Attached files

file filename
EXCEL - IDEA: XBRL DOCUMENT - QUICKSILVER RESOURCES INCFinancial_Report.xls
EX-31.2 - CHIEF FINANCIAL OFFICER CERTIFICATION UNDER SECTION 302 - QUICKSILVER RESOURCES INCkwk10-q20140930ex312.htm
EX-10.7 - OMNIBUS AMENDMENT NO. 8 TO COMBINED CREDIT AGREEMENTS - QUICKSILVER RESOURCES INCkwk10-q20140930ex107.htm
EX-31.1 - CHIEF EXECUTIVE OFFICER CERTIFICATION UNDER SECTION 302 - QUICKSILVER RESOURCES INCkwk10-q20140930ex311.htm
EX-10.5 - FOURTH AMENDMENT TO AMENDED AND RESTATED GAS GATHERING AGREEMENT - QUICKSILVER RESOURCES INCkwk10-q20140930ex105.htm
EX-10.1 - SECOND AMENDMENT TO GAS GATHERING AGREEMENT - QUICKSILVER RESOURCES INCkwk10-q20140930ex101.htm
EX-10.2 - THIRD AMENDMENT TO SIXTH AMENDED AND RESTATED GAS GATHERING AND PROCESSING AGREE - QUICKSILVER RESOURCES INCkwk10-q20140930ex102.htm
EX-10.4 - THIRD AMENDMENT TO AMENDED AND RESTATED GAS GATHERING AGREEMENT - QUICKSILVER RESOURCES INCkwk10-q20140930ex104.htm
EX-32.1 - CEO AND CFO CERTIFICATION UNDER SECTION 906 - QUICKSILVER RESOURCES INCkwk10-q20140930ex321.htm
EX-10.6 - FIFTH AMENDMENT TO AMENDED AND RESTATED GAS GATHERING AGREEMENT - QUICKSILVER RESOURCES INCkwk10-q20140930ex106.htm
EX-10.3 - FOURTH AMENDMENT TO SIXTH AMENDED AND RESTATED GAS GATHERING AND PROESSING AGREE - QUICKSILVER RESOURCES INCkwk10-q20140930ex103.htm

 
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 September 30, 2014
or
 
 
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
For the transition period from                      to                     
Commission file number: 001-14837
Quicksilver Resources Inc.
(Exact name of registrant as specified in its charter)
 
Delaware
 
75-2756163
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
 
 
 
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
 
¨
 
 
Accelerated filer
þ
Non-accelerated filer
 
¨
(Do not check if a smaller reporting company)
 
Smaller reporting company
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes  ¨  No   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 October 31, 2014
Common Stock, $0.01 par value
 
179,983,515 shares
 



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

ABR” means alternate base rate
AECO” is a reference, in U.S. dollars per MMbtu, for gas delivered at a trading hub on the NOVA Gas Transmission Ltd. System in Alberta, Canada
AOCI” means accumulated other comprehensive income
Bbl” or “Bbls” means barrel or barrels
Bbld” means barrel or barrels per day
Boed” means barrels of oil equivalent per day, calculated as six Mcf of gas equaling one Bbl of oil
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
MBbld” means thousand barrels per day
MMBtu” means million BTUs
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
RSU” means restricted stock unit

COMMONLY USED TERMS
Other commonly used terms and abbreviations include:

Alliance Asset” means all of our natural gas leasehold and royalty interests in northern Tarrant and southern Denton counties
Amended and Restated Canadian Credit Facility” means our Canadian senior secured revolving credit facility which was amended and restated, effective 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, effective 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
Combined Credit Agreements” means collectively our Amended and Restated U.S. Credit Facility and our Amended and Restated Canadian Credit Facility
Eni” means either or both Eni Petroleum US LLC and Eni US Operating Co. Inc., which are subsidiaries of Eni SpA
Eni Transaction” means the 2009 conveyance to Eni of 27.5% of Quicksilver's interest in our Alliance Asset
FASB” means the Financial Accounting Standards Board, which promulgates accounting standards in the U.S.
Fortune Creek” means Fortune Creek Gathering and Processing Partnership, a midstream partnership formed with KKR and 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


2


Horseshoe Canyon Asset” means our operations and our assets in Horseshoe Canyon, the coalbed methane fields of southern and central Alberta
KKR” means Kohlberg Kravis Roberts & Co. L.P., with whom we formed Fortune Creek
Mercury” means Mercury Exploration Company, which is owned by members of the Darden family
Niobrara Asset” means our operations and our assets in the Niobrara formation in northwest Colorado, which we were jointly developing with SWEPI LP and which were sold in the Southwestern Transaction
SEC” means the U.S. Securities and Exchange Commission
Second Lien Notes” means our senior secured second lien notes issued June 21, 2013
Second Lien Term Loan” means our senior secured second lien term loan agreement, effective June 21, 2013
Southern Alberta Basin Asset” means our operations and our assets in the Southern Alberta basin of northern Wyoming and Montana, including our Cutbank field operations and assets, which were sold in the Synergy Transaction
Southwestern Transaction” means the sale of our Niobrara Asset to Southwestern Energy Company
SWEPI” means SWEPI LP, a subsidiary of Royal Dutch Shell plc
Synergy” means Synergy Offshore LLC
Synergy Transaction” means the sale of our Southern Alberta Basin Asset to Synergy
Tokyo Gas Transaction” means the sale of an undivided 25% of our Barnett Shale Asset to TGBR
TGBR” means TG Barnett Resources LP, a wholly-owned U.S. subsidiary of Tokyo Gas Co., Ltd.
VIE” means variable interest entity
West Texas Asset” means our operations and our assets in the Delaware basin in West Texas, which we believe is prospective for the Bone Springs and Wolfcamp formations, principally concentrated in Pecos County, Texas


3


INDEX TO QUARTERLY REPORT ON FORM 10-Q
For the Quarter Ended September 30, 2014
 

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,” “contemplate,” “estimate,” “anticipate,” “believe,” “project,” “target,” “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;
failure to satisfy our short- or long-term liquidity needs, including the ability to access necessary capital resources and address near-term debt maturities;
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 and operational efficiencies;
failure to comply with covenants under our Combined Credit Agreements and other indebtedness, the resulting acceleration of debt thereunder and the inability to make necessary repayments or to make additional borrowings;
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, particularly in completing a transaction involving the sale of any or all of our assets, including our Horn River Asset;
failure to make the necessary expenditures under or related to our contractual commitments, including our spending requirement pursuant to Fortune Creek;
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, including any amendments thereto. 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
September 30,
 
For the Nine Months Ended
September 30,
  
2014
 
2013
 
2014
 
2013
 
 
 
 
 
 
 
 
Revenue
 
 
 
 
 
 
 
Production
$
102,615

 
$
104,546

 
$
332,187

 
$
358,281

Sales of purchased natural gas
16,660

 
15,130

 
53,401

 
50,373

Net derivative gains (losses)
43,310

 
32,733

 
(15,080
)
 
36,202

Other
913

 
707

 
2,808

 
2,462

Total revenue
163,498

 
153,116

 
373,316

 
447,318

Operating expense
 
 
 
 
 
 
 
Lease operating
17,176

 
18,591

 
54,622

 
63,699

Gathering, processing and transportation
34,807

 
35,567

 
102,511

 
112,064

Production and ad valorem taxes
4,067

 
4,678

 
12,557

 
15,462

Costs of purchased natural gas
16,599

 
15,114

 
53,305

 
50,311

Depletion, depreciation and accretion
13,969

 
14,390

 
42,584

 
47,911

Impairment
135

 

 
135

 

General and administrative
11,310

 
10,471

 
38,115

 
43,509

Other operating
651

 
2,230

 
2,221

 
4,435

Total expense
98,714

 
101,041

 
306,050

 
337,391

Gain on Tokyo Gas Transaction

 
7,974

 

 
341,146

Operating income
64,784

 
60,049

 
67,266

 
451,073

Other income (expense) - net
(2,465
)
 
667

 
(3,824
)
 
(14,588
)
Fortune Creek accretion
(3,602
)
 
(4,818
)
 
(11,605
)
 
(14,490
)
Interest expense
(39,899
)
 
(39,355
)
 
(121,927
)
 
(210,535
)
Income (loss) before income taxes
18,818

 
16,543

 
(70,090
)
 
211,460

Income tax benefit (expense)
4,939

 
(5,966
)
 
(1,081
)
 
(18,063
)
Net income (loss)
$
23,757

 
$
10,577

 
$
(71,171
)
 
$
193,397

Reclassification adjustments related to settlements of derivative contracts into production revenue- net of income tax
(7,968
)
 
(11,139
)
 
(20,939
)
 
(37,181
)
Foreign currency translation adjustment
(6,921
)
 
2,345

 
(6,162
)
 
(933
)
Other comprehensive loss
(14,889
)
 
(8,794
)
 
(27,101
)
 
(38,114
)
Comprehensive income (loss)
$
8,868

 
$
1,783

 
$
(98,272
)
 
$
155,283

Earnings (loss) per common share - basic
$
0.13

 
$
0.06

 
$
(0.41
)
 
$
1.10

Earnings (loss) per common share - diluted
$
0.13

 
$
0.06

 
$
(0.41
)
 
$
1.10


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
 
 
September 30, 2014
 
December 31, 2013
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
248,325

 
$
89,103

Marketable securities

 
166,343

Total cash, cash equivalents and marketable securities
248,325

 
255,446

Accounts receivable - net of allowance for doubtful accounts
59,491

 
58,645

Derivative assets at fair value
66,098

 
57,523

Other current assets
22,386

 
22,346

Total current assets
396,300

 
393,960

Property, plant and equipment - net
 
 
 
Oil and gas properties, full cost method (including unevaluated costs of $218,398 and $221,605, respectively)
608,572

 
640,443

Other property and equipment
203,908

 
220,362

Property, plant and equipment - net
812,480

 
860,805

Derivative assets at fair value
25,968

 
73,357

Other assets
33,509

 
41,604

 
$
1,268,257

 
$
1,369,726

LIABILITIES AND EQUITY
 
 
 
Current liabilities
 
 
 
Accounts payable
$
13,587

 
$
28,822

Accrued liabilities
94,091

 
102,850

Derivative liabilities at fair value
846

 
3,125

Total current liabilities
108,524

 
134,797

Long-term debt
2,037,844

 
1,988,946

Partnership liability
94,651

 
126,132

Asset retirement obligations
105,480

 
106,256

Derivative liabilities at fair value

 
323

Other liabilities
19,242

 
19,242

Commitments and contingencies (Note 7)

 

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 187,222,654 and 183,994,879 shares issued, respectively
1,872

 
1,840

Additional paid in capital
779,206

 
770,092

Treasury stock of 7,444,372 and 6,698,640 shares, respectively
(53,810
)
 
(51,422
)
Accumulated other comprehensive income
82,780

 
109,881

Retained deficit
(1,907,532
)
 
(1,836,361
)
Total stockholders' equity
(1,097,484
)
 
(1,005,970
)
 
$
1,268,257

 
$
1,369,726


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, 2012
$
1,790

 
$
751,394

 
$
(49,495
)
 
$
161,493

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

 

 

 

 
193,397

 
193,397

Hedge derivative contract settlements reclassified into production revenue from AOCI, net of income tax of $17,833

 

 

 
(37,181
)
 

 
(37,181
)
Foreign currency translation adjustment

 

 

 
(933
)
 

 
(933
)
Issuance and vesting of stock compensation
47

 
14,421

 
(1,472
)
 

 

 
12,996

Balances at September 30, 2013
$
1,837

 
$
765,815

 
$
(50,967
)
 
$
123,379

 
$
(1,804,582
)
 
$
(964,518
)
 
 
 
 
 
 
 
 
 
 
 
 
Balances at December 31, 2013
$
1,840

 
$
770,092

 
$
(51,422
)
 
$
109,881

 
$
(1,836,361
)
 
$
(1,005,970
)
Net loss

 

 

 

 
(71,171
)
 
(71,171
)
Hedge derivative contract settlements reclassified into production revenue from AOCI, net of income tax of $8,455

 

 

 
(20,939
)
 

 
(20,939
)
Foreign currency translation adjustment

 

 

 
(6,162
)
 

 
(6,162
)
Issuance and vesting of stock compensation
32

 
9,114

 
(2,388
)
 

 

 
6,758

Balances at September 30, 2014
$
1,872

 
$
779,206

 
$
(53,810
)
 
$
82,780

 
$
(1,907,532
)
 
$
(1,097,484
)

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 Nine Months Ended
September 30,
  
2014
 
2013
 
 
 
 
Operating activities:
 
 
 
Net income (loss)
$
(71,171
)
 
$
193,397

Adjustments to reconcile net income (loss) to net cash used in operating activities:
 
 
 
Depletion, depreciation and accretion
42,584

 
47,911

Impairment expense
135

 

Gain on Tokyo Gas Transaction

 
(341,146
)
Deferred income tax expense
8,455

 
17,833

Non-cash (gain) loss from hedging and derivative activities
6,731

 
(12,223
)
Stock-based compensation
9,146

 
13,699

Non-cash interest expense
8,441

 
23,643

Fortune Creek accretion
11,605

 
14,490

Other
(347
)
 
3,622

Changes in assets and liabilities
 
 
 
Accounts receivable
(1,936
)
 
7,398

Prepaid expenses and other assets
1,747

 
344

Accounts payable
(12,472
)
 
(17,973
)
Income taxes
(432
)
 
(148
)
Accrued and other liabilities
(7,469
)
 
(31,950
)
Net cash used in operating activities
(4,983
)
 
(81,103
)
Investing activities:
 
 
 
Capital expenditures
(111,444
)
 
(78,549
)
Proceeds from Southwestern Transaction
95,587

 

Proceeds from Tokyo Gas Transaction

 
463,418

Proceeds from Synergy Transaction

 
42,297

Proceeds from sale of properties and equipment
1,942

 
2,994

Purchases of marketable securities
(55,890
)
 
(142,823
)
Maturities and sales of marketable securities
222,025

 
13,178

Net cash provided by investing activities
152,220

 
300,515

Financing activities:
 
 
 
Issuance of debt
243,184

 
1,173,306

Repayments of debt
(193,689
)
 
(1,308,382
)
Debt issuance costs paid
(225
)
 
(25,868
)
Distribution of Fortune Creek Partnership funds
(37,113
)
 
(8,079
)
Purchase of treasury stock
(2,388
)
 
(1,472
)
Net cash provided by (used in) financing activities
9,769

 
(170,495
)
Effect of exchange rate changes in cash
2,216

 
2,610

Net change in cash and cash equivalents
159,222

 
51,527

Cash and cash equivalents at beginning of period
89,103

 
4,951

Cash and cash equivalents at end of period
$
248,325

 
$
56,478


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, DISCLOSURES AND NATURE OF OPERATIONS
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 September 30, 2014 and our results of operations and cash flows for the periods presented. All such adjustments are of a normal recurring nature unless otherwise noted. 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 2013 Annual Report on Form 10-K.
Our ability to borrow under our Combined Credit Agreements depends on our global borrowing base, which is scheduled to be redetermined twice each year. A reduction to the global borrowing base during the spring or autumn redetermination, or upon a special redetermination requested by our administrative agent under the Combined Credit Agreements, would adversely impact our liquidity and ability to meet our future obligations. Our derivatives contribute to the global borrowing base. Most of our derivative positions expire at year-end 2015. The expiration of these derivatives will adversely affect our global borrowing base, and absent an improvement in natural gas and NGL prices, significant deleveraging from a strategic transaction, reduced interest costs on our debt through refinancing, significant cost savings through avoidance or deferral, or operational efficiencies, we expect to need additional sources of liquidity, including additional debt or equity financing or proceeds from asset sales, at the beginning of 2016 assuming no material debt maturities prior to that date. In addition, we are exploring potential transactions involving any and all of our assets, including our Horn River Asset. If successful, a sale of our Horn River Asset could eliminate or defray our need to make or fund significant capital investments in the Horn River Asset but would also reduce our global borrowing base if not offset by the effects of any related debt reduction. A sale of our other assets could also enhance liquidity if the sale proceeds exceed the associated decrease to the global borrowing base, if any.
In November 2014, the Combined Credit Agreements were amended to eliminate the requirement to meet the minimum interest coverage ratio covenant beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015. A minimum EBITDAX covenant was added beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015. While we believe with these amendments we will be able to comply with the financial covenants contained in our Combined Credit Agreements through the end of 2015, we do not expect to exceed the required levels by a significant margin, particularly the minimum EBITDAX covenant under our Combined Credit Agreements. Accordingly, even a modest decline in prices for natural gas and NGLs, our failure to achieve anticipated cost savings through avoidance or deferral or operational efficiencies, our failure to execute certain asset purchases or the inaccuracy in any material respect of any of the other assumptions underlying our forecast could cause us to fall short of the financial covenants contained in the Combined Credit Agreements. Absent an improvement in natural gas and NGL prices, significant deleveraging from a strategic transaction, reduced interest costs on our debt through refinancing, significant cost savings through avoidance or deferral, or operational efficiencies, we do not expect to comply with our interest coverage ratio covenant under our Combined Credit Agreements beginning in the first quarter of 2016 and expect that we would need to seek additional covenant relief under the Combined Credit Agreements at that time. In addition, we have benefitted from our natural gas derivatives, which have resulted in cash proceeds being greater than the prevailing price for natural gas. Without the benefit of these derivatives, most of which expire at year-end 2015, our earnings would be reduced and our cash interest expense would exceed our resulting EBITDAX. Any inability to comply with the financial covenants contained in our Combined Credit Agreements, unless waived or amended by the requisite


10


lenders, could materially and adversely affect our liquidity by precluding further borrowings under our credit facilities and by accelerating the maturity of our debt. We may be unsuccessful in obtaining the necessary waivers or amendments.
In addition, we have significant fixed and springing debt maturities in 2015 and 2016, including the Combined Credit Agreements, the Second Lien Term Loan, the Second Lien Notes and the Senior Subordinated Notes. Note 5 contains a more complete description of our long-term debt, including springing maturities, which could occur as early as October 1, 2015. We do not expect to be able to satisfy these obligations with our cash on hand, committed financing or cash flow from operations. In order to satisfy these obligations we will need to obtain additional debt or equity financing or to sell assets, which we may not be able to do on satisfactory terms, or at all. We are limited in our ability to incur additional debt by the indenture restrictions. We may also seek to address the springing maturities by extending the maturity of or refinancing all or a portion of our Senior Subordinated Notes. If we are unsuccessful in extending or refinancing, we may not be able to satisfy such obligations when they mature.
Although we have been in discussions on a potential transaction involving our Horn River Asset and have proposed transaction terms, we reached no agreement on any material terms, including structure or valuation. Accordingly, we developed a formalized marketing process for this asset, along with any and all of our assets. We may be unsuccessful in consummating a transaction involving our Horn River Asset or any of our other assets being marketed on acceptable terms, or at all.
We have retained Houlihan Lokey Capital, Inc., Deloitte Transactions and Business Analytics LLP and other advisors to assist us in one or more of the following exercises:
evaluation of options to address near-term debt maturities;
enhancement of our liquidity position;
evaluation of various strategic alternatives, including the acquisition or monetization of any and all assets or the Company; and
employee retention.
Recently Issued Accounting Standards
In May 2014, the FASB issued accounting guidance, “Revenue from Contracts with Customers,” requiring an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The updated standard will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective and permits the use of either the retrospective or cumulative effect transition method. Early adoption is not permitted. The updated standard becomes effective for us in the first quarter of 2017. We have not yet selected a transition method and we are currently evaluating the effect, if any, that the updated standard will have on our consolidated financial statements and related disclosures.
No other pronouncements materially affecting our financial statements have been issued since the filing of our 2013 Annual Report on Form 10-K.
2. DIVESTITURES
In May 2014, we completed the sale of our Niobrara Asset to Southwestern Energy Company. The purchase price was subject to customary purchase price adjustments, which resulted in Southwestern paying us $95.6 million. We determined that the Southwestern Transaction did not represent a significant disposal of reserves under GAAP, therefore we reduced the balance of U.S. oil and gas properties by the amount of these proceeds and we did not recognize a gain or loss.
In August 2013, we completed the sale of our Southern Alberta Asset to Synergy. The purchase price was $46.0 million, which was subject to customary purchase price adjustments, resulting in a final purchase price of $42.3 million. We determined that the Synergy Transaction did not represent a significant disposal of reserves, therefore our U.S. oil and gas properties were reduced by these proceeds and we did not recognize a gain or a loss.
In April 2013, we sold an undivided 25% interest in our Barnett Shale Asset to TGBR for a purchase price of $485 million. The effective date of the transaction was September 1, 2012. The purchase price was subject to customary price adjustments, which resulted in a final purchase price of $464.0 million. We recognized a gain of $341.1 million, which was subsequently adjusted in the second half of 2013 to $339.3 million, including a revision of the gain calculation in the third quarter of 2013 of $8.0 million, before consideration of income taxes


11


based on our determination that the Tokyo Gas Transaction represented a significant disposal of reserves under GAAP. Our U.S. oil and gas properties were ultimately reduced through December 31, 2013 by $110.7 million as a result of the Tokyo Gas Transaction.
Note 3 to the consolidated financial statements in our 2013 Annual Report on Form 10-K contains additional information on other divestitures.
3. DERIVATIVES, MARKETABLE SECURITIES AND FAIR VALUE MEASUREMENTS
The following table categorizes our commodity derivative instruments based upon the level of the inputs used in estimating the fair value:
 
Asset Derivatives
 
Liability Derivatives
  
September 30, 2014
 
December 31, 2013
 
September 30, 2014
 
December 31, 2013
 
 
 
 
 
 
 
 
 
(in thousands)
 
(in thousands)
Level 2 derivative instruments
$
74,312

 
$
107,395

 
$
846

 
$
3,448

Level 3 derivative instruments
17,754

 
23,485

 

 

Total
$
92,066

 
$
130,880

 
$
846

 
$
3,448


The fair value of “Level 2” derivative instruments included in these disclosures was estimated using inputs quoted in active markets for the periods covered by the derivatives. 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 input is the market prices for natural gas 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 $3.85 to $4.90 and are based upon prices quoted in active markets for the period of time available. A decrease of these unobservable inputs would increase the fair value, while an increase would decrease the fair value.


12


The following table identifies the changes in “Level 3” net asset derivative fair values for the periods indicated:
 
 
For the Three Months Ended
September 30,
 
2014
 
2013
 
 
 
 
 
(in thousands)
Balance at beginning of period
$
(5,533
)
 
$
(9,873
)
Total gains (losses) for the period:
 
 
 
Unrealized gain (loss) on derivatives
24,829

 
24,080

Settlements in net derivative gains (losses)
(1,542
)
 
(3,302
)
Balance at end of period
$
17,754

 
$
10,905

 
 
 
 
Total gains (losses) included in net derivative gains (losses) attributable to the change in unrealized gains (losses) related to assets still held at the reporting date
$
24,485

 
$
24,026

 
 
For the Nine Months Ended
September 30,
 
2014
 
2013
 
 
 
 
 
(in thousands)
Balance at beginning of period
$
23,485

 
$
(4,931
)
Total gains (losses) for the period:
 
 
 
Unrealized gain (loss) on derivatives
(6,488
)
 
24,618

Settlements in net derivative gains (losses)
757

 
(8,782
)
Balance at end of period
$
17,754

 
$
10,905

 
 
 
 
Total gains (losses) included in net derivative gains (losses) attributable to the change in unrealized gains (losses) related to assets still held at the reporting date
$
(2,476
)
 
$
26,788

Commodity Price Derivatives
As of September 30, 2014, we had natural gas swaps as follows:
Production
Year
 
Daily Production
Volume
 
 
Natural Gas
 
Natural Gas Basis Swaps
 
 
MMcfd
 
MMcfd
Remaining 2014 (1)
 
170
 
40
2015
 
150
 
2016-2021
 
40
 
(1) 
Our natural gas basis swaps economically hedge the AECO basis adjustment from NYMEX.
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 over the original term of the hedging relationship (through 2021). Gains from the effective portion of derivative assets and liabilities held in AOCI expected to be reclassified into earnings during the following twelve months will result in production revenue of $22.7 million net of income taxes.


13


Interest Rate Derivatives
In 2010, we executed early settlements of our interest rate swaps that were designated as fair value hedges. Upon the early settlements, we recorded the resulting gain as a fair value adjustment to our debt and began to recognize the deferred gain as a reduction of interest expense over the lives of the respective notes. During the nine months ended September 30, 2014 and 2013, we recognized $1.5 million and $11.5 million, respectively, of those deferred gains as a reduction of interest expense. Gains from the effective portion of these interest rate swaps expected to reduce interest expense during the following twelve months are $2.2 million.
Fair Value Disclosures
The estimated fair value of our derivative instruments at September 30, 2014 and December 31, 2013 were as follows:
 
Asset Derivatives
 
 
Liability Derivatives
 
September 30, 2014
 
December 31, 2013
 
 
September 30, 2014
 
December 31, 2013
 
 
 
 
 
 
 
 
 
 
(in thousands)
 
 
(in thousands)
Derivatives not designated as hedges:
 
 
 
 
 
 
 
 
Commodity contracts reported in:
 
 
 
 
 
 
 
 
Current derivative assets
$
66,278

 
$
60,063

 
 
$
180

 
$
2,540

Noncurrent derivative assets
75,911

 
105,315

 
 
49,943

 
31,958

Current derivative liabilities

 

 
 
846

 
3,125

Noncurrent derivative liabilities

 

 
 

 
323

Total derivatives not designated as hedges
$
142,189

 
$
165,378

 
 
$
50,969

 
$
37,946

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 presentation 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, 2013 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.
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 sheets as of September 30, 2014 and December 31, 2013 are included in Note 5.


14


Investments
We hold certain short-term marketable securities related to interest bearing time deposits and commercial paper. These 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. During June 2014, we sold $10.0 million and transferred $10.0 million of held-to-maturity marketable securities to available-for-sale. Proceeds from these sales were used to reduce the outstanding balance on the Combined Credit Agreements. The estimated fair value of available-for-sale marketable securities is determined using market quotations based on recent trade activity (“Level 2” inputs). At September 30, 2014 we did not own any marketable securities. At December 31, 2013, we had the following marketable securities:
 
 
 
 
 
 
 
 
 
December 31, 2013
 
Amortized Cost
 
Gross Unrealized Gains
 
Gross Unrealized Losses
 
Fair Market Value
 
 
 
 
 
 
 
 
 
(in thousands)
Marketable securities (held-to-maturity)
 
 
 
 
 
 
 
Time deposits
$
29,419

 
$

 
$
(22
)
 
$
29,397

Commercial paper
136,924

 
27

 
(25
)
 
136,926

Marketable securities
$
166,343

 
$
27

 
$
(47
)
 
$
166,323

4. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consisted of the following:
 
September 30, 2014
 
December 31, 2013
 
 
 
 
 
(in thousands)
Oil and gas properties
 
 
 
Subject to depletion
$
5,635,307

 
$
5,687,557

Unevaluated costs
218,398

 
221,605

Accumulated depletion
(5,245,133
)
 
(5,268,719
)
Net oil and gas properties
608,572

 
640,443

Other property and equipment
 
 
 
Pipelines and processing facilities
332,710

 
347,093

General properties
71,049

 
72,125

Accumulated depreciation
(199,851
)
 
(198,856
)
Net other property and equipment
203,908

 
220,362

Property, plant and equipment, net of accumulated depletion and depreciation
$
812,480

 
$
860,805

We recognized other property and equipment impairment charges of $0.1 million in 2014 for pipeline in Texas.


15


5. LONG-TERM DEBT
Long-term debt consisted of the following:
 
 
September 30, 2014
 
December 31, 2013
 
 
 
 
 
(in thousands)
Combined Credit Agreements
$
275,966

 
$
211,200

Second Lien Term Loan, net of unamortized discount
609,555

 
607,572

Second Lien Notes due 2019, net of unamortized discount
195,058

 
194,423

Senior notes due 2015, net of unamortized discount

 
10,472

Senior notes due 2016, net of unamortized discount

 
8,044

Senior notes due 2019, net of unamortized discount
293,744

 
293,243

Senior notes due 2021, net of unamortized discount
310,229

 
309,190

Senior subordinated notes due 2016
350,000

 
350,000

Total debt
2,034,552

 
1,984,144

Unamortized deferred gain-terminated interest rate swaps
3,292

 
4,802

Long-term debt
$
2,037,844

 
$
1,988,946

Combined Credit Agreements
The Combined Credit Agreements’ global borrowing base was $325 million and the global letter of credit capacity was $280 million as of September 30, 2014. At September 30, 2014, we had $6.7 million available under the Combined Credit Agreements.
In November 2014, the Combined Credit Agreements' global borrowing base was reaffirmed at $325 million and the Combined Credit Agreements were amended to eliminate the requirement to meet the minimum interest coverage ratio covenant beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015. A minimum EBITDAX covenant was added beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015 that requires the following minimum EBITDAX levels:
 
Minimum EBITDAX Covenant
 
(in millions)
Three months ending December 31, 2014
$
30.0

Six months ending March 31, 2015
59.0

Nine months ending June 30, 2015
87.25

Twelve months ending September 30, 2015
120.5

Twelve months ending December 31, 2015
122.0

Additionally, the Combined Credit Agreements were amended changing certain definitions that impact the calculation of EBITDAX in both the November 2014 amendment and the April 2014 amendment and we permanently reduced the aggregate maximum credit amounts under the Combined Credit Agreements from $1.75 billion to $650 million in April 2014 and to $450 million in November 2014.
Senior Notes due 2015 and Senior Notes due 2016
In April 2014, we redeemed all remaining outstanding notes under our Senior Notes due 2015 and Senior Notes due 2016. Our Senior Notes due 2015 were redeemed at 101.938% of the principal amount plus accrued and unpaid interest representing a total payment of $10.9 million and our Senior Notes due 2016 were redeemed at 105.875% of the principal amount plus accrued and unpaid interest representing a total payment of $8.9 million.


16


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 September 30, 2014, 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 debt. We cannot predict when or if we will meet the incurrence test.
We retained a portion of the cash received from our asset sales. Our indentures require us to reinvest or repay senior debt with net cash proceeds from certain asset sales within one year.


17


Summary of All Outstanding Debt
The following table summarizes certain significant aspects of our long-term debt outstanding at September 30, 2014.
 
 
Priority on Collateral and Structural Seniority (1)
 
 
Highest
priority
Lowest
priority
 
 
First Lien
 
Second Lien
 
Senior Unsecured
 
Senior Subordinated
 
 
Combined Credit
Agreements
 
Second Lien Term Loan
 
Second Lien Notes due 2019
 
2019
Senior Notes
 
2021
Senior Notes
 
Senior
Subordinated Notes
Principal amount (1) (2)
 
$325 million
 
$625 million
 
$200 million
 
$298 million
 
$325 million
 
$350 million
Scheduled maturity date (3)
 
September 6, 2016
 
June 21, 2019
 
June 21, 2019
 
August 15, 2019
 
July 1, 2021
 
April 1, 2016
Springing maturity date (3)
 
October 1, 2015
 
January 1, 2016
 
January 1, 2016
 
N/A
 
N/A
 
N/A
Interest rate on outstanding borrowings at September 30, 2014 (4)
 
4.09%
 
7.00%
 
7.00%
 
9.125%
 
11.00%
 
7.125%
Base interest rate
options (5) (6)
 
LIBOR, ABR, CDOR
 
LIBOR floor of 1.25%; ABR floor of 2.25%
 
LIBOR floor of 1.25%
 
N/A
 
N/A
 
N/A
Financial covenants (7) (9)
 
- Minimum current ratio of 1.0
- Minimum EBITDA to cash interest expense ratio of 1.10
- Maximum senior secured debt leverage ratio of 2.0
 
N/A
 
N/A
 
N/A
 
N/A
 
N/A
Significant restrictive covenants (8)(9)
 
- 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
 
- 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 (9)
 
Any time
 
Any time, subject to re-pricing event
June 21,
2015: 101
 
Any time, subject to re-pricing event
June 21,
2015: 101
 
August 15,
2014: 104.563
2015: 103.042
2016: 101.521
2017: par
 
July 1,
2019: 102.000
2020: par
 
Any time
Make-whole redemption (9)
 
N/A
 
N/A
 
N/A
 
N/A
 
Callable prior
to July 1, 2019
at make-whole
call price of
Treasury +50 bps
 
N/A
Change of control (9)
 
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
Equity clawback (9)
 
N/A
 
N/A
 
N/A
 
N/A
 
Redeemable until
July 1, 2016
at 111.00%,
plus accrued
interest for
up to 35%
 
N/A
Estimated fair value (10)
 
$276.0 million
 
$568.8 million
 
$182.0 million
 
$186.3 million
 
$213.7 million
 
$136.5 million


18



(1) 
Borrowings under the Amended and Restated U.S. Credit Facility, Second Lien Term Loan and 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 Second Lien Term Loan and the 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 September 30, 2014.
(3) 
The Combined Credit Agreements are required to be repaid 91 days prior to the maturity of the Senior Subordinated Notes, the Second Lien Term Loan or the Second Lien Notes due 2019, if on the applicable date any amount of such debt remains outstanding. The Second Lien Term Loan and Second Lien Notes due 2019 are required to be repaid (1) 91 days prior to the maturity of the 2019 Senior Notes if more than $100 million of the 2019 Senior Notes remain outstanding and (2) 91 days prior to the maturity of the Senior Subordinated Notes if on the applicable date the amount remaining outstanding is greater than $100 million. As of September 30, 2014, as presently structured and assuming no changes in the amounts outstanding, amounts outstanding under the Combined Credit Agreements would be due on October 1, 2015 and the Second Lien Term Loan and Second Lien Notes due 2019 would be due on January 1, 2016.
(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% and 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% and 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 Eurodollar 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% and 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 Eurodollar loans, and a commitment fee on the unused availability under the Amended and Restated Canadian Credit Facility of 0.50%.


19


(7) 
As of September 30, 2014, the future minimum required interest coverage ratio for the Combined Credit Agreements is as follows:
Period
 
Interest Coverage Ratio
 
Period
 
Interest Coverage Ratio
Q4 2014
 
1.10
 
Q4 2015
 
1.20
Q1 2015
 
1.10
 
Q1 2016
 
1.50
Q2 2015
 
1.15
 
Q2 2016
 
2.00
Q3 2015
 
1.15
 
 
 
 
In November 2014, the Combined Credit Agreements were amended to eliminate the requirement to meet the minimum interest coverage ratio covenant beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015. A minimum EBITDAX covenant was added beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015 that requires the following minimum EBITDAX levels:
 
Minimum EBITDAX Covenant
 
(in millions)
Three months ending December 31, 2014
$
30.0

Six months ending March 31, 2015
59.0

Nine months ending June 30, 2015
87.25

Twelve months ending September 30, 2015
120.5

Twelve months ending December 31, 2015
122.0

(8) 
Our indentures require us to reinvest or repay senior debt with net cash proceeds from certain asset sales within one year.
(9) 
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.
(10) 
The estimated fair value is determined using market quotations based on recent trade activity for fixed rate obligations (“Level 2” inputs). Our Second Lien Term Loan and 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).
6. INCOME TAXES
Note 13 to the consolidated financial statements in our 2013 Annual Report on Form 10-K contains additional information about our income taxes. At September 30, 2014, our U.S. and Canadian valuation allowances are $372.0 million and $60.7 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 assets primarily related to our cumulative net operating losses. Income tax recognized for the three and nine months ended September 30, 2014 is a result of hedge gains previously deferred in AOCI being realized during the periods and the net tax impact being recognized, partially offset by a refund of $7.6 million filed in September 2014.
7. COMMITMENTS AND CONTINGENCIES
In each of July 2011 and June 2012, we received a subpoena duces tecum from the SEC requesting certain documents. In July 2014, the SEC notified us that the staff has completed its investigation and does not intend to recommend an enforcement action by the SEC against us.


20


Note 14 to the consolidated financial statements in our 2013 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 September 30, 2014.
8. FORTUNE CREEK
Note 15 to the consolidated financial statements in our 2013 Annual Report on Form 10-K contains additional information on Fortune Creek. In March 2014, we agreed with KKR to an amendment to extend the ending date of the minimum gross capital expenditures requirement, of which C$120 million remains, to the earlier of June 30, 2016 or 12 months following consummation of a transaction involving a material portion of our Horn River Asset and to broaden allowable spending to include acquisitions of producing properties that utilize partnership assets. As part of the amendment, we contributed C$28 million to Fortune Creek which was subsequently distributed to KKR and was applied against the gathering agreement requirement. The effect of this contribution was to reduce the balance of the partnership liability and to reduce the gathering rate that burdens our Horn River Asset production by C$0.13 per Mcf until at least 2016. We do not expect to be able to satisfy these capital expenditure requirements with our cash on hand, committed financing or cash flow from operations and will need to obtain additional debt or equity financing or sell assets, which we may not be able to do on satisfactory terms, or at all.
We committed gas production from our Horn River Asset for ten years beginning 2012, as more fully described below. KKR contributed C$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.
The firm gathering agreement with Fortune Creek is guaranteed by us. 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 in financing activities.
Based on a quarterly analysis of the partners’ equity at risk, we have determined the partnership to be a VIE. Further, based on our ability to direct the activities surrounding the production of natural gas and our direct management of the operations of the Fortune Creek facilities, we have determined we are the primary beneficiary and, therefore, we consolidate Fortune Creek.
9. 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 September 30, 2014 and December 31, 2013, we had 179.8 million and 177.3 million shares of common stock outstanding, respectively.
Stock Options
No options have been granted during 2014. The following summarizes the values from and assumptions for the Black-Scholes option pricing model for stock options issued during the nine months ended September 30, 2013:
Weighted avg grant date fair value
$1.05
Weighted avg risk-free interest rate
1.31%
Expected life
4.9 years
Wtd avg volatility
69.0%
Expected dividends



21


The following table summarizes our stock option activity for the nine months ended September 30, 2014:
 
Shares
 
Weighted
Average
Exercise
Price
 
Weighted
Average
Remaining
Contractual Life
 
Aggregate
Intrinsic
Value
 
 
 
 
 
(in years)
 
(in thousands)
Outstanding at January 1, 2014
6,771,578

 
$
7.82

 
 
 
 
Forfeited
(44,950
)
 
1.65

 
 
 
 
Expired
(111,494
)
 
9.83

 
 
 
 
Outstanding at September 30, 2014
6,615,134

 
$
7.83

 
5.4
 
$

Exercisable at September 30, 2014
5,232,903

 
$
9.18

 
4.6
 
$

As of September 30, 2014, we estimate that a total of 6.3 million stock options will vest including those options already exercisable. As of September 30, 2014, the unrecognized compensation cost related to outstanding unvested stock options was $1.0 million, which is expected to be recognized in expense through August 2016. Compensation expense related to stock options of $1.1 million and $3.2 million was recognized for the nine months ended September 30, 2014 and 2013, respectively.
Restricted Stock and Stock Units
The following table summarizes our restricted stock and stock unit activity for the nine months ended September 30, 2014:
 
Payable in shares
 
Payable in cash
 
Shares
 
Weighted
Average
Grant Date
Fair Value
 
Shares
 
Weighted
Average
Grant Date
Fair Value
Outstanding at January 1, 2014
5,668,090

 
$
3.90

 
1,572,341

 
$
3.69

Granted
4,765,425

 
2.64

 

 

Vested
(2,559,959
)
 
4.86

 
(631,275
)
 
4.29

Forfeited
(348,554
)
 
3.09

 
(33,458
)
 
3.20

Outstanding at September 30, 2014
7,525,002

 
$
2.82

 
907,608

 
$
3.32

As of September 30, 2014, the unrecognized compensation cost related to outstanding unvested restricted stock was $14.8 million, which is expected to be recognized in expense through July 2017. Grants of restricted stock and RSUs during the nine months ended September 30, 2014 had an estimated grant date fair value of $12.6 million. The fair value of outstanding RSUs to be settled in cash was $0.5 million at September 30, 2014. For the nine months ended September 30, 2014 and 2013, compensation expense related to restricted stock and RSUs of $8.4 million and $12.2 million, respectively, was recognized. The total fair value of shares vested during the nine months ended September 30, 2014 was $10.2 million.


22


10. 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
September 30,
 
For the Nine Months Ended
September 30,
 
2014
 
2013
 
2014
 
2013
 
 
 
 
 
 
 
 
 
(in thousands, except per share data)
Net income (loss) attributable to Quicksilver
$
23,757

 
$
10,577

 
$
(71,171
)
 
$
193,397

Basic income allocable to participating securities (1)
(772
)
 
(312
)
 

 
(5,111
)
Income (loss) available to shareholders
$
22,985

 
$
10,265

 
$
(71,171
)
 
$
188,286

Weighted average common shares – basic
173,936

 
171,682

 
173,783

 
171,403

Effect of dilutive securities (2)
 
 
 
 
 
 
 
Share-based compensation awards
216

 
311

 

 
170

Weighted average common shares – diluted
174,152

 
171,993

 
173,783

 
171,573

Earnings (loss) per common share – basic
$
0.13

 
$
0.06

 
$
(0.41
)
 
$
1.10

Earnings (loss) per common share – diluted
$
0.13

 
$
0.06

 
$
(0.41
)
 
$
1.10


(1) 
Restricted share awards that contain nonforfeitable rights to dividends are participating securities and, therefore, should be included in computing earnings per share 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 September 30, 2014, 6.6 million shares associated with our stock options and 1.2 million shares associated with our unvested RSUs were antidilutive and, therefore, excluded from the diluted share calculations. For the three months ended September 30, 2013, 6.2 million shares associated with our stock options and 0.2 million shares associated with our unvested RSUs were antidilutive and, therefore, excluded from the diluted share calculations. For the nine months ended September 30, 2014, 6.6 million shares associated with our stock options and 0.8 million shares associated with our unvested RSUs were antidilutive and, therefore, excluded from the diluted share calculations. For the nine months ended September 30, 2013, 5.5 million shares associated with our stock options and 0.2 million shares associated with our unvested RSUs were antidilutive and, therefore, excluded from the diluted share calculations.


23


11. CONDENSED CONSOLIDATING FINANCIAL INFORMATION
Note 18 to the consolidated financial statements in our 2013 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 three- and nine-month periods covered by the condensed 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
 
September 30, 2014
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)
ASSETS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current assets
$
338,424

 
$
13,096

 
$
65,733

 
$
(23,193
)
 
$
394,060

 
$
(455
)
 
$
1,746

 
$
949

 
$
396,300

Property and equipment
417,921

 
14,625

 
305,197

 

 
737,743

 

 
74,737

 

 
812,480

Investment in subsidiaries (equity method)
(227,994
)
 

 
(23,409
)
 
227,994

 
(23,409
)
 
(23,429
)
 

 
46,838

 

Other assets
457,285

 

 
15,473

 
(413,281
)
 
59,477

 

 

 

 
59,477

Total assets
$
985,636

 
$
27,721

 
$
362,994

 
$
(208,480
)
 
$
1,167,871

 
$
(23,884
)
 
$
76,483

 
$
47,787

 
$
1,268,257

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current liabilities
$
103,042

 
$
13,401

 
$
11,064

 
$
(23,193
)
 
$
104,314

 
$
(475
)
 
$
3,736

 
$
949

 
$
108,524

Long-term liabilities
1,980,078

 
19,241

 
575,003

 
(413,281
)
 
2,161,041

 

 
1,525

 
94,651

 
2,257,217

Stockholders' equity
(1,097,484
)
 
(4,921
)
 
(223,073
)
 
227,994

 
(1,097,484
)
 
(23,409
)
 
71,222

 
(47,813
)
 
(1,097,484
)
Total liabilities and equity
$
985,636

 
$
27,721

 
$
362,994

 
$
(208,480
)
 
$
1,167,871

 
$
(23,884
)
 
$
76,483

 
$
47,787

 
$
1,268,257

 
 
December 31, 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)
ASSETS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current assets
$
349,586

 
$
10,735

 
$
53,034

 
$
(19,642
)
 
$
393,713

 
$
909

 
$
1,110

 
$
(1,772
)
 
$
393,960

Property and equipment
455,822

 
15,486

 
307,865

 

 
779,173

 

 
81,632

 

 
860,805

Investment in subsidiaries (equity method)
(217,852
)
 

 
(33,840
)
 
217,852

 
(33,840
)
 
(33,840
)
 

 
67,680

 

Other assets
472,792

 

 
32,892

 
(390,723
)
 
114,961

 

 

 

 
114,961

Total assets
$
1,060,348

 
$
26,221

 
$
359,951

 
$
(192,513
)
 
$
1,254,007

 
$
(32,931
)
 
$
82,742

 
$
65,908

 
$
1,369,726

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current liabilities
$
124,275

 
$
12,210

 
$
17,167

 
$
(19,642
)
 
$
134,010

 
$
888

 
$
1,671

 
$
(1,772
)
 
$
134,797

Long-term liabilities
1,942,043

 
19,242

 
542,659

 
(390,723
)
 
2,113,221

 

 
1,546

 
126,132

 
2,240,899

Stockholders' equity
(1,005,970
)
 
(5,231
)
 
(199,875
)
 
217,852

 
(993,224
)
 
(33,819
)
 
79,525

 
(58,452
)
 
(1,005,970
)
Total liabilities and equity
$
1,060,348

 
$
26,221

 
$
359,951

 
$
(192,513
)
 
$
1,254,007

 
$
(32,931
)
 
$
82,742

 
$
65,908

 
$
1,369,726



24


Condensed Consolidating Statements of Income
 
For the Three Months Ended September 30, 2014
  
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
$
120,513

 
$
427

 
$
42,558

 
$

 
$
163,498

 
$

 
$
4,271

 
$
(4,271
)
 
$
163,498

Operating expenses
72,868

 
341

 
27,648

 

 
100,857

 

 
2,128

 
(4,271
)
 
98,714

Equity in net earnings of subsidiaries
8,821

 

 
(1,458
)
 
(8,821
)
 
(1,458
)
 
2,144

 

 
(686
)
 

Operating income (loss)
56,466

 
86

 
13,452

 
(8,821
)
 
61,183

 
2,144

 
2,143

 
(686
)
 
64,784

Fortune Creek accretion

 

 

 

 

 

 

 
(3,602
)
 
(3,602
)
Interest expense and other
(37,613
)
 
86

 
(4,838
)
 

 
(42,365
)
 

 
1

 

 
(42,364
)
Income tax (expense) benefit
4,826

 
(30
)
 
65

 
78

 
4,939

 

 

 

 
4,939

Net income (loss)
$
23,679

 
$
142

 
$
8,679

 
$
(8,743
)
 
$
23,757

 
$
2,144

 
$
2,144

 
$
(4,288
)
 
$
23,757

Other comprehensive income (loss)
(11,564
)
 

 
(3,325
)
 

 
(14,889
)
 

 

 

 
(14,889
)
Equity in OCI of subsidiaries
(3,325
)
 

 

 
3,325

 

 

 

 

 

Comprehensive income (loss)
$
8,790

 
$
142

 
$
5,354

 
$
(5,418
)
 
$
8,868

 
$
2,144

 
$
2,144

 
$
(4,288
)
 
$
8,868

 
 
For the Three Months Ended September 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
$
114,021

 
$
192

 
$
38,903

 
$

 
$
153,116

 
$

 
$
5,674

 
$
(5,674
)
 
$
153,116

Operating expenses
73,594

 
68

 
30,360

 

 
104,022

 

 
2,693

 
(5,674
)
 
101,041

Tokyo Gas Transaction gain
7,974

 

 

 

 
7,974

 

 

 

 
7,974

Equity in net earnings of subsidiaries
3,854

 

 
(1,834
)
 
(3,854
)
 
(1,834
)
 
2,984

 

 
(1,150
)
 

Operating income (loss)
52,255

 
124

 
6,709

 
(3,854
)
 
55,234

 
2,984

 
2,981

 
(1,150
)
 
60,049

Fortune Creek accretion

 

 

 

 

 

 

 
(4,818
)
 
(4,818
)
Interest expense and other
(36,922
)
 

 
(1,769
)
 

 
(38,691
)
 

 
3

 

 
(38,688
)
Income tax (expense) benefit
(4,756
)
 

 
(1,210
)
 

 
(5,966
)
 

 

 

 
(5,966
)
Net income (loss)
$
10,577

 
$
124

 
$
3,730

 
$
(3,854
)
 
$
10,577

 
$
2,984

 
$
2,984

 
$
(5,968
)
 
$
10,577

Other comprehensive income (loss)
(6,114
)
 

 
(2,680
)
 

 
(8,794
)
 

 

 

 
(8,794
)
Equity in OCI of subsidiaries
(2,680
)
 

 

 
2,680

 

 

 

 

 

Comprehensive income (loss)
$
1,783

 
$
124

 
$
1,050

 
$
(1,174
)
 
$
1,783

 
$
2,984

 
$
2,984

 
$
(5,968
)
 
$
1,783



25


 
For the Nine Months Ended September 30, 2014
  
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
$
269,321

 
$
1,212

 
$
102,783

 
$

 
$
373,316

 
$

 
$
13,349

 
$
(13,349
)
 
$
373,316

Operating expenses
225,906

 
988

 
86,491

 

 
313,385

 

 
6,014

 
(13,349
)
 
306,050

Equity in net earnings of subsidiaries
2,864

 

 
(4,266
)
 
(2,864
)
 
(4,266
)
 
7,339

 

 
(3,073
)
 

Operating income (loss)
46,279

 
224

 
12,026

 
(2,864
)
 
55,665

 
7,339

 
7,335

 
(3,073
)
 
67,266

Fortune Creek accretion

 

 

 

 

 

 

 
(11,605
)
 
(11,605
)
Interest expense and other
(117,315
)
 
86

 
(8,526
)
 

 
(125,755
)
 

 
4

 

 
(125,751
)
Income tax (expense) benefit
(213
)
 
(78
)
 
(868
)
 
78

 
(1,081
)
 

 

 

 
(1,081
)
Net income (loss)
$
(71,249
)
 
$
232

 
$
2,632

 
$
(2,786
)
 
$
(71,171
)
 
$
7,339

 
$
7,339

 
$
(14,678
)
 
$
(71,171
)
Other comprehensive income (loss)
(20,252
)
 

 
(6,849
)
 

 
(27,101
)
 

 

 

 
(27,101
)
Equity in OCI of subsidiaries
(6,849
)
 

 

 
6,849

 

 

 

 

 

Comprehensive income (loss)
$
(98,350
)
 
$
232

 
$
(4,217
)
 
$
4,063

 
$
(98,272
)
 
$
7,339

 
$
7,339

 
$
(14,678
)
 
$
(98,272
)
 
 
For the Nine Months Ended September 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
$
334,848

 
$
608

 
$
111,862

 
$

 
$
447,318

 
$

 
$
16,736

 
$
(16,736
)
 
$
447,318

Operating expenses
256,810

 
206

 
89,559

 

 
346,575

 

 
7,552

 
(16,736
)
 
337,391

Tokyo Gas Transaction gain
341,146

 

 

 

 
341,146

 

 

 

 
341,146

Equity in net earnings of subsidiaries
(9,227
)
 

 
(5,300
)
 
9,227

 
(5,300
)
 
9,190

 

 
(3,890
)
 

Operating income (loss)
409,957

 
402

 
17,003

 
9,227

 
436,589

 
9,190

 
9,184

 
(3,890
)
 
451,073

Fortune Creek accretion

 

 

 

 

 

 

 
(14,490
)
 
(14,490
)
Interest expense and other
(200,639
)
 

 
(24,490
)
 

 
(225,129
)
 

 
6

 

 
(225,123
)
Income tax (expense) benefit
(15,921
)
 

 
(2,142
)
 

 
(18,063
)
 

 

 

 
(18,063
)
Net income (loss)
$
193,397

 
$
402

 
$
(9,629
)
 
$
9,227

 
$
193,397

 
$
9,190

 
$
9,190

 
$
(18,380
)
 
$
193,397

Other comprehensive income (loss)
(29,014
)
 

 
(9,100
)
 

 
(38,114
)
 

 

 

 
(38,114
)
Equity in OCI of subsidiaries
(9,100
)
 

 

 
9,100

 

 

 

 

 

Comprehensive income (loss)
$
155,283

 
$
402

 
$
(18,729
)
 
$
18,327

 
$
155,283

 
$
9,190

 
$
9,190

 
$
(18,380
)
 
$
155,283



26


Condensed Consolidating Statements of Cash Flows
 
For the Nine Months Ended September 30, 2014
 
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)
Net cash flow provided by (used in) operating activities
$
(39,474
)
 
$
(688
)
 
$
28,843

 
$

 
$
(11,319
)
 
$

 
$
6,336

 
$

 
$
(4,983
)
Purchases of property, plant and equipment
(88,119
)
 
(57
)
 
(23,247
)
 

 
(111,423
)
 

 
(21
)
 

 
(111,444
)
Investment in subsidiary
(1,246
)
 

 
(26,395
)
 
1,246

 
(26,395
)
 
(26,395
)
 

 
52,790

 

Proceeds from Southwestern Transaction
95,587

 

 

 

 
95,587

 

 

 

 
95,587

Proceeds from sale of properties and equipment
1,445

 

 
497

 

 
1,942

 

 

 

 
1,942

Purchases of marketable securities
(55,890
)
 

 

 

 
(55,890
)
 

 

 

 
(55,890
)
Maturities and sales of marketable securities
222,025

 

 

 

 
222,025

 

 

 

 
222,025

Net cash flow provided by (used in) investing activities
173,802

 
(57
)
 
(49,145
)
 
1,246

 
125,846

 
(26,395
)
 
(21
)
 
52,790

 
152,220

Issuance of debt
174,000

 

 
69,184

 

 
243,184

 

 

 

 
243,184

Repayments of debt
(138,651
)
 

 
(55,038
)
 

 
(193,689
)
 

 

 

 
(193,689
)
Debt issuance costs paid
(225
)
 

 

 

 
(225
)
 

 

 

 
(225
)
Intercompany note
(22,558
)
 

 
22,558

 

 

 

 

 

 

Intercompany financing

 
745

 
501

 
(1,246
)
 

 

 

 

 

Contribution received

 

 

 

 

 
26,395

 
26,395

 
(52,790
)
 

Distribution of Fortune Creek Partnership funds

 

 

 

 

 

 
(37,113
)
 

 
(37,113
)
Purchase of treasury stock
(2,388
)
 

 

 

 
(2,388
)
 

 

 

 
(2,388
)
Net cash flow provided by (used in) financing activities
10,178

 
745

 
37,205

 
(1,246
)
 
46,882

 
26,395

 
(10,718
)
 
(52,790
)
 
9,769

Effect of exchange rates on cash

 

 
(2,718
)
 

 
(2,718
)
 

 
4,934

 

 
2,216

Net increase (decrease) in cash and equivalents
144,506

 

 
14,185

 

 
158,691

 

 
531

 

 
159,222

Cash and equivalents at beginning of period
83,893

 

 
4,135

 

 
88,028

 
22

 
1,053

 

 
89,103

Cash and equivalents at end of period
$
228,399

 
$

 
$
18,320

 
$

 
$
246,719

 
$
22

 
$
1,584

 
$

 
$
248,325



27


 
For the Nine Months Ended September 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
$
(113,029
)
 
$
(19
)
 
$
25,517

 
$
(87,531
)
 
$

 
$
6,428

 
$
(81,103
)
Purchases of property, plant and equipment
(53,291
)
 
19

 
(24,752
)
 
(78,024
)
 

 
(525
)
 
(78,549
)
Proceeds from Tokyo Gas Transaction
463,418

 

 

 
$
463,418

 

 

 
463,418

Proceeds from Synergy transaction
42,297

 

 

 
42,297

 

 

 
42,297

Proceeds from sale of properties and equipment
2,977

 

 
17

 
2,994

 

 

 
2,994

Purchases of marketable securities
(142,823
)
 

 

 
$
(142,823
)
 

 

 
(142,823
)
Maturities and sales of marketable securities
13,178

 

 

 
$
13,178

 

 

 
13,178

Net cash flow provided by (used in)
 investing activities
325,756

 
19

 
(24,735
)
 
301,040

 

 
(525
)
 
300,515

Issuance of debt
1,170,266

 

 
3,040

 
1,173,306

 

 

 
1,173,306

Repayments of debt
(1,157,969
)
 

 
(150,413
)
 
(1,308,382
)
 

 

 
(1,308,382
)
Debt issuance costs paid
(25,868
)
 

 

 
(25,868
)
 

 

 
(25,868
)
Intercompany note
(147,103
)
 

 
147,103

 

 

 

 

Distribution of Fortune Creek Partnership funds

 

 

 

 

 
(8,079
)
 
(8,079
)
Purchase of treasury stock
(1,472
)
 

 

 
(1,472
)
 

 

 
(1,472
)
Net cash flow used in financing activities
(162,146
)
 

 
(270
)
 
(162,416
)
 

 
(8,079
)
 
(170,495
)
Effect of exchange rates on cash

 

 
(512
)
 
(512
)
 

 
3,122

 
2,610

Net increase in cash and equivalents
50,581

 

 

 
50,581

 

 
946

 
51,527

Cash and equivalents at beginning of period
4,618

 

 

 
4,618

 

 
333

 
4,951

Cash and equivalents at end of period
$
55,199

 
$

 
$

 
$
55,199

 
$

 
$
1,279

 
$
56,478



28


12. 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. In Canada, our midstream operation is the Fortune Creek partnership. 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 September 30:
(in thousands)
2014
 
 
 
 
 
 
 
 
 
 
 
Revenue
$
120,513

 
$
42,072

 
$
5,184

 
$

 
$
(4,271
)
 
$
163,498

DD&A
8,096

 
4,171

 
1,256

 
446

 

 
13,969

Impairment expense

 

 
135

 

 

 
135

Operating income (loss)
57,809

 
16,364

 
2,367

 
(11,756
)
 

 
64,784

Property and equipment costs incurred
20,912

 
7,254

 
72

 
218

 

 
28,456

2013
 
 
 
 
 
 
 
 
 
 
 
Revenue
$
114,002

 
$
38,407

 
$
6,381

 
$

 
$
(5,674
)
 
$
153,116

DD&A
8,402

 
4,114

 
1,300

 
574

 

 
14,390

Operating income (loss)
56,911

 
11,076

 
3,107

 
(11,045
)
 

 
60,049

Property and equipment costs incurred
15,147

 
4,288

 
1,615

 
(329
)
 

 
20,721

For the Nine Months Ended September 30:
 
2014
 
 
 
 
 
 
 
 
 
 
 
Revenue
$
269,310

 
$
101,198

 
$
16,157

 
$

 
$
(13,349
)
 
$
373,316

DD&A
23,652

 
13,779

 
3,744

 
1,409

 

 
42,584

Impairment expense

 

 
135

 

 

 
135

Operating income (loss)
78,891

 
20,199

 
7,700

 
(39,524
)
 

 
67,266

Property and equipment costs incurred
85,814

 
20,924

 
83

 
763

 

 
107,584

2013
 
 
 
 
 
 
 
 
 
 
 
Revenue
$
334,804

 
$
110,052

 
$
19,198

 
$

 
$
(16,736
)
 
$
447,318

DD&A
29,745

 
12,458

 
3,947

 
1,761

 

 
47,911

Operating income (loss)
456,624

 
30,126

 
9,593

 
(45,270
)
 

 
451,073

Property and equipment costs incurred
50,459

 
9,972

 
2,369

 
9,655

 

 
72,455

Property, plant and equipment-net
 
 
 
 
 
 
 
 
 
 
 
September 30, 2014
$
415,163

 
$
303,827

 
$
89,362

 
$
4,128

 
$

 
$
812,480

December 31, 2013
451,840

 
306,423

 
97,118

 
5,424

 

 
860,805

Total assets
 
 
 
 
 
 
 
 
 
 
 
September 30, 2014
796,931

 
362,994

 
104,204

 
4,128

 

 
$
1,268,257

December 31, 2013
895,388

 
359,951

 
108,963

 
5,424

 

 
1,369,726



29


13. SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid (received) for interest and income taxes is as follows:
 
 
For the Nine Months Ended
September 30,
 
2014
 
2013
 
 
 
 
 
(in thousands)
Interest, net of capitalized interest
$
124,408

 
$
227,189

Income taxes
(7,844
)
 
1,217


Other significant non-cash transactions are as follows:
 
 
For the Nine Months Ended
September 30,
 
2014
 
2013
 
 
 
 
 
(in thousands)
Working capital related to capital expenditures
$
7,612

 
$
4,867

14. TRANSACTIONS AND OTHER MATTERS WITH RELATED PARTIES
As of September 30, 2014, 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 of Quicksilver.
During the first nine months of 2013, we paid $0.3 million 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 nine months of 2014 and 2013.
In August 2013, we paid $0.2 million in commission to an entity controlled by members of the Darden family in connection with the sublease of a portion of our office space.
Thomas Darden, brother of Glenn Darden and Anne Darden Self, retired as an employee on December 31, 2013, and resigned from the board of directors effective September 1, 2014. During the first nine months of 2014, consulting fee payments of $405,000, office allowance payments of $112,500 and COBRA payments of $39,000 were made to Mr. Darden. Additionally, in accordance with the agreement related to his retirement signed in May 2013 and following the execution and non-revocation of a release agreement satisfactory to us, we paid Mr. Darden a cash bonus of $286,650 and an equity bonus in the form of 72,662 fully vested shares having a grant date fair value equal to $191,100 in March 2014.


30


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 2013 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:
2014 Highlights – a summary of significant activities and events affecting Quicksilver
2014 Capital Program – a summary of our planned capital expenditures during 2014
Results of Operations – an analysis of our consolidated results of operations for the three- and nine-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
2014 HIGHLIGHTS
In March 2014, we executed an agreement with Southwestern Energy Company to sell all of our Niobrara Asset. The purchase price was subject to customary purchase price adjustments, which resulted in Southwestern paying us $95.6 million. The transaction closed on May 1, 2014. The decision to sell this acreage was largely rooted in SWEPI’s plans to exit its North American shale plays, including the shared interest in our Niobrara Asset.
In the third quarter of 2014, we drilled two wells in Pecos County as part of our joint venture with Eni. The first well began flow back up casing at a rate of 750 Boed. Tubing was later installed and the 83-day flow rate is approximately 535 Boed from a 3,700-foot lateral. A second well was completed in a 5,200-foot lateral with current flow back at a rate of 700 Boed, of which 75% is oil, on a restricted choke after recovering approximately 15% of the fracture fluid. Oil volumes have improved daily and continue to increase. The joint venture expects to commence drilling two additional wells in the fourth quarter of 2014.
Strategic Alternatives
We have appointed John Little with Deloitte Transactions and Business Analytics LLP as our Strategic Alternatives Officer. Mr. Little, in this capacity, has a number of duties that principally involve assisting us in various strategic pursuits, particularly involving our Combined Credit Agreements’ semi-annual redetermination, the springing debt maturities of our Combined Credit Agreements and our second lien indebtedness arising from our Senior Subordinated Notes’ stated maturity of April 2016, the marketing of our assets and our efforts to maximize liquidity in the present environment.
We completed a semi-annual borrowing base redetermination in early November 2014. Note 5 to our condensed consolidated interim financial statements included in Item 1 of this Quarterly Report contains more information about the results of this redetermination.
We are exploring several avenues to address our capital structure, including the stated and springing maturities. We are in frequent discussions with certain of the security holders regarding possible paths to be undertaken.
We have also begun a broad and more formalized asset marketing process. This process, being led by Houlihan Lokey Capital, Inc., covers any and all of our operating assets and is flexible with regard to structure of any transaction proposal. The marketing process is targeting receipt of bids in the fourth quarter 2014, with a targeted closing date on any transaction(s) in the ordinary course following successful execution of sales agreement(s), which aligns with our other strategic activities.
Despite having liquidity of over $230 million at October 31, 2014, we are also continuing our liquidity enhancement program, including sales of non-core assets, reducing outstanding letters of credit, tax structuring and other items.


31


While there are processes and accountabilities covering each separate component of these strategic alternatives, we are currently unable to predict when any of these efforts will be completed, or if they will be completed at all.
Significant Contract Revisions
In March 2014, we agreed with KKR to an amendment to extend the ending date of the remaining required capital spending to the earlier of June 30, 2016 or 12 months following consummation of a transaction involving a material portion of our Horn River Asset and to broaden allowable spending to include acquisitions of producing properties that utilize partnership assets. As part of the amendment, we contributed C$28 million to Fortune Creek which was subsequently distributed to KKR and was applied against the gathering agreement requirement. The effect of this contribution was to reduce the balance of the partnership liability and to reduce the gathering rate that burdens our Horn River Asset production by C$0.13 per Mcf until at least 2016. Additionally, as a result of this amendment, KKR is no longer required to fund the capital for construction of a proposed gas treatment facility, but at its option may provide funding for any facility to be constructed by the partnership, including the proposed gas treatment facility. The amendment provides us with additional time and flexibility in completing a joint venture transaction involving our Horn River Asset and immediate cash flow relief through the reduced gathering fee paid to Fortune Creek.
In July 2014, we reached an agreement to lower the rates assessed for gas lift and gas gathering and processing from midstream providers serving our Barnett Shale Asset. Under the terms of the amendment, which is effective June 1, 2014, the rate assessed for gas lift was reduced by as much as 65% for volumes originating from the core dry gas areas in the Barnett Shale. Additionally, in the southern liquids-rich area of our Barnett Shale Asset, the rate assessed for aggregate gathering and processing was reduced by 40% to 45% on new wells completed in the next 24 months, and the lower rates will apply to these wells through the remaining term of the gathering and processing agreement.
2014 CAPITAL PROGRAM
We incurred costs related to our capital program of $107.6 million for the first nine months of 2014. We anticipate full-year 2014 spending to be between $130 million and $135 million. The capital program may be further reduced should commodity prices retreat further and become unsupportive of forecasted capital spending.


32


RESULTS OF OPERATIONS
Three Months Ended September 30, 2014 and 2013
The following discussion compares the results of operations for the three months ended September 30, 2014 and 2013, or the 2014 quarter and 2013 quarter, respectively. “Other U.S.” refers to the combined amounts for our Niobrara Asset, West Texas Asset and Southern Alberta Basin Asset. The impacts of the Southwestern and Synergy Transactions were immaterial for further disaggregation.
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 view of the derivatives' usefulness, provides more comparability and is consistent with how management views and evaluates operating results.
Production Revenue and Realized Cash Gains (Losses) on Derivatives by Operating Area:
 
Natural Gas
 
NGL
 
Oil
 
Total
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(in millions)
Barnett Shale
$
47.4

 
$
39.7

 
$
15.8

 
$
18.4

 
$
0.9

 
$
1.3

 
$
64.1

 
$
59.4

Other U.S.

 
0.1

 

 
0.1

 
0.6

 
2.2

 
0.6

 
2.4

Hedging
7.3

 
13.5

 

 

 

 

 
7.3

 
13.5

U.S.
54.7

 
53.3

 
15.8

 
18.5

 
1.5

 
3.5

 
72.0

 
75.3

Horseshoe Canyon
16.5

 
13.2

 

 

 

 

 
16.5

 
13.2

Horn River
11.9

 
12.3

 

 

 

 

 
11.9

 
12.3

Hedging
2.2

 
3.7

 

 

 

 

 
2.2

 
3.7

Canada
30.6

 
29.2

 

 

 

 

 
30.6

 
29.2

Consolidated production revenue
$
85.3

 
$
82.5

 
$
15.8

 
$
18.5

 
$
1.5

 
$
3.5

 
$
102.6

 
$
104.5

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
U.S. realized cash derivative gains (losses)
$
1.9

 
$
4.3

 
$
0.2

 
$
(0.2
)
 
$

 
$

 
$
2.1

 
$
4.1

Canada realized cash derivative gains
0.8

 
3.9

 

 

 

 

 
0.8

 
3.9

Consolidated realized cash derivative gains (losses)
2.7

 
8.2

 
0.2

 
(0.2
)
 

 

 
2.9

 
8.0

Consolidated production revenue and realized cash derivative gains (1)
$
88.0

 
$
90.7

 
$
16.0

 
$
18.3

 
$
1.5

 
$
3.5

 
$
105.5

 
$
112.5

(1) 
Realized cash derivative gains (losses) from derivatives not treated as hedges are included in net derivative gains (losses). Unrealized derivative gains (losses) 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.


33


Average Daily Production Volume:
 
Natural Gas
 
NGL
 
Oil
 
Equivalent Total
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(MMcfd)
 
(Bbld)
 
(Bbld)
 
(MMcfed)
Barnett Shale
128.4

 
124.8

 
5,913

 
6,873

 
102

 
142

 
164.5

 
166.9

Other U.S.
0.1

 
0.1

 

 
16

 
72

 
258

 
0.5

 
1.8

U.S.
128.5

 
124.9

 
5,913

 
6,889

 
174

 
400

 
165.0

 
168.7

Horseshoe Canyon
45.8

 
49.5

 
3

 
6

 

 

 
45.8

 
49.5

Horn River
34.8

 
55.7

 

 

 

 

 
34.8

 
55.7

Canada
80.6

 
105.2

 
3

 
6

 

 

 
80.6

 
105.2

Consolidated
209.1

 
230.1

 
5,916

 
6,895

 
174

 
400

 
245.6

 
273.9


Average Realized Price:
 
Natural Gas
 
NGL
 
Oil
 
Equivalent Total
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(per Mcf)
 
(per Bbl)
 
(per Bbl)
 
(per Mcfe)
Barnett Shale
$
4.02

 
$
3.47

 
$
29.06

 
$
29.02

 
$
91.82

 
$
99.84

 
$
4.24

 
$
3.88

Other U.S.
1.38

 
7.15

 

 
50.05

 
89.08

 
95.18

 
12.84

 
14.63

Hedging
0.62

 
1.17

 

 

 

 

 
0.48

 
0.87

U.S.
4.63

 
4.64

 
29.06

 
29.07

 
90.69

 
96.83

 
4.74

 
4.86

Horseshoe Canyon
$
3.93

 
$
2.90

 
$
66.35

 
$
34.46

 
$

 
$

 
$
3.93

 
$
2.90

Horn River
3.71

 
2.40

 

 

 

 

 
3.71

 
2.40

Hedging
0.29

 
0.38

 

 

 

 

 
0.29

 
0.38

Canada
$
4.12

 
$
3.01

 
$
66.35

 
$
42.46

 
$

 
$

 
$
4.13

 
$
3.02

Consolidated production revenue
$
4.44

 
$
3.90

 
$
29.07

 
$
29.08

 
$
90.69

 
$
96.83

 
$
4.54

 
$
4.15

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
U.S. realized cash derivative gains (losses)
$
0.16

 
$
0.38

 
$
0.31

 
$
(0.26
)
 
$

 
$

 
$
0.14

 
$
0.27

Canada realized cash derivative gains
0.11

 
0.40

 

 

 

 

 
0.11

 
0.40

Consolidated realized cash derivative gains (losses)
0.14

 
0.39

 
0.31

 
(0.26
)
 

 

 
0.13

 
0.32

Consolidated production revenue and realized cash derivative gains
$
4.58

 
$
4.29

 
$
29.38

 
$
28.82

 
$
90.69

 
$
96.83

 
$
4.67

 
$
4.47




34


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 2013 quarter
$
90,713

 
$
18,281

 
$
3,561

 
$
112,555

Volume variances
(5,980
)
 
(2,618
)
 
(2,009
)
 
(10,607
)
Hedge revenue variances
(7,669
)
 

 

 
(7,669
)
Realized cash derivative variance (1)
(5,465
)
 
331

 

 
(5,134
)
Price variances
16,448

 
(5
)
 
(98
)
 
16,345

Consolidated production revenue and realized cash derivative gains for the 2014 quarter
$
88,047

 
$
15,989

 
$
1,454

 
$
105,490

(1) 
This amount is also included in the production revenue and realized cash derivatives gains table above.
Our natural gas revenue, without the effects of realized cash derivative gains/losses or hedge revenue, increased for the 2014 quarter from the 2013 quarter primarily due to an increase in our realized price partially offset by lower volumes produced. As the realized prices have increased, our hedge revenue and realized cash derivative gain/loss have decreased for the 2014 quarter compared to the 2013 quarter as we have maintained a similar derivative position only having a portion of our derivative portfolio with higher fixed prices expire resulting in a lower weighted average fixed price for our natural gas derivative portfolio. The decrease in natural gas volumes is primarily due to a decrease in volumes in our Horn River Asset due to natural well decline. The natural well decline in the U.S. was replaced by new well production. Consolidated production revenue and realized cash derivative gains from NGL revenue for the 2014 quarter decreased from the 2013 quarter due to lower volumes as we began ethane rejection in September 2014 and natural well decline partially offset by an increase from the impact of our derivatives. The decrease in oil volumes is primarily due to the Synergy Transaction partially offset by new well production in the 2014 quarter.
Our production revenue for the 2014 quarter and 2013 quarter was higher by $9.5 million and $17.2 million, respectively, because of our hedging activities.


35


Sales of Purchased Natural Gas and Costs of Purchased Natural Gas
 
For the Three Months Ended
September 30,
 
2014
 
2013
 
 
 
 
 
(in thousands)
Sales of purchased natural gas
 
Purchases from Eni
$
15,583

 
$
14,405

Purchases from others
1,077

 
725

Total
16,660

 
15,130

Costs of purchased natural gas sold
 
 
 
Purchases from Eni
15,582

 
14,405

Purchases from others
1,017

 
709

Total
16,599

 
15,114

Net sales and purchases of natural gas
$
61

 
$
16

Net Derivative Gains (Losses)
The following table summarizes our net derivative gains and losses:
 
For the Three Months Ended
September 30,
 
2014
 
2013
 
 
 
 
 
(in thousands)
Unrealized mark-to-market changes in fair value of natural gas derivative gains (1)
$
39,854

 
$
24,385

Realized cash settlements of natural gas derivative gains
2,709

 
8,174

Unrealized mark-to-market changes in fair value of NGL derivative gains (1)
581

 
339

Realized cash settlements of NGL derivative gains (losses)
166

 
(165
)
Derivative gains, net
$
43,310

 
$
32,733

(1) 
Unrealized mark-to-market changes in fair value are subject to continuing market risk.
Other Revenue
 
For the Three Months Ended
September 30,
 
2014
 
2013
 
 
 
 
 
(in thousands)
Midstream revenue from third parties
 
Canada
$
486

 
$
496

Texas
427

 
211

Total
$
913

 
$
707



36


Operating Expense
Lease Operating
 
For the Three Months Ended September 30,
 
2014
 
2013
 
 
 
(in thousands, except per unit amounts)
 
 
 
Per
Mcfe
 
 
 
Per
Mcfe
Barnett Shale
 
 
 
 
 
 
 
Expense
$
9,193

 
$
0.61

 
$
10,351

 
$
0.67

Equity compensation expense
165

 
0.01

 
99

 
0.01

 
$
9,358

 
$
0.62

 
$
10,450

 
$
0.68

Other U.S.
 
 
 
 
 
 
 
Expense
$
309

 
$
6.63

 
$
889

 
$
5.46

Equity compensation expense
48

 
1.03

 
(23
)
 
(0.14
)
 
$
357

 
$
7.66

 
$
866

 
$
5.32

Total U.S.
 
 
 
 
 
 
 
Expense
$
9,502

 
$
0.63

 
$
11,240

 
$
0.72

Equity compensation expense
213

 
0.01

 
76

 
0.00

 
$
9,715

 
$
0.64

 
$
11,316

 
$
0.72

Horseshoe Canyon
 
 
 
 
 
 
 
Expense
$
6,096

 
$
1.45

 
$
6,408

 
$
1.41

Equity compensation expense
415

 
0.10

 
84

 
0.02

 
$
6,511

 
$
1.55

 
$
6,492

 
$
1.43

Horn River
 
 
 
 
 
 
 
Expense
$
950

 
$
0.30

 
$
783

 
$
0.15

Equity compensation expense

 

 

 

 
$
950

 
$
0.30

 
$
783

 
$
0.15

Total Canada
 
 
 
 
 
 
 
Expense
$
7,046

 
$
0.95

 
$
7,191

 
$
0.74

Equity compensation expense
415

 
0.06

 
84

 
0.01

 
$
7,461

 
$
1.01

 
$
7,275

 
$
0.75

Total Company
 
 
 
 
 
 
 
Expense
$
16,548

 
$
0.73

 
$
18,431

 
$
0.73

Equity compensation expense
628

 
0.03

 
160

 
0.01

 
$
17,176

 
$
0.76

 
$
18,591

 
$
0.74


Lease operating expense for the 2014 quarter in the Barnett Shale decreased in total and on a unit basis primarily due to a non-cash inventory impairment in the 2013 quarter. In Other U.S., the decrease in total lease operating expense is primarily due to the Synergy and Southwestern Transactions. The Horn River increase on a unit basis is primarily due to fixed charges being distributed over lower volume compared to the 2013 quarter.


37


Gathering, Processing and Transportation
 
For the Three Months Ended September 30,
 
2014
 
2013
 
 
 
(in thousands, except per unit amounts)
 
 
 
Per
Mcfe
 
 
 
Per
Mcfe
Barnett Shale
$
23,910

 
$
1.58

 
$
23,398

 
$
1.52

Other U.S.
1

 
0.01

 
2

 
0.01

Total U.S.
23,911

 
1.58

 
23,400

 
1.51

Horseshoe Canyon
784

 
0.19

 
718

 
0.16

Horn River
10,112

 
3.16

 
11,449

 
2.23

Total Canada
10,896

 
1.47

 
12,167

 
1.26

Total
$
34,807

 
$
1.54

 
$
35,567

 
$
1.41


Barnett GPT increased on a unit basis for the 2014 quarter compared to the 2013 quarter primarily as a result of our production area mix as production has increased in the dry gas areas of our northern Barnett Asset. Horn River GPT increased on a unit basis for the 2014 quarter compared to the 2013 quarter primarily as a result of higher unused firm capacity. Canadian GPT includes payments made for unused firm capacity of $4.3 million and $1.7 million for the 2014 quarter and the 2013 quarter, respectively.
Production and Ad Valorem Taxes
 
For the Three Months Ended September 30,
 
2014
 
2013
 
 
 
(in thousands, except per unit amounts)
 
 
 
Per
Mcfe
 
 
 
Per
Mcfe
Production taxes
 
 
 
 
 
 
 
Barnett Shale
$
1,110

 
$
0.07

 
$
848

 
$
0.06

Other U.S.
251

 
5.40

 
172

 
1.05

Total U.S.
1,361

 
0.09

 
1,020

 
0.07

Horseshoe Canyon
26

 
0.01

 
(66
)
 
(0.01
)
Horn River

 

 

 

Total Canada
26

 
0.00

 
(66
)
 
(0.01
)
Total production taxes
1,387

 
0.06

 
954

 
0.04

Ad valorem taxes
 
 
 
 
 
 
 
Barnett Shale
$
1,746

 
$
0.12

 
$
2,645

 
$
0.17

Other U.S.
9

 
0.20

 
178

 
1.09

Total U.S.
1,755

 
0.12

 
2,823

 
0.18

Horseshoe Canyon
732

 
0.17

 
948

 
0.21

Horn River
193

 
0.06

 
(47
)
 
(0.01
)
Total Canada
925

 
0.12

 
901

 
0.09

Total ad valorem taxes
2,680

 
0.12

 
3,724

 
0.15

Total
$
4,067

 
$
0.18

 
$
4,678

 
$
0.19

Ad valorem taxes in our Barnett Shale Asset decreased primarily due to lower assessed values.


38


Depletion, Depreciation and Accretion
 
For the Three Months Ended September 30,
 
2014
 
2013
 
 
 
(in thousands, except per unit amounts)
 
 
 
Per
Mcfe
 
 
 
Per
Mcfe
Depletion
 
 
 
 
 
 
 
U.S.
$
7,654

 
$
0.50

 
$
7,880

 
$
0.51

Canada
1,080

 
0.15

 
1,058

 
0.11

Total depletion
8,734

 
0.39

 
8,938

 
0.35

Depreciation of other fixed assets
 
 
 
 
 
 
 
U.S.
$
1,554

 
$
0.10

 
$
1,802

 
$
0.12

Canada
2,262

 
0.30

 
2,377

 
0.25

Total depreciation
3,816

 
0.17

 
4,179

 
0.17

Accretion
1,419

 
0.06

 
1,273

 
0.05

Total
$
13,969

 
$
0.62

 
$
14,390

 
$
0.57

The Canadian depletion rate increased for the 2014 quarter, when compared to the 2013 quarter, primarily due to increased depletable asset base.
Impairment Expense
In the 2014 quarter, we recognized a non-cash impairment of $0.1 million related to midstream assets in our West Texas Asset.
General and Administrative
 
For the Three Months Ended September 30,
 
2014
 
2013
 
 
 
(in thousands, except per unit amounts)
 
 
 
Per
Mcfe
 
 
 
Per
Mcfe
Expense
$
6,484

 
$
0.29

 
$
7,299

 
$
0.29

Strategic transaction costs
1,885

 
0.08

 
823

 
0.03

Equity compensation
2,941

 
0.13

 
2,349

 
0.09

Total
$
11,310

 
$
0.50

 
$
10,471

 
$
0.41

The increase in equity compensation, when compared to the 2013 quarter, is primarily due to annual employee long-term incentive grants for 2014 being issued in the 2014 quarter and includes vesting for retirement eligible and imminently retirement eligible individuals. Strategic transaction costs relating to asset marketing and retaining a Strategic Alternatives Officer have increased for the 2014 quarter as activity has increased compared to the 2013 quarter.
Tokyo Gas Transaction Gain
In the 2013 quarter, we revised our Tokyo Gas Transaction gain, which resulted in an increase of $8.0 million. 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 the 2014 quarter the Canadian foreign currency exchange rate resulted in a recognized loss of $2.8 million compared to the 2013 quarter, which included a recognized gain of $0.2 million.


39


Fortune Creek Accretion
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. The decrease in Fortune Creek accretion is primarily due to a contribution made to Fortune Creek in March 2014, which reduced the partnership liability and related accretion expense.
Interest Expense
 
For the Three Months Ended
September 30,
 
2014
 
2013
 
 
 
 
 
(in thousands)
Interest costs on debt outstanding
$
38,736

 
$
39,443

Add:
 
 
 
Fees paid on letters of credit outstanding
89

 
71

Net expense paid on debt refinancing

 
(28
)
Non-cash interest (1)
2,601

 
1,870

Total interest costs incurred
41,426

 
41,356

Less:
 
 
 
Interest capitalized
(1,527
)
 
(2,001
)
Interest expense
$
39,899

 
$
39,355


(1) 
Represents amortization of deferred financing costs and original issue discount net of interest swap settlement amortization.
Income Taxes
The effective tax rates for the three months ended September 30, 2014 and 2013 are as follows:
 
For the Three Months Ended
September 30,
 
2014
 
2013
 
 
 
 
 
(in thousands)
Income tax (benefit) expense - U.S.
$
(4,873
)
 
$
4,755

Effective tax rate - U.S.
(48.0
)%
 
41.0
%
Income tax (benefit) expense - Canada
$
(66
)
 
$
1,211

Effective tax rate - Canada
(1.0
)%
 
25.0
%
Income tax (benefit) expense - total
$
(4,939
)
 
$
5,966

Effective tax rate - total
(26.2
)%
 
36.1
%
Income tax expense for the 2014 quarter included decreases in the U.S. and Canadian valuation allowances of $12.3 million and $5.4 million, respectively. Deferred income tax recognized for the 2014 and 2013 quarters is a result of hedge gains previously deferred in AOCI being realized during the quarter and the net tax impact being recognized and a $7.6 million refund being filed in the U.S. in September 2014.


40



RESULTS OF OPERATIONS
Nine Months Ended September 30, 2014 and 2013
The following discussion compares the results of operations for the nine months ended September 30, 2014 and 2013, or the 2014 period and 2013 period, respectively. “Other U.S.” refers to the combined amounts for our Niobrara Asset, West Texas Asset and Southern Alberta Basin Asset. The impacts of the Southwestern and Synergy Transactions were immaterial for further disaggregation.
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. Combining these items mirrors our view of the derivatives' usefulness, provides more comparability and is consistent with how management views and evaluates operating results.
Production Revenue and Realized Cash Gains (Losses) on Derivatives by Operating Area:
 
Natural Gas
 
NGL
 
Oil
 
Total
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(in millions)
Barnett Shale
$
148.0

 
$
141.8

 
$
51.1

 
$
59.6

 
$
3.7

 
$
4.9

 
$
202.8

 
$
206.3

Other U.S.

 
0.1

 

 
0.3

 
1.2

 
8.7

 
1.2

 
9.1

Hedging
22.1

 
43.2

 

 

 

 

 
22.1

 
43.2

U.S.
170.1

 
185.1

 
51.1

 
59.9

 
4.9

 
13.6

 
226.1

 
258.6

Horseshoe Canyon
53.5

 
43.1

 

 
0.1

 

 

 
53.5

 
43.2

Horn River
46.1

 
46.8

 

 

 

 

 
46.1

 
46.8

Hedging
6.5

 
9.7

 

 

 

 

 
6.5

 
9.7

Canada
106.1

 
99.6

 

 
0.1

 

 

 
106.1

 
99.7

Consolidated production revenue
$
276.2

 
$
284.7

 
$
51.1

 
$
60.0

 
$
4.9

 
$
13.6

 
$
332.2

 
$
358.3

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
U.S. realized cash derivative gains (losses)
$
(11.8
)
 
$
5.8

 
$
(2.3
)
 
$
(0.2
)
 
$

 
$

 
$
(14.1
)
 
$
5.6

Canada realized cash derivative gains (losses)
(0.7
)
 
8.5

 

 

 

 

 
(0.7
)
 
8.5

Consolidated realized cash derivative gains (losses)
(12.5
)
 
14.3

 
(2.3
)
 
(0.2
)
 

 

 
(14.8
)
 
14.1

Consolidated production revenue and realized cash derivative gains (losses) (1)
$
263.7

 
$
299.0

 
$
48.8

 
$
59.8

 
$
4.9

 
$
13.6

 
$
317.4

 
$
372.4

(1) 
Realized cash derivative gains (losses) from derivatives not treated as hedges are included in net derivative losses. Unrealized derivative gains (losses) 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.


41


Average Daily Production Volume:
 
Natural Gas
 
NGL
 
Oil
 
Equivalent Total
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(MMcfd)
 
(Bbld)
 
(Bbld)
 
(MMcfed)
Barnett Shale
123.4

 
145.9

 
6,195

 
7,852

 
141

 
193

 
161.4

 
194.2

Other U.S.

 
0.1

 

 
20

 
49

 
363

 
0.3

 
2.4

U.S.
123.4

 
146.0

 
6,195

 
7,872

 
190

 
556

 
161.7

 
196.6

Horseshoe Canyon
46.7

 
49.9

 
5

 
6

 

 

 
46.8

 
49.9

Horn River
40.5

 
59.4

 

 

 

 

 
40.5

 
59.3

Canada
87.2

 
109.3

 
5

 
6

 

 

 
87.3

 
109.2

Consolidated
210.6

 
255.3

 
6,200

 
7,878

 
190

 
556

 
249.0

 
305.8


Average Realized Price:
 
Natural Gas
 
NGL
 
Oil
 
Equivalent Total
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(per Mcf)
 
(per Bbl)
 
(per Bbl)
 
(per Mcfe)
Barnett Shale
$
4.39

 
$
3.56

 
$
30.24

 
$
27.78

 
$
94.98

 
$
92.38

 
$
4.61

 
$
3.90

Other U.S.

 
4.72

 

 
51.00

 
89.53

 
87.43

 
12.04

 
13.08

Hedging
0.66

 
1.08

 

 

 

 

 
0.50

 
0.80

U.S.
$
5.05

 
$
4.64

 
$
30.24

 
$
27.84

 
$
93.58

 
$
89.15

 
$
5.12

 
$
4.82

Horseshoe Canyon
$
4.19

 
$
3.16

 
$
37.39

 
$
55.62

 
$

 
$

 
$
4.19

 
$
3.17

Horn River
4.18

 
2.89

 

 

 

 

 
4.18

 
2.89

Hedging
0.27

 
0.32

 

 

 

 

 
0.27

 
0.32

Canada
$
4.46

 
$
3.34

 
$
37.39

 
$
55.62

 
$

 
$

 
$
4.46

 
$
3.34

Consolidated production revenue
$
4.80

 
$
4.09

 
$
30.25

 
$
27.87

 
$
93.58

 
$
89.15

 
$
4.89

 
$
4.29

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
U.S. realized cash derivative gains (losses)
$
(0.35
)
 
$
0.15

 
$
(1.33
)
 
$
(0.08
)
 
$

 
$

 
$
(0.32
)
 
$
0.10

Canada realized cash derivative gains (losses)
(0.03
)
 
0.29

 

 

 

 

 
(0.03
)
 
0.29

Consolidated realized cash derivative gains (losses)
$
(0.22
)
 
$
0.21

 
$
(1.33
)
 
$
(0.08
)
 
$

 
$

 
$
(0.22
)
 
$
0.17

Consolidated production revenue and realized cash derivative gains (losses)
$
4.58

 
$
4.30

 
$
28.92

 
$
27.79

 
$
93.58

 
$
89.15

 
$
4.67

 
$
4.46




42


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 2013 period
$
299,111

 
$
59,763

 
$
13,536

 
$
372,410

Volume variances
(40,633
)
 
(12,765
)
 
(8,907
)
 
(62,305
)
Hedge revenue variances
(24,237
)
 

 

 
(24,237
)
Realized cash derivative variance (1)
(26,772
)
 
(2,088
)
 

 
(28,860
)
Price variances
56,188

 
4,029

 
231

 
60,448

Consolidated production revenue and realized cash derivative gains for the 2014 period
$
263,657

 
$
48,939

 
$
4,860

 
$
317,456

(1) 
This amount is also included in the production revenue and realized cash derivatives gains table above.
Our natural gas revenue, without the effects of realized cash derivative gains/losses or hedge revenue, increased for the 2014 period from the 2013 period primarily due to an increase in our realized price. Lower volumes produced primarily attributable to the Tokyo Gas Transaction and natural declines in our Barnett and Horn River Assets partially offset by new well production reduced natural gas revenue. As the realized prices have increased, our hedge revenue and realized cash derivative gain/loss have decreased for the 2014 period compared to the 2013 period as we have maintained a similar derivative position by only having a portion of our derivative portfolio with higher fixed prices expire, resulting in a lower weighted average fixed price for our natural gas derivative portfolio. Consolidated production revenue and realized cash derivative gains from NGL revenue for the 2014 period decreased from the 2013 period due to lower volumes produced primarily attributable to the Tokyo Gas Transaction and declining well production and the 2014 period including an NGL derivative loss that the 2013 period did not, partially offset by an increase in realized prices. Our oil revenue decreased for the 2014 period from the 2013 period due to lower volumes resulting from the Synergy Transaction.
Our production revenue for the 2014 period and 2013 period was higher by $28.6 million and $52.9 million, respectively, because of our hedging activities.
Sales of Purchased Natural Gas and Costs of Purchased Natural Gas
 
For the Nine Months Ended
September 30,
 
2014
 
2013
 
 
 
 
 
(in thousands)
Sales of purchased natural gas
 
Purchases from Eni
$
50,627

 
$
48,208

Purchases from others
2,774

 
2,165

Total
53,401

 
50,373

Costs of purchased natural gas sold
 
 
 
Purchases from Eni
50,604

 
48,207

Purchases from others
2,701

 
2,104

Total
53,305

 
50,311

Net sales and purchases of natural gas
$
96

 
$
62




43


Net Derivative Gains (Losses)
The following table summarizes our net derivative gains and losses:
 
For the Nine Months Ended
September 30,
 
2014
 
2013
 
 
 
 
 
(in thousands)
Unrealized mark-to-market changes in fair value of natural gas derivative gains (losses) (1)
$
(1,948
)
 
$
21,734

Realized cash settlements of natural gas derivative gains (losses)
(12,478
)
 
14,294

Unrealized mark-to-market changes in fair value of NGL derivative gains (1)
1,599

 
339

Realized cash settlements of NGL derivative losses
(2,253
)
 
(165
)
Derivative gains (losses), net
(15,080
)
 
36,202

(1) 
Unrealized mark-to-market changes in fair value are subject to continuing market risk.
Other Revenue
 
For the Nine Months Ended
September 30,
 
2014
 
2013
 
 
 
 
 
(in thousands)
Midstream revenue from third parties
 
Canada
$
1,585

 
$
1,810

Texas
1,223

 
652

Total
$
2,808

 
$
2,462




44


Operating Expense
Lease Operating
 
For the Nine Months Ended September 30,
 
2014
 
2013
 
 
 
(in thousands, except per unit amounts)
 
 
 
Per
Mcfe
 
 
 
Per
Mcfe
Barnett Shale
 
 
 
 
 
 
 
Expense
$
29,638

 
$
0.67

 
$
33,785

 
$
0.64

Equity compensation expense
359

 
0.01

 
568

 
0.01

 
$
29,997

 
$
0.68

 
$
34,353

 
$
0.65

Other U.S.
 
 
 
 
 
 
 
Expense
$
1,339

 
$
15.17

 
$
3,911

 
$
5.96

Equity compensation expense
145

 
1.64

 
174

 
0.27

 
$
1,484

 
$
16.81

 
$
4,085

 
$
6.23

Total U.S.
 
 
 
 
 
 
 
Expense
$
30,977

 
$
0.70

 
$
37,696

 
$
0.70

Equity compensation expense
504

 
0.01

 
742

 
0.01

 
$
31,481

 
$
0.71

 
$
38,438

 
$
0.71

Horseshoe Canyon
 
 
 
 
 
 
 
Expense
$
19,456

 
$
1.52

 
$
21,793

 
$
1.60

Equity compensation expense
1,092

 
0.09

 
197

 
0.01

 
$
20,548

 
$
1.61

 
$
21,990

 
$
1.61

Horn River
 
 
 
 
 
 
 
Expense
$
2,593

 
$
0.23

 
$
3,271

 
$
0.20

Equity compensation expense

 

 

 

 
$
2,593

 
$
0.23

 
$
3,271

 
$
0.20

Total Canada
 
 
 
 
 
 
 
Expense
$
22,049

 
$
0.93

 
$
25,064

 
$
0.84

Equity compensation expense
1,092

 
0.05

 
197

 
0.01

 
$
23,141

 
$
0.98

 
$
25,261

 
$
0.85

Total Company
 
 
 
 
 
 
 
Expense
$
53,026

 
$
0.78

 
$
62,760

 
$
0.75

Equity compensation expense
1,596

 
0.02

 
939

 
0.01

 
$
54,622

 
$
0.80

 
$
63,699

 
$
0.76

Lease operating expense for the 2014 period in the Barnett Shale decreased in total primarily due to the Tokyo Gas Transaction and a non-cash inventory impairment in the 2013 period. Other U.S. decreased in total for the 2014 period primarily due to the Southwestern and Synergy Transactions and on a unit basis the 2014 period increased as fixed lease operating charges were distributed over lower volume compared to the 2013 period. In Canada, the decrease in lease operating expense in total for the 2014 period compared to the 2013 period is primarily due to a stronger U.S. dollar. Included in 2014 period lease operating expense above is a fully discretionary employee bonus of $0.3 million in the Barnett Shale and $1.0 million in the Horseshoe Canyon.


45


Gathering, Processing and Transportation
 
For the Nine Months Ended September 30,
 
2014
 
2013
 
 
 
(in thousands, except per unit amounts)
 
 
 
Per Mcfe
 
 
 
Per Mcfe
Barnett Shale
$
68,947

 
$
1.57

 
$
80,136

 
$
1.51

Other U.S.
1

 
0.02

 
8

 
0.01

Total U.S.
68,948

 
1.56

 
80,144

 
1.49

Horseshoe Canyon
2,531

 
0.20

 
2,335

 
0.17

Horn River
31,032

 
2.81

 
29,585

 
1.82

Total Canada
33,563

 
1.41

 
31,920

 
1.07

Total
$
102,511

 
$
1.51

 
$
112,064

 
$
1.34

U.S. GPT on a gross basis decreased primarily due to lower volumes in our Barnett Shale Asset attributable to the Tokyo Gas Transaction. On a unit basis, the 2014 period was higher primarily due to higher electric rates and new production being in an area with higher GPT rates. Our Horn River Asset GPT increased in total and on a unit basis for the 2014 period as compared to the 2013 period as a result of increased gathering rates as the 2013 period included discounted rates prior to the contractual increase in volumes. Our Horn River Asset GPT includes payments made for unused firm capacity of $11.0 million and $4.6 million for the 2014 period and the 2013 period, respectively.
Production and Ad Valorem Taxes
 
For the Nine Months Ended September 30,
 
2014
 
2013
 
 
 
(in thousands, except per unit amounts)
 
 
 
Per
Mcfe
 
 
 
Per
Mcfe
Production taxes
 
 
 
 
 
 
 
Barnett Shale
$
3,365

 
$
0.08

 
$
2,807

 
$
0.05

Other U.S.
260

 
2.95

 
650

 
0.99

Total U.S.
3,625

 
0.08

 
3,457

 
0.06

Horseshoe Canyon
128

 
0.01

 
(30
)
 
0.00

Horn River

 

 

 

Total Canada
128

 
0.01

 
(30
)
 
0.00

Total production taxes
3,753

 
0.06

 
3,427

 
0.04

Ad valorem taxes
 
 
 
 
 
 
 
Barnett Shale
$
5,938

 
$
0.13

 
$
9,102

 
$
0.17

Other U.S.
110

 
1.25

 
444

 
0.68

Total U.S.
6,048

 
0.14

 
9,546

 
0.18

Horseshoe Canyon
2,182

 
0.17

 
2,006

 
0.15

Horn River
574

 
0.05

 
483

 
0.03

Total Canada
2,756

 
0.12

 
2,489

 
0.08

Total ad valorem taxes
8,804

 
0.13

 
12,035

 
0.14

Total
$
12,557

 
$
0.18

 
$
15,462

 
$
0.19

Ad valorem taxes in our Barnett Shale Asset decreased primarily due to lower assessed values and lower property ownership due to the Tokyo Gas Transaction.


46


Depletion, Depreciation and Accretion
 
For the Nine Months Ended September 30,
 
2014
 
2013
 
 
 
(in thousands, except per unit amounts)
 
 
 
Per
Mcfe
 
 
 
Per
Mcfe
Depletion
 
 
 
 
 
 
 
U.S.
$
22,263

 
$
0.50

 
$
27,580

 
$
0.51

Canada
4,582

 
0.19

 
3,350

 
0.11

Total depletion
26,845

 
0.39

 
30,930

 
0.37

Depreciation of other fixed assets
 
 
 
 
 
 
 
U.S.
$
4,769

 
0.11

 
$
5,833

 
0.11

Canada
6,759

 
0.28

 
7,231

 
0.24

Total depreciation
11,528

 
0.17

 
13,064

 
0.16

Accretion
4,211

 
0.06

 
3,917

 
0.05

Total
$
42,584

 
$
0.62

 
$
47,911

 
$
0.58

U.S. depletion for the 2014 period, when compared to the 2013 period, reflects a decrease in production. Canadian depletion increased for the 2014 period, when compared to the 2013 period, due to an increase in the current year depletion rate primarily due to increased depletable asset base partially offset by a decrease in production.
Impairment Expense
In the 2014 period, we recognized a non-cash impairment of $0.1 million related to midstream assets in our West Texas Asset.
General and Administrative
 
For the Nine Months Ended September 30,
 
2014
 
2013
 
 
 
(in thousands, except per unit amounts)
 
 
 
Per
Mcfe
 
 
 
Per
Mcfe
Expense
$
24,722

 
$
0.36

 
$
28,198

 
$
0.33

Strategic transaction costs
5,843

 
0.09

 
2,693

 
0.03

Equity compensation
7,550

 
0.11

 
12,618

 
0.15

Total
$
38,115

 
$
0.56

 
$
43,509

 
$
0.51

The decrease in general and administrative expense is primarily due to reduced headcount compared to the 2013 period partially offset by an increase in employee incentive compensation. Included in the 2014 period expense above is a fully discretionary employee bonus of $3.0 million. Strategic transaction costs relating to asset marketing and retaining a Strategic Alternatives Officer have increased for the 2014 period as activity has increased compared to the 2013 period. The decrease in equity compensation is primarily due to the 2013 period including a $3.6 million correction for assumptions on forfeitures and vesting for retirement eligible and imminently retirement eligible individuals.
Tokyo Gas Transaction Gain
In April 2013, we recognized a $341.1 million gain upon closing of the Tokyo Gas Transaction, which was subsequently adjusted in the fourth quarter of 2013 to $339.3 million. 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.


47


Other Income (Expense)
In June 2013, we recognized an expense of $12.8 million in connection with the termination of the PEA with NGTL. In the 2014 period, the Canadian foreign currency exchange rate resulted in a recognized loss of $2.0 million compared to the 2013 period, which included a recognized loss of $2.3 million. In June 2014, we recognized expense of $3.0 million for an adjustment to the accounting of the Eni Transaction.
Fortune Creek Accretion
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. The decrease in Fortune Creek accretion is primarily due to a contribution made to Fortune Creek in the 2014 period, which reduced the partnership liability and related accretion expense.
Interest Expense
 
For the Nine Months Ended
September 30,
 
2014
 
2013
 
 
 
 
 
(in thousands)
Interest costs on debt outstanding
$
116,787

 
$
125,589

Add:
 
 
 
Fees paid on letters of credit outstanding
235

 
174

Net expense paid on debt refinancing
682

 
67,010

Non-cash interest (1)
8,441

 
23,643

Total interest costs incurred
126,145

 
216,416

Less:
 
 
 
Interest capitalized
(4,218
)
 
(5,881
)
Interest expense
$
121,927

 
$
210,535


(1) 
Represents amortization of deferred financing costs and original issue discount net of interest swap settlement amortization. The 2013 and 2014 periods include $18.9 million and $0.6 million, respectively, relating to the early redemption of our Senior Notes due 2015 and Senior Notes due 2016 and the reduction of the Combined Credit Agreements.
Interest costs incurred for the 2014 period were lower when compared to the 2013 period primarily because of the refinancing of our debt securities in June 2013, which reduced our weighted average interest rate. The refinancing costs included the premium and fees associated with the tender offer and consent solicitation for the Senior Notes due 2015 and Senior Notes due 2016 and the consent solicitation for the Senior Notes due 2019.
Income Taxes
The effective tax rates for the nine months ended September 30, 2014 and 2013 are as follows:
 
For the Nine Months Ended
September 30,
 
2014
 
2013
 
 
 
 
 
(in thousands)
Income tax (benefit) expense - U.S.
$
213

 
$
15,921

Effective tax rate - U.S.
(0.3
)%
 
7.3
 %
Income tax (benefit) expense - Canada
$
868

 
$
2,142

Effective tax rate - Canada
24.8
 %
 
(28.6
)%
Income tax (benefit) expense - total
$
1,081

 
$
18,063

Effective tax rate - total
(1.5
)%
 
8.5
 %



48


Income tax expense for the 2014 period included an increase in the U.S. valuation allowance of $21.1 million and a reduction in the Canadian valuation allowance of $2.2 million. Deferred income tax recognized for the 2014 and 2013 periods is a result of hedge gains previously deferred in AOCI being realized during the period and the net tax impact being recognized and a $7.6 million refund being filed in the U.S. in September 2014.
Quicksilver Resources Inc. and its Restricted Subsidiaries
Information about Quicksilver and our restricted and unrestricted subsidiaries is included in Note 11 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 September 30, 2014. 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 multiple factors discussed further in the Liquidity and Borrowing Capacity section below.
For the remainder of 2014 through 2021, swaps economically hedge a portion of our natural gas revenue. The following summarizes future production hedged with commodity derivatives as of September 30, 2014.
Production
Year
 
Daily Production
Volume
 
 
Natural Gas
 
Natural Gas Basis Swaps
 
 
MMcfd
 
MMcfd
 2014 (1)
 
170
 
40
2015
 
150
 
2016-2021
 
40
 
(1) 
Our natural gas basis swaps economically hedge the AECO basis adjustment from NYMEX.


49


The following summarizes our cash flow activity for the 2014 period and 2013 period:
 
For the Nine Months Ended September 30,
 
2014
 
2013
 
 
 
 
 
(in thousands)
Net cash used in operating activities
$
(4,983
)
 
$
(81,103
)
Net cash provided by investing activities
152,220

 
300,515

Net cash provided by (used in) financing activities
9,769

 
(170,495
)

Operating Cash Flows
Net cash used in operating activities for the 2014 period decreased from the 2013 period primarily due to reduced interest payments as the 2013 period included payments related to our early redemption of senior notes and positive changes in working capital.
Net cash used in operating activities for the 2014 period includes hedge cash settlements of $7.4 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 2014 period and 2013 period were as follows:
 
United States
 
Canada
 
Consolidated
 
 
 
 
 
 
 
(in thousands)
For the Nine Months Ended September 30, 2014
 
 
 
 
 
Exploration and development
$
85,814

 
$
20,924

 
$
106,738

Midstream
83

 

 
83

Administrative
310

 
453

 
763

Total
$
86,207

 
$
21,377

 
$
107,584

For the Nine Months Ended September 30, 2013
 
 
 
 
 
Exploration and development
$
50,459

 
$
9,972

 
$
60,431

Midstream
26

 
2,343

 
2,369

Administrative
473

 
9,182

 
9,655

Total
$
50,958

 
$
21,497

 
$
72,455

Costs incurred reflect the activity of the 2014 capital program, while capital expenditures shown in the condensed consolidated statement of cash flows also reflect the related changes in working capital. Changes in working capital are driven by changes in accounts payable from prior year activities.
All of our Marketable Securities matured during the 2014 period and were held as cash or cash equivalents.
Financing Cash Flows
Net borrowings increased in the 2014 period compared to the 2013 period as we utilized our Combined Credit Agreements. Distributions of Fortune Creek partnership funds of $37.1 million and $8.1 million were paid in the 2014 period and the 2013 period, respectively, to our partner based on our partner's preferential distribution rights.
Liquidity and Borrowing Capacity
At September 30, 2014, the Combined Credit Agreements’ global borrowing base was $325 million and the global letter of credit capacity was $280 million. At September 30, 2014, there was $6.7 million available under the Combined Credit Agreements and we held cash or cash equivalents of $248.3 million.


50


In November 2014, the Combined Credit Agreements' global borrowing base was reaffirmed at $325 million and the Combined Credit Agreements were amended to eliminate the requirement to meet the minimum interest coverage ratio covenant beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015. A minimum EBITDAX covenant was added beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015 that requires the following minimum EBITDAX levels:
 
Minimum EBITDAX Covenant
 
(in millions)
Three months ending December 31, 2014
$
30.0

Six months ending March 31, 2015
59.0

Nine months ending June 30, 2015
87.25

Twelve months ending September 30, 2015
120.5

Twelve months ending December 31, 2015
122.0

The minimum required interest coverage ratio for the first and second quarter of 2016 continues to be 1.50 and 2.00, respectively.
Additionally, the Combined Credit Agreements were amended changing certain definitions that impact the calculation of EBITDAX in both the November 2014 amendment and the April 2014 amendment and we permanently reduced the aggregate maximum credit amounts under the Combined Credit Agreements from $1.75 billion to $650 million in April 2014 and to $450 million in November 2014.
Our ability to borrow under our Combined Credit Agreements depends on our global borrowing base, which is scheduled to be redetermined twice each year. A reduction to the global borrowing base during the spring or autumn redetermination, or upon a special redetermination requested by our administrative agent under the Combined Credit Agreements, would adversely impact our liquidity and ability to meet our future obligations. Our derivatives contribute to the global borrowing base. Most of our derivative positions expire at year-end 2015. The expiration of these derivatives will adversely affect our global borrowing base, and absent an improvement in natural gas and NGL prices, significant deleveraging from a strategic transaction, reduced interest costs on our debt through refinancing, significant cost savings through avoidance or deferral, or operational efficiencies, we expect to need additional sources of liquidity, including additional debt or equity financing or proceeds from asset sales, at the beginning of 2016 assuming no material debt maturities prior to that date. In addition, we are exploring potential transactions involving any and all of our assets, including our Horn River Asset. If successful, a sale of our Horn River Asset could eliminate or defray our need to make or fund significant capital investments in the Horn River Asset but would also reduce our global borrowing base if not offset by the effects of any related debt reduction. A sale of our other assets could also enhance liquidity if the sale proceeds exceed the associated decrease to the global borrowing base, if any.
While we believe we will be able to comply with the financial covenants contained in our Combined Credit Agreements through the end of 2015, we do not expect to exceed the required levels by a significant margin, particularly the minimum EBITDAX covenant under our Combined Credit Agreements. Accordingly, even a modest decline in prices for natural gas and NGLs, our failure to achieve anticipated cost savings through avoidance or deferral or operational efficiencies, our failure to execute certain asset purchases or the inaccuracy in any material respect of any of the other assumptions underlying our forecast could cause us to fall short of the financial covenants contained in the Combined Credit Agreements. Absent an improvement in natural gas and NGL prices, significant deleveraging from a strategic transaction, reduced interest costs on our debt through refinancing, significant cost savings through avoidance or deferral, or operational efficiencies, we do not expect to comply with our interest coverage ratio covenant under our Combined Credit Agreements beginning in the first quarter of 2016 and expect that we would need to seek additional covenant relief under the Combined Credit Agreements at that time. In addition, we have benefitted from our natural gas derivatives, which have resulted in cash proceeds being greater than the prevailing price for natural gas. Without the benefit of these derivatives, most of which expire at year-end 2015, our earnings would be reduced and our cash interest expense would exceed our resulting EBITDAX. Any inability to comply with the financial covenants contained in our Combined Credit Agreements, unless waived or amended by the requisite lenders, could materially and adversely affect our


51


liquidity by precluding further borrowings under our credit facilities and by accelerating the maturity of our debt. We may be unsuccessful in obtaining the necessary waivers or amendments.
In addition, we have significant fixed and springing debt maturities in 2015 and 2016, including the Combined Credit Agreements, the Second Lien Term Loan, the Second Lien Notes and the Senior Subordinated Notes. We do not expect to be able to satisfy these obligations with our cash on hand, committed financing or cash flow from operations. In order to satisfy these obligations we will need to obtain additional debt or equity financing or to sell assets, which we may not be able to do on satisfactory terms, or at all. We are limited in our ability to incur additional debt by the indenture restrictions as more fully described in Note 5. We may also seek to address the springing maturities by extending the maturity of or refinancing all or a portion of our Senior Subordinated Notes. If we are unsuccessful in extending or refinancing, we may not be able to satisfy such obligations when they mature. Our ability to address these springing maturities prior to filing our financial statements for the year ended December 31, 2014, is a key factor in our auditor’s going concern assessment. Our Combined Credit Agreements and Second Lien Term Loan require us to provide financial statements within 120 days of year-end with an accompanying audit report without a going concern paragraph. If we fail to accomplish this it would be an event of default under these agreements.
Our indentures require us to reinvest or repay senior debt with net cash proceeds from sales of certain assets within one year. If certain capital spending and senior debt repayment thresholds are not met, we would be required to make an offer to repay our notes. We expect to meet the remaining obligation in our indentures through our planned capital program and investments during 2014.
In order to be able to incur debt, make restricted payments, designate unrestricted subsidiaries or effect mergers or consolidations, we must meet an incurrence test under the indentures applicable to our debt, which test requires EBITDA to exceed interest expense by 2.25 times. At September 30, 2014 and throughout the three months ended September 30, 2014, 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 the ability to refinance existing debt. Not meeting this ratio does not represent an event of default under our debt. We are unable to predict when or if our EBITDA will exceed interest expense by 2.25 times.
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.
Although we have been in discussions on a potential transaction involving our Horn River Asset and have proposed transaction terms, we reached no agreement on any material terms, including structure or valuation. Accordingly, we developed a formalized marketing process for this asset, along with any and all of our assets. We may be unsuccessful in consummating a transaction involving our Horn River Asset or any of our other assets being marketed on acceptable terms, or at all.
We anticipate that our remaining 2014 capital program, contractual commitments and recurring operating needs will be funded by cash flow from operations or cash and other short-term securities on hand and supplemented by proceeds from asset sales, although we could also borrow under the Combined Credit Agreements. If our capital resources are insufficient to fund our needs, we will need to reduce our capital expenditures, implement further cost reductions, successfully renegotiate our contractual commitments or seek other financing alternatives. We may be unable to realize further cost reductions, renegotiate our contractual commitments or obtain financing needed in the future on acceptable terms, or at all. If we limit or defer our 2014 capital expenditure plan or are unsuccessful in developing reserves and adding production through that capital program or our cost-cutting efforts are too overreaching, we could adversely affect our ability to meet our forecasted results and the value of our oil and natural gas properties.
In March 2014, we agreed with KKR to an amendment to extend the ending date of the minimum gross capital expenditures requirement, of which C$120 million remains, to the earlier of June 30, 2016 or 12 months following consummation of a transaction involving a material portion of our Horn River Asset and to broaden allowable spending to include acquisitions of producing properties that utilize partnership assets. As part of the amendment, we contributed C$28 million to Fortune Creek which was subsequently distributed to KKR and was applied against the gathering agreement requirement. The effect of this contribution was to reduce the balance of


52


the partnership liability and to reduce the gathering rate that burdens our Horn River Asset production by C$0.13 per Mcf until at least 2016. We do not expect to be able to satisfy these capital expenditure requirements with our cash on hand, committed financing or cash flow from operations and will need to obtain additional debt or equity financing or sell assets, which we may not be able to do on satisfactory terms, or at all.
Depending upon conditions in the capital markets and other factors, we will, from time to time, consider the issuance of debt or equity securities or other possible capital markets transactions, the proceeds of which could be used to refinance current indebtedness, reduce debt or for other corporate purposes. We will also consider, from time to time, additional acquisitions of, and 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. Because we have not met our incurrence test, we are unable to fund acquisitions with debt other than under our Combined Credit Agreements. Our ability to access the debt and equity capital markets on economic terms is affected by general economic conditions, the domestic and global financial markets, our credit ratings assigned by independent credit rating agencies, our operational and financial performance, the value and performance of our equity and debt securities, prevailing commodity prices, and other macroeconomic factors outside of our control. In addition, we believe that access to the capital markets will be limited if we are unable to execute significant deleveraging transactions, due in large part to our high debt levels relative to cash flow.
We continue to explore options to refinance the Senior Subordinated Notes. The economics and interest rate of any offering will be subject to market conditions. It is likely any new debt instruments will result in a material increase to our interest expense, which would be partially offset by the recognition of the unamortized deferred gain of the terminated interest rate swaps related to our Senior Subordinated Notes.
We have retained Houlihan Lokey Capital, Inc., Deloitte Transactions and Business Analytics LLP and other advisors to assist us in one or more of the following exercises:
evaluation of options to address near-term debt maturities;
enhancement of our liquidity position;
evaluation of various strategic alternatives, including the acquisition or monetization of any and all assets or the Company; and
employee retention.
Financial Position
The following impacted our balance sheet as of September 30, 2014, as compared to our balance sheet as of December 31, 2013:
Cash, cash equivalents and marketable securities decreased $7.1 million as we used cash on hand to fund operations and capital expenditures and make a contribution to Fortune Creek, which was distributed to KKR based on their preferential rights, partially offset by net borrowings under the Combined Credit Agreements.
The valuation of our current and non-current derivative assets and liabilities was $36.2 million lower on a net basis, which was primarily due to settlements during the year without additional derivatives being added and an increase in the natural gas forward curve.
Our net property, plant and equipment balance decreased $48.3 million from December 31, 2013 to September 30, 2014. The Southwestern Transaction resulted in a decrease of $97.1 million. Additional decreases were due to DD&A incurred of $38.5 million and $19.7 million related to U.S.-Canadian exchange rate changes. Offsetting these decreases, we incurred capital costs of $107.6 million during 2014.
The $15.2 million decrease in accounts payable was due primarily to a reduction in accrued capital expenditures of $1.8 million and a decrease in trade payables of $13.4 million from December 31, 2013 as ad valorem tax invoices were paid in 2014.
Long-term debt increased $48.9 million primarily from net borrowings under the Combined Credit Agreements of $68.0 million and $4.3 million of amortized discounts, partially offset by early retirement of $18.7 million of our 2015 Senior Notes and 2016 Senior Notes, recognition of $1.5


53


million of interest rate swaps and changes to the U.S.-Canadian exchange rate resulting in a decrease of $3.2 million.
Partnership liability decreased $31.5 million primarily due to a $25.4 million contribution to Fortune Creek and periodic distribution of $11.7 million, both of which were distributed to KKR based on their preferential rights, and foreign exchange rate changes of $6.0 million, partially offset by accretion of $11.6 million.
Contractual Obligations and Commercial Commitments
There have been no significant changes to our contractual obligations and commitments as reported in our 2013 Annual Report on Form 10-K.
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 2013 Annual Report on Form 10-K. These critical estimates, for which no significant changes, other than those discussed in the results of operations, occurred during the nine months ended September 30, 2014, 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.
OFF-BALANCE SHEET ARRANGEMENTS
We have no off-balance sheet arrangements within the meaning of Item 303(a)(4) of SEC Regulation S-K.
RECENTLY ISSUED ACCOUNTING STANDARDS
In May 2014, the FASB issued accounting guidance, “Revenue from Contracts with Customers,” requiring an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The updated standard will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective and permits the use of either the retrospective or cumulative effect transition method. Early adoption is not permitted. The updated standard becomes effective for us in the first quarter of 2017. We have not yet selected a transition method and we are currently evaluating the effect, if any, that the updated standard will have on our consolidated financial statements and related disclosures.
No other pronouncements materially affecting our financial statements have been issued since the filing of our 2013 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.


54


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 $28.6 million and $52.9 million for the 2014 period and 2013 period, respectively, and a loss was recognized in net derivative losses of $14.7 million for the 2014 period and a gain of $14.1 million for the 2013 period. Unrealized losses of $0.3 million and gains of $22.1 million were recognized for the 2014 period and 2013 period, respectively.
The following table details our open derivative positions at September 30, 2014:
Product
 
Type
 
Segment
 
Remaining Contract
Period
 
Volume
 
Price Per Mcf or Bbl
Gas
 
Swap
 
U.S.
 
Oct 2014 - Dec 2014
 
10 MMcfd
 
3.91
Gas
 
Swap
 
U.S.
 
Oct 2014 - Dec 2014
 
10 MMcfd
 
3.89
Gas
 
Swap
 
U.S.
 
Oct 2014 - Dec 2015
 
5 MMcfd
 
6.23
Gas
 
Swap
 
U.S.
 
Oct 2014 - Dec 2015
 
5 MMcfd
 
6.20
Gas
 
Swap
 
U.S.
 
Oct 2014 - Dec 2015
 
20 MMcfd
 
6.00
Gas
 
Swap
 
U.S.
 
Oct 2014 - Dec 2015
 
10 MMcfd
 
6.00
Gas
 
Swap
 
U.S.
 
Oct 2014 - Dec 2015
 
5 MMcfd
 
5.68
Gas
 
Swap
 
U.S.
 
Oct 2014 - Dec 2015
 
7.5 MMcfd
 
5.475
Gas
 
Swap
 
U.S.
 
Oct 2014 - Dec 2015
 
7.5 MMcfd
 
5.50
Gas
 
Swap
 
U.S.
 
Oct 2014 - Dec 2015
 
5 MMcfd
 
4.15
Gas
 
Swap
 
U.S.
 
Oct 2014 - Dec 2015
 
5 MMcfd
 
4.13
Gas
 
Swap
 
U.S.
 
Oct 2014 - Dec 2015
 
5 MMcfd
 
4.255
Gas
 
Swap
 
U.S.
 
Oct 2014 - Dec 2015
 
5 MMcfd
 
4.25
Gas
 
Swap
 
U.S.
 
Oct 2014 - Dec 2021
 
10 MMcfd
 
4.54
Gas
 
Swap
 
U.S.
 
Oct 2014 - Dec 2021
 
5 MMcfd
 
4.38
Gas
 
Swap
 
U.S.
 
Oct 2014 - Dec 2021
 
10 MMcfd
 
4.37
Gas
 
Swap
 
U.S.
 
Oct 2014 - Dec 2021
 
5 MMcfd
 
4.35
Gas
 
Swap
 
Canada
 
Oct 2014 - Dec 2015
 
10 MMcfd
 
6.42
Gas
 
Swap
 
Canada
 
Oct 2014 - Dec 2015
 
10 MMcfd
 
6.45
Gas
 
Swap
 
Canada
 
Oct 2014 - Dec 2015
 
10 MMcfd
 
4.04
Gas
 
Swap
 
Canada
 
Oct 2014 - Dec 2021
 
10 MMcfd
 
4.625
Gas Basis1
 
Swap
 
Canada
 
Oct 2014 - Dec 2014
 
5 MMcfd
 
(0.475)
Gas Basis1
 
Swap
 
Canada
 
Oct 2014 - Dec 2014
 
5 MMcfd
 
(0.475)
Gas Basis1
 
Swap
 
Canada
 
Oct 2014 - Dec 2014
 
10 MMcfd
 
(0.475)
Gas Basis1
 
Swap
 
Canada
 
Oct 2014 - Dec 2014
 
10 MMcfd
 
(0.47)
Gas Basis1
 
Swap
 
Canada
 
Oct 2014 - Dec 2014
 
10 MMcfd
 
(0.45)
1 Our gas basis swaps economically hedge the AECO basis adjustment at a discount from NYMEX.
These open derivative positions had a net fair value of $91.2 million as of September 30, 2014.
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. 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 and adjusted for counterparty credit risk.


55


Interest Rate Risk
Changes in interest rates affect the interest rate we pay on borrowings under the Combined Credit Agreements, Second Lien Term Loan and 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 2014 period and the 2013 period, we recognized $1.5 million and $11.5 million, respectively, of those deferred gains as a reduction of interest expense.
Should we be required to borrow under our Combined Credit Agreements and based on interest rates as of September 30, 2014, each $50 million in borrowings would result in additional annual interest payments of $2.0 million. If the current borrowing availability under our Combined Credit Agreements were to be fully utilized by year-end 2014 at interest rates as of September 30, 2014, we estimate that annual interest payments would increase by $0.3 million. If interest rates change by 1% on our September 30, 2014 variable debt balances of $276.0 million, our annual pre-tax income would decrease or increase by $2.8 million.
Our Second Lien Term Loan and 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 September 30, 2014, would not impact our applicable interest rate on this debt, as the floor would not be exceeded. A 1% decrease in the interest rate would not impact our applicable interest rate on this debt, as we have not exceeded the floor at September 30, 2014.
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 2014 period and the 2013 period resulted in losses of $2.0 million and $2.3 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 September 30, 2014, our disclosure controls and procedures were not effective, due to the outstanding remediation of the income tax material weakness identified at December 31, 2013, 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 2013 Annual Report on Form 10-K, two material weaknesses were identified related to the design and operating effectiveness of our controls. We identified a material weakness related to the accounting for significant, non-recurring transactions, particularly related to the accuracy of the inputs provided to accounting


56


to incorporate into the analysis of such transactions. This weakness caused several out of period adjustments principally between quarters in 2013 to be recognized in our financial statements though none of the adjustments were considered individually material. We remediated this material weakness as of June 30, 2014 by the design and operating effectiveness of additional controls regarding significant transactions.
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 the remediation 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 September 30, 2014, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.


57


PART II. OTHER INFORMATION

ITEM 1.   Legal Proceedings
In each of July 2011 and June 2012, we received a subpoena duces tecum from the SEC requesting certain documents. In July 2014, the SEC notified us that the staff has completed its investigation and does not intend to recommend an enforcement action by the SEC against us.
There have been no other material changes in the legal proceedings described in Part I, Item 3 included in our 2013 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 2013 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 September 30, 2014.
 
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)
July 2014
 

 
$

 

 

August 2014 (3)
 
436

 
$
1.80

 

 

September 2014
 
1,363

 
$
1.15

 

 

Total
 
1,799

 
$
1.31

 

 

(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.
(3) 
Excluded from this amount is 816 shares with an average price of $3.05 which were a correction to a previous month.
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.


58


ITEM 5. Entry into a Material Definitive Agreement
On November 7, 2014, Quicksilver Resources Inc. and Quicksilver Resources Canada Inc. (“Quicksilver Canada”) entered into an Omnibus Amendment to the Combined Credit Agreements, among Quicksilver, Quicksilver Canada, the U.S. lenders party thereto, the Canadian lenders party thereto, JPMorgan Chase Bank, N.A., as global administrative agent, and JPMorgan Chase Bank, N.A., Toronto Branch, as Canadian administrative agent (the “Amendment”). The Amendment amended the terms of the Combined Credit Agreements to, among other things:
Reaffirm the global borrowing base at $325 million;
Permanently reduce the aggregate maximum credit amount under the Combined Credit Agreements from $650 million to $450 million;
Eliminate the requirement to meet the minimum interest coverage ratio covenant beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015;
Add a minimum EBITDAX covenant beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015 that requires the following minimum EBITDAX levels:
 
Minimum EBITDAX Covenant
 
(in millions)
Three months ending December 31, 2014
$
30.0

Six months ending March 31, 2015
59.0

Nine months ending June 30, 2015
87.25

Twelve months ending September 30, 2015
120.5

Twelve months ending December 31, 2015
122.0

Change certain definitions that impact the calculation of EBITDAX.
The full text of the Amendment is attached as Exhibit 10.7 to this Quarterly Report on Form 10-Q.
Certain of the parties to the Amendment and their respective affiliates have, from time to time, performed, and may in the future perform, various financial, advisory, commercial banking and investment banking services for Quicksilver and Quicksilver’s affiliates in the ordinary course of business for fees and expenses.


59


ITEM 6.
Exhibits

 
 
 
 
Incorporated by Reference
 
Filed (†) or
Furnished (‡)
Herewith
(as indicated)
Exhibit
No.
 
Exhibit Description
 
Form
 
SEC
File No.
 
Exhibit
 
Filing
Date
 
10.1
 
Second Amendment to Gas Gathering Agreement, dated July 9, 2014, among Quicksilver Resources Inc., TG Barnett Resources LP and Cowtown Pipeline Partners L.P.
 
 
 
 
 
 
 
 
 
10.2
 
Third Amendment to Sixth Amended and Restated Gas Gathering and Processing Agreement, dated July 9, 2014, among Quicksilver Resources Inc., TG Barnett Resources LP, Cowtown Gas Processing Partners L.P. and Cowtown Pipeline Partners L.P.
 
 
 
 
 
 
 
 
 
10.3
 
Fourth Amendment to Sixth Amended and Restated Gas Gathering and Processing Agreement, dated July 9, 2014, among Quicksilver Resources Inc., TG Barnett Resources LP, Cowtown Pipeline Partners L.P. and Cowtown Gas Processing Partners L.P.
 
 
 
 
 
 
 
 
 
10.4
 
Third Amendment to Amended and Restated Gas Gathering Agreement, dated August 13, 2012, between Quicksilver Resources Inc. and Cowtown Pipeline Partners L.P.
 
 
 
 
 
 
 
 
 
10.5
 
Fourth Amendment to Amended and Restated Gas Gathering Agreement, dated July 9, 2014, among Quicksilver Resources Inc., TG Barnett Resources LP and Cowtown Pipeline Partners L.P.
 
 
 
 
 
 
 
 
 
10.6
 
Fifth Amendment to Amended and Restated Gas Gathering Agreement, dated July 9, 2014, among Quicksilver Resources Inc., TG Barnett Resources LP and Cowtown Pipeline Partners L.P.
 
 
 
 
 
 
 
 
 
10.7
 
Omnibus Amendment No. 8 to Combined Credit Agreements, dated as of November 7, 2014, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and lenders identified therein
 
 
 
 
 
 
 
 
 
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
 
 
 
 
 
 
 
 
 
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
 
 
 
 
 
 
 
 
 



60


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:
November 10, 2014
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)


61


EXHIBIT INDEX
 
 
 
 
 
Incorporated by Reference
 
Filed (†) or
Furnished (‡)
Herewith
(as indicated)
Exhibit
No.
 
Exhibit Description
 
Form
 
SEC
File No.
 
Exhibit
 
Filing
Date
 
10.1
 
Second Amendment to Gas Gathering Agreement, dated July 9, 2014, among Quicksilver Resources Inc., TG Barnett Resources LP and Cowtown Pipeline Partners L.P.
 
 
 
 
 
 
 
 
 
10.2
 
Third Amendment to Sixth Amended and Restated Gas Gathering and Processing Agreement, dated July 9, 2014, among Quicksilver Resources Inc., TG Barnett Resources LP, Cowtown Gas Processing Partners L.P. and Cowtown Pipeline Partners L.P.
 
 
 
 
 
 
 
 
 
10.3
 
Fourth Amendment to Sixth Amended and Restated Gas Gathering and Processing Agreement, dated July 9, 2014, among Quicksilver Resources Inc., TG Barnett Resources LP, Cowtown Pipeline Partners L.P. and Cowtown Gas Processing Partners L.P.
 
 
 
 
 
 
 
 
 
10.4
 
Third Amendment to Amended and Restated Gas Gathering Agreement, dated August 13, 2012, between Quicksilver Resources Inc. and Cowtown Pipeline Partners L.P.
 
 
 
 
 
 
 
 
 
10.5
 
Fourth Amendment to Amended and Restated Gas Gathering Agreement, dated July 9, 2014, among Quicksilver Resources Inc., TG Barnett Resources LP and Cowtown Pipeline Partners L.P.
 
 
 
 
 
 
 
 
 
10.6
 
Fifth Amendment to Amended and Restated Gas Gathering Agreement, dated July 9, 2014, among Quicksilver Resources Inc., TG Barnett Resources LP and Cowtown Pipeline Partners L.P.
 
 
 
 
 
 
 
 
 
10.7
 
Omnibus Amendment No. 8 to Combined Credit Agreements, dated as of November 7, 2014, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and lenders identified therein
 
 
 
 
 
 
 
 
 
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
 
 
 
 
 
 
 
 
 
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
 
 
 
 
 
 
 
 
 





62