Continental Resources Announces Full-Year 2020 And 4Q20 Results; 2021 Capital Budget And Guidance

Rhea-AI Summary

Continental Resources reported a FY20 cash flow from operations of $1.42 billion and $275 million of free cash flow, marking its fifth consecutive year of positive free cash flow despite a $596.9 million net loss. The 4Q20 results showed average daily production of 339,307 Boepd with production costs at $2.80 per Boe. For FY21, the company projects over $2.4 billion in cash flow from operations and plans to reduce debt to $4.5 billion by the end of the year. Additionally, it is expanding into the Wyoming Powder River Basin, adding resources to its portfolio.

Positive

• Generated $275 million in free cash flow in FY20.
• Projected $2.4 billion cash flow from operations and $1.0 billion free cash flow in FY21.
• Fifth consecutive year of positive free cash flow.
• Expanding operations into the Wyoming Powder River Basin with 130,000 net acres and 400 MMBoe resource potential.

Negative

• $596.9 million net loss for FY20.
• $92.5 million net loss for 4Q20.

OKLAHOMA CITY, Feb. 16, 2021 /PRNewswire/ --

FY20: $1.4 B Cash Flow from Operations & $275 MM Free Cash Flow (Non-GAAP)

• 4Q20: $488 MM Cash Flow from Operations & $332 MM Free Cash Flow (FCF)
   o $168 MM in Non-Acquisition Capex 
   o 176.6 MBopd & 976 MMcfpd Average Daily Production
   o $2.80 Production Expense per Boe

• FY20: Fifth Consecutive Year of Generating Positive FCF
   o $1.16 B in Non-Acquisition Capex ($1.2 B Guidance) 
   o 160.5 MBopd & 837.5 MMcfpd Avg. Daily Production (155-165 MBopd & 800-820 MMcfpd
      Guidance) 
   o $3.27 Production Expense per Boe ($3.50-$3.75 Guidance)

FY21: Projecting Sixth Consecutive Year of Generating Positive FCF

• In Excess of 40% of Cash Flow from Operations Projected toward Shareholder
  Capital Returns through Debt Reduction and Future Dividends¹ 
   o Targeting Approx. $4.5 B Total Debt by YE21; <$4.0 B by YE22

• Approx. $2.4 B of Cash Flow from Operations; $1.0 B of FCF; 12% FCF Yield²  (non-GAAP)
   o 58% Reinvestment Rate; 3-4% Total Production Growth; Budgeted at $52 WTI & $2.75 HH
   o $5 Increase in WTI = Approx. $250 MM Increase in Cash Flow

• Expanding Operations into the Oil-Weighted Wyoming Powder River Basin in March 2021
   o Adds 130,000 Net Acres & 400 MMBoe Net Unrisked Resource Potential to CLR Portfolio

Continental Resources, Inc. (NYSE: CLR) (the "Company") today announced its full-year 2020 and fourth quarter 2020 operating and financial results, as well as its 2021 capital expenditures budget and operating plan.

Logo - https://mma.prnewswire.com/media/95419/continental_resources_logo.jpg

"In 2020, Continental demonstrated our commitment to delivering sustainable free cash flow by generating $275 million of free cash flow in arguably one of the most challenging years of our over 50 years of operations. Delivering our fifth consecutive year of free cash flow in spite of unprecedented market volatility validates our durable approach to managing our business. We are well-positioned to sustainably deliver significant shareholder returns from strong free cash flow in 2021 and beyond," said Bill Berry, Chief Executive Officer.

1  All future dividends require Board approval.
2  Free cash flow yield is estimated by dividing the 2021 annual FCF estimate by the Company's current market     capitalization, as of February 16, 2021.

The Company reported a full-year 2020 net loss of $596.9 million, or $1.65 per diluted share. For full-year 2020, typically excluded items in aggregate represented $172.9 million, or $0.48 per diluted share, of Continental's reported net loss. Adjusted net loss for full-year 2020 was $424.0 million, or $1.17 per diluted share (non-GAAP). Net cash provided by operating activities for full-year 2020 was $1.42 billion and EBITDAX was $1.68 billion (non-GAAP).

The Company reported a net loss of $92.5 million, or $0.26 per diluted share, for the quarter ended December 31, 2020. In fourth quarter 2020, typically excluded items in aggregate represented $10.6 million, or $0.03 per diluted share, of Continental's reported net loss. Adjusted net loss for fourth quarter 2020 was $81.9 million, or $0.23 per diluted share (non-GAAP). Net cash provided by operating activities for fourth quarter 2020 was $487.5 million and EBITDAX was $572.0 million (non-GAAP).

Adjusted net income (loss), adjusted net income (loss) per share, free cash flow, free cash flow yield, 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.

Production & Operations Update

Full-year 2020 total production averaged 300,090 Boepd. Full-year 2020 oil production averaged 160,505 Bopd. Full-year 2020 natural gas production averaged 837.5 MMcfpd. Fourth quarter 2020 total production averaged 339,307 Boepd. Fourth quarter 2020 oil production averaged 176,639 Bopd. Fourth quarter 2020 natural gas production averaged 976.0 MMcfpd.

The Company achieved its 2020 completed well cost targets in both the Bakken and Oklahoma, with go forward well costs in the Bakken of approximately $690 per lateral foot, at a 10,000' lateral length, and in Oklahoma of approximately $1,070 per lateral foot, at an 8,200' lateral length. These all-in well costs include drilling and completion (D&C), full facilities and artificial lift. Cost savings are 70% to 80% structural and are being driven by a reduction in drilling cycle times, stage counts, proppant volumes and stimulation days, as well as the optimization of artificial lift.

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

		4Q		4Q		FY		FY
Boe per day		2020		2019		2020		2019
Bakken		183,141		194,156		158,604		194,691
South		149,377		163,552		134,540		137,579
All other		6,789		7,633		6,946		8,125
Total		339,307		365,341		300,090		340,395

Financial Update

"As part of our commitment to operational excellence and capital discipline, Continental spent approximately 3% less non-acquisition Capex than budgeted while delivering oil production in line with the midpoint of our guidance. Our strong cost performance continues to underpin and drive our ability to generate significant free cash flow historically and prospectively," said John Hart, Chief Financial Officer.

		Three Months Ended		Year Ended
2020 Financial Update		December 31, 2020		December 31, 2020
Cash and Cash Equivalents				$47.5 million
Total Debt				$5.53 billion
Net Debt (non-GAAP)(1)				$5.48 billion
Average Net Sales Price (non-GAAP)(1)
Per Barrel of Oil		$37.34		$34.71
Per Mcf of Gas		$1.81		$1.04
Per Boe		$24.63		$21.47
Production Expense per Boe		$2.80		$3.27
Total G&A Expenses per Boe		$2.14		$1.79
Crude Oil Differential per Barrel		($5.20)		($5.80)
Natural Gas Differential per Mcf		($0.87)		($1.10)
Non-Acquisition Capital Expenditures		$168.1 million		$1,159.0 million
Exploration & Development Drilling & Completion		$151.0 million		$971.7 million
Leasehold		$3.5 million		$34.5 million
Minerals, of which 80% was Recouped from FNV		$0.1 million		$23.9 million
Workovers, Recompletions and Other		$13.5 million		$128.9 million
(1) Net debt and net sales prices 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.

Strategic Acquisition and Entrance into the Wyoming Powder River Basin

The Company announced it has executed definitive documents to acquire approximately 130,000 net acres and approximately 9,000 Boepd of production in the Powder River Basin for $215 million, subject to customary closing conditions. This acquisition included 96 approved federal drilling permits and is expected to close in March 2021. The Company intends to begin delineating and developing the Shannon, Frontier and Niobrara reservoirs with 2 rigs in second quarter 2021.  

"These Powder River Basin assets provide Continental another oil-weighted platform, adding over 400 MMBoe of net unrisked resource potential to our portfolio," said Jack Stark, President and Chief Operating Officer. "We especially like the fact that the basin is in the very early stages of development with solid economics even before applying our low cost efficient operations."

2021 Capital Budget & Guidance

The Company is projecting a $1.4 billion capital expenditures budget, net of Franco Nevada's share of mineral costs, which approximates to a 58% cash flow from operations (CFFO) reinvestment rate for 2021. The 2021 capital budget is projected to generate approximately $2.4 billion of cash flow from operations and $1.0 billion of free cash flow (non-GAAP) for full-year 2021 at $52 per barrel WTI and $2.75 per Mcf Henry Hub. A $5 increase per barrel WTI is estimated to increase cash flow by approximately $250 million.

The Company is projecting approximately 12% free cash flow yield (non-GAAP) at $52 WTI. Free cash flow yield is estimated by dividing the 2021 annual FCF estimate by the Company's current market capitalization, as of February 16, 2021. The Company is targeting shareholder capital returns in excess of 40% of cash flow from operations through debt reduction and future dividends. All future dividends require Board approval. Additionally, the Company is projecting total debt of approximately $4.5 billion at year-end 2021 and $4.0 billion or below by year-end 2022.

Annual crude oil production is projected to range between 160,000 to 165,000 Bopd. Annual natural gas production is projected to range between 880,000 to 920,000 Mcfpd.

The Company is allocating approximately $1.1 billion to D&C activities, of which approximately 60% is allocated to the Bakken and approximately 35% to Oklahoma, with the remaining capital being allocated to the Powder River Basin asset. An additional $300 million is being allocated to non-D&C capital and is planned to be primarily for leasehold, mineral acquisitions, workovers and facilities.

At year-end 2021, the Company expects to have a working backlog of approximately 135 gross operated wells in progress in various stages of completion.

As an update on the previously disclosed water monetization process, the Company has made the decision not to further pursue this transaction. Ultimately, the Company has elected to maintain full operational flexibility to maximize the long-term value of these assets and enhance cash flow.

The Company's full 2021 guidance, capital expenditures budget and operating details can be found at the conclusion of this press release.

"Our 58% reinvestment rate at $52 WTI in 2021 highlights our commitment to generating significant and sustainable free cash flow. With expectations to deliver a strong free cash flow yield and shareholder capital returns in excess of 40% of cash flow from operations through debt reduction and future dividends, Continental will continue to drive shareholder value," said Bill Berry, Chief Executive Officer.

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.

	Three months ended December 31,				Year ended December 31,
	2020		2019		2020		2019
Average daily production:
Crude oil (Bbl per day)	176,639		206,249		160,505		197,991
Natural gas (Mcf per day)	976,011		954,556		837,509		854,424
Crude oil equivalents (Boe per day)	339,307		365,341		300,090		340,395
Average net sales prices (non-GAAP), excluding effect from derivatives: (1)
Crude oil ($/Bbl)	$           37.34		$           51.33		$           34.71		$           51.82
Natural gas ($/Mcf)	$             1.81		$             1.73		$             1.04		$             1.77
Crude oil equivalents ($/Boe)	$           24.63		$           33.49		$           21.47		$           34.56
Production expenses ($/Boe)	$             2.80		$             3.31		$             3.27		$             3.58
Production taxes (% of net crude oil and gas sales)	7.8%		8.1%		8.2%		8.3%
DD&A ($/Boe)	$           19.01		$           16.45		$           17.12		$           16.25
Total general and administrative expenses ($/Boe) (2)	$             2.14		$             1.59		$             1.79		$             1.57
Net income (loss) attributable to Continental Resources (in thousands)	$        (92,497)		$        193,946		$       (596,869)		$        775,641
Diluted net income (loss) per share attributable to Continental Resources	$            (0.26)		$             0.53		$            (1.65)		$             2.08
Adjusted net income (loss) (non-GAAP) (in thousands) (1)	$        (81,896)		$        203,589		$       (424,035)		$        838,723
Adjusted diluted net income (loss) per share (non-GAAP) (1)	$            (0.23)		$             0.55		$            (1.17)		$             2.25
Net cash provided by operating activities (in thousands)	$        487,537		$        803,812		$     1,422,304		$     3,115,688
EBITDAX (non-GAAP) (in thousands) (1)	$        571,952		$        905,525		$     1,675,523		$     3,447,033
(1) Net sales prices, adjusted net income (loss), adjusted diluted net income (loss) 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 $1.61, $1.15, $1.20, and $1.15 for 4Q 2020, 4Q 2019, FY 2020, and FY 2019, respectively. Non-cash equity compensation expense per Boe was $0.53, $0.44, $0.59, and $0.42 for 4Q 2020, 4Q 2019, FY 2020, and FY 2019, respectively.

Fourth Quarter Earnings Conference Call

The Company plans to host a conference call to discuss full-year 2020 and fourth quarter 2020 results on Wednesday, February 17, 2021 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:	12:00 p.m. ET, Wednesday, February 17, 2021
Dial-in:	1-888-317-6003
Intl. dial-in:	1-412-317-6061
Conference ID:	6942729

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

Replay number:	1-877-344-7529
Intl. replay:	1-412-317-0088
Conference ID:	10151479

The Company plans to publish a full-year 2020 and fourth quarter 2020 summary presentation to its website at www.CLR.com prior to the start of its conference call on Wednesday, February 17, 2021.

About Continental Resources

Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. 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 2021, the Company will celebrate 54 years of operations. For more information, please visit www.CLR.com.     

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

This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "target," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the effects of any national or international health crisis; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; our ability to pay future dividends or complete share repurchases; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2019, Quarterly Reports on Form 10-Q for the quarters ended March 31, 2020, June 30, 2020 and September 30, 2020, and once filed, the Company's Annual Report on Form 10-K for the year ended December 31, 2020, 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, if any, 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 Spaay
Investor Relations Analyst
405-774-5878
Lucy.Spaay@CLR.com

 

 

Continental Resources, Inc. and Subsidiaries
Consolidated Statements of Income (Loss)
	Three months ended December 31,				Year ended December 31,
	2020		2019		2020		2019
Revenues:	In thousands, except per share data
Crude oil and natural gas sales	$          816,571		$       1,185,980		$       2,555,434		$       4,514,389
Gain (loss) on derivative insturments, net	10,977		(4,436)		(14,658)		49,083
Crude oil and natural gas service operations	10,092		13,590		45,694		68,475
Total revenues	837,640		1,195,134		2,586,470		4,631,947
Operating costs and expenses:
Production expenses	87,415		111,203		359,267		444,649
Production taxes	60,274		90,751		192,718		357,988
Transportation expenses	48,613		61,080		196,692		225,649
Exploration expenses	3,094		7,268		17,732		14,667
Crude oil and natural gas service operations	3,006		6,614		18,294		33,230
Depreciation, depletion, amortization and accretion	592,774		552,711		1,880,959		2,017,383
Property impairments	12,965		19,348		277,941		86,202
General and administrative expenses	66,859		53,465		196,572		195,302
Net (gain) loss on sale of assets and other	(5,727)		(1,182)		187		(535)
Total operating costs and expenses	869,273		901,258		3,140,362		3,374,535
Income (loss) from operations	(31,633)		293,876		(553,892)		1,257,412
Other income (expense):
Interest expense	(65,693)		(64,981)		(258,240)		(269,379)
Gain (loss) on extinguishment of debt	(28,854)		-		35,719		(4,584)
Other	277		516		1,662		3,713
	(94,270)		(64,465)		(220,859)		(270,250)
Income (loss) before income taxes	(125,903)		229,411		(774,751)		987,162
(Provision) benefit for income taxes	30,840		(35,303)		169,190		(212,689)
Net income (loss)	(95,063)		194,108		(605,561)		774,473
Net income (loss) attributable to noncontrolling interests	(2,566)		162		(8,692)		(1,168)
Net income (loss) attributable to Continental Resources	$           (92,497)		$          193,946		$         (596,869)		$          775,641
Net income (loss) per share attributable to Continental Resources:
Basic	$              (0.26)		$               0.53		$              (1.65)		$               2.09
Diluted	$              (0.26)		$               0.53		$              (1.65)		$               2.08

 

 

Continental Resources, Inc. and Subsidiaries
Consolidated Balance Sheets
In thousands		December 31, 2020		December 31, 2019
Assets
Cash and cash equivalents		$                 47,470		$                 39,400
Other current assets		805,075		1,167,615
Net property and equipment (1)		13,737,292		14,497,726
Other noncurrent assets		43,261		23,166
Total assets		$           14,633,098		$           15,727,907
Liabilities and equity
Current liabilities		$                860,806		$             1,336,026
Long-term debt, net of current portion		5,530,173		5,324,079
Other noncurrent liabilities		1,819,394		1,959,451
Equity attributable to Continental Resources		6,056,446		6,741,667
Equity attributable to noncontrolling interests		366,279		366,684
Total liabilities and equity		$           14,633,098		$           15,727,907
(1) Balance is net of accumulated depreciation, depletion and amortization of $14.77 billion and $12.77  billion as of December 31, 2020 and December 31, 2019, respectively.

 

 

Continental Resources, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
		Three months ended December 31,				Year ended December 31,
In thousands		2020		2019		2020		2019
Net income (loss)		$             (95,063)		$            194,108		$           (605,561)		$            774,473
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Non-cash expenses		597,995		641,495		2,025,987		2,400,708
Changes in assets and liabilities		(15,395)		(31,791)		1,878		(59,493)
Net cash provided by operating activities		487,537		803,812		1,422,304		3,115,688
Net cash used in investing activities		(329,492)		(518,029)		(1,511,358)		(2,771,956)
Net cash provided by (used in) financing activities		(131,812)		(281,650)		97,124		(587,108)
Effect of exchange rate changes on cash		-		7		-		27
Net change in cash and cash equivalents		26,233		4,140		8,070		(243,349)
Cash and cash equivalents at beginning of period		21,237		35,260		39,400		282,749
Cash and cash equivalents at end of period		$              47,470		$              39,400		$              47,470		$              39,400

 

Non-GAAP Financial Measures

 

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

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

								Three months ended December 31,
								2020				2019
In thousands, except per share data								$		Diluted EPS		$		Diluted EPS
Net income (loss) attributable to Continental Resources (GAAP)								$      (92,497)		$     (0.26)		$     193,946		$      0.53
Adjustments:
Non-cash (gain) loss on derivatives								(22,052)				16,915
Property impairments								12,965				19,348
Net gain on sale of assets and other								(5,727)				(1,182)
Loss on extinguishment of debt								28,854				-
Total tax effect of adjustments (1)								(3,439)				(8,578)
Tax benefit from sale of Canadian subsidiary								-				(16,860)
Total adjustments, net of tax								10,601		0.03		9,643		0.02
Adjusted net income (loss) (non-GAAP)								$      (81,896)		($0.23)		$     203,589		$      0.55
Weighted average diluted shares outstanding								360,316				368,825
Adjusted diluted net income (loss) per share (non-GAAP)								$         (0.23)				$          0.55
								Year ended December 31,
								2020				2019
In thousands, except per share data								$		Diluted EPS		$		Diluted EPS
Net income (loss) attributable to Continental Resources (GAAP)								$    (596,869)		$     (1.65)		$     775,641		$      2.08
Adjustments:
Non-cash (gain) loss on derivatives								(13,492)				15,612
Property impairments								277,941				86,202
Net (gain) loss on sale of assets and other								187				(535)
(Gain) loss on extinguishment of debt								(35,719)				4,584
Total tax effect of adjustments (1)								(56,083)				(25,921)
Tax benefit from sale of Canadian subsidiary								-				(16,860)
Total adjustments, net of tax								172,834		0.48		63,082		0.17
Adjusted net income (loss) (non-GAAP)								$    (424,035)		($1.17)		$     838,723		$      2.25
Weighted average diluted shares outstanding								361,538				372,538
Adjusted diluted net income (loss) per share (non-GAAP)								$         (1.17)				$          2.25
(1) Computed by applying a combined federal and state statutory tax rate of 24.5% in effect for 2020 and 2019 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 December 31, 2020, the Company's total debt was $5.53 billion and its net debt amounted to $5.48 billion, representing total debt of $5.53 billion less cash and cash equivalents of $47.5 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 gains and losses on extinguishment of debt as applicable. EBITDAX is not a measure of net income or net cash provided by operating activities as determined by U.S. GAAP.

Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. Further, we believe EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. We exclude the items listed above from net income/loss and net cash provided by operating activities in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired.

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

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

		Three months ended December 31,						Year ended December 31,
In thousands		2020			2019			2020			2019
Net income (loss)		$	(95,063)		$	194,108		$	(605,561)		$	774,473
Interest expense		65,693			64,981			258,240			269,379
Provision (benefit) for income taxes		(30,840)			35,303			(169,190)			212,689
Depreciation, depletion, amortization and accretion		592,774			552,711			1,880,959			2,017,383
Property impairments		12,965			19,348			277,941			86,202
Exploration expenses		3,094			7,268			17,732			14,667
Impact from derivative instruments:
Total (gain) loss on derivatives, net		(10,977)			4,436			14,658			(49,083)
Total cash (paid) received on derivatives, net		(11,075)			12,479			(28,150)			64,695
Non-cash (gain) loss on derivatives, net		(22,052)			16,915			(13,492)			15,612
Non-cash equity compensation		16,527			14,891			64,613			52,044
(Gain) loss on extinguishment of debt		28,854			-			(35,719)			4,584
EBITDAX (non-GAAP)		$	571,952		$	905,525		$	1,675,523		$	3,447,033

 

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

		Three months ended December 31,						Year ended December 31,
In thousands		2020			2019			2020			2019
Net cash provided by operating activities		$	487,537		$	803,812		$	1,422,304		$	3,115,688
Current income tax provision (benefit)		4			—			(2,219)			—
Interest expense		65,693			64,981			258,240			269,379
Exploration expenses, excluding dry hole costs		3,092			7,268			11,274			14,667
Gain (loss) on sale of assets and other, net		5,727			1,182			(187)			535
Other, net		(5,496)			(3,509)			(12,011)			(12,729)
Changes in assets and liabilities		15,395			31,791			(1,878)			59,493
EBITDAX (non-GAAP)		$	571,952		$	905,525		$	1,675,523		$	3,447,033

 

Non-GAAP Free Cash Flow and Free Cash Flow Yield

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

The following table reconciles net cash provided by operating activities as determined under U.S. GAAP to free cash flow for the full-year 2020 and three months ended December 31, 2020.

In thousands		4Q 2020		FY 2020
Net cash provided by operating activities (GAAP)		$          487,537		$        1,422,304
Exclude: Changes in working capital items		15,395		(1,878)
Less: Capital expenditures (1)		(168,049)		(1,158,981)
Plus: Contributions from noncontrolling interests		529		27,116
Less: Distributions to noncontrolling interests		(2,995)		(13,809)
Free cash flow (non-GAAP)		$          332,417		$          274,752
(1) Capital expenditures are calculated as follows:
In thousands		4Q 2020		FY 2020
Cash paid for capital expenditures		$          330,066		$        1,514,137
Less: Total acquisitions		(191,508)		(225,553)
Plus: Change in accrued capital expenditures & other		28,756		(133,863)
Plus: Exploratory seismic costs		735		4,260
Capital expenditures		$          168,049		$        1,158,981

 

Non-GAAP Net Sales Prices

Revenues and transportation expenses associated with production from our operated properties are reported separately. For non-operated properties, we receive a net payment from the operator for our share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds received. As a result, the separate presentation of revenues and transportation expenses from our operated properties differs from the net presentation from non-operated properties. This impacts the comparability of certain operating metrics, such as per-unit sales prices, when such metrics are prepared in accordance with U.S. GAAP using gross presentation for some revenues and net presentation for others.

In order to provide metrics prepared in a manner consistent with how management assesses the Company's operating results and to achieve comparability between operated and non-operated revenues, we may present crude oil and natural gas sales net of transportation expenses, which we refer to as "net crude oil and natural gas sales," a non-GAAP measure.  Average sales prices calculated using net crude oil and natural gas sales are referred to as "net sales prices," a non-GAAP measure, and are calculated by taking revenues less transportation expenses divided by sales volumes, whether for crude oil or natural gas, as applicable. Management believes presenting our revenues and sales prices net of transportation expenses is useful because it normalizes the presentation differences between operated and non-operated revenues and allows for a useful comparison of net realized prices to NYMEX benchmark prices on a Company-wide basis.

The following tables present a reconciliation of crude oil and natural gas sales (GAAP) to net crude oil and natural gas sales and related net sales prices (non-GAAP) for the periods presented.

		Three months ended December 31, 2020						Three months ended December 31, 2019
In thousands		Crude oil		Natural gas		Total		Crude oil		Natural gas		Total
Crude oil and natural gas sales (GAAP)		$643,532		$173,039		$816,571		$1,024,432		$161,548		$1,185,980
Less: Transportation expenses		(38,208)		(10,405)		(48,613)		(51,332)		(9,748)		(61,080)
Net crude oil and natural gas sales (non-GAAP)		$605,324		$162,634		$767,958		$973,100		$151,800		$1,124,900
Sales volumes (MBbl/MMcf/MBoe)		16,210		89,793		31,175		18,956		87,819		33,593
Net sales price (non-GAAP)		$37.34		$1.81		$24.63		$51.33		$1.73		$33.49
		Year ended December 31, 2020						Year ended December 31, 2019
In thousands		Crude oil		Natural gas		Total		Crude oil		Natural gas		Total
Crude oil and natural gas sales (GAAP)		$2,199,976		$355,458		$2,555,434		$3,929,994		$584,395		$4,514,389
Less: Transportation expenses		(158,989)		(37,703)		(196,692)		(191,998)		(33,651)		(225,649)
Net crude oil and natural gas sales (non-GAAP)		$2,040,987		$317,755		$2,358,742		$3,737,996		$550,744		$4,288,740
Sales volumes (MBbl/MMcf/MBoe)		58,793		306,528		109,881		72,136		311,865		124,113
Net sales price (non-GAAP)		$34.71		$1.04		$21.47		$51.82		$1.77		$34.56

 

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.

		Three months ended December 31,				Year ended December 31,
		2020		2019		2020		2019
Total G&A per Boe (GAAP)		$               2.14		$               1.59		$               1.79		$               1.57
Less: Non-cash equity compensation per Boe		(0.53)		(0.44)		(0.59)		(0.42)
Cash G&A per Boe (non-GAAP)		$               1.61		$               1.15		$               1.20		$               1.15

 

 

Continental Resources, Inc.
2021 Guidance
As of February 16, 2021
			2021
Full-year average oil production (Bopd)			160,000 to 165,000
Full-year average natural gas production (Mcfpd)			880,000 to 920,000
Capital expenditures budget			$1.4 billion
Operating Expenses:
Production expense per Boe			$3.25 to $3.75
Production tax (% of net oil & gas revenue)			7.9% to 8.1%
Cash G&A expense per Boe(1)			$1.20 to $1.40
Non-cash equity compensation per Boe			$0.45 to $0.55
DD&A per Boe			$16.50 to $18.50
Average Price Differentials:
NYMEX WTI crude oil(per barrel of oil)			($4.50) to ($5.50)
Henry Hub natural gas(2)(per Mcf)			($0.25) to ($0.75)
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 a projected range of $1.65 to $1.95 per Boe.
2. Includes natural gas liquids production in differential range.

 

2021 Capital Expenditures
The following table provides the breakout of budgeted capital expenditures:
($ in Millions)	North D&C			South D&C		Leasehold, Facilities, Other(1)
Capex	$732			$380		$288
1.  Includes $13 million of minerals royalty acquisitions attributable to Continental. Excludes $52 million of minerals acquisitions attributable to      Franco-Nevada.
2021 Operational Detail
The following table provides additional operational detail for wells expected to have first production in 2021:
Asset	Average Rigs		Gross Operated Wells		Net Operated Wells		Total Net Wells(1)
North	7		143		85		94
South	4		67		54		57
Total	11		210		139		151
1.  Represents projected net operated and non-operated wells with first production.

 

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SOURCE Continental Resources

FAQ

What were Continental Resources' cash flow results for FY20?

Continental Resources reported a cash flow from operations of $1.42 billion and free cash flow of $275 million for FY20.

What is the debt reduction target for Continental Resources by YE21?

Continental Resources is targeting approximately $4.5 billion in total debt by the end of FY21.

What is the projected cash flow for Continental Resources in FY21?

Continental Resources projects over $2.4 billion in cash flow from operations and $1.0 billion in free cash flow for FY21.

What were the average daily production figures for Continental Resources in FY20?

In FY20, Continental Resources averaged daily production of 300,090 Boepd, with 160,505 Bopd from oil.

What is the significance of the Wyoming Powder River Basin acquisition for CLR?

The acquisition adds 130,000 net acres and 400 MMBoe of net unrisked resource potential to Continental Resources' portfolio.