Continental Resources Inc (CLR) 8-K Results of Operations and Financial Condition

Exhibit 99.1

NEWS RELEASE                

CONTINENTAL RESOURCES ANNOUNCES 2018 AND 4Q18 PRODUCTION,

YEAR-END 2018 PROVED RESERVES AND 2019 CAPITAL BUDGET AND GUIDANCE

2018 and 4Q18 Production andYear-End 2018 Proved Reserves:

• 298,190 Boepd Average Daily FY 2018 Total Production, up 23% over FY 2017

• 168,177 Bopd Average Daily FY 2018 Oil Production; up 21% over FY 2017

• 324,001 Boepd Average Daily 4Q18 Production; up 9% over 3Q18

• 186,934 Bopd Average Daily 4Q18 Oil Production; up 14% over 3Q18

• 1.52 Billion BoeYear-End 2018 Proved Reserves, up 14% overYear-End 2017

2019 Capital Budget and Guidance:

• $2.6 Billion Capital Expenditures (~$2.2 Billion Allocated to Drilling & Completion)

• Includes $125 Million for Minerals Royalty Acquisitions, of which $100 Million will be Recouped

• Approximately $3 Billion of Cash Flow from Operations and an Estimated $500 to $600 Million of Free Cash Flow(non-GAAP) at $55 per Barrel WTI and $3.00 per Mcf Henry Hub

• Budget Projected to be Cash Neutral in theMid-$40’s per Barrel WTI

• 13% to 19% Year-over-Year Oil Production Growth to 190,000 to 200,000 Bopd

• 1% to 4% Year-over-Year Natural Gas Production Growth to 790,000 to 810,000 Mcfpd

• 9% to 12% Return on Capital Employed (ROCE) at $55 per Barrel WTI

2019 Operating Expenses and Differentials:

• $3.75 to $4.25 per Boe Production Expense

• 8.0% to 8.3% Production Tax

• $1.70 to $2.00 per Boe Total G&A¹

• $15.00 to $17.00 per Boe DD&A

• ($4.50) to ($5.50) per Bo Oil Differential

• $0.00 to ($0.50) per Mcf Natural Gas Differential

Oklahoma City, February 13, 2019 – Continental Resources, Inc. (NYSE: CLR) (the “Company”) today announced a 2019 capital expenditures budget of $2.6 billion, which is focused on both strong free cash flow generation andoil-weighted production growth. Annual crude oil production is projected to grow 13% to 19% and to range between 190,000 to 200,000 barrels of oil (Bo) per day. Annual crude oil volumetric growth is projected to be split approximately equally between the Company’s North and South assets. Annual natural gas production is projected to grow 1% to 4% and to range between 790,000 to 810,000 thousand cubic feet (Mcf) per day.

¹ Total general and administrative (G&A) expense is comprised of cash G&A and non-cash equity compensation per Boe. Cash G&A is a non-GAAP measure. See “Non-GAAP Financial Measures” and the guidance table at the end of this press release for a definition and reconciliation of this measure to the most comparable U.S. GAAP financial measure. Cash G&A guidance is a projected range of $1.25 to $1.45 per Boe. Non-cash equity compensation per Boe guidance is a projected range of $0.45 to $0.55.

The 2019 capital budget is projected to generate approximately $3.0 billion of cash flow from operations and an estimated $500 to $600 million of free cash flow for full-year 2019 at $55 per barrel WTI and $3.00 per Mcf Henry Hub. This level of cash flow would enable the Company to reduce net debt(non-GAAP) to its $5 billion target. The Company anticipates achieving this debt reduction target late in 2019. The capital budget is projected to be cash neutral in themid-$40’s per barrel WTI price. A $5 change per barrel WTI is estimated to impact annual cash flow by $300 million to $325 million.

Free cash flow and net debt arenon-GAAP measures. See“Non-GAAP Financial Measures” at the end of this press release for definitions and an explanation for how these measures relate to the most comparable U.S. GAAP financial measures.

There are currently no oil hedges in place, allowing the Company to fully participate in the upside of oil prices. Natural gas is hedged 110,000 MMBtus per day for first quarter 2019 at an average price of $4.48 and 577,000 MMBtus per day for April through December 2019 at an average price of $2.80.

Of the total $2.6 billion capital budget, the Company is allocating approximately $125 million to the previously announced mineral royalty agreement. With a carry structure in place, the Company will recoup $100 million during the year, effectively reducing the Company’s share of total 2019 capital spend by $100 million. The Company expects to earn 50% of total revenue generated from this strategic royalty relationship in 2019.

The Company is allocating approximately $2.2 billion to drilling and completion (D&C) activities, of which approximately 50% is allocated to the Bakken and approximately 50% to Oklahoma. Capital allocation to the Bakken is lower than the prior year due to a lower rig count and the timing of drilling large pads later in the year, where completion spend is not expected to occur until 2020. Thenon-D&C capital is planned to be primarily focused on leasehold, mineral acquisitions, workovers and facilities.

In 2019, production expense is projected to be between $3.75 and $4.25 per Boe, reflecting a shift towardoil-weighted production growth. Total G&A is projected to be between $1.70 and $2.00 per Boe. In 2019, production tax is projected to be between 8.0% and 8.3% of net oil and gas revenue.

Oil differentials are projected to be in a range of ($4.50) to ($5.50) per Bo, and natural gas differentials are projected to be in a range of $0.00 to ($0.50) per Mcf in 2019. The Company has guided natural gas differentials wider than the prior year based on lower crude oil prices, which impact NGL realizations. The Company has also guided crude oil differentials wider than the prior year but expects improvement based on expanding pipeline infrastructure. The Company is realizing sequential monthly improvement in first quarter 2019.

“In 2019, Continental will deliver enhanced capital efficiency with greateroil-weighted production growth coupled with a lower capital spend. The high quality of our assets and operations will drive sustainable free cash flow generation, debt reduction and industry-leading returns,” said Harold Hamm, Chairman and Chief Executive Officer.

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2019 Operating Plan

The Company plans to operate an average of 25 drilling rigs during 2019, down from 31 rigs atyear-end 2018 and 1 more rig than the 2018 average of 24 rigs. The Company expects to complete approximately 307 gross (207 net) operated wells with first production in 2019 and average 9 completion crews.

In the Bakken, the Company plans to operate an average of 6 drilling rigs during 2019, slightly lower than the 2018 average. The Company expects to complete approximately 166 gross (107 net) operated wells in the Bakken with first production in 2019 and average 4 completion crews. Atyear-end 2019, the Company expects to have a normal working backlog of approximately 115 gross operated Bakken wells in progress in various stages of completion, of which 45 gross wells are projected to be completed but waiting on first sales. This compares to 137 gross operated Bakken wells in progress atyear-end 2018.

In Oklahoma, the Company plans to operate an average of 19 drilling rigs during 2019, up 1 rig from the 2018 average, with approximately 12 rigs focused on Project SpringBoard. The Company expects to complete approximately 141 gross (100 net) operated wells in Oklahoma with first production in 2019 and average 5 completion crews.

2018 and 4Q18 Production

Full-year 2018 production averaged 298,190 Boe per day, up 23% over full-year 2017. Total 2018 production included 168,177 barrels of oil per day, up 21% over full-year 2017. Fourth quarter 2018 production averaged 324,001 Boe per day, up 9% from third quarter 2018. Total production for fourth quarter included 186,934 barrels of oil per day, up 14% over third quarter 2018.

As a reminder, the entire fourth quarter and full-year 2018 results will be announced on Monday, February 18, 2019 following the usual time for the close of trading on the New York Stock Exchange. The Company will host a conference call on Tuesday, February 19, 2019 at 12:00 p.m. ET (11:00 a.m. CT). For more information, please refer to the previous press release announcing key upcoming events, dated January 23, 2019, or visitwww.CLR.com.

YE 2018 Proved Reserves: Standardized Measure andPV-10(non-GAAP) up 50% and 58%, respectively, over YE 2017

The Company announced proved reserves of 1.52 billion Boe at December 31, 2018, a 14% increase compared withyear-end 2017 proved reserves. The 2018 average SEC oil price was $65.56 per barrel, and the 2018 average SEC natural gas price was $3.10 per MMBtu. Of the 14% increase, only 2% was associated with the increased year-over-year SEC commodity prices.

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At December 31, 2018, the Company had a Standardized Measure of discounted future net cash flows of $15.7 billion. The Company’s 2018 proved reserves had aPV-10 of $18.7 billion, up 58% year-over-year.PV-10 is anon-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial metric, because it does not include the effects of discounted income taxes on future net revenues of approximately $3.0 billion. See“Non-GAAP Financial Measures” at the end of this press release for further discussion ofPV-10.

Year-end 2018 proved reserves were 50% crude oil, 85% operated by the Company, and approximately 44% were classified as proved developed producing (PDP).

The Bakken accounted for 798 MMBoe, or 52% of Continental’syear-end 2018 proved reserves. SCOOP accounted for 459 MMBoe, or 30% of Continental’syear-end 2018 proved reserves. STACK accounted for 230 MMBoe, or 15% of Continental’syear-end 2018 proved reserves.

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 2019, the Company will celebrate 52 years of operations. For more information, please visitwww.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,” “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

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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 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; 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 Form10-K for the year ended December 31, 2017, and once filed, for the year ended December 31, 2018, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this 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.

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Investor Contact:	Media Contact:
Rory Sabino	Kristin Thomas
Vice President, Investor Relations	Senior Vice President, Public Relations
405-234-9620	405-234-9480
Rory.Sabino@CLR.com	Kristin.Thomas@CLR.com

Lucy Guttenberger

Senior Investor Relations Associate

405-774-5878

Lucy.Guttenberger@CLR.com

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Non-GAAP Financial Measures

Free cash flow

Our presentation of free cash flow is anon-GAAP measure. We define free cash flow as cash flows from operations before changes in working capital items less capital expenditures, excluding acquisitions, plusnon-controlling interest capital contributions, less distributions tonon-controlling interests. The inclusion ofnon-controlling interest capital contributions and distributions, which began in the fourth quarter of 2018, is related to our newly formed relationship with Franco-Nevada 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 cash flows as determined by U.S. GAAP and should not be considered an alternative to, or more meaningful than, the comparable GAAP measure. Management believes that these measures are 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. These measures eliminate the impact of certain items that management does not consider to be indicative of the Company’s performance from period to period. From time to time the Company provides forward-looking free cash flow estimates; however, the Company is unable to provide a quantitative reconciliation of the forward-lookingnon-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.

Net debt

Net debt is anon-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, the 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. 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-lookingnon-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.

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Cash general and administrative expenses per Boe

Our presentation of cash general and administrative (“G&A”) expenses per Boe is anon-GAAP measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP lessnon-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.

PV-10

OurPV-10 value, anon-GAAP financial measure, is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable financial measure computed using U.S. GAAP.PV-10 generally differs from Standardized Measure because it does not include the effects of income taxes on future net revenues. At December 31, 2018, ourPV-10 totaled approximately $18.7 billion. The standardized measure of our discounted future net cash flows was approximately $15.7 billion at December 31, 2018, representing a $3.0 billion difference fromPV-10 due to the effect of deducting estimated future income taxes in arriving at Standardized Measure. We believe the presentation ofPV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to proved reserves held by companies without regard to the specific income tax characteristics of such entities and is a useful measure of evaluating the relative monetary significance of our crude oil and natural gas properties. Investors may utilizePV-10 as a basis for comparing the relative size and value of our proved reserves to other companies.PV-10 should not be considered as a substitute for, or more meaningful than, the Standardized Measure as determined in accordance with U.S. GAAP. NeitherPV-10 nor Standardized Measure represents an estimate of the fair market value of our crude oil and natural gas properties.

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Continental Resources, Inc.

2019 Guidance

As of February 13, 2019

	2019
Full-year average oil production	190,000 to 200,000 Bo per day
Full-year average natural gas production	790,000 to 810,000 Mcf per day
Capital expenditures budget	$2.6 billion
Operating Expenses:
Production expense per Boe	$3.75 to $4.25
Production tax (% of net oil & gas revenue)	8.0% to 8.3%
Cash G&A expense per Boe(1)	$1.25 to $1.45
Non-cash equity compensation per Boe	$0.45 to $0.55
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 (per Mcf)	$0.00 to ($0.50)

(1) Cash G&A is anon-GAAP measure and excludes the range of values shown fornon-cash equity compensation per Boe in the item appearing immediately below. Guidance for total G&A (cash andnon-cash) is a projected range of $1.70 to $2.00 per Boe.

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Continental Resources, Inc.

2019 Capital Expenditures

The following table provides the breakout of budgeted capital expenditures:

($ in Millions)	Bakken D&C		Oklahoma D&C		Leasehold, Facilities, Other(1)
Capex	$	1,063	$	1,102	$	435

1. Includes $125 million allocated to minerals royalty acquisitions, of which $100 million will be recouped from Franco-Nevada.

Continental Resources, Inc.

2019 Operational Detail

The following table provides additional operational detail for wells expected to have first production in 2019:

Asset	Average Rigs		Gross Operated Wells		Net Operated Wells		Total Net Wells(1)
Bakken		6		166		107		148
Oklahoma		19		141		100		109
Total		25		307		207		257

1. Represents projected net operated andnon-operated wells.

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