SCOTIA HOWARD WEIL 46 ANNUAL ENERGY...
Transcript of SCOTIA HOWARD WEIL 46 ANNUAL ENERGY...
Scotia Howard Weil – 46th Annual Energy Conference | 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
assumptions or bases underlying our expectations are reasonable and make them in good faith, they almost always vary from actual results, sometimes materially. We also believe third-
party statements we cite are accurate but have not independently verified them and do not warrant their accuracy or completeness. Factors (but not necessarily all the factors) that
could cause results to differ include:
Words such as "anticipate," "believe," "continue," "could," "estimate," "expect," "goal," "intend," "likely," "may," "might," "plan," "potential," "project," "seek," "should," "target, "will" or "would"
and similar words that reflect the prospective nature of events or outcomes typically identify forward-looking statements. Any forward-looking statement speaks only as of the date on
which such statement is made and we undertake no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise,
except as required by applicable law.
See the Investor Relations page at www.crc.com for important information about 3P reserves and other hydrocarbon resource quantities, finding and development costs, recycle ratio
calculations, and drilling locations.
• financial position, liquidity, cash flows and results of operations
• business prospects
• transactions and projects
• operating costs
• Value Creation Index (VCI) metrics 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
• 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 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.
Scotia Howard Weil – 46th Annual Energy Conference | 3
Value Proposition – Multiple Ways to Increase Valuation
Disciplined Portfolio Management
EBITDAX Growth*Regaining Momentum
Through Increased
Investment
• Increasing CRC
Investments and Deploying
Rigs
• Joint Ventures
• Opportunistic Deleveraging
• Significant Operating
Leverage to Crude Oil
*See Slide 24 for additional information regarding EBITDAX Growth planning scenarios.
400+
0
500
1,000
1,500
2,000
2,500
2017 2018E 2019E 2020E 2021E
$M
M
2017 2018E 2019E 2020E 2021E
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CRC’s Large Resource Base with Advantaged Infrastructure
Sacramento Basin
14 MMBOE Proved Reserves
6 MBOE/d production (100% dry gas)
San Joaquin Basin
419 MMBOE Proved Reserves
90 MBOE/d production (58% oil)
Ventura Basin
40 MMBOE Proved Reserves
6 MBOE/d production (67% oil)
World-Class Resource Base
• Operate 4 of the largest fields in the continental U.S.
• Diversified, conventional portfolio with low base decline rate
• 618 MMBOE proved reserves
• 129 MBOE/d production, 64% oil
• 2.3 million net mineral acres
Positioned to Grow
• Internally funded capital program designed to live within cash flow and drive growth
• Development investment augmented by JV capital and increases flexibility
• Operating flexibility across basins and drive mechanisms to optimize growth through commodity price cycles
• Increasing crude oil mix improves margins
• Deep inventory of high-return projects
Reserves as of 12/31/17; Production figures reflect average FY 2017 rates.
Los Angeles Basin
145 MMBOE Proved Reserves
27 MBOE/d production (100% oil)
Scotia Howard Weil – 46th Annual Energy Conference | 5
Largest California Producer with Deep Regional Insight
163
142
122
3021
-
50
100
150
200
CRC Chevron USA Aera Energy Sentinel Peak Berry
Gro
ss O
pe
rate
d M
Bo
e/d
*Source: DOGGR data (average production data for 2017)
**Information for CRC, Chevron, and Aera is from 2017, data for Berry and Sentinel Peak are from most recent available information which is 2016. Source: Wood Mackenzie, Company Estimates.
Largest 3-D Seismic
Position in California
$19$21
$24
$29 $29
$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**
MONTEREY
SANDS AND
SHALES
TEMBLOR
SANDS
EOCENE
SANDS AND
SHALES
UPPER
CRETACEOUS
SANDS AND
SHALES
1,0
00
’P
AY
TULARE
SANDS
SH
ALL
OW
DE
EP
ETCHEGOIN
SANDS
<5
,00
0’
15
,00
0’
Top California Producers in 2017*
Majority of CA Production is Shallow*
Scotia Howard Weil – 46th Annual Energy Conference | 6
San Joaquin Basin – An American Super Basin
Overview
• Oil and gas discovered in the late 1800s
• 70% of CRC production is from San Joaquin Basin
• Cretaceous to Pleistocene sedimentary section (>25,000 feet)
• Thermal recovery applied since early 1960s
• Currently running 7 drilling rigs
Key Assets
• 2017 average net production of 90 MBOE/d (58% oil) with <8% YOY decline
• Elk Hills is the flagship asset (~59% of FY 2017 CRC San Joaquin production)
• Two core steamfloods - Kern Front and Lost Hills
• Early stage waterfloods at Buena Vista and Mount Poso
• Substantial, integrated infrastructure that supports Elk Hills
Basin Map
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6
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100
200
300
2015 2016 2017
Avg
. Rig
Co
un
t
Gro
ss W
ells
Dri
lled
Steamflood Waterflood Primary Unconventional Avg. Rig Count
Legend
CRC Land
Oil Field
Gas Field
CRC Operated
Scotia Howard Weil – 46th Annual Energy Conference | 7
Los Angeles Basin – Kitchen is the Entire Basin
Overview
• World-class hydrocarbon-rich sedimentary basin with large quantities of stacked pay
• ~10 billion barrels OOIP in CRC fields
• Kitchen is the entire basin, hydrocarbons did not migrate laterally; basin depth (>30,000 ft)
• Very few penetrations >10,000 ft, leaving deep horizons underexplored
• Focus on mature waterfloods with generally low technical risk and proven repeatable technology across huge OOIP fields
• 2017 average net production of 27 MBOE/d (100% liquids) with a 10% YOY decline and an organic reserves replacement ratio of 330%*
• Over 30,000 net mineral acres
• Major properties are premier coastal development assets of Wilmington and Huntington Beach
• The Wilmington field is subject to contractual agreements similar to production-sharing contracts (PSCs). The contracts represented slightly less than 20% of our total 2017 production.
Wilmington
Huntington Beach
Basin Map
*Organic reserves replacement excludes the effect of price change on reserves volumes0
1
2
0
25
50
2015 2016 2017
Avg
. Rig
Co
un
t
Gro
ss W
ells
Dri
lled
Waterflood Avg. Rig Count
Performed 26 Capital Workover projects in 2017
Legend
CRC Land
Oil Field
Gas Field
CRC Operated
Scotia Howard Weil – 46th Annual Energy Conference | 8
Ventura Basin – Birthplace of the California Oil Industry
Overview• Prolific basin with a long history, including the first commercial oil well
in California
• ~8 billion barrels OOIP in CRC fields
• Operate 28 fields (over half the fields in the basin)
• ~250,000 net mineral acres (75% undeveloped)
• 2017 average net production of 6 MBOE/d (67% oil)
• Portfolio of drive mechanisms: Primary, New & Redevelopment Waterfloods and Steamfloods
• Building off exploration success: recent exploration wells have flowed in excess and 1,000 BOE/d (80% oil) along Oak Ridge trend
• Incorporating 10 square miles of 3D seismic into drillable locations
• Significant upside: movable oil, low recovery factor, controlling acreage position and existing infrastructure
• California wildfires in Ventura County impacted December 2017 production by approximately 2,000 BOE/d and production remained affected by approximately 1,000 BOE/d in January 2018
High Growth Area: large OOIP, low recovery
factor and potential for high-IP wells
Field Map
OOIP (MMBO) CUM PROD (MMBO) RF
7,843 813 10%
Legend
Active CRC Field
Idle CRC Field
Scotia Howard Weil – 46th Annual Energy Conference | 9
Sacramento Basin – Significant Gas Optionality
Overview
• Exploration started in 1918 and focused on seeps and topographic highs. In the 1970s the use of multifold 2D seismic led to largest discoveries
• Cretaceous Starkey, Winters, Forbes, Kione, and the Eocene Domengine sands
• Most current production under 6,000 feet, deeper targets remain at less than 10,000 feet
• 3D seismic surveys in mid-1990s helped define trapping mechanisms and reservoir geometries
• 2017 average net production of 33 MMcf/d (100% dry gas)
• CRC produces 85% of basin gas with synergies from scale
• Includes the Rio Vista field, which has produced over 3.7 TCF of natural gas over its lifetime
• CRC has an active exploration program in the basin
California imports >90% of its
natural gas requirements
Basin Map
0 20
Miles
Legend
CRC Land
Oil Field
Gas Field
CRC Operated
Scotia Howard Weil – 46th Annual Energy Conference | 10
Value Additive Inventory Growth
• Comprehensive technical review of 40% of CRC’s fields.
• 2017 proved reserves of 618 million BOE and 450 million BOE of probable reserves.
• 119% organic reserve replacement, excluding the effect of price adjustments.
• We added 34 million BOE of proved reserves from extension and discoveries and 22 million BOE from performance. We were also able to rebook 49 million BOE due to the increase in prices compared to prior years.
• Organic F&D costs excluding price related revisions was $6.82 per BOE and produced a recycle ratio of 2.1x.
• Over 95% of our total proved reserves have been audited by Ryder Scott in the last three years.
3P Reserves Growth Since Spin
58 109 156
768 644 568618
222 251202
321
340
826
1,129
0
250
500
750
1,000
1,250
1,500
1,750
2,000
2,250
Spin-off 2015 2016 2017
MM
Bo
e
Cummulative Production Proven
Revisions Due to Price Since 2014 Unproven
>350%
Growth
See the Investor Relations page at www.crc.com for important information about 3P reserves and other hydrocarbon quantities.
Scotia Howard Weil – 46th Annual Energy Conference | 11
Strategy at a Glance
Value Directed Investments
Targeting Balance Sheet Leverage 2x-3x (mid-cycle)
Value
Focus
Live within
Cash Flow
Smart Growth
(per share)
PV10 pre-tax cash flows
PV10 of investmentsVCI =
Enhancing Production
Margin Expansion
Through managing cost and increasing
oil weighting of commodity mix
Live within Cash Flow
Long-TermShort-Term
*Please see end notes for further information on how we calculate VCI.
Value Creation Index*
Scotia Howard Weil – 46th Annual Energy Conference | 12
History of Proactive Strategic Decisions
Swift, decisive actions through the commodity downturn have positioned CRC for growth. Proactive discussions with
lenders and solid asset base provide a path to recovery and an actionable inventory.
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07/20/14 10/20/14 01/20/15 04/20/15 07/20/15 10/20/15 01/20/16 04/20/16 07/20/16 10/20/16 01/20/17 04/20/17 07/20/17 10/20/17 01/20/18 04/20/18
CR
C D
rillin
g R
ig C
ou
nt
Bre
nt
Cru
de
Oil P
rice
($
/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
3
33
3
44
4
4
6
63
Scotia Howard Weil – 46th Annual Energy Conference | 13
Significant Reduction in Net Debt from Post-Spin Peak
6,7651
4,502
3,000
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 Ares Transactions PF 4Q17
Tota
l N
et
De
bt
($ M
M)
2
Total
Total Net Debt Reduction$535
million
$153
million
$102
million
$625
million
$59
million
$789
million$2,263 million
1 Represents mid-second quarter 2015 peak debt.2 Includes operating cash flow, positive working capital and proceeds from asset sales in 1H 2017, net of restricted cash.3 Pro Forma net debt at 4Q17 includes the payoff of the 12/31/2017 outstanding balance of $363 million on our RCF and $441 million of available cash after the completion of the Ares transactions.
-
Chose options to maximize deleveraging and minimize recurring cost to the income statement on a per share basis.
Continue to seek opportunistic transactions that reduce overall debt.
3
Scotia Howard Weil – 46th Annual Energy Conference | 14
Strengthening the Balance Sheet - Improved Creditworthiness and Liquidity
Pro-Forma1 Debt Maturities ($MM)*
1 Pro forma debt reflects the payoff of the 12/31/17 outstanding balance of $363 million on our RCF after the completion of the Ares JV. 2 The $441 million of available cash includes (1) $15 million unrestricted cash as of 12/31/17 and (2) $426 million of available cash after the Ares transaction and pro forma repayment of the RCF.
$0
$1,000
$2,000
$3,000
$4,000
2018 2019 2020 2021 2022 2023 2024
2017 Term Loan 2nd Lien Notes 2016 Term Loan Unsecured Notes 2014 RCF
Revolver Availability
$431
Revolver Availability
$850
Cash $11
Cash $441
$0
$200
$400
$600
$800
$1,000
$1,200
$1,400
3Q17 PF 4Q17*
Ava
ilab
ility
($
MM
)
Increased Liquidity
Pro Forma1 Total Debt
$4.9BRevolver Availability
$850MMAvailable Cash2
$441MM
Scotia Howard Weil – 46th Annual Energy Conference | 15
Development Joint Ventures: A Force Multiplier
$154 Million$260 MM Committed
~3.5-4.0 MBoe/dGross Peak Production per
$100 MM of development capital
>12 MMBoePotential Targeted Reserves per
$100 MM of development capital
JVs are generally focused in the San Joaquin Basin
$550 MillionTotal Potential JV Capital
Kern Front
-Legend-
Oxy Land
Oil Fields
Gas Fields
Buena Vista
Pleito Ranch
Elk Hills
Kettleman North Dome
Lost Hills
Mt Poso
CRC Land
Portfolio Flexibility
and Optionality
Enables High Margin
Production Growth
Accelerate Value
Derisk InventoryJVs add production and cashflow,
and help de-risk inventory to
increase CRC’s reserve base
Scotia Howard Weil – 46th Annual Energy Conference | 16
Resilient Resource Base
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1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 FY
2015
FY
2016
FY
2017
Ca
pit
al ($
MM
)
MB
oe
/d
)
Oil NGL Gas Total Capital* CRC Capital (Internally Funded)
Production By Stream (Mboe/d)
MIRA: $58MM BSP: $96MM CRC (Internally Funded): $275MM
Total Capital $401MM $75MM $429MM*Total Capital reflected in the graph includes the capital investment of internal CRC
capital as well as all JV partners which includes BSP and MIRA. Please note our
consolidated financial statements include BSP’s investment and exclude MIRA from
CRC consolidated results based on the accounting treatment of each agreement.
Scotia Howard Weil – 46th Annual Energy Conference | 17
Drilling
24%
Workover
18%BSP JV
Capital
22%
MIRA JV
Capital
14%
Exploration
2%Other1
6%
Development
Facilities
14%
Moved from Defense to Offense – 2017 Review
• CRC 2017 capital plan was 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
• JV capital was primarily focused in the San Joaquin Basin
2017 Investment Delivered Solid Returns
Total: $429 million3
1 Other includes maintenance and occupational health, safety and environmental projects, seismic and other investments.2 Facility Costs and other non-return capital are apportioned to producing wells in the year they are drilled.3 Includes capital funded by MIRA, which is not included in our consolidated results.
2017 Total Capital Invested
1.70
2.00
0.00
0.50
1.00
1.50
2.00
2.50
$55 Brent Flat
$3 NYMEX
$55 Brent 2017, $65 Brent
in 2018+ & $3 NYMEX
VC
I
Results of Fully-Burdened2
2017 CRC Development Program
Total: ~$240 million
Other1
~30% IRR* ~45% IRR*
*IRR estimate for the 2017 development program. For a description of how VCI is calculated please see the end notes.
Scotia Howard Weil – 46th Annual Energy Conference | 18
Investment Allocation through the Commodity CycleO
il P
rice
$/
BB
L
Gas Price $/MCF
• Invest to protect base production
• Take advantage of existing facilities and prior capacity investments
– Steamfloods and waterfloods: drill to fill
– Workovers on existing wellbores is 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
• Cash generation is high
• VCI 1.3 floor to reinvest for value
Bull Market
Mid-Cycle Market
Bear Market
• 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
– EOR and IOR for long-term cash flow. Primary and shale for high IP impact
• Delineate future growth areas to unlock upside
Scotia Howard Weil – 46th Annual Energy Conference | 19
Drilling
JV - Capital
Workover
Development
Facilities
ExplorationOther1Other1
San
Joaquin
Ventura
Los
Angeles
Production Enhancement Plans for 2018
• CRC 2018 capital plan will be directed to oil-weighted projects in our core fields: Elk Hills,
Wilmington, Kern Front, Huntington Beach, and continued delineation of Kettleman North
Dome and Buena Vista
• JV capital will be focused in the San Joaquin Basin and Huntington Beach
• We have a dynamic plan that can be scaled up or down depending on the price environment
and efficient deployment of joint venture proceeds
2018 Capital Investment Program – Living Within Cash Flow
Approx. $425 to $450 million
1Other includes maintenance and occupational health, safety and
environmental projects, seismic and other investments.
2018E Total Capital Plan 2018E Drilling Capital – By Drive
28%
30%
22%
12%
4%4%
10%
10%
Conventional
ExplorationWaterfloods
Steamfloods
Unconventional
42%
6%30%
16%
80%
The JV capital increases
flexibility or provides for
incremental deleveraging
Approx. $250 million Approx. $250 million
6%
2018E Drilling Capital – By Basin
Scotia Howard Weil – 46th Annual Energy Conference | 20
Deep Inventory of Actionable Projects at $65
Portfolio Spectrum
• Growth portfolio focus, fully
burdened
• All projects meet a Value
Creation Index (VCI)1
threshold of 1.3 at $65 Brent
and $3.00 NYMEX, and
deliver robust cash flow
• Portfolio has large
contributions from all
recovery mechanisms and
reserves types
• Many projects take
advantage of existing
infrastructure, while other
newer projects may require
infrastructure investment in
facilities and sales points
1 VCI is calculated by dividing the net present value of the project’s expected pre-tax cash flow over its life by the net present value of the investments, each using a 10% discount rate. 2 Full cycle costs = operating costs + development costs + facility costs + field-level G&A + taxes other than on income.3 See the Investor Relations page at www.crc.com for details regarding net resources.
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lop
me
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pit
al ($
B)
Net Resources3 (MMBoe)
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0 100 200 300 400 500 600 700 800
Fu
ll C
ycle
Co
st2
($/B
oe
)
Net Resources3 (MMBoe)
Steamflood
Waterflood
Primary
Shale
Gas
Scotia Howard Weil – 46th Annual Energy Conference | 21
Strong Returns Through the Commodity Cycle
Gas
Take advantage of dominant
position in the basin. Invest in
Sacramento Gas Projects.
Primary Shale
*Counts exclude prospective drilling and injector locations. Near term growth plan locations include inventory in the 5-year plan at $65 Brent
17,055 Total Net Producer Locations ~2,500 Total Near Term Growth Projects ~2,800 Additional Actionable Projects > 1.3 VCI
Total LOF Actionable Near Term Growth
Focus on lower operating costs. Invest
in steam floods above 5x Oil/Gas
Ratio.
Steamflood Waterflood
Gas Price
Oil Price
Gas Price
Oil Price
Gas Price
Oil Price
Gas Price
Oil Price
Oil/Gas Price Ratio
Optimum Investment
Range
CRC has a strong portfolio of actionable projects that
can thrive in varying commodity price environments
Gas Price
Oil Price
Scotia Howard Weil – 46th Annual Energy Conference | 22
Midstream JV Provides Optionality to Create Maximum Value
Invest in
Resources
Reduce Debt
• $750MM Mid-Stream Joint Venture
• Includes Elk Hills power plant, gas processing assets and related non-
borrowing base infrastructure
Scotia Howard Weil – 46th Annual Energy Conference | 23
0.9
1.0
1.1
1.2
1.3
1.4
1.5
1.6
1.7
0% 10% 20% 30% 40% 50%
PR
OJE
CT V
CI
DISCOUNT ON SECOND LIEN NOTES
PROJECT VS. SECOND LIEN (2L) NOTE REPURCHASE*
INVEST If the VCI of an investment opportunity falls above the indifference
curve, investing in the new project could be a better option
PURCHASE DEBTIf the VCI of an investment opportunity falls
below the indifference curve, repurchasing
2L notes could be a better option
Example of Investment Alternatives for Asset Sale Proceeds
Per the terms of the 2014 credit agreement on
asset sales, 2L notes must be repurchased at a
minimum 20% discount to par
Indifference Curve
*CRC will continue to review all opportunistic debt reduction transactions. We utilize VCI to guide management in allocating capital and prioritizing investments. Please see end notes for how we calculate VCI.
Scotia Howard Weil – 46th Annual Energy Conference | 24
70
80
90
100
110
120
130
140
2017 2018E 2019E 2020E 2021E
Oil P
rod
ucti
on
MB
/d
400
800
1,200
1,600
2,000
2017 2018E 2019E 2020E 2021E
EBIT
DA
X $
MM
Portfolio Flexibility Provides Range of Crude Oil Scenarios
Note: Scenarios assume flat pricing from $55 to $75 Brent and $3.00 to $3.10 NYMEX gas, respectively. Assumes lease operating costs are equal to 2017 levels for the mid-point of the range of planning scenario outcomes. Ranges of portfolio planning scenario outcomes
assume development of a variety of combinations of steamflood, waterflood, conventional and unconventional projects in our inventory and reflect estimates of geologic, development and permitting risk. All discretionary cash flow reinvested in business for each scenario.
EBITDAX calculation for all estimated periods reflects a reduction from associated payments to Ares based on our JV agreement. Please note that beginning in 2018 these charges will be incorporated after our calculation for net income on our consolidated financial
statement due to the accounting treatment of non-controlling interests.
* See the Investor Relations page at www.crc.com for a description of the calculation of debt-adjusted per share and other important information.
Combined with mid-cycle commodity
prices, we are positioned for growth in:
• Cash flow
• Production
• Reserves
on a debt-adjusted per share basis* Portfolio
Planning
Scenarios
Portfolio
Planning
Scenarios
Capital focused on oil projects that provide
Increasing
Margins
Low
Decline Rates
Compounding
Cash Flow+ =
-
Estimated Crude Oil Production Outcomes
≈
0
300
600
900
1,200
1,500
2017 2018E 2019E 2020E 2021E
Ca
pit
al ($
MM
) Estimated Ranges of Capital Investments
Estimated Range of EBITDAX Outcomes
(Inclusive of Ares payment)
-≈
Scotia Howard Weil – 46th Annual Energy Conference | 25
Margin Expansion Driven by Liquid-Rich Resource Base
• As we develop our reserves we anticipate the oil weight of production to trend from 64% produced in 2017 toward the 72% reflected in our 2017 Proved Reserves
• The 2017 average blended realized price of $41 per BOE was 75% of the average Brent Crude index
• We have significant operating control of our properties which allows us to adjust our activity based on commodity price and market conditions
0%
25%
50%
75%
FY 2015 FY 2016 FY 2017 2017
Reserves
% O
il M
ix
Oil NGL Gas Blended
Realized Price*
2017 Production Mix 64% 12% 24% $41.09
2017 Proved Reserves
Mix72% 9% 19%
*Includes effects of settled hedges
Scotia Howard Weil – 46th Annual Energy Conference | 26
PDP Value
Proved Value
Unproved4
$0
$4
$8
$12
$16
$20
$55 Brent $65 Brent $75 Brent
($B
illio
n)
2017 Reserves Value1 In Excess EV
Current EV
of $5.1 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.
Scotia Howard Weil – 46th Annual Energy Conference | 27
Project Inventory Drives Organic Deleveraging
Note: All cases are self-funding. Capital program in all cases assumes discretionary cash flow is reinvested. Assumes lease operating costs on an absolute basis are flat to 2017 levels for the mid-point case of
the range of portfolio planning scenario outcomes. EBITDAX calculation for all estimated periods reflects a reduction from associated payments to Ares based on our JV agreement. Please note that beginning in
2018 these charges will be incorporated after our calculation for net income on our consolidated financial statement due to the accounting treatment of non-controlling interests.
Estimated Leverage Ratios
0.0x
2.0x
4.0x
6.0x
8.0x
10.0x
2016 2017 2018E 2019E 2020E 2021E
Tota
l D
eb
t/LT
M E
BIT
DA
X
$55 $65 $75
Scotia Howard Weil – 46th Annual Energy Conference | 28
0
500
1,000
1,500
2,000
2,500
2017 2018E 2019E 2020E 2021E
$M
M
The Case for CRC: Investment Thesis Overview
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
Moved from defense to offense
Why Own CRC Now
Competitive Advantages
Disciplined portfolio management Potential for EBITDAX growth*
Clear runway and
available cash
-2017 2018E 2019E 2020E 2021E
*See Slide 24 for additional information regarding EBITDAX Growth planning scenarios.
Scotia Howard Weil – 46th Annual Energy Conference | 30
Wilmington Field – 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 greater than the Base
• Per the provisions of the contract, the Base of the LBU PSC ended in 4Q 2016
-
10,000
20,000
30,000
40,000
50,000
1992 1996 2000 2004 2008 2012 2016
Bo
e/d
Base Incremental
LBU PSC
-
2,000
4,000
6,000
8,000
10,000
12,000
2006 2008 2010 2012 2014 2016B
oe/
d
Base Incremental
Tidelands PSC
Base Profit Split:
4% CRC / 96% State*
Incremental Profit Split:
49% CRC / 51% State*
Base Profit Split:
4% CRC / 96% State*
Incremental Profit Split
49% CRC / 51% State & City*
*Average profit split %
End of
LBU Base
First of 3 new
PSC’s executed
Scotia Howard Weil – 46th Annual Energy Conference | 31
$40 $45 $50 $55 $60 $65 $70 $75 $80 $85 $90 $95 $100
Mb
oe
pd
$Brent
Total Production @ $ Brent Price
$40 $45 $50 $55 $60 $65 $70 $75 $80 $85 $90 $95
$100
$M
M
$Brent
Total Revenue @ $ Brent Price
Wilmington PSC Illustration
Net Profit Barrels
NPI Barrel Revenue
45% Share of Gross Production
Variable with Price
Cost Recovery BarrelsVariable with price
Cost Recovery RevenueFixed revenue from cost recovery of
the State & City of Long Beach
share of costs
Gross Production
CRC pays ~90% of gross costs (capital investments, OPEX, tax and overhead) up front and recovers our partners ~46%
share (State/City of LB) of these costs in the form of offsetting Revenues
Scotia Howard Weil – 46th Annual Energy Conference | 32
$3.26 $3.14 $2.95 $3.00
$2.75 $2.42
$3.09
$2.90
$2.47 $2.56 $2.77 $2.66
$2.28 $2.67
0.00
0.50
1.00
1.50
2.00
2.50
3.00
3.50
1Q 2017 2Q 2017 3Q 2017 4Q 2017 2015 2016 2017
$/
Mc
f
NYMEX Realizations
CRC – Price Realizations
66% 62%
72%79%
40%
52%
70%
63%59%
66%
72%
37%
50%
65%
0%
20%
40%
60%
80%
100%
1Q 2017 2Q 2017 3Q 2017 4Q 2017 2015 2016 2017
% o
f W
TI
& B
ren
t
WTI Brent
$51.91
$48.29
$48.21
$55.40
$48.80 $43.32
$50.95
$50.24 $47.98
$50.02
$56.92
$49.19
$42.01
$51.24
$54.66 $50.92
$52.18
$61.54
$53.64
$45.04
$54.82
30
40
50
60
70
1Q 2017 2Q 2017 3Q 2017 4Q 2017 2015 2016 2017
$/B
bl
WTI Realizations Brent
Realization %
of WTI97% 99% 104% 103% 101% 99% 101%
Realization %
of NYMEX89 % 79% 87% 92% 97% 94% 86%
Oil Price Realization (with Hedges) Gas Price Realization
NGL Price Realization - % of WTI & Brent
CRC believes near-term
differentials will remain strong
• California refinery demand for native crude continues to be strong
and reduction in heavy waterborne crude has positively
influenced differentials.
• NGL prices have been supported by lower inventories and export
markets.
-≈
Scotia Howard Weil – 46th Annual Energy Conference | 33
2014 Revolving Credit Facility Capacity -
$1 billion
Updated Capital Structure from Recent Transactions – Improved Liquidity
2017 Term Loan - $1.3 billion
2016 Term Loan - $1 billion
2015 Second Lien - $2.25 billion
Unsecured Notes - $0.393 billion
Drawn Revolver
$837
$0
$250
$500
$750
$1,000
3Q17 PF 4Q17*
($M
M)
Revolver
Availability
$431
Revolver
Availability
$850
Cash $11
Cash $441
$0
$200
$400
$600
$800
$1,000
$1,200
$1,400
3Q17 PF 4Q17*A
vaila
bilit
y ($
MM
)
Increased Liquidity**
* Pro Forma for the Ares JV and $50mm private placement
** Subject to minimum liquidity requirement under 2014 Revolving Credit Facility. Includes unrestricted cash.
Reduced Revolver Borrowing
Added in
NovemberDe
bt
Hie
rarc
hy
Undrawn
Revolver
Scotia Howard Weil – 46th Annual Energy Conference | 34
$100
$100
$193
$2,250
$1,000
$1,300
$0$0
$500
$1,000
$1,500
$2,000
$2,500
$3,000
$3,500
$4,000
Se
p-1
7
De
c-1
7
Ma
r-1
8
Jun
-18
Se
p-1
8
De
c-1
8
Ma
r-1
9
Jun
-19
Se
p-1
9
De
c-1
9
Ma
r-2
0
Jun
-20
Se
p-2
0
De
c-2
0
Ma
r-2
1
Jun
-21
Se
p-2
1
De
c-2
1
Ma
r-2
2
Jun
-22
Se
p-2
2
De
c-2
2
Ma
r-2
3
Jun
-23
Se
p-2
3
De
c-2
3
Ma
r-2
4
Jun
-24
Se
p-2
4
De
c-2
4
2014 RCF
2017 Term Loan
2016 Term Loan
2nd Lien Notes
Unsecured Notes
Strengthening the Balance Sheet - Improved Creditworthiness and Liquidity
• Pro forma net results from the Ares transactions which closed on February 7, 2018:
• CRC received $797 million in net proceeds, $8mm of which is restricted cash
• The RCF was paid in full
• The RCF has approximately $850 million of available borrowing capacity, excluding
$150 million minimum liquidity
• The recent amendment extends the maturity of the RCF to June 2021 and relaxes
financial covenants
1st Lien 2014 Revolving Credit Facility (RCF) -
1st Lien 2017 Term Loan 1,300
1st Lien 2016 Term Loan 1,000
2nd Lien Notes 2,250
Senior Unsecured Notes 393
Total Debt 4,943
Less cash2
(441)
Total Net Debt 4,502
Equity3
(764)
Total Net Capitalization 3,738
Total Net Debt / Total Net Capitalization 120%
Total Net Debt / LTM Adjusted EBITDAX4
5.9x
LTM Adjusted EBITDAX4
/ LTM Interest Expense 2.2x
PV-105 / Total Net Debt 1.0x
Total Net Debt / Proved Reserves ($/Boe) $7.28
Total Net Debt / Proved Developed Reserves ($/Boe) $10.23
Total Net Debt / 2017 Production ($/Boepd) $34,899
Pro-Forma1 Capitalization ($MM)
Pro-Forma1 Debt Maturities ($MM)*
1 Pro-forma capitalization table and debt maturities graph reflect the payoff of the 12/31/17 outstanding balance
of $363 million on our RCF after the completion of the Ares JV and $50 million private placement. 2 The $441 million of available cash includes (1) $15 million unrestricted cash as of 12/31/17 and (2) $426
million of available cash after the Ares transaction and proforma repayment of the RCF.3 Excludes noncontrolling interest at 12/31/17 and includes $50 million of equity from the Ares private placement.4 See www.crc.com, Investor Relations for a reconciliation to the closest GAAP measure and other important
information.5 PV-10 as of 12/31/17, see Attachment 2 of CRC’s Fourth Quarter Earnings Release dated February 26, 2018 for
details on this calculation.
* Previously, the RCF, the 2017 Term Loan and the 2016 Term Loan were subject to springing maturities related to the 2020
and 2021 Notes. During the fourth quarter of 2017, CRC repurchased $65 million in principal amount of the 2020 Notes and
$35 million in principal amount of the 2021 Notes, which eliminated those springing maturities. The 2017 Term Loan remains
subject to a springing maturity related to the 2016 Term Loan.
Undrawn RCF
Scotia Howard Weil – 46th Annual Energy Conference | 35
1Q 2018 2Q 2018 3Q 2018 4Q 2018 1Q 2019
Sold Calls Barrels per Day 9,000 6,200 16,100 16,100 1,100
Weighted Average Ceiling
Price per Barrel$59.58 $60.24 $58.91 $58.91 $60.00
Purchased Calls Barrels per Day - - - - 2,000
Weighted Average Ceiling
Price per Barrel- - - - $71.00
Purchased Puts Barrels per Day 1,200 1,200 6,100 1,100 14,100
Weighted Average
Floor Price per Barrel$45.82 $45.83 $61.48 $45.85 $58.93
Sold Puts Barrels per Day 29,000 29,000 24,000 19,000 10,000
Weighted Average
Floor Price per Barrel$45.00 $45.00 $46.04 $45.00 $47.50
Swaps Barrels per Day 38,300 34,000 19,000 19,000 7,000
Weighted Average
Price per Barrel$60.03 $60.00 $60.13 $60.13 $67.71
Percentage of 4Q 2017
Oil Production Hedged*49% 44% 31% 25% 26%
Opportunistically Built Oil Hedge Portfolio
Certain of our counterparties have options to increase swap volumes at weighted average costs between $60 and
$70 Brent. For potential volume changes and further details please see Attachment 10 of our Earnings Release.
* As of 2/26/2018. Assumes counterparty options are not exercised.
We target hedges
on 50% of crude
oil production
Strategy Protect cash flow for capital investments and covenant compliance
Scotia Howard Weil – 46th Annual Energy Conference | 36
Elk Hills Area – CRC’s Flagship Asset
Integrated Infrastructure
• 610 MMcf/d processing capacity through 4 gas plants
• Including California’s largest
• 3 CO2 removal plants
• Over 4,500 miles of gathering lines
• 45 MW cogeneration plant
• 550 MW power plant
1 DOGGR data and U.S. Energy Information Administration.
-
5
10
15
20
0
20
40
60
80
100
120
1998 2000 2002 2004 2006 2008 2010 2012 2014 2016
Rig
Co
un
t
Ne
t M
BO
E/d
Net MBOEPD Rig Count
Overview
• CRC’s flagship, a 100 year-old field with exploration opportunities
• Light oil from conventional and unconventional production
• Largest gas and NGL producing field in California, one of the largest fields in the continental U.S.1, >3,000 producing wells
• 11 billion OOIP (BOE) and cumulative production of over 2.7 billion BOE
• 2017 average net production of 53 MBOE/d (~40% of total CRC production)
Field Map
Production History
Large fee property position
with integrated infrastructure
Scotia Howard Weil – 46th Annual Energy Conference | 37
Buena Vista Area – Highly Prospective Area
FIELDMAP
Overview
• Includes Buena Vista (BV) Hills and BV Nose
• JV capital applied to infill development program that led to improved operational efficiencies
• Organic capital deployed to expand the extent of the play
• BV Nose was discovered in 2012 as a step-out to BV Hills
• 10,000’ average True Vertical Depth
• 32 API, 600 GOR
• Reduced capital costs with a new well design (two strings)
Growth potential near
existing infrastructure
34
21
0
10
20
30
40
2012-14 2017
Dri
llin
g T
ime
Da
ys/
we
ll
5.0
2.5
0
100
200
300
400
500
-
1.0
2.0
3.0
4.0
5.0
6.0
2012-14 2017
Dri
llin
g C
ost
$/
Ft
Dri
llin
g C
ost
$M
M/
we
ll
Drilling Cost/Well Drilling Cost $/Ft
2017 Conventional BV Nose Development
Drilling Cost Average Drilling Days/Well2017 BV Area development
program delivers a 1.8 VCI
at a $55 Brent price deck
Scotia Howard Weil – 46th Annual Energy Conference | 38
Accelerating Production Decline in U.S. Onshore Lower 48 Development Wells
-50%
-40%
-30%
-20%
-10%
0%
10%
20%
30%
40%
Year 1 Year 2 Year 3 Year 4 Year 5
Normalized Decline Rates
2010 Wells 2011 Wells 2012 Wells 2013 Wells 2014 Wells 2015 Wells
Source: Data from Wood Mackenzie, CRC analysis
Recent wells in the onshore Lower 48 are
showing steeper declines
-
1,000,000
2,000,000
3,000,000
4,000,000
5,000,000
6,000,000
7,000,000
2009 2010 2011 2012 2013 2014 2015 2016
Pro
du
ctio
n (
BO
PD
)
Pre 2010 2010 Wells 2011 Wells 2012 Wells 2013 Wells 2014 Wells 2015 Wells
Scotia Howard Weil – 46th Annual Energy Conference | 39
0%
10%
20%
30%
40%
50%
1 Year Decline
Median: 29%
Best In Class Corporate Decline Rates
0%
10%
20%
30%
40%
50%
60%
70%
80%
3 Year Decline
Median: 49%
CRC
CRC
Peers included: CLR, COG, CPE, CXO, DNR, EGN, EOG, EPE, FANG, HK, LPI, MRO, MTDR, MUR, NFX, OAS, PDCE, PE, PXD, QEP,RRC, RSPP, SM, SN, WLL,WPX, and XEC.
Source: Wood Mackenzie - Operated Production Data through 2016, CRC analysis.
FY 2016 Production Percentage Liquids
Less than 55% 55% - 75% Greater than 75%
Scotia Howard Weil – 46th Annual Energy Conference | 40
(3,000)
(2,500)
(2,000)
(1,500)
(1,000)
(500)
-
500
1,000
Un
leve
red
Fre
e C
ash
Flo
w (
$M
M)
CR
C
Core Principle of Living within Cash Flow
Peers included: APA, APC, AR, BBG, CHK, CLR, COG, CPE, CRK, CRZO, CXO, DNR, DVN, ECR, EGN, EOG, EPE, EQT, FANG, GPOR, GST, HK, JONE, LPI, MRO, MTDR, MUR, NBL, NFX, OAS, PDCE, PE, PXD, QEP, REI, RICE, RRC,
RSPP, SD, SGY, SM, SN, SWN, UNT, UPL, VNR, WLL, WPX, and XEC.
Source: FactSet.
2017 Unlevered Free Cash Flow
Average: $(341.5)MM
Scotia Howard Weil – 46th Annual Energy Conference | 41
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
― Two tranches of $50MM
― Total of $100MM 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
Scotia Howard Weil – 46th Annual Energy Conference | 42
-
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
o Partner pays 80-100% Capital
o Receives 80-100% Working Interest
o Typical hurdle rate:o 10% - 20% IRR
o Partner’s working interest once hurdle rate is achieved:o 5% - 25%
Hurdle Rate
Reached
Pro
du
cti
on
Time
Scotia Howard Weil – 46th Annual Energy Conference | 43
Strategic Partner Alignment
Summary of Deal
Partner ▪ Affiliate of Ares Management (Ares)
Contributed
Assets▪ Elk Hills power plant, gas processing assets and related non-borrowing base
infrastructure currently owned by CRC
Midstream JV
Capitalization
▪ Class A common interests (voting) owned 50% by Ares and 50% by California
Resources Elk Hills (CREH)
▪ Class B preferred interests (“Preferred”) owned 100% by Ares
▪ Class C common interests (distributing) owned 95.25% by CREH and 4.75% by Ares
Distribution to
Partners
▪ Preferred interests to receive distributions of 13.5% per annum on the $750 MM
contributed amount
▪ 9.5% cash pay and 4.0% PIK to be deferred for the first three years
▪ Deferred distributions are interest bearing and repaid over two years following the
deferral period
▪ Remaining cash after preferred distributions to be distributed pro rata to Class C
interests
Exit Provisions
▪ Prior to end of 5 or 7.5 years, CRC may redeem Preferred at variable amounts that
include make whole premiums
▪ At end of 5 years, CRC may elect to either redeem or extend to 7.5 years
▪ At 7.5 years, if not redeemed by CRC, Preferred can monetize the JV
Board▪ Board of Managers to consist of three CRC representatives and three
representatives from Ares
Scotia Howard Weil – 46th Annual Energy Conference | 44
CRC Midstream JV Structure with Ares
California Resources Elk
Hills, LLC
Elk Hills Power, LLC
Contributed
Assets
$750 MM gross proceeds
Class A (50%) and
Class C (95.25%)
Common Interests
Power and
Gas Processing
Services
Commercial Agreement
Capacity Charges
Ares Management, L.P. $750 MM gross
proceeds
Class B Preferred Interests, Class A and Class C
Common Interests
Benefits• Strategic alignment with Ares
• Provides CRC paths for opportunistic
deleveraging through cash flow
growth or debt reduction
• Greatly enhances liquidity
• Retain ownership and operational
control
• Defined exit criteria
Scotia Howard Weil – 46th Annual Energy Conference | 45
Dynamic Portfolio Provides Flexibility
0
200
400
600
800
BO
EP
D
YEAR 5
0
200
400
600
800
BO
EP
D
YEAR 5
Gas
0
200
400
600
800
BO
EP
D
YEAR 5
0%
25%
50%
75%
100%
Po
rtfo
lio
Mix
Higher Oil to Gas Price Ratio Lower Oil to Gas Price Ratio
Gas
Unconventional
Primary
Waterflood
Steamflood
Workover
EUR (MBOE per $10MM) 1,385 1,265 1,060
% Oil 81% 70% 53%
Development Cost/BOE $7.20 $7.90 $9.40
Recycle Ratio 3.4x 2.9x 2.2x
For illustration of portfolio optionality based on normalized results per $10MM of investment and not guidance. See endnote for details on type curves.
Prices for recycle ratio are $65 Brent and $3.50 NYMEX.
Oil
Gas
Oil OilGas
Scotia Howard Weil – 46th Annual Energy Conference | 46
0
25
50
75
100
0 1 2 3 4
BO
PD
YEAR
* Information is for a steamflood pattern assuming 3 producers per 1 injector and is 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 important information about our type curves.
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
300 Near Term Growth
Plan Pattern Locations
$NYMEX
VCI $3.5 $3 $2.5
$50 1.0 1.1 1.2
$55 1.3 1.4 1.5
$ B
RE
NT
$60 1.6 1.7 1.8
Scotia Howard Weil – 46th Annual Energy Conference | 47
0
15
30
45
60
0 1 2 3 4
BO
EP
D
YEAR
* Capital cost is fully burdened with facilities, injectors and tie-ins. Assumes 5-spot pattern with a 1:1 producer to injector ratio.
VCI 165 190
EUR
215
$50 1.3 1.5 1.7
$55 1.6 1.9 2.1
$ B
RE
NT
$60 1.9 2.2 2.5
Waterflood – New Pattern Composite Type Well
Composite
Type Curve
Mount Poso Actuals
Buena Vista Actuals
CRC OPERATED FIELDS
Rincon
Saticoy
South Mountain
Paloma
Mount Poso
Kettleman
Buena Vista
Elk Hills
CRC NEW & POTENTIAL WATERFLOODS
See endnote for important information about our type curves.
350 Near Term Growth
Plan Locations
PA
RA
ME
TER
S
PE
R P
ATT
ER
N Operating
Expense
$19/BOE
Capital
Cost*
$1.2MM
Total EUR
(MBOE)
190
Peak Rate
(BOEPD)
35
Drilling
Time (days)
10
Royalty
12.5%
Scotia Howard Weil – 46th Annual Energy Conference | 48
0
40
80
120
160
0 1 2 3 4
BO
EP
D
YEAR
* 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 important information about our type curves.
PA
RA
ME
TER
S Operating
Expense
$19/BOE
Capital
Cost*
$1.8MM
Total EUR
(MBOE)
165
Peak Rate
(BOEPD)
120
Drilling
Time (days)
14
Royalty
PSC**
VCI 140 165
EUR
190
$50 1.1 1.3 1.5
$55 1.4 1.6 1.9
$ B
RE
NT
$60 1.6 1.9 2.2
Waterflood – Redevelopment Type Well
Huntington Beach Actuals
Elk Hills Actuals
Composite Type well
West Wilmington Actuals
East Wilmington Actuals
CRC OPERATED FIELDS
San Miguelito
Elk Hills
Wilmington
Huntington
Beach
CRC REDEVELOPMENT
WATERFLOODS
350 Near Term Growth
Plan Locations
Scotia Howard Weil – 46th Annual Energy Conference | 49
PA
RA
ME
TER
S Operating
Expense
$10/BOE
Capital
Cost*
$5.0MM
Total EUR
(MBOE)
430
Peak Rate
(BOEPD)
360
Drilling
Time (days)
30
Royalty
12%
* 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
VCI 400 430
EUR
460
$50 1.5 1.6 1.7
$55 1.7 1.8 2.0
$ B
RE
NT
$60 1.9 2.1 2.2
0
150
300
450
600
750
900
0 1 2 3 4
BO
EP
D
YEAR
Composite Type well
Wheeler
Ridge Actuals
Bardsdale
Actuals
Pleito Ranch
Actuals
BV Nose
Actuals
CRC OPERATED FIELDS
Montalvo
Kettleman
Saticoy Bardsdale
South Mountain
Elk Hills
BV Nose
Yowlumne
Pleito Ranch
Wheeler Ridge
PalomaRio Viejo
CRC PRIMARY
See endnote for important information about our type curves.
150 Near Term Growth
Plan Locations
Scotia Howard Weil – 46th Annual Energy Conference | 50
California Shale Type Well
Asphalto
Elk Hills
Buena Vista
Kettleman
Rose
N. Shafter
Gunslinger
Railroad Gap
CRC SHALE
-
100
200
300
400
500
0 1 2 3 4
BO
EP
D
New Pool Type Curve
Infill Shale Curve
YEAR
Gunslinger Actuals
Rose/N. Shafter
Actuals
Elk Hills Actuals
Elk Hills (2001-2003)
VCI Infill New Pool
$50 1.2 1.7
$55 1.3 1.9
$ B
RE
NT
$60 1.4 2.0
*Capital cost includes drilling, completion and tie-ins. See endnote for important information about our type curves.
New Pool
Operating
Expense
$10/BOE
$8/BOE
Capital
Cost*
$5.0MM
$2.5MM
Total EUR
(MBOE)
765
220
Peak Rate
(BOEPD)
500
143
Drilling
Time (days)
30
20
Average
Royalty
13%
13%Infill
50 Near Term Growth Plan
Locations (Split Evenly)
CRC OPERATED FIELDS
Scotia Howard Weil – 46th Annual Energy Conference | 51
A Net Water Supplier
• For every gallon of fresh water CRC purchased in 2017, we delivered nearly 3 gallons of treated water to agriculture
• Recycled or reclaimed over 89% of our produced water in 2017, almost a 10% increase since 2015
• Reduced our produced water disposal by over 40% since 2015
• Reduced our potable water use by nearly 30% since 2015
In 2017, CRC supplied 4.9 billion
gallons – over 15,000 acre-feet – of
treated, reclaimed water for
irrigation or recharge.
94%
4% 2% WATER MANAGED IN
CRC’s OPERATIONS
Produced Water
Fresh Water
Non-Fresh Water
CRC set a new company record for
water deliveries to agriculture in
2017, an 85% increase since 2015,
preserving farmland and jobs.
CRC’s operations in Long Beach use
recycled or non-fresh water for
99.5% of their total water use.
Scotia Howard Weil – 46th Annual Energy Conference | 52
End Notes
1 Current CRC estimate of reserves value as of December 31, 2017. Includes field-level operating expenses and G&A. Assumes
$3.00/MMBTU NYMEX.
2 Reflects the value of facilities and midstream assets at 50% of estimated replacement value. This discount is estimated to exceed
the burden on reserves that would be incurred if assets were monetized. Excludes the value of the assets monetized in the Ares
transaction.
3 Surface & Minerals reflect the estimated value of undeveloped surface and minerals held in fee.
4 Unproved inventory comprises risked probable and possible reserves and contingent and prospective resources. Contingent and
prospective resources consist of volumes identified through life-of-field planning efforts to date.
5 Calculated using Pro Forma debt post Ares transaction and market cap as of March 16, 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.
Value Creation Index (VCI) Note: VCI is calculated by dividing the net present value of the project’s expected pre-tax cash flow over its
life by the net present value of project investments, each using a 10% discount rate