022620 Investor Update February 2020filecache.investorroom.com/mr5ir_clr/307/download... ·...

Investor UpdateFebruary 2020

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 effects of any national or international health crisis; 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 losses resultingtherefrom; difficulties in estimating proved reserves and other revenue-based measures; declines in the values of our crude oil and natural gas properties resulting in impairmentcharges; 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 andoilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drillingand well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative andregulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, includingfrom 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-Kfor the year ended December 31, 2019, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from timeto 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, Inc. Responsible Stewardship Of Shareholder Assets

3

1. As of December 31, 2019.2. Statement is based on comparing actuals with the final annual production and LOE per Boe guidance provided for each year since 2008.3. Statement is based on information presented on slide 7.4. Source: Bloomberg as of February 17, 2020. 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 3Q19 for companies within the S&P 500 Index.5. Source: Enverus.

Unmatched Shareholder Alignment 78% Insider Ownership(1)

Reliable Performance 10+ Consecutive Years of Meeting or Exceeding Guidance(2)

Low Cost Producer Lowest Per Unit Costs Amongst Oil-Weighted Peers(3)

Shareholder Capital Return Share Repurchases, Debt Reduction & Dividend

Strong Corporate Returns Return on Capital Outperforming S&P 500(4)

Top Tier Oil-Weighted Assets #1 Oil Producer in the Bakken & Oklahoma(5)

Comprehensive ESG Approach 2019 Sustainability Report Expected 2Q20


CLR’s Track Record of Outstanding Performance

4

1. Net debt and EBITDAX are non-GAAP measures. See slides 21-23 for definitions and reconciliations of these measures to the most comparable U.S. GAAP financial measures.

2. Free cash flow (FCF) is a non-GAAP measure. See slide 20 for a definition and reconciliation of this measure to the most comparable U.S. GAAP measure. 3. See the calculation of ROCE on slide 27. 4. Average WTI price is the SEC price used for reserve calculations; rounded to the nearest dollar.

Total Growth YoY

Up 57%2017-2019

FCF(2) ($ MM)

Up $1.4 B2017-2019

ROCE(3)

9.6% AVG2017-2019

Down $1.3 BSince YE16

Net Debt ($ B)(1)


CLR’s Capital Efficient & Sustainable Growth

5

1. Reserve replacement ratio represents the total change in proved reserves, excluding aggregate production, divided by aggregate production over the four year period from 2016-2019 on a Boe basis. 2. F&D cost per Boe represents the Company’s net exploration and development costs incurred for operated wells having first production in the respective year divided by the net estimated recoverable reserves for those wells expressed in barrels of oil equivalent. 3. See the calculation of Margin on slide 19.

Up 32%(198% Reserve

Replacement Ratio(1))

Proved Reserves

Down 20%

F&D Cost(2) ($/Boe)

Up 29%

Margin(3) ($/Boe)

PROPERTY OF CONTINENTAL RESOURCES, INC. REPRODUCTION AND DISTRIBUTION WITH WRITTEN PERMISSION ONLYPROPERTY OF CONTINENTAL RESOURCES, INC. REPRODUCTION AND DISTRIBUTION WITH WRITTEN PERMISSION ONLY 6

2019: Another Year Of Exceptional Performance

1. Net debt is a non-GAAP measure. See slide 21 for a definition and reconciliation of this measure to the most comparable U.S. GAAP financial measure. 2. Free cash flow (FCF) is a non-GAAP measure. See slide 20 for a definition and reconciliation of this measure to the most comparable U.S. GAAP measure. 3. See the calculation of ROCE on slide 27.

FCF(2) $608 MM Exceeded Guidance ($500 MM-$600 MM)

ROCE(3) 11% Delivered Guidance (9-12%)

Capex $2.66 B Maintained Capital Spend Expectations

Daily Oil Production 197,991 Delivered Guidance (18% Growth YOY)

LOE per Boe $3.58 Delivered Guidance ($3.50-$4.00)

Total G&A per Boe $1.57 Delivered Guidance ($1.55-$1.85)

$406 MM Shareholder Capital Return Share Repurchases: $190 MM

Net Debt(1) Reduction: 198 MM

Initiated Quarterly Dividend: $18 MM


CLR: Lowest Cost Operator Amongst Oil-Weighted Peers

7

1. Source: Public Company Filings as of December 31, 2019. Select peers include CXO, DVN, HES, MRO, NBL, OVV, PXD.

$0.00

$4.00

$8.00

$12.00

CLR2019

Peers 2019

Lowest LOE per Boe Amongst Peers(1)

(Source: Public Company Filings)

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

CLR2019

Peers 2019

Lowest G&A per Boe Amongst Peers(1)

(Source: Public Company Filings)

$3.00

$3.50

$4.00

$4.50

2015 2016 2017 2018 2019

LOE per Boe Down 17% Since 2015

$1.00

$1.25

$1.50

$1.75

$2.00

$2.25

$2.50

2015 2016 2017 2018 2019

G&A per Boe Down 33% Since 2015


2020 Plan: Exercising Market & Capital Discipline

1. Free cash flow (FCF) is a non-GAAP measure. With respect to the projected amount, please see slide 20 for an explanation of the factors that make a quantitative reconciliation of this forward-looking estimate to U.S. GAAP not possible.

Cash Flow from Operations: $2.9 B to $3.0 B

• Free Cash Flow(1): $350 MM to $400 MM

• Budgeted at $55 WTI and $2.50 HH

• $5 Change in WTI = Approx. $300 MM in Cash Flow

Additional 2020 Guidance & Operating Detail Available on Slide 17

Flat Capex Spend YoY: $2.65 B

• $2.2 B D&C (Flat Spend YoY)

• $314 MM Leasehold and Facilities

• $125 MM for Minerals ($100 MM Funded by FNV)

• 15% Reduction in Rig Count YoY

• Approx. $700 MM Capital Spend in 2020 with First Production Expected in 2021

Approx. 10% Avg. Growth CAGR for 2019-20

• Total Growth YoY: 4% to 6%

198,000 to 201,000 Bopd

935,000 to 960,000 Mcfpd

Continuing to Deliver Low Cost Operations

• $3.50 to $4.00 LOE per Boe

• $1.60 to $2.00 Total G&A per Boe

• 8.3% to $8.5% Production Tax

• $15.00 to $17.00 DD&A per Boe


CLR High Level Perspectives (2019-2021)

2019-2020

• Combined Deliver Approx. 10% Average Production CAGR

• Cumulative Volumes on Track with Original Estimate(1)

• 2020 Capex Projection 20% Lower than Original Estimate(1)

1. Original Five Year Vision estimate for 2020.

2020-2021

• Projecting Sequential Quarterly Growth in 2021

• Large Projects in 2020 Projected to Drive Double DigitGrowth from FY 2020 to 4Q21


CLR Five Year Outlook (2019-2023)

1. Free cash flow (FCF) is a non-GAAP measure. With respect to the projected amount, please see slide 20 for an explanation of the factors that make a quantitative reconciliation of this forward-looking estimate to U.S. GAAP not possible.

10

Five Year Vision Updated Original

Production CAGR 8-10% 10-15%

Free Cash Flow(1) $3.5 B to $4 B $5 B

Average Annual ROCE Low to Mid Teens Approx. 14%

Inventory Less than 30% Utilized Less than 30% Utilized

Commodity Price 2019-20: $55 WTI & $2.50 HH2021-23: $60 WTI & $2.50 HH $60 WTI & $3 HH

Vision for Shareholder Value Unchanged • Disciplined approach to balancing capital-efficient growth & capital return to benefit long term shareholders

Strategy• Responsibly aligning capital spending and associated growth to market fundamentals

Reducing capital spend by $1.5 billion from original estimates over five years


CLR Bakken: Delivering Exceptionally Consistent Results

2019: 148,416 Avg. Bopd; up 14% YoY

• 172 Gross Op Wells Completed

• 2019 Bakken Program Currently Approx. 75% Paid Out

• 18,000 Acres Added to Leasehold Position

2020 Bakken Program

• Avg. 9 Rigs; 175 Gross Operated Wells to be Completed

• Avg. Well Performance Expected to be in Line with 2017, 2018 & 2019 Drilling Programs

• Targeting Additional 5% CWC Reduction

100

200

300

0 1 2 3 4 5 6 7 8 9 10 11 12

Cum

ulat

ive

Prod

uctio

n (M

Boe

)

Months

2017 (133 Wells)

2018 (160 Wells)

2019 (172 Wells)

2020E (175 Wells)

Avg. Well Performance2017, 2018 & 2019 Drilling Programs

2020 Expected to be in Line

465 Gross Operated Wells on Line Last 3 Years


CLR South: Delivering Strong Oil-Weighted Results

2019: 43% Oil Growth YoY

• 41,695 Avg. Bopd; up 43% YoY

• 140 Gross Operated Wells Completed

• SpringBoard I 4Q19 Oil Production: 25,006 Bopd

Outperformed Original 3Q18 Growth Estimates by 50%

Drilling Cycle Times Reduced 25% in 2019

CWC Reduced 10% in 2019

2020 South Program

• Avg. 10.5 Rigs; 126 Gross Operated Wells to be Completed

• Projecting 35-40% Oil Growth YoY from SpringBoard I & II


Minerals OperatorDevelopment

Typical Minerals

OperatorDevelopment on Minerals

CLR Minerals

Value Uplift

Minerals & Water Enhancing Shareholder ValueSynchronized With CLR’s Drill Plan

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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.3. Estimated value based on current CLR internal estimates.

Strategic Advantage of CLR Minerals

Alignment with CLR development plan

>75% of CLR South op wells hit CLR minerals in 2019

90% of minerals acreage under CLR-operated units

CLR expects to earn 50% of revenue for 20% of cost(1)

Multi billion dollar IPO potential(2)

CLR’s Strategic Water Assets

CLR water business growing rapidly

Over 13 systems in place across Bakken and OK

Over 300 miles of gathering pipeline in place

Water sourcing, gathering, disposal and recycling

Over $1.5 billion estimated value from CLR water assets(3)

Value UpliftWater MidstreamProvider

OperatorDevelopment

Typical Water Operations

Water & Operator

DevelopmentAligned

CLR Water


CLR’s Comprehensive ESG Report Expected In 2Q20

14

CLR: Major Contributor to American Energy Renaissance

• First mover to call for the lifting of U.S. crude oil export ban in 2015

U.S. is now energy independent & a net exporter of oil & gas(1)

Virtues of the New Energy Era

• CO2 emissions have declined by 14% since 2007, thanks to the availability of natural gas(2)

• Access to affordable energy is driving economic growth & security

• Access to low-cost hydrocarbons is lifting the poor out of poverty

CLR’s Comprehensive ESG Report Expected in 2Q20

• ESG is a major contributor to CLR’s long-term business success

98% corporate gas capture

Think of us as a technologically elite company,

managed with integrity, always working to get

better at everything we do and forever dedicated

to changing the world for the better.

- Harold Hamm, Executive Chairman

“”

1. Source: U.S. Energy Information Administration, “U.S. petroleum exports exceed imports in September,” December 2019.2. Source: U.S. Energy Information Administration, “U.S. Energy-Related Carbon Dioxide Emissions, 2018,” November 2019.

For more info, visit www.clr.com/esg-report.


Contact Information

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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


Reference Materials


2020 Guidance & Operating Detail

17

Production & Capital 2020 Guidance

Capital expenditures budget $2.65 Billion

Oil Production (Bo per day) 198,000 to 201,000

Natural Gas Production (Mcf per day) 935,000 to 960,000

Operating Expenses

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

Production tax (% of net oil & gas revenue) 8.3% to $8.5%

Cash G&A expense(1) ($ per Boe) $1.10 to $1.40

Non-cash equity compensation ($ per Boe) $0.50 to $0.60

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

Average Price Differentials

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

Henry Hub natural gas(2) ($ per Mcf) ($0.50) to ($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 2020 total G&A (cash and non-cash) is an expected range of $1.60 - $2.00 per Boe.2. Includes natural gas liquids production in differential range. 3. Includes $125 million allocated to minerals royalty acquisitions, of which $100 million will be recouped from Franco-Nevada.

Capital Expenditures Budget ($ in Millions)

North D&C $1,368

South D&C $843

Leasehold, Facilities, Other(3) $439

Total $2,650

Operational Detail North South Total

Average Rigs 9 10.5 19.5

Gross Operated Wells 177 126 303

Net Operated Wells 122 84 206

Total Net Wells 154 91 245


Completed $500 MM Partial Call of $1.6 B

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

Financial Metrics

• 1.46x: Net debt(1) / 4Q19 Annualized EBITDAX(1)

• 1.53x: Net debt(1) / TTM EBITDAX(1)

Financial Strength

• 4.5% average interest rate in 4Q19

• Earliest debt maturity is 2022 bonds (callable)

Unsecured Credit Facility

• Ample liquidity with $1.5 B revolver;

fully undrawn at 1/31/2020

Continued Focus On Net Debt ReductionApprox. $200 MM Net Debt Reduction in 2019

18

1. Net debt and EBITDAX are non-GAAP measures. See slides 21-23 for definitions and reconciliations of these measures to the most comparable U.S. GAAP financial measures. With respect to the projected amount, please see slides 21-23 for an explanation of the factors that make a quantitative reconciliation of this forward-looking estimate to U.S. GAAP not possible.


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 25 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 22-23 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 26 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)

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2015 2016 2017 2018 4Q 2019 2019

Crude oil net sales price ($/Bbl)(2) $40.50 $35.51 $45.70 $59.19 $51.33 $51.82

Natural gas net sales price ($/Mcf)(2) $2.31 $1.87 $2.93 $3.01 $1.73 $1.77

Oil production (Bopd) 146,622 128,005 138,455 168,177 206,249 197,991

Natural gas production (Mcfpd) 450,558 533,442 625,093 780,083 954,556 854,424

Total production (Boepd) 221,715 216,912 242,637 298,190 365,341 340,395

EBITDAX ($000's)(3) $1,978,896 $1,881,889 $2,363,617 $3,623,373 $905,525 $3,447,033

Key Operational Statistics (per Boe)(4)

Oil equivalent net sales price (excludes derivatives) ($/Boe)(2) $31.48 $25.55 $33.65 $41.25 $33.49 $34.56

Production expenses $4.30 $3.65 $3.66 $3.59 $3.31 $3.58

Production taxes $2.47 $1.79 $2.35 $3.25 $2.70 $2.88

Cash G&A(5) $1.70 $1.53 $1.64 $1.25 $1.15 $1.15

Interest expense $3.86 $4.04 $3.32 $2.69 $1.93 $2.17

Total of selected costs $12.33 $11.01 $10.97 $10.78 $9.09 $9.78

Margin(1) $19.15 $14.54 $22.68 $30.47 $24.40 $24.78

Margin % 61% 57% 67% 74% 73% 72%


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 2017 2018 2019

Net cash provided by operating activities (GAAP) 2,079,106 3,456,008 3,115,688

Exclude: Changes in working capital items (1,415) (125,708) 59,493

Less: Capital expenditures (1) (1,995,246) (2,843,988) (2,661,794)

Plus: Contributions from noncontrolling interest — 267,920 109,137

Less: Distributions to noncontrolling interest — (604) (14,164)

Free cash flow (non-GAAP) 82,445 753,628 608,360

(1) Capital expenditures are calculated as follows:

In thousands 2017 2018 2019

Cash paid for capital expenditures 1,953,198 2,914,630 2,860,690

Less: Total acquisitions (40,007) (84,757) (147,398)

Plus: Change in accrued capital expenditures & other 79,222 14,115 (54,761)

Plus: Exploratory seismic costs 2,833 — 3,263

Capital expenditures 1,995,246 2,843,988 2,661,794


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 December 31, 2019, the Company’s total debt was $5.33 billion and its net debt amounted to $5.29 billion,representing total debt of $5.33 billion less cash and cash equivalents of $39.4 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 2016 2017 2018 2019

Total debt (GAAP) $6,579,916 $6,353,691 $5,768,349 $5,326,514

Less: Cash and cash equivalents (16,643) (43,902) (282,749) (39,400)

Net debt (non-GAAP) $6,563,273 $6,309,789 $5,485,600 $5,287,114

2015

$7,117,788

(11,463)

$7,106,325


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.

22


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

23

In thousands 2016 2017 2018 4Q 2019 2019Net income (loss) $ (399,679) $ 789,447 $ 989,700 $ 194,108 $ 774,473Interest expense 320,562 294,495 293,032 64,981 269,379Provision (benefit) for income taxes (232,775) (633,380) 307,102 35,303 212,689Depreciation, depletion, amortization and accretion 1,708,744 1,674,901 1,859,327 552,711 2,017,383Property impairments 237,292 237,370 125,210 19,348 86,202Exploration expenses 16,972 12,393 7,642 7,268 14,667Impact from derivative instruments:

Total (gain) loss on derivatives, net 67,099 (90,432) 23,930 4,436 (49,083)Total cash received (paid) on derivatives, net 89,522 32,401 (36,939) 12,479 64,695

Non-cash (gain) loss on derivatives, net 156,621 (58,031) (13,009) 16,915 15,612Non-cash equity compensation 48,097 45,868 47,236 14,891 52,044Loss on extinguishment of debt 26,055 554 7,133 — 4,584EBITDAX (non-GAAP) $ 1,881,889 $ 2,363,617 $ 3,623,373 $ 905,525 $ 3,447,033

In thousands 2016 2017 2018 4Q 2019 2019Net cash provided by operating activities $ 1,125,919 $ 2,079,106 $ 3,456,008 $ 803,812 $ 3,115,688Current income tax provision (benefit) (22,939) (7,781) (7,776) — —Interest expense 320,562 294,495 293,032 64,981 269,379Exploration expenses, excluding dry hole costs 12,106 12,217 7,495 7,268 14,667Litigation Settlement — (59,600) — — —Gain (loss) on sale of assets, net 304,489 55,124 16,671 1,182 535Tax benefit (deficiency) from stock-based compensation (9,828) — — — —Other, net (10,636) (8,529) (16,349) (3,509) (12,729)Changes in assets and liabilities 162,216 (1,415) (125,708) 31,791 59,493EBITDAX (non-GAAP) $ 1,881,889 $ 2,363,617 $ 3,623,373 $ 905,525 $ 3,447,033

2015($353,668)

313,079 (181,417)1,749,056

402,131 19,413

(91,085)69,553

(21,532)51,834

--$1,978,896

2015$1,857,101

24 313,079

11,032 --

23,149 13,177

(10,044)(228,622)

$1,978,896


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 2018 to the pre-tax amount of adjustments associated with our operations in the United States.

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Three months ended December 31,2019 2018

In thousands, except per share data $ Diluted EPS $ Diluted EPSNet income attributable to Continental Resources (GAAP) $ 193,946 $ 0.53 $ 197,738 $ 0.53

Adjustments:Non-cash (gain) loss on derivatives 16,915 (25,022)Property impairments 19,348 38,494Gain on sale of assets, net (1,182) (8,410)Total tax effect of adjustments (1) (8,578) (1,114)Tax benefit from sale of Canadian subsidiary (16,860) —

Total adjustments, net of tax 9,643 0.02 3,948 0.01Adjusted net income (non-GAAP) $ 203,589 $ 0.55 $ 201,686 $ 0.54Weighted average diluted shares outstanding 368,825 374,525Adjusted diluted net income per share (non-GAAP) $ 0.55 $ 0.54

Year ended December 31,2019 2018

In thousands, except per share data $ Diluted EPS $ Diluted EPSNet income attributable to Continental Resources (GAAP) $ 775,641 $ 2.08 $ 988,317 $ 2.64

Adjustments:Non-cash (gain) loss on derivatives 15,612 (13,009)Property impairments 86,202 125,210Gain on sale of assets, net (535) (16,671)Loss on extinguishment of debt 4,584 7,133Total tax effect of adjustments (1) (25,921) (24,743)Tax benefit from sale of Canadian subsidiary (16,860) —

Total adjustments, net of tax 63,082 0.17 77,920 0.20Adjusted net income (non-GAAP) $ 838,723 $ 2.25 $ 1,066,237 $ 2.84Weighted average diluted shares outstanding 372,538 374,838Adjusted diluted net income per share (non-GAAP) $ 2.25 $ 2.84


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 December 31, 2019 Three months ended December 31, 2018In thousands Crude oil Natural gas Total Crude oil Natural gas TotalCrude oil and natural gas sales (GAAP) $ 1,024,432 $ 161,548 $ 1,185,980 $ 900,872 $ 253,232 $ 1,154,104Less: Transportation expenses (51,332) (9,748) (61,080) (42,373) (6,655) (49,028)Net crude oil and natural gas sales (non-GAAP) $ 973,100 $ 151,800 $ 1,124,900 $ 858,499 $ 246,577 $ 1,105,076Sales volumes (MBbl/MMcf/MBoe) 18,956 87,819 33,593 17,149 75,661 29,759Net sales price (non-GAAP) $ 51.33 $ 1.73 $ 33.49 $ 50.06 $ 3.26 $ 37.13

Year ended December 31, 2019 Year ended December 31, 2018In thousands Crude oil Natural gas Total Crude oil Natural gas TotalCrude oil and natural gas sales (GAAP) $ 3,929,994 $ 584,395 $ 4,514,389 $ 3,792,594 $ 886,128 $ 4,678,722Less: Transportation expenses (191,998) (33,651) (225,649) (162,312) (29,275) (191,587)Net crude oil and natural gas sales (non-GAAP) $ 3,737,996 $ 550,744 $ 4,288,740 $ 3,630,282 $ 856,853 $ 4,487,135Sales volumes (MBbl/MMcf/MBoe) 72,136 311,865 124,113 61,332 284,730 108,787Net sales price (non-GAAP) $ 51.82 $ 1.77 $ 34.56 $ 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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2015 2016 2017 2018 4Q 2019 2019 2020 Guidance

Total G&A per Boe (GAAP) $ 2.34 $ 2.14 $ 2.16 $ 1.69 $ 1.59 $ 1.57 $1.60 - $2.00Less: Non-cash equity compensation per Boe $ (0.64) $ (0.61) $ (0.52) $ (0.44) $ (0.44) $ (0.42) ($0.50) - ($0.60)

Cash G&A per Boe (non-GAAP) $ 1.70 $ 1.53 $ 1.64 $ 1.25 $ 1.15 $ 1.15 $1.10 - $1.40


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 2017 2018 2019Net income (loss) attributable to Continental Resources $ 789,447 $ 988,317 $ 775,641Impact from derivative instruments:

Total (gain) loss on derivatives, net (90,432) 23,930 (49,083)Total cash received (paid), net 32,401 (36,939) 64,695

Non-cash (gain) loss on derivatives, net (58,031) (13,009) 15,612Provision (benefit) for income taxes (633,380) 307,102 212,689Non-cash equity compensation 45,868 47,236 52,044Interest expense 294,495 293,032 269,379Loss on extinguishment of debt 554 7,133 4,584Adjusted EBIT $ 438,953 $ 1,629,811 $ 1,329,949

Equity attributable to Continental Resources - beginning of period $ 4,301,996 $ 5,131,203 $ 6,145,133Total debt - beginning of period 6,579,916 6,353,691 5,768,349Capital employed - beginning of period 10,881,912 11,484,894 11,913,482

Equity attributable to Continental Resources - end of period 5,131,203 6,145,133 6,741,667Total debt - end of period 6,353,691 5,768,349 5,326,514Capital employed - end of period 11,484,894 11,913,482 12,068,181

Average capital employed $ 11,183,403 $ 11,699,188 $ 11,990,832

ROCE 3.9% 13.9% 11.1%

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