jp morgan 2018 energy conference - crc.com€¦ · jp morgan 2018 energy conference | 2 forward...

JP MORGAN 2018 ENERGY CONFERENCETodd Stevens | President & CEO | June 18-19, 2018

JP Morgan 2018 Energy Conference | 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/


Well-Positioned to Drive Value-Oriented Growth

Disciplined Portfolio Management

Adjusted EBITDAX

Growth*

Regaining Momentum

Through Increased

Investment

• Increasing CRC

Investments and Deploying

Rigs

• Joint Ventures

• Opportunistic Deleveraging

• Significant Operating

Leverage to Crude Oil

*See Slide 23 for additional information regarding Adjusted EBITDAX Growth planning scenarios.

400+

0

500

1,000

1,500

2,000

2,500

2017 2018E 2019E 2020E 2021E

$M

M

2017 2018E 2019E 2020E 2021E


Large Resource Base with Production Diversity

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




Leading Market Position 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

• San Joaquin Basin contributed 70% of CRC’s total FY 2017 production, 73% of pro forma FY 2017 production*

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

• Thermal recovery applied since early 1960s

• Currently running 7 drilling rigs

Key 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, ~65% of pro forma FY 2017 CRC San Joaquin production*)

• Two core steamfloods - Kern Front and Lost Hills

• Early stage waterfloods at Buena Vista and Mount Poso

• Substantial, integrated infrastructure that supports Elk Hills

Basin Map

0

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6

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100

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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

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


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

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0

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

Field Map

Production History

Large fee property position

with integrated infrastructure


Strategic Consolidation of Elk Hills Assets

• CRC acquired Chevron’s non-operated

working interest ranging between 20% to 22%

in different producing horizons within the Elk

Hills field for total consideration of $460MM

in cash and 2.85 MM CRC shares, effective

April 1, 2018

• CRC now owns Elk Hills in fee simple, holding

100% WI, NRI, and surface lands

• Acquired ~10,000 surface fee acres

Total Consideration

$460MM Cash +

2.85MM Shares

2017 Net Production

13 Mboepd46% Oil | 9% NGL

2017E Operating Cash Flow

~$100MM@ $65 Brent

2017 Proved Reserves

64 MmboeCRC estimate @ SEC 2017 Pricing

CRC now owns 100% WI & NRI in

its largest field

Existing CRC Surface Acreage

Acquired Surface Acreage

Elk Hills Unit

Elk Hills Unit47,000 acres


Accelerating Value with Midstream JV

• Expect to achieve $5MM of annualized

operational savings within 6 months of closing

and ~$15MM of additional synergies within the

next 18 months

Consolidate Operations

Streamline business processes

Increased revenue opportunities

Improve CRC capital efficiency

• Maximizes NGL yields and revenue through

increased utilization of CRC’s best -in-class

cryogenic plant

• Transaction reduces CRC’s per unit production

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

• Elk Hills produces light oil with an avg API of

~36, which has received a premium over Brent

in recent months

Cash Flow from

Acquired Assets

Avoided Interest

Cost Synergies

ARES Cash Distributions1

$-

$50

$100

$150

ARES TRANSACTION INCREMENTAL CASH FLOW

$M

M

Acquired assets will add

an incremental $40MM-

$50MM of cash flow/

saving per year for the

first 36 months1

Elk Hills Transaction delivers incremental cash

flow for investment in 1.7+ VCI inventory1 Assumes the PIK portion of the Ares distributions are deferred for the first 36 months.


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 more than 25% of our total 2017 oil 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 – High Growth Area with Large OOIP

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

in California

• ~8 billion barrels OOIP in CRC fields

• Operate more than 20 fields (over half the fields in the basin)

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

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

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

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

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

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

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

High Growth Area: large OOIP, low recovery

factor and potential for high-IP wells

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 extensions and discoveries and 22 million BOE from performance. We were also able to rebook 49 million BOE due to the increase in prices compared to prior years.

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

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

3P 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

Unproven

Revisions Due to Price Since 2014

Proven

Cumulative Production

>350%

Growth

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

http://www.crc.com/


Enduring Strategy

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

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$0

$20

$40

$60

$80

$100

$120

07/20/14 11/20/14 03/20/15 07/20/15 11/20/15 03/20/16 07/20/16 11/20/16 03/20/17 07/20/17 11/20/17 03/20/18 07/20/18

CR

C D

rilli

ng

Rig

Co

un

t

Bre

nt

Cru

de

Oil

Pri

ce (

$/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

4

5


Significant Reduction in Total Debt from Post-Spin Peak

3,000

4,000

5,000

6,000

7,000

2Q15 Debt Exchange for

2L

Open Market

Repurchases

Equity for Debt

Exchange

Cash Tender

for Unsecureds

Cash Flow Ares & Elk Hills

Transactions

3/31/2018 Pro

Forma

To

tal D

eb

t ($

MM

)

6,7651

Total

Total Debt Reduction$535

million

$205

million

$102

million

$625

million

$110

million

$297

million$1,874 million

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

-

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

Continue to seek opportunistic transactions that reduce overall debt.

2

4,891

2018 Debt

Repurchases

$97MM

Closed 2

transactions


Recent Transactions Result in Improving Debt Metrics

3/31/2018

Actual

Elk Hills (EH)

Transaction

April Debt

Repurchases

3/31/2018

Pro Forma1

1st Lien 2014 Revolving Credit Facility (RCF) -$ -$ 45$ 45$

1st Lien 2017 Term Loan 1,300 1,300

1st Lien 2016 Term Loan 1,000 1,000

2nd Lien Notes 2,248 (95) 2,153

Senior Unsecured Notes 393 393

Total Debt 4,941 - (50) 4,891

Less cash (494) 460 34 -

Total Net Debt 4,447 460 (16) 4,891

Mezzanine Equity 724 724

Equity (654) 51 (603)

Total Net Capitalization 4,517$ 511$ (16)$ 5,012$

Total Debt / Total Net Capitalization 109% 98%

Total Debt / LTM Adjusted EBITDAX4

6.0x 5.4x

LTM Adjusted EBITDAX4

/ LTM Interest Expense 2.4x 2.6x

PV-105 / Total Debt 0.9x 1.1x

Total Debt / Proved Reserves6 ($/Boe) $8.00 $7.17

Total Debt / Proved Developed Reserves6 ($/Boe) $11.23 $10.05

Total Debt / 1Q18 Production ($/Boepd) $40,171 $36,230

Pro Forma Capitalization1 ($MM)

1 Please see end notes for further information regarding the presentation of pro forma financial information.2 Includes $109 million of noncontrolling interest equity for BSP and Ares.3 Calculated using 2.85 million shares of CRC common stock at closing share price of $18.06 on 4/9/2018.4 Please see end notes for further information regarding Adjusted EBITDAX.

5 PV-10 as of 12/31/2017. PV-10 on a pro forma basis includes an estimate of the Elk Hills reserves acquired at SEC

2017 pricing. See the Investor Relations page at www.crc.com for details on this calculation.6 Reserves as of 12/31/2017. Reserves on a pro forma basis include an estimate of the Elk Hills reserves acquired.

2 3

$0

$1,000

$2,000

$3,000

$4,000

2018 2019 2020 2021 2022 2023 2024

2nd Lien Notes

2014 RCF

Unsecured Notes

2016 Term Loan

2017 Term Loan

Pro Forma1 Debt Maturities ($MM)

Pro Forma Total Debt

$4.89B

Recently initiated a 3 yr Cap on 1 month

Libor @ 2.75% on a notional $1.3B

http://www.crc.com/


Development and Midstream Joint Ventures: A Force Multiplier

JVs are generally focused in the San Joaquin Basin

Kern Front

-Legend-

Oxy Land

Oil Fields

Gas Fields

Buena Vista

Pleito Ranch

Elk Hills

Kettleman North Dome

Lost Hills

Mt Poso

CRC Land

$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

$550 MillionTotal Potential JV

Development Capital

Portfolio Flexibility

and Optionality

Enables High

Margin Production

Growth

Accelerate Value

Derisk Inventory

JVs add production and cash flow,

and help de-risk inventory to

increase CRC’s reserve base

$750 MillionMidstream JV

Reduce Debt

Acquire Elk Hills

Sole Ownership


Mid-Cycle Capital Investment Plan Delivers Production Growth

0

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180

210

240

0

20

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60

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100

120

140

160

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

Ca

pit

al ($

MM

)

MB

oe

/d

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

Net Production By Stream (Mboe/d)

*Total Capital reflected in the graph includes the capital investment of internal CRC capital as well as all JV partners which include BSP and MIRA. Please

note our consolidated financial statements include BSP’s investment and exclude MIRA’s investments based on the accounting treatment of each venture.

** Q2 Capital guidance includes CRC, BSP, and MIRA capital


Dynamic 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

ExplorationVentura

Los Angeles

San Joaquin

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 the

Buena Vista, Ventura and Southern San Joaquin Areas

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

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

environment and efficient deployment of joint venture proceeds

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

2018 Capital Investment Program Aligned to Mid-Cycle Commodity Pricing

Approx. $550 to $600 million

1Facility Costs and other non-return capital are apportioned to producing wells in the year they are drilled.2IRR estimate for the 2017 development program. VCI is calculated by dividing the net present value of the project’s expected pre-tax cash flow over its life by the net present value of the investments, each using a 10% discount rate.

2018E Total Capital Plan 2018E Development Capital By

Drive

42%

18%

16%

21%

3%

Conventional

ExplorationWaterfloods

Steamfloods

Unconventional

44%

29%

13%

At $55 flat Brent and $3 NYMEX, the

fully-burdened1 2017 CRC Development

Program delivered a 1.7 VCI or 30% IRR2

Approx. $375 million Approx. $375 million

10%

2018E Development Capital

By Basin

67%

6%

27%

4%


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

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0 100 200 300 400 500 600 700 800Deve

lop

me

nt

Ca

pit

al ($

B)

Net Resources3 (MMBoe)

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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/


80

90

100

110

120

130

2017 2018E 2019E 2020E 2021E

Oil P

rod

ucti

on

(M

B/d

)

400

800

1,200

1,600

2,000

2,400

2017 2018E 2019E 2020E 2021E

Ad

just

ed E

BIT

DA

X (

$M

M)

Portfolio Flexibility Provides Range of Crude Oil Scenarios

Note: Scenarios assume flat pricing from $55 to $75 Brent and $3.00 to $3.10 NYMEX gas, respectively. Assumes varying lease operating costs within historical ranges depending on the commodity prices of the planning scenario outcomes. Ranges of portfolio planning

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

business in 2019 and beyond for each scenario. Please see end notes for further information regarding Adjusted EBITDAX.

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

Combined with mid-cycle commodity

prices, we are positioned for growth in:

• Cash flow

• Production

• Reserves

in total and on a debt-adjusted per share

basis*

Portfolio

Planning

Scenarios

Portfolio

Planning

Scenarios

Capital focused on oil projects that provide

Increasing

Margins

Low

Decline Rates

Compounding

Cash Flow+ =

-

Estimated Crude Oil Production Outcomes

≈

0

300

600

900

1,200

1,500

1,800

2017 2018E 2019E 2020E 2021E

Ca

pit

al ($

MM

) Estimated Ranges of Capital Investments

Estimated Range of Adjusted EBITDAX Outcomes

-≈

http://www.crc.com/


Project Inventory and Operational Execution Drives Organic Deleveraging

Note: All cases are self-funding. Capital program in all cases assumes discretionary cash flow is reinvested. Assumes varying lease operating costs within historical ranges depending on the commodity prices of the

planning scenario outcomes. Please see end notes for further information regarding Adjusted EBITDAX.

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 A

dju

ste

d E

BIT

DA

X

$55 $65 $75


PDP Value

Proved Value

Unproved4

$0

$4

$8

$12

$16

$20

$24

$28

$65 Brent $75 Brent $85 Brent

($B

illio

n)

Elk Hills Acquisition Enhances NAV Above EV

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.

1

1

http://www.crc.com/


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 Adj. EBITDAX growth*

Clear runway and

available cash

-2017 2018E 2019E 2020E 2021E

*See Slide 23 for additional information regarding Adjusted EBITDAX Growth planning scenarios.

APPENDIX


Continued Forward Progress with Strong 1Q18 Results

123 Mboe/d~2% Sequential Quarter

Decline

$250 Million

$139 MillionEntirely Internally

Funded

9 RigsMaintained Sustainable

Level of Activity

Capital

Adj. EBITDAX*

ACTIVITY

PRODUCTION

* See the Investor Relations page at www.crc.com for a reconciliation to

the closest GAAP measure and other important information.

~8% Sequential

Quarter Growth

http://www.crc.com/


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

Realized Price ($/Boe)

Wilmington Production Sharing Contracts

• Over 25% of CRC’s oil production is subject to Production Sharing Contracts

• PSC Mechanics

• CRC pays our partners’ share of the Operating and Capital Cost

• CRC recovers our partners’ portion of the cost in barrels

• CRC receives 45-49% of the gross production as “Profit Barrels”

• As prices rise, fewer barrels are required to recover our partners’ portion of the cost

Effect of Oil Price on Net Production

Higher oil prices result in higher

cash flow, but lower net production

Cost Recovery Bbls

Net Profit Bbls 45-49% of Gross Production

Gross Production


$3.26 $3.14 $2.95 $3.00 $2.87

$2.75 $2.42

$3.09

$2.90

$2.47 $2.56 $2.77 $2.81 $2.66

$2.28

$2.67

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

1Q 2017 2Q 2017 3Q 2017 4Q 2017 1Q 2018 2015 2016 2017

$/

Mc

f

NYMEX Realizations

CRC – Price Realizations

66% 62%

72%79%

69%

40%

52%

70%

63%59%

66%

72%

64%

37%

50%

65%

0%

20%

40%

60%

80%

100%

1Q 2017 2Q 2017 3Q 2017 4Q 2017 1Q 2018 2015 2016 2017

% o

f W

TI

& B

ren

t

WTI Brent

$51.91 $48.29

$48.21

$55.40

$62.87

$48.80 $43.32

$50.95 $50.24 $47.98

$50.02

$56.92 $62.77

$49.19

$42.01

$51.24

$54.66 $50.92

$52.18

$61.54

$67.18

$53.64

$45.04

$54.82

30

40

50

60

70

80

1Q 2017 2Q 2017 3Q 2017 4Q 2017 1Q 2018 2015 2016 2017

$/Bbl

WTI Realizations Brent

Realization %

of WTI97% 99% 104% 103% 100% 101% 99% 101%

Realization

% of NYMEX89 % 79% 87% 92% 98% 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.

-≈

*

*See attachment 6 of the Q1 2018 Earnings Release for information

regarding the effects of an accounting change on realized natural gas prices.


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


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

Sold Calls Barrels per Day 6,200 6,100 16,100 16,100 6,000 1,000 1,000

Weighted Average Ceiling

Price per Barrel$60.24 $60.24 $58.91 $65.75 $67.01 $60.00 $60.00

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

Weighted Average Ceiling

Price per Barrel- - - $71.00 - - -

Purchased Puts Barrels per Day 1,200 6,100 1,100 29,100 21,000 11,000 1,000

Weighted Average

Floor Price per Barrel45.83 $61.47 45.85 $60.86 $62.40 $63.27 $45.85

Sold Puts Barrels per Day 29,000 24,000 19,000 30,000 15,000 10,000 -

Weighted Average

Floor Price per Barrel$45.00 $46.04 $45.00 $49.17 $50.00 $50.00 -

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

Weighted Average

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

Percentage of 2Q 2018

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

Opportunistically Built Oil Hedge Portfolio

As of 4/10/2018. Certain of our counterparties have options to increase swap volumes at weighted average costs between $60 and $70 Brent.

* Assumes future counterparty options are not exercised. Refers to guidance at $74 Brent.

We target hedges

on 50% of crude

oil production

Strategy Protect cash flow for capital investments and covenant compliance


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


(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

o Initial commitment of $160MM

• DrillCo type structure where Investor funds

100% of project capital for 90% WI, with

CRC carried on its 10% WI

o CRC interest reverts to 75% after

target IRR is achieved

o CRC retains early termination options

• Focus on four fields within the San Joaquin

Basin

o Kern Front, Mt. Poso, Pleito Ranch,

Wheeler Ridge

• CRC operates all wells

Highlights:

• Up to $250MM over ~2 years

o Two tranches of $50MM

o Total of $100MM funded

o Third tranche expected in Q2

• Investor funds 100% of project capital in

exchange for a net profits interest (NPI)

o Investor NPI interest reverts to CRC

after low teens target IRR

o 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


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 NotesFrom Slide 25

1 Current CRC estimate of reserves value as of December 31, 2017, including reserves acquired in the Elk Hills transaction. Includes field-level operating expenses and G&A.

Assumes $3.00/MMBTU NYMEX.

2 Reflects the value of facilities and midstream assets at 50% of estimated replacement value. This discount is estimated to exceed the burden on reserves that would be

incurred if assets were monetized. Excludes the value of the assets monetized in the Ares transaction.

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

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

identified through life-of-field planning efforts to date.

5 Calculated using a market cap as of 6/15/2018 and the 3/31/2018 Pro Forma debt adjusted for the Elk Hills transaction and the April debt repurchases. Includes Mezzanine

Equity and Non-Controlling interest.

Type Curve Note: Each field-specific type well curve represents an average of the historical results of multiple projects over the prior four-year time period. Drive mechanism type

curves are the weighted average of the field-specific curves related to the projects chosen for our near-term growth plan. Type curves represent management’s estimates of future

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

not useful for purpose of benchmarking any individual well or pattern performance. Actual results are expected to vary depending on which projects are specifically developed.

Value Creation Index (VCI) Note: VCI is calculated by dividing the net present value of the project’s

expected pre-tax cash flow over its life by the net present value of project investments, each using a

10% discount rate.

Adjusted EBITDAX Note: The 3/31/2018 Pro Forma Adjusted EBITDAX includes a +$20 million

adjustment as a result of the Elk Hills transaction and no adjustment as a result of the April debt

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

Investor Relations page at www.crc.com for other important information.

Pro Forma Financial Information and Elk Hills Transaction Note: The actual amount of drawings under

our revolver necessary to complete the Elk Hills transaction and the April debt repurchases will depend

on the actual amount of cash available at the closing date. The pro forma information in this

presentation does not take into account capital expenditures or changes in our business since

3/31/2018 other than the Elk Hills transaction and April debt repurchases.

(in millions)

Net income (loss) 9$ 20$ 29$

Interest and debt expense, net 92 92

Depreciation, depletion and

amortization 119 119

Exploration expense 8 8

Unusual, infrequent, and other items 10 10

Other non-cash items 12 12

Adjusted EBITDAX 250$ 20$ 270$

3/31/2018

Elk Hills

Transaction

3/31/2018

Pro Forma

The following table presents a reconciliation of the GAAP financial measure of net

income (loss) to the non-GAAP financial measure of Adjusted EBITDAX.

http://www.crc.com/

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