Continental Resources Inc (CLR) 8-K Continental Resources Reports Third Quarter 2018 Results

Exhibit 99.1

NEWS RELEASE                

CONTINENTAL RESOURCES REPORTS THIRD QUARTER 2018 RESULTS

$314.2 Million in Net Income, or $0.84 per Diluted Share

• $337.0 Million Adjusted Net Income, or $0.90 per Diluted Share(Non-GAAP)

$215 Million in Proceeds Received in October from Minerals Venture Closing

296,900 Boepd Average Daily 3Q18 Production; Beats 3Q18 Guidance & Consensus

• 164,605 Bopd Average Daily 3Q18 Oil Production; up 5% over 2Q18 and up 17% over 3Q17

• Oil as Percent of Production Rising: Approximately 57% in September

Bakken: 167,643 Boepd Average Daily 3Q18 Production; up 23% over 3Q17

• Significant 4Q18 Ramp with up to 70 Gross Operated Wells to be Completed by YE18 (Compared to 42 Gross Operated Wells Completed in 3Q18)

STACK: 3 Meramec Units Flow at Combined Initial Rate of 74,260 Boepd(24-Hr. IP)    

• 18 Wells in the Over-Pressured Window with 6 Equivalent2-Mile Wells in Each Unit:    

• Jalou Unit Avg.24-Hour IP per Well: 2,470 Bopd and 10,587 Mcfpd (4,234 Boepd)

• Homsey Unit Avg.24-Hr IP per Well: 2,071 Bopd and 8,701 Mcfpd (3,521 Boepd)

• Simba Unit Avg.24-Hr IP per Well: 621 Bopd and 24,001 Mcfpd (4,622 Boepd)

SCOOP: Project SpringBoard Proceeding on Schedule with 14 Rigs Drilling

• 9 Springer Wells Begin Flow-Back

Oklahoma City, October 29, 2018 – Continental Resources, Inc. (NYSE: CLR) (the Company) today announced third quarter operating and financial results. The Company reported net income of $314.2 million, or $0.84 per diluted share, for the quarter ended September 30, 2018. 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.” In third quarter 2018, these typically excluded items in aggregate represented $22.8 million, or $0.06 per diluted share, of Continental’s reported net income. Adjusted net income for third quarter 2018 was $337.0 million, or $0.90 per diluted share.

Net cash provided by operating activities for third quarter 2018 was $860.7 million. EBITDAX for third quarter 2018 was $1.0 billion. Definitions and reconciliations of adjusted net income, adjusted net income per share, free cash flow, EBITDAX, net debt, net sales prices and cash general and administrative (G&A) expenses per barrel of oil equivalent (Boe) presented herein to the most directly comparable U.S. generally accepted accounting principles (GAAP) financial measures are provided in the supporting tables at the conclusion of this press release.

The Company’s third quarter 2018 crude oil differential was $3.72 per barrel below the NYMEX daily average for the period, an improvement of $1.26 per barrel compared to third quarter 2017 due to strong Gulf Coast pricing, strong seasonal demand and lower Cushing inventories. The realized wellhead natural gas price for third quarter 2018 was a premium of $0.22 per Mcf compared to the average NYMEX Henry Hub benchmark price.

“With up to 70 of our forecasted 2018 Bakken wells and up to 18 SpringBoard wells scheduled to be completed by year end, Continental anticipates a strong wave ofoil-weighted production growth as we approach year end,” said Harold Hamm, Chairman and Chief Executive Officer. “Thanks to the quality of our oil assets, the ingenuity of our teams, and the positive tailwind provided by our unhedged oil portfolio, Continental’s strategic move to optimize capital-efficient,oil-weighted growth is enhancing shareholder value.”

$215 Million in Proceeds Received in October from Minerals Venture Closing

On October 23, 2018, the Company closed its strategic minerals agreement with Franco-Nevada. The Company received approximately $215 million in net proceeds at closing, which offset previously incurred Capex for acquired minerals. Moving forward, the minerals relationship will capitalize on the Company’s land and exploration expertise and will focus predominantly on acquiring minerals under the Company’s drill plan. To grow the minerals portfolio, Franco-Nevada has committed up to $300 million over the next three years, while the Company has committed up to $75 million (or 20% of the total investment) over the next three years, subject to achieving agreed upon development thresholds. With a carry structure in place, the Company will earn25-50% of total revenue from the minerals venture, based on achieving certain predetermined targets.

Production Update

Third quarter 2018 production totaled 27.3 million barrels of oil equivalent (Boe), or 296,904 Boe per day, up 22% from third quarter 2017. Total production for third quarter included 164,605 barrels of oil (Bo) per day, as well as 793.8 million cubic feet (MMcf) of natural gas per day. The following table provides the Company’s average daily production by region for the periods presented.

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	3Q		2Q		3Q		YTD		YTD
Boe per day	2018		2018		2017		2018		2017
North Region:
North Dakota Bakken		161,008		151,805		129,582		155,796		114,435
Montana Bakken		6,635		6,314		7,269		6,600		7,569
Red River Units		8,989		8,404		9,536		8,909		9,832
Other		26		258		449		232		422
South Region:
SCOOP		63,270		64,786		57,283		63,360		60,171
STACK		56,129		51,722		35,619		53,733		32,280
Arkoma(1)		8		9		1,722		6		1,755
Other		839		761		1,328		856		1,228
Total		296,904		284,059		242,788		289,492		227,692

(1) Producing properties comprising approximately 1,700 Boe per day of the Company’s Arkoma production were sold in September 2017.

Bakken: 167,643 Boepd Average Daily 3Q18 Production; up 23% over 3Q17

The Company’s Bakken production hit anall-time quarterly record, averaging 167,643 Boe per day in third quarter 2018, up 23% versus third quarter 2017. During the quarter, the Company completed 42 gross (26 net) operated wells flowing at an average initial24-hour rate of 2,013 Boe per day. Two of the wells ranked as top ten30-day rate Bakken wells for the Company, including the Wiley8-25H (2,289 Boe per day) and Mountain Gap3-10H (2,094 Boe per day). All Company top ten30-day rate Bakken wells have been completed in the past twelve months.

The Company currently has 8 rigs drilling in the Bakken, up 2 rigs from last quarter to facilitate continued oil growth in 2019. In fourth quarter 2018, production is expected to ramp significantly with up to 70 wells forecasted to be completed by year end 2018.

“The performance and returns from the Bakken have been exceptional,” said Jack Stark, President. “Our entire 2017 Bakken program, which included 133 operated wells, paid out by the end of third quarter 2018. Now that’s capital efficiency.”

STACK: 3 Meramec Units Flow at Combined Initial Rate of 74,260 Boepd(24-Hr. IP)

The Company’s STACK production increased 58% to 56,129 Boe per day in third quarter 2018, compared to third quarter 2017. During the quarter, the Company completed 15 gross (7 net) operated wells with first production. The Company currently has 5 operated drilling rigs in STACK.

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The Company recently completed three outstanding Meramec units in the over-pressured oil and condensate windows of STACK. All three units were developed with the equivalent of six,two-mile wells. In the oil window, the Jalou unit flowed at a combined initial24-hour rate of 25,404 Boe per day, averaging 2,470 Bo per day per well and 10,587 Mcf per day per well. At an average24-hour rate of 4,234 Boe per day, the Jalou wells set an industry record for fully developed units in the STACK over-pressured oil window. Additionally in the oil window, the Homsey unit flowed at a combined initial24-hour rate of 21,127 Boe per day, averaging 2,071 Bo per day per well and 8,701 Mcf per day per well. In the condensate window, the Simba unit flowed at a combined initial24-hour rate of 27,729 Boe per day, averaging 621 Bo per day per well and 24,001 Mcf per day per well.

“The outstanding results from these units confirm both our unit development model and the exceptional quality of our Meramec reservoirs, which are some of the thickest and most over-pressured in STACK,” said Tony Barrett, Vice President, Exploration. “These results demonstrate the potential of our operated STACK inventory with up to 65 units remaining to develop in the oil and condensate windows.”

The following table provides the average initial24-hour rates per well for recent STACK units:

Unit	2-Mi Equiv. Wells per Unit		Bopd per Well		Mcfpd per Well		Boepd per Well
Jalou		6		2,470		10,587		4,234
Homsey		6		2,071		8,701		3,521
Simba		6		621		24,001		4,622

SCOOP: Project SpringBoard Proceeding on Schedule with 14 Rigs Drilling

The Company’s SCOOP production averaged 63,270 Boe per day in third quarter 2018, up 10% versus third quarter 2017. The Company’s SCOOP crude oil production in third quarter 2018 increased 33% over third quarter 2017. The Company completed 9 gross (7 net) operated wells with first production in third quarter 2018. The Company currently has 16 operated drilling rigs in SCOOP, ramping up to 18 by year end.

Project SpringBoard is proceeding on schedule with 14 rigs drilling, 8 of which are targeting the Springer reservoir and 6 of which are targeting the Woodford and Sycamore reservoirs. In the Springer, the Company has finished drilling 17 of the 18 wells planned for row 1 and has begun drilling row 2. Of the 17 Springer wells drilled, 9 are flowing-back and 8 are in various stages of completions. In the Woodford and Sycamore, the Company has finished drilling 9 wells to date.

“Project SpringBoard is a massive oil project where we are concurrently developing three reservoirs,” said Gary Gould, Senior Vice President of Production & Resource Development. “As expected, we are already realizing operational efficiencies that will translate to significant additional value for our shareholders.”

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Financial Update

“Continental’s strong third quarter and early fourth quarter results reflect our strategic decision to focus operations onoil-weighted production growth,” said John Hart, Chief Financial Officer. “Continental is poised to deliver a strong exit rate, increase our oil production growth and continue to use significant free cash flow to further reduce debt toward our long-term target of $5 billion or below.”

As of September 30, 2018, the Company’s balance sheet included approximately $13 million in cash and cash equivalents and $5.96 billion in total debt. On September 30, 2018, net debt(non-GAAP) was $5.94 billion. Net debt is projected to be between $5.4 and $5.6 billion at year end 2018, driven by strong cash flow. The Company’s third quarter annualizednet-debt-to-EBITDAX ratio was 1.49x and has now reached levels seen prior to the three-year commodity down cycle.

In third quarter 2018, the Company’s average net sales price excluding the effects of derivative positions was $65.78 per barrel of oil and $3.12 per Mcf of gas, or $44.85 per Boe. The Company remains unhedged on oil. Production expense per Boe was $3.77 for third quarter 2018.

Non-acquisition capital expenditures for third quarter 2018 totaled approximately $790.8 million, including $633.5 million in exploration and development drilling, $105.5 million in leasehold, and $51.8 million in workovers, recompletions and other.Non-acquisition capital expenditures for third quarter were slightly higher than projected due to timing of completions that will see first production in fourth quarter 2018 or in 2019.

The following table provides the Company’s production results,per-unit operating costs, results of operations and certainnon-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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	Three months ended September 30,						Nine months ended September 30,
	2018			2017			2018			2017
Average daily production:
Crude oil (Bbl per day)		164,605			140,611			161,856			128,476
Natural gas (Mcf per day)		793,793			613,060			765,821			595,294
Crude oil equivalents (Boe per day)		296,904			242,788			289,492			227,692
Average net sales prices (non-GAAP), excluding effect from derivatives:(1)
Crude oil ($/Bbl)	$	65.78		$	43.27		$	62.73		$	43.26
Natural gas ($/Mcf)	$	3.12		$	2.74		$	2.92		$	2.78
Crude oil equivalents ($/Boe)	$	44.85		$	31.86		$	42.80		$	31.67
Production expenses ($/Boe)	$	3.77		$	3.82		$	3.62		$	3.86
Production taxes (% of net crude oil and gas sales)		8.0	%		7.3	%		7.8	%		6.8	%
DD&A ($/Boe)	$	17.15		$	19.00		$	17.35		$	19.31
Total general and administrative expenses ($/Boe)(2)	$	1.61		$	1.99		$	1.70		$	2.10
Net income (loss) (in thousands)	$	314,169		$	10,621		$	790,580		($	52,467	)
Diluted net income (loss) per share	$	0.84		$	0.03		$	2.11		($	0.14	)
Adjusted net income (non-GAAP) (in thousands)(1)	$	337,017		$	32,162		$	865,033		$	37,142
Adjusted diluted net income per share (non-GAAP)(1)	$	0.90		$	0.09		$	2.31		$	0.10
Net cash provided by operating activities (in thousands)	$	860,748		$	431,409		$	2,500,741		$	1,347,981
EBITDAX (non-GAAP) (in thousands)(1)	$	999,882		$	563,767		$	2,772,733		$	1,525,730

(1) Net sales prices, adjusted net income, adjusted diluted net income per share, and EBITDAX represent non-GAAP financial measures. Further information about these non-GAAP financial measures as well as reconciliations to the most directly comparable U.S. GAAP financial measures are provided subsequently under the headerNon-GAAP Financial Measures.

(2) Total general and administrative expense is comprised of cash general and administrative expense andnon-cash equity compensation expense. Cash general and administrative expense per Boe was $1.18, $1.45, $1.28, and $1.58 for 3Q 2018, 3Q 2017, YTD 2018 and YTD 2017, respectively.Non-cash equity compensation expense per Boe was $0.43, $0.54, $0.42, and $0.52 for 3Q 2018, 3Q 2017, YTD 2018 and YTD 2017, respectively.

Third Quarter Earnings Conference Call

Continental plans to host a conference call to discuss third quarter results on Tuesday, October 30, 2018, at 12 p.m. ET (11 a.m. CT). Those wishing to listen to the conference call may do so via the Company’s website atwww.CLR.com or by phone:

Time and date:	12 p.m. ET, Tuesday, October 30, 2018
Dial in:	844-309-6572
Intl. dial in:	484-747-6921
Pass code:	3745129

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

Replay number:	855-859-2056 or404-537-3406
Intl. replay:	800-585-8367
Pass code:	3745129

Continental plans to publish a third quarter 2018 summary presentation to its website atwww.CLR.com prior to the start of its earnings conference call on October 30, 2018.

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Upcoming Conferences

Members of Continental’s management team expect to participate in the following investment conference:

November14-15, 2018 Bank of America Global Energy Conference – Miami, Florida

Presentation materials for the conference mentioned above will be available on the Company’s web site atwww.CLR.com prior to the start of the Company’s presentation at such conference.

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 2018, the Company will celebrate 51 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 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

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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, 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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Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Income (Loss)

	Three months ended September 30,						Nine months ended September 30,
	2018			2017			2018			2017
	In thousands, except per share data
Revenues:
Crude oil and natural gas sales	$	1,273,238		$	704,818		$	3,524,618		$	1,965,216
Gain (loss) on natural gas derivatives, net		(2,025	)		8,602			(4,536	)		83,482
Crude oil and natural gas service operations		10,938			13,323			40,210			24,959
Total revenues		1,282,151			726,743			3,560,292			2,073,657
Operating costs and expenses:
Production expenses		103,032			84,514			286,165			239,842
Production taxes		98,572			51,264			262,747			134,462
Transportation expenses		46,008			—			142,559			—
Exploration expenses		2,324			1,389			4,347			9,591
Crude oil and natural gas service operations		5,163			3,349			17,434			10,664
Depreciation, depletion, amortization and accretion		469,333			420,243			1,370,912			1,198,169
Property impairments		23,770			35,130			86,715			209,819
General and administrative expenses		44,151			44,006			134,368			130,413
Net (gain) loss on sale of assets and other		(1,510	)		(4,905	)		(8,261	)		764
Total operating costs and expenses		790,843			634,990			2,296,986			1,933,724
Income from operations		491,308			91,753			1,263,306			139,933
Other income (expense):
Interest expense		(73,409	)		(74,756	)		(223,590	)		(218,672	)
Loss on extinguishment of debt		(7,133	)		—			(7,133	)		—
Other		869			394			2,231			1,209
		(79,673	)		(74,362	)		(228,492	)		(217,463	)
Income (loss) before income taxes		411,635			17,391			1,034,814			(77,530	)
(Provision) benefit for income taxes		(97,466	)		(6,770	)		(244,234	)		25,063
Net income (loss)	$	314,169		$	10,621		$	790,580		$	(52,467	)
Basic net income (loss) per share	$	0.84		$	0.03		$	2.13		$	(0.14	)
Diluted net income (loss) per share	$	0.84		$	0.03		$	2.11		$	(0.14	)

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Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Balance Sheets

	September 30, 2018		December 31, 2017
	In thousands
Assets
Cash and cash equivalents	$	12,896	$	43,902
Other current assets		1,356,241		1,207,823
Net property and equipment(1)		13,644,538		12,933,789
Other noncurrent assets		17,385		14,137
Total assets	$	15,031,060	$	14,199,651
Liabilities and shareholders’ equity
Current liabilities	$	1,490,449	$	1,330,242
Long-term debt, net of current portion		5,955,326		6,351,405
Other noncurrent liabilities		1,646,475		1,386,801
Total shareholders’ equity		5,938,810		5,131,203
Total liabilities and shareholders’ equity	$	15,031,060	$	14,199,651

(1) Balance is net of accumulated depreciation, depletion and amortization of $10.33 billion and $9.08 billion as of September 30, 2018 and December 31, 2017, respectively.

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Cash Flows

	Three months ended September 30,						Nine months ended September 30,
In thousands	2018			2017			2018			2017
Net income (loss)	$	314,169		$	10,621		$	790,580		$	(52,467	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Non-cash expenses		619,284			480,718			1,764,566			1,358,639
Changes in assets and liabilities		(72,705	)		(59,930	)		(54,405	)		41,809
Net cash provided by operating activities		860,748			431,409			2,500,741			1,347,981
Net cash used in investing activities		(759,880	)		(494,934	)		(2,103,483	)		(1,374,254	)
Net cash (used in) provided by financing activities		(217,976	)		57,080			(428,253	)		20,361
Effect of exchange rate changes on cash		15			20			(11	)		34
Net change in cash and cash equivalents		(117,093	)		(6,425	)		(31,006	)		(5,878	)
Cash and cash equivalents at beginning of period		129,989			17,190			43,902			16,643
Cash and cash equivalents at end of period	$	12,896		$	10,765		$	12,896		$	10,765

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Non-GAAP Financial Measures

Adjusted earnings (net income/loss) and adjusted earnings (net income/loss) per share

Our presentation of adjusted earnings and adjusted earnings per share that exclude the effect of certain items arenon-GAAP financial measures. Adjusted earnings and adjusted earnings per share represent earnings and diluted earnings per share determined under U.S. GAAP without regard tonon-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 earnings and adjusted earnings per share 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 not be comparable to other similarly titled measures of other companies. The following table reconciles earnings and diluted earnings per share as determined under U.S. GAAP to adjusted earnings and adjusted diluted earnings per share for the periods presented.

	Three months ended September 30,
	2018					2017
In thousands, except per share data	$			Diluted EPS		$			Diluted EPS
Net income (GAAP)	$	314,169		$	0.84	$	10,621		$	0.03
Adjustments:
Non-cash loss on derivatives		548					2,939
Property impairments		23,770					35,130
Gain on sale of assets		(1,510	)				(3,562	)
Loss on extinguishment of debt		7,133					—
Total tax effect of adjustments(1)		(7,093	)				(12,966	)
Total adjustments, net of tax		22,848			0.06		21,541			0.06
Adjusted net income (non-GAAP)	$	337,017		$	0.90	$	32,162		$	0.09
Weighted average diluted shares outstanding		374,623					373,015
Adjusted diluted net income per share (non-GAAP)	$	0.90				$	0.09
	Nine months ended September 30,
	2018					2017
In thousands, except per share data	$			Diluted EPS		$			Diluted EPS
Net income (loss) (GAAP)	$	790,580		$	2.11	$	(52,467	)	$	(0.14	)
Adjustments:
Non-cash (gain) loss on derivatives		12,013					(65,481	)
Property impairments		86,715					209,819
Gain on sale of assets		(8,261	)				(703	)
Loss on extinguishment of debt		7,133					—
Total tax effect of adjustments(1)		(23,147	)				(54,026	)
Total adjustments, net of tax		74,453			0.20		89,609			0.24
Adjusted net income (non-GAAP)	$	865,033		$	2.31	$	37,142		$	0.10
Weighted average diluted shares outstanding		374,762					373,588
Adjusted diluted net income per share (non-GAAP)	$	2.31				$	0.10

(1) Computed by applying a combined federal and state statutory tax rate of 24% in effect for 2018 and 38% in effect for 2017 to thepre-tax amount of adjustments associated with our operations in the United States.

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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. At September 30, 2018, the Company’s net debt amounted to $5.94 billion, representing total debt of $5.96 billion less cash and cash equivalents of $13 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-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.

EBITDAX

We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX. 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

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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.

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

	Three months ended September 30,						Nine months ended September 30,
In thousands	2018			2017			2018		2017
Net income (loss)	$	314,169		$	10,621		$	790,580	$	(52,467	)
Interest expense		73,409			74,756			223,590		218,672
Provision (benefit) for income taxes		97,466			6,770			244,234		(25,063	)
Depreciation, depletion, amortization and accretion		469,333			420,243			1,370,912		1,198,169
Property impairments		23,770			35,130			86,715		209,819
Exploration expenses		2,324			1,389			4,347		9,591
Impact from derivative instruments:
Total (gain) loss on derivatives, net		2,025			(9,945	)		4,536		(82,015	)
Total cash (paid) received on derivatives, net		(1,477	)		12,884			7,477		16,534
Non-cash (gain) loss on derivatives, net		548			2,939			12,013		(65,481	)
Non-cash equity compensation		11,730			11,919			33,209		32,490
Loss on extinguishment of debt		7,133			—			7,133		—
EBITDAX (non-GAAP)	$	999,882		$	563,767		$	2,772,733	$	1,525,730

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

	Three months ended September 30,						Nine months ended September 30,
In thousands	2018			2017			2018			2017
Net cash provided by operating activities	$	860,748		$	431,409		$	2,500,741		$	1,347,981
Current income tax provision (benefit)		(7,778	)		(1	)		(7,778	)		—
Interest expense		73,409			74,756			223,590			218,672
Exploration expenses, excluding dry hole costs		2,324			1,389			4,346			9,434
Gain on sale of assets, net		1,510			3,562			8,261			703
Other, net		(3,036	)		(7,278	)		(10,832	)		(9,251	)
Changes in assets and liabilities		72,705			59,930			54,405			(41,809	)
EBITDAX (non-GAAP)	$	999,882		$	563,767		$	2,772,733		$	1,525,730

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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, expected to begin 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 sales prices

On January 1, 2018, we adopted Accounting Standards Update2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), which impacted the presentation of our crude oil and natural gas revenues. We adopted the new rules using a modified retrospective transition approach whereby changes have been applied only to the most current period presented and prior period results have not been adjusted to conform to current presentation.

Under the new rules, revenues and transportation expenses associated with production from our operated properties are now reported on a gross basis compared to net presentation in the prior year. Fornon-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. Suchnon-operated revenues are recognized at the net amount of proceeds received, consistent with our historical practice. As a result, beginning January 1, 2018 the gross presentation of revenues from our operated properties differs from the net presentation of revenues fromnon-operated properties. This impacts the comparability of certain operating metrics, such asper-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.

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In order to provide metrics prepared in a manner consistent with how management assesses the Company’s operating results, and to achieve comparability with prior period metrics for analysis purposes, 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,” anon-GAAP measure. Average sales prices calculated using net crude oil and natural gas sales are referred to as “net sales prices,” anon-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 andnon-operated revenues and allows for a useful comparison of net realized prices to NYMEX benchmark prices on a Company-wide basis.

The following table presents a reconciliation of crude oil and natural gas sales (GAAP) to net crude oil and natural gas sales and related net sales prices(non-GAAP) for the three and nine months ended September 30, 2018. Information is also presented for the three and nine months ended September 30, 2017 for comparative purposes.

	Three months ended September 30, 2018									Three months ended September 30, 2017
In thousands	Crude oil			Natural gas			Total			Crude oil		Natural gas		Total
Crude oil and natural gas sales (GAAP)	$	1,038,558		$	234,680		$	1,273,238		$	550,451	$	154,367	$	704,818
Less: Transportation expenses		(39,336	)		(6,672	)		(46,008	)		—		—		—
Net crude oil and natural gas sales (non-GAAP for 2018)	$	999,222		$	228,008		$	1,227,230		$	550,451	$	154,367	$	704,818
Sales volumes (MBbl/MMcf/MBoe)		15,190			73,029			27,361			12,722		56,401		22,123
Net sales price (non-GAAP for 2018)	$	65.78		$	3.12		$	44.85		$	43.27	$	2.74	$	31.86
	Nine months ended September 30, 2018									Nine months ended September 30, 2017
In thousands	Crude oil			Natural gas			Total			Crude oil		Natural gas		Total
Crude oil and natural gas sales (GAAP)	$	2,891,722		$	632,896		$	3,524,618		$	1,512,990	$	452,226	$	1,965,216
Less: Transportation expenses		(119,939	)		(22,620	)		(142,559	)		—		—		—
Net crude oil and natural gas sales (non-GAAP for 2018)	$	2,771,783		$	610,276		$	3,382,059		$	1,512,990	$	452,226	$	1,965,216
Sales volumes (MBbl/MMcf/MBoe)		44,183			209,069			79,028			34,975		162,515		62,061
Net sales price (non-GAAP for 2018)	$	62.73		$	2.92		$	42.80		$	43.26	$	2.78	$	31.67

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.

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Continental Resources, Inc.

2018 Guidance

As of October 29, 2018

	2018
Full-year average production	290,000 to 300,000 Boe per day
Exit-rate average production	315,000 to 325,000 Boe per day
Capital expenditures budget(non-acquisition)	$2.7 billion
Operating Expenses:
Production expense per Boe	$3.50 to $3.75 (updated(1))
Production tax (% of net oil & gas revenue)	7.6% to 8.0%
Cash G&A expense per Boe(2)	$1.20 to $1.65
Non-cash equity compensation per Boe	$0.40 to $0.50
DD&A per Boe	$17.00 to $18.00
Average Price Differentials:
NYMEX WTI crude oil (per barrel of oil)	($3.50) to ($4.50)
Henry Hub natural gas (per Mcf)	$0.00 to +$0.50

(1) Updated from a prior guidance range of $3.00 to $3.50.

(2) 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 an expected range of $1.60 to $2.15 per Boe.

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