10-Q 1 kwk10-q20130630.htm 10-Q KWK 10-Q 2013.06.30
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
 
þ
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
For the quarterly period ended June 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: 001-14837
Quicksilver Resources Inc.
(Exact name of registrant as specified in its charter)
 
Delaware
 
75-2756163
(State or other jurisdiction of
 
(I.R.S. Employer Identification No.)
incorporation or organization)
 
 
 
 
 
801 Cherry Street, Suite 3700, Unit 19, Fort Worth, Texas
 
76102
(Address of principal executive offices)
 
(Zip Code)
(817) 665-5000
(Registrant’s telephone number, including area code)
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  þ  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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes  þ  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. (Check one):
    Large accelerated filer þ
 
Accelerated filer ¨
 
Non-accelerated filer ¨
 
Smaller reporting company ¨
 
 
 
 
(Do not check if a 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   þ
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:
 
Title of Class
  
Outstanding as of July 31, 2013
Common Stock, $0.01 par value
  
177,493,512 shares

 


DEFINITIONS
As used in this Quarterly Report unless the context otherwise requires:

“ABR” means alternate base rate
“AOCI” means accumulated other comprehensive income
“Bbl” or “Bbls” means barrel or barrels
“Bbld” means barrel or barrels per day
“Bcf” means billion cubic feet
“Bcfe” means Bcf of natural gas equivalents
“Canada” means our oil and natural gas operations located principally in British Columbia and Alberta, Canada
“C$” means Canadian dollars
“DD&A” means Depletion, Depreciation and Accretion
“GPT” means gathering, processing and transportation expense
“LIBOR” means London Interbank Offered Rate
“MBbl” or “MBbls” means thousand barrels
“MMBtu” means million British Thermal Units, a measure of heating value, and is approximately equal to one Mcf of natural gas
“Mcf” means thousand cubic feet
“Mcfe” means Mcf natural gas equivalent, calculated as one Bbl of oil or NGLs equaling six Mcf of gas
“MMcf” means million cubic feet
“MMcfd” means million cubic feet per day
“MMcfe” means MMcf of natural gas equivalent
“MMcfed” means MMcfe per day
“NGL” or “NGLs” means natural gas liquids
“NYMEX” means New York Mercantile Exchange
“OCI” means other comprehensive income
“Oil” includes crude oil and condensate
“PUD” means proved undeveloped reserve
“RSU” means restricted stock unit
“Tcfe” means trillion cubic feet of natural gas equivalents

COMMONLY USED TERMS
Other commonly used terms and abbreviations include:

“Amended and Restated Canadian Credit Facility” means our Canadian senior secured revolving credit facility, which was amended and restated as of December 22, 2011, and as further amended, restated, supplemented or otherwise modified from time to time
“Amended and Restated U.S. Credit Facility” means our U.S. senior secured revolving credit facility, which was amended and restated as of December 22, 2011, and as further amended, restated, supplemented or otherwise modified from time to time
“Barnett Shale Asset” means our operations and our assets in the Barnett Shale located in the Fort Worth basin of North Texas
“CMLP” means Crestwood Midstream Partners LP
“Combined Credit Agreements” means collectively our Amended and Restated U.S. Credit Facility and our Amended and Restated Canadian Credit Facility
“Crestwood” means Crestwood Holdings LLC
“Crestwood Transaction” means the sale to Crestwood of all our interests in KGS, including general partner interests and incentive distribution rights
“Eni” means either or both Eni Petroleum US LLC and Eni US Operating Co. Inc., which are subsidiaries of Eni SpA
“Fortune Creek” means Fortune Creek Gathering and Processing Partnership, a midstream partnership formed with KKR in December 2011 dedicated to the construction and operation of natural gas midstream services within the Horn River basin of northeast British Columbia
“GAAP” means accounting principles generally accepted in the U.S.
“Horn River Asset” means our operations and our assets in the Horn River basin of northeast British Columbia
“Horseshoe Canyon Asset” means our operations and our assets in Horseshoe Canyon, the coalbed methane fields of southern and central Alberta

2

“KGS” means Quicksilver Gas Services LP, a publicly-traded partnership, which we formerly owned that traded under the ticker symbol of “KGS” and subsequent to the Crestwood Transaction renamed itself Crestwood Midstream Partners LP and trades under the ticker symbol “CMLP”
“KKR” means Kohlberg Kravis Roberts & Co. L.P., with whom we formed Fortune Creek
“Komie North Project” means the series of contracts with NGTL for the construction of a pipeline and meter station, which will serve our and others’ transportation needs in the Horn River basin
“Mercury” means Mercury Exploration Company, which is owned by members of the Darden family
“NEB” means National Energy Board, an independent agency which regulates international and interprovincial aspects of the oil and gas industries in Canada and is accountable to Parliament through the Minister of Natural Resources Canada.
“NGTL” means NOVA Gas Transmission Ltd., a subsidiary of TransCanada PipeLines Limited
“Niobrara Asset” means our operations and our assets in the Niobrara formation in northwest Colorado, which we are jointly developing with SWEPI LP
“SEC” means the U.S. Securities and Exchange Commission
“Senior Secured Second Lien Credit Agreement” means our new senior secured term credit facility dated as of June 21, 2013
“Southern Alberta Asset” means our operations and our assets in the Southern Alberta basin of northern Wyoming and Montana, including our Cutbank field operations and assets
“SWEPI” means SWEPI LP, a subsidiary of Royal Dutch Shell plc
“Tokyo Gas Transaction” means the sale of an undivided 25% of our Barnett Shale Asset to TGBR
“TGBR” means TG Barnett Resources LP, a subsidiary of Tokyo Gas Co., Ltd.
“VIE” means variable interest entity
“West Texas Asset” means our operations and our assets in the Midland and Delaware basins in West Texas prospective in the Bone Springs and Wolfcamp formations, principally concentrated in three areas: Jeff Davis and Reeves Counties, Upton and Crockett Counties and Pecos County

3

INDEX TO QUARTERLY REPORT ON FORM 10-Q
For the Quarter Ended June 30, 2013
 

Except as otherwise specified and unless the context otherwise requires, references to the “Company,” “Quicksilver,” “we,” “us,” and “our” refer to Quicksilver Resources Inc. and its subsidiaries.

4

Forward-Looking Information
Certain statements contained in this Quarterly Report and other materials we file with the SEC, or in other written or oral statements made or to be made by us, other than statements of historical fact, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements give our current expectations or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:
•
changes in general economic conditions;
•
fluctuations in natural gas, NGL and oil prices;
•
failure or delays in achieving expected production from exploration and development projects;
•
our ability to achieve anticipated cost savings and other spending reductions;
•
uncertainties inherent in estimates of natural gas, NGL and oil reserves and predicting natural gas, NGL and oil production and reservoir performance;
•
effects of hedging natural gas, NGL and oil prices;
•
fluctuations in the value of certain of our assets and liabilities;
•
competitive conditions in our industry;
•
actions taken or non-performance by third parties, including suppliers, contractors, operators, processors, transporters, customers and counterparties;
•
changes in the availability and cost of capital;
•
delays in obtaining oilfield equipment and increases in drilling and other service costs;
•
delays in construction of transportation pipelines and gathering, processing and treating facilities;
•
operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;
•
the effects of existing and future laws and governmental regulations, including environmental and climate change requirements;
•
failure or delay in completing strategic transactions;
•
the effects of existing or future litigation; and
•
additional factors described elsewhere in this Quarterly Report.
This list of factors is not exhaustive, and new factors may emerge or changes to these factors may occur that would impact our business. Additional information regarding these and other factors may be contained in our filings with the SEC, especially on Forms 10-K, 10-Q and 8-K. All such risk factors are difficult to predict, and are subject to material uncertainties that may affect actual results and may be beyond our control. The forward-looking statements included in this Quarterly Report are made only as of the date of this Quarterly Report, and we undertake no obligation to update any of these forward-looking statements to reflect subsequent events or circumstances except to the extent required by applicable law.
All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements.

5

PART I    FINANCIAL INFORMATION

ITEM 1.
Condensed Consolidated Interim Financial Statements (Unaudited)

QUICKSILVER RESOURCES INC.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
In thousands, except for per share data – Unaudited
  
For the Three Months Ended
June 30,
 
For the Six Months Ended
June 30,
  
2013
 
2012 (1)
 
2013
 
2012 (1)
 
 
 
(Restated)
 
 
 
(Restated)
Revenue
 
 
 
 
 
 
 
Production
$
121,121

 
$
150,311

 
$
253,735

 
$
316,765

Sales of purchased natural gas
18,685

 
9,442

 
35,243

 
21,528

Net derivative gains (including realized loss of $3,476 and realized gains of $17,100; $6,120 and $22,682, respectively)
34,837

 
33,139

 
3,468

 
26,475

Other
854

 
1,126

 
1,755

 
2,116

Total revenue
175,497

 
194,018

 
294,201

 
366,884

Operating expense
 
 
 
 
 
 
 
Lease operating
20,213

 
21,599

 
45,108

 
50,290

Gathering, processing and transportation
36,674

 
42,624

 
76,498

 
85,701

Production and ad valorem taxes
5,300

 
7,189

 
10,784

 
13,952

Costs of purchased natural gas
18,679

 
9,337

 
35,197

 
21,274

Depletion, depreciation and accretion
15,265

 
48,016

 
33,521

 
102,455

Impairment
—

 
1,199,726

 
—

 
1,517,654

General and administrative
16,875

 
18,405

 
33,038

 
37,500

Other operating
769

 
134

 
2,205

 
152

Total expense
113,775

 
1,347,030

 
236,351

 
1,828,978

Tokyo Gas Transaction gain
333,172

 
—

 
333,172

 
—

Crestwood earn-out
—

 
—

 
—

 
41,097

Operating income (loss)
394,894

 
(1,153,012
)
 
391,022

 
(1,420,997
)
Other income (expense)
(15,105
)
 
65

 
(15,255
)
 
158

Fortune Creek accretion
(4,827
)
 
(4,830
)
 
(9,672
)
 
(9,571
)
Interest expense
(127,238
)
 
(40,076
)
 
(171,180
)
 
(80,246
)
Income (loss) before income taxes
247,724

 
(1,197,853
)
 
194,915

 
(1,510,656
)
Income tax (expense) benefit
(5,201
)
 
395,831

 
(12,097
)
 
497,069

Net income (loss)
$
242,523

 
$
(802,022
)
 
$
182,818

 
$
(1,013,587
)
Reclassification adjustments related to settlements of derivative contracts into production revenue- net of income tax
(11,287
)
 
(36,992
)
 
(26,042
)
 
(65,581
)
Net change in derivative fair value - net of income tax
—

 
10,923

 
—

 
72,210

Foreign currency translation adjustment
(3,580
)
 
(6,381
)
 
(3,278
)
 
(4,930
)
Other comprehensive income (loss)
(14,867
)
 
(32,450
)
 
(29,320
)
 
1,699

Comprehensive income (loss)
$
227,656

 
$
(834,472
)
 
$
153,498

 
$
(1,011,888
)
Earnings (loss) per common share - basic
$
1.37

 
$
(4.72
)
 
$
1.04

 
$
(5.96
)
Earnings (loss) per common share - diluted
$
1.37

 
$
(4.72
)
 
$
1.04

 
$
(5.96
)
(1) Note 1 contains additional information
The accompanying notes are an integral part of these condensed consolidated financial statements.

6

QUICKSILVER RESOURCES INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
In thousands, except for share data – Unaudited
 
 
June 30, 2013
 
December 31, 2012
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
96,793

 
$
4,951

Marketable securities
118,730

 
—

Total cash, cash equivalents and marketable securities
215,523

 
4,951

Accounts receivable - net of allowance for doubtful accounts
44,885

 
64,149

Derivative assets at fair value
70,009

 
113,367

Other current assets
25,090

 
25,046

Total current assets
355,507

 
207,513

Property, plant and equipment - net
 
 
 
Oil and gas properties, full cost method (including unevaluated costs of $281,875 and $307,267, respectively)
659,935

 
780,960

Other property and equipment
232,915

 
248,098

Property, plant and equipment - net
892,850

 
1,029,058

Derivative assets at fair value
101,141

 
105,270

Other assets
44,653

 
39,947

 
$
1,394,151

 
$
1,381,788

LIABILITIES AND EQUITY
 
 
 
Current liabilities
 
 
 
Accounts payable
$
16,074

 
$
37,131

Accrued liabilities
105,766

 
130,660

Total current liabilities
121,840

 
167,791

Long-term debt
1,968,407

 
2,063,206

Partnership liability
128,174

 
130,912

Asset retirement obligations
107,287

 
115,949

Derivative liabilities at fair value
17,693

 
17,485

Other liabilities
19,242

 
19,242

Commitments and contingencies (Note 8)

 

Stockholders' equity
 
 
 
Preferred stock, par value $0.01, 10,000,000 shares authorized, none outstanding
—

 
—

Common stock, $0.01 par value, 400,000,000 shares authorized, and 182,839,101 and 179,015,118 shares issued, respectively
1,828

 
1,790

Paid in capital in excess of par value
763,288

 
751,394

Treasury stock of 6,337,700 and 5,921,102 shares, respectively
(50,620
)
 
(49,495
)
Accumulated other comprehensive income
132,173

 
161,493

Retained deficit
(1,815,161
)
 
(1,997,979
)
Total stockholders' equity
(968,492
)
 
(1,132,797
)
 
$
1,394,151

 
$
1,381,788


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

7

QUICKSILVER RESOURCES INC.
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
In thousands – Unaudited
 
 
Quicksilver Resources Inc. Stockholders’ Equity
 
 
  
Common
Stock
 
Additional
Paid-in
Capital
 
Treasury
Stock
 
Accumulated
Other
Comprehensive
Income
 
Retained
Earnings
(Deficit)
 
Total
Balances at December 31, 2011
$
1,770

 
$
737,015

 
$
(46,351
)
 
$
214,858

 
$
354,627

 
$
1,261,919

Net loss
—

 
—

 
—

 
—

 
(1,013,587
)
 
(1,013,587
)
Hedge derivative contract settlements reclassified into earnings from AOCI, net of income tax of $34,238
—

 
—

 
—

 
(65,581
)
 
—

 
(65,581
)
Net change in derivative fair value, net of income tax of $35,656
—

 
—

 
—

 
72,210

 
—

 
72,210

Foreign currency translation adjustment
—

 
—

 
—

 
(4,930
)
 
—

 
(4,930
)
Issuance and vesting of stock compensation
17

 
10,004

 
(2,364
)
 
—

 
—

 
7,657

Stock option exercises
1

 
10

 
—

 
—

 
—

 
11

Balances at June 30, 2012, restated (1)
$
1,788

 
$
747,029

 
$
(48,715
)
 
$
216,557

 
$
(658,960
)
 
$
257,699

 
 
 
 
 
 
 
 
 
 
 
 
Balances at December 31, 2012
$
1,790

 
$
751,394

 
$
(49,495
)
 
$
161,493

 
$
(1,997,979
)
 
$
(1,132,797
)
Net income
—

 
—

 
—

 
—

 
182,818

 
182,818

Hedge derivative contract settlements reclassified into production revenue from AOCI, net of income tax of $12,385
—

 
—

 
—

 
(26,042
)
 
—

 
(26,042
)
Foreign currency translation adjustment
—

 
—

 
—

 
(3,278
)
 
—

 
(3,278
)
Issuance and vesting of stock compensation
38

 
11,894

 
(1,125
)
 
—

 
—

 
10,807

Balances at June 30, 2013
$
1,828

 
$
763,288

 
$
(50,620
)
 
$
132,173

 
$
(1,815,161
)
 
$
(968,492
)
(1) Note 1 contains additional information
The accompanying notes are an integral part of these condensed consolidated financial statements.

8

QUICKSILVER RESOURCES INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
In thousands – Unaudited

  
For the Six Months Ended
June 30,
  
2013
 
2012 (1)
 
 
 
(Restated)
Operating activities:
 
 
 
Net income (loss)
$
182,818

 
$
(1,013,587
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
Depletion, depreciation and accretion
33,521

 
102,455

Impairment expense
—

 
1,517,654

Tokyo Gas Transaction gain
(333,172
)
 
—

Crestwood earn-out
—

 
(41,097
)
Deferred income tax expense (benefit)
11,497

 
(497,827
)
Non-cash loss from hedging and derivative activities
9,135

 
8,651

Stock-based compensation
11,163

 
10,021

Non-cash interest expense
21,773

 
3,469

Fortune Creek accretion
9,672

 
9,571

Other
1,548

 
328

Changes in assets and liabilities
 
 
 
Accounts receivable
19,264

 
30,600

Prepaid expenses and other assets
(1,195
)
 
(5,031
)
Accounts payable
(16,443
)
 
(21,838
)
Accrued and other liabilities
(27,687
)
 
(3,853
)
Net cash provided by (used in) operating activities
(78,106
)
 
99,516

Investing activities:
 
 
 
Purchases of property, plant and equipment
(55,849
)
 
(307,169
)
Proceeds from Tokyo Gas Transaction
463,418

 
—

Proceeds from Crestwood earn-out
—

 
41,097

Proceeds from sale of properties and equipment
1,681

 
3,372

Purchases of marketable securities
(118,656
)
 
—

Net cash provided by (used in) investing activities
290,594

 
(262,700
)
Financing activities:
 
 
 
Issuance of debt
1,173,306

 
255,775

Repayments of debt
(1,264,117
)
 
(88,115
)
Debt issuance costs paid
(25,608
)
 
(148
)
Distribution of Fortune Creek Partnership funds
(5,009
)
 
(1,845
)
Proceeds from exercise of stock options
—

 
11

Purchase of treasury stock
(1,125
)
 
(2,364
)
Net cash provided by (used in) financing activities
(122,553
)
 
163,314

Effect of exchange rate changes in cash
1,907

 
727

Net increase in cash
91,842

 
857

Cash at beginning of period
4,951

 
13,146

Cash at end of period
$
96,793

 
$
14,003

(1) Note 1 contains additional information
The accompanying notes are an integral part of these condensed consolidated financial statements.

9

QUICKSILVER RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Unaudited

1. ACCOUNTING POLICIES AND DISCLOSURES
The accompanying condensed consolidated interim financial statements have not been audited. In management’s opinion, the accompanying condensed consolidated interim financial statements contain all adjustments necessary to fairly present our financial position as of June 30, 2013 and our results of operations and cash flows for the periods presented. All such adjustments are of a normal recurring nature. The results for interim periods are not necessarily indicative of annual results.
The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during each reporting period. We believe our estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties, which may cause actual results to differ materially from management’s estimates.
Certain disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted. Accordingly, these financial statements should be read in conjunction with our consolidated financial statements and notes thereto included in our 2012 Annual Report on Form 10-K.
Restatement of Previously Issued Unaudited Financial Statements
The consolidated financial statements as of and for the three and six months ended June 30, 2012 were restated as more fully disclosed within Item 8, Note 2 and the Supplemental Selected Quarterly Financial Data in the 2012 Annual Report on Form 10-K. The restatement is the result of our hedge documentation failing to give consideration to all sources of ineffectiveness for derivatives entered into during 2012 that had fair value on the dates they were initially designated as hedges. These derivatives did not qualify for hedge accounting in 2012 and their changes in value required recognition in earnings. Because the derivatives did not qualify for hedge accounting, their inclusion in the U.S. and Canadian full cost ceiling was inappropriate. Also, we determined that the deferred taxes used in our Canadian ceiling test included temporary differences for non-property related items. Thus, we revised our full cost ceiling calculations, which resulted in restatements to increase impairment expense recognized. Income taxes have also been restated to reflect the foregoing restated items.
For the three months ended June 30, 2012, the derivative restatement adjustment increased production revenue by $1.3 million for the U.S. and decreased production revenue by $1.5 million for Canada, while derivative gains increased $22.2 million and $3.5 million for the U.S. and Canada, respectively. Impairment expense increased as the result of these derivatives no longer being included in the cost center ceiling by $144.0 million and $63.8 million for the U.S. and Canada, respectively, while depletion expense decreased $1.3 million and $2.6 million for the U.S. and Canada, respectively. The income tax impact of these adjustments resulted in an increase to the tax benefit of $34.3 million and $14.6 million for the U.S. and Canada, respectively. Our consolidated net loss increased $129.5 million, which decreased our retained earnings by the same amount. Other comprehensive income and AOCI decreased $6.9 million as a result of these adjustments. The restatement increased diluted net loss per share by $0.76, from diluted net loss per share of $3.96 as previously reported, to diluted net loss per share of $4.72.
For the six months ended June 30, 2012, the derivative restatement decreased production revenue by $2.3 million and $3.3 million for the U.S. and Canada, respectively, while derivative gains increased $42.9 million and $15.5 million for the U.S. and Canada, respectively. Impairment expense increased as the result of these derivatives no longer being included in the cost center ceiling by $259.7 million and $203.3 million for the U.S. and Canada, respectively, while depletion expense decreased $1.3 million and $2.6 million for the U.S. and Canada, respectively. The income tax impact of these adjustments resulted in an increase to the tax benefit of $76.2 million and $48.8 million for the U.S. and Canada, respectively. Our consolidated net loss increased $281.1 million, which decreased our retained earnings by the same amount. Other comprehensive income and AOCI decreased $39.9 million as a result of these adjustments. The restatement increased diluted net loss per share by $1.65, from diluted net loss per share of $4.31 as previously reported, to diluted net loss per share of $5.96.
Recently Issued Accounting Standards
Accounting standards-setting organizations frequently issue new or revised accounting rules. We regularly review all new pronouncements to determine their impact, if any, on our financial statements. No pronouncements materially affecting our financial statements have been issued since the filing of our 2012 Annual Report on Form 10-K.


10

2. DIVESTITURES
In July 2013, we executed an agreement to sell all of our Southern Alberta Asset. The sale is expected to close in the third quarter and is subject to customary closing conditions.
In March 2013, we entered into a Purchase and Sale Agreement with TGBR to sell an undivided 25% of our Barnett Shale Asset for a purchase price of $485 million. The transaction closed in April 2013, but was effective as of September 1, 2012. The purchase price was subject to customary purchase price adjustments, which resulted in TGBR paying us $464.0 million, including an estimated final adjustment of $0.6 million in the third quarter of 2013. We recognized a gain of $333.2 million before consideration of income taxes as a result of this transaction.
Under the full cost method of accounting, our U.S. exploration and production assets are considered a single asset. The Tokyo Gas Transaction represented a significant disposal of reserves, which resulted in gain recognition for the transaction. Our U.S. oil and gas properties were reduced by $118.5 million as a result of the Tokyo Gas Transaction.
In October 2010, we completed the sale of all of our interests in KGS to Crestwood. As part of the sale, we had the right to collect future earn-out payments through 2013. In February 2012, we collected $41 million of these earn-out payments which is presented as “Crestwood earn-out” in the condensed consolidated statement of income. We will not receive additional earn-out payments in 2013.
Note 3 to the consolidated financial statements in our 2012 Annual Report on Form 10-K contains additional information regarding the Crestwood Transaction.
3. DERIVATIVES, MARKETABLE SECURITIES AND FAIR VALUE MEASUREMENTS
The following table categorizes our commodity derivative instruments based upon the use of input levels:
 
Asset Derivatives
 
Liability Derivatives
  
June 30, 2013
 
December 31, 2012
 
June 30, 2013
 
December 31, 2012
 
 
 
 
 
 
 
 
 
(in thousands)
 
(in thousands)
Level 2 inputs
$
163,299

 
$
207,042

 
$
(31
)
 
$
959

Level 3 inputs
7,851

 
11,595

 
17,724

 
16,526

Total
$
171,150

 
$
218,637

 
$
17,693

 
$
17,485


The fair value of “Level 2” derivative instruments included in these disclosures was estimated using prices quoted in active markets for the periods covered by the derivatives and the value reported by counterparties. The fair value of derivative instruments designated as “Level 3” was estimated using prices quoted in markets where there is insufficient market activity for consideration as “Level 2” instruments. Currently, only our natural gas derivatives with an original tenure of 10 years utilize “Level 3” inputs, primarily due to comparatively less market data available for the later portion of their term compared with our other shorter term derivatives. The fair value of both the “Level 2” and the “Level 3” assets and liabilities are determined using a discounted cash flow model using the terms of the derivative instrument, market prices for the periods covered by the derivatives, and the credit adjusted risk-free interest rates. The “Level 3” unobservable inputs are the market prices for the estimated market values for the period from 2018 to 2021, as there is not an active market for that period of time. These unobservable inputs included within the fair value calculation range from $3.56 to $6.32 and are based upon prices quoted in active markets for the period of time available and applying the differential from this period of time to the market prices for the later years in the term.

11

The following table identifies the changes in “Level 3” net asset derivative fair values for the periods indicated:
 
 
For the Three Months Ended
June 30,
 
2013
 
2012
 
 
 
 
 
(In thousands)
Balance at beginning of period
$
(9,037
)
 
$
21,587

Total gains (losses) for the period:
 
 
 
Unrealized gain (loss) on derivatives
556

 
35,197

Settlements in production revenue
—

 
(1,037
)
Settlements in net derivative gains (losses)
(1,392
)
 
(8,997
)
Unrealized gains reported in OCI
—

 
(1,405
)
Balance at end of period
$
(9,873
)
 
$
45,345

 
 
 
 
Total gains included in net derivative gains attributable to the change in unrealized gains related to assets still held at the reporting date
$
2,854

 
$
35,197

 
 
 
 
 
 
For the Six Months Ended
June 30,
 
2013
 
2012
 
 
 
 
 
(In thousands)
Balance at beginning of period
$
(4,931
)
 
$
150,989

Total gains (losses) for the period:
 
 
 
Unrealized gain (loss) on commodity hedges
538

 
35,525

Transfers out of Level 3
—

 
(153,418
)
Settlements in Production Revenue
—

 
(4,775
)
Settlements in Other Revenue
(5,480
)
 
(15,873
)
Unrealized gains reported in OCI
—

 
32,897

Balance at end of period
$
(9,873
)
 
$
45,345

 
 
 
 
Total gains included in net derivative gains attributable to the change in unrealized gains related to assets still held at the reporting date
$
2,762

 
$
35,525

In 2012, transfers from Level 3 to Level 2 represent our ten-year derivative instruments that were exchanged in January and February 2012 for derivative instruments with shorter durations and are valued on the date of the transfer.
Commodity Price Derivatives
As of June 30, 2013, we had natural gas swaps as follows:
Production
Year
 
Daily Production
Volume
 
 
MMcfd
Remainder of 2013
 
200
2014
 
170
2015
 
150
2016-2021
 
40

12

Effective December 31, 2012, we discontinued the use of hedge accounting. Changes in value subsequent to this date are recognized in net derivative gains (losses) in the period in which they occur. The net deferred hedge gain that was included in AOCI as of December 31, 2012 is being released into revenue from natural gas, NGL and oil production during the following periods in which we expect the underlying production to occur as follows:
 
(In thousands)
Remainder of 2013
$
32,377

2014
37,084

2015
33,191

2016
13,476

2017
12,531

2018 and thereafter
41,443

 
$
170,102

Gains and losses from the effective portion of derivative assets and liabilities held in AOCI expected to be reclassified into earnings during the following twelve months would result in a gain of $51.6 million net of income taxes.
Interest Rate Derivatives
In 2010, we executed early settlements of our interest rate swaps that were designated as fair value hedges of our senior notes due 2015 and our senior subordinated notes. We received cash of $41.5 million in the settlements, including $10.7 million for interest previously accrued and earned. Upon the early settlements, we recorded the resulting gain as a fair value adjustment to our debt and began to recognize the deferred gain of $30.8 million as a reduction of interest expense over the lives of our senior notes due 2015 and our senior subordinated notes.
In June 2013, we repurchased substantially all our senior notes due 2015 resulting in early recognition of the previously deferred gain of $8.3 million. During the six months ended June 30, 2013 and 2012, we recognized $11.0 million and $2.5 million, respectively, of those deferred gains as a reduction of interest expense. The remaining $5.8 million deferral of the 2010 early settlements from the senior subordinated notes interest rate swaps will continue to be recognized as a reduction of interest expense over the life of those instruments currently scheduled as follows:
 
(In thousands)
Remainder of 2013
$
965

2014
2,039

2015
2,194

2016
569

 
$
5,767

Fair Value Disclosures
The estimated fair values of our derivative instruments at June 30, 2013 and December 31, 2012 were as follows:
 
Asset Derivatives
 
 
Liability Derivatives
 
June 30, 2013
 
December 31, 2012
 
 
June 30, 2013
 
December 31, 2012
 
 
 
 
 
 
 
 
 
 
(In thousands)
 
 
(In thousands)
Derivatives not designated as hedges:
 
 
 
 
 
 
 
 
Commodity contracts reported in:
 
 
 
 
 
 
 
 
Current derivative assets
$
70,009

 
$
113,367

 
 
$
—

 
$
—

Noncurrent derivative assets
103,915

 
107,542

 
 
2,774

 
2,272

Current derivative liabilities
—

 
—

 
 
—

 
—

Noncurrent derivative liabilities
315

 
92

 
 
18,008

 
17,577

Total derivatives not designated as hedges
$
174,239

 
$
221,001

 
 
$
20,782

 
$
19,849

Derivative assets and liabilities shown in the table above are presented as gross assets and liabilities, without regard to master netting arrangements which are considered in the presentations of derivative assets and liabilities in the accompanying condensed consolidated balance sheets. The change in carrying value of our commodity price derivatives since December 31,

13

2012 principally resulted from the overall increase in market prices for natural gas relative to the prices in our open derivative instruments, offset by settlements during the period.
The changes in the carrying value of our derivatives accounted for as hedges for the three and six months ended June 30, 2012 are presented below:
 
For the Three Months Ended
June 30,
 
2012
 
Commodity Hedges
 
 
 
(In thousands)
Derivative fair value at beginning of period
$
211,163

Settlements in production revenue
(49,999
)
Ineffectiveness reported in net derivative gains
6,810

Unrealized gains reported in OCI
8,752

Derivative fair value at end of period
$
176,726

 
 
 
For the Six Months Ended
June 30,
 
2012
  
Commodity Hedges
 
 
 
(In thousands)
Derivative fair value at beginning of period
$
342,799

Settlements in production revenue
(91,736
)
Settlements in net derivative gains
(3,820
)
Ineffectiveness reported in net derivative gains
1,569

Unrealized gains reported in OCI
108,646

Derecognition of hedge
(180,732
)
Derivative fair value at end of period
$
176,726

Financial instruments not carried at fair value
Carrying values and fair values of financial instruments that are not carried at fair value in the consolidated balance sheet as of June 30, 2013 and December 31, 2012 are included in Note 5.
Investments
We have certain short-term marketable securities related to interest bearing time deposits and commercial paper. These held-to-maturity marketable securities are included in Cash and Cash Equivalents if the maturities at the time we made the investment were three months or less. For maturities greater than three months but less than a year, the marketable securities are included in current Marketable Securities. At June 30, 2013, we had the following marketable securities:
 
Amortized Cost
 
Gross Unrealized Gains
 
Gross Unrealized Losses
 
Net Carrying Value
 
 
 
 
 
 
 
 
 
(In thousands)
Marketable securities (held-to-maturity)
 
 
 
 
 
 
 
Time deposits
$
19,880

 
$
15

 
$
—

 
$
19,895

Commercial paper
98,776

 
59

 
—

 
98,835

Marketable securities
$
118,656

 
$
74

 
$
—

 
$
118,730

We had no marketable securities at December 31, 2012.

14

4. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consisted of the following:
 
June 30, 2013
 
December 31, 2012
 
 
 
 
 
(In thousands)
Oil and gas properties
 
 
 
Subject to depletion
$
5,639,725

 
$
5,770,913

Unevaluated costs
281,875

 
307,267

Accumulated depletion
(5,261,665
)
 
(5,297,220
)
Net oil and gas properties
659,935

 
780,960

Other plant and equipment
 
 
 
Pipelines and processing facilities
353,479

 
375,248

General properties
81,628

 
75,147

Accumulated depreciation
(202,192
)
 
(202,297
)
Net other property and equipment
232,915

 
248,098

Property, plant and equipment, net of accumulated depletion and depreciation
$
892,850

 
$
1,029,058


Ceiling Test Analysis and Impairment
We recorded impairment expense of $1,042.7 million and $157.0 million for the three months ended June 30, 2012 and $178.0 million and $139.9 million for the three months ended March 31, 2012 for our U.S. and Canadian oil and gas properties, respectively.
Notes 2 and 8 to the consolidated financial statements in our 2012 Annual Report on Form 10-K contain additional information regarding our property, plant and equipment and our quarterly ceiling test analysis.

5. LONG-TERM DEBT
Long-term debt consisted of the following:
 
 
June 30, 2013
 
December 31, 2012
 
 
 
 
 
(in thousands)
Combined Credit Agreements
$
190,211

 
$
388,150

Senior Secured Second Lien Credit Agreement, net of unamortized discount
606,250

 
—

Senior Secured Second Lien Notes due 2019, net of unamortized discount
194,000

 
—

Senior notes due 2015, net of unamortized discount
12,717

 
435,851

Senior notes due 2016, net of unamortized discount
8,021

 
579,795

Senior notes due 2019, net of unamortized discount
292,925

 
292,622

Senior notes due 2021, net of unamortized discount
308,516

 
—

Senior subordinated notes due 2016
350,000

 
350,000

Total debt
1,962,640

 
2,046,418

Unamortized deferred gain-terminated interest rate swaps
5,767

 
16,788

Current portion of long-term debt
—

 
—

Long-term debt
$
1,968,407

 
$
2,063,206


15

Combined Credit Facilities
The Combined Credit Agreements’ global borrowing base was $350 million and the global letter of credit capacity was $280 million as of June 30, 2013. At June 30, 2013, we had $104.7 million available under the Combined Credit Agreements.
We further amended our Combined Credit Agreements in April and June 2013 for the following:
•
Reduce the global borrowing base to $350 million from $850 million, including a reduction due to the Tokyo Gas Transaction
•
Reduce the minimum required interest coverage ratio to the following:
Period
 
Interest Coverage Ratio
 
Period
 
Interest Coverage Ratio
Q2 2013
 
1.25
 
Q1 2015
 
1.10
Q3 2013
 
1.25
 
Q2 2015
 
1.15
Q4 2013
 
1.25
 
Q3 2015
 
1.15
Q1 2014
 
1.20
 
Q4 2015
 
1.20
Q2 2014
 
1.15
 
Q1 2016
 
1.50
Q3 2014
 
1.10
 
Q2 2016
 
2.00
Q4 2014
 
1.10
 
 
 
 
•
Permit up to $825 million of second lien debt, subject to customary intercreditor terms
•
Permit redemption of junior debt with the proceeds from certain asset sales and permitted second lien debt, provided utilization under the global borrowing base after giving effect to such redemption is less than 75% and compliance with other customary conditions
•
Reduce the maximum senior secured debt leverage ratio to 2.0 and exclude permitted second lien debt from the senior secured debt definition
•
Increase the applicable margin by 0.75% for each type of loan and issued letters of credit
•
Increase the minimum mortgage properties requirement to 87.5% from 80% of proved hydrocarbon interests evaluated in the then most recent reserve report
•
Amend certain definitions which impact the financial covenant calculations.
Debt Refinancing
During the quarter ended June 30, 2013, we executed multiple debt transactions to extend our debt maturities and reduce the weighted average interest costs, which are more fully described below. Deferred issuance costs related to the new debt were $23.1 million and incurred costs related to the repurchased debt of $4.1 million were recognized as interest expense. Proceeds from the issuance of the Senior Secured Second Lien Credit Agreement, Senior Secured Second Lien Notes due 2019 and Senior Notes due 2021 were used to pay for all validly tendered Senior Notes due 2015 and Senior Notes due 2016 and accrued interest thereon and transaction expenses.
Senior Secured Second Lien Credit Agreement
On June 21, 2013, we entered into a $625 million six-year Senior Secured Second Lien Credit Agreement. The loans thereunder were made at 97% of par, which resulted in net proceeds of $606.3 million. The Senior Secured Second Lien Credit Agreement has a margin of 5.75% plus the Adjusted LIBOR (as defined in the Senior Secured Second Lien Credit Agreement, which is subject to a floor of 1.25%) or 4.75% plus the Alternate Base Rate (as defined in the Senior Secured Second Lien Credit Agreement, which is subject to a floor of 2.25%).
Senior Secured Second Lien Notes due 2019
On June 21, 2013, we issued $200 million Senior Secured Second Lien Notes due 2019. The notes were issued at 97% of par, which resulted in net proceeds of $194 million. The Senior Secured Second Lien Notes have a margin of 5.75% plus LIBOR (as defined in the indenture governing the Senior Secured Second Lien Notes due 2019, which is subject to a floor of 1.25%). Interest is payable on the last day of each quarter period.

16

Senior Notes due 2021
On June 21, 2013, we issued $325 million of senior notes due 2021, which are unsecured, senior obligations. The notes were issued at 94.928% of par, which resulted in proceeds of $308.5 million. Interest at the rate of 11.00% is payable semiannually on January 1 and July 1.
Senior Notes due 2015
During the quarter ended June 30, 2013, we announced a cash tender offer and consent solicitation on the Senior Notes due 2015 at a price of $1,027.90 plus interest of $32.08 per $1,000 outstanding. On June 21, 2013, we accepted and paid for all validly tendered notes, which was $425.2 million of the outstanding $438.0 million, which resulted in an aggregate payment of $450.7 million for such repurchase. We also entered into a supplemental indenture to eliminate substantially all of the restrictive covenants and certain events of default with respect to such notes.
Senior Notes Due 2016
During the quarter ended June 30, 2013, we announced a cash tender offer and consent solicitation on the Senior Notes due 2016 at a price of $1,068 plus interest of $55.49 per $1,000 outstanding. On June 21, 2013, we accepted and paid for all validly tendered notes, which was $582.5 million of the outstanding $590.6 million, which resulted in an aggregate payment of $654.4 million for such repurchase. We also entered into a supplemental indenture to eliminate substantially all of the restrictive covenants and certain events of default with respect to such notes.
Senior Notes Due 2019
During the quarter ended June 30, 2013, we announced a consent solicitation on the Senior Notes due 2019. On June 21, 2013, we entered into supplemental indentures to permit the refinancing of the Senior Subordinated Notes due 2016 by incurring indebtedness that ranks equally in right of payment with the Senior Notes due 2019 provided such indebtedness has maturities longer than the Senior Notes due 2019, which resulted in the payment of an $11.5 million consent fee for the consenting holders of the Senior Notes due 2019.
Indenture Restrictions
We have an incurrence test under our indentures applicable to debt, restricted payments, mergers and consolidations and designation of unrestricted subsidiaries that requires EBITDA to exceed interest expense by 2.25 times. At June 30, 2013, we did not meet this test and, as a result, we are limited in our ability to, among other things, incur additional debt, except for specific baskets. We do retain, however, the ability to utilize the full borrowing capacity under our Combined Credit Agreements and to refinance existing debt. Not meeting this ratio does not represent an event of default under our indentures. We are presently unable to predict when or if we will meet the incurrence test.

17

Summary of All Outstanding Debt
The following table summarizes certain significant aspects of our long-term debt outstanding at June 30, 2013.
 
 
Priority on Collateral and Structural Seniority (1)
 
 
Highest
priority
 
 
 
 
 
Lowest
priority
 
 
First Lien
 
Second Lien
 
Senior Unsecured
 
Senior Subordinated
 
 
Combined Credit
Agreements
 
Senior Secured Second Lien Credit Agreement
 
Senior Secured Second Lien Notes due 2019
 
2015
Senior Notes
 
2016
Senior Notes
 
2019
Senior Notes
 
2021
Senior Notes
 
Senior
Subordinated Notes
Principal amount (2)
 
$350 million
 
$625 million
 
$200 million
 
$13 million
 
$8 million
 
$298 million
 
$325 million
 
$350 million
Scheduled maturity date (3)
 
September 6, 2016
 
June 21, 2019
 
June 21, 2019
 
August 1, 2015
 
January 1, 2016
 
August 15, 2019
 
July 1, 2021
 
April 1, 2016
Interest rate on outstanding borrowings at June 30, 2013 (4)
 
3.88%
 
7.00%
 
7.00%
 
8.25%
 
11.75%
 
9.125%
 
11.00%
 
7.125%
Base interest rate options (5) (6)
 
LIBOR, ABR, CDOR
 
LIBOR floor of 1.25%; ABR floor 2.25%
 
LIBOR floor of 1.25%
 
N/A
 
N/A
 
N/A
 
N/A
 
N/A
Financial covenants (7)
 
- Minimum current ratio of 1.0
- Minimum EBITDA to cash interest expense ratio of 1.25
- Maximum senior secured debt leverage ratio of 2.0
 
N/A
 
N/A
 
N/A
 
N/A
 
N/A
 
N/A
 
N/A
Significant restrictive covenants (7)
 
- Incurrence of debt
- Incurrence of liens
- Payment of dividends
- Equity purchases- Asset sales
- Affiliate transactions
- Limitations on derivatives and investments
 
- Incurrence of debt
- Incurrence of liens and 1st lien cap
-Payment of dividends
- Equity purchases
- Asset sales
- Affiliate transactions
 
- Incurrence of debt
- Incurrence of liens and 1st lien cap
-Payment of dividends
- Equity purchases
- Asset sales
- Affiliate transactions
 
- Asset sales
 
- Asset sales
 
- Incurrence of debt
- Incurrence of liens
-Payment of dividends
- Equity purchases
- Asset sales
- Affiliate transactions
 
- Incurrence of debt
- Incurrence of liens
-Payment of dividends
- Equity purchases
- Asset sales
- Affiliate transactions
 
- Incurrence of debt
- Incurrence of liens
-Payment of dividends
- Equity purchases
- Asset sales
- Affiliate transactions
Optional redemption (7)
 
Any time
 
Any time, subject to
re-pricing event
June 21,
2014: 102
2015: 101
 
Any time, subject to
re-pricing event
June 21,
2014: 102
2015: 101
 
August 1,
2013: 101.938
2014: par
 
July 1,
2013: 105.875
2014: 102.938
2015: par
 
August 15,
2014: 104.563
2015: 103.042
2016: 101.521
2017: par
 
July 1,
2019: 102.000
2020: par
 
April 1,
2013: 101.188
2014: par
Make-whole redemption (7)
 
N/A
 
N/A
 
N/A
 
N/A
 
Callable prior to
July 1, 2013 at
make-whole call price of Treasury +50 bps
 
Callable prior to
August 15, 2014 at
make-whole call price of Treasury +50 bps
 
N/A
 
N/A
Change of control (7)
 
Event of default
 
Put at 101% of
principal plus
accrued interest
 
Put at 101% of
principal plus
accrued interest
 
Put at 101% of
principal plus
accrued interest
 
Put at 101% of
principal plus
accrued interest
 
Put at 101% of
principal plus
accrued interest
 
Put at 101% of
principal plus
accrued interest
 
Put at 101% of
principal plus
accrued interest
Estimated fair value (8)
 
$190.2 million
 
$560.2 million
 
$179.3 million
 
$11.1 million
 
$7.7 million
 
$253.3 million
 
$284.4 million
 
$283.5 million

18


(1) 
Borrowings under the Amended and Restated U.S. Credit Facility, Senior Secured Second Lien Credit Agreement and Senior Secured Second Lien Notes due 2019 are guaranteed by certain of Quicksilver’s domestic subsidiaries and are secured (on a first priority basis with respect to the Amended and Restated U.S. Credit Facility and on a second priority basis with respect to the Senior Secured Second Lien Credit Agreement and the Senior Secured Second Lien Notes due 2019) by 100% of the equity interests of each of Cowtown Pipeline Management, Inc., Cowtown Pipeline Funding, Inc., Cowtown Gas Processing L.P., Cowtown Pipeline L.P., Barnett Shale Operating LLC, Silver Stream Pipeline Company LLC, QPP Parent LLC and QPP Holdings LLC (collectively, the “Domestic Pledged Equity”), 65% of the equity interests of Quicksilver Resources Canada Inc. (“Quicksilver Canada”) and Quicksilver Production Partners Operating Ltd. (with respect to the Amended and Restated U.S. Credit Facility, on a ratable basis with borrowings under the Amended and Restated Canadian Credit Facility) and the majority of Quicksilver's domestic proved oil and gas properties and related assets, (the “Domestic Pledged Property”). Borrowings under the Amended and Restated Canadian Credit Facility are guaranteed by Quicksilver and certain of its domestic subsidiaries and are secured by the Domestic Pledged Equity, the Domestic Pledged Property, 100% of the equity interests of Quicksilver Canada (65% of which is on a ratable basis with the borrowings under the Amended and Restated U.S. Credit Facility) and any Canadian restricted subsidiaries, under the Amended and Restated Canadian Credit Facility, and 65% of the equity interests of Quicksilver Production Partners Operating Ltd. (which is on a ratable basis with the borrowings under the Amended and Restated U.S. Credit Facility) and the majority of Quicksilver Canada's oil and gas properties and related assets. The other debt presented is based upon structural seniority and priority of payment.
(2) 
The principal amount for the Combined Credit Agreements represents the global borrowing base as of June 30, 2013.
(3) 
The Combined Credit Agreements are required to be repaid 91 days prior to the maturity of the 2015 Senior Notes, the 2016 Senior Notes, the 2016 Senior Subordinated Notes, the Senior Secured Second Lien Credit Agreement or the Senior Secured Second Lien Notes due 2019, if on the applicable date any amount of such debt remains outstanding. The Senior Secured Second Lien Credit Agreement and Senior Secured Second Lien Notes due 2019 are required to be repaid (1) 91 days prior the maturity of the 2019 Notes if more than $100 million of 2019 Senior Notes remain outstanding and (2) 91 days prior to the maturity of the 2015 Senior Notes, the 2016 Senior Notes or the 2016 Senior Subordinated Notes if on the applicable date the aggregate amount of all such notes remaining outstanding is greater than $100 million.
(4) 
Represents the weighted average borrowing rate payable to lenders.
(5) 
Amounts outstanding under the Amended and Restated U.S. Credit Facility bear interest, at our election, at (i) adjusted LIBOR (as defined in the Amended and Restated U.S. Credit Facility) plus an applicable margin between 2.75% to 3.75%, (ii) ABR (as defined in the Amended and Restated U.S. Credit Facility), which is the greatest of (a) the prime rate announced by JPMorgan, (b) the federal funds rate plus 0.50% and (c) adjusted LIBOR for an interest period of one month plus 1.00%, plus, in each case under scenario (ii), an applicable margin between 1.75% to 2.75%. We also pay a per annum fee on the LC Exposure (as defined in the Amended and Restated U.S. Credit Facility) of all letters of credit issued under the Amended and Restated U.S. Credit Facility equal to the applicable margin, with respect to adjusted LIBOR loans, and a commitment fee on the unused availability under the Amended and Restated U.S. Credit Facility of 0.50%.
(6) 
Amounts outstanding under the Amended and Restated Canadian Credit Facility bear interest, at our election, at (i) the CDOR Rate (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 2.75% and 3.75%, (ii) the Canadian Prime Rate (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 1.75% and 2.75%, (iii) the U.S. Prime Rate (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 1.75% and 2.75% and (iv) adjusted LIBOR (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 2.75% to 3.75%. We pay a per annum fee on the LC Exposure (as defined in the Amended and Restated Canadian Credit Facility) of all letters of credit issued under the Amended and Restated Canadian Credit Facility equal to the applicable margin, with respect to adjusted LIBOR loans, and a commitment fee on the unused availability under the Amended and Restated Canadian Credit Facility of 0.50%.
(7) 
The information presented in this table is qualified in all respects by reference to the full text of the covenants, provisions and related definitions contained in the documents governing the various components of our debt.
(8) 
The estimated fair value is determined using market quotations based on recent trade activity for fixed rate obligations (“Level 2” inputs). Our Senior Secured Second Lien Credit Agreement and Senior Secured Second Lien Notes due 2019 feature variable interest rates and we estimate their fair value by using market quotations based on recent trade activity (“Level 3” input). We consider our Combined Credit Agreements which have a variable interest rate to have a fair value equal to their carrying value (“Level 1” input).


19

6. ASSET RETIREMENT OBLIGATIONS
The following table provides a reconciliation of the changes in the estimated asset retirement obligation for the six months ended June 30, 2013.
 
 
(In thousands)
Beginning asset retirement obligations
$
116,526

Additional liability incurred
3,124

Change in estimates
1,691

Accretion expense
2,644

Asset retirement costs incurred
(1,053
)
Settlement of liability in excess of obligation recorded
269

Disposition
(12,230
)
Currency translation adjustment
(3,107
)
Ending asset retirement obligations
107,864

Less current portion
(577
)
Long-term asset retirement obligation
$
107,287

7. INCOME TAXES
Deferred income taxes are established for all temporary differences between the book and the tax basis of assets and liabilities. In addition, deferred tax balances must be adjusted to reflect tax rates that we expect will be in effect during years in which we expect the temporary differences will reverse. Net operating loss carry-forwards and other deferred tax assets are reviewed for recoverability, and if necessary, are recorded net of a valuation allowance. At June 30, 2013, our U.S. and Canadian valuation allowances are $472.2 million and $62.6 million, respectively, which reduce our net deferred tax assets to a zero value as we continue to believe that it is not more likely than not that we will realize the deferred tax benefits primarily related to our cumulative net operating losses. Income tax recognized for the three and six months ended June 30, 2013 is a result of hedge gains previously deferred in AOCI being realized during the periods and the net tax impact being recognized without a corresponding valuation allowance.
8. COMMITMENTS AND CONTINGENCIES
Contractual Obligations, Commitments and Contingencies
In July 2013, in light of the Canadian Governor in Council's failure to approve NGTL's construction of the Komie North Project, NGTL terminated the Project and Expenditure Authorization (PEA), which authorized NGTL to construct the Komie North Project and the related meter station. The PEA necessitated the construction of a treatment facility and required financial guarantees to cover NGTL's costs for the Komie North Project. We have provided C$14 million in letters of credit to support this obligation. NGTL will release the letters of credit in connection with our paying NGTL an amount equal to actual costs incurred by NGTL, which is estimated to be approximately $12.8 million and is reflected in other income (expense) in our consolidated financial statements. With this termination of the PEA as described above, our agreement to deliver gas to the Komie North Project, has also terminated. We maintain our ability to sell gas at the Station 2 and AECO hubs, as our current production is served by existing treating facilities and pipelines.
In April 2013, we increased our outstanding letters of credit by C$13 million for the contractual increase of treating volumes in the Horn River Basin.
In December 2012, Vantage Fort Worth Energy LLC (“Plaintiff”) served a lawsuit against us and others in the 352nd Judicial District Court of Texas in Tarrant County asserting claims for trespass to try title, suit to quiet title, trespass and conversion in connection with 16 wells located on a 158.75 acre tract located in Tarrant County, Texas. On May 8, 2013, all parties to the suit entered into a settlement agreement, effective April 1, 2013, whereby we assigned to Plaintiff various property and equipment and Plaintiff agreed to non-suit all of the Defendants in the matter. The court entered its Order of Dismissal with prejudice on May 13, 2013. We recognized an expense of $0.4 million in connection with this settlement.
In July 2011, we received a subpoena duces tecum from the SEC requesting certain documents. The SEC has informed us that their investigation arises out of press releases in 2011 questioning the projected decline curves and economics of shale gas wells. In June 2012, we received an additional request from the SEC for certain information regarding our assessment for impairment of unevaluated properties and plans for development of unevaluated properties. We provided responsive information and in February 2013 we met with the SEC.

20

Note 14 to the consolidated financial statements in our 2012 Annual Report on Form 10-K contains a more complete description of our contractual obligations, commitments and contingencies for which there are no other significant updates during the quarter ended June 30, 2013.
9. FORTUNE CREEK
Note 12 to the consolidated financial statements in our 2012 Annual Report on Form 10-K contains additional information on Fortune Creek. We committed to minimum expenditures of $300 million for drilling and completion activities in our Horn River Asset between 2012 and 2014, of which we incurred $148.8 million as of June 30, 2013, and pursuant to the partnership agreement will be required to incur an additional $31.2 million by December 31, 2013, with the balance to be incurred through December 31, 2014; provided further that up to $20 million could be deferred until December 31, 2015. Additionally, we committed gas production from our Horn River Asset for ten years beginning 2012, as more fully described below. KKR contributed $125 million cash in exchange for a 50% interest in Fortune Creek. Our Canadian subsidiary has responsibility for the day-to-day operations of Fortune Creek.
Our Canadian subsidiary entered into a firm gathering agreement with Fortune Creek which is guaranteed by us. At our election and based on the satisfaction of certain conditions, KKR has the responsibility to fund up to C$130 million of the capital required for construction of a new gas treatment facility in exchange for preferential cash flow distributions. If our subsidiary does not meet its obligations under the gathering agreement, KKR has the right to liquidate the partnership and consequently we have recorded the funds contributed by KKR as a liability in our consolidated financial statements. We recognize accretion expense to reflect the rate of return earned by KKR via its investment. Fortune Creek has made cash distributions to KKR, which are reported as cash used by financing activities, since May 2012.
10. QUICKSILVER STOCKHOLDERS’ EQUITY
Common Stock, Preferred Stock and Treasury Stock
We are authorized to issue 400 million shares of common stock with a $0.01 par value per share and 10 million shares of preferred stock with a $0.01 par value per share. At June 30, 2013 and December 31, 2012, we had 176.5 million and 173.1 million shares of common stock outstanding, respectively.
On May 15, 2013, our stockholders approved an amendment to the 2006 Equity Plan, which increased the shares available for issuance under the plan by 12 million shares. Note 17 to the consolidated financial statements in our 2012 Annual Report on Form 10-K contains additional information about our equity-based compensation plan.
Stock Options
Options to purchase shares of common stock were granted in 2013 with an estimated fair value of $0.9 million. The following summarizes the values from and assumptions for the Black-Scholes option pricing model for stock options issued during the six months ended June 30:
 
2013
 
2012
Weighted avg grant date fair value
$0.99
 
$4.21
Weighted avg risk-free interest rate
0.44%
 
1.14%
Expected life
2.9 years
 
6.0 years
Wtd avg volatility
64.3%
 
68.2%
Expected dividends
—
 
—

The following table summarizes our stock option activity for the six months ended June 30, 2013:
 
Shares
 
Wtd Avg
Exercise
Price
 
Wtd Avg
Remaining
Contractual Life
 
Aggregate
Intrinsic Value
 
 
 
 
 
(In years)
 
(In thousands)
Outstanding at January 1, 2013
4,979,980

 
$
10.23

 
 
 
 
Granted
888,197

 
2.33

 
 
 
 
Expired
(53,588
)
 
9.10

 
 
 
 
Outstanding at June 30, 2013
5,814,589

 
$
9.04

 
7.1
 
$
—

Exercisable at June 30, 2013
4,575,938

 
$
9.31

 
6.7
 
$
—

As of June 30, 2013, we estimate that a total of 5.7 million stock options will become vested including those options already exercisable. As of June 30, 2013, the unrecognized compensation cost related to outstanding unvested stock options

21

was $2.9 million, which is expected to be recognized in expense through June 2015. Compensation expense related to stock options of $2.7 million and $3.4 million was recognized for each of the six months ended June 30, 2013 and 2012, respectively.
Restricted Stock
The following table summarizes our restricted stock and stock unit activity for the six months ended June 30, 2013:
 
Payable in shares
 
Payable in cash
 
Shares
 
Wtd Avg
Grant Date
Fair Value
 
Shares
 
Wtd Avg
Grant Date
Fair Value
Outstanding at January 1, 2013
3,099,135

 
$
8.48

 
678,217

 
$
7.71

Granted
5,133,495

 
2.96

 
1,322,352

 
2.97

Vested
(1,419,440
)
 
9.11

 
(271,864
)
 
8.32

Forfeited
(636,458
)
 
3.98

 
(183,721
)
 
3.94

Outstanding at June 30, 2013
6,176,732

 
$
4.21

 
1,544,984

 
$
3.99

As of June 30, 2013, the unrecognized compensation cost related to outstanding unvested restricted stock was $18.8 million, which is expected to be recognized in expense through March 2016. Grants of restricted stock and RSUs during the six months ended June 30, 2013 had an estimated grant date fair value of $19.1 million. The fair value of outstanding RSUs to be settled in cash is $2.6 million at June 30, 2013. For the six months ended June 30, 2013 and 2012, compensation expense of $10.0 million and $7.3 million, respectively, was recognized. The total fair value of shares vested during the six months ended June 30, 2013 was $4.6 million.
In the 2nd quarter of 2013, the Company recognized $3.6 million in stock-based compensation to correct for assumptions on forfeitures and vesting for retirement eligible and imminently retirement eligible individuals, including $2.2 million which pertain to periods before 2013.

11. EARNINGS PER SHARE
The following is a reconciliation of the numerator and denominator used for the computation of basic and diluted net income (loss) per common share.
 
 
For the Three Months Ended
June 30,
 
For the Six Months Ended
June 30,
 
2013
 
2012
 
2013
 
2012
 
 
 
(Restated)
 
 
 
 
 
 
 
 
 
 
 
 
 
(In thousands, except per share data)
 
 
 
 
Net income (loss) attributable to Quicksilver
$
242,523

 
$
(802,022
)
 
$
182,818

 
$
(1,013,587
)
Basic income allocable to participating securities (1)
(7,020
)
 
—

 
$
(5,126
)
 
$
—

Income (loss) available to shareholders
$
235,503

 
$
(802,022
)
 
$
177,692

 
$
(1,013,587
)
Weighted average common shares – basic
171,357

 
170,043

 
171,261

 
169,991

Effect of dilutive securities (2)
 
 
 
 
 
 
 
Share-based compensation awards
5

 
—

 
4

 
—

Weighted average common shares – diluted
171,362

 
170,043

 
171,265

 
169,991

Earnings (loss) per common share – basic
$
1.37

 
$
(4.72
)
 
$
1.04

 
$
(5.96
)
Earnings (loss) per common share – diluted
$
1.37

 
$
(4.72
)
 
$
1.04

 
$
(5.96
)

(1) 
Restricted share awards that contain nonforfeitable rights to dividends are participating securities and, therefore, should be included in computing earnings using the two-class method. Participating securities, however, do not participate in undistributed net losses because there is no contractual obligation to do so.
(2) 
For the three months ended June 30, 2013, 5.3 million shares associated with our stock options and 1.0 million shares associated with our unvested restricted stock units were antidilutive; therefore, excluded from the diluted share calculation. For the three months ended June 30, 2012, 5.2 million shares associated with our stock options and 0.3 million shares associated with our unvested restricted stock units were antidilutive; therefore, excluded from the diluted share calculation. For the six months ended June 30, 2013, 5.2 million shares associated with our stock options and 1.0 million

22

shares associated with our unvested restricted stock units were antidilutive; therefore, excluded from the diluted share calculation. For the six months ended June 30, 2012, 5.2 million shares associated with our stock options and 0.3 million shares associated with our unvested restricted stock units were antidilutive; therefore, excluded from the diluted share calculation.
12. CONDENSED CONSOLIDATING FINANCIAL INFORMATION
Note 19 to the consolidated financial statements in our 2012 Annual Report on Form 10-K contains a more complete description of our guarantor, non-guarantor, restricted and unrestricted subsidiaries under the indentures for our senior notes and senior subordinated notes.
The following tables present financial information about Quicksilver and our restricted subsidiaries for the six-month period covered by the consolidated financial statements. Under the indentures for our senior notes and senior subordinated notes, Fortune Creek is not considered to be a subsidiary and therefore it is presented separately from the other subsidiaries for these purposes.
Condensed Consolidating Balance Sheets

 
June 30, 2013
Quicksilver
Resources Inc.
 
Restricted
Guarantor
Subsidiaries
 
Restricted
Non-
Guarantor
Subsidiaries
 
Restricted
Subsidiary
Eliminations
 
Quicksilver
and
Restricted
Subsidiaries
 
Unrestricted
Non-
Guarantor
Subsidiaries
 
Fortune
Creek
 
Consolidating
Eliminations
 
Quicksilver
Resources Inc.
Consolidated
(In thousands)
ASSETS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current assets
$
315,840

 
$
9,234

 
$
61,819

 
$
(21,456
)
 
$
365,437

 
$
12,838

 
$
2,866

 
$
(25,634
)
 
$
355,507

Property and equipment
496,367

 
16,029

 
295,864

 
—

 
808,260

 
—

 
84,590

 
—

 
892,850

Investment in subsidiaries (equity method)
(214,588
)
 
—

 
(31,168
)
 
214,588

 
(31,168
)
 
(31,167
)
 
—

 
62,335

 
—

Other assets
494,776

 
—

 
41,741

 
(390,723
)
 
145,794

 
—

 
—

 
—

 
145,794

Total assets
$
1,092,395

 
$
25,263

 
$
368,256

 
$
(197,591
)
 
$
1,288,323

 
$
(18,329
)
 
$
87,456

 
$
36,701

 
$
1,394,151

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current liabilities
$
98,542

 
$
11,417

 
$
44,472

 
$
(21,456
)
 
$
132,975

 
$
12,819

 
$
1,680

 
$
(25,634
)
 
$
121,840

Long-term liabilities
1,962,342

 
19,242

 
520,231

 
(390,723
)
 
2,111,092

 
—

 
1,537

 
128,174

 
2,240,803

Stockholders' equity
(968,489
)
 
(5,396
)
 
(196,447
)
 
214,588

 
(955,744
)
 
(31,148
)
 
84,239

 
(65,839
)
 
(968,492
)
Total liabilities and equity
$
1,092,395

 
$
25,263

 
$
368,256

 
$
(197,591
)
 
$
1,288,323

 
$
(18,329
)
 
$
87,456

 
$
36,701

 
$
1,394,151

 
 
December 31, 2012
Quicksilver
Resources
Inc.
 
Restricted
Guarantor
Subsidiaries
 
Restricted
Non-
Guarantor
Subsidiaries
 
Restricted
Subsidiary
Eliminations
 
Quicksilver
and
Restricted
Subsidiaries
 
Unrestricted
Non-
Guarantor
Subsidiaries
 
Fortune
Creek
 
Consolidating
Eliminations
 
Quicksilver
Resources
Inc.
Consolidated
 
(In thousands)
ASSETS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current assets
$
261,130

 
$
105,695

 
$
76,088

 
$
(222,586
)
 
$
220,327

 
$
13,250

 
$
391

 
$
(26,455
)
 
$
207,513

Property and equipment
621,073

 
20,007

 
296,462

 
—

 
937,542

 
—

 
91,516

 
—

 
1,029,058

Investment in subsidiaries (equity method)
(191,725
)
 
—

 
(42,883
)
 
191,725

 
(42,883
)
 
(42,905
)
 
—

 
85,788

 
—

Other assets
346,972

 
—

 
41,865

 
(243,620
)
 
145,217

 
—

 
—

 
—

 
145,217

Total assets
$
1,037,450

 
$
125,702

 
$
371,532

 
$
(274,481
)
 
$
1,260,203

 
$
(29,655
)
 
$
91,907

 
$
59,333

 
$
1,381,788

LIABILITIES AND EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current liabilities
$
255,678

 
$
112,133

 
$
33,475

 
$
(222,586
)
 
$
178,700

 
$
13,230

 
$
2,316

 
$
(26,455
)
 
$
167,791

Long-term liabilities
1,914,568

 
19,242

 
524,107

 
(243,620
)
 
2,214,297

 
—

 
1,585

 
130,912

 
2,346,794

Stockholders' equity
(1,132,796
)
 
(5,673
)
 
(186,050
)
 
191,725

 
(1,132,794
)
 
(42,885
)
 
88,006

 
(45,124
)
 
(1,132,797
)
Total liabilities and equity
$
1,037,450

 
$
125,702

 
$
371,532

 
$
(274,481
)
 
$
1,260,203

 
$
(29,655
)
 
$
91,907

 
$
59,333

 
$
1,381,788



23

Condensed Consolidating Statements of Income
 
For the Three Months Ended June 30, 2013
  
Quicksilver
Resources Inc.
 
Restricted
Guarantor
Subsidiaries
 
Restricted
Non-
Guarantor
Subsidiaries
 
Restricted
Subsidiary
Eliminations
 
Quicksilver
and
Restricted
Subsidiaries
 
Unrestricted
Non-
Guarantor
Subsidiaries
 
Fortune
Creek
 
Consolidated
Eliminations
 
Quicksilver
Resources Inc.
Consolidated
 
(In thousands)
Revenue
$
131,925

 
$
202

 
$
43,370

 
$
—

 
$
175,497

 
$
—

 
$
5,737

 
$
(5,737
)
 
$
175,497

Operating expenses
86,194

 
108

 
30,740

 
—

 
117,042

 
—

 
2,470

 
(5,737
)
 
113,775

Tokyo Gas Transaction gain
333,172

 
—

 
—

 
—

 
333,172

 
—

 
—

 
—

 
333,172

Equity in net earnings of subsidiaries
(8,890
)
 
—

 
(1,558
)
 
8,890

 
(1,558
)
 
3,269

 
—

 
(1,711
)
 
—

Operating income (loss)
370,013

 
94

 
11,072

 
8,890

 
390,069

 
3,269

 
3,267

 
(1,711
)
 
394,894

Fortune Creek accretion
—

 
—

 
—

 
—

 
—

 
—

 
—

 
(4,827
)
 
(4,827
)
Interest expense and other
(122,549
)
 
—

 
(19,796
)
 
—

 
(142,345
)
 
—

 
2

 
—

 
(142,343
)
Income tax (expense) benefit
(4,941
)
 
—

 
(260
)
 
—

 
(5,201
)
 
—

 
—

 
—

 
(5,201
)
Net income (loss)
$
242,523

 
$
94

 
$
(8,984
)
 
$
8,890

 
$
242,523

 
$
3,269

 
$
3,269

 
$
(6,538
)
 
$
242,523

Other comprehensive income (loss)
(11,898
)
 
—

 
(2,969
)
 
2,969

 
(11,898
)
 
—

 
—

 
—

 
(11,898
)
Equity in OCI of subsidiaries
(2,969
)
 
—

 
—

 
—

 
(2,969
)
 
—

 
—

 
—

 
(2,969
)
Comprehensive income (loss)
$
227,656

 
$
94

 
$
(11,953
)
 
$
11,859

 
$
227,656

 
$
3,269

 
$
3,269

 
$
(6,538
)
 
$
227,656

 
 
For the Three Months Ended June 30, 2012 (Restated)
 
Quicksilver
Resources Inc.
 
Restricted
Guarantor
Subsidiaries
 
Restricted
Non-
Guarantor
Subsidiaries
 
Restricted
Subsidiary
Eliminations
 
Quicksilver
and
Restricted
Subsidiaries
 
Unrestricted
Non-
Guarantor
Subsidiaries
 
Fortune
Creek
 
Consolidated
Eliminations
 
Quicksilver
Resources Inc.
Consolidated
 
(In thousands)
Revenue
$
172,818

 
$
1,078

 
$
20,817

 
$
(695
)
 
$
194,018

 
$
—

 
$
3,202

 
$
(3,202
)
 
$
194,018

Operating expenses
1,166,469

 
893

 
181,749

 
(695
)
 
1,348,416

 
—

 
1,816

 
(3,202
)
 
1,347,030

Equity in net earnings of subsidiaries
(122,952
)
 
—

 
(1,051
)
 
122,952

 
(1,051
)
 
1,386

 
—

 
(335
)
 
—

Operating income (loss)
(1,116,603
)
 
185

 
(161,983
)
 
122,952

 
(1,155,449
)
 
1,386

 
1,386

 
(335
)
 
(1,153,012
)
Fortune Creek accretion
—

 
—

 
—

 
—

 
—

 
—

 
—

 
(4,830
)
 
(4,830
)
Interest expense and other
(37,971
)
 
—

 
(2,040
)
 
—

 
(40,011
)
 
—

 
—

 
—

 
(40,011
)
Income tax (expense) benefit
352,694

 
(65
)
 
40,809

 
—

 
393,438

 
—

 
—

 
2,393

 
395,831

Net income
$
(801,880
)
 
$
120

 
$
(123,214
)
 
$
122,952

 
$
(802,022
)
 
$
1,386

 
$
1,386

 
$
(2,772
)
 
$
(802,022
)
Other comprehensive income (loss)
(29,498
)
 
—

 
(2,952
)
 
2,952

 
(29,498
)
 
—

 
—

 
—

 
(29,498
)
Equity in OCI of subsidiaries
(2,952
)
 
—

 
—

 
—

 
(2,952
)
 
—

 
—

 
—

 
(2,952
)
Comprehensive income (loss)
$
(834,330
)
 
$
120

 
$
(126,166
)
 
$
125,904

 
$
(834,472
)
 
$
1,386

 
$
1,386

 
$
(2,772
)
 
$
(834,472
)

24


 
For the Six Months Ended June 30, 2013
  
Quicksilver
Resources Inc.
 
Restricted
Guarantor
Subsidiaries
 
Restricted
Non-
Guarantor
Subsidiaries
 
Restricted
Subsidiary
Eliminations
 
Quicksilver
and
Restricted
Subsidiaries
 
Unrestricted
Non-
Guarantor
Subsidiaries
 
Fortune
Creek
 
Consolidated
Eliminations
 
Quicksilver
Resources Inc.
Consolidated
 
(In thousands)
Revenue
$
220,826

 
$
416

 
$
72,959

 
$
—

 
$
294,201

 
$
—

 
$
11,062

 
$
(11,062
)
 
$
294,201

Operating expenses
183,217

 
138

 
59,199

 
—

 
242,554

 
—

 
4,859

 
(11,062
)
 
236,351

Tokyo Gas Transaction gain
333,172

 
—

 
—

 
—

 
333,172

 
—

 
—

 
—

 
333,172

Equity in net earnings of subsidiaries
(13,081
)
 
—

 
(3,466
)
 
13,081

 
(3,466
)
 
6,206

 
—

 
(2,740
)
 
—

Operating income (loss)
357,700

 
278

 
10,294

 
13,081

 
381,353

 
6,206

 
6,203

 
(2,740
)
 
391,022

Fortune Creek accretion
—

 
—

 
—

 
—

 
—

 
—

 
—

 
(9,672
)
 
(9,672
)
Interest expense and other
(163,717
)
 
—

 
(22,721
)
 
—

 
(186,438
)
 
—

 
3

 
—

 
(186,435
)
Income tax (expense) benefit
(11,165
)
 
—

 
(932
)
 
—

 
(12,097
)
 
—

 
—

 
—

 
(12,097
)
Net income (loss)
$
182,818

 
$
278

 
$
(13,359
)
 
$
13,081

 
$
182,818

 
$
6,206

 
$
6,206

 
$
(12,412
)
 
$
182,818

Other comprehensive income (loss)
(22,900
)
 
—

 
(6,420
)
 
6,420

 
(22,900
)
 
—

 
—

 
—

 
(22,900
)
Equity in OCI of subsidiaries
(6,420
)
 
—

 
—

 
—

 
(6,420
)
 
—

 
—

 
—

 
(6,420
)
Comprehensive income (loss)
$
153,498

 
$
278

 
$
(19,779
)
 
$
19,501

 
$
153,498

 
$
6,206

 
$
6,206

 
$
(12,412
)
 
$
153,498

 
 
For the Six Months Ended June 30, 2012 (Restated)
 
Quicksilver
Resources Inc.
 
Restricted
Guarantor
Subsidiaries
 
Restricted
Non-
Guarantor
Subsidiaries
 
Restricted
Subsidiary
Eliminations
 
Quicksilver
and
Restricted
Subsidiaries
 
Unrestricted
Non-
Guarantor
Subsidiaries
 
Fortune
Creek
 
Consolidated
Eliminations
 
Quicksilver
Resources Inc.
Consolidated
 
(In thousands)
Revenue
$
321,408

 
$
2,208

 
$
44,866

 
$
(1,598
)
 
$
366,884

 
$
—

 
$
5,599

 
$
(5,599
)
 
$
366,884

Operating expenses
1,482,081

 
1,802

 
349,209

 
(1,598
)
 
1,831,494

 
—

 
3,083

 
(5,599
)
 
1,828,978

Crestwood earn-out
41,097

 
—

 
—

 
—

 
41,097

 
—

 
—

 
—

 
41,097

Equity in net earnings of subsidiaries
(233,294
)
 
—

 
(4,662
)
 
233,294

 
(4,662
)
 
2,516

 
—

 
2,146

 
—

Operating income (loss)
(1,352,870
)
 
406

 
(309,005
)
 
233,294

 
(1,428,175
)
 
2,516

 
2,516

 
2,146

 
(1,420,997
)
Fortune Creek accretion
—

 
—

 
—

 
—

 
—

 
—

 
—

 
(9,571
)
 
(9,571
)
Interest expense and other
(76,614
)
 
—

 
(3,474
)
 
—

 
(80,088
)
 
—

 
—

 
—

 
(80,088
)
Income tax (expense) benefit
416,039

 
(142
)
 
78,779

 
—

 
494,676

 
—

 
—

 
2,393

 
497,069

Net income
$
(1,013,445
)
 
$
264

 
$
(233,700
)
 
$
233,294

 
$
(1,013,587
)
 
$
2,516

 
$
2,516

 
$
(5,032
)
 
$
(1,013,587
)
Other comprehensive income (loss)
(7,739
)
 
—

 
9,438

 
(9,438
)
 
(7,739
)
 
—

 
—

 
—

 
(7,739
)
Equity in OCI of subsidiaries
9,438

 
—

 
—

 
—

 
9,438

 
—

 
—

 
—

 
9,438

Comprehensive income (loss)
$
(1,011,746
)
 
$
264

 
$
(224,262
)
 
$
223,856

 
$
(1,011,888
)
 
$
2,516

 
$
2,516

 
$
(5,032
)
 
$
(1,011,888
)
 


 



25

Condensed Consolidating Statements of Cash Flows

 
For the Six Months Ended June 30, 2013
 
Quicksilver
Resources Inc.
 
Restricted
Guarantor
Subsidiaries
 
Restricted
Non-Guarantor
Subsidiaries
 
Quicksilver
and Restricted
Subsidiaries
 
Unrestricted
Non-Guarantor
Subsidiaries
 
Fortune
Creek
 
Quicksilver
Resources Inc.
Consolidated
 
(In thousands)
Net cash flow provided by (used in) operating activities
$
(102,770
)
 
$
(37
)
 
$
18,791

 
$
(84,016
)
 
$
—

 
$
5,910

 
$
(78,106
)
Purchases of property, plant and equipment
(36,840
)
 
37

 
(18,558
)
 
(55,361
)
 
—

 
(488
)
 
(55,849
)
Proceeds from Tokyo Gas Transaction
463,418

 
—

 
—

 
463,418

 
—

 
—

 
463,418

Proceeds from sale of properties and equipment
1,664

 
—

 
17

 
1,681

 
—

 
—

 
1,681

Purchase of marketable securities
(118,656
)
 
—

 
—

 
(118,656
)
 
—

 
—

 
(118,656
)
Net cash flow provided by (used in) investing activities
309,586

 
37

 
(18,541
)
 
291,082

 
—

 
(488
)
 
290,594

Issuance of debt
1,170,266

 
—

 
3,040

 
1,173,306

 
—

 
—

 
1,173,306

Repayments of debt
(1,113,704
)
 
—

 
(150,413
)
 
(1,264,117
)
 
—

 
—

 
(1,264,117
)
Debt issuance costs paid
(25,608
)
 
—

 
—

 
(25,608
)
 
—

 
—

 
(25,608
)
Intercompany note
(147,103
)
 
—

 
147,103

 
—

 
—

 
—

 
—

Distribution of Fortune Creek Partnership funds
—

 
—

 
—

 
—

 
—

 
(5,009
)
 
(5,009
)
Purchase of treasury stock
(1,125
)
 
—

 
—

 
(1,125
)
 
—

 
—

 
(1,125
)
Net cash flow provided by (used in) financing activities
(117,274
)
 
—

 
(270
)
 
(117,544
)
 
—

 
(5,009
)
 
(122,553
)
Effect of exchange rates on cash
—

 
—

 
20

 
20

 
—

 
1,887

 
1,907

Net increase (decrease) in cash and equivalents
89,542

 
—

 
—

 
89,542

 
—

 
2,300

 
91,842

Cash and equivalents at beginning of period
4,618

 
—

 
—

 
4,618

 
—

 
333

 
4,951

Cash and equivalents at end of period
$
94,160

 
$
—

 
$
—

 
$
94,160

 
$
—

 
$
2,633

 
$
96,793

 
 
For the Six Months Ended June 30, 2012 (Restated)
 
Quicksilver
Resources Inc.
 
Restricted
Guarantor
Subsidiaries
 
Restricted
Non-Guarantor
Subsidiaries
 
Quicksilver
and Restricted
Subsidiaries
 
Unrestricted
Non-Guarantor
Subsidiaries
 
Fortune
Creek
 
Quicksilver
Resources Inc.
Consolidated
 
(In thousands)
Net cash flow provided by operating activities
$
57,359

 
$
590

 
$
32,987

 
$
90,936

 
$
2

 
$
8,578

 
$
99,516

Purchases of property, plant and equipment
(140,256
)
 
(590
)
 
(157,508
)
 
(298,354
)
 
—

 
(8,815
)
 
(307,169
)
Proceeds from Crestwood earn-out
41,097

 
—

 
—

 
41,097

 
—

 
—

 
41,097

Proceeds from sale of properties and equipment
3,060

 
—

 
312

 
3,372

 
—

 
—

 
3,372

Net cash flow used by investing activities
(96,099
)
 
(590
)
 
(157,196
)
 
(253,885
)
 
—

 
(8,815
)
 
(262,700
)
Issuance of debt
119,000

 
—

 
136,775

 
255,775

 
—

 
—

 
255,775

Repayments of debt
(75,018
)
 
—

 
(13,097
)
 
(88,115
)
 
—

 
—

 
(88,115
)
Debt issuance costs paid
(148
)
 
—

 
—

 
(148
)
 
—

 
—

 
(148
)
Distribution of Fortune Creek Partnership funds
—

 
—

 
—

 
—

 
—

 
(1,845
)
 
(1,845
)
Proceeds from exercise of stock options
11

 
—

 
—

 
11

 
—

 
—

 
11

Purchase of treasury stock
(2,364
)
 
—

 
—

 
(2,364
)
 
—

 
—

 
(2,364
)
Net cash flow provided by (used in) financing activities
41,481

 
—

 
123,678

 
165,159

 
—

 
(1,845
)
 
163,314

Effect of exchange rates on cash
—

 
—

 
531

 
531

 
—

 
196

 
727

Net increase (decrease) in cash and equivalents
2,741

 
—

 
—

 
2,741

 
2

 
(1,886
)
 
857

Cash and equivalents at beginning of period
363

 
—

 
—

 
363

 
—

 
12,783

 
13,146

Cash and equivalents at end of period
$
3,104

 
$
—

 
$
—

 
$
3,104

 
$
2

 
$
10,897

 
$
14,003





26

13. SEGMENT INFORMATION
We operate in two geographic segments, the U.S. and Canada, where we are engaged in the exploration and production segment of the oil and gas industry. Additionally, we operate a significantly smaller midstream segment in the U.S. and Canada, where we provide natural gas gathering and processing services, primarily to our U.S. and Canadian exploration and production segments. Following the formation of our partnership with KKR, beginning in January 2012, we have additional midstream operations in Canada through Fortune Creek. Revenue earned by Fortune Creek for the gathering and processing of our gas is eliminated on a consolidated basis as is the GPT recognized by our producing properties. Based on the immateriality of our midstream segment, we have combined our U.S. and Canadian midstream information. We evaluate performance based on operating income and property and equipment costs incurred.
 
Exploration &
Production
 
 
 
 
 
 
 
Quicksilver Consolidated
 
U.S.
 
Canada
 
Midstream
 
Corporate
 
Elimination
 
 
 
 
 
 
 
 
 
 
 
 
 
For the Three Months Ended June 30:
(In thousands)
2013
 
 
 
 
 
 
 
 
 
 
 
Revenue
$
140,393

 
$
34,264

 
$
6,576

 
$
—

 
$
(5,736
)
 
$
175,497

DD&A
10,323

 
3,047

 
1,307

 
588

 
—

 
15,265

Operating income (loss)
392,786

 
16,209

 
3,362

 
(17,463
)
 
—

 
394,894

Property and equipment costs incurred
14,760

 
2,620

 
675

 
9,344

 
—

 
27,399

2012 (Restated)
 
 
 
 
 
 
 
 
 
 
 
Revenue
$
166,642

 
$
26,249

 
$
5,024

 
$
—

 
$
(3,897
)
 
$
194,018

DD&A
39,410

 
6,700

 
1,320

 
586

 
—

 
48,016

Impairment expense
1,042,737

 
156,989

 
—

 
—

 
—

 
1,199,726

Operating income (loss)
(975,741
)
 
(158,465
)
 
184

 
(18,990
)
 
—

 
(1,153,012
)
Property and equipment costs incurred
44,546

 
103,778

 
5,459

 
1,914

 
—

 
155,697

For the Six Months Ended June 30:
 
2013
 
 
 
 
 
 
 
 
 
 
 
Revenue
$
221,949

 
$
70,523

 
$
12,791

 
$
—

 
$
(11,062
)
 
294,201

DD&A
23,451

 
6,237

 
2,647

 
1,186

 
—

 
33,521

Operating income (loss)
399,710

 
19,050

 
6,486

 
(34,224
)
 
—

 
391,022

Property and equipment costs incurred
35,313

 
5,684

 
755

 
9,984

 
—

 
51,736

2012 (Restated)
 
 
 
 
 
 
 
 
 
 
 
Revenue
$
308,418

 
$
56,382

 
$
9,282

 
$
—

 
$
(7,198
)
 
366,884

DD&A
81,227

 
17,516

 
2,528

 
1,184

 
—

 
102,455

Impairment expense
1,220,777

 
296,877

 
—

 
—

 
—

 
1,517,654

Operating income (loss)
(1,083,053
)
 
(299,666
)
 
406

 
(38,684
)
 
—

 
(1,420,997
)
Property and equipment costs incurred
116,977

 
157,401

 
11,439

 
5,447

 
—

 
291,264

Property, plant and equipment-net
 
 
 
 
 
 
 
 
 
 
 
June 30, 2013
$
490,516

 
$
294,405

 
$
100,619

 
$
7,310

 
$
—

 
$
892,850

December 31, 2012
614,071

 
294,921

 
111,523

 
8,543

 
—

 
1,029,058

Total assets
 
 
 
 
 
 
 
 
 
 
 
June 30, 2013
905,866

 
368,256

 
112,719

 
7,310

 
—

 
$
1,394,151

December 31, 2012
784,104

 
371,532

 
217,609

 
8,543

 
—

 
1,381,788

14. SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid (received) for interest and income taxes was as follows:
 
 
For the Six Months Ended
June 30,
 
2013
 
2012
 
 
 
 
 
(In thousands)
Interest, net of capitalized interest
$
129,569

 
$
77,940

Income taxes
1,108

 
(1,565
)


27

Other significant non-cash transactions were as follows:
 
 
For the Six Months Ended
June 30,
 
2013
 
2012
 
 
 
 
 
(In thousands)
Working capital related to capital expenditures
$
5,742

 
$
98,692


15. TRANSACTIONS AND OTHER MATTERS WITH RELATED PARTIES
As of June 30, 2013, members of the Darden family and entities controlled by them beneficially owned approximately 30% of our outstanding common stock. Glenn Darden and Anne Darden Self are officers and directors and Thomas Darden is an employee and director of Quicksilver.
During the first six months of 2013 and 2012, we paid $0.3 million and $0.3 million, respectively, for use of an airplane owned by an entity controlled by members of the Darden family. Usage rates were determined based upon comparable rates charged by third parties.
Payments received from Mercury, a company owned by members of the Darden family, for sublease rentals, employee insurance coverage and administrative services were less than $0.1 million for the first six months of 2013 and 2012.
In May 2013, we entered into an agreement with Thomas F. Darden with respect to Mr. Darden’s retirement and Mr. Darden’s provision of consulting services following his retirement. Effective May 15, 2013, Mr. Darden retired from his executive position and is expected to remain an employee that does not serve as an officer through December 31, 2013 and a member of the Board of Directors as Chairman Emeritus. While an employee, Mr. Darden will continue to receive his same base salary, benefits and, subject to the execution of a general release and waiver of claims, annual incentive compensation opportunity. In addition, he will be entitled to $12,500 per month, and additional reimbursements, with respect to certain business expenses. In recognition of his contributions to the Tokyo Gas Transaction, Mr. Darden received a cash bonus of $1.1 million, of which $0.6 million was paid in May 2013 with the remaining payable in August 2013, and a stock option grant with an aggregate grant date fair value of $1.1 million granted in May 2013. Both the cash bonus and the stock option grant are included in the Tokyo Gas Transaction gain on our consolidated financial statements. In connection with his retirement, he will be entitled to full vesting of his outstanding unvested equity awards (242,724 shares of restricted stock and 304,407 options); reimbursement of legal fees in connection with the agreement, up to $40,000; and payment of accrued and unused vacation and estimated COBRA premiums. Mr. Darden will be engaged as a consultant for the three-year period following his retirement and will receive a monthly consulting fee of $45,000. While a consultant, Mr. Darden will be entitled to $12,500 per month, and additional reimbursements, with respect to certain business expenses. In addition, Mr. Darden will be eligible to receive bonuses of up to $2.5 million in the aggregate under certain circumstances in connection with certain possible future strategic transactions occurring on or before December 31, 2016.

28

ITEM 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following Management’s Discussion and Analysis (“MD&A”) is intended to help readers of our financial statements understand our business, results of operations, financial condition, liquidity and capital resources. MD&A is provided as a supplement to, and should be read in conjunction with, the other sections of this Quarterly Report as well as our 2012 Annual Report on Form 10-K. We conduct our operations in two segments: (1) our more dominant exploration and production segment, and (2) our significantly smaller midstream segment. Except as otherwise specifically noted, or as the context requires otherwise, and except to the extent that differences between these segments or our geographic segments are material to an understanding of our business taken as a whole, we present this MD&A on a consolidated basis.
Our MD&A includes the following sections:
•
2013 Highlights – a summary of significant activities and events affecting Quicksilver
•
2013 Capital Program – a summary of our planned capital expenditures during 2013
•
Results of Operations – an analysis of our consolidated results of operations for the three- and six-month periods presented in our financial statements
•
Liquidity, Capital Resources and Financial Position – an analysis of our cash flows, sources and uses of cash, contractual obligations and commercial commitments
2013 HIGHLIGHTS
Joint Venture Update
In March 2013, we entered into a Purchase and Sale Agreement with TGBR to sell an undivided 25% of our Barnett Shale Asset for a purchase price of $485 million. The transaction closed in April 2013, but was effective as of September 1, 2012. The purchase price was subject to customary purchase price adjustments, which resulted in TGBR paying us $464.0 million, including an estimated final adjustment of $0.6 million in the third quarter of 2013. We recognized a gain of $333.2 million before consideration of income taxes as a result of this transaction.
In July 2013, we executed an agreement to sell all of our interest in approximately 143,000 acres and 2.6 MMBbl of reserves located in our Southern Alberta Asset. The sale is expected to close in the third quarter and is subject to customary closing conditions.
We are running an integrated joint venture process in our Horn River Asset with a select group of potential partners. The process is currently in the formal bidding stage.
We are progressing with the effort to attract outside capital for our West Texas Asset and expect a minimal drilling program until a joint venture partner is secured.
Significant Contract Revisions
In the second quarter of 2013, we refinanced a portion of our debt to extend maturities and reduce the weighted average interest costs on outstanding debt. We also amended our Combined Credit Agreements primarily to loosen the financial covenants through the second quarter of 2016 and to permit the incurrence of up to $825 million of second lien debt. Specific refinancing activities and changes to the Combined Credit Agreements are outlined in Note 5 to the condensed consolidated financial statements in Item 1 of this Quarterly Report.
In July 2013, in light of the Canadian Governor in Council's failure to approve NGTL's construction of the Komie North Project, NGTL terminated the Project and Expenditure Authorization (PEA), which authorized NGTL to construct the Komie North Project and the related meter station. The PEA necessitated the construction of a treatment facility and required financial guarantees to cover NGTL's costs for the Komie North Project. We have provided C$14 million in letters of credit to support this obligation. NGTL will release the letters of credit in connection with our paying NGTL an amount equal to actual costs incurred by NGTL, which is estimated to be approximately $12.8 million and is reflected in other income (expense) in our consolidated financial statements. With this termination of the PEA as described above, our agreement to deliver gas to the Komie North Project, has also terminated. We maintain our ability to sell gas at the Station 2 and AECO hubs, as our current production is served by existing treating facilities and pipelines.
2013 CAPITAL PROGRAM
We incurred costs related to our capital program of $51.7 million for the first six months of 2013. We continue to anticipate full year 2013 spending to approximate $120 million.


29

RESULTS OF OPERATIONS
The following discussion compares the results of operations for the three months ended June 30, 2013 and 2012, or the 2013 quarter and 2012 quarter, respectively. “Other U.S.” refers to the combined amounts for our Niobrara Asset, West Texas Asset and Southern Alberta Asset.
Revenue
We aggregate production revenue and realized cash gains (losses) on derivatives not treated as hedges in measuring revenue from our oil and gas production. Historically, we have used hedge accounting and combining these items mirrors our views of the derivatives' usefulness and provides more comparability.
Production Revenue and Realized Cash Gains (Losses) on Derivatives by Operating Area:
 
Natural Gas
 
NGL
 
Oil
 
Total
 
2013
 
2012
 
2013
 
2012
 
2013
 
2012
 
2013
 
2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(In millions)
Barnett Shale
$
50.3

 
$
41.7

 
$
17.5

 
$
34.3

 
$
1.7

 
$
3.0

 
$
69.5

 
$
79.0

Other U.S.
—

 
0.1

 
—

 
0.1

 
2.9

 
3.3

 
2.9

 
3.5

Hedging
14.4

 
45.4

 
—

 
6.3

 
—

 
—

 
14.4

 
51.7

U.S.
64.7

 
87.2

 
17.5

 
40.7

 
4.6

 
6.3

 
86.8

 
134.2

Horseshoe Canyon
14.7

 
8.9

 
—

 
—

 
—

 
—

 
14.7

 
8.9

Horn River
16.8

 
2.6

 
—

 
—

 
—

 
—

 
16.8

 
2.6

Hedging
2.8

 
4.6

 
—

 
—

 
—

 
—

 
2.8

 
4.6

Canada
34.3

 
16.1

 
—

 
—

 
—

 
—

 
34.3

 
16.1

Consolidated production revenue
$
99.0

 
$
103.3

 
$
17.5

 
$
40.7

 
$
4.6

 
$
6.3

 
$
121.1

 
$
150.3

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
U.S. realized cash derivative gains (losses)
$
(4.0
)
 
$
8.9

 
$
—

 
$
—

 
$
—

 
$
—

 
$
(4.0
)
 
$
8.9

Canada realized cash derivative gains
0.5

 
8.2

 
—

 
—

 
—

 
—

 
0.5

 
8.2

Consolidated realized cash derivative gains (losses)
(3.5
)
 
17.1

 
—

 
—

 
—

 
—

 
(3.5
)
 
17.1

Consolidated production revenue and realized cash derivative gains (1)
$
95.5

 
$
120.4

 
$
17.5

 
$
40.7

 
$
4.6

 
$
6.3

 
$
117.6

 
$
167.4

(1) 
Realized cash derivative gains from derivatives not treated as hedges are included in net derivative gains. Unrealized derivative gains and losses, non-cash loss in fair value from restructured natural gas derivatives and hedge ineffectiveness make up the remainder of net derivative gains as reported on our statement of income. A discussion of net derivative gains is found elsewhere in our discussion of our results of operations. Total revenue is comprised of production revenue, net derivative gains , sales of purchased natural gas and other revenue.
Average Daily Production Volume:
 
Natural Gas
 
NGL
 
Oil
 
Equivalent Total
 
2013
 
2012
 
2013
 
2012
 
2013
 
2012
 
2013
 
2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(MMcfd)
 
(Bbld)
 
(Bbld)
 
(MMcfed)
Barnett Shale
137.7

 
216.8

 
7,069

 
11,339

 
207

 
366

 
181.4

 
287.1

Other U.S.
—

 
0.7

 
21

 
26

 
377

 
441

 
2.4

 
3.5

Total U.S.
137.7

 
217.5

 
7,090

 
11,365

 
584

 
807

 
183.8

 
290.6

Horseshoe Canyon
48.9

 
53.2

 
7

 
—

 
—

 
—

 
48.9

 
53.2

Horn River
54.6

 
14.9

 
—

 
—

 
—

 
—

 
54.6

 
14.9

Total Canada
103.5

 
68.1

 
7

 
—

 
—

 
—

 
103.5

 
68.1

Total
241.2

 
285.6

 
7,097

 
11,365

 
584

 
807

 
287.3

 
358.7



30

Average Realized Price:
 
Natural Gas
 
NGL
 
Oil
 
Equivalent Total
 
2013
 
2012
 
2013
 
2012
 
2013
 
2012
 
2013
 
2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(per Mcf)
 
(per Bbl)
 
(per Bbl)
 
(per Mcfe)
Barnett Shale
$
4.01

 
$
2.11

 
$
27.14

 
$
33.23

 
$
88.85

 
$
89.73

 
$
4.21

 
$
3.02

Other U.S.
3.94

 
2.04

 
50.05

 
55.18

 
83.80

 
82.42

 
13.70

 
11.26

Hedging
1.15

 
2.29

 
—

 
6.08

 
—

 
—

 
0.86

 
1.95

Total U.S.
5.16

 
4.40

 
27.21

 
39.36

 
85.59

 
85.73

 
5.19

 
5.07

Horseshoe Canyon
$
3.30

 
$
1.84

 
$
57.84

 
$
—

 
$
—

 
$
—

 
$
3.31

 
$
1.84

Horn River
3.38

 
1.91

 
—

 
—

 
—

 
—

 
3.38

 
1.91

Hedging
0.29

 
0.75

 
—

 
—

 
—

 
—

 
0.29

 
0.75

Total Canada
$
3.64

 
$
2.61

 
$
57.84

 
$
—

 
$
—

 
$
—

 
$
3.64

 
$
2.61

Consolidated production revenue
$
4.51

 
$
3.97

 
$
27.24

 
$
39.36

 
$
85.61

 
$
85.73

 
$
4.63

 
$
4.60

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
U.S. realized cash derivative gains (losses)
$
(0.32
)
 
$
0.45

 
$
—

 
$
—

 
$
—

 
$
—

 
$
(0.24
)
 
$
0.34

Canada realized cash derivative gains
0.06

 
1.33

 
—

 
—

 
—

 
—

 
0.06

 
1.33

Consolidated realized cash derivative gains (losses)
(0.16
)
 
0.66

 
—

 
—

 
—

 
—

 
(0.13
)
 
0.52

Consolidated production revenue and realized cash derivative gains
$
4.35

 
$
4.63

 
$
27.24

 
$
39.36

 
$
85.61

 
$
85.73

 
$
4.50

 
$
5.12


The following table summarizes the changes in our production revenue and realized cash gains on derivatives:
 
Natural
Gas
 
NGL
 
Oil
 
Total
 
 
 
 
 
 
 
 
 
(In thousands)
Consolidated production revenue and realized cash derivative gains for the 2012 quarter
$
120,401

 
$
40,709

 
$
6,300

 
$
167,410

Volume variances
(8,285
)
 
(12,929
)
 
(1,739
)
 
(22,953
)
Hedge revenue variances
(32,827
)
 
(6,285
)
 
—

 
(39,112
)
Realized cash derivative variance (1)
(20,575
)
 
—

 
—

 
(20,575
)
Price variances
36,787

 
(3,903
)
 
(8
)
 
32,876

Consolidated production revenue and realized cash derivative gains for the 2013 quarter
$
95,501

 
$
17,592

 
$
4,553

 
$
117,646

(1) 
This amount is also included in the production revenue and realized cash derivatives gains table above.
Consolidated production revenue and realized cash derivative gains from natural gas for the 2013 quarter decreased from the 2012 quarter due to lower volumes produced and a net decrease in hedge revenue and realized cash derivative gains due to improved natural gas prices partially offset by an increase in the realized price for natural gas. Consolidated production revenue and realized cash derivative gains from NGL revenue for the 2013 quarter decreased from the 2012 quarter due to lower volumes produced, decreased realized prices and the 2013 quarter not including NGL derivatives. The decrease in natural gas and NGL volumes is primarily due to the Tokyo Gas Transaction and is partially offset by an increase in volumes in our Horn River Asset as additional wells began producing in the second half of 2012.
At June 30, 2013, we had $1.8 million in deferred revenue related to NGLs held in storage by the purchaser of the NGLs. The title and risk of loss of the NGL volumes have transferred to the purchaser. However, the sales price of the NGLs will not

31

be determined until the NGLs undergo further processing by the purchaser, which is expected to occur during the second half of 2013. We have deferred recognition of production and revenue on these NGL volumes as of June 30, 2013.
Our production revenue and realized derivative cash gain (loss) for the 2013 quarter and 2012 quarter was higher by $13.7 million and $73.4 million, respectively, because of our derivative activities.
Sales of Purchased Natural Gas and Costs of Purchased Natural Gas
 
For the Three Months Ended
June 30,
 
2013
 
2012
 
 
 
 
 
(In thousands)
Sales of purchased natural gas
 
Purchases from Eni
$
17,903

 
$
8,724

Purchases from others
782

 
718

Total
18,685

 
9,442

Costs of purchased natural gas sold
 
 
 
Purchases from Eni
17,906

 
8,723

Purchases from others
773

 
614

Total
18,679

 
9,337

Net sales and purchases of natural gas
$
6

 
$
105

Net Derivative Gains
The following table summarizes our net derivative gains and losses:
 
For the Three Months Ended
June 30,
 
2013
 
2012
 
 
 
 
 
(In thousands)
Unrealized mark-to-market changes in fair value of natural gas derivative gains (1)
$
38,313

 
9,229

Realized cash settlements of natural gas derivative gains (losses)
(3,476
)
 
17,100

Gain from hedge ineffectiveness
—

 
6,810

Net derivative gains
34,837

 
33,139

(1) 
Unrealized mark-to-market changes in fair value are subject to continuing market risk.
In 2012 we began to account for the fair value changes of certain natural gas derivatives in the income statement as reflected in the above table.
Other Revenue
 
For the Three Months Ended
June 30,
 
2013
 
2012
 
 
 
 
 
(In thousands)
Midstream revenue from third parties:
 
Canada
$
638

 
$
744

Texas
216

 
382

Total midstream revenue
854

 
1,126

Total
$
854

 
$
1,126


32

Operating Expense
Lease Operating
 
For the Three Months Ended June 30,
 
2013
 
2012
 
 
 
(In thousands, except per unit amounts)
 
 
 
Per
Mcfe
 
 
 
Per
Mcfe
Barnett Shale
 
 
 
 
 
 
 
Cash expense
$
10,274

 
$
0.62

 
$
12,936

 
$
0.50

Equity compensation
214

 
0.01

 
227

 
0.01

 
$
10,488

 
$
0.63

 
$
13,163

 
$
0.51

Other U.S.
 
 
 
 
 
 
 
Cash expense
$
1,345

 
$
6.16

 
$
2,139

 
$
6.76

Equity compensation
112

 
0.51

 
38

 
0.12

 
$
1,457

 
$
6.67

 
$
2,177

 
$
6.88

Total U.S.
 
 
 
 
 
 
 
Cash expense
$
11,619

 
$
0.69

 
$
15,075

 
$
0.57

Equity compensation
326

 
0.02

 
265

 
0.01

 
$
11,945

 
$
0.71

 
$
15,340

 
$
0.58

Horseshoe Canyon
 
 
 
 
 
 
 
Cash expense
$
7,173

 
$
1.61

 
$
5,878

 
$
1.21

Equity compensation
48

 
0.01

 
83

 
0.01

 
$
7,221

 
$
1.62

 
$
5,961

 
$
1.22

Horn River
 
 
 
 
 
 
 
Cash expense
$
1,047

 
$
0.21

 
$
298

 
$
0.92

Equity compensation
—

 
—

 
—

 
—

 
$
1,047

 
$
0.21

 
$
298

 
$
0.92

Total Canada
 
 
 
 
 
 
 
Cash expense
$
8,220

 
$
0.87

 
$
6,176

 
$
1.00

Equity compensation
48

 
0.01

 
83

 
0.01

 
$
8,268

 
$
0.88

 
$
6,259

 
$
1.01

Total Company
 
 
 
 
 
 
 
Cash expense
$
19,839

 
$
0.76

 
$
21,251

 
$
0.65

Equity compensation
374

 
0.01

 
348

 
0.01

 
$
20,213

 
$
0.77

 
$
21,599

 
$
0.66


Lease operating expense for the 2013 quarter in the Barnett Shale increased on a unit basis primarily due to fixed lease operating charges being distributed over lower volume compared to the 2012 quarter. In Canada, the increase in lease operating expense on a gross basis compared to the 2012 quarter is primarily due to increased volumes in our Horn River Asset. The reduction on a unit basis is due to the increased volumes in our Horn River Asset as fixed lease operating costs were distributed over a higher volume compared to the 2012 quarter.

33

Gathering, Processing and Transportation
 
For the Three Months Ended June 30,
 
2013
 
2012
 
 
 
(In thousands, except per unit amounts)
 
 
 
Per
Mcfe
 
 
 
Per
Mcfe
Barnett Shale
$
25,941

 
$
1.57

 
$
36,464

 
$
1.40

Other U.S.
2

 
0.01

 
4

 
0.01

Total U.S.
25,943

 
1.55

 
36,468

 
1.38

Horseshoe Canyon
794

 
0.18

 
960

 
0.20

Horn River
9,937

 
2.00

 
5,196

 
3.83

Total Canada
10,731

 
1.14

 
6,156

 
0.99

Total
$
36,674

 
$
1.40

 
$
42,624

 
$
1.31


U.S. GPT on a gross basis decreased primarily due to lower volume in our Barnett Shale Asset, with the Tokyo Gas Transaction contributing to this decline. On a unit basis, the 2013 quarter was higher primarily due to our production mix between areas within our Barnett Shale Asset. To a lesser extent the decrease was a result of deferred sales production to later in 2013 for our NGLs without a reduction in transportation expense as the NGLs were transported to the third-party facility for storage and incurred demand charges for our NGL transportation contracts. Canadian GPT increased in total for the 2013 quarter as compared to the 2012 quarter as a result of increased volumes in our Horn River Asset, and decreased on a unit basis in the Horn River primarily as a result of fixed costs under our firm agreements with third parties being spread over increased volumes in the 2013 quarter. Canadian GPT includes unused firm capacity of $1.7 million and $1.8 million for the 2013 quarter and the 2012 quarter, respectively.
Production and Ad Valorem Taxes
 
For the Three Months Ended June 30,
 
2013
 
2012
 
 
 
(In thousands, except per unit amounts)
 
 
 
Per
Mcfe
 
 
 
Per
Mcfe
Production taxes
 
 
 
 
 
 
 
Barnett Shale
$
1,038

 
$
0.06

 
$
1,338

 
$
0.05

Other U.S.
226

 
1.03

 
165

 
0.68

Total U.S.
1,264

 
0.08

 
1,503

 
0.06

Horseshoe Canyon
(29
)
 
(0.01
)
 
50

 
0.01

Horn River
—

 
—

 
—

 
—

Total Canada
(29
)
 
—

 
50

 
0.01

Total production taxes
1,235

 
0.05

 
1,553

 
0.05

Ad valorem taxes
 
 
 
 
 
 
 
Barnett Shale
$
3,119

 
$
0.19

 
$
4,579

 
$
0.18

Other U.S.
104

 
0.48

 
155

 
0.49

Total U.S.
3,223

 
0.19

 
4,734

 
0.18

Horseshoe Canyon
361

 
0.08

 
829

 
0.17

Horn River
481

 
0.10

 
73

 
0.05

Total Canada
842

 
0.09

 
902

 
0.15

Total ad valorem taxes
4,065

 
0.16

 
5,636

 
0.17

Total
$
5,300

 
$
0.20

 
$
7,189

 
$
0.22



34

Depletion, Depreciation and Accretion
 
For the Three Months Ended June 30,
 
2013
 
2012
 
 
 
(In thousands, except per unit amounts)
 
 
 
Per
Mcfe
 
 
 
Per
Mcfe
Depletion
 
 
 
 
 
 
 
U.S.
$
8,593

 
$
0.51

 
$
36,242

 
$
1.37

Canada
1,087

 
0.12

 
6,044

 
0.97

Total depletion
9,680

 
0.37

 
42,286

 
1.30

Depreciation of other fixed assets
 
 
 
 
 
 
 
U.S.
$
1,915

 
$
0.11

 
$
2,300

 
$
0.09

Canada
2,396

 
0.25

 
2,406

 
0.39

Total depreciation
4,311

 
0.16

 
4,706

 
0.14

Accretion
1,274

 
0.05

 
1,024

 
0.03

Total
$
15,265

 
$
0.58

 
$
48,016

 
$
1.47

U.S. depletion for the 2013 quarter, when compared to the 2012 quarter, reflected a decrease in production and a decrease in the current year depletion rate due to impairments recognized in 2012. Canadian depletion decreased for the 2013 quarter, when compared to the 2012 quarter, due to a decrease in the current year depletion rate as a result of impairment recognized in 2012 partially offset by an increase in production.
Impairment Expense
We perform quarterly ceiling tests to assess impairment of our oil and gas properties. We also assess our fixed assets reported outside the full-cost pool when circumstances indicate impairment may have occurred. The calculation of impairment expense is more fully described in Note 4 to the condensed consolidated interim financial statements in Item 1 of this Quarterly Report.
In the 2012 quarter, we recognized $1.0 billion and $157.0 million in non-cash charges for impairment of our U.S. and Canadian oil and gas properties, respectively. No impairment was recognized in the 2013 quarter.
General and Administrative
 
For the Three Months Ended June 30,
 
2013
 
2012
 
 
 
(In thousands, except per unit amounts)
 
 
 
Per
Mcfe
 
 
 
Per
Mcfe
Cash expense
$
8,982

 
$
0.34

 
$
11,700

 
$
0.36

Audit and accounting fees
318

 
0.01

 
2,661

 
0.08

Strategic transaction costs
1,870

 
0.07

 
—

 
—

Equity compensation
5,705

 
0.22

 
4,044

 
0.12

Total
$
16,875

 
$
0.64

 
$
18,405

 
$
0.56

Tokyo Gas Transaction Gain
In April 2013, we recognized a $333.2 million gain upon closing of the Tokyo Gas Transaction. Further information regarding the transaction can be found in Note 2 to our condensed consolidated interim financial statements included in Item 1 of this Quarterly Report.
Other Income (Expense)
In June 2013, we recognized an expense of $12.8 million in connection with the termination of the PEA with NGTL. Further information regarding the transaction can be found in Note 8 to our condensed consolidated interim financial statements included in Item 1 of this Quarterly Report. In the 2013 quarter the Canadian foreign currency exchange rate change resulted in a recognized loss of $2.4 million.

35

Fortune Creek Accretion
In December 2011, we entered into an agreement with KKR to form Fortune Creek to construct and operate midstream assets for natural gas produced by us and others primarily in British Columbia. KKR’s contribution is shown as Partnership liability in the condensed consolidated balance sheet, and we recognize accretion expense to reflect the rate of return earned by KKR via its investment.
Interest Expense
 
For the Three Months Ended
June 30,
 
2013
 
2012
 
 
 
 
 
(In thousands)
Interest costs on debt outstanding
$
42,174

 
$
42,488

Add:
 
 
 
Fees paid on letters of credit outstanding
53

 
23

Net expense paid on debt refinancing
67,038

 
—

Non-cash interest (1)
19,914

 
1,727

Total interest costs incurred
129,179

 
44,238

Less:
 
 
 
Interest capitalized
(1,941
)
 
(4,162
)
Interest expense
$
127,238

 
$
40,076

(1) 
Amortization of deferred financing costs, original issue discount net of interest swap settlement amortization, including portions related to the early redemption of our Senior Notes due 2015 and Senior Notes due 2016 of $18.9 million.
Interest costs incurred for the 2013 quarter were higher when compared to the 2012 quarter primarily because of the refinancing of our debt securities in June 2013, which is more fully discussed in Note 5 to our condensed consolidated interim financial statements included in Item 1 of this Quarterly Report.
Income Taxes
The effective tax rates for the three months ended June 30, 2013 and 2012 are as follows:
 
For the Three Months Ended
June 30,
 
2013
 
2012
 
 
 
 
 
(in thousands)
Income tax (benefit) expense - U.S.
$
4,941

 
$
(352,630
)
Effective tax rate-U.S.
1.9
 %
 
34.2
%
Income tax (benefit) expense - Canada
$
260

 
$
(43,202
)
Effective tax rate-Canada
(3.0
)%
 
26.0
%
Income tax (benefit) expense - total
$
5,201

 
$
(395,832
)
Effective tax rate-total
2.1
 %
 
33.0
%
Income tax expense for the 2013 quarter included a reduction in the U.S. valuation allowance of $84.9 million primarily related to the gain recognized from the Tokyo Gas Transaction and an increase in the Canadian valuation allowance of $0.4 million. During the latter half of 2012, we determined reduced likelihood of realizing deferred tax benefits primarily related to our cumulative net operating losses. Income tax recognized for the 2013 quarter is a result of hedge gains previously deferred in AOCI being realized during the quarter and the net tax impact being recognized without a corresponding valuation allowance. The effective rate for the 2012 quarter reflected a projection of full year of U.S. and Canadian taxable losses.


36

RESULTS OF OPERATIONS
Six Months Ended June 30, 2013 and 2012
The following discussion compares the results of operations for the six months ended June 30, 2013 and 2012, or the 2013 period and 2012 period, respectively. “Other U.S.” refers to the combined amounts for our Niobrara Asset, West Texas Asset and Southern Alberta Asset.
Revenue
We aggregate production revenue and realized cash gains (losses) on derivatives not treated as hedges in measuring revenue from our oil and gas production. Historically, we have used hedge accounting and combining these items mirrors our views of the derivatives' usefulness and provides more comparability.
Production Revenue and Realized Cash Gains (Losses) on Derivatives by Operating Area:
 
Natural Gas
 
NGL
 
Oil
 
Total
 
2013
 
2012
 
2013
 
2012
 
2013
 
2012
 
2013
 
2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(In millions)
Barnett Shale
$
102.0

 
$
96.8

 
$
41.2

 
$
78.9

 
$
3.9

 
$
6.2

 
$
147.1

 
$
181.9

Other U.S.
0.1

 
0.3

 
0.2

 
0.2

 
6.0

 
7.4

 
6.3

 
7.9

Hedging
29.7

 
85.0

 
—

 
6.6

 
—

 
—

 
29.7

 
91.6

U.S.
131.8

 
182.1

 
41.4

 
85.7

 
9.9

 
13.6

 
183.1

 
281.4

Horseshoe Canyon
29.9

 
22.3

 
0.1

 
0.1

 
—

 
—

 
30.0

 
22.4

Horn River
34.6

 
4.7

 
—

 
—

 
—

 
—

 
34.6

 
4.7

Hedging
6.0

 
8.3

 
—

 
—

 
—

 
—

 
6.0

 
8.3

Canada
70.5

 
35.3

 
0.1

 
0.1

 
—

 
—

 
70.6

 
35.4

Consolidated production revenue
$
202.3

 
$
217.4

 
$
41.5

 
$
85.8

 
$
9.9

 
$
13.6

 
$
253.7

 
$
316.8

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
U.S. realized cash derivative gains
$
1.5

 
$
12.5

 
$
—

 
$
—

 
$
—

 
$
—

 
$
1.5

 
$
12.5

Canada realized cash derivative gains
4.7

 
10.2

 
—

 
—

 
—

 
—

 
4.7

 
10.2

Consolidated realized cash derivative gains
6.2

 
22.7

 
—

 
—

 
—

 
—

 
6.2

 
22.7

Consolidated production revenue and realized cash derivative gains (1)
$
208.5

 
$
240.1

 
$
41.5

 
$
85.8

 
$
9.9

 
$
13.6

 
$
259.9

 
$
339.5

(1) 
Realized cash derivative gains from derivatives not treated as hedges are included in net derivative gains (losses). Unrealized derivative gains and losses, non-cash loss in fair value from restructured natural gas derivatives and hedge ineffectiveness make up the remainder of net derivative gains (losses) as reported on our statement of income. A discussion of net derivative gains (losses) is found elsewhere in our discussion of our results of operations. Total revenue is comprised of production revenue, net derivative gains (losses), sales of purchased natural gas and other revenue.
Average Daily Production Volume:
 
Natural Gas
 
NGL
 
Oil
 
Equivalent Total
 
2013
 
2012
 
2013
 
2012
 
2013
 
2012
 
2013
 
2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(MMcfd)
 
(Bbld)
 
(Bbld)
 
(MMcfed)
Barnett Shale
156.7

 
224.8

 
8,349

 
11,416

 
244

 
363

 
208.3

 
295.5

Other U.S.
0.1

 
0.7

 
22

 
26

 
392

 
463

 
2.6

 
3.7

Total U.S.
156.8

 
225.5

 
8,371

 
11,442

 
636

 
826

 
210.9

 
299.2

Horseshoe Canyon
50.1

 
55.6

 
7

 
7

 
—

 
—

 
50.1

 
55.6

Horn River
61.3

 
13.1

 
—

 
—

 
—

 
—

 
61.2

 
13.1

Total Canada
111.4

 
68.7

 
7

 
7

 
—

 
—

 
111.3

 
68.7

Total
268.2

 
294.2

 
8,378

 
11,449

 
636

 
826

 
322.2

 
367.9


37


Average Realized Price:
 
Natural Gas
 
NGL
 
Oil
 
Equivalent Total
 
2013
 
2012
 
2013
 
2012
 
2013
 
2012
 
2013
 
2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(per Mcf)
 
(per Bbl)
 
(per Bbl)
 
(per Mcfe)
Barnett Shale
$
3.60

 
$
2.37

 
$
27.26

 
$
37.96

 
$
89.58

 
$
94.13

 
$
3.90

 
$
3.38

Other U.S.
3.49

 
2.22

 
51.34

 
54.33

 
84.89

 
87.25

 
13.59

 
11.84

Hedging
1.05

 
2.07

 
—

 
3.17

 
—

 
—

 
0.78

 
1.68

Total U.S.
$
4.64

 
$
4.44

 
$
27.33

 
$
41.17

 
$
86.69

 
$
90.27

 
$
4.80

 
$
5.17

Horseshoe Canyon
$
3.30

 
$
2.21

 
$
61.74

 
$
69.79

 
$
—

 
$
—

 
$
3.30

 
$
2.22

Horn River
3.12

 
1.98

 
—

 
—

 
—

 
—

 
3.12

 
1.98

Hedging
0.30

 
0.66

 
—

 
—

 
—

 
—

 
0.30

 
0.66

Total Canada
$
3.50

 
$
2.82

 
$
61.74

 
$
69.79

 
$
—

 
$
—

 
$
3.50

 
$
2.83

Consolidated production revenue
$
4.17

 
$
4.06

 
$
27.36

 
$
41.18

 
$
86.69

 
$
90.28

 
$
4.35

 
$
4.73

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
U.S. realized cash derivative gains
$
0.05

 
$
0.30

 
$
—

 
$
—

 
$
—

 
$
—

 
$
0.04

 
$
0.23

Canada realized cash derivative gains
0.23

 
0.81

 
—

 
—

 
—

 
—

 
0.23

 
0.81

Consolidated realized cash derivative gains
$
0.13

 
$
0.42

 
$
—

 
$
—

 
$
—

 
$
—

 
$
0.10

 
$
0.34

Consolidated production revenue and realized cash derivative gains
$
4.30

 
$
4.48

 
$
27.36

 
$
41.18

 
$
86.69

 
$
90.28

 
$
4.45

 
$
5.07


The following table summarizes the changes in our production revenue and realized cash gains (losses) on derivatives:
 
Natural
Gas
 
NGL
 
Oil
 
Total
 
 
 
 
 
 
 
 
 
(In thousands)
Consolidated production revenue and realized cash derivative gains for the 2012 period
$
240,059

 
$
85,809

 
$
13,578

 
$
339,446

Volume variances
(11,627
)
 
(21,560
)
 
(3,189
)
 
(36,376
)
Hedge revenue variances
(57,494
)
 
(6,607
)
 
—

 
(64,101
)
Realized cash derivative variance (1)
(16,563
)
 
—

 
—

 
(16,563
)
Price variances
54,022

 
(16,160
)
 
(414
)
 
37,448

Consolidated production revenue and realized cash derivative gains for the 2013 period
$
208,397

 
$
41,482

 
$
9,975

 
$
259,854

(1) 
This amount is also included in the production revenue and realized cash derivatives gains table above.
Consolidated production revenue and realized cash derivative gains from natural gas for the 2013 period decreased from the 2012 period due to lower volumes produced and a net decrease in hedge revenue and realized cash derivative gains due to improved natural gas prices partially offset by an increase in the realized price for natural gas. Consolidated production revenue and realized cash derivative gains from NGL revenue for the 2013 period decreased from the 2012 period due to lower volumes produced, decreased realized prices and the 2013 period not including NGL derivatives. The decrease in natural gas and NGL volumes is primarily due to the Tokyo Gas Transaction and is partially offset by an increase in volumes in our Horn River Asset as additional wells began producing in the second half of 2012.
At June 30, 2013, we had $1.8 million in deferred revenue related to NGLs held in storage by the purchaser of the NGLs. The title and risk of loss of the NGL volumes have transferred to the purchaser. However, the sales price of the NGLs will not be determined until the NGLs undergo further processing by the purchaser, which is expected to occur during the second half of 2013. We have deferred recognition of revenue on these NGL volumes as of June 30, 2013.

38

Our production revenue for the 2013 period and 2012 period was higher by $41.9 million and $122.6 million, respectively, because of our hedging activities.
Sales of Purchased Natural Gas and Costs of Purchased Natural Gas
 
For the Six Months Ended
June 30,
 
2013
 
2012
 
 
 
 
 
(In thousands)
Sales of purchased natural gas
 
Purchases from Eni
$
33,803

 
$
19,870

Purchases from others
1,440

 
1,658

Total
35,243

 
21,528

Costs of purchased natural gas sold
 
 
 
Purchases from Eni
33,802

 
19,906

Purchases from others
1,395

 
1,368

Total
35,197

 
21,274

Net sales and purchases of natural gas
$
46

 
$
254


Net Derivative Gains (Losses)
The following table summarizes our net derivative gains and losses:
 
For the Six Months Ended
June 30,
 
2013
 
2012
 
 
 
 
 
(In thousands)
Unrealized mark-to-market changes in fair value of natural gas derivative gains (losses) (1)
$
(2,652
)
 
$
16,060

Realized cash settlements of natural gas derivative gains
6,120

 
22,682

Non-cash loss in fair value from restructured natural gas derivatives
—

 
(13,836
)
Gain (loss) from hedge ineffectiveness
—

 
1,569

Derivative gains (losses), net
3,468

 
26,475

(1) 
Unrealized mark-to-market changes in fair value are subject to continuing market risk.
In 2012 we began to account for the fair value changes of certain natural gas derivatives in the income statement as reflected in the above table. In 2012 we terminated a number of our ten-year derivative instruments in exchange for derivative instruments with shorter durations at above market terms. The decrease in the fair value between the terminated ten-year instrument and the new shorter term instrument was recognized as a non-cash loss in fair value from restructured derivatives.
Other Revenue
 
For the Six Months Ended
June 30,
 
2013
 
2012
 
 
 
 
 
(In thousands)
Midstream revenue from third parties
 
Canada
$
1,313

 
$
1,475

Texas
442

 
610

Total midstream revenue
1,755

 
2,085

Other
—

 
31

Total
$
1,755

 
$
2,116


39

Operating Expense
Lease Operating
 
For the Six Months Ended June 30,
 
2013
 
2012
 
 
 
(In thousands, except per unit amounts)
 
 
 
Per
Mcfe
 
 
 
Per
Mcfe
Barnett Shale
 
 
 
 
 
 
 
Cash expense
$
23,708

 
$
0.63

 
$
30,169

 
$
0.56

Equity compensation
486

 
0.01

 
642

 
0.01

 
$
24,194

 
$
0.64

 
$
30,811

 
$
0.57

Other U.S.
 
 
 
 
 
 
 
Cash expense
$
2,748

 
$
5.93

 
$
4,298

 
$
6.43

Equity compensation
180

 
0.39

 
87

 
0.13

 
$
2,928

 
$
6.32

 
$
4,385

 
$
6.56

Total U.S.
 
 
 
 
 
 
 
Cash expense
$
26,456

 
$
0.69

 
$
34,467

 
$
0.63

Equity compensation
666

 
0.02

 
729

 
0.01

 
$
27,122

 
$
0.71

 
$
35,196

 
$
0.64

Horseshoe Canyon
 
 
 
 
 
 
 
Cash expense
$
15,385

 
$
1.70

 
$
13,634

 
$
1.35

Equity compensation
113

 
0.01

 
208

 
0.02

 
$
15,498

 
$
1.71

 
$
13,842

 
$
1.37

Horn River
 
 
 
 
 
 
 
Cash expense
$
2,488

 
$
0.22

 
$
1,252

 
$
0.53

Equity compensation
—

 
—

 
—

 
—

 
$
2,488

 
$
0.22

 
$
1,252

 
$
0.53

Total Canada
 
 
 
 
 
 
 
Cash expense
$
17,873

 
$
0.89

 
$
14,886

 
$
1.19

Equity compensation
113

 
0.01

 
208

 
0.02

 
$
17,986

 
$
0.90

 
$
15,094

 
$
1.21

Total Company
 
 
 
 
 
 
 
Cash expense
$
44,329

 
$
0.76

 
$
49,353

 
$
0.74

Equity compensation
779

 
0.01

 
937

 
0.01

 
$
45,108

 
$
0.77

 
$
50,290

 
$
0.75


Lease operating expense for the 2013 period in the Barnett Shale increased on a unit basis primarily due to fixed lease operating charges being distributed over lower volume compared to the 2012 period. In Canada, the increase in lease operating expense on a gross basis compared to the 2012 period is primarily due to increased volumes in our Horn River Asset. The reduction on a unit basis is due to the increased volumes in our Horn River Asset as fixed lease operating costs were distributed over a higher volume compared to the 2012 period.

40

Gathering, Processing and Transportation
 
For the Six Months Ended June 30,
 
2013
 
2012
 
 
 
(In thousands, except per unit amounts)
 
 
 
Per Mcfe
 
 
 
Per Mcfe
Barnett Shale
$
56,740

 
$
1.51

 
$
75,102

 
$
1.40

Other U.S.
5

 
0.01

 
7

 
0.01

Total U.S.
56,745

 
1.49

 
75,109

 
1.38

Horseshoe Canyon
1,617

 
0.18

 
2,029

 
0.20

Horn River
18,136

 
1.64

 
8,563

 
3.59

Total Canada
19,753

 
0.98

 
10,592

 
0.85

Total
$
76,498

 
$
1.31

 
$
85,701

 
$
1.28

U.S. GPT on a gross basis decreased primarily due to lower volume in our Barnett Shale Asset, with the Tokyo Gas Transaction contributing to this decline. On a unit basis, the 2013 period was higher primarily due to our production mix between areas within our Barnett Shale Asset. To a lesser extent the decrease was a result of deferred sales production to later in 2013 for our NGLs without a reduction in transportation expense as the NGLs were transported to the third-party facility for storage and incurred demand charges for our NGL transportation contracts. Canadian GPT increased in total for the 2013 period as compared to the 2012 period as a result of increased volumes in our Horn River Asset, and decreased on a unit basis in the Horn River primarily as a result of fixed costs under our firm agreements with third parties being spread over increased volumes in the 2013 period. Canadian GPT includes unused firm capacity of $2.8 million and $3.8 million for the 2013 period and the 2012 period, respectively.
Production and Ad Valorem Taxes
 
For the Six Months Ended June 30,
 
2013
 
2012
 
 
 
(In thousands, except per unit amounts)
 
 
 
Per
Mcfe
 
 
 
Per
Mcfe
Production taxes
 
 
 
 
 
 
 
Barnett Shale
$
1,979

 
$
0.05

 
$
2,644

 
$
0.05

Other U.S.
458

 
0.99

 
411

 
0.69

Total U.S.
2,437

 
0.06

 
3,055

 
0.06

Horseshoe Canyon
36

 
—

 
52

 
0.01

Horn River
—

 
—

 
—

 
—

Total Canada
36

 
—

 
52

 
0.01

Total production taxes
2,473

 
0.04

 
3,107

 
0.05

Ad valorem taxes
 
 
 
 
 
 
 
Barnett Shale
$
6,473

 
$
0.17

 
$
9,192

 
$
0.17

Other U.S.
250

 
0.54

 
253

 
0.38

Total U.S.
6,723

 
0.18

 
9,445

 
0.17

Horseshoe Canyon
1,058

 
0.12

 
1,257

 
0.12

Horn River
530

 
0.05

 
143

 
0.06

Total Canada
1,588

 
0.08

 
1,400

 
0.11

Total ad valorem taxes
8,311

 
0.14

 
10,845

 
0.16

Total
$
10,784

 
$
0.18

 
$
13,952

 
$
0.21



41

Depletion, Depreciation and Accretion
 
For the Six Months Ended June 30,
 
2013
 
2012
 
 
 
(In thousands, except per unit amounts)
 
 
 
Per
Mcfe
 
 
 
Per
Mcfe
Depletion
 
 
 
 
 
 
 
U.S.
$
19,700

 
$
0.52

 
$
76,231

 
$
1.40

Canada
2,293

 
0.11

 
14,999

 
1.20

Total depletion
21,993

 
0.38

 
91,230

 
1.36

Depreciation of other fixed assets
 
 
 
 
 
 
 
U.S.
$
4,030

 
0.11

 
$
4,679

 
0.09

Canada
4,854

 
0.24

 
4,577

 
0.37

Total depreciation
8,884

 
0.15

 
9,256

 
0.14

Accretion
2,644

 
0.05

 
1,969

 
0.03

Total
$
33,521

 
$
0.58

 
$
102,455

 
$
1.53

U.S. depletion for the 2013 period, when compared to the 2012 period, reflects a decrease in production and a decrease in the current year depletion rate due to impairments recognized in 2012. Canadian depletion decreased for the 2013 period, when compared to the 2012 period, due to a decrease in the current year depletion rate as a result of impairment recognized in 2012 partially offset by an increase in production.
Impairment Expense
As required under GAAP, we perform quarterly ceiling tests to assess impairment of our oil and gas properties. We also assess our fixed assets reported outside the full-cost pool when circumstances indicate impairment may have occurred. The calculation of impairment expense is more fully described in Note 4 to the condensed consolidated interim financial statements in Item 1 of this Quarterly Report.
In the 2012 period, we recognized $1.2 billion and $296.9 million in non-cash charges for impairment of our U.S. and Canadian oil and gas properties, respectively. No impairment was recognized in the 2013 period.
General and Administrative
 
For the Six Months Ended June 30,
 
2013
 
2012
 
 
 
(In thousands, except per unit amounts)
 
 
 
Per
Mcfe
 
 
 
Per
Mcfe
Cash expense
$
19,315

 
$
0.33

 
$
23,870

 
$
0.35

Audit and accounting fees
1,584

 
0.03

 
4,544

 
0.07

Strategic transaction costs
1,870

 
0.03

 
—

 
—

Equity compensation
10,269

 
0.18

 
9,086

 
0.14

Total
$
33,038

 
$
0.57

 
$
37,500

 
$
0.56

Tokyo Gas Transaction Gain
In April 2013, we recognized a $333.2 million gain upon closing of the Tokyo Gas Transaction. Further information regarding the transaction can be found in Note 2 to our condensed consolidated interim financial statements included in Item 1 of this Quarterly Report.
Crestwood Earn-Out
In February 2012, we collected $41 million of earn-out payments from Crestwood, which is presented as Crestwood earn-out in the condensed consolidated statement of income for the six months ended June 30, 2013.

42

Other Income (Expense)
In June 2013, we recognized an expense of $12.8 million in connection with the termination of the PEA with NGTL. Further information regarding the transaction can be found in Note 8 to our condensed consolidated interim financial statements included in Item 1 of this Quarterly Report. In the 2013 period the Canadian foreign currency exchange rate change resulted in a loss of $2.5 million.
Fortune Creek Accretion
In December 2011, we entered into an agreement with KKR to form Fortune Creek to construct and operate midstream assets for natural gas produced by us and others primarily in British Columbia. KKR’s contribution is shown as Partnership liability in the condensed consolidated balance sheet, and we recognize accretion expense to reflect the rate of return earned by KKR via its investment.
Interest Expense
 
For the Six Months Ended
June 30,
 
2013
 
2012
 
 
 
 
 
(In thousands)
Interest costs on debt outstanding
$
86,146

 
$
84,531

Add:
 
 
 
Fees paid on letters of credit outstanding
103

 
52

Net expense paid on debt refinancing
67,038

 
—

Non-cash interest (1)
21,773

 
3,469

Total interest costs incurred
175,060

 
88,052

Less:
 
 
 
Interest capitalized
(3,880
)
 
(7,806
)
Interest expense
$
171,180

 
$
80,246


(1) 
Amortization of deferred financing costs, original issue discount net of interest swap settlement amortization, including portions related to the early redemption of our Senior Notes due 2015 and Senior Notes due 2016 of $18.9 million.
Interest costs incurred for the 2013 period were higher when compared to the 2012 period primarily because of the refinancing of our debt securities in June 2013, which is more fully discussed in Note 5 to our condensed consolidated interim financial statements included in Item 1 of this Quarterly Report.
Income Taxes
The effective tax rates for the six months ended June 30, 2013 and 2012 are as follows:
 
For the Six Months Ended
June 30,
 
2013
 
2012
 
 
 
 
 
(in thousands)
Income tax (benefit) expense - U.S.
$
11,165

 
$
(415,897
)
Effective tax rate - U.S.
5.4
 %
 
34.8
%
Income tax (benefit) expense - Canada
$
932

 
$
(81,172
)
Effective tax rate - Canada
(7.5
)%
 
25.8
%
Income tax (benefit) expense - total
$
12,097

 
$
(497,069
)
Effective tax rate - total
6.2
 %
 
32.9
%

Income tax expense for the 2013 period included a reduction in the U.S. valuation allowance of $61.8 million primarily related to the gain recognized from the Tokyo Gas Transaction and an increase in the Canadian valuation allowance of $1.2 million. During the latter half of 2012, we determined reduced likelihood of realizing deferred tax benefits primarily related to our cumulative net operating losses. Income tax recognized for the 2013 period is a result of hedge gains previously deferred in

43

AOCI being realized during the quarter and the net tax impact being recognized without a corresponding valuation allowance. The effective rate for the 2012 period reflected a projection of full year of U.S. and Canadian taxable losses.
Quicksilver Resources Inc. and its Restricted Subsidiaries
Information about Quicksilver and our restricted and unrestricted subsidiaries is included in Note 12 to our condensed consolidated interim financial statements included in Item 1 of this Quarterly Report.
The combined results of operations for Quicksilver and our restricted subsidiaries are substantially similar to our consolidated results of operations, which are discussed above under “Results of Operations,” except for Fortune Creek accretion expense. The combined financial position of Quicksilver and our restricted subsidiaries and our consolidated financial position are materially the same except for balances related to Fortune Creek which were included in the consolidated financial position as of June 30, 2013. The combined operating cash flows, financing cash flows and investing cash flows for Quicksilver and our restricted subsidiaries are substantially similar to our consolidated operating cash flows, financing cash flows and investing cash flows, which are discussed below in “Cash Flow Activity,” except for cash flows associated with the operations and development of Fortune Creek.


LIQUIDITY, CAPITAL RESOURCES AND FINANCIAL POSITION
Cash Flow Activity
Our financial condition and results of operations, including our liquidity and profitability, are significantly affected by the prices that we realize for our natural gas, NGL and oil production and the volumes of natural gas, NGLs and oil that we produce.
The natural gas, NGLs and oil that we produce are commodity products for which established trading markets exist. Accordingly, product pricing is generally influenced by the relationship between supply and demand for these products. Product supply is affected primarily by fluctuations in production volumes, and product demand is affected by the state of the economy in general, the availability and price of alternative fuels and a variety of other factors. Prices for our products historically have been volatile, and we have no meaningful influence over the timing and extent of price changes for our products. Although we have mitigated our near-term exposure to such price declines through derivative financial instruments covering substantial portions of our expected near-term production, we cannot confidently predict whether or when commodity prices will increase or decrease.
The volumes that we produce may be significantly affected by the rates at which we acquire leaseholds and other mineral interests and explore, exploit and develop our leasehold and other mineral interests through drilling and production activities. These activities require substantial capital expenditures, and our ability to fund these activities through cash flow from our operations, borrowings and other sources may be affected by instability in the capital markets.
For the remainder of 2013 through 2021, swaps economically hedge a portion of our natural gas revenue. The following summarizes future production hedged with commodity derivatives as of June 30, 2013.
 
Production
 
Daily Production
Year
 
Gas
 
 
MMcfd
Remainder of 2013
 
200
2014
 
170
2015
 
150
2016-2021
 
40

The following summarizes our cash flow activity for the 2013 period and 2012 period:
 
Six months ended,
June 30,
 
2013
 
2012
 
 
 
 
 
(In thousands)
Net cash provided by (used in) operating activities
$
(78,106
)
 
$
99,516

Net cash provided by (used in) investing activities
290,594

 
(262,700
)
Net cash provided by (used in) financing activities
(122,553
)
 
163,314


Operating Cash Flows
Net cash provided by operating activities for the 2013 period decreased from the 2012 period due to expenses related to our debt refinancing, lower realized prices (including derivative effects), lower production volumes and negative changes in working capital.
Net cash provided by operating activities for the 2013 period also includes hedge cash settlements of $6.5 million which is deferred in other comprehensive income related to our long-dated hedges restructured in the first and fourth quarters of 2012. The revenue impact will be realized over the original term of the hedges which extends until 2021.
Investing Cash Flows
Costs incurred for property, plant and equipment for the 2013 period and 2012 period were as follows:
 
United States
 
Canada
 
Consolidated
 
 
 
 
 
 
 
(In thousands)
For the Six Months Ended June 30, 2013
 
 
 
 
 
Exploration and development
$
35,313

 
$
5,684

 
$
40,997

Midstream
25

 
730

 
755

Administrative
440

 
9,544

 
9,984

Total
$
35,778

 
$
15,958

 
$
51,736

For the Six Months Ended June 30, 2012
 
 
 
 
 
Exploration and development
$
116,977

 
$
157,401

 
$
274,378

Midstream
636

 
10,803

 
11,439

Administrative
2,444

 
3,003

 
5,447

Total
$
120,057

 
$
171,207

 
$
291,264

Costs incurred reflect the true nature of the activity of the 2013 capital program, while capital expenditures shown in the condensed consolidated statement of cash flows also reflect the related changes in working capital. Our 2013 capital costs incurred have decreased for the U.S. and Canada as a result of our overall decrease in capital spend in 2013 compared to 2012. Changes in working capital are driven by the reduction in accounts payable from prior year activities.
We received a $463.4 million payment from the Tokyo Gas Transaction in April 2013 and a $41.1 million earn-out payment from Crestwood in February 2012.
A portion of the cash received from the Tokyo Gas Transaction was invested in interest bearing time deposits and commercial paper with maturities of less than one year. We intend to hold these investments until maturity.
Financing Cash Flows
Net financing cash flows in the 2013 period include net payments of $90.8 million under our Combined Credit Agreements. During the quarter ended June 30, 2013, we executed a number of refinancing transactions to extend our debt maturities and reduce the weighted average interest costs, which are more fully described in Note 5 to our condensed consolidated interim financial statements included in Item 1 of this Quarterly Report. Issuance costs related to these transactions were $23.1 million. Proceeds from the issuance of the Senior Secured Second Lien Credit Agreement, Senior Secured Second Lien Notes due 2019 and Senior Notes due 2021 were used to pay for validly tendered Senior Notes due 2015 and Senior Notes due 2016 and accrued interest and transaction expenses.
Distributions of Fortune Creek partnership funds in the 2013 period of $5.0 million were paid to our partner based on its preferential distribution rights.
Liquidity and Borrowing Capacity
At June 30, 2013, the Combined Credit Agreements’ global borrowing base was $350 million and the global letter of credit capacity was $280 million. At June 30, 2013, there was $104.7 million available under the Combined Credit Agreements.
We further amended our Combined Credit Agreements in April and June 2013 for the following:
•
Permit the sale and transfer of a 25% interest in Quicksilver’s Barnett Shale assets to TGBR
•
Reduce the global borrowing base to $350 million from $850 million, including a reduction due to the Tokyo Gas Transaction
•
Reduce the minimum required interest coverage ratio to the following:

44

Period
 
Interest Coverage Ratio
 
Period
 
Interest Coverage Ratio
Q2 2013
 
1.25
 
Q1 2015
 
1.10
Q3 2013
 
1.25
 
Q2 2015
 
1.15
Q4 2013
 
1.25
 
Q3 2015
 
1.15
Q1 2014
 
1.20
 
Q4 2015
 
1.20
Q2 2014
 
1.15
 
Q1 2016
 
1.50
Q3 2014
 
1.10
 
Q2 2016
 
2.00
Q4 2014
 
1.10
 
 
 
 
•
Permit up to $825 million of second lien debt, subject to customary intercreditor terms
•
Permit redemption of junior debt with the proceeds from certain asset sales and permitted second lien debt, provided utilization under the global borrowing base after giving effect to such redemption is less than 75% and compliance with other customary conditions
•
Reduce the maximum senior secured debt leverage ratio to 2.0 and exclude permitted second lien debt from the senior secured debt definition
•
Increase the applicable margin by 0.75% for each type of loan and issued letters of credit
•
Increase the minimum mortgage properties requirement to 87.5% from 80% of proved hydrocarbon interests evaluated in the then most recent reserve report
•
Amend certain definitions which impact the financial covenant calculations.
In April 2013, we increased our outstanding letters of credit by C$13 million for the step-up of treating volumes in the Horn River Basin.
Our ability to remain in compliance with the financial covenants in our Combined Credit Agreements may be affected by events beyond our control. While we believe that we will be able to comply with these covenants for the next 12 months, we do not expect to exceed the required levels by a significant margin. Accordingly, even a modest decline in prices for natural gas and NGLs, our failure to achieve anticipated cost savings or the inaccuracy in any material respect of any of the other assumptions underlying our forecast could cause us to fail to comply with the covenants contained in the Combined Credit Agreements. Any future inability to comply with these covenants, unless waived or amended by the requisite lenders, could materially and adversely affect our liquidity by rendering us unable to borrow further under our credit facilities and by accelerating the maturity of our debt.
We have an incurrence test under our indentures applicable to debt, restricted payments, mergers and consolidations and designation of unrestricted subsidiaries that requires EBITDA to exceed interest expense by 2.25 times. At June 30, 2013, we did not meet this test and, as a result, we are limited in our ability to, among other things, incur additional debt, except for specific baskets. We do retain, however, the ability to utilize the full borrowing capacity under our Combined Credit Agreements and our ability to refinance existing debt. Not meeting this ratio does not represent an event of default under our indentures. We are presently unable to predict when or if we will meet the incurrence test.
Additional information about our debt and related covenants is included in Note 5 to the condensed consolidated interim financial statements in Item 1 of this Quarterly Report. The information presented above is qualified in all respects by reference to the full text of the documents governing the various components of our debt.
We anticipate that our remaining 2013 capital program will be funded by cash flow from operations or cash on hand and supplemented by proceeds from additional asset sales, although we could also borrow under the Combined Credit Agreements. If our capital resources are insufficient to fund our 2013 capital expenditure plan, we will need to reduce our capital expenditures or seek other financing alternatives. We may not be able to obtain financing needed in the future on terms that would be acceptable to us, or at all. If we limit or defer our 2013 capital expenditure plan, we could adversely affect the recoverability and ultimate value of our oil and gas properties.
We retained a portion of the cash received from the Tokyo Gas Transaction. Our indentures require us to reinvest or repay debt with net cash proceeds from asset sales within one year. If certain capital spending thresholds are not met, our liquidity could be adversely affected.
Depending upon conditions in the capital markets and other factors, we will from time to time consider the issuance of debt or other securities or other possible capital markets transactions, the proceeds of which could be used to refinance current indebtedness or for other corporate purposes. We will also consider from time to time additional acquisitions of, and

45

investments in, assets or businesses that complement our existing asset portfolio. Acquisition transactions, if any, are expected to be financed through cash flow from operations, borrowings under the Combined Credit Agreements, proceeds from asset sales, the issuance of debt or other securities or a combination of those sources.
Financial Position
The following impacted our balance sheet as of June 30, 2013, as compared to our balance sheet as of December 31, 2012:
•
Cash, cash equivalents and marketable securities increased $210.6 million as we retained a portion of the Tokyo Gas Transaction payment in cash.
•
Our accounts receivable balance decreased $19.3 million from December 31, 2012 to June 30, 2013, primarily due to lower production volumes compared to December 31, 2012 as well as a decrease of $3.1 million related to NGL hedge settlement accruals in 2012.
•
Our net property, plant and equipment balance decreased $136.2 million from December 31, 2012 to June 30, 2013. The decrease was primarily due to the Tokyo Gas Transaction, which resulted in a decrease of $138.0 million and additional decreases due to DD&A incurred of $30.9 million and $21.1 million related to U.S.-Canadian exchange rate changes. Offsetting these decreases, we incurred capital cost of $51.7 million during 2013.
•
The $21.1 million decrease in accounts payable was due primarily to a reduction in accrued capital expenditures of $4.6 million from the December 31, 2012 amount and a decrease in trade payables of $16.5 million from December 31, 2012 as activity has decreased from year‑end.
•
Our accrued liabilities decreased $24.9 million, primarily due to early payment of accrued interest of $46.6 million, partially offset by the accrual of the NGTL termination invoice and increase in ad valorem tax accrual.
•
Long-term debt decreased $94.8 million primarily from net payments under the Combined Credit Agreements of $191.9 million, recognition of $11.0 million of interest rate swaps and changes to the U.S.-Canadian exchange rate resulting in a decrease of $6.1 million, partially offset by net borrowings of $101.1 million as a result of our refinancing of our debt and $13.1 million of amortized discounts, including the impact of the redemption from the refinancing of our debt.
Contractual Obligations and Commercial Commitments
There have been no significant changes to our contractual obligations and commitments as reported in our 2012 Annual Report on Form 10-K, other than the termination of the PEA with NGTL as described in Note 8 to our condensed consolidated interim financial statements included in Item 1 of this Quarterly Report.
Critical Accounting Estimates
Management’s discussion and analysis of financial condition and results of operations are based on our condensed consolidated interim financial statements and related footnotes contained within this report. The process of preparing financial statements in conformity with GAAP requires the use of estimates and assumptions to determine certain of the assets, liabilities, revenue and expense. Our more critical accounting estimates used in the preparation of the consolidated financial statements were discussed in our 2012 Annual Report on Form 10-K. These critical estimates, for which no significant changes occurred during the six months ended June 30, 2013, include estimates and assumptions for:
•     oil and gas reserves
  
•     stock-based compensation
•     full cost ceiling calculations
  
•     income taxes
•     derivative instruments
  
 
These estimates and assumptions are based upon what we believe is the best information available at the time we make the estimate or assumption. The estimates and assumptions could change materially as conditions within and beyond our control change. Accordingly, actual results could differ materially from those estimates and assumptions.


46

OFF-BALANCE SHEET ARRANGEMENTS
In July 2013, in light of the Canadian Governor in Council's failure to approve NGTL's construction of the Komie North Project, NGTL terminated the Project and Expenditure Authorization (PEA), which authorized NGTL to construct the Komie North Project and the related meter station. The PEA necessitated the construction of a treatment facility and required financial guarantees to cover NGTL's costs for the Komie North Project. We have provided C$14 million in letters of credit to support this obligation. NGTL will release the letters of credit in connection with our paying NGTL an amount equal to actual costs incurred by NGTL, which is estimated to be approximately $12.8 million and is reflected in other income (expense) in our consolidated financial statements. With this termination of the PEA as described above, our agreement to deliver gas to the Komie North Project, has also terminated. We maintain our ability to sell gas at the Station 2 and AECO hubs, as our current production is served by existing treating facilities and pipelines.
RECENTLY ISSUED ACCOUNTING STANDARDS
Accounting standards-setting organizations frequently issue new or revised accounting rules. We regularly review all new pronouncements to determine their impact, if any, on our financial statements. No pronouncements materially affecting our financial statements have been issued since the filing of our 2012 Annual Report on Form 10-K.

ITEM 3.
Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
We have established internal control policies and procedures for managing risk within our organization. The possibility of decreasing prices received for our natural gas, NGL and oil production is among the several risks that we face. We seek to manage this risk by entering into derivative contracts. We have mitigated the downside risk of adverse price movements through the use of derivatives but, in doing so, we have also limited our ability to benefit from favorable price movements. This commodity price strategy enhances our ability to execute our development, exploitation and exploration programs, meet debt service requirements and pursue acquisition opportunities even in periods of price volatility or depression.
We enter into financial derivative contracts to mitigate our exposure to commodity price risk associated with anticipated future production and to increase the predictability of our revenue. Utilization of our financial hedging program will most often result in realized prices from the sale of our natural gas and NGLs that vary from market prices. As a result of settlements of derivative contracts, our revenue from natural gas and NGL production was greater by $41.9 million and $122.6 million for the 2013 period and 2012 period, respectively and a gain was recognized in net derivative gains of $6.1 million and $22.7 million for the 2013 period and 2012 period, respectively. These increases in production revenue and realized gains were offset by an unrealized loss of $2.7 million and an unrealized gain of $16.1 million for the 2013 period and 2012 period, respectively.

47

The following table details our open derivative positions at June 30, 2013:
Product
 
Type
 
Segment
 
Remaining Contract
Period
 
Volume
 
Price Per Mcf
Gas
 
Swap
 
Canada
 
Jul 2013 - Dec 2013
 
10 MMcfd
 
5.00
Gas
 
Swap
 
Canada
 
Jul 2013 - Dec 2015
 
10 MMcfd
 
6.42
Gas
 
Swap
 
Canada
 
Jul 2013 - Dec 2015
 
10 MMcfd
 
6.45
Gas
 
Swap
 
Canada
 
Jul 2013 - Dec 2015
 
10 MMcfd
 
4.04
Gas
 
Swap
 
Canada
 
Jul 2013 -Dec 2021
 
10 MMcfd
 
4.625
Gas
 
Swap
 
U.S.
 
Jul 2013 - Dec 2013
 
20 MMcfd
 
5.00
Gas
 
Swap
 
U.S.
 
Jul 2013 - Dec 2013
 
10 MMcfd
 
5.00
Gas
 
Swap
 
U.S
 
Jul 2013 - Dec 2014
 
10 MMcfd
 
3.91
Gas
 
Swap
 
U.S
 
Jul 2013 - Dec 2014
 
10 MMcfd
 
3.89
Gas
 
Swap
 
U.S.
 
Jul 2013 - Dec 2015
 
5 MMcfd
 
6.23
Gas
 
Swap
 
U.S.
 
Jul 2013 - Dec 2015
 
5 MMcfd
 
6.20
Gas
 
Swap
 
U.S.
 
Jul 2013 - Dec 2015
 
20 MMcfd
 
6.00
Gas
 
Swap
 
U.S.
 
Jul 2013 - Dec 2015
 
10 MMcfd
 
6.00
Gas
 
Swap
 
U.S.
 
Jul 2013 - Dec 2015
 
5 MMcfd
 
5.68
Gas
 
Swap
 
U.S.
 
Jul 2013 - Dec 2015
 
7.5 MMcfd
 
5.48
Gas
 
Swap
 
U.S.
 
Jul 2013 - Dec 2015
 
7.5 MMcfd
 
5.50
Gas
 
Swap
 
U.S.
 
Jul 2013 - Dec 2015
 
5 MMcfd
 
4.15
Gas
 
Swap
 
U.S.
 
Jul 2013 - Dec 2015
 
5 MMcfd
 
4.13
Gas
 
Swap
 
U.S.
 
Jan 2014 - Dec 2015
 
5 MMcfd
 
4.26
Gas
 
Swap
 
U.S.
 
Jan 2014 - Dec 2015
 
5 MMcfd
 
4.25
Gas
 
Swap
 
U.S.
 
Jul 2013 - Dec 2021
 
10 MMcfd
 
4.54
Gas
 
Swap
 
U.S.
 
Jul 2013 - Dec 2021
 
5 MMcfd
 
4.38
Gas
 
Swap
 
U.S.
 
Jul 2013 - Dec 2021
 
10 MMcfd
 
4.37
Gas
 
Swap
 
U.S.
 
Jul 2013 - Dec 2021
 
5 MMcfd
 
4.35

These open derivative positions had a net fair value of $153.5 million as of June 30, 2013.
The fair value of all derivative instruments included in these disclosures was estimated using prices quoted in markets for the periods covered by the derivatives and the value confirmed by counterparties and does not include an adjustment for counterparty credit risk. Estimates were determined by applying the net differential between the prices in each derivative and market prices for future periods to the amounts stipulated in each contract to arrive at an estimated future value. This estimated future value was discounted on each contract at rates commensurate with federal treasury instruments with similar contractual lives.
Interest Rate Risk
Changes in interest rates affect the interest rate we pay on borrowings under the Combined Credit Agreements, Senior Secured Second Lien Credit Agreement and Senior Secured Second Lien Notes due 2019. Our senior unsecured notes and senior subordinated notes have fixed interest rates and thus do not expose us to risk from fluctuations in market interest rates. Changes in interest rates do affect the fair value of our fixed rate debt.
In 2010, we executed early settlements of our interest rate swaps that were designated as fair value hedges of our senior notes due 2015 and our senior subordinated notes. We deferred gains of $30.8 million as a fair value adjustment to our debt, which we began to recognize over the life of the associated debt instruments. During the 2013 quarter and the 2012 quarter, we recognized $11.0 million and $2.5 million, respectively, of those deferred gains as a reduction of interest expense. In June 2013, we repurchased substantially all our senior notes due 2015 resulting in early recognition of the associated deferred gain.
Should we be required to borrow under our Combined Credit Agreements and based on interest rates as of June 30, 2013, each $50 million in borrowings would result in additional annual interest payments of $1.9 million. If the current borrowing availability under our Combined Credit Agreements were to be fully utilized by year-end 2013 at interest rates as of June 30, 2013, we estimate that annual interest payments would increase by $4.1 million. If interest rates change by 1% on our June 30, 2013 variable debt balances of $190.2 million, our annual pre-tax income would decrease or increase by $1.9 million.

48

Our Senior Secured Second Lien Credit Agreement and Senior Secured Second Lien Notes due 2019 feature a LIBOR floor. Consequently, a 1% increase in the interest rates on our outstanding variable rate debt as of June 30, 2012, would have an impact of increasing our applicable interest rate on this debt by only 0.02% or an estimated annual interest payment increase of $0.2 million.
In the future, we may enter into interest rate derivative contracts on a portion of our outstanding debt to mitigate the risk of fluctuation of rates or manage the floating versus fixed rate risk.
Foreign Currency Risk
Our Canadian subsidiary uses the Canadian dollar as its functional currency. To the extent that business transactions in Canada are not denominated in Canadian dollars, we are exposed to foreign currency exchange rate risk. Non-functional currency transactions for the 2013 period and the 2012 period resulted in a loss of $2.5 million and a gain of less than $0.1 million, respectively, and were included in other income. Furthermore, the Amended and Restated Canadian Credit Facility permits Canadian borrowings to be made in either U.S. or Canadian-denominated amounts. However, the aggregate borrowing capacity of the entire facility is calculated using the U.S. dollar equivalent. Accordingly, there is a risk that exchange rate movements could impact our available borrowing capacity.

ITEM 4.  Controls and Procedures
Conclusions Regarding the Effectiveness of Disclosure Controls and Procedures
We carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Securities Exchange Act Rule 13a-15. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of June 30, 2013, our disclosure controls and procedures were not effective, due to the outstanding remediation of the income tax material weakness identified at December 31, 2012, to provide reasonable assurance that material information required to be disclosed by us (including our consolidated subsidiaries) in reports that we file or submit under the Securities Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Changes in Internal Control Over Financial Reporting
As disclosed in our 2012 Annual Report on Form 10-K, two material weaknesses were identified related to the design and operating effectiveness of our controls. Our controls failed to detect that, for contracts designated as hedges that had a fair value on the date of designation, there were undocumented potential sources of ineffectiveness. Specifically, our documentation in 2012 did not include an assessment of whether interest rate changes could cause the instruments to not be effective over the life of the derivative, which was required due to the presence of fair value on the designation date. Effective December 31, 2012, we no longer account for our derivatives as hedges and have clarified our policies regarding application of hedge accounting if we apply this election in the future and have therefore remediated this material weakness.
We also had a material weakness related to the operating effectiveness of controls over the reconciliation of deferred income taxes, particularly related to the tax basis in property, plant and equipment. In response to this material weakness, management is working to complete a detailed reconciliation of the property, plant and equipment account balances. While this process is not yet complete, we have concluded that the financial statements in this Quarterly Report on Form 10-Q present fairly, in all material respects, our consolidated financial condition, results of operations and cash flows in conformity with generally accepted accounting principles in the U.S.
There has been no other change in our internal control over financial reporting during the quarter ended June 30, 2013, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

49

PART II. OTHER INFORMATION

ITEM 1.   Legal Proceedings
In December 2012, Vantage Fort Worth Energy LLC (“Plaintiff”) served a lawsuit against us and others in the 352nd Judicial District Court of Texas in Tarrant County asserting claims for trespass to try title, suit to quiet title, trespass and conversion in connection with 16 wells located on a 158.75 acre tract located in Tarrant County, Texas. They seek declaratory and injunctive relief, an accounting and an unspecified amount of actual damages, interest and court costs. We filed our answer in January 2013. In January 2013, Vantage filed its Motion for Non-suit with respect to certain defendants and First Amended Petition. Vantage's current complaint also seeks an unspecified amount of actual damages, interests and costs.
On May 8, 2013, all parties to the suit entered into a settlement agreement, effective April 1, 2013, whereby we assigned to Plaintiff various property and equipment and Plaintiff agreed to non-suit all of the Defendants in the matter. The court entered its Order of Dismissal with prejudice on May 13, 2013. The final resolution of this matter did not have a material effect on our financial condition, results of operations, or cash flows.
There have been no other material changes in the legal proceedings described in Part I, Item 3 included in our 2012 Annual Report on Form 10-K.
ITEM 1A.   Risk Factors
There have been no material changes in the risk factors described in Part I, Item 1A included in our 2012 Annual Report on Form 10-K.
ITEM 2.   Unregistered Sales of Equity Securities and Use of Proceeds
Issuer Purchases of Equity Securities
The following table summarizes our repurchases of Quicksilver common stock during the quarter ended June 30, 2013.
 
Period
 
Total Number
of Shares
Purchased (1)
 
Average Price
Paid per Share
 
Total Number of
Shares Purchased as
Part of Publicly
Announced Plan (2)
 
Maximum Number
of Shares that May
Yet Be Purchased
Under the Plan (2)
April 2013
 
42,475

 
$
2.65

 
—

 
—

May 2013
 
—

 
$
—

 
—

 
—

June 2013
 
2,268

 
$
2.22

 
—

 
—

Total
 
44,743

 
$
2.63

 
—

 
—

(1) 
Represents shares of common stock surrendered by employees to satisfy income tax withholding obligations arising upon the vesting of restricted stock issued under our stock plan.
(2) 
We do not have a publicly announced plan for repurchasing our common stock.
We have not paid cash dividends on our common stock and intend to retain our cash flows from operations for future operations and development of our business. In addition, we have debt agreements that restrict the payment of dividends.
ITEM 3. Defaults Upon Senior Securities
None.
ITEM 4. Mine Safety Disclosures
None.
ITEM 5. Other Information
None.


50

ITEM 6.
Exhibits

 
 
 
 
Incorporated by Reference
 
Filed (†) or
Furnished (‡)
Herewith
(as indicated)
Exhibit
No.
 
Exhibit Description
 
Form
 
SEC
File No.
 
Exhibit
 
Filing
Date
 
3.1
 
Amended and Restated Bylaws of Quicksilver Resources Inc., effective on May 15, 2013
 
8-K
 
001-14837
 
3.1
 
5/16/2013
 
 
4.1
 
Twenty-first Supplemental Indenture, dated as of June 12, 2013, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee
 
8-K
 
001-14837
 
4.1
 
6/12/2013
 
 
4.2
 
Twenty-second Supplemental Indenture, dated as of June 12, 2013, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee
 
8-K
 
001-14837
 
4.2
 
6/12/2013
 
 
4.3
 
Twenty-third Supplemental Indenture, dated as of June 12, 2013, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee
 
8-K
 
001-14837
 
4.3
 
6/12/2013
 
 
4.4
 
Twenty-fourth Supplemental Indenture, dated as of June 21, 2013, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee
 
8-K/A
 
001-14837
 
4.4
 
7/1/2013
 
 
4.5
 
Indenture, dated as of June 21, 2013, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee
 
8-K/A
 
001-14837
 
4.1
 
7/1/2013
 
 
4.6
 
Indenture, dated as of June 21, 2013, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee and second lien collateral agent
 
8-K/A
 
001-14837
 
4.2
 
7/1/2013
 
 
4.7
 
Registration Rights Agreement, dated as of June 21, 2013, among Quicksilver Resources Inc., the subsidiary guarantors named therein and Credit Suisse Securities (USA) LLC, Citigroup Global Markets Inc. and Deutsche Bank Securities Inc., as representatives of the initial purchasers
 
8-K/A
 
001-14837
 
4.3
 
7/1/2013
 
 
10.1
 
Quicksilver Resources Inc. Seventh Amended and Restated 2006 Equity Plan
 
 
 
 
 
 
 
 
 
†
10.2
 
Agreement, dated as of May 15, 2013, between Quicksilver Resources Inc. and Thomas F. Darden
 
 
 
 
 
 
 
 
 
†
10.3
 
Omnibus Amendment No. 4 to Combined Credit Agreements, dated as of April 30, 2013, among Quicksilver Resources Inc., Quicksilver Reources Canada Inc. and the agents and lenders identified therein
 
 
 
 
 
 
 
 
 
†
10.4
 
Omnibus Amendment No. 5 to the Combined Credit Agreements, dated as of June 21, 2013, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and lenders identified therein
 
8-K/A
 
001-14387
 
10.2
 
7/1/2013
 
 
10.5
 
Second Lien Credit Agreement, dated as of June 21, 2013, among Quicksilver Resources Inc., the lenders party thereto and Credit Suisse AG, as administrative agent
 
8-K/A
 
001-14837
 
10.1
 
7/1/2013
 
 
31.1
 
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
 
 
 
 
 
 
 
 
†
31.2
 
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
 
 
 
 
 
 
 
 
†

51

32.1
 
Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
 
 
 
 
 
 
 
 
†
101.INS
 
XBRL Instance Document
 
 
 
 
 
 
 
 
 
‡
101.SCH
 
XBRL Taxonomy Extension Schema Linkbase Document
 
 
 
 
 
 
 
 
 
‡
101.CAL
 
XBRL Taxonomy Extension Calculation Linkbase Document
 
 
 
 
 
 
 
 
 
‡
101.LAB
 
XBRL Taxonomy Extension Labels Linkbase Document
 
 
 
 
 
 
 
 
 
‡
101.PRE
 
XBRL Taxonomy Extension Presentation Linkbase Document
 
 
 
 
 
 
 
 
 
‡
101.DEF
 
XBRL Taxonomy Extension Definition Linkbase Document
 
 
 
 
 
 
 
 
 
‡

52

SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
Dated:
August 8, 2013
Quicksilver Resources Inc.
 
 
 
 
 
 
 
By:

/s/ John C. Regan
 
 
 

John C. Regan
 
 
 

Senior Vice President-Chief Financial Officer
(Duly Authorized Officer, Principal Financial and Accounting Officer)

53

EXHIBIT INDEX
 
 
 
 
 
Incorporated by Reference
 
Filed (†) or
Furnished (‡)
Herewith
(as indicated)
Exhibit
No.
 
Exhibit Description
 
Form
 
SEC
File No.
 
Exhibit
 
Filing
Date
 
3.1
 
Amended and Restated Bylaws of Quicksilver Resources Inc., effective on May 15, 2013
 
8-K
 
001-14837
 
3.1
 
5/16/2013
 
 
4.1
 
Twenty-first Supplemental Indenture, dated as of June 12, 2013, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee
 
8-K
 
001-14837
 
4.1
 
6/12/2013
 
 
4.2
 
Twenty-second Supplemental Indenture, dated as of June 12, 2013, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee
 
8-K
 
001-14837
 
4.2
 
6/12/2013
 
 
4.3
 
Twenty-third Supplemental Indenture, dated as of June 12, 2013, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee
 
8-K
 
001-14837
 
4.3
 
6/12/2013
 
 
4.4
 
Twenty-fourth Supplemental Indenture, dated as of June 21, 2013, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee
 
8-K/A
 
001-14837
 
4.4
 
7/1/2013
 
 
4.5
 
Indenture, dated as of June 21, 2013, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee
 
8-K/A
 
001-14837
 
4.1
 
7/1/2013
 
 
4.6
 
Indenture, dated as of June 21, 2013, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee and second lien collateral agent
 
8-K/A
 
001-14837
 
4.2
 
7/1/2013
 
 
4.7
 
Registration Rights Agreement, dated as of June 21, 2013, among Quicksilver Resources Inc., the subsidiary guarantors named therein and Credit Suisse Securities (USA) LLC, Citigroup Global Markets Inc. and Deutsche Bank Securities Inc., as representatives of the initial purchasers
 
8-K/A
 
001-14837
 
4.3
 
7/1/2013
 
 
10.1
 
Quicksilver Resources Inc. Seventh Amended and Restated 2006 Equity Plan
 
 
 
 
 
 
 
 
 
†
10.2
 
Agreement, dated as of May 15, 2013, between Quicksilver Resources Inc. and Thomas F. Darden
 
 
 
 
 
 
 
 
 
†
10.3
 
Omnibus Amendment No. 4 to Combined Credit Agreements, dated as of April 30, 2013, among Quicksilver Resources Inc., Quicksilver Reources Canada Inc. and the agents and lenders identified therein
 
 
 
 
 
 
 
 
 
†
10.4
 
Omnibus Amendment No. 5 to the Combined Credit Agreements, dated as of June 21, 2013, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and lenders identified therein
 
8-K/A
 
001-14387
 
10.2
 
7/1/2013
 
 
10.5
 
Second Lien Credit Agreement, dated as of June 21, 2013, among Quicksilver Resources Inc., the lenders party thereto and Credit Suisse AG, as administrative agent
 
8-K/A
 
001-14837
 
10.1
 
7/1/2013
 
 
31.1
 
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
 
 
 
 
 
 
 
 
†
31.2
 
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
 
 
 
 
 
 
 
 
†

54

32.1
 
Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
 
 
 
 
 
 
 
 
†
101.INS
 
XBRL Instance Document
 
 
 
 
 
 
 
 
 
‡
101.SCH
 
XBRL Taxonomy Extension Schema Linkbase Document
 
 
 
 
 
 
 
 
 
‡
101.CAL
 
XBRL Taxonomy Extension Calculation Linkbase Document
 
 
 
 
 
 
 
 
 
‡
101.LAB
 
XBRL Taxonomy Extension Labels Linkbase Document
 
 
 
 
 
 
 
 
 
‡
101.PRE
 
XBRL Taxonomy Extension Presentation Linkbase Document
 
 
 
 
 
 
 
 
 
‡
101.DEF
 
XBRL Taxonomy Extension Definition Linkbase Document
 
 
 
 
 
 
 
 
 
‡



55