CRC: VALUE-DRIVEN NOVE VEMBE BER CORPO PORATE PRESENTATI TION - - PowerPoint PPT Presentation

CRC: VALUE-DRIVEN

NOVE VEMBE BER CORPO PORATE PRESENTATI TION ON

November Corporate Presentation | 2

Forward Looking / Cautionary Statements – Certain Terms

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, organic finding and development (F&D) costs, organic recycle ratio calculations, original hydrocarbons in place, Value Creation Index (VCI), drilling locations and reconciliations of non-GAAP measures to the closest GAAP equivalent.

• 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
• budgets and maintenance capital requirements
• reserves
• type curves
• expected synergies from acquisitions and joint ventures
• commodity price changes
• debt limitations on our financial flexibility
• insufficient cash flow to fund planned investments, debt repurchases or changes to our

capital plan

• inability to enter desirable transactions, including acquisitions, 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

• joint ventures and acquisitions and our ability to achieve expected synergies
• the recoverability of resources and unexpected geologic conditions
• incorrect estimates of reserves and related future cash flows and the inability to replace

reserves

• changes in business strategy
• PSC effects on production and unit production costs
• effect of stock price on costs associated with incentive compensation
• insufficient capital, including as a result of lender restrictions, unavailability of capital

markets or inability to attract potential investors

• effects of hedging transactions
• 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, joint

ventures 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.

November Corporate Presentation | 3

The VCI Difference Delivers Real Value

Value Focu cus

PV10 pre-tax cash flows PV10 of investments VCI = Value Creation Index

Delivering Smart Growth and Real Value

• Value-directed investments
• Disciplined capital allocation
• Enhanced returns over full-cycle time

frame

• Prioritization of projects and drives

alignment of team

• Ahead of competitive landscape shifting

to value

November Corporate Presentation | 4

CRC’s Value-Driven Strategic Approach

• Utilize VCI-based

decision-making

• Optimize core operating

area investment

• Enhance targeted

growth area investment

• Pursue impactful

capital workovers

• Streamline processes
• Apply technology
• Leverage sizeable

infrastructure

• Drive strategic

consolidation

• Employ new thinking

and approaches

• Reinvest to grow cash

flow

• Simplify capital

structure

• Enhance credit metrics
• Pursue value-accretive

M&A

• Reduce absolute level of

debt

• Pursue value-driven

production

• Delineate future growth

areas

• Enhance already

substantial inventory

• Pursue strategic joint

ventures

Capture Value of Portfolio Ensure Effective Capital Allocation Drive Operational Excellence Strengthen Balance Sheet

Proven and pressure-tested strategic approach preserved value through the downturn and is set to drive significant value creation for years to come

November Corporate Presentation | 5

Key Highlights

136 Mboe/d

62% Oil

$308 Million

$400 million Core Adjusted EBITDAX3

$196 Million2

$158 million internally funded

95 Gross Wells Drilled1

includes 59 CRC wells

Capital

• Adj. EBITDAX3

ACTIVITY PRODUCTION

131 Mboe/d

62% Oil

$803 Million

$1,022 million Core Adjusted EBITDAX3

$550 Million2

$467 million internally funded

252 Gross Wells Drilled1

includes 151 CRC wells

3rd Quarter 2018 3QYTD 2018

and cash-settled equity compensation of $13 million in the third quarter and $41 million in the first nine months. See the Investor Relations page at www.crc.com for historical reconciliations to the closest GAAP measure and other important information.

November Corporate Presentation | 6

• 5

10 15 20 25 30

Niobrara Barnett Anadarko - Woodford Haynesville - Bossier Utica Marcellus Shale Eagle Ford Bakken Permian (Wolfcamp + Sprayberry) California

Remaining Recoverable Resources (BBOE*)

Oil (BBO) NGL (BBOE) Gas (BBOE)

World-Class Hydrocarbon Province with Significant Potential

• Five of the largest conventional, onshore fields in

the lower 48

▪ Over 35 billion BOE produced since 1876 ▪ Still discovering the limits of remaining potential ▪ Over 10 billion BOE* in remaining recoverable resources

*MCF:BOE = 20:1 Note: produced volumes source: DOGGR; Remaining Recoverable Resources Source: USGS

California – a Top Oil Province CRC Advantage

• Stacked pays provide additional opportunity

through value chain

• Operating expertise to develop the diverse
• pportunity set
• Robust infrastructure turns disparate fields into

integrated plays

November Corporate Presentation | 7

Strength of Portfolio Allocation Strategy Supported by Diverse Assets

SAN JOAQUIN BASIN

Greater Elk Hills – Flagship Asset Thermal – Protecting Base Production South Valley – New Opportunities Shales & Tight Sands – New Opportunities

#2 Producer - 99,000 BOE/d1

26% of basin production 60% of basin mineral acreage

SACRAMENTO BASIN

Gas Optionality

#1 Producer - 5,000 BOE/d1

86% of basin production 85% of basin mineral acreage

VENTURA BASIN

Growth and Exploration

#1 Producer - 6,000 BOE/d1

25% of basin production 90% of basin mineral acreage

LOS ANGELES BASIN

Steady High Margin Oil Assets

#1 Producer - 26,000 BOE/d1

52% of basin production 65% of basin mineral acreage

in Mid-Year 2018 Proved Reserves

Note: Total basin production is based on FY2017

• production. Source: DOGGR. Total basin mineral

acreage is based on internal estimates.

Largest Operator in California

across Operate

135 fields ~12,000 000 wells

with

731 MMBOE2

November Corporate Presentation | 8

Enhanced Inventory Growth and Expanded 3P Position

First Half 2018 Highlights

• Mid-year reserves audited by Ryder Scott
• Proved reserves today only 5% lower despite 25%

decrease in price from the Spin

• Life-of-field studies increased unproven resources
• Recent exploration success not included

2017 Highlights

• Organic F&D costs excluding price related revisions were

$6.82 per BOE in 2017 and 3-year average of $4.84 per BOE

• Organic recycle ratio of 2.1x in 2017 and 3-year average
• f 2.8x
• Comprehensive technical review of 40% of fields
• Over 95% of total proved reserves audited by Ryder Scott

in the previous three years

Unproven Reserves1 Growth

58 58 109 156 179 768 644 568 568 618 731 222 222 251 226 226 175 171 181 431 450 458 150 159 395 679 699

250 500 750 1,000 1,250 1,500 1,750 2,000 2,250 2,500 2014 2015 2016 2017 1H18

MMBoe

>250% Unproven Growth

hydrocarbon quantities.

reserves utilize applicable SEC prices for all year-end periods. 1H18 proven reserves utilize $75 Brent.

Probable3 Price-Contingent Reserves2 Proved Cumulative Production Possible3

November Corporate Presentation | 9

5 10 15 20 25 30 35 40 45 50 100 200 300 400 500 600 700 800 900 1,000

Full Cycle Cost1 ($/Boe)

Net Resources2 (MMBoe)

Unlocking Value with a Deep Inventory of Actionable Projects at $75 Brent

Steamflood Waterflood Primary Shale Gas 3 6 9 12 100 200 300 400 500 600 700 800 900 1,000

Dev Capital (B$)

Net Resources2 (MMBoe)

• Fully burdened, growth-

focused portfolio

• Achieve a VCI of 1.3 or

greater at $75 Brent and $3.00 NYMEX

• Deliver robust cash flow
• Reflects all recovery

mechanisms and reserves types

• Leverage existing

infrastructure, while

• pportunistically targeting

new infrastructure investment

November Corporate Presentation | 10 $2.95 $3.00 $2.87 $2.75 $2.88 $2.56 $2.77 $2.81 $2.25 $3.16

0.00 0.50 1.00 1.50 2.00 2.50 3.00 3.50 4.00

3Q17 4Q17 1Q18 2Q18 3Q18 $/Mcf NYMEX Realizations

CRC – Price Realizations

72% 79% 69% 62% 66% 66% 72% 64% 56% 60%

0% 20% 40% 60% 80% 100%

3Q17 4Q17 1Q18 2Q18 3Q18 % of WTI & Brent WTI Brent $48.21 $55.40 $62.87 $67.88 $69.50 $50.02 $56.92 $62.77 $64.11 $63.63 $52.18 $61.54 $67.18 $74.90 $75.97

30 40 50 60 70 80

3Q17 4Q17 1Q18 2Q18 3Q18 $/Bbl WTI Realizations Brent

Realization % of WTI

104% 103% 100% 94% 92%

Realization %

• f NYMEX

87% 92% 98%* 82%* 110%*

Oil P Price Re Realizat ation

• n (with Hedges)

Gas Price Re Realizat ation

• n

NGL Price Re Realizat zation

• n - % of WTI & Brent

nt 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 summer heat and continued limits on

3rd party storage

• NGL prices have been supported by lower inventories and export

markets.

• ≈

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

* * *

November Corporate Presentation | 11

$0 $120 $240 $360 $480 $20 $50 $80 $110 07/14 01/15 07/15 01/16 07/16 01/17 07/17 01/18 07/18

Quarterly Capital ($MM) Brent Crude Oil Price ($/BBL)

Brent Crude Price Capital

Pressure Tested Through Cycle and Focused on Long-Term Value

TRANSITION TO OFFENSE

Cut rigs Began hedging Managed liabilities Utilized existing facilities Protected base production

VALUE- DRIVEN GROWTH

Increased activity Engaged in JVs Locked in hedges Increased liquidity Extended maturities Invest for value-driven production growth Delineate future growth areas Drill high-graded portfolio Invest in exploration Invest in facilities Strengthen balance sheet

VALUE PRESERVATION SEPARATION ANNOUNCEMENT

Spin Date

November Corporate Presentation | 12

Dynamic Capital Allocation Through Commodity Cycle

High-Price Scenario Mid-Cycle Scenario Low-Price Scenario

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 ▪ Workover existing wellbores for 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
• High cash generation
• VCI 1.3 floor to reinvest for value
• Accelerate balance sheet strengthening
• 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 facilities ▪ EOR and IOR for long-term cash flow - Primary/shale for high IP impact

• Delineate future growth areas to unlock upside
• Target 10-15% of discretionary cash flow to balance sheet strengthening

Up to $300MM Approx. $750MM 75%

25%

Over $1.5B 50%

50%

90%

10%

November Corporate Presentation | 13

CRC’s Dynamic Portfolio Provides Flexibility

200 400 600 800

YEAR 5 200 400 600 800

YEAR 5 200 400 600 800

YEAR 5

0% 25% 50% 75% 100% Portfolio Mix

Gas Shale Primary Waterflood Steamflood Workover For illustration of portfolio optionality based on normalized results per $10MM of investment and not guidance. See end note for details on type curves. Prices for recycle ratio are $75 Brent and $3.00 NYMEX.

Oil Oil Oil

November Corporate Presentation | 14

$85 $85 $75 $65

Strategic Development Joint Ventures – BSP & MIRA

~$240 Million

Invested Through Q3 2018

~3.5-4.0 MBoe/d

Gross Peak Production per $100 MM of Development Capital

>12 MMBoe

Potential Targeted Reserves per $100 MM

• f Development Capital

$550 Million

Total Potential JV Capital Portfolio Flexibility and Optionality Enable High Margin Production Growth Accelerate Value De-Risk Inventory

2018 2019 2020 2021 2022 2023

Reversio ion Esti timates

$75 $65

• f BSP Capital

• f MIRA Capital

Note: Price scenarios assume Brent pricing.

November Corporate Presentation | 15

Unparalleled California Expertise

Core Assets Provide Operational Leverage

Applying analog development to adjacent fields Midstream infrastructure provides low cost advantage

Largest 3-D Seismic Position in California

Extensive Field Operations Experience Decades

• f observed field

behavior and demonstrated shallow base decline rates

~ 20,000 net identified

proven and unproven drilling locations in 2017

Source: DOGGR, Wood Mackenzie, Company Estimates Note: Gross production data is average production in 2017. Opex data for CRC, Chevron, Aera, and Berry is from FY 2017, opex data for Sentinel Peak is from most recent available information which is FY 2016.

163 142 122 30 18

• 50

100 150 200 CRC Chevron USA Aera Energy Sentinel Peak Berry

Gross Operated MBOE/d $19 $21 $24 $29 $19

$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

Top California Producers in 2017 Majority of CA Production is Shallow

November Corporate Presentation | 16

Elk Hills Flagship Asset in San Joaquin Basin

• Large field with 100% NRI

▪ 10 billion original BOE in place within multiple reservoirs ▪ Produces ~60,000 BOE/d with annual 10% base decline

• Infrastructure provides low-cost advantage

▪ On-site gas processing and liquids extraction ▪ Large power plant reduces electricity costs by 75% ▪ Various light crude blends desired by multiple customers

• Large integrated business

▪ Stacked reservoirs with 280+ MMBOE proven reserves ▪ Diverse development inventory ▪ Proving ground for recovery techniques

$34MM Realized

$0 $5 $10 $15 $20 $25 $30 $35

Estimated Annualized Elk Hills Synergies* ($MM)

*Synergies include operational cost savings and revenue enhancement

Initial Target

November Corporate Presentation | 17

Leveraging Infrastructure for Nearby Low-Cost Field Development

• Coring up with Elk Hills

▪ Elk Hills serves as the hub ▪ Power, pipelines, compression ▪ Connecting fields and building out

• Lower cost shared resources

▪ Central control facilities and automation ▪ Optimized service provider utilization ▪ Shared support staff across fields

• Efficient step-out to new growth areas

▪ Dominant acreage position ▪ Low development costs for bolt-ons ▪ Discovering new resources through exploration

Southern San Joaquin Valley Consolidation 900 Million BOE of 3P reserves*

*1H18: 400 MMBOE proved, 270 MMBOE probable, 230 MMBOE possible

November Corporate Presentation | 18

Applying CRC asset playbook to substantial drilling inventory extends core Elk Hills

• perations and infrastructure

Developing Entire Southern San Joaquin Basin into Core Area

Field Area Original MMBOE in Place Rf Projects Yowlumne 900 13% Workover, primary drilling, new reservoirs and EOR Paloma 1,000 14% Workover, primary drilling and EOR Coles Levee 1,300 21% Workover, primary drilling and EOR Rio Viejo 60 16% Primary drilling, new reservoirs Landslide 70 23% Workover, primary drilling and EOR TOTAL 3,330 18%

• Redevelopment, expansion and additional

recovery in existing CRC operated fields

▪ Large fields with low recovery factors ▪ >500 identified development locations ▪ >150 MMBOE potential 3P reserves*

• New field development project following recent

exploration successes: Pleito Ranch

▪ Extension of CRC operated Pleito Ranch field ▪ >90 identified development locations ▪ >30 MMBOE discovered resources*

• Delivering value-driven growth

▪ Apply technology, operating expertise and knowledge ▪ Improved returns from leveraging existing infrastructure ▪ Disciplined and deliberate investment into high graded portfolio

Large Inventory of Development Projects

*See the Investor Relations page at www.crc.com for important information regarding potential reserves, discovered resources and other hydrocarbon resources.

November Corporate Presentation | 19

Conventional Exploration Program Generates Real Value

• 9 well exploration program since mid-year 2017

▪ Delineation and expansion of proven play trends plus new impact play concepts

• Reduced risk via joint ventures

▪ 7 exploration wells funded by partners1; CRC total initial net investment of ~$17MM

• Meaningful value creation

▪ ~$4/share value, potential to increase further with additional appraisal

• Repeatable recipe for success provided by analog

prospects in CRC’s unparalleled inventory

Multiple Small Joint Ventures $200+MM2,3 PV10 from Initial Net Investment of ~$17MM Fully-Burdened VCI of 1.82,4 Commercial Success >50%

SIGNED SEVEN JVs

November Corporate Presentation | 20

Strengthening the Balance Sheet Remains a Priority

0.0x 2.0x 4.0x 6.0x 8.0x 10.0x

YE14 YE15 YE16 YE17 YE18E Target

Total Debt / Adj. EBITDAX1 Leverage Core Adjusted EBITDAX Leverage

Target t 2x-3x x Lev everag erage e Ratio io

Complicated Capital Structure Simplified Capital Structure

Continue to Employ

ALL of the ABOVE Approach

Capital Markets Solutions Disciplined Capital Investment Asset Monetizations

Joint ventures Infrastructure Producing assets Refinance and simplify capital structure Target 10-15% of discretionary cash flow for balance sheet strengthening3

Simple Capital Structure

• information. Core Adjusted EBITDAX excludes settled hedges and cash settled equity compensation costs.

Accretive acquisitions Cash flow growth and support future reinvestment

November Corporate Presentation | 21 9/30/2018 1st Lien 2014 Revolving Credit Facility (RCF) 342 $ 1st Lien 2017 Term Loan 1,300 1st Lien 2016 Term Loan 1,000 2nd Lien Notes 2,122 Senior Unsecured Notes 344 Total Debt 5,108 Less cash1 (18) Total Net Debt 5,090 Mezzanine Equity 745 Equity (605) Total Net Capitalization 5,230 $ Total Debt / Total Net Capitalization 98% Total Debt / LTM Adjusted EBITDAX3 4.7x LTM Adjusted EBITDAX3 / LTM Interest Expense 2.9x PV-104 / Total Debt 2.0x Total Debt / Proved Reserves4 ($/Boe) $6.99 Total Debt / Proved Developed Reserves4 ($/Boe) $9.67 Total Debt / 3Q18 Production ($/Boepd) $37,559

Recent Transactions - Improving Debt Metrics

Capital alizati zation

• n ($MM)

MM)

as a result of the Elk Hills transaction.

the Investor Relations page at www.crc.com for details on how PV-10 is calculated.

$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 Maturi rities ($MM) MM) Highlight hts

• Received 8th Amendment to the 2014 Credit Agreement to repurchase

$300 million in 2nd Lien Notes notes and unsecured notes

• Repurchased face value of $128 MM of 2nd Lien Notes and $49 MM of

senior notes YTD for $149 MM in cash

• Purchased LIBOR interest caps which cap a notional $1.3B of floating rate

debt at one-month LIBOR of 2.75% through May 2021

• Recent S&P upgrade on 2nd Lien Notes to B- from CCC+

November Corporate Presentation | 22

Disciplined Capital Plan Leverages Portfolio of Projects and Management Expertise

Core Program

Buena Vista Elk Hills Long Beach Kern Front Mount Poso

Growth/Appraisal Program

South Valley Ventura Other Thermal Sacramento Valley Kettleman

~1.7+ Fully Burdened VCI @ $75 Brent

(Develop appraisal projects/ transfer reserves to proven)

Expect to

Live Within Cash Flow

Deliver

• Approx. Double-Digit

EBITDAX Growth

(Production wedge of 70%+ Oil) 20% 20% Fac acili iliti ties 5% 5% Explo Exploratio ion 3% 3% Oth ther Ventures 12% 12% Wor

• rkover

30 30-40% 40% Cor

• re

20 20-30% 30% Grow

• wth

2019 Expected Capital Allocation and Expected Outcomes

November Corporate Presentation | 23 80 90 100 110 120 130 2018E 2019E 2020E 2021E 2022E

Oil Production (MB/d)

600 900 1,200 1,500 1,800 2,100 2,400 2,700

Adjusted EBITDAX ($MM)

~16% Midpoint Adj. EBITDAX3 CAGR

Cash-Neutral Scenarios Targeting Double-Digit EBITDAX Growth

~7% Midpoint Production CAGR

Targeting 10-15% discretionary cash flow for balance sheet strengthening1 Combined with mid-cycle commodity prices, CRC is positioned for growth in:

• Cash flow
• Production
• Reserves

in total and on a debt-adjusted per share basis2

Capital focused on oil projects that provide

Increasing Margins Low Decline Rates Compounding Cash Flow

+ =

• Estimated Cash-Neutral Crude Oil Production Outcomes

Estimated Range of Cash-Neutral Adjusted EBITDAX Outcomes

• ≈

≈

500 1,000 1,500 2,000 2,500 2018E 2019E 2020E 2021E 2022E

Capital ($MM) Estimated Ranges of Capital Investments

November Corporate Presentation | 24

Continuous Efforts Provide Pathway to Reasonable Leverage

compensation costs.

Note: Targeting 10-15% of discretionary cash flow for balance sheet strengthening, remaining discretionary cash flow to be reinvested in business in 2019 and beyond for each scenario. Scenarios assume Brent pricing.

Estimated Leverage Ratios

0.0x 2.0x 4.0x 6.0x 8.0x 10.0x 2016 2017 2018E 2019E 2020E 2021E 2022E Total Debt/Adj. EBITDAX1 $65 $75 $85 Core Adj. EBITDAX Leverage

2 1

November Corporate Presentation | 25

Current Enterprise Value Deeply Discounted

PD PUD Unproved4

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

$65 Brent $75 Brent $85 Brent

Value ($Billion)

Current EV

• f $7.3

3 Bn5 Infrastructure2

Surface & Minerals3

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

November Corporate Presentation | 26

Portfolio of world- class assets investable throughout the commodity cycle

Investment Proposition: Delivering Smart Growth and Real Value

Disciplined and effective capital allocation Integrated and complementary infrastructure

Effective capital allocation through cycle for smart growth

Production Innovation Deep Inventory

Robust inventory

• f high value

growth projects

VALUE E

DRIVEN

Balance Sheet Goals High VCI Projects

Investing for the Future Growth Prospects Core Operating Areas Simplify Balance Sheet Reduce Fixed Charges Reduce Debt

Oil Price $/BBL Gas Price $/MCF

$

Balance capital investment with financial strengthening efforts for best long-term value creation

Deep operational knowledge and technical expertise

APPENDIX

November Corporate Presentation | 28 Drilling JV - Capital Workover Facilities Exploration Other1

Production Enhancement Plans for 2018

• CRC 2018 capital plan directed to oil-weighted projects in core fields: Elk Hills,

Buena Vista, Wilmington, Kern Front, Huntington Beach, and continued delineation of Ventura and Southern San Joaquin areas

• JV capital focused in the San Joaquin basin and Huntington Beach

2018 Capital Investment Program Aligned with Mid-Cycle Pricing

• Approx. $720 to $750 million

2018E Total Capital Plan Including JVs 2018E Internally Funded Development Capital By Drive

Dynamic plan that can be scaled up or down based on expected cash flows

• Approx. $450 million
• Approx. $450 million

2018E Internally Funded Development Capital By Basin

San Joaquin Ventura Los Angeles

46% 14% 14% 22%

3%

Conventional Waterfloods Steamfloods Unconventional

46% 31% 13% 10% 67% 5% 5% 28%

1%

November Corporate Presentation | 29

Investment Grade Assets with a Non-Investment Grade Balance Sheet

2017 Operational Metrics1 2017 Financial Metrics1

Source: CapIQ; Comparison Peers include APA, APC, AR, CHK, CLR, COP, CRK, CRZO, CXO, DNR, DVN, ECR, EGN, EQT, FANG, GPOR, HES, HK, KOS, LPI, MRO, MTDR, MUR, NBL, OAS, OXY, PDCE, PXD, QEP, RRC, RSPP, SM, SRCI, SWN, UNT, UPL, WLL, WRD and XEC.

certain respects from organic F&D, organic recycle ratio and free cash flow reported by the company and available in the Investor Relations section of www.crc.com.

$0 $5 $10 $15 CRC A A-

3 Yr F&D, All-In ($/BOE)

500 1,000 BB CRC BB-

Proven Reserves (MMBOE)

0.0 1.0 2.0 3.0 A- CRC BBB

Recycle Ratio (3 Yr Avg)

($500) ($400) ($300) ($200) ($100) $0 $100 $200 $300 A CRC BBB+

Free Cash Flow ($MM)

• 50

100 150 BB- CRC B+

Production (MBOEPD)

0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 B CRC B-

Debt/PV10

CCC+

CRC’s S&P Corporate Family Rating

CRC’s operations and finances are comparable to peers with higher credit agency ratings

November Corporate Presentation | 30

Summary of Mid-Year 2018 Reserves Changes

limitations.

CRC C Reserves es Change nges s (Net t MMBOE) OE)

Reserve Category YE 2017 Balance Price Related Revision 1H 2018 Production Changes2 Acq & Div July 2018 Balance 1P RRR3 (Excl Price) Proved R/P YE 17 Gross Well Count YE 18 Gross Well Count

PD 440 40 (23) 25 46 528 9,695 10,097 PUD 178 10 (2) 18 203 1,691 1,546 Proved4 618 50 (23) 23 64 731 96% 15 11,386 11,643

731 MMBOE

Proved Reserves Up 18% from YE 2017

96%

Half-Year Proven Organic Reserves Replacement (excl. price-related revisions – unaudited)

<$10/BOE F&D Cost1 15 Year R/P

November Corporate Presentation | 31 4Q18 1Q19 2Q19 3Q19 4Q19 1Q20 Sold Calls Barrels per Day 15,000 15,000 5,000

• Weighted Average

Ceiling Price per Barrel $58.83 $66.15 $68.45

• Purchased

Calls Barrels per Day

• 2,000
• Weighted Average

Ceiling Price per Barrel

• $71.00
• Purchased Puts

Barrels per Day

• 38,000

40,000 40,000 35,000 10,000 Weighted Average Floor Price per Barrel

• $65.66

$69.75 $73.13 $75.71 $75.00 Sold Puts Barrels per Day 19,000 40,000 35,000 40,000 35,000 10,000 Weighted Average Floor Price per Barrel $45.00 $51.88 $55.71 $57.50 $60.00 $60.00 Swaps Barrels per Day 48,000 7,000

• Weighted Average

Price per Barrel $60.35 $67.71

• Percentage of 3Q 2018 Oil Production

Hedged Against Downside 57% 57% 54% 54% 48% 48% 48% 48% 42% 42% 12% 12%

Opportunistically Built Oil Hedge Portfolio

As of October 2018. Assumes counterparty options are not exercised. Certain of our counterparties have options to increase swap volumes by up to 5,000 barrels per day at a weighted average Brent price of $70.00 for the first quarter of 2019. The BSP JV entered into crude oil derivatives that are included in our consolidated results but not in the above table. For further information please see attachment 8 of our latest earnings release.

2019 program continues to target hedges on 50% of crude oil production and provides more upside exposure to commodity price movement

Strategy

Protect cash flow,

• perating margins

and capital investment program

November Corporate Presentation | 32

Daily SoCalGas natural gas inventories Source: EIA

$0 $2 $4 $6 $8 $10 $12 $14 01/2017 04/2017 07/2017 10/2017 01/2018 04/2018 07/2018 10/2018 So Cal City Gate Wheeler Ridge NG Futures

California Policies Impact Natural Gas Prices

Lack of Natural Gas Storage and Peak Demand

California Natural Gas Prices “Duck” Curve

Impact of Solar Generation Aliso Canyon Effect on Inventory

Limited third-party storage, summer heat and reliance on renewable sources have increased volatility in local natural gas prices

>$20

Source: Bloomberg

Source: California ISO

November Corporate Presentation | 33

✓ Reflect Californians’ values ✓ Solicit community input ✓ Advance community interests ✓ Build strategic alliances ✓ Educate and inform policy makers ✓ Sustain 90-day permit inventory per rig line ✓ Fulfill California’s high standards ✓ Help achieve the state’s long-term goals ✓ Contribute to vibrant future for all Californians

CRC’s Regulatory Strategy Advances California’s Leading Standards

200 400 600 800 1000 1200 YE16 YE17 1Q18 2Q18 3Q18E

Growing Permit Inventory

(Permitted drilling rig days at end of period)

CRC’S CONSISTENT REGULATORY STRATEGY

Seasoned operator with proven local expertise

November Corporate Presentation | 34

CRC Positioned as California’s Operator of Choice

• Proudly share state’s commitment to natural resources
• Proven track record in sensitive coastal, urban and

agricultural settings

• Design and maintain facilities with a highly qualified

workforce, including the California Building and Construction Trades

• Workforce received 14 safety awards from the National

Safety Council for 2017

• Certified wildlife habitat conservation programs at Elk

Hills, THUMS Islands and Huntington Beach CRC is recognized by national safety and environmental organizations

THUMS Island Grissom, Long Beach Sutter Buttes, Sacramento Basin Oakridge Lease, Ventura Bolsa Chica Reserve, Huntington Beach

November Corporate Presentation | 35

Buena Vista Field – Applying our Asset Playbook to Adjacent Field

• Large field adjacent to Elk Hills

▪ 7 billion original BOE in place, 10% Rf ▪ Decades of production history, 10% annual base decline ▪ 3P reserves of 245 MMBOE* with 650 locations

• Analogous to Elk Hills

▪ Predictable recoveries ▪ Extending the field boundaries ▪ Applying new technology, such as horizontals

• Integration with Elk Hills lowers F&D costs

▪ Gas processing at Elk Hills ▪ Low-cost power and water handling ▪ Shared overhead with Elk Hills 3,000 6,000 9,000 12,000 15,000 18,000 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18

Gross BOE/d

Buena Vista

25% CAGR

Preservation

• f capital

*1H18: 70 MMBOE proved, 65 MMBOE probable, 110 MMBOE possible

November Corporate Presentation | 36

• World-class waterflood

▪ 7 billion original BOE in place, 34% Rf ▪ Partnership with State of California and City of Long Beach

• Operational excellence

▪ Decades of operational experience ▪ Low annual base decline of 8% ▪ 640 identified locations

• Big fields get bigger

▪ Targeting bypassed pay, exploring deeper potential ▪ 280% organic RRR since Spin ▪ LA Basin 3P reserves of 290 MMBOE1

LA Basin – World-Class Wilmington Field

• 37
• 62

166 +104 171

50 100 150 200 YE14 Production Price-Related Revisions E&D & Tech Revisions 1H18

Proved MMBOE

LA Basin Reserves Higher than at Spin

Small footprint to access vast resources

November Corporate Presentation | 37

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)

• PSC Mechanics

▪ CRC pays partners’ share of the Operating and Capital Cost ▪ CRC recovers 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 partners’ portion of the cost Effect of Oil Price on Net Production

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

November Corporate Presentation | 38

Wilmington 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 4Q16

• 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

November Corporate Presentation | 39

Renewed Investment in Analog Field

• Large underdeveloped field

▪ 2 billion original BOE in place, 30% Rf ▪ Waterflood, low annual base decline <8% ▪ Acquired in 2013 w/ 94 surface acres

• Wilmington is an analog

▪ Multiple stacked pay zones ▪ Primary, waterflood and steamflood ▪ 60 MMBOE 3P reserves*

• 2018 drilling delivering 50% better IP’s than

2013-2015 program

▪ Building on prior appraisal program ▪ Successful execution of horizontal wells ▪ Average 2018 IP of ~250 bopd, VCI 2.5

Huntington Beach Onshore

2,000 4,000 6,000 8,000 Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18

Gross BOE/d

Huntington Beach

Preservation

• f capital

20% CAGR

*1H18: 30 MMBOE proved, 15 MMBOE probable, 15 MMBOE possible

Deliver new value in fields drilled over decades

November Corporate Presentation | 40

Low-Cost Capital Workovers Deliver Value and Volume

• Existing assets in multiple stacked pay zones

▪ 12,000 wellbores with pay behind pipe ▪ CRC owned processing facilities

• Low-risk, high-reward well work opportunities

▪ Adding pay behind pipe ▪ Upgrading artificial lift equipment ▪ Stimulation of existing zones

• Currently operating 18 capital workover rigs

▪ Average cost $180,000 per job ▪ Develops 3,500 BOEPD annually ▪ 6.0 VCI

2,000 4,000 6,000 8,000 10,000 12,000 14,000

Jan-17 Jan-18 Jan-19 Jan-20 Gross BOEPD

Workover Program

2017 Program 2018 Program

estimated production

Continuous drilling program leads to additional locations, approx. 4.4 million reservoir-ft behind pipe

November Corporate Presentation | 41

Expanding CRC’s Asset Playbook to Ventura Basin

• Prolific basin with a long history, including the first

commercial oil well in California

▪ Operate more than 20 fields ▪ ~9 billion original BOE in place in CRC fields, Rf ~14% ▪ ~250,000 net mineral acres (75% undeveloped)

• 2017 average net production of 6 MBOE/d (67% oil)

▪ Low decline asset, maintaining flat with limited capital

• Portfolio of drive mechanisms

▪ Primary, new and redevelopment waterfloods and steamfloods

• Building off exploration success

▪ Recent CRC exploration wells flowed > 1,000 BOE/d (80% oil) along Oakridge trend

• Activity increasing in mid-cycle price environment

▪ Focus on development and exploration in core South Mountain asset and expand across basin

CRC Operated Fields in the Ventura Basin

CRC is the largest operator in the Ventura Basin

November Corporate Presentation | 42

Sacramento Basin Provides Gas Optionality

• Prolific gas basin

▪ CRC is largest operator in basin, operates ~ 86% of production ▪ 2017 average production of 33 MMCF/D

• Rio Vista is core asset with > 5 TCF original gas in place

▪ > 10,000’ of stacked sands, majority of activity to drill depths < 6,000’ ▪ Joint venture improves returns and increases activity and reserve bookings

• Similar upside and JV potential in CRC operated Willows

and Grimes analog fields

• Impact exploration potential

▪ Multi-TCF Tulainyo prospect plus analog, oil upside ▪ 5-7 “Dempsey” analog prospects

GRIME MES 14,000 mcfd 1.1 TCF cum RIO VISTA 15,000 mcfd 3.8 TCF cum WILLO LOWS 7,500 mcfd 650 BCF F cum THOMP MPKINS HILL LL 1,000 mcfd 125 BCF F cum LATHROP 3,000 mcfd 700 BCF F cum TULAIN LAINYO YO PROJE JECT 50 50 sq sq mile, le, 4-way clos

• sure

Stacked gas sands, deep ep oil l potentia ial

November Corporate Presentation | 43

Elk Hills CO2 Project: Advancing Contingent Resources

Many CRC fields suitable for additional EOR recovery techniques

▪ Large resource, known production profiles ▪ Infrastructure largely in place ▪ Pilot responses confirm suitability

175 1085 655

Contingent Resources MMBOE*

Econ Limit/5Yr Rule Technical CO2 EOR

• Project scope

▪ Utilizing 6 MMCF/day miscible gas from Elk Hills plant ▪ Permits approved, injection begins 4Q18 ▪ Anticipated response time of 6 to 8 months

• Dedicated team focused on full field project

▪ Evaluating various carbon capture technologies ▪ Project scoping and economics

*As of 1H18

2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 2044 2046

Net BOPD

Elk Hills Project Initiation

Stevens CO2 Wedge Base

November Corporate Presentation | 44

Conventional Exploration Program Generates Real Value

• 9 well exploration program since mid-year 2017

▪ Delineation and expansion of proven play trends plus new impact play concepts

• Reduced risk via joint ventures

▪ 7 exploration wells funded by partners1; $CRC total initial net investment ~$17MM

• Meaningful value creation

▪ ~$4/share value, potential to increase further with additional appraisal

• Repeatable recipe for success provided by analog

prospects in CRC’s unparalleled inventory

Multiple Small Joint Ventures $200+MM2,3 PV10 from Initial Net Investment of ~$17MM Fully-Burdened VCI of 1.82,4 Commercial Success >50%

SIGNED SEVEN JVs

November Corporate Presentation | 45

Example Life Cycle of Wellbore with Stacked Reservoirs

1 2

3

1 3 2

NPV 10 ($MM) IRR (%) VCI

A B

November Corporate Presentation | 46

0% 5% 10% 15% 20% 25% 30% 50 100 150 200 250 300 350 400 450 5 10 15 Recovery Factor BOEPD years

2 3

Example Life Cycle of Wellbore with Multiple Recoveries

1 3

1

2

NPV 10 ($MM) IRR (%) VCI

November Corporate Presentation | 47

• Steam injection contributes to over 1.2 MMBO/d of production worldwide
• Thermal techniques account for over 40% of US EOR production; 95% of these are in California
• Up to 75% of the oil-in-place can be recovered
• Characterized by low risk and stable/low decline

Steamflood Overview

$75 Brent Marker Price $71 Realized Price/BOE Differentials/Marketing

Cash Margin

19% of CRC 2017 production from steamfloods

58%

SHALLOW DEEP

58%

November Corporate Presentation | 48

Heat reduces viscosity of oil and increases its mobility

• riginal reservoir

Steamflood – Single Pattern Mechanics

Ramp-Up Peak Mature

Facilities Established Maximize Injection 6 mos. – 2+ yrs. Maximum Oil Rate Steam Breakthrough 1 – 5 yrs. Stable Oil Decline Injection Reduction 5+ yrs.

Steam Injection Rate Oil Rate

$20/BBL $15/BBL $10/BBL

Operating Expense

Up-front steam costs scale with gas price

November Corporate Presentation | 49 25 50 75 100 1 2 3 4

• Information is for a steamflood pattern assuming 3 producers per 1 injector and 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 details.

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

Oxnard Midway Sunset McKittrick McDonald Anticline Kern Front Lost Hills

• N. Antelope

Hills

VCI $3.5 $3 $2.5 $65 1.9 2.0 2.1 $75 2.5 2.6 2.7

$85 3.1 3.2 3.3

BOEPD YEAR

November Corporate Presentation | 50

• Water-flooding techniques are the most commonly used EOR production methods
• 20 – 40% of the oil-in-place can be recovered
• The oil rate decline for waterfloods is generally ~10%
• Low capital intensity and robust margins make it an attractive investment at low prices
• Many existing wells in CRC fields can be converted to injectors, maximizing effectiveness and value without

drilling new wells

Waterflood Overview

$75 Brent Marker Price $71 Realized Price/BOE Differentials/Marketing

Cash Margin

30% of CRC 2017 production from waterfloods

SHALLOW DEEP

60%

November Corporate Presentation | 51 Fill Up Recovery Redevelopment

Establish Facilities & Reservoir Fill- up / Plateau Period 6 mos. – 2+ yrs. Expected Water Rate Breakthrough & Oil Decline 3 – 5+ yrs. High initial rates targeting bypassed pay using horizontal wells and other technologies

Injection Rate Oil Rate

Waterflood – Single Pattern Mechanics

New Pattern Well Redevelopment Well

Injection Rate Oil Rate

November Corporate Presentation | 52 15 30 45 60 1 2 3 4

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

Waterflood – New Pattern Composite Type Well

Composite Type Curve

Mount Poso Actuals Buena Vista Actuals

See endnote for details.

BOEPD YEAR

PARAMETERS PER PATTERN Operating Expense/bbl

$19/BOE

Capital Cost *

$1.2MM

Total EUR (MBO)

190

Peak Rate (BOPD)

35

Drilling Time (days)

10

Royalty

12.5%

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

VCI 165 190 215 $65 2.2 2.6 2.9 $75 2.8 3.2 3.7

$85 3.3 3.8 4.4

November Corporate Presentation | 53 40 80 120 160 1 2 3 4

* 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 details.

Waterflood – Redevelopment Type Well

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

VCI 140 165 190 $65 1.9 2.3 2.6 $75 2.4 2.9 3.3

$85 2.8 3.4 4.0

San Miguelito Elk Hills Wilmington Huntington Beach

BOEPD YEAR

PARAMETERS PER PATTERN Operating Expense/bbl

$19/BOE

Capital Cost *

$1.8MM

Total EUR (MBO)

165

Peak Rate (BOPD)

120

Drilling Time (days)

14

Royalty

PSC**

November Corporate Presentation | 54

• CRC experiences repeatable success in deeper (>10,000 ft.) producing horizons and projects with

high IPs

• Generally characterized by sandstones with shallower declines as compared with non-California

shale wells

• Natural flow followed by conversion to artificial lift
• Many primary fields have stacked reservoirs, allowing access to multiple zones using the same wellbore
• In addition to deeper primary, CRC also targets projects in medium/shallower zones with scalable costs

and similar economics.

Deeper Horizons Primary Overview

$75 Brent Marker Price $67 Realized Price/BOE Differentials/Marketing

Cash Margin

17% of CRC 2017 production from primary

SHALLOW DEEP

Targeted Zone

80%

November Corporate Presentation | 55

* 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

150 300 450 600 750 900 1 2 3 4

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

See endnote for details.

VCI 400 430 460 $65 2.2 2.3 2.5 $75 2.6 2.8 3.0

$85 3.1 3.2 3.6

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

BOEPD YEAR

PARAMETERS PER PATTERN Operating Expense/bbl

$10/BOE

Capital Cost *

$5.0MM

Total EUR (MBO)

430

Peak Rate (BOPD)

360

Drilling Time (days)

30

Royalty

12%

November Corporate Presentation | 56

• Upper Monterey Shale Reservoirs (Infill): naturally fractured, low permeability reservoirs. Produce from

conventional structural and stratigraphic traps containing hydrocarbons migrated from source kitchen. Successful commercial developments with >30% of CRC’s total production coming from these type of reservoirs.

• Lower Monterey, Kreyenhagen, and Moreno Shale Reservoirs (New Pool): prolific source rocks that have

generated the majority of the hydrocarbons produced from fields across California. Potential California resource play opportunity with reservoir properties similar to other successful Lower 48 resource plays. Near-term focus

• n the Kreyenhagen reservoirs in our Kettleman North Dome field.
• Initial portfolio of 50 high-graded locations in the near-term growth plan that cover both

types of shales.

California Shale Overview

$75 Brent Marker Price $41 Realized Price/BOE Differentials/Marketing

Cash Margin

34% of CRC 2017 production from shale

SHALLOW DEEP

71%

November Corporate Presentation | 57

California Shale Type Well

• 100

200 300 400 500 1 2 3 4

New Pool Type Curve Infill Shale Curve Gunslinger Actuals Rose/N. Shafter Actuals Elk Hills Actuals Elk Hills (2001-2003) VCI Infill New Pool $65 1.5 2.2 $75 1.7 2.6

$85 2.0 2.9

*Capital cost includes drilling, completion, and tie-ins. See endnote for details.

New Pool Infill

Asphalto Elk Hills Buena Vista Kettleman Rose

• N. Shafter

Gunslinger Railroad Gap

BOEPD YEAR

Operating Expense/bbl

$10/BOE $8/BOE

Capital Cost *

$5.0MM $2.5MM

Total EUR (MBO)

765 220

Peak Rate (BOPD)

500 143

Drilling Time (days)

30 20

Average Royalty

13% 13%

November Corporate Presentation | 58

Sacramento Basin – Gas Overview

SHALLOW DEEP

$75 Brent Marker Price and $3.00 NYMEX $18 / BOE or $3.0 / MCF Realized Pricing Differentials/Marketing

Cash Margin

• CRC is the largest gas producer in California
• Operates 85% of the gas production in the Sacramento Basin
• Gas production is a natural hedge to rising steam and electrical energy costs
• At current prices, CRC pursues capital workovers in the Sacramento Basin. New wells have been funded

with JV/farmout capital

• Provides significant optionality at higher gas prices for a state that imports 90% of its natural gas

~5% of CRC 2017 production from the Sacramento Basin

38%

November Corporate Presentation | 59

End Notes

From Slide 25

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

Brent prices. Includes field-level operating expenses, G&A and taxes other than on income. Assumes $3.00/MMBTU NYMEX in all cases.

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 & Mineral reflect the estimated value of undeveloped surface and mineral acreage held in fee. 4 Unproved reserves are comprised of risked probable and possible reserves as of December 31, 2017. 5 Calculated using September 30, 2018 debt at par and a market cap as of 11/08/2018. Includes non-controlling interests reported

as mezzanine and permanent equity as of September 30, 2018. Type Curve Note: Each field-specific type well curve represents an average of the historical results of multiple projects over the prior four- year time period. Drive mechanism type curves are the weighted average of the field-specific curves related to the projects chosen for our near-term growth plan. Type curves represent management’s estimates of future results and are subject to project selection and other

• variables. Our type well curves are prepared for purposes of modeling overall results of our near-term growth program and are not useful

for purpose of benchmarking any individual well or pattern performance. Actual results are expected to vary depending on which projects are specifically developed. See the Investor Relations page at www.crc.com for important information about 3P reserves and other hydrocarbon resource quantities,

• rganic finding and development (F&D) costs, organic recycle ratio calculations, organic reserves replacement ratios, original

hydrocarbons in place, Value Creation Index (VCI), drilling locations and reconciliations of non-GAAP measures to the closest GAAP equivalent.