fourth quarter and full year 2019 earnings review february ...€¦ · fourth quarter and full year...

Fourth Quarter and Full Year 2019 Earnings Review

February 26, 2020

Todd Stevens | President & CEO

Mark Smith | Senior EVP & CFO

4Q 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 made 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 into desirable transactions, including acquisitions, asset sales and

joint ventures

• legislative or regulatory changes, including those related to drilling, completion, well

stimulation, operation, inspection, 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 or liquidity, including as a result of lender restrictions, the

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, power outages, transportation or

storage constraints, natural disasters, pandemics, labor difficulties, cyber attacks or

other catastrophic events

• factors discussed in “Item 1A – 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 additional 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, VCI, debt-adjusted shares calculations, drilling locations and reconciliations of non-GAAP measures to the closest GAAP equivalent.

http://www.crc.com/


Key Highlights

1 Includes all wells drilled by CRC, including BSP, MIRA and Alpine wells. Includes steam injectors and drilled but uncompleted wells, which would not be included in the SEC definition of wells drilled.2 Includes BSP, MIRA and Alpine capital.3 See the Investor Relations page at www.crc.com for a reconciliation to the closest GAAP measure and other important information.4 Reflects the face amount of principal reduced.

$308 Million

4th

Qu

art

er

20

19

$146 Million2

$62 million

internally funded

123 Mboe/d62% Oil

104 Total Wells Drilled1

Includes 15 internally

funded wells

$1.14 Billion$612 Million2

$407 million

internally funded

128 Mboe/d63% Oil

294 Total Wells Drilled1

Includes 126 internally

funded wells

Fu

ll Y

ea

r 2

01

9

AC

TIV

ITY

PR

OD

UC

TIO

N

CA

PIT

AL

Ad

j.E

BIT

DA

X3

$19 Million Reduction

$274 Million Reduction

TOTA

L D

EB

T4

http://www.crc.com/


Strengthen

Balance SheetDrive Operational

Excellence

Ensure Effective

Capital Allocation

• 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

CRC’s Value-Driven Strategic Approach

Proven and pressure-tested strategic approach

preserved value through the downturn and is set to

drive significant value creation for years to come


1 Average CRC operated drilling rigs in the quarter. 2 Includes all wells drilled by CRC, including BSP, MIRA and Alpine wells. Includes steam injectors and drilled but uncompleted wells, which would not be included in the SEC

definition of wells drilled. 3 Kern Front wells are steamflood wells which have low IPs and then ramp up over a period of 12-24 months. 42019 drilling and completion costs may not be comparable to prior periods due to variances

in project mix, well depth, horizontal length and other aspects. 5 Peak rate is the average of the highest well test rate for each well drilled in 2019.

0

2,000

4,000

6,000

8,000

0

25

50

75

100

125

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

Ave

rage

Mea

sure

d W

ell D

epth

(ft

)

To

tal W

ells D

rille

d2

San Joaquin Los Angeles Ventura Average Well DepthDrilling Program History

0

100

200

300

400

500

600

HuntingtonBeach

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

Mount Poso ESOZ

0

10

20

30

40

50

60

70

80

90

100

Ave

rage

We

ll T

est

Pe

ak

Ra

te (

BO

EP

D)

We

lls O

nlin

e >

30

da

ys

Well Count Average Peak Rate

2 2,3

Development Activity Driving Value

Sacramento Basin

4,000 BOE per day

No Active Drilling1

San Joaquin Basin

91,000 BOE per day

7 Drilling Rigs1

Ventura Basin

5,000 BOE per day

No Active Drilling1

Los Angeles Basin

23,000 BOE per day

1 Drilling Rig1

San Joaquin Basin

2019 Results of Major Drilling Programs

Q4 2019 Operations Results

Average

D&C Cost

per well4

$3.2 MM $1.0 MM $1.8 MM $3.4 MM $0.4 MM $0.8 MM5

5

$0.6 MM

2

Los Angeles Basin


0

5

10

15

20

25

30

35

40

45

50

0 100 200 300 400 500 600 700F

ull C

ycle

Co

st1

($/B

oe

)Net Resources2 (MMBoe)

Unlocking Value with a Deep Inventory of Actionable Projects at $60 Brent

• Fully burdened, growth-focused

portfolio

• Achieve a VCI of 1.3 or greater at

$60 Brent and $3.00 NYMEX

• Projects deliver robust cash flow

• Reflects all recovery

mechanisms and reserves types

• Leverage existing infrastructure,

while opportunistically targeting

new infrastructure investment

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 and other hydrocarbon resource

quantities.

Steamflood

Waterflood

Primary

Shale

Gas

02468

0 100 200 300 400 500 600 700De

v C

ap

ita

l ($

B)

Net Resources2 (MMBoe)

http://www.crc.com/


542

1,583

CRCContingentResources(MMBOE)1

CO2 EOR Technical

CCS+EOR Project Elements• Awarded financial assistance from the Department of Energy

on carbon capture FEED study to capture CO2 produced at

the Elk Hills power plant

• Over 150 MMBOE of enhanced recovery potential2 from

existing producing reservoirs utilizing CO2 EOR at Elk Hills

• Potentially up to 542 MMBOE of enhanced recovery

• Designing long-term carbon sequestration and monitoring

• Engaged with key regulatory agencies

Elk Hills Carbon Capture and Sequestration (CCS)

20

18

20

20

20

22

20

24

20

26

20

28

20

30

20

32

20

34

20

36

20

38

20

40

20

42

20

44

20

46

Net

BO

PD

Elk Hills CCS + EOR Project

Projected CO2

Production Response

Projected Base Production

California Energy Commission:

The Project identified the Elk Hills Field as one of the premier CO2 EOR and sequestration sites in the U.S. As

described in this Appendix, analysis and study of the Elk Hills Field has confirmed that it is an optimal site for the

safe and secure sequestration of CO2.

- Report to the Legislature under AB 1925, App. F, page 29 (2010)

‘‘

‘‘1 As of year-end 2019.2 Based on internal estimates.


Total of $200MM fully funded

Focus on three fields within the San

Joaquin Basin

▪ Kern Front, Mt. Poso, Pleito Ranch

Accelerating Value and Derisking Inventory through Development JVs

Up to $500MM

▪ Current commitment of $320MM, with

$134MM funded through 2019

Investor funds project capital in exchange

for a net profits interest (NPI) held through

a JV

▪ Investor preferred interest fully reverts

upon achieving target IRR

▪ CRC retains an acceleration option

Focus on the San Joaquin and

Los Angeles Basins

CRC operates all wells

Up to $140MM

▪ $138MM funded through 2019

DrillCo-type structure where investor funds

100% of project capital for 90% working

interest (WI) in wells drilled, with CRC

carried on its 10% WI

▪ CRC interest increases to 75% upon investor

achieving target IRR

▪ CRC retains an acceleration option


DrillCo-type structure where investor

funds 100% of project capital for 90% WI

in wells drilled, with CRC carried on its

10% WI

▪ CRC interest increases to 82.5% upon

investor achieving target IRR

Focus on portions of the Elk

Hills field within the San

Joaquin Basin


April 2017Feb 2017 July 2019


$0

$40

$80

$120

$160

$200

$240

$280

$320

0

20

40

60

80

100

120

140

160

1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 1Q19 2Q19 3Q19 4Q19 1Q20E

Ca

pit

al ($

MM

)

Pro

du

cti

on

(M

BO

EP

D)

Oil NGL Gas Total Capital CRC Capital (Internally Funded)

JVs Provide Additional Capital Flexibility

Net Production By Commodity (MBOEPD)

1 Total Capital reflected in the graph includes the capital investment of internal CRC capital as well as JV partners BSP, MIRA, and Alpine. Our consolidated financial statements include BSP’s

investment and exclude MIRA’s and Alpine’s investment based on the accounting treatment of each venture.

1


JV

33%

Drilling and

Completion

40%

Workover

9%

Facilities

13%

Exploration

2% Other

3%

1

San Joaquin, ~75%

Los Angeles, ~20%

Sacramento and

Ventura, ~5%

Disciplined Capital Plan Leveraged Project Portfolio

2019 Internally Funded

Development Capital By Basin2019 Total Capital

1 Other includes corporate, maintenance and occupational health, safety and environmental projects and other investments.

Primary,

~13%

Waterflood, ~40%Steamflood, ~9%

Unconventional,

~38%

2019 Internally Funded Development

Capital By Drive Mechanism


Consistent History of Capital Discipline

1 Other includes corporate, maintenance and occupational health, safety and environmental projects and other investments.2 Facility 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 and Alpine JVs.

$40

$45

$50

$55

$60

$65

$70

$75

$80

$0

$100

$200

$300

$400

$500

$600

$700

$800

2015 2016 2017 2018 2019

Bre

nt

Oil P

rice

($

/b

bl)

To

tal C

ap

ita

l ($

MM

)

Drilling Workover Facilities Exploration Other JV - Capital Avg. Brent ($/bbl)1

Results of Fully-Burdened2

2019 CRC Development Program

Total: $455 million

$63.15 Brent/$2.58 NYMEX

Delivered 1.6 VCI


2020 Dynamic Capital Plan

2020 Estimated Total

Capital Program

$260 to $500 Million

Discretionary Cash Flow

Expect to Remain within

CRC Program Focus

2020 Estimated JV Capital


Buena Vista | Elk Hills

Huntington Beach

Long Beach| Shallow

Horizontals

1 Other includes corporate, maintenance and occupational health, safety and environmental projects and other investments.2 Inner circle represents percentages in a low capital scenario, and outer circle represents percentages in a high capital scenario. Based on current prices, CRC plans to begin the year at the low

end of the capital investment range.

Drilling and

Completion

Workover

Facilities

Exploration

Other

2020E Total Internal Capital


1

Low

Range2

High

Range2


20%

25%

30%

35%

40%

45%

50%

55%

$0

$50

$100

$150

$200

$250

$300

$350

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

Ad

juste

d E

BIT

DA

X M

arg

in1

,2

Ad

juste

d E

BIT

DA

X1

$M

M

Adjusted EBITDAX1 by Quarter

Adj. EBITDAX Margin

Adj. EBITDAX1

1, 2

CRC Delivers Stable Adjusted EBITDAX1 Margins

1 See the Investor Relations page at www.crc.com for a reconciliation to the closest GAAP measure and other additional information.2 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.

Highest quarterly Adjusted

EBITDAX margin1,2 to date

http://www.crc.com/


$58.81 $54.90

$59.82 $56.45

$56.96

$59.97

$65.28

$70.66 $68.41

$70.21 $68.08

$63.90 $68.32 $62.00 $62.50

$40

$50

$60

$70

$80

4Q18 1Q19 2Q19 3Q19 4Q19

$/B

bl

WTI Realizations Brent

-

≈

74%

77%

47%42%

59%

64%67%

41% 38%

54%

30%

40%

50%

60%

70%

80%

4Q18 1Q19 2Q19 3Q19 4Q19

% o

f W

TI

& B

ren

t

WTI Brent

-

≈ CRC believes its realizations for all hydrocarbon

streams will remain strong

CRC Price Realizations – Strong Brent Realizations

Oil Price Realization (with Hedges) Gas Price Realization

NGL Price Realization - % of WTI & Brent

Realization

% of WTI102% 119% 118% 121% 112%

$3.40 $3.24 $2.66

$2.27

$2.50

$3.77

$3.43

$2.33

$2.73 $3.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

4Q18 1Q19 2Q19 3Q19 4Q19

$/M

MB

tu &

$/M

cf

NYMEX Realizations

≈

Realization %

of NYMEX111% 106% 88% 120% 120%

-

• California native crude continues to see a strong premium over WTI

due to Brent based pricing and transportation advantages

• Realized natural gas prices recovered from lows seen in the

second quarter after temperate winter across the U.S. and colder

California weather

• NGL prices continue to see a premium over peers due to the

disconnect between the California market place and other major

basins


$314 $21

$(19)

$(17) $15 $(6)$308

$0

$50

$100

$150

$200

$250

$300

$350

$4004Q18

Oil Price and

Volume with

Hedges

NGL Price

and Volume

Gas Price

and Volume Costs Other 4Q19

4Q18 to 4Q19 Adj. EBITDAX1

Ad

juste

d E

BIT

DA

X1

($

MM

)

1 See the Investor Relations page at www.crc.com for historical reconciliations to the closest GAAP measure and other additional information. 2 Costs includes changes in operating expenses, general and administrative expenses and taxes other than on income.3 Other includes GHG costs, trading income, EHPP gross margin, and other.

2 3

http://www.crc.com/


$461

$(80)

$99 $12

$111

$73 $676

$0

$100

$200

$300

$400

$500

$600

$700

$8002018 Volume Price Costs Greenhouse Gas Other 2019

Op

era

tin

g C

ash

Flo

w (

$M

M)

Total Year Operating Cash Flow

1 Costs includes changes in operating expenses, general and administrative expenses and taxes.2 Greenhouse gas includes payments in 2018 of $98 million to purchase GHG allowances which we sold in 2016 to enhance our liquidity at the lowest point of the

commodity price cycle. In 2019 we monetized $13 million of greenhouse gas allowances.3 Other includes derivative payments, interest payments and other.

1 32

Working Capital


712 (47)

(20) 15 (24)(19)

(10)36

644

0

100

200

300

400

500

600

700

8002018 Production Price Technical

Management

Discretion 5 Year Rule Divestiture

Extensions

and

Discoveries 2019

Reserves Update

Re

se

rve

s (

MM

BO

E)

1

1 Management Discretion reflects PUDs deferred and recategorized due to changes in capital allocations.2 Includes Improved Recovery.

2


4Q18 3Q19 4Q19

Net Oil Production 86 MBbl/d 79 MBbl/d 76 MBbl/d

Total Net Production 136 MBoe/d 128 MBoe/d 123 MBoe/d

Realized Oil Price w/ Hedge ($/Bbl) $59.97 $68.41 $70.21

Realized NGL Price ($/Bbl) $43.56 $23.55 $33.81

Realized Natural Gas Price ($/Mcf) $3.77 $2.73 $3.00

Net Income (loss) Attributable to Common Stock $346 MM $94 MM $(67 MM)

Net Income (loss) Attributable to Common

Stock per Share – Diluted $7.00 $1.89 $(1.36)

Adjusted Net Income1 per Share – Diluted $0.53 $0.34 $0.73

Adjusted EBITDAX1 $314 MM $278 MM $308 MM

Internally Funded Capital Investments $174 MM $117 MM $62 MM

Cash Provided by Operating Activities $68 MM $268 MM $136 MM

Fourth Quarter 2019 Results 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

4Q18 3Q19 4Q19

Production costs ($/Boe) $18.61 $18.82 $18.67

Production costs excluding PSC

effects1 ($/Boe)$17.44 $17.44 $17.32

Taxes other than on income

($MM)$29 $42 $38

Exploration expense ($MM) $16 $5 $4

Interest and debt expense ($MM) $98 $95 $90

1 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/


Strengthening the Balance Sheet

1st Lien 2014 Revolving Credit Facility (RCF) 518$

1st Lien 2017 Term Loan 1,300

1st Lien 2016 Term Loan 1,000

2nd Lien Notes 1,815

Senior Unsecured Notes 344

Total Debt 4,977

Less cash (14)

Net Debt 4,963

Mezzanine Equity 802

Total Equity (296)

Total Net Capitalization 5,469$

Total Debt / Total Net Capitalization 91%

Total Debt / LTM Adjusted EBITDAX2

4.4x

LTM Adjusted EBITDAX2

/ LTM Interest Expense 3.0x

PV-103 / Total Debt 1.4x

Total Debt / Proved Reserves3 ($/Boe) $7.73

Total Debt / Proved Developed Reserves3 ($/Boe) $10.12

Total Debt / 4Q19 Production ($/Boepd) $40,462

As of 12/31/19

Capitalization ($MM)

1 Excludes $3MM of restricted cash.2 See the Investor Relations page at www.crc.com for a reconciliation to the closest GAAP measure and other

important information.3 Proved Reserves and PV-10 estimates are as of 12/31/19 and based on SEC19 prices of $63.15 per barrel

Brent / $2.58 per MMBTU NYMEX. See the Investor Relations page at www.crc.com for details on how PV-10

is calculated.4 The 2017 Term Loan is subject to a springing maturity in October 2021 related to the outstanding balance of

the 2016 Term Loan.

Debt Maturities ($MM)

1

$0

$1,000

$2,000

$3,000 2020 Notes (Repaid)

2nd Lien Notes

2014 RCF

Unsecured Notes

2016 Term Loan

2017 Term Loan4

Total debt below $5.0 billion

at year-end 2019

http://www.crc.com/

http://www.crc.com/


Strengthening the Balance Sheet Remains a Priority

Target 2.5x – 3x Leverage Ratio

0.0x

1.0x

2.0x

3.0x

4.0x

5.0x

6.0x

7.0x

8.0x

9.0x

YE14 YE15 YE16 YE17 YE18 YE19 Target

To

tal D

eb

t / L

TM

Ad

j. E

BIT

DA

X1

Leverage

Complicated

Capital Structure

Simplified

Capital Structure

Simple

Capital Structure

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

additional information. 2 Subject to limitations on debt repayment in finance agreements.

Capital MarketsSolutions

Disciplined Capital

Investment

Asset Monetizations

Joint ventures

Infrastructure

Producing

assets

Refinance and

simplify

capital

structure

Target 10-15% of

discretionary

cash flow for

balance sheet

strengthening2

Accretive

acquisitions

Cash flow growth

and support future

reinvestment

Continue to Employ

ALL of the ABOVE Approach

Mineral

interests

http://www.crc.com/


Debt Repurchases

Second Lien Note Repurchases

• CRC has opportunistically

repurchased approximately

$435MM in face value of Second

Lien Notes since issuance including

$23MM in the fourth quarter of

2019 and $252MM in full-year

2019

• Received an average discount of 27

percent from the face value, for a

discount capture of over $119MM

$0

$20

$40

$60

$80

$100

$120

$140

$160

$180

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

Fa

ce

Va

lue

Re

pu

rch

ase

d (

$M

M)

Face Value Repurchased ($MM)


First Quarter 2020 Guidance

Anticipated Realizations Against the Prevailing Index Prices for 1Q20

Oil 96% to 101% of Brent

NGLs 48% to 53% of Brent

Natural Gas 110% to 120% of NYMEX

Production, Capital and Income Statement Guidance

Production1 119 to 124 MBOEPD

Capital2 $100 to $125 million

Production Costs1 $18.35 to $19.45 per Boe

Adjusted G&A1, 3 $5.70 to $6.10 per Boe

DD&A1 $10.05 to $10.35 per Boe

Taxes other than on income $38 to $42 million

Exploration expense $3 to $8 million

Interest expense $87 to $92 million

Cash interest $64 to $69 million

Effective tax rate -- to --

Cash tax rate -- to --

1 Ranges in the above table are based on average Q1 2020 Brent price of $60 per barrel. If based on average Q1 2020 Brent price of $65 per barrel, production guidance would range from 118 to 123

MBOEPD and production costs would range from $18.45 to $19.55 per BOE. 2 Capital guidance includes CRC, MIRA and Alpine capital. For further detail on our Q1 2020 guidance, please see our latest Earnings Release. 3 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/


Barrels per Day 30,000 20,000 13,000 8,000

Weighted Average

Price per Barrel$70.83 $67.50 $65.00 $65.00

Barrels per Day 30,000 20,000 18,000 13,000

Weighted Average

Price per Barrel$56.67 $53.75 $54.31 $53.81

Barrels per Day - 5,0001 5,0001 5,0001

Weighted Average

Price per Barrel- $70.05 $65.00 $65.00

Percentage Hedged Against 4Q19

Net Oil Production39% 33% 24% 17%

Strategically Built Oil Hedge Portfolio

Strategy

• Protect cash flow, operating

margins and capital

investment program

• Hedge program targets up to

50% of crude oil production

Hedge program preserves

significant upside exposure to

commodity price movement

Note: 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 9 of our Q4 2019 Earnings Release.

Sold Calls

Sold Puts

Purchased

Calls

Swaps

1 Counterparties have the option to increase swap volumes by up to 5,000 barrels per day at a weighted-average Brent price of $70.05 for the second quarter of 2020, a counterparty has an

option to increase volumes up to 5,000 barrels per day at $65.00 for the third and fourth quarters of 2020.

1Q20 2Q20 3Q20 4Q20

Sold Puts

Purchased

Puts

Swaps


Current Enterprise Value Deeply Discounted

1-5 See endnotes in the Appendix. See the Investor Relations page at www.crc.com for additional information about 3P reserves and other hydrocarbon quantities.

PD4

PUD4

Unproved3

Surface Acreage2

Infrastructure and Other1

0 1

0

5

10

15

20

25

$55 Brent $65 Brent $75 Brent

Va

lue

($

B)

Current EV

of $6.3 Bn5

http://www.crc.com/


Disciplined Execution on Highest Value Projects

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

Reduce Fixed Charges

Reduce Leverage

Reduce Debt

Balance capital investment with

Financial

Strengthening Effortsfor best long-term value creation

VALUE DRIVEN

APPENDIX


Complex Road to Becoming a Law: California’s Legislative Process

Source: http://www.leginfo.ca.gov/pdf/Ch_09_CaLegi06.pdf1 Keyword search in Legislature’s web site on 2/24/20 for terms “oil and gas” or “crude oil” at http://leginfo.legislature.ca.gov/faces/billSearchClient.xhtml.

Less than 1% of the measures introduced in the 2019-20 legislative session currently mention “oil and gas” or “crude oil” anywhere in the text1

http://www.leginfo.ca.gov/pdf/Ch_09_CaLegi06.pdf

http://leginfo.legislature.ca.gov/faces/billSearchClient.xhtml


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

• Consistently controlled production

costs throughout price cycles

2014

(Pre-spin)2015

2016

20172018

1 Includes JV Capital.

Capital Investment

Scale ($MM)

1

1

20191


Pressure Tested Through the Commodity Price Cycle and Focused on Long-Term Value

5

10

15

20

25

30

$20

$50

$80

$110

07/14 07/15 07/16 07/17 07/18 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 and facilities

Strengthen balance sheet

Entered into JV with Alpine

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 07/17 01/18 07/18 01/19 07/19 01/20

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


CRC’s Natural Gas Liquids Marketing

CRC’s NGLs trend with national prices, but trade at a

premium due to market conditions in California and

isolation from the larger national market.

• Approximately half sold locally and half exported

to Mexico

• Dynamically adjust market mix to achieve

highest net realization

• 100% sold in the California market

• Infrastructure connected to multiple processing

facilities

• California is a premium market for butane

• 100% sold in the California market

• Minimize transportation costs and maximize net

realization

• CRC is the largest NGLs producer in California

Approximately 15,000 bpd

• Breakdown of CRC’s NGLs production:

1 Proxy peers with reported NGLs include: CRZO, FANG, GPOR, LPI, PDCE, PE, QEP, RRC, SM, SWN,

WLL, WPX, XEC. All prices, including CRC’s, are unhedged and current as reported in 2018 10-K and

1Q19, 2Q19 and 3Q19 10-Q filings.

NG

L R

ea

lize

d P

rice

pe

r B

arr

el ($

/b

bl)

CR

C's

% P

rem

ium

Ove

r P

roxy

Pe

ers

53%Propane

33%Butane

14%Natural

Gasoline

0%

20%

40%

60%

80%

100%

120%

140%

160%

180%

$0

$5

$10

$15

$20

$25

$30

$35

$40

$45

$50

2016 2017 2018 1Q19 2Q19 3Q19 4Q19

CRC Average of Proxy Peers Premium % Over Proxy Peers' Avg


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

10

1

10

5

10

9

11

3

11

7

JV Share Typical E&P Share

Typical DrillCo JV Structure

• Based on recent industry JV deals, a typical DrillCo structure is

o Partner pays 80-100% Capital

o Partner receives 80-100% Working Interest in wells drilled

o Typical hurdle rate:o 10% - 20% IRR

o Partner’s working interest if hurdle rate is achieved:o 5% - 25%

Hurdle Rate Reached

Pro

du

cti

on

Time


Midstream Joint Venture

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 preferred 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 2020

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 2018 2020B

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

1 Average 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


End Notes

From Slide 25

1 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.

2 Surface reflects the estimated value of undeveloped surface acreage held in fee.

3 Unproved reserves are comprised of probable and possible reserves as of December 31, 2019.

4 CRC estimate of reserves value as of December 31, 2019. Includes field-level operating expenses, G&A and taxes other than on

income. Assumes $2.58/MMBTU NYMEX in all cases.

5 Calculated using December 31, 2019 debt at par and a market cap as of 12/31/2019. Includes non-controlling interests reported

as mezzanine and permanent equity as of December 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/

fourth quarter and full year 2019 earnings review february ...€¦ · fourth quarter and full year...

Documents