Scotia Howard Weil Energy Conference March 2017

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, 2016, 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

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

~1.78 Million Net Reservoir Acres

NORTH

SOUTH

Continental Resources Celebrating 50 Years of Organic Growth

3

MT Bakken

ND Bakken

Arkoma Woodford

Anadarko Woodford

SCOOP Woodford

SCOOP Springer

STACK Meramec

Cedar Hills

Boe

pd

BAKKEN

SCOOP

STACK

Play Net Acres

Bakken: ~848,000

STACK:

Meramec ~200,000

Woodford ~185,000

SCOOP:

Springer ~200,000

Woodford ~346,000

250,000

225,000

200,000

175,000

150,000

125,000

100,000

75,000

50,000

25,000

2017

Performance Taken to New Level Last 2 Years Structural Improvements Benefiting 2017 and Beyond

$5.49 $5.69 $5.58 $4.30 $3.65

$2.38 $2.07 $2.06 $1.70

$1.53

$7.87 $7.76 $7.64

$6.00 $5.18

$0

$2

$4

$6

$8

$10

2012 2013 2014 2015 2016

$/B

oe

Production and Cash G&A Costs

Cash G&A

1. See “Cash G&A Reconciliation to GAAP“ on slide 23 for a reconciliation of GAAP Total G&A per Boe to Cash G&A per Boe, which is a non-GAAP measure 2. Capital efficiency based on reserves developed per dollar invested; average net revenue interest of 82% assumed for net capital efficiency

Production Expense

470 506 711

1,110

1,416

41 47 54

104

149

0

40

80

120

160

0200400600800

1,0001,2001,4001,600

2012 2013 2014 2015 2016

Net

Boe

/$1,

000(2

)

EUR Per Operated Well

• Capital efficiency(2) UP ~175% • EUR/operated well UP ~100% • Production expense & cash

G&A(1) DOWN ~32%

Boe/$1k Boe/$1k Boe/$1k

Boe/$1k

Boe/$1k

(1)

2016 vs 2014

Key Drivers

MB

oe

(1)

4

• Added STACK • Moved to Bakken core • Enhanced completions • Operating efficiencies

Boe/$1k

2017: Disciplined Growth Targeting 20%+ Increase in Production by Year End

5

$1.95 billion capital budget (~90% D&C)

• 20 rigs vs. 19 rigs in 2016 • ~11 stim crews vs. ~4 stim crews in 2016 • Over 2X more operated completions than 2016

Oil-weighted production growth

• Targeting 250,000 to 260,000 Boepd 2017 exit rate • 82% of D&C capex allocated to Bakken & STACK (75% oil)

No new debt • Capital budget cash flow neutral at $55 WTI and $3.14 gas • Targeting over $600 million of additional non-strategic

asset sales in 2017

Momentum carries into 2018

• ~72 Bakken stimulated wells waiting on first production at year-end 2017

• Targeting 290,000 to 310,000 Boepd 2018 exit rate

2017 Capital Focused on High ROR Oil Plays

Play Capital ($ in MM)

% of D&C Budget ROR % Oil

Est. Total % Liquids

Bakken DUCs $550 32% 100%+ 80% 90% Bakken Drilling $490 28% ~40% 80% 90% STACK $375 22% 100%+ 60% 70% SCOOP $245 14% ~55% 20% 55% NW Cana $60 4% 100%+ 2% 20% Total D&C Program (weighted avg) $1,720 100% - 58% 73%

Non-D&C Capital (land, facilities, other) $230 - - -

Total 2017 Capital $1,950 - - -

1. Inclusive of capital for outside operated activity, except for Bakken DUCs 2.At $55 WTI and $3.50 gas, see footnote 1 on slide 11 3.Based upon 2-stream oil volumes at the wellhead 4.Based upon theoretical NGL recoveries after processing

5.ROR is on the incremental cost forward cost of completion 6.STACK ROR is based on STACK over-pressured oil wells 7.SCOOP ROR is based on SCOOP Woodford condensate wells 8.NW Cana as part of the JDA with SK E&S

(1) (2) (3) (4)

(5)

(6)

(7)

(8)

6

82% of D&C capex allocated to Bakken and STACK (75% oil)

2017 Sets Up Multi-Year Double-Digit Growth

7

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

450,000

2012 2013 2014 2015 2016 2017E 2018E 2019E 2020E

STACKSCOOPBakkenLegacy

9%

~225,000 (Midpoint)

Production guidance:

• 2017 exit rate: 250,000 to 260,000 Boe per day

• 2018 exit rate: 290,000 to 310,000 Boe per day

• Oil production growing to 60%-65% of total production

Annual Production Chart

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

450,000

500,000

4Q 2016 4Q 2017E 4Q 2018E 4Q 2019E 4Q 2020E

STACKSCOOPBakkenLegacy

~210,000

~255,000 (Exit rate)

Fourth Quarter Production Chart

Boe

per

day

Boe p

er da

y

Completion Technology Continues to Increase Well Performance in all Plays

8

0

40,000

80,000

120,000

0 50 100 150 200

Cum

Boe

Days

Bakken

90 days 35% higher than

type curve

0

50,000

100,000

150,000

200,000

0 50 100 150 200

Cum

Boe

Days

SCOOP Woodford Oil

SCOOP Enhanced completions SCOOP Offsets SCOOP Enhanced Type Curve (1,340 MBoe)

0

150,000

300,000

450,000

0 50 100 150 200

Cum

Boe

Days

SCOOP Woodford Condensate SCOOP Enhanced CompletionsSCOOP OffsetsSCOOP Enhanced Type Curve (2,300 MBOE)

180 days 45% Uplift

180 days 30% Uplift

Bakken Enhanced completions average Bakken Enhanced Type Curve (980 MBoe)

• Higher proppant loads

• Increased fluid volumes

• Shorter stage lengths

• More aggressive flowbacks and lift

200,000 net acres • ~98% in over-pressured window

• ~40% oil, ~30% liquids-rich, ~30% gas

~1,500 potential net unrisked drilling locations

7 completions announced 4Q16 • 1,600–2,500 Boepd 24-hr IPs

• 55%-73% oil

As of late February, 35 operated wells in progress 12 rigs drilling (7 Meramec, 5 Woodford)

Wells Drilling / Completing

CLR Leasehold CLR Rigs Industry Rigs Industry Meramec well CLR Meramec producing wells CLR Meramec wells drilling / completing

Over-Pressured

Normally-Pressured Intermediate pipe required

STACK Expansion Continues with Excellent Results

9

STACK 2017 Drilling Program Focused on Density Development and Play Expansion ~47,000 net acres under development in oil window

• ~55 operated units

• ~60% operated working interest

6 units scheduled for 2017

• 5 units in oil window

• 1 unit in condensate window

• Testing 4 to 6 wells per zone

Unit efficiencies further uplift economics

Density Activity

De-risked portion of over-pressured oil

window

6 units scheduled

for 2017

CLR Leasehold CLR Rigs Industry Rigs Industry Meramec well CLR Meramec producing wells CLR Meramec wells drilling / completing

10

0%

20%

40%

60%

80%

100%

$30 $40 $50 $60 $70

RO

R

WTI Oil Price, $/BBL

STACK Over-Pressured Oil $9.0MM Budget 2017$7.8MM Budget

$9.0MM standalone CWC $7.8MM density CWC

Target EUR: 1,700 MBOE Avg. Lateral: 9,800’

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. $3.50 gas is used for oil price sensitivities and $55 WTI is used for gas price sensitivities. The description of the ROR calculation applies to any ROR reference appearing in this presentation.

100

1000

10000

0 30 60 90 120

Boe

pd

Days on Production

710’

MICROSEISMIC SURVEY

1 Mile

Outstanding First STACK Density Test in Meramec Over-Pressured Oil Window

660’ 175’

1,320’

New Well Parent Well

Hunton

Upper Meramec

Middle Meramec

Osage Woodford

Lower Meramec

21,354 Boe per day (70% oil) from 8 Meramec wells (combined peak 24-hour rates)

Efficiency gains: • 30% reduction in CWC ($7.8 million)

• 36% reduction in drill time (25 days)

CLR: Ludwig Density

Ludwig Daily Production(1)

1. Normalized to 9,800’ lateral

Parent well 7 New wells 1,700 MBoe type curve

11

SCOOP Woodford Condensate Enhanced Stimulations Uplift EURs Another 15%

12

EUR 2,300 MBoe per well (7,500’ lateral) • Up from 2,000 MBoe EUR 80% ROR(1) for $10.3 million CWC Two completions announced 4Q 2016: • 3,547 and 3,463 Boepd 24-hr IPs • 26% and 29% oil • 3,220 and 3,160 psi flowing casing pressure

1. Assumes $55 oil and $3.50 gas. 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. $3.50 gas is used for oil price sensitivities and $55 WTI is used for gas price sensitivities. The description of the ROR calculation applies to any ROR reference appearing in this presentation.

Peppered Ranch

Boatright

12 Miles CLR Leasehold

Woodford HZ Producing Well

CLR Enhanced Completion

Gas Condensate Oil

0%

20%

40%

60%

80%

100%

$2 $3 $4

RO

R

Gas Price, $/MCF

SCOOP Woodford Condensate

$10.3MM Budget 2017 (2,300 MBOE)

~80% ROR

Target EUR: 2,300 MBOE Avg. Lateral: 7,500’

MB, TF1, TF2, TF3

MB, TF1, TF2

MB & TF1

MB & TF1

MB or TF1

MB or TF1

Charolais North 1-31H1

IP: 2,761 Boe

Brangus North 1-2H2

IP: 2,493 Boe

Rath Federal 5-22H

IP: 2,395 Boe

Corsican Federal 1-15H

IP: 1,836 Boe

Holstein Federal 13-25H

IP: 2,718 Boe Maryland 2-16H

IP: 1,264 Boe

Nashville 2-21H IP: 1,417 Boe

CLR Leasehold

CLR Larger Enhanced Completion

50 Miles

Three Record CLR Bakken Wells in Last Two Quarters

13

Note: Larger enhanced completions defined by 7 initial unit wells with greater than 720 lb/ft proppant 1. Normalized to 9,800’ lateral

Larger stimulations and more aggressive flowback resulted in record 30-day rates: • Brangus North, Holstein Federal & Rath Federal

Wells performing above 980 MBoe type curve(1)

(initial wells on unit)

Larger enhanced completions well locations

0

20,000

40,000

60,000

80,000

100,000

120,000

0 20 40 60 80 100

Cum

Boe

Normalized Days

90 days 35% higher than type

curve

14

~148 Bakken wells to be completed in 2017 (90% drilled but uncompleted) Average 7 operated stimulation crews ~72 additional wells stimulated at year-end 2017 with first sales in 2018

Harvesting Uncompleted Bakken Wells Underway

0%

20%

40%

60%

80%

100%

$40 $50 $60 $70

RO

R

WTI Oil Price, $/BBL

Bakken

$4.9MM DUC Budget 2017(980 MBOE)

$7MM Drilling Budget 2017(920 MBOE)

~40% ROR

Drilling Target EUR: 920 MBOE DUC EUR: 980 MBOE Avg. Lateral: 9,800’

Note: 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. $3.50 gas is used for oil price sensitivities and $55 WTI is used for gas price sensitivities. The description of the ROR calculation applies to any ROR reference appearing in this presentation. 1.$4.9 MM gross cost forward incremental completion cost

~100% ROR

(1)

CLR Leasehold

CLR YE 2016 uncompleted well

50 Miles

Uncompleted well locations

North Dakota Pipeline Authority and CLR estimates

-

500

1,000

1,500

2,000

2,500

3,000

3,500

2009 2010 2011 2012 2013 2014 2015 2016 2017EST

Local Refining Pipeline Rail Bakken Production

Thou

sand

Bop

d

Bakken Takeaway Capacity

Bakken Differentials Improving with Added Pipeline Takeaway Capacity

15

More than 90% of CLR Bakken barrels on pipe

With completion of DAPL, pipeline takeaway capacity should exceed production in 2017 Basin differentials may drop by $2 or more

Pi

pe

Rai

l

Low Costs(1) Competitively Positions CLR in Any Environment

16

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, 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 19 for additional details on the method for calculating margin.

2. See “Cash G&A Reconciliation to GAAP“ on slide 23 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.)

$6.89 $5.87 $6.13 $5.49 $5.69 $5.58 $4.30 $3.65

$2.19 $2.35 $2.36 $2.38 $2.07 $2.06 $1.70 $1.53

$2.95 $4.47 $5.82 $5.58 $6.02 $5.54 $2.47 $1.79

$1.72 $3.34 $3.40 $3.95 $4.74 $4.49

$3.86 $4.04

$30.93

$43.32

$54.74

$48.59

$53.52 $48.86

$19.15

$14.54

$44.68

$59.35

$72.45 $65.99

$72.04 $66.53

$31.48 $25.55

$0

$10

$20

$30

$40

$50

$60

$70

$80

2009 2010 2011 2012 2013 2014 2015 2016

69% 73%

76% 74% 74%

73% $11.01 per Boe

Production Expense Cash G&A(2) Production/Severance Tax & Other Interest Margin(1)

61% 57% Avg.

Rea

lized

$/B

oe(3

)

• Depth and quality of inventory has never been better

• Capital efficiencies at all-time high

• Production expense and cash G&A among the lowest in the E&P space

• Debt reduced by ~$600 million in 2016

• ~20% projected production growth (exit-rate 2017 over 4Q 2016)

• 82% of 2017 D&C capex focused on oil-weighted Bakken and STACK

• Targeting debt reduction by another ~$600 million in 2017 through non-

strategic asset sales

Continental Resources - In Closing

17

APPENDIX

18

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, 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 35 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 37 for a reconciliation of GAAP Total G&A per Boe to Cash G&A per Boe, which is a non-GAAP measure.

2009 2010 2011 2012 2013 2014 2015 4Q 2016 2016

Realized oil price ($/Bbl) $54.44 $70.69 $88.51 $84.59 $89.93 $81.26 $40.50 $42.23 $35.51

Realized natural gas price ($/Mcf) $2.95 $4.26 $4.87 $3.73 $4.87 $5.40 $2.31 $2.70 $1.87 Oil production (Bopd) 27,459 32,385 45,121 68,497 95,859 121,999 146,622 116,486 128,005 Natural gas production (Mcfpd) 59,194 65,598 100,469 174,521 240,355 313,137 450,558 560,251 533,442 Total production (Boepd) 37,324 43,318 61,865 97,583 135,919 174,189 221,715 209,861 216,912

EBITDAX ($000's)(2) $450,648 $810,877 $1,303,959 $1,963,123 $2,839,510 $3,776,051 $1,978,896 $652,382 $1,881,889 Key Operational Statistics (per Boe)(3) Average oil equivalent price (excludes derivatives) $44.68 $59.35 $72.45 $65.99 $72.04 $66.53 $31.48 $30.64 $25.55

Production expense $6.89 $5.87 $6.13 $5.49 $5.69 $5.58 $4.30 $3.60 $3.65

Production tax and other $2.95 $4.47 $5.82 $5.58 $6.02 $5.54 $2.47 $1.98 $1.79

Cash G&A(4) $2.19 $2.35 $2.36 $2.38 $2.07 $2.06 $1.70 $2.21 $1.53 Interest $1.72 $3.34 $3.40 $3.95 $4.74 $4.49 $3.86 $3.92 $4.04

Total of selected costs $13.75 $16.03 $17.71 $17.40 $18.52 $17.67 $12.33 $11.71 $11.01 Margin(1) $30.93 $43.32 $54.74 $48.59 $53.52 $48.86 $19.15 $18.93 $14.54 Margin % 69% 73% 76% 74% 74% 73% 61% 62% 57%

Continuing to Deliver Strong Margins(1)

19

We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX. 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 losses resulting from the requirements of accounting for derivatives, non-cash equity compensation expense, and losses on extinguishment of debt. EBITDAX is not a measure of net income or net cash provided by operating activities as determined by GAAP. Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. Further, we believe that EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. We exclude the items listed above from net income (loss) and net cash provided by operating activities in arriving at EBITDAX because those amounts can vary substantially from company to company within our industry depending upon accounting methods and 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 cash provided by operating activities as determined in accordance with GAAP or as an indicator of a company’s operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not 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 to EBITDAX for the applicable periods.

EBITDAX Reconciliation to GAAP

20

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 2009 2010 2011 2012 2013 2014 2015 4Q 2016 2016

Net income (loss) $ 71,338 $ 168,255 $ 429,072 $ 739,385 $ 764,219 $ 977,341 $ (353,668) $ 27,670 $ (399,679) Interest expense 23,232 53,147 76,722 140,708 235,275 283,928 313,079 75,613 320,562

Provision (benefit) for income taxes 38,670 90,212 258,373 415,811 448,830 584,697 (181,417) 26,478 (232,775)

Depreciation, depletion, amortization and accretion 207,602 243,601 390,899 692,118 965,645 1,358,669 1,749,056 388,321 1,708,744

Property impairments 83,694 64,951 108,458 122,274 220,508 616,888 402,131 34,564 237,292

Exploration expenses 12,615 12,763 27,920 23,507 34,947 50,067 19,413 8,246 16,972

Impact from derivative instruments:

Total (gain) loss on derivatives, net 1,520 130,762 30,049 (154,016) 191,751 (559,759) (91,085) 45,331 67,099

Total cash received (paid), net 569 35,495 (34,106) (45,721) (61,555) 385,350 69,553 6,281 89,522

Non-cash (gain) loss on derivatives, net 2,089 166,257 (4,057) (199,737) 130,196 (174,409) (21,532) 51,612 156,621

Non-cash equity compensation 11,408 11,691 16,572 29,057 39,890 54,353 51,834 13,823 48,097

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

EBITDAX (non-GAAP) $ 450,648 $ 810,877 $ 1,303,959 $ 1,963,123 $ 2,839,510 $ 3,776,051 $ 1,978,896 $ 652,382 $ 1,881,889

In thousands 2009 2010 2011 2012 2013 2014 2015 4Q 2016 2016

Net cash provided by operating activities $ 372,986 $ 653,167 $ 1,067,915 $ 1,632,065 $ 2,563,295 $ 3,355,715 $ 1,857,101 $ 262,031 $ 1,125,919 Current income tax provision (benefit) 2,551 12,853 13,170 10,517 6,209 20 24 (22,941) (22,939) Interest expense 23,232 53,147 76,722 140,708 235,275 283,928 313,079 75,613 320,562 Exploration expenses, excluding dry hole costs 6,138 9,739 19,971 22,740 25,597 26,388 11,032 3,613 12,106 Gain on sale of assets, net 709 29,588 20,838 136,047 88 600 23,149 201,315 304,489 Tax benefit (deficiency) from stock-based compensation 2,872 5,230 -- 15,618 -- -- 13,177 (368) (9,828) Other, net (3,890) (3,513) (4,606) (7,587) (1,829) (17,279) (10,044) (1,613) (10,636) Changes in assets and liabilities 46,050 50,666 109,949 13,015 10,875 126,679 (228,622) 134,732 162,216 EBITDAX (non-GAAP) $ 450,648 $ 810,877 $ 1,303,959 $ 1,963,123 $ 2,839,510 $ 3,776,051 $ 1,978,896 $ 652,382 $ 1,881,889

EBITDAX Reconciliation to GAAP

21

ADJUSTED Earnings Reconciliation to GAAP

22

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, gains and losses on asset

sales and losses on extinguishment of debt. 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 tables

reconcile 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 2016 4Q 2015 2016 2015

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

Net income (loss) (GAAP) $ 27,670 $ 0.07 $ (139,677) $ (0.38) $(399,679) $ (1.08) $(353,668) $ (0.96)

Adjustments:

Non-cash (gain) loss on derivatives 51,612 4,479 156,621 (21,532)

Property impairments 34,564 81,001 237,292 402,131

Gain on sale of assets (201,315) (218) (304,489) (23,149)

Loss on extinguishment of debt 26,055 - 26,055

Total tax effect of adjustments 33,998 (32,229) (42,448) (119,307)

Total adjustments, net of tax (55,086) (0.14) 53,033 0.15 73,031 0.20 238,143 0.65

Adjusted net income (loss) (Non-GAAP) $ (27,416) $ (0.07) $ (86,644) $ (0.23) $ (326,648) $ (0.88) $ (115,525) $ (0.31)

Weighted average diluted shares outstanding 370,539 369,662 370,380 369,540

Adjusted diluted net income (loss) per share (Non-GAAP) $ (0.07) $ (0.23) $ (0.88) $ (0.31)

Cash G&A Reconciliation to GAAP

23

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 and corporate relocation 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.

2009 2010 2011 2012 2013 2014 2015 4Q 2016 2016 2017 Guidance Total G&A per Boe (GAAP) $3.03 $3.09 $3.23 $3.42 $2.91 $2.92 $2.34 $2.93 $2.14 $2.10 - $2.70 Less: Non-cash equity compensation per Boe ($0.84) ($0.74) ($0.73) ($0.82) ($0.80) ($0.86) ($0.64) ($0.72) ($0.61) ($0.60) – ($0.70)

Less: Relocation expenses per Boe -

- ($0.14) ($0.22) ($0.04)

-

- -

- -

Cash G&A per Boe (non-GAAP) $2.19 $2.35 $2.36 $2.38 $2.07 $2.06 $1.70 $2.21 $1.53 $1.50 - $2.00