AUGUST CORPORATE PRESENTATION Forward Looking / Cautionary - - PowerPoint PPT Presentation

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AUGUST CORPORATE PRESENTATION Forward Looking / Cautionary - - PowerPoint PPT Presentation

AUGUST CORPORATE PRESENTATION 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


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SLIDE 1

AUGUST CORPORATE PRESENTATION

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SLIDE 2

August Corporate Presentation | 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

  • r 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, which are based on certain estimates including

future production rates, costs and commodity prices

  • perations and operational results including production, hedging and capital investment
  • Capital budgets and maintenance capital requirements
  • reserves
  • type curves
  • commodity price changes
  • debt limitations on our financial flexibility
  • insufficient cash flow to fund planned investment or changes to our capital plan
  • 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

  • risks of drilling
  • unexpected geologic conditions
  • tax law changes
  • changes in business strategy
  • inability to replace reserves
  • effects of PSC-type contracts on production and unit production costs
  • insufficient capital, including as a result of lender restrictions, unavailability of capital

markets or inability to attract potential investors

  • effects of hedging transactions and limitations on our ability to enter such transactions
  • equipment, service or labor price inflation or unavailability
  • incorrect estimates of reserves and related future cash flows
  • 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

  • joint ventures and acquisition activities and our ability to achieve expected synergies
  • 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.

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SLIDE 3

August Corporate Presentation | 3

Well-Positioned to Drive Value-Oriented Growth

Disciplined Portfolio Management Adjusted 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 23 for additional information regarding Adjusted 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

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SLIDE 4

August Corporate Presentation | 4

Large Resource Base with Production Diversity

Sacram amento ento Basin in 14 MMBOE Proved Reserves 5 MBOE/d production (100% dry gas) San Joaquin uin Basin in 483 MMBOE Proved Reserves 98 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
  • 682 MMBOE proved reserves
  • 134 MBOE/d production, 62% 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, including estimate of reserves related to the Elk Hills acquisition Production figures reflect Q2 2018 rates Los Angel eles Basin in 145 MMBOE Proved Reserves 25 MBOE/d production (100% oil)

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SLIDE 5

August Corporate Presentation | 5

Leading Market Position with Deep Regional Insight

163 142 122 30 18

  • 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 FY 2017, information for Berry is from Q1 2018, and information for Sentinel Peak is from most recent available information which is 2016. Source: Wood Mackenzie, Company Estimates.

Largest 3-D Seismic Position in California

$19 $20 $21 $24 $29

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

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*

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SLIDE 6

August Corporate Presentation | 6

San Joaquin Basin – An American Super Basin

Ove Overvie view

  • Oil and gas discovered in the late 1800s
  • San Joaquin Basin contributed 73% of CRC’s total Q2 2018 production
  • Cretaceous to Pleistocene sedimentary section (>25,000 feet)
  • Thermal recovery applied since early 1960s
  • Currently running 7 drilling rigs

Key y Asse sets

  • 2Q 2018 average net production of 98 MBOE/d (55% oil)
  • Elk Hills is the flagship asset (~61% of Q2 2018 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 8 100 200 300 2015 2016 2017 1H 2018

  • Avg. Rig Count

Gross Wells Drilled

Steamflood Waterflood Primary Unconventional

  • Avg. Rig Count

Legend CRC Land Oil Field Gas Field CRC Operated

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SLIDE 7

August Corporate Presentation | 7

  • 5

10 15 20 20 40 60 80 100 120

1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 1H 2018

Rig Count

Net MBOE/d

Net MBOEPD Rig Count

Elk Hills Area – CRC’s Flagship Asset

Integr ntegrated d Inf nfrast rastru ructure cture

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

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

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.*, >3,000 producing wells

  • 11 billion OOIP (BOE) and cumulative production of over 2.7 billion BOE
  • Q2 2018 average net production of 60 MBOE/d (~45% of total CRC production)

Fie ield ld Map Producti roduction

  • n Histor
  • ry

CRC Land owned in fee with integrated infrastructure

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SLIDE 8

August Corporate Presentation | 8

Strategic Consolidation of Elk Hills Assets

  • CRC acquired Chevron’s non-operated

working interest ranging between 20% to 22% in different producing horizons within the Elk Hills field for total consideration of $460MM in cash and 2.85MM CRC shares, effective April 1, 2018

  • CRC now owns Elk Hills Unit in fee simple,

holding 100% WI, NRI, and surface lands

  • Acquired ~10,000 surface fee acres

Total Consideration

$462MM Cash + 2.85MM Shares

2017 Net Production

13 Mboepd

46% Oil | 9% NGL

2017E Operating Cash Flow

~$100MM

@ $65 Brent

2017 Proved Reserves

64 Mmboe

CRC estimate @ SEC 2017 Pricing

CRC now owns 100% WI & NRI in its largest field

Existing CRC Surface Acreage Acquired Surface Acreage Elk Hills Unit

Elk Hills Unit

47,000 acres

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SLIDE 9

August Corporate Presentation | 9

$15MM Implemented $0 $5 $10 $15 $20

Annualized Synergies ($MM)

Elk Hills Acquisition Synergies

  • Streamlined Operations
  • Equipment Optimization
  • Redundancy Elimination
  • Processing Efficiencies

Implemented Savings & Other Synergies

Estimat timated ed Ann nnualize lized d Elk lk Hill ills Synerg ergies es

Initial synergy estimate within 6 months Target total synergies

  • ver 18 months
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SLIDE 10

August Corporate Presentation | 10

1 2 3 15 30 45 2015 2016 2017 1H 2018

  • Avg. Rig Count

Gross Wells Drilled

Waterflood Average Rig Count

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

  • Q2 2018 average net production of 25 MBOE/d (100% liquids) with a

4% YOY decline and a 2017 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 more than 25% of our total 2017 oil production.

Wilmington Huntington Beach

Basin in Map

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

Performed 26 capital workover projects in 2017

Legend CRC Land Oil Field Gas Field CRC Operated

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SLIDE 11

August Corporate Presentation | 11

Ventura Basin – High Growth Area with Large OOIP

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 more than 20 fields (over half the fields in the basin)
  • ~250,000 net mineral acres (75% undeveloped)
  • Q2 2018 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

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SLIDE 12

August Corporate Presentation | 12

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

  • Q2 2018 average net production of 29 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

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SLIDE 13

August Corporate Presentation | 13

Value Additive Inventory Growth

  • Comprehensive technical review of 40% of CRC’s fields.
  • 2017 proved reserves of 618 million BOE (682 million BOE pro

forma including the Elk Hills acquisition) and 450 million BOE

  • f probable reserves.
  • 119% organic reserve replacement, excluding the effect of

price adjustments.

  • We added 34 million BOE of proved reserves from extensions

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 were $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 64 222 251 202 321 340 826 1,129

250 500 750 1,000 1,250 1,500 1,750 2,000 2,250 2,500 Spin-off 2015 2016 2017

MMBoe

2017 Unproven Revisions due to Price since 2014

  • Est. 2017 Reserves associated with Elk Hills Transaction

2017 Proven Cumulative Production

>350% Growth

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

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SLIDE 14

August Corporate Presentation | 14

Enduring Strategy

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

Invest est for Value ue 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*

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SLIDE 15

August Corporate Presentation | 15

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 11/20/14 03/20/15 07/20/15 11/20/15 03/20/16 07/20/16 11/20/16 03/20/17 07/20/17 11/20/17 03/20/18 07/20/18

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
  • 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 4 5

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SLIDE 16

August Corporate Presentation | 16

3,000 4,000 5,000 6,000 7,000

2Q15 Debt Exchange for 2L Open Market Purchases Equity for Debt Exchange Cash Tender for Unsecureds Cash & Working Capital 2Q18

Total Debt ($ MM)

Significant Reduction in Total Debt from Post-Spin Peak

Total

Total Debt Reduction $535 million $298 million $102 million $625 million $130 million $1,690 million

1 Represents mid-second quarter 2015 peak debt.

  • 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.

5,075

2018 Debt Repurchases $145MM

6,7651

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SLIDE 17

August Corporate Presentation | 17

Recent Transactions - Improving Debt Metrics

6/30/2018 1st Lien 2014 Revolving Credit Facility (RCF) 277 $ 1st Lien 2017 Term Loan 1,300 1st Lien 2016 Term Loan 1,000 2nd Lien Notes 2,153 Senior Unsecured Notes 345 Total Debt 5,075 Less cash1 (19) Total Net Debt 5,056 Mezzanine Equity 735 Equity (645) Total Net Capitalization 5,146 $ Total Debt / Total Net Capitalization 99% Total Debt / LTM Adjusted EBITDAX3 5.1x LTM Adjusted EBITDAX3 / LTM Interest Expense 2.8x PV-104 / Total Debt 1.0x Total Debt / Proved Reserves5 ($/Boe) $7.44 Total Debt / Proved Developed Reserves5 ($/Boe) $10.42 Total Debt / 2Q18 Production ($/Boepd) $37,873

Capitali talization ation ($MM)

1 Excludes $23MM of restricted cash. 2 Includes $144 million of noncontrolling interest equity for BSP and Ares. 3 LTM Adjusted EBITDAX includes a +$85 million adjustment as a result of the Elk Hills transaction. 4 PV-10 includes an estimate of the Elk Hills reserves acquired at SEC 2017 pricing. See the Investor Relations

page at www.crc.com for details on this calculation.

5 Reserves include an estimate of the Elk Hills reserves acquired at SEC 2017 pricing.

2

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

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

Debt t Matur uriti ties es ($MM) Not

  • table

ble Quarter erly y Highl hlights ghts

  • Repurchased face value of $95 million of 2nd Lien Notes

and $48 million of 2024 Senior Notes in the second quarter for $118 million in cash

  • Purchased LIBOR interest caps which cap a notional $1.3B
  • f floating rate debt at one-month LIBOR of 2.75% through

May, 2021

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SLIDE 18

August Corporate Presentation | 18

Development and Midstream Joint Ventures: A Force Multiplier

JVs are generally focused in the San Joaquin Basin

Kern Front

  • Legend-

Oxy Land Oil Fields Gas Fields

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

CRC Land

$200 Million

  • Approx. $300 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

$550 Million

Total Potential JV Development Capital

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

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

$750 Million

Midstream JV

Reduce Debt

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SLIDE 19

August Corporate Presentation | 19

Mid-Cycle Capital Investment Plan Delivers Production Growth

30 60 90 120 150 180 210 240

20 40 60 80 100 120 140 160 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18E**

Capital ($MM)

MBoe/d

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

Net et Producti roduction

  • n By St

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

*Total Capital reflected in the graph includes the capital investment of internal CRC capital as well as all JV partners which include BSP and MIRA. Please note our consolidated financial statements include BSP’s investment and exclude MIRA’s investment based on the accounting treatment of each venture. ** Q3 2018 Capital guidance includes CRC, BSP and MIRA capital.

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SLIDE 20

August Corporate Presentation | 20

Dynamic 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
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SLIDE 21

August Corporate Presentation | 21

Drilling JV - Capital Workover Development Facilities Exploration Other 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 Buena Vista, Ventura and Southern San Joaquin Areas

  • Additional Capital will be deployed to Drilling, Workovers and Facilities focused in the Ventura

and San Joaquin Basins

  • 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 – Transitioning to Mid-Cycle Commodity Prices

  • Approx. $650 to $700 million

1Facility and other support capital are apportioned to producing wells in the year they are drilled. 2IRR estimate for the 2017 development program. 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. 3Other includes maintenance and occupational health, safety and environmental projects, seismic, and other investments.

2018E 8E Tot

  • tal Capital

tal Plan n Inclu ludi ding ng JVs 2018E 8E Inter erna nally y Funde nded d Deve velopm pment nt Capital tal By Drive ve

47% 15% 13% 21%

3% 3%

Conventional Waterfloods Steamfloods Unconventional

46% 31% 13%

At $65 flat Brent and $3 NYMEX, the fully-burdened1 2017 CRC Development Program delivered a 2.0 VCI or 45% IRR2

  • Approx. $405 million
  • Approx. $405 million

10%

2018E 8E Inter erna nally y Funde nded d Develo velopm pment nt Capital tal By Basin

67% 5% 5% 28%

1% 1%

3

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SLIDE 22

August Corporate Presentation | 22

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

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SLIDE 23

August Corporate Presentation | 23

80 90 100 110 120 130 2017 2018E 2019E 2020E 2021E

Oil Production (MB/d)

400 800 1,200 1,600 2,000 2,400

Adjusted 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 varying lease operating costs within historical ranges depending on the commodity prices of the 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 is reinvested in business in 2019 and beyond for each scenario.

1 See the Investor Relations page at www.crc.com for a description of the calculation of the debt-adjusted per share basis and other important information. 2 See the Investor Relations page at www.crc.com for a reconciliation to the closest GAAP measure and other important information.

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

  • Cash flow
  • Production
  • Reserves

in total and on a debt-adjusted per share basis1

Portfolio Planning Scenarios Portfolio Planning Scenarios

Capital focused on oil projects that provide

Increa easing ng Mar argins ns Low

  • w

Decline e Rates es Compou pound nding ng Cash Flow

+ =

  • Estimated Crude Oil Production Outcomes

300 600 900 1,200 1,500 1,800 2017 2018E 2019E 2020E 2021E

Capital ($MM)

Estimated Ranges of Capital Investments Estimated Range of Adjusted EBITDAX Outcomes

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SLIDE 24

August Corporate Presentation | 24

Project Inventory and Operational Execution Drives Organic Deleveraging

Note: All cases are self-funding. Capital program in all cases assumes discretionary cash flow is reinvested. Assumes varying lease operating costs within historical ranges depending on the commodity prices of the planning scenario outcomes. See the Investor Relations page at www.crc.com for a reconciliation to the closest GAAP measure and other important information.

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 Adjusted EBITDAX

$55 $65 $75

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SLIDE 25

August Corporate Presentation | 25

PDP Value Proved Value Unproved4

$0 $4 $8 $12 $16 $20 $24 $28

$65 Brent $75 Brent $85 Brent

($Billion)

Elk Hills Acquisition Enhances NAV Above EV

Curren ent EV of $7.8 .8 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. 1 1

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SLIDE 26

August Corporate Presentation | 26 500 1,000 1,500 2,000 2,500 2017 2018E 2019E 2020E 2021E $MM

The Case for CRC: Investment Thesis Overview

Industry leading base 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 Adj. EBITDAX growth*

Clear runway and available cash

  • 2017 2018E 2019E 2020E 2021E

*See Slide 23 for additional information regarding Adjusted EBITDAX Growth planning scenarios.

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SLIDE 27

APPENDIX

slide-28
SLIDE 28

August Corporate Presentation | 28

Continued Forward Progress with Strong 1H18 Results

134 Mboe/d

62% Oil

$245 Million

$337 million Core Adjusted EBITDAX3

$194 Million2

$170 million internally funded

83 Gross Wells Drilled1

includes 48 CRC wells

Capital

  • Adj. EBITDAX4

ACTIVITY PRODUCTION

129 Mboe/d

62% Oil

$495 Million

$622 million Core Adjusted EBITDAX3

$355 Million2

$309 million internally funded

157 Gross Wells Drilled1

includes 92 CRC wells

2nd Quarter 2018 First Half 2018

1 Includes JV and non operated wells. 2 Includes JV capital. 3 Excludes settled hedges of $31MM in Q1 and $68MM in Q2 and cash settled equity compensation of $4MM in Q1 and $24MM in Q2. 4 See the Investor Relations page at www.crc.com for a reconciliation to the closest GAAP measure and other important information.

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SLIDE 29

August Corporate Presentation | 29

Wilmington Field – Production Sharing Contracts

  • 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

slide-30
SLIDE 30

August Corporate Presentation | 30

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

Realized Price ($/Boe)

Wilmington Production Sharing Contracts

  • Over 25% of CRC’s oil production is subject to

Production Sharing Contracts

  • PSC Mechanics
  • CRC pays our partners’ share of the Operating and

Capital Cost

  • CRC recovers our partners’ portion of the cost in barrels
  • CRC receives 45-49% of the gross production as “Profit

Barrels”

  • As prices rise, fewer barrels are required to recover
  • ur partners’ portion of the cost

Effect of Oil Price on Net Production Higher oil prices result in higher cash flow, but lower net production Cost Recovery Bbls Net Profit Bbls 45-49% of Gross Production Gross Production

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August Corporate Presentation | 31

$3.26 $3.14 $2.95 $3.00 $2.87 $2.75 $2.90 $2.47 $2.56 $2.77 $2.81 $2.25 0.00 0.50 1.00 1.50 2.00 2.50 3.00 3.50 4.00 1Q 2017 2Q 2017 3Q 2017 4Q 2017 1Q 2018 2Q 2018

$/Mcf

NYMEX Realizations

CRC – Price Realizations

66% 62% 72% 79% 69% 62% 63% 59% 66% 72% 64% 56% 0% 20% 40% 60% 80% 100% 1Q 2017 2Q 2017 3Q 2017 4Q 2017 1Q 2018 2Q 2018

% of WTI & Brent

WTI Brent

$51.91 $48.29 $48.21 $55.40 $62.87 $67.88 $50.24 $47.98 $50.02 $56.92 $62.77 $64.11 $54.66 $50.92 $52.18 $61.54 $67.18 $74.90 30 40 50 60 70 80 1Q 2017 2Q 2017 3Q 2017 4Q 2017 1Q 2018 2Q 2018

$/Bbl

WTI Realizations Brent

Realization % of WTI

97% 99% 104% 103% 100% 94%

Realization %

  • f NYMEX

89 % 79% 87% 92% 98%* 82%*

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 crude oil differentials will remain strong

  • California refinery demand for native crude continues to be strong and

reduction in heavy waterborne crude has positively influenced differentials.

  • Natural gas prices impacted by continued limits on 3rd party storage
  • NGL prices have been supported by lower inventories and export

markets.

*See attachment 6 of the Earnings Release for information regarding the effects of an accounting change on realized natural gas prices.

*

Seasonality in NGL prices experienced in Q2 every year

*

slide-32
SLIDE 32

August Corporate Presentation | 32

3Q 2018 4Q 2018 1Q 2019 2Q 2019 3Q 2019 4Q 2019 FY 2020 FY 2021 Sold Calls Barrels per Day 6,100 16,100 16,100 6,000 1,000 1,000 500

  • Weighted Average

Ceiling Price per Barrel $60.24 $58.91 $65.75 $67.01 $60.00 $60.00 $60.00

  • Purchased Calls

Barrels per Day

  • 2,000
  • Weighted Average

Ceiling Price per Barrel

  • $71.00
  • Purchased Puts

Barrels per Day 6,900 1,900 34,800 36,700 31,700 21,600 1,500 600 Weighted Average Floor Price per Barrel $61.31 $51.70 $62.77 $67.40 $70.50 $73.09 $47.97 $45.00 Sold Puts Barrels per Day 24,000 19,000 35,000 30,000 30,000 20,000

  • Weighted Average

Floor Price per Barrel $46.04 $45.00 $50.71 $55.00 $56.67 $60.00

  • Swaps

Barrels per Day 48,000 29,000 7,000

  • Weighted Average

Price per Barrel $60.35 $60.50 $67.71

  • Percentage of 2Q 2018

Oil Production Hedged 66% 37% 50% 44% 38% 26% 2% 2% 1% 1%

Opportunistically Built Oil Hedge Portfolio

As of 7/10/2018, assumes counterparty options are not exercised. Certain of our counterparties have options to increase swap volumes at weighted average prices between $60 and $70 Brent. For potential volume changes and further details please see Attachment 8 of our Earnings Release.

We target hedges

  • n 50% of crude
  • il production

Strategy

Protect cash flow, operating margins and capital investment program

slide-33
SLIDE 33

August Corporate Presentation | 33

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

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SLIDE 34

August Corporate Presentation | 34

Accelerating Value and Derisking Inventory through JVs

Highlights:

  • Up to $300MM
  • Current commitment of $140MM
  • 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
  • Three tranches of $50MM
  • Total of $150MM 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 and

Los Angeles Basin

  • CRC operates all wells
slide-35
SLIDE 35

August Corporate Presentation | 35

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 Capitalizatio n ▪ 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 consists of three CRC representatives and three representatives from Ares

slide-36
SLIDE 36

August Corporate Presentation | 36

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
slide-37
SLIDE 37

August Corporate Presentation | 37

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

slide-38
SLIDE 38

August Corporate Presentation | 38

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.

slide-39
SLIDE 39

August Corporate Presentation | 39

End Notes

From Slide 25

1 Current CRC estimate of reserves value as of December 31, 2017, including reserves acquired in the Elk Hills transaction.

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 June 30, 2018 debt at par and a market cap as of 7/24/2018. Includes mezzanine equity and non-

controlling interest equity. 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.