10-Q
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 September 30, 2015
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
 _______________________________
 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, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting 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
  
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes ¨    No x
373,008,223 shares of our $0.01 par value common stock were outstanding on October 31, 2015.




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.
“DD&A” Depreciation, depletion, amortization and accretion.
“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.
“enhanced recovery” The recovery of crude oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Enhanced recovery methods are sometimes applied when production slows due to depletion of the natural pressure.
“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.
“horizontal drilling” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled horizontally within a specified interval.
“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.
“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.

i



“productive well” A well found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
“prospect” A potential geological feature or formation which geologists and geophysicists believe may contain hydrocarbons. A prospect can be in various stages of evaluation, ranging from a prospect that has been fully evaluated and is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation.
“proved reserves” The quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain.
“reservoir” A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.
“royalty interest” Refers to the ownership of a percentage of the resources or revenues produced from a crude oil or natural gas property. A royalty interest owner does not bear exploration, development, or operating expenses associated with drilling and producing a crude oil or natural gas property.
“SCOOP” Refers to the South Central Oklahoma Oil Province, a term we use to describe an area of crude oil and liquids-rich natural gas properties located in the Anadarko basin of Oklahoma in which we operate.
"STACK" Refers to Sooner Trend Anadarko Canadian Kingfisher, a term used to describe a play located in the Anadarko Basin of Oklahoma in which we operate.
“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 business and financial strategy;
our future operations;
our crude oil and natural gas reserves and related development plans;
our technology;
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 or property acquisitions and dispositions;
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 results;
our 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. 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, 2014, registration statements filed 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 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
 
 
September 30, 2015
 
December 31, 2014
In thousands, except par values and share data
 
(Unaudited)
 
 
Assets
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
16,955

 
$
24,381

Receivables:
 
 
 
 
Crude oil and natural gas sales
 
429,350

 
552,476

Affiliated parties
 
104

 
13,360

Joint interest and other, net
 
355,250

 
567,476

Derivative assets
 
78,610

 
52,423

Inventories
 
93,010

 
102,179

Deferred and prepaid taxes
 
2,137

 
63,266

Prepaid expenses and other
 
11,492

 
14,040

Total current assets
 
986,908

 
1,389,601

Net property and equipment, based on successful efforts method of accounting
 
14,173,563

 
13,635,852

Noncurrent derivative assets
 
27,271

 
31,992

Other noncurrent assets
 
18,135

 
18,588

Total assets
 
$
15,205,877

 
$
15,076,033

 
 
 
 
 
Liabilities and shareholders’ equity
 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable trade
 
$
613,780

 
$
1,263,724

Revenues and royalties payable
 
227,724

 
272,755

Payables to affiliated parties
 
482

 
7,305

Accrued liabilities and other
 
305,705

 
404,506

Derivative liabilities
 
99

 
1,645

Current portion of long-term debt
 
2,127

 
2,078

Total current liabilities
 
1,149,917

 
1,952,013

Long-term debt, net of current portion
 
7,108,702

 
5,926,800

Other noncurrent liabilities:
 
 
 
 
Deferred income tax liabilities
 
2,048,413

 
2,141,447

Asset retirement obligations, net of current portion
 
84,179

 
75,462

Noncurrent derivative liabilities
 
110

 
3,109

Other noncurrent liabilities
 
15,979

 
9,358

Total other noncurrent liabilities
 
2,148,681

 
2,229,376

Commitments and contingencies (Note 7)
 
 
 


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; 372,968,752 shares issued and outstanding at September 30, 2015; 372,005,502 shares issued and outstanding at December 31, 2014
 
3,730

 
3,720

Additional paid-in capital
 
1,335,574

 
1,287,941

Accumulated other comprehensive loss
 
(3,303
)
 
(385
)
Retained earnings
 
3,462,576

 
3,676,568

Total shareholders’ equity
 
4,798,577

 
4,967,844

Total liabilities and shareholders’ equity
 
$
15,205,877

 
$
15,076,033



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 September 30,
 
Nine months ended September 30,
In thousands, except per share data
 
2015
 
2014
 
2015
 
2014
Revenues
 
 
 
 
 
 
 
 
Crude oil and natural gas sales
 
$
628,457

 
$
1,138,460

 
$
1,999,751

 
$
3,223,605

Crude oil and natural gas sales to affiliates
 

 
21,821

 
1,400

 
77,094

Gain on derivative instruments, net
 
46,527

 
473,999

 
74,545

 
171,801

Crude oil and natural gas service operations
 
7,685

 
11,048

 
28,991

 
31,418

Total revenues
 
682,669

 
1,645,328

 
2,104,687

 
3,503,918

 
 
 
 
 
 
 
 
 
Operating costs and expenses
 
 
 
 
 
 
 
 
Production expenses
 
84,036

 
95,700

 
267,058

 
255,911

Production expenses to affiliates
 

 
1,674

 
1,654

 
2,870

Production taxes and other expenses
 
47,682

 
97,399

 
157,589

 
272,726

Exploration expenses
 
232

 
13,514

 
14,680

 
29,532

Crude oil and natural gas service operations
 
4,059

 
4,337

 
15,045

 
18,390

Depreciation, depletion, amortization and accretion
 
448,809

 
363,677

 
1,288,278

 
963,409

Property impairments
 
96,697

 
85,561

 
321,130

 
223,085

General and administrative expenses
 
53,798

 
43,980

 
143,368

 
134,435

(Gain) loss on sale of assets, net
 
(288
)
 
(5,411
)
 
(22,930
)
 
952

Total operating costs and expenses
 
735,025

 
700,431

 
2,185,872

 
1,901,310

Income (loss) from operations
 
(52,356
)
 
944,897

 
(81,185
)
 
1,602,608

Other income (expense):
 
 
 
 
 
 
 
 
Interest expense
 
(79,399
)
 
(73,912
)
 
(232,904
)
 
(209,728
)
Loss on extinguishment of debt
 

 
(24,517
)
 

 
(24,517
)
Other
 
588

 
393

 
1,474

 
1,945


 
(78,811
)
 
(98,036
)
 
(231,430
)
 
(232,300
)
Income (loss) before income taxes
 
(131,167
)
 
846,861

 
(312,615
)
 
1,370,308

Provision (benefit) for income taxes
 
(48,744
)
 
313,340

 
(98,623
)
 
507,015

Net income (loss)
 
$
(82,423
)
 
$
533,521

 
$
(213,992
)
 
$
863,293

Basic net income (loss) per share
 
$
(0.22
)
 
$
1.45

 
$
(0.58
)
 
$
2.34

Diluted net income (loss) per share
 
$
(0.22
)
 
$
1.44

 
$
(0.58
)
 
$
2.33

 
 
 
 
 
 
 
 
 
Comprehensive income (loss):
 
 
 
 
 
 
 
 
Net income (loss)
 
$
(82,423
)
 
$
533,521

 
$
(213,992
)
 
$
863,293

Other comprehensive loss, net of tax:
 
 
 
 
 
 
 
 
Foreign currency translation adjustments
 
(438
)
 

 
(2,918
)
 

Total other comprehensive loss, net of tax
 
(438
)
 

 
(2,918
)
 

Comprehensive income (loss)
 
$
(82,861
)
 
$
533,521

 
$
(216,910
)
 
$
863,293

 
 
 
 
 
 
 
 
 


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
loss
 
Retained
earnings
 
Total
shareholders’
equity
Balance at December 31, 2014
 
372,005,502

 
$
3,720

 
$
1,287,941

 
$
(385
)
 
$
3,676,568

 
$
4,967,844

Net loss (unaudited)
 

 

 

 

 
(213,992
)
 
(213,992
)
Other comprehensive loss, net of tax (unaudited)
 

 

 

 
(2,918
)
 

 
(2,918
)
Stock-based compensation (unaudited)
 

 

 
40,273

 

 

 
40,273

Excess tax benefit from stock-based compensation (unaudited)
 

 

 
13,177

 

 

 
13,177

Restricted stock:
 
 
 
 
 
 
 
 
 
 
 
 
Granted (unaudited)
 
1,383,557

 
14

 

 

 

 
14

Repurchased and canceled (unaudited)
 
(128,308
)
 
(1
)
 
(5,817
)
 

 

 
(5,818
)
Forfeited (unaudited)
 
(291,999
)
 
(3
)
 

 

 

 
(3
)
Balance at September 30, 2015 (unaudited)
 
372,968,752

 
$
3,730

 
$
1,335,574

 
$
(3,303
)
 
$
3,462,576

 
$
4,798,577



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
 
 
Nine months ended September 30,
In thousands
 
2015
 
2014
Cash flows from operating activities
 
 
Net income (loss)
 
$
(213,992
)
 
$
863,293

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
 
Depreciation, depletion, amortization and accretion
 
1,286,158

 
970,273

Property impairments
 
321,130

 
223,085

Non-cash gain on derivatives, net
 
(26,011
)
 
(269,018
)
Stock-based compensation
 
40,290

 
39,419

Provision (benefit) for deferred income taxes
 
(98,645
)
 
504,737

Excess tax benefit from stock-based compensation
 
(13,177
)
 

Dry hole costs
 
8,183

 
9,142

(Gain) loss on sale of assets, net
 
(22,930
)
 
952

Loss on extinguishment of debt
 

 
24,517

Other, net
 
10,143

 
5,986

Changes in assets and liabilities:
 
 
 
 
Accounts receivable
 
351,309

 
(192,178
)
Inventories
 
9,137

 
(28,124
)
Other current assets
 
64,271

 
(7,017
)
Accounts payable trade
 
(178,000
)
 
82,297

Revenues and royalties payable
 
(45,030
)
 
32,500

Accrued liabilities and other
 
(78,947
)
 
16,645

Other noncurrent assets and liabilities
 
1,603

 
1,342

Net cash provided by operating activities
 
1,415,492

 
2,277,851

 
 
 
 
 
Cash flows from investing activities
 
 
 
 
Exploration and development
 
(2,598,367
)
 
(3,255,327
)
Purchase of producing crude oil and natural gas properties
 
(557
)
 
(48,305
)
Purchase of other property and equipment
 
(31,991
)
 
(51,974
)
Proceeds from sale of assets
 
33,216

 
129,346

Net cash used in investing activities
 
(2,597,699
)
 
(3,226,260
)
 
 
 
 
 
Cash flows from financing activities
 
 
 
 
Credit facility borrowings
 
1,780,000

 
1,105,000

Repayment of credit facility
 
(600,000
)
 
(1,380,000
)
Proceeds from issuance of Senior Notes
 

 
1,681,834

Redemption of Senior Notes
 

 
(300,000
)
Premium on redemption of Senior Notes
 

 
(17,497
)
Repayment of other debt
 
(1,552
)
 
(1,503
)
Debt issuance costs
 
(2,110
)
 
(7,999
)
Repurchase of restricted stock for tax withholdings
 
(5,818
)
 
(7,618
)
Excess tax benefit from stock-based compensation
 
13,177

 

Net cash provided by financing activities
 
1,183,697

 
1,072,217

Effect of exchange rate changes on cash
 
(8,916
)
 

Net change in cash and cash equivalents
 
(7,426
)
 
123,808

Cash and cash equivalents at beginning of period
 
24,381

 
28,482

Cash and cash equivalents at end of period
 
$
16,955

 
$
152,290


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 Kansas and all properties south of Kansas and west of the Mississippi River including various plays in the South Central Oklahoma Oil Province (“SCOOP”), Northwest Cana, and Arkoma areas of Oklahoma. The East region is comprised of undeveloped leasehold acreage east of the Mississippi River with no current drilling or production operations.
The Company’s operations are geographically concentrated in the North region, with that region comprising 68% of the Company’s crude oil and natural gas production and 77% of its crude oil and natural gas revenues for the nine months ended September 30, 2015. 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 activity in the South region with its discovery and announcement of the SCOOP play in Oklahoma. The South region now comprises 32% of the Company's crude oil and natural gas production and 23% of its crude oil and natural gas revenues for the nine months ended September 30, 2015.
The Company has focused its operations on the exploration and development of crude oil since the 1980s. For the nine months ended September 30, 2015, crude oil accounted for 67% of the Company’s total production and 86% 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. 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, 2014 (“2014 Form 10-K”), which includes a summary of the Company’s significant accounting policies and other disclosures.
The condensed consolidated financial statements as of September 30, 2015 and for the three and nine month periods ended September 30, 2015 and 2014 are unaudited. The condensed consolidated balance sheet as of December 31, 2014 was derived from the audited balance sheet included in the 2014 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 of the estimates and assumptions that affect reported results are the 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. Diluted net income (loss) 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

5

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

weighted average shares outstanding and net income (loss) per share for the three and nine months ended September 30, 2015 and 2014.
 
 
Three months ended September 30,
 
Nine months ended September 30,
In thousands, except per share data
 
2015
 
2014
 
2015
 
2014
Income (loss) (numerator):
 
 
 
 
 
 
 
 
Net income (loss) - basic and diluted
 
$
(82,423
)
 
$
533,521

 
$
(213,992
)
 
$
863,293

Weighted average shares (denominator):
 
 
 
 
 
 
 
 
Weighted average shares - basic
 
369,599

 
368,814

 
369,499

 
368,740

Non-vested restricted stock (1)
 

 
1,714

 

 
1,892

Weighted average shares - diluted
 
369,599

 
370,528

 
369,499

 
370,632

Net income (loss) per share:
 
 
 
 
 
 
 
 
Basic
 
$
(0.22
)
 
$
1.45

 
$
(0.58
)
 
$
2.34

Diluted
 
$
(0.22
)
 
$
1.44

 
$
(0.58
)
 
$
2.33

(1)
The potential dilutive effect of approximately 688,800 and 1,521,000 weighted average restricted shares were not included in the calculation of diluted net loss per share for the three and nine months ended September 30, 2015, respectively, because to do so would have been anti-dilutive.
Inventories
Inventory is comprised of crude oil held in storage or as line fill in pipelines 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 at the lower of cost or market, with cost determined primarily using a weighted average cost method applied to specific classes of inventory items.
The components of inventory as of September 30, 2015 and December 31, 2014 consisted of the following:
In thousands
 
September 30, 2015
 
December 31, 2014
Tubular goods and equipment
 
$
15,936

 
$
15,659

Crude oil
 
77,074

 
86,520

Total
 
$
93,010

 
$
102,179

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. 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 recorded valuation allowances of $0.9 million and $13.3 million for the three and nine months ended September 30, 2015, respectively, against deferred tax assets associated with operating loss carryforwards generated by its Canadian subsidiary in 2015 for which the Company does not expect to realize a benefit.
Affiliate transactions
The affiliate transactions reflected in the accompanying unaudited condensed consolidated statements of comprehensive income (loss) include transactions between the Company and Hiland Partners, LP and its subsidiaries ("Hiland"). Hiland was controlled by the Company's principal shareholder through February 13, 2015, at which time it was sold to an unaffiliated third party. As a result of the sale, the prior related party relationship between the Company and Hiland terminated as of February 13, 2015, which resulted in a reduction in affiliate transactions recognized in the Company's financial statements at September 30, 2015 and for the three and nine months then ended.

6

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

Adoption of new accounting pronouncement
In April 2015, the Financial Accounting Standards Board issued Accounting Standards Update 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs ("ASU 2015-03"). The new standard requires debt issuance costs related to a recognized term debt liability, such as the Company's senior notes and note payable, be presented in the balance sheet as a direct deduction from the carrying amount of that term debt liability, consistent with the presentation of a debt discount. Under previous guidance, debt issuance costs were required to be presented in the balance sheet as an asset. The new standard does not affect the existing recognition and measurement guidance for debt issuance costs. The new standard is effective for annual and interim periods beginning after December 15, 2015, with early adoption permitted.
The Company early adopted ASU 2015-03 as of June 30, 2015 on a retrospective basis to all prior balance sheet periods presented. As a result of the adoption, the Company reclassified unamortized debt issuance costs associated with its senior notes and note payable, which totaled $65.7 million and $69.0 million as of June 30, 2015 and December 31, 2014, respectively, from "Other noncurrent assets" to a reduction of "Long-term debt, net of current portion" on the condensed consolidated balance sheets. Unamortized debt issuance costs reflected as a reduction of long-term debt subsequently totaled $64.0 million as of September 30, 2015. Adoption of ASU 2015-03 had no impact on the Company's current and previously reported shareholders' equity, results of operations, or cash flows. The December 31, 2014 carrying amounts for the Company's senior notes and note payable presented throughout this report on Form 10-Q have been adjusted to reflect the retroactive adoption of ASU 2015-03. Unamortized debt issuance costs associated with the Company's credit facility, which amounted to $7.6 million and $7.0 million as of September 30, 2015 and December 31, 2014, respectively, have not been reclassified and remain reflected in "Other noncurrent assets" on the condensed consolidated balance sheets.

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. 
 
 
Nine months ended September 30,
In thousands
 
2015
 
2014
Supplemental cash flow information:
 
 
 
 
Cash paid for interest
 
$
204,180

 
$
173,057

Cash paid for income taxes
 
27

 
4,012

Cash received for income tax refunds
 
59,117

 
5

Non-cash investing activities:
 
 
 
 
Increase (decrease) in accrued capital expenditures
 
(482,475
)
 
235,431

Asset retirement obligation additions and revisions, net
 
6,267

 
6,232


Note 4. Derivative Instruments
The Company recognizes all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its 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 on derivative instruments, net.”
The Company may utilize swap and collar derivative contracts to economically hedge against the variability in cash flows associated with the sale of future crude oil and 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.
With respect to a 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 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.

7

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

The Company’s derivative contracts are settled based upon reported settlement prices on commodity exchanges. Crude oil derivative settlements are based on NYMEX West Texas Intermediate (“WTI”) pricing or Inter-Continental Exchange (“ICE”) pricing for Brent crude oil. Natural gas derivative settlements are based on NYMEX Henry Hub pricing. The estimated fair value of derivative contracts is based upon various factors, including commodity exchange prices, over-the-counter quotations, and, in the case of collars and written call options, volatility, the risk-free interest rate, and the time to expiration. The calculation of the fair value of collars and written call options requires the use of an option-pricing model. See Note 5. Fair Value Measurements.
At September 30, 2015, the Company had outstanding derivative contracts with respect to future production as set forth in the tables below. 
Crude Oil - NYMEX WTI
 
 
 
Ceilings
 
 
 
 
 
 
Weighted Average
Price
Period and Type of Contract
 
Bbls
 
Range
 
October 2015 - December 2015
 
 
 
 
 
 
Written call options - WTI (1)
 
1,104,000

 
$95.85 - $103.75
 
$
98.36

Crude Oil - ICE Brent
 
 
 
Ceilings
 
 
 
 
 
 
Weighted Average
Price
Period and Type of Contract
 
Bbls
 
Range
 
October 2015 - December 2015
 
 
 
 
 
 
Written call options - ICE Brent (1)
 
184,000

 
$
107.40

 
$
107.40

January 2016 - December 2016
 
 
 
 
 
 
Written call options - ICE Brent (1)
 
1,464,000

 
$
107.70

 
$
107.70

 
 
 
 
 
 
Collars
Natural Gas - NYMEX Henry Hub
 
Swaps Weighted Average Price
 
Floors
 
Ceilings
 
 
 
 
 
 
 
Weighted Average Price
 
 
 
Weighted Average Price
Period and Type of Contract
 
MMBtus
 
 
Range
 
 
Range
 
October 2015 - December 2015
 
 
 
 
 
 
 
 
 
 
 
 
Swaps - Henry Hub
 
9,780,000

 
$
3.37

 
 
 
 
 
 
 
 
Collars - Henry Hub
 
7,360,000

 
 
 
$3.50 - $3.75
 
$
3.69

 
$4.89 - $5.48

 
$
5.04

January 2016 - December 2016
 
 
 
 
 
 
 
 
 
 
 
 
Swaps - Henry Hub
 
75,930,000

 
$
3.85

 
 
 
 
 
 
 
 
January 2017 - December 2017
 
 
 
 
 
 
 
 
 
 
 
 
Swaps - Henry Hub
 
25,550,000

 
$
3.35

 
 
 
 
 
 
 
 
Collars - Henry Hub
 
7,300,000

 
 
 
$
3.00

 
$
3.00

 
$
3.88

 
$
3.88


(1) Written call options represent the ceiling positions remaining from the Company's previous crude oil collar contracts. The floor positions of the collars were liquidated in the fourth quarter of 2014. For these written call options, the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price.


8

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

Derivative gains and losses
The following table presents cash settlements on matured derivative instruments and non-cash gains and losses on open derivative instruments for the periods presented. Cash receipts and payments below 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 September 30,
 
Nine months ended September 30,
In thousands
 
2015
 
2014
 
2015
 
2014
Cash received (paid) on derivatives:
 
 
 
 
 
 
 
 
Crude oil fixed price swaps
 
$

 
$
(4,126
)
 
$

 
$
(77,148
)
Crude oil collars
 

 
(233
)
 

 
(2,270
)
Natural gas fixed price swaps
 
5,142

 
4,549

 
29,084

 
(17,799
)
Natural gas collars
 
6,775

 

 
19,450

 

Cash received (paid) on derivatives, net
 
11,917

 
190

 
48,534

 
(97,217
)
Non-cash gain (loss) on derivatives:
 
 
 
 
 
 
 
 
Crude oil fixed price swaps
 

 
416,637

 

 
228,845

Crude oil collars
 

 
27,386

 

 
28,300

Crude oil written call options
 
617

 

 
4,544

 

Natural gas fixed price swaps
 
36,257

 
25,851

 
33,453

 
7,944

Natural gas collars
 
(2,264
)
 
3,935

 
(11,986
)
 
3,929

Non-cash gain on derivatives, net
 
34,610

 
473,809

 
26,011

 
269,018

Gain on derivative instruments, net
 
$
46,527

 
$
473,999

 
$
74,545

 
$
171,801

Balance sheet offsetting of derivative assets and liabilities
All of 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”. 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 derivative assets and liabilities, 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
 
September 30, 2015
 
December 31, 2014
Commodity derivative assets:
 
 
 
 
Gross amounts of recognized assets
 
$
105,881

 
$
84,415

Gross amounts offset on balance sheet
 

 

Net amounts of assets on balance sheet
 
105,881

 
84,415

Commodity derivative liabilities:
 
 
 
 
Gross amounts of recognized liabilities
 
(209
)
 
(4,770
)
Gross amounts offset on balance sheet
 

 
16

Net amounts of liabilities on balance sheet
 
$
(209
)
 
$
(4,754
)
 

9

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

The following table reconciles the net amounts disclosed above to the individual financial statement line items in the condensed consolidated balance sheets. 
In thousands
 
September 30, 2015
 
December 31, 2014
Derivative assets
 
$
78,610

 
$
52,423

Noncurrent derivative assets
 
27,271

 
31,992

Net amounts of assets on balance sheet
 
105,881

 
84,415

Derivative liabilities
 
(99
)
 
(1,645
)
Noncurrent derivative liabilities
 
(110
)
 
(3,109
)
Net amounts of liabilities on balance sheet
 
(209
)
 
(4,754
)
Total derivative assets, net
 
$
105,672

 
$
79,661


Note 5. 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 that are 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 that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.
A financial instrument’s categorization within the hierarchy is based upon the lowest level of input that is significant to the fair value measurement. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the hierarchy. As Level 1 inputs generally provide the most reliable evidence of fair value, the Company uses Level 1 inputs when available. The Company’s policy is to recognize transfers between the hierarchy levels as of the beginning of the reporting period in which the event or change in circumstances caused the transfer.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The Company's derivative instruments are reported at fair value on a recurring basis. In determining the fair values of fixed price swaps, 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 fixed price swaps are calculated mainly using significant observable inputs (Level 2). Calculation of the fair values of collars and written call options requires the use of an industry-standard option pricing model that considers various inputs including quoted forward commodity prices, 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.

10

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

The following tables summarize the valuation of financial instruments by pricing levels that were accounted for at fair value on a recurring basis as of September 30, 2015 and December 31, 2014. 
 
 
Fair value measurements at September 30, 2015 using:
 
 
In thousands
 
Level 1
 
Level 2
 
Level 3
 
Total
Derivative assets (liabilities):
 
 
 
 
 
 
 
 
Fixed price swaps
 
$

 
$
96,052

 
$

 
$
96,052

Collars
 

 
9,829

 

 
9,829

Written call options
 

 
(209
)
 

 
(209
)
Total
 
$

 
$
105,672

 
$

 
$
105,672

 
 
 
 
 
 
 
 
 
 
 
Fair value measurements at December 31, 2014 using:
 
 
In thousands
 
Level 1
 
Level 2
 
Level 3
 
Total
Derivative assets (liabilities):
 
 
 
 
 
 
 
 
Fixed price swaps
 
$

 
$
62,599

 
$

 
$
62,599

Collars
 

 
21,816

 

 
21,816

Written call options
 

 
(4,754
)
 

 
(4,754
)
Total
 
$

 
$
79,661

 
$

 
$
79,661

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. 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, 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 2019 (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 0 to 50 years
Discount rate
  
10%
Unobservable inputs to the fair value assessment are reviewed quarterly and are revised as warranted based on a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Fair value measurements of proved properties are reviewed and approved by certain members of the Company’s management.
During the three and nine month periods ended September 30, 2015 and September 30, 2014, 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 amounted to $36.3 million and $111.3 million for the three and nine months ended September 30, 2015, respectively, resulting from declines in commodity prices that indicated the carrying amounts for certain fields were not recoverable. The 2015 year to date impairments reflect fair value adjustments primarily concentrated in an emerging area with minimal production and costly reserve additions ($42.5 million, including $1.3 million in the third quarter), the Buffalo Red River units ($26.3 million, all in the third quarter), the Medicine Pole Hills units ($22.9 million, including $8.2 million in the third quarter), various non-core areas in the South region ($11.4 million, including $0.4 million in the third

11

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

quarter), and non-Bakken areas of North Dakota and Montana ($8.2 million, including $0.1 million in the third quarter). The impaired properties were written down to their estimated fair value totaling approximately $48.5 million.
Impairments of proved properties totaled $38.0 million and $69.3 million for the three and nine months ended September 30, 2014, respectively, which primarily reflected fair value adjustments made for certain properties in non-core areas of the South region. The impaired properties were written down to their estimated fair value totaling approximately $15.4 million as of September 30, 2014.
Certain unproved crude oil and natural gas properties were impaired during the three and nine months ended September 30, 2015 and 2014, 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 September 30,
 
Nine months ended September 30,
In thousands
 
2015
 
2014
 
2015
 
2014
Proved property impairments
 
$
36,302

 
$
38,046

 
$
111,346

 
$
69,337

Unproved property impairments
 
60,395

 
47,515

 
209,784

 
153,748

Total
 
$
96,697

 
$
85,561

 
$
321,130

 
$
223,085

Financial Instruments Not Recorded at Fair Value
The following table sets forth the fair values of financial instruments that are not recorded at fair value in the condensed consolidated financial statements. 
 
 
September 30, 2015
 
December 31, 2014
In thousands
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Debt:
 
 
Credit facility
 
$
1,345,000

 
$
1,345,000

 
$
165,000

 
$
165,000

Note payable
 
14,832

 
13,300

 
16,375

 
14,900

7.375% Senior Notes due 2020
 
196,424

 
204,100

 
195,997

 
213,000

7.125% Senior Notes due 2021
 
395,184

 
412,000

 
394,668

 
421,000

5% Senior Notes due 2022
 
1,996,747

 
1,760,100

 
1,996,507

 
1,857,900

4.5% Senior Notes due 2023
 
1,481,945

 
1,290,000

 
1,480,479

 
1,372,800

3.8% Senior Notes due 2024
 
989,681

 
820,400

 
988,940

 
868,700

4.9% Senior Notes due 2044
 
691,016

 
504,800

 
690,912

 
572,400

Total debt
 
$
7,110,829

 
$
6,349,700

 
$
5,928,878

 
$
5,485,700

The fair value of credit facility borrowings approximates carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and is 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 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 7.375% Senior Notes due 2020 (“2020 Notes”), the 7.125% Senior Notes due 2021 (“2021 Notes”), 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"), 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.

12

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

Note 6. Long-Term Debt
Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $49.1 million and $52.6 million at September 30, 2015 and December 31, 2014, respectively, consists of the following. See Note 2. Basis of Presentation and Significant Accounting Policies—Adoption of new accounting pronouncement for a discussion of the impact on long-term debt from the Company's adoption of ASU 2015-03.
In thousands
 
September 30, 2015
 
December 31, 2014
Credit facility
 
$
1,345,000

 
$
165,000

Note payable
 
14,832

 
16,375

7.375% Senior Notes due 2020
 
196,424

 
195,997

7.125% Senior Notes due 2021
 
395,184

 
394,668

5% Senior Notes due 2022
 
1,996,747

 
1,996,507

4.5% Senior Notes due 2023
 
1,481,945

 
1,480,479

3.8% Senior Notes due 2024
 
989,681

 
988,940

4.9% Senior Notes due 2044
 
691,016

 
690,912

Total debt
 
$
7,110,829

 
$
5,928,878

Less: Current portion of long-term debt
 
2,127

 
2,078

Long-term debt, net of current portion
 
$
7,108,702

 
$
5,926,800

 
Credit Facility
The Company has an unsecured credit facility, maturing on May 16, 2019, with aggregate commitments totaling $2.5 billion as of September 30, 2015, which may be increased up to a total of $4.0 billion upon agreement between the Company and participating lenders.
The Company had $1.35 billion and $165 million of outstanding borrowings on its credit facility at September 30, 2015 and December 31, 2014, respectively. Borrowings bear interest at market-based interest rates plus a margin that is based on the terms of the borrowing and the credit ratings assigned to the Company's senior unsecured debt. The weighted-average interest rate on outstanding borrowings at September 30, 2015 was 1.7%.
The Company had approximately $1.15 billion of borrowing availability on its credit facility at September 30, 2015 and incurs commitment fees based on currently assigned credit ratings of 0.225% per annum on the daily average amount of unused borrowing availability.
The credit facility contains certain restrictive covenants including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. This ratio represents the ratio of net debt (total debt 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 this covenant at September 30, 2015.
See Note 11. Subsequent Events for a discussion of changes to the Company's credit facility and other borrowings subsequent to September 30, 2015.

13

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 September 30, 2015. 
 
 
2020 Notes
  
2021 Notes
  
2022 Notes
 
2023 Notes
 
2024 Notes
 
2044 Notes
Face value (in thousands)
 
$200,000
 
$400,000
 
$2,000,000
 
$1,500,000
 
$1,000,000
 
$700,000
Maturity date
  
Oct 1, 2020
  
April 1, 2021
  
Sep 15, 2022
 
April 15, 2023
 
June 1, 2024
 
June 1, 2044
Interest payment dates
  
April 1, Oct 1
  
April 1, Oct 1
  
March 15, Sep 15
 
April 15, Oct 15
 
June 1, Dec 1
 
June 1, Dec 1
Call premium redemption period (1)
  
Oct 1, 2015
  
April 1, 2016
  
March 15, 2017
 
 
 
Make-whole redemption period (2)
  
Oct 1, 2015
  
April 1, 2016
  
March 15, 2017
 
Jan 15, 2023
 
Mar 1, 2024
 
Dec 1, 2043

(1)
On or after these dates, the Company has the option to redeem all or a portion of its senior notes of the applicable series at the decreasing redemption prices specified in the respective senior note indentures (together, the “Indentures”) plus any accrued and unpaid interest to the date of redemption.
(2)
At any time prior to these 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 Indentures 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 and leaseback transactions, and 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 September 30, 2015. Two of the Company’s subsidiaries, Banner Pipeline Company, L.L.C. and CLR Asset Holdings, LLC, which have no material assets or operations, fully and unconditionally guarantee the senior notes. 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 $2.1 million is reflected as a current liability under the caption “Current portion of long-term debt” in the condensed consolidated balance sheets as of September 30, 2015.
2014 Redemption of Senior Notes
In July 2014, the Company redeemed its then outstanding 8.25% Senior Notes due 2019 ("2019 Notes") using a portion of the proceeds from the May 2014 issuances of 2024 Notes and 2044 Notes. The 2019 Notes were redeemed for $317.5 million, representing a make-whole amount calculated in accordance with the terms of the 2019 Notes and related indenture. The Company recognized a pre-tax loss of $24.5 million related to the redemption, which included the make-whole premium and the write-off of deferred financing costs and unaccreted debt discount and is reflected under the caption “Loss on extinguishment of debt" in the unaudited condensed consolidated statements of comprehensive income (loss) for the three and nine months ended September 30, 2014.
Note 7. Commitments and Contingencies
Included below is a discussion of various future commitments of the Company as of September 30, 2015. The commitments under these arrangements are not recorded in the accompanying condensed consolidated balance sheets.
Drilling commitments – As of September 30, 2015, the Company had drilling rig contracts with various terms extending through March 2019. These contracts were entered into in the ordinary course of business to ensure rig availability to allow the Company to execute its business objectives in its strategic plays. Future commitments as of September 30, 2015 total

14

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

approximately $475 million, of which $59 million is expected to be incurred in the remainder of 2015, $220 million in 2016, $129 million in 2017, $62 million in 2018, and $5 million in 2019.
Pipeline transportation commitments – The Company has entered into firm transportation commitments to guarantee pipeline access capacity on operational crude oil and natural gas pipelines. The commitments, which have varying terms extending as far as 2027, require the Company to pay per-unit transportation charges regardless of the amount of pipeline capacity used. Future commitments remaining as of September 30, 2015 under the operational pipeline transportation arrangements amount to approximately $1.1 billion, of which $52 million is expected to be incurred in the remainder of 2015, $213 million in 2016, $210 million in 2017, $206 million in 2018, $170 million in 2019, and $217 million thereafter.
Further, the Company was a party to a five year firm transportation commitment (the "Agreement") for a future crude oil pipeline project being considered for development that is not yet operational. The project requires the granting of regulatory approvals and requires additional construction efforts by the counterparty before being completed. The project has faced significant delays and has failed to gain the necessary permits and approvals. As a result of the persistent delays and continuous uncertainty, the Agreement’s basic assumptions and purpose have become commercially impracticable. Accordingly, in 2015 the Company provided a shipper termination notice pursuant to the Agreement and formally provided the counterparty with the Company’s termination of the Agreement in its entirety. The Company's previously disclosed commitments under the Agreement totaled approximately $260 million, which is no longer expected to be incurred.
The Company’s pipeline commitments are for production primarily in the North region where the Company allocates a significant portion of its capital expenditures. The Company is not committed under these contracts to deliver fixed and determinable quantities of crude oil or natural gas in the future.
Fuel purchase commitment The Company has entered into a forward purchase contract with a third party to purchase specified quantities of diesel fuel at specified prices each month through June 2016 for use in the normal course of drilling operations. Over the remaining contract term, the Company has committed to purchase approximately 16 million gallons of diesel fuel at varying prices depending on the grade of diesel fuel purchased and the timing and location of delivery. The contract satisfies a significant portion of the Company's anticipated diesel fuel needs and provides for physical delivery to desired locations. Future commitments under the arrangement as of September 30, 2015 total approximately $47 million, of which $16 million is expected to be incurred in the remainder of 2015 and $31 million is expected to be incurred in 2016.
Litigation In November 2010, a putative class action was filed in the District Court of Blaine County, Oklahoma by Billy J. Strack and Daniela A. Renner as trustees of certain named trusts and on behalf of other similarly situated parties against the Company. The Petition 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 seek recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the proposed class. On November 3, 2014, plaintiffs filed an Amended Petition that did not add any substantive claims, but sought a “hybrid class action” in which they sought certification of certain claims for injunctive relief, reserving the right to seek a further class certification on money damages in the future. Plaintiffs filed an Amended Motion for Class Certification on January 9, 2015, that modified the proposed class to royalty owners in Oklahoma production from July 1, 1993, to the present (instead of 1980 to the present) and sought certification of over 45 separate “issues” for injunctive or declaratory relief, again, reserving the right to seek a further class certification of money damages in the future. The Company responded to the petition, its amendment, and the motions for class certification denying the allegations and raising a number of affirmative defenses and legal arguments to each of the claims and filings. Certain discovery was undertaken and the “hybrid” motion was briefed by plaintiffs and the Company. A hearing on the “hybrid” class certification was held on June 1st and 2nd, 2015. On June 11, 2015, the trial court certified a “hybrid” class as requested by plaintiffs. The Company has appealed the trial court’s class certification order, which will be reviewed de novo by the appellate court. A mediation is scheduled for December 7, 2015. The Company is not currently able to estimate a reasonably possible loss or range of loss or what impact, if any, the action will 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 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. Although not currently at issue in the “hybrid” certification, plaintiffs have alleged underpayments in excess of $200 million that they may claim as damages, which may increase with the passage of time, a majority of which would be comprised of interest. The Company disputes plaintiffs’ claims, disputes that the case meets the requirements for a class action and is vigorously defending the case. The Company will continue to assert its defenses to the case as certified as well as any future attempt to certify a money damages class.

15

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

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 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. As of September 30, 2015 and December 31, 2014, the Company had recorded a liability in the condensed consolidated balance sheets under the caption “Other noncurrent liabilities” of $6.1 million and $2.9 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 8. Stock-Based Compensation
The Company has granted restricted stock to employees and directors pursuant to the Continental Resources, Inc. 2005 Long-Term Incentive Plan (“2005 Plan”) and 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 $12.9 million and $13.4 million for the three months ended September 30, 2015 and 2014, respectively, and $40.3 million and $39.4 million for the nine months ended September 30, 2015 and 2014, respectively.
In May 2013, the Company adopted the 2013 Plan and reserved a maximum of 19,680,072 shares of common stock that may be issued pursuant to the plan. The 2013 Plan replaced the Company's 2005 Plan as the instrument used to grant long-term incentive awards and no further awards will be granted under the 2005 Plan. However, restricted stock awards granted under the 2005 Plan prior to the adoption of the 2013 Plan will remain outstanding in accordance with their terms. As of September 30, 2015, the Company had a maximum of 17,027,803 shares of restricted stock available to grant to officers, directors and employees under the 2013 Plan.
Restricted stock is awarded in the name of the recipient and constitutes issued and outstanding shares of the Company’s common stock for all corporate purposes during the period of restriction and, except as otherwise provided under the 2013 Plan or agreement relevant to a given award, includes the right to vote the restricted stock or 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 nine months ended September 30, 2015 is presented below: 
 
 
Number of
non-vested
shares
 
Weighted
average
grant-date
fair value
Non-vested restricted shares outstanding at December 31, 2014
 
2,678,764

 
$
49.40

Granted
 
1,383,557

 
47.36

Vested
 
(420,852
)
 
45.92

Forfeited
 
(291,999
)
 
50.99

Non-vested restricted shares outstanding at September 30, 2015
 
3,349,470

 
$
48.86

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 a fixed amount determined at the grant date fair value and is recognized ratably over the vesting period as services are rendered by employees and directors. The expected life of restricted stock is based on the non-vested period that remains subsequent to the date of grant. There are no post-vesting restrictions related to the Company’s restricted stock. The fair value of restricted stock that vested during the nine months ended September 30, 2015 at the vesting date was approximately $19.1 million. As of September 30, 2015, there was approximately $81 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized ratably over a weighted average period of 1.4 years.

16

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

Note 9. Accumulated Other Comprehensive Loss
Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in "Accumulated other comprehensive loss" within shareholders’ equity on the condensed consolidated balance sheets. The following table summarizes the change in accumulated other comprehensive loss for the three and nine months ended September 30, 2015:
In thousands
 
Three months ended September 30, 2015
 
Nine months ended September 30, 2015
Beginning accumulated other comprehensive loss, net of tax
 
$
(2,865
)
 
$
(385
)
Foreign currency translation adjustments
 
(438
)
 
(2,918
)
Income tax benefit (1)
 

 

Other comprehensive loss, net of tax
 
(438
)
 
(2,918
)
Ending accumulated other comprehensive loss, net of tax
 
$
(3,303
)
 
$
(3,303
)
(1)
A valuation allowance has been recognized against deferred tax assets associated with losses generated by the Company's Canadian operations, thereby resulting in no income taxes on other comprehensive loss for the period.
Note 10. Property Dispositions
During the nine months ended September 30, 2015, the Company sold certain non-strategic properties in various areas to third parties for proceeds totaling $33.2 million. The proceeds primarily related to the assignment of certain non-producing leasehold acreage in Oklahoma to a third party for $25.9 million in May 2015. The Company recognized a pre-tax gain on the transaction of $20.5 million. The assigned properties represented an immaterial portion of the Company’s leasehold acreage.
During the nine months ended September 30, 2014, the Company sold certain non-strategic properties in various areas to third parties for proceeds totaling $129.3 million. The proceeds primarily related to dispositions of properties in the Niobrara play in Colorado and Wyoming in March 2014 for proceeds totaling $30.3 million and $85.8 million of proceeds received in conjunction with the disposition of a portion of the Company's Northwest Cana properties in Oklahoma in September 2014. The disposed properties represented an immaterial portion of the Company’s total proved reserves, production, and revenues.
Note 11. Subsequent Events
New term loan
On November 4, 2015, the Company, as borrower, and its subsidiaries Banner Pipeline Company, L.L.C. and CLR Asset Holdings, LLC, as guarantors, entered into a Term Loan Agreement with MUFG Union Bank, N.A., as Administrative Agent, Bank of America, N.A., Citibank, N.A., JPMorgan Chase Bank, N.A. and Mizuho Bank, LTD., as Co-Syndication Agents, and Compass Bank, Toronto Dominion (Texas) LLC and U.S. Bank National Association, as Co-Documentation Agents, and the other lenders party thereto (the "Term Loan"). The Term Loan provides for aggregate lender commitments of $500 million, the full amount of which the Company borrowed at the closing of the Term Loan. The proceeds from the Term Loan were used to repay a portion of the borrowings outstanding on the Company's credit facility, which had a balance prior to repayment of $1.38 billion.
The Term Loan will mature on November 4, 2018 and will bear interest at a market-based interest rate plus a margin that is based on the terms of the borrowing and the credit ratings assigned to the Company's senior, unsecured, long-term indebtedness. The initial per annum interest rate on the Term Loan is LIBOR plus 1.375%, which is 0.125% lower than the interest rate currently available under the Company's credit facility for similar borrowings.
The terms of the Term Loan include covenants limiting the amount of debt that can be incurred by the Company’s subsidiaries that do not guarantee the Term Loan and that restrict the ability of the Company and its Restricted Subsidiaries (as such term is defined in the Term Loan) to incur liens and engage in sale and leaseback transactions. The Term Loan also contains a financial covenant that requires the Company to maintain a debt to capitalization ratio that does not exceed 0.65 to 1.0 and a covenant that restricts the ability of the Company to merge, consolidate or sell all or substantially all of its assets.
The Term Loan includes events of default relating to customary matters, including, among other things, nonpayment of principal, interest or other amounts; violation of covenants; incorrectness of representations and warranties in any material respect; cross default and cross acceleration with respect to certain non-payments in connection with indebtedness in an aggregate principal amount of $100 million or more; bankruptcy; judgments involving liability of $100 million or more that are not paid; and ERISA events. Many events of default are subject to customary notice and cure periods.

17

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

MUFG Union Bank, N.A. was the arranger and book runner for the Term Loan. In addition, certain of the lenders party to the Term Loan, and their respective affiliates, have performed, and may in the future perform, various commercial banking, investment banking and other financial advisory services for the Company and its subsidiaries for which they have received, and will receive, customary fees and expenses.
The above description of the material terms and conditions of the Term Loan does not purport to be complete and is qualified in its entirety by reference to the full text of the Term Loan, which is filed as Exhibit 10.1 to this Form 10-Q.
Increase in credit facility commitments
On November 4, 2015, the aggregate lender commitments on the Company's credit facility were increased from $2.5 billion to $2.75 billion to provide enhanced liquidity for the Company. After giving effect to the increased commitments and the use of proceeds from the $500 million Term Loan discussed above to repay borrowings outstanding under the Company's credit facility, the Company had approximately $880 million of outstanding borrowings and $1.87 billion of availability on its credit facility at November 4, 2015.






18



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 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, 2014. 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, 2014, 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 play in Oklahoma.
Business Environment and Outlook

Commodity prices have remained depressed through September 30, 2015 and continue to be volatile and unpredictable. We remain focused on balancing our capital expenditures with operating cash flows and have taken measures to achieve this balance at a $50 WTI oil price. We have reduced our operated rig count and are deferring well completion activities except for where we have contractual considerations or where completing wells accomplishes specific strategic objectives. These measures will continue to slow our rate of capital spending and production growth for the remainder of 2015 and are expected to result in a decline in production in the 2015 fourth quarter compared to the 2015 third quarter.
2015 Highlights
Production
Production for the third quarter of 2015 averaged 228,278 Boe per day, an increase of 1% from the second quarter of 2015 and 25% higher than the third quarter of 2014. Year to date production averaged 220,630 Boe per day, a 32% increase over the comparable 2014 period.
North Dakota Bakken production averaged 123,560 Boe per day for the third quarter of 2015, a 3% decrease from the second quarter of 2015 and 16% higher than the third quarter of 2014. Year to date, North Dakota Bakken production averaged 124,139 Boe per day, a 31% increase over the comparable 2014 period.
SCOOP production averaged 69,136 Boe per day for the third quarter of 2015, an 11% increase over the second quarter of 2015 and 90% higher than the third quarter of 2014. Year to date, SCOOP production averaged 60,592 Boe per day, an 82% increase over the comparable 2014 period.
SCOOP comprised 30% of our total production for the 2015 third quarter compared to 28% for the 2015 second quarter and 20% for the 2014 third quarter. SCOOP comprised 27% of our total production for year to date 2015 compared to 20% for the comparable 2014 period.
Revenues
Crude oil and natural gas revenues for the 2015 third quarter decreased 46% compared to the 2014 third quarter driven by a 57% decrease in realized commodity prices, the effect of which was partially offset by a 25% increase in total sales volumes.
Year to date crude oil and natural gas revenues decreased 39% from the comparable 2014 period driven by a 54% decrease in realized commodity prices, the effect of which was partially offset by a 33% increase in total sales volumes.
Average crude oil sales prices for the third quarter and year to date periods of 2015 decreased 54% and 52%, respectively, from the comparable 2014 periods.
Crude oil sales volumes for the third quarter and year to date periods of 2015 increased 15% and 27%, respectively, from the comparable 2014 periods.

19



Average natural gas sales prices for the third quarter and year to date periods of 2015 decreased 56% and 59%, respectively, from the comparable 2014 periods.
Natural gas sales volumes for the third quarter and year to date periods of 2015 increased 48% and 45%, respectively, from the comparable 2014 periods.
Proved property impairments
Decreases in commodity prices in the third quarter of 2015 adversely impacted the recoverability of capitalized costs in certain operating areas and contributed to the recognition of non-cash impairment charges for proved properties totaling $36.3 million for the third quarter, bringing year to date proved property impairments to $111.3 million through September 30, 2015. These impairments were primarily concentrated in non-core areas of our North and South regions.
Capital expenditures and drilling activity
We invested approximately $540.0 million in our capital program in the third quarter of 2015 compared to $585.5 million for the 2015 second quarter and $983.8 million for the 2015 first quarter. Year to date non-acquisition capital expenditures totaled $2.1 billion through September 30, 2015.
For the quarter and year to date periods of 2015 we participated in the drilling and completion of the following number of wells by area:
 
1Q 2015
 
2Q 2015
 
3Q 2015
 
YTD 2015
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
North Dakota Bakken
210

 
62

 
160

 
55

 
160

 
35

 
530

 
152

Montana Bakken
8

 
6

 
1

 

 

 

 
9

 
6

SCOOP
74

 
37

 
55

 
18

 
34

 
11

 
163

 
66

Northwest Cana

 

 
5

 
2

 
6

 
2

 
11

 
4

STACK

 

 

 

 
3

 
1

 
3

 
1

Other
12

 
6

 
5

 

 
1

 

 
18

 
6

Total wells
304

 
111

 
226

 
75

 
204

 
49

 
734

 
235

Included in the completed well counts at September 30, 2015 are 14 gross (9 net) wells that were completed during the third quarter but are not yet producing. Additionally, as of September 30, 2015 we had 105 gross (80 net) operated wells that are drilled but not yet completed. Due to current market conditions we have chosen to defer completions and new production on certain wells until the commodity pricing environment improves.
As of September 30, 2015, we operated 23 rigs on our properties, down from 27 operated rigs at June 30, 2015 and 49 operated rigs at December 31, 2014.
Credit facility and liquidity
At September 30, 2015, we had $17.0 million of cash and cash equivalents and $1.15 billion of borrowing availability on our credit facility after considering outstanding borrowings and letters of credit. We had $1.35 billion of outstanding borrowings on our credit facility at September 30, 2015 compared to $1.23 billion at June 30, 2015 and $165 million at December 31, 2014.
Credit facility borrowings, net of repayments, totaled $120 million for the 2015 third quarter compared to $270 million for the 2015 second quarter and $790 million for the 2015 first quarter, the decreasing trend of which resulted from a reduced level of capital expenditures due to our efforts to align capital expenditures with operating cash flows in response to decreased commodity prices.
On November 4, 2015, aggregate lender commitments on our credit facility were increased from $2.5 billion to $2.75 billion to provide enhanced liquidity. Additionally on that date, we entered into a $500 million term loan maturing in November 2018 and used the proceeds therefrom to repay a portion of our outstanding credit facility borrowings. After giving effect to the repayment and increased commitments, we had approximately $880 million of outstanding borrowings and $1.87 billion of availability on our credit facility at November 4, 2015.

20



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 prices realized,
Per unit operating and administrative costs, and
EBITDAX (a non-GAAP financial measure).
The following table contains financial and operating highlights for the periods presented. Average sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes. 
 
 
Three months ended September 30,
 
Nine months ended September 30,
 
 
2015
 
2014
 
2015
 
2014
Average daily production:
 

 

 

 

Crude oil (Bbl per day)
 
147,472

 
127,788

 
146,975

 
116,954

Natural gas (Mcf per day)
 
484,834

 
327,287

 
441,930

 
304,453

Crude oil equivalents (Boe per day)
 
228,278

 
182,335

 
220,630

 
167,696

Average sales prices:
 

 

 

 

Crude oil ($/Bbl)
 
$
38.95

 
$
85.49

 
$
42.60

 
$
89.02

Natural gas ($/Mcf)
 
$
2.23

 
$
5.10

 
$
2.39

 
$
5.80

Crude oil equivalents ($/Boe)
 
$
29.90

 
$
69.08

 
$
33.18

 
$
72.52

Crude oil sales price differential to NYMEX ($/Bbl)
 
$
(7.54
)
 
$
(11.77
)
 
$
(8.54
)
 
$
(10.60
)
Natural gas sales price premium (discount) to NYMEX ($/Mcf)
 
$
(0.54
)
 
$
1.04

 
$
(0.39
)
 
$
1.28

Production expenses ($/Boe)
 
$
4.00

 
$
5.80

 
$
4.45

 
$
5.69

Production taxes (% of oil and gas revenues)
 
7.6
%
 
8.3
%
 
7.8
%
 
8.1
%
DD&A ($/Boe)
 
$
21.36

 
$
21.65

 
$
21.36

 
$
21.17

General and administrative expenses ($/Boe) (1)
 
$
1.95

 
$
1.82

 
$
1.71

 
$
2.08

Non-cash equity compensation ($/Boe)
 
$
0.61

 
$
0.80

 
$
0.67

 
$
0.87

Net income (loss) (in thousands)
 
$
(82,423
)
 
$
533,521

 
$
(213,992
)
 
$
863,293

Diluted net income (loss) per share
 
$
(0.22
)
 
$
1.44

 
$
(0.58
)
 
$
2.33

EBITDAX (in thousands) (2)
 
$
472,221

 
$
947,635

 
$
1,558,656

 
$
2,590,980

 
(1)
Excludes non-cash equity compensation expense.
(2)
We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, non-cash equity compensation expense, and losses on extinguishment of debt. EBITDAX is not a measure of net income or operating cash flows as determined by U.S. GAAP. Reconciliations of net income and operating cash flows to EBITDAX are provided below under the heading Non-GAAP Financial Measures.

21



Three months ended September 30, 2015 compared to the three months ended September 30, 2014
Results of Operations
The following table presents selected financial and operating information for the periods presented. 
 
 
Three months ended September 30,
In thousands, except sales price data
 
2015
 
2014
Crude oil and natural gas sales
 
$
628,457

 
$
1,160,281

Gain on derivative instruments, net
 
46,527

 
473,999

Crude oil and natural gas service operations
 
7,685

 
11,048

Total revenues
 
682,669

 
1,645,328

Operating costs and expenses
 
(735,025
)
 
(700,431
)
Other expenses, net (1)
 
(78,811
)
 
(98,036
)
Income (loss) before income taxes
 
(131,167
)
 
846,861

(Provision) benefit for income taxes
 
48,744

 
(313,340
)
Net income (loss)
 
$
(82,423
)
 
$
533,521

Production volumes:
 

 

Crude oil (MBbl)
 
13,567

 
11,756

Natural gas (MMcf)
 
44,605

 
30,110

Crude oil equivalents (MBoe)
 
21,002

 
16,775

Sales volumes:
 

 

Crude oil (MBbl)
 
13,582

 
11,777

Natural gas (MMcf)
 
44,605

 
30,110

Crude oil equivalents (MBoe)
 
21,016

 
16,796

Average sales prices:
 

 

Crude oil ($/Bbl)
 
$
38.95

 
$
85.49

Natural gas ($/Mcf)
 
2.23

 
5.10

Crude oil equivalents ($/Boe)
 
29.90

 
69.08

(1)
Amount includes a loss on extinguishment of debt of $24.5 million for the three months ended September 30, 2014 related to the July 2014 redemption of our 8.25% Senior Notes due 2019.
Production
The following tables reflect our production by product and region for the periods presented. 
 
 
Three months ended September 30,
 
Volume
increase
 
Volume
percent
increase
 
 
2015
 
2014
 
 
 
 
Volume
 
Percent
 
Volume
 
Percent
 
Crude oil (MBbl)
 
13,567

 
65
%
 
11,756

 
70
%
 
1,811

 
15
%
Natural gas (MMcf)
 
44,605

 
35
%
 
30,110

 
30
%
 
14,495

 
48
%
Total (MBoe)
 
21,002

 
100
%
 
16,775

 
100
%
 
4,227

 
25
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three months ended September 30,
 
Volume
increase
 
Volume
percent
increase
 
 
2015
 
2014
 
 
 
 
MBoe
 
Percent
 
MBoe
 
Percent
 
North Region
 
13,681

 
65
%
 
12,519

 
75
%
 
1,162

 
9
%
South Region
 
7,321

 
35
%
 
4,256

 
25
%
 
3,065

 
72
%
Total
 
21,002

 
100
%
 
16,775

 
100
%
 
4,227

 
25
%
The 15% increase in crude oil production for the third quarter was driven by increased production from our properties in the North Dakota Bakken field and SCOOP play. Production in North Dakota Bakken increased 1,160 MBbls, or 14%, over the prior year third quarter, while SCOOP production increased 1,096 MBbls, or 116%. Production growth in these areas was primarily due to additional drilling and completion activity resulting from our drilling program. These increases were partially offset by a decrease in production from our properties in Montana Bakken and the Red River units totaling 456 MBbls, or 19%, compared to the prior year third quarter due to a combination of natural declines in production and reduced drilling activity.

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The 48% increase in natural gas production for the third quarter was driven by increased production from our properties in the SCOOP play, Bakken field, and Northwest Cana field due to additional wells being completed and producing subsequent to September 30, 2014. Natural gas production in SCOOP increased 11,522 MMcf, or 80%, over the prior year third quarter, while Bakken production increased 2,593 MMcf, or 25%, and Northwest Cana production increased 697 MMcf, or 28%. These increases were partially offset by decreases in production from various areas in our North and South regions primarily due to natural declines in production.
Our ongoing reduction in capital spending prompted by depressed commodity prices has adversely impacted our production growth. Our average daily production for the month of September 2015 was approximately 222,000 Boe per day, a decrease of 3% compared to our production of approximately 230,000 Boe per day for the month of June 2015. We expect our year-over-year production growth to continue slowing for the remainder of 2015 as we continue to curtail our capital spending, and we expect to exit the year with daily production of approximately 210,000 Boe per day.
Revenues
Our total revenues consist of sales of crude oil and natural gas, gains and losses resulting from changes in the fair value of our derivative instruments and revenues associated with crude oil and natural gas service operations.
Crude Oil and Natural Gas Sales. Crude oil and natural gas sales for the third quarter of 2015 were $628.5 million, a 46% decrease from sales of $1.16 billion for the same period in 2014 primarily due to a significant decrease in commodity prices, partially offset by an increase in sales volumes.
Our crude oil sales prices averaged $38.95 per barrel in the 2015 third quarter compared to $85.49 for the 2014 third quarter. Market prices for crude oil remained depressed in the 2015 third quarter, resulting in significantly lower realized sales prices compared to the prior year. The differential between NYMEX WTI calendar month average crude oil prices and our realized crude oil price per barrel was $7.54 for the 2015 third quarter compared to $11.77 for the 2014 third quarter. The improved differential was due in part to increased availability and use of pipeline transportation to move our crude oil to market with less dependence on more costly rail transportation.
Our average natural gas sales price for the 2015 third quarter decreased to $2.23 per Mcf compared to $5.10 for the 2014 third quarter due to lower market prices for natural gas and natural gas liquids ("NGLs"). Our natural gas production is primarily sold at the wellhead with price realizations being impacted by the volume and value of NGLs that purchasers extract from our sales stream. The difference between our realized natural gas sales prices and NYMEX Henry Hub calendar month natural gas prices was a discount of $0.54 per Mcf for the 2015 third quarter compared to a premium of $1.04 for the 2014 third quarter. NGL prices remained depressed in the 2015 third quarter in conjunction with low crude oil prices, which reduced the value of our natural gas sales stream and unfavorably impacted the difference between our realized prices and Henry Hub benchmark pricing.
Crude oil, natural gas and NGL prices remain volatile and we are unable to predict the impact future price changes may have on our revenues and differentials for the remainder of 2015 and beyond.
Our sales volumes for the third quarter of 2015 increased 4,220 MBoe, or 25%, over the comparable period in 2014 primarily due to an increase in producing wells resulting from the success of our drilling programs in North Dakota Bakken and SCOOP. At various times we have stored crude oil due to pipeline line fill requirements, low commodity prices, or marketing disruptions or we have sold crude oil from inventory. These actions result in differences between produced and sold crude oil volumes and caused crude oil sales volumes to be higher than crude oil production by 15 MBbls for the third quarter of 2015.
Derivatives. Changes in commodity prices during the third quarter of