investor update february 2018 final

Investor UpdateFebruary 2018

Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995

This presentation includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this presentation other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company’s business and statements or information concerning the Company’s future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows, are forward-looking statements. When used in this presentation, the words “could,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “budget,” “plan,” “continue,” “potential,” “guidance,” “strategy,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

Forward-looking statements are based on the Company’s current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company’s control. No assurance can be given that such expectations will be correct or achieved or the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial, market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas exploration, drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other revenue-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A Risk Factors and elsewhere in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this presentation occur, or should underlying assumptions prove incorrect, the Company’s actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as expressly stated above or otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this presentation, or otherwise.

Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.

We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.

Forward-Looking Information

2

2018: Breakout Year for CLRTop-Tier Production Growth w/ Up to $900MM in Free Cash Flow

$2.3 billion capital budget

• 100% funded from internal cash flow• $2.0 billion for D&C • 78% of D&C targeting Bakken and Springer oil reservoirs• 25% of D&C will benefit 2019 production• Flat rig count (~21 rigs vs. ~20 rigs in 2017)

17% - 24% YoY production growth

• Targeting annual 285,000 to 300,000 Boe per day • 57% to 60% of production is forecasted to be oil • Projected exit-rate of 305,000 to 315,000 Boe per day

$800 to $900MMfree cash flow

• At $60 WTI and $3.00 Henry Hub• Capital budget cash neutral at low-to-mid-$40’s WTI• Currently no oil hedges in place• ~80% of gas hedged at $2.88 per Mcf for rest of year

Continued debt reduction

• Free cash flow will be applied to reducing debt• Additional non-core asset divestitures

3

2018 Budget Highlights:

(1)

1. Free cash flow is a non-GAAP measure, please see slide 30 for additional information.

-$526-$845

-$1,393

-$999-$1,329

-$875

$79$96 $95 $97 $95

$50

$43$51

$0

$20

$40

$60

$80

$100

-$2,000-$1,500-$1,000

-$500$0

$500$1,000$1,500$2,000

2010 2011 2012 2013 2014 2015 2016 2017 2018E

CLR Has Transitioned to Sustainable PositiveCash-Flow Growth

4

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

2010 2011 2012 2013 2014 2015 2016 2017 2018E

STACKSCOOPBakkenLegacy

242,637

Annual Production Chart

Boe p

er d

ay

285,000-300,000

$ in

MM

$800-$900

Outspend Asset divestiture proceedsFree cash flow Projected free cash flow

2010-2014• Growing Bakken and SCOOP 2015-2016• Growing STACK and SCOOP • Building Bakken DUCs2017• Optimized completions• Begin completing Bakken DUCs• 12% YoY growth• ~70% net reservoir acres HBP’d2018• 17%-24% projected growth• Harvest Bakken DUCs• Begin Springer development

2010-2014• Outspent to grow/secure assets 2015-2017• Transitioned to free cash flow• Adjusted to market conditions• Operating efficiency gains• Non-strategic asset sales2018• $800-$900 MM of free cash flow • Cash from non-strategic asset

sales

1. Free cash flow / outspend is a non-GAAP measure. See slide 30 for a definition of this measure and a reconciliation of the historical amounts to the most comparable U.S. GAAP measure. Also, with respect to projected amounts, please see slide 30 for an explanation of the factors that make a quantitative reconciliation of this forward-looking estimate to U.S. GAAP not possible. 2016 & 2017 totals are inclusive of asset divestiture proceeds of $631 million and $144 million, respectively.

2. Average WTI price is the SEC price used for reserve calculations; rounded to the nearest dollar

Annual Free Cash Flow vs. Outspend(1)

$845$227

Avg. WTI Price (2)

CLR Restoring Historical Returns and Debt Metrics

5

23.1% 21.9%

16.9%18.8%

16.1%

-1.6% -0.7%

3.8%

$79

$96 $95 $97$95

$50

$43

$51

$0

$20

$40

$60

$80

$100

-5%

0%

5%

10%

15%

20%

25%

30%

2010 2011 2012 2013 2014 2015 2016 2017 2018E

10.0%-15.0%

Return on Capital Employed (ROCE)(1)

Net Debt / TTM EBITDAX(2)

1.8x1.6x 1.6x

3.6x 3.5x

2.7x

$79

$96 $95 $97 $95

$50

$43

$51

$0

$20

$40

$60

$80

$100

0.0

1.0

2.0

3.0

4.0

2010 2011 2012 2013 2014 2015 2016 2017 2018E1. See the calculation of ROCE on slide 362. Net Debt and EBITDAX are non-GAAP measures. See slides 31-33 for definitions and reconciliations of

these measures to the most comparable U.S. GAAP financial measures. 3. Average WTI price is the SEC price used for reserve calculations; rounded to the nearest dollar

1.1x 0.9x

Avg. WTI Price (3)

2015-2017• No equity dilution to fund

growth / reduce debt• Build operating efficiencies and

lower costs: • LOE• G&A• Differentials

2018• Projecting ROCE back in line

with historical average

2010-2014• Grew/secured assets• Net-debt-to-EBITDAX well

below 2x2015 -2017• Paid down debt by ~$800

million• Net-debt-to-annualized 4Q

2017 EBITDAX produces a leverage ratio of 1.9x

2018• Leverage ratio expected to

improve with further debt reduction/higher crude prices

Avg. WTI Price (3)

4Q EBITDAX annualized 1.9x

CLR

$0

$2

$4

$6

$8

$10

0% 20% 40% 60% 80% 100%LO

E/B

oe

Oil Production Percentage (Excludes Liquids)

CLR: Low-Cost, Oil-Weighted Producer

6

Select peers include: APC, CXO, DVN, EOG, MRO, NFX, OAS, PXD, WLL, WPX, XEC

LOE and Oil % vs. Peers (4Q’17)(Source: Public company filings)

$0

$1

$2

$3

$4

$5

$6

$7

2Q'1

23Q

'12

4Q'1

21Q

'13

2Q'1

33Q

'13

4Q'1

31Q

'14

2Q'1

43Q

'14

4Q'1

41Q

'15

2Q'1

53Q

'15

4Q'1

51Q

'16

2Q'1

63Q

'16

4Q'1

61Q

'17

2Q'1

73Q

'17

4Q'1

7

Sustained Downward Shift in Production Expense per Boe

Asset Optimization

Exploration

4Q’17 production expense $3.17 per Boe, down 17% from 3Q’17

Guiding to $3.00 to $3.50 for full-year 2018

LOE among the lowest of select peers

CLR: Low Costs Generate Strong Margins(1)

7

1. Margin presented on this slide represents the Company’s average sales price for a period expressed in barrels of oil equivalent (Boe) less production expenses, production taxes, G&A expenses (exclusive of non-cash equity compensation expenses), and interest expense, all expressed on a per-Boe basis. Margin does not reflect all activities of the Company that give rise to cash inflows and outflows and specifically excludes income and costs associated with derivative settlements, service operations, exploration activities, asset dispositions, litigation settlement and various non-operating activities. These items are excluded from the computation of Margin because they can vary significantly from period to period in a manner that does not correlate with changes in the Company’s production and sales volumes. Therefore, these items are not typically utilized by management on a per-Boe basis in assessing the performance of the Company’s E&P operations from period to period. See “Continuing to Deliver Strong Margins” on slide 29 for additional details on the method for calculating margin.

2. See “Cash G&A Reconciliation to GAAP” on slide 35 for a reconciliation of GAAP Total G&A per Boe to Cash G&A per Boe, which is a non-GAAP measure.3. Based on average oil equivalent price (excluding derivatives and including natural gas.)4. Margins calculated as E&P revenue less LOE, TT&O, cash G&A and interest expense per Boe 5. Recycle ratio calculated as margins per footnote 4, divided by F&D per Boe 6. Select peers include: APC, CXO, DVN, EOG, NBL, NFX, OAS, PXD, WLL, WPX, XEC

$4.30 $3.65 $3.66 $3.17$1.70 $1.53 $1.64 $1.80

$2.47 $1.79 $2.35 $2.78

$3.86$4.04 $3.32 $2.85

$19.15

$14.54

$22.68

$27.67$31.48

$25.55

$33.65

$38.27

$0

$10

$20

$30

$40

$50

$60

2015 2016 2017 4Q 2017

Margin(1)

InterestProduction/Severance TaxCash G&A(2)

Production Expense

61%57%

Avg

. Rea

lized

$/B

oe(3

)

4Q’17: Select Cash Costs of $10.60 per Boe

67%72%

CLR

$-

$5

$10

$15

$20

$25

$30

0% 100% 200% 300% 400%A

vg. U

nhed

ged

Mar

gins

(4) p

er B

oe(2

014

–20

17E)

Average Unhedged Recycle Ratio(5) (2014-2016)

Margin(4) and Recycle Ratio(5) vs. Peers(6)

(Source: Stephens, Inc. August 2017)

CLR: 4Q 2017 Highlights

8

Bakken: • 39 gross operated wells completed with avg. 24-hour IP of 2,180 Boe per well • 5 wells were record 30-day Bakken producers for CLR, avg. 2,230 Boepd • 4Q 2017 production up 58% over 4Q 2016, all time high

SCOOP Springer: • Initial density testing complete; beginning full-field development with 5 rigs • Type curve uplifted 28% to 1,200 MBoe for a 7,500-foot lateral unit well

STACK Meramec: • Preliminary economic model to maximize net present value for unit development

announced in over-pressured oil window

Production

Operations

• 4Q 2017: 286,985 Boe per day (59% oil); up 37% over 4Q 2016• Oil production up 44% over 4Q 2016

• FY 2017: 242,637 Boe per day (57% oil); up 12% over FY 2016

Financial Metrics• $3.17 production expense per Boe• $4.23 per Bo oil differential; +$0.37 per Mcf gas premium• Upgraded to Investment Grade by S&P to BBB- in February 2018

CLR’s Superior Oil-Weighted Assets Provide the Foundation for Future Growth

9

Play Net ReservoirAcres(1)

HBP(1)

Bakken: 802,000 90%

STACK:

Meramec 212,500 58%

Woodford 197,000 63%

SCOOP:

Springer 170,000 64%

Sycamore 277,000 56%

Woodford 277,000 56%

1. Acreage and HBP numbers are approximate

4Q 2017 Production: 286,985 Boe per day (59% oil)

NORTH175,563 Boepd

SOUTH111,422 Boepd

1.9 Million Net Reservoir Acres

~70% HBP

10

20 Miles

CLR 30‐Day Record WellsCLR Acreage

Tarentaise Fed. 1-19H



Tarentaise Fed. 12-19H2

Holstein Fed 8-25H

Monroe 6-2H

Monroe 7-2H

Akron Fed 7-27H

Radermecher 2-22H1

Wiley 7-25H

Well 30-Day Avg, Boepd % Oil Formation Quarter

Monroe 6-2H 2,869 79% MB 4Q17

Tarentaise Federal 1-19H 2,126 79% MB 4Q17


Monroe 7-2H 2,055 80% MB 4Q17


Holstein Federal 8-25H 2,015 83% MB 2Q17

Wiley 7-25H 1,966 76% MB 3Q17

Akron Federal 7-27H 1,853 79% MB 1Q17

Tarentaise Federal 12-19H2 1,848 79% TF2 4Q17

Radermecher 2-22H1 1,833 79% TF1 1Q17

Bakken Continues to Deliver Record Results39 gross operated wells turned to production in 4Q’17• Average 24-Hr IP: 2,180 Boe per day

• Top 5 all-time 30-day rate Bakken wells

0

50,000

100,000

150,000

200,000

250,000

300,000

0 30 60 90 120 150 180 210 240 270 300

Cum

ulat

ive

Prod

uctio

n B

oe

Days

ND Bakken Well Production

11

Bakken Optimized Completions Continue to Uplift Performance & Economics Across Our Acreage

1. 134 optimized completions for MB, TF1 and TF2 through 4Q’17 in Mountrail, Williams, McKenzie and Dunn counties; down days removed

2. ROR, PV-10 & payout are based on $60 WTI and $3.00 gas, see ROR footnote on slide 23 or 24

CLR Leasehold

CLR Larger Optimized Completion

Optimized completions successful across broad area

All optimized completions(1)

1,100 MBoe TC

~40 miles

1,100 MBoe type curve supported by 134 optimized completions • Generates ~125% ROR(2)

• 10 month(2) payout period• PV-10 up 47% per well(2) compared to previous

type curve

12

• 4Q’17 Bakken differential improved $4.54 from 2015 average

• Revised Bakken transportation contract - lowered oil differential to $3.75 per Bo on ~30% of production through Oct. 2024 (starting in January 2018)

• As a result, CLR Bakken differentials expected to remain low in 2018

• 4Q’17 corporate differential improved $3.10 from 2016 average

• 2018 corporate differential expected to be ($3.50) to ($4.50) per Bo

Bakken Differentials Continued to Improve in 4Q 2017 Benefiting Corporate Netbacks

Rai

lPi

pelin

e

$10.81

$8.33 $7.33 $7.09

$6.31 $4.98

$4.23

$0

$2

$4

$6

$8

$10

$12

2014 2015 2016 1Q'17 2Q'17 3Q'17 4Q'17

Corporate Oil Differentials to WTI

$11.83

$9.21 $8.26 $8.10

$7.13 $5.54 $4.67

$0$2$4$6$8

$10$12$14

2014 2015 2016 1Q'17 2Q'17 3Q'17 4Q'17

Bakken Oil Differentials to WTI

STACK Density Results Providing Template for Future Development

Blurton

Compton

Over-Pressured

Normally-Pressured

Bernhardt

Intermediate pipe required

Ludwig

CLR LeaseholdCLR RigsIndustry Meramec wellCLR Meramec producing wells CLR Meramec wells drilling / completing

13

STACKSCOOP

Angus Trust

Gillilan

Verona

CLR Density Results

Unit name Average 24-hour IP per well

# of wells per zone

Zones tested

Bernhardt (5-well unit)

752 Boe (78% oil)

5 Lower

Ludwig (8-well unit)

2,669 Boe (70% oil)

4 Upper, Middle

Blurton (8-well unit)

1,314 Boe (78% oil)

3-5 Upper, Lower

Verona (8-well unit)

2,281 Boe (68% oil)

4 Upper, Lower

Compton (10-well unit)

2,203 Boe (75% oil)

5 Upper, Lower

Gillilan (10-well unit)

1,102 Boe (64% oil)

5 Upper, Lower

Angus Trust (12-well equivalentunit)

2,659 Boe (39% oil)

6 Upper, Lower

CLR Density Tests Completed• 6 full-unit tests in over-pressured oil window• 1 half-unit test in condensate window (Angus Trust)

$0

$20

$40

$60

$80

$100

$120

$140

$50 $60 $70

PV-1

0 ($

in M

M)

WTI Oil Price, $/BBL

Maximizing Unit Value in STACK Over-Pressured Oil

0%

50%

100%

150%

200%

$0

$20

$40

$60

$80

$100

Uni

t RO

R%

Uni

t PV-

10($

in M

M)

Maximizing Unit Value

Taking STACK to Next Level: Introducing Unit Economic Model for Over Pressured Meramec Oil

14

Objective: Maximizing the Net PV-10 (PV-10)(1) of Unit

Preliminary Unit Economic Model for Meramec Oil • Maximum PV-10 achieved with 8 wells

• Estimate $87 MM PV-10 for unit• 96% ROR(1) for unit• 9,600 MBoe unit EUR• $9.5MM CWC for a 9,800’ lateral• 2 targeted Meramec reservoirs/unit on avg.• 4 wells per zone, 8 total Meramec wells/unit• Based on 6 full density tests

Over 40 operated units in inventory to develop in de-risked portion of the over-pressured oil window

Well Count 1 2 4 6 8 10Unit EUR(2) 1,700 3,400 6,000 8,000 9,600 10,500Unit PV-10 $20 MM $40 MM $64 MM $80 MM $87 MM $80 MMUnit ROR 175% 175% 140% 115% 96% 78%

1. All references to ROR & PV-10 are based on $60 WTI and $3.00 gas, see ROR footnote on slide 23 or 242. EUR in MBoe

$67 MM increase in PV-10

Unit PV-10: $87 MMParent well PV-10: $20 MM

10

100

1,000

10,000

0 365 730 1095 1460 1825 2190 2555 2920 3285 3650

Prod

uctio

n B

oe p

er d

ay

Years

Unit vs. Parent Well Type Curves in Over-Pressured Oil

Unit average Parent well

1 2 3 4 5 6 7 8 9 10

SCOOP Springer: Moving to Full Field Development in 2018, Guided by Density Test Results

15

Three Density Pilots Completed• Tested 4, 5 and 6 wells per unit

Third density test completed in 4Q 2017 • Celesta Unit

• 6-wells, average ~9,400 lateral

• 6,014 Boe (81% oil) - combined IP

• Early performance indicates fewer wells are needed to maximize PV-10

Conclusion: 4 wells per unit on average should maximize PV-10 for Springer units

Moving to full-field development in 2018• Currently 6 rigs drilling Springer, plan to average 5

rigs during the year

12 Miles

Celesta Density (6-well unit)

SCOOP Springer Fairway

Jeanna Density (4-well unit)

CLR Leasehold OSO SPRG HZCLR Leasehold OSO SPRG HZCLR SPRG HZ

6 Miles

Hartley Density(5-well unit)

0%

50%

100%

150%

200%

$0

$20

$40

$60

$80

Uni

t RO

R%

Uni

t PV-

10($

in M

M)

Maximizing Springer Unit Value

SCOOP Springer: Introducing Unit Economic Model Type Curve EUR up 28%, 175% ROR

16

1. All references to ROR & PV-10 are based on $60 WTI and $3.00 gas, see ROR footnote on slide 23 or 24

2. EUR in MBoe

Well Count 1 2 3 4 5 6Unit EUR(2) 1,700 3,300 4,200 4,800 5,100 5,300 Unit PV-10 $24MM $46MM $59MM $68MM $62MM $53MMUnit ROR 195% 188% 181% 175% 127% 82%

Updated Springer type curve for unit wells• 1,200 MBoe (~75% oil), 7500’ lateral• ~175% ROR(1) at $9.5 MM CWC• 2.6X ROR of legacy 940MBoe type curve for 4,500’ lateral• Payout(1) 11 months• $4 million incremental first year gross cash flow per well

Preliminary Unit Economic Model for Springer Oil • Maximum PV-10 achieved with 4 wells

• Estimate $68 MM PV-10 for unit• 4,800 MBoe unit EUR

50100150200250300350400

0 30 60 90 120 150 180 210 240 270 300 330 360 389

MB

oe

Days

1,200 MBoe Springer Type Curve

0%25%50%75%

100%125%150%175%200%

$50 $60 $70

RO

R


Springer Unit Well 2.6X Legacy ROR

~175% ROR

~65% ROR

SCOOP Woodford OilEnhanced Completions Increase EUR 13%

17

30+ enhanced completions outperform legacy offsets• ~13% increase in EUR to 1,520 MBoe per

well for 2-mile lateral • ~55% ROR(1) for $12.7 million CWC

Recent completion with Pyle 1-36-25XH: • 1,812 Boe per day (81% oil)• 9,800-foot lateral

SCOOP Woodford Enhanced Completions

CLR Leasehold

Woodford HZ Producing Well

CLR Enhanced Completion

Gas Condensate Oil

12 Miles

1. ROR is based on $60 WTI and $3.00 gas, see ROR footnote on slide 23 or 24

Pyle 1-36-25XH

0

10

20

30

40

50

60

0 6 12 18 24 30 3610

100

1,000

10,000

Wel

l Cou

nt

Producing Months

Boe

per

day

SCOOP Oil Type CurveWell Count

1,520 MBOE Type Curve (Normalized to 9800' LL)

Actual Production (Normalized to 9800' LL)

Dicksion Project(1): Testing the Future of SCOOPSimultaneous Drilling & Completing Springer/Woodford/Sycamore

18

Aerial photograph of Dicksion Unit

Potential Efficiency Gains• 30% cycle time(2) reduction for

Woodford and Sycamore wells• 15% cycle time(2) reduction of

Springer wells

Reduced Cycle Times = Accelerated Production = Value Creation

DrillingSpringer

CompletingSycamore & Woodford

Drilling RigStimulation Crew

Total thickness 1,700’

Drilling WellProducing WellCompleting Well

Template for full-unit development:

1. Dicksion project is currently testing a half-unit with 9 wells2. Cycle time is referring to spud to first production

J. Warren HenryVice President, Investor Relations & ResearchPhone: 405-234-9127Email: [email protected]

Alyson L. GilbertManager, Investor Relations Phone: 405-774-5814Email: [email protected]

Website:www.CLR.com/Investors

CONTACT INFORMATION

19

REFERENCE MATERIALS

20

0

300

600

900

1,200

1,500

2010 2011 2012 2013 2014 2015 2016 2017

STACK

SCOOP

Bakken

Legacy

MM

Boe

1,331

37%

48%

2%

52%48%

Natural

Gas OilFor YE 2017:

21

Proved Reserves up 4% over YE 2016

13%

Total Proved ReservesYear-end 2017:• Proved reserves were 1,331 MMBoe,

up 4% over YE 2016 proved reserves of 1,275 MMBoe

• PV-10: $11.83 billion(1), up 78% over YE 2016 of $6.65 billion

• 45% PDP• 89% operated

SEC price deck: • Year-end 2017: $51.34 per Bo and

$2.98 per MMbtu gas

1. At December 31, 2017, Continental had a Standardized Measure of discounted future net cash flows of $10.47 billion. PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues of approximately $1.36 billion.

2018 Guidance Builds on Successful 2017

Production & Capital Full-Year 2017 Performance

2018 Guidance as of 2/21/18

Capital expenditures (non-acquisition) $1.995 billion $2.3 billion

Production (Boe per day) 242,637 285,000 – 300,000

Exit rate production (Boe per day) 283,857 305,000 – 315,000

Operating ExpensesProduction expense ($ per Boe) $3.66 $3.00 - $3.50

Production tax (% of oil & gas revenue) 7.0% 7.6% - 8.0%

Cash G&A expense(1) ($ per Boe) $1.64 $1.25 - $1.75

Non-cash equity compensation ($ per Boe) $0.52 $0.45 - $0.55

DD&A ($ per Boe) $18.89 $17.00 - $19.00

Average Price Differentials NYMEX WTI crude oil ($ per barrel of oil) $(5.50) ($3.50) - ($4.50)Henry Hub natural gas(2) ($ per Mcf) $(0.16) $0.00 - +$0.50

1. Cash G&A is a non-GAAP measure and excludes the range of values shown for non-cash equity compensation per Boe in the item appearing immediately below. Guidance for total G&A (cash and non-cash) is an expected range of $1.70 to $2.30 per Boe. See “Cash G&A Reconciliation to GAAP” on slide 35 for a reconciliation of 2017 GAAP total G&A per Boe to cash G&A per Boe.2. Includes natural gas liquids production in differential range

22

0%

25%

50%

75%

100%

125%

150%

175%

200%

$50 $55 $60 $65 $70

RO

R


SCOOP Springer

0%

40%

80%

120%

160%

200%

$50 $55 $60 $65 $70

RO

R


Bakken

$7.9MM Budget 20180%

25%

50%

75%

100%

125%

150%

175%

200%

$50 $55 $60 $65 $70

RO

R


STACK Over-Pressured Oil

1. Pre-tax rate of return (ROR) is based on projected cash flow and time value of money; costs include completed well cost, production expense, severance tax and variable operating costs. $3.00 Henry Hub is the gas price used for oil price sensitivities and $60 WTI is used for gas price sensitivities. The description of the ROR calculation applies to any ROR reference appearing in this presentation.

23

2018 Drilling Program: CLR Oil Assets

Target EUR: 1,100 MBoeAvg. Lateral: 9,800’

~100% ROR

~175% ROR

$9.5MM Budget 2018 – unit well$10.0MM Budget 2018 – parent well

Target EUR for unit: 1,200 MBoeAvg. Lateral:9,800’

0%

25%

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$50 $55 $60 $65 $70

RO

R


SCOOP Woodford Oil

$12.7MM Budget 2018


~55% ROR

Target EUR for parent wells: 1,700 MBoeAvg. Lateral:9,800’

~125% ROR

~175% ROR


$9.5MM Budget 2018

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$2.50 $3.00 $3.50 $4.00

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Gas Price, $/MCF

SCOOP Woodford Condensate

$10.8MM Budget 2018

~85% ROR


1. Pre-tax rate of return (ROR) is based on projected cash flow and time value of money; costs include completed well cost, production expense, severance tax and variable operating costs. $3.00 Henry Hub is the gas price used for oil price sensitivities and $60 WTI is used for gas price sensitivities. The description of the ROR calculation applies to any ROR reference appearing in this presentation.

24

2018 Drilling Program: CLR Condensate Assets

0%

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$2.50 $3.00 $3.50 $4.00

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Gas Price, $/MCF

STACK Condensate

~75% ROR


$10.6MM Budget 2018

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STACK Over-Pressured Oil Type CurveWell Count


1,700 MBOE Parent Type Curve

1,200 MBOE Child Curve

25

Optimized Oil Completions Type Curves

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Bakken Production

Well Count1,100 Mboe Type Curve

Act. Production (Normalized to 9,800’ LL)1,200 MBOE Unit Curve

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SCOOP Oil Type CurveWell Count1,520 MBOE Type Curve (Normalized to 9800' LL)Actual Production (Normalized to 9800' LL)

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Springer Oil Type Curve940 Curve Well CountUnit Well 1,200 MBOE Type Curve (Normalized to 7,500 LL)Cash, Trammell, Strassle, Robinson Avg (Normalized to 7,500' LL)Actual Production (Normalized to 4,500' LL)Parent 940 MBOE Type Curve (Normalized to 4,500' LL)Enhanced Well Count

Actual Production (Normalized to 9,800’ LL)

Wel

l Cou

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26

Optimized Condensate Completions Type Curves

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SCOOP Woodford Condensate Type CurveWell Count

2,300 MBOE Type Curve (Normalized to 7500' LL)


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STACK Condensate Type CurveWell Count


Previous 2,400 MBOE Type Curve2,400 MBoe Type Curve (Normalized to 9,800’ LL)

0%10%20%30%40%50%60%70%80%90%

100%110%120%130%140%150%

$40 $50 $60 $70 $80

RO

R(2

)


Evolution of Bakken Type Curves

Optimized Completions Unlock Bakken Value Generating ~$2.6MM First Year Incremental Cash Flow per Well(1)

27

.

1,100 MBoe vs. 980 MBoe Type Curves

• More than doubled ROR(2) to ~125%

• Payout period down to 10 months(2)

• PV-10 up 47% per well(2)

• Both type curves deliver 80% oil

1. Compared to the 980 MBoe type curve; cash flow per well is on a gross basis 2. ROR, PV-10 & payout are based on $60 WTI and $3.00 gas, see ROR footnote on slide 23 or 24

2018

20112014

2015

1H 2017

1,100 MBoe; $7.9MM CWC980 MBoe; $7.0MM CWC800 MBoe; $6.8MM CWC603 MBoe; $7.8MM CWC430 MBoe; $6.5MM CWC

Upgraded to IG by S&P to BBB-

Financial Metrics

• 1.9x: net debt(1) / 4Q 2017 annual EBITDAX(1)

• 2.7x: net debt(1) / TTM EBITDAX(1)

Financial Strength

• Earliest debt maturity is revolver balance in May 2019

• 4.2% average interest rate in 4Q’17

Unsecured Credit Facility

• Ample liquidity with $2.75 billion revolver

• Projecting to pay off revolver in 2018

$93

$2,000 $1,500

$1,000 $1,000 $700

$2,657

0

500

1,000

1,500

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3,000

2017 2018 2019 2020 2021 2022 2023 2024 2028 2044

4.375%

($M

M)

Debt Maturities Summary

5.0%

4.5%

3.8%4.9%

Undrawn

Continued Focus on Debt Reduction

28

($M

M)

Long-Term Debt(2) Declining

Callable3/15/17

Balance1/31/18

$7,116 $6,578 $6,351 $6,000$5,000

01,0002,0003,0004,0005,0006,0007,000

YE 2015 YE 2016 YE 2017 Near TermTarget

Long TermTarget

Drawn

1. Net Debt and EBITDAX are non-GAAP measures. See slides 31-33 for definitions and reconciliations of these measures to the most comparable U.S. GAAP financial measures. 2. Net of current portion of long-term debt

1. Margin represents the Company’s average sales price for a period expressed in barrels of oil equivalent (Boe) less production expenses, production taxes, G&A expenses (exclusive of non-cash equity compensation expenses), and interest expense, all expressed on a per-Boe basis. Margin does not reflect all activities of the Company that give rise to cash inflows and outflows and specifically excludes income and costs associated with derivative settlements, service operations, exploration activities, asset dispositions, litigation settlement and various non-operating activities. These items are excluded from the computation of Margin because they can vary significantly from period to period in a manner that does not correlate with changes in the Company’s production and sales volumes. Therefore, these items are not typically utilized by management on a per-Boe basis in assessing the performance of the Company’s E&P operations from period to period.

2. See “EBITDAX reconciliation to GAAP” on slide 33 for a reconciliation of GAAP net income and net cash provided by operating activities to EBITDAX, which is a non-GAAP measure. 3. Average costs per Boe have been computed using sales volumes and exclude any effect of derivative transactions.4. See “Cash G&A Reconciliation to GAAP“ on slide 35 for a reconciliation of GAAP Total G&A per Boe to Cash G&A per Boe, which is a non-GAAP measure.

2015 2016 4Q 2017 2017

Realized oil price ($/Bbl) $40.50 $35.51 $51.16 $45.70

Realized natural gas price ($/Mcf) $2.31 $1.87 $3.30 $2.93

Oil production (Bopd) 146,622 128,005 168,066 138,455

Natural gas production (Mcfpd) 450,558 533,442 713,518 625,093

Total production (Boepd) 221,715 216,912 286,985 242,637

EBITDAX ($000's)(2) $1,978,896 $1,881,889 $837,887 $2,363,617 Key Operational Statistics (per Boe)(3)

Average oil equivalent price (excludes derivatives) $31.48 $25.55 $38.27 $33.65

Production expense $4.30 $3.65 $3.17 $3.66Production tax and other $2.47 $1.79 $2.78 $2.35Cash G&A(4) $1.70 $1.53 $1.80 $1.64Interest $3.86 $4.04 $2.85 $3.32Total of selected costs $12.33 $11.01 $10.60 $10.97

Margin(1) $19.15 $14.54 $27.67 $22.68Margin % 61% 57% 72% 67%

Continuing to Deliver Strong Margins(1)

29

Free cash flow/outspend is a non-GAAP measure. We define free cash flow/outspend as cash flows from operations before changes in working capital items less capital expenditures excluding acquisitions and divestitures. Free cash flow is not a measure of net income (loss) or cash flows as determined by U.S. GAAP. Management believes that these measures are useful to management and investors as a measure of a company’s ability to internally fund its capital expenditures and to service or incur additional debt. These measures eliminate the impact of certain items that management does not consider to be indicative of the Company’s performance from period to period. This presentation includes forward-looking free cash flow estimates for 2018; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to its most directly comparable forward-looking GAAP measure because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.

The following table reconciles historical net cash provided by operating activities as determined under U.S. GAAP to free cash flow (outspend) amounts for the periods presented.

(1) Capital expenditures are calculated as follows:

Free Cash Flow/Outspend Reconciliation to GAAP

30

In thousands 2010 2011 2012 2013 2014 2015 2016 2017Net cash provided by operating activities (GAAP) $653,167 $1,067,915 $1,632,065 $2,563,295 $3,355,715 $1,857,101 $1,125,919 $2,079,106 Exclude: Changes in working capital items 50,667 109,949 13,015 10,875 126,679 (228,622) 162,216 (1,415)Less: Capital expenditures (1) (1,229,851) (2,023,165) (3,038,405) (3,573,573) (4,811,647) (2,503,317) (1,074,345) (1,995,246)Free cash flow (outspend) (non-GAAP) ($526,017) ($845,301) ($1,393,325) ($999,403) ($1,329,253) ($874,838) $213,790 $82,445

In thousands 2010 2011 2012 2013 2014 2015 2016 2017Cash paid for capital expenditures $1,083,401 $2,035,642 $4,118,105 $3,739,431 $4,716,787 $3,080,255 $1,164,514 $1,953,198 Less: Total acquisitions (7,337) (200,931) (1,143,778) (268,200) (203,948) (60,975) (35,911) (40,007)Plus: Change in accrued capital expenditures 147,997 173,591 49,039 89,482 290,782 (519,949) (59,062) 79,222 Plus: Exploratory seismic costs 5,790 14,863 15,039 12,860 8,026 3,986 4,804 2,833 Capital expenditures $1,229,851 $2,023,165 $3,038,405 $3,573,573 $4,811,647 $2,503,317 $1,074,345 $1,995,246

Net debt is a non-GAAP measure. We define net debt as total debt less cash and cash equivalents as determined under U.S. GAAP. Management uses net debt to determine the Company’s outstanding debt obligations that would not be readily satisfied by its cash and cash equivalents on hand. We believe this metric is useful to analysts and investors in determining the Company’s leverage position since the Company has the ability to, and may decide to, use a portion of its cash and cash equivalents to reduce debt.

The following table reconciles total debt as determined under U.S. GAAP to net debt for the periods presented.

Net Debt Reconciliation to GAAP

31

In thousands 2010 2011 2012 2013 2014 2015 2016 2017Total debt (GAAP) $ 907,264 $ 1,236,909 $ 3,491,994 $ 4,650,889 $ 5,928,878 $ 7,117,788 $ 6,579,916 $ 6,353,691 Less: Cash and cash equivalents (7,916) (53,544) (35,729) (28,482) (24,381) (11,463) (16,643) (43,902)Net debt (non-GAAP) $ 899,348 $ 1,183,365 $ 3,456,265 $ 4,622,407 $ 5,904,497 $ 7,106,325 $ 6,563,273 $ 6,309,789

We use a variety of financial and operational measures to assess our performance. Among these measures isEBITDAX. We define EBITDAX as earnings (net income (loss)) before interest expense, income taxes, depreciation,depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and lossesresulting from the requirements of accounting for derivatives, non-cash equity compensation expense, and losses onextinguishment of debt. EBITDAX is not a measure of net income (loss) or net cash provided by operating activitiesas determined by GAAP.

Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performanceand compare the results of our operations from period to period without regard to our financing methods or capitalstructure. Further, we believe that EBITDAX is a widely followed measure of operating performance and may also beused by investors to measure our ability to meet future debt service requirements, if any. We exclude the items listedabove from net income (loss) and net cash provided by operating activities in arriving at EBITDAX because thoseamounts can vary substantially from company to company within our industry depending upon accounting methodsand book values of assets, capital structures and the method by which the assets were acquired.

EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) or net cashprovided by operating activities as determined in accordance with GAAP or as an indicator of a company’s operatingperformance or liquidity. Certain items excluded from EBITDAX are significant components in understanding andassessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as thehistoric costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX maynot be comparable to other similarly titled measures of other companies.

See the following page for reconciliations of our net income (loss) and net cash provided by operating activities toEBITDAX for the applicable periods.

EBITDAX Reconciliation to GAAP

32

The following tables provide reconciliations of our net income (loss) and net cash provided by operating activities to EBITDAX for the periods presented:

In thousands 2010 2011 2012 2013 2014 2015 2016 4Q 2017 2017

Net income (loss) $ 168,255 $ 429,072 $ 739,385 $ 764,219 $ 977,341 $ (353,668) $ (399,679) $ 841,914 $ 789,447 Interest expense 53,147 76,722 140,708 235,275 283,928 313,079 320,562 75,823 294,495

Provision (benefit) for income taxes 90,212 258,373 415,811 448,830 584,697 (181,417) (232,775) (608,317) (633,380)

Depreciation, depletion, amortization and accretion 243,601 390,899 692,118 965,645 1,358,669 1,749,056 1,708,744 476,732 1,674,901 Property impairments 64,951 108,458 122,274 220,508 616,888 402,131 237,292 27,552 237,370

Exploration expenses 12,763 27,920 23,507 34,947 50,067 19,413 16,972 2,802 12,393

Impact from derivative instruments:

Total (gain) loss on derivatives, net 130,762 30,049 (154,016) 191,751 (559,759) (91,085) 67,099 (8,417) (90,432)

Total cash received (paid), net 35,495 (34,106) (45,721) (61,555) 385,350 69,553 89,522 15,867 32,401

Non-cash (gain) loss on derivatives, net 166,257 (4,057) (199,737) 130,196 (174,409) (21,532) 156,621 7,450 (58,031)

Non-cash equity compensation 11,691 16,572 29,057 39,890 54,353 51,834 48,097 13,377 45,868

Loss on extinguishment of debt -- -- -- -- 24,517 -- 26,055 554 554

EBITDAX (non-GAAP) $ 810,877 $ 1,303,959 $ 1,963,123 $ 2,839,510 $ 3,776,051 $ 1,978,896 $ 1,881,889 $ 837,887 $ 2,363,617

In thousands 2010 2011 2012 2013 2014 2015 2016 4Q 2017 2017

Net cash provided by operating activities $ 653,167 $ 1,067,915 $ 1,632,065 $ 2,563,295 $ 3,355,715 $ 1,857,101 $ 1,125,919 $ 731,125 $ 2,079,106 Current income tax provision (benefit) 12,853 13,170 10,517 6,209 20 24 (22,939) (7,781) (7,781)Interest expense 53,147 76,722 140,708 235,275 283,928 313,079 320,562 75,823 294,495 Exploration expenses, excluding dry hole costs 9,739 19,971 22,740 25,597 26,388 11,032 12,106 2,783 12,217 Litigation Settlement -- -- -- -- -- -- -- (59,600) (59,600)Gain on sale of assets, net 29,588 20,838 136,047 88 600 23,149 304,489 54,420 55,124 Tax benefit (deficiency) from stock-based compensation 5,230 -- 15,618 -- -- 13,177 (9,828) -- --Other, net (3,513) (4,606) (7,587) (1,829) (17,279) (10,044) (10,636) 723 (8,529)Changes in assets and liabilities 50,666 109,949 13,015 10,875 126,679 (228,622) 162,216 40,394 (1,415)EBITDAX (non-GAAP) $ 810,877 $ 1,303,959 $ 1,963,123 $ 2,839,510 $ 3,776,051 $ 1,978,896 $ 1,881,889 $ 837,887 $ 2,363,617

EBITDAX Reconciliation to GAAP

33

ADJUSTED Earnings Reconciliation to GAAP

34

Our presentation of adjusted earnings and adjusted earnings per share that exclude the effect of certain items are non-GAAP financial measures. Adjusted earnings and adjusted earnings per share represent earnings and diluted earnings per share determined under U.S. GAAP without regard to non-cash gains and losses on derivative instruments, property impairments, losses on certain litigation settlements, gains and losses on asset sales, losses on extinguishment of debt and the impact of U.S. tax reform legislation. Management believes these measures provide useful information to analysts and investors for analysis of our operating results. In addition, management believes these measures are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis without regard to an entity’s specific derivative portfolio, impairment methodologies, and property dispositions. Adjusted earnings and adjusted earnings per share should not be considered in isolation or as a substitute for earnings or diluted earnings per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following table reconciles earnings and diluted earnings per share as determined under U.S. GAAP to adjusted earnings and adjusted diluted earnings per share for the periods presented.

4Q 2017 4Q 2016 YTD 2017 YTD 2016

In thousands, except per share data $ Diluted EPS $ Diluted EPS $ Diluted EPS $ Diluted EPS

Net income (loss) (GAAP) $ 841,914 $ 2.25 $ 27,670 $ 0.07 $ 789,447 $ 2.11 $(399,679) $ (1.08)Adjustments:

Non-cash (gain) loss on derivatives 7,450 51,612 (58,031) 156,621 Property impairments 27,552 34,564 237,370 237,292

Litigation settlement 59,600 -- 59,600 --

Gain on sale of assets (54,420) (201,315) (55,124) (304,489)Loss of extinguishment of debt 554 26,055 554 26,055 Total tax effect of adjustments(1) (15,335) 33,998 (69,358) (42,448)Tax benefit from US tax reform legislation (713,655) -- (713,655) --

Total adjustments, net of tax (688,254) (1.84) (55,086) (0.14) (598,644) (1.60) 73,031 0.20 Adjusted net income (loss) (Non-GAAP) $ 153,660 $ 0.41 $ (27,416) $ (0.07) $ 190,803 $ 0.51 $(326,648) $ (0.88)

Weighted average diluted shares outstanding 373,764 370,539 373,768 370,380Adjusted diluted net income (loss) per share (Non-GAAP) $0.41 $ (0.07) $0.51 ($0.88)

1. Computed by applying a combined federal and state statutory tax rate of 38% in effect for 2017 and 2016 to the pre-tax amount of adjustments associated with our operations in the United States other than the tax benefit adjustment related to US tax reform.

Cash G&A Reconciliation to GAAP

35

Our presentation of cash general and administrative (“G&A”) expenses per Boe is a non-GAAP measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses, expressed on a per-Boe basis. We report and provide guidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than, total G&A per Boe as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies.

The following table reconciles total G&A per Boe as determined under U.S. GAAP to cash G&A per Boe for the periods presented.

2015 2016 4Q 2017 2017 2018 GuidanceTotal G&A per Boe (GAAP) $2.34 $2.14 $2.30 $2.16 $1.70 - $2.30Less: Non-cash equity compensation per Boe ($0.64) ($0.61) ($0.50) ($0.52) ($0.45) – ($0.55)Cash G&A per Boe (non-GAAP) $1.70 $1.53 $1.80 $1.64 $1.25 - $1.75

Calculation of Return on Capital Employed (ROCE)

36

In thousands, except per share data 2010 2011 2012 2013 2014 2015 2016 2017

Net income (loss) $ 168,255 $ 429,072 $ 739,385 $ 764,219 $ 977,341 $ (353,668) $ (399,679) $ 789,447 Impact from derivative instruments:

Total (gain) loss on derivatives, net 130,762 30,049 (154,016) 191,751 (559,759) (91,085) 67,099 (90,432)Total cash received (paid), net 35,495 (34,106) (45,721) (61,555) 385,350 69,553 89,522 32,401

Non-cash (gain) loss on derivatives, net 166,257 (4,057) (199,737) 130,196 (174,409) (21,532) 156,621 (58,031)

Provision (benefit) for income taxes 90,212 258,373 415,811 448,830 584,697 (181,417) (232,775) (633,380)

Non-cash equity compensation 11,691 16,572 29,057 39,890 54,353 51,834 48,097 45,868

Interest expense 53,147 76,722 140,708 235,275 283,928 313,079 320,562 294,495

Loss on extinguishment of debt -- -- -- -- 24,517 -- 26,055 554

Adjusted EBIT $ 489,562 $ 776,682 $ 1,125,224 $ 1,618,410 $ 1,750,427 $ (191,704) $ (81,119) $ 438,953

Total equity $ 1,208,155 $2,308,126 $ 3,163,699 $ 3,953,118 $ 4,967,844 $ 4,668,900 $4,301,996 $5,131,203Total long term debt 907,264 1,236,909 3,491,994 4,650,889 5,928,878 7,117,788 6,579,916 6,353,691Capital employed $ 2,115,419 $3,545,035 $6,655,693 $ 8,604,007 $10,896,722 $11,786,688 $ 10,881,912 $11,484,894

ROCE 23.1% 21.9% 16.9% 18.8% 16.1% -1.6% -0.7% 3.8%

The following table shows the calculation of ROCE:

investor update february 2018 final

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