080519 investor update august 2019filecache.investorroom.com › mr5ir_clr › 281 › 080519... ·...

Investor UpdateAugust 2019

PROPERTY OF CONTINENTAL RESOURCES, INC. REPRODUCTION AND DISTRIBUTION WITH WRITTEN PERMISSION ONLYPROPERTY OF CONTINENTAL RESOURCES, INC. REPRODUCTION AND DISTRIBUTION WITH WRITTEN PERMISSION ONLYPROPERTY OF CONTINENTAL RESOURCES, INC. REPRODUCTION AND DISTRIBUTION WITH WRITTEN PERMISSION ONLY

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 SecuritiesExchange Act of 1934. All statements included in this presentation other than statements of historical fact, including, but not limited to, forecasts or expectationsregarding the Company’s business and statements or information concerning the Company’s future operations, performance, financial condition, production andreserves, 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,” “target,” “plan,” “continue,”“potential,” “guidance,” “strategy,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements containsuch identifying words.

Forward-looking statements are based on the Company’s current expectations and assumptions about future events and currently available information as to theoutcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerousbusiness, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company’scontrol. No assurance can be given that such expectations will be correct or achieved or the assumptions are accurate. The risks and uncertainties include, but arenot limited to, commodity price volatility; the geographic concentration of our operations; financial, market and economic volatility; the inability to access neededcapital; the risks and potential liabilities inherent in crude oil and natural gas exploration, drilling and production and the availability of insurance to cover any lossesresulting therefrom; difficulties in estimating proved reserves and other revenue-based measures; declines in the values of our crude oil and natural gas propertiesresulting in impairment charges; our ability to replace proved reserves and sustain production; our ability to pay future dividends or complete share repurchases;the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability toproject future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availabilityand cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, includinginitiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risksdescribed 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, 2018, registrationstatements 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 oneor more of the risks or uncertainties described in this presentation occur, or should underlying assumptions prove incorrect, the Company’s actual results and planscould differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by thiscautionary statement. Except as expressly stated above or otherwise required by applicable law, the Company undertakes no obligation to publicly correct orupdate 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. Inparticular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressurefracturing 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 theseestimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much morespeculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may beultimately 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

PROPERTY OF CONTINENTAL RESOURCES, INC. REPRODUCTION AND DISTRIBUTION WITH WRITTEN PERMISSION ONLYPROPERTY OF CONTINENTAL RESOURCES, INC. REPRODUCTION AND DISTRIBUTION WITH WRITTEN PERMISSION ONLY

CLR: Increasing Shareholder ReturnsThrough Share Repurchases & Dividend

3

Ongoing/Historical

Organic Growth through ExplorationLeading Position in 3 Top U.S. Oil Plays

Industry-Leading Returns Compete with Broader Market

Sustainable, Cash Flow Positive GrowthProject up to $5 Billion FCF(1) Next 5 Years

Net Debt(2) Reduction~$1.5 Billion Last 3 Years

Added

$1 Billion Share Repurchase Program$92 Million Repurchased as of 8/2/19

Quarterly Dividend Begins 4Q19$75MM/Year Annualized(3)

Growing Mineral/Royalty AssetsCapitalizing on CLR Proprietary Knowledge

and Operations

Monetization of Non-Strategic Assets$85 Million Divestiture Water Facility

1. Free cash flow (FCF) is a non-GAAP measure. See slide 24 for a definition of this measure and a reconciliation of historical amounts to the most comparable U.S. GAAP measure. Also, with respect to projected amounts, please see slide 24 for anexplanation of the factors that make a quantitative reconciliation of this forward-looking estimate to U.S. GAAP not possible. $60 WTI price on an annualized basis is assumed in our model for free cash flow.

2. Net Debt is a non-GAAP measure. See slide 25 for a definition of this measure and a reconciliation of historical amounts to the most comparable U.S. GAAP measure. Also, with respect to projected amounts, please see slide 25 for an explanation of thefactors that make a quantitative reconciliation of this forward-looking estimate to U.S. GAAP not possible.

3. The Company’s Board of Directors has declared a dividend of $0.05 per share on its common stock, payable on November 21, 2019 to shareholders of record as of November 7, 2019. All future dividend payments are subject to Board approval.

VALUE GENERATORS


CLR’s Five Year Vision Sustainable Cash Flow Positive Production Growth

CLR Five Year Vision (2019-2023)

1. Free cash flow (FCF) is a non-GAAP measure. See slide 24 for a definition of this measure and a reconciliation of historical amounts to the most comparable U.S. GAAP measure. Also, with respect to projected amounts, please see slide 24 for anexplanation of the factors that make a quantitative reconciliation of this forward-looking estimate to U.S. GAAP not possible. 2016, 2017 and 2018 totals are inclusive of asset divestiture proceeds of $631 million, $144 million and $54 million, respectively.$60 WTI price on an annualized basis is assumed in our model for free cash flow.

2. The 2019 capital budget is projected to generate an estimated $500 to $600 million of free cash flow for full-year 2019 at $55 WTI and $3 HH. A $5 change per barrel WTI is estimated to impact annual cash flow by approximately $325 million.

4

• ~12.5% Production CAGR

• Utilizes Less Than 30% of Current Inventory

• ~$5 Billion Free Cash Flow(1)

• ~14.5% Average Annual ROCE

Asset Divestiture ProceedsFree Cash Flow Projected Free Cash Flow

$

$1

$2

$3

$4

$5

2016 2017 2018 2019E

Bill

ions

($)

2019E(2) 5-Year Cumulative

Projected Free Cash Flow(1)

North North NorthNorth

60-65%

North60-65%

South SouthSouth

South35-40%

South35-40%

100

200

300

400

500

2016 2017 2018 2019E 2023EM

Boe

pd2020 - 2022

Projected Production


Free Cash Flow Drives Total Shareholder Return Strategy

5

1. Free cash flow (FCF) is a non-GAAP measure. See slide 24 for a definition of this measure and a reconciliation of historical amounts to the most comparable U.S. GAAP measure. Also, with respect to projected amounts, please see slide 24 for anexplanation of the factors that make a quantitative reconciliation of this forward-looking estimate to U.S. GAAP not possible. $60 WTI price on an annualized basis is assumed in our model for free cash flow.

2. The Company’s Board of Directors has declared a dividend of $0.05 per share on its common stock, payable on November 21, 2019 to shareholders of record as of November 7, 2019. All future dividend payments are subject to Board approval.

$1BProgram

~$1.4BReduction

~$75MM/Year

$0B

$5B

Cash Available Annual Dividend Share Repurchases Debt Reduction

$92MM Executed as of 8/2/19

Potential To Grow(2)

Targeting $4.2B LTD

$5BCumulative

FCF(1)

($60 WTI)

5-Ye

ar V

isio

nC

umul

ativ

e FC

F ($

60 W

TI)

Cash Available Annual Dividend Share Repurchases Debt Reduction

Committed to Maximizing Shareholder Value

• Initiating Quarterly Dividend in 4Q19

• $1B Share-Repurchase Program

• Debt Reduction (Targeting $4.2B Long Term)

• Ample Liquidity for Add’l Debt Pay Down, Dividends & Buybacks


1. Net Debt and EBITDAX are non-GAAP measures. See slides 25-27 for definitions and reconciliations of historical amounts to the most comparable U.S. GAAP financial measures. With respect to projected amounts, please see slides 25-27 for anexplanation of the factors that make a quantitative reconciliation of these forward-looking estimates to U.S. GAAP not possible.

2. Source: Bloomberg as of April 10, 2019. Data is calculated as net income plus minority interest plus after-tax interest expense divided by the average of current and prior capital employed. Data represents an average of quarterly return over the trailing4 quarters as of 4Q18. E&P: S&P 500 Exploration & Production Index; OFS: S&P 500 Oil Field Services Index; Tech: S&P 500 Info Tech Index; Industrials: S&P 500 Industrials Index; Cons. Disc.: S&P 500 Consumer Discretionary Index; Healthcare:S&P 500 Health Care Index.

6

15%

13%12%

8% 8%

7%

0%0%

4%

8%

12%

16%

CLR 2018 Corporate Returns vs. the Market(2)

(Source: Bloomberg)

Driving Down Debt / Delivering Competitive Returns

$7.1B$6.6B

$6.3B

$5.5B$5.6B

$4.2B

3.6x3.5x

2.7x

1.5x1.6x

1.0x

0.0x

0.5x

1.0x

1.5x

2.0x

2.5x

3.0x

3.5x

2015 2016 2017 2018 2Q19 2023E

Net

Deb

t/TTM

EB

ITD

AX(1

)

CLR Net Debt Continues to Decline


CLR Continues To Be A Low Cost Leader Among Peers

7

1. Source: Public company filings as of 1Q19. 2. Source: Tudor, Pickering & Holt estimates for full-year 2019.3. Source: Jefferies. 2019 maintenance capital is the estimated capital allocation necessary to hold production flat 4Q19/4Q18. Assuming maintenance programs, 2019 implied free cash flow yields are based on $60 Brent and $2.80 HH.

APA

NBL XEC

OAS

WLL WPXFANG

PXDEOG CXO

CLR

-16%

-14%

-12%

-10%

-8%

-6%

-4%

-2%

1%

3%

5%

Impl

ied

FCF

Yiel

d

Select Peers CLR

2019 Maintenance Capital Implied FCF Yields(3)

Source: Jefferies

APA

CXO

DVN

ECA

EOG

FANG

MRONBL

OAS

PXDWLL

WPX

XEC

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

$9.00

20% 30% 40% 50% 60% 70% 80%

Low Cost per Boe(1)

Source: Public Company Filings

1Q19 Oil Production % (Excludes Liquids)

1Q19

LO

E pe

r Boe

CLR 2Q19CLR 1Q19

APACXO

DVN

EOG

ECA

FANG

MRO

NBL

OAS

PXDWLL

WPX

XEC

5%

7%

9%

11%

13%

15%

17%

19%

$0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 $4.50

2019

E G

&A

/ EB

ITD

A

2019E G&A / Boe

Top-Tier G&A(2)

Source: Tudor, Pickering & Holt

CLR 2019ECLR 2Q19


Long Term Outlook Multi-$ Billion IPO Potential

CLR’s Minerals Strategy Enhances Returns to Shareholders

8

1. Based on achieving certain predetermined targets.2. Statement is made based on the historic performance of Viper Energy Partners. While CLR’s mineral assets and structure are different, CLR believes similar performance is possible.

Top-Tier Acreage 90% of Minerals Entity Acreage under CLR-Operated Units

Low Cost Structure CLR Expects to Earn 50% of Revenue for 20% of Cost(1)

Known Drill Plan >75% of CLR Operated South Wells in 1H19 Hit CLR Minerals

Leading Operator Capitalizes on CLR’s Operational Leadership✔

✔

✔

✔

✔

Strategic Advantages

Minerals OperatorDevelopment Value Uplift

OperatorDevelopment on Minerals

Typical Minerals CLR Minerals

Synchronizing with CLR’s Drill Plans Increases Pace of Minerals Development

$375MM Combined(2019-2021)

~$215MM Initial

Total Investment Future Returns

~$600MM Total

~4x Potential Value(2)Growing Minerals EntityGenerating Added Value


CLR 2Q19 ResultsRaising Production Guidance; Lowering Costs

9

1. Acreage numbers are approximate as of 2Q19.

2Q19 Earnings & Recent Transactions

North: Bakken35% Oil Growth YoY (36,337 Bopd)

10% Total Growth YoY (128,777 Boepd)

22 Gross Op Wells with 1st Production

SpringBoard: On Track to Achieve 18,000 Bopd 3Q19 Target;July Avg: ~19,000 Bopd; 4Q19 Targeting: 22,000 Bopd

STACK: Completion Underway on Two, 7-Well Oil Units

South: SCOOP & STACK

Updates to 2019 Guidance

22% Oil Growth YoY (149,078 Bopd)

23% Total Growth YoY (194,014 Boepd)

35 Gross Op Wells with 1st Production

60-Well Long Creek Bakken Unit Development Announced

1Q19 Step-Outs Outperforming Legacy Wells by 75-145% at 120 Days

Net Income $237MM

Oil Production 23% Oil Growth YoY (193,586 Bopd)

Buybacks Executed $92MM as of Aug 2, 2019

Divestiture $85MM Water System Infrastructure Divestiture in STACK

LOE per Boe $3.74 (Better than Previous Guidance)

G&A per Boe $1.57 (Better than Previous Guidance)

Crude Oil Diff $5.11 (Within Guidance)

Metric Previous Update

Oil Production 190-200,000 Bopd 195-200,000 Bopd

Gas Production 790-810,000 Mcfpd 820-840,000 Mcfpd

LOE per Boe $3.75 - $4.25 $3.50 - $4.00

G&A per Boe $1.70 - $2.00 $1.55 - $1.85

Production Tax 8.0% - 8.3% 8.5%

Gas Differential $0.00 - ($0.50) ($0.50) - ($1.00)

800K Net Reservoir Acres(1)

1.1MM Net Reservoir

Acres(1)


CLR’s Bakken Well Performance Increasing Year-Over-Year

10

1. Includes wells with 365 days of production as of July 26, 2019.

0

50,000

100,000

150,000

200,000

2014 2015 2016 2017 2018

Avg

. Firs

t Yea

r Cum

ulat

ive

Oil

Prod

uctio

n pe

r Wel

l (B

bl)

Program Year(1)

First Year Average Cumulative Production

Improvements Driven By:

• Increased Stimulated Rock Volume

• Enhanced Production Techniques

• Growing Infrastructure


Bakken: Step-Outs Continue To Meet ExpectationsSignificantly Outperform Legacy Offsets

11

1. 3-mile lateral well performance compared to 2-mile lateral well.

1,680 Boepd 24-Hour IPOutperforming Legacy Well

by 100% at 120 Days

MT: Baird Federal 2-34H


by 145% at 120 Days

ND: McClintock 8-1H1(1)


by 75% at 120 Days

ND: Burian 4-27H1 2015-2019 Bakken Wells

Approx. Bakken Field Outline

Wells or Units with Wells 75-100 MBoe in 90 Days

Wells or Units with Wells >100 MBoe in 90 Days

CLR Acreage


Long Creek Bakken Unit Another High Impact Oil Project For CLR

Williston Basin

Long Creek

Long Creek Bakken Unit

12

Estimated Peak Production of up to ~20,000 Net Bopd • First production expected 3Q20

• Peak production expected 2H21

10 Square Miles of Contiguous Leasehold• ~6,400 gross acres (~5,600 net)

Up to 56 Wells to be Drilled• Drilling to begin 4Q19; 2 rigs

87% Avg. Working Interest

Row Development to Maximize Efficiencies and Value• All products to be on pipe

• Installation of facilities underway


SCOOP: Project Springboard Oil Growth Exceeding Expectations

13

1. 3Q18 net oil volumes: 164,605 Bopd.

On Track for 18,000 Net Bopd Avg. in 3Q19• July 2019 Oil Production: ~19,000 Net Bopd

Targeting 22,000 Bopd Avg. in 4Q19

~5 Million Gross Barrels of Oil Produced

60 Gross Wells Producing• 46 Springer and 14 Woodford

~30 Additional Wells on Line by YE19

10

20

30

40

50

60

0 10 20 30 40 50 60

Avg

. Cum

ulat

ive

MB

o

Days On

Woodford Well Outperformance

14 Wells Outperforming Legacy Woodford

Oil Type Curve

1,300

5,260

8,700

15,100

~19,000

18,000

22,000

0

4,000

8,000

12,000

16,000

20,000

3Q18 4Q18 1Q19 2Q19 Jul-19 3Q19E 4Q19E

Post

3Q

18(1

)Sp

ringB

oard

Oil

Prod

uctio

n (B

opd)

Average Production

Avg

. Jul

y Pr

oduc

tion

SpringBoard Oil Growth Target


SpringBoard Operations Maximizing ValueDecreasing Costs, Growing Infrastructure And Market Advantages

14

46

3937

32 3230

25

30

35

40

45

50

2Q18 3Q18 4Q18 1Q19 2Q19 Target

Sprin

gBoa

rd S

prin

ger &

Woo

dfor

d Sp

ud to

TD

(Day

s)

$571 $470 $445 $377 $357

$702 $678 $652

$612 $602

$1,273 $1,148 $1,097

$989 $959

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

ParentMono-Bore

2018Mono-Bore

1Q19Mono-Bore

2Q19Mono-Bore

Target

Woo

dfor

d C

WC

($/L

ater

al F

oot)

Drilling Completion

Drilling and Completion Efficiencies

• 22% reduction in SpringBoard Woodford CWC

• 30% reduction in SpringBoard drilling cycle time

90%+ of Oil, Gas and Water on Pipe

Marketing Advantage

• Premium market provides ~$3.00 per barrel differential uplift for SpringBoard production

• SpringBoard crude oil differentials below $2.00 per barrel


STACK Unit Development Delivering Outstanding Repeatable Results

15

0 20 40 60 80 100 1200

100

200

300

400

Producing Days

Avg.

Cum

ulat

ive

MB

oe

0 20 40 60 80 100 120

50

100

150

200

250

300

Producing Days

Avg.

Cum

ulat

ive

MB

oe

Average Oil Unit Wells Outperforming Unit Type Curve

By ~40% at 120 Days

Average Condensate Unit Wells Outperforming Parent Type Curve

by ~32% at 120 Days


STACK: Location MattersWell Performance Reinforces Quality Of CLR’s Leasehold

16

Meramec Horizontal Wells with Average 30-Day Rate > 1,500 Boepd (2015 - Present)

Source: IHSM Enerdeq, July 2019.

Meramec HZ Wells with > 1,500 Boepd IP30CLR Meramec Wells with > 1,500 Boepd IP30

CLR Leasehold

Over-Pressured Normal-Pressured

STACK

SimbaUnit

JalouUnit

HomseyUnit

BodenUnit

TolbertUnit

CLR Operates over 40% of STACK IP-30 Wells Delivering > 1,500 Boepd

CLR Formula for Industry Leading Performance• Higher pressure• Thicker reservoirs• Proper well density• Focus on maximizing unit value

Currently Completing 2 Addl. Oil Units • Both units contain 7 Meramec wells 4 wells targeting upper Meramec 3 wells targeting lower Meramec


CLR Delivers on Guidance Unique Insider Ownership Ensures Shareholder Alignment

17

1. Annual guidance calculated at the upper end of the most current guidance provided for each year.2. Source: Bloomberg as of June 28, 2019. Insider ownership calculated as the average percentage of insider shares outstanding for companies within each sector listed, based on holdings data collected by Bloomberg. Cons. Disc.: S&P

500 Consumer Discretionary Index; E&P: S&P 500 Exploration & Production Index; Healthcare: S&P 500 Health Care; Industrials: S&P 500 Industrials Index; OFS: S&P 500 Oil Field Services Index; Tech: S&P 500 Info Tech Index.

Annual Guidance(1) vs. Actual

$/Boe

$3.00

$4.00

$5.00

$6.00

$7.00

2011

2012

2013

2014

2015

2016

2017

2018

LOE per BoeExploration

Development

0

50,000

100,000

150,000

200,000

250,000

300,000

2011

2012

2013

2014

2015

2016

2017

2018

ProductionBoepd

77.3%

3.5% 2.1% 1.5% 1.4% 0.8% 0.4%0%

10%

20%

30%

40%

50%

60%

70%

80%

CLR Insider Ownership vs. the Market(2)

(Source: Bloomberg)


Contact Information

18

Rory SabinoVice President, Investor RelationsPhone: 405-234-9620Email: [email protected]

Lucy GuttenbergerInvestor Relations Analyst Phone: 405-774-5878Email: [email protected]

Website:www.CLR.com/Investors

PROPERTY OF CONTINENTAL RESOURCES, INC. REPRODUCTION AND DISTRIBUTION WITH WRITTEN PERMISSION ONLYPROPERTY OF CONTINENTAL RESOURCES, INC. REPRODUCTION AND DISTRIBUTION WITH WRITTEN PERMISSION ONLY 19

Reference Materials


CLR’s 2019 Plan:Sustained Returns, FCF, Low-Cost Oil-Weighted Growth

20

2019: Delivering Capital-Efficient Growth, Strong FCF(1) & Returns

• 16% to 19% YoY oil production growth

195,000 to 200,000 Bopd

• 9% to 12% annual Return on Capital Employed (ROCE)

$5 WTI change = 4% change in ROCE

• $500MM to $600MM FCF(1) at $55 WTI

Cash neutral in mid-$40’s WTI

$5 WTI change = ~$325MM change in FCF(1)

1. Free cash flow (FCF) is a non-GAAP measure. With respect to this projected amount, please see slide 24 for an explanation of the factors that make a quantitative reconciliation of this forward-looking estimate to U.S. GAAP not possible.

0%

4%

8%

12%

16%

$0

$500

$1,000

$45 WTI $50 WTI $55 WTI $60 WTI

RO

CE

2019

FC

F Es

timat

e ($

MM

)

Cash Flow Positive Above $45 WTI

FCF Estimate

ROCE EstimateROCE Estimate Range

FCF Estimate Range


Updated 2019 Guidance

21

Production & Capital Previous 2019 Guidance Updated 2019 Guidance

Capital expenditures budget $2.6 billion $2.6 billion

Production (Boe per day)

Oil Production (Bo per day) 190,000 - 200,000 195,000 - 200,000

Natural Gas Production (Mcf per day) 790,000 - 810,000 820,000 - 840,000

Operating Expenses

Production expense ($ per Boe) $3.75 - $4.25 $3.50 - $4.00

Production tax (% of net oil & gas revenue) 8.0% - 8.3% 8.5%

Cash G&A expense(1) ($ per Boe) $1.25 - $1.45 $1.15 - $1.35

Non-cash equity compensation ($ per Boe) $0.45 - $0.55 $0.40 - $0.50

DD&A ($ per Boe) $15.00 - $17.00 $15.00 - $17.00

Average Price Differentials

NYMEX WTI crude oil ($ per barrel of oil) ($4.50) - ($5.50) ($4.50) - ($5.50)

Henry Hub natural gas(2) ($ per Mcf) $0.00 - ($0.50) ($0.50) - ($1.00)

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 2019 total G&A (cash and non-cash) is an expected range of $1.55 - $1.85 per Boe. 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.

2. Includes natural gas liquids production in differential range.


Financial Metrics

• 1.62x: Net debt(1) / 2Q19 Annualized EBITDAX(1)

• 1.56x: Net debt(1) / TTM EBITDAX(1)

Financial Strength

• Earliest debt maturity is 2022 bonds (callable)

• 4.5% average interest rate in 2Q19

Unsecured Credit Facility

• Ample liquidity with $1.5B revolver;

fully undrawn at 6/30/19

Continued Focus On Net Debt Reduction

22

($M

M)

Net Debt(1) Declining

$7,106 $6,563 $6,310$5,486

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

YE 2015 YE 2016 YE 2017 YE 2018

1. Net debt and EBITDAX are non-GAAP measures. See slides 25-27 for definitions and reconciliations of these measures to the most comparable U.S. GAAP financial measures.

$1,600Remaining $1,500

$1,000 $1,000 $700

0

500

1,000

1,500

2,000

2018 2019 2020 2021 2022 2023 2024 2028 2044

($M

M) 5.0% 4.5%

3.8%

4.9%

Callable3/15/17

Debt Maturities Summary

4.375%


$1,000 $1,000 $700

0

500

1,000

1,500

2,000

2018 2019 2020 2021 2022 2023 2024 2028 2044

($M

M) 5.0% 4.5%

3.8%

4.9%

Callable3/15/17


4.375%


$1,000 $1,000 $700

0

500

1,000

1,500

2,000

2018 2019 2020 2021 2022 2023 2024 2028 2044

($M

M) 5.0% 4.5%

3.8%

4.9%

Callable3/15/17


4.375%


1. Margin represents the Company’s average net 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 slide 29 for a discussion and calculation of net sales prices, which are non-GAAP measures for 2018 and 2019.3. See “EBITDAX reconciliation to GAAP” on slides 26-27 for a reconciliation of GAAP net income/loss and net cash provided by operating activities to EBITDAX, which is a non-GAAP measure. 4. Average costs per Boe have been computed using sales volumes and exclude any effect of derivative transactions.5. 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.

Continuing To Deliver Strong Margins(1)

23

2015 2016 2017 2018 2Q 2019

Crude oil net sales price ($/Bbl)(2) $40.50 $35.51 $45.70 $59.19 $54.66

Natural gas net sales price ($/Mcf)(2) $2.31 $1.87 $2.93 $3.01 $1.66

Oil production (Bopd) 146,622 128,005 138,455 168,177 193,586

Natural gas production (Mcfpd) 450,558 533,442 625,093 780,083 826,969

Total production (Boepd) 221,715 216,912 242,637 298,190 331,414

EBITDAX ($000's)(3) $1,978,896 $1,881,889 $2,363,617 $3,623,373 $858,019

Key Operational Statistics (per Boe)(4)

Oil equivalent net sales price (excludes derivatives) ($/Boe)(2) $31.48 $25.55 $33.65 $41.25 $36.03

Production expenses $4.30 $3.65 $3.66 $3.59 $3.74

Production taxes $2.47 $1.79 $2.35 $3.25 $3.12

Cash G&A(5) $1.70 $1.53 $1.64 $1.25 $1.17

Interest expense $3.86 $4.04 $3.32 $2.69 $2.28

Total of selected costs $12.33 $11.01 $10.97 $10.78 $10.31

Margin(1) $19.15 $14.54 $22.68 $30.47 $25.72

Margin % 61% 57% 67% 74% 71%


Free Cash FlowOur presentation of free cash flow is a non-GAAP measure. We define free cash flow as cash flows from operations before changes in workingcapital items, less capital expenditures, excluding acquisitions, plus noncontrolling interest capital contributions, less distributions to noncontrollinginterests. Noncontrolling interest capital contributions and distributions primarily relate to our relationship formed with Franco-Nevada in 2018 to funda portion of certain mineral acquisitions which are included in our capital expenditures and operating results. Free cash flow is not a measure of netincome or operating cash flows as determined by U.S. GAAP and should not be considered an alternative to, or more meaningful than, thecomparable GAAP measure, and free cash flow does not represent residual cash flows available for discretionary expenditures. Managementbelieves that this measure is useful to management and investors as a measure of a company’s ability to internally fund its capital expenditures andto service or incur additional debt. From time to time the Company provides forward-looking free cash flow estimates or targets; however, theCompany is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to its most directly comparable forward-lookingGAAP measure because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. Thereconciling 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 amounts for theperiods presented.

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In thousands 2016 2017 2018Net cash provided by operating activities (GAAP) 1,125,919 2,079,106 3,456,008Exclude: Changes in working capital items 162,216 (1,415) (125,708)Less: Capital expenditures (1) (1,074,345) (1,995,246) (2,843,988)Plus: Contributions from noncontrolling interest — — 267,920Less: Distributions to noncontrolling interest — — (604)Free cash flow (non-GAAP) 213,790 82,445 753,628

(1) Capital expenditures are calculated as follows:In thousands 2016 2017 2018Cash paid for capital expenditures 1,164,514 1,953,198 2,914,630Less: Total acquisitions (35,911) (40,007) (84,757)Plus: Change in accrued capital expenditures & other (59,062) 79,222 14,115Plus: Exploratory seismic costs 4,804 2,833 —Capital expenditures 1,074,345 1,995,246 2,843,988


Net Debt Reconciliation To GAAP

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. Net debtshould not be considered an alternative to, or more meaningful than, total debt, the most directly comparable GAAP measure. Management usesnet debt to determine the Company’s outstanding debt obligations that would not be readily satisfied by its cash and cash equivalents on hand. Webelieve this metric is useful to analysts and investors in determining the Company’s leverage position since the Company has the ability to, and maydecide to, use a portion of its cash and cash equivalents to reduce debt. This metric is sometimes presented as a ratio with EBITDAX in order toprovide investors with another means of evaluating the Company’s ability to service its existing debt obligations as well as any future increase in theamount of such obligations. At June 30, 2019, the Company’s total debt was $5.77 billion and its net debt amounted to $5.56 billion, representingtotal debt of $5.77 billion less cash and cash equivalents of $206.5 million. From time to time the Company provides forward-looking net debtforecasts; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to the most directlycomparable forward-looking GAAP measure of total debt because management cannot reliably quantify certain of the necessary components ofsuch forward-looking GAAP measure. The reconciling items in future periods could be significant.

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

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In thousands 2015 2016 2017 2018 2Q 2019

Total debt (GAAP) $7,117,788 $6,579,916 $6,353,691 $5,768,349 $5,769,713

Less: Cash and cash equivalents (11,463) (16,643) (43,902) (282,749) (206,482)

Net debt (non-GAAP) $7,106,325 $6,563,273 $6,309,789 $5,485,600 $5,563,231


EBITDAX Reconciliation To GAAP

We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX, a non-GAAP measure. Wedefine EBITDAX as earnings 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 compensationexpense, and losses on extinguishment of debt as applicable. EBITDAX is not a measure of net income or net cash provided by operating activitiesas determined by U.S. GAAP.

Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results ofour operations from period to period without regard to our financing methods or capital structure. Further, we believe EBITDAX is a widely followedmeasure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. Weexclude the items listed above from net income/loss and net cash provided by operating activities in arriving at EBITDAX because these amountscan vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capitalstructures 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 asdetermined in accordance with U.S. GAAP or as an indicator of a company’s operating performance or liquidity. Certain items excluded fromEBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital andtax structure, as well as the historic 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. From time to time the Company provides forward-looking EBITDAXforecasts; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to the most directlycomparable forward-looking GAAP measure of net income (loss) and net cash provided by operating activities because management cannot reliablyquantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.

See the following page for reconciliations of our net income (loss) and net cash provided by operating activities to EBITDAX for the applicableperiods.

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

EBITDAX Reconciliation To GAAP

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In thousands 2015 2016 2017 2018 2Q 2019 TTMNet income (loss) $ (353,668) $ (399,679) $ 789,447 $ 989,700 $ 236,450 $ 936,233Interest expense 313,079 320,562 294,495 293,032 68,471 279,158Provision (benefit) for income taxes (181,417) (232,775) (633,380) 307,102 75,649 287,973Depreciation, depletion, amortization and accretion 1,749,056 1,708,744 1,674,901 1,859,327 485,621 1,938,389Property impairments 402,131 237,292 237,370 125,210 21,339 108,919Exploration expenses 19,413 16,972 12,393 7,642 3,090 10,546Impact from derivative instruments:

Total (gain) loss on derivatives, net (91,085) 67,099 (90,432) 23,930 (53,448) (30,905)Total cash (paid) received on derivatives, net 69,553 89,522 32,401 (36,939) 8,670 (24,161)

Non-cash (gain) loss on derivatives, net (21,532) 156,621 (58,031) (13,009) (44,778) (55,066)Non-cash equity compensation 51,834 48,097 45,868 47,236 12,177 50,041Loss on extinguishment of debt — 26,055 554 7,133 — 7,133EBITDAX (non-GAAP) $ 1,978,896 $ 1,881,889 $ 2,363,617 $ 3,623,373 $ 858,019 $ 3,563,326

In thousands 2015 2016 2017 2018 2Q 2019 TTMNet cash provided by operating activities $ 1,857,101 $ 1,125,919 $ 2,079,106 $ 3,456,008 $ 783,396 $ 3,320,919Current income tax provision (benefit) 24 (22,939) (7,781) (7,776) — (7,776)Interest expense 313,079 320,562 294,495 293,032 68,471 279,158Exploration expenses, excluding dry hole costs 11,032 12,106 12,217 7,495 3,090 10,400Litigation Settlement — — (59,600) — — —Gain on sale of assets, net 23,149 304,489 55,124 16,671 (364) 9,808Tax benefit (deficiency) from stock-based compensation 13,177 (9,828) — — — —Other, net (10,044) (10,636) (8,529) (16,349) (1,853) (15,630)Changes in assets and liabilities (228,622) 162,216 (1,415) (125,708) 5,279 (33,553)EBITDAX (non-GAAP) $ 1,978,896 $ 1,881,889 $ 2,363,617 $ 3,623,373 $ 858,019 $ 3,563,326


ADJUSTED Earnings Reconciliation To GAAPOur 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 pershare 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, and gainsand losses on asset sales. Management believes these measures provide useful information to analysts and investors for analysis of our operating results. In addition, management believesthese 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 anentity’s specific derivative portfolio, impairment methodologies, and property dispositions. Adjusted earnings and adjusted earnings per share should not be considered in isolation or as analternative to, or more meaningful than, earnings or diluted earnings per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures ofother 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 theperiods presented.

1. Computed by applying a combined federal and state statutory tax rate of 24.5% in effect for 2019 and 24.0% in effect for 2018 to the pre-tax amount of adjustments associated with our operations in the United States.

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Three months ended June 30,2019 2018

In thousands, except per share data $ Diluted EPS $ Diluted EPSNet income attributable to Continental Resources (GAAP) $ 236,557 $ 0.63 $ 242,464 $ 0.65

Adjustments:Non-cash (gain) loss on derivatives (44,778) 17,443Property impairments 21,339 29,162(Gain) loss on sale of assets, net 364 (6,711)Total tax effect of adjustments (1) 5,654 (9,481)

Total adjustments, net of tax (17,421) (0.04) 30,413 0.08Adjusted net income (non-GAAP) $ 219,136 $ 0.59 $ 272,877 $ 0.73Weighted average diluted shares outstanding 374,009 374,505Adjusted diluted net income per share (non-GAAP) $ 0.59 $ 0.73

Six months ended June 30,2019 2018

In thousands, except per share data $ Diluted EPS $ Diluted EPSNet income attributable to Continental Resources (GAAP) $ 423,533 $ 1.13 $ 476,410 $ 1.27

Adjustments:Non-cash (gain) loss on derivatives (30,592) 11,465Property impairments 46,655 62,946(Gain) loss on sale of assets, net 112 (6,751)Total tax effect of adjustments (1) (3,962) (16,054)

Total adjustments, net of tax 12,213 0.03 51,606 0.14Adjusted net income (non-GAAP) $ 435,746 $ 1.16 $ 528,016 $ 1.41Weighted average diluted shares outstanding 374,557 374,583Adjusted diluted net income per share (non-GAAP) $ 1.16 $ 1.41


Revenues and transportation expenses associated with production from our operated properties are reported separately. For non-operated properties, we receive a net payment from theoperator for our share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds received. As a result,the separate presentation of revenues and transportation expenses from our operated properties differs from the net presentation from non-operated properties. This impacts the comparabilityof certain operating metrics, such as per-unit sales prices, when such metrics are prepared in accordance with U.S. GAAP using gross presentation for some revenues and net presentation forothers.

In order to provide metrics prepared in a manner consistent with how management assesses the Company's operating results and to achieve comparability between operated and non-operatedrevenues, we may present crude oil and natural gas sales net of transportation expenses, which we refer to as "net crude oil and natural gas sales," a non-GAAP measure. Average sales pricescalculated using net crude oil and natural gas sales are referred to as "net sales prices," a non-GAAP measure, and are calculated by taking revenues less transportation expenses divided bysales volumes, whether for crude oil or natural gas, as applicable. Management believes presenting our revenues and sales prices net of transportation expenses is useful because it normalizesthe presentation differences between operated and non-operated revenues and allows for a useful comparison of net realized prices to NYMEX benchmark prices on a Company-wide basis.

The following table presents a reconciliation of crude oil and natural gas sales (GAAP) to net crude oil and natural gas sales and related net sales prices (non-GAAP) for the periods presented.

Net Sales Prices Reconciliation To GAAP

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Three months ended June 30, 2019 Three months ended June 30, 2018In thousands Crude oil Natural gas Total Crude oil Natural gas TotalCrude oil and natural gas sales (GAAP) $ 1,005,146 $ 132,279 $ 1,137,425 $ 946,884 $ 190,644 $ 1,137,528Less: Transportation expenses (45,981) (7,412) (53,393) (40,217) (7,037) (47,254)Net crude oil and natural gas sales (non-GAAP) $ 959,165 $ 124,867 $ 1,084,032 $ 906,667 $ 183,607 $ 1,090,274Sales volumes (MBbl/MMcf/MBoe) 17,549 75,254 30,091 14,311 69,310 25,863Net sales price (non-GAAP) $ 54.66 $ 1.66 $ 36.03 $ 63.35 $ 2.65 $ 42.16

Six months ended June 30, 2019 Six months ended June 30, 2018In thousands Crude oil Natural gas Total Crude oil Natural gas TotalCrude oil and natural gas sales (GAAP) $ 1,916,264 $ 330,745 $ 2,247,009 $ 1,853,165 $ 398,215 $ 2,251,380Less: Transportation expenses (87,628) (14,903) (102,531) (80,603) (15,948) (96,551)Net crude oil and natural gas sales (non-GAAP) $ 1,828,636 $ 315,842 $ 2,144,478 $ 1,772,562 $ 382,267 $ 2,154,829Sales volumes (MBbl/MMcf/MBoe) 34,922 149,944 59,912 28,993 136,040 51,667Net sales price (non-GAAP) $ 52.36 $ 2.11 $ 35.79 $ 61.14 $ 2.81 $ 41.71

Year ended December 31, 2018In thousands Crude oil Natural gas TotalCrude oil and natural gas sales (GAAP) $ 3,792,594 $ 886,128 $ 4,678,722Less: Transportation expenses (162,312) (29,275) (191,587)Net crude oil and natural gas sales (non-GAAP) $ 3,630,282 $ 856,853 $ 4,487,135Sales volumes (MBbl/MMcf/MBoe) 61,332 284,730 108,787Net sales price (non-GAAP) $ 59.19 $ 3.01 $ 41.25


Cash G&A Reconciliation To GAAP

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&Adetermined in accordance with U.S. GAAP less non-cash equity compensation expenses, expressed on a per-Boe basis. We report and provideguidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of costmanagement and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used byanalysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&Aspend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A per Boe shouldnot 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 becomparable 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.

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Three months ended June 30, Six months ended June 30,2019 2018 2019 2018 2019 Guidance

Total G&A per Boe (GAAP) $ 1.57 $ 1.82 $ 1.58 $ 1.75 $1.55 - $1.85

Less: Non-cash equity compensation per Boe $ (0.40) $ (0.41) $ (0.40) $ (0.42) ($0.40) - ($0.50)

Cash G&A per Boe (non-GAAP) $ 1.17 $ 1.41 $ 1.18 $ 1.33 $1.15 - $1.35

2015 2016 2017 2018

Total G&A per Boe (GAAP) $ 2.34 $ 2.14 $ 2.16 $ 1.69

Less: Non-cash equity compensation per Boe $ (0.64) $ (0.61) $ (0.52) $ (0.44)

Cash G&A per Boe (non-GAAP) $ 1.70 $ 1.53 $ 1.64 $ 1.25

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