PROJECT VCI DISCOUNT ON SECOND LIEN NOTES

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

PURCHASE DEBT

If the VCI of an investment opportunity falls below the indifference curve, repurchasing 2L notes could be a better option

Example of Investment Alternatives for Asset Sale Proceeds

Per the terms of the 2014 credit agreement on asset sales, 2L notes must be repurchased at a minimum 20% discount to par Indifference Curve *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.

CRC Corporate Presentation – April 2018 | 24 70 80 90 100 110 120 130 140

2017 2018E 2019E 2020E 2021E

Oil Production MB/d

400 800 1,200 1,600 2,000 2017 2018E 2019E 2020E 2021E EBITDAX $MM

Portfolio Flexibility Provides Range of Crude Oil Scenarios

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 www.crc.com for a description of the calculation of debt-adjusted per share and other important information.

Combined with mid-cycle commodity prices, we are positioned for growth in:

• Cash flow
• Production
• Reserves
• n a debt-adjusted per share basis*

Portfolio Planning Scenarios Portfolio Planning Scenarios

Capital focused on oil projects that provide Increa easi sing Margin ins Low w Decline line Rates es Compoun

• undin

ding Cash Flow

+ =

• Estimated Crude Oil Production Outcomes

≈

300 600 900 1,200 1,500 2017 2018E 2019E 2020E 2021E

Capital ($MM)

Estimated Ranges of Capital Investments Estimated Range of EBITDAX Outcomes (Inclusive of Ares payment)

• ≈

CRC Corporate Presentation – April 2018 | 25

Margin Expansion Driven by Liquid-Rich Resource Base

• 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

• 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

• n commodity price and market conditions

0% 25% 50% 75% FY 2015 FY 2016 FY 2017 2017 Reserves % Oil Mix Oil NGL Gas Blended Realized Price* 2017 Production Mix 64% 12% 24% $41.09 2017 Proved Reserves Mix 72% 9% 19%

*Includes effects of settled hedges

CRC Corporate Presentation – April 2018 | 26

PDP Value Proved Value Unproved4 $0 $4 $8 $12 $16 $20

$55 Brent $65 Brent $75 Brent ($Billion)

2017 Reserves Value1 In Excess EV

Curren ent EV

• f $5.1

.1 Bn5 Infrastructure2 Surface & Minerals3

1-5 See endnotes in the Appendix.

See the Investor Relations page at www.crc.com for important information about 3P reserves and other hydrocarbon quantities.

CRC Corporate Presentation – April 2018 | 27

Project Inventory Drives Organic Deleveraging

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.

Estimat mated d Lever verage age Ratios

0.0x 2.0x 4.0x 6.0x 8.0x 10.0x 2016 2017 2018E 2019E 2020E 2021E

Total Debt/LTM EBITDAX

$55 $65 $75

CRC Corporate Presentation – April 2018 | 28 500 1,000 1,500 2,000 2,500 2017 2018E 2019E 2020E 2021E $MM

The Case for CRC: Investment Thesis Overview

Grow within cash flow Industry leading decline rate Integrated and complementary infrastructure

Maintain Production Production and Cash Flow Growth

Production Innovation Deep Inventory

Investment Case for CRC

World-class assets with significant inventory Resilient model that preserves optionality and protects downside Focused on value and poised for growth

Moved from defense to offense

Why Own CRC Now

Competitive Advantages

Disciplined portfolio management Potential for EBITDAX growth*

Clear runway and available cash

• 2017 2018E 2019E 2020E 2021E

*See Slide 24 for additional information regarding EBITDAX Growth planning scenarios.

APPENDIX

CRC Corporate Presentation – April 2018 | 30

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

• 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

• 10,000

20,000 30,000 40,000 50,000 1992 1996 2000 2004 2008 2012 2016 Boe/d Base Incremental

LBU PSC

• 2,000

4,000 6,000 8,000 10,000 12,000 2006 2008 2010 2012 2014 2016 Boe/d Base Incremental

Tidelands PSC

Base Profit Split: 4% CRC / 96% State* Incremental Profit Split: 49% CRC / 51% State* Base Profit Split: 4% CRC / 96% State* Incremental Profit Split 49% CRC / 51% State & City*

*Average profit split %

End of LBU Base First of 3 new PSC’s executed

CRC Corporate Presentation – April 2018 | 31

$40 $45 $50 $55 $60 $65 $70 $75 $80 $85 $90 $95 $100 Mboep epd

$Brent ent

Total

• tal Producti
• duction
• n @ $ Bren

ent t Pric ice

$40 $45 $50 $55 $60 $65 $70 $75 $80 $85 $90 $95 $100 $MM $Bren ent

Total

• tal Reven

enue e @ $ Bren ent t Pric ice

Wilmington PSC Illustration

Net Profit Barrels NPI Barrel Revenue

45% Share of Gross Production Variable with Price

Cost Recovery Barrels

Variable with price

Cost Recovery Revenue

Fixed revenue from cost recovery of the State & City of Long Beach share of costs

Gross Production

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

CRC Corporate Presentation – April 2018 | 32

$3.26 $3.14 $2.95 $3.00 $2.75 $2.42 $3.09 $2.90 $2.47 $2.56 $2.77 $2.66 $2.28 $2.67

0.00 0.50 1.00 1.50 2.00 2.50 3.00 3.50

1Q 2017 2Q 2017 3Q 2017 4Q 2017 2015 2016 2017

$/Mcf

NYMEX Realizations

CRC – Price Realizations

66% 62% 72% 79% 40% 52% 70% 63% 59% 66% 72% 37% 50% 65% 0% 20% 40% 60% 80% 100% 1Q 2017 2Q 2017 3Q 2017 4Q 2017 2015 2016 2017 % of WTI & Brent WTI Brent $51.91 $48.29 $48.21 $55.40 $48.80 $43.32 $50.95 $50.24 $47.98 $50.02 $56.92 $49.19 $42.01 $51.24 $54.66 $50.92 $52.18 $61.54 $53.64 $45.04 $54.82 30 40 50 60 70 1Q 2017 2Q 2017 3Q 2017 4Q 2017 2015 2016 2017 $/Bbl WTI Realizations Brent Realization %

• f WTI

97% 99% 104% 103% 101% 99% 101% Realization %

• f NYMEX

89 % 79% 87% 92% 97% 94% 86%

Oil Price Realization ation (with h Hedge ges) s) Gas Price Realization ation NGL Pric ice e Realizati lization n - % of W WTI & B Brent

CRC believes near-term differentials will remain strong

• 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 Corporate Presentation – April 2018 | 33

2014 Revolving Credit Facility Capacity - $1 billion

Updated Capital Structure from Recent Transactions – Improved Liquidity

2017 Term Loan - $1.3 billion 2016 Term Loan - $1 billion 2015 Second Lien - $2.25 billion Unsecured Notes - $0.393 billion

Drawn Revolver $837 $0 $250 $500 $750 $1,000

3Q17 PF 4Q17* ($MM)

Revolver Availability $431 Revolver Availability $850 Cash $11 Cash $441 $0 $200 $400 $600 $800 $1,000 $1,200 $1,400

3Q17 PF 4Q17* Availability ($MM)

Increased eased Liqui uidity** dity**

* Pro Forma for the Ares JV and $50mm private placement ** Subject to minimum liquidity requirement under 2014 Revolving Credit Facility. Includes unrestricted cash.

Reduc uced ed Revo volver er Borro rowing ng Added in November Debt Hierarchy

Undr drawn Revolv volver er

CRC Corporate Presentation – April 2018 | 34

$100 $100 $193 $2,250 $1,000 $1,300 $0

$0 $500 $1,000 $1,500 $2,000 $2,500 $3,000 $3,500 $4,000 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 2014 RCF 2017 Term Loan 2016 Term Loan 2nd Lien Notes Unsecured Notes

Strengthening the Balance Sheet - Improved Creditworthiness and Liquidity

• Pro forma net results from the Ares transactions which closed on February 7, 2018:
• 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

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 cash2 (441) Total Net Debt 4,502 Equity3 (764) Total Net Capitalization 3,738 Total Net Debt / Total Net Capitalization 120% Total Net Debt / LTM Adjusted EBITDAX4 5.9x LTM Adjusted EBITDAX4 / LTM Interest Expense 2.2x PV-105 / 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

Pro ro-Forma ma1 Capitali talization ation ($MM) Pro ro-Forma ma1 Debt t Matur uriti ties es ($MM)* )*

1 Pro-forma capitalization table and debt maturities graph reflect the payoff of the 12/31/17 outstanding balance

• f $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 www.crc.com, 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. * 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.

Undrawn RCF

CRC Corporate Presentation – April 2018 | 35

2Q 2018 3Q 2018 4Q 2018 1Q 2019 2Q 2019 Sold Calls Barrels per Day 6,200 6,100 16,100 16,100 6,000 Weighted Average Ceiling Price per Barrel $60.24 $60.24 $58.91 $65.75 $67.01 Purchased Calls Barrels per Day

• 2,000
• Weighted Average Ceiling

Price per Barrel

• $71.00
• Purchased Puts

Barrels per Day 1,200 6,100 1,100 24,100 11,000 Weighted Average Floor Price per Barrel 45.83 $61.47 45.85 $60.00 $60.05 Sold Puts Barrels per Day 29,000 24,000 19,000 25,000 5,000 Weighted Average Floor Price per Barrel $45.00 $46.04 $45.00 $49.00 $50.00 Swaps Barrels per Day 44,400 19,000 19,000 7,000

• Weighted Average

Price per Barrel $60.00 $60.13 $60.13 $67.71

• Percentage of 4Q 2017

Oil Production Hedged* 57% 31% 25% 25% 39% 39% 14%

Opportunistically Built Oil Hedge Portfolio

As of 3/30/2018. Certain of our counterparties have options to increase swap volumes at weighted average costs between $60 and $70 Brent. * Assumes future counterparty options are not exercised.

We target hedges

• n 50% of crude
• il production

Strategy

Protect cash flow for capital investments and covenant compliance

CRC Corporate Presentation – April 2018 | 36

Elk Hills Area – CRC’s Flagship Asset

Integr ntegrated d Inf nfrast rastru ructure cture

• 610 MMcf/d processing capacity through 4 gas plants
• Including California’s largest
• 3 CO2 removal plants
• Over 4,500 miles of gathering lines
• 45 MW cogeneration plant
• 550 MW power plant

1 DOGGR data and U.S. Energy Information Administration.

• 5

10 15 20 20 40 60 80 100 120

1998 2000 2002 2004 2006 2008 2010 2012 2014 2016

Rig Count

Net MBOE/d

Net MBOEPD Rig Count

Ove Overvie view

• CRC’s flagship, a 100 year-old field with exploration opportunities
• 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)

Fie ield ld Map Producti roduction

• n Histor
• ry

Large fee property position with integrated infrastructure

CRC Corporate Presentation – April 2018 | 37

Buena Vista Area – Highly Prospective Area

FIELDMAP

Ove Overvie view

• Includes Buena Vista (BV) Hills and BV Nose
• JV capital applied to infill development program that led to improved
• perational 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)

Growth potential near existing infrastructure

34 21 10 20 30 40 2012-14 2017 Drilling Time Days/well

5.0 2.5 100 200 300 400 500

• 1.0

2.0 3.0 4.0 5.0 6.0 2012-14 2017 Drilling Cost $/Ft Drilling Cost $MM/well Drilling Cost/Well Drilling Cost $/Ft

2017 Conventional BV Nose Development Drilling Cost Average Drilling Days/Well

2017 BV Area development program delivers a 1.8 VCI at a $55 Brent price deck

CRC Corporate Presentation – April 2018 | 38

Accelerating Production Decline in U.S. Onshore Lower 48 Development Wells

• 50%
• 40%
• 30%
• 20%
• 10%

0% 10% 20% 30% 40% Year 1 Year 2 Year 3 Year 4 Year 5

Normalized Decline Rates

2010 Wells 2011 Wells 2012 Wells 2013 Wells 2014 Wells 2015 Wells Source: Data from Wood Mackenzie, CRC analysis

Recent wells in the onshore Lower 48 are showing steeper declines

• 1,000,000

2,000,000 3,000,000 4,000,000 5,000,000 6,000,000 7,000,000 2009 2010 2011 2012 2013 2014 2015 2016

Production (BOPD)

Pre 2010 2010 Wells 2011 Wells 2012 Wells 2013 Wells 2014 Wells 2015 Wells

CRC Corporate Presentation – April 2018 | 39

0% 10% 20% 30% 40% 50%

1 Year Decline

Median: 29%

Best In Class Corporate Decline Rates

0% 10% 20% 30% 40% 50% 60% 70% 80%

3 Year Decline

Median: 49%

CRC CRC

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. FY 2016 Production Percentage Liquids Less than 55% 55% - 75% Greater than 75%

CRC Corporate Presentation – April 2018 | 40

(3,000) (2,500) (2,000) (1,500) (1,000) (500)

• 500

1,000

Unlevered Free Cash Flow ($MM)

CRC

Core Principle of Living within Cash Flow

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.

2017 Unlevered Free Cash Flow

Average: $(341.5)MM

CRC Corporate Presentation – April 2018 | 41

Accelerating Value and Derisking Inventory through JVs

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

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

• ptions
• Current focus is in the San Joaquin

Basin

• CRC operates all wells

CRC Corporate Presentation – April 2018 | 42

• 1,000.00

2,000.00 3,000.00 4,000.00 5,000.00 6,000.00 7,000.00 1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46 49 52 55 58 61 64 67 70 73 76 79 82 85 88 91 94 97 100103106109112115118 JV Share Typical E&P Share

Typical Industry JV Structure

• Based on recent industry JV

deals, a typical deal structure is

• Partner pays 80-100% Capital
• Receives 80-100% Working

Interest

• Typical hurdle rate:
• 10% - 20% IRR
• Partner’s working interest once

hurdle rate is achieved:

• 5% - 25%

Hurdle Rate Reached

Production Time

CRC Corporate Presentation – April 2018 | 43

Strategic Partner Alignment

Summary of Deal Partner

▪ Affiliate of Ares Management (Ares)

Contributed Assets

▪ Elk Hills power plant, gas processing assets and related non-borrowing base infrastructure currently owned by CRC

Midstream JV Capitalization

▪ 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

Distribution to Partners

▪ 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

Exit Provisions

▪ 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

CRC Corporate Presentation – April 2018 | 44

CRC Midstream JV Structure with Ares

California Resources Elk Hills, LLC Elk Hills Power, LLC

Contributed Assets $750 MM gross proceeds Class A (50%) and Class C (95.25%) Common Interests Power and Gas Processing Services Commercial Agreement Capacity Charges

Ares Management, L.P.

$750 MM gross proceeds Class B Preferred Interests, Class A and Class C Common Interests

Benefits

• Strategic alignment with Ares
• Provides CRC paths for opportunistic

deleveraging through cash flow growth or debt reduction

• Greatly enhances liquidity
• Retain ownership and operational

control

• Defined exit criteria

CRC Corporate Presentation – April 2018 | 45

Dynamic Portfolio Provides Flexibility

200 400 600 800

BOEPD

YEAR 5 200 400 600 800

BOEPD

YEAR 5

Gas

200 400 600 800

BOEPD

YEAR 5

0% 25% 50% 75% 100%

Portfolio Mix Higher Oil to Gas Price Ratio Lower Oil to Gas Price Ratio

Gas Unconventional Primary Waterflood Steamflood Workover

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.

Oil Gas Oil Oil Gas

CRC Corporate Presentation – April 2018 | 46

25 50 75 100 1 2 3 4 BOPD YEAR

* 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.

PARAMETERS PER PATTERN Operating Expense/bbl

$10-20

Capital Cost *

$2.8MM

Total EUR (MBO)

270

Peak Rate (BOPD)

90

D&C (days)

15

Royalty

10%

Greenfield Steamflood Type Pattern

Composite Type Curve Kern Front Actuals

CRC OPERATED FIELDS

Oxnard Midway Sunset McKittrick McDonald Anticline Kern Front Lost Hills

• N. Antelope

Hills

CRC STEAMFLOODS

300 Near Term Growth Plan Pattern Locations

$NYMEX

VCI

$3.5 $3 $2.5 $50 1.0 1.1 1.2 $55 1.3 1.4 1.5

$ BRENT

$60 1.6 1.7 1.8

CRC Corporate Presentation – April 2018 | 47

15 30 45 60 1 2 3 4 BOEPD YEAR

* Capital cost is fully burdened with facilities, injectors and tie-ins. Assumes 5-spot pattern with a 1:1 producer to injector ratio.

VCI

165 190

EUR

215 $50 1.3 1.5 1.7 $55 1.6 1.9 2.1

$ BRENT

$60 1.9 2.2 2.5

Waterflood – New Pattern Composite Type Well

Composite Type Curve

Mount Poso Actuals Buena Vista Actuals

CRC OPERATED FIELDS

Rincon Saticoy South Mountain Paloma Mount Poso Kettleman Buena Vista Elk Hills

CRC NEW & POTENTIAL WATERFLOODS

See endnote for important information about our type curves.

350 Near Term Growth Plan Locations

PARAMETERS PER PATTERN Operating Expense

$19/BOE

Capital Cost*

$1.2MM

Total EUR (MBOE)

190

Peak Rate (BOEPD)

35

Drilling Time (days)

10

Royalty

12.5%

CRC Corporate Presentation – April 2018 | 48

40 80 120 160 1 2 3 4 BOEPD YEAR

* 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.

PARAMETERS Operating Expense

$19/BOE

Capital Cost*

$1.8MM

Total EUR (MBOE)

165

Peak Rate (BOEPD)

120

Drilling Time (days)

14

Royalty

PSC**

VCI

140 165

EUR

190 $50 1.1 1.3 1.5 $55 1.4 1.6 1.9

$ BRENT

$60 1.6 1.9 2.2

Waterflood – Redevelopment Type Well

Huntington Beach Actuals Elk Hills Actuals Composite Type well West Wilmington Actuals East Wilmington Actuals

CRC OPERATED FIELDS

San Miguelito Elk Hills Wilmington Huntington Beach

CRC REDEVELOPMENT WATERFLOODS

350 Near Term Growth Plan Locations

CRC Corporate Presentation – April 2018 | 49 PARAMETERS Operating Expense

$10/BOE

Capital Cost*

$5.0MM

Total EUR (MBOE)

430

Peak Rate (BOEPD)

360

Drilling Time (days)

30

Royalty

12%

* 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.

Primary Type Well – Deeper Horizons

VCI

400 430

EUR

460 $50 1.5 1.6 1.7 $55 1.7 1.8 2.0

$ BRENT

$60 1.9 2.1 2.2

150 300 450 600 750 900 1 2 3 4 BOEPD YEAR

Composite Type well Wheeler Ridge Actuals Bardsdale Actuals Pleito Ranch Actuals BV Nose Actuals

CRC OPERATED FIELDS

Montalvo Kettleman Saticoy Bardsdale South Mountain Elk Hills BV Nose Yowlumne Pleito Ranch Wheeler Ridge Paloma Rio Viejo

CRC PRIMARY

See endnote for important information about our type curves.

150 Near Term Growth Plan Locations

CRC Corporate Presentation – April 2018 | 50

California Shale Type Well

Asphalto Elk Hills Buena Vista Kettleman Rose

• N. Shafter

Gunslinger Railroad Gap

CRC SHALE

• 100

200 300 400 500

1 2 3 4

BOEPD

New Pool Type Curve Infill Shale Curve

YEAR

Gunslinger Actuals Rose/N. Shafter Actuals Elk Hills Actuals Elk Hills (2001-2003) VCI

Infill New Pool $50 1.2 1.7 $55 1.3 1.9

$ BRENT

$60 1.4 2.0

*Capital cost includes drilling, completion and tie-ins. See endnote for important information about our type curves.

New Pool Operating Expense

$10/BOE $8/BOE

Capital Cost*

$5.0MM $2.5MM

Total EUR (MBOE)

765 220

Peak Rate (BOEPD)

500 143

Drilling Time (days)

30 20

Average Royalty

13% 13%

Infill

50 Near Term Growth Plan Locations (Split Evenly)

CRC OPERATED FIELDS

CRC Corporate Presentation – April 2018 | 51

A Net Water Supplier

• 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

In 2017, CRC supplied 4.9 billion gallons – over 15,000 acre-feet – of treated, reclaimed water for irrigation or recharge.

94% 94% 4% 4% 2% 2%

WA WATER ER MANAGE GED IN CRC’s OPERATIONS

Produced Water Fresh Water Non-Fresh Water

CRC set a new company record for water deliveries to agriculture in 2017, an 85% increase since 2015, preserving farmland and jobs. CRC’s operations in Long Beach use recycled or non-fresh water for 99.5% of their total water use.

CRC Corporate Presentation – April 2018 | 52

End Notes

1 Current CRC estimate of reserves value as of December 31, 2017. 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, 2018.

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