EX-99.1

EX-99.1 2 d726548dex991.htm EX-99.1 EX-99.1

Exhibit 99.1

NEWS RELEASE

CONTINENTAL RESOURCES FIRST QUARTER 2019 RESULTS UNDERSCORE COMPANY’S FORMULA FOR SUCCESS

Oil-Weighted Assets + Low Cost Operations = Sustainable, Cash Flow Positive Growth

$187.0 Million in Net Income in 1Q19, or $0.50 per Diluted Share

•

$216.6 Million Adjusted Net Income in 1Q19, or $0.58 per Diluted Share (Non-GAAP)

193,921 Bopd Average Daily 1Q19 Oil Production; up 18% over 1Q18

•

332,236 Boepd Average Daily 1Q19 Production; up 16% over 1Q18

Bakken: 3 Strategic Step-Out Wells Deliver Excellent Results

•

Initial Rates: MT: 1,680 Boepd (Baird); ND: 2,400 Boepd (Burian) and 2,440 Boepd (McClintock)

SpringBoard: Oil Growth Ahead of Schedule; Avg. ~14,000 Net Bopd in April (28 Days)

•

First 6 Woodford Wells Avg. Initial Rate per Well: 1,660 Boepd (1,245 Bopd); 75% Oil

STACK: Continues to Deliver Outstanding Results

•

Tolbert 5-Well Cond. Unit: 18,700 Boepd Initial Rate; Avg per Well: 3,740 Boepd (1,180 Bopd)

•

Lugene 3-Well Oil Unit: 9,270 Boepd Initial Rate; Avg per Well: 3,090 Boepd (1,540 Bopd)

•

Blondie 1-6-7-18XHM 3-Mile Lateral Well Initial Rate: 3,400 Boepd (2,460 Bopd)

Oklahoma City, April 29, 2019 – Continental Resources, Inc. (NYSE: CLR) (the Company) today announced first quarter 2019 operating and financial results.

The Company reported net income of $187.0 million, or $0.50 per diluted share, for the quarter ended March 31, 2019. 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 first quarter 2019, these typically excluded items in aggregate represented $29.6 million, or $0.08 per diluted share, of Continental’s reported net income. Adjusted net income for first quarter 2019 was $216.6 million, or $0.58 per diluted share (non-GAAP). Net cash provided by operating activities for first quarter 2019 was $721.5 million and EBITDAX was $854.8 million (non-GAAP).

Adjusted net income, adjusted net income per share, EBITDAX, 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.

“Continental’s outstanding first quarter 2019 results reflect our commitment to our formula for success. The combination of high quality Bakken and Oklahoma assets with efficient, low cost operations translates to strong corporate returns and sustainable cash flow generation,” said Harold Hamm, Chairman and Chief Executive Officer.

Production Update: 1Q19 Average Daily Oil Production up 18% over 1Q18

First quarter 2019 production increased 16% over first quarter 2018, averaging 332,236 Boe per day. First quarter 2019 oil production increased 18% over first quarter 2018, averaging 193,921 barrels of oil (Bo) per day. First quarter 2019 natural gas production increased 12% over first quarter 2018, averaging 829.9 million cubic feet (MMcf) per day. The following table provides the Company’s average daily production by region for the periods presented.


	1Q		4Q		1Q
Boe per day	2019		2018		2018
Bakken		199,423		183,836		161,356
SCOOP		67,659		67,244		62,012
STACK		56,513		62,947		53,361
All other		8,641		9,974		10,681

Total		332,236		324,001		287,410

Bakken: 3 Strategic Step-Out Wells Deliver Excellent Results

The Company’s first quarter 2019 Bakken production increased 24% over first quarter 2018, averaging 199,423 Boe per day. In first quarter 2019, average daily Bakken oil production increased 8% over fourth quarter 2018 and the Company completed 55 gross (40 net) operated wells with first production. These wells flowed at an average initial 24-hour rate per well of 2,300 Boe per day, with 80% of the production being oil.

In first quarter 2019, the Company completed 3 strategic step-out wells in North Dakota and Montana Bakken. The wells were the Company’s first tests of its optimized completion technology in these extended portions of its Bakken leasehold. The tests proved successful, as the wells are outperforming offsetting legacy producers by as much as 110% in the first 60 days. In Montana, the Baird Federal 2-34H flowed at an initial rate of 1,680 Boe per day (85% oil), outperforming the legacy well by 110% at 60 days. In southern Billings County, North Dakota, the Burian 4-27H1 flowed at an initial rate of 2,400 Boe per day (80% oil), outperforming the legacy well by 80% at 60 days. In eastern Williams County, North Dakota, the three-mile lateral McClintock 8-1H1 flowed at an initial rate of 2,440 Boe per day (80% oil), outperforming the two-mile legacy well by 100% at 60 days.

“These strategic step-outs provide further proof that our optimized completion technology is uplifting well performance across all of our Bakken leasehold, even into Montana. This is great news for our shareholders as the value of our Bakken inventory of approximately 4,000 wells continues to grow,” said Jack Stark, President.

SpringBoard: Oil Growth Ahead of Schedule; Avg. ~14,000 Net Bopd in April (28 Days)

The Company’s first quarter 2019 SCOOP production increased 9% over first quarter 2018, averaging 67,659 Boe per day. The Company completed 15 gross (13 net) operated wells with first production in first quarter 2019.

Project SpringBoard oil production is growing ahead of schedule, averaging ~14,000 Bo per day in the first 28 days of April 2019. The Company has updated its SpringBoard oil production growth target to 18,000 Bo per day in third quarter 2019, compared to the initial target of 16,500 Bo per day. Cycle time improvements and higher early time well productivity are accelerating production growth and enabling the Company to achieve its objectives for 2019 with 25% fewer rigs. The Company currently has 9 rigs drilling, 33 wells waiting on completion and 39 wells producing in Project SpringBoard.

In first quarter 2019, the Company completed the first 6 Woodford wells in Project SpringBoard, which flowed at a combined initial rate of 9,960 Boe per day, averaging 1,660 Boe per day per well, which includes 1,245 Bo per day per well. These wells are currently outperforming the legacy 1.5 MMBoe Woodford legacy oil type curve.

STACK: Continues to Deliver Outstanding Results

The Company’s first quarter 2019 STACK production increased 6% over first quarter 2018, averaging 56,513 Boe per day. During the quarter, the Company completed 9 gross (5 net) operated wells with first production in 2019.

In the over-pressured condensate window, the 5-well Tolbert unit flowed at a combined initial rate of 18,700 Boe per day, averaging 3,740 Boe per day per well, which includes 1,180 Bo per day per well. In the over-pressured oil window, the 3-well Lugene unit flowed at a combined initial rate of 9,270 Boe per day, averaging 3,090 Boe per day per well, which includes 1,540 Bo per day per well. The Tolbert unit was developed with 2-mile laterals and the Lugene unit with 1-mile laterals. The Company also completed its first 3-mile Meramec well in STACK. The Blondie 1-6-7-18XHM 3-mile lateral flowed at an initial rate of 3,400 Boe per day, which includes 2,460 Bo per day per well.

Financial Update

“Continental’s capital-efficient and highly productive first quarter 2019 results underscore our commitment to delivering shareholder value in 2019. We are extremely pleased with our execution on cost metrics and the potential for favorable updates to these targets later in the year,” said John Hart, Chief Financial Officer.

As of March 31, 2019, the Company’s balance sheet included approximately $264.4 million in cash and cash equivalents, $5.77 billion in total debt and $5.50 billion in net debt (non-GAAP). The Company anticipates further reducing net debt to $5 billion in 2019.

In first quarter 2019, the Company’s average net sales prices excluding the effects of derivative positions were $50.05 per barrel of oil and $2.56 per Mcf of gas, or $35.56 per Boe. Production expense per Boe was $3.59 for first quarter 2019, below annual guidance of $3.75 to $4.25 per Boe. Total G&A expenses per Boe were $1.60 for first quarter 2019, also below annual guidance of $1.70 to $2.00 per Boe.

The Company’s first quarter 2019 crude oil differential was $4.77 per barrel below the NYMEX daily average for the period, a 43% improvement over fourth quarter 2018 and within annual guidance of $4.50 to $5.50 per barrel. The wellhead natural gas price for first quarter 2019 was $0.60 per Mcf below the average NYMEX Henry Hub benchmark price. The Company expects further improvement to the natural gas differential in 2019.

The Company realized approximately $13 million of cash gains from natural gas hedges in the first quarter. For the balance of 2019, natural gas is hedged 577,000 MMBtus per day at an average NYMEX Henry Hub price of $2.80.

Non-acquisition capital expenditures for first quarter 2019 totaled approximately $750.2 million, including $631.1 million in exploration and development drilling and completion, $14.8 million in leasehold, $51.3 million in minerals, of which 80% was recouped from Franco-Nevada, and $53.0 million in workovers, recompletions and other. Our first quarter capital expenditures reflect an accelerated pace of development due to improved cycle times and efficiency gains which resulted in 8 more net wells being completed and 6 more net wells being spud during the quarter than budgeted while using the same number of rigs and completion crews. The Company maintains its $2.6 billion capital expenditures guidance for 2019.

The Company’s full 2019 guidance remains as announced on February 13, 2019 and can be found at the conclusion of this press release.

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.


	1Q			4Q			1Q
	2019			2018			2018
Average daily production:
Crude oil (Bbl per day)		193,921			186,934			163,837
Natural gas (Mcf per day)		829,891			822,402			741,442
Crude oil equivalents (Boe per day)		332,236			324,001			287,410
Average net sales prices (non-GAAP), excluding effect from derivatives: ⁽¹⁾
Crude oil ($/Bbl)	$	50.05		$	50.06		$	58.98
Natural gas ($/Mcf)	$	2.56		$	3.26		$	2.98
Crude oil equivalents ($/Boe)	$	35.56		$	37.13		$	41.26
Production expenses ($/Boe)	$	3.59		$	3.50		$	3.60
Production taxes (% of net crude oil and gas sales)		8.2	%		8.2	%		7.6	%
DD&A ($/Boe)	$	16.60		$	16.41		$	17.61
Total general and administrative expenses ($/Boe) ⁽²⁾	$	1.60		$	1.65		$	1.67
Net income attributable to Continental Resources (in thousands)	$	186,976		$	197,738		$	233,946
Diluted net income per share attributable to Continental Resources	$	0.50		$	0.53		$	0.63
Adjusted net income (non-GAAP) (in thousands) ⁽¹⁾	$	216,610		$	201,686		$	255,140
Adjusted diluted net income per share (non-GAAP) ⁽¹⁾	$	0.58		$	0.54		$	0.68
Net cash provided by operating activities (in thousands)	$	721,508		$	955,267		$	886,191
EBITDAX (non-GAAP) (in thousands) ⁽¹⁾	$	854,785		$	850,640		$	876,196

(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 header Non-GAAP Financial Measures.

(2)

Total general and administrative expense is comprised of cash general and administrative expense and non-cash equity compensation expense. Cash general and administrative expense per Boe was $1.19, $1.18, and $1.25 for 1Q 2019, 4Q 2018, and 1Q 2018, respectively. Non-cash equity compensation expense per Boe was $0.41, $0.47, and $0.42 for 1Q 2019, 4Q 2018, and 1Q 2018, respectively.

First Quarter Earnings Conference Call

The Company plans to host a conference call to discuss first quarter 2019 results on Tuesday, April 30, 2019 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:


Time and date:		12 p.m. ET, Tuesday, April 30, 2019
Dial-in:		844-309-6572
Intl. dial-in:		484-747-6921
Conference ID:		4290299

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


Replay number:		855-859-2056 or 404-537-3406
Intl. replay:		800-585-8367
Conference ID:		4290299

The Company plans to publish a first quarter 2019 summary presentation to its website at www.CLR.com prior to the start of its conference call on April 30, 2019.

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 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 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 Form 10-K 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.


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

Investor Relations Analyst

405-774-5878

Lucy.Guttenberger@CLR.com

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Income


	Three months ended March 31,
	2019			2018
	In thousands, except per share data
Revenues:
Crude oil and natural gas sales	$	1,109,584		$	1,113,852
Gain (loss) on natural gas derivatives, net		(1,124	)		10,174
Crude oil and natural gas service operations		15,774			17,002

Total revenues		1,124,234			1,141,028

Operating costs and expenses:
Production expenses		106,966			92,962
Production taxes		86,441			80,580
Transportation expenses		49,139			49,297
Exploration expenses		1,837			1,720
Crude oil and natural gas service operations		7,186			4,583
Depreciation, depletion, amortization and accretion		495,019			454,378
Property impairments		25,316			33,784
General and administrative expenses		47,617			43,043
Net gain on sale of assets and other		(252	)		(41	)

Total operating costs and expenses		819,269			760,306

Income from operations		304,965			380,722
Other income (expense):
Interest expense		(67,837	)		(75,894	)
Other		1,355			654

		(66,482	)		(75,240	)

Income before income taxes		238,483			305,482
Provision for income taxes		(51,990	)		(71,536	)

Net income		186,493			233,946
Net loss attributable to noncontrolling interests		(483	)		—

Net income attributable to Continental Resources	$	186,976		$	233,946

Net income per share attributable to Continental Resources:
Basic	$	0.50		$	0.63
Diluted	$	0.50		$	0.63

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Balance Sheets


In thousands	March 31, 2019		December 31, 2018
Assets
Cash and cash equivalents	$	264,371	$	282,749
Other current assets		1,219,691		1,129,612
Net property and equipment (1)		14,118,264		13,869,800
Other noncurrent assets		31,597		15,786

Total assets	$	15,633,923	$	15,297,947

Liabilities and equity
Current liabilities	$	1,445,451	$	1,387,509
Long-term debt, net of current portion		5,766,647		5,765,989
Other noncurrent liabilities		1,783,522		1,722,588
Equity attributable to Continental Resources		6,323,710		6,145,133
Equity attributable to noncontrolling interests		314,593		276,728

Total liabilities and equity	$	15,633,923	$	15,297,947

(1)	Balance is net of accumulated depreciation, depletion and amortization of $11.30 billion and $10.81 billion as of March 31, 2019 and December 31, 2018, respectively.

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Cash Flows


	Three months ended March 31,
In thousands	2019			2018
Net income	$	186,493		$	233,946
Adjustments to reconcile net income to net cash provided by operating activities:
Non-cash expenses		603,591			569,174
Changes in assets and liabilities		(68,576	)		83,071

Net cash provided by operating activities		721,508			886,191
Net cash used in investing activities		(753,071	)		(628,211	)
Net cash (used in) provided by financing activities		13,170			(203,724	)
Effect of exchange rate changes on cash		15			(13	)

Net change in cash and cash equivalents		(18,378	)		54,243
Cash and cash equivalents at beginning of period		282,749			43,902

Cash and cash equivalents at end of period	$	264,371		$	98,145

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, and gains and losses on asset sales. 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 table reconciles 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.


	1Q 2019					4Q 2018					1Q 2018
In thousands, except per share data	$			Diluted EPS		$			Diluted EPS		$			Diluted EPS
Net income attributable to Continental Resources (GAAP)	$	186,976		$	0.50	$	197,738		$	0.53	$	233,946		$	0.63
Adjustments:
Non-cash (gain) loss on derivatives		14,186					(25,022	)				(5,978	)
Property impairments		25,316					38,494					33,784
Gain on sale of assets, net		(252	)				(8,410	)				(41	)
Total tax effect of adjustments (1)		(9,616	)				(1,114	)				(6,571	)

Total adjustments, net of tax		29,634			0.08		3,948			0.01		21,194			0.05

Adjusted net income (non-GAAP)	$	216,610		$	0.58	$	201,686		$	0.54	$	255,140		$	0.68
Weighted average diluted shares outstanding		374,474					374,525					374,181

Adjusted diluted net income per share (non-GAAP)	$	0.58				$	0.54				$	0.68

(1)	Computed by applying a combined federal and state statutory tax rate of 24.5% in effect for 1Q 2019 and 4Q 2018 and 24.0% in effect for 1Q 2018 to the pre-tax amount of adjustments associated with our operations in the United States.

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 March 31, 2019, the Company’s total debt was $5.77 billion and its net debt amounted to $5.50 billion, representing total debt of $5.77 billion less cash and cash equivalents of $264.4 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 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 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.

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


	1Q		4Q			1Q
In thousands	2019		2018			2018
Net income	$	186,493	$	199,121		$	233,946
Interest expense		67,837		69,441			75,894
Provision for income taxes		51,990		62,868			71,536
Depreciation, depletion, amortization and accretion		495,019		488,416			454,378
Property impairments		25,316		38,494			33,784
Exploration expenses		1,837		3,295			1,720
Impact from derivative instruments:
Total (gain) loss on derivatives, net		1,124		19,394			(10,174	)
Total cash (paid) received on derivatives, net		13,062		(44,416	)		4,196

Non-cash (gain) loss on derivatives, net		14,186		(25,022	)		(5,978	)
Non-cash equity compensation		12,107		14,027			10,916

EBITDAX (non-GAAP)	$	854,785	$	850,640		$	876,196

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


	1Q			4Q			1Q
In thousands	2019			2018			2018
Net cash provided by operating activities	$	721,508		$	955,267		$	886,191
Current income tax provision		—			2			—
Interest expense		67,837			69,441			75,894
Exploration expenses, excluding dry hole costs		1,837			3,149			1,719
Gain on sale of assets, net		252			8,410			41
Other, net		(5,225	)		(5,516	)		(4,578	)
Changes in assets and liabilities		68,576			(180,113	)		(83,071	)

EBITDAX (non-GAAP)	$	854,785		$	850,640		$	876,196

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 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 periods presented.


	Three months ended March 31, 2019
In thousands	Crude oil			Natural gas			Total
Crude oil and natural gas sales (GAAP)	$	911,118		$	198,466		$	1,109,584
Less: Transportation expenses		(41,648	)		(7,491	)		(49,139	)

Net crude oil and natural gas sales (non-GAAP)	$	869,470		$	190,975		$	1,060,445
Sales volumes (MBbl/MMcf/MBoe)		17,373			74,690			29,821

Net sales price (non-GAAP)	$	50.05		$	2.56		$	35.56

	Three months ended December 31, 2018
In thousands	Crude oil			Natural gas			Total
Crude oil and natural gas sales (GAAP)	$	900,872		$	253,232		$	1,154,104
Less: Transportation expenses		(42,373	)		(6,655	)		(49,028	)

Net crude oil and natural gas sales (non-GAAP)	$	858,499		$	246,577		$	1,105,076
Sales volumes (MBbl/MMcf/MBoe)		17,149			75,661			29,759

Net sales price (non-GAAP)	$	50.06		$	3.26		$	37.13

	Three months ended March 31, 2018
In thousands	Crude oil			Natural gas			Total
Crude oil and natural gas sales (GAAP)	$	906,281		$	207,571		$	1,113,852
Less: Transportation expenses		(40,386	)		(8,911	)		(49,297	)

Net crude oil and natural gas sales (non-GAAP)	$	865,895		$	198,660		$	1,064,555
Sales volumes (MBbl/MMcf/MBoe)		14,682			66,730			25,804

Net sales price (non-GAAP)	$	58.98		$	2.98		$	41.26

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.

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.


	1Q			4Q			1Q
	2019			2018			2018
Total G&A per Boe (GAAP)	$	1.60		$	1.65		$	1.67
Less: Non-cash equity compensation per Boe		(0.41	)		(0.47	)		(0.42	)

Cash G&A per Boe (non-GAAP)	$	1.19		$	1.18		$	1.25

Continental Resources, Inc.

2019 Guidance

As of April 29, 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 a non-GAAP measure and excludes the range of values shown for non-cash equity compensation per Boe in the item appearing immediately below. Guidance for total G&A (cash and non-cash) is an expected range of $1.70 to $2.00 per Boe.