crc 1q 2019 earnings presentation · 1q 2019 earnings | 3 key highlights $301 million $1,168...

First Quarter 2019 Earnings ReviewMay 2, 2019

Todd Stevens | President & CEO

Mark Smith | Senior EVP & CFO

1Q 2019 Earnings | 2

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.

• 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.

Forward Looking / Cautionary Statements – Certain Terms

See the Investor Relations page at www.crc.com for important information about 3P reserves and other hydrocarbon resource quantities, PV-10 and standardized measure, finding and development

(F&D) costs, recycle ratio calculations, reserve replacement ratios, Value Creation Index (VCI), debt adjusted shares calculation, drilling locations and reconciliations of non-GAAP measures to the

closest GAAP equivalent.

http://www.crc.com/


Key Highlights

$301 Million$1,168 million LTM

1st Quarter 2019

1 Includes all wells drilled by CRC, including JV wells.2 Includes BSP and MIRA capital.3 See the Investor Relations page at www.crc.com for

historical reconciliations to the closest GAAP measure and other important information.

4 Calculated as oil and gas revenue, including settled hedges, on a per BOE basis, less production costs per BOE, excluding the effect of PSC-type contracts.

$138 Million2

$104 million internally funded

133 Mboe/d63% Oil

60 Total Wells Drilled1

Includes 42 CRC wells

Adj. EBITDAX3 Growth

Operating Margin4 Growth

http://www.crc.com/


Strengthen

Balance SheetDrive Operational

Excellence

Ensure Effective

Capital Allocation

CRC’s Value-Driven Strategic Approach

• Reinvest to grow cash

flow

• Simplify capital

structure

• Enhance credit metrics

• Pursue value-accretive

M&A

• Reduce absolute level of

debt

• 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

• Pursue value-driven

production growth

• Delineate future growth

areas

• Enhance already

substantial inventory

• Pursue strategic joint

ventures

Capture Value

of Portfolio

Proven and pressure-tested strategic approach

preserved value through the downturn and is set to

drive significant value creation for years to come


0

25

50

75

100

125

1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 1Q19

Gro

ss W

ells D

rille

d San Joaquin Los Angeles Ventura

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 3

0 D

ay

Pe

ak

Ra

te (

BO

EP

D)

We

lls O

nlin

e >

30

da

ys

Well Count Avg 30 Day Peak Rate

2 2,3

Development Results Driving Growth

Sacramento Basin

5,000 BOE per day

No Active Drilling

San Joaquin Basin

97,000 BOE per day

6 Drilling Rigs1

Ventura Basin

6,000 BOE per day

No Active Drilling

Los Angeles Basin

25,000 BOE per day

1 Drilling Rig1

Los Angeles Basin San Joaquin Basin

1 Average CRC operated drilling rigs per quarter. 2Includes JV wells. 3 Kern Front wells are steam flood wells which have low IPs and then ramp up over a period of 12-24 months.4 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 well4$3.5 MM $1.7 MM $2.2 MM $3.9 MM $0.4 MM

FY 2018 Results of Major Drilling Programs

Q1 2019 Operations Results


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

• 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

0

5

10

0 100 200 300 400 500 600 700 800Dev

Cap

ital

(B

$)

Net Resources2 (MMBoe)

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 3P resources and other hydrocarbon resource

quantities.

0

10

20

30

40

50

0 100 200 300 400 500 600 700 800

Full

Cyc

le C

ost

1($

/Bo

e)

Net Resources2 (MMBoe)

Steamflood

Waterflood

Primary

Shale

Gas

http://www.crc.com/


JVs Provide Additional Capital Flexibility

Net Production By Stream (Mboe/d)

1Total Capital reflected in the graph includes the capital investment of internal CRC capital as well as JV partners BSP

and MIRA. Our consolidated financial statements include BSP’s investment and exclude MIRA’s investment based

on the accounting treatment of each venture.22Q19 capital guidance includes CRC, BSP and MIRA capital.


Disciplined Capital Plan Leverages Project Portfolio

50-55%

Core

Workover

Growth

FacilitiesOther

VenturesExploration

5-10%

15%

14%

8%2%

2019 Internally Funded

Capital Program

$300 to $385 Million

Discretionary Cash Flow

Expect to Align with

Core Program

Potential 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.

1Buena Vista | Elk Hills | Long Beach

Kern Front | Mount Poso


Production Delivers Growth with Expanding Adjusted EBITDAX Margins

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 Earnings Release for the calculation of Adj. EBITDAX Margin and Revenues, which excludes non-cash

derivatives gains and losses.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 Adjusted EBITDAX to the closest GAAP measure and other

important information.

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

0

50

100

150

200

250

300

350

400

450

1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 1Q19

% o

f R

eve

nu

es

2

$M

M

Adjusted EBITDAX

Adj. EBITDAX Margin

Adj. EBITDAX4

2, 3

Field Production1

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

Elk Hills Acquisition

Increasing oil production

and Adjusted EBITDAX

http://www.crc.com/


CRC believes near-term crude oil

realizations will remain strong

CRC Price Realizations

69%62% 66%

74%77%

64%56% 60% 64% 67%

0%

20%

40%

60%

80%

100%

1Q18 2Q18 3Q18 4Q18 1Q19

% o

f W

TI

& B

ren

t

WTI Brent

Oil Price Realization (with Hedges) Gas Price Realization

• 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 peak demand and seasonality.

• NGL prices have been supported by lower inventories and export

markets.

NGL Price Realization - % of WTI & Brent

$62.87

$67.88 $69.50

$58.81 $54.90 $62.77

$64.11 $63.63 $59.97

$65.28 $67.18

$74.90 $75.97

$68.08

$63.90

30

40

50

60

70

80

1Q18 2Q18 3Q18 4Q18 1Q19

$/B

bl

WTI Realizations Brent

Realization

% of WTI100% 94% 92% 102% 119%

-≈

$2.87 $2.75

$2.88

$3.40 $3.24

$2.81

$2.25

$3.16

$3.77

$3.43

1.50

2.00

2.50

3.00

3.50

4.00

1Q18 2Q18 3Q18 4Q18 1Q19

$/M

cf

NYMEX Realizations

≈

Realization %

of NYMEX98% 82% 110% 111% 106%

-

-≈


44

250

44

27

21

3

301

0

50

100

150

200

250

300

3501Q18 Volume Price Costs Trading Income Other 1Q19

$M

M

Strong Adjusted EBITDAX GrowthO

pe

rati

ng

Ca

sh

Flo

w

1 Costs includes changes in operating expenses, general and administrative expenses, and taxes.

1


250

500

1000

$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

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

2014

(Pre-spin)2015

2016

20172018

1Includes JV Capital.

Capital Investment

Scale ($MM)

1

1


1Q18 4Q18 1Q19

Net Income (Loss) Attributable to Common

Stock per Share – Diluted

$(0.05) $7.00 $(1.38)

Adjusted Net Income1 per Share – Diluted $0.18 $0.53 $0.63

Oil Production 77 MBbl/d 86 MBbl/d 84 MBbl/d

Total Production 123 MBoe/d 136 MBoe/d 133 MBoe/d

Realized Oil Price w/ Hedge ($/Bbl) $62.77 $59.97 $65.28

Realized NGL Price ($/Bbl) $43.13 $43.56 $42.52

Realized Natural Gas Price ($/Mcf) $2.81 $3.77 $3.43

Net Income (Loss) Attributable to Common Stock $(2) MM $346 MM $(67) MM

Adjusted EBITDAX1 $250 MM $314 MM $301 MM

Internally Funded Capital Investments $139 MM $174 MM $104 MM

Cash Flow Provided by Operations $200 MM $68 MM $158 MM

First Quarter 2019 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/


Quarterly Cost Comparison

1Q18 4Q18 1Q19

Production costs ($/Boe) $19.08 $18.61 $19.46

Production costs excluding PSC

effects ($/Boe)$17.47 $17.44 $18.01

Taxes other than on income

($MM)$38 $29 $41

Exploration expense ($MM) $8 $16 $10

Interest expense ($MM) $92 $98 $100


Recent Transactions - Improving Debt Metrics

3/31/2019

1st Lien 2014 Revolving Credit Facility (RCF) 576$

1st Lien 2017 Term Loan 1,300

1st Lien 2016 Term Loan 1,000

2nd Lien Notes 2,049

Senior Unsecured Notes 344

Total Debt 5,269

Less cash (17)

Total Net Debt 5,252

Mezzanine Equity 766

Equity (289)

Total Net Capitalization 5,729$

Total Debt / Total Net Capitalization 92%

Total Debt / LTM Adjusted EBITDAX3

4.5x

Total Debt / 1Q19 Annualized Adjusted EBITDAX4

4.3x

LTM Adjusted EBITDAX3

/ LTM Interest Expense 3.0x

PV-105 / Total Debt 1.8x

Total Debt / Proved Reserves5 ($/Boe) $7.40

Total Debt / Proved Developed Reserves5 ($/Boe) $9.94

Total Debt / 1Q19 Production ($/Boepd) $39,617

Capitalization ($MM)

1 Excludes $26 MM of restricted cash.2 Includes $137 million of noncontrolling interest for BSP and Ares.3 See the Investor Relations page at www.crc.com for historical reconciliations to the closest GAAP measure

and other important information. 4 1Q19 Annualized EBITDAX reflects realized oil price including the effect of hedges of $65.28/bbl Brent.5 Proved Reserves and PV-10 estimates are as of 12/31/18 and 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.6 The 2017 Term Loan remains subject to a springing maturity in October 2021 related to the outstanding

balance of the 2016 Term Loan.

$0

$1,000

$2,000

$3,000

$4,000

2019 2020 2021 2022 2023 2024

2nd Lien Notes

2014 RCF

Unsecured Notes

2016 Term Loan

2017 Term Loan

Debt Maturities ($MM)

1

2

6

http://www.crc.com/

http://www.crc.com/


• Completed a sale of operatorship and a 50% working interest in certain zones in the Lost Hills field

• Over $200 MM in total consideration consisting of $168 MM in cash + drilling carry with estimated minimum value of $35 MM

• Implied transaction metrics (assuming minimum carry):

• ~$88,000 per flowing barrel

• Other transaction highlights:

• Partner will carry CRC on 100% of the investment in 200 new wells

• Operatorship is transferred to buyer

• CRC retains rights to deep formations

• Closed May 1, 2019

• Lost Hills is a heavy oil field in the northwestern San Joaquin basin

Lost Hills Field – 50% Operated Working Interest Sale + Joint Venture

Map to be updated

Proposed Patterns

Proposed Tulare Producer

Elk Hills

Buena Vista

Lost Hills

Kern

Front


Second Quarter 2019 Guidance

Anticipated Realizations Against the Prevailing Index Prices for 2Q19

Oil 95% to 100% of Brent

NGLs 41% to 46% of Brent

Natural Gas 85% to 95% of NYMEX

Production, Capital and Income Statement Guidance

Production1 127 to 133 Mboe/d

Capital2 $115 to $145 million

Production Costs1 $17.75 to $19.25 per Boe

Adjusted G&A1 $6.55 to $6.95 per Boe

DD&A1 $10.15 to $10.45 per Boe

Taxes other than on income $36 to $40 million

Exploration expense $9 to $14 million

Interest expense $96 to $101 million

Cash interest $151 to $156 million

Income tax expense rate -- to --

Cash tax rate -- to --

1Based on average Q2 2019 Brent price of $68 per barrel. 2Capital guidance includes CRC, BSP, and MIRA capital. For further detail on our Q2 2019 guidance, please see our latest Earnings Release.


Opportunistically Built Oil Hedge Portfolio

Strategy

Protect cash flow, operating

margins and capital

investment program

Hedge program continues to target

hedges on 50% of crude oil production

and provides more upside exposure to

commodity price movement

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 7 of

our Earnings Release.

Sold Calls

Purchased

Puts

Sold Puts

3Q19 4Q19 1Q20 2Q20

Barrels per Day

Weighted Average

Ceiling Price per Barrel

-

-

-

-

40,000

$73.13

40,000

$57.50

-

-

-

-

-

-

35,000

$75.71

35,000

$60.00

-

-

-

-

-

-

20,000

$72.50

20,000

$57.50

5,000

$70.29

-

-

-

-

10,000

$70.00

10,000

$55.00

5,000

$70.05

48% 42% 30% 18%Percentage of 1Q19 Oil Production

Hedged Against Downside

2Q19

Purchased

Calls

Swaps

Barrels per Day

Weighted Average

Ceiling Price per Barrel

Barrels per Day

Weighted Average

Floor Price per Barrel

Barrels per Day

Weighted Average

Floor Price per Barrel

Barrels per Day

Weighted Average

Price per Barrel

5,000

$68.45

-

-

40,000

$69.75

35,000

$55.71

-

-

48%


CRC Significantly Undervalued

EV Undervalued

CRC has a top PV-101 value

among Proxy peers, but is

undervalued by enterprise

value.

CRC’s market cap and debt

are significantly below the

PV-101 value of our assets.

1PV-10 values as disclosed in 4Q18 and effective 12/31/18 using

2018 SEC pricing: Brent $71.75, WTI $65.55, NYMEX $3.10.

Total debt as of 12/31/18. Market capitalization as of 4/30/19.

Note Proxy peers include: COG, CPE, CRZO, DNR, EPE, FANG, LPI,

MTDR, MUR, OAS, PDCE, PE, QEP, RRC, SM, SWN, WLL, WPX, XEC.

% D

isco

un

t o

f E

nte

rpri

se

Va

lue

/ P

V-1

01


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.

Current EV

of $7.2 Bn5

http://www.crc.com/


Disciplined Execution on Highest Value Projects to Deliver Substantial Value

Portfolio of world-class assets investable

throughout the commodity cycle

Robust inventory of high value

growth projects

Deep operational knowledge

and technical expertise

Integrated and complementary

infrastructure

Disciplined and effective

capital allocation

Balance Sheet Goals

High VCI Projects

Investing for the Future

Growth Prospects

Core Operating Areas

Simplify Balance Sheet

Reduce Fixed Charges

Reduce Debt

Balance capital investment with

Financial

Strengthening Effortsfor best long-term value creation

VALUE DRIVEN

APPENDIX


Pressure Tested Through Cycle and Focused on Long-Term Value

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 07/19

Rig

Co

un

t

Bre

nt

Cru

de

Oil P

rice

($

/B

BL)

Brent Crude Price

CRC + JV Rig Count

CRC Rig Count

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


“Duck” Curve

California Policies Impact Natural Gas Prices

Limited third-party storage, peak demand, and

reliance on renewable sources have increased

volatility in local natural gas prices

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

$16

$18

$20

01/17 04/17 07/17 10/17 01/18 04/18 07/18 10/18 01/19 04/19

So Cal City Gate Wheeler Ridge NG Futures

Lack of Natural Gas Storage and Peak Demand

California Natural Gas Prices

Impact of Solar Generation

Aliso Canyon Effect on Inventory

>$20

Source: Bloomberg

Source: California ISO

>$20


• Up to $250MM over ~2 years

▪ Four tranches of $50MM

▪ Total of $200MM funded

• Investor funds 100% of project capital

in exchange for a net profits interest

(NPI)

▪ Investor NPI interest reverts to CRC

after low teens target IRR

▪ CRC retains early termination options

• Current focus is in the San Joaquin

and Los Angeles Basin

• CRC operates all wells

• Up to $300MM

▪ Current commitment of $140MM

• DrillCo type structure where Investor

funds 100% of project capital for 90%

WI, with CRC carried on its 10% WI

▪ CRC interest reverts to 75% after

target IRR is achieved

▪ CRC retains early termination options

• Focus on four fields within the San

Joaquin Basin

▪ Kern Front, Mt. Poso, Pleito Ranch,

Wheeler Ridge

• CRC operates all wells

Highlights

Accelerating Value and Derisking Inventory through JVs


-

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 101105109113117

JV 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 IncrementalTidelands 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


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

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

Realized Price ($/Boe)

Cost Recovery Bbls

Net Profit Bbls 45-49% of Gross Production

Gross Production

Higher oil prices result in higher

cash flow, but lower net production

Effect of Oil Price on Net Production


0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

$-

$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

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

Proxy Group Peers with Published Oil Hedges

Median Peer Floor Price: ~$55/Bbl (WTI)

Opportunistically Built Oil Hedge Portfolio

Highest Floor Price Among Peers

CRC has a well-positioned

2019 hedge portfolio that still

provides upside exposure to

commodity price movements

CRC benefits from both Brent

pricing and a top hedge

portfolio compared to Proxy

peer group after accounting

for Brent pricing advantage.

1At prices above $58/bbl Brent. At prices below $58/bbl,

the hedge value is $15/bbl + Brent.

Note: Hedge positions cover Q2-Q4 of 2019 and are

current as of 4Q18 Earnings.

Proxy peers with published hedges include: CPE, CRZO,

DNR, EPE, FANG, LPI, MTDR, OAS, PDCE, PE, QEP, RRC,

SM, SWN, WLL, WPX, XEC.

CRC’s 2019 Weighted Avg Floor Price: ~$731/Bbl

(Brent)


End Notes

From Slide 20

1 CRC estimate of reserves value as of December 31, 2018. 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, excluding assets owned by the Ares JV, at 50% of estimated replacement value.

This discount is estimated to exceed the burden on reserves that would be incurred if assets were monetized. Does not include value

of extensive seismic library.

3 Surface & Mineral reflects 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 March 31, 2019 debt at par and a market cap as of 4/30/2019. Includes non-controlling interests reported as

mezzanine and permanent equity as of March 31, 2019.

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

PV-10 and standardized measure, finding and development (F&D) costs, recycle ratio calculations, reserve replacement ratios, Value

Creation Index (VCI), debt adjusted shares calculation, drilling locations and reconciliations of non-GAAP measures to the closest GAAP

equivalent.

http://www.crc.com/

crc 1q 2019 earnings presentation · 1q 2019 earnings | 3 key highlights $301 million $1,168...

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