Second Quarter 2017 Earnings Review · Oil Price Realization (with Hedges) Gas Price Realization...

Second Quarter 2017 Earnings ReviewTodd Stevens | President & CEO | Los Angeles, CA | August 3, 2017

Mark Smith | Sr. EVP & CFO

2Q 2017 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 the

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 www.crc.com Investor Relations 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

• operations and operational results including production, hedging, capital

investment and expected VCI

• 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

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/


1H 2017 Highlights

~4%2H’16 to 1H’17 Decline

131,000 Boe/d

$57 Million

$51 MillionJV Capital Invested

7 RigsExit Rate Shows

Increased Activity

JVs

Free Cash

Flow*

ACTIVITY

PRODUCTION

*See www.crc.com/investor-relations for a reconciliation to the

closest GAAP measure and other important information.


Drilling

$115

JV - Capital

$150

Workover

$55

Development

Facilities

$45

Exploration

$10

Other

$25

1

San

Joaquin

Ventura

Los

Angeles

Moving from Defense to Offense

• CRC 2017 capital plan will be directed to oil-weighted projects in our core fields: Elk Hills,

Wilmington, Kern Front, Buena Vista, Mt. Poso, Pleito Ranch, Wheeler Ridge and the

delineation of Kettleman North Dome

• MIRA and BSP capital will be focused in the San Joaquin Basin

• We have a dynamic plan which can be scaled up or down depending on the price

environment

Capital Investment Program – Living within Cash Flow

Total: $400 million

1Other includes maintenance and occupational health, safety and environmental projects, seismic and other investments.2 Inclusive of BSP and MIRA capital

2017E Total Capital Plan 2017E Drilling Capital2 – By Drive

29%

38%

14%

11%

2%6%

11%

9%

Conventional

Exploration

Waterfloods

Steamfloods

Unconventional

38%

4%28%

20%

80%

The JV capital increases

flexibility in a lower commodity

environment or provides for

incremental deleveraging

Total: Up to $275 million Total: Up to $275 million

10%

2017E Drilling Capital2 – By Basin


Deep Inventory of Actionable Projects at $45 Brent

Steamflood

Waterflood

Primary

Shale

Gas

Portfolio Spectrum

• Growth portfolio focus,

fully burdened

• All projects meet VCI 1.3

threshold at $45 Brent

and $2.50 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

new projects may require

infrastructure investment

in facilities and sales

points

Full cycle costs = operating costs + development costs + facility costs + field-level G&A + taxes other than income

** See www.crc.com, Investor Relations for details regarding net resources.

0

10

20

30

40

0 50 100 150 200 250 300 350 400 450 500

Fu

ll C

ycle

Co

st

($/B

oe

)

Net Resources (MMBoe)


70

80

90

100

110

120

2017E 2018E 2019E 2020E 2021E

Oil P

rod

ucti

on

MB

/d

0

300

600

900

1,200

2017 2018 2019 2020 2021

Ca

pit

al ($

MM

)

400

600

800

1,000

1,200

1,400

2017E 2018E 2019E 2020E 2021E

$M

M

Portfolio Flexibility Provides Range of Crude Oil Scenarios

Note: The high case assumes $45 Brent for remainder of 2017 and $55 Brent and $3.50 NYMEX gas price thereafter. The low case assumes $45 Brent for remainder of 2017 and $50 Brent and $3.50 NYMEX gas price thereafter. Assumes lease operating costs are equal to 2016 levels for the mid-point of the range of 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 reinvested in business for each outcome and include the effects of BSP and MIRA capital. See www.crc.com/investor-relations for a reconciliation to the closest GAAP measure of debt-adjusted per share basis.

At about current commodity prices, we are

positioned for growth in:

• Cash flow

• Production

• Reserves

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

Estimated Range of EBITDAX Outcomes

Estimated Capital Invested

≈

≈


Resilient Resource Base – Inflection Point

0

25

50

75

100

125

150

175

200

0

20

40

60

80

100

120

140

160

180

1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17E

Ca

pit

al ($

MM

)

MB

oe

/d

)

Oil NGL Gas Capital

Production By Stream (Mboe/d)

Note: Due to consolidated financials, capital and production for 2017 includes BSP’s investment


Responsible Growth: Living within Cash Flow

0

100

200

300

400

500

1H15 2H15 1H16 2H16 1H17

$ M

M

Adj. EBITDAX* Operating Cash Flow Organic Capital Investment**

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

** Does not include JV capital


$2.75

$2.42

$3.26 $3.14

$2.66

$2.28

$2.90

$2.47

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

2015 2016 1Q 2017 2Q 2017

$/

Mc

f

NYMEX Realizations

CRC – Price Realizations

40%

52%

66%

62%

0%

10%

20%

30%

40%

50%

60%

70%

2015 2016 1Q 2017 2Q 2017

% o

f W

TI

$48.80

$43.32

$51.91 $48.29 $49.19

$42.01

$50.24 $47.98

$53.64

$45.04

$54.66

$50.92

30

40

50

60

2015 2016 1Q 2017 2Q 2017

$/B

bl

WTI Realizations Brent

Realization

% of Brent92% 93% 92% 94%

Realization

% of NYMEX97 % 94% 89% 79%

Oil Price Realization (with Hedges) Gas Price Realization

NGL Price Realization - % of WTI

CRC sees near term

tightening to benchmarks

• California refinery demand for native California crude continues to

be strong with realizations, including hedges, averaging 94% of

Brent and 99% of WTI.

• NGL prices have also remained strong. This increase was driven

by tighter domestic supplies, strong exports and higher contract

prices on natural gasoline.

-≈


Defending Cash Margins

$-

$4.00

$8.00

$12.00

$16.00

$20.00

1H 15 2H 15 1H 16 2H 16 1H 17

$/B

oe

Operating Cash Margin = Oil and Gas Revenue including settled hedges – Production Costs (Lease Operating Expenses) – Taxes Other than Income – Operating Overhead


CRC Pivots to Increased Activity & Higher Cash Flows

44

120

-100

-50

0

50

100

150

200

2H16 Volume Price Costs Interest

Working

Capital and

Other 2H17

$ M

M

Op

era

tin

g C

ash

Flo

w


Strengthening the Balance Sheet

$25

$359

$165 $135

$1,000

$2,250

$193

$842

$0

$500

$1,000

$1,500

$2,000

$2,500

Jan

-16

Ma

y-1

6

Se

p-1

6

Jan

-17

Ma

y-1

7

Se

p-1

7

Jan

-18

Ma

y-1

8

Se

p-1

8

Jan

-19

Ma

y-1

9

Se

p-1

9

Jan

-20

Ma

y-2

0

Se

p-2

0

Jan

-21

Ma

y-2

1

Se

p-2

1

Jan

-22

Ma

y-2

2

Se

p-2

2

Jan

-23

Ma

y-2

3

Se

p-2

3

Jan

-24

Ma

y-2

4

Se

p-2

4

RCF

Senior Notes

Term Loan

• Deleveraging remains a priority; ~$1.6 billion decrease to date

from post-spin peak

• Going forward, we are focused on opportunistic deleveraging

• Reduced debt by $100 million in 1H 2017

• Borrowing base was reaffirmed at $2.3 billion in May 2017

1st Lien Secured RCF1

(1LFO) 842

1st Lien Secured Term Loan (1LFO) 584

1st Lien Second Out Term Loan (1LSO) 1,000

Senior 2nd Lien Notes 2,250

Senior Unsecured Notes 493

Total Debt 5,169

Less cash (9)

Total Net Debt 5,160

Equity (491)

Total Net Capitalization 4,669

Total Net Debt / Total Net Capitalization 111%

Total Net Debt / LTM Adjusted EBITDAX2

7.5x

LTM Adjusted EBITDAX2 / LTM Interest Expense 2.0x

PV-103 / Total Net Debt 0.5x

Total Net Debt / Proved Reserves4 ($/Boe) $9.08

Total Net Debt / PD Reserves4 ($/Boe) $12.71

Total Net Debt / Production5 ($/Boepd) $40,000

*The 1LFO and 1LSO have springing maturities which are detailed in our 10-K.

Capitalization as of 6/30/17 ($MM)

Debt Maturities ($MM)*

1 As of June 30th, 2017, we had approximately $437 MM of available borrowing capacity under our

revolving credit facility subject to maintaining a minimum liquidity of $250MM, this facility matures in

November 2019.2 See www.crc.com, Investor Relations for a reconciliation to the closest GAAP measure and other

important information. 3 PV-10 as of 12/31/16, see www.crc.com, Investor Relations for details on this calculation.4 Reserves as of 12/31/16.5 Average production for Q2 2017.


Reserves Value1 In Excess of EV

PDP Value

Proved Value

Unproved4

$0

$4

$8

$12

$16

$20

$50 Brent $55 Brent $60 Brent

($B

illio

n)

Current EV

of $5.5 Bn5

Infrastructure3

Surface & Minerals2

1-5 See endnotes in the Appendix.


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

Barrels per Day 6,100 6,300 16,800 16,200 16,100 16,100

Weighted Average Ceiling

Price per Barrel$57.73 $57.80 $58.86 $58.92 $58.91 $58.91

Purchased Puts

Barrels per Day 18,100 11,300 1,200 1,200 1,100 1,100

Weighted Average

Floor Price per Barrel$50.63 $47.75 $45.82 $45.83 $45.85 $45.85

Sold Puts

Barrels per Day - - 29,000 29,000 4,000 4,000

Weighted Average

Floor Price per Barrel$ - $ - $45.00 $45.00 $45.00 $45.00

Swaps

Barrels per Day 25,000 25,0002 29,0003 29,0003 4,0004 4,0004

Weighted Average

Price per Barrel$54.99 $54.99 $60.00 $60.00 $60.00 $60.00

Percentage of 2Q 2017

Oil Production Hedged52% 44% 37% 37%

Opportunistically Built Oil Hedge Portfolio1

1 – Prices are based on Brent. Positions as of July 31, 2017.2 – Includes an option for counterparties to increase volumes by up to 10,000 barrels per day at a weighted-average Brent price of $55.46.3 – Includes an option for counterparties to further increase swap volumes for the first half of 2018 by up to 10,000 barrels per day at a weighted-average Brent price of $60.00 and

quarterly options for counterparties to further increase swap volumes for the first half of 2018 by up to 19,000 barrels at a weighted-average Brent price of $60.00.4 – Includes quarterly options for counterparties to further increase swap volumes for the second half of 2018 by up to 4,000 barrels at a weighted-average Brent price of $60.00

We target hedges on 50% of

crude oil production to

protect cash flow


Quarterly & Six Month Cost Comparison

2Q16 1Q17 2Q17 1H16 1H17

Productioncosts ($/Boe)

$14.76 $17.70 $18.34 $14.21 $18.02

Taxes other than on income ($MM)

$42 $33 $31 $81 $64

Exploration expense ($MM)

$5 $6 $6 $10 $12

Interest expense($MM)

$74 $84 $83 $148 $167


2Q17 Results Summary Comparison

2Q16 1Q17 2Q17

Earnings (Loss) per Share – Diluted ($3.51) $1.22 ($1.13)

Adjusted Earnings (Loss) per Share* ($1.80) ($1.02) ($1.83)

Oil Production 90 MBbl/d 86 MBbl/d 83 MBbl/d

Total Production 140 MBoe/d 132 MBoe/d 129 MBoe/d

Realized Oil Price w/ Hedge ($/Bbl) $43.70 $50.24 $47.98

Realized NGL Price ($/Bbl) $22.54 $34.33 $30.08

Realized Natural Gas Price ($/Mcf) $1.66 $2.90 $2.47

Net Income (Loss) Attributable to Common Stock ($140) MM $53 MM ($48) MM

Adjusted EBITDAX* $160 MM $200 MM $158 MM

Capital Investments $5 MM $50 MM $82 MM

Cash Flow from Operations** ($71) MM $133 MM ($13) MM

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

**Operating cash flow includes semi-annual interest and property tax payments.


3Q17 Guidance

Anticipated Realizations Against the Prevailing Index Prices for 3Q17

Oil 90% to 94% of Brent

NGLs 58% to 62% of Brent

Natural Gas 84% to 88% of NYMEX

Production, Capital and Income Statement Guidance

Production 127 to 132 Mboe/d

Capital $115 to $135 million

Production Costs $18.35 to $18.85 per Boe

Adjusted G&A $5.30 to $5.60 per Boe

DD&A $11.50 to $11.80 per Boe

Taxes other than on income $36 to $40 million

Exploration expense $3 to $7 million

Interest expense $83 to $87 million

Cash Interest $55 to $59 million

Income tax expense rate 0%

Cash tax rate 0%


History of Proactive Strategic Decisions

Swift, decisive actions have positioned the company for growth through the commodity downturn. Proactive

discussions with lenders and solid asset base provide line of sight to a recovery and an actionable inventory.

0

5

10

15

20

25

30

0

20

40

60

80

100

120

07/06/14 10/06/14 01/06/15 04/06/15 07/06/15 10/06/15 01/06/16 04/06/16 07/06/16 10/06/16 01/06/17 04/06/17 07/06/17 10/06/17

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

333

3

4

44

4

6

E


The Case for CRC: Investment Thesis Overview

Operational

flexibility

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

Positioned to go from defense to offense

Why Own CRC Now

Competitive Advantages

Disciplined portfolio management Potential for EBITDAX growth

0

500

1,000

1,500

2017E 2018E 2019E 2020E 2021E

$M

M

Appendix


Significant Debt Reduction from Post-Spin Peak

6,7651

5,169

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 2Q17

Tota

l D

eb

t ($

MM

)

2

Cumulative Debt Reduction Total

Total Net Principal Reduction$535

million

$144

million

$102

million

$625

million

$190

Million$1,596 million

Annual Income Statement Effect

(Annualized Interest)

$22

million

($7)

Million

($6)

Million

$27

million

~($5)

Million

~$31

million

1 Represents mid-second quarter 2015 peak debt.2 Includes operating cash flow, as well as positive working capital and proceeds from asset sales in the first half of 2017.

-

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


Inventory of Actionable Projects Expands by >200MMBoe at $55 Brent

Steamflood

Waterflood

Primary

Shale

Gas

Portfolio Spectrum

• Growth portfolio focus,

fully burdened

• All projects meet VCI 1.3

threshold at $55 Brent

and $3.50 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

new projects may require

infrastructure investment

in facilities and sales

points

Full cycle costs = operating costs + development costs + facility costs + field-level G&A + production taxes

** See www.crc.com, Investor Relations for details regarding net resources.

0

10

20

30

40

0 50 100 150 200 250 300 350 400 450 500 550 600 650 700

Fu

ll C

ycle

Co

st

($/B

oe

)

Net Resources (MMBoe)


JVs Validate Inventory and Enhance Value

>$250 MillionAlready Committed

~3.5-4.0 MBoe/dGross Peak Production per

$100 MM of development capital

PRODUCTION

>12 MMBoePotential Targeted Reserves per

$100 MM of development capital

INVESTMENTS

RESERVES

SIGNED TWO

JVs

JVs are currently focused in the San Joaquin Basin

$550 MillionTotal Potential JV Capital

Kern Front

-Legend-

Oxy Land

Oil Fields

Gas Fields

Buena Vista

Pleito Ranch

Elk Hills

Kettleman North Dome

Lost Hills

Mt Poso

CRC Land

Portfolio Flexibility

and Optionality

Enables High

Margin Production

Growth

Accelerate Value

Derisk Inventory


Accelerating Value and Derisking Inventory through JVs

Highlights:

• Up to $300MM

― Initial commitment of $160MM

• 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:

• Up to $250MM over ~2 years

― Initial tranche of $50MM

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

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 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46 49 52 55 58 61 64 67 70 73 76 79 82 85 88 91 94 97 100103106109112115118JV Share Typical E&P Share

Typical Industry JV Structure

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

– Partner pays 80-100% Capital

– Receives 80-100% Working Interest

– Typical hurdle rate:– 10% - 20% IRR

– Partner’s working interest once hurdle rate is achieved:

– 5% - 25%

Hurdle Rate

Reached

Pro

du

cti

on

Time


Life of Field Plans – Growing Inventory

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

• Updated Geologic models, OOIP

• Teams shared analog experience across CRC

• Cataloged opportunities consistent with our proven reserves methodology

• Rolled into our portfolio ranking process Base Production

AdditionalRecovery

New Pools

3P Resource Growth

110

768 568

251

321

826

0

250

500

750

1,000

1,250

1,500

1,750

2,000

Spin-off 2016

MM

Bo

e

Produced Proven Price Affected Reserves Unproven

>250%

Growth


End Notes

1 Current CRC estimate of reserves value as of December 31, 2016. Includes field-level operating expenses and G&A. Assumes

$3.30/Mcf NYMEX.

2 Surface & Minerals reflect the estimated value of undeveloped surface and fee interests.

3Reflects 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.

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, 2017 debt at par and market cap as of June 30, 2017.

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 benchmarking any individual well or pattern performance. Actual results are expected to vary

depending on which projects are specifically developed.

Second Quarter 2017 Earnings Review · Oil Price Realization (with Hedges) Gas Price Realization...

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