Second Quarter 2017 Earnings ReviewTodd Stevens | President & CEO | Los Angeles, CA | August 3, 2017
Mark Smith | Sr. EVP & CFO
2Q 2017 Earnings | 2
Forward Looking / Cautionary Statements
This presentation contains forward-looking statements that involve risks and uncertainties that could materially affect our expected results of operations, liquidity, cash flows and
business prospects. Such statements include those regarding our expectations as to our future:
Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. While we believe the
assumptions or bases underlying our expectations are reasonable and make them in good faith, they almost always vary from actual results, sometimes materially. We also believe third-
party statements we cite are accurate but have not independently verified them and do not warrant their accuracy or completeness. Factors (but not necessarily all the factors) that
could cause results to differ include:
Words such as "anticipate," "believe," "continue," "could," "estimate," "expect," "goal," "intend," "likely," "may," "might," "plan," "potential," "project," "seek," "should," "target, "will" or "would"
and similar words that reflect the prospective nature of events or outcomes typically identify forward-looking statements. Any forward-looking statement speaks only as of the date on
which such statement is made and we undertake no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise,
except as required by applicable law.
See www.crc.com Investor Relations for important information about 3P reserves and other hydrocarbon resource quantities, finding and development costs, recycle ratio calculations,
and drilling locations.
• financial position, liquidity, cash flows and results of operations
• business prospects
• transactions and projects
• operating costs
• operations and operational results including production, hedging, capital
investment and expected VCI
• budgets and maintenance capital requirements
• reserves
• type curves
• commodity price changes
• debt limitations on our financial flexibility
• insufficient cash flow to fund planned investment
• inability to enter desirable transactions including asset sales and joint
ventures
• legislative or regulatory changes, including those related to drilling,
completion, well stimulation, operation, maintenance or abandonment of
wells or facilities, managing energy, water, land, greenhouse gases or
other emissions, protection of health, safety and the environment, or
transportation, marketing and sale of our products
• unexpected geologic conditions
• changes in business strategy
• inability to replace reserves
• insufficient capital, including as a result of lender restrictions, unavailability
of capital markets or inability to attract potential investors
• inability to enter efficient hedges
• equipment, service or labor price inflation or unavailability
• availability or timing of, or conditions imposed on, permits and approvals
• lower-than-expected production, reserves or resources from development
projects or acquisitions or higher-than-expected decline rates
• disruptions due to accidents, mechanical failures, transportation
constraints, natural disasters, labor difficulties, cyber attacks or other
catastrophic events
• factors discussed in “Risk Factors” in our Annual Report on Form 10-K
available on our website at crc.com.
2Q 2017 Earnings | 3
1H 2017 Highlights
~4%2H’16 to 1H’17 Decline
131,000 Boe/d
$57 Million
$51 MillionJV Capital Invested
7 RigsExit Rate Shows
Increased Activity
JVs
Free Cash
Flow*
ACTIVITY
PRODUCTION
*See www.crc.com/investor-relations for a reconciliation to the
closest GAAP measure and other important information.
2Q 2017 Earnings | 4
Drilling
$115
JV - Capital
$150
Workover
$55
Development
Facilities
$45
Exploration
$10
Other
$25
1
San
Joaquin
Ventura
Los
Angeles
Moving from Defense to Offense
• CRC 2017 capital plan will be directed to oil-weighted projects in our core fields: Elk Hills,
Wilmington, Kern Front, Buena Vista, Mt. Poso, Pleito Ranch, Wheeler Ridge and the
delineation of Kettleman North Dome
• MIRA and BSP capital will be focused in the San Joaquin Basin
• We have a dynamic plan which can be scaled up or down depending on the price
environment
Capital Investment Program – Living within Cash Flow
Total: $400 million
1Other includes maintenance and occupational health, safety and environmental projects, seismic and other investments.2 Inclusive of BSP and MIRA capital
2017E Total Capital Plan 2017E Drilling Capital2 – By Drive
29%
38%
14%
11%
2%6%
11%
9%
Conventional
Exploration
Waterfloods
Steamfloods
Unconventional
38%
4%28%
20%
80%
The JV capital increases
flexibility in a lower commodity
environment or provides for
incremental deleveraging
Total: Up to $275 million Total: Up to $275 million
10%
2017E Drilling Capital2 – By Basin
2Q 2017 Earnings | 5
Deep Inventory of Actionable Projects at $45 Brent
Steamflood
Waterflood
Primary
Shale
Gas
Portfolio Spectrum
• Growth portfolio focus,
fully burdened
• All projects meet VCI 1.3
threshold at $45 Brent
and $2.50 NYMEX, and
deliver robust cash flow
• Portfolio has large
contributions from all
recovery mechanisms
and reserves types
• Many projects take
advantage of existing
infrastructure, while other
new projects may require
infrastructure investment
in facilities and sales
points
Full cycle costs = operating costs + development costs + facility costs + field-level G&A + taxes other than income
** See www.crc.com, Investor Relations for details regarding net resources.
0
10
20
30
40
0 50 100 150 200 250 300 350 400 450 500
Fu
ll C
ycle
Co
st
($/B
oe
)
Net Resources (MMBoe)
2Q 2017 Earnings | 6
70
80
90
100
110
120
2017E 2018E 2019E 2020E 2021E
Oil P
rod
ucti
on
MB
/d
0
300
600
900
1,200
2017 2018 2019 2020 2021
Ca
pit
al ($
MM
)
400
600
800
1,000
1,200
1,400
2017E 2018E 2019E 2020E 2021E
$M
M
Portfolio Flexibility Provides Range of Crude Oil Scenarios
Note: The high case assumes $45 Brent for remainder of 2017 and $55 Brent and $3.50 NYMEX gas price thereafter. The low case assumes $45 Brent for remainder of 2017 and $50 Brent and $3.50 NYMEX gas price thereafter. Assumes lease operating costs are equal to 2016 levels for the mid-point of the range of planning scenario outcomes. Ranges of portfolio planning scenario outcomes assume development of a variety of combinations of steamflood, waterflood, conventional and unconventional projects in our inventory and reflect estimates of geologic, development and permitting risk. All discretionary cash flow reinvested in business for each outcome and include the effects of BSP and MIRA capital. See www.crc.com/investor-relations for a reconciliation to the closest GAAP measure of debt-adjusted per share basis.
At about current commodity prices, we are
positioned for growth in:
• Cash flow
• Production
• Reserves
on a debt-adjusted per share basis
Portfolio
Planning
Scenarios
Portfolio
Planning
Scenarios
-
Capital focused on oil projects that provide
Increasing
Margins
Low
Decline Rates
Compounding
Cash Flow+ =
-
-
Estimated Crude Oil Production Outcomes
Estimated Range of EBITDAX Outcomes
Estimated Capital Invested
≈
≈
2Q 2017 Earnings | 7
Resilient Resource Base – Inflection Point
0
25
50
75
100
125
150
175
200
0
20
40
60
80
100
120
140
160
180
1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17E
Ca
pit
al ($
MM
)
MB
oe
/d
)
Oil NGL Gas Capital
Production By Stream (Mboe/d)
Note: Due to consolidated financials, capital and production for 2017 includes BSP’s investment
2Q 2017 Earnings | 8
Responsible Growth: Living within Cash Flow
0
100
200
300
400
500
1H15 2H15 1H16 2H16 1H17
$ M
M
Adj. EBITDAX* Operating Cash Flow Organic Capital Investment**
* See www.crc.com, Investor Relations for a reconciliation to the closest GAAP measure and other important information.
** Does not include JV capital
2Q 2017 Earnings | 9
$2.75
$2.42
$3.26 $3.14
$2.66
$2.28
$2.90
$2.47
0.00
0.50
1.00
1.50
2.00
2.50
3.00
3.50
2015 2016 1Q 2017 2Q 2017
$/
Mc
f
NYMEX Realizations
CRC – Price Realizations
40%
52%
66%
62%
0%
10%
20%
30%
40%
50%
60%
70%
2015 2016 1Q 2017 2Q 2017
% o
f W
TI
$48.80
$43.32
$51.91 $48.29 $49.19
$42.01
$50.24 $47.98
$53.64
$45.04
$54.66
$50.92
30
40
50
60
2015 2016 1Q 2017 2Q 2017
$/B
bl
WTI Realizations Brent
Realization
% of Brent92% 93% 92% 94%
Realization
% of NYMEX97 % 94% 89% 79%
Oil Price Realization (with Hedges) Gas Price Realization
NGL Price Realization - % of WTI
CRC sees near term
tightening to benchmarks
• California refinery demand for native California crude continues to
be strong with realizations, including hedges, averaging 94% of
Brent and 99% of WTI.
• NGL prices have also remained strong. This increase was driven
by tighter domestic supplies, strong exports and higher contract
prices on natural gasoline.
-≈
2Q 2017 Earnings | 10
Defending Cash Margins
$-
$4.00
$8.00
$12.00
$16.00
$20.00
1H 15 2H 15 1H 16 2H 16 1H 17
$/B
oe
Operating Cash Margin = Oil and Gas Revenue including settled hedges – Production Costs (Lease Operating Expenses) – Taxes Other than Income – Operating Overhead
2Q 2017 Earnings | 11
CRC Pivots to Increased Activity & Higher Cash Flows
44
120
-100
-50
0
50
100
150
200
1H16 Volume Price Costs Interest
Working
Capital and
Other 1H17
$ M
M
Op
era
tin
g C
ash
Flo
w
2Q 2017 Earnings | 12
Strengthening the Balance Sheet
$25
$359
$165 $135
$1,000
$2,250
$193
$842
$0
$500
$1,000
$1,500
$2,000
$2,500
Jan
-16
Ma
y-1
6
Se
p-1
6
Jan
-17
Ma
y-1
7
Se
p-1
7
Jan
-18
Ma
y-1
8
Se
p-1
8
Jan
-19
Ma
y-1
9
Se
p-1
9
Jan
-20
Ma
y-2
0
Se
p-2
0
Jan
-21
Ma
y-2
1
Se
p-2
1
Jan
-22
Ma
y-2
2
Se
p-2
2
Jan
-23
Ma
y-2
3
Se
p-2
3
Jan
-24
Ma
y-2
4
Se
p-2
4
RCF
Senior Notes
Term Loan
• Deleveraging remains a priority; ~$1.6 billion decrease to date
from post-spin peak
• Going forward, we are focused on opportunistic deleveraging
• Reduced debt by $100 million in 1H 2017
• Borrowing base was reaffirmed at $2.3 billion in May 2017
1st Lien Secured RCF1
(1LFO) 842
1st Lien Secured Term Loan (1LFO) 584
1st Lien Second Out Term Loan (1LSO) 1,000
Senior 2nd Lien Notes 2,250
Senior Unsecured Notes 493
Total Debt 5,169
Less cash (9)
Total Net Debt 5,160
Equity (491)
Total Net Capitalization 4,669
Total Net Debt / Total Net Capitalization 111%
Total Net Debt / LTM Adjusted EBITDAX2
7.5x
LTM Adjusted EBITDAX2 / LTM Interest Expense 2.0x
PV-103 / Total Net Debt 0.5x
Total Net Debt / Proved Reserves4 ($/Boe) $9.08
Total Net Debt / PD Reserves4 ($/Boe) $12.71
Total Net Debt / Production5 ($/Boepd) $40,000
*The 1LFO and 1LSO have springing maturities which are detailed in our 10-K.
Capitalization as of 6/30/17 ($MM)
Debt Maturities ($MM)*
1 As of June 30th, 2017, we had approximately $437 MM of available borrowing capacity under our
revolving credit facility subject to maintaining a minimum liquidity of $250MM, this facility matures in
November 2019.2 See www.crc.com, Investor Relations for a reconciliation to the closest GAAP measure and other
important information. 3 PV-10 as of 12/31/16, see www.crc.com, Investor Relations for details on this calculation.4 Reserves as of 12/31/16.5 Average production for Q2 2017.
2Q 2017 Earnings | 13
Reserves Value1 In Excess of EV
PDP Value
Proved Value
Unproved4
$0
$4
$8
$12
$16
$20
$50 Brent $55 Brent $60 Brent
($B
illio
n)
Current EV
of $5.5 Bn5
Infrastructure3
Surface & Minerals2
1-5 See endnotes in the Appendix.
2Q 2017 Earnings | 14
Calls 3Q 2017 4Q 2017 1Q 2018 2Q 2018 3Q 2018 4Q 2018
Barrels per Day 6,100 6,300 16,800 16,200 16,100 16,100
Weighted Average Ceiling
Price per Barrel$57.73 $57.80 $58.86 $58.92 $58.91 $58.91
Purchased Puts
Barrels per Day 18,100 11,300 1,200 1,200 1,100 1,100
Weighted Average
Floor Price per Barrel$50.63 $47.75 $45.82 $45.83 $45.85 $45.85
Sold Puts
Barrels per Day - - 29,000 29,000 4,000 4,000
Weighted Average
Floor Price per Barrel$ - $ - $45.00 $45.00 $45.00 $45.00
Swaps
Barrels per Day 25,000 25,0002 29,0003 29,0003 4,0004 4,0004
Weighted Average
Price per Barrel$54.99 $54.99 $60.00 $60.00 $60.00 $60.00
Percentage of 2Q 2017
Oil Production Hedged52% 44% 37% 37%
Opportunistically Built Oil Hedge Portfolio1
1 – Prices are based on Brent. Positions as of July 31, 2017.2 – Includes an option for counterparties to increase volumes by up to 10,000 barrels per day at a weighted-average Brent price of $55.46.3 – Includes an option for counterparties to further increase swap volumes for the first half of 2018 by up to 10,000 barrels per day at a weighted-average Brent price of $60.00 and
quarterly options for counterparties to further increase swap volumes for the first half of 2018 by up to 19,000 barrels at a weighted-average Brent price of $60.00.4 – Includes quarterly options for counterparties to further increase swap volumes for the second half of 2018 by up to 4,000 barrels at a weighted-average Brent price of $60.00
We target hedges on 50% of
crude oil production to
protect cash flow
2Q 2017 Earnings | 15
Quarterly & Six Month Cost Comparison
2Q16 1Q17 2Q17 1H16 1H17
Productioncosts ($/Boe)
$14.76 $17.70 $18.34 $14.21 $18.02
Taxes other than on income ($MM)
$42 $33 $31 $81 $64
Exploration expense ($MM)
$5 $6 $6 $10 $12
Interest expense($MM)
$74 $84 $83 $148 $167
2Q 2017 Earnings | 16
2Q17 Results Summary Comparison
2Q16 1Q17 2Q17
Earnings (Loss) per Share – Diluted ($3.51) $1.22 ($1.13)
Adjusted Earnings (Loss) per Share* ($1.80) ($1.02) ($1.83)
Oil Production 90 MBbl/d 86 MBbl/d 83 MBbl/d
Total Production 140 MBoe/d 132 MBoe/d 129 MBoe/d
Realized Oil Price w/ Hedge ($/Bbl) $43.70 $50.24 $47.98
Realized NGL Price ($/Bbl) $22.54 $34.33 $30.08
Realized Natural Gas Price ($/Mcf) $1.66 $2.90 $2.47
Net Income (Loss) Attributable to Common Stock ($140) MM $53 MM ($48) MM
Adjusted EBITDAX* $160 MM $200 MM $158 MM
Capital Investments $5 MM $50 MM $82 MM
Cash Flow from Operations** ($71) MM $133 MM ($13) MM
*See www.crc.com, Investor Relations for a reconciliation to the closest GAAP measure and other important information.
**Operating cash flow includes semi-annual interest and property tax payments.
2Q 2017 Earnings | 17
3Q17 Guidance
Anticipated Realizations Against the Prevailing Index Prices for 3Q17
Oil 90% to 94% of Brent
NGLs 58% to 62% of Brent
Natural Gas 84% to 88% of NYMEX
Production, Capital and Income Statement Guidance
Production 127 to 132 Mboe/d
Capital $115 to $135 million
Production Costs $18.35 to $18.85 per Boe
Adjusted G&A $5.30 to $5.60 per Boe
DD&A $11.50 to $11.80 per Boe
Taxes other than on income $36 to $40 million
Exploration expense $3 to $7 million
Interest expense $83 to $87 million
Cash Interest $55 to $59 million
Income tax expense rate 0%
Cash tax rate 0%
2Q 2017 Earnings | 18
History of Proactive Strategic Decisions
Swift, decisive actions have positioned the company for growth through the commodity downturn. Proactive
discussions with lenders and solid asset base provide line of sight to a recovery and an actionable inventory.
0
5
10
15
20
25
30
0
20
40
60
80
100
120
07/06/14 10/06/14 01/06/15 04/06/15 07/06/15 10/06/15 01/06/16 04/06/16 07/06/16 10/06/16 01/06/17 04/06/17 07/06/17 10/06/17
CR
C D
rillin
g R
ig C
ou
nt
Bre
nt
Cru
de
Oil P
rice
($
/B
bl)
Oil Price
CRC Rig Count
1. Cut rig count/began hedging 4. Deleveraging Transactions
2. Cut 2015 Capital Budget 5. Increasing activity, invest within Cash Flow
3. Bank Amendments 6. JV Transactions
2
1
5
3Under
OXY
6
SPIN-OFF
3
333
3
4
44
4
6
E
2Q 2017 Earnings | 19
The Case for CRC: Investment Thesis Overview
Operational
flexibility
Grow within
cash flow
Industry leading
decline rate
Integrated and
complementary
infrastructure
Maintain
Production
Production and
Cash Flow Growth
Production Innovation Deep Inventory
Investment Case for CRC
World-class assets with
significant inventory
Resilient model that
preserves optionality
and protects downside
Focused on value
and poised for growth
Positioned to go from defense to offense
Why Own CRC Now
Competitive Advantages
Disciplined portfolio management Potential for EBITDAX growth
0
500
1,000
1,500
2017E 2018E 2019E 2020E 2021E
$M
M
Appendix
2Q 2017 Earnings | 21
Significant Debt Reduction from Post-Spin Peak
6,7651
5,169
4,000
5,000
6,000
7,000
2Q15 Debt Exchange for 2L Open Market
Repurchases
Equity for Debt
Exchange
Cash Tender
for Unsecureds
Cash Flow 2Q17
Tota
l D
eb
t ($
MM
)
2
Cumulative Debt Reduction Total
Total Net Principal Reduction$535
million
$144
million
$102
million
$625
million
$190
Million$1,596 million
Annual Income Statement Effect
(Annualized Interest)
$22
million
($7)
Million
($6)
Million
$27
million
~($5)
Million
~$31
million
1 Represents mid-second quarter 2015 peak debt.2 Includes operating cash flow, as well as positive working capital and proceeds from asset sales in the first half of 2017.
-
Chose options to maximize deleveraging and minimize recurring cost to the income statement on a per share basis
Continue to seek opportunistic transactions that reduce overall debt
2Q 2017 Earnings | 22
Inventory of Actionable Projects Expands by >200MMBoe at $55 Brent
Steamflood
Waterflood
Primary
Shale
Gas
Portfolio Spectrum
• Growth portfolio focus,
fully burdened
• All projects meet VCI 1.3
threshold at $55 Brent
and $3.50 NYMEX, and
deliver robust cash flow
• Portfolio has large
contributions from all
recovery mechanisms
and reserves types
• Many projects take
advantage of existing
infrastructure, while other
new projects may require
infrastructure investment
in facilities and sales
points
Full cycle costs = operating costs + development costs + facility costs + field-level G&A + production taxes
** See www.crc.com, Investor Relations for details regarding net resources.
0
10
20
30
40
0 50 100 150 200 250 300 350 400 450 500 550 600 650 700
Fu
ll C
ycle
Co
st
($/B
oe
)
Net Resources (MMBoe)
2Q 2017 Earnings | 23
JVs Validate Inventory and Enhance Value
>$250 MillionAlready Committed
~3.5-4.0 MBoe/dGross Peak Production per
$100 MM of development capital
PRODUCTION
>12 MMBoePotential Targeted Reserves per
$100 MM of development capital
INVESTMENTS
RESERVES
SIGNED TWO
JVs
JVs are currently focused in the San Joaquin Basin
$550 MillionTotal Potential JV Capital
Kern Front
-Legend-
Oxy Land
Oil Fields
Gas Fields
Buena Vista
Pleito Ranch
Elk Hills
Kettleman North Dome
Lost Hills
Mt Poso
CRC Land
Portfolio Flexibility
and Optionality
Enables High
Margin Production
Growth
Accelerate Value
Derisk Inventory
2Q 2017 Earnings | 24
Accelerating Value and Derisking Inventory through JVs
Highlights:
• Up to $300MM
― Initial commitment of $160MM
• DrillCo type structure where Investor funds
100% of project capital for 90% WI, with
CRC carried on its 10% WI
― CRC interest reverts to 75% after
target IRR is achieved
― CRC retains early termination options
• Focus on four fields within the San Joaquin
Basin
― Kern Front, Mt. Poso, Pleito Ranch,
Wheeler Ridge
• CRC operates all wells
Highlights:
• Up to $250MM over ~2 years
― Initial tranche of $50MM
funded
• Investor funds 100% of project
capital in exchange for a net profits
interest (NPI)
― Investor NPI interest reverts to
CRC after low teens target IRR
― CRC retains early termination
options
• Current focus is in the San Joaquin
Basin
• CRC operates all wells
2Q 2017 Earnings | 25
-
1,000.00
2,000.00
3,000.00
4,000.00
5,000.00
6,000.00
7,000.00
1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46 49 52 55 58 61 64 67 70 73 76 79 82 85 88 91 94 97 100103106109112115118JV Share Typical E&P Share
Typical Industry JV Structure
• Based on recent industry JV deals, a typical deal structure is
– Partner pays 80-100% Capital
– Receives 80-100% Working Interest
– Typical hurdle rate:– 10% - 20% IRR
– Partner’s working interest once hurdle rate is achieved:
– 5% - 25%
Hurdle Rate
Reached
Pro
du
cti
on
Time
2Q 2017 Earnings | 26
Life of Field Plans – Growing Inventory
• Comprehensive technical review of 40% of CRC’s fields
• Updated Geologic models, OOIP
• Teams shared analog experience across CRC
• Cataloged opportunities consistent with our proven reserves methodology
• Rolled into our portfolio ranking process Base Production
AdditionalRecovery
New Pools
3P Resource Growth
110
768 568
251
321
826
0
250
500
750
1,000
1,250
1,500
1,750
2,000
Spin-off 2016
MM
Bo
e
Produced Proven Price Affected Reserves Unproven
>250%
Growth
2Q 2017 Earnings | 27
End Notes
1 Current CRC estimate of reserves value as of December 31, 2016. Includes field-level operating expenses and G&A. Assumes
$3.30/Mcf NYMEX.
2 Surface & Minerals reflect the estimated value of undeveloped surface and fee interests.
3Reflects the value of facilities and midstream assets at 50% of estimated replacement value. This discount is estimated to exceed
the burden on reserves that would be incurred if assets were monetized.
4 Unproved inventory comprises risked probable and possible reserves and contingent and prospective resources. Contingent and
prospective resources consist of volumes identified through life-of-field planning efforts to date.
5 Calculated using June 30, 2017 debt at par and market cap as of June 30, 2017.
Type Curve Note: Each field-specific type well curve represents an average of the historical results of multiple projects over the prior
four-year time period. Drive mechanism type curves are the weighted average of the field-specific curves related to the projects
chosen for our near-term growth plan. Type curves represent management’s estimates of future results and are subject to project
selection and other variables. Our type well curves are prepared for purposes of modeling overall results of our near-term growth
program and are not useful for benchmarking any individual well or pattern performance. Actual results are expected to vary
depending on which projects are specifically developed.