PowerPoint Presentation...Title: PowerPoint Presentation Author: Joe Day Created Date: 2/27/2019...

FOURTH QUARTER & FY 2018 EARNINGS REVIEWTodd Stevens | President & CEO | February 27th, 2019

Mark Smith | Senior EVP & CFO

4Q & YE 2018 Earnings | 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, finding and development (F&D) costs, recycle ratio calculations,

reserve replacement ratios, 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/


Key Highlights

136 Mboe/d63% Oil

$314 Million$352 million Core

Adjusted EBITDAX3

$197 Million2

$174 million internally funded

91 Gross Wells Drilled1

includes 86 CRC wells

Capital

Adj. EBITDAX3

ACTIVITY

PRODUCTION132 Mboe/d62% Oil

$1,117 Million$1,374 million Core

Adjusted EBITDAX3

$747 Million2

$641 million internally funded

343 Gross Wells Drilled1

includes 237 CRC wells

4th Quarter 2018 2018

1 Includes all wells drilled by CRC, including JV wells.2 Includes JV capital.3 Core Adjusted EBITDAX excludes the effect of settled hedges of $50 million in the fourth quarter and $228 million for the year and cash-

settled equity compensation of $(12) million in the fourth quarter and $29 million for the year. 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/


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


Development Results Driving Growth

Sacramento Basin

5,000 BOE per Day

No Drilling Rigs

San Joaquin Basin

99,000 BOE per Day

6 Drilling Rigs

Ventura Basin

6,000 BOE per Day

1 Drilling Rig

FY 2018 Results of Major Drilling Programs

Q4 2018 Operations Results

Los Angeles Basin

26,000 BOE per Day

3 Drilling Rigs

Drilling Program History

0

50

100

150

200

250

HuntingtonBeach

Long Beach BV Hills BV Nose (Pre-Steam)Kern Front

0

10

20

30

40

50

60

70

Avg

30

Day

Pea

k R

ate

(BO

EPD

)

Wel

ls O

nlin

e >3

0 d

ays

Well CountAvg 30 Day Peak Rate

Los Angeles Basin San Joaquin Basin

0

25

50

75

100

125

1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18

Gro

ss W

ells

D

rille

d

San Joaquin Los Angeles Ventura

1 Includes JV wells.2 Kern Front wells are steam flood wells which have low IPs and then ramp up over a period of 12-24 months.3 Year to date drilling costs may not be comparable to prior periods due to variances in project mix, well depth, horizontal

length and other aspects.

Avg D&C

Cost per well3$3.5 MM $1.7 MM $2.2 MM $3.9 MM $0.4 MM

1 1,2


0

10

20

30

40

50

0 100 200 300 400 500 600 700 800Fu

ll C

ycle

Co

st1

($/B

oe

)Net Resources2 (MMBoe)

0

5

10

0 100 200 300 400 500 600 700 800Dev

Cap

ital

(B

$)

Net Resources2 (MMBoe)

• Fully burdened, growth-

focused portfolio

• Achieve a VCI of 1.3 or

greater at $65 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

Unlocking Value with a Deep Inventory of Actionable Projects at $65 Brent

Steamflood

Waterflood

Primary

Shale

Gas

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.

http://www.crc.com/


Strategic Consolidation of Elk Hills Assets

• CRC acquired Chevron’s non-operating working

interest ranging between 20% to 22% in different

producing horizons within the Elk Hills Unit for

total consideration of $460MM in cash and

2.85MM CRC shares of common stock, closed

early April using some of the Ares proceeds

• CRC now owns Elk Hills Unit in fee simple,

holding 100% WI, NRI and surface lands

• Implemented approximately $20MM in non-

recurring capital cost savings

• Acquired ~10,000 surface fee acres

CRC now owns 100% WI & NRI in the Elk Hills Unit

Existing CRC Surface Acreage

Acquired Surface Acreage

Former Elk Hills Unit

Elk Hills Unit

47,000

acres

$34MM Implemented

$0 $5 $10 $15 $20 $25 $30 $35

Annualized Elk Hills Synergies1 ($MM)

1Synergies include operational cost savings and revenue enhancement

Initial Target


Resilient Resource Base

Net Production By Stream (Mboe/d)

1Total 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.21Q19 Capital guidance includes CRC, BSP, and MIRA capital.

low

pri

ce

sce

na

rio

mid

-cyc

le s

ce

na

rio

1

0

30

60

90

120

150

180

210

240

0

20

40

60

80

100

120

140

160

1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 1Q19E

Ca

pit

al ($

MM

)

MB

oe

/d

Oil NGL Gas Total Capital CRC Capital (Internally Funded)

2


Drilling

46%

Workover

13%

JV - BSP

7%

JV - MIRA

8%

Other

1%

Exploration

3%Facilities

22%

2018 Capital Investment Program Results

Total: $747 million

1Other includes maintenance and occupational health, safety and environmental projects, seismic and other investments.2Facility costs and certain non-return capital are apportioned to producing wells in the year they are drilled. Excludes exploration, other, and amounts related to our MIRA JV.

2018 Total Capital Invested Results of Fully-Burdened2

2018 CRC Development ProgramTotal: $690 million

Value Creation in 2018• CRC 2018 capital plan was directed to oil-weighted projects in our core fields: Elk Hills, Buena Vista, Wilmington, Kern Front, Huntington Beach,

and continued delineation of Ventura and southern San Joaquin areas

• JV capital was focused in the San Joaquin basin and Huntington Beach

1

$60 Brent/$3 NYMEX 1.5 VCI

$65 Brent/$3 NYMEX 1.6 VCI


2018 Proved Reserves Increased

618

48

21 27

34

64

38

712

300

350

400

450

500

550

600

650

700

750

Balance

as of

12/31/17

Production Management

Discretion

Performance

Revisions

Extensions

and

Discoveries

Purchases Price Revisions Balance

as of

12/31/18

Pro

ved

Re

se

rve

s (

MM

BO

E)

- ≈

1

1Certain performance revisions related to reserves that are not anticipated to be developed within their five-year window of initial booking were transferred out of the proved undeveloped category at management’s discretion.


58 109 156 204

768 644 568618

712

222 251226

204

171

181

431450

458

150

159

395

679

704

0

250

500

750

1,000

1,250

1,500

1,750

2,000

2,250

2,500

2014 2015 2016 2017 2018

MM

Bo

e

Enhanced Inventory Growth and Expanded 3P Position

2018 Highlights

• Proved reserves today only 7% lower despite 29%

decrease in price from the YE 2014

• Life-of-field studies increased unproven resources

• Recent exploration success not included

• Organic F&D costs excluding price related revisions and

acquisitions were $11.31 per BOE in 2018 and 4-year

average of $6.42

• Organic recycle ratio of 1.9x in 2018 and 4-year average

of 2.6x

• 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

>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) represent technical volumes irrespective of commodity price. Proven

reserves utilize applicable SEC prices for all year-end periods.

Probable3Price-Contingent

Reserves2

ProvedCumulative

Production

Possible3

http://www.crc.com/


Disciplined 2019 Capital Plan Leverages Portfolio of Projects and Management Expertise

Focus on

Core ProgramBuena Vista

Elk Hills

Long Beach

Kern Front

Mount Poso

Expect to Align with

Discretionary

Cash Flow

15%Facilities

2%Exploration

8%Other

14%Workover

50-55%Core

5-10%Growth

2019 Internally Funded Capital Program

$300 to $385 Million

Potential Additional JV Capital

$100 to $150 Million

to invest in Core and Growth

properties

1Other includes corporate, maintenance and occupational health, safety and environmental projects, seismic and other investments, and Elk Hills power

1


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


Field Production1

Field Oil Prod (MBOPD) Field NGL Prod (MBPD) Field Gas Prod (MBOEPD)

Production Delivers Growth with Expanding Adjusted EBITDAX Margins

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

0

50

100

150

200

250

300

350

400

450

1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18

%

of

Ad

juste

d R

eve

nu

es

$M

M

Adjusted EBITDAX

Adj. EBITDAX Margin

Impact of Accounting Change

Adj. EBITDAX

Core Adj. EBITDAX

Increasing oil production and

Adjusted EBITDAX

1 Field Production includes gross production from the Wilmington field, which is subject to PSCs, and net production from all other assets.2 See Attachment 3 of the current Earnings Release for the calculation of Adj. EBITDAX Margin.3 Results for reporting periods beginning after January 1, 2018 are presented under the new revenue recognition accounting standard while prior

periods are not adjusted and continue to be reported under accounting standards in effect for the applicable period.4 See the Investor Relations page at www.crc.com for a reconciliation of Core Adjusted EBITDAX and Adjusted EBITDAX to the closest GAAP measure

and other important information.

3

4

4

2

Elk Hills Acquisition

http://www.crc.com/


Source: EIA and

SoCalGas Envoy

Da

ily S

oC

alG

as n

atu

ral

ga

s in

ve

nto

rie

s (

Bcf)

$0

$2

$4

$6

$8

$10

$12

$14

01/2017 04/2017 07/2017 10/2017 01/2018 04/2018 07/2018 10/2018 01/2019

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


$3.00 $2.87 $2.75

$2.88

$3.40

$2.77 $2.81

$2.25

$3.16

$3.77

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

4.00

4Q17 1Q18 2Q18 3Q18 4Q18

$/M

cf

NYMEX Realizations

CRC – Price Realizations

79%69%

62% 66%74%

72%64%

56% 60% 64%

0%

20%

40%

60%

80%

100%

4Q17 1Q18 2Q18 3Q18 4Q18

% o

f W

TI

& B

ren

t

WTI Brent

$55.40

$62.87

$67.88 $69.50

$58.81 $56.92

$62.77

$64.11 $63.63 $59.97

$61.54

$67.18

$74.90 $75.97

$68.08

30

40

50

60

70

80

4Q17 1Q18 2Q18 3Q18 4Q18

$/B

bl

WTI Realizations Brent

Realization

% of WTI103% 100% 94% 92% 102%

Realization %

of NYMEX92% 98%* 82%* 110%* 111%*

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 the Price Statistics attachment in the Earnings Release for information

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

*

*

*

*


248

461

0

100

200

300

400

500

600

700

800FY2017 Volume Price Costs Interest

Working

Capital/Other FY2018$

MM

Strong Annual Cash Flow GrowthO

pe

rati

ng

Ca

sh

Flo

w


60

70

80

90

75

100

125

150

Oil

Pro

du

ctio

n (

MB

OP

D)

Tota

l Pro

du

ctio

n

(MB

OEP

D)

Total Production Oil Production

Increasing Efficiencies Lower Per Barrel Costs as Production Grows

$17.00

$17.50

$18.00

$18.50

4Q17 1Q18 2Q18 3Q18 4Q18

Pro

du

ctio

n C

ost

s2

($/B

OE)

As production increased,

production costs2 per BOE

decreased 5%

1

1Shaded area illustrates the increase in production from the Elk Hills acquisition.2Production costs excluding effects of PSC.

$0

.87

pe

r B

OE


250

500

1000

Demonstrated Experience Controlling Production Costs Through Price Cycle

• Capital investment scales with commodity price changes

• Flexible operations and shallow base decline allow for quick response to commodity price changes while preserving value

• Proven we can consistently control production costs through any price cycle

• Production costs have been as low as approximately $15/boe since CRC’s inception

$600

$700

$800

$900

$1,000

$1,100

$1,200

$20 $40 $60 $80 $100 $120P

rod

ucti

on

Co

sts

($

MM

)Brent $/Bbl

Annual Production Costs & Capital Investment1

Capital Investment

Scale ($MM)

2014

(Pre-spin)2015

2016

2017120181

1Includes development JV Capital.


Quarterly Cost Comparison

4Q17 3Q18 4Q18 FY 17 FY 18

Production costs ($/Boe) $19.64 $18.92 $18.61 $18.64 $18.88

Production costs

excluding PSC effects

($/Boe)

$18.31 $17.55 $17.44 $17.48 $17.47

Taxes other than on

income ($MM)$33 $45 $29 $136 $149

Exploration expense

($MM)$5 $4 $16 $22 $34

Interest expense ($MM) $91 $95 $98 $343 $379


4Q17 3Q18 4Q18

Net Income (Loss) Attributable to Common Stock per

Share – Diluted

($3.23) $1.32 $7.00

Adjusted Net Income (Loss) 1 per Share – Diluted ($0.33) $0.81 $0.53

Oil Production 80 MBbl/d 84 MBbl/d 86 MBbl/d

Total Production 126 MBoe/d 136 MBoe/d 136 MBoe/d

Realized Oil Price w/ Hedge ($/Bbl) $56.92 $63.63 $59.97

Realized NGL Price ($/Bbl) $44.03 $45.72 $43.56

Realized Natural Gas Price ($/Mcf) $2.77 $3.16 $3.77

Net Income (Loss) Attributable to Common Stock ($138) MM $66 MM $346 MM

Adjusted EBITDAX1 $231 MM $308 MM $314 MM

Core Adjusted EBITDAX1 $261 MM $400 MM $352 MM

Internally Funded Capital Investments $125 MM $158 MM $174 MM

Cash Flow Provided by Operations $23 MM $159 MM $68 MM

4Q18 Results Summary Comparison

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

http://www.crc.com/


1st Lien 2014 Revolving Credit Facility (RCF) 540$

1st Lien 2017 Term Loan 1,300

1st Lien 2016 Term Loan 1,000

2nd Lien Notes 2,067

Senior Unsecured Notes 344

Total Debt 5,251

Less cash (15)

Total Net Debt 5,236

Mezzanine Equity 756

Equity (247)

Total Net Capitalization 5,745$

Total Debt / Total Net Capitalization 91%

Total Debt / LTM Adjusted EBITDAX3

4.6x

LTM Adjusted EBITDAX3

/ LTM Interest Expense 3.0x

PV-104 / Total Debt 1.8x

Total Debt / Proved Reserves4 ($/Boe) $7.38

Total Debt / Proved Developed Reserves4 ($/Boe) $9.91

Total Debt / 4Q18 Production ($/Boepd) $38,610

Recent Transactions - Improving Debt Metrics

Capitalization ($MM)

1 Excludes $2MM of restricted cash.2 Includes $114 million of noncontrolling interest for BSP and Ares.3 LTM Adjusted EBITDAX includes an estimated adjustment of $33.5 million for 1Q18 at approximately $65 Brent,

as a result of the Elk Hills transaction, including synergies. See the Investor Relations page at www.crc.com for

historical reconciliations to the closest GAAP measure and other important information. 4 Proved Reserves and PV-10 estimates are based on SEC18 prices of $71.75 Brent / $3.10 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)

Annual Highlights

• Repurchased face value of $183 MM of 2nd Lien Notes and $49 MM of

senior notes in 2018 for $199 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

• S&P upgrade on 2nd Lien Notes to B-

1

http://www.crc.com/

http://www.crc.com/


1Q19 Guidance

Anticipated Realizations Against the Prevailing Index Prices for 1Q19

Oil 94% to 99% of Brent

NGLs 55% to 60% of Brent

Natural Gas 100% to 110% of NYMEX

Production, Capital and Income Statement Guidance

Production1 132 to 137 Mboe/d

Capital2 $110 to $140 million

Production Costs1 $18.25 to $19.75 per Boe

Adjusted G&A1 $6.55 to $6.95 per Boe

DD&A1 $9.85 to $10.15 per Boe

Taxes other than on income $41 to $45 million

Exploration expense $9 to $14 million

Interest expense $98 to $103 million

Cash interest $70 to $75 million

Income tax expense rate -- to --

Cash tax rate -- to --

1Based on average Q1 2019 Brent price of $60 per barrel.2Capital guidance includes CRC, BSP, and MIRA capital.

For further detail on our Q1 2019 guidance, please see our latest Earnings Release.


1Q19 2Q19 3Q19 4Q19 1Q20

Sold Calls Barrels per Day 15,000 5,000 - - -

Weighted Average

Ceiling Price per Barrel$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 40,000 35,000 40,000 35,000 10,000

Weighted Average

Floor Price per Barrel$51.88 $55.71 $57.50 $60.00 $60.00

Swaps Barrels per Day 7,000 - - - -

Weighted Average

Price per Barrel$67.71 - - - -

Percentage of 4Q 2018 Oil Production

Hedged Against Downside52% 47% 47% 41% 12%

Opportunistically Built Oil Hedge Portfolio

The BSP JV entered into crude oil derivatives that are included in our consolidated results but not in the above table. For further information please see Attachment 10 of our latest Earnings Release.

2019 program continues

to target hedges on 50% of

crude oil production with

exposure to upside in

commodity price increases

Strategy

Protect cash flow,

operating margins,

and capital

investment program


Opportunistically Built Oil Hedge Portfolio

CRC benefits from both

Brent pricing and a top

hedge portfolio compared

to peer group after

accounting for Brent

pricing advantage.

Highest Floor Price

Among Peers

CRC has a well-positioned

2019 hedge portfolio that

still provides upside

exposure to commodity

price movements

Note: Hedge positions are current as of 3Q18 Earnings.

2018 Proxy-listed peers include: CPE, CRZO, DNR, EPE, FANG, GPOR, LPI, MTDR, NFX, OAS, PDCE, PE, RRC, SM, WLL, WPX, XEC.

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

$-

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00

$70.00

$80.00

CRC

% o

f 2

01

9 C

on

sen

sus

Pro

du

ctio

n H

edge

d a

t Fl

oo

r P

rice

Wei

ghte

d-A

vera

ge F

loo

r P

rice

($

/bb

l)

WTI-based Floor Price Brent Advantage Median Floor Price % Hedged

Proxy Group Peers with Published Oil Hedges

Median Floor Price: $54.71/Bbl


PD

PUD

Unproved4

$0

$4

$8

$12

$16

$20

$24

$55 Brent $65 Brent $75 Brent

Va

lue

($

Billio

n)

1

1

Current EV

of $7.2 Bn5

Infrastructure & Other2

Surface & Minerals3

Current Enterprise Value Deeply Discounted

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


5

10

15

20

25

30

$20

$50

$80

$110

07/14 01/15 07/15 01/16 07/16 01/17 07/17 01/18 07/18 01/19

Rig

Co

un

t

Bre

nt

Cru

de

Oil

Pri

ce (

$/B

BL) Brent Crude Price

CRC + JV Rig Count

CRC Rig Count

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

QUICK

RESPONSE TO

PRICE CHANGE

Increased activity

Engaged in JVs

Locked in hedges

Increased liquidity

Extended maturities

Invest for value preservation

Drill high-graded portfolio

Invest in exploration

Invest in facilities

Strengthen balance sheet

VALUE

PRESERVATION

SEPARATION

ANNOUNCEMENT

Spin

Date


Accelerating Value and Derisking Inventory through JVs

Highlights:

• Up to $300MM

o Current commitment of $140MM

• 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 Three tranches of $50MM

o Total of $150MM funded

• 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 and

Los Angeles 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 5 9 13 17 21 25 29 33 37 41 45 49 53 57 61 65 69 73 77 81 85 89 93 97 101105109113117JV 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 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 consists of three CRC representatives and three representatives

from Ares


-

10,000

20,000

30,000

40,000

50,000

1992 1996 2000 2004 2008 2012 2016

Bo

e/d

Base Incremental

Wilmington Field – Production Sharing Contracts

• 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 is 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

LBU PSC

-

2,000

4,000

6,000

8,000

10,000

12,000

2006 2008 2010 2012 2014 2016 2018B

oe/

d

Base Incremental

Tidelands PSC

Base Profit Split:

4% CRC / 96% State1

Incremental Profit Split:

49% CRC / 51% State1

Base Profit Split:

4% CRC / 96% State1

Incremental Profit Split

49% CRC / 51% State & City1

1Average 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


End Notes

From Slide 27

1 CRC estimate of reserves value as of December 31, 2018, 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 cost. 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. Does not include value of extensive seismic library.

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, 2018.

5 Calculated using December 31, 2018 debt at par and a market cap as of 02/22/2019. Includes non-controlling interests reported

as mezzanine and permanent equity as of December 31, 2018.

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

finding and development (F&D) costs, recycle ratio calculations, reserve 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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