Exhibit 99.1

NEWS RELEASE                

CONTINENTAL RESOURCES ANNOUNCES FULL-YEAR 2019 AND 4Q19 RESULTS;

2020 CAPITAL BUDGET AND GUIDANCE

Full-Year 2019 Results

4Q19 Results

2020 Capital Budget & Guidance

Oklahoma City, February 26, 2020 – Continental Resources, Inc. (NYSE: CLR) (the “Company”) today announced its full-year 2019 and fourth quarter 2019 operating and financial results, as well as its 2020 capital expenditures budget and operating plan.

The Company reported full-year 2019 net income of $775.6 million, or $2.08 per diluted share. The Company’s net income includes certain items typically excluded by the investment community in published estimates, the result of which is referred to as “adjusted net income.” For full-year 2019, typically excluded items in aggregate represented $63.1 million, or $0.17 per diluted share. Adjusted net income for full-year 2019 was $838.7 million, or $2.25 per diluted share (non-GAAP). Net cash provided by operating activities for full-year 2019 was $3.12 billion and EBITDAX was $3.45 billion (non-GAAP).

The Company reported net income of $193.9 million, or $0.53 per diluted share, for the quarter ended December 31, 2019. In fourth quarter 2019, typically excluded items in aggregate represented $9.7 million, or $0.02 per diluted share, of Continental’s reported net income. Adjusted net income for fourth quarter 2019 was $203.6 million, or $0.55 per diluted share (non-GAAP). Net cash provided by operating activities for fourth quarter 2019 was $803.8 million and EBITDAX was $905.5 million (non-GAAP).

Adjusted net income, adjusted net income per share, EBITDAX, free cash flow, net debt, net sales prices and cash general and administrative (G&A) expenses per barrel of oil equivalent (Boe) presented herein are non-GAAP financial measures. Definitions and explanations for how these measures relate to the most directly comparable U.S. generally accepted accounting principles (GAAP) financial measures are provided at the conclusion of this press release.

2019 Production Update

Full-year 2019 production increased 14% over full-year 2018, averaging 340,395 barrels of oil equivalent per day (Boepd). 2019 oil production increased 18% over 2018, averaging 197,991 barrels of oil per day (Bopd). 2019 natural gas production increased 10% over 2018, averaging 854.4 million cubic feet per day (MMcfpd).

Fourth quarter 2019 total production increased 13% over fourth quarter 2018, averaging 365,341 Boepd. Fourth quarter 2019 oil production increased 10% over fourth quarter 2018, averaging 206,249 Bopd. Fourth quarter 2019 natural gas production increased 16% over fourth quarter 2018, averaging 954.6 MMcfpd.

The following table provides the Company’s average daily production by region for the periods presented.

2019 Operations Update

“Operationally, 2019 was an exceptional year. We met or exceeded all of our guidance and delivered 18% oil production growth year-over-year. We also consummated strategic trades, bolt-on acquisitions and leasing in Continental-dominated core areas for approximately $165 million, adding up to 370 gross operated locations to our deep inventory position,” said Harold Hamm, Executive Chairman.

CLR Bakken: #1 Bakken Oil Producer; 148,416 Average Daily 2019 Oil Production up 14% over 2018

In 2019, Bakken oil production increased 14% over 2018, averaging 148,416 Bopd. Bakken total production increased 16% over 2018, averaging 194,691 Boepd. During the year, the Company completed 172 gross (119 net) operated wells with first production. These 2019 Bakken program wells are performing in line with wells completed in the Company’s 2017 and 2018 Bakken programs, each of which paid out in approximately one year. The 2019 program wells are approximately 75% paid out, as of January 2020. The 2020 Bakken program is projected to continue this performance trend.

CLR South: #1 OK Oil Producer; 41,695 Average Daily 2019 Oil Production up 43% over 2018

In 2019, South oil production increased 43% over 2018, averaging 41,695 Bopd. South total production increased 13% over 2018, averaging 137,579 Boepd. During the year, the Company completed 140 gross (98 net) operated wells with first production in the South. In SCOOP, Project SpringBoard produced an average 25,006 net Bopd, outperforming the Company’s expectations announced in third quarter 2018 by 50%.

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Year-End 2019 Proved Reserves

The Company’s year-end 2019 proved reserves grew 6% year-over-year to 1,619 MMBoe, as of December 31, 2019. These additions equate to a reserve replacement ratio of 178% for 2019 (defined as total change in proved reserves, excluding production, divided by production). SEC prices used for calculating proved reserves were approximately $10.00 less per barrel WTI and $0.50 less per Mcf gas than the SEC prices used in the prior year. The Company’s proved reserves have grown by 32% since December 31, 2015 and these additions equate to a four year reserve replacement ratio of 198%.

2019 Financial Update

“In 2019, Continental maintained capital discipline and generated strong corporate returns with an 11% return on capital employed (ROCE). The Company also delivered $190 million in share repurchases, approximately $200 million in net debt reduction and the initiation of the Company’s quarterly dividend,” said John Hart, Chief Financial Officer.

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2020 Capital Budget & Guidance

“In 2020, Continental will prioritize maximizing shareholder capital return in the form of share repurchases, debt reduction and dividends. With our strong portfolio and disciplined approach to value creation, we will continue to increase capital and corporate returns for our shareholders,” said Bill Berry, Chief Executive Officer.

The 2020 capital budget is projected to generate $2.9 to $3.0 billion of cash flow from operations and $350 to $400 million of free cash flow for full-year 2020 at $55 per barrel WTI and $2.50 per Mcf Henry Hub. A $5 change per barrel WTI is estimated to impact annual cash flow by approximately $300 million.

Annual crude oil production is projected to range between 198,000 to 201,000 Bopd. Annual natural gas production is projected to range between 935,000 to 960,000 Mcfpd. The Company is targeting 4% to 6% annual production growth year-over-year, which is expected to average an approximately 10% CAGR for 2019 and 2020. The Company believes the projected growth range is appropriate given prevailing market conditions and outperformance in 2019. Cumulative volumes are projected to be on track with the Company’s original Five Year Vision estimates for 2019 and 2020.

The Company’s 2020 capital expenditures budget is flat year-over-year at $2.65 billion. Estimated Capex spend is approximately 20% lower than the Company’s original Five Year Vision estimate for 2020. An estimated $700 million of capital to be spent in 2020 will not realize first production until 2021 as the Company prioritizes large scale multi-pad development projects in SCOOP and Bakken Long Creek.

Consequently, at year-end 2020, the Company expects to have a working backlog of approximately 242 gross operated wells in progress in various stages of completion, which is 12% higher than year-end 2019. This includes 188 gross operated wells in the Bakken, which is 42% higher than year-end 2019.

The Company is allocating approximately $2.2 billion to drilling and completion (D&C) activities, of which approximately 60% is allocated to the Bakken and approximately 40% to Oklahoma. The non-D&C capital is planned to be primarily focused on leasehold, mineral acquisitions, workovers and facilities.

The Company is allocating approximately $125 million to the previously announced mineral royalty agreement. With a carry structure in place, $100 million of capital costs will be funded by Franco-Nevada and the Company expects to earn 50% of total revenue generated from this strategic relationship in 2020.

In 2020, the Company plans to deliver approximately 8% ROCE at $55 WTI.

“Looking to 2020 and beyond, Continental expects to continue to be the low cost leader among our oil-weighted peers as we maximize performance and returns from our growing, high quality assets,” said Jack Stark, President and Chief Operating Officer.

The Company’s full 2020 guidance, capital expenditures budget and operating details can be found at the conclusion of this press release.

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The following table provides the Company’s production results, per-unit operating costs, results of operations and certain non-GAAP financial measures for the periods presented. Average net sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.

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Fourth Quarter Earnings Conference Call

The Company plans to host a conference call to discuss full-year 2019 and 4Q19 results on Thursday, February 27, 2020 at 12:00 p.m. ET (11:00 a.m. CT). Those wishing to listen to the conference call may do so via the Company’s website at www.CLR.com or by phone:

A replay of the call will be available for 14 days on the Company’s website or by dialing:

The Company plans to publish a full-year 2019 and 4Q19 summary presentation to its website at www.CLR.com prior to the start of its conference call on Thursday, February 27, 2020.

About Continental Resources

Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America’s energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation’s premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation’s leadership in the new world oil market. In 2020, the Company will celebrate 53 years of operations. For more information, please visit www.CLR.com.

Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995

This press release 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 press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company’s business and statements or information concerning the Company’s future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, 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 contain such identifying words.

Forward-looking statements are based on the Company’s current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company’s control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the effects of any national or international health crisis; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; 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 to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company’s Annual Report on Form 10-K for the year ended December 31, 2018, and once filed, for 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 time to time.

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Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company’s actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.

Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.

We use the term “EUR” or “estimated ultimate recovery” to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.

Lucy Guttenberger

Investor Relations Analyst

405-774-5878    

Lucy.Guttenberger@CLR.com

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Continental Resources, Inc. and Subsidiaries

Consolidated Statements of Income

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Continental Resources, Inc. and Subsidiaries

Consolidated Balance Sheets

Continental Resources, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

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Non-GAAP Financial Measures

Non-GAAP adjusted net income and adjusted net income per share attributable to Continental

Our presentation of adjusted net income and adjusted net income per share that exclude the effect of certain items are non-GAAP financial measures. Adjusted net income and adjusted net income per share represent net income and diluted net income per share determined under U.S. GAAP without regard to non-cash gains and losses on derivative instruments, property impairments, gains and losses on asset sales, and losses on extinguishment of debt as applicable. Management believes these measures provide useful information to analysts and investors for analysis of our operating results. In addition, management believes these measures are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis without regard to an entity’s specific derivative portfolio, impairment methodologies, and property dispositions. Adjusted net income and adjusted net income per share should not be considered in isolation or as an alternative to, or more meaningful than, net income or diluted net income per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following tables reconcile net income and diluted net income per share as determined under U.S. GAAP to adjusted net income and adjusted diluted net income per share for the periods presented.

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Non-GAAP Net Debt

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 debt should not be considered an alternative to, or more meaningful than, total debt, the most directly comparable GAAP measure. Management uses net debt to determine the Company’s outstanding debt obligations that would not be readily satisfied by its cash and cash equivalents on hand. We believe this metric is useful to analysts and investors in determining the Company’s leverage position since the Company has the ability to, and may decide 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 to provide investors with another means of evaluating the Company’s ability to service its existing debt obligations as well as any future increase in the amount 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. At December 31, 2018, the Company’s total debt was $5.77 billion and its net debt amounted to $5.49 billion, representing total debt of $5.77 billion less cash and cash equivalents of $282.7 million. From time to time the Company provides forward-looking net debt forecasts; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to the most directly comparable forward-looking GAAP measure of total debt because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.

Non-GAAP EBITDAX

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, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, non-cash equity compensation expense, and losses on extinguishment of debt as applicable. EBITDAX is not a measure of net income or net cash provided by operating 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 results of our operations from period to period without regard to our financing methods or capital structure. Further, we believe EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. We exclude the items listed above from net income/loss and net cash provided by operating activities in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired.

EBITDAX should not be considered as an alternative to, or more meaningful than, net income/loss or net cash provided by operating activities as determined in accordance with U.S. GAAP or as an indicator of a company’s operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies.

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The following table provides a reconciliation of our net income to EBITDAX for the periods presented.

The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented.

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Non-GAAP Net Sales Prices

Revenues and transportation expenses associated with production from our operated properties are reported separately. For non-operated properties, we receive a net payment from the operator 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 comparability of 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 for others.

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-operated revenues, 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 prices calculated 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 by sales 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 normalizes the 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.

Non-GAAP Cash General and Administrative Expenses per Boe

Our presentation of cash general and administrative (“G&A”) expenses per Boe is a non-GAAP measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses, expressed on a per-Boe basis. We report and provide guidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than, total G&A per Boe as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies.

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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.

Non-GAAP Free Cash Flow

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

The following table reconciles net cash provided by operating activities as determined under U.S. GAAP to free cash flow for the year ended December 31, 2019.

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Calculation of Return on Capital Employed (ROCE)

The following table shows the calculation of ROCE for 2019.

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Continental Resources, Inc.

2020 Guidance

As of February 26, 2020

Continental Resources, Inc.

2020 Capital Expenditures

The following table provides the breakout of budgeted capital expenditures:

Continental Resources, Inc.

2020 Operational Detail

The following table provides additional operational detail for wells expected to have first production in 2020:

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