Investor Update May 2017 Forward-Looking Information Cautionary - PDF document

Investor Update May 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 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. 2

Continental Resources Celebrating 50 Years of Organic Growth 350,000 Play Net Reservoir Acres (1) SCOOP Sycamore SCOOP Sycamore Bakken: 815,000 NORTH 300,000 STACK: STACK Meramec STACK Meramec 2.0 Million Meramec 205,000 Net Reservoir Acres 250,000 Woodford 191,000 SCOOP Springer SCOOP Springer SCOOP: SOUTH Springer 197,000 200,000 Woodford 330,000 SCOOP Woodford SCOOP Woodford Sycamore 300,000 Boepd 150,000 Anadarko Woodford Anadarko Woodford BAKKEN Arkoma Woodford Arkoma Woodford 100,000 ND Bakken ND Bakken STACK MT Bakken MT Bakken Cedar Hills Cedar Hills 50,000 SCOOP 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 2017 1. All acreage numbers are approximate 3

1Q 2017 Highlights Bakken wells exceed 980 MBoe EUR type curve by an average 65% at 30 days • Four wells in 1Q’17 produced CLR record 30-day rates at an average of 1,712 Boe per day • 1Q’17 wells expected to average 75% ROR, nearly 2X ROR originally targeted by the 2017 Bakken drilling program SCOOP Springer wells outperform 940 MBoe EUR type curve by an average 60% at 30 days Sycamore expansion adds ~300,000 net reservoir acres under existing leasehold in SCOOP STACK Meramec wells continue to deliver strong 24-hour IPs ranging from 1,907 to 3,011 Boe per day 2Q’17 production trending ahead of forecast; now expected to range from 220,000 to 225,000 Boe per Day 4

Performance Taken to New Level Last 2 Years Structural Improvements Benefiting 2017 and Beyond (1) From 2014 to 2016: Production and Cash G&A Costs $10 $7.87 $7.76 $7.64 • Production and cash G&A (1) $8 $6.00 $2.07 $2.38 $2.06 DOWN ~30% $5.18 $6 $/Boe $1.70 $1.53 • Bakken production expense $4 $5.69 $5.58 $5.49 DOWN ~20% $4.30 $2 $3.65 $0 2012 2013 2014 2015 2016 (1) Production Expense Cash G&A EUR Per Operated Well From 2014 to 2016: 1,600 1,416 160 Net Boe/$1,000 (2) 1,400 140 149 1,110 1,200 120 • EUR per operated well UP ~100% Boe/$1,000 1,000 100 711 • Capital efficiency (2) (Boe/$ invested) 104 800 80 MBoe Boe/$1,000 506 470 600 60 UP ~175% 400 40 54 47 41 Boe/$1,000 200 20 Boe/$1,000 Boe/$1,000 0 0 2012 2013 2014 2015 2016 1. See “Cash G&A Reconciliation to GAAP“ on slide 30 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 is based on estimated ultimate recoveries added per dollar invested for wells spud during the indicated periods. An assumed net revenue interest of 82% and cost estimates are used in determining capital efficiency for non-producing properties. 5

2017 Sets Up Multi-Year Double-Digit Growth at $50 to $55 WTI Strong Production Growth Current production forecast: 500,000 STACK • 2Q’17 expected to range from 220,000 to 225,000 Boe per Day 450,000 SCOOP Bakken 400,000 Legacy 350,000 • 2017 exit rate: 250,000 to 260,000 Boe Boe per day 300,000 per day; trending at top end of guidance 250,000 200,000 • Targeting 20% CAGR 2018 – 2020 150,000 100,000 50,000 • Cash flow neutral at $50 to $55 WTI 0 4Q 2016 2017E 2018E 2019E 2020E Exit Rate • Oil production growing to 60%-65% of total production in 2018 - 2020 6

2017 Capital Focused on High ROR Oil Plays % of D&C Est. Total (1) Capital (2) (3) Play ROR % Oil (4) ($ in MM) Budget % Liquids (5) Bakken DUCs $550 32% 100%+ 80% 90% Bakken Drilling $490 28% 40% - 75% 80% 90% (6) STACK $375 22% 100%+ 60% 70% (7) SCOOP $245 14% ~70% 25% 55% (8) NW Cana $60 4% 100%+ 2% 20% Total D&C Program $1,720 100% - 60% 75% (weighted avg) Non-D&C Capital $230 - - - (land, facilities, other) Total 2017 Capital $1,950 - - - 1.Inclusive of capital for outside operated activity, except for Bakken DUCs 5.ROR is on the incremental cost forward cost of completion 2.At $55 WTI and $3.15 gas, see footnote 1 on slide 20 6.STACK ROR is based on STACK over-pressured oil wells 3.Estimates based upon 2-stream oil volumes at the wellhead 7.SCOOP ROR is based on SCOOP Woodford condensate wells 4.Estimates based upon theoretical NGL recoveries after processing 8.NW Cana as part of the JDA with SK E&S 7