Company Quick10K Filing
Quick10K
Continental Resources
Closing Price ($) Shares Out (MM) Market Cap ($MM)
$42.03 377 $15,830
10-Q 2019-03-31 Quarter: 2019-03-31
10-K 2018-12-31 Annual: 2018-12-31
10-Q 2018-09-30 Quarter: 2018-09-30
10-Q 2018-06-30 Quarter: 2018-06-30
10-Q 2018-03-31 Quarter: 2018-03-31
10-K 2017-12-31 Annual: 2017-12-31
10-Q 2017-09-30 Quarter: 2017-09-30
10-Q 2017-06-30 Quarter: 2017-06-30
10-Q 2017-03-31 Quarter: 2017-03-31
10-K 2016-12-31 Annual: 2016-12-31
10-Q 2016-09-30 Quarter: 2016-09-30
10-Q 2016-06-30 Quarter: 2016-06-30
10-Q 2016-03-31 Quarter: 2016-03-31
10-K 2015-12-31 Annual: 2015-12-31
10-Q 2015-09-30 Quarter: 2015-09-30
10-Q 2015-06-30 Quarter: 2015-06-30
10-Q 2015-03-31 Quarter: 2015-03-31
10-K 2014-12-31 Annual: 2014-12-31
10-Q 2014-09-30 Quarter: 2014-09-30
10-Q 2014-06-30 Quarter: 2014-06-30
10-Q 2014-03-31 Quarter: 2014-03-31
10-K 2013-12-31 Annual: 2013-12-31
8-K 2019-06-04 Officers
8-K 2019-05-16 Shareholder Vote
8-K 2019-04-29 Earnings, Regulation FD, Exhibits
8-K 2019-02-18 Earnings, Regulation FD, Exhibits
8-K 2019-02-13 Earnings, Exhibits
8-K 2019-02-12 Officers
8-K 2018-10-29 Earnings, Regulation FD, Exhibits
8-K 2018-08-07 Earnings, Regulation FD, Exhibits
8-K 2018-07-24 Earnings, Exhibits
8-K 2018-05-17 Shareholder Vote
8-K 2018-05-02 Earnings, Regulation FD, Exhibits
8-K 2018-04-09 Enter Agreement, Leave Agreement, Off-BS Arrangement, Exhibits
8-K 2018-03-26 Officers
8-K 2018-03-19 Officers
8-K 2018-02-21 Earnings, Regulation FD, Exhibits
8-K 2018-02-16 Other Events
8-K 2018-02-15 Earnings, Exhibits
EA Electronic Arts 27,960
CSOD Cornerstone Ondemand 3,190
ALTR Altair Engineering 2,630
POWI Power Integrations 2,210
WDR Waddell & Reed Financial 1,340
QHC Quorum Health 65
WHLM Wilhelmina 31
XPL Solitario Zinc 20
AKAO Achaogen 0
FEPI First Equity Properties 0
CLR 2019-03-31
Part I. Financial Information
Item 1. Financial Statements
Note 1. Organization and Nature of Business
Note 2. Basis of Presentation and Significant Accounting Policies
Note 3. Supplemental Cash Flow Information
Note 4. Revenues
Note 5. Derivative Instruments
Note 6. Fair Value Measurements
Note 7. Long-Term Debt
Note 8. Leases
Note 9. Commitments and Contingencies
Note 10. Stock-Based Compensation
Note 11. Accumulated Other Comprehensive Income
Note 12. Income Taxes
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Item 4. Controls and Procedures
Part II. Other Information
Item 1. Legal Proceedings
Item 1A. Risk Factors
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Item 3. Defaults Upon Senior Securities
Item 4. Mine Safety Disclosures
Item 5. Other Information
Item 6. Exhibits
EX-10.1 clr1q2019-ex10i.htm
EX-10.2 clr1q2019-ex10ii.htm
EX-10.3 clr1q2019-ex10iii.htm
EX-10.4 clr1q2019-ex10iv.htm
EX-31.1 clr1q2019-ex31i.htm
EX-31.2 clr1q2019-ex31ii.htm
EX-32 clr1q2019-ex32.htm

Continental Resources Earnings 2019-03-31

CLR 10Q Quarterly Report

Balance SheetIncome StatementCash Flow

10-Q 1 clr1q2019.htm 10-Q Document
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
________________________________________
FORM 10-Q
________________________________________
(Mark One)
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2019
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
Commission File Number: 001-32886
 ____________________________________
logoa02a11.jpg
 CONTINENTAL RESOURCES, INC.
(Exact name of registrant as specified in its charter)
 ____________________________________
Oklahoma
 
73-0767549
(State of incorporation or organization)
 
(I.R.S. Employer Identification No.)
 
 
 
20 N. Broadway, Oklahoma City, Oklahoma
 
73102
(Address of principal executive offices)
 
(Zip Code)
(405) 234-9000
(Registrant’s telephone number, including area code)
Not Applicable
(Former name, former address and former fiscal year, if changed since last report)
Securities registered pursuant to Section 12(b) of the Act:
Title of class
 Trading symbol
Name of exchange on which registered
Common Stock, $0.01 par value
CLR
New York Stock Exchange
 ____________________________________
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes x    No ¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes x    No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
 
x
  
Accelerated filer
  
¨
Non-accelerated filer
 
¨ 
  
Smaller reporting company
  
¨
 
 
 
 
Emerging growth company
 
¨
 
 
 
 
 
 
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes ¨    No x
376,745,750 shares of our $0.01 par value common stock were outstanding on April 22, 2019.




Table of Contents
 
 
 
Item 1.
 
 
 
 
 
Item 2.
Item 3.
Item 4.
 
 
 
Item 1.
Item 1A.
Item 2.
Item 3.
Item 4.
Item 5.
Item 6.
 
When we refer to “us,” “we,” “our,” “Company,” or “Continental” we are describing Continental Resources, Inc. and our subsidiaries.




Glossary of Crude Oil and Natural Gas Terms

The terms defined in this section may be used throughout this report:
“Bbl” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids.
“Boe” Barrels of crude oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of crude oil based on the average equivalent energy content of the two commodities.
“Btu” British thermal unit, which represents the amount of energy needed to heat one pound of water by one degree Fahrenheit and can be used to describe the energy content of fuels.
“completion” The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil and/or natural gas.
“developed acreage” The number of acres allocated or assignable to productive wells or wells capable of production.
“development well” A well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
“dry hole” Exploratory or development well that does not produce crude oil and/or natural gas in economically producible quantities.
“exploratory well” A well drilled to find crude oil or natural gas in an unproved area, to find a new reservoir in an existing field previously found to be productive of crude oil or natural gas in another reservoir, or to extend a known reservoir beyond the proved area.
“field” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
“formation” A layer of rock which has distinct characteristics that differs from nearby rock.
"gross acres" or "gross wells" Refers to the total acres or wells in which a working interest is owned.
“MBbl” One thousand barrels of crude oil, condensate or natural gas liquids.
“MBoe” One thousand Boe.
“Mcf” One thousand cubic feet of natural gas.
“MMBoe” One million Boe.
“MMBtu” One million British thermal units.
“MMcf” One million cubic feet of natural gas.
net acres” or "net wells" Refers to the sum of the fractional working interests owned in gross acres or gross wells.
"Net crude oil and natural gas sales" Represents total crude oil and natural gas sales less total transportation expenses. Net crude oil and natural gas sales presented herein are non-GAAP measures. See Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures for a discussion and calculation of this measure.
"Net sales price" Represents the average net wellhead sales price received by the Company for its crude oil or natural gas sales after deducting transportation expenses. Amount is calculated by taking revenues less transportation expenses divided by sales volumes for a period, whether for crude oil or natural gas, as applicable. Net sales prices presented herein are non-GAAP measures. See Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures for a discussion and calculation of this measure.
“NYMEX” The New York Mercantile Exchange.

i



“play” A portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential crude oil and natural gas reserves.
“proved reserves” The quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain.
“reservoir” A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.
“royalty interest” Refers to the ownership of a percentage of the resources or revenues produced from a crude oil or natural gas property. A royalty interest owner does not bear exploration, development, or operating expenses associated with drilling and producing a crude oil or natural gas property.
“SCOOP” Refers to the South Central Oklahoma Oil Province, a term used to describe properties located in the Anadarko basin of Oklahoma in which we operate. Our SCOOP acreage extends across portions of Garvin, Grady, Stephens, Carter, McClain and Love counties of Oklahoma and has the potential to contain hydrocarbons from a variety of conventional and unconventional reservoirs overlying and underlying the Woodford formation.
"STACK" Refers to Sooner Trend Anadarko Canadian Kingfisher, a term used to describe a resource play located in the Anadarko Basin of Oklahoma characterized by stacked geologic formations with major targets in the Meramec, Osage and Woodford formations. A significant portion of our STACK acreage is located in over-pressured portions of Blaine, Dewey and Custer counties of Oklahoma.
“undeveloped acreage” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and/or natural gas.
“unit” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
“working interest” The right granted to the lessee of a property to explore for and to produce and own crude oil, natural gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.
 


ii


Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995
This report and information incorporated by reference in this report include “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 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, included in this report are forward-looking statements. 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 may include, but are not limited to, statements about:
our strategy;
our business and financial plans;
our future operations;
our crude oil and natural gas reserves and related development plans;
technology;
future crude oil, natural gas liquids, and natural gas prices and differentials;
the timing and amount of future production of crude oil and natural gas and flaring activities;
the amount, nature and timing of capital expenditures;
estimated revenues, expenses and results of operations;
drilling and completing of wells;
competition;
marketing of crude oil and natural gas;
transportation of crude oil, natural gas liquids, and natural gas to markets;
property exploitation, property acquisitions and dispositions, or joint development opportunities;
costs of exploiting and developing our properties and conducting other operations;
our financial position;
general economic conditions;
credit markets;
our liquidity and access to capital;
the impact of governmental policies, laws and regulations, as well as regulatory and legal proceedings involving us and of scheduled or potential regulatory or legal changes;
our future operating and financial results;
our future commodity or other hedging arrangements; and
the ability and willingness of current or potential lenders, hedging contract counterparties, customers, and working interest owners to fulfill their obligations to us or to enter into transactions with us in the future on terms that are acceptable to us.
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 or will not change over time. The risks and uncertainties that may affect the operations, performance and results of the business and forward-looking statements include, but are not limited to, those risk factors and other cautionary statements described under Part II, Item 1A. Risk Factors and elsewhere in this report, if any, our Annual Report on Form 10-K for the year ended December 31, 2018, registration statements we file from time to time with the Securities and Exchange Commission, and other announcements we make 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 report or our Annual Report on Form 10-K 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 expressly stated above or 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.

iii


PART I. Financial Information
ITEM 1.
Financial Statements
Continental Resources, Inc. and Subsidiaries
Condensed Consolidated Balance Sheets
 
 
March 31, 2019
 
December 31, 2018
In thousands, except par values and share data
 
(Unaudited)
 
 
Assets
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
264,371

 
$
282,749

Receivables:
 
 
 
 
Crude oil and natural gas sales
 
698,641

 
644,107

Affiliated parties
 
74

 
73

Joint interest and other, net
 
395,657

 
368,235

Derivative assets
 
1,975

 
15,612

Inventories
 
103,287

 
88,544

Prepaid expenses and other
 
20,057

 
13,041

Total current assets
 
1,484,062

 
1,412,361

Net property and equipment, based on successful efforts method of accounting
 
14,118,264

 
13,869,800

Operating lease right-of-use assets
 
16,099

 

Other noncurrent assets
 
15,498

 
15,786

Total assets
 
$
15,633,923

 
$
15,297,947

 
 
 
 
 
Liabilities and equity
 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable trade
 
$
755,834

 
$
717,560

Revenues and royalties payable
 
406,832

 
400,567

Payables to affiliated parties
 
259

 
203

Accrued liabilities and other
 
268,507

 
266,819

Derivative liabilities
 
549

 

Current portion of operating lease liabilities
 
11,092

 

Current portion of long-term debt
 
2,378

 
2,360

Total current liabilities
 
1,445,451

 
1,387,509

Long-term debt, net of current portion
 
5,766,647

 
5,765,989

Other noncurrent liabilities:
 
 
 
 
Deferred income tax liabilities, net
 
1,626,426

 
1,574,436

Asset retirement obligations, net of current portion
 
141,172

 
136,986

Operating lease liabilities, net of current portion
 
5,007

 

Other noncurrent liabilities
 
10,917

 
11,166

Total other noncurrent liabilities
 
1,783,522

 
1,722,588

Commitments and contingencies (Note 9)
 
 
 


Equity:
 
 
 
 
Preferred stock, $0.01 par value; 25,000,000 shares authorized; no shares issued and outstanding
 

 

Common stock, $0.01 par value; 1,000,000,000 shares authorized; 376,768,684 shares issued and outstanding at March 31, 2019; 376,021,575 shares issued and outstanding at December 31, 2018
 
3,768

 
3,760

Additional paid-in capital
 
1,426,300

 
1,434,823

Accumulated other comprehensive income
 
531

 
415

Retained earnings
 
4,893,111

 
4,706,135

Total shareholders’ equity attributable to Continental Resources
 
6,323,710

 
6,145,133

Noncontrolling interests
 
314,593

 
276,728

Total equity
 
6,638,303

 
6,421,861

Total liabilities and equity
 
$
15,633,923

 
$
15,297,947


The accompanying notes are an integral part of these condensed consolidated financial statements.
1



Continental Resources, Inc. and Subsidiaries
Unaudited Condensed Consolidated Statements of Comprehensive Income
 
 
 
Three months ended March 31,
In thousands, except per share data
 
2019
 
2018
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

 
 
 
 
 
Comprehensive income:
 
 
 
 
Net income
 
$
186,493

 
$
233,946

Other comprehensive income, net of tax:
 
 
 
 
Foreign currency translation adjustments
 
116

 
2

Total other comprehensive income, net of tax
 
116

 
2

Comprehensive income
 
186,609

 
233,948

Comprehensive loss attributable to noncontrolling interests
 
(483
)
 

Comprehensive income attributable to Continental Resources
 
$
187,092

 
$
233,948



The accompanying notes are an integral part of these condensed consolidated financial statements.
2



Continental Resources, Inc. and Subsidiaries
Condensed Consolidated Statements of Equity
 
Three months ended March 31, 2019
 
Shareholders’ equity attributable to Continental Resources
 
 
 
 
In thousands, except share data
 
Shares
outstanding
 
Common
stock
 
Additional
paid-in
capital
 
Accumulated
other
comprehensive
income
 
Retained
earnings
 
Total shareholders’ equity of Continental Resources
 
Noncontrolling
interests
 
Total equity
Balance at December 31, 2018
 
376,021,575

 
$
3,760

 
$
1,434,823

 
$
415

 
$
4,706,135

 
$
6,145,133

 
$
276,728

 
$
6,421,861

Net income (loss) (unaudited)
 

 

 

 

 
186,976

 
186,976

 
(483
)
 
186,493

Other comprehensive income, net of tax (unaudited)
 

 

 

 
116

 

 
116

 

 
116

Stock-based compensation (unaudited)
 

 

 
12,095

 

 

 
12,095

 

 
12,095

Restricted stock:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Granted (unaudited)
 
1,333,602

 
13

 

 

 

 
13

 

 
13

Repurchased and canceled (unaudited)
 
(439,419
)
 
(4
)
 
(20,618
)
 

 

 
(20,622
)
 

 
(20,622
)
Forfeited (unaudited)
 
(147,074
)
 
(1
)
 

 

 

 
(1
)
 

 
(1
)
Contributions from noncontrolling interests (unaudited)
 

 

 

 

 

 

 
42,204

 
42,204

Distributions to noncontrolling interests (unaudited)
 

 

 

 

 

 

 
(3,856
)
 
(3,856
)
Balance at March 31, 2019 (unaudited)
 
376,768,684

 
$
3,768

 
$
1,426,300

 
$
531

 
$
4,893,111

 
$
6,323,710

 
$
314,593

 
$
6,638,303



Three months ended March 31, 2018
 
Shareholders’ equity attributable to Continental Resources
 
 
 
 
In thousands, except share data
 
Shares
outstanding
 
Common
stock
 
Additional
paid-in
capital
 
Accumulated
other
comprehensive
income
 
Retained
earnings
 
Total shareholders’ equity of Continental Resources
 
Noncontrolling
interests
 
Total equity
Balance at December 31, 2017
 
375,219,769

 
$
3,752

 
$
1,409,326

 
$
307

 
$
3,717,818

 
$
5,131,203

 
$

 
$
5,131,203

Net income (unaudited)
 

 

 

 

 
233,946

 
233,946

 

 
233,946

Other comprehensive income, net of tax (unaudited)
 

 

 

 
2

 

 
2

 

 
2

Stock-based compensation (unaudited)
 

 

 
10,905

 

 

 
10,905

 

 
10,905

Restricted stock:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Granted (unaudited)
 
1,180,032

 
12

 

 

 

 
12

 

 
12

Repurchased and canceled (unaudited)
 
(276,108
)
 
(3
)
 
(14,843
)
 

 

 
(14,846
)
 

 
(14,846
)
Forfeited (unaudited)
 
(66,489
)
 
(1
)
 

 

 

 
(1
)
 

 
(1
)
Balance at March 31, 2018 (unaudited)
 
376,057,204

 
$
3,760

 
$
1,405,388

 
$
309

 
$
3,951,764

 
$
5,361,221

 
$

 
$
5,361,221



The accompanying notes are an integral part of these condensed consolidated financial statements.
3



Continental Resources, Inc. and Subsidiaries
Unaudited Condensed Consolidated Statements of Cash Flows
 
 
Three months ended March 31,
In thousands
 
2019
 
2018
Cash flows from operating activities
 
 
Net income
 
$
186,493

 
$
233,946

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
Depreciation, depletion, amortization and accretion
 
496,561

 
455,559

Property impairments
 
25,316

 
33,784

Non-cash (gain) loss on derivatives, net
 
14,186

 
(5,978
)
Stock-based compensation
 
12,107

 
10,916

Provision for deferred income taxes
 
51,990

 
71,536

Gain on sale of assets, net
 
(252
)
 
(41
)
Other, net
 
3,683

 
3,398

Changes in assets and liabilities:
 
 
 
 
Accounts receivable
 
(78,027
)
 
38,268

Inventories
 
(14,742
)
 
(9,763
)
Other current assets
 
(5,786
)
 
(6,343
)
Accounts payable trade
 
24,341

 
48,307

Revenues and royalties payable
 
6,282

 
18,541

Accrued liabilities and other
 
(563
)
 
(5,848
)
Other noncurrent assets and liabilities
 
(81
)
 
(91
)
Net cash provided by operating activities
 
721,508

 
886,191

 
 
 
 
 
Cash flows from investing activities
 
 
 
 
Exploration and development
 
(732,770
)
 
(618,200
)
Purchase of producing crude oil and natural gas properties
 
(15,849
)
 
(2,647
)
Purchase of other property and equipment
 
(4,951
)
 
(7,421
)
Proceeds from sale of assets
 
499

 
57

Net cash used in investing activities
 
(753,071
)
 
(628,211
)
 
 
 
 
 
Cash flows from financing activities
 
 
 
 
Credit facility borrowings
 
100,000

 
370,000

Repayment of credit facility
 
(100,000
)
 
(558,000
)
Repayment of other debt
 
(576
)
 
(566
)
Debt issuance costs
 

 
(312
)
Contributions from noncontrolling interests
 
38,242

 

Distributions to noncontrolling interests
 
(3,874
)
 

Repurchase of restricted stock for tax withholdings
 
(20,622
)
 
(14,846
)
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


The accompanying notes are an integral part of these condensed consolidated financial statements.
4


Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
Note 1. Organization and Nature of Business
Continental Resources, Inc. (the “Company”) was formed in 1967 and is incorporated under the laws of the State of Oklahoma. The Company’s principal business is crude oil and natural gas exploration, development and production with properties primarily located in the North, South, and East regions of the United States. Additionally, the Company pursues the acquisition and management of perpetually owned minerals located in certain of its key operating areas. The North region consists of properties north of Kansas and west of the Mississippi River and includes North Dakota Bakken, Montana Bakken, and the Red River units. The South region includes all properties south of Nebraska and west of the Mississippi River including various plays in the SCOOP and STACK areas of Oklahoma. The East region is primarily comprised of undeveloped leasehold acreage east of the Mississippi River with no significant drilling or production operations.
A majority of the Company’s operations are located in the North region, with that region comprising 63% of the Company’s crude oil and natural gas production and 75% of its crude oil and natural gas revenues for the three months ended March 31, 2019. The Company's principal producing properties in the North region are located in the Bakken field of North Dakota and Montana. The Company's operations in the South region continue to expand with its increased activity in the SCOOP and STACK plays and that region comprised 37% of the Company's crude oil and natural gas production and 25% of its crude oil and natural gas revenues for the three months ended March 31, 2019.
For the three months ended March 31, 2019, crude oil accounted for 58% of the Company’s total production and 82% of its crude oil and natural gas revenues.    
Note 2. Basis of Presentation and Significant Accounting Policies
Basis of presentation
The condensed consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries, and entities in which the Company has a controlling financial interest. Intercompany accounts and transactions have been eliminated upon consolidation. Noncontrolling interests reflected herein represent third party ownership in the net assets of consolidated subsidiaries. The portions of consolidated net income and equity attributable to the noncontrolling interests are presented separately in the Company’s financial statements.
This report has been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”) applicable to interim financial information. Because this is an interim period filing presented using a condensed format, it does not include all disclosures required by accounting principles generally accepted in the United States (“U.S. GAAP”), although the Company believes the disclosures are adequate to make the information not misleading. You should read this Quarterly Report on Form 10-Q (“Form 10-Q”) together with the Company’s Annual Report on Form 10-K for the year ended December 31, 2018 (“2018 Form 10-K”), which includes a summary of the Company’s significant accounting policies and other disclosures.
The condensed consolidated financial statements as of March 31, 2019 and for the three month periods ended March 31, 2019 and 2018 are unaudited. The condensed consolidated balance sheet as of December 31, 2018 was derived from the audited balance sheet included in the 2018 Form 10-K. The Company has evaluated events or transactions through the date this report on Form 10-Q was filed with the SEC in conjunction with its preparation of these condensed consolidated financial statements.
The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure and estimation of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Actual results may differ from those estimates. The most significant estimates and assumptions impacting reported results are estimates of the Company’s crude oil and natural gas reserves, which are used to compute depreciation, depletion, amortization and impairment of proved crude oil and natural gas properties. In the opinion of management, all adjustments (consisting only of normal recurring adjustments) necessary for a fair presentation in accordance with U.S. GAAP have been included in these unaudited condensed consolidated financial statements. The results of operations for any interim period are not necessarily indicative of the results of operations that may be expected for any other interim period or for an entire year.
Earnings per share
Basic net income per share is computed by dividing net income attributable to the Company by the weighted-average number of shares outstanding for the period. In periods where the Company has net income, diluted earnings per share reflects the potential dilution of non-vested restricted stock awards, which are calculated using the treasury stock method. The following

5

Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

table presents the calculation of basic and diluted weighted average shares outstanding and net income per share attributable to the Company for the three months ended March 31, 2019 and 2018.
 
 
Three months ended March 31,
In thousands, except per share data
 
2019
 
2018
Net income attributable to Continental Resources (numerator)
 
$
186,976

 
$
233,946

Weighted average shares (denominator):
 
 
 
 
Weighted average shares - basic
 
372,563

 
371,543

Non-vested restricted stock
 
1,911

 
2,638

Weighted average shares - diluted
 
374,474

 
374,181

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

 
$
0.63

Diluted
 
$
0.50

 
$
0.63

Inventories
Inventory is comprised of crude oil held in storage or as line fill in pipelines, pipeline imbalances, and tubular goods and equipment to be used in the Company's exploration and development activities. Crude oil inventories are valued at the lower of cost or net realizable value primarily using the first-in, first-out inventory method. Tubular goods and equipment are valued primarily using a weighted average cost method applied to specific classes of inventory items.
The components of inventory as of March 31, 2019 and December 31, 2018 consisted of the following:
In thousands
 
March 31, 2019
 
December 31, 2018
Tubular goods and equipment
 
$
14,794

 
$
14,623

Crude oil
 
88,493

 
73,921

Total
 
$
103,287

 
$
88,544

Adoption of new accounting pronouncement
On January 1, 2019 the Company adopted Accounting Standards Update ("ASU") 2016-02, Leases (Topic 842). See Note 8. Leases for discussion of the adoption impact and the applicable disclosures required by the new guidance.
New accounting pronouncement not yet adopted
In June 2016 the Financial Accounting Standards Board ("FASB") issued ASU 2016-13, Financial InstrumentsCredit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. This standard changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. The standard is effective for interim and annual periods beginning after December 15, 2019 and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Company continues to evaluate the new standard and is unable to estimate its financial statement impact at this time; however, the impact is not expected to be material. Historically, the Company's credit losses on crude oil and natural gas sales receivables and joint interest receivables have been immaterial.

6

Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

Note 3. Supplemental Cash Flow Information
The following table discloses supplemental cash flow information about cash paid for interest and income tax payments and refunds. Also disclosed is information about investing activities that affects recognized assets and liabilities but does not result in cash receipts or payments. 
 
 
Three months ended March 31,
In thousands
 
2019
 
2018
Supplemental cash flow information:
 
 
 
 
Cash paid for interest
 
$
61,964

 
$
52,251

Cash paid for income taxes
 
9

 

Cash received for income tax refunds
 
4

 
5

Non-cash investing activities:
 
 
 
 
Asset retirement obligation additions and revisions, net
 
2,570

 
1,609


As of March 31, 2019 and December 31, 2018, the Company had $329.6 million and $317.5 million, respectively, of accrued capital expenditures included in “Net property and equipment” and “Accounts payable trade” in the condensed consolidated balance sheets.
As of March 31, 2019 and December 31, 2018, the Company had $13.2 million and $9.3 million, respectively, of accrued contributions from noncontrolling interests included in "ReceivablesJoint interest and other, net" and "EquityNoncontrolling interests" in the condensed consolidated balance sheets.
As of March 31, 2019 and December 31, 2018, the Company had $1.3 million and $1.3 million, respectively, of accrued distributions to noncontrolling interests included in "Revenues and royalties payable" and "EquityNoncontrolling interests" in the condensed consolidated balance sheets.
On January 1, 2019 the Company adopted ASU 2016-02 which resulted in the non-cash recognition of offsetting right-of-use assets and lease liabilities totaling approximately $19 million. See Note 8. Leases for additional information.
Note 4. Revenues
Below is a discussion of the nature, timing, and presentation of revenues arising from the Company's major revenue-generating arrangements.
Operated crude oil revenues – The Company pays third parties to transport the majority of its operated crude oil production from lease locations to downstream market centers, at which time the Company's customers take title and custody of the product in exchange for prices based on the particular market where the product was delivered. Operated crude oil revenues are recognized during the month in which control transfers to the customer and it is probable the Company will collect the consideration it is entitled to receive. Crude oil sales proceeds from operated properties are generally received by the Company within one month after the month in which a sale has occurred. Operated crude oil revenues are presented separately from transportation expenses as the Company controls the operated production prior to its transfer to customers. Transportation expenses associated with the Company's operated crude oil production totaled $41.6 million and $40.4 million for the three months ended March 31, 2019 and 2018, respectively.
Operated natural gas revenues – The Company sells the majority of its operated natural gas production to midstream customers at its lease locations based on market prices in the field where the sales occur. Under these arrangements, the midstream customers obtain control of the unprocessed gas stream at the lease location and the Company's revenues from each sale are determined using contractually agreed pricing formulas which contain multiple components, including the volume and Btu content of the natural gas sold, the midstream customer's proceeds from the sale of residue gas and natural gas liquids ("NGLs") at secondary downstream markets, and contractual pricing adjustments reflecting the midstream customer's estimated recoupment of its investment over time. Such revenues are recognized net of pricing adjustments applied by the midstream customer during the month in which control transfers to the customer at the delivery point and it is probable the Company will collect the consideration it is entitled to receive. Natural gas sales proceeds from operated properties are generally received by the Company within one month after the month in which a sale has occurred.
Under certain arrangements, the Company has the right to take a volume of processed residue gas and/or NGLs in-kind at the tailgate of the midstream customer's processing plant in lieu of a monetary settlement for the sale of the Company's operated natural gas production. The Company currently takes certain processed residue gas volumes in kind in lieu of monetary

7

Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

settlement, but does not take NGL volumes. When the Company elects to take volumes in kind, it pays third parties to transport the processed products it took in-kind to downstream delivery points, where it then sells to customers at prices applicable to those downstream markets. In such situations, operated revenues are recognized during the month in which control transfers to the customer at the delivery point and it is probable the Company will collect the consideration it is entitled to receive. Operated sales proceeds are generally received by the Company within one month after the month in which a sale has occurred. In these scenarios, the Company's revenues include the pricing adjustments applied by the midstream processing entity according to the applicable contractual pricing formula, but exclude the transportation expenses the Company incurs to transport the processed products to downstream customers. Transportation expenses associated with these arrangements totaled $7.5 million and $8.9 million for the three months ended March 31, 2019 and 2018, respectively, comprised entirely of costs to transport processed residue gas.
Non-operated crude oil and natural gas revenues – The Company's proportionate share of production from non-operated properties is generally marketed at the discretion of the operators. For non-operated properties, the Company receives a net payment from the operator representing its proportionate 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 to be received by the Company during the month in which production occurs and it is probable the Company will collect the consideration it is entitled to receive. Proceeds are generally received by the Company within two to three months after the month in which production occurs.
Revenues from derivative instruments – See Note 5. Derivative Instruments for discussion of the Company's accounting for its derivative instruments.
Revenues from service operations – Revenues from the Company's crude oil and natural gas service operations consist primarily of revenues associated with water gathering, recycling, and disposal activities and the treatment and sale of crude oil reclaimed from waste products. Revenues associated with such activities, which are derived using market-based rates or rates commensurate with industry guidelines, are recognized during the month in which services are performed, the Company has an unconditional right to receive payment, and collectability is probable. Payment is generally received by the Company within one month after the month in which services are provided.
Disaggregation of crude oil and natural gas revenues
The following table presents the disaggregation of the Company's crude oil and natural gas revenues for the three months ended March 31, 2019 and 2018.
 
 
Three months ended March 31, 2019
 
Three months ended March 31, 2018
In thousands
 
North Region
 
South Region
 
Total
 
North Region
 
South Region
 
Total
Crude oil revenues:
 
 
 
 
 
 
 
 
 
 
 
 
Operated properties
 
$
585,605

 
$
136,547

 
$
722,152

 
$
569,211

 
$
138,453

 
$
707,664

Non-operated properties
 
178,728

 
10,238

 
188,966

 
182,887

 
15,730

 
198,617

Total crude oil revenues
 
764,333

 
146,785

 
911,118

 
752,098

 
154,183

 
906,281

Natural gas revenues:
 
 
 
 
 
 
 
 
 
 
 
 
Operated properties
 
51,461

 
124,698

 
176,159

 
51,820

 
127,254

 
179,074

Non-operated properties
 
10,866

 
11,441

 
22,307

 
13,680

 
14,817

 
28,497

Total natural gas revenues
 
62,327

 
136,139

 
198,466

 
65,500

 
142,071

 
207,571

Crude oil and natural gas sales
 
$
826,660

 
$
282,924

 
$
1,109,584

 
$
817,598

 
$
296,254

 
$
1,113,852

 
 
 
 
 
 

 
 
 
 
 
 
Timing of revenue recognition
 
 
 
 
 
 
 
 
 
 
 
 
Goods transferred at a point in time
 
$
826,660

 
$
282,924

 
$
1,109,584

 
$
817,598

 
$
296,254

 
$
1,113,852

Goods transferred over time
 

 

 

 

 

 

 
 
$
826,660

 
$
282,924

 
$
1,109,584

 
$
817,598

 
$
296,254

 
$
1,113,852

Performance obligations
The Company satisfies the performance obligations under its crude oil and natural gas sales contracts upon delivery of its production and related transfer of control to customers. Upon delivery of production, the Company has a right to receive consideration from its customers in amounts determined by the sales contracts.

8

Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

All of the Company's outstanding crude oil sales contracts at March 31, 2019 are short-term in nature with contract terms of less than one year. For such contracts, the Company has utilized the practical expedient in Accounting Standards Codification ("ASC") 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations, if any, if the performance obligation is part of a contract that has an original expected duration of one year or less.
The majority of the Company's operated natural gas production is sold at lease locations to midstream customers under multi-year term contracts. For such contracts having a term greater than one year, the Company has utilized the practical expedient in ASC 606-10-50-14A which indicates an entity is not required to disclose the transaction price allocated to remaining performance obligations, if any, if variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under the Company's sales contracts, whether for crude oil or natural gas, each unit of production delivered to a customer represents a separate performance obligation; therefore, future volumes to be delivered are wholly unsatisfied at period-end and disclosure of the transaction price allocated to remaining performance obligations is not applicable.
Contract balances
Under the Company’s crude oil and natural gas sales contracts or activities that give rise to service revenues, the Company recognizes revenue after its performance obligations have been satisfied, at which point the Company has an unconditional right to receive payment. Accordingly, the Company’s commodity sales contracts and service activities generally do not give rise to contract assets or contract liabilities under ASC Topic 606. Instead, the Company's unconditional rights to receive consideration are presented as a receivable within "ReceivablesCrude oil and natural gas sales" or "ReceivablesJoint interest and other, net", as applicable, in its condensed consolidated balance sheets.
Revenues from previously satisfied performance obligations
To record revenues for commodity sales, at the end of each month the Company estimates the amount of production delivered and sold to customers and the prices to be received for such sales. Differences between estimated revenues and actual amounts received for all prior months are recorded in the month payment is received from the customer and are reflected in the financial statements within the caption "Crude oil and natural gas sales". Revenues recognized during the three months ended March 31, 2019 and 2018 related to performance obligations satisfied in prior reporting periods were not material.

Note 5. Derivative Instruments
Natural gas derivatives
From time to time the Company has entered into natural gas swap and collar derivative contracts to economically hedge against the variability in cash flows associated with future sales of natural gas production. The Company recognizes its derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The Company has not designated its derivatives as hedges for accounting purposes and, as a result, marks such derivative instruments to fair value and recognizes the changes in fair value in the unaudited condensed consolidated statements of comprehensive income under the caption “Gain (loss) on natural gas derivatives, net”.
The Company's natural gas derivative contracts are settled based upon reported NYMEX Henry Hub settlement prices. The estimated fair value of derivatives is based upon various factors, including commodity exchange prices, over-the-counter quotations and, in the case of collars, volatility, the risk-free interest rate, and the time to expiration. The calculation of the fair value of collars requires the use of an option-pricing model. See Note 6. Fair Value Measurements.
With respect to a natural gas fixed price swap contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the swap price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. For a natural gas collar contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price. Neither party is required to make a payment to the other party if the settlement price for any settlement period is between the floor price and the ceiling price.

9

Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

At March 31, 2019 the Company had outstanding natural gas derivative contracts as set forth in the table below. The volumes reflected below represent an aggregation of multiple derivative contracts having similar remaining durations expected to be realized ratably over the reflected period. At March 31, 2019 the Company had no outstanding crude oil derivative contracts.
 
 
 
 
Swaps Weighted Average Price
Period and Type of Contract
 
MMBtus
 
April 2019 - December 2019
 
 
 
 
Swaps - Henry Hub
 
158,675,000

 
$
2.80


Natural gas derivative gains and losses
Cash receipts and payments in the following table reflect the gain or loss on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash gains and losses below represent the change in fair value of derivative instruments which continue to be held at period end and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period.
 
 
Three months ended March 31,
In thousands
 
2019
 
2018
Cash received on derivatives:
 
 
 
 
Natural gas fixed price swaps
 
$
7,645

 
$
4,196

Natural gas collars
 
5,417

 

Cash received on derivatives, net
 
13,062

 
4,196

Non-cash gain (loss) on derivatives:
 
 
 
 
Natural gas fixed price swaps
 
(8,704
)
 
5,978

Natural gas collars
 
(5,482
)
 

Non-cash gain (loss) on derivatives, net
 
(14,186
)
 
5,978

Gain (loss) on natural gas derivatives, net
 
$
(1,124
)
 
$
10,174

Balance sheet offsetting of derivative assets and liabilities
The Company’s derivative contracts are recorded at fair value in the condensed consolidated balance sheets under the captions “Derivative assets”, “Noncurrent derivative assets”, “Derivative liabilities”, and “Noncurrent derivative liabilities”, as applicable. Derivative assets and liabilities with the same counterparty that are subject to contractual terms which provide for net settlement are reported on a net basis in the condensed consolidated balance sheets.
The following table presents the gross amounts of recognized natural gas derivative assets and liabilities, as applicable, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the condensed consolidated balance sheets for the periods presented, all at fair value. 
In thousands
 
March 31, 2019
 
December 31, 2018
Commodity derivative assets:
 
 
 
 
Gross amounts of recognized assets
 
$
4,622

 
$
16,789

Gross amounts offset on balance sheet
 
(2,647
)
 
(1,177
)
Net amounts of assets on balance sheet
 
1,975

 
15,612

Commodity derivative liabilities:
 
 
 
 
Gross amounts of recognized liabilities
 
(3,196
)
 
(1,177
)
Gross amounts offset on balance sheet
 
2,647

 
1,177

Net amounts of liabilities on balance sheet
 
$
(549
)
 
$

 

10

Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

The following table reconciles the net amounts disclosed above to the individual financial statement line items in the condensed consolidated balance sheets. 
In thousands
 
March 31, 2019
 
December 31, 2018
Derivative assets
 
$
1,975

 
$
15,612

Noncurrent derivative assets
 

 

Net amounts of assets on balance sheet
 
1,975

 
15,612

Derivative liabilities
 
(549
)
 

Noncurrent derivative liabilities
 

 

Net amounts of liabilities on balance sheet
 
(549
)
 

Total derivative assets, net
 
$
1,426

 
$
15,612


Note 6. Fair Value Measurements
The Company follows a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:
Level 1: Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.
Level 2: Observable market-based inputs or unobservable inputs corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.
Level 3: Unobservable inputs not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.
A financial instrument’s categorization within the hierarchy is based upon the lowest level of input that is significant to the fair value measurement. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the hierarchy. As Level 1 inputs generally provide the most reliable evidence of fair value, the Company uses Level 1 inputs when available. The Company’s policy is to recognize transfers between the hierarchy levels as of the beginning of the reporting period in which the event or change in circumstances caused the transfer.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The Company's derivative instruments are reported at fair value on a recurring basis. In determining the fair values of swap contracts, a discounted cash flow method is used due to the unavailability of relevant comparable market data for the Company’s exact contracts. The discounted cash flow method estimates future cash flows based on quoted market prices for forward commodity prices and a risk-adjusted discount rate. The fair values of swap contracts are calculated mainly using significant observable inputs (Level 2). Calculation of the fair values of collars requires the use of an industry-standard option pricing model that considers various inputs including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. These assumptions are observable in the marketplace or can be corroborated by active markets or broker quotes and are therefore designated as Level 2 within the valuation hierarchy. The Company’s calculation of fair value for each of its derivative positions is compared to the counterparty valuation for reasonableness.

11

Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

The following tables summarize the valuation of financial instruments by pricing levels that were accounted for at fair value on a recurring basis as of March 31, 2019 and December 31, 2018. 
 
 
Fair value measurements at March 31, 2019 using:
 
 
In thousands
 
Level 1
 
Level 2
 
Level 3
 
Total
Derivative assets:
 
 
 
 
 
 
 
 
Swaps
 
$

 
$
1,426

 
$

 
$
1,426

Total
 
$

 
$
1,426

 
$

 
$
1,426

 
 
 
 
 
 
 
 
 
 
 
Fair value measurements at December 31, 2018 using:
 
 
In thousands
 
Level 1
 
Level 2
 
Level 3
 
Total
Derivative assets:
 
 
 
 
 
 
 
 
Swaps
 
$

 
$
10,130

 
$

 
$
10,130

Collars
 

 
5,482

 

 
5,482

Total
 
$

 
$
15,612

 
$

 
$
15,612

Assets Measured at Fair Value on a Nonrecurring Basis
Certain assets are reported at fair value on a nonrecurring basis in the condensed consolidated financial statements. The following methods and assumptions were used to estimate the fair values for those assets.
Asset impairments – Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter. The estimated future cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value. Risk-adjusted probable and possible reserves may be taken into consideration when determining estimated future net cash flows and fair value when such reserves exist and are economically recoverable. Due to the unavailability of relevant comparable market data, a discounted cash flow method is used to determine the fair value of proved properties. The discounted cash flow method estimates future cash flows based on the Company’s estimates of future crude oil and natural gas production, commodity prices based on commodity futures price strips adjusted for differentials, operating costs, and a risk-adjusted discount rate. The fair value of proved crude oil and natural gas properties is calculated using significant unobservable inputs (Level 3). The following table sets forth quantitative information about the significant unobservable inputs used by the Company at March 31, 2019 to calculate the fair value of proved crude oil and natural gas properties using a discounted cash flow method. 
Unobservable Input
  
Assumption
Future production
  
Future production estimates for each property
Forward commodity prices
  
Forward NYMEX strip prices through 2023 (adjusted for differentials), escalating 3% per year thereafter
Operating costs
  
Estimated costs for the current year, escalating 3% per year thereafter
Productive life of properties
  
Up to 50 years
Discount rate
  
10%
Unobservable inputs to the fair value assessment are reviewed quarterly and are revised as warranted based on a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Fair value measurements of proved properties are reviewed and approved by certain members of the Company’s management.
For the three months ended March 31, 2019 and 2018, estimated future net cash flows were determined to be in excess of cost basis, therefore no impairment was recorded for the Company’s proved crude oil and natural gas properties for those periods.
Certain unproved crude oil and natural gas properties were impaired during the three months ended March 31, 2019 and 2018, reflecting recurring amortization of undeveloped leasehold costs on properties the Company expects will not be transferred to proved properties over the lives of the leases based on drilling plans, experience of successful drilling, and the average holding period.

12

Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

The following table sets forth the non-cash impairments of both proved and unproved properties for the indicated periods. Proved and unproved property impairments are recorded under the caption “Property impairments” in the unaudited condensed consolidated statements of comprehensive income.
 
 
Three months ended March 31,
In thousands
 
2019
 
2018
Proved property impairments
 
$

 
$

Unproved property impairments
 
25,316

 
33,784

Total
 
$
25,316

 
$
33,784

Financial Instruments Not Recorded at Fair Value
The following table sets forth the estimated fair values of financial instruments that are not recorded at fair value in the condensed consolidated financial statements. 
 
 
March 31, 2019
 
December 31, 2018
In thousands
 
Carrying
Amount
 
Estimated Fair Value
 
Carrying
Amount
 
Estimated Fair Value
Debt:
 
 
Credit facility
 
$

 
$

 
$

 
$

Note payable
 
7,119

 
7,100

 
7,700

 
7,700

5% Senior Notes due 2022
 
1,598,496

 
1,611,700

 
1,598,404

 
1,590,900

4.5% Senior Notes due 2023
 
1,489,536

 
1,550,900

 
1,488,960

 
1,476,300

3.8% Senior Notes due 2024
 
993,436

 
1,007,500

 
993,151

 
947,200

4.375% Senior Notes due 2028
 
988,879

 
1,027,800

 
988,617

 
942,800

4.9% Senior Notes due 2044
 
691,559

 
710,400

 
691,517

 
618,800

Total debt
 
$
5,769,025

 
$
5,915,400

 
$
5,768,349

 
$
5,583,700

The fair value of the note payable is determined using a discounted cash flow approach based on the interest rate and payment terms of the note payable and an assumed discount rate. The fair value of the note payable is significantly influenced by the discount rate assumption, which is derived by the Company and is unobservable. Accordingly, the fair value of the note payable is classified as Level 3 in the fair value hierarchy.
The fair values of the 5% Senior Notes due 2022 (“2022 Notes”), the 4.5% Senior Notes due 2023 (“2023 Notes”), the 3.8% Senior Notes due 2024 (“2024 Notes”), the 4.375% Senior Notes due 2028 (“2028 Notes”), and the 4.9% Senior Notes due 2044 (“2044 Notes”) are based on quoted market prices and, accordingly, are classified as Level 1 in the fair value hierarchy.
The carrying values of all classes of cash and cash equivalents, trade receivables, and trade payables are considered to be representative of their respective fair values due to the short term maturities of those instruments.

13

Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

Note 7. Long-Term Debt
Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $38.1 million and $39.4 million at March 31, 2019 and December 31, 2018, respectively, consists of the following.
In thousands
 
March 31, 2019
 
December 31, 2018
Credit facility
 
$

 
$

Note payable
 
7,119

 
7,700

5% Senior Notes due 2022
 
1,598,496

 
1,598,404

4.5% Senior Notes due 2023
 
1,489,536

 
1,488,960

3.8% Senior Notes due 2024
 
993,436

 
993,151

4.375% Senior Notes due 2028
 
988,879

 
988,617

4.9% Senior Notes due 2044
 
691,559

 
691,517

Total debt
 
$
5,769,025

 
$
5,768,349

Less: Current portion of long-term debt
 
2,378

 
2,360

Long-term debt, net of current portion
 
$
5,766,647

 
$
5,765,989

Credit Facility
The Company has an unsecured credit facility, maturing on April 9, 2023, with aggregate lender commitments totaling $1.5 billion. The Company had no outstanding borrowings on its credit facility at March 31, 2019 and December 31, 2018.
Borrowings under the credit facility, if any, bear interest at market-based interest rates plus a margin based on the terms of the borrowing and the credit ratings assigned to the Company's senior, unsecured, long-term indebtedness. The Company incurs commitment fees based on currently assigned credit ratings of 0.20% per annum on the daily average amount of unused borrowing availability.
The credit facility contains certain restrictive covenants including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. This ratio represents the ratio of net debt (calculated as total face value of debt plus outstanding letters of credit less cash and cash equivalents) divided by the sum of net debt plus total shareholders' equity plus, to the extent resulting in a reduction of total shareholders’ equity, the amount of any non-cash impairment charges incurred, net of any tax effect, after June 30, 2014. The Company was in compliance with the credit facility covenants at March 31, 2019.
Senior Notes
The following table summarizes the face values, maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding senior note obligations at March 31, 2019. 
 
 
2022 Notes (1)
 
2023 Notes
 
2024 Notes
 
2028 Notes
 
2044 Notes
Face value (in thousands)
 
$1,600,000
 
$1,500,000
 
$1,000,000
 
$1,000,000
 
$700,000
Maturity date
  
Sep 15, 2022
 
April 15, 2023
 
June 1, 2024
 
January 15, 2028
 
June 1, 2044
Interest payment dates
  
March 15, Sep 15
 
April 15, Oct 15
 
June 1, Dec 1
 
Jan 15, July 15
 
June 1, Dec 1
Make-whole redemption period (2)
  
 
Jan 15, 2023
 
Mar 1, 2024
 
Oct 15, 2027
 
Dec 1, 2043
(1)
The Company has the option to redeem all or a portion of its remaining 2022 Notes at the decreasing redemption prices specified in the indenture related to the 2022 Notes plus any accrued and unpaid interest to the date of redemption.
(2)
At any time prior to the indicated dates, the Company has the option to redeem all or a portion of its senior notes of the applicable series at the “make-whole” redemption amounts specified in the respective senior note indentures plus any accrued and unpaid interest to the date of redemption. On or after the indicated dates, the Company may redeem all or a portion of its senior notes at a redemption amount equal to 100% of the principal amount of the senior notes being redeemed plus any accrued and unpaid interest to the date of redemption.
The Company’s senior notes are not subject to any mandatory redemption or sinking fund requirements.
The indentures governing the Company’s senior notes contain covenants that, among other things, limit the Company’s ability to create liens securing certain indebtedness, enter into certain sale-leaseback transactions, or consolidate, merge or transfer

14

Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

certain assets. The senior note covenants are subject to a number of important exceptions and qualifications. The Company was in compliance with these covenants at March 31, 2019.
Three of the Company’s wholly-owned subsidiaries, Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC, and The Mineral Resources Company, the value of whose assets, equity, and results of operations are minor, fully and unconditionally guarantee the senior notes on a joint and several basis. The Company’s other subsidiaries, the value of whose assets, equity, and results of operations attributable to the Company are minor, do not guarantee the senior notes.
Note Payable
In February 2012, 20 Broadway Associates LLC, a wholly-owned subsidiary of the Company, borrowed $22 million under a 10-year amortizing term loan secured by the Company’s corporate office building in Oklahoma City, Oklahoma. The loan bears interest at a fixed rate of 3.14% per annum. Principal and interest are payable monthly through the loan’s maturity date of February 26, 2022. Accordingly, approximately $2.4 million is reflected as a current liability under the caption “Current portion of long-term debt” in the condensed consolidated balance sheets as of March 31, 2019.
Note 8. Leases
In February 2016 the FASB issued ASU 2016-02, Leases (Topic 842), which requires companies to recognize a right-of-use asset and related liability on the balance sheet for the rights and obligations arising from leases with durations greater than twelve months. The standard became effective for interim and annual reporting periods beginning after December 15, 2018. The Company adopted the new standard on January 1, 2019 on a prospective basis using the simplified transition method prescribed by ASU 2018-11, Leases (Topic 842): Targeted Improvements. Offsetting right-of-use assets and lease liabilities recognized by the Company on the January 1, 2019 adoption date totaled approximately $19 million, representing minimum payment obligations associated with drilling rig commitments, surface use agreements, equipment, and other leases with contractual durations in excess of one year. No cumulative-effect adjustment to retained earnings was recognized upon adoption of the new standard.
The Company has elected to account for lease and non-lease components in its contracts as a single lease component for all asset classes. Additionally, the Company has elected not to apply the recognition requirements of ASC Topic 842 to leases with durations of twelve months or less and has elected to use hindsight in determining the lease term for all leases. The Company's leasing activities as a lessor are negligible.
Presented below are disclosures required by the new lease standard. The amounts disclosed herein primarily represent costs associated with properties operated by the Company that are presented on a gross basis and do not reflect the Company's net proportionate share of such amounts. A portion of these costs have been or will be billed to other working interest owners. Once paid, the Company's share of these costs are included in property and equipment, production expenses, or general and administrative expenses, as applicable.
The Company’s lease liabilities recognized on the balance sheet as a lessee totaled $16.1 million as of March 31, 2019 at discounted present value, which is comprised of the asset classes reflected in the table below. All leases recognized on the Company's balance sheet are classified as operating leases.
In thousands
 
Amount
Drilling rig commitments
 
$
10,543

Surface use agreements
 
3,791

Field equipment
 
1,384

Other
 
381

Total
 
$
16,099

Drilling rig commitments reflected above represent minimum payment obligations expected to be incurred through February 2020 on enforceable commitments with durations in excess of one year beyond January 1, 2019.

15

Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

Minimum future commitments by year for the Company's operating leases as of March 31, 2019 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the balance sheet.
In thousands
 
Amount
Remainder of 2019
 
$
9,819

2020
 
2,300

2021
 
706

2022
 
691

2023
 
624

Thereafter
 
4,872

Total operating lease liabilities, at undiscounted value
 
$
19,012

Less: Imputed interest
 
(2,913
)
Total operating lease liabilities, at discounted present value
 
$
16,099

Less: Current portion of operating lease liabilities
 
(11,092
)
Operating lease liabilities, net of current portion
 
$
5,007

Additional information for the Company's operating leases is presented below. Lease costs are reflected at gross amounts and primarily represent costs incurred for drilling rigs, most of which are short term contracts that are not recognized as right-of-use assets and lease liabilities on the balance sheet. Variable lease costs primarily represent differences between minimum payment obligations and actual operating day-rate charges incurred by the Company for its long term drilling rig contracts.
In thousands, except weighted average data
 
Three months ended March 31, 2019
Lease costs:
 
 
Operating lease costs
 
$
3,273

Variable lease costs
 
3,122

Short-term lease costs
 
55,161

Total lease costs
 
$
61,556

 
 
 
Other information:
 


Operating cash flows from operating leases included in lease liabilities
 
$
199

Weighted average remaining lease term
 
5.9 years

Weighted average discount rate
 
4.7
%
Note 9. Commitments and Contingencies
Included below is a discussion of certain future commitments and contingencies of the Company as of March 31, 2019.
Drilling rig commitments – As of March 31, 2019, the Company has drilling rig contracts with various terms extending to February 2020 to ensure rig availability in its key operating areas. Future operating day-rate commitments as of March 31, 2019 total approximately $83 million, of which $82 million is expected to be incurred in the remainder of 2019 and $1 million in 2020. A portion of these future costs will be borne by other interest owners. Such future commitments include minimum payment obligations to be incurred through February 2020 with a discounted present value totaling $10.5 million that are required to be recognized on the Company's balance sheet at March 31, 2019 in accordance with ASC Topic 842 as discussed in Note 8. Leases.
Other lease commitments – The Company has various other lease commitments primarily associated with surface use agreements and field equipment. See Note 8. Leases for additional information.
Transportation and processing commitments – The Company has entered into transportation and processing commitments to guarantee capacity on crude oil and natural gas pipelines and natural gas processing facilities. The commitments, which have varying terms extending as far as 2028, require the Company to pay per-unit transportation or processing charges regardless of

16

Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

the amount of capacity used. Future commitments remaining as of March 31, 2019 under the arrangements amount to approximately $1.74 billion, of which $182 million is expected to be incurred in the remainder of 2019, $269 million in 2020, $250 million in 2021, $245 million in 2022, $245 million in 2023, and $551 million thereafter. A portion of these future costs will be borne by other interest owners. The Company is not committed under the above contracts to deliver fixed and determinable quantities of crude oil or natural gas in the future. These commitments do not qualify as leases under ASC Topic 842 and are not recognized on the Company's balance sheet.
Litigation – In November 2010, a putative class action was filed in the District Court of Blaine County, Oklahoma by Billy J. Strack and Daniela A. Renner as trustees of certain named trusts and on behalf of other similarly situated parties against the Company. The Petition, as amended, alleged the Company improperly deducted post-production costs from royalties paid to plaintiffs and other royalty interest owners from crude oil and natural gas wells located in Oklahoma. The plaintiffs alleged a number of claims, including breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and sought recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the proposed class. The Company denied all allegations and denied that the case was properly brought as a class action. Due to the uncertainty of and burdens of litigation, in February 2018 the Company reached a settlement in connection with this matter, which was subsequently approved by the District Court of Garfield County, Oklahoma in June 2018. Under the settlement, the Company initially expected to make payments and incur costs associated with the settlement of approximately $59.6 million and accrued a loss for such amount at December 31, 2017. In the third quarter of 2018, the Company made payments totaling $45.8 million to satisfy the majority of its obligations under the settlement. The Company's remaining loss accrual for this matter totals $21.1 million at March 31, 2019, representing additional settlement obligations expected to be satisfied in the third quarter of 2019. The accrual for this matter is included in “Accrued liabilities and other” on the condensed consolidated balance sheets.
The Company is involved in various other legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, regulatory compliance matters, disputes with tax authorities and other matters. While the outcome of these legal matters cannot be predicted with certainty, the Company does not expect them to have a material effect on its financial condition, results of operations or cash flows. In addition to the accrued loss on the matter described above, as of March 31, 2019 and December 31, 2018 the Company had recorded a liability in the condensed consolidated balance sheets under the caption “Other noncurrent liabilities” of $4.5 million and $4.7 million, respectively, for various matters, none of which are believed to be individually significant.
Environmental risk – Due to the nature of the crude oil and natural gas business, the Company is exposed to possible environmental risks. The Company is not aware of any material environmental issues or claims.
Note 10. Stock-Based Compensation
The Company has granted restricted stock to employees and directors pursuant to the Continental Resources, Inc. 2013 Long-Term Incentive Plan ("2013 Plan") as discussed below. The Company’s associated compensation expense, which is included in the caption “General and administrative expenses” in the unaudited condensed consolidated statements of comprehensive income, was $12.1 million and $10.9 million for the three months ended March 31, 2019 and 2018, respectively.
In May 2013, the Company adopted the 2013 Plan and reserved 19,680,072 shares of common stock that may be issued pursuant to the plan. As of March 31, 2019, the Company had 12,989,625 shares of common stock available for long-term incentive awards to employees and directors under the 2013 Plan.
Restricted stock is awarded in the name of the recipient and constitutes issued and outstanding shares of the Company’s common stock for all corporate purposes during the period of restriction and, except as otherwise provided under the 2013 Plan or agreement relevant to a given award, includes the right to vote the restricted stock and to receive dividends, subject to forfeiture. Restricted stock grants generally vest over periods ranging from one to three years.

17

Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

A summary of changes in non-vested restricted shares outstanding for the three months ended March 31, 2019 is presented below. 
 
 
Number of
non-vested
shares
 
Weighted average
grant-date
fair value
Non-vested restricted shares outstanding at December 31, 2018
 
4,022,409

 
$
38.44

Granted
 
1,333,602

 
44.32

Vested
 
(1,566,904
)
 
21.65

Forfeited
 
(147,074
)
 
46.85

Non-vested restricted shares outstanding at March 31, 2019
 
3,642,033

 
$
47.48

The grant date fair value of restricted stock represents the closing market price of the Company’s common stock on the date of grant. Compensation expense for a restricted stock grant is determined at the grant date fair value and is recognized over the vesting period as services are rendered by employees and directors. The Company estimates the number of forfeitures expected to occur in determining the amount of stock-based compensation expense to recognize. There are no post-vesting restrictions related to the Company’s restricted stock. The fair value at the vesting date of restricted stock that vested during the three months ended March 31, 2019 was approximately $74 million. As of March 31, 2019, there was approximately $110 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized over a weighted average period of 1.9 years.
Note 11. Accumulated Other Comprehensive Income
Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in “Accumulated other comprehensive income” within shareholders’ equity attributable to Continental Resources on the condensed consolidated balance sheets and “Other comprehensive income, net of tax” in the unaudited condensed consolidated statements of comprehensive income. The following table summarizes the change in accumulated other comprehensive income for the three months ended March 31, 2019 and 2018:
 
 
Three months ended March 31,
In thousands
 
2019
 
2018
Beginning accumulated other comprehensive income, net of tax
 
$
415

 
$
307

Foreign currency translation adjustments
 
116

 
2

Income taxes (1)
 

 

Other comprehensive income, net of tax
 
116

 
2

Ending accumulated other comprehensive income, net of tax
 
$
531

 
$
309

(1)
A valuation allowance has been recognized against all deferred tax assets associated with losses generated by the Company's Canadian operations, thereby resulting in no income taxes on other comprehensive income.

Note 12. Income Taxes
Income taxes are accounted for using the liability method under which deferred income taxes are recognized for the future tax effects of temporary differences between financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at period-end. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. The Company’s policy is to recognize penalties and interest related to unrecognized tax benefits, if any, in income tax expense. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.

18

Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

The Company's provision for income taxes totaled $52.0 million and $71.5 million for the three months ended March 31, 2019 and 2018, respectively. These amounts differ from the amounts computed by applying the United States statutory federal income tax rate to net income before income taxes. The sources and tax effects of the differences are reflected in the table below:
 
 
Three months ended March 31,
$ in thousands
 
2019
 
Tax rate %
 
2018
 
Tax rate %
Expected income tax provision based on US statutory tax rate
 
$
(50,081
)
 
21.0
%
 
$
(64,151
)
 
21.0
%
State income taxes, net of federal benefit
 
(7,798
)
 
3.3
%
 
(9,164
)
 
3.0
%
Tax benefit from stock-based compensation
 
8,318

 
(3.5
%)
 
1,509

 
(0.5
%)
Other, net
 
(2,429
)
 
1.0
%
 
270

 
(0.1
%)
Provision for income taxes
 
$
(51,990
)
 
21.8
%
 
$
(71,536
)
 
23.4
%


19



ITEM 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with the unaudited condensed consolidated financial statements and notes thereto included elsewhere in this report and our historical consolidated financial statements and notes included in our Form 10-K for the year ended December 31, 2018. Our operating results for the periods discussed below may not be indicative of future performance. The following discussion and analysis includes forward-looking statements and should be read in conjunction with the risk factors described in Part II, Item 1A. Risk Factors included in this report, if any, and in our Form 10-K for the year ended December 31, 2018, along with Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995 at the beginning of this report, for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.
Overview
We are an independent crude oil and natural gas company engaged in the exploration, development and production of crude oil and natural gas. Additionally, we pursue the acquisition and management of perpetually owned minerals located in certain of our key operating areas. We derive the majority of our operating income and cash flows from the sale of crude oil and natural gas and expect this to continue in the future. Our operations are primarily focused on exploration and development activities in the Bakken field of North Dakota and Montana and the SCOOP and STACK areas of Oklahoma. Our common stock trades on the New York Stock Exchange under the symbol “CLR” and our corporate internet website is www.clr.com.
First Quarter 2019 Highlights
Total production for the first quarter of 2019 averaged 332,236 Boe per day, up 3% sequentially from the fourth quarter of 2018 and 16% higher than the first quarter of 2018.
Average daily crude oil production increased 4% over the 2018 fourth quarter and 18% over the 2018 first quarter driven by strong production growth in the Bakken field and Project SpringBoard play in SCOOP.
Bakken average daily crude oil production increased 8% over the 2018 fourth quarter and 22% over the 2018 first quarter.
Crude oil sales price differentials improved significantly from late 2018 levels to $4.77 per barrel for the 2019 first quarter compared to $8.44 per barrel for the 2018 fourth quarter.
Maintained low per-unit production expenses through the winter months at $3.59 per Boe for the 2019 first quarter.
Debt reduction over the past year generated an $8.1 million, or 11%, decrease in interest expense in the 2019 first quarter compared to the 2018 first quarter.
The following table contains financial and operating highlights 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 March 31,
 
 
2019
 
2018
Average daily production:
 

 

Crude oil (Bbl per day)
 
193,921

 
163,837

Natural gas (Mcf per day)
 
829,891

 
741,442

Crude oil equivalents (Boe per day)
 
332,236

 
287,410

Average net sales prices (1):
 

 

Crude oil ($/Bbl)
 
$
50.05

 
$
58.98

Natural gas ($/Mcf)
 
$
2.56

 
$
2.98

Crude oil equivalents ($/Boe)
 
$
35.56

 
$
41.26

Crude oil net sales price discount to NYMEX ($/Bbl)
 
$
(4.77
)
 
$
(3.91
)
Natural gas net sales price discount to NYMEX ($/Mcf)
 
$
(0.60
)
 
$

Production expenses ($/Boe)
 
$
3.59

 
$
3.60

Production taxes (% of net crude oil and natural gas sales)
 
8.2
%
 
7.6
%
Depreciation, depletion, amortization and accretion ($/Boe)
 
$
16.60

 
$
17.61

Total general and administrative expenses ($/Boe)
 
$
1.60

 
$
1.67

 
(1)
See the subsequent section titled Non-GAAP Financial Measures for a discussion and calculation of net sales prices, which are non-GAAP measures.

20



Three months ended March 31, 2019 compared to the three months ended March 31, 2018
Results of Operations
The following table presents selected financial and operating information for the periods presented. 
 
 
Three months ended March 31,
In thousands
 
2019
 
2018
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
 
(819,269
)
 
(760,306
)
Other expenses, net
 
(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

Production volumes:
 
 
 
 
Crude oil (MBbl)
 
17,453

 
14,745

Natural gas (MMcf)
 
74,690

 
66,730

Crude oil equivalents (MBoe)
 
29,901

 
25,867

Sales volumes:
 
 
 
 
Crude oil (MBbl)
 
17,373

 
14,682

Natural gas (MMcf)
 
74,690

 
66,730

Crude oil equivalents (MBoe)
 
29,821

 
25,804

Production
The following table summarizes the changes in our average daily Boe production by major operating area for the periods presented.
Boe production per day
 
1Q 2019
 
1Q 2018
 
% Change from 1Q 2018
 
4Q 2018
 
% Change from 4Q 2018
Bakken
 
199,423

 
161,356

 
24
%
 
183,836

 
8
%
SCOOP
 
67,659

 
62,012

 
9
%
 
67,244

 
1
%
STACK
 
56,513

 
53,361

 
6
%
 
62,947

 
(10
%)
All other
 
8,641

 
10,681

 
(19
%)
 
9,974

 
(13
%)
Total
 
332,236

 
287,410

 
16
%
 
324,001

 
3
%
The following tables reflect our production by product and region for the periods presented. 
 
 
Three months ended March 31,
 
Volume
increase
 
Volume
percent
increase
 
 
2019
 
2018
 
 
 
 
Volume
 
Percent
 
Volume
 
Percent
 
Crude oil (MBbl)
 
17,453

 
58
%
 
14,745

 
57
%
 
2,708

 
18
%
Natural gas (MMcf)
 
74,690

 
42
%
 
66,730

 
43
%
 
7,960

 
12
%
Total (MBoe)
 
29,901

 
100
%
 
25,867

 
100
%
 
4,034

 
16
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three months ended March 31,
 
Volume
increase
 
Volume
percent
increase
 
 
2019
 
2018
 
 
 
 
MBoe
 
Percent
 
MBoe
 
Percent
 
North Region
 
18,711

 
63
%
 
15,400

 
60
%
 
3,311

 
22
%
South Region
 
11,190

 
37
%
 
10,467

 
40
%
 
723

 
7
%
Total
 
29,901

 
100
%
 
25,867

 
100
%
 
4,034

 
16
%

21



The 18% increase in crude oil production for the 2019 first quarter was primarily driven by a 2,519 MBbls, or 22%, increase in Bakken production due to additional wells being completed. Additionally, crude oil production from the SCOOP play increased 545 MBbls, or 37%, from the prior year first quarter due to new well completions in our oil-weighted Project SpringBoard. These increases were partially offset by decreased crude oil production from various other areas due to natural declines in production.
The 12% increase in natural gas production for the 2019 first quarter was driven by a 5,445 MMcf, or 30%, increase in Bakken gas production in conjunction with the aforementioned increase in Bakken crude oil production over the prior year first quarter. Additionally, natural gas production in the STACK play increased 3,250 MMcf, or 14%, due to additional wells being completed. These increases were partially offset by reduced production from various other areas due to natural declines in production.
Revenues
Our revenues consist of sales of crude oil and natural gas, gains and losses resulting from changes in the fair value of our natural gas derivative instruments, and revenues associated with crude oil and natural gas service operations.
Net crude oil and natural gas sales and related net sales prices presented below are non-GAAP measures. See the subsequent section titled Non-GAAP Financial Measures for a discussion and calculation of these measures.
Net crude oil and natural gas sales. Net crude oil and natural gas sales totaled $1.06 billion for the first quarter of 2019, consistent with net sales of $1.06 billion for the 2018 first quarter due to offsetting changes in sales volumes and net sales prices as discussed below.
Total sales volumes for the first quarter of 2019 increased 4,017 MBoe, or 16%, compared to the 2018 first quarter, reflecting an increase in drilling and completion activities over the past year. For the first quarter of 2019, our crude oil sales volumes increased 18% from the comparable 2018 period, while our natural gas sales volumes increased 12%.
Our crude oil net sales prices averaged $50.05 per barrel in the 2019 first quarter, a decrease of 15% compared to $58.98 per barrel for the 2018 first quarter primarily due to lower crude oil market prices. Crude oil market prices decreased significantly in late 2018 to 18-month lows and remained depressed in early 2019, causing our sales prices to be lower than prices realized in the 2018 first quarter. Crude oil prices have steadily improved from early 2019 levels.
The differential between NYMEX West Texas Intermediate calendar month prices and our realized crude oil net sales prices increased to $4.77 per barrel for the 2019 first quarter compared to $3.91 per barrel for the 2018 first quarter, reflecting changes in supply and demand fundamentals in the North region over the past year that created volatility in our Bakken price realizations between periods.
Our 2019 first quarter crude oil price differentials reflect a significant improvement from 2018 fourth quarter differentials, which averaged $8.44 per barrel, due to an increase in pipeline takeaway capacity, reduced Canadian crude oil imports, and reduced refinery maintenance downtime.
Our natural gas net sales prices averaged $2.56 per Mcf for the 2019 first quarter, a decrease of 14% compared to $2.98 per Mcf for the 2018 first quarter. The discount between our net sales prices and NYMEX Henry Hub calendar month prices weakened by $0.60 per Mcf compared to the 2018 first quarter. We sell the majority of our operated natural gas production to midstream customers at lease locations based on market prices in the field where the sales occur. The field markets are impacted by residue gas and natural gas liquids ("NGLs") prices at secondary, downstream markets. NGL prices in 2019 have decreased from 2018 first quarter levels in conjunction with decreased crude oil prices and other factors, resulting in reduced price realizations for our natural gas sales stream relative to benchmark prices.
Derivatives. Changes in natural gas prices during the first quarter of 2019 had an unfavorable impact on the fair value of our natural gas derivatives, which resulted in negative revenue adjustments of $1.1 million in the current period compared to positive revenue adjustments of $10.2 million in the comparable 2018 period.
Operating Costs and Expenses
Production Expenses. Production expenses increased $14.0 million, or 15%, from $93.0 million for the first quarter of 2018 to $107.0 million for the first quarter of 2019 primarily due to an increase in the number of producing wells and related 16% increase in sales volumes. Production expenses on a per-Boe basis averaged $3.59 for the 2019 first quarter, slightly improved from $3.60 per Boe recognized for the 2018 first quarter.

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Production Taxes. Production taxes increased $5.8 million, or 7%, to $86.4 million for the first quarter of 2019 compared to $80.6 million for the first quarter of 2018, despite lower revenues, primarily due to a significant increase in production and revenues generated in North Dakota from increased well completion activities over the past year. North Dakota has higher production tax rates compared to Oklahoma, which caused our production taxes as a percentage of net crude oil and natural gas sales to increase from 7.6% for the first quarter of 2018 to 8.2% for the first quarter of 2019. Additionally, in March 2018 new legislation was enacted in Oklahoma that increased the state's production tax rate, effective July 1, 2018, from 2% to 5% for the first 36 months of production for wells commencing production after July 1, 2015, which also contributed to the increase in our average production tax rate compared to the prior year first quarter.
Depreciation, Depletion, Amortization and Accretion. Total DD&A increased $40.6 million, or 9%, to $495.0 million for the first quarter of 2019 compared to $454.4 million for the first quarter of 2018 due to an increase in total sales volumes, the impact of which was partially offset by a reduction in our DD&A rate per Boe as further discussed below. The following table shows the components of our DD&A on a unit of sales basis for the periods presented. 
 

Three months ended March 31,
$/Boe

2019
 
2018
Crude oil and natural gas
 
$
16.37

 
$
17.35