4pm 103019 investor update october 2019...

Investor UpdateOctober 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 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 andstatements or information concerning the Company’s future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, ratesof 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 identifyforward-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 andtiming 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 giventhat 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; thegeographic concentration of our operations; financial, market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oiland natural gas exploration, drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and otherrevenue-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 sustainproduction; our ability to pay future dividends or complete share repurchases; the availability or cost of equipment and oilfield services; leasehold terms expiring on undevelopedacreage 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 ofdevelopment expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and ourbusiness, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the otherrisks 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, 2018, registration statementsand 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 therisks or uncertainties described in this presentation occur, or should underlying assumptions prove incorrect, the Company’s actual results and plans could differ materially fromthose expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as expresslystated 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 ofnew 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 typicallycharacterized 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 todemonstrate 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 ofproved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties willdiffer 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

Continental Resources Focused on Disciplined, Oil-Weighted Growth and Building Shareholder Value

3

Value Drivers

• Cash Flow Positive Growth and Strong Returns

• Lowest Cost Operator Amongst Oil-Weighted Peers(1)

• Superior Oil-Weighted Portfolio: 3 Top U.S. Plays (Bakken & OK SCOOP/STACK)

• Strong Corporate Returns Compete with Broader Market

• Growing Strategic Minerals Portfolio

• High Value Water Infrastructure Assets

• Total Shareholder Return Strategy $0.05 per Share Quarterly Dividend (Nov. 2019)(2)

$187MM in Share Repurchases (YTD Oct. 2019)

3Q19 Results: Driven by Assets & Execution

• $158MM Net Income in 3Q19 $582MM Net Income YTD 2019

• 20% Oil Growth YoY (198,074 Bopd)

• Bakken: 13% Oil Growth YoY 57 Gross Op. Wells: 2,313 Boepd Avg/Well Initial Rate(3)

• South: 62% Oil Growth YoY SpringBoard:

• 23,641 Bopd in 3Q19• Exceeded 3Q19 Oil Target by 31% • Raising 4Q19 Target from 22,000 Bopd to ~24,000 Bopd

CLR STACK: • Two, 7-Well Oil Units: 38,320 Bopd Combined Initial Rate(3)

• 2019 Capex In Line with Expectations

1. Statement is based on information presented under heading “Low Cost per Boe” on slide 10.2. All dividends beyond the November 2019 dividend are subject to Board approval.3. Maximum average 24-hour IP rate.


1. 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.2. See the calculation of ROCE for historical periods on slide 28.3. Average WTI price is the SEC price used for reserve calculations; rounded to the nearest dollar.4. Net Debt and EBITDAX are non-GAAP measures. See slides 22-24 for definitions and reconciliations of historical amounts to the most comparable U.S. GAAP financial measures. With respect to projected amounts, please see slides 22-24 for an

explanation of the factors that make a quantitative reconciliation of these forward-looking estimates to U.S. GAAP not possible.5. 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 trailing

4 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.

CLR: Delivering Competitive Returns & Driving Down Debt

4

15%13% 12%

8% 8%7%

0%0%

4%

8%

12%

16%

CLR 2018 Corporate Returns vs. the Market(5)

(Source: Bloomberg)

APA

NBL XEC

OAS

WLL WPXFANG

PXDEOG CXO CLR

-15%

-10%

-5%

0%

5%

Impl

ied

FCF

Yiel

d

2019 Maintenance Capital Implied FCF Yields(1)

(Source: Jefferies)

$7.1B $6.6B

$6.3B

$5.5B $5.5B

$4.2B

3.6x 3.5x

2.7x

1.5x 1.6x

1.0x

0.0x0.5x1.0x1.5x2.0x2.5x3.0x3.5x

2015 2016 2017 2018 3Q19 2023E

Net

Deb

t/TTM

EB

ITD

AX(4

)

CLR Net Debt Continues to Decline

-2%-1%

4%

14%

9-12%$50

$43

$51

$66

$55 (Est)

2015 2016 2017 2018 2019E-4%

0%

4%

8%

12%

16%

Avg. WTI Price(3) ($)

CLR ROCE(2): 9-12% at $55 WTI in 2019


CLR Bakken: Exceptional Assets And ExecutionDelivering Consistent, Industry-Leading Results

5

Since Moving into “Multi-Zone Unit Development”

• 440 Gross Operated Unit Wells Completed (2017-2019 YTD)

• ~2,300 Boepd Avg/Well Initial Rate(1)

• 80% Oil

• Widely Distributed Results

• 2017 & 2018 Programs Paid Out in ~1 Year

CLR Developed Bakken Units 2017- 2019 YTD

2017 Units2018 Units2019 YTD Units

CLR Bakken Units

0

50,000

100,000

150,000

200,000

250,000

300,000

0 50 100 150 200 250 300 350

Avg

. Cum

ulat

ive

Boe

Days

2017 (133 Wells)2018 (160 Wells)2019 YTD (147 Wells)

Average Cumulative Production per Well2017, 2018 & 2019 YTD Drilling Programs

1. Maximum average 24-hour IP rate.


Bakken Manufacturing Mode Continues to Build Operational Efficiencies

6

Operational Efficiencies (2017-2019 YTD)

$500K Well Cost Reduction

55% Increase Completed Lateral Ft/Day

60% Decrease Completion Cycle Time

6% LOE per Boe Improvement38

20

15

10

20

30

40

2017 2018 2019

Day

s

Completion Cycle Time

1,090'

1,417'

1,686'

400

800

1,200

1,600

2017 2018 2019

Completed Lat. Feet per Day


CLR South: Oil Production Up 62% Year-Over-Year

7

Oklahoma SCOOP and STACK Assets Continue to Deliver Outstanding Results

Driven by Geologically Superior Oil-Rich Acreage Position & Operational Expertise

80 Gross Operated Wells Completed in 3Q19 (63 SCOOP; 17 STACK)

Record South Production: 133,266 Boepd (44,854 Bopd) in 3Q19

Normal-Pressured

CLR SOUTH: SCOOP & STACK

CLR Wells with > 1,500 Boepd IP30

CLR Acreage

Anadarko Basin Petroleum System

Over/Normal-Pressured Windows

3Q19 Units:Reba Jo &

Schulte

SCOOP

CLR Headquarters

Over-Pressured

STACK

Anadarko Basin Petroleum System

Project SpringBoard

Oklahoma


SCOOP SpringBoard Hits 23,641 Net Bopd in 3Q19 31% Above Target

8

1,300

5,260

8,700

15,100

23,641

~24,000

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

22,000

24,000

3Q18 4Q18 1Q19 2Q19 3Q19 4Q19Target

Sprin

gBoa

rd O

il Pr

oduc

tion

(Bop

d)

Average Production

Exceeded 3Q19 Target by 31%

+31%

4Q19 Oil Target Raised to ~24,000 Net Bopd

Increased Targ

et

100

1,000

10,000

0 30 60 90 120 150 180

Boe

pd

Days

Woodford Wells Perform as Expected

32 Woodford Well Average (~77% Oil)

100

1,000

10,000

0 10 20 30 40 50 60

Boe

pd

Days

SpringBoard Range of Well Outcomes1.3 MMBoe Springer Type Curve52 Springer Well Average

Springer Rows 1, 2 & 3 Perform as Expected

52 Springer Well Average (~80% Oil)


0 10 20 30 40 50 60

20

40

60

80

100

120

140

Producing Days

Avg.

Cum

ulat

ive

MB

oe

Oil Unit Wells Outperforming Unit Type Curve

STACK: Continued Outstanding Results57,292 Boepd (67% Oil; 38,320 Bopd) From 2 New Units

9

Reba Jo & Schulte Units• 14 Total Wells: Over-Pressured Oil Window

• 3-4 Wells in Both Upper and Lower Meramec Reservoirs

• Avg/Well Initial Rate(1): 4,092 Boepd (67% Oil)

8 Units Completed Since Shift to Full Field Development• Outperforming Expectations and Type Curves

• Proper Density and Superior Reservoir Quality

Normal-PressuredOver-Pressured

JalouHomsey

Boden

Simba

Tolbert

Lugene

CLR STACK: Oil & Condensate Units in Over-Pressured Window

CLR Meramec Wells > 1,500 Boepd IP30CLR AcreageOver/Normal-Pressured Line

CLR Condensate Unit CLR Oil Unit

Reba Jo

Schulte

0 20 40 60 80 100 1200

100

200

300

400

Producing Days

Avg.

Cum

ulat

ive

MB

oe

Condensate Unit Wells Outperforming Parent Type Curve

1. Maximum average 24-hour IP rate.


CLR Continues To Be The Low Cost Leader Amongst Oil-Weighted Peers

10

1. Source: Public company filings as of 1H19. 2. Source: Tudor, Pickering & Holt estimates for full-year 2019.

APA

CXO

DVN

ECAEOG FANG

MRO

NBL

OASPXD WLL

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

1H19 Oil Production % (Excludes Liquids)

1H19

LOE

per B

oe

CLR 1H19 CLR YTD

APACXO

DVN

EOG

MRO

NBL

PXD

ECA

WPX

XEC OAS

WLL

4%

6%

8%

10%

12%

14%

16%

18%

20%

22%

$1.25 $1.75 $2.25 $2.75 $3.25 $3.75

2019

E G

&A

/ EB

ITD

A

2019E G&A / Boe

Top-Tier G&A(2)

Source: Tudor, Pickering & Holt

CLR 2019ECLR YTD


CLR Delivers on Guidance Unique Insider Ownership Ensures Shareholder Alignment

11

1. Annual guidance calculated at the upper end of the most current guidance provided for each year.2. Source: Bloomberg as of September 30, 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

350,000

400,000

2011

2012

2013

2014

2015

2016

2017

2018

ProductionBoepd 77.8%

3.5% 2.1% 1.4% 1.3% 0.8% 0.4%0%

10%

20%

30%

40%

50%

60%

70%

80%

CLR Insider Ownership vs. the Market(2)

(Source: Bloomberg)


Contact Information

12

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 13

Reference Materials


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 21 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 21 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.

14

• ~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

15

1. Free cash flow (FCF) is a non-GAAP measure. See slide 21 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 21 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.

$1B Program

~$1.3BReduction

~$75MM/Year

$0B

$5B

Cash Available Annual Dividend Share Repurchases Debt Reduction

$187MM Executed as of 10/29/19

Potential To Grow(2)

Targeting $4.2B LTD

$5B Cumulative

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(2)

• $1B Share-Repurchase Program

• Debt Reduction (Targeting $4.2B Long-Term)

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


Long Term Outlook Multi-$ Billion IPO Potential

CLR’s Minerals Strategy Enhances Returns to Shareholders

16

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 Hit CLR Minerals (2019 YTD)

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’s 2019 PlanSustained Returns, FCF, Low-Cost Oil-Weighted Growth

17

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 21 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


2019 Guidance

18

Production & Capital 2019 Guidance

Capital expenditures budget $2.6 billion

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

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

Operating Expenses

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

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

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

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

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

Average Price Differentials

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

Henry Hub natural gas(2) ($ per Mcf) ($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 27 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.


Completed $500MM Partial Call of $1.6B

5% Senior Notes due 2022 on Sept. 12, 2019

Financial Metrics

• 1.67x: Net debt(1) / 3Q19 Annualized EBITDAX(1)

• 1.63x: Net debt(1) / TTM EBITDAX(1)

Financial Strength

• Earliest debt maturity is 2022 bonds (callable)

• 4.5% average interest rate in 3Q19

Unsecured Credit Facility

• Ample liquidity with $1.5B revolver;

$1.2B available at 9/30/19

Continued Focus On Net Debt Reduction

19

($ B

illio

ns)

Net Debt(1) Declining

$7.1 $6.6 $6.3$5.5 $5.5

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

YE 2015 YE 2016 YE 2017 YE 2018 9/30/19

1. Net debt and EBITDAX are non-GAAP measures. See slides 22-24 for definitions and reconciliations of these measures to the most comparable U.S. GAAP financial measures.

$1,100 Remaining

$1,500

$300 Drawn

$1,000 $1,000 $700

$1,200Undrawn

0

500

1,000

1,500

2,000

2019 2020 2021 2022 2023 2023 2024 2028 2044

($M

M)

5.0%

4.5%

3.8%

4.9%

Callable3/15/17

Debt Maturities Summary

4.375%

Balance9/30/19


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 26 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 23-24 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 27 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)

20

2015 2016 2017 2018 3Q 2019

Crude oil net sales price ($/Bbl)(2) $40.50 $35.51 $45.70 $59.19 $51.28

Natural gas net sales price ($/Mcf)(2) $2.31 $1.87 $2.93 $3.01 $1.12

Oil production (Bopd) 146,622 128,005 138,455 168,177 198,074

Natural gas production (Mcfpd) 450,558 533,442 625,093 780,083 805,446

Total production (Boepd) 221,715 216,912 242,637 298,190 332,315

EBITDAX ($000's)(3) $1,978,896 $1,881,889 $2,363,617 $3,623,373 $828,704

Key Operational Statistics (per Boe)(4)

Oil equivalent net sales price (excludes derivatives) ($/Boe)(2) $31.48 $25.55 $33.65 $41.25 $33.30

Production expenses $4.30 $3.65 $3.66 $3.59 $3.73

Production taxes $2.47 $1.79 $2.35 $3.25 $2.84

Cash G&A(5) $1.70 $1.53 $1.64 $1.25 $1.12

Interest expense $3.86 $4.04 $3.32 $2.69 $2.22

Total of selected costs $12.33 $11.01 $10.97 $10.78 $9.91

Margin(1) $19.15 $14.54 $22.68 $30.47 $23.39

Margin % 61% 57% 67% 74% 70%


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.

21

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 September 30, 2019, the Company’s total debt was $5.57 billion and its net debt amounted to $5.54 billion,representing total debt of $5.57 billion less cash and cash equivalents of $35.3 million. From time to time the Company provides forward-looking netdebt forecasts; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to the mostdirectly comparable forward-looking GAAP measure of total debt because management cannot reliably quantify certain of the necessarycomponents of such 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 9/30/19

Total debt (GAAP) $7,117,788 $6,579,916 $6,353,691 $5,768,349 $5,570,829

Less: Cash and cash equivalents (11,463) (16,643) (43,902) (282,749) (35,260)

Net debt (non-GAAP) $7,106,325 $6,563,273 $6,309,789 $5,485,600 $5,535,569


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.We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, propertyimpairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, non-cash equitycompensation expense, and losses on extinguishment of debt as applicable. EBITDAX is not a measure of net income or net cash provided byoperating activities as determined by U.S. GAAP.

Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the resultsof our operations from period to period without regard to our financing methods or capital structure. Further, we believe EBITDAX is a widelyfollowed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, ifany. We exclude the items listed above from net income/loss and net cash provided by operating activities in arriving at EBITDAX because theseamounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets,capital structures and the method by which the assets were acquired.

EBITDAX should not be considered as an alternative to, or more meaningful than, net income/loss or net cash provided by operating activities 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 capitaland tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAXmay not be comparable to other similarly titled measures of other companies. From time to time the Company provides forward-lookingEBITDAX forecasts; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to themost directly comparable forward-looking GAAP measure of net income (loss) and net cash provided by operating activities becausemanagement cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items infuture 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 3Q 2019 TTMNet income (loss) $ (353,668) $ (399,679) $ 789,447 $ 989,700 $ 157,422 $ 779,486Interest expense 313,079 320,562 294,495 293,032 68,090 273,839Provision (benefit) for income taxes (181,417) (232,775) (633,380) 307,102 49,747 240,254Depreciation, depletion, amortization and accretion 1,749,056 1,708,744 1,674,901 1,859,327 484,031 1,953,087Property impairments 402,131 237,292 237,370 125,210 20,199 105,348Exploration expenses 19,413 16,972 12,393 7,642 2,472 10,694Impact from derivative instruments:

Total (gain) loss on derivatives, net (91,085) 67,099 (90,432) 23,930 (1,195) (34,125)Total cash received (paid) on derivatives, net 69,553 89,522 32,401 (36,939) 30,484 7,800

Non-cash (gain) loss on derivatives, net (21,532) 156,621 (58,031) (13,009) 29,289 (26,325)Non-cash equity compensation 51,834 48,097 45,868 47,236 12,870 51,181Loss on extinguishment of debt — 26,055 554 7,133 4,584 4,584EBITDAX (non-GAAP) $ 1,978,896 $ 1,881,889 $ 2,363,617 $ 3,623,373 $ 828,704 $ 3,392,148

In thousands 2015 2016 2017 2018 3Q 2019 TTMNet cash provided by operating activities $ 1,857,101 $ 1,125,919 $ 2,079,106 $ 3,456,008 $ 806,972 $ 3,267,143Current income tax provision (benefit) 24 (22,939) (7,781) (7,776) — 2Interest expense 313,079 320,562 294,495 293,032 68,090 273,839Exploration expenses, excluding dry hole costs 11,032 12,106 12,217 7,495 2,472 10,548Litigation Settlement — — (59,600) — — —Gain (loss) on sale of assets, net 23,149 304,489 55,124 16,671 (535) 7,763Tax benefit (deficiency) from stock-based compensation 13,177 (9,828) — — — —Other, net (10,044) (10,636) (8,529) (16,349) (2,142) (14,736)Changes in assets and liabilities (228,622) 162,216 (1,415) (125,708) (46,153) (152,411)EBITDAX (non-GAAP) $ 1,978,896 $ 1,881,889 $ 2,363,617 $ 3,623,373 $ 828,704 $ 3,392,148


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, gains andlosses on asset sales, and losses on extinguishment of debt as applicable. Management believes these measures provide useful information to analysts and investors for analysis of ouroperating results. In addition, management believes these measures are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil andgas industry to allow for analysis without regard to an entity’s specific derivative portfolio, impairment methodologies, and property dispositions. Adjusted earnings and adjusted earnings pershare should not be considered in isolation or as an alternative to, or more meaningful than, earnings or diluted earnings per share as determined in accordance with U.S. GAAP and may notbe 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 adjustedearnings and adjusted diluted earnings per share for the periods 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 September 30,2019 2018

In thousands, except per share data $ Diluted EPS $ Diluted EPSNet income attributable to Continental Resources (GAAP) $ 158,162 $ 0.43 $ 314,169 $ 0.84

Adjustments:Non-cash loss on derivatives 29,289 548Property impairments 20,199 23,770(Gain) loss on sale of assets, net 535 (1,510)Loss on extinguishment of debt 4,584 7,133Total tax effect of adjustments (1) (13,380) (7,093)

Total adjustments, net of tax 41,227 0.11 22,848 0.06Adjusted net income (non-GAAP) $ 199,389 $ 0.54 $ 337,017 $ 0.90Weighted average diluted shares outstanding 370,676 374,623Adjusted diluted net income per share (non-GAAP) $ 0.54 $ 0.90

Nine months ended September 30,2019 2018

In thousands, except per share data $ Diluted EPS $ Diluted EPSNet income attributable to Continental Resources (GAAP) $ 581,695 $ 1.56 $ 790,580 $ 2.11

Adjustments:Non-cash (gain) loss on derivatives (1,303) 12,013Property impairments 66,854 86,715(Gain) loss on sale of assets, net 647 (8,261)Loss on extinguishment of debt 4,584 7,133Total tax effect of adjustments (1) (17,342) (23,147)

Total adjustments, net of tax 53,440 0.14 74,453 0.20Adjusted net income (non-GAAP) $ 635,135 $ 1.70 $ 865,033 $ 2.31Weighted average diluted shares outstanding 373,506 374,762Adjusted diluted net income per share (non-GAAP) $ 1.70 $ 2.31


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 tables present 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 September 30, 2019 Three months ended September 30, 2018In thousands Crude oil Natural gas Total Crude oil Natural gas TotalCrude oil and natural gas sales (GAAP) $ 989,297 $ 92,103 $ 1,081,400 $ 1,038,558 $ 234,680 $ 1,273,238Less: Transportation expenses (53,038) (9,000) (62,038) (39,336) (6,672) (46,008)Net crude oil and natural gas sales (non-GAAP) $ 936,259 $ 83,103 $ 1,019,362 $ 999,222 $ 228,008 $ 1,227,230Sales volumes (MBbl/MMcf/MBoe) 18,258 74,101 30,608 15,190 73,029 27,361Net sales price (non-GAAP) $ 51.28 $ 1.12 $ 33.30 $ 65.78 $ 3.12 $ 44.85

Nine months ended September 30, 2019 Nine months ended September 30, 2018In thousands Crude oil Natural gas Total Crude oil Natural gas TotalCrude oil and natural gas sales (GAAP) $ 2,905,561 $ 422,848 $ 3,328,409 $ 2,891,722 $ 632,896 $ 3,524,618Less: Transportation expenses (140,666) (23,903) (164,569) (119,939) (22,620) (142,559)Net crude oil and natural gas sales (non-GAAP) $ 2,764,895 $ 398,945 $ 3,163,840 $ 2,771,783 $ 610,276 $ 3,382,059Sales volumes (MBbl/MMcf/MBoe) 53,179 224,045 90,520 44,183 209,069 79,028Net sales price (non-GAAP) $ 51.99 $ 1.78 $ 34.95 $ 62.73 $ 2.92 $ 42.80

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 September 30, Nine months ended September 30,

2019 2018 2019 2018 2019 Guidance

Total G&A per Boe (GAAP) $ 1.54 $ 1.61 $ 1.57 $ 1.70 $1.55 - $1.85

Less: Non-cash equity compensation per Boe $ (0.42) $ (0.43) $ (0.41) $ (0.42) ($0.40) - ($0.50)

Cash G&A per Boe (non-GAAP) $ 1.12 $ 1.18 $ 1.16 $ 1.28 $1.15 - $1.35

FY 2015 FY 2016 FY 2017 FY 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


Calculation Of Return On Capital Employed (ROCE)

The following table shows the calculation of ROCE for the following periods.

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In thousands 2015 2016 2017 2018Net income (loss) attributable to Continental Resources $ (353,668) $ (399,679) $ 789,447 $ 988,317

Impact from derivative instruments:

Total (gain) loss on derivatives, net (91,085) 67,099 (90,432) 23,930

Total cash received (paid), net 69,553 89,522 32,401 (36,939)

Non-cash (gain) loss on derivatives, net (21,532) 156,621 (58,031) (13,009)

Provision (benefit) for income taxes (181,417) (232,775) (633,380) 307,102

Non-cash equity compensation 51,834 48,097 45,868 47,236

Interest expense 313,079 320,562 294,495 293,032

Loss on extinguishment of debt — 26,055 554 7,133

Adjusted EBIT $ (191,704) $ (81,119) $ 438,953 $ 1,629,811

Equity attributable to Continental Resources - beginning of period $ 4,967,844 $ 4,668,900 $ 4,301,996 $ 5,131,203

Total debt - beginning of period 5,928,878 7,117,788 6,579,916 6,353,691

Capital employed - beginning of period 10,896,722 11,786,688 10,881,912 11,484,894

Equity attributable to Continental Resources - end of period 4,668,900 4,301,996 5,131,203 6,145,133

Total debt - end of period 7,117,788 6,579,916 6,353,691 5,768,349

Capital employed - end of period 11,786,688 10,881,912 11,484,894 11,913,482

Average capital employed $ 11,341,705 $ 11,334,300 $ 11,183,403 $ 11,699,188

ROCE (1.7)% (0.7)% 3.9% 13.9%

4pm 103019 investor update october 2019...

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