First Quarter 2016

Earnings ReviewTodd Stevens| President & CEO| Los Angeles, CA| May 5, 2016

Mark Smith | Sr. EVP & CFO

1Q16 Earnings

Forward-Looking / Cautionary StatementsThis 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 workoverprogram, production, projected costs, future operations, hedging activities, future transactions, planned capital investments and other guidance. 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: 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; faster 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 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 10Qs 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 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 adjusted EBITDAX, adjusted EPS and PV-10 to the nearest comparable measure in accordance with GAAP, please see the Appendix.

2

1Q16 Earnings

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 program

Shareholder Value Focus

• Internally funded capital investment program

• Optimized capital allocation

3

1Q16 Earnings

Management Priorities and Response

1. Address Balance Sheet

2. Adjust Activity Levels for Current

Environment

• Live within means and align

capital investments with

projected cash flow

3. Focus on base production and

protect our margins

4. Right-size costs for the current

operating environment

Reduced outstanding debt with free cash

flow and through open market repurchases

No change to borrowing base in the spring

redetermination

Generated free cash flow after working

capital of $87 million

Production exceeded the midpoint of

guidance at 148 Mboe/d and was

accomplished with no drilling capital

Delivered the same amount of operating

cash flow after working capital in 1Q16

versus 1Q15 despite a 36% lower average

crude oil price

Focused on costs: Achieved 24% reduction

in production costs year-over-year

Successfully concluded the Elk Hills power

plant turnaround on budget and ahead of

schedule

Priorities Execution

4

1Q16 Earnings

Living Within Cash Flow

-$5

$5

$15

$25

$35

$45

$55

$65

$75

-25

25

75

125

175

225

275

1Q15 2Q15* 3Q15 4Q15* 1Q16

Bre

nt

Pri

ce

$ M

M

Adj. EBITDAX** Operating Cash Flow Capital Investment Brent Price

* Operating cash flow includes a semi-annual cash property tax payment** See Appendix for reconciliations to GAAP

5

1Q16 Earnings

• We have assessed various deleveraging alternatives and are

taking strategic steps to delever the balance sheet

Deleveraging Options

UPSTREAM

• JV

• M&A

MIDSTREAM

• MLP

• Drop into Existing MLP

• Sale

• Triple Net Lease

CAPITAL MARKETS

• Debt Exchange

• Open market bond

repurchases

AVAILABLE ASSETS

• 14 Gas Plants with 650 MMcfd Capacity

• Elk Hills has largest Gas Plant Complex in CA

• 300 Compressors / Stations with 395,000 HP

of Compression

• 600 MW Electrical Generation with 700 miles

of High Voltage Transmission Lines

• 305 Tank Settings / LACT / Sales Facilities

• 74 Water Plants / Treatment Facilities

• 50 Steam Generators with 220,000 Bbl Steam

Capacity

• ~20,000 Miles of Pipelines

AVAILABLE ASSETS

• 2.4 Million Acres

• ~60% of Land held in Fee

• Large Economic Development

Project Inventory

• Seismic

• Robust Exploration Portfolio

TRANSACTION

• Exchange offer for Unsecured

Notes reduced debt by $563

million

• Repurchased ~$135mm in

principal amount of unsecured

bonds for $25mm in 4Q15 and

1Q16

6

1Q16 Earnings

Capital Allocation Approach

• Portfolio Management since spin-off

• Three principal drivers:

o Maximize long-term value – VCI > 1.3

o Oil production growth

o Financial discipline – self-funding business

• Results in combination of projects that provide quick payback (workovers) and

longer term value / future growth (steamfloods/waterfloods).

PV10 pre-tax cash flows

PV10 of investmentsVCI =

Value Creation Index

Measures value created per dollar investment (“Bang for the buck”)

7

1Q16 Earnings

Strong Execution Track Record

130

135

140

145

150

155

160

165

170

1Q15 2Q15 3Q15 4Q15 1Q16

Mb

oe

/d

Total ProductionGuidance vs. Actual

Production Guidance Range Actual

0

40

80

120

160

1Q15 2Q15 3Q15 4Q15 1Q16

$M

M

Capital InvestmentGuidance vs. Actual

Capital Investment Guidance Range Capex Actual

Production will drop with natural decline; capital focused on mechanical integrity and safety

8

1Q16 Earnings

$-

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

$14.00

$16.00

$18.00

1Q 15 2Q 15 3Q 15 4Q 15 1Q 16

Pro

du

ctio

n C

ost

s ($

/Bo

e)

Steam Injectant Gas Plant Expense

Energy Supports and Other

Downhole Maintenance Workovers/Well Enhancement

Surface Operations and Maintenance Pipeline/Transportation/Terminals

9

Defending Margins By Managing Costs

~15%

Decrease

1Q16 Earnings

Capitalization as of 3/31/16 ($MM)

$25

$625$392

$805

$2,250

855

$0

$500

$1,000

$1,500

$2,000

$2,500

Jan

-16

Jul-

16

Jan

-17

Jul-

17

Jan

-18

Jul-

18

Jan

-19

Jul-

19

Jan

-20

Jul-

20

Jan

-21

Jul-

21

Jan

-22

Jul-

22

Jan

-23

Jul-

23

Jan

-24

Jul-

24

Term Loan

Debt Maturities ($MM)*

Focus on Balance Sheet

• Deleveraging is a priority

• Utilized free cash flow to execute open

market purchases of bonds and make

payment on term loan

• Borrowing base reconfirmed at $2.3 billion

1 Effective May 2, 2016 the borrowing base under our Credit Facilities was $2.3 billion. As of March 31, we had the ability to incur total borrowings under the RCF of $1.3 billion less outstanding amounts (or approximately ~$578MM).

2 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.

1st Lien Secured RCF1 695

1st Lien Secured Term Loan 975

Senior 2nd Lien Notes 2,250

Senior Unsecured Notes 2,052

Total Debt 5,972

Less cash (10)

Total Net Debt 5,962

Equity (952)

Total Net Capitalization 5,010

Total Net Debt / Net Capitalization 119%

Total Net Debt / LTM Adjusted EBITDAX 7.2x

LTM Adjusted EBITDAX / Interest Expense 2.6x

PV-102 / Total Net Debt 0.8x

Total Net Debt / Proved Reserves ($/Boe) $9.26

Total Net Debt / PD Reserves ($/Boe) $12.40

Total Net Debt / Production ($/Boepd) $40,284

* As of 3/31/16

10

1Q16 Earnings

$94

$55$64

$51

$45

$35

0

10

20

30

40

50

60

70

80

90

100

$0

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

$7,000

10/1/14 3/31/15 6/30/15 9/30/15 12/31/15 3/31/16

Bre

nt

Oil

($/B

bl)

Tota

l Deb

t ($

M)

Total Debt

Long Term Notes Term Loan Revolving Credit Facility Oil Price

CRC Effectively Managing Down Debt

11

Reduced debt approximately $700 million from the high point in 2Q15 through free

cash flow, debt exchanges and open market repurchases of bonds

1Q16 Earnings

Progressing Inventory to VCI Threshold

12

0

1,000

2,000

3,000

4,000

5,000

6,000

$40 $50 $60

Dri

llin

g an

d W

ork

ove

rIn

ven

tory

($

MM

)

Brent Marker Price ($/Bbl)

Economic Project Inventory

VCI 1.3 VCI 1.0

1Q16 Earnings

Capex Reduction

• 2016 Capital Investment Plan to focus on mechanical integrity and safe

operations

• Monitor cash flow throughout the year and retain flexibility to increase

investments in drilling and capital workovers to the extent crude oil prices show

sustained improvement, while abiding by financial covenants

* Full Year 2016 Guidance

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

RIGS 3.3 3 3 2.3 0 0 0 0

Quarterly

Operations

CAPEX,

$mm

FY 2016E2015 Actual

$133 $95 $95 $78 $50*

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1Q16 Earnings

Opportunistically Built Hedge Portfolio*

* As of April 28, 2016

• 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

Q2 2016 Q3 2016 Q4 2016 2017 2018

Calls

Barrels per Day 35,500 4,000 23,000 30,000 23,300

Wtd Avg Ceiling Price per Barrel $66.15 $71.13 $53.67 $55.68 $57.99

Puts

Barrels per Day 55,500 28,000 3,000 - -

Wtd Avg Floor Price per Barrel $50.14 $50.65 $50.00 - -

Swap

Barrels per Day - 1,000 25,000 - -

Wtd Avg Price per Barrel - $61.25 $49.10 - -

14

1Q16 Earnings

$97.97 $93.00

$48.80

$33.45

$104.16

$92.30

$49.19

$36.39

$108.76

$99.51

$53.64

$35.08

$20

$30

$40

$50

$60

$70

$80

$90

$100

$110

$120

2013 2014 2015 1Q16

$/B

bl

WTI Realizations Brent

$3.66

$4.34

$2.75

$2.07

$3.73

$4.39

$2.66

$2.05

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0

2013 2014 2015 1Q16

$/M

cf

NYMEX Realizations

NGL Price Realization - % of WTI

Realization % of WTI

106% 99% 97% 109% Realization % of NYMEX

102% 101 % 97% 99%

Oil Price Realization* Gas Price Realization*

• Oil pricing continued to deteriorate even further in 1Q 2016

• NGL pricing has followed the general energy market lower.

Downside pressure has come from extraction volumes as

gas production throughout the U.S. has continued to

increase

• Natural gas prices continued to decline due to continued

supply growth and lower demand which reflects Aliso

Canyon and mild weather

51% 51%

40%

49%

0%

10%

20%

30%

40%

50%

60%

2013 2014 2015 1Q16

% o

f W

TICRC – Price Realizations

* Reflects realizations with hedges

15

1Q16 Earnings

115 115

-40

-20

0

20

40

60

80

100

120

140

1Q15 Volume Price Costs Interest Working

Capital and

Other

1Q16

$ M

M

Op

era

tin

g C

ash

Flo

wCRC Executing on Controllable Items

16

1Q16 Earnings

Quarterly Cost Comparison

1Q15 4Q15 1Q16

Production costs($/Boe)

$16.20 $15.51 $13.69

Taxes other than on income ($MM)

$55 $30 $39

Exploration expense ($MM)

$17 $7 $5

Interest expense($MM)

$79 $82 $74

17

1Q16 Earnings

Managing Base Production with No Drilling Capital

4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16E FY 2014 FY 2015 FY 2016E

Mb

oe

/d

Production By Stream (MBoe/d)

Oil NGL Gas Guidance

159 Mboe/d

Average Oil

Production

Average Total

Production

160 Mboe/d

99 MBbl/d104 MBbl/d

18

1Q16 Earnings

1Q16 Results Summary Comparison

1Q15 4Q15 1Q16

Adjusted EPS* ($0.25) ($0.20) ($0.26)

Oil Production 108 MBbl/d 102 MBbl/d 98 MBbl/d

Total Production 166 MBoe/d 155 MBoe/d 148 MBoe/d

Realized Oil Price w/ Hedge ($/Bbl) $46.44 $45.88 $36.39

Realized NGL Price ($/Bbl) $21.55 $19.56 $16.39

Realized Natural Gas Price w/ Hedge($/Mcf) $2.84 $2.44 $2.05

Adjusted EBITDAX* $198 mm $226 mm $124 mm

Capital Investments $133 mm $78 mm $21 mm

Cash Flow from Operations $115 mm ($9 mm)** $115 mm

*See Appendix for reconciliations to GAAP**Operating cash flow includes a semi-annual cash property tax payment

19

1Q16 Earnings

2Q16 Guidance

Anticipated Realizations Against the Prevailing Index Prices for 2Q16

Oil 85% to 89% of Brent

NGLs 43% to 47% of Brent

Natural Gas 81% to 85% of NYMEX

Production, Capital and Income Statement Guidance

Production 138 to 143 MBOE per day

Capital $8 to $12 million

Production Costs $15.75 to $16.25 per BOE

G&A $4.15 to $4.45 per BOE

DD&A $11.10 to $11.30 per BOE

Taxes other than on income $38 to $42 million

Exploration expense $4 to $8 million

Interest expense $74 to $78 million

Cash Interest $130 to $134 million

Income tax expense rate 0%

Cash tax rate 0%

20

See Attachment 8 of the 1Q16 earnings press release issued May 5, 2016 for more details.

1Q16 Earnings

NY00813G / 589203_1.WOR

Sacramento Basin

14 MMBoe Proved Reserves

7 MBoe/d production

San Joaquin Basin

451 MMBoe Proved Reserves

110 MBoe/d production

Ventura Basin

47 MMBoe Proved Reserves

9 MBoe/d production

Los Angeles Basin

132 MMBoe Proved Reserves

34 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 Leverage:

High level of operating leverage and 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 FY 2015 rates.

21

1Q16 Earnings

California Resources Corporation

Appendix

22

1Q16 Earnings

Non-GAAP Reconciliation for Adjusted EBITDAXFor the

First QuarterEnded March 31,

($ in millions) 2016 2015

Net loss ($50) ($100)

Interest expense 74 79

Income taxes benefit (78) (69)

Depreciation, depletion and amortization 147 253

Exploration expense 5 17

Adjusted income items 13 5

Other (a) 13 13

Adjusted EBITDAX $124 $198

Net cash provided by operating activities $115 $115

Interest expense 74 79

Exploration expense 5 11

Changes in operating assets and liabilities (98) 1

Non-cash gains/(losses) in income 2 (26)

Adjusted income items 13 5

Other non-cash items 13 13

Adjusted EBITDAX $124 $198

(a) Includes non-cash items

23

1Q16 Earnings

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 andnatural gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cashflows 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 construedas 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 anasset 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.

24

1Q16 Earnings

Non-GAAP Reconciliation for Adjusted EPSFor the

First QuarterEnded March 31,

($ in millions) 2016 2015

Net Loss $(50) $(100)

Non-cash loss on outstanding hedges 81 3

Severance costs and other employee-related costs 14 -

Plant turnaround costs 7 2

Gain on debt repurchases (89) -

Valuation allowance for deferred tax assets (a) (63) -

Tax effects of these items - (2)

Adjusted net loss $(100) $(97)

EPS – diluted $(0.13) ($0.26)

Adjusted EPS – diluted $(0.26) $(0.25)

Weighted average diluted shares outstanding 385.3 382.1

(a) Amount represents the out-of-period portion of the valuation allowance reversal.

25