CLR FY2013 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, 2013
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
185,754,905 shares of our $0.01 par value common stock were outstanding on November 1, 2013.




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 gas” Refers to natural gas that remains in a gaseous state in the reservoir and does not produce large quantities of liquid hydrocarbons when brought to the surface. Also may refer to gas that has been processed or treated to remove all natural gas liquids.
“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.
“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.
“hydraulic fracturing” A process involving the high pressure injection of water, sand and additives into rock formations to stimulate crude oil and natural gas production.
“injection well” A well into which liquids or gases are injected in order to “push” additional crude oil or natural gas out of underground reservoirs and into the wellbores of producing wells. Typically considered an enhanced recovery process.
“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.

i



“MMcf” One million cubic feet of natural gas.
“net acres” The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has a 50% interest in 100 acres owns 50 net acres.
“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 multi-stage fracturing 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 emerging 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, our Annual Report on Form 10-K for the year ended December 31, 2012, 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 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 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, environmental risks, drilling and other operating risks, 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, our Annual Report on Form 10-K for the year ended December 31, 2012, 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, 2013
 
December 31, 2012
In thousands, except par values and share data
 
(Unaudited)
 
 
Assets
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
91,507

 
$
35,729

Receivables:
 
 
 
 
Crude oil and natural gas sales
 
644,401

 
468,650

Affiliated parties
 
16,923

 
12,410

Joint interest and other, net
 
356,897

 
356,111

Derivative assets
 
17,380

 
18,389

Inventories
 
55,272

 
46,743

Deferred and prepaid taxes
 
21,514

 
365

Prepaid expenses and other
 
9,287

 
8,386

Total current assets
 
1,213,181

 
946,783

Net property and equipment, based on successful efforts method of accounting
 
10,112,506

 
8,105,269

Net debt issuance costs and other
 
72,424

 
55,726

Noncurrent derivative assets
 
22,177

 
32,231

Total assets
 
$
11,420,288

 
$
9,140,009

 
 
 
 
 
Liabilities and shareholders’ equity
 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable trade
 
$
906,688

 
$
687,310

Revenues and royalties payable
 
310,137

 
261,856

Payables to affiliated parties
 
8,341

 
6,069

Accrued liabilities and other
 
197,264

 
153,454

Derivative liabilities
 
41,590

 
12,999

Current portion of asset retirement obligations
 
2,054

 
2,227

Current portion of long-term debt
 
1,997

 
1,950

Total current liabilities
 
1,468,071

 
1,125,865

Long-term debt, net of current portion
 
4,439,825

 
3,537,771

Other noncurrent liabilities:
 
 
 
 
Deferred income tax liabilities
 
1,641,589

 
1,262,576

Asset retirement obligations, net of current portion
 
47,667

 
44,944

Noncurrent derivative liabilities
 
157

 
2,173

Other noncurrent liabilities
 
2,366

 
2,981

Total other noncurrent liabilities
 
1,691,779

 
1,312,674

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; 185,665,535 shares issued and outstanding at September 30, 2013; 185,604,681 shares issued and outstanding at December 31, 2012
 
1,857

 
1,856

Additional paid-in capital
 
1,252,353

 
1,226,835

Retained earnings
 
2,566,403

 
1,935,008

Total shareholders’ equity
 
3,820,613

 
3,163,699

Total liabilities and shareholders’ equity
 
$
11,420,288

 
$
9,140,009



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
 
2013
 
2012
 
2013
 
2012
Revenues
 
 
 
 
 
 
 
 
Crude oil and natural gas sales
 
$
988,956

 
$
617,934

 
$
2,616,126

 
$
1,664,438

Crude oil and natural gas sales to affiliates
 
29,828

 
15,410

 
78,362

 
44,557

Gain (loss) on derivative instruments, net
 
(203,774
)
 
(158,294
)
 
(89,548
)
 
144,377

Crude oil and natural gas service operations
 
8,825

 
8,679

 
29,876

 
30,176

Total revenues
 
823,835

 
483,729

 
2,634,816

 
1,883,548

 
 
 
 
 
 
 
 
 
Operating costs and expenses
 
 
 
 
 
 
 
 
Production expenses
 
66,790

 
53,952

 
201,250

 
137,447

Production and other expenses to affiliates
 
1,422

 
1,454

 
4,574

 
3,950

Production taxes and other expenses
 
92,120

 
61,717

 
244,428

 
159,524

Exploration expenses
 
8,173

 
4,899

 
29,138

 
17,752

Crude oil and natural gas service operations
 
6,654

 
7,626

 
22,567

 
24,723

Depreciation, depletion, amortization and accretion
 
244,721

 
189,374

 
695,189

 
499,847

Property impairments
 
42,167

 
27,375

 
161,960

 
93,153

General and administrative expenses
 
34,070

 
31,925

 
103,761

 
86,704

Gain on sale of assets, net
 
(325
)
 
(115
)
 
(112
)
 
(67,139
)
Total operating costs and expenses
 
495,792

 
378,207

 
1,462,755

 
955,961

Income from operations
 
328,043

 
105,522

 
1,172,061

 
927,587

Other income (expense):
 
 
 
 
 
 
 
 
Interest expense
 
(62,756
)
 
(39,205
)
 
(171,609
)
 
(95,174
)
Other
 
584

 
710

 
1,765

 
2,280


 
(62,172
)
 
(38,495
)
 
(169,844
)
 
(92,894
)
Income before income taxes
 
265,871

 
67,027

 
1,002,217

 
834,693

Provision for income taxes
 
98,373

 
22,931

 
370,822

 
315,819

Net income
 
$
167,498

 
$
44,096

 
$
631,395

 
$
518,874

Basic net income per share
 
$
0.91

 
$
0.24

 
$
3.43

 
$
2.88

Diluted net income per share
 
$
0.91

 
$
0.24

 
$
3.42

 
$
2.86



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, 2012
 
185,604,681

 
$
1,856

 
$
1,226,835

 
$
1,935,008

 
$
3,163,699

Net income (unaudited)
 

 

 

 
631,395

 
631,395

Stock-based compensation (unaudited)
 

 

 
29,460

 

 
29,460

Restricted stock:
 
 
 
 
 
 
 
 
 
 
Issued (unaudited)
 
166,200

 
2

 

 

 
2

Repurchased and canceled (unaudited)
 
(46,222
)
 

 
(3,942
)
 

 
(3,942
)
Forfeited (unaudited)
 
(59,124
)
 
(1
)
 

 

 
(1
)
Balance at September 30, 2013
 
185,665,535

 
$
1,857

 
$
1,252,353

 
$
2,566,403

 
$
3,820,613



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
 
2013
 
2012
Cash flows from operating activities
 
 
Net income
 
$
631,395

 
$
518,874

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
Depreciation, depletion, amortization and accretion
 
694,729

 
500,359

Property impairments
 
161,960

 
93,153

Change in fair value of derivatives
 
37,638

 
(192,752
)
Stock-based compensation
 
29,460

 
20,804

Provision for deferred income taxes
 
360,599

 
323,543

Dry hole costs
 
9,180

 
319

Gain on sale of assets, net
 
(112
)
 
(67,139
)
Other, net
 
4,308

 
3,604

Changes in assets and liabilities:
 
 
 
 
Accounts receivable
 
(178,171
)
 
(112,316
)
Inventories
 
(8,529
)
 
(6,285
)
Prepaid expenses and other
 
(11,118
)
 
(5,080
)
Accounts payable trade
 
151,266

 
(26,918
)
Revenues and royalties payable
 
46,611

 
49,499

Accrued liabilities and other
 
41,791

 
48,240

Other noncurrent assets and liabilities
 
7,446

 
(8
)
Net cash provided by operating activities
 
1,978,453

 
1,147,897

 
 
 
 
 
Cash flows from investing activities
 
 
 
 
Exploration and development
 
(2,767,448
)
 
(2,584,434
)
Purchase of producing crude oil and natural gas properties
 
(12,404
)
 
(62,519
)
Purchase of other property and equipment
 
(41,942
)
 
(45,472
)
Proceeds from sale of assets and other
 
22,406

 
101,298

Net cash used in investing activities
 
(2,799,388
)
 
(2,591,127
)
 
 
 
 
 
Cash flows from financing activities
 
 
 
 
Revolving credit facility borrowings
 
470,000

 
1,524,000

Repayment of revolving credit facility
 
(1,065,000
)
 
(1,882,000
)
Proceeds from issuance of Senior Notes
 
1,479,375

 
1,999,000

Proceeds from other debt
 

 
22,000

Repayment of other debt
 
(1,457
)
 
(1,101
)
Debt issuance costs
 
(2,263
)
 
(7,117
)
Repurchase of equity grants
 
(3,942
)
 
(5,711
)
Exercise of stock options
 

 
60

Net cash provided by financing activities
 
876,713

 
1,649,131

Net change in cash and cash equivalents
 
55,778

 
205,901

Cash and cash equivalents at beginning of period
 
35,729

 
53,544

Cash and cash equivalents at end of period
 
$
91,507

 
$
259,445



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
Description of the Company
Continental’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 the South Central Oklahoma Oil Province (“SCOOP”), Northwest Cana, and Arkoma Woodford plays in Oklahoma. The East region is comprised of undeveloped leasehold acreage east of the Mississippi River. In December 2012, the Company sold its producing properties in the East region. The sold properties represented an immaterial portion of the Company’s operations and do not materially affect the comparability of the financial statements for the periods presented in this report.
The Company’s operations are geographically concentrated in the North region, with that region comprising approximately 77% of the Company’s crude oil and natural gas production and approximately 87% of its crude oil and natural gas revenues for the nine months ended September 30, 2013. The Company has focused its operations on the exploration and development of crude oil since the 1980s. For the nine months ended September 30, 2013 crude oil accounted for approximately 71% of the Company’s total production and approximately 88% 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 Continental and its 100% owned subsidiaries after all significant intercompany accounts and transactions have been eliminated upon consolidation.
This report has been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”) applicable to interim financial information. Because this is an interim period filing presented using a condensed format, it does not include all disclosures required by accounting principles generally accepted in the United States (“U.S. GAAP”), although the Company believes the disclosures are adequate to make the information not misleading. You should read this Form 10-Q together with the Company’s Annual Report on Form 10-K for the year ended December 31, 2012 (“2012 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, 2013 and for the three and nine month periods ended September 30, 2013 and 2012 are unaudited. The condensed consolidated balance sheet as of December 31, 2012 was derived from the audited balance sheet included in the 2012 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 could 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.
Inventories
Inventories are stated at the lower of cost or market and consist of the following: 

5


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


In thousands
 
September 30, 2013
 
December 31, 2012
Tubular goods and equipment
 
$
11,579

 
$
13,590

Crude oil
 
43,693

 
33,153

Total
 
$
55,272

 
$
46,743


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, 2013
 
December 31, 2012
Crude oil line fill requirements
 
405

 
391

Temporarily stored crude oil
 
263

 
211

Total
 
668

 
602

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 and stock options, which are calculated using the treasury stock method as if the awards and options were exercised. 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, 2013 and 2012. All stock options issued by the Company in prior periods had been exercised or had expired as of March 31, 2012.
 
 
Three months ended September 30,
 
Nine months ended September 30,
In thousands, except per share data
 
2013
 
2012
 
2013
 
2012
Income (numerator):
 
 
 
 
 
 
 
 
Net income - basic and diluted
 
$
167,498

 
$
44,096

 
$
631,395

 
$
518,874

Weighted average shares (denominator):
 
 
 
 
 
 
 
 
Weighted average shares - basic
 
184,069

 
181,909

 
184,036

 
180,471

Non-vested restricted stock
 
811

 
628

 
742

 
624

Stock options
 

 

 

 
21

Weighted average shares - diluted
 
184,880

 
182,537

 
184,778

 
181,116

Net income per share:
 
 
 
 
 
 
 
 
Basic
 
$
0.91

 
$
0.24

 
$
3.43

 
$
2.88

Diluted
 
$
0.91

 
$
0.24

 
$
3.42

 
$
2.86

Adoption of new accounting standard
In December 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-11, Balance Sheet (Topic 210)–Disclosures about Offsetting Assets and Liabilities. The new standard requires an entity to disclose information about offsetting arrangements to enable financial statement users to understand the effect of netting arrangements on an entity’s financial position. The disclosures are required for recognized financial instruments and derivative instruments that are subject to offsetting or are subject to master netting arrangements irrespective of whether they are offset. The disclosure requirements became effective for periods beginning on or after January 1, 2013 and must be applied retrospectively to all periods presented on the balance sheet. The Company adopted the provisions of the new standard on January 1, 2013 and has included the required disclosures in Note 4. Derivative Instruments. Adoption of the new standard required additional footnote disclosures for the Company's derivative instruments and did not have an impact on its financial position, results of operations 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. 

6


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


 
 
Nine months ended September 30,
In thousands
 
2013
 
2012
Supplemental cash flow information:
 
 
 
 
Cash paid for interest
 
$
139,023

 
$
67,638

Cash paid for income taxes
 
23,413

 
759

Cash received for income tax refunds
 
(173
)
 
(72
)
Non-cash investing activities:
 
 
 
 
Increase in accrued capital expenditures
 
69,767

 
4,521

Acquisition of assets through issuance of common stock
 

 
176,563

Asset retirement obligations, net
 
5,043

 
4,910


Note 4. Derivative Instruments
The Company is required to recognize 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 has utilized 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.
At September 30, 2013, the Company had outstanding derivative contracts with respect to future production as set forth in the tables below. In August 2013, the Company settled its 2013 natural gas derivative contracts prior to their contractual maturities scheduled for September 2013 through December 2013 and recognized $11.0 million of gains upon settlement. As of September 30, 2013, no natural gas derivative contracts remain in place for the remainder of 2013.
 
 
 
 
 
 
Collars
Crude Oil - NYMEX WTI
 
 
 
Swaps Weighted Average
Price
 
Floors
 
Ceilings
 
 
 
 
 
 
 
Weighted Average
Price
 
 
 
Weighted Average
Price
Period and Type of Contract
 
Bbls
 
 
Range
 
 
Range
 
October 2013 - December 2013
 
 
 
 
 
 
 
 
 
 
 
 
Swaps - WTI
 
3,910,000

 
$
96.00

 
 
 
 
 
 
 
 
Collars - WTI
 
2,208,000

 
 
 
$80.00 - $95.00
 
$
86.92

 
$92.30 - $110.33
 
$
99.46

January 2014 - March 2014
 
 
 
 
 
 
 
 
 
 
 
 
Swaps - WTI
 
3,082,500

 
$
97.26

 
 
 
 
 
 
 
 
April 2014 - December 2014
 
 
 
 
 
 
 
 
 
 
 
 
Swaps - WTI
 
7,768,750

 
$
96.20

 
 
 
 
 
 
 
 

7


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


 
 
 
 
 
 
Collars
Crude Oil - ICE Brent
 
 
 
Swaps Weighted Average Price
 
Floors
 
Ceilings
 
 
 
 
 
 
 
Weighted Average
Price
 
 
 
Weighted Average
Price
Period and Type of Contract
 
Bbls
 
 
Range
 
 
Range
 
October 2013 - December 2013
 
 
 
 
 
 
 
 
 
 
 
 
Swaps - ICE Brent
 
1,426,000

 
$
108.21

 
 
 
 
 
 
 
 
January 2014 - March 2014
 
 
 
 
 
 
 
 
 
 
 
 
Swaps - ICE Brent
 
3,555,000

 
$
102.63

 
 
 
 
 
 
 
 
Collars - ICE Brent
 
540,000

 
 
 
$90.00 - $95.00
 
$
90.83

 
$104.70 - $108.85
 
$
107.13

April 2014 - December 2014
 
 
 
 
 
 
 
 
 
 
 
 
Swaps - ICE Brent
 
10,312,500

 
$
102.52

 
 
 
 
 
 
 
 
Collars - ICE Brent
 
1,650,000

 
 
 
$90.00 - $95.00
 
$
90.83

 
$104.70 - $108.85
 
$
107.13

January 2015 - December 2015
 
 
 
 
 
 
 
 
 
 
 
 
Swaps - ICE Brent
 
2,007,500

 
$
98.12

 
 
 
 
 
 
 
 
Natural Gas - NYMEX Henry Hub
 
Swaps Weighted Average Price
 
 
 
 
Period and Type of Contract
 
MMBtus
 
January 2014 - March 2014
 
 
 
 
Swaps - Henry Hub
 
14,400,000

 
$
4.30

April 2014 - June 2014
 
 
 
 
Swaps - Henry Hub
 
10,010,000

 
$
4.14

July 2014 - December 2014
 
 
 
 
Swaps - Henry Hub
 
23,920,000

 
$
4.12

January 2015 - March 2015
 
 
 
 
Swaps - Henry Hub
 
1,800,000

 
$
4.27


Derivative gains and losses
The following table presents cash settlements and non-cash gains and losses on derivative instruments for the periods presented. 
 
 
Three months ended September 30,
 
Nine months ended September 30,
In thousands
 
2013
 
2012
 
2013
 
2012
Cash received (paid) on derivatives:
 
 
 
 
 
 
 
 
Crude oil fixed price swaps
 
$
(39,298
)
 
$
(4,571
)
 
$
(46,810
)
 
$
(42,362
)
Crude oil collars
 
(15,081
)
 
(372
)
 
(14,701
)
 
(15,340
)
Natural gas fixed price swaps (1)
 
14,030

 
3,549

 
9,601

 
9,327

Cash paid on derivatives, net
 
$
(40,349
)
 
$
(1,394
)
 
$
(51,910
)
 
$
(48,375
)
Non-cash gain (loss) on derivatives:
 
 
 
 
 
 
 
 
Crude oil fixed price swaps
 
$
(146,782
)
 
$
(106,412
)
 
$
(38,234
)
 
$
142,135

Crude oil collars
 
(13,243
)
 
(40,997
)
 
(11,037
)
 
58,113

Natural gas fixed price swaps
 
(3,400
)
 
(9,491
)
 
11,633

 
(7,496
)
Non-cash gain (loss) on derivatives, net
 
$
(163,425
)
 
$
(156,900
)
 
$
(37,638
)
 
$
192,752

Gain (loss) on derivative instruments, net
 
$
(203,774
)
 
$
(158,294
)
 
$
(89,548
)
 
$
144,377

(1) Cash gains on natural gas swaps for both the three and nine month periods ended September 30, 2013 include $11.0 million of gains related to 2013 natural gas derivative contracts that were settled in August 2013 prior to their contractual maturities scheduled for September 2013 through December 2013.


8


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


Balance sheet offsetting of derivative assets and liabilities
In December 2011, the FASB issued ASU No. 2011-11, Balance Sheet (Topic 210)–Disclosures about Offsetting Assets and Liabilities, which requires an entity to disclose information about offsetting arrangements to enable financial statement users to understand the effect of netting arrangements on an entity’s financial position. The Company adopted the provisions of the new standard on January 1, 2013 as required and has provided the applicable disclosures below with respect to its derivative instruments.
All of the Company’s derivative contracts are carried at their fair value in the condensed consolidated balance sheets under the captions “Derivative assets”, “Noncurrent derivative assets”, “Derivative liabilities”, and “Noncurrent derivative liabilities”. Derivative assets and liabilities with the same counterparty that are subject to contractual terms which provide for net settlement are reported on a net basis in the condensed consolidated balance sheets.
The following tables present 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. 
 
 
September 30, 2013
 
December 31, 2012
In thousands
 
Gross amounts of recognized assets
 
Gross amounts offset on balance sheet         
 
Net amounts of assets on balance sheet
 
Gross amounts of recognized assets
 
Gross amounts offset on balance sheet         
 
Net amounts of assets on balance sheet
Commodity derivative assets
 
$
47,031

 
$
(7,474
)
 
$
39,557

 
$
86,506

 
$
(35,886
)
 
$
50,620

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
September 30, 2013
 
December 31, 2012
In thousands
 
Gross amounts of recognized liabilities
 
Gross amounts offset on balance sheet         
 
Net amounts of liabilities on balance sheet
 
Gross amounts of recognized liabilities
 
Gross amounts offset on balance sheet         
 
Net amounts of liabilities on balance sheet
Commodity derivative liabilities
 
$
(68,802
)
 
$
27,055

 
$
(41,747
)
 
$
(16,241
)
 
$
1,069

 
$
(15,172
)
 
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, 2013
 
December 31, 2012
Derivative assets
 
$
17,380

 
$
18,389

Noncurrent derivative assets
 
22,177

 
32,231

Net amounts of assets on balance sheet
 
$
39,557

 
$
50,620

Derivative liabilities
 
$
(41,590
)
 
$
(12,999
)
Noncurrent derivative liabilities
 
(157
)
 
(2,173
)
Net amounts of liabilities on balance sheet
 
$
(41,747
)
 
$
(15,172
)
Total derivative assets (liabilities), net
 
$
(2,190
)
 
$
35,448


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.

9


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


A financial instrument’s categorization within the hierarchy is based upon the lowest level of input that is significant to the fair value measurement. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the hierarchy. As Level 1 inputs generally provide the most reliable evidence of fair value, the Company uses Level 1 inputs when available. The Company’s policy is to recognize transfers between the hierarchy levels as of the beginning of the reporting period in which the event or change in circumstances caused the transfer.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Certain assets and liabilities are reported at fair value on a recurring basis, including the Company’s derivative instruments. 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, 2013 and December 31, 2012. 
 
 
Fair value measurements at September 30, 2013 using:
 
 
In thousands
 
Level 1
 
Level 2
 
Level 3
 
Total
Description
 

Derivative assets (liabilities):
 
 
 
 
 
 
 
 
Fixed price swaps
 
$

 
$
10,115

 
$

 
$
10,115

Collars
 

 
(12,305
)
 

 
(12,305
)
Total
 
$

 
$
(2,190
)
 
$

 
$
(2,190
)
 
 
 
 
 
 
 
 
 
 
 
Fair value measurements at December 31, 2012 using:
 
 
In thousands
 
Level 1
 
Level 2
 
Level 3
 
Total
Description
 

Derivative assets (liabilities):
 
 
 
 
 
 
 
 
Fixed price swaps
 
$

 
$
36,716

 
$

 
$
36,716

Collars
 

 
(1,268
)
 

 
(1,268
)
Total
 
$

 
$
35,448

 
$

 
$
35,448

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. 

10


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


Unobservable Input
  
Assumption
Future production
  
Future production estimates for each property
Forward commodity prices
  
Forward NYMEX swap prices through 2017 (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, 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 nine months ended September 30, 2013 and 2012, 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 $39.6 million for the nine months ended September 30, 2013, all of which was recognized in the second quarter. Such impairments primarily reflected uneconomic results for certain wells drilled on the Company's acreage in the Niobrara play in Colorado and Wyoming. The impaired properties were written down to their estimated fair value totaling approximately $22.2 million. Impairment provisions for proved properties totaled $4.3 million for the nine months ended September 30, 2012, primarily reflecting uneconomic results in a non-Woodford single-well field in the Company's South region. Those impaired properties were written down to their estimated fair value totaling approximately $2.2 million.
Certain unproved crude oil and natural gas properties were impaired during the three and nine months ended September 30, 2013 and 2012, 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
 
2013
 
2012
 
2013
 
2012
Proved property impairments
 
$

 
$

 
$
39,635

 
$
4,332

Unproved property impairments
 
42,167

 
27,375

 
122,325

 
88,821

Total
 
$
42,167

 
$
27,375

 
$
161,960

 
$
93,153

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, 2013
 
December 31, 2012
In thousands
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Debt:
 
 
Revolving credit facility
 
$

 
$

 
$
595,000

 
$
595,000

Note payable
 
18,964

 
17,456

 
20,421

 
20,148

8 1/4% Senior Notes due 2019
 
298,248

 
329,800

 
298,085

 
339,000

7 3/8% Senior Notes due 2020
 
198,658

 
222,200

 
198,552

 
226,833

7 1/8% Senior Notes due 2021
 
400,000

 
447,300

 
400,000

 
454,333

5% Senior Notes due 2022
 
2,025,952

 
2,018,300

 
2,027,663

 
2,165,833

4 1/2% Senior Notes due 2023
 
1,500,000

 
1,475,000

 

 

Total debt
 
$
4,441,822

 
$
4,510,056

 
$
3,539,721

 
$
3,801,147


11


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


The fair value of any revolving credit facility borrowings approximates the carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy.
The fair value of the note payable is determined using a discounted cash flow approach based on the interest rate and payment terms of the note payable and an assumed discount rate. The fair value of the note payable is significantly influenced by the discount rate assumption, which is derived by the Company and is unobservable. Accordingly, the fair value of the note payable is classified as Level 3 in the fair value hierarchy.
The fair values of the 8 1/4% Senior Notes due 2019 (“2019 Notes”), the 7 3/8% Senior Notes due 2020 (“2020 Notes”), the 7 1/8% Senior Notes due 2021 (“2021 Notes”), the 5% Senior Notes due 2022 (“2022 Notes”), and the 4 1/2% Senior Notes due 2023 ("2023 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: 
In thousands
 
September 30, 2013
 
December 31, 2012
Revolving credit facility
 
$

 
$
595,000

Note payable
 
18,964

 
20,421

8 1/4% Senior Notes due 2019 (1)
 
298,248

 
298,085

7 3/8% Senior Notes due 2020 (2)
 
198,658

 
198,552

7 1/8% Senior Notes due 2021 (3)
 
400,000

 
400,000

5% Senior Notes due 2022 (4)
 
2,025,952

 
2,027,663

4 1/2% Senior Notes due 2023 (3)
 
1,500,000

 

Total debt
 
$
4,441,822

 
$
3,539,721

Less: Current portion of long-term debt
 
(1,997
)
 
(1,950
)
Long-term debt, net of current portion
 
$
4,439,825

 
$
3,537,771

 
(1)
The carrying amount is net of unamortized discounts of $1.8 million and $1.9 million at September 30, 2013 and December 31, 2012, respectively.
(2)
The carrying amount is net of unamortized discounts of $1.3 million and $1.4 million at September 30, 2013 and December 31, 2012, 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 $26.0 million and $27.7 million at September 30, 2013 and December 31, 2012, respectively. 
Revolving Credit Facility
The Company had no outstanding borrowings at September 30, 2013 on its credit facility, which matures on July 1, 2015. At December 31, 2012, the Company had $595.0 million of outstanding borrowings on its credit facility. The credit facility had aggregate commitments of $1.5 billion and a borrowing base of $4.25 billion at September 30, 2013, subject to semi-annual redetermination. The most recent borrowing base redetermination was completed in May 2013, whereby the lenders approved an increase in the Company’s borrowing base from $3.25 billion to $4.25 billion. The terms of the facility allow for the commitment level to be increased up to the lesser of the borrowing base then in effect or $2.5 billion. Borrowings under the facility bear interest at a rate per annum equal to the London Interbank Offered Rate ("LIBOR") for one, two, three or six months, as elected by the Company, plus a margin ranging from 150 to 250 basis points, depending on the percentage of the borrowing base utilized, or the lead bank’s reference rate (prime) plus a margin ranging from 50 to 150 basis points. At September 30, 2013, credit facility borrowings were required to be secured by the lesser of (i) crude oil and natural gas properties of the Company representing 80% of the Present Value, as defined in the amended credit facility, of such properties and (ii) such of the Company’s proved reserves and associated crude oil and natural gas properties sufficient to provide a Collateral Coverage Ratio, as defined in the amended credit facility, of at least 1.75 to 1.0.


12


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


The Company had approximately $1.5 billion of unused commitments under its credit facility at September 30, 2013 and incurs commitment fees of 0.375% 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 current ratio of not less than 1.0 to 1.0 and a ratio of total funded debt to EBITDAX of no greater than 4.0 to 1.0. As defined by the credit facility, the current ratio represents the ratio of current assets to current liabilities, inclusive of available borrowing capacity under the credit facility and exclusive of current balances associated with derivative contracts and asset retirement obligations. 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, and non-cash equity compensation expense. 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 in Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Non-GAAP Financial Measures. The total funded debt to EBITDAX ratio represents the sum of outstanding borrowings and letters of credit on the credit facility plus the Company’s note payable and senior note obligations, divided by total EBITDAX for the most recent four quarters. The Company was in compliance with these covenants at September 30, 2013.
Senior Notes
On April 5, 2013, the Company issued $1.5 billion of 4 1/2% Senior Notes due 2023 and received net proceeds of approximately $1.48 billion after deducting the initial purchasers’ fees. The Company used the net proceeds from the offering to repay all borrowings then outstanding under its credit facility, which had a balance prior to payoff of approximately $1.04 billion, to fund a portion of its 2013 capital budget, and for general corporate purposes.
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, 2013. 
 
 
2019 Notes
  
2020 Notes
  
2021 Notes
  
2022 Notes
 
2023 Notes
Maturity date
  
Oct 1, 2019
  
Oct 1, 2020
  
April 1, 2021
  
Sep 15, 2022
 
April 15, 2023
Interest payment dates
  
April 1, Oct. 1
  
April 1, Oct. 1
  
April 1, Oct. 1
  
March 15, Sept. 15
 
April 15, Oct. 15
Call premium redemption period (1)
  
Oct 1, 2014
  
Oct 1, 2015
  
April 1, 2016
  
March 15, 2017
 
n/a
Make-whole redemption period (2)
  
Oct 1, 2014
  
Oct 1, 2015
  
April 1, 2016
  
March 15, 2017
 
Jan 15, 2023
Equity offering redemption period (3)
  
  
  
April 1, 2014
  
March 15, 2015
 
n/a

(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 these dates, the Company may redeem up to 35% of the principal amount of its senior notes under certain circumstances with the net cash proceeds from one or more equity offerings at the redemption prices specified in the Indentures plus any accrued and unpaid interest to the date of redemption. The optional redemption periods for the 2019 Notes and 2020 Notes using equity offering proceeds expired on October 1, 2012 and October 1, 2013, respectively.
The Company’s senior notes are not subject to any mandatory redemption or sinking fund requirements.
The Indentures, excluding the indenture governing the 2023 Notes, contain certain restrictions on the Company’s ability to incur additional debt, pay dividends on common stock, make certain investments, create certain liens on assets, engage in certain transactions with affiliates, transfer or sell certain assets, consolidate or merge, or sell substantially all of the Company’s assets. The indenture governing the 2023 Notes is less restrictive and contains covenants that limit the Company's ability to create liens securing certain indebtedness and consolidate, merge or transfer certain assets. These covenants are subject to a number of important exceptions and qualifications. The Company was in compliance with these covenants at September 30, 2013. Two of the Company’s subsidiaries, Banner Pipeline Company, L.L.C. and CLR Asset Holdings, LLC, which have insignificant assets with no current value and no operations, fully and unconditionally guarantee the senior notes. The Company’s other subsidiary, 20 North Broadway Associates LLC, the value of whose assets and operations are minor, does not guarantee the senior notes.


13


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


Note Payable
In February 2012, 20 North 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 $2.0 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, 2013.
Note 7. Commitments and Contingencies
Included below is a discussion of various future commitments of the Company as of September 30, 2013. The commitments under these arrangements are not recorded in the accompanying condensed consolidated balance sheets.
Drilling commitments – As of September 30, 2013, the Company had drilling rig contracts with various terms extending through August 2014. 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, 2013 total approximately $53 million, of which $31 million is expected to be incurred in the remainder of 2013 and $22 million in 2014.
Pipeline transportation commitments – The Company has entered into firm transportation commitments to guarantee pipeline access capacity totaling 15,000 barrels of crude oil per day on operational crude oil pipelines in order to reduce the impact of possible production curtailments that may arise due to limited transportation capacity. The commitments, which have 5-year terms extending as far as November 2017, require the Company to pay varying per-barrel transportation charges regardless of the amount of pipeline capacity used. Future commitments remaining as of September 30, 2013 under the operational crude oil pipeline transportation arrangements amount to approximately $46 million, of which $3 million is expected to be incurred in the remainder of 2013, $14 million in 2014, $14 million in 2015, $10 million in 2016 and $5 million in 2017.
The Company has also entered into a commitment to guarantee pipeline access capacity on an operational natural gas pipeline system to move a portion of its North region natural gas production to market. The commitment, which has a 10-year term ending in October 2023, requires the Company to pay per-unit transportation charges regardless of the amount of pipeline capacity used. Future commitments under the arrangement amount to approximately $25 million, which is expected to be incurred ratably over its 10-year term.
Further, the Company is a party to additional 5-year firm transportation commitments for future pipeline projects being considered for development that are not yet operational. Such projects require the granting of regulatory approvals or otherwise require significant additional construction efforts by the counterparties before being completed. Future commitments under the non-operational arrangements total approximately $1.0 billion at September 30, 2013, including approximately $96 million with an affiliate controlled by the Company's Chairman of the Board, Chief Executive Officer and principal shareholder. These commitments represent aggregate transportation charges expected to be incurred over the 5-year terms of the arrangements assuming the proposed pipeline projects are completed and become operational. The 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 these non-operational arrangements 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. Although timing is uncertain, the Company’s obligations under these arrangements are not expected to begin until at least the second half of 2014.
Rail transportation commitments – The Company has entered into firm transportation commitments to guarantee capacity on rail transportation facilities in order to reduce the impact of possible curtailments that may arise due to limited transportation capacity. The rail commitments have various terms extending through December 2014 and require the Company to pay varying per-barrel transportation charges on volumes ranging from 2,500 to 10,000 barrels of crude oil per day regardless of the amount of rail capacity used. Future commitments remaining as of September 30, 2013 under the rail transportation arrangements amount to approximately $19 million, of which $9 million is expected to be incurred in the remainder of 2013 and $10 million in 2014.
The Company’s pipeline and rail transportation 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.

14


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


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, 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, 2013 and December 31, 2012, the Company had recorded a liability in the condensed consolidated balance sheets under the caption “Other noncurrent liabilities” of $1.7 million and $2.4 million, respectively, for various matters, none of which are believed to be individually significant.
Environmental risk – Due to the nature of the crude oil and natural gas business, the Company is exposed to possible environmental risks. The Company is not aware of any material environmental issues or claims.
Note 8. Stock-Based Compensation
The Company has granted restricted stock to employees and directors pursuant to the Continental Resources, Inc. 2005 Long-Term Incentive Plan (“2005 Plan”) and 2013 Long-Term Incentive Plan ("2013 Plan") as discussed below. The Company’s associated compensation expense, which is included in the caption “General and administrative expenses” in the unaudited condensed consolidated statements of income, is reflected in the table below for the periods presented.
 
 
 
Three months ended September 30,
 
Nine months ended September 30,
In thousands
 
2013
 
2012
 
2013
 
2012
Non-cash equity compensation
 
$
10,462

 
$
7,499

 
$
29,460

 
$
20,804

    
In May 2013, the Company's shareholders, upon recommendation by the Board of Directors, approved the adoption of the Company's 2013 Plan. The 2013 Plan is a broad-based incentive plan that allows the Company to use, if desired, a variety of equity compensation alternatives in structuring compensation arrangements for the Company's officers, directors and select employees. Effective May 23, 2013, 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.
    
The maximum number of shares of common stock available for issuance under the 2013 Plan is 9,840,036 shares, which includes (i) 7,500,000 new shares authorized under the 2013 Plan, (ii) 1,840,036 shares that remained available for issuance under the 2005 Plan as of March 27, 2013 that have been transferred from the 2005 Plan to the 2013 Plan, and (iii) up to 500,000 shares available for issuance under the 2013 Plan to the extent such shares are forfeited or withheld for payment of income taxes related to existing awards outstanding under the 2005 Plan. As of September 30, 2013, the Company had a maximum of 9,807,113 shares of restricted stock available to grant to officers, directors and key 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 stock shares outstanding for the nine months ended September 30, 2013 is presented below: 

15


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


 
 
Number of
non-vested
shares
 
Weighted
average
grant-date
fair value
Non-vested restricted shares outstanding at December 31, 2012
 
1,629,462

 
$
63.28

Granted
 
166,200

 
87.03

Vested
 
(147,440
)
 
60.27

Forfeited
 
(59,124
)
 
71.93

Non-vested restricted shares outstanding at September 30, 2013
 
1,589,098

 
$
68.35

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, 2013 at the vesting date was approximately $12.5 million. As of September 30, 2013, there was approximately $55 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized over a weighted average period of 1.4 years.
Note 9. 2012 Property Dispositions
In February 2012, the Company assigned certain non-strategic leaseholds and producing properties located in Wyoming to a third party for cash proceeds of $84.4 million. In connection with the transaction, the Company recognized a pre-tax gain of $50.1 million. The disposed properties comprised 3.2 MMBoe, or 1%, of the Company’s total proved reserves at December 31, 2011 and 259 MBoe, or 1%, of its 2011 total crude oil and natural gas production.
In June 2012, the Company assigned certain non-strategic leaseholds and producing properties located in Oklahoma to a third party for $15.9 million and recognized a pre-tax gain on the transaction of $15.9 million. The disposed properties represented an immaterial portion of the Company’s total proved reserves and production.
The gains on the above dispositions are included in the caption “Gain on sale of assets, net” in the unaudited condensed consolidated statements of income for the nine months ended September 30, 2012.



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, 2012. 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 under the heading 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, 2012, 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 the South Central Oklahoma Oil Province (“SCOOP”), Northwest Cana, and Arkoma Woodford plays in Oklahoma. The SCOOP and Northwest Cana plays were previously combined by us and referred to as the Anadarko Woodford play. The East region is comprised of undeveloped leasehold acreage east of the Mississippi River. In December 2012, we sold the producing properties in our East region. The sold properties represented an immaterial portion of our operations and do not materially affect the comparability of the operating results and cash flows for the periods presented in this report. Our operations are geographically concentrated in the North region, with that region comprising approximately 77% of our crude oil and natural gas production and approximately 87% of our crude oil and natural gas revenues for the nine months ended September 30, 2013.
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 horizontal drilling, advanced fracture stimulation and enhanced recovery technologies provide the means to economically develop and produce crude oil and natural gas reserves from unconventional formations.
We derive the majority of our operating income and cash flows from the sale of crude oil and natural gas. We expect growth in our revenues and operating income will primarily depend on commodity prices and our ability to increase our crude oil and natural gas production. In recent months and years, there has been significant volatility in crude oil and natural gas prices due to a variety of factors we cannot control or predict, including political and economic events, weather conditions, and competition from other energy sources. These factors impact supply and demand for crude oil and natural gas, which affect crude oil and natural gas prices. In addition, the prices we realize for our crude oil and natural gas production are affected by price differences in the markets where we deliver our production.
2013 Highlights
Production, revenues and operating cash flows
For the third quarter of 2013, our crude oil and natural gas production averaged 141,873 Boe per day, representing a 5% increase over average daily production of 135,700 Boe per day for the second quarter of 2013 and a 38% increase over average daily production of 102,964 Boe per day for the third quarter of 2012. Crude oil and natural gas production averaged 133,110 Boe per day for the nine months ended September 30, 2013, a 41% increase over average daily production of 94,478 Boe per day for the comparable 2012 period. Crude oil represented 71% of our total production for both the three and nine months ended September 30, 2013 compared to 70% for both the three and nine months ended September 30, 2012.
The increase in 2013 production was primarily driven by higher production from our properties in the North Dakota Bakken field and the SCOOP play due to the continued success of our drilling programs in those areas.
Our Bakken production in North Dakota averaged 75,394 Boe per day for the nine months ended September 30, 2013, a 56% increase over the same period in 2012. Third quarter 2013 average daily production in North Dakota Bakken averaged 81,545 Boe per day, a 6% increase over the second quarter of 2013 and 46% higher than the third quarter of 2012.
Production in the emerging SCOOP play averaged 17,308 Boe per day for the nine months ended September 30, 2013, 375% higher than the comparable period in 2012. Average daily production in the SCOOP totaled 20,070 Boe per day for the third quarter of 2013, an increase of 14% over the second quarter of 2013 and 293% higher than the third quarter of 2012.

17



Crude oil and natural gas revenues for the third quarter of 2013 increased 61% to $1.02 billion primarily due to a 34% increase in sales volumes along with a 20% increase in realized commodity prices when compared to the third quarter of 2012. For the nine months ended September 30, 2013, crude oil and natural gas revenues totaled $2.69 billion, a 58% increase from the comparable 2012 period due to a 40% increase in sales volumes along with a 12% increase in realized commodity prices. Crude oil represented 88% of our total crude oil and natural gas revenues for both the three and nine months ended September 30, 2013 compared to 89% for both the three and nine months ended September 30, 2012.
Cash flows from operating activities for the nine months ended September 30, 2013 were $1.98 billion, a 72% increase from $1.15 billion provided by our operating activities during the comparable 2012 period. The increase in operating cash flows in 2013 was primarily due to increased crude oil and natural gas revenues driven by higher sales volumes and higher realized commodity prices, partially offset by higher production expenses, production taxes, general and administrative expenses, and other expenses associated with the growth of our operations over the past year.
Capital expenditures
Our capital expenditures budget for 2013 is $3.60 billion, excluding acquisitions. For the nine months ended September 30, 2013, we invested approximately $2.71 billion in our capital program, excluding $196.9 million of unbudgeted acquisitions and including $11.6 million of seismic costs and $69.8 million of capital costs associated with increased accruals for capital expenditures. Capital expenditures for the third quarter of 2013 totaled $910.3 million, excluding $74.2 million of unbudgeted acquisitions. Our 2013 capital program is focused primarily on increased exploration and development in the Bakken field of North Dakota and Montana and the SCOOP play.
In September 2013, our Board of Directors approved a 2014 capital expenditures budget of $4.05 billion excluding acquisitions. Our 2014 capital program is expected to continue focusing on exploratory and development drilling in the Bakken field and the SCOOP play. We expect to continue participating as a buyer of properties if and when we have the ability to increase our position in strategic plays at favorable terms.
We economically hedge a portion of our anticipated future production to achieve more predictable cash flows and reduce our exposure to fluctuations in commodity prices. Reducing our exposure to price volatility helps ensure adequate funds are available for our capital program. We expect our cash flows from operations, our remaining cash balance, and our credit facility, including our ability to increase our borrowing capacity thereunder, will be sufficient to meet our budgeted capital expenditure needs for 2013 and 2014; however, we may choose to access the capital markets for additional financing to take advantage of business opportunities that may arise if such financing can be arranged at favorable terms.    
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 presents financial and operating highlights for the periods presented.
 
 
 
Three months ended September 30,
 
Nine months ended September 30,
 
 
2013
 
2012
 
2013
 
2012
Average daily production:
 

 

 

 

Crude oil (Bbl per day)
 
100,684

 
72,235

 
94,315

 
65,826

Natural gas (Mcf per day)
 
247,135

 
184,377

 
232,769

 
171,912

Crude oil equivalents (Boe per day)
 
141,873

 
102,964

 
133,110

 
94,478

Average sales prices: (1)
 

 

 

 

Crude oil ($/Bbl)
 
$
98.02

 
$
82.87

 
$
91.89

 
$
84.44

Natural gas ($/Mcf)
 
5.23

 
4.00

 
5.16

 
3.97

Crude oil equivalents ($/Boe)
 
78.55

 
65.62

 
74.13

 
66.06

Production expenses ($/Boe) (1)
 
5.17

 
5.62

 
5.57

 
5.34

General and administrative expenses ($/Boe) (1)
 
2.63

 
3.31

 
2.85

 
3.35

Net income (in thousands)
 
$
167,498

 
$
44,096

 
$
631,395

 
$
518,874

Diluted net income per share
 
$
0.91

 
$
0.24

 
$
3.42

 
$
2.86

EBITDAX (in thousands) (2)
 
797,575

 
492,279

 
2,127,211

 
1,368,671

 
(1)
Average sales prices and per unit expenses have been calculated using sales volumes and exclude any effect of derivative transactions.
(2)
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, and non-cash equity compensation expense. 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, 2013 compared to the three months ended September 30, 2012
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
 
2013
 
2012
Crude oil and natural gas sales
 
$
1,018,784

 
$
633,344

Loss on derivative instruments, net (1)
 
(203,774
)
 
(158,294
)
Crude oil and natural gas service operations
 
8,825

 
8,679

Total revenues
 
823,835

 
483,729

Operating costs and expenses
 
(495,792
)
 
(378,207
)
Other expenses, net
 
(62,172
)
 
(38,495
)
Income before income taxes
 
265,871

 
67,027

Provision for income taxes
 
(98,373
)
 
(22,931
)
Net income
 
$
167,498

 
$
44,096

Production volumes:
 

 

Crude oil (MBbl) (2)
 
9,263

 
6,645

Natural gas (MMcf)
 
22,736

 
16,963

Crude oil equivalents (MBoe)
 
13,052

 
9,472

Sales volumes:
 

 

Crude oil (MBbl) (2)
 
9,180

 
6,825

Natural gas (MMcf)
 
22,736

 
16,963

Crude oil equivalents (MBoe)
 
12,969

 
9,651

Average sales prices: (3)
 

 

Crude oil ($/Bbl)
 
$
98.02

 
$
82.87

Natural gas ($/Mcf)
 
5.23

 
4.00

Crude oil equivalents ($/Boe)
 
78.55

 
65.62

(1)
Amounts include non-cash mark-to-market losses on derivatives of $163.4 million and $156.9 million for the three months ended September 30, 2013 and 2012, respectively.
(2)
At various times we have stored crude oil due to pipeline line fill requirements, low commodity prices, or transportation constraints 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 83 MBbls less than crude oil production for the three months ended September 30, 2013 and 180 MBbls more than crude oil production for the three months ended September 30, 2012.
(3)
Average sales prices have been calculated using sales volumes and exclude any effect of derivative transactions.

20



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
 
 
2013
 
2012
 
 
 
 
Volume
 
Percent
 
Volume
 
Percent
 
Crude oil (MBbl)
 
9,263

 
71
%
 
6,645

 
70
%
 
2,618

 
39
%
Natural gas (MMcf)
 
22,736

 
29
%
 
16,963

 
30
%
 
5,773

 
34
%
Total (MBoe)
 
13,052

 
100
%
 
9,472

 
100
%
 
3,580

 
38
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three months ended September 30,
 
Volume
increase
(decrease)
 
Volume
percent
increase
(decrease)
 
 
2013
 
2012
 
 
 
 
MBoe
 
Percent
 
MBoe
 
Percent
 
North Region
 
10,084

 
77
%
 
7,241

 
76
%
 
2,843

 
39
%
South Region
 
2,968

 
23
%
 
2,130

 
23
%
 
838

 
39
%
East Region (1)
 

 

 
101

 
1
%
 
(101
)
 
(100
%)
Total
 
13,052

 
100
%
 
9,472

 
100
%
 
3,580

 
38
%
(1)
In December 2012, we sold the producing crude oil and natural gas properties in our East region and no new wells have been subsequently drilled in that region. Accordingly, no production is reflected for the East region for the three months ended September 30, 2013.
Crude oil production volumes increased 2,618 MBbls, or 39%, for the three months ended September 30, 2013 compared to the three months ended September 30, 2012. Production increases in the Bakken field and SCOOP play contributed incremental production volumes in 2013 of 2,794 MBbls, a 55% increase over production in these areas for the third quarter of 2012. Production growth in these areas is primarily due to increased drilling and completion activity resulting from our drilling program. These increases were partially offset by a decrease of 94 MBbls associated with non-strategic properties in the East region that were sold in December 2012. Additionally, production from our properties in the Red River units and Northwest Cana play decreased a total of 67 MBbls, or 5%, over the prior year third quarter due to a combination of natural declines in production and reduced drilling activity in those areas.
Natural gas production volumes increased 5,773 MMcf, or 34%, during the three months ended September 30, 2013 compared to the same period in 2012. Natural gas production in the Bakken field increased 3,365 MMcf, or 67%, for the three months ended September 30, 2013 compared to the same period in 2012 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 5,821 MMcf, or 294%, due to additional wells being completed and producing in the three months ended September 30, 2013 compared to the same period in 2012. These increases were partially offset by decreases in production volumes totaling 2,963 MMcf, or 33%, from our properties in Northwest Cana, Arkoma Woodford, and non-core areas in our South region due to a combination of natural declines in production and reduced drilling activity prompted by the pricing environment for natural gas in those areas. For 2013 and 2014, we are allocating a greater portion of our capital expenditures to crude oil and liquids-rich natural gas areas such as the Bakken field and SCOOP play. Additionally, natural gas production decreased 41 MMcf associated with non-strategic properties in the East region that were sold in December 2012.
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, 2013 were $1,018.8 million, a 61% increase from sales of $633.3 million for the same period in 2012. Our sales volumes increased 3,318 MBoe, or 34%, over the comparable period in 2012 primarily due to the success of our drilling programs in the Bakken field and SCOOP play.
Our realized price per Boe increased $12.93 to $78.55 for the three months ended September 30, 2013 from $65.62 for the three months ended September 30, 2012. This increase reflects an improvement in crude oil differentials realized in the 2013 third quarter compared to the 2012 third quarter along with higher crude oil and natural gas prices realized in connection with improved market prices.

21



The differential between NYMEX West Texas Intermediate ("WTI") calendar month average crude oil prices and our realized crude oil price per barrel for the three months ended September 30, 2013 decreased to $7.80 per barrel compared to $9.45 for the three months ended September 30, 2012 and $9.06 for the year ended December 31, 2012. The improved differential primarily reflects our concerted shift of Bakken crude oil sales to east, west, and gulf coast markets in the United States with less dependence on currently available pipeline markets. We continue to rely heavily on rail transportation for accessing U.S. coastal markets and expect this trend to continue for the remainder of 2013. Rail transportation costs are higher than pipeline costs, but market prices realized in U.S. coastal markets continue to be competitive with currently available pipeline markets. We plan to continue pursuing a portfolio approach, balancing volumes delivered to pipeline and rail market destinations in an effort to maximize net wellhead value.
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.
Changes in commodity futures price strips during the third quarter of 2013 had a negative impact on the fair value of our derivatives, which resulted in negative revenue adjustments of $203.8 million for the three months ended September 30, 2013. We expect our revenues will continue to be significantly impacted, either positively or negatively, by changes in the fair value of our derivative instruments as a result of volatility in crude oil and natural gas prices. The following table presents the impact on total revenues related to cash and non-cash gains and losses on derivative instruments for the periods presented. 
 
 
Three months ended September 30,
In thousands
 
2013

2012
Cash received (paid) on derivatives:
 

 

Crude oil derivatives
 
$
(54,379
)
 
$
(4,943
)
Natural gas derivatives (1)
 
14,030

 
3,549

Cash paid on derivatives, net
 
$
(40,349
)
 
$
(1,394
)
Non-cash gain (loss) on derivatives:
 

 

Crude oil derivatives
 
$
(160,025
)
 
$
(147,409
)
Natural gas derivatives
 
(3,400
)
 
$
(9,491
)
Non-cash loss on derivatives, net
 
$
(163,425
)
 
$
(156,900
)
Gain (loss) on derivative instruments, net
 
$
(203,774
)
 
$
(158,294
)
(1) Cash gains on natural gas derivatives for the three months ended September 30, 2013 include $11.0 million of gains related to 2013 natural gas derivative contracts that were settled in August 2013 prior to their contractual maturities scheduled for September 2013 through December 2013.
The non-cash mark-to-market losses reflected above at September 30, 2013 relate to derivative instruments with various terms that are scheduled to be realized over the period from October 2013 to December 2015. Over this period, actual derivative settlements may differ significantly, either positively or negatively, from the mark-to-market valuation at September 30, 2013.
Operating Costs and Expenses
Production Expenses and Production Taxes and Other Expenses. Production expenses increased 24% to $67.0 million during the three months ended September 30, 2013 from $54.2 million during the three months ended September 30, 2012. This increase was primarily the result of an increase in the number of producing wells. Production expense per Boe was $5.17 for the three months ended September 30, 2013 compared to $5.62 per Boe for the three months ended September 30, 2012. Higher production volumes and nonrecurring accrual changes associated with the increased number of producing wells generated lower costs realized on a per Boe basis.
Production taxes and other expenses increased $30.4 million, or 48%, to $93.3 million during the three months ended September 30, 2013 compared to $62.9 million for the three months ended September 30, 2012 primarily as a result of higher crude oil and natural gas revenues resulting from increased sales volumes and higher realized commodity prices. Production taxes and other expenses include charges for marketing, gathering, dehydration and compression fees primarily related to natural gas sales in the Oklahoma Woodford and North Dakota Bakken areas of $8.9 million for both the three months ended September 30, 2013 and 2012. Production taxes, excluding other charges, as a percentage of crude oil and natural gas revenues

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were 8.2% for the three months ended September 30, 2013 compared to 8.4% for the three months ended September 30, 2012. Production taxes are generally based on the wellhead values of production and vary by state. Some states offer exemptions or reduced production tax rates for wells that produce less than a certain quantity of crude oil or natural gas and to encourage certain activities, such as horizontal drilling and enhanced recovery projects. In Montana and Oklahoma, new horizontal wells qualify for a tax incentive and are taxed at a lower rate during their initial months of production. After the incentive period expires, the tax rate reverts to the statutory rate.
On a unit of sales basis, production expenses and production taxes and other expenses were as follows for the periods presented: 
 

Three months ended September 30,
$/Boe

2013

2012
Production expenses
 
$
5.17

 
$
5.62

Production taxes and other expenses
 
7.19

 
6.52

Production expenses, production taxes and other expenses
 
$
12.36

 
$
12.14

Exploration Expenses. Exploration expenses consist primarily of dry hole costs and exploratory geological and geophysical costs that are expensed as incurred. The following table shows the components of exploration expenses for the periods presented.
 

Three months ended September 30,
In thousands

2013

2012
Geological and geophysical costs
 
$
7,055

 
$
4,678

Dry hole costs
 
1,118

 
221

Exploration expenses
 
$
8,173

 
$
4,899

Geological and geophysical costs increased $2.4 million for the three months ended September 30, 2013 due to changes in the timing and amount of acquisitions of exploratory seismic data between periods. No significant dry holes were drilled during the three months ended September 30, 2013 and 2012.
Depreciation, Depletion, Amortization and Accretion (“DD&A”). Total DD&A increased $55.3 million, or 29%, to $244.7 million for the third quarter of 2013 compared to $189.4 million for the third quarter of 2012 primarily due to a 34% increase in sales volumes. The following table shows the components of our DD&A on a unit of sales basis. 
 

Three months ended September 30,
$/Boe

2013
 
2012
Crude oil and natural gas
 
$
18.58

 
$
19.30

Other equipment
 
0.24

 
0.24

Asset retirement obligation accretion
 
0.05

 
0.08

Depreciation, depletion, amortization and accretion
 
$
18.87

 
$
19.62

The decrease in DD&A per Boe is primarily the result of a decrease in average costs being incurred to drill operated wells in the Bakken field and SCOOP play in 2013 compared to 2012, coupled with an increase in proved reserves from extensions and discoveries resulting from our successful drilling results in those areas.
Property Impairments. Property impairments increased in the three months ended September 30, 2013 by $14.8 million to $42.2 million compared to $27.4 million for the three months ended September 30, 2012.
Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Individually insignificant non-producing properties are amortized on an aggregate basis based on our estimated experience of successful drilling and the average holding period. Impairments of non-producing properties increased $14.8 million during the three months ended September 30, 2013 to $42.2 million compared to $27.4 million for the three months ended September 30, 2012. The increase resulted from a larger base of amortizable costs in the current period coupled with higher rates of amortization resulting from changes in management's estimates of undeveloped properties not expected to be developed before lease expiration. We currently have no individually significant non-producing properties that are assessed for impairment on a property-by-property basis.
We evaluate proved crude oil and natural gas properties for impairment by comparing their cost basis to the estimated future cash flows on a field basis. If the cost basis is in excess of estimated future cash flows, then we impair it based on an estimate of fair value using discounted cash flows. No impairment provisions for proved properties were recognized for the

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three months ended September 30, 2013 and 2012. For those periods, future cash flows were determined to be in excess of the related cost basis, therefore no impairment was necessary.
General and Administrative Expenses. General and administrative expenses (“G&A”) increased $2.2 million, or 7%, to $34.1 million for the three months ended September 30, 2013 from $31.9 million for the comparable period in 2012. G&A expenses include non-cash charges for equity compensation of $10.5 million and $7.5 million for the three months ended September 30, 2013 and 2012, respectively. The increase in equity compensation in 2013 resulted primarily from additional grants of restricted stock being made throughout 2013 due to employee growth along with an increase in our grant-date stock prices, which resulted in increased expense recognition in the third quarter of 2013 compared to the third quarter of 2012.
The previously announced relocation of our corporate headquarters from Enid, Oklahoma to Oklahoma City was completed during 2012; however, residual costs continue to be incurred under the terms of the Company's relocation plan offered to employees. For the three months ended September 30, 2013, we recognized $0.1 million of costs associated with our relocation compared to $2.3 million for the three months ended September 30, 2012.
G&A expenses excluding equity compensation and relocation expenses increased $1.4 million for the three months ended September 30, 2013 compared to the same period in 2012. The increase was primarily due to an increase in personnel costs and office-related expenses associated with our rapid growth.
The following table shows the components of G&A expenses on a unit of sales basis for the periods presented.  The decrease in G&A expenses on a per-Boe basis in the 2013 third quarter was due to the rapid growth in our crude oil and natural gas sales volumes coupled with an increase in G&A overhead costs billed to and recouped from our joint interest partners over the prior year, which helped generate low