CRC: VALUE-DRIVEN...November Corporate Presentation | 11 $0 $120 $240 $360 $480 $20 $50 $80 $110...
Transcript of CRC: VALUE-DRIVEN...November Corporate Presentation | 11 $0 $120 $240 $360 $480 $20 $50 $80 $110...
CRC: VALUE-DRIVENNOVEMBER CORPORATE PRESENTATION
November Corporate Presentation | 2
Forward Looking / Cautionary Statements – Certain Terms
This presentation contains forward-looking statements that involve risks and uncertainties that could materially affect our expected results of operations, liquidity, cash flows and business prospects.
Such statements include those regarding our expectations as to our future:
Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. While we believe assumptions or bases
underlying our expectations are reasonable and make them in good faith, they almost always vary from actual results, sometimes materially. We also believe third-party statements we cite are accurate
but have not independently verified them and do not warrant their accuracy or completeness. Factors (but not necessarily all the factors) that could cause results to differ include:
Words such as "anticipate," "believe," "continue," "could," "estimate," "expect," "goal," "intend," "likely," "may," "might," "plan," "potential," "project," "seek," "should," "target, "will" or "would" and similar
words that reflect the prospective nature of events or outcomes typically identify forward-looking statements. Any forward-looking statement speaks only as of the date on which such statement is made
and we undertake no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.
See the Investor Relations page at www.crc.com for important information about 3P reserves and other hydrocarbon resource quantities, organic finding and development (F&D) costs, organic recycle
ratio calculations, original hydrocarbons in place, Value Creation Index (VCI), drilling locations and reconciliations of non-GAAP measures to the closest GAAP equivalent.
• 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.
November Corporate Presentation | 3
The VCI Difference Delivers Real Value
Value
Focus
PV10 pre-tax cash flows
PV10 of investmentsVCI =
Value Creation Index
Delivering Smart Growth and Real Value
• Value-directed investments
• Disciplined capital allocation
• Enhanced returns over full-cycle time frame
• Prioritization of projects and drives alignment of team
• Ahead of competitive landscape shifting to value
November Corporate Presentation | 4
CRC’s Value-Driven Strategic Approach
• 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
• Reinvest to grow cash
flow
• Simplify capital
structure
• Enhance credit metrics
• Pursue value-accretive
M&A
• Reduce absolute level of
debt
• Pursue value-driven
production
• Delineate future growth
areas
• Enhance already
substantial inventory
• Pursue strategic joint
ventures
Capture Value of
Portfolio
Ensure Effective
Capital Allocation
Drive Operational
Excellence
Strengthen
Balance Sheet
Proven and pressure-tested strategic approach preserved value through the
downturn and is set to drive significant value creation for years to come
November Corporate Presentation | 5
Key Highlights
136 Mboe/d62% Oil
$308 Million$400 million Core
Adjusted EBITDAX3
$196 Million2
$158 million internally funded
95 Gross Wells Drilled1
includes 59 CRC wells
Capital
Adj. EBITDAX3
ACTIVITY
PRODUCTION131 Mboe/d62% Oil
$803 Million$1,022 million Core
Adjusted EBITDAX3
$550 Million2
$467 million internally funded
252 Gross Wells Drilled1
includes 151 CRC wells
3rd Quarter 2018 3QYTD 2018
1 Includes JV and non-operated wells.2 Includes JV capital.3 Core Adjusted EBITDAX excludes the effect of settled hedges of $79 million in the third quarter and $178 million in the first nine months,
and cash-settled equity compensation of $13 million in the third quarter and $41 million in the first nine months. See the Investor
Relations page at www.crc.com for historical reconciliations to the closest GAAP measure and other important information.
November Corporate Presentation | 6
- 5 10 15 20 25 30
Niobrara
Barnett
Anadarko - Woodford
Haynesville - Bossier
Utica
Marcellus Shale
Eagle Ford
Bakken
Permian (Wolfcamp + Sprayberry)
California
Remaining Recoverable Resources
(BBOE*)
Oil (BBO) NGL (BBOE) Gas (BBOE)
World-Class Hydrocarbon Province with Significant Potential
• Five of the largest conventional, onshore fields in the lower 48
▪ Over 35 billion BOE produced since 1876
▪ Still discovering the limits of remaining potential
▪ Over 10 billion BOE* in remaining recoverable resources
*MCF:BOE = 20:1
Note: produced volumes source: DOGGR; Remaining Recoverable Resources Source: USGS
California – a Top Oil Province
CRC Advantage
• Stacked pays provide additional opportunity through value chain
• Operating expertise to develop the diverse opportunity set
• Robust infrastructure turns disparate fields into integrated plays
November Corporate Presentation | 7
Strength of Portfolio Allocation Strategy Supported by Diverse Assets
SAN JOAQUIN BASIN
Greater Elk Hills – Flagship Asset
Thermal – Protecting Base Production
South Valley – New Opportunities
Shales & Tight Sands – New Opportunities
#2 Producer - 99,000 BOE/d1
26% of basin production
60% of basin mineral acreage
SACRAMENTO BASIN
Gas Optionality
#1 Producer - 5,000 BOE/d1
86% of basin production
85% of basin mineral acreage
VENTURA BASINGrowth and Exploration
#1 Producer - 6,000 BOE/d1
25% of basin production
90% of basin mineral acreage
LOS ANGELES BASIN
Steady High Margin Oil Assets
#1 Producer - 26,000 BOE/d1
52% of basin production
65% of basin mineral acreage
in Mid-Year 2018
Proved Reserves
1 CRC production based on 3Q18.2 Proved reserves at $75 Brent / $3 Nymex.
Note: Total basin production is based on FY2017
production. Source: DOGGR. Total basin mineral
acreage is based on internal estimates.
Largest Operator in California
across
Operate
135 fields
~12,000 wells
with
731 MMBOE2
November Corporate Presentation | 8
Enhanced Inventory Growth and Expanded 3P Position
First Half 2018 Highlights
• Mid-year reserves audited by Ryder Scott
• Proved reserves today only 5% lower despite 25%
decrease in price from the Spin
• Life-of-field studies increased unproven resources
• Recent exploration success not included
2017 Highlights
• Organic F&D costs excluding price related revisions were
$6.82 per BOE in 2017 and 3-year average of $4.84 per
BOE
• Organic recycle ratio of 2.1x in 2017 and 3-year average
of 2.8x
• Comprehensive technical review of 40% of fields
• Over 95% of total proved reserves audited by Ryder Scott
in the previous three years
Unproven Reserves1 Growth
58 109 156 179
768 644 568618
731
222 251226
175171
181431
450458
150
159
395
679699
0
250
500
750
1,000
1,250
1,500
1,750
2,000
2,250
2,500
2014 2015 2016 2017 1H18
MM
Bo
e
>250%
Unproven
Growth
1 See the Investor Relations page at www.crc.com for important information about 3P reserves and other
hydrocarbon quantities.2 Reserve amounts uneconomic at SEC prices for the applicable year.3 Unproven reserves (probable and possible) utilize similar price assumptions as of 2014 ($101.30 Brent). Proven
reserves utilize applicable SEC prices for all year-end periods. 1H18 proven reserves utilize $75 Brent.
Probable3Price-Contingent
Reserves2
ProvedCumulative
Production
Possible3
November Corporate Presentation | 9
0
5
10
15
20
25
30
35
40
45
50
0 100 200 300 400 500 600 700 800 900 1,000Fu
ll C
ycle
Co
st1
($/B
oe
)Net Resources2 (MMBoe)
Unlocking Value with a Deep Inventory of Actionable Projects at $75 Brent
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.
Steamflood
Waterflood
Primary
Shale
Gas
0
3
6
9
12
0 100 200 300 400 500 600 700 800 900 1,000
Dev
Cap
ital
(B
$)
Net Resources2 (MMBoe)
• Fully burdened, growth-
focused portfolio
• Achieve a VCI of 1.3 or
greater at $75 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
November Corporate Presentation | 10
$2.95 $3.00 $2.87 $2.75
$2.88 $2.56
$2.77 $2.81
$2.25
$3.16
0.00
0.50
1.00
1.50
2.00
2.50
3.00
3.50
4.00
3Q17 4Q17 1Q18 2Q18 3Q18
$/M
cf
NYMEX Realizations
CRC – Price Realizations
72%79%
69%62% 66%
66%72%
64%56% 60%
0%
20%
40%
60%
80%
100%
3Q17 4Q17 1Q18 2Q18 3Q18
% o
f W
TI
& B
ren
t
WTI Brent
$48.21
$55.40
$62.87
$67.88 $69.50
$50.02
$56.92 $62.77
$64.11 $63.63 $52.18
$61.54
$67.18
$74.90 $75.97
30
40
50
60
70
80
3Q17 4Q17 1Q18 2Q18 3Q18
$/B
bl
WTI Realizations Brent
Realization
% of WTI104% 103% 100% 94% 92%
Realization %
of NYMEX87% 92% 98%* 82%* 110%*
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 summer heat and continued limits on
3rd party storage
• NGL prices have been supported by lower inventories and export
markets.
-≈
*See attachment 6 of the latest Earnings Release for information regarding
the effects of an accounting change on realized natural gas prices.
*
*
*
November Corporate Presentation | 11
$0
$120
$240
$360
$480
$20
$50
$80
$110
07/14 01/15 07/15 01/16 07/16 01/17 07/17 01/18 07/18
Qu
arte
rly
Cap
ital
($
MM
)
Bre
nt
Cru
de
Oil
Pri
ce (
$/B
BL)
Brent Crude Price
Capital
Pressure Tested Through Cycle and Focused on Long-Term Value
TRANSITION TO OFFENSE
Cut rigs
Began hedging
Managed liabilities
Utilized existing facilities
Protected base production
VALUE-
DRIVEN
GROWTH
Increased activity
Engaged in JVs
Locked in hedges
Increased liquidity
Extended maturities
Invest for value-driven
production growth
Delineate future growth areas
Drill high-graded portfolio
Invest in exploration
Invest in facilities
Strengthen balance sheet
VALUE
PRESERVATION
SEPARATION
ANNOUNCEMENT
Spin
Date
November Corporate Presentation | 12
Dynamic Capital Allocation Through Commodity Cycle
High-Price Scenario
Mid-Cycle Scenario
Low-Price Scenario
Oil
Pri
ce $
/B
BL
Gas Price $/MCF
• Invest to protect base production
• Take advantage of existing facilities and prior capacity investments
▪ Steamfloods and waterfloods - drill to fill
▪ Workover existing wellbores for best investment
• Utilize excess equipment to reduce capital costs
• Engineering efforts focused on field surveillance to protect existing production
• Invest to accelerate production growth and explore/pilot new resources
• Add facilities (steam and water handling) to support pace of growth
• High cash generation
• VCI 1.3 floor to reinvest for value
• Accelerate balance sheet strengthening
• Invest to grow cash flow
• Drill in high-graded portfolio (>1.5 VCI)
▪ Oil to gas ratio for steamfloods (>5:1) - Selectively add steam generation
facilities
▪ EOR and IOR for long-term cash flow - Primary/shale for high IP impact
• Delineate future growth areas to unlock upside
• Target 10-15% of discretionary cash flow to balance sheet strengthening
Up to
$300MM
Approx.
$750MM
75%Mature
Projects
25%Growth
Projects
Over
$1.5B
50%Mature
Projects
50%Growth
Projects
90%Mature
Projects
10%Growth
Projects
November Corporate Presentation | 13
CRC’s Dynamic Portfolio Provides Flexibility
0
200
400
600
800
BO
EP
D
YEAR 5
0
200
400
600
800
BO
EP
D
YEAR 5
0
200
400
600
800
BO
EP
D
YEAR 5
0%
25%
50%
75%
100%
Po
rtfo
lio
Mix
Gas
Shale
Primary
Waterflood
Steamflood
Workover
For illustration of portfolio optionality based on normalized results per $10MM of investment and not guidance. See end note for details on type curves.
Prices for recycle ratio are $75 Brent and $3.00 NYMEX.
Oil Oil Oil
November Corporate Presentation | 14
$85
$85
$75
$65
Strategic Development Joint Ventures – BSP & MIRA
~$240 MillionInvested Through
Q3 2018
~3.5-4.0 MBoe/dGross Peak Production
per $100 MM of
Development Capital
>12 MMBoePotential Targeted
Reserves per $100 MM
of Development Capital
$550 MillionTotal Potential
JV Capital
Portfolio Flexibility
and Optionality
Enable High Margin
Production Growth
Accelerate Value
De-Risk Inventory
2018 2019 2020 2021 2022 2023
Reversion Estimates
$75
$65
Estimated Last Date
of BSP Capital
Investment
Estimated Last Date
of MIRA Capital
Investment
Note: Price scenarios assume Brent pricing.
November Corporate Presentation | 15
Unparalleled California Expertise
Core Assets Provide Operational Leverage
Applying analog development to adjacent fields
Midstream infrastructure provides low cost advantage
Largest 3-D Seismic
Position in California
Extensive Field Operations Experience
Decadesof observed field behavior and demonstrated shallow base decline rates
~ 20,000 net identified
proven and unproven drilling
locations in 2017
Source: DOGGR, Wood Mackenzie, Company Estimates
Note: Gross production data is average production in 2017. Opex data for CRC, Chevron, Aera, and Berry is
from FY 2017, opex data for Sentinel Peak is from most recent available information which is FY 2016.
163142
122
3018
-
50
100
150
200
CRC Chevron USA Aera Energy Sentinel Peak Berry
Gro
ss O
pe
rate
d M
BO
E/d
$19$21
$24
$29
$19
$0
$5
$10
$15
$20
$25
$30
$35
0%
25%
50%
75%
100%
CRC Chevron
USA
Aera Energy Sentinel
Peak
Berry
OP
EX
$/B
OE
Pro
du
cti
on
Mix
Shallow Deeper (>5,000') FY OPEX $/BOE
Top California Producers in 2017
Majority of CA Production is Shallow
November Corporate Presentation | 16
Elk Hills Flagship Asset in San Joaquin Basin
• Large field with 100% NRI
▪ 10 billion original BOE in place within multiple
reservoirs
▪ Produces ~60,000 BOE/d with annual 10% base
decline
• Infrastructure provides low-cost advantage
▪ On-site gas processing and liquids extraction
▪ Large power plant reduces electricity costs by 75%
▪ Various light crude blends desired by multiple
customers
• Large integrated business
▪ Stacked reservoirs with 280+ MMBOE proven reserves
▪ Diverse development inventory
▪ Proving ground for recovery techniques
$34MM Realized
$0 $5 $10 $15 $20 $25 $30 $35
Estimated Annualized Elk Hills Synergies* ($MM)
*Synergies include operational cost savings and revenue enhancement
Initial Target
November Corporate Presentation | 17
Leveraging Infrastructure for Nearby Low-Cost Field Development
• Coring up with Elk Hills
▪ Elk Hills serves as the hub
▪ Power, pipelines, compression
▪ Connecting fields and building out
• Lower cost shared resources
▪ Central control facilities and automation
▪ Optimized service provider utilization
▪ Shared support staff across fields
• Efficient step-out to new growth areas
▪ Dominant acreage position
▪ Low development costs for bolt-ons
▪ Discovering new resources through exploration
Southern San Joaquin Valley Consolidation
900 Million BOE of 3P reserves*
*1H18: 400 MMBOE proved, 270 MMBOE probable, 230 MMBOE possible
November Corporate Presentation | 18
Applying CRC asset playbook to substantial
drilling inventory extends core Elk Hills
operations and infrastructure
Developing Entire Southern San Joaquin Basin into Core Area
Field AreaOriginal MMBOE
in PlaceRf Projects
Yowlumne 900 13%Workover, primary drilling, new
reservoirs and EOR
Paloma 1,000 14% Workover, primary drilling and EOR
Coles Levee 1,300 21% Workover, primary drilling and EOR
Rio Viejo 60 16% Primary drilling, new reservoirs
Landslide 70 23% Workover, primary drilling and EOR
TOTAL 3,330 18%
• Redevelopment, expansion and additional recovery in existing CRC operated fields
▪ Large fields with low recovery factors
▪ >500 identified development locations
▪ >150 MMBOE potential 3P reserves*
• New field development project following recent exploration successes: Pleito Ranch
▪ Extension of CRC operated Pleito Ranch field
▪ >90 identified development locations
▪ >30 MMBOE discovered resources*
• Delivering value-driven growth
▪ Apply technology, operating expertise and knowledge
▪ Improved returns from leveraging existing infrastructure
▪ Disciplined and deliberate investment into high graded portfolio
Large Inventory of Development Projects
*See the Investor Relations page at www.crc.com for important information regarding potential reserves, discovered resources and other hydrocarbon resources.
November Corporate Presentation | 19
Conventional Exploration Program Generates Real Value
• 9 well exploration program since mid-year 2017
▪ Delineation and expansion of proven play trends plus
new impact play concepts
• Reduced risk via joint ventures
▪ 7 exploration wells funded by partners1; CRC total
initial net investment of ~$17MM
• Meaningful value creation
▪ ~$4/share value, potential to increase further with
additional appraisal
• Repeatable recipe for success provided by analog
prospects in CRC’s unparalleled inventory
Multiple Small Joint Ventures
$200+MM2,3 PV10 from Initial Net Investment of ~$17MM
Fully-Burdened VCI of 1.82,4
Commercial Success >50%
1 Partner WI funding varied by well; 2 $75 Brent and $3/NYMEX; 3 Net P50 NPV10 = Sum [P50 type curve NPV10 x NRI] for development locations; 4 VCI = 1+ [net P50 NPV10] / [PV10 exploration and development capital]
SIGNED SEVEN
JVs
November Corporate Presentation | 20
Strengthening the Balance Sheet Remains a Priority
0.0x
2.0x
4.0x
6.0x
8.0x
10.0x
YE14 YE15 YE16 YE17 YE18E Target
To
tal D
eb
t / A
dj. E
BIT
DA
X1
Leverage Core Adjusted EBITDAX Leverage
Target 2x-3x Leverage Ratio
Complicated
Capital Structure
Simplified
Capital
Structure
Continue to Employ
ALL of the ABOVE Approach
Capital MarketsSolutions
Disciplined Capital
Investment
Asset Monetizations
Joint ventures
Infrastructure
Producing
assets
Refinance and
simplify
capital
structure
Target 10-15% of
discretionary cash flow
for balance sheet
strengthening3
Simple
Capital
Structure
1See the Investor Relations page at www.crc.com for a reconciliation to the closest GAAP measure and other important
information. Core Adjusted EBITDAX excludes settled hedges and cash settled equity compensation costs.23QYTD annualized.3Subject to limitations on debt repayment in finance agreements.
1
Accretive
acquisitions
Cash flow growth
and support future
reinvestment
2
November Corporate Presentation | 21
9/30/2018
1st Lien 2014 Revolving Credit Facility (RCF) 342$
1st Lien 2017 Term Loan 1,300
1st Lien 2016 Term Loan 1,000
2nd Lien Notes 2,122
Senior Unsecured Notes 344
Total Debt 5,108
Less cash1
(18)
Total Net Debt 5,090
Mezzanine Equity 745
Equity (605)
Total Net Capitalization 5,230$
Total Debt / Total Net Capitalization 98%
Total Debt / LTM Adjusted EBITDAX3
4.7x
LTM Adjusted EBITDAX3
/ LTM Interest Expense 2.9x
PV-104 / Total Debt 2.0x
Total Debt / Proved Reserves4 ($/Boe) $6.99
Total Debt / Proved Developed Reserves4 ($/Boe) $9.67
Total Debt / 3Q18 Production ($/Boepd) $37,559
Recent Transactions - Improving Debt Metrics
Capitalization ($MM)
1 Excludes $13MM of restricted cash.2 Includes $120 million of noncontrolling interest for BSP and Ares.3 LTM Adjusted EBITDAX includes an estimated adjustment of +$27.5 million for both 4Q17 and 1Q18
as a result of the Elk Hills transaction.4 Proved Reserves and PV-10 estimates are based on mid-year reserves at $75 Brent / $3 Nymex. See
the Investor Relations page at www.crc.com for details on how PV-10 is calculated.
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)
Highlights
• Received 8th Amendment to the 2014 Credit Agreement to repurchase
$300 million in 2nd Lien Notes notes and unsecured notes
• Repurchased face value of $128 MM of 2nd Lien Notes and $49 MM of
senior notes YTD for $149 MM 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
• Recent S&P upgrade on 2nd Lien Notes to B- from CCC+
November Corporate Presentation | 22
Disciplined Capital Plan Leverages Portfolio of Projects and Management Expertise
Core ProgramBuena Vista
Elk Hills
Long Beach
Kern Front
Mount Poso
Growth/Appraisal
ProgramSouth Valley
Ventura
Other Thermal
Sacramento Valley
Kettleman
~1.7+ Fully
Burdened VCI
@ $75 Brent(Develop appraisal projects/
transfer reserves to proven)
Expect to
Live Within
Cash Flow
Deliver
Approx. Double-Digit
EBITDAX Growth(Production wedge of 70%+ Oil)
20%Facilities
5%Exploration
3%Other Ventures
12%Workover
30-40%Core
20-30%Growth
2019 Expected Capital Allocation
and Expected Outcomes
November Corporate Presentation | 23
80
90
100
110
120
130
2018E 2019E 2020E 2021E 2022E
Oil
Pro
du
ctio
n
(MB
/d)
600900
1,2001,5001,8002,1002,4002,700
Ad
just
ed E
BIT
DA
X
($M
M) ~16% Midpoint Adj.
EBITDAX3 CAGR
Cash-Neutral Scenarios Targeting Double-Digit EBITDAX Growth
~7% Midpoint
Production CAGR
1Subject to limitations on debt repayment in finance agreements.2 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.3 See the Investor Relations page at www.crc.com for a reconciliation to the closest GAAP measure and other important information.
Note: Scenarios assume flat pricing from $65 to $85 Brent and $3.00 to $3.10 NYMEX gas, respectively. Assumes varying lease operating costs within historical ranges depending on the commodity prices of the planning scenario outcomes. Ranges of portfolio planning
scenario outcomes assume development of a variety of combinations of steamflood, waterflood, conventional and unconventional projects in our inventory and reflect estimates of geologic, development and permitting risk. Assumes 10-15% of discretionary cash flow for
balance sheet strengthening, remaining discretionary cash flow to be reinvested in business in 2019 and beyond for each scenario.
Targeting 10-15% discretionary cash flow for
balance sheet strengthening1
Combined with mid-cycle commodity prices,
CRC is positioned for growth in:
• Cash flow
• Production
• Reserves
in total and on a debt-adjusted per share
basis2
Portfolio
Planning
Scenarios
Portfolio
Planning
Scenarios
Capital focused on oil projects that provide
Increasing
Margins
Low
Decline Rates
Compounding
Cash Flow+ =
-
Estimated Cash-Neutral Crude Oil Production Outcomes
Estimated Range of Cash-Neutral Adjusted EBITDAX
Outcomes
-≈
≈
0
500
1,000
1,500
2,000
2,500
2018E 2019E 2020E 2021E 2022E
Cap
ital
($
MM
) Estimated Ranges of Capital Investments
November Corporate Presentation | 24
Continuous Efforts Provide Pathway to Reasonable Leverage
1 See the Investor Relations page at www.crc.com for a reconciliation to the closest GAAP measure and other important information. Core Adjusted EBITDAX excludes settled hedges and cash settled equity
compensation costs.2 3QYTD annualized.
Note: Targeting 10-15% of discretionary cash flow for balance sheet strengthening, remaining discretionary cash flow to be reinvested in business in 2019 and beyond for each scenario. Scenarios
assume Brent pricing.
Estimated Leverage Ratios
0.0x
2.0x
4.0x
6.0x
8.0x
10.0x
2016 2017 2018E 2019E 2020E 2021E 2022E
Tota
l D
eb
t/A
dj. E
BIT
DA
X1
$65 $75 $85 Core Adj. EBITDAX Leverage
2
1
November Corporate Presentation | 25
Current Enterprise Value Deeply Discounted
PD
PUD
Unproved4
$0
$4
$8
$12
$16
$20
$24
$28
$65 Brent $75 Brent $85 Brent
Va
lue
($
Billio
n)
1
1
Current EV
of $7.3 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.
November Corporate Presentation | 26
Portfolio of world-
class assets
investable throughout
the commodity cycle
Investment Proposition: Delivering Smart Growth and Real Value
Disciplined and
effective capital
allocation
Integrated and
complementary
infrastructure
Effective capital allocation through
cycle for smart growth
Production
Innovation
Deep Inventory
Robust inventory
of high value
growth projects
VALUE DRIVEN
Balance Sheet Goals
High VCI Projects
Investing for the Future
Growth Prospects
Core Operating Areas
Simplify Balance Sheet
Reduce Fixed Charges
Reduce Debt
Oil
Pri
ce $
/B
BL
Gas Price $/MCF
$
Balance capital investment with
financial strengthening efforts for best
long-term value creation
Deep operational
knowledge and
technical expertise
APPENDIX
November Corporate Presentation | 28
Drilling
JV - Capital
Workover
Facilities
Exploration Other1
Production Enhancement Plans for 2018
• CRC 2018 capital plan directed to oil-weighted projects in core fields: Elk Hills,
Buena Vista, Wilmington, Kern Front, Huntington Beach, and continued
delineation of Ventura and Southern San Joaquin areas
• JV capital focused in the San Joaquin basin and Huntington Beach
2018 Capital Investment Program Aligned with Mid-Cycle Pricing
Approx. $720 to $750 million
1Other 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
Dynamic plan that can be scaled up or
down based on expected cash flows
Approx. $450 million Approx. $450 million
2018E Internally Funded
Development Capital By Basin
San Joaquin
Ventura
Los
Angeles46%
14%
14%
22%
3%
Conventional
Waterfloods
Steamfloods
Unconventional
46%
31%
13%
10%
67%
5%
28%
1%
November Corporate Presentation | 29
Investment Grade Assets with a Non-Investment Grade Balance Sheet
2017 Operational Metrics1 2017 Financial Metrics1
Source: CapIQ; Comparison Peers include APA, APC, AR, CHK, CLR, COP, CRK, CRZO, CXO, DNR,
DVN, ECR, EGN, EQT, FANG, GPOR, HES, HK, KOS, LPI, MRO, MTDR, MUR, NBL, OAS, OXY, PDCE,
PXD, QEP, RRC, RSPP, SM, SRCI, SWN, UNT, UPL, WLL, WRD and XEC. 1F&D, recycle ratio and free cash flow are based on information provided by CapIQ and differ in
certain respects from organic F&D, organic recycle ratio and free cash flow reported by the
company and available in the Investor Relations section of www.crc.com.
$0
$5
$10
$15
CRC A A-
3 Yr F&D, All-In ($/BOE)
0
500
1,000
BB CRC BB-
Proven Reserves (MMBOE)
0.0
1.0
2.0
3.0
A- CRC BBB
Recycle Ratio (3 Yr Avg)
($500)
($400)
($300)
($200)
($100)
$0
$100
$200
$300
A CRC BBB+
Free Cash Flow ($MM)
-
50
100
150
BB- CRC B+
Production (MBOEPD)
0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
B CRC B-
Debt/PV10
CCC+CRC’s S&P Corporate Family Rating
CRC’s operations and finances are comparable
to peers with higher credit agency ratings
November Corporate Presentation | 30
Summary of Mid-Year 2018 Reserves Changes
1 Organic F&D including the effect of the Elk Hills acquisition.2 Includes transfers, revisions, exploration and development and improved recovery. 58 MMBOE “Technical” proven reserves in contingent replacement due to economics and/or 5-year rule
limitations.3 RRR refers to organic reserves replacement ratio.4 Proved reserves at $75 Brent / $3 Nymex.
CRC Reserves Changes (Net MMBOE)
Reserve
Category
YE 2017
Balance
Price
Related
Revision
1H 2018
ProductionChanges2
Acq &
Div
July
2018
Balance
1P RRR3
(Excl
Price)
Proved
R/P
YE 17
Gross
Well
Count
YE 18
Gross
Well
Count
PD 440 40 (23) 25 46 528 9,695 10,097
PUD 178 10 0 (2) 18 203 1,691 1,546
Proved4 618 50 (23) 23 64 731 96% 15 11,386 11,643
731 MMBOEProved Reserves
Up 18% from YE 2017
96%Half-Year Proven Organic
Reserves Replacement
(excl. price-related
revisions – unaudited)
<$10/BOE
F&D Cost1
15 Year
R/P
November Corporate Presentation | 31
4Q18 1Q19 2Q19 3Q19 4Q19 1Q20
Sold Calls Barrels per Day 15,000 15,000 5,000 - - -
Weighted Average
Ceiling Price per Barrel$58.83 $66.15 $68.45 - - -
Purchased
CallsBarrels per Day - 2,000 - - - -
Weighted Average
Ceiling Price per Barrel- $71.00 - - - -
Purchased Puts Barrels per Day - 38,000 40,000 40,000 35,000 10,000
Weighted Average
Floor Price per Barrel- $65.66 $69.75 $73.13 $75.71 $75.00
Sold Puts Barrels per Day 19,000 40,000 35,000 40,000 35,000 10,000
Weighted Average
Floor Price per Barrel$45.00 $51.88 $55.71 $57.50 $60.00 $60.00
Swaps Barrels per Day 48,000 7,000 - - - -
Weighted Average
Price per Barrel$60.35 $67.71 - - - -
Percentage of 3Q 2018 Oil Production
Hedged Against Downside57% 54% 48% 48% 42% 12%
Opportunistically Built Oil Hedge Portfolio
As of October 2018. Assumes counterparty options are not exercised. Certain of our counterparties have options to increase swap volumes by up to 5,000 barrels per day at a weighted average Brent price of $70.00 for the first
quarter of 2019. 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 8 of our latest earnings release.
2019 program continues
to target hedges on 50% of
crude oil production and
provides more upside
exposure to commodity
price movement
Strategy
Protect cash flow,
operating margins
and capital
investment program
November Corporate Presentation | 32
Da
ily S
oC
alG
as n
atu
ral
ga
s in
ve
nto
rie
s
Source: EIA
$0
$2
$4
$6
$8
$10
$12
$14
01/2017 04/2017 07/2017 10/2017 01/2018 04/2018 07/2018 10/2018
So Cal City Gate Wheeler Ridge NG Futures
California Policies Impact Natural Gas Prices
Lack of Natural Gas Storage and Peak Demand
California Natural Gas Prices
“Duck” Curve
Impact of Solar Generation
Aliso Canyon Effect on Inventory
Limited third-party storage, summer heat and
reliance on renewable sources have increased
volatility in local natural gas prices
>$20
Source: Bloomberg
Source: California ISO
November Corporate Presentation | 33
✓ Reflect Californians’ values
✓ Solicit community input
✓ Advance community interests
✓ Build strategic alliances
✓ Educate and inform policy makers
✓ Sustain 90-day permit inventory per rig line
✓ Fulfill California’s high standards
✓ Help achieve the state’s long-term goals
✓ Contribute to vibrant future for all Californians
CRC’s Regulatory Strategy Advances California’s Leading Standards
0
200
400
600
800
1000
1200
YE16 YE17 1Q18 2Q18 3Q18E
Growing Permit Inventory(Permitted drilling rig days at end of period)CRC’S CONSISTENT REGULATORY STRATEGY
Seasoned operator with proven local expertise
November Corporate Presentation | 34
CRC Positioned as California’s Operator of Choice
• Proudly share state’s commitment to natural resources
• Proven track record in sensitive coastal, urban and agricultural settings
• Design and maintain facilities with a highly qualified workforce, including the California Building and Construction Trades
• Workforce received 14 safety awards from the National Safety Council for 2017
• Certified wildlife habitat conservation programs at Elk Hills, THUMS Islands and Huntington Beach
CRC is recognized by national safety
and environmental organizations
THUMS Island Grissom, Long Beach
Sutter Buttes, Sacramento BasinOakridge Lease, Ventura
Bolsa Chica Reserve,
Huntington Beach
November Corporate Presentation | 35
Buena Vista Field – Applying our Asset Playbook to Adjacent Field
• Large field adjacent to Elk Hills
▪ 7 billion original BOE in place, 10% Rf
▪ Decades of production history, 10% annual base decline
▪ 3P reserves of 245 MMBOE* with 650 locations
• Analogous to Elk Hills
▪ Predictable recoveries
▪ Extending the field boundaries
▪ Applying new technology, such as horizontals
• Integration with Elk Hills lowers F&D costs
▪ Gas processing at Elk Hills
▪ Low-cost power and water handling
▪ Shared overhead with Elk Hills
0
3,000
6,000
9,000
12,000
15,000
18,000
Jan
-08
Jan
-09
Jan
-10
Jan
-11
Jan
-12
Jan
-13
Jan
-14
Jan
-15
Jan
-16
Jan
-17
Jan
-18
Gro
ss B
OE
/d
Buena Vista
25% CAGR
Preservation
of capital
*1H18: 70 MMBOE proved, 65 MMBOE probable, 110 MMBOE possible
November Corporate Presentation | 36
• World-class waterflood
▪ 7 billion original BOE in place, 34% Rf
▪ Partnership with State of California and City of Long Beach
• Operational excellence
▪ Decades of operational experience
▪ Low annual base decline of 8%
▪ 640 identified locations
• Big fields get bigger
▪ Targeting bypassed pay, exploring deeper potential
▪ 280% organic RRR since Spin
▪ LA Basin 3P reserves of 290 MMBOE1
LA Basin – World-Class Wilmington Field
-37
-62
166 +104 171
0
50
100
150
200
YE14 Production Price-RelatedRevisions
E&D & TechRevisions
1H18
Pro
ved
MM
BO
E
LA Basin Reserves Higher than at Spin
1 1H18: 170 MMBOE proved, 80 MMBOE probable, 40 MMBOE possible2 at $75 Brent and $3.00 Nymex price
2
Small footprint to access vast resources
November Corporate Presentation | 37
40 45 50 55 60 65 70 75 80 85 90 95 100
Realized Price ($/Boe)
Wilmington Production Sharing Contracts
• Over 25% of CRC’s oil production is subject to Production Sharing Contracts (PSC)
• PSC Mechanics▪ CRC pays partners’ share of the Operating and
Capital Cost
▪ CRC recovers 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 partners’ portion of the cost
Effect of Oil Price on Net Production
Higher oil prices result in higher cash
flow, but lower reported net production
Cost Recovery Bbls
Net Profit Bbls 45-49% of Gross Production
Gross Production
November Corporate Presentation | 38
Wilmington Production Sharing Contract
• Over 90% of CRC’s Long Beach production is covered under Production Sharing Contracts (PSCs) with the State and the City of Long Beach
• CRC’s net production decreases when prices rise and increases when prices decline
• “Base” rate/profit are defined in contracts
▪ State/City receive most of base profit
▪ CRC receives remainder
• “Incremental” rate/profit is everything greaterthan the Base
• Per the provisions of the contract, the Base of the LBU PSC ended in 4Q16
-
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
November Corporate Presentation | 39
Renewed Investment in Analog Field
• Large underdeveloped field
▪ 2 billion original BOE in place, 30% Rf
▪ Waterflood, low annual base decline <8%
▪ Acquired in 2013 w/ 94 surface acres
• Wilmington is an analog
▪ Multiple stacked pay zones
▪ Primary, waterflood and steamflood
▪ 60 MMBOE 3P reserves*
• 2018 drilling delivering 50% better IP’s than 2013-2015 program
▪ Building on prior appraisal program
▪ Successful execution of horizontal wells
▪ Average 2018 IP of ~250 bopd, VCI 2.5
Huntington Beach Onshore
0
2,000
4,000
6,000
8,000
Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18
Gro
ss B
OE
/d
Huntington Beach
Preservation
of capital20% CAGR
*1H18: 30 MMBOE proved, 15 MMBOE probable, 15 MMBOE possible
Deliver new value in fields drilled over decades
November Corporate Presentation | 40
Low-Cost Capital Workovers Deliver Value and Volume
• Existing assets in multiple stacked pay zones
▪ 12,000 wellbores with pay behind pipe
▪ CRC owned processing facilities
• Low-risk, high-reward well work opportunities
▪ Adding pay behind pipe
▪ Upgrading artificial lift equipment
▪ Stimulation of existing zones
• Currently operating 18 capital workover rigs
▪ Average cost $180,000 per job
▪ Develops 3,500 BOEPD annually
▪ 6.0 VCI0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
Jan-17 Jan-18 Jan-19 Jan-20
Gro
ss B
OE
PD
Workover Program
2017 Program 2018 Program
estimated
production
Continuous drilling program leads
to additional locations, approx. 4.4
million reservoir-ft behind pipe
November Corporate Presentation | 41
Expanding CRC’s Asset Playbook to Ventura Basin
• Prolific basin with a long history, including the first commercial oil well in California
▪ Operate more than 20 fields
▪ ~9 billion original BOE in place in CRC fields, Rf ~14%
▪ ~250,000 net mineral acres (75% undeveloped)
• 2017 average net production of 6 MBOE/d (67% oil)
▪ Low decline asset, maintaining flat with limited capital
• Portfolio of drive mechanisms
▪ Primary, new and redevelopment waterfloods and steamfloods
• Building off exploration success
▪ Recent CRC exploration wells flowed > 1,000 BOE/d (80% oil) along Oakridge trend
• Activity increasing in mid-cycle price environment
▪ Focus on development and exploration in core South Mountain asset and expand across basin
CRC Operated Fields in the Ventura Basin
CRC is the largest operator in
the Ventura Basin
November Corporate Presentation | 42
Sacramento Basin Provides Gas Optionality
• Prolific gas basin
▪ CRC is largest operator in basin, operates ~ 86% of production
▪ 2017 average production of 33 MMCF/D
• Rio Vista is core asset with > 5 TCF original gas in place
▪ > 10,000’ of stacked sands, majority of activity to drill depths < 6,000’
▪ Joint venture improves returns and increases activity and reserve bookings
• Similar upside and JV potential in CRC operated Willows and Grimes analog fields
• Impact exploration potential
▪ Multi-TCF Tulainyo prospect plus analog, oil upside
▪ 5-7 “Dempsey” analog prospects
GRIMES
14,000 mcfd
1.1 TCF cum
RIO VISTA
15,000 mcfd
3.8 TCF cum
WILLOWS
7,500 mcfd
650 BCF cum
THOMPKINS HILL
1,000 mcfd
125 BCF cum
LATHROP
3,000 mcfd
700 BCF cum
TULAINYO PROJECT
50 sq mile, 4-way
closure
Stacked gas sands,
deep oil potential
November Corporate Presentation | 43
Elk Hills CO2 Project: Advancing Contingent Resources
Many CRC fields suitable for additional EOR recovery techniques
▪ Large resource, known production profiles
▪ Infrastructure largely in place
▪ Pilot responses confirm suitability
175
1085
655
Contingent Resources MMBOE*
Econ Limit/5Yr Rule
Technical
CO2 EOR
• Project scope
▪ Utilizing 6 MMCF/day miscible gas from Elk Hills plant
▪ Permits approved, injection begins 4Q18
▪ Anticipated response time of 6 to 8 months
• Dedicated team focused on full field project
▪ Evaluating various carbon capture technologies
▪ Project scoping and economics
*As of 1H18
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 Project Initiation
Stevens CO2 Wedge
Base
November Corporate Presentation | 44
Conventional Exploration Program Generates Real Value
• 9 well exploration program since mid-year 2017
▪ Delineation and expansion of proven play trends plus
new impact play concepts
• Reduced risk via joint ventures
▪ 7 exploration wells funded by partners1; $CRC total
initial net investment ~$17MM
• Meaningful value creation
▪ ~$4/share value, potential to increase further with
additional appraisal
• Repeatable recipe for success provided by analog
prospects in CRC’s unparalleled inventory
Multiple Small Joint Ventures
$200+MM2,3 PV10 from Initial Net Investment of ~$17MM
Fully-Burdened VCI of 1.82,4
Commercial Success >50%
1 Partner WI funding varied by well; 2 $75 Brent and $3/NYMEX; 3 Net P50 NPV10 = Sum [P50 type curve NPV10 x NRI] for development locations; 4 VCI = 1+ [net P50 NPV10] / [PV10 exploration and development capital]
SIGNED SEVEN
JVs
November Corporate Presentation | 45
Example Life Cycle of Wellbore with Stacked Reservoirs
1
2
3
1
3
2
NPV 10 ($MM) IRR (%) VCI
A
B
November Corporate Presentation | 46
0%
5%
10%
15%
20%
25%
30%
0
50
100
150
200
250
300
350
400
450
0 5 10 15
Re
co
ve
ry F
acto
r
BO
EP
D
years
Primary Workover Water Flood Recovery
2
3
Example Life Cycle of Wellbore with Multiple Recoveries
1
3
1
2
NPV 10 ($MM) IRR (%) VCI
November Corporate Presentation | 47
• Steam injection contributes to over 1.2 MMBO/d of production worldwide
• Thermal techniques account for over 40% of US EOR production; 95% of these are in California
• Up to 75% of the oil-in-place can be recovered
• Characterized by low risk and stable/low decline
Steamflood Overview
$75 Brent Marker Price
$71 Realized Price/BOEDifferentials/Marketing
Cash Margin
19% of CRC 2017 production from
steamfloods
58%
TEMBLOR
SANDS
EOCENE
SANDS AND
SHALES
UPPER
CRETACEOUS
SANDS AND
SHALES
MONTEREY
SANDS AND
SHALES
1,0
00
’P
AY
TULARE
SANDS20
40
200
50
40
50
SH
ALL
OW
DE
EP
ETCHEGOIN
SANDS
# o
f S
tack
ed
Re
se
rvo
irs
Targeted Zone
58%
November Corporate Presentation | 48
Heat reduces viscosity of oil and increases its mobility
Steam and
Condensed Water Hot
Water
Oil
Bank
Oil and Water
Zone near
original reservoir
temperature
Steam Generator
Injection
Well
Production
Well
Steamflood – Single Pattern Mechanics
Ramp-Up Peak Mature
Facilities Established
Maximize Injection
6 mos. – 2+ yrs.
Maximum Oil Rate
Steam Breakthrough
1 – 5 yrs.
Stable Oil Decline
Injection Reduction
5+ yrs.
Steam Injection Rate
Oil Rate
$20/BBL $15/BBL $10/BBLOperating
Expense
Up-front steam costs scale with gas price
November Corporate Presentation | 49
0
25
50
75
100
0 1 2 3 4
• Information is for a steamflood pattern assuming 3 producers per 1 injector and fully burdened with new steam generator
infrastructure costs of $900K per pattern. At low prices, new steam generation infrastructure is not added to the project.
• See endnotes for details.
PA
RA
ME
TER
S
PE
R P
ATT
ER
N Operating
Expense/bbl
$10-20
Capital
Cost *
$2.8MM
Total EUR
(MBO)
270
Peak Rate
(BOPD)
90
D&C
(days)
15
Royalty
10%
Greenfield Steamflood Type Pattern
Composite
Type Curve
Kern Front
Actuals
CRC OPERATED FIELDS
Oxnard
Midway
SunsetMcKittrick
McDonald
Anticline
Kern Front
Lost HillsN. Antelope
Hills
CRC STEAMFLOODS
$NYMEX
VCI $3.5 $3 $2.5
$65 1.9 2.0 2.1
$75 2.5 2.6 2.7
$ B
RE
NT
$85 3.1 3.2 3.3
BO
EP
D
YEAR
November Corporate Presentation | 50
• Water-flooding techniques are the most commonly used EOR production methods
• 20 – 40% of the oil-in-place can be recovered
• The oil rate decline for waterfloods is generally ~10%
• Low capital intensity and robust margins make it an attractive investment at low prices
• Many existing wells in CRC fields can be converted to injectors, maximizing effectiveness and value without drilling new wells
Waterflood Overview
$75 Brent Marker Price
$71 Realized Price/BOEDifferentials/Marketing
Cash Margin
30% of CRC 2017 production from
waterfloods
TEMBLOR
SANDS
EOCENE
SANDS AND
SHALES
UPPER
CRETACEOUS
SANDS AND
SHALES
MONTEREY
SANDS AND
SHALES
1,0
00
’P
AY
TULARE
SANDS20
40
200
50
40
50
SH
ALL
OW
DE
EP
ETCHEGOIN
SANDS
# o
f S
tack
ed
Re
se
rvo
irs
Targeted Zone
60%
November Corporate Presentation | 51
Fill Up Recovery Redevelopment
Establish Facilities & Reservoir Fill-
up / Plateau Period
6 mos. – 2+ yrs.
Expected Water Rate
Breakthrough & Oil Decline
3 – 5+ yrs.
High initial rates targeting bypassed
pay using horizontal wells and other
technologies
Injection Rate
Oil Rate
Waterflood – Single Pattern Mechanics
New Pattern Well Redevelopment Well
Injection Rate
Oil Rate
November Corporate Presentation | 52
0
15
30
45
60
0 1 2 3 4
* Capital cost is fully burdened with facilities, injectors and tie-ins. Assumes 5-spot pattern with a 1:1 producer to injector ratio.
Waterflood – New Pattern Composite Type Well
Composite
Type Curve
Mount Poso Actuals
Buena Vista Actuals
See endnote for details.
BO
EP
D
YEAR
PA
RA
ME
TER
S
PE
R P
ATT
ER
N Operating
Expense/bbl
$19/BOE
Capital
Cost *
$1.2MM
Total EUR
(MBO)
190
Peak Rate
(BOPD)
35
Drilling
Time (days)
10
Royalty
12.5%
CRC OPERATED FIELDS
Rincon
Saticoy
South Mountain
Paloma
Mount Poso
Kettleman
Buena Vista
Elk Hills
CRC NEW & POTENTIAL
WATERFLOODS
EUR
VCI 165 190 215
$65 2.2 2.6 2.9
$75 2.8 3.2 3.7
$ B
RE
NT
$85 3.3 3.8 4.4
November Corporate Presentation | 53
0
40
80
120
160
0 1 2 3 4
* Capital cost is fully burdened with facilities, injectors and tie-ins.
** A majority of locations are subject to PSCs, which have a 49% NPI. For NPV calculation, this can be modeled as 49% WI/NRI. For Production Rate, Net/Gross ratio is typically 75% when including cost recovery barrels. See endnote for details.
Waterflood – Redevelopment Type Well
Huntington Beach
Actuals
Elk Hills Actuals
Composite Type well
West Wilmington
Actuals
East Wilmington Actuals
EUR
VCI 140 165 190
$65 1.9 2.3 2.6
$75 2.4 2.9 3.3
$ B
RE
NT
$85 2.8 3.4 4.0
CRC OPERATED FIELDS
San Miguelito
Elk Hills
Wilmington
Huntington
Beach
CRC REDEVELOPMENT
WATERFLOODS
BO
EP
D
YEAR
PA
RA
ME
TER
S
PE
R P
ATT
ER
N Operating
Expense/bbl
$19/BOE
Capital
Cost *
$1.8MM
Total EUR
(MBO)
165
Peak Rate
(BOPD)
120
Drilling
Time (days)
14
Royalty
PSC**
November Corporate Presentation | 54
• CRC experiences repeatable success in deeper (>10,000 ft.) producing horizons and projects with high IPs
• Generally characterized by sandstones with shallower declines as compared with non-California shale wells
• Natural flow followed by conversion to artificial lift
• Many primary fields have stacked reservoirs, allowing access to multiple zones using the same wellbore
• In addition to deeper primary, CRC also targets projects in medium/shallower zones with scalable costsand similar economics.
Deeper Horizons Primary Overview
$75 Brent Marker Price
$67 Realized Price/BOEDifferentials/Marketing
Cash Margin
17% of CRC 2017 production from
primary
TEMBLOR
SANDS
EOCENE
SANDS AND
SHALES
UPPER
CRETACEOUS
SANDS AND
SHALES
MONTEREY
SANDS AND
SHALES
1,0
00
’P
AY
TULARE
SANDS20
40
200
50
40
50
SH
ALL
OW
DE
EP
ETCHEGOIN
SANDS
# o
f S
tack
ed
Re
se
rvo
irs
Targeted Zone
80%
November Corporate Presentation | 55
* Capital cost includes drilling, completion, and tie-ins.
Does not include 450 shallow (<5.000 ft) locations with costs under $1.5 MM/well and with similar economics.
Primary Type Well – Deeper Horizons
0
150
300
450
600
750
900
0 1 2 3 4
Composite Type well
Wheeler
Ridge Actuals
Bardsdale
Actuals
Pleito Ranch
Actuals
BV Nose
Actuals
See endnote for details.
EUR
VCI 400 430 460
$65 2.2 2.3 2.5
$75 2.6 2.8 3.0
$ B
RE
NT
$85 3.1 3.2 3.6
CRC OPERATED FIELDS
Montalvo
Kettleman
Saticoy Bardsdale
South Mountain
Elk Hills
BV Nose
Yowlumne
Pleito Ranch
Wheeler Ridge
PalomaRio Viejo
CRC PRIMARY
BO
EP
D
YEAR
PA
RA
ME
TER
S
PE
R P
ATT
ER
N Operating
Expense/bbl
$10/BOE
Capital
Cost *
$5.0MM
Total EUR
(MBO)
430
Peak Rate
(BOPD)
360
Drilling
Time (days)
30
Royalty
12%
November Corporate Presentation | 56
• Upper Monterey Shale Reservoirs (Infill): naturally fractured, low permeability reservoirs. Produce from
conventional structural and stratigraphic traps containing hydrocarbons migrated from source kitchen.
Successful commercial developments with >30% of CRC’s total production coming from these type of reservoirs.
• Lower Monterey, Kreyenhagen, and Moreno Shale Reservoirs (New Pool): prolific source rocks that have
generated the majority of the hydrocarbons produced from fields across California. Potential California resource
play opportunity with reservoir properties similar to other successful Lower 48 resource plays. Near-term focus
on the Kreyenhagen reservoirs in our Kettleman North Dome field.
• Initial portfolio of 50 high-graded locations in the near-term growth plan that cover both
types of shales.
California Shale Overview
$75 Brent Marker Price
$41 Realized Price/BOEDifferentials/Marketing
Cash Margin
34% of CRC 2017 production from
shale
TEMBLOR
SANDS
EOCENE
SANDS AND
SHALES
UPPER
CRETACEOUS
SANDS AND
SHALES
MONTEREY
SANDS AND
SHALES
1,0
00
’P
AY
TULARE
SANDS20
40
200
50
40
50
SH
ALL
OW
DE
EP
ETCHEGOIN
SANDS
# o
f S
tack
ed
Re
se
rvo
irs
Targeted Zone
71%
November Corporate Presentation | 57
California Shale Type Well
-
100
200
300
400
500
0 1 2 3 4
New Pool Type Curve
Infill Shale
Curve
Gunslinger
Actuals
Rose/N. Shafter
ActualsElk Hills Actuals
Elk Hills (2001-2003)
VCI Infill New Pool
$65 1.5 2.2
$75 1.7 2.6
$ B
RE
NT
$85 2.0 2.9
*Capital cost includes drilling, completion, and tie-ins. See endnote for details.
New Pool
Infill
Asphalto
Elk Hills
Buena Vista
Kettleman
Rose
N. Shafter
Gunslinger
Railroad Gap
CRC SHALE
CRC OPERATED FIELDS
BO
EP
D
YEAR
Operating
Expense/bbl
$10/BOE
$8/BOE
Capital
Cost *
$5.0MM
$2.5MM
Total EUR
(MBO)
765
220
Peak Rate
(BOPD)
500
143
Drilling
Time (days)
30
20
Average
Royalty
13%
13%
November Corporate Presentation | 58
Sacramento Basin – Gas Overview
TEMBLOR
SANDS
EOCENE
SANDS AND
SHALES
UPPER
CRETACEOUS
SANDS AND
SHALES
MONTEREY
SANDS AND
SHALES
1,0
00
’P
AY
TULARE
SANDS20
40
200
50
40
50
SH
ALL
OW
DE
EP
ETCHEGOIN
SANDS
# o
f S
tack
ed
Re
se
rvo
irs
Targeted Zone
$75 Brent Marker Price and $3.00 NYMEX
$18 / BOE or $3.0 / MCF Realized PricingDifferentials/Marketing
Cash Margin
• CRC is the largest gas producer in California
• Operates 85% of the gas production in the Sacramento Basin
• Gas production is a natural hedge to rising steam and electrical energy costs
• At current prices, CRC pursues capital workovers in the Sacramento Basin. New wells have been funded with JV/farmout capital
• Provides significant optionality at higher gas prices for a state that imports 90% of its natural gas
~5% of CRC 2017 production from
the Sacramento Basin
38%
November Corporate Presentation | 59
End Notes
From Slide 25
1 CRC estimate of reserves value as of December 31, 2017, including reserves acquired in the Elk Hills transaction at the indicated
Brent prices. 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 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 & Mineral reflect 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, 2017.
5 Calculated using September 30, 2018 debt at par and a market cap as of 11/08/2018. Includes non-controlling interests reported
as mezzanine and permanent equity as of September 30, 2018.
Type Curve Note: Each field-specific type well curve represents an average of the historical results of multiple projects over the prior four-
year time period. Drive mechanism type curves are the weighted average of the field-specific curves related to the projects chosen for our
near-term growth plan. Type curves represent management’s estimates of future results and are subject to project selection and other
variables. Our type well curves are prepared for purposes of modeling overall results of our near-term growth program and are not useful
for purpose of benchmarking any individual well or pattern performance. Actual results are expected to vary depending on which projects
are specifically developed.
See the Investor Relations page at www.crc.com for important information about 3P reserves and other hydrocarbon resource quantities,
organic finding and development (F&D) costs, organic recycle ratio calculations, organic reserves replacement ratios, original
hydrocarbons in place, Value Creation Index (VCI), drilling locations and reconciliations of non-GAAP measures to the closest GAAP
equivalent.