crc: value-driven...november corporate presentation | 11 $0 $120 $240 $360 $480 $20 $50 $80 $110...

CRC: VALUE-DRIVENNOVEMBER CORPORATE PRESENTATION

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

• operating costs

• Value Creation Index (VCI) metrics, which 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

• 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.

http://www.crc.com/


The VCI Difference Delivers Real Value

Value

Focus

PV10 pre-tax cash flows

PV10 of investmentsVCI =

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


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


Key Highlights

136 Mboe/d62% 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

PRODUCTION131 Mboe/d62% 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

1 Includes JV and non-operated wells.2 Includes JV capital.3 Core Adjusted EBITDAX excludes the effect of settled hedges of $79 million in the third quarter and $178 million in the first nine months,

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.

http://www.crc.com/


- 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 opportunity set

• Robust infrastructure turns disparate fields into integrated plays


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




VENTURA BASINGrowth and Exploration




LOS ANGELES BASIN

Steady High Margin Oil Assets




in Mid-Year 2018

Proved Reserves

1 CRC production based on 3Q18.2 Proved reserves at $75 Brent / $3 Nymex.

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 wells

with

731 MMBOE2


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

of 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

58 109 156 179

768 644 568618

731

222 251226

175171

181431

450458

150

159

395

679699

0

250

500

750

1,000

1,250

1,500

1,750

2,000

2,250

2,500

2014 2015 2016 2017 1H18

MM

Bo

e

>250%

Unproven

Growth

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

hydrocarbon quantities.2 Reserve amounts uneconomic at SEC prices for the applicable year.3 Unproven reserves (probable and possible) utilize similar price assumptions as of 2014 ($101.30 Brent). Proven

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

Probable3Price-Contingent

Reserves2

ProvedCumulative

Production

Possible3

http://www.crc.com/


0

5

10

15

20

25

30

35

40

45

50

0 100 200 300 400 500 600 700 800 900 1,000Fu

ll C

ycle

Co

st1

($/B

oe

)Net Resources2 (MMBoe)

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

1 Full cycle costs = operating costs + development costs + facility costs + field-level G&A + taxes other than on income.2 See the Investor Relations page at www.crc.com for details regarding net resources.

Steamflood

Waterflood

Primary

Shale

Gas

0

3

6

9

12

0 100 200 300 400 500 600 700 800 900 1,000

Dev

Cap

ital

(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

opportunistically targeting

new infrastructure

investment

http://www.crc.com/


$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

$/M

cf

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

% o

f W

TI

& B

ren

t

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

$/B

bl

WTI Realizations Brent

Realization

% of WTI104% 103% 100% 94% 92%

Realization %

of NYMEX87% 92% 98%* 82%* 110%*

Oil Price Realization (with Hedges) Gas Price Realization

NGL Price Realization - % of WTI & Brent

CRC believes near-term crude oil

differentials will remain strong

• California refinery demand for native crude continues to be strong

and reduction in heavy waterborne crude has positively influenced

differentials.

• Natural gas prices impacted by 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.

*

*

*


$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

Qu

arte

rly

Cap

ital

($

MM

)

Bre

nt

Cru

de

Oil

Pri

ce (

$/B

BL)

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


Dynamic Capital Allocation Through Commodity Cycle

High-Price Scenario

Mid-Cycle Scenario

Low-Price Scenario

Oil

Pri

ce $

/B

BL

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%Mature

Projects

25%Growth

Projects

Over

$1.5B

50%Mature

Projects

50%Growth

Projects

90%Mature

Projects

10%Growth

Projects


CRC’s Dynamic Portfolio Provides Flexibility

0

200

400

600

800

BO

EP

D

YEAR 5

0

200

400

600

800

BO

EP

D

YEAR 5

0

200

400

600

800

BO

EP

D

YEAR 5

0%

25%

50%

75%

100%

Po

rtfo

lio

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


$85

$85

$75

$65

Strategic Development Joint Ventures – BSP & MIRA

~$240 MillionInvested Through

Q3 2018

~3.5-4.0 MBoe/dGross Peak Production

per $100 MM of

Development Capital

>12 MMBoePotential Targeted

Reserves per $100 MM

of Development Capital

$550 MillionTotal Potential

JV Capital

Portfolio Flexibility

and Optionality

Enable High Margin

Production Growth

Accelerate Value

De-Risk Inventory

2018 2019 2020 2021 2022 2023

Reversion Estimates

$75

$65

Estimated Last Date

of BSP Capital

Investment

Estimated Last Date

of MIRA Capital

Investment

Note: Price scenarios assume Brent pricing.


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

Decadesof 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.

163142

122

3018

-

50

100

150

200

CRC Chevron USA Aera Energy Sentinel Peak Berry

Gro

ss O

pe

rate

d M

BO

E/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

OP

EX

$/B

OE

Pro

du

cti

on

Mix

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

Top California Producers in 2017

Majority of CA Production is Shallow


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


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


Applying CRC asset playbook to substantial

drilling inventory extends core Elk Hills

operations and infrastructure

Developing Entire Southern San Joaquin Basin into Core Area

Field AreaOriginal MMBOE

in PlaceRf 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.

http://www.crc.com/


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%

1 Partner WI funding varied by well; 2 $75 Brent and $3/NYMEX; 3 Net P50 NPV10 = Sum [P50 type curve NPV10 x NRI] for development locations; 4 VCI = 1+ [net P50 NPV10] / [PV10 exploration and development capital]

SIGNED SEVEN

JVs


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

To

tal D

eb

t / A

dj. E

BIT

DA

X1

Leverage Core Adjusted EBITDAX Leverage

Target 2x-3x Leverage Ratio

Complicated

Capital Structure

Simplified

Capital

Structure

Continue to Employ

ALL of the ABOVE Approach

Capital MarketsSolutions

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

1See the Investor Relations page at www.crc.com for a reconciliation to the closest GAAP measure and other important

information. Core Adjusted EBITDAX excludes settled hedges and cash settled equity compensation costs.23QYTD annualized.3Subject to limitations on debt repayment in finance agreements.

1

Accretive

acquisitions

Cash flow growth

and support future

reinvestment

2

http://www.crc.com/


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

Capitalization ($MM)

1 Excludes $13MM of restricted cash.2 Includes $120 million of noncontrolling interest for BSP and Ares.3 LTM Adjusted EBITDAX includes an estimated adjustment of +$27.5 million for both 4Q17 and 1Q18

as a result of the Elk Hills transaction.4 Proved Reserves and PV-10 estimates are based on mid-year reserves at $75 Brent / $3 Nymex. See

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

2

$0

$1,000

$2,000

$3,000

$4,000

2018 2019 2020 2021 2022 2023 2024

2nd Lien Notes

2014 RCF

Unsecured Notes

2016 Term Loan

2017 Term Loan

Debt Maturities ($MM)

Highlights

• 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+

http://www.crc.com/


Disciplined Capital Plan Leverages Portfolio of Projects and Management Expertise

Core ProgramBuena Vista

Elk Hills

Long Beach

Kern Front

Mount Poso

Growth/Appraisal

ProgramSouth 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%Facilities

5%Exploration

3%Other Ventures

12%Workover

30-40%Core

20-30%Growth

2019 Expected Capital Allocation

and Expected Outcomes


80

90

100

110

120

130

2018E 2019E 2020E 2021E 2022E

Oil

Pro

du

ctio

n

(MB

/d)

600900

1,2001,5001,8002,1002,4002,700

Ad

just

ed E

BIT

DA

X

($M

M) ~16% Midpoint Adj.

EBITDAX3 CAGR

Cash-Neutral Scenarios Targeting Double-Digit EBITDAX Growth

~7% Midpoint

Production CAGR

1Subject to limitations on debt repayment in finance agreements.2 See the Investor Relations page at www.crc.com for a description of the calculation of the debt-adjusted per share basis and other important information.3 See the Investor Relations page at www.crc.com for a reconciliation to the closest GAAP measure and other important information.

Note: Scenarios assume flat pricing from $65 to $85 Brent and $3.00 to $3.10 NYMEX gas, respectively. Assumes varying lease operating costs within historical ranges depending on the commodity prices of the planning scenario outcomes. Ranges of portfolio planning

scenario outcomes assume development of a variety of combinations of steamflood, waterflood, conventional and unconventional projects in our inventory and reflect estimates of geologic, development and permitting risk. Assumes 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.

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

Portfolio

Planning

Scenarios

Portfolio

Planning

Scenarios

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

-≈

≈

0

500

1,000

1,500

2,000

2,500

2018E 2019E 2020E 2021E 2022E

Cap

ital

($

MM

) Estimated Ranges of Capital Investments

http://www.crc.com/

http://www.crc.com/


Continuous Efforts Provide Pathway to Reasonable Leverage

1 See the Investor Relations page at www.crc.com for a reconciliation to the closest GAAP measure and other important information. Core Adjusted EBITDAX excludes settled hedges and cash settled equity

compensation costs.2 3QYTD annualized.

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

Tota

l D

eb

t/A

dj. E

BIT

DA

X1

$65 $75 $85 Core Adj. EBITDAX Leverage

2

1

http://www.crc.com/


Current Enterprise Value Deeply Discounted

PD

PUD

Unproved4

$0

$4

$8

$12

$16

$20

$24

$28

$65 Brent $75 Brent $85 Brent

Va

lue

($

Billio

n)

1

1

Current EV

of $7.3 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/


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

of high value

growth projects

VALUE 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

Pri

ce $

/B

BL

Gas Price $/MCF

$

Balance capital investment with

financial strengthening efforts for best

long-term value creation

Deep operational

knowledge and

technical expertise

APPENDIX


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

1Other includes maintenance and occupational health, safety and environmental projects, seismic, and other investments.

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

Angeles46%

14%

14%

22%

3%

Conventional

Waterfloods

Steamfloods

Unconventional

46%

31%

13%

10%

67%

5%

28%

1%


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. 1F&D, recycle ratio and free cash flow are based on information provided by CapIQ and differ in

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)

0

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

http://www.crc.com/


Summary of Mid-Year 2018 Reserves Changes

1 Organic F&D including the effect of the Elk Hills acquisition.2 Includes transfers, revisions, exploration and development and improved recovery. 58 MMBOE “Technical” proven reserves in contingent replacement due to economics and/or 5-year rule

limitations.3 RRR refers to organic reserves replacement ratio.4 Proved reserves at $75 Brent / $3 Nymex.

CRC Reserves Changes (Net MMBOE)

Reserve

Category

YE 2017

Balance

Price

Related

Revision

1H 2018

ProductionChanges2

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 0 (2) 18 203 1,691 1,546

Proved4 618 50 (23) 23 64 731 96% 15 11,386 11,643

731 MMBOEProved 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


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

CallsBarrels 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 Downside57% 54% 48% 48% 42% 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,

operating margins

and capital

investment program


Da

ily S

oC

alG

as n

atu

ral

ga

s in

ve

nto

rie

s

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


✓ 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

0

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


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 BasinOakridge Lease, Ventura

Bolsa Chica Reserve,

Huntington Beach


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

0

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

Gro

ss B

OE

/d

Buena Vista

25% CAGR

Preservation

of capital



• World-class waterflood


▪ 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

0

50

100

150

200

YE14 Production Price-RelatedRevisions

E&D & TechRevisions

1H18

Pro

ved

MM

BO

E

LA Basin Reserves Higher than at Spin

1 1H18: 170 MMBOE proved, 80 MMBOE probable, 40 MMBOE possible2 at $75 Brent and $3.00 Nymex price

2

Small footprint to access vast resources


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


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 greaterthan 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

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


Renewed Investment in Analog Field

• Large underdeveloped field


▪ 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

0

2,000

4,000

6,000

8,000

Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18

Gro

ss B

OE

/d

Huntington Beach

Preservation

of capital20% CAGR


Deliver new value in fields drilled over decades


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 VCI0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

Jan-17 Jan-18 Jan-19 Jan-20

Gro

ss B

OE

PD

Workover Program

2017 Program 2018 Program

estimated

production

Continuous drilling program leads

to additional locations, approx. 4.4

million reservoir-ft behind pipe


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


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

GRIMES

14,000 mcfd

1.1 TCF cum

RIO VISTA

15,000 mcfd

3.8 TCF cum

WILLOWS

7,500 mcfd

650 BCF cum

THOMPKINS HILL

1,000 mcfd

125 BCF cum

LATHROP

3,000 mcfd

700 BCF cum

TULAINYO PROJECT

50 sq mile, 4-way

closure

Stacked gas sands,

deep oil potential


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

20

18

20

20

20

22

20

24

20

26

20

28

20

30

20

32

20

34

20

36

20

38

20

40

20

42

20

44

20

46

Net

BO

PD

Elk Hills Project Initiation

Stevens CO2 Wedge

Base


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%

1 Partner WI funding varied by well; 2 $75 Brent and $3/NYMEX; 3 Net P50 NPV10 = Sum [P50 type curve NPV10 x NRI] for development locations; 4 VCI = 1+ [net P50 NPV10] / [PV10 exploration and development capital]

SIGNED SEVEN

JVs


Example Life Cycle of Wellbore with Stacked Reservoirs

1

2

3

1

3

2

NPV 10 ($MM) IRR (%) VCI

A

B


0%

5%

10%

15%

20%

25%

30%

0

50

100

150

200

250

300

350

400

450

0 5 10 15

Re

co

ve

ry F

acto

r

BO

EP

D

years

Primary Workover Water Flood Recovery

2

3

Example Life Cycle of Wellbore with Multiple Recoveries

1

3

1

2

NPV 10 ($MM) IRR (%) VCI


• 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/BOEDifferentials/Marketing

Cash Margin

19% of CRC 2017 production from

steamfloods

58%

TEMBLOR

SANDS

EOCENE

SANDS AND

SHALES

UPPER

CRETACEOUS

SANDS AND

SHALES

MONTEREY

SANDS AND

SHALES

1,0

00

’P

AY

TULARE

SANDS20

40

200

50

40

50

SH

ALL

OW

DE

EP

ETCHEGOIN

SANDS

# o

f S

tack

ed

Re

se

rvo

irs

Targeted Zone

58%


Heat reduces viscosity of oil and increases its mobility

Steam and

Condensed Water Hot

Water

Oil

Bank

Oil and Water

Zone near

original reservoir

temperature

Steam Generator

Injection

Well

Production

Well

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/BBLOperating

Expense

Up-front steam costs scale with gas price


0

25

50

75

100

0 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.

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

$NYMEX

VCI $3.5 $3 $2.5

$65 1.9 2.0 2.1

$75 2.5 2.6 2.7

$ B

RE

NT

$85 3.1 3.2 3.3

BO

EP

D

YEAR


• 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



Cash Margin


waterfloods

TEMBLOR

SANDS

EOCENE

SANDS AND

SHALES

UPPER

CRETACEOUS

SANDS AND

SHALES

MONTEREY

SANDS AND

SHALES

1,0

00

’P

AY

TULARE

SANDS20

40

200

50

40

50

SH

ALL

OW

DE

EP

ETCHEGOIN

SANDS

# o

f S

tack

ed

Re

se

rvo

irs

Targeted Zone

60%


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


0

15

30

45

60

0 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.

BO

EP

D

YEAR

PA

RA

ME

TER

S

PE

R P

ATT

ER

N Operating

Expense/bbl

$19/BOE

Capital

Cost *

$1.2MM

Total EUR

(MBO)

190

Peak Rate

(BOPD)

35

Drilling

Time (days)

10

Royalty

12.5%

CRC OPERATED FIELDS

Rincon

Saticoy

South Mountain

Paloma

Mount Poso

Kettleman

Buena Vista

Elk Hills

CRC NEW & POTENTIAL

WATERFLOODS

EUR

VCI 165 190 215

$65 2.2 2.6 2.9

$75 2.8 3.2 3.7

$ B

RE

NT

$85 3.3 3.8 4.4


0

40

80

120

160

0 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

EUR

VCI 140 165 190

$65 1.9 2.3 2.6

$75 2.4 2.9 3.3

$ B

RE

NT

$85 2.8 3.4 4.0

CRC OPERATED FIELDS

San Miguelito

Elk Hills

Wilmington

Huntington

Beach

CRC REDEVELOPMENT

WATERFLOODS

BO

EP

D

YEAR

PA

RA

ME

TER

S

PE

R P

ATT

ER

N Operating

Expense/bbl

$19/BOE

Capital

Cost *

$1.8MM

Total EUR

(MBO)

165

Peak Rate

(BOPD)

120

Drilling

Time (days)

14

Royalty

PSC**


• 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 costsand similar economics.

Deeper Horizons Primary Overview



Cash Margin


primary

TEMBLOR

SANDS

EOCENE

SANDS AND

SHALES

UPPER

CRETACEOUS

SANDS AND

SHALES

MONTEREY

SANDS AND

SHALES

1,0

00

’P

AY

TULARE

SANDS20

40

200

50

40

50

SH

ALL

OW

DE

EP

ETCHEGOIN

SANDS

# o

f S

tack

ed

Re

se

rvo

irs

Targeted Zone

80%


* 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

0

150

300

450

600

750

900

0 1 2 3 4

Composite Type well

Wheeler

Ridge Actuals

Bardsdale

Actuals

Pleito Ranch

Actuals

BV Nose

Actuals

See endnote for details.

EUR

VCI 400 430 460

$65 2.2 2.3 2.5

$75 2.6 2.8 3.0

$ B

RE

NT

$85 3.1 3.2 3.6

CRC OPERATED FIELDS

Montalvo

Kettleman

Saticoy Bardsdale

South Mountain

Elk Hills

BV Nose

Yowlumne

Pleito Ranch

Wheeler Ridge

PalomaRio Viejo

CRC PRIMARY

BO

EP

D

YEAR

PA

RA

ME

TER

S

PE

R P

ATT

ER

N Operating

Expense/bbl

$10/BOE

Capital

Cost *

$5.0MM

Total EUR

(MBO)

430

Peak Rate

(BOPD)

360

Drilling

Time (days)

30

Royalty

12%


• 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

on 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



Cash Margin


shale

TEMBLOR

SANDS

EOCENE

SANDS AND

SHALES

UPPER

CRETACEOUS

SANDS AND

SHALES

MONTEREY

SANDS AND

SHALES

1,0

00

’P

AY

TULARE

SANDS20

40

200

50

40

50

SH

ALL

OW

DE

EP

ETCHEGOIN

SANDS

# o

f S

tack

ed

Re

se

rvo

irs

Targeted Zone

71%


California Shale Type Well

-

100

200

300

400

500

0 1 2 3 4

New Pool Type Curve

Infill Shale

Curve

Gunslinger

Actuals

Rose/N. Shafter

ActualsElk Hills Actuals

Elk Hills (2001-2003)

VCI Infill New Pool

$65 1.5 2.2

$75 1.7 2.6

$ B

RE

NT

$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

CRC SHALE

CRC OPERATED FIELDS

BO

EP

D

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%


Sacramento Basin – Gas Overview

TEMBLOR

SANDS

EOCENE

SANDS AND

SHALES

UPPER

CRETACEOUS

SANDS AND

SHALES

MONTEREY

SANDS AND

SHALES

1,0

00

’P

AY

TULARE

SANDS20

40

200

50

40

50

SH

ALL

OW

DE

EP

ETCHEGOIN

SANDS

# o

f S

tack

ed

Re

se

rvo

irs

Targeted Zone

$75 Brent Marker Price and $3.00 NYMEX

$18 / BOE or $3.0 / MCF Realized PricingDifferentials/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%


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,

organic 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.

http://www.crc.com/

crc: value-driven...november corporate presentation | 11 $0 $120 $240 $360 $480 $20 $50 $80 $110...

Documents