CRC Corporate Presentation · 1. Cut rig count/began hedging 4. Deleveraging Transactions 2. Cut 2015 Capital Budget 5. Increasing activity, invest within Cash Flow 3. Bank Amendments

CRC Corporate PresentationApril 2018

CRC Corporate Presentation – April 2018 | 2

Forward Looking / Cautionary Statements

This presentation contains forward-looking statements that involve risks and uncertainties that could materially affect our expected results of operations, liquidity, cash flows and

business prospects. Such statements include those regarding our expectations as to our future:

Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. While we believe

assumptions or bases underlying our expectations are reasonable and make them in good faith, they almost always vary from actual results, sometimes materially. We also believe third-

party statements we cite are accurate but have not independently verified them and do not warrant their accuracy or completeness. Factors (but not necessarily all the factors) that

could cause results to differ include:

Words such as "anticipate," "believe," "continue," "could," "estimate," "expect," "goal," "intend," "likely," "may," "might," "plan," "potential," "project," "seek," "should," "target, "will" or "would"

and similar words that reflect the prospective nature of events or outcomes typically identify forward-looking statements. Any forward-looking statement speaks only as of the date on

which such statement is made and we undertake no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise,

except as required by applicable law.

See the Investor Relations page at www.crc.com for important information about 3P reserves and other hydrocarbon resource quantities, finding and development costs, recycle ratio

calculations, and drilling locations.

• financial position, liquidity, cash flows and results of operations

• business prospects

• transactions and projects

• operating costs

• Value Creation Index (VCI) metrics are based on certain estimates

including future production rates, costs and commodity prices

• operations 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

other 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

of 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.

http://www.crc.com/


Value Proposition – Multiple Ways to Increase Valuation

Disciplined Portfolio Management

EBITDAX Growth*Regaining Momentum

Through Increased

Investment

• Increasing CRC

Investments and Deploying

Rigs

• Joint Ventures

• Opportunistic Deleveraging

• Significant Operating

Leverage to Crude Oil

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

400+

0

500

1,000

1,500

2,000

2,500

2017 2018E 2019E 2020E 2021E

$M

M

2017 2018E 2019E 2020E 2021E


CRC’s Large Resource Base with Advantaged Infrastructure

Sacramento Basin

14 MMBOE Proved Reserves

6 MBOE/d production (100% dry gas)

San Joaquin Basin


90 MBOE/d production (58% oil)

Ventura Basin



World-Class Resource 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 to Grow

• 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 optimize 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 Angeles Basin




Largest California Producer with Deep Regional Insight

163

142

122

3021

-

50

100

150

200

CRC Chevron USA Aera Energy Sentinel Peak Berry

Gro

ss O

pe

rate

d M

Bo

e/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

OP

EX

$/B

oe

**

Pro

du

cti

on

Mix

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

MONTEREY

SANDS AND

SHALES

TEMBLOR

SANDS

EOCENE

SANDS AND

SHALES

UPPER

CRETACEOUS

SANDS AND

SHALES

1,0

00

’P

AY

TULARE

SANDS

SH

ALL

OW

DE

EP

ETCHEGOIN

SANDS

<5

,00

0’

15

,00

0’

Top California Producers in 2017*

Majority of CA Production is Shallow*


San Joaquin Basin – An American Super Basin

Overview

• Oil and gas discovered in the late 1800s

• 70% of CRC production is from San Joaquin Basin

• Cretaceous to Pleistocene sedimentary section (>25,000 feet)

• Thermal recovery applied since early 1960s

• Currently running 7 drilling rigs

Key Assets

• 2017 average net production of 90 MBOE/d (58% oil) with <8% YOY decline

• Elk Hills is the flagship asset (~59% of FY 2017 CRC San Joaquin production)

• Two core steamfloods - Kern Front and Lost Hills

• Early stage waterfloods at Buena Vista and Mount Poso

• Substantial, integrated infrastructure that supports Elk Hills

Basin Map

0

2

4

6

0

100

200

300

2015 2016 2017

Avg

. Rig

Co

un

t

Gro

ss W

ells

Dri

lled

Steamflood Waterflood Primary Unconventional Avg. Rig Count

Legend

CRC Land

Oil Field

Gas Field

CRC Operated


Los Angeles Basin – Kitchen is the Entire Basin

Overview

• World-class hydrocarbon-rich sedimentary basin with large quantities of stacked pay

• ~10 billion barrels OOIP in CRC fields

• Kitchen is the entire basin, hydrocarbons did not migrate laterally; basin depth (>30,000 ft)

• Very few penetrations >10,000 ft, leaving deep horizons underexplored

• Focus on mature waterfloods with generally low technical risk and proven repeatable technology across huge OOIP fields

• 2017 average net production of 27 MBOE/d (100% liquids) with a 10% YOY decline and an organic reserves replacement ratio of 330%*

• Over 30,000 net mineral acres

• Major properties are premier coastal development assets of Wilmington and Huntington Beach

• The Wilmington field is subject to contractual agreements similar to production-sharing contracts (PSCs). The contracts represented slightly less than 20% of our total 2017 production.

Wilmington

Huntington Beach

Basin Map

*Organic reserves replacement excludes the effect of price change on reserves volumes0

1

2

0

25

50

2015 2016 2017

Avg

. Rig

Co

un

t

Gro

ss W

ells

Dri

lled

Waterflood Avg. Rig Count

Performed 26 Capital Workover projects in 2017

Legend

CRC Land

Oil Field

Gas Field

CRC Operated


Ventura Basin – Birthplace of the California Oil Industry

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

in California

• ~8 billion barrels OOIP in CRC fields

• Operate 28 fields (over half the fields in the basin)

• ~250,000 net mineral acres (75% undeveloped)

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

• Portfolio of drive mechanisms: Primary, New & Redevelopment Waterfloods and Steamfloods

• Building off exploration success: recent exploration wells have flowed in excess and 1,000 BOE/d (80% oil) along Oak Ridge trend

• Incorporating 10 square miles of 3D seismic into drillable locations

• Significant upside: movable oil, low recovery factor, controlling acreage position and existing infrastructure

• California wildfires in Ventura County impacted December 2017 production by approximately 2,000 BOE/d and production remained affected by approximately 1,000 BOE/d in January 2018

High Growth Area: large OOIP, low recovery

factor and potential for high-IP wells

Field Map

OOIP (MMBO) CUM PROD (MMBO) RF

7,843 813 10%

Legend

Active CRC Field

Idle CRC Field


Sacramento Basin – Significant Gas Optionality

Overview

• 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 Map

0 20

Miles

Legend

CRC Land

Oil Field

Gas Field

CRC Operated


Value Additive Inventory Growth

• Comprehensive technical review of 40% of CRC’s fields.

• 2017 proved reserves of 618 million BOE and 450 million BOE of probable reserves.

• 119% organic reserve replacement, excluding the effect of price adjustments.

• We added 34 million BOE of proved reserves from extension and discoveries and 22 million BOE from performance. We were also able to rebook 49 million BOE due to the increase in prices compared to prior years.

• Organic F&D costs excluding price related revisions was $6.82 per BOE and produced a recycle ratio of 2.1x.

• Over 95% of our total proved reserves have been audited by Ryder Scott in the last three years.

3P Reserves Growth Since Spin

58 109 156

768 644 568618

222 251202

321

340

826

1,129

0

250

500

750

1,000

1,250

1,500

1,750

2,000

2,250

Spin-off 2015 2016 2017

MM

Bo

e

Cummulative Production Proven

Revisions Due to Price Since 2014 Unproven

>350%

Growth

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

http://www.crc.com/


Strategy at a Glance

Value Directed Investments

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

Value

Focus

Live within

Cash Flow

Smart Growth

(per share)

PV10 pre-tax cash flows

PV10 of investmentsVCI =

Enhancing Production

Margin Expansion

Through managing cost and increasing

oil weighting of commodity mix

Live within Cash Flow

Long-TermShort-Term

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

Value Creation Index*


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.

0

5

10

15

20

25

30

$0

$20

$40

$60

$80

$100

$120

07/20/14 10/20/14 01/20/15 04/20/15 07/20/15 10/20/15 01/20/16 04/20/16 07/20/16 10/20/16 01/20/17 04/20/17 07/20/17 10/20/17 01/20/18 04/20/18

CR

C D

rillin

g R

ig C

ou

nt

Bre

nt

Cru

de

Oil P

rice

($

/B

bl)

*

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

3Under

OXY

6

SPIN-OFF

3

3

33

3

44

4

4

6

63


Significant Reduction in Net Debt from Post-Spin Peak

6,7651

4,502

3,000

4,000

5,000

6,000

7,000

2Q15 Debt Exchange for

2L

Open Market

Repurchases

Equity for Debt

Exchange

Cash Tender

for Unsecureds

Cash Flow Ares Transactions PF 4Q17

Tota

l N

et

De

bt

($ M

M)

2

Total

Total Net Debt Reduction$535

million

$153

million

$102

million

$625

million

$59

million

$789

million$2,263 million

1 Represents mid-second quarter 2015 peak debt.2 Includes operating cash flow, positive working capital and proceeds from asset sales in 1H 2017, net of restricted cash.3 Pro Forma net debt at 4Q17 includes the payoff of the 12/31/2017 outstanding balance of $363 million on our RCF and $441 million of available cash after the completion of the Ares transactions.

-

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

Continue to seek opportunistic transactions that reduce overall debt.

3


Strengthening the Balance Sheet - Improved Creditworthiness and Liquidity

Pro-Forma1 Debt Maturities ($MM)*

1 Pro forma debt reflects the payoff of the 12/31/17 outstanding balance of $363 million on our RCF after the completion of the Ares JV. 2 The $441 million of available cash includes (1) $15 million unrestricted cash as of 12/31/17 and (2) $426 million of available cash after the Ares transaction and pro forma repayment of the RCF.

$0

$1,000

$2,000

$3,000

$4,000

2018 2019 2020 2021 2022 2023 2024

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

Revolver Availability

$431

Revolver Availability

$850

Cash $11

Cash $441

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

3Q17 PF 4Q17*

Ava

ilab

ility

($

MM

)

Increased Liquidity

Pro Forma1 Total Debt

$4.9BRevolver Availability

$850MMAvailable Cash2

$441MM


Development Joint Ventures: A Force Multiplier

$154 Million$260 MM Committed

~3.5-4.0 MBoe/dGross Peak Production per

$100 MM of development capital

>12 MMBoePotential Targeted Reserves per

$100 MM of development capital

JVs are generally focused in the San Joaquin Basin

$550 MillionTotal 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 InventoryJVs add production and cashflow,

and help de-risk inventory to

increase CRC’s reserve base


Resilient Resource Base

0

25

50

75

100

125

150

175

200

0

20

40

60

80

100

120

140

160

180

1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 FY

2015

FY

2016

FY

2017

Ca

pit

al ($

MM

)

MB

oe

/d

)

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

Production By Stream (Mboe/d)

MIRA: $58MM BSP: $96MM CRC (Internally Funded): $275MM

Total Capital $401MM $75MM $429MM*Total Capital reflected in the graph includes the capital investment of internal CRC

capital as well as all JV partners which includes BSP and MIRA. Please note our

consolidated financial statements include BSP’s investment and exclude MIRA from

CRC consolidated results based on the accounting treatment of each agreement.


Drilling

24%

Workover

18%BSP JV

Capital

22%

MIRA JV

Capital

14%

Exploration

2%Other1

6%

Development

Facilities

14%

Moved from Defense to Offense – 2017 Review

• CRC 2017 capital plan was directed to oil-weighted projects in our core fields: Elk Hills, Wilmington, Kern Front, Buena Vista, Mt. Poso, Pleito

Ranch, Wheeler Ridge and the delineation of Kettleman North Dome

• JV capital was primarily focused in the San Joaquin Basin

2017 Investment Delivered Solid Returns

Total: $429 million3

1 Other includes maintenance and occupational health, safety and environmental projects, seismic and other investments.2 Facility Costs and other non-return capital are apportioned to producing wells in the year they are drilled.3 Includes capital funded by MIRA, which is not included in our consolidated results.

2017 Total Capital Invested

1.70

2.00

0.00

0.50

1.00

1.50

2.00

2.50

$55 Brent Flat

$3 NYMEX

$55 Brent 2017, $65 Brent

in 2018+ & $3 NYMEX

VC

I

Results of Fully-Burdened2

2017 CRC Development Program

Total: ~$240 million

Other1

~30% IRR* ~45% IRR*

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


Investment Allocation through the Commodity CycleO

il P

rice

$/

BB

L

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


Drilling

JV - Capital

Workover

Development

Facilities

ExplorationOther1Other1

San

Joaquin

Ventura

Los

Angeles

Production Enhancement Plans for 2018

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

Wilmington, Kern Front, Huntington Beach, and continued delineation of Kettleman North

Dome and Buena Vista

• JV capital will be focused in the San Joaquin Basin and Huntington Beach

• We have a dynamic plan that can be scaled up or down depending on the price environment

and efficient deployment of joint venture proceeds

2018 Capital Investment Program – Living Within Cash Flow

Approx. $425 to $450 million

1Other includes maintenance and occupational health, safety and

environmental projects, seismic and other investments.

2018E Total Capital Plan 2018E Drilling Capital – By Drive

28%

30%

22%

12%

4%4%

10%

10%

Conventional

ExplorationWaterfloods

Steamfloods

Unconventional

42%

6%30%

16%

80%

The JV capital increases

flexibility or provides for

incremental deleveraging

Approx. $250 million Approx. $250 million

6%

2018E Drilling Capital – By Basin


Deep Inventory of Actionable Projects at $65

Portfolio Spectrum

• Growth portfolio focus, fully

burdened

• 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.

0

2

4

6

8

10

0 100 200 300 400 500 600 700 800Deve

lop

me

nt

Ca

pit

al ($

B)

Net Resources3 (MMBoe)

0

5

10

15

20

25

30

35

40

45

50

0 100 200 300 400 500 600 700 800

Fu

ll C

ycle

Co

st2

($/B

oe

)

Net Resources3 (MMBoe)

Steamflood

Waterflood

Primary

Shale

Gas

http://www.crc.com/


Strong Returns Through the Commodity Cycle

Gas

Take advantage of dominant

position in the basin. Invest in

Sacramento Gas Projects.

Primary Shale

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

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

Total LOF Actionable Near Term Growth

Focus on lower operating costs. Invest

in steam floods above 5x Oil/Gas

Ratio.

Steamflood Waterflood

Gas Price

Oil Price

Gas Price

Oil Price

Gas Price

Oil Price

Gas Price

Oil Price

Oil/Gas Price Ratio

Optimum Investment

Range

CRC has a strong portfolio of actionable projects that

can thrive in varying commodity price environments

Gas Price

Oil Price


Midstream JV Provides Optionality to Create Maximum Value

Invest in

Resources

Reduce Debt

• $750MM Mid-Stream Joint Venture

• Includes Elk Hills power plant, gas processing assets and related non-

borrowing base infrastructure


0.9

1.0

1.1

1.2

1.3

1.4

1.5

1.6

1.7

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

PR

OJE

CT V

CI

DISCOUNT ON SECOND LIEN NOTES

PROJECT VS. SECOND LIEN (2L) NOTE REPURCHASE*

INVEST If the VCI of an investment opportunity falls above the indifference

curve, investing in the new project could be a better option

PURCHASE DEBTIf the VCI of an investment opportunity falls

below the indifference curve, repurchasing

2L notes could be a better option

Example of Investment Alternatives for Asset Sale Proceeds

Per the terms of the 2014 credit agreement on

asset sales, 2L notes must be repurchased at a

minimum 20% discount to par

Indifference Curve

*CRC will continue to review all opportunistic debt reduction transactions. We utilize VCI to guide management in allocating capital and prioritizing investments. Please see end notes for how we calculate VCI.


70

80

90

100

110

120

130

140

2017 2018E 2019E 2020E 2021E

Oil P

rod

ucti

on

MB

/d

400

800

1,200

1,600

2,000

2017 2018E 2019E 2020E 2021E

EBIT

DA

X $

MM

Portfolio Flexibility Provides Range of Crude Oil Scenarios

Note: Scenarios assume flat pricing from $55 to $75 Brent and $3.00 to $3.10 NYMEX gas, respectively. Assumes lease operating costs are equal to 2017 levels for the mid-point of the range of planning scenario outcomes. Ranges of portfolio planning scenario outcomes

assume development of a variety of combinations of steamflood, waterflood, conventional and unconventional projects in our inventory and reflect estimates of geologic, development and permitting risk. All discretionary cash flow reinvested in business for each scenario.

EBITDAX calculation for all estimated periods reflects a reduction from associated payments to Ares based on our JV agreement. Please note that beginning in 2018 these charges will be incorporated after our calculation for net income on our consolidated financial

statement due to the accounting treatment of non-controlling interests.

* See the Investor Relations page at www.crc.com for a description of the calculation of debt-adjusted per share and other important information.

Combined with mid-cycle commodity

prices, we are positioned for growth in:

• Cash flow

• Production

• Reserves

on a debt-adjusted per share basis* Portfolio

Planning

Scenarios

Portfolio

Planning

Scenarios

Capital focused on oil projects that provide

Increasing

Margins

Low

Decline Rates

Compounding

Cash Flow+ =

-

Estimated Crude Oil Production Outcomes

≈

0

300

600

900

1,200

1,500

2017 2018E 2019E 2020E 2021E

Ca

pit

al ($

MM

) Estimated Ranges of Capital Investments

Estimated Range of EBITDAX Outcomes

(Inclusive of Ares payment)

-≈

http://www.crc.com/


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 on commodity price and market conditions

0%

25%

50%

75%

FY 2015 FY 2016 FY 2017 2017

Reserves

% O

il M

ix

Oil NGL Gas Blended

Realized Price*

2017 Production Mix 64% 12% 24% $41.09

2017 Proved Reserves

Mix72% 9% 19%

*Includes effects of settled hedges


PDP Value

Proved Value

Unproved4

$0

$4

$8

$12

$16

$20

$55 Brent $65 Brent $75 Brent

($B

illio

n)

2017 Reserves Value1 In Excess EV

Current EV

of $5.1 Bn5

Infrastructure2

Surface & Minerals3

1-5 See endnotes in the Appendix.

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

http://www.crc.com/


Project Inventory Drives Organic Deleveraging

Note: All cases are self-funding. Capital program in all cases assumes discretionary cash flow is reinvested. Assumes lease operating costs on an absolute basis are flat to 2017 levels for the mid-point case of

the range of portfolio planning scenario outcomes. EBITDAX calculation for all estimated periods reflects a reduction from associated payments to Ares based on our JV agreement. Please note that beginning in

2018 these charges will be incorporated after our calculation for net income on our consolidated financial statement due to the accounting treatment of non-controlling interests.

Estimated Leverage Ratios

0.0x

2.0x

4.0x

6.0x

8.0x

10.0x

2016 2017 2018E 2019E 2020E 2021E

Tota

l D

eb

t/LT

M E

BIT

DA

X

$55 $65 $75


0

500

1,000

1,500

2,000

2,500

2017 2018E 2019E 2020E 2021E

$M

M

The Case for CRC: Investment Thesis Overview

Grow within

cash flow

Industry leading

decline rate

Integrated and

complementary

infrastructure

Maintain

Production

Production and

Cash Flow Growth

Production Innovation Deep Inventory

Investment Case for CRC

World-class assets

with significant

inventory

Resilient model that

preserves optionality

and protects downside

Focused on value

and poised for

growth

Moved from defense to offense

Why Own CRC Now

Competitive Advantages

Disciplined portfolio management Potential for EBITDAX growth*

Clear runway and

available cash

-2017 2018E 2019E 2020E 2021E

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

APPENDIX


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

Bo

e/d

Base Incremental

LBU PSC

-

2,000

4,000

6,000

8,000

10,000

12,000

2006 2008 2010 2012 2014 2016B

oe/

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


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

Mb

oe

pd

$Brent

Total Production @ $ Brent Price

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

$100

$M

M

$Brent

Total Revenue @ $ Brent Price

Wilmington PSC Illustration

Net Profit Barrels

NPI Barrel Revenue

45% Share of Gross Production

Variable with Price

Cost Recovery BarrelsVariable with price

Cost Recovery RevenueFixed revenue from cost recovery of

the State & City of Long Beach

share of costs

Gross Production

CRC pays ~90% of gross costs (capital investments, OPEX, tax and overhead) up front and recovers our partners ~46%

share (State/City of LB) of these costs in the form of offsetting Revenues


$3.26 $3.14 $2.95 $3.00

$2.75 $2.42

$3.09

$2.90

$2.47 $2.56 $2.77 $2.66

$2.28 $2.67

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

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

$/

Mc

f

NYMEX Realizations

CRC – Price Realizations

66% 62%

72%79%

40%

52%

70%

63%59%

66%

72%

37%

50%

65%

0%

20%

40%

60%

80%

100%

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

% o

f W

TI

& B

ren

t

WTI Brent

$51.91

$48.29

$48.21

$55.40

$48.80 $43.32

$50.95

$50.24 $47.98

$50.02

$56.92

$49.19

$42.01

$51.24

$54.66 $50.92

$52.18

$61.54

$53.64

$45.04

$54.82

30

40

50

60

70

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

$/B

bl

WTI Realizations Brent

Realization %

of WTI97% 99% 104% 103% 101% 99% 101%

Realization %

of NYMEX89 % 79% 87% 92% 97% 94% 86%

Oil Price Realization (with Hedges) Gas Price Realization

NGL Price Realization - % of WTI & 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.

-≈


2014 Revolving Credit Facility Capacity -

$1 billion

Updated Capital Structure from Recent Transactions – Improved Liquidity

2017 Term Loan - $1.3 billion

2016 Term Loan - $1 billion

2015 Second Lien - $2.25 billion

Unsecured Notes - $0.393 billion

Drawn Revolver

$837

$0

$250

$500

$750

$1,000

3Q17 PF 4Q17*

($M

M)

Revolver

Availability

$431

Revolver

Availability

$850

Cash $11

Cash $441

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

3Q17 PF 4Q17*A

vaila

bilit

y ($

MM

)

Increased Liquidity**

* Pro Forma for the Ares JV and $50mm private placement

** Subject to minimum liquidity requirement under 2014 Revolving Credit Facility. Includes unrestricted cash.

Reduced Revolver Borrowing

Added in

NovemberDe

bt

Hie

rarc

hy

Undrawn

Revolver


$100

$100

$193

$2,250

$1,000

$1,300

$0$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500

$4,000

Se

p-1

7

De

c-1

7

Ma

r-1

8

Jun

-18

Se

p-1

8

De

c-1

8

Ma

r-1

9

Jun

-19

Se

p-1

9

De

c-1

9

Ma

r-2

0

Jun

-20

Se

p-2

0

De

c-2

0

Ma

r-2

1

Jun

-21

Se

p-2

1

De

c-2

1

Ma

r-2

2

Jun

-22

Se

p-2

2

De

c-2

2

Ma

r-2

3

Jun

-23

Se

p-2

3

De

c-2

3

Ma

r-2

4

Jun

-24

Se

p-2

4

De

c-2

4

2014 RCF

2017 Term Loan

2016 Term Loan

2nd Lien Notes

Unsecured Notes

Strengthening the Balance Sheet - Improved Creditworthiness and Liquidity

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

• CRC received $797 million in net proceeds, $8mm of which is restricted cash

• The RCF was paid in full

• The RCF has approximately $850 million of available borrowing capacity, excluding

$150 million minimum liquidity

• The recent amendment extends the maturity of the RCF to June 2021 and relaxes

financial covenants

1st Lien 2014 Revolving Credit Facility (RCF) -

1st Lien 2017 Term Loan 1,300

1st Lien 2016 Term Loan 1,000

2nd Lien Notes 2,250

Senior Unsecured Notes 393

Total Debt 4,943

Less cash2

(441)

Total Net Debt 4,502

Equity3

(764)

Total Net Capitalization 3,738

Total Net Debt / Total Net Capitalization 120%

Total Net Debt / LTM Adjusted EBITDAX4

5.9x

LTM Adjusted EBITDAX4

/ LTM Interest Expense 2.2x

PV-105 / Total Net Debt 1.0x

Total Net Debt / Proved Reserves ($/Boe) $7.28

Total Net Debt / Proved Developed Reserves ($/Boe) $10.23

Total Net Debt / 2017 Production ($/Boepd) $34,899

Pro-Forma1 Capitalization ($MM)

Pro-Forma1 Debt Maturities ($MM)*

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

of $363 million on our RCF after the completion of the Ares JV and $50 million private placement. 2 The $441 million of available cash includes (1) $15 million unrestricted cash as of 12/31/17 and (2) $426

million of available cash after the Ares transaction and proforma repayment of the RCF.3 Excludes noncontrolling interest at 12/31/17 and includes $50 million of equity from the Ares private placement.4 See www.crc.com, Investor Relations for a reconciliation to the closest GAAP measure and other important

information.5 PV-10 as of 12/31/17, see Attachment 2 of CRC’s Fourth Quarter Earnings Release dated February 26, 2018 for

details on this calculation.

* Previously, the RCF, the 2017 Term Loan and the 2016 Term Loan were subject to springing maturities related to the 2020

and 2021 Notes. During the fourth quarter of 2017, CRC repurchased $65 million in principal amount of the 2020 Notes and

$35 million in principal amount of the 2021 Notes, which eliminated those springing maturities. The 2017 Term Loan remains

subject to a springing maturity related to the 2016 Term Loan.

Undrawn RCF


2Q 2018 3Q 2018 4Q 2018 1Q 2019 2Q 2019

Sold Calls Barrels per Day 6,200 6,100 16,100 16,100 6,000

Weighted Average Ceiling

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

Purchased Calls Barrels per Day - - - 2,000 -

Weighted Average Ceiling

Price per Barrel- - - $71.00 -

Purchased Puts Barrels per Day 1,200 6,100 1,100 24,100 11,000

Weighted Average

Floor Price per Barrel45.83 $61.47 45.85 $60.00 $60.05

Sold Puts Barrels per Day 29,000 24,000 19,000 25,000 5,000

Weighted Average

Floor Price per Barrel$45.00 $46.04 $45.00 $49.00 $50.00

Swaps Barrels per Day 44,400 19,000 19,000 7,000 -

Weighted Average

Price per Barrel$60.00 $60.13 $60.13 $67.71 -

Percentage of 4Q 2017

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

Opportunistically Built Oil Hedge Portfolio

As of 3/30/2018. Certain of our counterparties have options to increase swap volumes at weighted average costs between $60 and $70 Brent.

* Assumes future counterparty options are not exercised.

We target hedges

on 50% of crude

oil production

Strategy Protect cash flow for capital investments and covenant compliance


Elk Hills Area – CRC’s Flagship Asset

Integrated Infrastructure

• 610 MMcf/d processing capacity through 4 gas plants

• Including California’s largest

• 3 CO2 removal plants

• Over 4,500 miles of gathering lines

• 45 MW cogeneration plant

• 550 MW power plant

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

-

5

10

15

20

0

20

40

60

80

100

120

1998 2000 2002 2004 2006 2008 2010 2012 2014 2016

Rig

Co

un

t

Ne

t M

BO

E/d

Net MBOEPD Rig Count

Overview

• 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)

Field Map

Production History

Large fee property position

with integrated infrastructure


Buena Vista Area – Highly Prospective Area

FIELDMAP

Overview

• Includes Buena Vista (BV) Hills and BV Nose

• JV capital applied to infill development program that led to improved operational 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

0

10

20

30

40

2012-14 2017

Dri

llin

g T

ime

Da

ys/

we

ll

5.0

2.5

0

100

200

300

400

500

-

1.0

2.0

3.0

4.0

5.0

6.0

2012-14 2017

Dri

llin

g C

ost

$/

Ft

Dri

llin

g C

ost

$M

M/

we

ll

Drilling Cost/Well Drilling Cost $/Ft

2017 Conventional BV Nose Development

Drilling Cost Average Drilling Days/Well2017 BV Area development

program delivers a 1.8 VCI

at a $55 Brent price deck


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

-50%

-40%

-30%

-20%

-10%

0%

10%

20%

30%

40%

Year 1 Year 2 Year 3 Year 4 Year 5

Normalized Decline Rates

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

Source: Data from Wood Mackenzie, CRC analysis

Recent wells in the onshore Lower 48 are

showing steeper declines

-

1,000,000

2,000,000

3,000,000

4,000,000

5,000,000

6,000,000

7,000,000

2009 2010 2011 2012 2013 2014 2015 2016

Pro

du

ctio

n (

BO

PD

)

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


0%

10%

20%

30%

40%

50%

1 Year Decline

Median: 29%

Best In Class Corporate Decline Rates

0%

10%

20%

30%

40%

50%

60%

70%

80%

3 Year Decline

Median: 49%

CRC

CRC

Peers included: CLR, COG, CPE, CXO, DNR, EGN, EOG, EPE, FANG, HK, LPI, MRO, MTDR, MUR, NFX, OAS, PDCE, PE, PXD, QEP,RRC, RSPP, SM, SN, WLL,WPX, and XEC.

Source: Wood Mackenzie - Operated Production Data through 2016, CRC analysis.

FY 2016 Production Percentage Liquids

Less than 55% 55% - 75% Greater than 75%


(3,000)

(2,500)

(2,000)

(1,500)

(1,000)

(500)

-

500

1,000

Un

leve

red

Fre

e C

ash

Flo

w (

$M

M)

CR

C

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


Accelerating Value and Derisking Inventory through JVs

Highlights:

• Up to $300MM

― Initial commitment of $160MM

• DrillCo type structure where Investor funds

100% of project capital for 90% WI, with

CRC carried on its 10% WI

― CRC interest reverts to 75% after

target IRR is achieved

― CRC retains early termination options

• Focus on four fields within the San Joaquin

Basin

― Kern Front, Mt. Poso, Pleito Ranch,

Wheeler Ridge

• CRC operates all wells

Highlights:

• Up to $250MM over ~2 years

― Two tranches of $50MM

― Total of $100MM funded

• Investor funds 100% of project

capital in exchange for a net profits

interest (NPI)

― Investor NPI interest reverts to

CRC after low teens target IRR

― CRC retains early termination

options

• Current focus is in the San Joaquin

Basin

• CRC operates all wells


-

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 100103106109112115118JV Share Typical E&P Share

Typical Industry JV Structure

• Based on recent industry JV deals, a typical deal structure is

o Partner pays 80-100% Capital

o Receives 80-100% Working Interest

o Typical hurdle rate:o 10% - 20% IRR

o Partner’s working interest once hurdle rate is achieved:o 5% - 25%

Hurdle Rate

Reached

Pro

du

cti

on

Time


Strategic Partner Alignment

Summary of Deal

Partner ▪ Affiliate of Ares Management (Ares)

Contributed

Assets▪ Elk Hills power plant, gas processing assets and related non-borrowing base

infrastructure currently owned by CRC

Midstream JV

Capitalization

▪ Class A common interests (voting) owned 50% by Ares and 50% by California

Resources Elk Hills (CREH)

▪ Class B preferred interests (“Preferred”) owned 100% by Ares

▪ Class C common interests (distributing) owned 95.25% by CREH and 4.75% by Ares

Distribution to

Partners

▪ Preferred interests to receive distributions of 13.5% per annum on the $750 MM

contributed amount

▪ 9.5% cash pay and 4.0% PIK to be deferred for the first three years

▪ Deferred distributions are interest bearing and repaid over two years following the

deferral period

▪ Remaining cash after preferred distributions to be distributed pro rata to Class C

interests

Exit Provisions

▪ Prior to end of 5 or 7.5 years, CRC may redeem Preferred at variable amounts that

include make whole premiums

▪ At end of 5 years, CRC may elect to either redeem or extend to 7.5 years

▪ At 7.5 years, if not redeemed by CRC, Preferred can monetize the JV

Board▪ Board of Managers to consist of three CRC representatives and three

representatives from Ares


CRC 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


Dynamic Portfolio Provides Flexibility

0

200

400

600

800

BO

EP

D

YEAR 5

0

200

400

600

800

BO

EP

D

YEAR 5

Gas

0

200

400

600

800

BO

EP

D

YEAR 5

0%

25%

50%

75%

100%

Po

rtfo

lio

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 OilGas


0

25

50

75

100

0 1 2 3 4

BO

PD

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.

PA

RA

ME

TER

S

PE

R P

ATT

ER

N 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

SunsetMcKittrick

McDonald

Anticline

Kern Front

Lost HillsN. 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

$ B

RE

NT

$60 1.6 1.7 1.8


0

15

30

45

60

0 1 2 3 4

BO

EP

D

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

$ B

RE

NT

$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.


Plan Locations

PA

RA

ME

TER

S

PE

R P

ATT

ER

N Operating

Expense

$19/BOE

Capital

Cost*

$1.2MM

Total EUR

(MBOE)

190

Peak Rate

(BOEPD)

35

Drilling

Time (days)

10

Royalty

12.5%


0

40

80

120

160

0 1 2 3 4

BO

EP

D

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.


PA

RA

ME

TER

S 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

$ B

RE

NT

$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


Plan Locations


PA

RA

ME

TER

S 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

$ B

RE

NT

$60 1.9 2.1 2.2

0

150

300

450

600

750

900

0 1 2 3 4

BO

EP

D

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

PalomaRio Viejo

CRC PRIMARY



Plan Locations


California Shale Type Well

Asphalto

Elk Hills

Buena Vista

Kettleman

Rose

N. Shafter

Gunslinger

Railroad Gap

CRC SHALE

-

100

200

300

400

500

0 1 2 3 4

BO

EP

D

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

$ B

RE

NT

$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


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%

4% 2% WATER MANAGED 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.


End Notes

1 Current CRC estimate of reserves value as of December 31, 2017. Includes field-level operating expenses and G&A. Assumes

$3.00/MMBTU NYMEX.

2 Reflects the value of facilities and midstream assets at 50% of estimated replacement value. This discount is estimated to exceed

the burden on reserves that would be incurred if assets were monetized. Excludes the value of the assets monetized in the Ares

transaction.

3 Surface & Minerals reflect the estimated value of undeveloped surface and minerals held in fee.

4 Unproved inventory comprises risked probable and possible reserves and contingent and prospective resources. Contingent and

prospective resources consist of volumes identified through life-of-field planning efforts to date.

5 Calculated using Pro Forma debt post Ares transaction and market cap as of March 16, 2018.

Type Curve Note: Each field-specific type well curve represents an average of the historical results of multiple projects over the prior

four-year time period. Drive mechanism type curves are the weighted average of the field-specific curves related to the projects

chosen for our near-term growth plan. Type curves represent management’s estimates of future results and are subject to project

selection and other variables. Our type well curves are prepared for purposes of modeling overall results of our near-term growth

program and are not useful for purpose of benchmarking any individual well or pattern performance. Actual results are expected to

vary depending on which projects are specifically developed.

Value Creation Index (VCI) Note: VCI is calculated by dividing the net present value of the project’s expected pre-tax cash flow over its

life by the net present value of project investments, each using a 10% discount rate

Documents

CRC Corporate Presentation · 1. Cut rig count/began hedging 4. Deleveraging Transactions 2. Cut 2015 Capital Budget 5. Increasing activity, invest within Cash Flow 3. Bank Amendments