Global Energy Conference
Bank of America Merrill Lynch
Todd Stevens| President & CEO| Miami, FL| November 16-17, 2016
BOAML 2016
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 specifically include our expectations as to our future financial position, drilling
and workover program, joint ventures, production, projected costs, future operations, hedging activities, future transactions, planned capital
investments and other guidance (including VCI calculations). Actual results may differ from anticipated results, sometimes materially, and reported
results should not be considered an indication of future performance. For any such forward-looking statement that includes a statement of the
assumptions or bases underlying such forward-looking statement, we caution that, while we believe such assumptions or bases to be reasonable and
make them in good faith, assumed facts or bases almost always vary from actual results, sometimes materially. Factors (but not necessarily all the
factors) that could cause results to differ include: assumptions underlying our expectations for meeting our guidance and projections, including any
effect on reserves values of monetizations of infrastructure; commodity price fluctuations; the ability of our lenders to limit our borrowing capacity;
other liquidity constraints; the effect of our debt on our financial flexibility; limitations on our ability to enter efficient hedging transactions; insufficiency
of our operating cash flow to fund planned capital expenditures; steeper than expected production decline rates; inability to implement our capital
investment program; inability to replace reserves; inability to obtain government permits and approvals; inability to monetize selected assets;
restrictions and changes in restrictions imposed by regulations including those related to our ability to obtain, use, manage or dispose of water or use
advanced well stimulation techniques like hydraulic fracturing; risks of drilling; tax law changes; competition with larger, better funded competitors for
and costs of oilfield equipment, services, qualified personnel and acquisitions; the subjective nature of estimates of proved reserves and recoverable
quantities from resources not classified as proved, and related future net cash flows; risks related to our disposition and acquisition activities; restriction
of operations to, and concentration of exposure to events such as industrial accidents, natural disasters and labor difficulties in, California; the
recoverability of resources; concerns about climate change and air quality issues; lower-than-expected production from development projects or
acquisitions; catastrophic events for which we may be uninsured or underinsured; effects of litigation; cyber attacks; operational issues that restrict
market access; and uncertainties related to the Spin-off and the agreements related thereto. Material risks are further discussed in “Risk Factors” in our
Annual Report on Form 10-K and subsequent 10-Qs available on our website at crc.com. Words such as "aim," "anticipate," "believe," "budget,"
"continue," "could," "effort," "estimate," "expect," "forecast," "goal," "guidance," "intend," "likely," "may," "might," "objective," "outlook," "plan,"
"potential," "predict," "project," "seek," "should," "target, "will" or "would" or similar expressions that convey the prospective nature of events or
outcomes generally indicate forward-looking statements. Any forward-looking statement speaks only as of the date on which such statement is made
and CRC undertakes 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.
Some of the data in this presentation is from external sources as noted. While we believe it is accurate, we have not independently verified the data and
do not represent or warrant that it is accurate, complete or reliable.
This presentation includes financial measures that are not in accordance with United States generally accepted accounting principles (“GAAP”), including
adjusted net income (loss), PV-10, adjusted EPS and adjusted EBITDAX. While management believes that such measures are useful for investors, they
should not be used as a replacement for financial measures that are in accordance with GAAP. For a reconciliation of such measures to the nearest
comparable measure in accordance with GAAP, please see the Appendix.
2
BOAML 2016
Cautionary Statements Regarding
Hydrocarbon Quantities
We have provided internally generated estimates for proved reserves and aggregated proved, probable and possible reserves (“3P Reserves”) as of
December 31, 2015 in this presentation, with each category of reserves estimated in accordance with SEC guidelines and definitions, though we have
not reported all such estimates to the SEC. As used in this presentation:
• Probable reserves. We use deterministic methods to estimate probable reserve quantities, and when deterministic methods are used, it is as
likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves.
• Possible reserves. We use deterministic methods to estimate possible reserve quantities, and when deterministic methods are used to
estimate possible reserve quantities, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus
probable plus possible reserves.
The SEC prohibits companies from aggregating proved, probable and possible reserves estimated using deterministic estimation methods in filings with
the SEC due to the different levels of certainty associated with each reserve category.
Actual quantities that may be ultimately recovered from our interests may differ substantially from the estimates in this presentation. Factors affecting
ultimate recovery include the scope of our ongoing drilling and workover program, which will be directly affected by commodity prices, the availability of
capital, regulatory approvals, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations,
transportation constraints and other factors; actual drilling results, which may be affected by geological, mechanical and other factors that determine
recovery rates; and budgets based upon our future evaluation of risk, returns and the availability of capital.
We use the term “oil-in-place” and “inventory” in this presentation to describe estimates of potentially recoverable hydrocarbons remaining in the
applicable reservoir. These resources are not proved reserves in accordance with SEC regulations and SEC guidelines restrict us from including these
measures in filings with the SEC. These have been estimated internally without review by independent engineers and may include shale resources which
are not considered in most older, publicly available estimates. Actual recovery of these potential resource volumes is inherently more speculative than
recovery of estimated reserves and any such recovery will be dependent upon future design and implementation of a successful development plan and
the actual geologic characteristics of the reservoirs. Management’s estimate of original hydrocarbons in place includes historical production plus
estimates of proved, probable and possible reserves and a gross resource estimate that has not been reduced by appropriate factors for potential
recovery and as a result differs significantly from estimates of hydrocarbons that can potentially be recovered. Unproved inventory comprises risked
probable and possible reserves and may include contingent and prospective resources. Contingent and prospective resources consist of volumes
identified through life-of-field planning efforts to date that have not been risked by reference to analogy or other methods used to estimate the chance
of success from drilling. For information on the determination of locations, please consult our Form 10-K. Ultimate recoveries will be dependent upon
numerous factors including those noted above.
3
BOAML 2016
• CRC Opportunity Defined
• Priorities and Accomplishments
• Value Creation Focus – Doubles Inventory
• Capital Allocation – Inflection Point
4
BOAML 2016
Reserve Value1 Well in Excess of EV
5
1,2,3,4,5 See End Notes in the Appendix.
PDP Value
Proved Value
$0
$2,000
$4,000
$6,000
$8,000
$10,000
$12,000
$14,000
$16,000
$18,000
Strip Price 8/23 $65 Brent $75 Brent
($MM
)
Current EV of
$5.7 Bn5
Infrastructure2
Surface & Minerals3
Unproved4
BOAML 2016
Project Inventory Drives Organic Deleveraging
6
Surface & Minerals3
0.0x
2.0x
4.0x
6.0x
8.0x
10.0x
12.0x
2016E 2017E 2018E 2019E 2020E
To
ta
l D
eb
t/
LTM
E
B
IT
D
A
X
Leverage Ratios
Strip 10/10 $65 $75
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 escalate ~5% per year from 2016 levels for the mid-point case of the range of portfolio planning scenario outcomes.
BOAML 2016 NY00813G / 589203_1.WOR
Sacramento Basin
14 MMBoe Proved Reserves
6 MBoe/d production
San Joaquin Basin
451 MMBoe Proved Reserves
98 MBoe/d production
Ventura Basin
47 MMBoe Proved Reserves
7 MBoe/d production
Los Angeles Basin
132 MMBoe Proved Reserves
31 MBoe/d production
World-Class Resource Base
Operate in 4 of 12 largest fields in the
continental U.S.
644 MMBoe proved reserves
142 MBoe/d production, 77% liquids
2.4 million net acres with significant mineral
interest
Low, flattening decline rate
Positioned to Grow as Prices Increase
Internally funded capital program designed to live
within cash flow and drive growth
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
CRC’s Large Resource Base with Advantaged Infrastructure
Reserves as of 12/31/15; Production figures reflect average 3Q YTD 2016 rates.
7
BOAML 2016
Largest California Producer with Deep Regional Insight
8
Surface & Minerals3
Top California Producers in 2015
196
161
134
35 34
-
20
40
60
80
100
120
140
160
180
200
CRC Chevron
USA
Aera Energy Freeport
McMoRan
LINN Energy
G
ro
ss
O
p
erat
ed
M
b
o
e/
d
Source: DOGGR, IHS, Wood Mackenzie, Company Estimates
$16
$23
$22
$29 $29
$0
$5
$10
$15
$20
$25
$30
$35
0%
25%
50%
75%
100%
CRC Chevron
USA
Aera Energy Freeport
McMoran
LINN Energy
Majority of CA production is shallow
Shallow Deep (>5,000') Avg. 2016 OPEX $/BOE
Largest 3-D Seismic Position in California
BOAML 2016
California Stacked Reservoirs:
Multiple opportunity sets with large accumulations
9
Surface & Minerals3
Source: Information based on internal observed data and external published reports.
TEMBLOR
SANDS
EOCENE
SANDS AND
SHALES
UPPER
CRETACEOUS
SANDS AND
SHALES
MONTEREY
SANDS AND
SHALES
1
,0
0
0
’
P
A
Y
TULARE
SANDS
20
50
100
20
30
50
SH
A
LL
O
W
D
EE
P
Primary Oil
Primary Shale
Primary Dry Gas
SteamFlood
WaterFlood
Type Wells
• OOIP: 2 BBO
• Estimated Recovery Factor: 25 %
• Heavy Oil Trend
• OOIP: 5 BBO
• Estimated Recovery Factor : 20%
• OOIP: 50 BBO
• Estimated Recovery Factor : 8%
• Heavy Oil Trend
• Source Rock
• Conventional and Unconventional Primary Oil and Gas
Zones
• OOIP: 10 BBO
• Estimated Recovery Factor: 35%
• OOIP:6 BBO
• OGIP: 20 TCF
• Estimated Recovery Factor : 10%
• OGIP: 20 TCF
• Estimated Recovery Factor : 40%
>5,000’ +
ETCHEGOIN
SANDS
<5,000’ +
15,000’
#
of
S
ta
ck
ed
R
e
se
rv
oi
rs
BOAML 2016
Benefits of the Spin: Focus Led to Improvements
10
Sac
Valley
Thermal PV10 pre-tax cash flows
PV10 of investments
VCI =
Value Creation Index
One CRC
• Entrepreneurial culture
• Disciplined capital allocation through portfolio
management
• Three principal drivers:
o Maximize long-term value – VCI > 1.3
o Value focused growth
o Financial discipline – self-funding business
Elk Hills
THUMS
Vintage
BOAML 2016
• CRC Opportunity Defined
• Priorities and Accomplishments
• Value Creation Focus – Doubles Inventory
• Capital Allocation – Inflection Point
11
BOAML 2016 12
6,765(1)
5,247
4,000
5,000
6,000
7,000
2Q15 Debt Exchange
for 2L
Open Market
Repurchases
Equity for Debt
Exchange
Cash Tender
for Unsecureds
Operating Cash
Flow
3Q16
To
ta
l D
e
b
t
($
MM
)
(2)
Strengthen the Balance Sheet
Significant Debt Reduction From Post-Spin Peak
Chose options to maximize deleveraging and minimize recurring cost
to the income statement and on a per share basis
Cumulative Debt Reduction Total
Total Net Principal Reduction
$535
million
$110
million
$80
million
$625
million
$168
million
$1,518
million
Annual Income Statement
Effect (Annualized Interest)
+$22
million
-$6
million
-$5
million
+$27
million
-$5
million
$33
million
1 Represents mid-second quarter peak debt.
2 CRC reduced an additional $21mm of principal amount in October 2016 in exchange for 1.26mm shares of common stock.
BOAML 2016
Protect the Base
Low Decline Asset Base Requires Low Levels of D&C* Capital
Rich asset portfolio and thoughtful capital
allocation deliver high margin production and
operational flexibility through the price cycle
• Conventional assets with long production
life and relatively low decline rates
• Large inventory of conventional,
repeatable, development projects with low
technical risk
Application of modern technologies/margin
improvement/growth opportunities
• Deferring many high-return project
opportunities until prices rise
• Identifying investments that meet our VCI
threshold through commodity price cycles
• Sophisticated well surveillance
13
FY 2014 FY 2015 FY 2016E
MB
o
e/
d
Production By Stream (MBoe/d)
Oil NGL Gas Guidance
99 MB/d
104 MB/d
Down
~12-14% With
Only ~$50MM
D&C + Workover
Capital Investment
Up ~5%
With Only
<$200MM D&C +
Workover Capital
Investment
160 MBoe/d
159 MBoe/d
*D&C = Drilling and Completion
BOAML 2016
$-
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
$14.00
$16.00
$18.00
$20.00
2014 2015 2016 YTD
P
ro
d
u
ct
io
n
C
o
st
s ($/Boe
)
Steam Injectant Gas Plant Expense
Energy Supports and Other
Downhole Maintenance Workovers/Well Enhancement
Surface Operations and Maintenance Pipeline/Transportation
14
Defend Margins
Continued Operating Cost Reductions and Efficiencies
3Q YTD 2016 Avg: $15.01
2015 Avg: $16.30
Down $1.29/Boe
Or ~8% decrease 2014 Avg: $18.23
BOAML 2016 15
Reduced Well Costs
2016 program has ~23% lower well costs compared to prior similar wells
0
300
600
900
1,200
1,500
1,800
Long Beach
Horizontal
Elk Hills
ESOZ
Mt. Poso Lost Hill
Injector
Kern Front Lost Hills
Producer
$
M
Last Drilled (2014/2015) 2016
Efficiency drivers:
Rig costs – Rig optimization and day work rate reduction
Cementing – Slurry redesign, volume optimization
Back to Basics – Cost reduction workshops covering spud
through online well scope, logging, and completion methods
Includes drilling, completion and hook-up costs
40%
15%
13%
9%
7%
6%
6%
4%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
2016 Dri l l ing
Savings
Logging
Casing
Materials
Cementing
Services Fluid Hauling
Contr Rig Supervisor
Rental Service Equip
Rig Costs
BOAML 2016 16
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
2015 2016 2015 2016 2015 2016
$55 $65 $75
D
rilling and
W
or
k
o
ve
r
Capital (
$
MM
)
Brent Marker Price ($/BBL)
VCI > 1.0
VCI > 1.3
Focus on Life of Field Plans
Doubled project inventory at $55 Brent
Actionable Economic Project Inventory
BOAML 2016
• CRC Opportunity Defined
• Priorities and Accomplishments
• Value Creation Focus – Doubles Inventory
• Capital Allocation – Inflection Point
17
BOAML 2016
Value Chain Progress: Building Inventory Across 135 Fields
18
Legacy Field Review - Paloma
• Technical reevaluation doubled OOIP
estimate
• Analog field performance
• Applying new technology and thinking
to generate new opportunities
Delineation - Pleito
• Grew production since acquisition
• Applying reservoir learnings
• Targeting additional zones
Development – Kern Front
• Production ramp drives cash flows
• Repeatability of operations &
techniques
• Low base decline
0
20
40
60
80
100
0
750
1,500
2,250
3,000
3,750
4,500
A
ct
iv
e
P
ro
d
u
ce
r Co
u
n
t
G
ro
ss
A
vg
M
o
n
th
ly
R
at
e
(B
o
e/
d
)
Pleito Production
Boepd
Well Count
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
G
ro
ss
P
ro
d
u
ct
io
n
R
at
e
(B
/d
)
Steamflood Example: Kern Front
Kern
Front
Paloma
Pleito
BOAML 2016
Updated Inventory by Project Type
19
Actionable projects >1.3 VCI
Table indicates the years of inventory available at each price deck and continuous activity level (active rig counts per year)
Rigs/Year Years of Inventory
4 29 35 47
6 19 24 31
8 14 18 24
10 12 14 19
12 10 12 16
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
$55 Brent /
$3 Mcf
$65 Brent /
$3.5 Mcf
$75 Brent /
$4 Mcf
Dri
lli
n
g
Ca
p
it
a
l ($
M
M
)
Workovers
Waterflood
Unconventional
Steamflood
Primary
BOAML 2016
Steamflood
Primary-
Conventional Waterflood
Primary-
Unconventional Primary-Gas
35-50+%
Per Pattern
30-90+%
Per Well
30-100+%
Per Pattern
15-40+%
Per Well
12-30+%
Per Well
20
Robust Returns Across Multiple Drive Mechanisms
Oxnard Oakridge Wilmington Asphalto Rio Vista
Midway Sunset Montalvo Huntington Beach Railroad Gap Thompkins Hill
McDonald Anticline Rio Viejo San Miguelito BV Nose Willows
McKittrick Pleito Ranch Mt. Poso Shale 29R Grimes
Lost Hills Wheeler Ridge Rincon Buena Vista Kettleman
Kern Front Saticoy S. Mountain N. Shafter
Bardsdale Buena Vista Rose
Paloma Paloma Gunslinger
WSOZ WSOZ EH Stevens
ESOZ ESOZ Kettleman
EH Stevens EH Stevens
Kettleman Kettleman
All economics are pre-tax and assume $65/bbl Brent & $3.50/MMBTU NYMEX. Range is determined by low & high EUR boundaries
BOAML 2016
Elk Hills Adjacent Field: Buena Vista Field Development
21
2500
TVD
2750
3000
3250
3750
4000
4250
3500
B
V
S
ha
le
B
V
W
at
e
rf
loo
d
Effective Production Management
• Current net production of ~10,000 Boe/d (no
rigs since 2014)
• Surveillance with modern tools
• Daily exception reports/weekly pattern reviews
• Bi-annual update of life of field plan
Operational Efficiencies/Cost Reduction
• Using produced water from shale wells as
injection water in waterflood (WF)
• Switched to Elk Hills power resulting in 60%
reduction in yearly energy cost
Development Opportunities
• 250 unconventional unproven drilling locations
and 180 WF patterns in development inventory
• Potential to more than double field production
from 10,000 boepd with full field development
• Exploration discovery in 2012 - average IP for
5 wells 500 Bbl/d
$50.94
$20.31
$19.78
$13.54
$11.48
$0.00
$15.00
$30.00
$45.00
$60.00
2012 2013 2014 2015 2016
Opex/Boe
Other Opex $/Boe Energy - $/Boe Total OPEX - $/Boe
42%
reduction
post spin
BOAML 2016
Elk Hills Analog: Kettleman North Dome
22
• OOIP of 4 billion barrels, 14,000 Acres (2 mi.
wide, 15 mi. long)
• 1000’s of feet of stacked pay
• Light oil – API > 36o
• WI=100% and NRI=80% in KNDU
• Modern formation evaluation, new wells, and
workovers
• Advancing the understanding and development
potential
• 7 stacked pay reservoirs
• >5000 feet thick
• Limited current production
• Initial technical appraisal complete
• Acquired 200 mi2 3D seismic survey in
2015
• Reinterpreted reservoirs and structure
• Pilots that validated understanding
• Implement development plan
Bakersfield
Elk Hills
Lost Hills
Relatively
Steep SE Flank
-4000
-6000
-8000
-10000
-12000
Temblor
McA ams
Upper
Lower
Zone I
Zone II
Zone III
Zone IV
Zone V
SW NE
Vaqueros
Upper McAdams Gas
Original
Oil Band
Temblor Primary Gas Caps
Kreyenhagen Shale
Prior Kr Wells
2014 Kr Well
Rio Lobo
seismic
survey
KNDU
Field
Boundary
BOAML 2016
Steamfloods
23
AVG. DEPTH (True Vertical) 2,000
AVG. GROSS THICKNESS
(feet)
1,000
# OF SECTIONS 20
Avg. OOIP/OGIP per Section
(MMBOE)
40
Avg. EUR (MBOE) 270
AVG. SPACING (acres) 5
# OF LOCATIONS 2,560
% OF SECTIONS COVERED
BY 3D SEISMIC
50%
STEAM GENERATOR COST $4mm
PATTERNS PER STEAM
GENERATOR
5
• Analog fields have had success with
horizontal wells – up to 10x productivity for
2x the cost
• Multi-zone development
• Strong cash flow generation and asset
preservation by lowering base decline
• Steam injection contributes to over 1.2mm
bopd worldwide
• Thermal techniques account for over 40% of
US EOR production, 95% of these are in
California
• Up to 70% of the oil-in-place can be
recovered through steam injection
• Characterized by low risk and stable/low
decline
• Low capital intensity and robust margins
make it attractive investment at low prices
TEMBLOR
SANDS
EOCENE
SANDS AND
SHALES
UPPER
CRETACEOUS
SANDS AND
SHALES
MONTEREY
SANDS AND
SHALES
1
,0
0
0
’
P
A
Y
TULARE
SANDS
20
50
100
20
30
50
SH
A
LL
O
W
D
EE
P
ETCHEGOIN
SANDS
#
of
S
ta
ck
ed
Reser
voi
rs
Targeted Zones
Characteristics
Portfolio Contribution
Untapped Potential
BOAML 2016
Waterfloods
24
AVG. DEPTH (True Vertical) 5,000
AVG. GROSS THICKNESS
(feet)
1,000
# OF SECTIONS 50
Avg. OOIP/OGIP per Section
(MMBOE)
20
Avg. EUR (MBOE) 200
AVG. SPACING (acres) 10
# OF LOCATIONS 3,200
% OF SECTIONS COVERED
BY 3D SEISMIC
80%
• Potential to convert several primary fields to
waterfloods
• Strong cash flow generation and asset
preservation by protecting oil production
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 a waterflood is
generally 1/3 less vs. unconventional wells
Low capital intensity and robust margins
make it attractive investment at low prices
Portfolio Contribution
Untapped Potential
TEMBLOR
SANDS
EOCENE
SANDS AND
SHALES
UPPER
CRETACEOUS
SANDS AND SHALES
MONTEREY
SANDS AND
SHALES
1
,0
0
0
’
P
A
Y
TULARE
SANDS
20
50
100
20
30
50
S
H
A
LL
O
W
D
EE
P
ETCHEGOIN
SANDS
#
of
S
ta
ck
ed
Reser
voi
rs
Targeted Zones
Characteristics
BOAML 2016
• CRC Opportunity Defined
• Priorities and Accomplishments
• Value Creation Focus – Doubles Inventory
• Capital Allocation – Inflection Point
25
BOAML 2016
• Investment balanced against deleveraging
opportunities with goal of high single-digit
production growth
• Existing Core Areas
• Focus on 2-3 Growth Areas
Elk Hills Analogs
Elk Hills Adjacent Areas
Heavy Oil
• Joint Venture opportunities
• Double-digit growth possible if supported by
price outlook, while sustaining balance sheet
objectives
• Core Areas + Growth Areas
• 3+ High Impact Growth Areas Identified
• Joint Venture opportunities
• Exploration
Capital Allocation Strategies with Improving Strip
26
Base Case Pricing*
Steamfloods & Waterfloods
Conventional
Upside Pricing*
Steamfloods and Waterfloods
Conventional
Unconventional and Other
Capital
Investments
Capital
Investments
* Base Case Pricing assumes $65 Brent and Upside Case Pricing assumes $75+ Brent oil price.
BOAML 2016
Portfolio Flexibility Provides Range of Crude Oil Scenarios
27
80
90
100
110
120
130
2016E 2017E 2018E 2019E 2020E
O
il
P
ro
d
u
ct
io
n
MB/
d
Crude Oil Production Outcomes
Portfolio Planning
Scenarios
0
300
600
900
1200
Ca
p
it
al
(
$MM
) Estimated Capital Invested
Note: Assumes $60 Brent in 2017 and $65 Brent thereafter. Assumes lease operating costs on an absolute basis escalate ~5% per year from 2016 levels for the mid-point of the range of
planning scenario outcomes. Ranges of portfolio planning scenario outcomes assume development of a variety of combinations of steamflood, waterflood, conventional and unconventional
projects in our inventory. Top end of range of planning scenario outcomes includes geologic, development and permitting risks. All free cash flow reinvested in business for each outcome.
BOAML 2016
Double-Digit EBITDAX Growth
28
400
600
800
1000
1200
1400
1600
1800
2016E 2017E 2018E 2019E 2020E
$M
M
Range of EBITDAX Outcomes
Portfolio Planning
Scenarios
Note: See comments on previous slide.
BOAML 2016 NY00813G / 589203_1.WOR
Sacramento Basin
14 MMBoe Proved Reserves
6 MBoe/d production
San Joaquin Basin
451 MMBoe Proved Reserves
98 MBoe/d production
Ventura Basin
47 MMBoe Proved Reserves
7 MBoe/d production
Los Angeles Basin
132 MMBoe Proved Reserves
31 MBoe/d production
World-Class Resource Base:
Large inventory of assets across basins and
drive mechanisms that provide strong
returns through the commodity price cycle
Exceptional Operating Control:
High level of operating control
favorably positions CRC to capitalize on a
strengthening commodity market
Stable Base:
Diverse and stable assets enable a predictable
production profile with low base declines
Focused and Experienced Management Team:
Proactive executive team that swiftly executes
strategic objectives
Poised to Take Advantage of a Commodity Price Recovery
Reserves as of 12/31/15; Production figures reflect average 3Q YTD 2016 rates.
29
BOAML 2016
California Resources Corporation
Appendix
30
BOAML 2016
Capitalization as of 9/30/16 ($MM)
$18
$449
$193 $149
$1,000
$2,250
212
$0
$500
$1,000
$1,500
$2,000
$2,500
Jan-1
6
Ju
l-1
6
Jan-1
7
Ju
l-1
7
Jan-1
8
Ju
l-1
8
Jan-1
9
Ju
l-1
9
Jan-2
0
Ju
l-2
0
Jan-2
1
Ju
l-2
1
Jan-2
2
Ju
l-2
2
Jan-2
3
Ju
l-2
3
Jan-2
4
Ju
l-2
4
Term Loan
Debt Maturities ($MM)*
Strengthening the Balance Sheet
• Deleveraging is a priority; ~$1.5 billion
decrease to date from post-spin peak
• Utilized cash flow to make amortization
payments on term loan
• $625 million net debt reduction from cash
tender for bonds
• Exchanged equity for $101 million of 5.5%
and 6% bonds
1 As of September 30, 2016, we had approximately $506MM of available borrowing capacity under our
revolving credit facility.
2 See Appendix for reconciliation to GAAP.
3 PV-10 as of 12/31/15 based on SEC five-year rule applied to PUDs using SEC price deck. See Appendix
for reconciliation to GAAP.
4 Reserves as of 12/31/15.
5 Production in 3Q16.
1st Lien Secured RCF1 772
1st Lien Secured Term Loan (1L) 671
1st Lien Second Out Term Loan (1LSO) 1,000
Senior 2nd Lien Notes 2,250
Senior Unsecured Notes 554
Total Debt 5,247
Less cash (10)
Total Net Debt 5,237
Equity (493)
Total Net Capitalization 4,744
Total Net Debt / Total Net Capitalization 110%
Total Net Debt / LTM Adjusted EBITDAX2 7.8x
LTM Adjusted EBITDAX / LTM Interest Expense 2.1x
PV-103 / Total Net Debt 1.0x
Total Net Debt / Proved Reserves4 ($/Boe) $8.13
Total Net Debt / PD Reserves4 ($/Boe) $10.89
Total Net Debt / Production5 ($/Boepd) $37,949
* As of 9/30/16
31
BOAML 2016
Living within Cash Flow Plus Additional Liquidity
32
Based on our current capital program and at current price levels, we believe that we
will have sufficient liquidity for the rest of this year, all of 2017 and well into 2018.
Consensus2 EBITDA
Consensus2 EBITDA
Revolver Availability 1
Revolver Availability 1
Annual Cash Interest Annual Cash Interest
Term Loan Amortization Term Loan Amortization
HSE Capital Investment
Credit Amendment CapEx 2
$0
$200
$400
$600
$800
$1,000
$1,200
$1,400
$1,600
2016E 2016E 2017E 2017E
($MM
)
2
HSE & Capital Investment
1 Effective November 1, 2016, the borrowing base under our Credit Facilities was reaffirmed at $2.3 billion. As of September 30, we had approximately $506MM of available borrowing
capacity under our revolving credit facility.
2 As of 11/09/16.
3 CRC’s investment budget for 2017 is currently limited by our credit facility up to $200 million plus carry-over of unspent 2016 investment and an additional potential $50 million on meeting a
liquidity test in June 2017. CRC has not set a 2017 budget at this time; the Capital Investment reflects current maximum level in CRC’s Reserves-Based Credit Agreement.
1
1
3
2
BOAML 2016
Opportunistically Built Oil Hedge Portfolio1
• Hedge book started at zero post spin; we target hedges on 50% of production
• Strategy focuses on protecting cash flow for capital investments and covenant compliance
Q4
2016
Q1
2017
Q2
2017
Q3
2017
Q4
2017
1Q
2018
2Q
2018
3Q
2018
4Q
2018
Calls
Barrels per Day 25,000 12,100 5,000 10,000 15,000 15,600 15,000 15,000 15,000
Wtd Avg Ceiling
Price per Barrel
$53.62 $56.37 $55.05 $56.15 $56.12 $58.77 $58.83 $58.83 $58.83
Puts
Barrels per Day 3,000 22,100 15,000 10,000 10,000
Wtd Avg Floor
Price per Barrel
$50.00 $49.10 $48.67 $48.00 $48.00
Swap
Barrels per Day 39,000 20,0002 20,0002 20,0002 20,0002
Wtd Avg Price
per Barrel
$49.71 53.98 53.98 53.98 53.98
33
1 Prices are based on Brent. Positions as of November 11, 2016.
2 Includes a quarterly counterparty option to increase volumes by up to 10,000 barrels per day for that quarter at a weighted-average Brent price of $55.46.
BOAML 2016
2015 Net Proved Reserves (MMBoe) 644
2015 % Oil – Net Proved1 72%
Pre-Tax Proved PV-10 ($ billion)2 5.1
2015 Avg. Net Production (MBoe/d) 160
2015 % Oil Production 65%
2015 Net Acreage (million acres) 1 2.4
2015 Identified Gross Locations1 23,450
1 As of 12/31/15. Drilling locations exclude 6,400 gross prospective locations.
2 See Appendix for reconciliation to GAAP.
Figures shown are full year 2015, unless otherwise noted.
San Joaquin Basin Los Angeles Basin Ventura Basin Sacramento Basin
2015 Net Proved Reserves (MMBoe)
451 132 47 14
2015 % Proved Developed 72% 80% 77% 100%
2015 % Liquids – Net Proved
1
78% 98% 89% 0%
2015 Avg. Net Production (MBoe/d) 110 34 9 7
2015 % Oil Production 58% 100% 67% 0%
2015 Net Acreage (million acres)
1
1.6 <0.1 0.3 0.5
2015 Identified Gross Drilling Locations
1
19,150 1,650 1,500 1,150
Diverse Assets with Flexible Development Opportunities
• Diversity of basins, drive mechanisms
• Predictable production, low decline rates
• Multiple stacked reservoirs
• Development targets include repeatable
projects with low technical risk
34
BOAML 2016 35
Key CRC Fields by Drive Mechanism
Oakridge Wilmington
Montalvo Huntington Beach
Rio Viejo San Miguelito Asphalto
Pleito Ranch Mt. Poso Railroad Gap
Wheeler Ridge Rincon BV Nose
Saticoy S. Mountain Shale 29R
Oxnard Bardsdale Buena Vista Buena Vista
Midway Sunset Paloma Paloma N. Shafter Rio Vista
McDonald Anticline WSOZ WSOZ Rose Thompkins Hill
McKittrick ESOZ ESOZ Gunslinger Willows
Lost Hills EH Stevens EH Stevens EH Stevens Grimes
Kern Front Kettleman Kettleman Kettleman Kettleman
Steamflood
Primary-
Conventional
Waterflood
Primary-
Unconventional
Primary-Gas
Fields in green have multiple recovery/drive mechanism and a combination of conventional and unconventional drilling targets.
BOAML 2016
San Joaquin Basin
• Oil and gas discovered in the late 1800s
• Accounts for ~69% of CRC production
• ~25 billion barrels OOIP in CRC fields1
• Cretaceous to Pleistocene sedimentary section
(>25,000 feet)
• Source rocks are organic rich shales from Moreno,
Kreyenhagen, Tumey, and Monterey Formations
• Thermal techniques applied since 1960s
• 3Q YTD 2016 average net production of 98 MBoe/d
(59% oil)
• Elk Hills is the flagship asset (~58% of CRC San
Joaquin production)
• Two core steamfloods - Kern Front and Lost Hills
• Early stage waterfloods at Buena Vista and Mount
Poso
Overview
Key Assets
Basin Map
-Legend-
Oxy Land
Oil Fields
Gas Fields
Buena Vista
Pleito Ranch
Elk Hills
Kettleman
Lost Hills
Mt Poso
CRC Land
Kern Front
1 Information based on CRC internal estimates; includes shales which are not considered in most older, publicly available estimates.
36
BOAML 2016
0
20
40
60
80
100
120
140
1998 2000 2002 2004 2006 2008 2010 2012 2014
N
et
MB
o
e/
d
• CRC’s flagship asset, a 100 year-old field with
exploration opportunities
• Large fee property with multiple stacked reservoirs
• Light oil from conventional and unconventional
production
• Largest gas and NGL producing field in CA, one of the
largest fields in the continental U.S.1, >3,000
producing wells
• 7.8 billion barrels OOIP2 and cumulative production
of over 2.5 billion Boe
• 3Q YTD 2016 avg. net production of 56 MBoe/d
(40% of total production)
• 540 MMcf/d processing capacity through 3 gas plants
(including California’s largest)
• 2 CO2 removal plants
• Over 4,200 miles of gathering lines
• 45 MW cogeneration plant
• 550 MW power plant
Overview
Comprehensive Infrastructure
Field Map
Production History
1 DOGGR data and U.S. Energy Information Administration.
Elk Hills
Buena
Vista
RR Gap
Elk Hills Area - Overview
2 Information based on CRC internal estimates; includes shales which are not considered in most older, publicly available estimates.
37
BOAML 2016
Los Angeles Basin
• Large, world-class basin with thick deposits
• Kitchen is the entire basin, hydrocarbons did not
migrate laterally; basin depth (>30,000 ft)
• ~10 billion barrels OOIP in CRC fields1
• Most significant discoveries date to the 1920s – past
exploration focused on seeps & surface expressions
• Very few deep wells (> 10,000 ft) ever drilled
• Focus on urban, mature waterfloods, with generally
low technical risk and proven repeatable technology
across huge OOIP fields
• 3Q YTD 2016 average net production of 31 MBoe/d
(98% oil)
• Over 20,000 net acres
• Major properties are world class coastal developments
of Wilmington and Huntington Beach
Overview
Key Assets
Basin Map
38
1 Information based on CRC internal estimates; includes shales which are not considered in most older, publicly available estimates.
BOAML 2016
-
50
100
150
200
250
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
M
M
B
o
e
Net Proved Reserves Production to Date
Overview Field Map
Proved Reserves & Cumulative Production Structure Map & Acquisition History
*
• CRC’s flagship coastal asset: acquired in 2000
• Field discovered in 1932; 3rd largest field in the U.S.
• Over 7 billion barrels OOIP (34% recovered to date)1
• Depths 2,000’ – 10,000’ (TVDSS)
• 3Q YTD 2016 avg. production of 33 MBoe/d (gross)
• Over 8,000 wells drilled to date
• PSC (Working Interest and NRI vary by contract)
• CRC partnering with State and City of Long Beach
*Proved reserves prior to 2009 represent previously effective SEC methodology. Proved reserves for 2009 – 2015 are based on current SEC reserve methodology and SEC pricing.
1 Information based on CRC internal estimates; includes shales which are not considered in most older, publicly available estimates.
Tidelands
Acquired: 2006
Belmont Offshore
Acquired: 2003
Long Beach Unit
Acquired: 2000
Pico Properties
Acquired: 2008
Wilmington Field - Overview
39
BOAML 2016
Ventura Basin
• Estimated ~3.5 billion barrels OOIP in CRC
fields1
• Operate 29 fields (about 40% of basin)
• ~300,000 net acres
• Multiple source rocks: Miocene (Monterey and
Rincon Formations), Eocene (Anita and Cozy
Dell Formations)
• 3Q YTD 2016 average net production of 7 MBoe/d
(69% oil)
• In 2013, shot 10 mi2 of 3D Seismic
> First 3D seismic acquired by any company in
the basin
Overview
Key Assets
Basin Map
• CRC has four early stage waterfloods
• Ventura Avenue Field analog has >30% RF
• CRC fields have 3.5 Bn Boe in place at 14% RF
Waterflood Potential2
1 Information based on CRC internal estimates; includes shales which are not considered in most older, publicly available estimates
2 Source: USGS
40
BOAML 2016
Sacramento Basin
• 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 is less than 10,000 feet
• 3D seismic surveys in mid 1990s helped define
trapping mechanisms and reservoir geometries
• CRC has 53 active fields (consolidated into 35
operating areas where we have facilities)
• 3Q YTD 2016 average net production of 6
MBoe/d (100% dry gas)
• Produce 85% of basin gas with synergies of scale
• Price and volume opportunity
Overview
Key Assets
Basin Map
41
Shale Geological Overview
Major U.S. Shale Plays
Play
Thickness
(feet)
Porosity
(%)
Permeability
(mD)
TOC
(%)
Maturity
(%Ro)
P
(PSI/Ft)
Monterey 200 – 3,500 5 - 30 0.0001 - 1.0 1 – 12 0.7 – 1.0 0.5 – 0.8
Kreyenhagen 250 – 1,000 5 - 12 0.001 – 0.1 2 – 18 0.7 – 1.2 0.5 – 0.8
Moreno 200 – 500 5 - 12 0.001 – 0.1 1 – 6 0.7 – 1.3 0.5 – 0.8
Bakken 6 – 145 2 - 12 0.01 – 1.0 8 – 21 0.8 – 1.0 0.5 – 0.8
Barnett 100 – 500 4 – 9 0.0001 – 0.1 4 – 8 0.8 – 2.0 0.5 – 0.6
Eagle Ford 100 – 250 3 – 14 0.001 – 0.1 2 - 9 1.0 – 1.4 0.4 – 0.6
California Unconventional Potential
0 GR 150 0 GR 150 0 GR 150 0 GR 150 0 GR 150
0 GR 150
3,000
2,000
1,000
Kreyenhagen
Productive interval Target interval
Moreno Bakken Barnett Eagle Ford
N
A
B
C
D
PG
• Successful in upper Monterey using precise development approach
• Expanding efforts into lower Monterey and other shales
Play
Depth
(ft)
Thickness
(gross ft)
Porosity
(%)
Permeability
(mD)
Total
Organic
Carbon
(%)
Upper Monterey(1) 3,500' – 12,000' 250' – 3,500' 5 – 30 <0.0001 – 2 1 – 12
Lower Monterey(1) 9,000' – 16,000' 200' – 500' 5 – 12 <0.001 – 0.05 2 – 18
Kreyenhagen(1) 8,000' – 16,000' 200' – 350' 5 – 15 <0.001 – 0.1 1 – 6
Moreno(1) 8,000' – 16,000' 200' – 300' 5 – 10 <0.001 – 0.1 2 – 6
Bakken 3,000' – 11,000' 6' – 145' 2 – 12 0.05 8 – 21
Barnett 5,400' – 9,500' 100' – 500' 4.0 – 9.6 <0.0001 – 0.1 4 – 8
Eagle Ford 5,000' – 12,000' 100' – 250' 3.4 – 14.6 0.13 2 – 9
CRC Current Production CRC Areas of Future Development
1Reservoir characteristics were internally generated based on regional 2D seismic data, 3D seismic data, open hole and mud log data, cores and other reservoir engineering data.
BOAML 2016
Recovery Factors for Discovered Fields¹
9
40
0
5
10
15
20
25
30
35
40
45
Cum
Recovered
to Date
Remaining 3P
+ Contingent
RF + 10% RF + 15% RF + 20% Original in
Place
Billion Boe
1 Does not include undiscovered unconventional resource potential.
• In place volumes of ~40 billion Boe at
low recovery factor (22%) to date
• Conventional “value chain” approach
to life of field development
• Unconventional success with attractive
upside positioning
• Untapped opportunities to apply
technology advances to California
• Good return projects that can
withstand a variety of price
environments
Large in Place Volumes with Significant Upside for CRC
43
BOAML 2016
A Net Water Supplier
• CRC’s delivery of reclaimed produced water to agriculture in 2015
exceeded the amount of fresh water we purchased by nearly
1 billion gallons
• We expedited the North Kern Drought Relief project in 2015,
achieving a 30% increase in our water supply to agriculture
• We recycled approximately 77% of our produced water in improved
or enhanced recovery operations in 2015
• We reduced our purchased fresh water volume by over 11% in 2015
94%
3% 3% WATER MANAGED IN
CRC’s OPERATIONS
Produced Water
Fresh Water
Non-Fresh Water
In 2015, CRC’s steamflood operations
supplied more than 2.6 billion gallons – over
8,100 acre-feet – of water for irrigation
This preserves fresh water for other
beneficial uses, equivalent to the needs of
approximately 17,800 families per year
44
CRC’s operations in
Long Beach use
recycled water for
99.5% of their total
water use
BOAML 2016
Diverse Resource Base
• Interests in 4 of the 12 largest fields in the
lower 48 states
• 644 MMBoe proved reserves (12/31/2015)
• Largest producer in California on a gross
operated basis with significant exploration
and development potential
California Heritage
• Strong track record of operations since
1950s
• Longstanding community and state
relationships
• Actively involved in communities with CRC
operations
Management Expertise
• Operations exclusively in California
• Assembled largest privately-held land
position in California
• Operator of choice in sensitive
environments
Portfolio of Lower-Risk, Lower-
Decline Opportunities
• Oil-weighted reserves
• Broad exploration and development
inventory
Shareholder Value Focus
• Internally funded capital investment
program
• Optimized capital allocation
45
BOAML 2016
End Notes:
46
1 Reflects CRC estimate of reserves value as of August 23, 2016 applying a 15% tax rate. Includes $125 MM of annual,
non-field level G&A.
2 Reflects the value of facilities and midstream assets at 50% of estimated replacement value. This discount is estimated
to exceed the burden on reserves that would be incurred if assets were monetized.
3 Surface & Minerals reflect the estimated value of undeveloped surface and fee interests.
4 Unproved inventory comprises risked probable and possible reserves and may include contingent and prospective
resources. Contingent and prospective resources consist of volumes identified through life-of-field planning efforts to
date.
5 Calculated using September 30, 2016 debt at par and market cap as of October 31, 2016.
BOAML 2016
Non-GAAP Reconciliation for Adjusted EBITDAX
47
Third Quarter Nine Months
($ in millions) 2016 2015 2016 2015
Net Income (loss) $546 ($104) $356 ($272)
Interest and debt expense 95 82 243 244
Income tax benefit - (50) (78) (165)
Depreciation, depletion and amortization 137 253 422 757
Exploration expense 3 5 13 29
Adjusted income items before interest and taxes (a) (629) 12 (548) 45
Other non-cash items 12 14 40 42
Adjusted EBITDAX $164 $212 $448 $680
Net cash provided by operating activities $101 $180 $145 $412
Cash interest 64 99 244 248
Exploration expenditures 3 3 13 20
Other changes in operating assets and liabilities (9) (73) 32 (6)
Plant turnaround, outage and other costs 5 3 14 6
Adjusted EBITDAX $164 $212 $448 $680
(a) See slide 48 for a table reconciling net income (loss) to adjusted net income (loss).
BOAML 2016
Non-GAAP Reconciliation for Adjusted Net Loss and
Adjusted EPS
48
Third Quarter Nine Months
($ in millions) 2016 2015 2016 2015
Net Income (loss) $546 ($104) $356 ($272)
Non-cash, unusual and infrequent items
Non-cash derivative losses (gains) 25 (53) 243 (33)
Severance and early retirement costs 1 62 19 72
Plant turnaround, outage and other costs 5 3 14 6
Net gain on early extinguishment of debt (660) - (793) -
Gain from asset divestitures - - (31) -
Adjusted income items before interest and taxes (629) 12 (548) 45
Deferred debt issuance costs write-off 12 - 12 -
Valuation allowance for deferred tax assets (a) - - (63) -
Tax effects of these items - 6 - (7)
Total (617) 18 (599) 38
Adjusted net loss ($71) ($86) ($243) ($234)
Net income (loss) per diluted share $13.06 ($2.72) $8.79 ($7.10)
Adjusted net loss per diluted share ($1.75) ($2.25) ($6.12) ($6.11)
Weighted average diluted shares outstanding 41.8 38.3 40.5 38.3
(a) Amount represents the out-of-period portion of the valuation allowance reversal.
BOAML 2016
Non-GAAP Reconciliation for PV-10
($ in millions)
At December
31, 2015
PV-10 of Proved Reserves $5,059
Present value of future income taxes discounted at
10%
(1,035)
Standardized Measure of Discounted Future Net
Cash Flows
$4,024
PV-10 is a non-GAAP financial measure and represents the year-end present value of estimated future cash inflows from proved oil and
natural gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash
flows and using SEC prescribed pricing assumptions for the period. PV-10 differs from Standardized Measure because Standardized
Measure includes the effects of future income taxes on future net cash flows. Neither PV-10 nor Standardized Measure should be construed
as the fair value of our oil and natural gas reserves. PV-10 and Standardized Measure are used by the industry and by our management as an
asset value measure to compare against our past reserves bases and the reserves bases of other business entities because the pricing, cost
environment and discount assumptions are prescribed by the SEC and are comparable. PV-10 further facilitates the comparisons to other
companies as it is not dependent on the tax paying status of the entity.
49