Fourth Quarter and Year End

2015 Earnings Review

Todd Stevens| President & CEO| Los Angeles, CA| February 29, 2016

Mark Smith | Sr. EVP & CFO

4Q15 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 program, 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 effect of our debt on our financial flexibility; sufficiency of our operating cash flow to fund planned capital expenditures; the ability to obtain government permits and approvals; effectiveness our capital investments; our ability 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; restriction of operations to, and concentration of exposure to events such as industrial accidents, natural disasters and labor difficulties in, California; limitations on our ability to enter efficient hedging transactions; 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; the 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 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 to the nearest comparable measure in accordance with GAAP, please see the Appendix.

2

4Q15 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

4Q15 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

Balanced 2015 operating cash flows of

$403 million with capital investment of $401

million

Exceeded 2015 production target with 90%

of target capital investment

Delivered average 4Q15 oil production of

102,000 bbls/day, which was 3% higher

than the FY 2014 average of 99,000

bbls/day and down just 1% from 3Q15

Focused on costs. Total cash costs per

boe, excluding interest expense, declined

~18% in 4Q15 vs 4Q14

• Op Cash costs down to $15.51/Boe for

4Q15, compared to $16.65/Boe in 4Q14

• Expected run-rate G&A to be roughly

$4.00/Boe for 2016

Executed debt exchange that reduced

principal by $563 million

Priorities Execution

4

4Q15 Earnings

Living Within Cash Flow

-75

125

325

525

725

925

-25

25

75

125

175

225

275

325

1Q15 2Q15* 3Q15 4Q15* FY 2015

FY (

$M

M )

$ M

M

Adj. EBITDAX** Operating Cash Flow Capital Investment

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

5

4Q15 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”)

6

4Q15 Earnings

Strong Execution Track Record

140

145

150

155

160

165

170

1Q15 2Q15 3Q15 4Q15

Mb

oe

/d

Total ProductionGuidance vs. Actual

Production Guidance Range Actual

0

40

80

120

160

1Q15 2Q15 3Q15 4Q15

$M

M

Capital InvestmentGuidance vs. Actual

Capital Investment Guidance Range Capex Actual

Delivered production toward the high end of guidance with a lower than target capital investment

7

4Q15 Earnings

Best in Class Corporate Decline Rate

Unlabeled operators include : AMXG, AREX, BBG, BCEI, CLR, CPE, CRK, CWEI, CXO, EGN, EOG, EPE, EXXI, FANG, GDP, HK, JONE, LPI, MPO, NFX, OAS, PDCE, PE, PVA, PXD, ROSE, RSPP, SFY, SM,

SN, TPLM, WTI, XEC

Source: ITG IR, raw data provided by Drilling Info, Inc.

8

4Q15 Earnings

Resilient Asset Base

-

200

400

600

800

1,000

1,200

-

10.0

20.0

30.0

40.0

50.0

60.0

70.0

80.0

90.0

2010 2011 2012 2013 2014 2015

Net

Dev

elo

pm

ent

Cap

ital

($

MM

)

Mb

oe

/d

Elk Hills Field

Net Production MBOED Net Development Capital ($MM)

9

4Q15 Earnings

Defending Margins Through Efficiencies and

Focus on Cash Costs

4Q15 production costs per boe were approximately 7% lower year over year.

Lower fourth quarter costs reflected cost reductions across the board,

particularly in well servicing efficiency, surface operations and energy use,

and were also aided by lower natural gas and power prices.

$4.97 $5.00 $5.28 $5.57 $5.09 $5.13 $4.61 $4.80

$3.74 $3.88 $3.79 $3.55 $3.65 $3.63 $2.89 $2.10

$19.00 $19.03 $18.35 $16.65 $16.20 $16.59 $16.91$15.51

$2.23 $1.06 $1.69 $4.49$1.11 $0.52 $0.34

$0.49

$0

$5

$10

$15

$20

$25

$30

$35

1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16E

Cash Costs $/Boe

Adj G&A* Taxes (non income) Production Costs Exploration Guidance

2014 Average = $29.57

2015 Average = $24.91

* Adjusted G&A expenses exclude early retirement and severance costs which amounted to $10 million in 2Q15, $62 million in 3Q15 and $(5) million in 4Q15.

10

4Q15 Earnings

Capitalization as of 12/31/15 ($MM)

$25

$625$433

$829

$2,250

892

$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

• Ratings action initiated transition to

secured borrowing base facility

• Borrowing base of $2.3 billion effective

February 2016

• Approximately $1.6 billion outstanding

under senior credit facilities currently*

1 On February 23, 2016 we amended the Credit Facilities and reduced our borrowing base to $2.3 billion. After taking into account borrowing base limitations, we now have the ability to incur total borrowings under the RCF of $1.3 billion less outstanding amounts (currently ~$600MM)*, subject to compliance with our quarterly financial covenants which currently further limit our availability.

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 739

1st Lien Secured Term Loan 1,000

Senior 2nd Lien Notes 2,250

Senior Unsecured Notes 2,154

Total Debt 6,143

Less cash (12)

Total Net Debt 6,131

Equity (916)

Total Net Capitalization 5,215

Total Net Debt / Net Capitalization 118%

Total Net Debt / LTM Adjusted EBITDAX 6.8x

LTM Adjusted EBITDAX / Interest Expense 2.8x

PV-102 / Total Net Debt 0.8x

Total Net Debt / Proved Reserves ($/Boe) $9.52

Total Net Debt / PD Reserves ($/Boe) $12.75

Total Net Debt / Production ($/Boepd) $38,319

* As of 2/29/16** As of 12/31/15

11

4Q15 Earnings

$94

$55

$64

$48

$37

$33

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 2/29/16

Bre

nt

Oil

($/B

bl)

Tota

l Deb

t ($

M)

Total Debt

Long Term Notes Term Loan Revolving Credit Facility Oil Price

Deleveraging Update

12

Given the significant decline in oil prices, focused on 1) free cash flow to reduce

residual working capital from Spin, and 2) successful execution of debt exchange

4Q15 Earnings

• We have assessed various deleveraging alternatives and are

taking decisive 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

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

13

4Q15 Earnings

Revised Amendment Previous

Maximum Leverage First Lien Leverage Ratio suspended through 12/31/16; At and after 3/31/17 : < 2.25x

Maximum First Lien Secured Leverage Ratio: 2.25x

Minimum Interest Coverage

03/31/16 : > 2.00x 06/30/16 : > 1.50x 09/30/16 : > 1.25x 12/31/16 : > 0.70x

Thereafter: > 2.00x 2.00x

Cumulative Minimum EBITDAX

03/31/16 : $55mm 06/30/16 : $130mm09/30/16 : $190mm 12/31/16 : $250mm N/A

Borrowing Base, Revolver Commitment, Total Commitment

$2.3 Bn Borrowing Base$1.6 Bn Revolver Commitment$2.6 Bn Total Commitment

$3.0 Bn Borrowing Base$2.0 Bn Revolver Commitment$3.0 Bn Total Commitment

Redetermination Semi-Annually, May 1st and November 1st Annually – May 1st

Anti-hoarding Provisions Cash > $150mm must be used to the repay the revolver Cash > $250mm must be used to the repay the revolver

Other • Maximum Capital Expenditures: $100mm• General lien basket of up to $50mm • Accordion and Swingline eliminated• Increase of 75 bps across pricing grid

General lien basket of greater of $200mm and 1.5% of Consolidated Total Assets

Amendment – Summary of General Terms & Conditions

14

4Q15 Earnings

Revised Amendment Previous

Sale of Borrowing Base Properties

100% of proceeds used to repay first the term loan, then the revolver

Subject to potential repayment of revolver due to resultant borrowing base reduction

Sale of Non-Borrowing Base Properties

• 100% of proceeds used to repay first the term loan, then the revolver except:

• 40% of proceeds can be used to repurchase:• 2L notes at a minimum of 40% discount• Unsecured notes at a minimum of 60% discount

$150 million + 50% of proceeds could be used to repurchase senior notes and other junior debt

Deleveraging Debt Basket A • May incur debt of $1Bn secured with junior liens• 40% of proceeds can be used to repurchase:

• 2L notes at a minimum of 40% discount• Unsecured notes at a minimum of 60% discount

N/A

Deleveraging Debt Basket B • May incur debt of up to $200mm secured with liens on non-borrowing base properties in order to repurchase:

• 2L notes at a minimum of 40% discount• Unsecured notes at a minimum of 60% discount

N/A

Junior Notes Basket Used in the December 2015 bond exchange Up to $2.25 Bn in junior notes

Amendment – Summary of Liability Management Terms

15

4Q15 Earnings

Progressing Inventory to VCI Threshold

16

0

500

1000

1500

2000

2500

$40 $50

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

4Q15 Earnings

2015 Net Proved Reserves (MMBoe) 644

2015 % Oil– Net Proved1 72%

Pre-Tax Proved PV-10 ($ billion)2 5.06

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 Proved1

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 Locations1

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

17

4Q15 Earnings

San Joaquin$8565%

Los Angeles $4535%

Drilling $13032%

Dev. Facilities $120 30%

Workovers $55 14%

Exploration $15 4%

Other1

$81 20%

Commentary

2015 Drilling Capital Actuals – By Basin

2015 Total Capital Actuals

2015 Drilling Capital Actuals – By Drive

• 2015 actual capital investment of $401 million

was directed almost entirely toward oil-weighted

investments

• Total and oil production increased 1% and 5%

respectively in 2015 without exceeding cash flows

• Expect multi-year crude oil maintenance capital

range of $600-$700 million per year to maintain

flat crude oil production*

• Primary tenet for 2016 capital program of $50mm

is to invest within cash flow, emphasizing

mechanical integrity and safe operations

Total: $401 million

Total: $130 million Primary$10 8%

Steamfloods$70 54%

Waterfloods$50 38%

Self-Funded Capital Investment Program

1 Other includes maintenance and occupational health, safety and environmental projects, seismic and other investments.*Calculated over 3 years based on current operating costs and expenses in the current commodity environment.

18

4Q15 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

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 1Q 2Q 3Q 4Q

RIGS 4 3 3 3 3 3 3 3 3 3 3 1 0 0 0 0

Quarterly

Operations

CAPEX,

$mm

FY 2016E2015 Actual

$133 $95 $95 $78 $50*

19

4Q15 Earnings

Opportunistically Built Hedge Portfolio*

* As of February 23, 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

• Q1 2016 averages include Brent-based puts for 10,000 barrels of oil per day of our March

2016 production at $46 per barrel

Q1 2016 Q2 2016 Q3 2016 Q4 2016 2017 2018

Calls

Barrels per Day 35,500 35,500 3,000 3,000 30,000 23,300

Wtd Avg Ceiling Price per Barrel $66.15 $66.15 $74.42 $74.42 $55.68 $57.99

Puts

Barrels per Day 33,800 55,500 28,000 3,000 - -

Wtd Avg Floor Price per Barrel $51.75 $50.14 $50.65 $50.00 - -

Swap

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

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

20

4Q15 Earnings

$95.12 $94.21 $97.97 $93.00

$48.80

$103.80 $104.02 $104.16

$92.30

$49.19

$110.90 $111.70 $108.76

$99.51

$53.64

$30

$40

$50

$60

$70

$80

$90

$100

$110

$120

2011 2012 2013 2014 2015

$/B

bl

WTI Realizations Brent

$4.11

$2.81

$3.66 $4.34

$2.75

$4.31

$2.94

$3.73 $4.39

$2.66

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0

2011 2012 2013 2014 2015

$/M

cf

NYMEX Realizations

NGL Price Realization - % of WTI

Realization % of WTI

109% 110% 106 % 99% 97% Realization % of NYMEX

105% 105 % 102 % 101% 97%

Oil Price Realization* Gas Price Realization*

• Oil pricing continued to deteriorate over 2015

• 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 declined in 2015 due to continued supply

growth, lower demand due to mild weather, record storage

inventory levels and lower industrial demand

74%

56%51% 51%

40%

0%

10%

20%

30%

40%

50%

60%

70%

80%

2011 2012 2013 2014 2015

% o

f W

TICRC – Price Realizations

* Reflects realizations with hedges

21

4Q15 Earnings

2,371

403

0

500

1000

1500

2000

2500

3000

FY 2014 Volume Price Costs Interest Working

Capital and

Other

FY 2015

$ M

M

Op

era

tin

g C

ash

Flo

wCRC Executing on Controllable Items

22

4Q15 Earnings

Cost Variance

4Q14 3Q15 4Q15

Production costs($/Boe)

$16.65 $16.91 $15.51

Taxes other than on income ($MM)

$54 $42 $30

Exploration expense ($MM)

$68 $5 $7

Interest expense($MM)

NA $82 $82

23

4Q15 Earnings

Modest Production Decline Despite Drastically Lower Capital Investment

165,000

155,000

-3,000

-6,000

-1,000

$0

$100

$200

$300

$400

$500

100,000

110,000

120,000

130,000

140,000

150,000

160,000

170,000

4Q14 Oil Gas NGL 4Q15

Cap

ital

Inve

stm

ent

($M

M)

Bo

e/D

Quarterly Capital Investment of $78mm

Quarterly capital Investment of $520mm

24

4Q15 Earnings

Focus on Oil Enhances Base & Margins

1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16E FY 2014 FY 2015 FY2016E

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

25

4Q15 Earnings

4Q15 Results Summary Comparison

4Q14 3Q15 4Q15

Adjusted EPS* ($0.02) ($0.22) ($0.20)

Oil Production 105 MBbl/d 103 MBbl/d 102 MBbl/d

Total Production 165 MBoe/d 158 MBoe/d 155 MBoe/d

Realized Oil Price w/hedge ($/Bbl) $68.54 $47.79 $45.88

Realized NGL Price ($/Bbl) $34.41 $16.92 $19.56

Realized Natural Gas Price w/ hedge($/Mcf) $4.00 $2.83 $2.44

Adjusted EBITDAX* $454 mm $212 mm $226 mm

Capital Investments $520 mm $95 mm $78 mm

Cash Flow from Operations $504 mm $180 mm ($9 mm)**

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

26

4Q15 Earnings

1Q16 Guidance

Anticipated Realizations Against the Prevailing Index Prices for 1Q16

Oil 83% to 87% of Brent

NGLs 45% to 49% of Brent

Natural Gas 96% to 100% of NYMEX

Production, Capital and Income Statement Guidance

Production 145 to 150 MBOE per day

Capital $18 to $28 million

Production Costs $14.50 to $15.00 per BOE

G&A $3.95 to $4.15 per BOE

DD&A $10.30 to $10.50 per BOE

Taxes other than on income $36 to $40 million

Exploration expense $7 to $11 million

Interest expense $74 to $78 million

Cash Interest $47 to $51 million

Income tax expense rate 10%

Cash tax rate 0%

27

See Attachment 9 of the 4Q15 earnings press release issued February 29, 2016 for more details.

4Q15 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.

28

4Q15 Earnings

California Resources Corporation

Appendix

29

4Q15 Earnings

Non-GAAP Reconciliation for Adjusted EBITDAXFor the

Fourth QuarterEnded December 31,

For the TwelveMonths EndedDecember 31,

($ in millions) 2015 2014 2015 2014

Net Income/(loss) ($3,282) ($2,091) ($3,554) ($1,434)

Interest expense 82 72 326 72

Income taxes expense/(benefit) (1,757) (1,431) (1,922) (987)

Depreciation, depletion and amortization 247 312 1,004 1,198

Exploration expense 7 68 36 139

Asset Impairments 4,852 3,402 4,852 3,402

Other (a) 77 122 164 158

Adjusted EBITDAX $226 $454 $906 $2,548

Net cash provided by operating activities ($9) $504 $403 $2,371

Interest expense 82 72 326 72

Cash income taxes - (17) - 165

Cash exploration expenses 7 19 27 38

Changes in operating assets and liabilities 104 (155) 147 (143)

Other, net 42 31 3 45

Adjusted EBITDAX $226 $454 $906 $2,548

(a) Includes non-cash and unusual or infrequent charges.

30

4Q15 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 annatural 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.

31

4Q15 Earnings

Non-GAAP Reconciliation for Adjusted EPSFor the

Fourth QuarterEnded December 31,

For the Third Quarter Ended September 30,

For the TwelveMonths EndedDecember 31,

($ in millions) 2015 2014 2015 2015 2014

Adjusted net Income/(loss) $(77) $(7) $(104) $(311) $650

Asset impairments (4,852) (3,402) - (4,852) (3,402)

Write-down of certain other assets (71) - - (71) -

Non-cash hedge related gains 19 - (53) 52 -

Early retirement and severance costs 5 - 62 (67) -

Rig terminations and other costs (5) (52) 3 (11) (52)

Debt transaction costs (8) - - (8) -

Spin-off and transition related costs - (55) - - (55)

Valuation allowance for deferred tax assets (294) - - (294) -

Tax effects of these items and related adjustments 2,001 1,425 6 2,008 1,425

Net income / (loss) $(3,282) $(2,091) $(86) $(3,554) $(1,434)

EPS – diluted$(8.54)

$5.47 $(0.27) $(9.27) $(3.75)

Adjusted EPS – diluted $(0.20) $0.02 $(0.22) $(0.81) $1.67

Weighted average diluted shares outstanding (a) 384.2 381.9 383.1 383.2 381.9

(a) On November 30, 2014, the Spin-off date from Occidental Petroleum Corporation, we issued 381.4 million shares of our common stock. Additional shares were distributed to our employees and vested in December. For comparative purposes, and to provide a more meaningful calculation of weighted-average shares outstanding, we have assumed these amounts to be outstanding for each period prior to the Spin-off.

32