CLR FY2014 Q3
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, 2014
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
372,213,798 shares of our $0.01 par value common stock were outstanding on October 31, 2014.




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.
“conventional play” An area believed to be capable of producing crude oil and natural gas occurring in discrete accumulations in structural and stratigraphic traps.
“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 a new field or to find a new reservoir in a field previously found to be productive of crude oil or natural gas in another reservoir.
“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.
“fracture stimulation” A process involving the high pressure injection of water, sand and additives into rock formations to stimulate crude oil and natural gas production.
"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.

i



“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.
“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.
“proved developed reserves” Reserves expected to be recovered through existing wells with existing equipment and operating methods.
“proved undeveloped reserves” or “PUD” Proved reserves expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
“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.
“resource play” Refers to an expansive contiguous geographical area with prospective crude oil and/or natural gas reserves that has the potential to be developed uniformly with repeatable commercial success due to advancements in horizontal drilling and completion technologies.
“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 south central Oklahoma.
“unconventional play” An area believed to be capable of producing crude oil and natural gas occurring in accumulations that are regionally extensive, but may lack readily apparent traps, seals and discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These areas tend to have low permeability and may be closely associated with source rock, as is the case with oil and gas shale, tight oil and gas sands and coalbed methane, and generally require horizontal drilling, fracture stimulation treatments or other special recovery processes in order to achieve economic production.
“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 includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact, including, but not limited to, statements or information concerning the Company’s future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, returns, budgets, costs, business strategy, objectives, and cash flow, included in this report are forward-looking statements. When used in this report, 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 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 the expectations reflected in the forward-looking statements are reasonable and based on reasonable assumptions, no assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under Part II, Item 1A. Risk Factors included in this report, if any, our Annual Report on Form 10-K for the year ended December 31, 2013, registration statements filed from time to time with the Securities and Exchange Commission ("SEC"), and other announcements we make from time to time.
Without limiting the generality of the foregoing, certain statements incorporated by reference, if any, or included in this report constitute forward-looking statements.
Forward-looking statements may include statements about:
our business strategy;
our future operations;
our crude oil and natural gas reserves;
our technology;
our financial strategy;
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;
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;
plans, objectives, expectations and intentions contained in this report that are not historical, including, without limitation, statements regarding our future growth plans;
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.

We caution you these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for, and development, production, and sale of,

iii


crude oil and natural gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling, completion and production equipment and services and transportation infrastructure, environmental risks, drilling and other operating risks, lack of availability and security of computer-based systems, regulatory changes, the uncertainty inherent in estimating crude oil and natural gas reserves and in projecting future rates of production, cash flows and access to capital, the timing of development expenditures, and the other risks described under Part II, Item 1A. Risk Factors in this report, if any, our Annual Report on Form 10-K for the year ended December 31, 2013, registration statements filed from time to time with the SEC, 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 hereof. Should one or more of the risks or uncertainties described in this report occur, or should underlying assumptions prove incorrect, our 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. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements to reflect events or circumstances after the date of this report.
 


iv


PART I. Financial Information
ITEM 1.
Financial Statements
Continental Resources, Inc. and Subsidiaries
Condensed Consolidated Balance Sheets
 
 
September 30, 2014
 
December 31, 2013
In thousands, except par values and share data
 
(Unaudited)
 
 
Assets
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
152,290

 
$
28,482

Receivables:
 
 
 
 
Crude oil and natural gas sales
 
671,769

 
643,498

Affiliated parties
 
15,066

 
13,107

Joint interest and other, net
 
507,038

 
349,579

Derivative assets
 
143,268

 
3,616

Inventories
 
82,564

 
54,440

Deferred and prepaid taxes
 
11,393

 
44,337

Prepaid expenses and other
 
15,488

 
10,207

Total current assets
 
1,598,876

 
1,147,266

Net property and equipment, based on successful efforts method of accounting
 
12,993,789

 
10,721,272

Net debt issuance costs and other
 
88,420

 
72,644

Noncurrent derivative assets
 
31,002

 

Total assets
 
$
14,712,087

 
$
11,941,182

 
 
 
 
 
Liabilities and shareholders’ equity
 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable trade
 
$
1,201,082

 
$
885,289

Revenues and royalties payable
 
323,277

 
291,772

Payables to affiliated parties
 
10,473

 
5,436

Accrued liabilities and other
 
267,623

 
198,113

Derivative liabilities
 

 
90,535

Current portion of long-term debt
 
2,062

 
2,011

Total current liabilities
 
1,804,517

 
1,473,156

Long-term debt, net of current portion
 
5,831,860

 
4,713,821

Other noncurrent liabilities:
 
 
 
 
Deferred income tax liabilities
 
2,155,442

 
1,736,812

Asset retirement obligations, net of current portion
 
62,331

 
54,353

Noncurrent derivative liabilities
 

 
7,829

Other noncurrent liabilities
 
9,727

 
2,093

Total other noncurrent liabilities
 
2,227,500

 
1,801,087

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; 500,000,000 shares authorized; 372,046,368 shares issued and outstanding at September 30, 2014; 371,317,318 shares issued and outstanding at December 31, 2013
 
3,720

 
3,713

Additional paid-in capital
 
1,281,970

 
1,250,178

Retained earnings
 
3,562,520

 
2,699,227

Total shareholders’ equity
 
4,848,210

 
3,953,118

Total liabilities and shareholders’ equity
 
$
14,712,087

 
$
11,941,182



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



Continental Resources, Inc. and Subsidiaries
Unaudited Condensed Consolidated Statements of Income
 
 
 
Three months ended September 30,
 
Nine months ended September 30,
In thousands, except per share data
 
2014
 
2013
 
2014
 
2013
Revenues
 
 
 
 
 
 
 
 
Crude oil and natural gas sales
 
$
1,138,460

 
$
981,170

 
$
3,223,605

 
$
2,595,416

Crude oil and natural gas sales to affiliates
 
21,821

 
28,666

 
77,094

 
74,843

Gain (loss) on derivative instruments, net
 
473,999

 
(203,774
)
 
171,801

 
(89,548
)
Crude oil and natural gas service operations
 
11,048

 
8,825

 
31,418

 
29,876

Total revenues
 
1,645,328

 
814,887

 
3,503,918

 
2,610,587

 
 
 
 
 
 
 
 
 
Operating costs and expenses
 
 
 
 
 
 
 
 
Production expenses
 
95,700

 
66,790

 
255,911

 
201,250

Production and other expenses to affiliates
 
1,674

 
260

 
2,870

 
1,055

Production taxes and other expenses
 
97,399

 
84,334

 
272,726

 
223,718

Exploration expenses
 
13,514

 
8,173

 
29,532

 
29,138

Crude oil and natural gas service operations
 
4,337

 
6,654

 
18,390

 
22,567

Depreciation, depletion, amortization and accretion
 
363,677

 
244,721

 
963,409

 
695,189

Property impairments
 
85,561

 
42,167

 
223,085

 
161,960

General and administrative expenses
 
43,980

 
34,070

 
134,435

 
103,761

(Gain) loss on sale of assets, net
 
(5,411
)
 
(325
)
 
952

 
(112
)
Total operating costs and expenses
 
700,431

 
486,844

 
1,901,310

 
1,438,526

Income from operations
 
944,897

 
328,043

 
1,602,608

 
1,172,061

Other income (expense):
 
 
 
 
 
 
 
 
Interest expense
 
(73,912
)
 
(62,756
)
 
(209,728
)
 
(171,609
)
Loss on extinguishment of debt
 
(24,517
)
 

 
(24,517
)
 

Other
 
393

 
584

 
1,945

 
1,765


 
(98,036
)
 
(62,172
)
 
(232,300
)
 
(169,844
)
Income before income taxes
 
846,861

 
265,871

 
1,370,308

 
1,002,217

Provision for income taxes
 
313,340

 
98,373

 
507,015

 
370,822

Net income
 
$
533,521

 
$
167,498

 
$
863,293

 
$
631,395

Basic net income per share
 
$
1.45

 
$
0.45

 
$
2.34

 
$
1.72

Diluted net income per share
 
$
1.44

 
$
0.45

 
$
2.33

 
$
1.71



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



Continental Resources, Inc. and Subsidiaries
Condensed Consolidated Statements of Shareholders’ Equity
 
In thousands, except share data
 
Shares
outstanding
 
Common
stock
 
Additional
paid-in
capital
 
Retained
earnings
 
Total
shareholders’
equity
Balance at December 31, 2013
 
371,317,318

 
$
3,713

 
$
1,250,178

 
$
2,699,227

 
$
3,953,118

Net income (unaudited)
 

 

 

 
863,293

 
863,293

Stock-based compensation (unaudited)
 

 

 
39,409

 

 
39,409

Restricted stock:
 
 
 
 
 
 
 
 
 
 
Granted (unaudited)
 
1,251,264

 
12

 

 

 
12

Repurchased and canceled (unaudited)
 
(117,314
)
 
(1
)
 
(7,617
)
 

 
(7,618
)
Forfeited (unaudited)
 
(404,900
)
 
(4
)
 

 

 
(4
)
Balance at September 30, 2014 (unaudited)
 
372,046,368

 
$
3,720

 
$
1,281,970

 
$
3,562,520

 
$
4,848,210



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
 
2014
 
2013
Cash flows from operating activities
 
 
Net income
 
$
863,293

 
$
631,395

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
Depreciation, depletion, amortization and accretion
 
970,273

 
694,729

Property impairments
 
223,085

 
161,960

Non-cash (gain) loss on derivatives, net
 
(269,018
)
 
37,638

Stock-based compensation
 
39,419

 
29,460

Provision for deferred income taxes
 
504,737

 
360,599

Dry hole costs
 
9,142

 
9,180

(Gain) loss on sale of assets, net
 
952

 
(112
)
Loss on extinguishment of debt
 
24,517

 

Other, net
 
5,986

 
4,308

Changes in assets and liabilities:
 
 
 
 
Accounts receivable
 
(192,178
)
 
(178,171
)
Inventories
 
(28,124
)
 
(8,529
)
Prepaid expenses and other
 
(7,017
)
 
(11,118
)
Accounts payable trade
 
82,297

 
151,266

Revenues and royalties payable
 
32,500

 
46,611

Accrued liabilities and other
 
16,645

 
41,791

Other noncurrent assets and liabilities
 
1,342

 
7,446

Net cash provided by operating activities
 
2,277,851

 
1,978,453

 
 
 
 
 
Cash flows from investing activities
 
 
 
 
Exploration and development
 
(3,255,327
)
 
(2,767,448
)
Purchase of producing crude oil and natural gas properties
 
(48,305
)
 
(12,404
)
Purchase of other property and equipment
 
(51,974
)
 
(41,942
)
Proceeds from sale of assets
 
129,346

 
22,406

Net cash used in investing activities
 
(3,226,260
)
 
(2,799,388
)
 
 
 
 
 
Cash flows from financing activities
 
 
 
 
Credit facility borrowings
 
1,105,000

 
470,000

Repayment of credit facility
 
(1,380,000
)
 
(1,065,000
)
Proceeds from issuance of Senior Notes
 
1,681,834

 
1,479,375

Redemption of Senior Notes
 
(300,000
)
 

Premium on redemption of Senior Notes
 
(17,497
)
 

Repayment of other debt
 
(1,503
)
 
(1,457
)
Debt issuance costs
 
(7,999
)
 
(2,263
)
Repurchase of equity grants
 
(7,618
)
 
(3,942
)
Net cash provided by financing activities
 
1,072,217

 
876,713

Net change in cash and cash equivalents
 
123,808

 
55,778

Cash and cash equivalents at beginning of period
 
28,482

 
35,729

Cash and cash equivalents at end of period
 
$
152,290

 
$
91,507



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 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 approximately 74% of the Company’s crude oil and natural gas production and approximately 83% of its crude oil and natural gas revenues for the nine months ended September 30, 2014. Our principal producing properties in the North region are located in the Bakken field of North Dakota and Montana. The remainder of the Company's crude oil and natural gas production and revenue is derived from the South region, primarily from producing properties in the SCOOP play in south-central Oklahoma.
The Company has focused its operations on the exploration and development of crude oil since the 1980s. For the nine months ended September 30, 2014, crude oil accounted for approximately 70% of the Company’s total production and approximately 85% of its crude oil and natural gas revenues.
Note 2. Basis of Presentation and Significant Accounting Policies
Basis of presentation
The condensed consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are 100% owned, after all significant intercompany accounts and transactions have been eliminated upon consolidation.
On August 18, 2014, the Company's Board of Directors declared a 2-for-1 stock split of the Company's common stock to be effected in the form of a stock dividend. The stock dividend was distributed on September 10, 2014 to shareholders of record as of September 3, 2014. All previously reported common stock and earnings per share amounts have been retroactively adjusted in the accompanying financial statements and related notes to reflect the stock split.
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 Form 10-Q together with the Company’s Annual Report on Form 10-K for the year ended December 31, 2013 (“2013 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, 2014 and for the three and nine month periods ended September 30, 2014 and 2013 are unaudited. The condensed consolidated balance sheet as of December 31, 2013 was derived from the audited balance sheet included in the 2013 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.

5

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

Inventories
Inventories are stated at the lower of cost or market and consist of the following: 
In thousands
 
September 30, 2014
 
December 31, 2013
Tubular goods and equipment
 
$
13,586

 
$
11,139

Crude oil
 
68,978

 
43,301

Total
 
$
82,564

 
$
54,440


Crude oil inventories are valued at the lower of cost or market using the first-in, first-out inventory method. Crude oil inventories consist of the following volumes: 
MBbls
 
September 30, 2014
 
December 31, 2013
Crude oil line fill and tank requirements
 
941

 
370

Temporarily stored crude oil
 
196

 
344

Total
 
1,137

 
714

Earnings per share
Basic net income per share is computed by dividing net income by the weighted-average number of shares outstanding for the period. Diluted net income per share reflects the potential dilution of non-vested restricted stock awards, which are calculated using the treasury stock method. The following table presents the calculation of basic and diluted weighted average shares outstanding and net income per share for the three and nine months ended September 30, 2014 and 2013. Weighted average shares and net income per share amounts for the three and nine months ended September 30, 2013 have been retroactively adjusted to reflect the Company's 2-for-1 stock split occurring in September 2014.
 
 
Three months ended September 30,
 
Nine months ended September 30,
In thousands, except per share data
 
2014
 
2013
 
2014
 
2013
Income (numerator):
 
 
 
 
 
 
 
 
Net income - basic and diluted
 
$
533,521

 
$
167,498

 
$
863,293

 
$
631,395

Weighted average shares (denominator):
 
 
 
 
 
 
 
 
Weighted average shares - basic
 
368,814

 
368,139

 
368,740

 
368,072

Non-vested restricted stock
 
1,714

 
1,622

 
1,892

 
1,485

Weighted average shares - diluted
 
370,528

 
369,761

 
370,632

 
369,557

Net income per share:
 
 
 
 
 
 
 
 
Basic
 
$
1.45

 
$
0.45

 
$
2.34

 
$
1.72

Diluted
 
$
1.44

 
$
0.45

 
$
2.33

 
$
1.71

New accounting pronouncement
In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606). The standard’s core principle is that an entity shall recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard generally requires an entity to identify performance obligations in its contracts, estimate the amount of variable consideration to be received in the transaction price, allocate the transaction price to each separate performance obligation, and recognize revenue as obligations are satisfied. The standard will be effective for annual and interim periods beginning after December 15, 2016. The standard allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. The Company is evaluating the impact of the provisions of ASU 2014-09; however, the standard is not expected to have a material effect on the Company’s financial position, results of operations or cash flows.
Reclassifications
Certain prior year amounts have been reclassified to conform to the current year presentation. In the prior year, the Company presented charges related to natural gas transportation and processing under the caption “Production taxes and other expenses” or “Production and other expenses to affiliates” in the unaudited condensed consolidated statements of income. Such

6

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

charges, which totaled $8.9 million for the three months ended September 30, 2013, including transactions with an affiliate totaling $1.2 million, and $24.2 million for the nine months ended September 30, 2013, including transactions with an affiliate totaling $3.5 million, have been reclassified to be netted within Crude oil and natural gas sales” or "Crude oil and natural gas sales to affiliates", as applicable, in order to conform to the current year presentation. The reclassifications had no impact on previously reported operating income, net income, current assets, total assets, current liabilities, total liabilities, stockholders' equity or cash flows.

Note 3. Supplemental Cash Flow Information
The following table discloses supplemental cash flow information about cash paid for interest and income taxes. 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
 
2014
 
2013
Supplemental cash flow information:
 
 
 
 
Cash paid for interest
 
$
173,057

 
$
139,023

Cash paid for income taxes
 
4,012

 
23,413

Cash received for income tax refunds
 
5

 
173

Non-cash investing activities:
 
 
 
 
Increase in accrued capital expenditures
 
235,431

 
69,767

Asset retirement obligation additions and revisions, net
 
6,232

 
5,043


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 income under the caption “Gain (loss) 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 forecasted 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, the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price, and 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.
The Company’s derivative contracts are settled based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX West Texas Intermediate (“WTI”) pricing or Inter-Continental Exchange (“ICE”) pricing for Brent crude oil and natural gas derivative settlements 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, volatility, the risk-free interest rate, and the time to expiration. The calculation of the fair value of collars requires the use of an option-pricing model. See Note 5. Fair Value Measurements.

7

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

At September 30, 2014, the Company had outstanding derivative contracts as set forth in the tables below. Subsequent to September 30, 2014, the Company settled substantially all of its outstanding crude oil derivative contracts prior to their contractual maturities as discussed below under the heading Derivative liquidations.
 
 
 
 
 
 
Collars
Crude Oil - NYMEX WTI - as of September 30, 2014

Swaps Weighted Average
Price

Floors

Ceilings
 

 


 

Weighted Average
Price

 

Weighted Average
Price
Period and Type of Contract

Bbls


Range


Range

October 2014 - December 2014












Swaps - WTI

3,335,000


$
96.22









January 2015 - December 2015














Collars - WTI

4,380,000




$
87.00


$
87.00


$95.85 - $103.75

$
98.36



 

 

Collars
Crude Oil - ICE Brent - as of September 30, 2014
Swaps Weighted Average Price

Floors

Ceilings
 

 


 

Weighted Average
Price

 

Weighted Average
Price
Period and Type of Contract

Bbls


Range


Range

October 2014 - December 2014












Swaps - ICE Brent

4,508,000


$
103.29









Collars - ICE Brent

552,000




$90.00 - $95.00


$
90.83


$104.70 - $108.85


$
107.13

January 2015 - December 2015












Swaps - ICE Brent

24,637,500


$
100.85









Collars - ICE Brent

730,000




$
95.00


$
95.00


$
107.40


$
107.40

January 2016 - December 2016

















Collars - ICE Brent
 
1,464,000

 
 
 
$
90.00

 
$
90.00

 
$
107.70

 
$
107.70

Natural Gas - Henry Hub - as of September 30, 2014

Collars


Swaps Weighted Average Price

Floors

Ceilings







Weighted Average Price



Weighted Average Price
Period and Type of Contract

MMBtus


Range


Range

October 2014 - December 2014












Swaps - Henry Hub

30,820,000


$
4.20











January 2015 - December 2015












Swaps - Henry Hub

24,500,000


$
4.27











Collars - Henry Hub

29,200,000




$3.50 - $3.75

$
3.69


$4.89 - $5.48

$
5.04

January 2016 - December 2016












Swaps - Henry Hub

4,550,000


$
4.27












Derivative liquidations
In October 2014, following a decrease in crude oil commodity prices and related increase in the fair value of derivative assets, substantially all of the Company's crude oil derivative contracts outstanding as of September 30, 2014 were settled prior to the expiration of their contractual maturities, resulting in the receipt of cash proceeds totaling approximately $433 million which will be reflected in fourth quarter results. No natural gas derivative contracts in place as of September 30, 2014 were liquidated in October 2014.

8

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

The tables below set forth the Company's remaining crude oil derivative contracts in place as of October 31, 2014 after settlement of matured October 2014 contracts and the liquidations referred to above.
Crude Oil - NYMEX WTI - as of October 31, 2014
 
Ceilings
 
 
 
 
 
 
Weighted Average
Price
Period and Type of Contract
 
Bbls
 
Range
 
January 2015 - December 2015
 
 
 
 
 
 
Written call options - WTI (1)
 
4,380,000

 
$95.85 - $103.75
 
$
98.36

Crude Oil - ICE Brent - as of October 31, 2014
 
Floors
 
Ceilings
 
 
 
 
 
 
Weighted Average
Price
 
 
 
Weighted Average
Price
Period and Type of Contract
 
Bbls
 
Range
 
 
Range
 
November 2014 - December 2014
 
 
 
 
 
 
 
 
 
 
Collars - ICE Brent
 
366,000

 
$90.00 - $95.00
 
$
90.83

 
$104.70 - $108.85

 
$
107.13

January 2015 - December 2015
 
 
 
 
 
 
 
 
 
 
Written call options - ICE Brent (1)
 
730,000

 
 
 
 
 
$
107.40

 
$
107.40

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

 
 
 
 
 
$
107.70

 
$
107.70

(1)
The written call options represent the ceiling positions remaining from the Company's crude oil collar contracts. The floor positions of the collars were liquidated. 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, and neither party is required to make a payment to the other party if the settlement price for any settlement period is below the ceiling price.

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
 
2014
 
2013
 
2014
 
2013
Cash received (paid) on derivatives:
 
 
 
 
 
 
 
 
Crude oil fixed price swaps
 
$
(4,126
)
 
$
(39,298
)
 
$
(77,148
)
 
$
(46,810
)
Crude oil collars
 
(233
)
 
(15,081
)
 
(2,270
)
 
(14,701
)
Natural gas fixed price swaps
 
4,549

 
14,030

 
(17,799
)
 
9,601

Cash received (paid) on derivatives, net
 
190

 
(40,349
)
 
(97,217
)
 
(51,910
)
Non-cash gain (loss) on derivatives:
 
 
 
 
 
 
 
 
Crude oil fixed price swaps
 
416,637

 
(146,782
)
 
228,845

 
(38,234
)
Crude oil collars
 
27,386

 
(13,243
)
 
28,300

 
(11,037
)
Natural gas fixed price swaps
 
25,851

 
(3,400
)
 
7,944

 
11,633

Natural gas collars
 
3,935

 

 
3,929

 

Non-cash gain (loss) on derivatives, net
 
473,809

 
(163,425
)
 
269,018

 
(37,638
)
Gain (loss) on derivative instruments, net
 
$
473,999

 
$
(203,774
)
 
$
171,801

 
$
(89,548
)
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.

9

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

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, 2014
 
December 31, 2013
Commodity derivative assets:
 
 
 
 
Gross amounts of recognized assets
 
$
174,478

 
$
4,213

Gross amounts offset on balance sheet
 
(208
)
 
(597
)
Net amounts of assets on balance sheet
 
174,270

 
3,616

Commodity derivative liabilities:
 
 
 
 
Gross amounts of recognized liabilities
 

 
(125,709
)
Gross amounts offset on balance sheet
 

 
27,345

Net amounts of liabilities on balance sheet
 
$

 
$
(98,364
)
 
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, 2014
 
December 31, 2013
Derivative assets
 
$
143,268

 
$
3,616

Noncurrent derivative assets
 
31,002

 

Net amounts of assets on balance sheet
 
174,270

 
3,616

Derivative liabilities
 

 
(90,535
)
Noncurrent derivative liabilities
 

 
(7,829
)
Net amounts of liabilities on balance sheet
 

 
(98,364
)
Total derivative assets (liabilities), net (1)
 
$
174,270

 
$
(94,748
)
(1) As discussed above, subsequent to September 30, 2014 the Company settled substantially all of its outstanding crude oil derivative contracts prior to their contractual maturities. As of October 31, 2014, the fair value of the Company's remaining derivative contracts was a net asset of approximately $20 million, representing a net asset of $27 million associated with natural gas derivatives partially offset by a net liability of $7 million associated with remaining crude oil derivatives.

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.

10

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

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 collar contracts requires the use of an industry-standard option pricing model that considers various inputs including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. These assumptions are observable in the marketplace or can be corroborated by active markets or broker quotes and are therefore designated as Level 2 within the valuation hierarchy. The Company’s calculation of fair value for each of its derivative positions is compared to the counterparty valuation for reasonableness.
The following tables summarize the valuation of financial instruments by pricing levels that were accounted for at fair value on a recurring basis as of September 30, 2014 and December 31, 2013. 
 
 
Fair value measurements at September 30, 2014 using:
 
 
In thousands
 
Level 1
 
Level 2
 
Level 3
 
Total
Derivative assets (liabilities):
 
 
 
 
 
 
 
 
Fixed price swaps
 
$

 
$
151,896

 
$

 
$
151,896

Collars
 

 
22,374

 

 
22,374

Total
 
$

 
$
174,270

 
$

 
$
174,270

 
 
 
 
 
 
 
 
 
 
 
Fair value measurements at December 31, 2013 using:
 
 
In thousands
 
Level 1
 
Level 2
 
Level 3
 
Total
Derivative assets (liabilities):
 
 
 
 
 
 
 
 
Fixed price swaps
 
$

 
$
(84,893
)
 
$

 
$
(84,893
)
Collars
 

 
(9,855
)
 

 
(9,855
)
Total
 
$

 
$
(94,748
)
 
$

 
$
(94,748
)
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, or when events and circumstances indicate a possible decline in the recoverability of the carrying value of such field. 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 management’s estimates of future crude oil and natural gas production, commodity prices based on commodity futures price strips, operating and development 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 swap prices through 2018 (adjusted for differentials), escalating 3% per year thereafter
Operating and development 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,

11

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

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 periods ended September 30, 2014 and September 30, 2013, 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 $38.0 million and $69.3 million for the three and nine months ended September 30, 2014, respectively, which primarily reflect 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. Impairment provisions for proved properties totaled $39.6 million for the nine months ended September 30, 2013, which were recognized in the second quarter of that period and primarily reflected uneconomic results for certain wells drilled in the Niobrara play in Colorado and Wyoming. Those impaired properties were written down to their estimated fair value totaling approximately $22.2 million as of September 30, 2013.
Certain unproved crude oil and natural gas properties were impaired during the three and nine months ended September 30, 2014 and 2013, reflecting recurring amortization of undeveloped leasehold costs on properties that management expects will not be transferred to proved properties over the lives of the leases based on 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 income.
 
 
Three months ended September 30,
 
Nine months ended September 30,
In thousands
 
2014
 
2013
 
2014
 
2013
Proved property impairments
 
$
38,046

 
$

 
$
69,337

 
$
39,635

Unproved property impairments
 
47,515

 
42,167

 
153,748

 
122,325

Total
 
$
85,561

 
$
42,167

 
$
223,085

 
$
161,960

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, 2014
 
December 31, 2013
In thousands
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Debt:
 
 
Credit facility
 
$

 
$

 
$
275,000

 
$
275,000

Note payable
 
16,967

 
15,186

 
18,470

 
16,500

8.25% Senior Notes due 2019 (1)
 

 

 
298,305

 
327,800

7.375% Senior Notes due 2020
 
198,809

 
220,940

 
198,695

 
223,700

7.125% Senior Notes due 2021
 
400,000

 
443,240

 
400,000

 
450,300

5% Senior Notes due 2022
 
2,023,568

 
2,106,000

 
2,025,362

 
2,063,300

4.5% Senior Notes due 2023
 
1,500,000

 
1,560,000

 
1,500,000

 
1,519,400

3.8% Senior Notes due 2024
 
996,548

 
1,003,900

 

 

4.9% Senior Notes due 2044
 
698,030

 
728,350

 

 

Total debt
 
$
5,833,922

 
$
6,077,616

 
$
4,715,832

 
$
4,876,000

(1) These senior notes were redeemed in July 2014. See Note 6. Long-Term Debt for further discussion.
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.

12

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

The fair values of the 8.25% Senior Notes due 2019 (“2019 Notes”), 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.
Note 6. Long-Term Debt
Long-term debt consists of the following at September 30, 2014 and December 31, 2013: 
In thousands
 
September 30, 2014
 
December 31, 2013
Credit facility
 
$

 
$
275,000

Note payable
 
16,967

 
18,470

8.25% Senior Notes due 2019 (1)
 

 
298,305

7.375% Senior Notes due 2020 (2)
 
198,809

 
198,695

7.125% Senior Notes due 2021 (3)
 
400,000

 
400,000

5% Senior Notes due 2022 (4)
 
2,023,568

 
2,025,362

4.5% Senior Notes due 2023 (3)
 
1,500,000

 
1,500,000

3.8% Senior Notes due 2024 (5)
 
996,548

 

4.9% Senior Notes due 2044 (6)
 
698,030

 

Total debt
 
5,833,922

 
4,715,832

Less: Current portion of long-term debt
 
(2,062
)
 
(2,011
)
Long-term debt, net of current portion
 
$
5,831,860

 
$
4,713,821

 
(1)
The carrying amount is net of an unamortized discount of $1.7 million at December 31, 2013. The 2019 Notes were redeemed in July 2014 as discussed further below.
(2)
The carrying amount is net of unamortized discounts of $1.2 million and $1.3 million at September 30, 2014 and December 31, 2013, respectively.
(3)
These notes were sold at par and are recorded at 100% of face value.
(4)
The carrying amount includes an unamortized premium of $23.6 million and $25.4 million at September 30, 2014 and December 31, 2013, respectively. 
(5)
The carrying amount is net of an unamortized discount of $3.5 million at September 30, 2014.
(6)
The carrying amount is net of an unamortized discount of $2.0 million at September 30, 2014.
Credit Facility
The Company has an unsecured credit facility, maturing on May 16, 2019, with aggregate commitments totaling $1.75 billion, which may be increased up to $4.0 billion upon agreement between the Company and participating lenders. The Company had no outstanding borrowings and approximately $1.75 billion of unused commitments on its credit facility at September 30, 2014. Borrowings under the credit facility 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 Company incurs commitment fees based on currently assigned credit ratings of 0.225% per annum of the daily average amount of unused borrowing availability.
The credit facility contains certain restrictive covenants including a requirement that the Company maintain a net debt to 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. The Company was in compliance with this covenant at September 30, 2014.
Senior Notes
On May 19, 2014, the Company issued $1.0 billion of new 3.8% Senior Notes due 2024 and $700 million of new 4.9% Senior Notes due 2044 and received total net proceeds of approximately $1.68 billion after deducting the initial purchasers' fees. The Company used a portion of the net proceeds from the offerings to repay all borrowings then outstanding under its credit facility, which had a balance prior to payoff of $1.01 billion, and to finance the redemption of its 2019 Notes as discussed

13

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

below. The remaining net proceeds are being used to fund a portion of the Company's 2014 capital program and for general corporate purposes.
On July 11, 2014, the Company redeemed its 2019 Notes using a portion of the proceeds from its 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 includes 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 income for the three and nine months ended September 30, 2014.
The following table summarizes the maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding senior note obligations at September 30, 2014.
 
  
2020 Notes
  
2021 Notes
  
2022 Notes
 
2023 Notes
 
2024 Notes
 
2044 Notes
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, Sept. 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
Equity offering redemption period (3)
  
  
  
March 15, 2015
 
 
 

(1)
On or after these dates, the Company has the option to redeem all or a portion of its senior notes 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 at the “make-whole” redemption prices or amounts specified in the Indentures plus any accrued and unpaid interest to the date of redemption.
(3)
At any time prior to this date, the Company may redeem up to 35% of the principal amount of its 2022 Notes under certain circumstances with the net cash proceeds from one or more equity offerings at the redemption price specified in the indenture for the 2022 Notes 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 others, limit the Company's ability to create liens securing certain indebtedness, enter into certain sale-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, 2014. 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, 2014.
Note 7. Commitments and Contingencies
Included below is a discussion of various future commitments of the Company as of September 30, 2014. The commitments under these arrangements are not recorded in the accompanying condensed consolidated balance sheets.
Drilling commitments – As of September 30, 2014, the Company had drilling rig contracts with various terms extending through July 2018. 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 key strategic plays. Future commitments as of September 30, 2014

14

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

total approximately $675 million, of which $66 million is expected to be incurred in the remainder of 2014, $246 million in 2015, $213 million in 2016, $122 million in 2017, and $28 million in 2018.
Pipeline transportation commitments – The Company has entered into firm transportation commitments to guarantee pipeline access capacity on operational crude oil and natural gas pipelines in order to reduce the impact of possible production curtailments that may arise due to limited transportation capacity. The commitments, which have varying terms extending as far as 2025, require the Company to pay per-unit transportation charges regardless of the amount of pipeline capacity used. Future commitments remaining as of September 30, 2014 under the operational pipeline transportation arrangements amount to approximately $1.0 billion, of which $40 million is expected to be incurred in the remainder of 2014, $181 million in 2015, $186 million in 2016, $180 million in 2017, $175 million in 2018, and $241 million thereafter.
Further, the Company is a party to an additional firm transportation commitment 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. Future commitments under the non-operational arrangement total approximately $260 million at September 30, 2014. This commitment represents aggregate transportation charges expected to be incurred over the five year term beginning when the proposed pipeline project is completed and becomes operational. The exact timing of the commencement of pipeline operations is not known due to uncertainties involving matters such as regulatory approvals, resolution of legal and environmental disputes, construction progress, and the ultimate probability of pipeline completion. Accordingly, the timing of the Company’s obligations under this non-operational arrangement cannot be predicted with certainty and may not be incurred on a ratable basis over a calendar year or may not be incurred at all.
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.
Cost sharing commitment – The Company has entered into an arrangement to share certain costs associated with a local utility company's construction and installation of electrical infrastructure that will provide service to parts of North Dakota where the Company operates. This arrangement extends through January 2016 and requires the Company to make scheduled periodic payments based on the projected total cost of the project and the progress of construction. Future commitments under the arrangement as of September 30, 2014 total approximately $13 million, of which $3 million is expected to be incurred in the remainder of 2014, $8 million in 2015, and $2 million in 2016.
Litigation – In November 2010, an alleged class action was filed against the Company alleging the Company improperly deducted post-production costs from royalties paid to plaintiffs and other royalty interest owners as categorized in the petition from crude oil and natural gas wells located in Oklahoma. The plaintiffs have 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 alleged class. The Company has responded to the petition, denied the allegations and raised a number of affirmative defenses. Discovery is ongoing and information and documents continue to be exchanged. 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. The class has not been certified. Plaintiffs have indicated that if the class is certified they may seek damages in excess of $165 million 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 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, 2014 and December 31, 2013, the Company had recorded a liability in the condensed consolidated balance sheets under the caption “Other noncurrent liabilities” of $2.9 million and $1.7 million, respectively, for various matters, none of which are believed to be individually significant.
Environmental risk – Due to the nature of the crude oil and natural gas business, the Company is exposed to possible environmental risks. The Company is not aware of any material environmental issues or claims.

15

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

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 income, is reflected in the table below for the periods presented.
 
 
 
Three months ended September 30,
 
Nine months ended September 30,
In thousands
 
2014
 
2013
 
2014
 
2013
Non-cash equity compensation
 
$
13,402

 
$
10,462

 
$
39,419

 
$
29,460

In May 2013, the Company adopted the 2013 Plan and reserved a maximum of 19,680,072 shares of common stock (adjusted for stock split) 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, 2014, the Company had a maximum of 18,220,078 shares of restricted stock (adjusted for stock split) available to grant to officers, directors and select 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, 2014 is presented below. Share amounts and related grant-date fair values have been retroactively adjusted to reflect the Company's 2-for-1 stock split occurring in September 2014.
 
 
Number of
non-vested
shares
 
Weighted
average
grant-date
fair value
Non-vested restricted shares outstanding at December 31, 2013
 
2,714,312

 
$
37.50

Granted
 
1,251,264

 
61.69

Vested
 
(365,498
)
 
36.53

Forfeited
 
(404,900
)
 
44.04

Non-vested restricted shares outstanding at September 30, 2014
 
3,195,178

 
$
46.25

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, 2014 at the vesting date was approximately $23.6 million. As of September 30, 2014, there was approximately $78 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 1.3 years.


16



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, 2013. 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, 2013, 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 exploration and production company with properties 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.
Our operations are geographically concentrated in the North region, with that region comprising approximately 74% of our crude oil and natural gas production and approximately 83% of our crude oil and natural gas revenues for the nine months ended September 30, 2014. Our principal producing properties in the North region are located in the Bakken field of North Dakota and Montana. The remainder of our crude oil and natural gas production and revenue is derived from the South region, primarily from producing properties in the SCOOP play in south-central Oklahoma.
We derive the majority of our operating income and cash flows from the sale of crude oil and natural gas. We focus our exploration activities in large new or developing crude oil and liquids-rich natural gas plays that provide us the opportunity to acquire undeveloped acreage positions for future drilling operations. We have been successful in targeting large repeatable resource plays where three dimensional seismic, horizontal drilling, geosteering technologies, advanced completion technologies (e.g., fracture stimulation) and enhanced recovery technologies provide the means to economically develop and produce crude oil and natural gas reserves from unconventional formations. We expect growth in our revenues and operating income will primarily depend on commodity prices and our ability to increase our reserves and related crude oil and natural gas production.
2014 Highlights
Production, revenues and operating cash flows
For the third quarter of 2014, our crude oil and natural gas production averaged 182,335 Boe per day, representing a 9% increase over average daily production of 167,953 Boe per day for the second quarter of 2014 and a 29% increase over average daily production of 141,873 Boe per day for the third quarter of 2013. Crude oil and natural gas production averaged 167,696 Boe per day for the nine months ended September 30, 2014, a 26% increase over average daily production of 133,110 Boe per day for the comparable 2013 period. Crude oil represented 70% of our total production for both the three and nine months ended September 30, 2014, compared to 71% for both the three and nine months ended September 30, 2013.
The increase in 2014 production was primarily driven by higher production from our properties in the Bakken field and SCOOP play due to the continued success of our drilling programs in those areas.
Our total Bakken production averaged 121,604 Boe per day for the third quarter of 2014, a 12% increase over the second quarter of 2014 and 29% higher than the third quarter of 2013. Total Bakken production averaged 109,300 Boe per day for the nine months ended September 30, 2014, a 26% increase over the nine months ended September 30, 2013.
Production in the SCOOP play averaged 36,346 Boe per day for the third quarter of 2014, a 6% increase over the second quarter of 2014 and 81% higher than the third quarter of 2013. SCOOP production averaged 33,350 Boe per day for the nine months ended September 30, 2014, an increase of 93% over the nine months ended September 30, 2013.
Crude oil and natural gas revenues for the third quarter of 2014 increased 15% to $1.16 billion due to a 30% increase in sales volumes partially offset by an 11% decrease in realized commodity prices when compared to the third quarter of 2013. For the nine months ended September 30, 2014, crude oil and natural gas revenues totaled $3.30 billion, a 24% increase from

17



the comparable 2013 period due to a 25% increase in sales volumes partially offset by a 1% decrease in realized commodity prices. Crude oil represented 87% and 85% of our total crude oil and natural gas revenues for the three and nine months ended September 30, 2014, respectively, compared to 89% for both the three and nine months ended September 30, 2013. The decreased percentage of crude oil revenues resulted from a significant increase in SCOOP revenues as a percentage of our total revenues over the past year. Our properties in SCOOP produce a higher concentration of liquids-rich natural gas compared to certain other operating areas such as the Bakken.
Cash flows from operating activities for the nine months ended September 30, 2014 were $2.28 billion, a 15% increase from $1.98 billion provided by our operating activities during the comparable 2013 period. The increased operating cash flows in 2014 were primarily due to higher crude oil and natural gas revenues driven by higher sales volumes, partially offset by an increase in cash losses on matured derivatives and higher production expenses, production taxes, general and administrative expenses, interest expense and other expenses associated with the growth of our operations over the past year.
Capital expenditures
Our capital expenditures budget for 2014 is $4.55 billion, excluding acquisitions. For the nine months ended September 30, 2014, we invested approximately $3.42 billion in our capital program, excluding $179.8 million of unbudgeted acquisitions. Our 2014 capital program is focused primarily on increased exploration and development in the Bakken field and the SCOOP play.     
Stock split
On August 18, 2014, our Board of Directors declared a 2-for-1 stock split of our common stock to be effected in the form of a stock dividend. The stock dividend was distributed on September 10, 2014 to shareholders of record as of September 3, 2014. All previously reported common stock and earnings per share amounts have been retroactively adjusted throughout this report to reflect the stock split.
Redemption of senior notes
On June 3, 2014, we announced our intention to redeem our $300 million of 8.25% Senior Notes due 2019. The 2019 Notes were fully redeemed on July 11, 2014 for $317.5 million. We recognized a pre-tax loss of $24.5 million related to the redemption, which is reflected under the caption “Loss on extinguishment of debt" in the unaudited condensed consolidated statements of income for the three and nine months ended September 30, 2014.
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).

18



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,
 
 
2014
 
2013
 
2014
 
2013
Average daily production:
 

 

 

 

Crude oil (Bbl per day)
 
127,788

 
100,684

 
116,954

 
94,315

Natural gas (Mcf per day)
 
327,287

 
247,135

 
304,453

 
232,769

Crude oil equivalents (Boe per day)
 
182,335

 
141,873

 
167,696

 
133,110

Average sales prices:
 
 
 
 
 
 
 
 
Crude oil ($/Bbl)
 
$
85.49

 
$
98.02

 
$
89.02

 
$
91.89

Natural gas ($/Mcf)
 
$
5.10

 
$
4.84

 
$
5.80

 
$
4.78

Crude oil equivalents ($/Boe)
 
$
69.08

 
$
77.86

 
$
72.52

 
$
73.46

Crude oil sales price differential to NYMEX ($/Bbl)
 
$
(11.77
)
 
$
(7.80
)
 
$
(10.60
)
 
$
(6.51
)
Natural gas sales price premium to NYMEX ($/Mcf)
 
$
1.04

 
$
1.26

 
$
1.28

 
$
1.09

Production expenses ($/Boe)
 
$
5.80

 
$
5.17

 
$
5.69

 
$
5.57

Production taxes (% of oil and gas revenues)
 
8.3
%
 
8.3
%
 
8.1
%
 
8.3
%
DD&A ($/Boe)
 
$
21.65

 
$
18.87

 
$
21.17

 
$
19.13

General and administrative expenses ($/Boe)
 
$
1.82

 
$
1.81

 
$
2.08

 
$
2.00

Non-cash equity compensation ($/Boe)
 
$
0.80

 
$
0.81

 
$
0.87

 
$
0.81

Net income (in thousands)
 
$
533,521

 
$
167,498

 
$
863,293

 
$
631,395

Diluted net income per share
 
$
1.44

 
$
0.45

 
$
2.33

 
$
1.71

EBITDAX (in thousands) (1)
 
$
947,635

 
$
797,575

 
$
2,590,980

 
$
2,127,211

 
(1)
EBITDAX represents 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 subsequently under the heading Non-GAAP Financial Measures.

19



Three months ended September 30, 2014 compared to the three months ended September 30, 2013
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
 
2014
 
2013
Crude oil and natural gas sales
 
$
1,160,281

 
$
1,009,836

Gain (loss) on derivative instruments, net
 
473,999

 
(203,774
)
Crude oil and natural gas service operations
 
11,048

 
8,825

Total revenues
 
1,645,328

 
814,887

Operating costs and expenses
 
(700,431
)
 
(486,844
)
Other expenses, net (1)
 
(98,036
)
 
(62,172
)
Income before income taxes
 
846,861

 
265,871

Provision for income taxes
 
(313,340
)
 
(98,373
)
Net income
 
$
533,521

 
$
167,498

Production volumes:
 
 
 
 
Crude oil (MBbl) (2)
 
11,756

 
9,263

Natural gas (MMcf)
 
30,110

 
22,736

Crude oil equivalents (MBoe)
 
16,775

 
13,052

Sales volumes:
 
 
 
 
Crude oil (MBbl) (2)
 
11,777

 
9,180

Natural gas (MMcf)
 
30,110

 
22,736

Crude oil equivalents (MBoe)
 
16,796

 
12,969

Average sales prices: (3)
 
 
 
 
Crude oil ($/Bbl)
 
$
85.49

 
$
98.02

Natural gas ($/Mcf)
 
5.10

 
4.84

Crude oil equivalents ($/Boe)
 
69.08

 
77.86

(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.
(2)
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. Crude oil sales volumes were 21 MBbls more than crude oil production for the three months ended September 30, 2014 and 83 MBbls less than crude oil production for the three months ended September 30, 2013.
(3)
Average sales prices have been calculated using sales volumes and exclude any effect of derivative transactions.
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
 
 
2014
 
2013
 
 
 
 
Volume
 
Percent
 
Volume
 
Percent
 
Crude oil (MBbl)
 
11,756

 
70
%
 
9,263

 
71
%
 
2,493

 
27
%
Natural gas (MMcf)
 
30,110

 
30
%
 
22,736

 
29
%
 
7,374

 
32
%
Total (MBoe)
 
16,775

 
100
%
 
13,052

 
100
%
 
3,723

 
29
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three months ended September 30,
 
Volume
increase
 
Volume
percent
increase
 
 
2014
 
2013
 
 
 
 
MBoe
 
Percent
 
MBoe
 
Percent
 
North Region
 
12,519

 
75
%
 
10,084

 
77
%
 
2,435

 
24
%
South Region
 
4,256

 
25
%
 
2,968

 
23
%
 
1,288

 
43
%
Total
 
16,775

 
100
%
 
13,052

 
100
%
 
3,723

 
29
%

20



Crude oil production volumes increased 2,493 MBbls, or 27%, for the three months ended September 30, 2014 compared to the three months ended September 30, 2013. Production increases in the Bakken field and SCOOP play contributed incremental production volumes in the 2014 third quarter of 2,587 MBbls, a 33% increase over production in these areas for the third quarter of 2013. Production growth in these areas is primarily due to increased drilling and completion activity resulting from our drilling program.
Natural gas production volumes increased 7,374 MMcf, or 32%, during the three months ended September 30, 2014 compared to the same period in 2013. Natural gas production in the Bakken field increased 1,832 MMcf, or 22%, for the three months ended September 30, 2014 compared to the same period in 2013 due to new wells being completed and gas from existing wells being connected to natural gas processing plants in the play. Natural gas production in the SCOOP play increased 6,592 MMcf, or 84%, due to additional wells being completed and producing in the three months ended September 30, 2014 compared to the same period in 2013. These increases were partially offset by decreases in production from various areas in our North and South regions due to a combination of natural declines in production and reduced drilling activity.
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 three months ended September 30, 2014 were $1,160.3 million, a 15% increase from sales of $1,009.8 million for the same period in 2013. Our sales volumes increased 3,827 MBoe, or 30%, over the comparable period in 2013 primarily due to the success of our drilling programs in the Bakken field and SCOOP play.
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. Crude oil sales volumes were 21 MBbls more than crude oil production for the three months ended September 30, 2014. An increase in crude oil line fill requirements and related reduction in sales volumes in the 2014 third quarter associated with new pipelines put into service was more than offset by the sale of crude oil during the quarter that was temporarily stored in inventory at June 30, 2014.
Our realized sales price per Boe decreased $8.78 to $69.08 for the three months ended September 30, 2014 from $77.86 for the three months ended September 30, 2013. This decrease primarily reflects lower prices realized in connection with reduced market prices for crude oil compared to the prior year.
The differential between NYMEX West Texas Intermediate ("WTI") calendar month average crude oil prices and our realized crude oil sales price per barrel for the third quarter of 2014 was $11.77 compared to $7.80 for the third quarter of 2013. We expect volatility in crude oil prices and differentials to continue.
Derivatives. We have entered into a number of derivative contracts, including fixed price swaps and zero-cost collars, to reduce the uncertainty of future cash flows in order to underpin our capital expenditures and drilling program. We are required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the changes in fair value in the unaudited condensed consolidated statements of income under the caption “Gain (loss) on derivative instruments, net”, which is a component of total revenues.
Subsequent to September 30, 2014, substantially all of our crude oil derivative contracts were settled prior to the expiration of their contractual maturities. See Note 4. Derivative Instruments in Notes to Unaudited Condensed Consolidated Financial Statements for further discussion including a summary of remaining derivative contracts in place as of October 31, 2014.
Changes in commodity prices during the third quarter of 2014 had a positive impact on the fair value of our derivatives, which resulted in positive revenue adjustments of $474.0 million for the three months ended September 30, 2014. We expect our revenues may continue to be impacted, either positively or negatively, by changes in the fair value of our derivative instruments as a result of volatility in commodity prices.



21



The following table presents the impact on total revenues related to 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,
In thousands
 
2014

2013
Cash received (paid) on derivatives:
 

 

Crude oil derivatives
 
$
(4,359
)
 
$
(54,379
)
Natural gas derivatives
 
4,549

 
14,030

Cash received (paid) on derivatives, net
 
190

 
(40,349
)
Non-cash gain (loss) on derivatives:
 

 

Crude oil derivatives
 
444,023

 
(160,025
)
Natural gas derivatives
 
29,786

 
(3,400
)
Non-cash gain (loss) on derivatives, net
 
473,809

 
(163,425
)
Gain (loss) on derivative instruments, net
 
$
473,999

 
$
(203,774
)
Operating Costs and Expenses
Production Expenses and Production Taxes and Other Expenses. Production expenses increased 45% to $97.4 million for the three months ended September 30, 2014 from $67.0 million for the three months ended September 30, 2013. This increase was primarily the result of an increase in the number of producing wells. Production expense per Boe was $5.80 for the three months ended September 30, 2014 compared to $5.17 per Boe for the three months ended September 30, 2013.
Production taxes and other expenses increased $13.1 million, or 16%, to $97.4 million for the three months ended September 30, 2014 compared to $84.3 million for the three months ended September 30, 2013 primarily as a result of higher crude oil and natural gas revenues resulting from increased sales volumes. Production taxes as a percentage of crude oil and natural gas revenues were 8.3% for both the three months ended September 30, 2014 and 2013. Production taxes are generally based on t