SECOND QUARTER 2018 EARNINGS REVIEW · Well Count Avg 30 Day IP Los Angeles Basin San Joaquin Basin...

SECOND QUARTER 2018 EARNINGS REVIEWTodd Stevens | President & CEO | August 2, 2018

Mark Smith | Senior EVP & CFO

2Q 2018 Earnings | 2

Forward Looking / Cautionary StatementsThis 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, which are based on certain estimates including

future production rates, costs and commodity prices

• operations and operational results including production, hedging and capital investment

• Capital budgets and maintenance capital requirements

• reserves

• type curves

• commodity price changes

• debt limitations on our financial flexibility

• insufficient cash flow to fund planned investment or changes to our capital plan

• 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

• effects of PSC-type contracts 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 and limitations on our ability to enter such 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 or

acquisitions or higher-than-expected decline rates

• joint ventures and acquisition activities and our ability to achieve expected synergies

• 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

134 Mboe/d62% Oil

$245 Million$337 million Core

Adjusted EBITDAX3

$194 Million2

$170 million internally funded

83 Gross Wells Drilled1

includes 48 CRC wells

Capital

Adj. EBITDAX4

ACTIVITY

PRODUCTION129 Mboe/d62% Oil

$495 Million$622 million Core

Adjusted EBITDAX3

$355 Million2

$309 million internally funded

157 Gross Wells Drilled1

includes 92 CRC wells

2nd Quarter 2018 First Half 2018

1 Includes JV and non operated wells.2 Includes JV capital.3 Excludes settled hedges of $31MM in Q1 and $68MM in Q2 and cash settled equity compensation of $4MM in Q1 and $24MM in Q2.4 See the Investor Relations page at www.crc.com for a reconciliation to the closest GAAP measure and other important information.

http://www.crc.com/


Development Results Driving Growth

Sacramento Basin

5,000 BOE per Day

No Drilling Rigs in Q2

San Joaquin Basin

98,000 BOE per Day

7 Drilling Rigs

Ventura Basin

6,000 BOE per Day

No Drilling Rigs in Q2

1H 2018 Results of Major Drilling Programs

Q2 2018 Operations Results

Los Angeles Basin

25,000 BOE per Day

3 Drilling Rigs

Drilling Program History

0

50

100

150

200

HuntingtonBeach

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

0

10

20

30

40

Avg

30

Day

IP (

BO

EPD

)

Wel

ls O

nlin

e >3

0 d

ays

Well Count Avg 30 Day IP

Los Angeles Basin San Joaquin Basin

0

25

50

75

100

Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018

Wel

ls D

rille

d

San Joaquin Los Angeles Ventura Sacramento

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.

Avg D&C

Cost ($MM)

per well

$3.00 $1.53 $2.10 $3.30 $0.42

1 1,2


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/


$15MM Implemented

$0 $5 $10 $15 $20

Annualized Synergies ($MM)

Elk Hills Acquisition Synergies

• Streamlined Operations

• Equipment Optimization

• Redundancy Elimination

• Processing Efficiencies

Implemented Savings & Other Synergies

Estimated Annualized Elk Hills Synergies

Initial synergy estimate

within 6 months

Target total synergies

over 18 months


Resilient Resource Base

0

30

60

90

120

150

180

210

240

0

20

40

60

80

100

120

140

160

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

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 investment based on the accounting treatment of each venture.

** Q3 2018 Capital guidance includes CRC, BSP and MIRA capital.


Q1'16

Q2'16

Q3'16

Q4'16

Q1'17

Q2'17

Q3'17

Q4'17

Q1'18

Q2'18

Q3E'18

Field Production1

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

Production Delivers Growth with Expanding Adjusted EBITDAX Margins

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

0

40

80

120

160

200

240

280

320

360

Q1 '16 Q2 '16 Q3 '16 Q4 '16 Q1 '17 Q2 '17 Q3 '17 Q4 '17 Q1 '18 Q2 '18$

MM

Adjusted EBITDAX

Adj. EBITDAX Margin

Impact of Accounting Change

Adj. EBITDAX

Core Adj. EBITDAX

CRC reversed 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.2 Core Adjusted EBITDAX excludes settled hedges and equity compensation costs. 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 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 prior period.

3

2

2

2

Elk Hills Acquisition

http://www.crc.com/


Drilling

JV - Capital

Workover

Development Facilities

Exploration Other

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

• Additional Capital will be deployed to Drilling, Workovers and Facilities focused in the Ventura

and San Joaquin Basins

• 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

2018 Capital Investment Program – Transitioning to Mid-Cycle Commodity Prices

Approx. $650 to $700 million

1Facility and other support 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.3Other 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

47%

15%

13%

21%

3%

Conventional

Waterfloods

Steamfloods

Unconventional

46%

31%

13%

At $65 flat Brent and $3 NYMEX, the

fully-burdened1 2017 CRC Development

Program delivered a 2.0 VCI or 45% IRR2

Approx. $405 million Approx. $405 million

10%

2018E Internally Funded

Development Capital By Basin

67%

5%

28%

1%3


80

90

100

110

120

130

2017 2018E 2019E 2020E 2021E

Oil

Pro

du

ctio

n (

MB

/d)

400

800

1,200

1,600

2,000

2,400

Ad

just

ed E

BIT

DA

X

($M

M)

Portfolio Flexibility Provides Range of Crude Oil Scenarios

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

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

business in 2019 and beyond for each scenario. Please see end notes for further information regarding Adjusted EBITDAX.1 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.2 See the Investor Relations page at www.crc.com for a reconciliation to the closest GAAP measure 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

basis1

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/

http://www.crc.com/


$3.26 $3.14 $2.95 $3.00 $2.87 $2.75

$2.90 $2.47 $2.56 $2.77 $2.81

$2.25

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

4.00

1Q 2017 2Q 2017 3Q 2017 4Q 2017 1Q 2018 2Q 2018

$/M

cf

NYMEX Realizations

CRC – Price Realizations

66% 62%72% 79%

69%

62%

63% 59%66%

72%64%

56%

0%

20%

40%

60%

80%

100%

1Q 2017 2Q 2017 3Q 2017 4Q 2017 1Q 2018 2Q 2018

% o

f W

TI

& B

ren

t

WTI Brent

$51.91 $48.29

$48.21

$55.40

$62.87

$67.88

$50.24 $47.98

$50.02

$56.92 $62.77

$64.11 $54.66 $50.92 $52.18

$61.54

$67.18 $74.90

30

40

50

60

70

80

1Q 2017 2Q 2017 3Q 2017 4Q 2017 1Q 2018 2Q 2018

$/B

bl

WTI Realizations Brent

Realization

% of WTI97% 99% 104% 103% 100% 94%

Realization

% of NYMEX89 % 79% 87% 92% 98%* 82%*

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 continued limits on 3rd party storage

• 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.

*

Seasonality in NGL prices

experienced in Q2 every year

*


120

234

0

50

100

150

200

250

300

3501H17 Volume Price* Costs Interest

Working

Capital/Other 1H18$

MM

Strong Cash Flow GrowthO

pe

rati

ng

Ca

sh

Flo

w

*Includes effects of PSCs


250 245

0

50

100

150

200

250

300

350Q1 2018

Elk Hills

Acquisition Price Settled Hedges

Long Term Equity

Compensation

Expense Other* Q2 2018$

MM

Cash settled – avoided share count dilution

Cash Generation Improvement Offset by Hedges and Equity CompensationA

dju

ste

d E

BIT

DA

X

*Other includes lower seasonal trading income and higher G&A partially due to timing.


Quarterly Cost Comparison

2Q17 1Q18 2Q18 2Q18

Production costs

($/Boe)$18.34 $19.08 $18.93 $18.52

Production costs

excluding PSC effects

($/Boe)

$17.18 $17.47 $17.41 $17.00

Taxes other than on

income ($MM)$31 $38 $37

Exploration expense

($MM)$6 $8 $6

Interest expense

($MM)$83 $92 $94

Without the increase

in compensation due

to stock price


2Q18 Results Summary Comparison

2Q17 1Q18 2Q18

Net Income (Loss) Attributable to Common Stock per

Share – Diluted

($1.13) ($0.05) ($1.70)

Adjusted Earnings (Loss) per Share – Diluted* ($1.83) $0.18 ($0.29)

Oil Production 83 MBbl/d 77 MBbl/d 83 MBbl/d

Total Production 129 MBoe/d 123 MBoe/d 134 MBoe/d

Realized Oil Price w/ Hedge ($/Bbl) $47.98 $62.77 $64.11

Realized NGL Price ($/Bbl) $30.08 $43.13 $42.13

Realized Natural Gas Price ($/Mcf) $2.47 $2.81 $2.25

Net Income (Loss) Attributable to Common Stock ($48) MM ($2) MM ($82) MM

Adjusted EBITDAX* $161 MM $250 MM $245 MM

Internally Funded Capital Investments $45 MM $139 MM $170 MM

Cash Flow (used) provided by Operations ($13) MM $200 MM $34 MM

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

http://www.crc.com/


Recent Transactions - Improving Debt Metrics

6/30/2018

1st Lien 2014 Revolving Credit Facility (RCF) 277$

1st Lien 2017 Term Loan 1,300

1st Lien 2016 Term Loan 1,000

2nd Lien Notes 2,153

Senior Unsecured Notes 345

Total Debt 5,075

Less cash1

(19)

Total Net Debt 5,056

Mezzanine Equity 735

Equity (645)

Total Net Capitalization 5,146$

Total Debt / Total Net Capitalization 99%

Total Debt / LTM Adjusted EBITDAX3

5.1x

LTM Adjusted EBITDAX3

/ LTM Interest Expense 2.8x

PV-104 / Total Debt 1.0x

Total Debt / Proved Reserves5 ($/Boe) $7.44

Total Debt / Proved Developed Reserves5 ($/Boe) $10.42

Total Debt / 2Q18 Production ($/Boepd) $37,873

Capitalization ($MM)

1 Excludes $23MM of restricted cash.2 Includes $144 million of noncontrolling interest equity for BSP and Ares.3 LTM Adjusted EBITDAX includes a +$85 million adjustment as a result of the Elk Hills transaction.4 PV-10 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.5 Reserves include an estimate of the Elk Hills reserves acquired at SEC 2017 pricing.

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)

Notable Quarterly Highlights

• Repurchased face value of $95 million of 2nd Lien Notes

and $48 million of 2024 Senior Notes in the second

quarter for $118 million 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

http://www.crc.com/


2Q18 Guidance

Anticipated Realizations Against the Prevailing Index Prices for 3Q18

Oil 95% to 100% of Brent

NGLs 55% to 60% of Brent

Natural Gas 100% to 110% of NYMEX

Production, Capital and Income Statement Guidance

Production* 134 to 138 Mboe/d

Capital $180 to $200 million

Production Costs* $18.60 to $20.10 per Boe

Adjusted G&A* $6.60 to $6.90 per Boe

DD&A* $10.05 to $10.35 per Boe

Taxes other than on income $42 to $46 million

Exploration expense $6 to $10 million

Interest expense $94 to $98 million

Cash interest $66 to $70 million

Income tax expense rate 0%

Cash tax rate 0%

* Based on average Q2 2018 Brent of $75.


3Q

2018

4Q

2018

1Q

2019

2Q

2019

3Q

2019

4Q

2019

FY

2020

FY

2021

Sold Calls Barrels per Day 6,100 16,100 16,100 6,000 1,000 1,000 500 -

Weighted Average

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

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

Weighted Average

Ceiling Price per Barrel- - $71.00 - - - - -

Purchased Puts Barrels per Day 6,900 1,900 34,800 36,700 31,700 21,600 1,500 600

Weighted Average

Floor Price per Barrel$61.31 $51.70 $62.77 $67.40 $70.50 $73.09 $47.97 $45.00

Sold Puts Barrels per Day 24,000 19,000 35,000 30,000 30,000 20,000 - -

Weighted Average

Floor Price per Barrel$46.04 $45.00 $50.71 $55.00 $56.67 $60.00 - -

Swaps Barrels per Day 48,000 29,000 7,000 - - - - -

Weighted Average

Price per Barrel$60.35 $60.50 $67.71 - - - - -

Percentage of 2Q 2018

Oil Production Hedged66% 37% 50% 44% 38% 26% 2% 1%

Opportunistically Built Oil Hedge Portfolio

As of 7/10/2018, assumes counterparty options are not exercised. Certain of our counterparties have options to increase swap volumes at weighted average

prices between $60 and $70 Brent. For potential volume changes and further details please see Attachment 8 of our Earnings Release.

We target hedges

on 50% of crude

oil production

Strategy Protect cash flow, operating margins

and capital investment program


3,000

4,000

5,000

6,000

7,000

2Q15 Debt Exchange for2L

Open MarketPurchases

Equity for DebtExchange

Cash Tender forUnsecureds

Cash & WorkingCapital

2Q18

Tota

l Deb

t ($

MM

)Significant Reduction in Total Debt from Post-Spin Peak

Total

Total Debt Reduction$535

million

$298

million

$102

million

$625

million

$130

million$1,690 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.

5,075

2018 Debt

Repurchases

$145MM6,7651


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

rilli

ng

Rig

Co

un

t

Bre

nt

Cru

de

Oil

Pri

ce (

$/B

bl)

Oil Price

CRC Rig Count

1. Cut Rig Count/Began Hedging 4. Deleveraging Transactions

2. Cut 2015 Capital Budget 5. Increasing Activity

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

$24

$28

$65 Brent $75 Brent $85 Brent

($B

illio

n)

Elk Hills Acquisition Enhances NAV Above EV

Current EV of

$7.8 Bn5

Infrastructure2

Surface & Minerals3

1-5 See endnotes in the Appendix.

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

1

1

http://www.crc.com/


0

500

1,000

1,500

2,000

2,500

2017 2018E 2019E 2020E 2021E

$M

M

The Case for CRC: Investment Thesis Overview

Industry

leading base

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 10 for additional information regarding Adjusted EBITDAX Growth planning scenarios.

Appendix


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 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 consists of three CRC representatives and three representatives

from Ares


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

-

10,000

20,000

30,000

40,000

50,000

1992 1996 2000 2004 2008 2012 2016

Bo

e/d

Base Incremental

LBU PSC

-

2,000

4,000

6,000

8,000

10,000

12,000

2006 2008 2010 2012 2014 2016B

oe/

d

Base Incremental

Tidelands PSC

Base Profit Split:

4% CRC / 96% State*

Incremental Profit Split:

49% CRC / 51% State*

Base Profit Split:

4% CRC / 96% State*

Incremental Profit Split

49% CRC / 51% State & City*

*Average profit split %.

End of

LBU

Base

First of 3 new

PSC’s executed


40 45 50 55 60 65 70 75 80 85 90 95 100

Realized Price ($/Boe)

Wilmington Production Sharing Contracts

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

• PSC Mechanics

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

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

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

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

Effect of Oil Price on Net Production

Higher oil prices result in higher

cash flow, but lower net production

Cost Recovery Bbls

Net Profit Bbls 45-49% of Gross Production

Gross Production


Value Additive Inventory Growth

• Comprehensive technical review of 40% of CRC’s fields.

• 2017 proved reserves of 618 million BOE (682 million BOE pro forma including the Elk Hills acquisition) 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

64222 251

202321

340

826

1,129

0

250

500

750

1,000

1,250

1,500

1,750

2,000

2,250

2,500

Spin-off 2015 2016 2017

MM

Bo

e

2017 Unproven

Revisions due to Price since 2014

Est. 2017 Reserves associated with Elk Hills Transaction

2017 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 21

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 June 30, 2018 debt at par and a market cap as of 7/24/2018. Includes mezzanine equity and non-

controlling interest equity.

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.

SECOND QUARTER 2018 EARNINGS REVIEW · Well Count Avg 30 Day IP Los Angeles Basin San Joaquin Basin...

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