Investor Update February 2017 NYSE: CLR Forward Looking Information - - PowerPoint PPT Presentation

NYSE: CLR

Investor Update

February 2017

Forward‐Looking Information

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

• f 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

• f 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.

2

2017: Disciplined Growth

Targeting 20%+ Increase in Production by Year End

$1.95 billion capital budget ($1.72 billion D&C)

• Targeting 250,000 to 260,000 Boepd 2017 exit rate
• 20 rigs vs. 19 rigs in 2016
• Over 2X more operated completions than 2016
• 7 Bakken stimulation crews on average during year

Oil‐weighted production growth

• 82% of D&C capex allocated to Bakken and STACK (75% oil)
• ~148 Bakken gross operated wells with first production
• STACK activity focused on density drilling

No new debt

• Capital budget cash flow neutral at $55 WTI and $3.14 gas
• Continued debt reduction from non‐strategic asset sales

Momentum carries into 2018

• Exit 2017 with approximately 72 Bakken stimulated wells

waiting on first production

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

3

2016 Achievements Fuel 2017 Growth

4 Over‐pressured STACK becomes proven catalyst for growth

• Adds up to 35% to CLR’s net unrisked resource potential
• Delivering some of the best and most repeatable returns in the country
• Full‐field development already underway in portion of the over‐pressured oil window

Reduced debt by over $600 million since peak in 2016 through non‐strategic assets sales Enhanced completions improving well performance in all plays

• SCOOP Woodford condensate: Boosting EURs by ~35% and early production rates up to 45%
• SCOOP Woodford oil: Boosting EURs and early production rates by ~30%
• Bakken: Larger completions delivering record results for CLR

Quality of assets increased proved reserves 4% YoY despite 15% decline in SEC oil prices

• 1.27 billion Boe, up from 1.23 billion Boe at year‐end 2015

Began harvesting Bakken uncompleted well inventory

• Over 100% cost forward ROR(1) inventory: 187 drilled‐wells in inventory; target EUR of 980 Mboe
• Ramping up activity: Currently at 5 completion crews, increasing to 8 by mid‐May
• 1. See footnote 1 on slide 9 for a description of how ROR is calculated

2016 Structural Improvements Carry Into 2017

5

$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

$/Boe

Production and Cash G&A Costs

Cash G&A

• 1. 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
• 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 20 40 60 80 100 120 140 160

200 400 600 800 1,000 1,200 1,400 1,600

2012 2013 2014 2015 2016 Net Boe/$1,000(2)

EUR Per Operated Well

• Combined production and

cash G&A(1) costs DOWN ~32%

• Bakken production expense

down ~19%

• Continued low operating costs

projected in 2017

• EUR per operated well UP ~100%
• Capital efficiency(2) (Boe/$

invested) UP ~175%

Boe/$1,000 Boe/$1,000 Boe/$1,000 Boe/$1,000 Boe/$1,000

(1)

From 2014 to 2016: From 2014 to 2016:

MBoe

(1)

2017 Guidance Reflects 2016 Achievements

Production & Capital Full‐Year 2016 Performance 2017 Guidance as

• f 2/22/17

Production (Boe per day) 216,912 220,000 – 230,000 Capital expenditures (non‐acquisition) $1.07 billion $1.95 billion

Operating Expenses

Production expense ($ per Boe) $3.65 $3.50 ‐ $4.00 Production tax (% of oil & gas revenue) 7.0% 6.75% ‐ 7.25% Cash G&A expense(1) ($ per Boe) $1.53 $1.50 ‐ $2.00 Non‐cash equity compensation ($ per Boe) $0.61 $0.60 ‐ $0.70 DD&A ($ per Boe) $21.54 $19.00 ‐ $22.00

Average Price Differentials

NYMEX WTI crude oil ($ per barrel of oil) $(7.33) ($6.50) ‐ ($7.50) Henry Hub natural gas(2) ($ per Mcf) $(0.61) $0.10 ‐ ($0.40)

• 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 $2.10 to $2.70 per Boe. See “Cash G&A Reconciliation to GAAP“ on slide 37 for a reconciliation of 2016 GAAP total G&A per Boe to cash G&A per Boe.

• 2. Includes natural gas liquids production in differential range

6

2017 Capital Focused on High ROR Oil Plays

$ in MM

Capital % 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 ‐ ‐ ‐

7

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 9 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)

BAKKEN

~848,000 NET ACRES

STACK MERAMEC/OSAGE

~200,000 NET ACRES

SCOOP WOODFORD

~346,000 NET ACRES

SCOOP SPRINGER

~200,000 NET ACRES

~1.78 Million Net Reservoir Acres

STACK WOODFORD

~185,000 NET ACRES

ROR (%)

Source: Bank of America Merrill Lynch, December 2016

0% 20% 40% 60% 80% 100% 120% 140% 160%

Meramec ‐ Overpressured oil Bakken ‐ Core Midland Northern Wolfcamp A & B Tier I Wattenberg ‐ Core Marcellus ‐ NE PA Delaware Wolfcamp Tier I Meramec ‐ Oil Lower Spraberry Delaware ‐ Bone Spring & Leonard Utica ‐Dry Gas SCOOP ‐ Condensate Marcellus‐ SW Dry gas‐ Non Core Marcellus ‐ SW Wet Gas and Super Rich Central Platform ‐ Permian SCOOP ‐ Oil Canyon Lime Delaware Wolfcamp Tier II Meramec‐ Wet Gas Powder River Basin Utica‐Wet gas Haynesville / East Texas Eastern Midland Wolfcamp Southern Midland Wolfcamp Eagle Ford ‐ Tier 3 Eagle Ford ‐ Tier 2 Cana Midland Wolfcamp D Fayetteville‐Tier 1 Wattenberg ‐ Noncore Eaglebine Barnett Bakken ‐ Non‐core Uinta Basin and Greater Natural Buttes Delaware Wolfcamp Tier 3 Fayetteville ‐Tier 2 Delaware ‐ Brushy Canyon Fayetteville ‐ Tier 3

8

82% of 2017 D&C Capital Allocated to Top Two ROR Oil Plays in the Country

Single Well Rate of Return @ $60 WTI & $3.50 HH 82% of CLR D&C capital

0% 20% 40% 60% 80% 100% $2 $3 $4 ROR Gas Price, $/MCF

SCOOP Woodford Condensate

$10.3MM Budget 2017 (2,300 MBOE)

~80% ROR

Target EUR: 2,300 MBOE

• Avg. Lateral: 7,500’

0% 20% 40% 60% 80% 100% $2 $3 $4 ROR Gas Price, $/MCF

STACK Woodford (JDA)(3)

$13.0MM Budget 2017

100+% ROR

Target EUR: 2,150 MBOE

• Avg. Lateral: 9,800’

CLR Assets Deliver Excellent Rates of Return(1)

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. 2. $4.9 MM gross cost forward incremental completion cost 3. JDA economics factor in a ~50% carry from JDA participant.

0% 20% 40% 60% 80% 100% $40 $50 $60 $70 ROR WTI Oil Price, $/BBL

STACK Over-Pressured Oil

$9.0MM Budget 2017 Target EUR: 1,700 MBOE

• Avg. Lateral: 9,800’

100+% ROR

9

0% 20% 40% 60% 80% 100% $40 $50 $60 $70 ROR 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’

~100+% ROR

2017 Sets Up Multi‐Year Double‐Digit Growth

10

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 STACK SCOOP Bakken Legacy

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

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

STACK SCOOP Bakken Legacy ~210,000 ~255,000 (Exit rate)

Fourth Quarter Production Chart

Boeper day Boeper day

Woodford Shale Thickness 50 ft 100 ft > 200 ft CLR Leasehold

SCOOP SCOOP

STACK STACK

11

SCOOP & STACK

Leading Acreage Positions in Top‐Tier Plays

~931,000 Net Reservoir Acres

STACK STACK Geologic Age Atoka Sands Morrow Sands Springer Sands Springer Shale Meramec Osage/Sycamore Woodford Hunton Limestone

Pennsylvanian Mississippian Devonian Silurian Formation

~346,000 ~200,000 ‐ ‐ SCOOP ~200,000 ~185,000 ‐ STACK

TARGETED RESERVOIRS

12

CLR’s Strategic STACK Position

Wells Drilling / Completing

200,000 net acres in Meramec

• ~64,000 net acres added since

August 2015

~98% of acreage in over‐ pressured window

• ~40% oil, ~30% liquids‐rich, ~30%

gas

Project ~1,500 potential net unrisked drilling locations

• Up to 12 wells per 1,280‐acre unit
• Targeting 2 Meramec zones on

average, 1 Woodford zone

Current activity

• 7 rigs drilling Meramec, 5 rigs

drilling Woodford

• 35 operated wells in progress

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

13

STACK Value Increasing as Expansion Continues

Wells Drilling / Completing Over‐pressured oil window completions:

• 2,463 Boepd (73% oil) Roth 1‐26‐35XH
• 2,263 Boepd (68% oil) Glenwood Pearl 1‐19H
• 2,239 Boepd (71% oil) Zella 1‐4‐9XH
• 2,152 Boepd (62% oil) Homsey 1‐22H
• 1,929 Boepd (72% oil) Laura FIU 1‐4H
• 1,822 Boepd (55% oil) Sherry Lanelle Fed 1‐31‐30XH
• 1,604 Boepd (70% oil) Wintersole 1‐4‐33‐28XH
• Laterals ranged from 4,575 to 10,500
• Flowing casing pressures ranged from 2,850 to

3,925 psi

Over‐pressured gas window completions:

• 22.2 MMcfpd & 49 Bopd Andersons Half 1‐30‐19XH
• 20.1 MMcfpd & 84 Bopd Eichelberger 1‐28‐21XH
• 20.1 MMcfpd & 78 Bopd Edith Mae 1‐24‐25XH
• Flowing casing pressures ranged from 5,900 to

7,500 psi

• Average EUR of 20 Bcf per well (9,800’ lateral)
• 50% ROR at targeted CWC of $11.0 million & $3.50

per Mcf of gas

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 Eichelberger Edith Mae Andersons Half Laura FIU Glenwood Pearl Sherry Lanelle Federal Roth Wintersole Zella Homsey

710’

MICROSEISMIC SURVEY

1 Mile

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

14

660’ 660’ 175’ 175’ 1,320’ 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)

• To date, 8 wells have produced a

combined 1.75 MMBoe Efficiency gains:

• Drilling times averaged 25 days, 36%

reduction from Ludwig parent well

• CWC averaged $7.8 million, 30%

reduction

CLR: Ludwig Density Ludwig Daily Production(1)

• 1. Normalized to 9,800’ lateral

100 1000 10000 30 60 90 120 Boepd Days on Production Parent well 7 New wells 1,700 MBoe type curve

15

STACK 2017 Drilling Focused on Density Development in Over‐Pressured Oil Window

Density Activity

Blurton Compton Over‐ Pressured Normally‐ Pressured Bernhardt Verona Ludwig De‐risked portion of

• ver‐pressured oil

window

~47,000 net acres under development

• ~55 operated units
• ~60% operated working

interest 6 unit developments scheduled for 2017

• 5 units in oil window
• 1 unit in condensate window

(Angus Trust)

• Testing 4 to 6 wells per zone

Gillilan Angus Trust CLR Leasehold CLR Rigs Industry Rigs Industry Meramec well CLR Meramec producing wells CLR Meramec wells drilling / completing

Bernhardt Marks Foree

16

STACK Meramec: Exceptional, Repeatable Results

Boden McBee Blurton Ludwig Ladd Quintle

Data as of February 14, 2017 Well Name

• Cum. MBoe

Prod Days Current Rate (Boepd) Flowing Casing Pressure Boden(1) 684 (25% oil) 433 1,361 (21% oil) 2,600 psi Andersons Half 483 (99% gas) 195 2,383 (99% gas) 4,200 psi Yocum 433 (99.5% gas) 291 1,057 (99.7% gas) 1,480 psi Madeline 370 (62% oil) 235 1,470 (57% oil) 2,545 psi Ludwig(1)(2) 368 (71% oil) 445 523 (51% oil) 640 psi Compton(1) 340 (68% oil) 388 462 (69% oil) 810 psi Eichelberger 305 (99% gas) 111 2,928 (99% gas) 4,625 psi Gillilan 287 (57% oil) 280 845 (44% oil) 820 psi Ladd(1)(2) 271 (72% oil) 465 414 (63% oil) 820 psi Blurton(1)(2) 270 (73% oil) 373 475 (68% oil) 940 psi Quintle(1) 252 (66% oil) 286 646 (58% oil) 720 psi Verona(2) 228 (68% oil) 177 845 (62% oil) 345 psi Frankie Jo 205 (45% oil) 218 631 (41% oil) 1,905 psi Marks 203 (55% oil) 517 276 (48% oil) 630 psi Foree 188 (57% oil) 261 349 (52% oil) 440 psi Oppel 152 (60% oil) 218 447 (48% oil) 170 psi McBee 106 (45% oil) 124 564 (42% oil) 1,380 psi Bernhardt(2) 80 (70% oil) 218 365 (70% oil) 340 psi

1. Wells not produced at maximum capacity 2. Parent well or well shut in density stimulation

Normally‐ Pressured Over‐ Pressured

CLR Completed Wells

With 100 days of production Yocum

CLR Leasehold Industry Meramec well CLR Meramec well

Verona Madeline Frankie Jo Gillilan Oppel Eichelberger Andersons Half Compton

SCOOP Woodford Condensate: Raising EUR Again by 15%

17

• EUR 2,300 MBoe per well up from 2,000

MBoe EUR (7,500’ lateral)

• 80% ROR(1) for $10.3 million CWC
• Supported by 26 wells with enhanced

completions

• Two recent completions – 24‐hr IPs:
• 3,547 Boepd (26% oil) from an 8,600’ lateral

(Peppered Ranch 1‐36‐25XH)

• 3,463 Boepd (29% oil) from a 10,000’ lateral

(Boatright 1‐31‐30XH)

• Flowing casing pressures were 3,220 and

3,160 psi

• 1. Assumes $55 oil and $3.50 gas

50,000 100,000 150,000 200,000 250,000 300,000 350,000 400,000 450,000 30 60 90 120 150 180 210 240 270 300

Cum BOE Days

SCOOP Woodford Condensate Fairway

SCOOP Enhanced Completions SCOOP Offsets SCOOP Enhanced Type Curve (2,300 MBOE)

45% Uplift

Peppered Ranch Boatright

CLR Leasehold Woodford HZ Producing Well CLR Enhanced Completion Gas Condensate Oil

12 Miles

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

18

Note: Larger enhanced completions defined by 7 initial unit wells with greater than 720 lb/ft proppant

• 1. Normalized to 9,800’ lateral

Larger enhanced completions 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

20,000 40,000 60,000 80,000 100,000 120,000 20 40 60 80 100 Cum Boe Normalized Days

90 days 35% higher than type curve

Harvesting Uncompleted Bakken Wells Has Begun

5 stimulation crews currently working, increasing to 8 by mid‐May Targeting completion of ~148 Bakken wells in 2017 Average 980 MBoe EUR per uncompleted well

• Up 15% from previous target of 850 Mboe
• Over 100% cost forward ROR
• $4.9 million completion cost at $55 WTI

and $3.50 Mcf At year‐end 2017, will have ~72 additional wells stimulated with first sales in 2018

• Provides momentum into 2018

Uncompleted well locations

19

CLR Leasehold

20 miles

Uncompleted wells

MB,TF1,TF2,TF3 MB,TF1,TF2 MB and TF1

Bakken Drilling Efficiency Gains: Structural and Sustainable

20

Bakken cycle times down 65% (spud to TD) Bakken lateral feet per day up 233% Driven by technology:

• Multi‐well pads
• Super “Spec” rigs
• Motor technology
• Bits advancements
• Rotary steerable systems

33.0 21.7 18.6 17.4 16.4 14.3 11.4 14.0 9.5 8.1 6.9 6.2 5.4 3.9

5 10 15 20 25 30 35 2011 2012 2013 2014 2015 2016 4Q 2016

Days Bakken Cycle Times

Spud to TD Lateral Days 607 855 947 1,157 1,360 1,654 1,893 832 1,150 1,333 1,495 1,903 2,402 2,771 500 1,000 1,500 2,000 2,500 3,000 2011 2012 2013 2014 2015 2016 4Q 2016

Feet Bakken Feet per Day

Total Ft/Day Lateral Ft/Day

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 2017 EST Local Refining Pipeline Rail Bakken Production Thousand Bopd

Bakken Takeaway Capacity

21

Bakken Differentials Improving with Ample Pipeline Takeaway Capacity

• More than 90% of CLR

Bakken barrels on pipe

• Pipeline takeaway

capacity to exceed production in 2017 with completion of DAPL pipeline

• Growing pipeline

capacity should reduce basin differentials by at least $2

$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

Low Costs(1) Competitively Positions CLR in Any Environment

69% 73% 76% 74% 74% 73%

Select costs: $11.01 per Boe, ~11% lower than 2015

• 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
• f 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 33 for additional details on the method for calculating margin.

• 2. 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
• 3. Based on average oil equivalent price (excluding derivatives and including natural gas)

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

61% 57%

22

• Avg. Realized $/Boe(3)

Unsecured Credit Facility

• Ample liquidity with $2.75 billion

revolver; can upsize to $4.0 billion(1)

• No borrowing base redetermination
• 2‐year extension option beyond

2019(1)

Financial Strength

• Redeemed $600 million in 2020

Notes and 2021 Notes on 11/10/16

• No near‐term debt maturities

(Earliest is $500 million in 11/2018)

• 4.3% average interest rate in 2016

$500 $840 $2,000 $1,500 $1,000 $700

$1,910 500 1,000 1,500 2,000 2,500 3,000 2016 2017 2018 2019 2020 2021 2022 2023 2024 2044

LIBOR + 1.5%

Financial Metrics(2)

Net Debt(3)/ 4Q 2016 Annualized EBITDAX(4) 2.52x Net Debt(3) / TTM EBITDAX(4) 3.49x Net Debt(3)/4Q 2016

• Avg. Daily Production

$31,274 Net Debt(3)/YE 2016 Proved Reserves $5.15 ($MM)

Debt Maturities Summary No maturities for ~1.5 years

$2.75 billion credit facility

5.0% 4.5% 3.8% 4.9%

Revolver Balance 1/31/17 Callable 3/15/17

Undrawn

• 1. With lender consent
• 2. All ratios are as of 12/31/16, except where noted
• 3. Net debt is a non‐GAAP measure and represents total debt as reflected on the Company’s balance sheet of $6.58 billion, less cash and cash equivalents of $16.6 million as determined under GAAP as of December 31, 2016
• 4. See slide 35 for reconciliation of GAAP net income and net cash provided by operating activities to EBITDAX , which is a non‐GAAP measure

Strong Liquidity & Financial Profile

23

200 400 600 800 1,000 1,200 1,400 2010 2011 2012 2013 2014 2015 2016 STACK SCOOP Bakken Legacy

MMBoe 1,275 37% 46% 4%

50% 50%

Natural

Gas Oil

For YE 2016:

24

Proved Reserves Growth Despite 15% Reduction in SEC Oil Price

13%

Total Proved Reserves Year‐end 2016:

• Proved reserves were 1,275 MMBoe, up

4% from year‐end 2015 proved reserves

• f 1,226 MMBoe
• PV‐10: $6.65 billion(1)
• 41% PDP
• 88% operated

SEC price deck:

• 15% reduction in oil price YoY
• Year‐end 2016: $42.75/bbl oil and

$2.49/mcf gas

• Year‐end 2015: $50.28/bbl oil and

$2.58/mcf gas

• 1. At December 31, 2016, Continental had a Standardized Measure of discounted future net cash flows of $5.51 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 $1.14 billion.

CONTACT INFORMATION

• J. Warren Henry

Vice President, Investor Relations & Research Phone: 405‐234‐9127 Email: Warren.Henry@CLR.com Alyson L. Gilbert Manager, Investor Relations Phone: 405‐774‐5814 Email: Alyson.Gilbert@CLR.com Website: www.CLR.com/Investors 25

26

REFERENCE MATERIALS

2017 Guidance: Operational Detail

2017 wells with first production Average Rigs Average Well Cost(1) ($ in MM) Average EUR (MBoe) Gross Operated Wells Net Operated Wells Total Net Wells(2) Bakken 4 $7.0 920 17 8 43 Bakken DUCs ‐ $4.9 980 131 100 100 SCOOP 5 $10.3 2,000 34 20 24 STACK 6 $9.0 1,700 72 42 43 NW Cana JDA & Other 5 $13.0 2,150 26 8 8 Totals 20 ‐ ‐ 280 178 218

1. SCOOP well cost is for SCOOP Woodford condensate wells; STACK well cost is for STACK over‐pressured

• il stand alone wells; NW Cana JDA & Other well cost is for NW Cana JDA wells

2. Represents projected net operated & non‐operated wells

27

10 20 30 40 50 60 6 12 18 24 30 36 10 100 1,000 10,000

Well Count Producing Months BOE per day

SCOOP Woodford Condensate Type Curve

Enhanced Well Count 2,300 MBOE Type Curve Actual Production (Normalized to 7,500' LL)

Enhanced Completions Type Curves

28

10 20 30 40 50 60

6 12 18 24 30 36

10 100 1,000 10,000 Well Count

Producing Months BOE per day

NW Cana Woodford Type Curve

Well Count Type Curve (Normalized to 9800' LL)

• Act. Production (Normalized to 9800' LL)

10 20 30 40 50 60

6 12 18 24 30 36

10 100 1,000 10,000

Well Count Producing Months BOE per day

STACK Over-Pressured Oil Type Curve

Well Count 1,700 MBOE Type Curve (Norm. to 9,800' LL)

• Act. Production (Norm. to 9800' LL)

10 20 30 40 50 60 10 100 1,000 10,000

6 12 18 24 30 36 Well Count BOE per day Producing Months

Bakken Type Curve

Well Count 900 Mboe Type Curve (9,800' LL) Actual Production 920 MBoe Type Curve (Norm. to 9,800’ LL)

• Act. Production (Norm. to 9,800’ LL)

2,300 MBoe Type Curve (Norm. to 7,500’ LL)

• Act. Production (Norm. to 7,500’ LL)

2,150 MBoe Type Curve (Norm. to 9,800’ LL)

• Act. Production (Norm. to 9,800’ LL)

STACK Woodford Type Curve

CLR Unit Developments Currently Drilling

in STACK Over‐Pressured Oil Window

29

Bernhardt Gillilan

Parent Well

725’ 705’

Blurton

• 5 wells in Lower

Meramec and 4 wells in Woodford

• ~1,100’ to ~1,200’

inter‐well spacing

• 640‐acre unit
• Currently completing,

results expected 2Q 2017

• 4 – 5 wells in Upper &

Lower Meramec and Woodford

• ~1,000’ to ~1,600’

inter‐well spacing

• 1,280‐acre unit
• Currently drilling,

results expected 2H 2017

• 3 ‐ 5 wells in Upper &

Lower Meramec and 4 wells in Woodford

• ~1,000’ to ~2,100’

inter‐well spacing

• 1,280‐acre unit
• Currently completing,

results expected 2H 2017

Verona

• 4 wells in Upper &

Lower Meramec and Woodford

• ~1,300’ inter‐well

spacing

• 1,280‐acre unit
• Currently drilling, results

expected 2H 2017 785’ 675’

Hunton Upper Meramec Middle Meramec Osage Woodford Lower Meramec Parent Well Unit Well

CLR Unit Developments Recently Announced

in STACK Over‐Pressured Oil and Condensate Windows

30

Compton

785’ 705’

Angus Trust

• 5 wells in Upper &

Lower Meramec and 4 wells in Woodford

• ~825’ to ~1,320’

inter‐well spacing

• 1,280‐acre unit
• Currently drilling,

results expected 4Q 2017

• 6 wells in Upper &

Lower Meramec

• ~785’ to ~840’ inter‐

well spacing

• 1,280‐acre unit
• To begin drilling

soon, results expected 4Q 2017

• First density in the

condensate window

Hunton Upper Meramec Middle Meramec Osage Woodford Lower Meramec Parent Well Unit Well

SCOOP Woodford Oil

Enhanced Completions Success Increase EUR 30%

31

20+ enhanced completions outperform legacy offsets

• ~30% increase in 180‐day rate
• ~30% increase in EUR to 1.3 MMBoe

per well for 2‐mile lateral

• ~38% ROR(1) for $12.0 million CWC
• At least 50,000 net acres upgraded to

new EUR model

• 1. Assumes $55 WTI and $3.50 Mcf

20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000 180,000 200,000 50 100 150 200

Cum Boe Days

Enhanced completions (23 wells) Offset wells 1,340 MBoe Type Curve

180 days ~30% higher than

• ffsets

Oil Window Enhanced Completions

CLR Leasehold Woodford HZ Producing Well CLR Enhanced Completion Gas Condensate Oil

12 Miles

MAY INFILL

6 Miles

Emery 1R‐9‐16XH IP: 1,334 Boepd (77% oil)

7 well density

• 6,881 Boe per day (77% oil) ‐ combined peak 24‐hour

rate; average 983 Boe per day per well

• Combined cumulative production of 934 MBoe (74%
• il) in 158 days
• All wells are outperforming the type curve
• Average CWC: $9.3 million
• Laterals range from 4,500’ to 9,700’
• 1. Normalized to 7,500’ lateral

SCOOP Woodford Oil ‐ May Density Results

32

May Project ‐7 Well Density ‐755’ Inter‐well Spacing

2 Parent wells 5 New May Wells 1,000MBoe Type Curve

May Daily Production(1)

1 Mile 175’ Upper Woodford Lower Woodford 100 1000 10000 30 60 90 120 150 180 Boepd Days on Production

• 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%

33

Continuing to Deliver Strong Margins(1)

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

• perating 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

34

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

35

EBITDAX Reconciliation to GAAP

ADJUSTED Earnings Reconciliation to GAAP

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

• il 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.

36

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

37

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