first quarter 2018 earnings review · portfolio flexibility provides range of crude oil scenarios...

FIRST QUARTER 2018 EARNINGS REVIEWTodd Stevens | President & CEO | May 3, 2018

Mark Smith | Senior EVP & CFO

1Q 2018 Earnings | 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/


1Q 2018 Highlights – Continued Forward Progress

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/


Resilient Resource Base

0

30

60

90

120

150

180

210

240

0

20

40

60

80

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


Q1

2016

Q2

2016

Q3

2016

Q4

2016

Q1

2017

Q2

2017

Q3

2017

Q4

2017

Q1

2018

Q2

2018E

Field Production1

Field Oil Production Field Gas & NGL Production Incremental Elk Hills Production

Q2 2018 Guidance

Range

Flattening Production while Growing Adjusted EBITDAX Margins

0%

10%

20%

30%

40%

50%

60%

70%

0

40

80

120

160

200

240

280

Q1

2016

Q2

2016

Q3

2016

Q4

2016

Q1

2017

Q2

2017

Q3

2017

Q4

2017

Q1

2018

$M

M

Adjusted EBITDAX

Adj. Due to Accounting Change

Adj. EBITDAX Margin

Adj. EBITDAX

CRC arrested oil decline and is growing

Adjusted EBITDAX

1 Field Production includes gross production from the Wilmington field, which is subject to PSCs, and net production from all other assets.


Elk Hills Transaction Summary

• 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 and

surface in its largest field

Existing CRC Surface Acreage

Acquired Surface Acreage

Elk Hills Unit

Elk Hills

Unit47,000 acres


Accelerating Value Further from 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

ARESTRANSACTION

INCREMENTALCASH 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.


Drilling

JV - Capital

Workover

Development

Facilities

Exploration

San Joaquin

Ventura

Los Angeles

Production Enhancement Plans for 2018• CRC 2018 capital plan will be directed to oil-weighted projects in our core fields: Elk

Hills, Wilmington, Kern Front, Huntington Beach, and continued delineation of 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 – Transitioning to Mid-Cycle Commodity Prices

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%


80

90

100

110

120

130

2017 2018E 2019E 2020E 2021E

Oil

Pro

du

ctio

n M

B/d

400

800

1,200

1,600

2,000

2,400

Ad

just

ed E

BIT

DA

X $

MM

Portfolio Flexibility Provides Range of Crude Oil Scenarios

Note: Scenarios assume flat pricing from $55 to $75 Brent and $3.00 to $3.10 NYMEX gas, respectively. Assumes 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 the debt-adjusted per share basis 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

0300600900

1,2001,5001,800

2017 2018E 2019E 2020E 2021E

Cap

ital

($

MM

) Estimated Ranges of Capital Investments

Estimated Range of Adjusted EBITDAX Outcomes

- ≈

≈

http://www.crc.com/


$2.75 $2.42

$3.09 $2.87

$2.66 $2.28

$2.67 $2.81

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

2015 2016 2017 1Q 2018

$/M

cf

NYMEX Realizations

CRC – Price Realizations

40%

52%

70%69%

37%

50%

65% 64%

0%

20%

40%

60%

80%

100%

2015 2016 2017 1Q 2018

% o

f W

TI

& B

ren

t

WTI Brent

$48.80

$43.32

$50.95

$62.87

$49.19

$42.01

$51.24

$62.77 $53.64

$45.04

$54.82

$67.18

30

40

50

60

70

80

2015 2016 2017 1Q 2018

$/Bbl

WTI Realizations Brent

Realization

% of WTI101% 99% 97% 100%

Realization

% of NYMEX97 % 94% 86% 98%*

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 Earnings Release for information regarding

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

*


Strong Cash Flow Growth

133

200

0

50

100

150

200

250

1Q17 Volume* Price* Costs Interest

Working

Capital and

Other 1Q18$

MM

Op

era

tin

g C

ash

Flo

w

*Includes effects of PSCs


0

200

400

600

800

1000

FY 2016 FY 2017 1Q 2018

$ M

M

Adj. EBITDAX Operating Cash Flow Capital Investment

Living Within Cash Flow

1 See the Investor Relations page at www.crc.com for a reconciliation to the closest GAAP measure and other important information.2 Does not include JV capital. Net of capital-related accruals.

1 2

Annual Quarterly

http://www.crc.com/


Quarterly Cost Comparison

1Q17 4Q17 1Q18

Production costs

($/Boe)$17.70 $19.64 $19.08

Production costs

excluding PSC effects

($/Boe)

$16.66 $18.31 $17.47

Taxes other than on

income ($MM)$33 $33 $38

Exploration expense

($MM)$6 $5 $8

Interest expense

($MM)$84 $91 $92


1Q18 Results Summary Comparison

1Q17 4Q17 1Q18

Earnings (Loss) per Share - Diluted $1.22 ($3.23) ($0.05)

Adjusted Earnings (Loss) per Share – Diluted* ($1.02) ($0.33) $0.18

Oil Production 86 MBbl/d 80 MBbl/d 77 MBbl/d

Total Production 132 MBoe/d 126 MBoe/d 123 MBoe/d

Realized Oil Price w/ Hedge ($/Bbl) $50.24 $56.92 $62.77

Realized NGL Price ($/Bbl) $34.33 $44.03 $43.13

Realized Natural Gas Price ($/Mcf) $2.90 $2.77 $2.81

Net Income (Loss) Attributable to Common Stock $53 MM ($138) MM ($2) MM

Adjusted EBITDAX* $200 MM $231 MM $250 MM

Capital Investments $50 MM $139 MM** $139 MM

Cash Flow from Operations $133 MM $23 MM $200 MM

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

** 4Q 2017 Includes $14MM of BSP funded capital

http://www.crc.com/


Recent Transactions - 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) $39,847 $35,623

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

http://www.crc.com/


2Q18 Guidance

Anticipated Realizations Against the Prevailing Index Prices for 2Q18

Oil 94% to 98% of Brent

NGLs 52% to 56% of Brent

Natural Gas 81% to 85% of NYMEX

Production, Capital and Income Statement Guidance

Production at $67 Brent 133 to 138 Mboe/d

Production at $74 Brent 131 to 136 Mboe/d

Capital $165 to $185 million

Production Costs at $67 Brent $17.90 to $19.40 per Boe

Production Costs at $74 Brent $18.10 to $19.60 per Boe

Adjusted G&A* $6.45 to $6.75 per Boe

DD&A* $10.30 to $10.60 per Boe

Taxes other than on income $34 to $38 million

Exploration expense $7 to $11 million

Interest expense $91 to $95 million

Cash Interest $150 to $154 million

Income tax expense rate 0%

Cash tax rate 0%

* Guidance assumes production at $74 Brent levels


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


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


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


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


History of Proactive Strategic Decisions

Swift, decisive actions through the commodity downturn have positioned CRC for growth. Proactive discussions with

lenders and solid asset base provide a path to recovery and an actionable inventory.

0

5

10

15

20

25

30

$0

$20

$40

$60

$80

$100

$120

07/20/14 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

rillin

g R

ig C

ou

nt

Bre

nt

Cru

de

Oil P

rice

($

/B

bl)

*

Oil Price

CRC Rig Count

1. Cut rig count/began hedging 4. Deleveraging Transactions

2. Cut 2015 Capital Budget 5. Increasing activity, invest within Cash Flow

3. Bank Amendments 6. JV Transactions

2

1

5

3Under

OXY

6

SPIN-OFF

3

3

33

3

44

4

4

6

63

4

5


PDP Value

Proved Value

Unproved4

$0

$4

$8

$12

$16

$20

$55 Brent $65 Brent $75 Brent

($B

illio

n)

Elk Hills Acquisition Enhances 2017 Reserves1 Value Further Above EV

Current EV of

$6.0 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

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 9 for additional information regarding Adjusted EBITDAX Growth planning scenarios.

Appendix


Deep Inventory of Actionable Projects at $65 Brent

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 For further information on how VCI is calculated please see the end notes. 2 Full cycle costs = operating costs + development costs + facility costs + field-level G&A + taxes other than on income.3 See the Investor Relations page at www.crc.com for details regarding net resources.

0

2

4

6

8

10

0 100 200 300 400 500 600 700 800De

ve

lop

me

nt

Ca

pit

al ($

B)

Net Resources3 (MMBoe)

0

5

10

15

20

25

30

35

40

45

50

0 100 200 300 400 500 600 700 800

Fu

ll C

ycle

Co

st2

($/B

oe

)

Net Resources3 (MMBoe)

Steamflood

Waterflood

Primary

Shale

Gas

http://www.crc.com/


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 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 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


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/


End Notes

From Slide 22

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 4/20/2018 and the 3/31/2018 Pro Forma debt adjusted for the Elk Hills transaction and the April debt repurchases.

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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