CRC: VALUE-DRIVEN Januar uary Corp rporat ate e Presen entatio - - PowerPoint PPT Presentation

CRC: VALUE-DRIVEN

Januar uary Corp rporat ate e Presen entatio tation

January 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.

January Corporate Presentation | 3

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 growth

• 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

January Corporate Presentation | 4

Positioned for Value-Driven and Sustainable Growth

Value Focu cus

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

The VCI Difference Delivers Real Value

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

frame

• Drives team alignment
• CRC ahead of competitive landscape in

shifting to value

January Corporate Presentation | 5

• 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

January Corporate Presentation | 6

Large Resource Base with Production Diversity

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/d2

26% of basin production 60% of basin mineral acreage

SACRAMENTO BASIN

Gas Optionality

#1 Producer - 5,000 BOE/d2

86% of basin production 85% of basin mineral acreage

VENTURA BASIN

Growth and Exploration

#1 Producer - 6,000 BOE/d2

25% of basin production 90% of basin mineral acreage

LOS ANGELES BASIN

Steady High Margin Oil Assets

#1 Producer - 26,000 BOE/d2

52% of basin production 65% of basin mineral acreage

in Mid-Year 2018 Proved Reserves

Note: Total basin production and CRC’s % of basin production are based on gross FY2017 production. Source: DOGGR. Total basin mineral acreage is based on internal estimates.

Largest Operator in California1

across Operate

135 fields ~12,000 000 wells

with

731 MMBOE3

January Corporate Presentation | 7

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 YE 2014

• 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

• 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

January Corporate Presentation | 8

Unparalleled California Expertise and Insight

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

January Corporate Presentation | 9 $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.

* * *

January Corporate Presentation | 10

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 $6.7

7 Bn5 Infrastructure2

Surface & Minerals3

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

January Corporate Presentation | 11

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

January Corporate Presentation | 12

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

January Corporate Presentation | 13

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.

January Corporate Presentation | 14

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 NINE JVs

January Corporate Presentation | 15

$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

January Corporate Presentation | 16

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 $65 Brent and $3.00 NYMEX.

Oil Oil Oil

January Corporate Presentation | 17

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%

January Corporate Presentation | 18

Demonstrated Experience Controlling Production Costs through Price Cycle

• Keen focus on both alignment of capital

investment and control of production costs

• Monitoring commodity markets to adjust

costs to appropriate level

• Flexible operations allow for cost control

for defense of margins

• Benefits of shallow decline
• Energy costs are variable
• Management has proven it can reduce

production costs to $15/boe

$600 $700 $800 $900 $1,000 $1,100 $1,200 $20 $40 $60 $80 $100 $120

Production Costs ($000) Brent $/Boe

5 years of Production Costs & Capital Investment

Bubbles represent relative size of CRC funded capital investment

2014 (Pre-spin) 2015 2016 2017 2018E*

*2018E Production costs and CRC funded capital investment based on internal estimates, Brent price is average daily close price for 2018

January Corporate Presentation | 19

$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.

January Corporate Presentation | 20

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

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

Capital ($MM) MBoe/d Oil NGL Gas Total Capital* CRC Capital (Internally Funded)

JVs Provide Additional Capital Flexibility

Net Production n By Stream am (Mboe

• e/d)

d)

*Total Capital reflected in the graph includes the capital investment of internal CRC capital as well as all JV partners which include BSP and MIRA. Please note our consolidated financial statements include BSP’s investment and exclude MIRA’s investment based on the accounting treatment of each venture. ** Q4 2018 Capital guidance includes CRC, BSP and MIRA capital. low price scenario mid-cycle scenario

January Corporate Presentation | 21

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

January Corporate Presentation | 22 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

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

January Corporate Presentation | 23 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

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

January Corporate Presentation | 24

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

January Corporate Presentation | 26

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.

January Corporate Presentation | 27 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%

January Corporate Presentation | 28

Accelerating Value and Derisking Inventory through JVs

Highlights:

• Up to $300MM
• Current commitment of $140MM
• DrillCo type structure where Investor

funds 100% of project capital for 90% WI, with CRC carried on its 10% WI

• CRC interest reverts to 75% after

target IRR is achieved

• CRC retains early termination
• ptions
• Focus on four fields within the San

Joaquin Basin

• Kern Front, Mt. Poso, Pleito Ranch,

Wheeler Ridge

• CRC operates all wells

Highlights:

• Up to $250MM over ~2 years
• Three tranches of $50MM
• Total of $150MM funded
• Investor funds 100% of project capital in

exchange for a net profits interest (NPI)

• Investor NPI interest reverts to CRC

after low teens target IRR

• CRC retains early termination
• ptions
• Current focus is in the San Joaquin and

Los Angeles Basin

• CRC operates all wells

January Corporate Presentation | 29

3,000 4,000 5,000 6,000 7,000 2Q15 Debt Exchange for 2L Open Market Purchases Equity for Debt Exchange Cash Tender for Unsecureds Cash & Working Capital 3Q18

Total Debt ($ MM)

Significant Reduction in Total Debt from Post-Spin Peak

Total

Total Debt Reduction $535 million $330 million $102 million $625 million $65 million $1,657 million

• Chose options to maximize deleveraging and minimize recurring cost to the income statement on a per share basis.

Continue to seek opportunistic transactions that reduce overall debt.

5,108

Includes Debt Repurchases of $177MM in YTD 2018

6,7651

January 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

January Corporate Presentation | 31

CRC’s BOE Recovery per Foot Competes With Major Shale Plays

Well l Total l Measur ured Depth h (ft)

6,000’

BOE/ft ft

BV Nose South Valley LA Basin Notes: Source: Wood Mackenzie data for Shale Play areas; Source: Internal estimates for CRC, taking all wells drilled since 2012. BOE calculated as Oil + 20:1 Gas. Well dots sized by oil expected ultimate recovery (MMBOE). Darker colors are newer wells; lighter colors are older wells. Wolfcamp includes Midland and Delaware Basins.

Normalizing estimated ultimate recovery (EUR)

• vs. measured depth shows CRC advantage
• Better recovery factors driven by low decline

rate waterfloods and steamfloods

• Diverse reservoir portfolio provides
• ptionality to drill deep large EUR producers

with later life up-hole recompletions

Historical focus:

• Cheaper, simpler well designs (primarily

vertical)

• Quality reservoirs that do not require

complicated completions or long horizontal Future upside:

• Tighter rock, horizontal drilling with new

generation stimulation, increasing reservoir contact

January Corporate Presentation | 32

✓ 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

January Corporate Presentation | 33

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

January Corporate Presentation | 34

End Notes

From Slide 10

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 1/02/2019. 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.