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 June 30, 2018
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
 ____________________________________
logoa02a10.jpg
 CONTINENTAL RESOURCES, INC.
(Exact name of registrant as specified in its charter)
 ____________________________________
Oklahoma
 
73-0767549
(State or other jurisdiction 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)
 ____________________________________
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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post 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
 
¨  (Do not check if a smaller reporting company)
  
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
376,037,498 shares of our $0.01 par value common stock were outstanding on July 31, 2018.



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 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.
“NYMEX” The New York Mercantile Exchange.
“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

i


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,” “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, 2017, 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
 
 
June 30, 2018
 
December 31, 2017
In thousands, except par values and share data
 
(Unaudited)
 
 
Assets
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
129,989

 
$
43,902

Receivables:
 
 
 
 
Crude oil and natural gas sales
 
671,004

 
671,665

Affiliated parties
 
58

 
63

Joint interest and other, net
 
506,301

 
426,585

Derivative assets
 
203

 
2,603

Inventories
 
115,310

 
97,406

Prepaid expenses and other
 
18,424

 
9,501

Total current assets
 
1,441,289

 
1,251,725

Net property and equipment, based on successful efforts method of accounting
 
13,339,571

 
12,933,789

Other noncurrent assets
 
17,620

 
14,137

Total assets
 
$
14,798,480

 
$
14,199,651

 
 
 
 
 
Liabilities and shareholders’ equity
 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable trade
 
$
811,965

 
$
692,908

Revenues and royalties payable
 
380,651

 
374,831

Payables to affiliated parties
 
237

 
143

Accrued liabilities and other
 
280,199

 
260,074

Derivative liabilities
 
9,065

 
—

Current portion of long-term debt
 
2,322

 
2,286

Total current liabilities
 
1,484,439

 
1,330,242

Long-term debt, net of current portion
 
6,164,221

 
6,351,405

Other noncurrent liabilities:
 
 
 
 
Deferred income tax liabilities, net
 
1,406,326

 
1,259,558

Asset retirement obligations, net of current portion
 
117,924

 
111,794

Other noncurrent liabilities
 
12,082

 
15,449

Total other noncurrent liabilities
 
1,536,332

 
1,386,801

Commitments and contingencies (Note 8)
 
 
 


Shareholders’ 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; 376,030,797 shares issued and outstanding at June 30, 2018; 375,219,769 shares issued and outstanding at December 31, 2017
 
3,760

 
3,752

Additional paid-in capital
 
1,415,175

 
1,409,326

Accumulated other comprehensive income
 
325

 
307

Retained earnings
 
4,194,228

 
3,717,818

Total shareholders’ equity
 
5,613,488

 
5,131,203

Total liabilities and shareholders’ equity
 
$
14,798,480

 
$
14,199,651



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 (Loss)
 
 
 
Three months ended June 30,
 
Six months ended June 30,
In thousands, except per share data
 
2018
 
2017
 
2018
 
2017
Revenues:
 
 
 
 
 
 
 
 
Crude oil and natural gas sales
 
$
1,137,528

 
$
626,548

 
$
2,251,380

 
$
1,260,398

Gain (loss) on natural gas derivatives, net
 
(12,685
)
 
28,022

 
(2,511
)
 
74,880

Crude oil and natural gas service operations
 
12,270

 
6,916

 
29,272

 
11,636

Total revenues
 
1,137,113

 
661,486

 
2,278,141

 
1,346,914

 
 
 
 
 
 
 
 
 
Operating costs and expenses:
 
 
 
 
 
 
 
 
Production expenses
 
90,171

 
82,474

 
183,133

 
155,328

Production taxes
 
83,595

 
41,965

 
164,175

 
83,198

Transportation expenses
 
47,254

 
—

 
96,551

 
—

Exploration expenses
 
303

 
3,204

 
2,023

 
8,202

Crude oil and natural gas service operations
 
7,688

 
4,478

 
12,271

 
7,315

Depreciation, depletion, amortization and accretion
 
447,200

 
395,770

 
901,578

 
777,926

Property impairments
 
29,162

 
123,316

 
62,946

 
174,689

General and administrative expenses
 
47,174

 
39,186

 
90,217

 
86,407

Net (gain) loss on sale of assets and other
 
(6,710
)
 
134

 
(6,751
)
 
5,669

Total operating costs and expenses
 
745,837

 
690,527

 
1,506,143

 
1,298,734

Income (loss) from operations
 
391,276

 
(29,041
)
 
771,998

 
48,180

Other income (expense):
 
 
 
 
 
 
 
 
Interest expense
 
(74,288
)
 
(72,744
)
 
(150,182
)
 
(143,916
)
Other
 
708

 
373

 
1,362

 
815


 
(73,580
)
 
(72,371
)
 
(148,820
)
 
(143,101
)
Income (loss) before income taxes
 
317,696

 
(101,412
)
 
623,178

 
(94,921
)
(Provision) benefit for income taxes
 
(75,232
)
 
37,855

 
(146,768
)
 
31,833

Net income (loss)
 
$
242,464

 
$
(63,557
)
 
$
476,410

 
$
(63,088
)
Basic net income (loss) per share
 
$
0.65

 
$
(0.17
)
 
$
1.28

 
$
(0.17
)
Diluted net income (loss) per share
 
$
0.65

 
$
(0.17
)
 
$
1.27

 
$
(0.17
)
 
 
 
 
 
 
 
 
 
Comprehensive income (loss):
 
 
 
 
 
 
 
 
Net income (loss)
 
$
242,464

 
$
(63,557
)
 
$
476,410

 
$
(63,088
)
Other comprehensive income, net of tax:
 
 
 
 
 
 
 
 
Foreign currency translation adjustments
 
16

 
189

 
18

 
327

Total other comprehensive income, net of tax
 
16

 
189

 
18

 
327

Comprehensive income (loss)
 
$
242,480

 
$
(63,368
)
 
$
476,428

 
$
(62,761
)


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


Continental Resources, Inc. and Subsidiaries
Condensed Consolidated Statement of Shareholders’ Equity
 
In thousands, except share data
 
Shares
outstanding
 
Common
stock
 
Additional
paid-in
capital
 
Accumulated
other
comprehensive
income
 
Retained
earnings
 
Total
shareholders’
equity
Balance at December 31, 2017
 
375,219,769

 
$
3,752

 
$
1,409,326

 
$
307

 
$
3,717,818

 
$
5,131,203

Net income (unaudited)
 
—

 
—

 
—

 
—

 
476,410

 
476,410

Other comprehensive income, net of tax (unaudited)
 
—

 
—

 
—

 
18

 
—

 
18

Stock-based compensation (unaudited)
 
—

 
—

 
21,465

 
—

 
—

 
21,465

Restricted stock:
 
 
 
 
 
 
 
 
 
 
 
 
Granted (unaudited)
 
1,277,491

 
13

 
—

 
—

 
—

 
13

Repurchased and canceled (unaudited)
 
(287,506
)
 
(3
)
 
(15,616
)
 
—

 
—

 
(15,619
)
Forfeited (unaudited)
 
(178,957
)
 
(2
)
 
—

 
—

 
—

 
(2
)
Balance at June 30, 2018 (unaudited)
 
376,030,797

 
$
3,760

 
$
1,415,175

 
$
325

 
$
4,194,228

 
$
5,613,488



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
 
 
Six months ended June 30,
In thousands
 
2018
 
2017
Cash flows from operating activities
 
 
Net income (loss)
 
$
476,410

 
$
(63,088
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
 
Depreciation, depletion, amortization and accretion
 
902,217

 
774,810

Property impairments
 
62,946

 
174,689

Non-cash (gain) loss on derivatives, net
 
11,465

 
(68,420
)
Stock-based compensation
 
21,478

 
20,571

Provision (benefit) for deferred income taxes
 
146,768

 
(31,834
)
Dry hole costs
 
1

 
157

(Gain) loss on sale of assets, net
 
(6,751
)
 
2,859

Other, net
 
7,159

 
5,089

Changes in assets and liabilities:
 
 
 
 
Accounts receivable
 
(79,043
)
 
(19,347
)
Inventories
 
(17,904
)
 
14,984

Other current assets
 
(8,138
)
 
(2,225
)
Accounts payable trade
 
103,710

 
105,441

Revenues and royalties payable
 
5,857

 
21,105

Accrued liabilities and other
 
17,550

 
(17,968
)
Other noncurrent assets and liabilities
 
(3,732
)
 
(251
)
Net cash provided by operating activities
 
1,639,993

 
916,572

 
 
 
 
 
Cash flows from investing activities
 
 
 
 
Exploration and development
 
(1,334,681
)
 
(877,115
)
Purchase of producing crude oil and natural gas properties
 
(24,097
)
 
(812
)
Purchase of other property and equipment
 
(12,205
)
 
(9,372
)
Proceeds from sale of assets
 
27,380

 
7,979

Net cash used in investing activities
 
(1,343,603
)
 
(879,320
)
 
 
 
 
 
Cash flows from financing activities
 
 
 
 
Credit facility borrowings
 
803,000

 
540,000

Repayment of credit facility
 
(991,000
)
 
(565,000
)
Repayment of other debt
 
(1,134
)
 
(1,099
)
Debt issuance costs
 
(5,524
)
 
—

Repurchase of restricted stock for tax withholdings
 
(15,619
)
 
(10,620
)
Net cash used in financing activities
 
(210,277
)
 
(36,719
)
Effect of exchange rate changes on cash
 
(26
)
 
14

Net change in cash and cash equivalents
 
86,087

 
547

Cash and cash equivalents at beginning of period
 
43,902

 
16,643

Cash and cash equivalents at end of period
 
$
129,989

 
$
17,190


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 originally 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. 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 substantial portion of the Company’s operations are located in the North region, with that region comprising 59% of the Company’s crude oil and natural gas production and 74% of its crude oil and natural gas revenues for the six months ended June 30, 2018. The Company's principal producing properties in the North region are located in the Bakken field of North Dakota and Montana. In recent years, the Company has significantly expanded its operations in the South region with its increased activity in the SCOOP and STACK plays. The South region comprised 41% of the Company's crude oil and natural gas production and 26% of its crude oil and natural gas revenues for the six months ended June 30, 2018.
For the six months ended June 30, 2018, crude oil accounted for 56% 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 and its subsidiaries, all of which are 100% owned, after all significant intercompany accounts and transactions have been eliminated upon consolidation.
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, 2017 (“2017 Form 10-K”), which includes a summary of the Company’s significant accounting policies and other disclosures.
The condensed consolidated financial statements as of June 30, 2018 and for the three and six month periods ended June 30, 2018 and 2017 are unaudited. The condensed consolidated balance sheet as of December 31, 2017 was derived from the audited balance sheet included in the 2017 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 interim 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 (loss) per share is computed by dividing net income (loss) 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 table presents the calculation of basic and diluted weighted average shares outstanding and net income (loss) per share for the three

5
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

and six months ended June 30, 2018 and 2017.
 
 
Three months ended June 30,
 
Six months ended June 30,
In thousands, except per share data
 
2018
 
2017
 
2018
 
2017
Net income (loss) (numerator)
 
$
242,464

 
$
(63,557
)
 
$
476,410

 
$
(63,088
)
Weighted average shares (denominator):
 
 
 
 
 
 
 
 
Weighted average shares - basic
 
371,921

 
371,111

 
371,733

 
370,972

Non-vested restricted stock (1)
 
2,584

 
—

 
2,850

 
—

Weighted average shares - diluted
 
374,505

 
371,111

 
374,583

 
370,972

Net income (loss) per share:
 
 
 
 
 
 
 
 
Basic
 
$
0.65

 
$
(0.17
)
 
$
1.28

 
$
(0.17
)
Diluted
 
$
0.65

 
$
(0.17
)
 
$
1.27

 
$
(0.17
)
(1)
For the three and six months ended June 30, 2017, the Company had a net loss and therefore the potential dilutive effect of approximately 1,933,200 and 2,546,200 weighted average non-vested restricted shares, respectively, were not included in the calculation of diluted net loss per share because to do so would have been anti-dilutive to the computations for those periods.
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 market 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 June 30, 2018 and December 31, 2017 consisted of the following:
In thousands
 
June 30, 2018
 
December 31, 2017
Tubular goods and equipment
 
$
18,722

 
$
14,946

Crude oil
 
96,588

 
82,460

Total
 
$
115,310

 
$
97,406

Adoption of new accounting pronouncements
Revenue recognition and presentation – In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers (Topic 606), which supersedes nearly all previously existing revenue recognition guidance under U.S. GAAP. Subsequently, the FASB issued additional guidance to assist entities with implementation efforts, including the issuance of ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). This new guidance became effective for reporting periods beginning after December 15, 2017. The Company adopted the new revenue recognition and presentation guidance on January 1, 2018 as required. See Note 4. Revenues for discussion of the adoption impact and the applicable disclosures required by the new guidance.
New accounting pronouncements not yet adopted
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 12 months. The standard is effective for interim and annual reporting periods beginning after December 15, 2018. The Company plans to adopt the new standard using the simplified transition method prescribed by ASU 2018-11, Leases (Topic 842): Targeted Improvements, whereby the Company will initially apply the new standard as of the January 1, 2019 adoption date and will recognize a cumulative-effect adjustment to the opening balance of retained earnings, if any, upon adoption in lieu of retrospectively applying the new standard to pre-adoption periods.
The Company continues to evaluate the impact of ASU 2016-02 on its financial statements, accounting policies and internal controls and is in the process of implementing systems and processes to capture, classify, and account for leases within the scope of the new guidance and to comply with the related disclosure requirements. Interpretations and application of the new guidance continue to evolve and are being monitored for applicability and impact on the Company.

6
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

Based on an initial review of the new guidance and the Company’s current commitments, the Company anticipates it will be required to recognize lease assets and liabilities related to drilling rig commitments, certain equipment rentals and leases, certain surface use agreements, and potentially other arrangements. The Company does not believe any of its firm transportation agreements will qualify as leases, but continues to evaluate such arrangements.
Based on commitments in place as of June 30, 2018, the Company currently estimates its lease assets and liabilities to be recognized under ASU 2016-02 will total approximately $100 million, the majority of which will be comprised of future cash flows associated with drilling rig commitments, which are further discussed in Note 8. Commitments and Contingencies–Drilling commitments. This estimate may be subsequently revised based on unforeseen changes in the nature, timing, and extent of the Company's contractual arrangements from period to period, finalization of the Company's evaluation of its firm transportation agreements, or due to changes in the Company's interpretation or application of the new guidance.
Credit losses – In June 2016, the FASB issued ASU 2016-13, Financial Instruments–Credit 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.
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. 
 
 
Six months ended June 30,
In thousands
 
2018
 
2017
Supplemental cash flow information:
 
 
 
 
Cash paid for interest
 
$
122,940

 
$
138,346

Cash paid for income taxes
 
—

 
2

Cash received for income tax refunds
 
5

 
148

Non-cash investing activities:
 
 
 
 
Asset retirement obligation additions and revisions, net
 
3,562

 
3,771


As of June 30, 2018 and December 31, 2017, the Company had $317.5 million and $302.8 million, respectively, of accrued capital expenditures included in “Net property and equipment” and “Accounts payable trade” in the condensed consolidated balance sheets.
Note 4. Revenues
Adoption of new revenue recognition and disclosure guidance
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which generally requires an entity to identify performance obligations in its contracts, estimate the amount of consideration to be received, allocate the consideration to each separate performance obligation, and recognize revenue as obligations are satisfied. Additionally, the standard requires expanded disclosures related to revenue recognition.
Subsequent to the issuance of ASU 2014-09, the FASB issued additional guidance to assist entities with implementation efforts, including the issuance of ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. This guidance requires an entity to record revenue on a gross basis if it controls a promised good or service before transferring it to a customer, whereas an entity records revenue on a net basis if its role is to arrange for another entity to provide the goods or services to a customer. Applying the guidance in ASU 2016-08 requires significant judgment in determining the point in time when control of products transfers to customers.

7
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

The Company adopted the new revenue recognition and presentation guidance on January 1, 2018 using a modified retrospective transition approach to all applicable contracts at the date of initial application, whereby the standard has been applied for periods commencing after December 31, 2017 and prior period results have not been adjusted to conform to current presentation. Adoption of the new guidance had no cumulative effect impact on the Company's retained earnings at January 1, 2018.
The new guidance does not have a material impact on the timing of the Company’s revenue recognition or its financial position, results of operations, net income, or cash flows, but does impact the Company's presentation of revenues and expenses under the gross-versus-net presentation guidance in ASU 2016-08. In years prior to 2018, the Company generally presented its revenues net of costs incurred to transport its production to market. Under the new guidance, revenues and transportation expenses associated with production originating from the Company’s operated properties are now reported on a gross basis as further discussed below. The changes from net to gross presentation resulted in an increase in revenues and a corresponding increase in separately reported transportation expenses, with no net effect on the Company’s results of operations, net income, or cash flows for the three and six months ended June 30, 2018.
The following table reflects the change in presentation of revenues and applicable expenses on the Company's 2018 results under the new and previous guidance.
 
 
Three months ended June 30, 2018
 
Six months ended June 30, 2018
In thousands
 
New Standard
 
Prior Presentation
 
Change
 
New Standard
 
Prior Presentation
 
Change
Revenues:
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil and natural gas sales
 
$
1,137,528

 
$
1,090,274

 
$
47,254

 
$
2,251,380

 
$
2,154,829

 
$
96,551

Loss on natural gas derivatives, net
 
(12,685
)
 
(12,685
)
 
—

 
(2,511
)
 
(2,511
)
 
—

Crude oil and natural gas service operations
 
12,270

 
12,270

 
—

 
29,272

 
29,272

 
—

Total revenues
 
$
1,137,113

 
$
1,089,859

 
$
47,254

 
$
2,278,141

 
$
2,181,590

 
$
96,551

Operating costs and expenses:
 
 
 
 
 


 
 
 
 
 
 
Transportation expenses
 
$
47,254

 
$
—

 
$
47,254

 
$
96,551

 
$
—

 
$
96,551

Net income
 
$
242,464

 
$
242,464

 
$
—

 
$
476,410

 
$
476,410

 
$
—

Revenue from contracts with customers
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 and transportation expenses are reported on a gross basis, 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 $40.2 million and $80.6 million for the three and six months ended June 30, 2018, respectively.
Operated natural gas revenues – The Company sells the majority of its operated natural gas production to midstream customers at its lease locations under multi-year term contracts 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 may elect 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 based on the customer's proceeds for sale of those processed products. When the Company elects to do so, it pays third parties to transport the processed products

8
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

which it took in-kind to downstream delivery points, where it then sells the products 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 $7.0 million and $15.9 million for the three and six months ended June 30, 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 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.
Natural gas derivative revenues – 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 and six months ended June 30, 2018.
 
 
Three months ended June 30, 2018
 
Six months ended June 30, 2018
In thousands
 
North Region
 
South Region
 
Total
 
North Region
 
South Region
 
Total
Crude oil revenues:
 
 
 
 
 
 
 
 
 
 
 
 
Operated properties
 
$
587,582

 
$
145,603

 
$
733,185

 
$
1,156,794

 
$
284,056

 
$
1,440,850

Non-operated properties
 
196,301

 
17,398

 
213,699

 
379,188

 
33,127

 
412,315

Total crude oil revenues
 
783,883

 
163,001

 
946,884

 
1,535,982

 
317,183

 
1,853,165

Natural gas revenues:
 
 
 
 
 
 
 
 
 
 
 
 
Operated properties
 
41,425

 
121,188

 
162,613

 
93,245

 
248,442

 
341,687

Non-operated properties
 
13,982

 
14,049

 
28,031

 
27,661

 
28,867

 
56,528

Total natural gas revenues
 
55,407

 
135,237

 
190,644

 
120,906

 
277,309

 
398,215

Crude oil and natural gas sales
 
$
839,290

 
$
298,238

 
$
1,137,528

 
$
1,656,888

 
$
594,492

 
$
2,251,380

 
 
 
 
 
 

 
 
 
 
 
 
Timing of revenue recognition
 
 
 
 
 
 
 
 
 
 
 
 
Goods transferred at a point in time
 
$
839,290

 
$
298,238

 
$
1,137,528

 
$
1,656,888

 
$
594,492

 
$
2,251,380

Goods transferred over time
 
—

 
—

 
—

 
—

 
—

 
—

 
 
$
839,290

 
$
298,238

 
$
1,137,528

 
$
1,656,888

 
$
594,492

 
$
2,251,380

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 that correspond with the value of the production transferred.
All of the Company's outstanding crude oil sales contracts at June 30, 2018 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

9
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

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 our 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 "Receivables–Crude oil and natural gas sales" or "Receivables–Joint 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 and six months ended June 30, 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. While the use of these derivative instruments limits the downside risk of adverse price movements, their use also limits future revenues from upward price movements.
The Company recognizes its natural gas derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The Company has not designated its natural gas 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 (loss) 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.

10
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

At June 30, 2018 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 remainder of 2018. At June 30, 2018 the Company had no outstanding crude oil derivative contracts.
 
 
 
 
Swaps Weighted Average Price
Period and Type of Contract
 
MMBtus
 
July 2018 - December 2018
 
 
 
 
Swaps - Henry Hub
 
115,920,000

 
$
2.88


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 June 30,
 
Six months ended June 30,
In thousands
 
2018
 
2017
 
2018
 
2017
Cash received (paid) on derivatives:
 
 
 
 
 
 
 
 
Natural gas fixed price swaps
 
$
4,758

 
$
6,709

 
$
8,954

 
$
12,187

Natural gas collars
 
—

 
(3,050
)
 
—

 
(9,456
)
Cash received (paid) on derivatives, net
 
4,758

 
3,659

 
8,954

 
2,731

Non-cash gain (loss) on derivatives:
 
 
 
 
 
 
 
 
Natural gas fixed price swaps
 
(17,443
)
 
12,520

 
(11,465
)
 
35,416

Natural gas collars
 
—

 
11,843

 
—

 
36,733

Non-cash gain (loss) on derivatives, net
 
(17,443
)
 
24,363

 
(11,465
)
 
72,149

Gain (loss) on natural gas derivatives, net
 
$
(12,685
)
 
$
28,022

 
$
(2,511
)
 
$
74,880

Diesel fuel derivatives
The Company previously entered into diesel fuel swap derivative contracts, all of which matured on or before December 31, 2017, to economically hedge against the variability in cash flows associated with purchases of diesel fuel for use in drilling activities. With respect to the diesel fuel swap contracts, the counterparty was required to make a payment to the Company if the settlement price for any settlement period was greater than the swap price, and the Company was required to make a payment to the counterparty if the settlement price for any settlement period was less than the swap price. The diesel fuel swap contracts were settled based upon reported NYMEX settlement prices for New York Harbor ultra-low sulfur diesel fuel.
The Company recognized its diesel fuel derivatives on the balance sheet as either assets or liabilities measured at fair value. The estimated fair value was based upon various factors, including commodity exchange prices, over-the-counter quotations, the risk-free interest rate, and time to expiration. The Company did not designate its diesel fuel derivatives as hedges for accounting purposes and, as a result, marked the derivative instruments to fair value and recognized the changes in fair value in the unaudited condensed consolidated statements of comprehensive income (loss) under the caption “Operating costs and expenses—Net (gain) loss on sale of assets and other.”
Cash receipts in the following table reflect gains on diesel fuel derivatives which matured during the 2017 period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash losses below represent the change in fair value of diesel fuel derivatives held at June 30, 2017 and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the three and six months ended June 30, 2017.
 
 
Three months ended June 30,
 
Six months ended June 30,
In thousands
 
2018
 
2017
 
2018
 
2017
Cash received on diesel fuel derivatives
 
$
—

 
$
185

 
$
—

 
$
919

Non-cash loss on diesel fuel derivatives
 
—

 
(1,098
)
 
—

 
(3,729
)
Loss on diesel fuel derivatives, net
 
$
—

 
$
(913
)
 
$
—

 
$
(2,810
)

11
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

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 and diesel fuel 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
 
June 30, 2018
 
December 31, 2017
Commodity derivative assets:
 
 
 
 
Gross amounts of recognized assets
 
$
885

 
$
2,603

Gross amounts offset on balance sheet
 
(682
)
 
—

Net amounts of assets on balance sheet
 
203

 
2,603

Commodity derivative liabilities:
 
 
 
 
Gross amounts of recognized liabilities
 
(9,747
)
 
—

Gross amounts offset on balance sheet
 
682

 
—

Net amounts of liabilities on balance sheet
 
$
(9,065
)
 
$
—

 
The following table reconciles the net amounts disclosed above to the individual financial statement line items in the condensed consolidated balance sheets. 
In thousands
 
June 30, 2018
 
December 31, 2017
Derivative assets
 
$
203

 
$
2,603

Noncurrent derivative assets
 
—

 
—

Net amounts of assets on balance sheet
 
203

 
2,603

Derivative liabilities
 
(9,065
)
 
—

Noncurrent derivative liabilities
 
—

 
—

Net amounts of liabilities on balance sheet
 
(9,065
)
 
—

Total derivative assets (liabilities), net
 
$
(8,862
)
 
$
2,603


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

12
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

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.
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 June 30, 2018 and December 31, 2017. 
 
 
Fair value measurements at June 30, 2018 using:
 
 
In thousands
 
Level 1
 
Level 2
 
Level 3
 
Total
Derivative liabilities:
 
 
 
 
 
 
 
 
Swaps
 
$
—

 
$
(8,862
)
 
$
—

 
$
(8,862
)
Total
 
$
—

 
$
(8,862
)
 
$
—

 
$
(8,862
)
 
 
 
 
 
 
 
 
 
 
 
Fair value measurements at December 31, 2017 using:
 
 
In thousands
 
Level 1
 
Level 2
 
Level 3
 
Total
Derivative assets:
 
 
 
 
 
 
 
 
Swaps
 
$
—

 
$
2,603

 
$
—

 
$
2,603

Total
 
$
—

 
$
2,603

 
$
—

 
$
2,603

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 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 2022 (adjusted for differentials), escalating 3% per year thereafter
Operating costs
  
Estimated costs for the current year, escalating 3% per year thereafter
Productive life of field
  
Ranging from 1 to 38 years
Discount rate
  
10%

13
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

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 and six months ended June 30, 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.
For the three and six months ended June 30, 2017, the Company determined the carrying amounts of certain proved properties were not recoverable from future cash flows, and therefore, were impaired. Impairments of proved properties totaled $81.5 million and $82.3 million for the three and six months ended June 30, 2017, respectively. The 2017 impairments reflected fair value adjustments primarily concentrated in the Arkoma Woodford field ($81.2 million, all in the second quarter of 2017) and various non-core areas in the North and South regions ($1.1 million, including $0.3 million in the second quarter of 2017). The impaired properties were written down to their estimated fair value at the time of impairment of approximately $72 million.
Certain unproved crude oil and natural gas properties were impaired during the three and six months ended June 30, 2018 and 2017, 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.
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 (loss).
 
 
Three months ended June 30,
 
Six months ended June 30,
In thousands
 
2018
 
2017
 
2018
 
2017
Proved property impairments
 
$
—

 
$
81,469

 
$
—

 
$
82,340

Unproved property impairments
 
29,162

 
41,847

 
62,946

 
92,349

Total
 
$
29,162

 
$
123,316

 
$
62,946

 
$
174,689

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. 
 
 
June 30, 2018
 
December 31, 2017
In thousands
 
Carrying
Amount
 
Estimated Fair Value
 
Carrying
Amount
 
Estimated Fair Value
Debt:
 
 
Revolving credit facility
 
$
—

 
$
—

 
$
188,000

 
$
188,000

Note payable
 
8,845

 
8,800

 
9,974

 
9,900

5% Senior Notes due 2022 (1)
 
1,997,782

 
2,030,100

 
1,997,576

 
2,040,000

4.5% Senior Notes due 2023
 
1,487,803

 
1,522,900

 
1,486,690

 
1,526,800

3.8% Senior Notes due 2024
 
992,588

 
976,000

 
992,036

 
988,800

4.375% Senior Notes due 2028
 
988,090

 
994,100

 
988,061

 
987,200

4.9% Senior Notes due 2044
 
691,435

 
683,600

 
691,354

 
679,900

Total debt
 
$
6,166,543

 
$
6,215,500

 
$
6,353,691

 
$
6,420,600

(1) As discussed in Note 12. Subsequent Events, on July 12, 2018 the Company announced it will redeem $400 million, or 20%, of its outstanding $2.0 billion of 5% Senior Notes due 2022 on August 16, 2018.
The fair value of revolving credit facility borrowings at December 31, 2017 approximate carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and are classified as Level 2 in the fair value hierarchy.
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

14
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

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.
Note 7. Long-Term Debt
Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $42.3 million and $44.3 million at June 30, 2018 and December 31, 2017, respectively, consists of the following.
In thousands
 
June 30, 2018
 
December 31, 2017
Revolving credit facility
 
$
—

 
$
188,000

Note payable
 
8,845

 
9,974

5% Senior Notes due 2022 (1)
 
1,997,782

 
1,997,576

4.5% Senior Notes due 2023
 
1,487,803

 
1,486,690

3.8% Senior Notes due 2024
 
992,588

 
992,036

4.375% Senior Notes due 2028
 
988,090

 
988,061

4.9% Senior Notes due 2044
 
691,435

 
691,354

Total debt
 
$
6,166,543

 
$
6,353,691

Less: Current portion of long-term debt
 
2,322

 
2,286

Long-term debt, net of current portion
 
$
6,164,221

 
$
6,351,405

(1) As discussed in Note 12. Subsequent Events, on July 12, 2018 the Company announced it will redeem $400 million, or 20%, of its outstanding $2.0 billion of 5% Senior Notes due 2022 on August 16, 2018.
Revolving Credit Facility
On April 9, 2018, the Company entered into a new unsecured revolving credit facility, maturing on April 9, 2023, with aggregate lender commitments totaling $1.5 billion, which may be increased up to a total of $4.0 billion upon agreement between the Company and participating lenders. In connection with the execution of the new credit facility, the Company terminated its then-existing $2.75 billion credit facility that was due to mature in May 2019. The Company had no outstanding borrowings on its credit facility at June 30, 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 under its credit facility.
The Company's new credit facility retains substantially the same restrictive covenants as the previous credit facility, 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 June 30, 2018.

15
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

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 June 30, 2018. 
 
 
2022 Notes (1)
 
2023 Notes
 
2024 Notes
 
2028 Notes
 
2044 Notes
Face value (in thousands)
 
$2,000,000
 
$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 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. See Note 12. Subsequent Events.
(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 prices or 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 price 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 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 June 30, 2018. Three of the Company’s subsidiaries, Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC, and The Mineral Resources Company, which have no material assets or operations, fully and unconditionally guarantee the senior notes on a joint and several basis. The Company’s other subsidiaries, the value of whose assets and operations are minor, do not guarantee the senior notes.
Note Payable
In February 2012, 20 Broadway Associates LLC, a 100% 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 $2.3 million is reflected as a current liability under the caption “Current portion of long-term debt” in the condensed consolidated balance sheets as of June 30, 2018.
Note 8. Commitments and Contingencies
Included below is a discussion of various future commitments of the Company as of June 30, 2018. The commitments under these arrangements are not recorded in the accompanying condensed consolidated balance sheets.
Drilling commitments – As of June 30, 2018, the Company has drilling rig contracts with various terms extending to June 2021 to ensure rig availability in its key operating areas. Future commitments as of June 30, 2018 total approximately $97 million, of which $42 million is expected to be incurred in the remainder of 2018, $41 million in 2019, $10 million in 2020, and $4 million in 2021.
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 the amount of capacity used. Future commitments remaining as of June 30, 2018 under the arrangements amount to approximately $1.36 billion, of which $112 million is expected to be incurred in the remainder of 2018, $225 million in 2019, $194 million in 2020, $175 million in 2021, $168 million in 2022, and $487 million thereafter. The Company is not committed under the above contracts to deliver fixed and determinable quantities of crude oil or natural gas in the future.
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

16
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

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. On June 11, 2015, the trial court certified a “hybrid” class requested by plaintiffs over the objections of the Company. The Company appealed the trial court’s class certification order. On February 8, 2017, the Oklahoma Court of Civil Appeals reversed the trial court’s ruling on certification and remanded the case for further proceedings. The plaintiffs filed a Petition for Rehearing which was denied by the Oklahoma Court of Civil Appeals. Plaintiffs then filed a Petition for Writ of Certiorari on May 23, 2017 to the Oklahoma Supreme Court, which was denied on October 2, 2017. On October 10, 2017, Plaintiffs filed with the trial court a “Second Amended and Renewed Motion for Class Action Certification and Request that the Court to Set a Briefing Schedule Related to Class Certification.” During the litigation the Company was not able to estimate a reasonably possible loss or range of loss or what impact, if any, the ultimate resolution of the action would have on its financial condition, results of operations or cash flows due to the preliminary status of the matter, the complexity and number of legal and factual issues presented by the matter and uncertainties with respect to, among other things, the nature of the claims and defenses, the existence and the potential size of the class, the scope and types of the properties and agreements involved, the production years involved, and the ultimate potential outcome of the matter. The Company further disclosed that it was reasonably possible one or more events could occur in the near term that could impact the Company’s ability to estimate the potential effect of this matter if any, on its financial condition, results of operations or cash flows. During the litigation the Company also disclosed plaintiffs alleged underpayments in excess of $200 million as damages, which may increase with the passage of time, a majority of which would be comprised of interest. After certification of the case as a class action was reversed the parties continued settlement negotiations. Due to the uncertainty of and burdens of litigation, on February 16, 2018, the Company reached a settlement in connection with this matter. Under the settlement, the Company initially expected to make payments and incur costs associated with the settlement of approximately $59.6 million. The Company accrued a loss for such amount at December 31, 2017, which was subsequently increased to $61.7 million at June 30, 2018 to reflect additional settlement obligations resulting from the passage of time. Such accrual is included in “Accrued liabilities and other” on the condensed consolidated balance sheets. On April 3, 2018, the District Court of Garfield County, Oklahoma preliminarily approved the settlement and set certain dates applicable to the settlement including the timing and content of Notice, Opt-out, and Objections to Class Members. The Fairness Hearing was held on June 11, 2018. On June 12, 2018, the court entered an order formally approving the settlement. The order approving the settlement is not subject to appeal. On June 20, 2018, the court entered an order approving Plaintiff Counsels’ request for Attorney Fees and Expenses. The deadline for an appeal of the order approving Attorney Fees and Expenses is August 13, 2018. In accordance with the settlement terms, the Company expects to make payments totaling approximately $50 million in the third quarter of 2018 and expects to satisfy the remainder of its settlement obligations in 2019.
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, 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 June 30, 2018 and December 31, 2017 the Company recorded a liability in the condensed consolidated balance sheets under the caption “Other noncurrent liabilities” of $4.7 million and $7.6 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 9. 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 (loss), was $10.6 million and $9.1 million for the three months ended June 30, 2018 and 2017, respectively, and $21.5 million and $20.6 million for the six months ended June 30, 2018 and 2017, 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 June 30, 2018, the Company had 13,727,512 shares of common stock available for long-term incentive awards to employees and directors under the 2013 Plan.

17
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

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.
A summary of changes in non-vested restricted shares outstanding for the six months ended June 30, 2018 is presented below. 
 
 
Number of
non-vested
shares
 
Weighted average
grant-date
fair value
Non-vested restricted shares outstanding at December 31, 2017
 
4,026,110

 
$
35.63

Granted
 
1,277,491

 
52.47

Vested
 
(1,041,748
)
 
47.10

Forfeited
 
(178,957
)
 
37.27

Non-vested restricted shares outstanding at June 30, 2018
 
4,082,896

 
$
37.90

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 six months ended June 30, 2018 was approximately $57.0 million. As of June 30, 2018, there was approximately $94 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized over a weighted average period of 1.5 years.

Note 10. Accumulated Other Comprehensive Income (Loss)
Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in “Accumulated other comprehensive income (loss)” within shareholders’ equity in the condensed consolidated balance sheets and “Other comprehensive income, net of tax” in the unaudited condensed consolidated statements of comprehensive income (loss). The following table summarizes the change in accumulated other comprehensive income (loss) for the three and six months ended June 30, 2018 and 2017:
 
 
Three months ended June 30,
 
Six months ended June 30,
In thousands
 
2018
 
2017
 
2018
 
2017
Beginning accumulated other comprehensive income (loss), net of tax
 
$
309

 
$
(122
)
 
$
307

 
$
(260
)
Foreign currency translation adjustments
 
16

 
189

 
18

 
327

Income taxes (1)
 
—

 
—

 
—

 
—

Other comprehensive income, net of tax
 
16

 
189

 
18

 
327

Ending accumulated other comprehensive income, net of tax
 
$
325

 
$
67

 
$
325

 
$
67

(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 11. 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.
The Company's (provision) benefit for income taxes totaled ($75.2) million and $37.9 million for the three months ended June 30, 2018 and 2017, respectively. The Company's (provision) benefit for income taxes totaled ($146.8) million and

18
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

$31.8 million for the six months ended June 30, 2018 and 2017, 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 June 30,
 
Six months ended June 30,
$ in thousands
 
2018
 
Tax rate %
 
2017
 
Tax rate %
 
2018
 
Tax rate %
 
2017
 
Tax rate %
Expected income tax (provision) benefit based on US statutory tax rate (1)
 
$
(66,716
)
 
21
%
 
$
35,494

 
35
%
 
$
(130,867
)
 
21
%
 
$
33,222

 
35
%
State income taxes, net of federal benefit
 
(9,531
)
 
3
%
 
3,043

 
3
%
 
(18,695
)
 
3
%
 
2,848

 
3
%
Tax benefit (deficiency) from stock-based compensation
 
359

 
—
%
 
(473
)
 
(1
%)
 
1,868

 
—
%
 
(3,773
)
 
(4
%)
Canadian valuation allowance (2)
 
(78
)
 
—
%
 
(112
)
 
—
%
 
(148
)
 
—
%
 
(257
)
 
—
%
Other, net
 
734

 
—
%
 
(97
)
 
—
%
 
1,074

 
—
%
 
(207
)
 
—
 %
(Provision) benefit for income taxes
 
$
(75,232
)
 
24
%
 
$
37,855

 
37
%
 
$
(146,768
)
 
24
%
 
$
31,833

 
34
%
(1)
In December 2017 the Tax Cuts and Jobs Act was signed into law, which among other things reduced the U.S. federal corporate income tax rate from 35% to 21% effective January 1, 2018.
(2)
Represents valuation allowances recognized against all deferred tax assets associated with operating loss carryforwards generated by the Company's Canadian operations during the respective periods for which the Company does not expect to realize a benefit.
Note 12. Subsequent Events
Partial redemption of senior notes    
On July 12, 2018, the Company announced it will redeem $400 million, or 20%, of its outstanding $2.0 billion of 5% Senior Notes due 2022 on August 16, 2018. The redemption price will be equal to 101.667% of the principal amount called for redemption plus accrued and unpaid interest to the redemption date in accordance with the terms of the 2022 Notes and the related indenture under which the 2022 Notes were issued.
The aggregate of the principal amount, redemption premium, and accrued interest payable upon partial redemption of the 2022 Notes is expected to total approximately $415 million. The Company expects to record a pre-tax loss on extinguishment of debt related to the partial redemption of approximately $7 million, which will be reflected in third quarter 2018 results.

Formation of strategic relationship
On August 6, 2018, the Company executed definitive documents to form a strategic relationship with Franco-Nevada, subject to customary closing conditions, to acquire minerals in the SCOOP and STACK plays, primarily in areas operated by the Company. In accordance with the deal terms, Franco-Nevada has agreed to pay approximately $220 million for a stake in a newly-formed minerals subsidiary. The Company expects to receive the proceeds at closing in the fourth quarter of 2018. The amount to be received by the Company is subject to adjustment under the terms of the transaction documents.
In addition, the parties have also committed, subject to satisfaction of agreed upon development thresholds, to spend up to a combined $125 million per year over the next three years to acquire additional minerals through the newly-formed subsidiary. With a carry component on capital acquisition costs, the Company is to fund 20% of future mineral acquisitions. The Company will be entitled to receive between 25% and 50% of total revenues generated by the minerals subsidiary based upon performance relative to certain predetermined targets.

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 Annual Report on Form 10-K for the year ended December 31, 2017. 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 Annual Report on Form 10-K for the year ended December 31, 2017, 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. 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.
Change in presentation of revenues
As discussed in Notes to Unaudited Condensed Consolidated Financial Statements–Note 4. Revenues, we adopted new revenue recognition and presentation rules on January 1, 2018. The new rules did not have a material impact on the timing of our revenue recognition or our financial position, results of operations, net income, or cash flows for the three and six months ended June 30, 2018, but did impact the presentation of our crude oil and natural gas revenues. We adopted the new rules using a modified retrospective transition approach whereby changes have been applied for periods commencing after December 31, 2017 and prior period results have not been adjusted to conform to current presentation.
Under the new rules, revenues and transportation expenses associated with production from our operated properties are now reported on a gross basis compared to net presentation in the prior year. For non-operated properties, we receive a net payment from the operator for our share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds received, consistent with our historical practice. As a result, beginning January 1, 2018 the gross presentation of revenues from our operated properties differs from the net presentation of revenues from non-operated properties. This impacts the comparability of certain operating metrics, such as per-unit sales prices, when such metrics are prepared in accordance with U.S. GAAP using gross presentation for some revenues and net presentation for others.
In order to provide metrics prepared in a manner consistent with how management assesses the Company's operating results, and to achieve comparability with prior period metrics for analysis purposes, we have presented crude oil and natural gas sales net of transportation expenses within MD&A, which we refer to as "net crude oil and natural gas sales," a non-GAAP measure. Average sales prices calculated using net crude oil and natural gas sales are referred to as "net sales prices," a non-GAAP measure, and are calculated by taking revenues less transportation expenses divided by sales volumes, whether for crude oil or natural gas, as applicable. Management believes presenting our revenues and sales prices net of transportation expenses is useful because it normalizes the presentation differences between operated and non-operated revenues and allows for a useful comparison of net realized prices to NYMEX benchmark prices on a Company-wide basis.
The following table presents a reconciliation of crude oil and natural gas sales (GAAP) to net crude oil and natural gas sales and related net sales prices (non-GAAP) for the three and six months ended June 30, 2018. Information is also presented for the three and six months ended June 30, 2017 for comparative purposes.
 
 
Three months ended June 30, 2018
 
Three months ended June 30, 2017
In thousands
 
Crude oil
 
Natural gas
 
Total
 
Crude oil
 
Natural gas
 
Total
Crude oil and natural gas sales (GAAP)
 
$
946,884

 
$
190,644

 
$
1,137,528

 
$
481,898

 
$
144,650

 
$
626,548

Less: Transportation expenses
 
(40,217
)
 
(7,037
)
 
(47,254
)
 
—

 
—

 
—

Net crude oil and natural gas sales (non-GAAP for 2018)
 
$
906,667

 
$
183,607

 
$
1,090,274

 
$
481,898

 
$
144,650

 
$
626,548

Sales volumes (MBbl/MMcf/MBoe)
 
14,311

 
69,310

 
25,863

 
11,499

 
55,054

 
20,674

Net sales price (non-GAAP for 2018)
 
$
63.35

 
$
2.65

 
$
42.16

 
$
41.91

 
$
2.63

 
$
30.31


20


 
 
Six months ended June 30, 2018
 
Six months ended June 30, 2017
In thousands
 
Crude oil
 
Natural gas
 
Total
 
Crude oil
 
Natural gas
 
Total
Crude oil and natural gas sales (GAAP)
 
$
1,853,165

 
$
398,215

 
$
2,251,380

 
$
962,539

 
$
297,859

 
$
1,260,398

Less: Transportation expenses
 
(80,603
)
 
(15,948
)
 
(96,551
)
 
—

 
—

 
—

Net crude oil and natural gas sales (non-GAAP for 2018)
 
$
1,772,562

 
$
382,267

 
$
2,154,829

 
$
962,539

 
$
297,859

 
$
1,260,398

Sales volumes (MBbl/MMcf/MBoe)
 
28,993

 
136,040

 
51,667

 
22,253

 
106,114

 
39,938

Net sales price (non-GAAP for 2018)
 
$
61.14

 
$
2.81

 
$
41.71

 
$
43.26

 
$
2.81

 
$
31.56

Second Quarter 2018 Highlights
Production
Total production for the second quarter of 2018 averaged 284,059 Boe per day, down 1% compared to the first quarter of 2018 and 26% higher than the second quarter of 2017.

Second quarter production was negatively impacted by abnormally rainy weather in the Bakken as well as the voluntary curtailment of production in the STACK play until third party natural gas pipeline infrastructure, which provides access to premium pricing in the North Texas market, became fully operational in early July. Without the impact of these events, our 2018 second quarter production would have been higher by approximately 5,000 Boe per day. Following these events, full production commenced in July.
The following table summarizes the changes in our average daily Boe production by major operating area.
Boe production per day
 
2Q 2018
 
2Q 2017
 
% Change from 2Q 2017
 
1Q 2018
 
% Change from 1Q 2018
Bakken
 
158,119

 
119,861

 
32
%
 
161,356

 
(2
%)
SCOOP
 
64,786

 
61,107

 
6
%
 
62,012

 
4
%
STACK
 
51,722

 
31,934

 
62
%
 
53,361

 
(3
%)
All other
 
9,432

 
13,311

 
(29
%)
 
10,681

 
(12
%)
Total
 
284,059

 
226,213

 
26
%
 
287,410

 
(1
%)
Revenues
Net crude oil and natural gas sales totaled $1.1 billion for the 2018 second quarter, a 74% increase compared to the 2017 second quarter driven by a 51% increase in crude oil net sales prices coupled with a 25% increase in total sales volumes.
Cash flows
Net cash inflows from operating activities totaled $753.8 million for the second quarter of 2018, exceeding second quarter net cash outflows from investing activities by $38.4 million.
Debt and liquidity
In April 2018 we entered into a new unsecured credit facility, maturing in April 2023, with aggregate lender commitments totaling $1.5 billion. The new credit facility replaced our previous $2.75 billion credit facility that was due to mature in May 2019.
At June 30, 2018 we had no outstanding borrowings on our credit facility and $130.0 million of cash and cash equivalents.
On July 12, 2018 we announced we will redeem $400 million, or 20%, of our outstanding $2.0 billion of 5% Senior Notes due 2022 on August 16, 2018. The redemption price will be equal to 101.667% of the principal amount called for redemption plus accrued and unpaid interest to the redemption date. The aggregate of the principal amount, redemption premium, and accrued interest payable upon partial redemption of the 2022 Notes is expected to total approximately $415 million.

21


Capital expenditures and drilling activity
Non-acquisition capital expenditures totaled $714.2 million for the second quarter of 2018, bringing year to date 2018 non-acquisition capital expenditures to $1.31 billion compared to $978.9 million for year to date 2017.
In the 2018 second quarter, production was initiated on 171 gross (56 net) operated and non-operated completed wells, bringing the 2018 year to date total to 309 gross (107 net) completed wells with first production compared to 228 gross (67 net) wells for the comparable 2017 period.
Financial and operating highlights
We use a variety of financial and operating measures to assess our performance. Among these measures are:
•
Volumes of crude oil and natural gas produced;
•
Crude oil and natural gas net sales price differentials relative to NYMEX benchmark prices; and
•
Per unit operating and administrative costs.
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 June 30,
 
Six months ended June 30,
 
 
2018
 
2017
 
2018
 
2017
Average daily production:
 
 
 
 
 

 

Crude oil (Bbl per day)
 
157,116

 
125,381

 
160,458

 
122,308

Natural gas (Mcf per day)
 
761,653

 
604,991

 
751,603

 
586,263

Crude oil equivalents (Boe per day)
 
284,059

 
226,213

 
285,725

 
220,018

Average net sales prices (1):
 

 

 

 

Crude oil ($/Bbl)
 
$
63.35

 
$
41.91

 
$
61.14

 
$
43.26

Natural gas ($/Mcf)
 
$
2.65

 
$
2.63

 
$
2.81

 
$
2.81

Crude oil equivalents ($/Boe)
 
$
42.16

 
$
30.31

 
$
41.71

 
$
31.56

Crude oil net sales price discount to NYMEX ($/Bbl)
 
$
(4.55
)
 
$
(6.31
)
 
$
(4.22
)
 
$
(6.69
)
Natural gas net sales price discount to NYMEX ($/Mcf)
 
$
(0.15
)
 
$
(0.56
)
 
$
(0.08
)
 
$
(0.43
)
Production expenses ($/Boe)
 
$
3.49

 
$
3.99

 
$
3.54

 
$
3.89

Production taxes (% of net crude oil and natural gas sales)
 
7.7
%
 
6.7
%
 
7.6
%
 
6.6
%
Depreciation, depletion, amortization and accretion ($/Boe)
 
$
17.29

 
$
19.14

 
$
17.45

 
$
19.48

Total general and administrative expenses ($/Boe)
 
$
1.82