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

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

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CRC Corporate Presentation May 2018 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,

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SLIDE 1

CRC Corporate Presentation

May 2018

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SLIDE 2

CRC Corporate Presentation – May 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.

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SLIDE 3

CRC Corporate Presentation – May 2018 | 3

Value Proposition – Multiple Ways to Increase Valuation

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

CRC Corporate Presentation – May 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)

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SLIDE 5

CRC Corporate Presentation – May 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*

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SLIDE 6

CRC Corporate Presentation – May 2018 | 6

San Joaquin Basin – An American Super Basin

Ove Overvie view

  • Oil and gas discovered in the late 1800s
  • San Joaquin Basin contributed 70% of CRC’s total FY 2017 production, 73%
  • f pro forma FY 2017 production*
  • Cretaceous to Pleistocene sedimentary section (>25,000 feet)
  • Thermal recovery applied since early 1960s
  • Currently running 7 drilling rigs

Key y Asset 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,

~65% of pro forma 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

* Pro forma production includes 13 MBoepd 2017 production acquired in the Elk Hills transaction.

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SLIDE 7

CRC Corporate Presentation – May 2018 | 7

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. 2 Pro forma production includes 13 MBoepd 2017 production acquired in the Elk Hills transaction.

  • 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), 66

MBOE/d (~46% of total CRC production on a pro forma2 basis)

Fie ield ld Map Producti roduction

  • n Histor
  • ry

Large fee property position with integrated infrastructure

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SLIDE 8

CRC Corporate Presentation – May 2018 | 8

Elk Hills Transaction Summary

  • 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 2.85 MM CRC shares, effective April 1, 2018

  • CRC now owns Elk Hills in fee simple, holding

100% WI, NRI, and surface lands

  • Acquired ~10,000 surface fee acres

Total Consideration

$460MM 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

CRC Corporate Presentation – May 2018 | 9

Accelerating Value Further from Midstream JV

  • Expect to achieve $5MM of annualized
  • perational savings within 6 months of closing

and ~$15MM of additional synergies within the next 18 months

 Consolidate Operations  Streamline business processes  Increased revenue opportunities  Improve CRC capital efficiency

  • Maximizes NGL yields and revenue through

increased utilization of CRC’s best-in-class cryogenic plant

  • Transaction reduces CRC’s per unit production

costs by ~$0.55/boe and SG&A by ~$0.20/boe

  • Elk Hills produces light oil with an avg API of

~36, which has received a premium over Brent in recent months

Cash Flow from Acquired Assets Avoided Interest Cost Synergies ARES Cash Distributions1 $- $50 $100 $150

ARES TRANSACTION INCREMENTAL CASH FLOW

$MM

Acquired assets will add an incremental $40MM- $50MM of cash flow/ saving per year for the first 36 months1

Elk Hills Transaction delivers incremental cash flow for investment in 1.7+ VCI inventory

1 Assumes the PIK portion of the Ares distributions are deferred for the first 36 months.

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SLIDE 10

CRC Corporate Presentation – May 2018 | 10

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 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

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

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SLIDE 11

CRC Corporate Presentation – May 2018 | 11

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 more than 20 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

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SLIDE 12

CRC Corporate Presentation – May 2018 | 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

  • 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

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SLIDE 13

CRC Corporate Presentation – May 2018 | 13

Value Additive Inventory Growth

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

58 109 156 768 644 568 618 222 251 202 321 340 826 1,129 250 500 750 1,000 1,250 1,500 1,750 2,000 2,250 Spin-off 2015 2016 2017 MMBoe Unproven Revisions Due to Price Since 2014 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

CRC Corporate Presentation – May 2018 | 14

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*

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SLIDE 15

CRC Corporate Presentation – May 2018 | 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, 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 4 5

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SLIDE 16

CRC Corporate Presentation – May 2018 | 16

Significant Reduction in Total Debt from Post-Spin Peak

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 & Elk Hills Transactions 3/31/2018 Pro Forma Total Debt ($ MM)

6,7651 Total

Total Debt Reduction $535 million $205 million $102 million $625 million $110 million $297 million $1,874 million

1 Represents mid-second quarter 2015 peak debt. 2 Please see end notes for further information regarding the presentation of pro forma financial information.

  • 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.

2

4,891

2018 Debt Repurchases $97MM Closed 2 transactions

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SLIDE 17

CRC Corporate Presentation – May 2018 | 17

Recent Transactions - Improving Debt Metrics

3/31/2018 Actual Elk Hills (EH) Transaction April Debt Repurchases 3/31/2018 Pro Forma1 1st Lien 2014 Revolving Credit Facility (RCF)

  • $
  • $

45 $ 45 $ 1st Lien 2017 Term Loan 1,300 1,300 1st Lien 2016 Term Loan 1,000 1,000 2nd Lien Notes 2,248 (95) 2,153 Senior Unsecured Notes 393 393 Total Debt 4,941

  • (50)

4,891 Less cash (494) 460 34

  • Total Net Debt

4,447 460 (16) 4,891 Mezzanine Equity 724 724 Equity (654) 51 (603) Total Net Capitalization 4,517 $ 511 $ (16) $ 5,012 $ Total Debt / Total Net Capitalization 109% 98% Total Debt / LTM Adjusted EBITDAX4 6.0x 5.4x LTM Adjusted EBITDAX4 / LTM Interest Expense 2.4x 2.6x PV-105 / Total Debt 0.9x 1.1x Total Debt / Proved Reserves6 ($/Boe) $8.00 $7.17 Total Debt / Proved Developed Reserves6 ($/Boe) $11.23 $10.05 Total Debt / 1Q18 Production ($/Boepd) $40,171 $36,230

Pro ro Forma Capitali talization ation1 ($MM)

1 Please see end notes for further information regarding the presentation of pro forma financial information. 2 Includes $109 million of noncontrolling interest equity for BSP and Ares. 3 Calculated using 2.85 million shares of CRC common stock at closing share price of $18.06 on 4/9/2018. 4 Please see end notes for further information regarding Adjusted EBITDAX. 5 PV-10 as of 12/31/2017. PV-10 on a pro forma basis 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.

6 Reserves as of 12/31/2017. Reserves on a pro forma basis include an estimate of the Elk Hills reserves acquired.

2 3

$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

Pro ro Forma1 Debt t Matur uriti ties es ($MM)

Pro Forma Total Debt

$4.89B

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SLIDE 18

CRC Corporate Presentation – May 2018 | 18

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

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SLIDE 19

CRC Corporate Presentation – May 2018 | 19

Resilient Resource Base

30 60 90 120 150 180 210 240 20 40 60 80 100 120 140 160

1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18E**

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 investments based on the accounting treatment of each venture. ** Q2 Capital guidance includes CRC, BSP, and MIRA capital

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SLIDE 20

CRC Corporate Presentation – May 2018 | 20

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

CRC Corporate Presentation – May 2018 | 21

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

  • 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

  • Increased 2018 capital plan due to recent Elk Hills transaction and cash flow outlook

2018 Capital Investment Program – Transitioning to Mid-Cycle Commodity Prices

  • Approx. $550 to $600 million

1Facility Costs and other non-return 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.

2018E 8E Tot

  • tal Capital

tal Plan 2018E 8E Deve velopment pment Capital tal By Drive ve

42% 18% 16% 21%

3% 3%

Conventional Exploration

Waterfloods

Steamfloods Unconventional

44% 29% 13%

At $55 flat Brent and $3 NYMEX, the fully-burdened1 2017 CRC Development Program delivered a 1.7 VCI or 30% IRR2

  • Approx. $375 million
  • Approx. $375 million

10%

2018E 8E Deve velopment pment Capital tal By Basin

67% 6% 6% 27% 4% 4%

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SLIDE 22

CRC Corporate Presentation – May 2018 | 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

CRC Corporate Presentation – May 2018 | 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 2017 2018E 2019E 2020E 2021E 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. Please see end notes for further information regarding Adjusted EBITDAX. * 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

in total and on 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 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

CRC Corporate Presentation – May 2018 | 24

Project Inventory 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. Please see end notes for further information regarding Adjusted EBITDAX.

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

CRC Corporate Presentation – May 2018 | 25

PDP Value

Proved Value

Unproved4

$0 $4 $8 $12 $16 $20

$55 Brent $65 Brent $75 Brent

($Billion)

Elk Hills Acquisition Enhances 2017 Reserves1 Value Further Above EV

Curren ent EV of $6.0 .0 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.

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SLIDE 26

CRC Corporate Presentation – May 2018 | 26 500 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 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

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SLIDE 28

CRC Corporate Presentation – May 2018 | 28

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

slide-29
SLIDE 29

CRC Corporate Presentation – May 2018 | 29

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

slide-30
SLIDE 30

CRC Corporate Presentation – May 2018 | 30

$3.26 $3.14 $2.95 $3.00 $2.87 $2.75 $2.42 $3.09 $2.90 $2.47 $2.56 $2.77 $2.81 $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 1Q 2018 2015 2016 2017

$/Mcf

NYMEX Realizations

CRC – Price Realizations

66% 62% 72% 79% 69% 40% 52% 70% 63% 59% 66% 72% 64% 37% 50% 65% 0% 20% 40% 60% 80% 100% 1Q 2017 2Q 2017 3Q 2017 4Q 2017 1Q 2018 2015 2016 2017

% of WTI & Brent

WTI Brent $51.91 $48.29 $48.21 $55.40 $62.87 $48.80 $43.32 $50.95 $50.24 $47.98 $50.02 $56.92 $62.77 $49.19 $42.01 $51.24 $54.66 $50.92 $52.18 $61.54 $67.18 $53.64 $45.04 $54.82 30 40 50 60 70 80 1Q 2017 2Q 2017 3Q 2017 4Q 2017 1Q 2018 2015 2016 2017

$/Bbl

WTI Realizations Brent Realization %

  • f WTI

97% 99% 104% 103% 100% 101% 99% 101% Realization % of NYMEX 89 % 79% 87% 92% 98% 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.

  • ≈

* *See attachment 6 of the Q1 2018 Earnings Release for information regarding the effects of an accounting change on realized natural gas prices.

slide-31
SLIDE 31

CRC Corporate Presentation – May 2018 | 31

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

slide-32
SLIDE 32

CRC Corporate Presentation – May 2018 | 32

2Q 2018 3Q 2018 4Q 2018 1Q 2019 2Q 2019 3Q 2019 4Q 2019 Sold Calls Barrels per Day 6,200 6,100 16,100 16,100 6,000 1,000 1,000 Weighted Average Ceiling Price per Barrel $60.24 $60.24 $58.91 $65.75 $67.01 $60.00 $60.00 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 29,100 21,000 11,000 1,000 Weighted Average Floor Price per Barrel 45.83 $61.47 45.85 $60.86 $62.40 $63.27 $45.85 Sold Puts Barrels per Day 29,000 24,000 19,000 30,000 15,000 10,000

  • Weighted Average

Floor Price per Barrel $45.00 $46.04 $45.00 $49.17 $50.00 $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 2Q 2018

Oil Production Hedged* 55 55 - 57% 30 30 - 31% 24 - 25% 43 43 - 45% 25 25 - 26% 13 - 14% 1% 1%

Opportunistically Built Oil Hedge Portfolio

As of 4/10/2018. 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. Refers to guidance at $74 Brent.

We target hedges

  • n 50% of crude
  • il production

Strategy

Protect cash flow for capital investments and covenant compliance

slide-33
SLIDE 33

CRC Corporate Presentation – May 2018 | 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

slide-34
SLIDE 34

CRC Corporate Presentation – May 2018 | 34

(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

slide-35
SLIDE 35

CRC Corporate Presentation – May 2018 | 35

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
  • Third tranche expected in Q2
  • 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
slide-36
SLIDE 36

CRC Corporate Presentation – May 2018 | 36

  • 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

slide-37
SLIDE 37

CRC Corporate Presentation – May 2018 | 37

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

slide-38
SLIDE 38

CRC Corporate Presentation – May 2018 | 38

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-39
SLIDE 39

CRC Corporate Presentation – May 2018 | 39

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-40
SLIDE 40

CRC Corporate Presentation – May 2018 | 40

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

slide-41
SLIDE 41

CRC Corporate Presentation – May 2018 | 41

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%

slide-42
SLIDE 42

CRC Corporate Presentation – May 2018 | 42

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

slide-43
SLIDE 43

CRC Corporate Presentation – May 2018 | 43 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

slide-44
SLIDE 44

CRC Corporate Presentation – May 2018 | 44

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

slide-45
SLIDE 45

CRC Corporate Presentation – May 2018 | 45

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-46
SLIDE 46

CRC Corporate Presentation – May 2018 | 46

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 a market cap as of 4/20/2018 and the 3/31/2018 Pro Forma debt adjusted for the Elk Hills transaction and the April debt repurchases.

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. Adjusted EBITDAX Note: The 3/31/2018 Pro Forma Adjusted EBITDAX includes a +$20 million adjustment as a result of the Elk Hills transaction and no adjustment as a result of the April debt

  • repurchases. See the table to the right for a reconciliation to the closest GAAP measure. See the

Investor Relations page at www.crc.com for other important information. Pro Forma Financial Information and Elk Hills Transaction Note: The actual amount of drawings under

  • ur revolver necessary to complete the Elk Hills transaction and the April debt repurchases will depend
  • n the actual amount of cash available at the closing date. The pro forma information in this

presentation does not take into account capital expenditures or changes in our business since 3/31/2018 other than the Elk Hills transaction and April debt repurchases.

(in millions) Net income (loss) 9 $ 20 $ 29 $ Interest and debt expense, net 92 92 Depreciation, depletion and amortization 119 119 Exploration expense 8 8 Unusual, infrequent, and other items 10 10 Other non-cash items 12 12 Adjusted EBITDAX 250 $ 20 $ 270 $ 3/31/2018 Elk Hills Transaction 3/31/2018 Pro Forma The following table presents a reconciliation of the GAAP financial measure of net income (loss) to the non-GAAP financial measure of Adjusted EBITDAX.