Bank of America Merrill Lynch 2018 Leveraged Finance ... · Bank of America Merrill Lynch 2018...

CRC: VALUE-DRIVEN

M a r k S m i t h | S r . E V P & C F O

D e c e m b e r 4 , 2 0 1 8 | B o c a R a t o n , F L

Bank of America Merrill Lynch 2018 Leveraged Finance Conference

Bank of America Merrill Lynch 2018 Leveraged Finance Conference – Boca Raton, FL | 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/


CRC’s Value-Driven Strategic Approach

• Utilize VCI-based

decision-making

• Optimize core operating

area investment

• Enhance targeted

growth area investment

• Pursue impactful

capital workovers

• Streamline processes

• Apply technology

• Leverage sizeable

infrastructure

• Drive strategic

consolidation

• Employ new thinking

and approaches

• Reinvest to grow cash

flow

• Simplify capital

structure

• Enhance credit metrics

• Pursue value-accretive

M&A

• Reduce absolute level of

debt

• Pursue value-driven

production growth

• Delineate future growth

areas

• Enhance already

substantial inventory

• Pursue strategic joint

ventures

Capture Value of

Portfolio

Ensure Effective

Capital Allocation

Drive Operational

Excellence

Strengthen

Balance Sheet

Proven and pressure-tested strategic approach preserved value through the

downturn and is set to drive significant value creation for years to come


Positioned for Value-Driven and Sustainable Growth

Value

Focus

PV10 pre-tax cash flows

PV10 of investmentsVCI =

Value Creation Index

The VCI Difference Delivers Real Value

• Value-directed investments

• Disciplined capital allocation

• Enhanced returns over full-cycle time frame

• Drives team alignment

• CRC ahead of competitive landscape in shifting to value


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 Drilled1includes 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/


Large Resource Base with Production Diversity

SAN JOAQUIN BASIN

Greater Elk Hills – Flagship Asset

Thermal – Protecting Base Production

South Valley – New Opportunities

Shales & Tight Sands – New Opportunities

#2 Producer - 99,000 BOE/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


World-Class Fields Delivering Value-Driven Growth

• CRC has over 50 billion original BOE in place in four key basins

▪ 135 fields; 9 large fields each with over 1 billion original BOE in place and reserves of 731 MMBOE

▪ 10 billion BOE produced to date (20% recovery factor)

• Focused on improving recovery

▪ Applying CRC “know-how” for efficient recovery

▪ Utilizing repeatable techniques across fields and basins

• Observed analogs guide development

▪ Utilizing proven, successful techniques

▪ De-risking and accelerating reserve growth

0

5

10

15

20

25

30

San Joaquin LA Basin Ventura Sacramento

MM

BO

E

CRC’s Resources and Recovery

Original BOE in Place

Recovery Factor

16%33%

14% 62%


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

• 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

Reserves2ProvedCumulative

Production

Possible3

http://www.crc.com/


Unparalleled California Expertise and Insight

Core Assets Provide Operational Leverage

Applying analog development to adjacent fields

Midstream infrastructure provides low cost advantage

Largest 3-D Seismic

Position in California

Extensive Field Operations Experience

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


$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.

*

*

*


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 $7.1 Bn5

Infrastructure2

Surface & Minerals3

1-5 See endnotes in the Appendix.

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

http://www.crc.com/


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/


$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


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


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/


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


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 NINE

JVs


$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.


0

30

60

90

120

150

180

210

240

0

20

40

60

80

100

120

140

160

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

Ca

pit

al ($

MM

)

MB

oe

/d

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

JVs Provide Additional Capital Flexibility

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 investment based on the accounting treatment of each venture.

** Q4 2018 Capital guidance includes CRC, BSP and MIRA capital.

low

pri

ce

sce

na

rio

mid

-cyc

le s

ce

na

rio


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/


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


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/


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%


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


3,000

4,000

5,000

6,000

7,000

2Q15 Debt Exchange for2L

Open MarketPurchases

Equity for DebtExchange

Cash Tender forUnsecureds

Cash & WorkingCapital

3Q18

Tota

l Deb

t ($

MM

)Significant Reduction in Total Debt from Post-Spin Peak

Total

Total Debt Reduction$535

million

$330

million

$102

million

$625

million

$65

million$1,657 million

1 Represents mid-second quarter 2015 peak debt.

-

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

Continue to seek opportunistic transactions that reduce overall debt.

5,108

Includes Debt

Repurchases of

$177MM in YTD

2018

6,7651


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

CRC’s S&P Corporate Family Rating

CCC+

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)


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

ell T

ota

l M

ea

su

red

De

pth

(ft

)

21,000’

17,000’

6,000’

13,000’

14,000’

BOE/ft

BV Nose

South

Valley

LA Basin

Notes:

Source: Wood Mackenzie data for Shale Play areas; Source: Internal estimates for CRC, taking all wells drilled since 2012. BOE calculated as Oil + 20:1 Gas.

Well dots sized by oil expected ultimate recovery (MMBOE). Darker colors are newer wells; lighter colors are older wells.

Wolfcamp includes Midland and Delaware Basins.

Normalizing estimated ultimate recovery (EUR) vs. measured depth shows CRC advantage

• Better recovery factors driven by low decline rate waterfloods and steamfloods

• Diverse reservoir portfolio provides optionality to drill deep large EUR producers with later life up-hole recompletions

Historical focus:

• Cheaper, simpler well designs (primarily vertical)

• Quality reservoirs that do not require complicated completions or long horizontal

Future upside:

• Tighter rock, horizontal drilling with new generation stimulation, increasing reservoir contact


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


• World-class waterflood

▪ 7 billion original BOE in place, 34% Rf

▪ Partnership with State of California and City of Long Beach

• Operational excellence

▪ Decades of operational experience

▪ Low annual base decline of 8%

▪ 640 identified locations

• Big fields get bigger

▪ Targeting bypassed pay, exploring deeper potential

▪ 280% organic RRR since Spin

▪ LA Basin 3P reserves of 290 MMBOE1

LA Basin – World-Class Wilmington Field

-37

-62

166 +104 171

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


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


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


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


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**


* Capital cost includes drilling, completion, and tie-ins.

Does not include 450 shallow (


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%


End Notes

From Slide 11

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 11/20/2018. 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/

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