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EXCEL - IDEA: XBRL DOCUMENT - QUICKSILVER RESOURCES INC | Financial_Report.xls |
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EX-31.1 - EX-31.1 - QUICKSILVER RESOURCES INC | d73189exv31w1.htm |
EX-31.2 - EX-31.2 - QUICKSILVER RESOURCES INC | d73189exv31w2.htm |
Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 2010
or
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from ________ to __________
Commission file number: 001-14837
Quicksilver Resources Inc.
(Exact name of registrant as specified in its charter)
Delaware | 75-2756163 | |
(State or other jurisdiction of | (I.R.S. Employer Identification No.) | |
incorporation or organization) | ||
777 West Rosedale, Fort Worth, Texas | 76104 | |
(Address of principal executive offices) | (Zip Code) |
(817) 665-5000
(Registrants telephone number, including area code)
(Registrants telephone number, including area code)
None
(Former name, former address and former fiscal year, if changed since last report)
(Former name, former address and former fiscal year, if changed since last report)
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
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 o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the
Exchange Act. (Check one):
Large accelerated filer þ | Accelerated filer o | Non-accelerated filer o | Smaller reporting company o | |||
(Do not check if a smaller reporting company) |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). Yes o No þ
Indicate the number of shares outstanding of each of the issuers classes of common
stock, as of the latest practicable date:
Title of Class | Outstanding as of July 30, 2010 | |
Common Stock, $0.01 par value | 170,355,422 |
Table of Contents
DEFINITIONS
As used in this quarterly report unless the context otherwise requires:
Bbl or Bbls means barrel or barrels
Bbld means barrel or barrels per day
Bcf means billion cubic feet
Canada means the division of Quicksilver encompassing oil and natural gas properties located in Canada
DD&A means Depletion, Depreciation and Accretion
LIBOR means London Interbank Offered Rate
MBbl or MBbls means thousand barrels
MBbld means thousand barrels per day
MMBbls means million barrels
MMBtu means million British Thermal Units, a measure of heating value approximately equal to 1 Mcf of natural gas
MMBtud means million Btu per day
Mcf means thousand cubic feet
Mcfe means Mcf natural gas equivalents calculated as one Bbl of oil or NGLs equaling six Mcf of natural gas
MMcf means million cubic feet
MMcfd means million cubic feet per day
MMcfe means MMcf of natural gas equivalents calculated as one Bbl of oil or NGLs equaling six Mcf of natural gas
MMcfed means MMcfe per day
NGL or NGLs means natural gas liquids
NYMEX means New York Mercantile Exchange
Oil includes crude oil and condensate
COMMONLY USED TERMS
Other commonly used terms and abbreviations include:
ABR means adjusted base rate
AOCI means accumulated other comprehensive income
Alliance Leasehold means the natural gas leasehold and royalty interests acquired on August 8,
2008 in northern Tarrant and southern Denton counties of Texas and developed thereafter
Alliance Midstream Assets means the natural gas gathering system and processing facility
purchased by KGS from Quicksilver in January 2010
BBEP means BreitBurn Energy Partners L.P.
Crestwood means Crestwood Midstream Partners, LP and its affiliates
Crestwood Transaction means the sale to Crestwood of all our interests in KGS, consisting of 100%
of the general partner units, including incentive distribution rights, all of our common and
subordinated units and the subordinated note due from KGS
Eni means either or both Eni Petroleum US LLC and Eni US Operating Co. Inc., which are
subsidiaries of Eni SpA
Eni Production means production attributable to Eni pursuant to the Eni Transaction
Eni Transaction means the June 19, 2009 conveyance of a 27.5% interest in our Alliance Leasehold
FASB means the Financial Accounting Standards Board, which promulgates accounting standards in
the U.S.
FASC means the FASB Accounting Standards Codification, which is the single source of
authoritative U.S. GAAP not promulgated by the SEC
GAAP means accounting principles generally accepted in the U.S.
Gas Purchase Commitment means the commitment pursuant to the Eni Transaction to purchase Eni
Production through December 2010
KGS means Quicksilver Gas Services LP, which is our publicly traded partnership, which trades
under the ticker symbol of KGS
KGS Credit Facility means the KGS senior secured revolving credit facility
KGS Secondary Offering means the public offering of 4,000,000 KGS common units on December 16,
2009 and the underwriters purchase of an additional 549,200 KGS common units in January 2010
Lake Arlington Project means our natural gas leasehold and royalty interests in Tarrant County
that we have developed and also includes an additional 25% working interest we purchased on
May 11, 2010
Mercury means Mercury Exploration Company, which is owned by members of the Darden family
2
Table of Contents
Michigan Sales Contract means the gas supply contract, which expired in March 2009 under which we
agreed to deliver 25 MMcfd at a floor price of $2.49 per Mcf
OCI means other comprehensive income
RSU means restricted stock unit
SEC means the U.S. Securities and Exchange Commission
Senior Secured Credit Facility means our U.S. senior secured revolving credit facility and our
Canadian senior secured revolving credit facility
3
QUICKSILVER RESOURCES INC.
INDEX TO FORM 10-Q
For the Period Ending June 30, 2010
INDEX TO FORM 10-Q
For the Period Ending June 30, 2010
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
Table of Contents
Forward-Looking Information
Certain statements contained in this report and other materials we file with the SEC, or in
other written or oral statements made or to be made by us, other than statements of historical
fact, are forward-looking statements as defined in the Private Securities Litigation Reform Act
of 1995. Forward-looking statements give our current expectations or forecasts of future events.
Words such as may, assume, forecast, position, predict, strategy, expect, intend,
plan, estimate, anticipate, believe, project, budget, potential, or continue, and
similar expressions are used to identify forward-looking statements. They can be affected by
assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking
statements can be guaranteed. Actual results may vary materially. You are cautioned not to place
undue reliance on any forward-looking statements. You should also understand that it is not
possible to predict or identify all such factors and should not consider the following list to be a
complete statement of all potential risks and uncertainties. Factors that could cause our actual
results to differ materially from the results contemplated by such forward-looking statements
include:
| changes in general economic conditions; | ||
| fluctuations in natural gas, NGL and crude oil prices; | ||
| failure or delays in achieving expected production from exploration and development projects; | ||
| uncertainties inherent in estimates of natural gas, NGL and crude oil reserves and predicting natural gas, NGL and crude oil reservoir performance; | ||
| effects of hedging natural gas, NGL and crude 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; | ||
| 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; | ||
| the effects of existing or future litigation; and | ||
| certain factors discussed elsewhere in this quarterly report. |
This list of factors is not exhaustive, and new factors may emerge or changes to these factors
may occur that would impact our business. Additional information regarding these and other factors
may be contained in our filings with the SEC, especially on Forms
10-K, 10-Q and 8-K. All such
risk factors are difficult to predict, and are subject to material uncertainties that may affect
actual results and may be beyond our control. The forward-looking statements included in this
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
Table of Contents
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
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
In thousands, except for per share data Unaudited
For the Three Months Ended | For the Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Revenue |
||||||||||||||||
Natural gas, NGL and oil |
$ | 211,687 | $ | 199,315 | $ | 413,250 | $ | 382,869 | ||||||||
Sales of purchased natural gas |
16,821 | 5,217 | 33,045 | 5,217 | ||||||||||||
Other |
62 | 1,509 | 4,433 | 3,887 | ||||||||||||
Total revenue |
228,570 | 206,041 | 450,728 | 391,973 | ||||||||||||
Operating expense |
||||||||||||||||
Oil and gas production expense |
38,202 | 31,703 | 74,191 | 63,874 | ||||||||||||
Production and ad valorem taxes |
8,889 | 7,441 | 17,372 | 11,807 | ||||||||||||
Costs of purchased natural gas |
3,756 | 8,582 | 37,063 | 8,582 | ||||||||||||
Other operating costs |
970 | 1,744 | 2,224 | 3,271 | ||||||||||||
Depletion, depreciation and accretion |
50,669 | 50,966 | 97,426 | 110,662 | ||||||||||||
General and administrative |
17,217 | 24,389 | 37,740 | 41,770 | ||||||||||||
Total expense |
119,703 | 124,825 | 266,016 | 239,966 | ||||||||||||
Impairment related to oil and gas properties |
- | (70,643 | ) | - | (967,126 | ) | ||||||||||
Operating income (loss) |
108,867 | 10,573 | 184,712 | (815,119 | ) | |||||||||||
Income from earnings of BBEP - net |
23,168 | 19,016 | 7,179 | 19,016 | ||||||||||||
Other income (expense) - net |
53,050 | (855 | ) | 53,393 | (94 | ) | ||||||||||
Interest expense |
(46,122 | ) | (68,081 | ) | (90,639 | ) | (108,282 | ) | ||||||||
Income (loss) before income taxes |
138,963 | (39,347 | ) | 154,645 | (904,479 | ) | ||||||||||
Income tax (expense) benefit |
(48,219 | ) | 18,897 | (53,301 | ) | 316,720 | ||||||||||
Net income (loss) |
90,744 | (20,450 | ) | 101,344 | (587,759 | ) | ||||||||||
Net income attributable to noncontrolling interests |
(3,941 | ) | (1,312 | ) | (6,353 | ) | (2,982 | ) | ||||||||
Net income (loss) attributable to Quicksilver |
$ | 86,803 | $ | (21,762 | ) | $ | 94,991 | $ | (590,741 | ) | ||||||
Other comprehensive income (loss) - net of income
tax |
||||||||||||||||
Reclassification adjustments related to
settlements of derivative contracts |
(46,089 | ) | (60,073 | ) | (72,358 | ) | (96,987 | ) | ||||||||
Net change in derivative fair value |
14,087 | 3,701 | 112,693 | 112,304 | ||||||||||||
Foreign currency translation adjustment |
(9,715 | ) | 14,007 | (2,755 | ) | 6,782 | ||||||||||
Comprehensive income (loss) |
$ | 45,086 | $ | (64,127 | ) | $ | 132,571 | $ | (568,642 | ) | ||||||
Earnings (loss) per common share - basic |
$ | 0.51 | $ | (0.13 | ) | $ | 0.56 | $ | (3.50 | ) | ||||||
Earnings (loss) per common share - diluted |
$ | 0.49 | $ | (0.13 | ) | $ | 0.54 | $ | (3.50 | ) | ||||||
Basic weighted average shares outstanding |
170,290 | 169,009 | 170,225 | 168,894 | ||||||||||||
Diluted weighted average shares outstanding |
180,872 | 169,009 | 180,855 | 168,894 |
The accompanying notes are an integral part of these condensed consolidated financial statements.
6
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QUICKSILVER RESOURCES INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
In thousands, except for share data Unaudited
CONDENSED CONSOLIDATED BALANCE SHEETS
In thousands, except for share data Unaudited
June 30, | December 31, | |||||||
2010 | 2009 | |||||||
ASSETS |
||||||||
Current assets |
||||||||
Cash and cash equivalents |
$ | 3,308 | $ | 1,785 | ||||
Accounts receivable - net of allowance for doubtful accounts |
42,595 | 65,253 | ||||||
Derivative assets at fair value |
138,871 | 97,957 | ||||||
Other current assets |
63,137 | 54,943 | ||||||
Total current assets |
247,911 | 219,938 | ||||||
Investment in BBEP |
92,956 | 112,763 | ||||||
Property, plant and equipment |
||||||||
Oil and gas properties, full cost method (including unevaluated costs of
$375,100 and $458,037, respectively) |
2,613,688 | 2,338,244 | ||||||
Other property and equipment |
769,214 | 747,696 | ||||||
Property, plant and equipment - net |
3,382,902 | 3,085,940 | ||||||
Derivative assets at fair value |
67,763 | 14,427 | ||||||
Deferred income taxes |
73,083 | 133,051 | ||||||
Other assets |
42,084 | 46,763 | ||||||
$ | 3,906,699 | $ | 3,612,882 | |||||
LIABILITIES AND EQUITY |
||||||||
Current liabilities |
||||||||
Accounts payable |
$ | 122,400 | $ | 157,986 | ||||
Accrued liabilities |
156,639 | 156,604 | ||||||
Derivative liabilities at fair value |
- | 395 | ||||||
Deferred income taxes |
54,888 | 51,675 | ||||||
Total current liabilities |
333,927 | 366,660 | ||||||
Long-term debt |
2,586,923 | 2,427,523 | ||||||
Asset retirement obligations |
61,634 | 59,268 | ||||||
Other liabilities |
30,396 | 20,691 | ||||||
Deferred income taxes |
49,037 | 41,918 | ||||||
Commitments and contingencies (Note 7) |
- | - | ||||||
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; 175,496,888
and 174,469,836 shares issued, respectively |
1,755 | 1,745 | ||||||
Paid in capital in excess of par value |
748,405 | 730,265 | ||||||
Treasury stock of 5,025,337 and 4,704,448 shares, respectively |
(41,167 | ) | (36,363 | ) | ||||
Accumulated other comprehensive income |
158,916 | 121,336 | ||||||
Retained deficit |
(85,994 | ) | (180,985 | ) | ||||
Quicksilver stockholders equity |
781,915 | 635,998 | ||||||
Noncontrolling interests |
62,867 | 60,824 | ||||||
Total equity |
844,782 | 696,822 | ||||||
$ | 3,906,699 | $ | 3,612,882 | |||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
7
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QUICKSILVER RESOURCES INC.
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
In thousands Unaudited
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
In thousands Unaudited
Quicksilver Resources Inc. Stockholders | ||||||||||||||||||||||||||||
Accumulated | ||||||||||||||||||||||||||||
Additional | Other | Retained | ||||||||||||||||||||||||||
Common | Paid-in | Treasury | Comprehensive | Earnings | Noncontrolling | |||||||||||||||||||||||
Stock | Capital | Stock | Income | (Deficit) | Interests | Total | ||||||||||||||||||||||
Balances at December 31, 2008 |
$ | 1,717 | $ | 656,958 | $ | (35,441 | ) | $ | 185,104 | $ | 376,488 | $ | 26,737 | $ | 1,211,563 | |||||||||||||
Net income (loss) |
- | - | - | - | (590,741 | ) | 2,982 | (587,759 | ) | |||||||||||||||||||
Hedge derivative contract settlements
reclassified into earnings from accumulated
other comprehensive income, net of
income tax of $45,138 |
- | - | - | (96,987 | ) | - | - | (96,987 | ) | |||||||||||||||||||
Net change in derivative fair value, net
of income tax of $53,212 |
- | - | - | 112,304 | - | - | 112,304 | |||||||||||||||||||||
Foreign currency translation adjustment |
- | - | - | 6,782 | - | - | 6,782 | |||||||||||||||||||||
Issuance and vesting of stock compensation |
22 | 10,389 | (627 | ) | - | - | 812 | 10,596 | ||||||||||||||||||||
Stock option exercises |
- | 80 | - | - | - | - | 80 | |||||||||||||||||||||
Distributions paid on KGS common units |
- | - | - | - | - | (4,896 | ) | (4,896 | ) | |||||||||||||||||||
Balances at June 30, 2009 |
$ | 1,739 | $ | 667,427 | $ | (36,068 | ) | $ | 207,203 | $ | (214,253 | ) | $ | 25,635 | $ | 651,683 | ||||||||||||
Balances at December 31, 2009 |
$ | 1,745 | $ | 730,265 | $ | (36,363 | ) | $ | 121,336 | $ | (180,985 | ) | $ | 60,824 | $ | 696,822 | ||||||||||||
Net income |
- | - | - | - | 94,991 | 6,353 | 101,344 | |||||||||||||||||||||
Hedge derivative contract settlements
reclassified into earnings from accumulated
other comprehensive income, net of
income tax of $38,226 |
- | - | - | (72,358 | ) | - | - | (72,358 | ) | |||||||||||||||||||
Net change in derivative fair value, net
of income tax of $56,906 |
- | - | - | 112,693 | - | - | 112,693 | |||||||||||||||||||||
Foreign currency translation adjustment |
- | - | - | (2,755 | ) | - | - | (2,755 | ) | |||||||||||||||||||
Issuance and vesting of stock compensation |
8 | 10,187 | (4,804 | ) | - | - | 190 | 5,581 | ||||||||||||||||||||
Stock option exercises |
2 | 1,207 | - | - | - | - | 1,209 | |||||||||||||||||||||
Issuance of KGS common units |
- | 6,746 | - | - | - | 4,308 | 11,054 | |||||||||||||||||||||
Distributions paid on KGS common units |
- | - | - | - | - | (8,808 | ) | (8,808 | ) | |||||||||||||||||||
Balances at June 30, 2010 |
$ | 1,755 | $ | 748,405 | $ | (41,167 | ) | $ | 158,916 | $ | (85,994 | ) | $ | 62,867 | $ | 844,782 | ||||||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
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QUICKSILVER RESOURCES INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
In thousands Unaudited
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
In thousands Unaudited
For the Six Months Ended | ||||||||
June 30, | ||||||||
2010 | 2009 | |||||||
Operating activities: |
||||||||
Net income (loss) |
$ | 101,344 | $ | (587,759 | ) | |||
Adjustments to reconcile net income (loss) to
net cash provided by operating activities: |
||||||||
Depletion, depreciation and accretion |
97,426 | 110,662 | ||||||
Impairment related to oil and gas properties |
- | 967,126 | ||||||
Deferred income tax expense (benefit) |
52,243 | (331,321 | ) | |||||
Stock-based compensation |
11,529 | 11,223 | ||||||
Non-cash (gain) loss from hedging and derivative activities |
(27,852 | ) | 5,544 | |||||
Non-cash interest expense |
10,178 | 35,848 | ||||||
Non-cash gain on sale of BBEP units |
(35,426 | ) | - | |||||
(Income) loss from BBEP in excess of cash distributions,
net of impairment |
826 | (7,915 | ) | |||||
Other |
(469 | ) | 420 | |||||
Changes in assets and liabilities |
||||||||
Accounts receivable |
22,858 | 89,580 | ||||||
Derivative assets at fair value |
18,682 | 54,896 | ||||||
Other assets |
(11,144 | ) | (4,266 | ) | ||||
Accounts payable |
(20,169 | ) | (25,864 | ) | ||||
Accrued and other liabilities |
26,481 | (7,833 | ) | |||||
Net cash provided by operating activities |
246,507 | 310,341 | ||||||
Investing activities: |
||||||||
Purchases of property, plant and equipment |
(356,402 | ) | (441,184 | ) | ||||
Proceeds from sales of property and equipment |
864 | 233,488 | ||||||
Net cash used for investing activities |
(355,538 | ) | (207,696 | ) | ||||
Financing activities: |
||||||||
Issuance of debt |
540,032 | 1,020,750 | ||||||
Repayments of debt |
(409,613 | ) | (1,144,031 | ) | ||||
Debt issuance costs paid |
(109 | ) | (22,802 | ) | ||||
Gas Purchase Commitment assumed |
- | 46,628 | ||||||
Gas Purchase Commitment repayments |
(16,592 | ) | - | |||||
Issuance of KGS common units - net of offering costs |
11,054 | - | ||||||
Distributions paid on KGS common units |
(8,808 | ) | (4,896 | ) | ||||
Proceeds from exercise of stock options |
1,209 | 80 | ||||||
Taxes paid by KGS for equity-based compensation vesting |
(1,144 | ) | (63 | ) | ||||
Purchase of treasury stock for stock-based compensation vesting |
(4,804 | ) | (627 | ) | ||||
Net cash provided by (used for) financing activities |
111,225 | (104,961 | ) | |||||
Effect of exchange rate changes in cash |
(671 | ) | 125 | |||||
Net increase (decrease) in cash and cash equivalents |
1,523 | (2,191 | ) | |||||
Cash and cash equivalents at beginning of period |
1,785 | 2,848 | ||||||
Cash and cash equivalents at end of period |
$ | 3,308 | $ | 657 | ||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
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QUICKSILVER RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS
Unaudited
NOTES TO CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS
Unaudited
1. ACCOUNTING POLICIES AND DISCLOSURES
The accompanying condensed consolidated interim financial statements have not been audited.
In managements opinion, the accompanying condensed consolidated interim financial statements
contain all adjustments necessary to fairly present our financial position as of June 30, 2010 and
our results of operations for the three and six months ended June 30, 2010 and 2009 and cash flows
for the six months ended June 30, 2010 and 2009. All such adjustments are of a normal recurring
nature. The results for interim periods are not necessarily indicative of annual results.
Preparing financial statements in conformity with GAAP requires management to make estimates
and assumptions that affect the reported amounts of certain assets and liabilities, the 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, but actual results could differ from our 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 2009
Annual Report on Form 10-K.
Recently Issued Accounting Standards
Accounting standards-setting organizations frequently issue new or revised accounting rules.
We regularly review all new pronouncements to determine their impact, if any, on our financial
statements. No pronouncements materially affecting our financial statements have been issued since
the filing of our 2009 Annual Report on Form 10-K.
2. DERIVATIVES AND FAIR VALUE MEASUREMENTS
The following table shows the level of inputs used in our fair value calculations of our
derivative instruments at June 30, 2010 and December 31, 2009:
Significant Other Observable | ||||||||
Inputs - Level 2 | ||||||||
June 30, | December 31, | |||||||
2010 | 2009 | |||||||
(in thousands) | ||||||||
Commodity contracts |
$ | 193,394 | $ | 107,881 | ||||
Interest rate contracts |
13,240 | 4,108 | ||||||
Gas Purchase Commitment |
(6,161 | ) | (6,625 | ) | ||||
Total |
$ | 200,473 | $ | 105,364 | ||||
The fair value of all derivative instruments included in these disclosures was estimated
using prices quoted in active 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.
Commodity Price Derivatives
As of June 30, 2010, we had price collars and fixed price swaps that hedge 200 MMcfd, 150
MMcfd and 90 MMcfd of our anticipated natural gas production for 2010, 2011 and 2012, respectively.
We also have fixed price swaps that hedge 30 MMcfd of our anticipated natural gas production for
2013 through 2015. A portion of our anticipated 2010 and 2011 NGL production has been hedged with
fixed price swaps that cover 10 MBbld and 8 MBbld, respectively.
The increase in carrying value of our commodity price derivatives since December 31, 2009
principally resulted from the overall decline in market prices for natural gas and NGLs relative to
the prices of our open derivative instruments. Additional derivatives entered into further increased the carrying value. Monthly settlements received
during 2010 have partially offset these increases.
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Interest Rate Derivatives
In February 2010, we executed the early settlement of the 2009 interest rate swaps that hedged
our senior notes due 2015 and our senior subordinated notes. We received cash of $18.0
million in the settlement, including $3.7 million for interest previously accrued and earned,
and recognized an adjustment of $14.3 million to the carrying value of the debt. In February 2010,
we entered into new interest swaps to hedge the same debt instruments. In May 2010, we executed an
early settlement of a portion of the 2010 interest rate swaps. We received cash of $6.8
million in the settlement, including $2.4 million for interest previously accrued and earned,
and recognized an additional adjustment of $4.4 million to the carrying value of the debt. These
two settlements, totaling $18.7 million, will be recognized as a reduction of interest expense over
the life of the associated underlying debt instruments currently scheduled as follows:
(In thousands) | ||||
2010 (1) |
$ | 2,263 | ||
2011 |
2,899 | |||
2012 |
3,142 | |||
2013 |
3,404 | |||
2014 |
3,689 | |||
2015 |
2,908 | |||
2016 |
377 | |||
$ | 18,682 | |||
(1) | Through June 30, 2010, we have recognized $0.9 million of the early settlements as a reduction of interest expense. |
As of June 30, 2010, our remaining interest swaps, entered into during February 2010, cover
$295 million of our senior notes due 2015 and $155 million of our senior subordinated notes. The
interest rate swaps convert the interest paid on those issues from a fixed to a floating rate
indexed to six-month LIBOR. The maturity dates and all other significant terms are the same as
those of the underlying debt. As a result, the remaining 2010 interest rate swaps qualify for
accounting treatment as fair value hedges. The value of the remaining 2010 interest rate swaps,
excluding the net interest accrual, amounted to a net asset of $13.2 million as of June 30, 2010.
The offsetting fair value adjustment to the debt hedged decreased the carrying value of the debt.
There was no ineffectiveness recorded in connection with the remaining 2010 interest rate swaps.
The average effective interest rates on the senior notes due 2015 and the senior subordinated
notes, including all interest earned from both the early settled and open interest rate swaps, were
approximately 5.52% and 4.25%, respectively, for the first half of 2010.
In July 2010, we executed the early settlement of our remaining 2010 interest rate swaps. We
received cash of $16.7 million, including $4.6 million for interest previously accrued and earned.
We will recognize the remaining $12.1 million as an adjustment to the carrying value of the debt
that will be recognized as a reduction of interest expense over the life of the associated
underlying debt instruments.
Gas Purchase Commitment
The Gas Purchase Commitment, which is effective through December 31, 2010, contains an
embedded derivative revalued for changes to estimated volumes and prices from June 19, 2009 to June
30, 2010. At June 30, 2010, we have estimated the remaining liability at $33.7 million, including
an embedded derivative liability for cumulative changes in estimates since inception of $6.2
million. The derivative reflects a 3.3 Bcf reduction of the total estimated volumes we expect to
purchase under the commitment offset by a decrease in market prices over the remaining commitment
period compared with our December 31, 2009 estimate. The following summarizes 2010 activity to the
Gas Purchase Commitment:
(In thousands) | ||||
Liability fair value at December 31, 2009 |
$ | 50,744 | ||
Decrease due to gas volumes purchased |
(16,592 | ) | ||
Embedded derivative increase (decrease) due to: |
||||
Price changes |
8,930 | |||
Volume changes |
(9,394 | ) | ||
Total increase (decrease) in embedded derivative |
(464 | ) | ||
Liability fair value at June 30, 2010 (1) |
$ | 33,688 | ||
(1) | The liability for the Gas Purchase Commitment was valued using estimated Eni production volumes through December 2010 and published future market prices and risk-adjusted interest rates as of June 30, 2010. |
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The estimated fair value of our derivatives at June 30, 2010 and December 31, 2009 were as
follows:
Asset Derivatives | Liability Derivatives | ||||||||||||||||
June 30, | December 31, | June 30, | December 31, | ||||||||||||||
2010 | 2009 | 2010 | 2009 | ||||||||||||||
(In thousands) | (In thousands) | ||||||||||||||||
Derivatives designated as hedges: |
|||||||||||||||||
Commodity contracts reported in: |
|||||||||||||||||
Current derivative assets |
$ | 137,473 | $ | 97,883 | $ | 1,107 | $ | 638 | |||||||||
Noncurrent derivative assets |
57,028 | 11,031 | - | - | |||||||||||||
Current derivative liabilities |
- | 243 | - | 638 | |||||||||||||
Interest rate contracts reported in: |
|||||||||||||||||
Current derivative assets |
2,505 | 712 | - | - | |||||||||||||
Noncurrent derivative assets |
10,735 | 3,396 | - | - | |||||||||||||
Total derivatives designated as hedges |
$ | 207,741 | $ | 113,265 | $ | 1,107 | $ | 1,276 | |||||||||
Derivatives not designated as hedges: |
|||||||||||||||||
Gas Purchase Commitment reported in accrued liabilities |
$ | - | $ | - | $ | 6,161 | $ | 6,625 | |||||||||
Total derivatives not designated as hedges |
$ | - | $ | - | $ | 6,161 | $ | 6,625 | |||||||||
Total derivatives |
$ | 207,741 | $ | 113,265 | $ | 7,268 | $ | 7,901 | |||||||||
The changes in the carrying value of our derivatives for the three and six months ended June
30, 2010 and 2009 are presented below:
For the Three Months Ended June 30, 2010 | ||||||||||||||||
Gas Purchase | Interest Rate | Commodity | ||||||||||||||
Commitment | Swaps | Hedges | Total | |||||||||||||
(In thousands) | ||||||||||||||||
Derivative fair value at March 31, 2010 |
$ | (23,263 | ) | $ | (5,030 | ) | $ | 230,718 | $ | 202,425 | ||||||
Net change in amounts receivable/payable |
- | 209 | 1,362 | 1,571 | ||||||||||||
Net settlements reported in revenue |
- | - | (57,076 | ) | (57,076 | ) | ||||||||||
Net settlements reported in interest expense |
- | (4,267 | ) | - | (4,267 | ) | ||||||||||
Cash settlements reported in long-term debt |
- | (4,422 | ) | - | (4,422 | ) | ||||||||||
Change in fair value of Gas Purchase Commitment |
||||||||||||||||
reported in costs of purchased gas |
17,102 | - | - | 17,102 | ||||||||||||
Change in fair value of effective interest swaps |
- | 26,750 | - | 26,750 | ||||||||||||
Ineffectiveness reported in other revenue |
- | - | (2,983 | ) | (2,983 | ) | ||||||||||
Unrealized gains reported in OCI |
- | - | 21,373 | 21,373 | ||||||||||||
Derivative fair value at June 30, 2010 |
$ | (6,161 | ) | $ | 13,240 | $ | 193,394 | $ | 200,473 | |||||||
For the Three Months Ended June 30, 2009 | ||||||||||||||||
Gas Purchase | Interest Rate | Commodity | ||||||||||||||
Commitment | Swaps | Hedges | Total | |||||||||||||
(In thousands) | ||||||||||||||||
Derivative fair value at March 31, 2009 |
$ | - | $ | - | $ | 342,323 | $ | 342,323 | ||||||||
Net change in amounts receivable/payable |
- | 768 | - | 768 | ||||||||||||
Net settlements reported in revenue |
- | - | (88,261 | ) | (88,261 | ) | ||||||||||
Change in fair value of Gas Purchase Commitment |
||||||||||||||||
reported in costs of purchased gas |
(3,818 | ) | - | - | (3,818 | ) | ||||||||||
Change in fair value of effective interest swaps |
- | (1,034 | ) | - | (1,034 | ) | ||||||||||
Ineffectiveness reported in other revenue |
- | - | (598 | ) | (598 | ) | ||||||||||
Unrealized gains reported in OCI |
- | - | 4,083 | 4,083 | ||||||||||||
Derivative fair value at June 30, 2009 |
$ | (3,818 | ) | $ | (266 | ) | $ | 257,547 | $ | 253,463 | ||||||
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For the Six Months Ended June 30, 2010 | ||||||||||||||||
Gas Purchase | Interest Rate | Commodity | ||||||||||||||
Commitment | Swaps | Hedges | Total | |||||||||||||
(In thousands) | ||||||||||||||||
Derivative fair value at December 31, 2009 |
$ | (6,625 | ) | $ | 4,108 | $ | 107,881 | $ | 105,364 | |||||||
Net change in amounts receivable/payable |
- | (4,788 | ) | (861 | ) | (5,649 | ) | |||||||||
Net settlements reported in revenue |
- | - | (81,633 | ) | (81,633 | ) | ||||||||||
Net settlements reported in interest expense |
- | (6,237 | ) | - | (6,237 | ) | ||||||||||
Cash settlements reported in long-term debt |
- | (18,682 | ) | - | (18,682 | ) | ||||||||||
Change in
fair value of Gas Purchase Commitment reported in costs of purchased gas |
464 | - | - | 464 | ||||||||||||
Change in fair value of effective interest swaps |
- | 38,839 | - | 38,839 | ||||||||||||
Ineffectiveness reported in other revenue |
- | - | (1,588 | ) | (1,588 | ) | ||||||||||
Cash settlement reported in OCI |
- | - | - | - | ||||||||||||
Unrealized gains reported in OCI |
- | - | 169,595 | 169,595 | ||||||||||||
Derivative fair value at June 30, 2010 |
$ | (6,161 | ) | $ | 13,240 | $ | 193,394 | $ | 200,473 | |||||||
For the Six Months Ended June 30, 2009 | ||||||||||||||||||||
Michigan | Gas Purchase | Interest Rate | Commodity | |||||||||||||||||
Contract | Commitment | Swaps | Hedges | Total | ||||||||||||||||
(In thousands) | ||||||||||||||||||||
Derivative fair value at December 31, 2008 |
$ | (12,901 | ) | $ | - | $ | - | $ | 290,719 | $ | 277,818 | |||||||||
Net change in amounts receivable/payable |
(3,518 | ) | - | 768 | - | (2,750 | ) | |||||||||||||
Net settlements |
16,479 | - | - | - | 16,479 | |||||||||||||||
Net settlements reported in revenue |
- | - | - | (142,125 | ) | (142,125 | ) | |||||||||||||
Change in
fair value of Gas Purchase Commitment reported in costs of purchased gas |
- | (3,818 | ) | - | - | (3,818 | ) | |||||||||||||
Change in fair value of effective interest swaps |
- | - | (1,034 | ) | - | (1,034 | ) | |||||||||||||
Ineffectiveness reported in other revenue |
(60 | ) | - | - | (1,666 | ) | (1,726 | ) | ||||||||||||
Cash settlement reported in OCI |
- | - | - | (54,896 | ) | (54,896 | ) | |||||||||||||
Unrealized gains reported in OCI |
- | - | - | 165,516 | 165,516 | |||||||||||||||
Derivative fair value at June 30, 2009 |
$ | - | $ | (3,818 | ) | $ | (266 | ) | $ | 257,548 | $ | 253,464 | ||||||||
Gains and losses from the effective portion of derivative assets and liabilities held in AOCI
expected to be reclassified into earnings over the next twelve months would result in a gain of
$89.4 million net of income taxes. An additional $17.4 million, net of income taxes, remains from
the early settlement of the 2010 natural gas collar settled in 2009 and will be reclassified from
AOCI into revenue during the remainder of 2010. Hedge derivative ineffectiveness resulted in
losses of $1.6 million and $1.7 million recorded in other revenue for the six months ended June 30,
2010 and 2009, respectively.
3. INVESTMENT IN BREITBURN ENERGY PARTNERS L.P.
We own approximately 17.7 million common units, or 33%, of BBEP, a publicly traded limited
partnership, whose price closed at $14.93 per unit at June 30, 2010. Note 4 contains additional
information regarding the use of 3.6 million BBEP common units as partial consideration in the
acquisition of oil and gas properties in May 2010.
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We account for our investment in BBEP units using the equity method, utilizing a one-quarter
lag from BBEPs publicly available information. Summarized estimated financial information for
BBEP is as follows:
For the Three Months Ended |
For the Six Months Ended |
|||||||||||||||
March 31, | March 31, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
(In thousands) | ||||||||||||||||
Revenues (1) |
$ | 133,166 | $ | 127,939 | $ | 171,429 | $ | 571,186 | ||||||||
Operating expenses |
69,277 | 74,243 | 142,549 | 240,039 | ||||||||||||
Operating income (loss) |
63,889 | 53,696 | 28,880 | 331,147 | ||||||||||||
Interest and other (2) |
5,835 | 6,871 | 11,694 | 32,470 | ||||||||||||
Income tax (benefit) expense |
144 | 468 | (1,030 | ) | 1,145 | |||||||||||
Noncontrolling interests |
71 | 7 | 90 | 20 | ||||||||||||
Net income attributable to BBEP |
$ | 57,839 | $ | 46,350 | $ | 18,126 | $ | 297,512 | ||||||||
(1) | The three months ended March 31, 2010 and 2009 include commodity derivative unrealized gains of $39.9 million and unrealized losses of $4.1 million, respectively. The six months ended March 31, 2010 and 2009 include commodity derivative unrealized losses of $14.8 million and unrealized gains $342.3 million, respectively. | |
(2) | The three months ended March 31, 2010 and 2009 include interest rate swap derivative unrealized gains of $0.7 million and $1.0 million, respectively. The six months ended March 31, 2010 and 2009 include interest rate swap derivative unrealized gains of $2.4 million and $11.1 million, respectively. |
As of | As of | |||||||
March 31, | December 31, | |||||||
2010 | 2009 | |||||||
(In thousands) | ||||||||
Current assets |
$ | 155,455 | $ | 142,441 | ||||
Property, plant and equipment |
1,728,086 | 1,741,089 | ||||||
Other assets |
98,523 | 87,499 | ||||||
Current liabilities |
88,691 | 91,890 | ||||||
Long-term debt |
523,000 | 559,000 | ||||||
Other non-current liabilities |
79,604 | 91,338 | ||||||
Total equity |
1,290,769 | 1,228,801 |
For the six months ended June 30, 2010, we recognized income of $7.2 million, or approximately
40%, of BBEPs income for the six months ended March 31, 2010. For the comparable 2009 period, we
recognized income of $121.1 million and impairment expense of $102.1 million.
Changes in the balance of our investment in BBEP for the six months ended June 30, 2010 were
as follows:
(In thousands, except unit data) | ||||
Balance at December 31, 2009 |
$ | 112,763 | ||
Equity income from BBEP |
7,179 | |||
Distributions from BBEP |
(8,005 | ) | ||
Conveyance of 3,619,901 BBEP units |
(18,981 | ) | ||
Balance at June 30, 2010 |
$ | 92,956 | ||
Note 7 contains additional information regarding the April 2010 settlement of our lawsuit
against BBEP and other parties.
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4. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consisted of the following:
June 30, | December 31, | |||||||
2010 | 2009 | |||||||
(In thousands) | ||||||||
Oil and gas properties |
||||||||
Subject to depletion |
$ | 4,376,233 | $ | 3,947,676 | ||||
Unevaluated costs |
375,100 | 458,037 | ||||||
Accumulated depletion |
(2,137,645 | ) | (2,067,469 | ) | ||||
Net oil and gas properties |
2,613,688 | 2,338,244 | ||||||
Other plant and equipment |
||||||||
Pipelines and processing facilities |
799,045 | 767,430 | ||||||
General properties |
72,035 | 68,698 | ||||||
Construction in progress |
23,533 | 17,693 | ||||||
Accumulated depreciation |
(125,399 | ) | (106,125 | ) | ||||
Net other property and equipment |
769,214 | 747,696 | ||||||
Property, plant and equipment, net of |
||||||||
accumulated depletion and depreciation |
$ | 3,382,902 | $ | 3,085,940 | ||||
Ceiling Test Analysis
Our U.S. and Canadian ceiling tests for the first and second quarters of 2010 resulted in no
impairment of our U.S. or Canadian oil and gas properties. The ceiling limitations were determined
using internally prepared proved reserve reports using the unweighted average of the preceding
12-month first-day-of-the-month prices for natural gas, NGL and oil.
In the first half of 2009, we recorded impairments of our U.S. and Canadian oil and gas
properties that totaled $786.9 million and $109.6 million, respectively. Lower period-end
benchmark prices for natural gas, oil and NGL prices at March 31, 2009 and June 30, 2009 were the
primary factor contributing to a reduction of the U.S. and Canadian ceiling limitations at March
31, 2009 and the Canadian ceiling limit at June 30, 2009.
For additional information regarding our property, plant and equipment and our 2009 full cost
ceiling impairments, see Note 10 to our consolidated financial statements in our 2009 Annual Report
on Form 10-K.
Lake Arlington Acquisition
On May 11, 2010, we completed the acquisition of an additional 25% working interest in our
company-operated Lake Arlington Project. We acquired the Lake Arlington assets, subject to
customary adjustments as provided in the purchase and agreement, for which we conveyed $62.0
million in cash and 3,619,901 BBEP common units we had previously owned with a market value of
$54.4 million to the seller on the date of closing. We recognized a gain of $35.4 million as other
income for the difference between our carrying value of $5.24 per BBEP unit and the fair value of
$15.03 per BBEP unit. We expect to finalize adjustments to the purchase price in the third quarter
of 2010.
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5. LONG-TERM DEBT
Long-term debt consisted of the following:
June 30, | December 31, | |||||||
2010 | 2009 | |||||||
(In thousands) | ||||||||
Senior Secured Credit Facility |
$ | 493,234 | $ | 467,569 | ||||
Senior notes due 2015, net of unamortized discount |
470,415 | 469,964 | ||||||
Senior notes due 2016, net of unamortized discount |
582,448 | 581,359 | ||||||
Senior notes due 2019, net of unamortized discount |
293,254 | 293,004 | ||||||
Senior subordinated notes due 2016 |
350,000 | 350,000 | ||||||
Convertible debentures, net of unamortized discount |
139,736 | 136,119 | ||||||
KGS credit agreement |
226,800 | 125,400 | ||||||
Total debt |
2,555,887 | 2,423,415 | ||||||
Unamortized deferred gain - terminated interest
rate swaps |
17,796 | - | ||||||
Fair value - interest rate swaps |
13,240 | 4,108 | ||||||
Long-term debt |
$ | 2,586,923 | $ | 2,427,523 | ||||
Senior Secured Credit Facility
The $1.0 billion borrowing base on our Senior Secured Credit Facility was re-affirmed in May
2010.
Convertible Debentures
The convertible debentures are contingently convertible into shares of Quicksilver common
stock at a rate of 65.4418 shares for each $1,000 debenture, subject to adjustment. In the event
of conversion, we have the option to deliver either Quicksilver common stock, cash, or any
combination thereof. Should all debentures be converted to Quicksilver common stock, an additional
9,816,270 shares would become outstanding; however, as of July 1, 2010, the debentures were not
convertible based on share prices for the quarter ended June 30, 2010.
At June 30, 2010 and December 31, 2009, the remaining unamortized discount on the debentures
was $10.3 million and $13.9 million, respectively, resulting in a carrying value of $139.7 million
and $136.1 million, respectively. The remaining discount will be accreted to face value through
October 2011. For the six months ended June 30, 2010 and 2009, interest expense on our convertible
debentures, recognized at an effective interest rate of 6.75%, was $5.0 million and $4.8 million,
respectively, including contractual interest of $1.4 million for each period.
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Summary of All Outstanding Debt
The following table summarizes significant aspects of our long-term debt:
Priority on Collateral and Structural Seniority (1) | Recourse only to | |||||||||||||||||||||||||||
Highest priority | Lowest priority | KGS assets(2) | ||||||||||||||||||||||||||
Equal priority | ||||||||||||||||||||||||||||
Senior Secured | 2015 | 2016 | 2019 | Senior | Convertible | KGS Credit | ||||||||||||||||||||||
Credit Facility | Senior Notes | Senior Notes | Senior Notes | Subordinated Notes | Debentures | Agreement | ||||||||||||||||||||||
Scheduled maturity date | February 9, 2012 | August 1, 2015 | January 1, 2016 | August 15, 2019 | April 1, 2016 | November 1, 2024 | August 10, 2012 | |||||||||||||||||||||
Interest rate at June 30, 2010 (3) |
3.44% | 8.25% | 11.75% | 9.125% | 7.125% | 1.875% | 3.49% | |||||||||||||||||||||
Base interest rate options (4)
|
LIBOR, ABR or
specified (5) |
N/A | N/A | N/A | N/A | N/A | LIBOR, ABR or
specified (6) |
|||||||||||||||||||||
Financial covenants (7)
|
- Minimum
current ratio of 1.0 |
N/A | N/A | N/A | N/A | N/A | - Maximum debt
to EBITDA ratio of 4.5 |
|||||||||||||||||||||
- Minimum
EBITDA to interest expense ratio of 2.5 |
- Minimum
EBITDA to interest expense ratio of 2.5 |
|||||||||||||||||||||||||||
Significant restrictive
|
- Incurrence of debt | - Incurrence of debt | - Incurrence of debt | - Incurrence of debt | - Incurrence of debt | N/A | - Incurrence of debt | |||||||||||||||||||||
covenants (7)
|
- Incurrence of liens | - Incurrence of liens | - Incurrence of liens | - Incurrence of liens | - Incurrence of liens | - Incurrence of liens | ||||||||||||||||||||||
- Payment of dividends | - Payment of dividends | - Payment of dividends | - Payment of dividends | - Payment of dividends | - Equity purchases | |||||||||||||||||||||||
- Equity purchases | - Equity purchases | - Equity purchases | - Equity purchases | - Equity purchases | - Asset sales | |||||||||||||||||||||||
- Asset sales | - Asset sales | - Asset sales | - Asset sales | - Asset sales | - Limitations on | |||||||||||||||||||||||
- Affiliate transactions | - Affiliate transactions | - Affiliate transactions | - Affiliate transactions | - Affiliate transactions | derivatives | |||||||||||||||||||||||
- Limitations on derivatives |
||||||||||||||||||||||||||||
Estimated fair value (8)
|
$493.2 million | $469.1 million | $666.0 million | $304.5 million | $321.1 million | $152.6 million | $226.8 million |
(1) | The Senior Secured Credit Facility is secured by a first perfected lien on substantially all our assets, excluding KGS assets. The other debt presented is based upon structural seniority and priority of payment. | |
(2) | The KGS Credit Facility is secured by a first perfected lien on substantially all KGS assets. | |
(3) | Represents the weighted average borrowing rate payable to lenders and excludes effects of interest rate derivatives. | |
(4) | Interest rate options include a base rate plus a spread. | |
(5) | Interest rate spreads on our Senior Secured Credit Facility include a floor to ABR of one-month LIBOR plus 1%, an ABR margin range of 1.125% to 2.125% and a Eurodollar and specified rate margin range of 2.00% to 3.00%. | |
(6) | Interest rate spreads on the KGS Credit Facility include a floor to ABR of one-month LIBOR plus 1%, an ABR margin range of 2.00% to 3.00% and a Eurodollar and specified rate margin range of 3.00% to 4.00%. | |
(7) | The covenant information presented in this table is qualified in all respects by reference to the full text of the covenants, terms and related definitions contained in the documents governing the various components of our debt. | |
(8) | The estimated fair value is determined based on market quotations on the balance sheet date for fixed rate obligations. We believe that debt with market-based interest rates has a fair value equal to its carrying value. |
For a more complete description of our long-term debt, see Note 13 to the consolidated
financial statements in our 2009 Annual Report on Form 10-K.
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6. ASSET RETIREMENT OBLIGATIONS
The following table provides information about our estimated asset retirement obligation
activity for the six months ended June 30, 2010.
(In thousands) | ||||
Beginning asset retirement obligations |
$ | 59,377 | ||
Incremental liability incurred |
1,422 | |||
Accretion expense |
1,513 | |||
Asset retirement costs incurred |
(352 | ) | ||
Gain on settlement of liability |
271 | |||
Currency translation adjustment |
(488 | ) | ||
Ending asset retirement obligations |
61,743 | |||
Less current portion |
(109 | ) | ||
Long-term asset retirement obligations |
$ | 61,634 | ||
7. COMMITMENTS AND CONTINGENCIES
As of June 30, 2010, our estimate of total Eni Production volumes purchased under the Gas
Purchase Commitment has been reduced 3.3 Bcf from our December 31, 2009 estimates and we determined
our remaining liability to be $33.7 million, including an embedded derivative liability of $6.2
million. Valuation of the liability was based on the most recent estimate of remaining 2010 Eni
Production volumes and natural gas prices at June 30, 2010.
In April 2010, we finalized a global settlement agreement with BBEP and all other parties to
our lawsuit whereby we received $18.0 million in cash, which was recognized as other income in the
second quarter of 2010. Pursuant to the agreement, we also retained full voting rights for our
units held in BBEP subject to the provisions of a limited standstill agreement and the ability to name two directors to the board of directors of BBEPs general
partner. If we were to own less than 10% of the outstanding BBEP common units, one of the
directors appointed by us would resign. BBEP also agreed to the reinstitution of quarterly
distributions and other governance accommodations.
In April 2010, Quicksilver entered into a lease of office space for a term of 12 years that is
scheduled to commence August 2010. Aggregate rentals over the life of the lease will total $29.8
million.
In June 2010, we structured a portion of the credit support for our surety bonds to include a
$15.0 million cash deposit reported in other current assets. We have the option to replace the cash deposit with a letter of credit
in the future. As of July 2010, our letters of credit were reduced to $25.2 million, which
includes $13.9 million issued in support of surety bonds.
There have been no other significant changes to our commitments and contingencies as reported
in Note 16 to the consolidated financial statements in our 2009 Annual Report on Form 10-K.
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8. NONCONTROLLING INTERESTS AND KGS
In January 2010, the underwriters purchased an additional 549,200 newly issued common units
for $11.0 million in connection with the KGS Secondary Offering. After the underwriters purchase
of additional units, our ownership of KGS was reduced to 61.0%. As a result of the transaction, we
recognized an increase of $6.7 million to Additional Paid-in Capital at that time. In December
2009, KGS offered units to the public as part of its funding strategy for its acquisition of the
Alliance Midstream Assets from us. The acquisition was completed in January 2010 for an initial
purchase price of $95.2 million, which was subsequently reduced to $84.4 million due to a purchase
price adjustment based on timing of construction costs of the system. KGS ownership, as of June
30, 2010, is summarized in the following table.
KGS Ownership | ||||||||||||
Quicksilver | Public | Total | ||||||||||
General partner interests |
1.6 | % | - | 1.6 | % | |||||||
Limited partner interests: |
||||||||||||
Common interests |
19.7 | % | 39.0 | % | 58.7 | % | ||||||
Subordinated interests |
39.7 | % | - | 39.7 | % | |||||||
Total interests |
61.0 | % | 39.0 | % | 100.0 | % | ||||||
The subordinated units will convert into an equal number of common units upon termination of
the subordination period, which would end in the fourth quarter of 2010, if KGS continues to earn
and pay at least $0.30 per quarter on each outstanding common and subordinated unit through that
time.
In July 2010, we agreed to sell all of our interests in KGS to Crestwood. The Crestwood
Transaction will include the sale of a 100% ownership interest in Quicksilver Gas Services Holdings
LLC, which owns (a) 5,696,752 common units of KGS, (b) 11,513,635 subordinated units of KGS
representing limited partner interests in KGS and (c) 100% of the outstanding membership interests
in Quicksilver Gas Services GP LLC including 469,949 general partner units in KGS and 100% of the
outstanding incentive distribution rights in KGS. Crestwood will also receive a $57 million
subordinated promissory note issued to us by KGS with a carrying value of $57 million at June 30,
2010. We expect to receive $701 million in cash at closing and up to $72 million in future
earn-out payments in 2012 and 2013. The Crestwood Transaction is expected to close in the fourth
quarter 2010, subject to customary closing conditions.
9. STOCK-BASED COMPENSATION
Note 19 to the consolidated financial statements in our 2009 Annual Report on Form 10-K
contains additional information about our equity-based compensation plans.
Quicksilver Stock Options
Options to purchase shares of common stock were granted in 2010 with an estimated fair value
of $8.9 million over the vesting period. We recognized expense of $3.5 million for all unvested
stock options in the first six months of 2010.
We estimated the fair value of stock options granted in 2010 on the dates of grant using the
Black-Scholes option-pricing model with the following assumptions:
Stock | ||||
Options | ||||
Issued | ||||
Weighted average grant date fair value
|
$ | 15.88 | ||
Weighted average grant date
|
Jan 4, 2010 | |||
Weighted average risk-free interest rate
|
3.00 | % | ||
Expected life (in years)
|
6.0 | |||
Weighted average volatility
|
66.76 | % | ||
Expected dividends
|
- |
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Table of Contents
The following table summarizes stock option activity during the six months ended June 30,
2010:
Wtd Avg | Wtd Avg | |||||||||||||||
Exercise | Remaining | Aggregate | ||||||||||||||
Shares | Price | Contractual Life | Intrinsic Value | |||||||||||||
(In years) | (In thousands) | |||||||||||||||
Outstanding at December 31, 2009 |
3,014,441 | $ | 8.97 | |||||||||||||
Granted |
901,887 | 15.88 | ||||||||||||||
Exercised |
(206,876 | ) | 5.85 | |||||||||||||
Cancelled |
(77,113 | ) | 8.70 | |||||||||||||
Outstanding at June 30, 2010 |
3,632,339 | $ | 10.87 | 8.6 | $ | 11,414 | ||||||||||
Exercisable at June 30, 2010 |
1,096,610 | $ | 11.49 | 8.0 | $ | 3,967 | ||||||||||
Vested at June 30, 2010 or expected to vest in the future |
3,548,324 | $ | 10.91 | |||||||||||||
Cash received from the exercise of stock options was $1.2 million for the six months ended
June 30, 2010 and the total fair value of those options exercised was $1.9 million.
Quicksilver Restricted Stock and Restricted Stock Units
The following table summarizes information regarding our restricted stock and RSU activity:
Payable in stock | Payable in cash | |||||||||||||||
Wtd Avg | Wtd Avg | |||||||||||||||
Grant Date | Grant Date | |||||||||||||||
Shares | Fair Value | Stock Units | Fair Value | |||||||||||||
Outstanding at December 31, 2009 |
2,722,875 | $ | 10.33 | 328,695 | $ | 6.22 | ||||||||||
Granted |
892,069 | 15.58 | 167,618 | 15.82 | ||||||||||||
Vested |
(1,084,214 | ) | 12.18 | (109,602 | ) | 6.22 | ||||||||||
Cancelled |
(68,737 | ) | 11.37 | (47,995 | ) | 10.22 | ||||||||||
Outstanding at June 30, 2010 |
2,461,993 | $ | 11.39 | 338,716 | $ | 10.40 | ||||||||||
At January 1, 2010, we had total unvested compensation cost of $15.1 million. During the
first six months of 2010, we recognized compensation expense for all unvested restricted stock and
RSUs of $6.7 million. Grants of restricted stock and stock-settled RSUs during the six months
ended June 30, 2010 had an estimated grant date fair value of $13.9 million, which will be
recognized as expense over the vesting period. Unrecognized compensation cost remaining at June
30, 2010 for restricted stock and stock-settled RSUs was $21.5 million, which will be recognized
through March 2013. The fair value of unvested RSUs settled in cash was $3.7 million at June 30,
2010. The total fair value of restricted shares and RSUs vested during the six months ended June
30, 2010 was $13.1 million.
Expense for all Quicksilver unvested stock-based compensation granted to our employees who
become KGS employees will be recognized upon closing of the Crestwood Transaction. Grant date fair
value for unvested stock options and restricted stock was $0.6 million and $0.4 million,
respectively.
20
Table of Contents
KGS Phantom Units
The following table summarizes information regarding KGS phantom unit activity:
Payable in units | Payable in cash | |||||||||||||||
Wtd Avg Grant Date |
Wtd Avg Grant Date |
|||||||||||||||
Units | Fair Value | Units | Fair Value | |||||||||||||
Outstanding at December 31, 2009 |
485,672 | $ | 12.75 | 33,240 | $ | 20.90 | ||||||||||
Granted |
211,600 | 21.15 | - | - | ||||||||||||
Vested |
(179,886 | ) | 13.74 | (1,956 | ) | 18.94 | ||||||||||
Cancelled |
(763 | ) | 17.52 | - | - | |||||||||||
Outstanding at June 30, 2010 |
516,623 | $ | 15.83 | 31,284 | $ | 20.82 | ||||||||||
At January 1, 2010, KGS had total unrecognized compensation cost of $2.9 million related to
unvested phantom unit awards. KGS recognized compensation expense of approximately $1.8 million
during the six months ended June 30, 2010. Grants of phantom units during the six months
ended June 30, 2010 had an estimated grant date fair value of $4.5 million.
KGS has unearned compensation expense of $4.4 million at June 30, 2010 that will be recognized
in expense over the vesting period. Phantom units that vested during the six months ended June 30,
2010 had a fair value of $2.5 million on their vesting date. We will recognize $4.4 million of
expense for all unvested KGS phantom units upon closing of the Crestwood Transaction in accordance
with the terms of KGS amended 2007 Equity plan.
10. EARNINGS PER SHARE
The following is a reconciliation of the components used to compute basic and diluted net income
per common share.
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
(In thousands, except per share | (In thousands, except per share | |||||||||||||||
data) | data) | |||||||||||||||
Net income (loss) attributable to Quicksilver |
$ | 86,803 | $ | (21,762 | ) | $ | 94,991 | $ | (590,741 | ) | ||||||
Impact of
assumed conversions - interest on 1.875% |
||||||||||||||||
convertible debentures, net of income taxes (1) |
1,787 | - | 3,552 | - | ||||||||||||
Income (loss) available to stockholders assuming |
||||||||||||||||
conversion of convertible debentures |
$ | 88,590 | $ | (21,762 | ) | $ | 98,543 | $ | (590,741 | ) | ||||||
Weighted
average common shares - basic |
170,290 | 169,009 | 170,225 | 168,894 | ||||||||||||
Effect of dilutive securities(1): |
||||||||||||||||
Employee stock options |
766 | - | 814 | - | ||||||||||||
Employee stock unit awards |
- | - | - | - | ||||||||||||
Contingently convertible debentures |
9,816 | - | 9,816 | - | ||||||||||||
Weighted
average common shares - diluted |
180,872 | 169,009 | 180,855 | 168,894 | ||||||||||||
Earnings
(loss) per common share - basic |
$ | 0.51 | $ | (0.13 | ) | $ | 0.56 | $ | (3.50 | ) | ||||||
Earnings
(loss) per common share - diluted |
$ | 0.49 | $ | (0.13 | ) | $ | 0.54 | $ | (3.50 | ) |
(1) | For the three and six months ended June 30, 2009, the effects of 9.8 million shares for our convertible debt and stock options and unvested restricted stock units representing 0.9 million shares were antidilutive and excluded from the diluted share calculations. For the three and six months ended June 30, 2010, the effects of stock options and unvested restricted stock units representing 1.3 million shares were antidilutive and excluded from the diluted share calculations. |
21
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11. CONDENSED CONSOLIDATING FINANCIAL INFORMATION
Note 20 to the consolidated financial statements in our 2009 Annual Report on Form 10-K
contains a more complete description of our guarantor, non-guarantor, restricted and unrestricted
subsidiaries.
The following condensed consolidating financial information includes information about the
Company and our restricted subsidiaries. The 2009 condensed consolidating financial information
includes changes in the financial information of our unrestricted non-guarantor subsidiaries
(primarily KGS) to present the 2009 financial information including the effects of the purchase of
the Alliance Midstream Assets by KGS.
The Crestwood Transaction will result in the sale of all unrestricted non-guarantor
subsidiaries.
June 30, 2010 | ||||||||||||||||||||||||||||||||
Restricted | Restricted | Restricted | Quicksilver | Unrestricted | Quicksilver | |||||||||||||||||||||||||||
Quicksilver | Guarantor | Non-Guarantor | Subsidiary | and Restricted | Non-Guarantor | Consolidating | Resources Inc. | |||||||||||||||||||||||||
Resources Inc. | Subsidiaries | Subsidiaries | Eliminations | Subsidiaries | Subsidiaries | Eliminations | Consolidated | |||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||||||
ASSETS |
||||||||||||||||||||||||||||||||
Current assets |
$ | 239,863 | $ | 85,189 | $ | 47,595 | $ | (109,425 | ) | $ | 263,222 | $ | 4,935 | $ | (20,246 | ) | $ | 247,911 | ||||||||||||||
Property and equipment |
2,246,197 | 128,527 | 499,328 | - | 2,874,052 | 508,850 | - | 3,382,902 | ||||||||||||||||||||||||
Investment in subsidiaries
(equity method) |
551,333 | 152,319 | - | (458,377 | ) | 245,275 | - | (152,319 | ) | 92,956 | ||||||||||||||||||||||
Other assets |
219,129 | - | 9,104 | - | 228,233 | 8,624 | (53,927 | ) | 182,930 | |||||||||||||||||||||||
Total assets |
$ | 3,256,522 | $ | 366,035 | $ | 556,027 | $ | (567,802 | ) | $ | 3,610,782 | $ | 522,409 | $ | (226,492 | ) | $ | 3,906,699 | ||||||||||||||
LIABILITIES AND EQUITY |
||||||||||||||||||||||||||||||||
Current liabilities |
$ | 323,078 | $ | 108,751 | $ | 15,593 | $ | (109,425 | ) | $ | 337,997 | $ | 16,176 | $ | (20,246 | ) | $ | 333,927 | ||||||||||||||
Long-term liabilities |
2,151,529 | 21,715 | 317,626 | - | 2,490,870 | 291,047 | (53,927 | ) | 2,727,990 | |||||||||||||||||||||||
Quicksilver stockholders equity |
781,915 | 235,569 | 222,808 | (458,377 | ) | 781,915 | 152,319 | (152,319 | ) | 781,915 | ||||||||||||||||||||||
Noncontrolling interests |
- | - | - | - | - | 62,867 | - | 62,867 | ||||||||||||||||||||||||
Total liabilities and equity |
$ | 3,256,522 | $ | 366,035 | $ | 556,027 | $ | (567,802 | ) | $ | 3,610,782 | $ | 522,409 | $ | (226,492 | ) | $ | 3,906,699 | ||||||||||||||
December 31, 2009 | ||||||||||||||||||||||||||||||||
Restricted | Restricted | Restricted | Quicksilver | Unrestricted | Quicksilver | |||||||||||||||||||||||||||
Quicksilver | Guarantor | Non-Guarantor | Subsidiary | and Restricted | Non-Guarantor | Consolidating | Resources Inc. | |||||||||||||||||||||||||
Resources Inc. | Subsidiaries | Subsidiaries | Eliminations | Subsidiaries | Subsidiaries | Eliminations | Consolidated | |||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||||||
ASSETS |
||||||||||||||||||||||||||||||||
Current assets |
$ | 313,485 | $ | 394 | $ | 42,622 | $ | (121,580 | ) | $ | 234,921 | $ | 2,268 | $ | (17,251 | ) | $ | 219,938 | ||||||||||||||
Property and equipment |
1,980,053 | 131,862 | 491,528 | - | 2,603,443 | 482,497 | - | 3,085,940 | ||||||||||||||||||||||||
Investment in subsidiaries
(equity method) |
549,200 | 230,221 | - | (436,437 | ) | 342,984 | - | (230,221 | ) | 112,763 | ||||||||||||||||||||||
Other assets |
235,304 | - | 3,112 | - | 238,416 | 9,067 | (53,242 | ) | 194,241 | |||||||||||||||||||||||
Total assets |
$ | 3,078,042 | $ | 362,477 | $ | 537,262 | $ | (558,017 | ) | $ | 3,419,764 | $ | 493,832 | $ | (300,714 | ) | $ | 3,612,882 | ||||||||||||||
LIABILITIES AND EQUITY |
||||||||||||||||||||||||||||||||
Current liabilities |
$ | 349,415 | $ | 116,298 | $ | 25,321 | $ | (121,580 | ) | $ | 369,454 | $ | 14,457 | $ | (17,251 | ) | $ | 366,660 | ||||||||||||||
Long-term liabilities |
2,092,629 | 11,843 | 309,840 | - | 2,414,312 | 188,330 | (53,242 | ) | 2,549,400 | |||||||||||||||||||||||
Quicksilver stockholders equity |
635,998 | 234,336 | 202,101 | (436,437 | ) | 635,998 | 230,221 | (230,221 | ) | 635,998 | ||||||||||||||||||||||
Noncontrolling interests |
- | - | - | - | - | 60,824 | - | 60,824 | ||||||||||||||||||||||||
Total liabilities and equity |
$ | 3,078,042 | $ | 362,477 | $ | 537,262 | $ | (558,017 | ) | $ | 3,419,764 | $ | 493,832 | $ | (300,714 | ) | $ | 3,612,882 | ||||||||||||||
For the Three Months Ended June 30, 2010 | ||||||||||||||||||||||||||||||||
Restricted | Restricted | Restricted | Quicksilver | Unrestricted | Quicksilver | |||||||||||||||||||||||||||
Quicksilver | Guarantor | Non-Guarantor | Subsidiary | and Restricted | Non-Guarantor | Resources Inc. | ||||||||||||||||||||||||||
Resources Inc. | Subsidiaries | Subsidiaries | Eliminations | Subsidiaries | Subsidiaries | Eliminations | Consolidated | |||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||||||
Revenue |
$ | 195,394 | $ | 1,566 | $ | 28,700 | $ | (629 | ) | $ | 225,031 | $ | 27,194 | $ | (23,655 | ) | $ | 228,570 | ||||||||||||||
Operating expense |
103,657 | 2,470 | 23,797 | (629 | ) | 129,295 | 14,063 | (23,655 | ) | 119,703 | ||||||||||||||||||||||
Equity in net earnings of subsidiaries |
5,544 | 6,172 | - | (5,544 | ) | 6,172 | - | (6,172 | ) | - | ||||||||||||||||||||||
Operating income |
97,281 | 5,268 | 4,903 | (5,544 | ) | 101,908 | 13,131 | (6,172 | ) | 108,867 | ||||||||||||||||||||||
Income from earnings of BBEP |
23,168 | - | - | - | 23,168 | - | - | 23,168 | ||||||||||||||||||||||||
Interest expense and other |
11,658 | - | (1,785 | ) | - | 9,873 | (2,945 | ) | - | 6,928 | ||||||||||||||||||||||
Income tax (expense) benefit |
(45,304 | ) | (1,843 | ) | (999 | ) | - | (48,146 | ) | (73 | ) | - | (48,219 | ) | ||||||||||||||||||
Net income |
$ | 86,803 | $ | 3,425 | $ | 2,119 | $ | (5,544 | ) | $ | 86,803 | $ | 10,113 | $ | (6,172 | ) | $ | 90,744 | ||||||||||||||
Net income attributable to
noncontrolling interests |
- | - | - | - | - | (3,941 | ) | - | (3,941 | ) | ||||||||||||||||||||||
Net income attributable Quicksilver |
$ | 86,803 | $ | 3,425 | $ | 2,119 | $ | (5,544 | ) | $ | 86,803 | $ | 6,172 | $ | (6,172 | ) | $ | 86,803 | ||||||||||||||
22
Table of Contents
For the Three Months Ended June 30, 2009 | ||||||||||||||||||||||||||||||||
Restricted | Restricted | Restricted | Quicksilver | Unrestricted | Quicksilver | |||||||||||||||||||||||||||
Quicksilver | Guarantor | Non-Guarantor | Subsidiary | and Restricted | Non-Guarantor | Resources Inc. | ||||||||||||||||||||||||||
Resources Inc. | Subsidiaries | Subsidiaries | Eliminations | Subsidiaries | Subsidiaries | Eliminations | Consolidated | |||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||||||
Revenue |
$ | 157,389 | $ | 185 | $ | 47,324 | $ | (110 | ) | $ | 204,788 | $ | 23,340 | $ | (22,087 | ) | $ | 206,041 | ||||||||||||||
Operating expense |
112,301 | 1,154 | 90,946 | (110 | ) | 204,291 | 13,015 | (21,838 | ) | 195,468 | ||||||||||||||||||||||
Equity in net earnings of subsidiaries |
(31,157 | ) | 5,704 | - | 31,157 | 5,704 | - | (5,704 | ) | - | ||||||||||||||||||||||
Operating income (loss) |
13,931 | 4,735 | (43,622 | ) | 31,157 | 6,201 | 10,325 | (5,953 | ) | 10,573 | ||||||||||||||||||||||
Income from earnings of BBEP |
19,016 | - | - | - | 19,016 | - | - | 19,016 | ||||||||||||||||||||||||
Interest expense and other |
(64,606 | ) | 1,191 | (2,709 | ) | - | (66,124 | ) | (2,242 | ) | (570 | ) | (68,936 | ) | ||||||||||||||||||
Income tax (expense) benefit |
9,897 | (2,074 | ) | 11,322 | - | 19,145 | (248 | ) | - | 18,897 | ||||||||||||||||||||||
Discontinued operations |
- | - | - | - | - | (819 | ) | 819 | - | |||||||||||||||||||||||
Net income (loss) |
$ | (21,762 | ) | $ | 3,852 | $ | (35,009 | ) | $ | 31,157 | $ | (21,762 | ) | $ | 7,016 | $ | (5,704 | ) | $ | (20,450 | ) | |||||||||||
Net income attributable to
noncontrolling interests |
- | - | - | - | - | (1,312 | ) | - | (1,312 | ) | ||||||||||||||||||||||
Net income (loss) attributable
to Quicksilver |
$ | (21,762 | ) | $ | 3,852 | $ | (35,009 | ) | $ | 31,157 | $ | (21,762 | ) | $ | 5,704 | $ | (5,704 | ) | $ | (21,762 | ) | |||||||||||
For the Six Months Ended June 30, 2010 | ||||||||||||||||||||||||||||||||
Restricted | Restricted | Restricted | Quicksilver | Unrestricted | Quicksilver | |||||||||||||||||||||||||||
Quicksilver | Guarantor | Non-Guarantor | Subsidiary | and Restricted | Non-Guarantor | Resources Inc. | ||||||||||||||||||||||||||
Resources Inc. | Subsidiaries | Subsidiaries | Eliminations | Subsidiaries | Subsidiaries | Eliminations | Consolidated | |||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||||||
Revenues |
$ | 377,894 | $ | 3,211 | $ | 64,549 | $ | (1,325 | ) | $ | 444,329 | $ | 51,933 | $ | (45,534 | ) | $ | 450,728 | ||||||||||||||
Operating expenses |
231,498 | 4,353 | 47,142 | (1,325 | ) | 281,668 | 29,882 | (45,534 | ) | 266,016 | ||||||||||||||||||||||
Equity in net earnings of subsidiaries |
16,146 | 9,949 | - | (16,146 | ) | 9,949 | - | (9,949 | ) | - | ||||||||||||||||||||||
Operating income (loss) |
162,542 | 8,807 | 17,407 | (16,146 | ) | 172,610 | 22,051 | (9,949 | ) | 184,712 | ||||||||||||||||||||||
Income from earnings of BBEP |
7,179 | - | - | - | 7,179 | - | - | 7,179 | ||||||||||||||||||||||||
Interest expense and other |
(28,401 | ) | - | (3,222 | ) | - | (31,623 | ) | (5,623 | ) | - | (37,246 | ) | |||||||||||||||||||
Income tax (expense) benefit |
(46,329 | ) | (3,082 | ) | (3,764 | ) | - | (53,175 | ) | (126 | ) | - | (53,301 | ) | ||||||||||||||||||
Net income (loss) |
$ | 94,991 | $ | 5,725 | $ | 10,421 | $ | (16,146 | ) | $ | 94,991 | $ | 16,302 | $ | (9,949 | ) | $ | 101,344 | ||||||||||||||
Net income attributable to
noncontrolling interests |
- | - | - | - | - | (6,353 | ) | - | (6,353 | ) | ||||||||||||||||||||||
Net income (loss) attributable
to Quicksilver |
$ | 94,991 | $ | 5,725 | $ | 10,421 | $ | (16,146 | ) | $ | 94,991 | $ | 9,949 | $ | (9,949 | ) | $ | 94,991 | ||||||||||||||
For the Six Months Ended June 30, 2009 | ||||||||||||||||||||||||||||||||
Restricted | Restricted | Restricted | Quicksilver | Unrestricted | Quicksilver | |||||||||||||||||||||||||||
Quicksilver | Guarantor | Non-Guarantor | Subsidiary | and Restricted | Non-Guarantor | Resources Inc. | ||||||||||||||||||||||||||
Resources Inc. | Subsidiaries | Subsidiaries | Eliminations | Subsidiaries | Subsidiaries | Eliminations | Consolidated | |||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||||||
Revenues |
$ | 294,996 | $ | 217 | $ | 93,138 | $ | (34 | ) | $ | 388,317 | $ | 47,304 | $ | (43,648 | ) | $ | 391,973 | ||||||||||||||
Operating expenses |
1,004,499 | 1,438 | 219,839 | (34 | ) | 1,225,742 | 24,752 | (43,402 | ) | 1,207,092 | ||||||||||||||||||||||
Equity in net earnings of subsidiaries |
(88,798 | ) | 13,428 | - | 88,798 | 13,428 | - | (13,428 | ) | - | ||||||||||||||||||||||
Operating income |
(798,301 | ) | 12,207 | (126,701 | ) | 88,798 | (823,997 | ) | 22,552 | (13,674 | ) | (815,119 | ) | |||||||||||||||||||
Income from earnings of BBEP |
19,016 | - | - | - | 19,016 | - | - | 19,016 | ||||||||||||||||||||||||
Interest expense and other |
(101,157 | ) | 2,575 | (4,109 | ) | - | (102,691 | ) | (4,477 | ) | (1,208 | ) | (108,376 | ) | ||||||||||||||||||
Income tax (expense) benefit |
289,701 | (5,174 | ) | 32,404 | - | 316,931 | (211 | ) | - | 316,720 | ||||||||||||||||||||||
Discontinued operations |
- | - | - | - | - | (1,454 | ) | 1,454 | - | |||||||||||||||||||||||
Net income |
$ | (590,741 | ) | $ | 9,608 | $ | (98,406 | ) | $ | 88,798 | $ | (590,741 | ) | $ | 16,410 | $ | (13,428 | ) | $ | (587,759 | ) | |||||||||||
Net income attributable to |
||||||||||||||||||||||||||||||||
noncontrolling interests |
- | - | - | - | - | (2,982 | ) | - | (2,982 | ) | ||||||||||||||||||||||
Net income attributable to Quicksilver |
$ | (590,741 | ) | $ | 9,608 | $ | (98,406 | ) | $ | 88,798 | $ | (590,741 | ) | $ | 13,428 | $ | (13,428 | ) | $ | (590,741 | ) | |||||||||||
23
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For the Six Months Ended June 30, 2010 | ||||||||||||||||||||||||||||||||
Restricted | Restricted | Restricted | Quicksilver | Unrestricted | Quicksilver | |||||||||||||||||||||||||||
Quicksilver | Guarantor | Non-Guarantor | Subsidiary | and Restricted | Non-Guarantor | Resources Inc. | ||||||||||||||||||||||||||
Resources Inc. | Subsidiaries | Subsidiaries | Eliminations | Subsidiaries | Subsidiaries | Eliminations | Consolidated | |||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||||||
Net cash flow provided by operating activities |
$ | 187,555 | $ | 100 | $ | 43,850 | $ | - | $ | 231,505 | $ | 26,749 | $ | (11,747 | ) | $ | 246,507 | |||||||||||||||
Purchases of property, plant and equipment |
(271,897 | ) | (100 | ) | (46,987 | ) | - | (318,984 | ) | (34,845 | ) | (2,573 | ) | (356,402 | ) | |||||||||||||||||
Distribution to parent |
80,276 | - | - | - | 80,276 | (80,276 | ) | - | - | |||||||||||||||||||||||
Proceeds from sales of property and equipment |
864 | - | - | - | 864 | - | - | 864 | ||||||||||||||||||||||||
Net cash flow used for investing activities |
(190,757 | ) | (100 | ) | (46,987 | ) | - | (237,844 | ) | (115,121 | ) | (2,573 | ) | (355,538 | ) | |||||||||||||||||
Issuance of debt |
376,000 | - | 39,532 | - | 415,532 | 124,500 | - | 540,032 | ||||||||||||||||||||||||
Repayments of debt |
(352,500 | ) | - | (34,013 | ) | - | (386,513 | ) | (23,100 | ) | - | (409,613 | ) | |||||||||||||||||||
Debt issuance costs |
(109 | ) | - | - | - | (109 | ) | - | - | (109 | ) | |||||||||||||||||||||
Gas Purchase
Commitment - net |
(16,592 | ) | - | - | - | (16,592 | ) | - | - | (16,592 | ) | |||||||||||||||||||||
Issuance of KGS common units |
- | - | - | - | - | 11,054 | - | 11,054 | ||||||||||||||||||||||||
Distributions to parent |
- | - | - | - | - | (14,320 | ) | 14,320 | - | |||||||||||||||||||||||
Distributions to noncontrolling interests |
- | - | - | - | - | (8,808 | ) | - | (8,808 | ) | ||||||||||||||||||||||
Proceeds from exercise of stock options |
1,209 | - | - | - | 1,209 | - | - | 1,209 | ||||||||||||||||||||||||
Treasury
transactions - equity |
(4,804 | ) | - | - | - | (4,804 | ) | (1,144 | ) | - | (5,948 | ) | ||||||||||||||||||||
Net cash flow provided by financing activities |
3,204 | - | 5,519 | - | 8,723 | 88,182 | 14,320 | 111,225 | ||||||||||||||||||||||||
Effect of exchange rates on cash |
- | - | (671 | ) | - | (671 | ) | - | - | (671 | ) | |||||||||||||||||||||
Net decrease in cash and equivalents |
2 | - | 1,711 | - | 1,713 | (190 | ) | - | 1,523 | |||||||||||||||||||||||
Cash and equivalents at beginning of period |
5 | - | 1,034 | - | 1,039 | 746 | - | 1,785 | ||||||||||||||||||||||||
Cash and equivalents at end of period |
$ | 7 | $ | - | $ | 2,745 | $ | - | $ | 2,752 | $ | 556 | $ | - | $ | 3,308 | ||||||||||||||||
For the Six Months Ended June 30, 2009 | ||||||||||||||||||||||||||||||||
Restricted | Restricted | Restricted | Quicksilver | Unrestricted | Quicksilver | |||||||||||||||||||||||||||
Quicksilver | Guarantor | Non-Guarantor | Subsidiary | and Restricted | Non-Guarantor | Resources Inc. | ||||||||||||||||||||||||||
Resources Inc. | Subsidiaries | Subsidiaries | Eliminations | Subsidiaries | Subsidiaries | Eliminations | Consolidated | |||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||||||
Net cash flow provided by operations |
$ | 184,519 | $ | 20,495 | $ | 85,310 | $ | - | $ | 290,324 | $ | 33,249 | $ | (13,232 | ) | $ | 310,341 | |||||||||||||||
Purchases of property, plant and equipment |
(316,015 | ) | (20,495 | ) | (68,894 | ) | - | (405,404 | ) | (35,780 | ) | - | (441,184 | ) | ||||||||||||||||||
Proceeds from sales of property and equipment |
232,720 | - | 768 | - | 233,488 | - | - | 233,488 | ||||||||||||||||||||||||
Net cash flow used for investing activities |
(83,295 | ) | (20,495 | ) | (68,126 | ) | - | (171,916 | ) | (35,780 | ) | - | (207,696 | ) | ||||||||||||||||||
Issuance of debt |
946,302 | - | 42,948 | - | 989,250 | 31,500 | - | 1,020,750 | ||||||||||||||||||||||||
Repayments of debt |
(1,073,605 | ) | - | (59,926 | ) | - | (1,133,531 | ) | (10,500 | ) | - | (1,144,031 | ) | |||||||||||||||||||
Debt issuance costs |
(21,677 | ) | - | (1,125 | ) | - | (22,802 | ) | - | - | (22,802 | ) | ||||||||||||||||||||
Gas Purchase Commitment assumed |
46,628 | - | - | - | 46,628 | - | - | 46,628 | ||||||||||||||||||||||||
Distributions to parent |
- | - | - | - | - | (13,232 | ) | 13,232 | - | |||||||||||||||||||||||
Distributions to noncontrolling interests |
- | - | - | - | - | (4,896 | ) | - | (4,896 | ) | ||||||||||||||||||||||
Proceeds from exercise of stock options |
80 | - | - | - | 80 | - | - | 80 | ||||||||||||||||||||||||
Treasury
transactions - equity |
(627 | ) | - | - | - | (627 | ) | (63 | ) | - | (690 | ) | ||||||||||||||||||||
Net cash flow provided by (used for) financing activities |
(102,899 | ) | - | (18,103 | ) | - | (121,002 | ) | 2,809 | 13,232 | (104,961 | ) | ||||||||||||||||||||
Effect of exchange rates on cash |
- | - | 125 | - | 125 | - | - | 125 | ||||||||||||||||||||||||
Net decrease in cash and equivalents |
(1,675 | ) | - | (794 | ) | - | (2,469 | ) | 278 | - | (2,191 | ) | ||||||||||||||||||||
Cash and equivalents at beginning of period |
1,679 | - | 866 | - | 2,545 | 303 | - | 2,848 | ||||||||||||||||||||||||
Cash and equivalents at end of period |
$ | 4 | $ | - | $ | 72 | $ | - | $ | 76 | $ | 581 | $ | - | $ | 657 | ||||||||||||||||
12. SEGMENT INFORMATION
We operate in two geographic segments, the United States and Canada, where we are engaged in
the exploration and production segment of the oil and gas industry. Additionally, we operate in the midstream segment, where we provide natural gas processing and gathering services in the United
States, predominantly through KGS. Revenue earned by KGS for the processing and gathering of Quicksilver gas are eliminated on a consolidated basis as are the fees paid for these services by Quicksilver on producing properties. We evaluate performance based on operating income and
property and equipment costs incurred.
Based upon our board of directors approval of the Crestwood Transaction, our historical
financial statements to be contained in our September 30, 2010 Report on Form 10-Q will reflect
KGS financial information as discontinued operations, which similarly will cause the cessation of
reporting KGS financial information within the midstream caption within our segment disclosures.
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Exploration & Production | Corporate | Quicksilver | ||||||||||||||||||||||
United States | Canada | Midstream | and Other | Elimination | Consolidated | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
For the Three Months Ended June 30, 2010 |
||||||||||||||||||||||||
Revenues |
$ | 195,395 | $ | 28,701 | $ | 28,181 | $ | - | $ | (23,707 | ) | $ | 228,570 | |||||||||||
Depletion, depreciation and accretion |
31,708 | 11,152 | 7,356 | 453 | - | 50,669 | ||||||||||||||||||
Operating income |
106,642 | 5,834 | 14,061 | (17,670 | ) | - | 108,867 | |||||||||||||||||
Property and equipment costs incurred |
246,917 | 4,550 | 9,317 | 1,347 | - | 262,131 | ||||||||||||||||||
For the Three Months Ended June 30, 2009 |
||||||||||||||||||||||||
Revenues |
$ | 152,051 | $ | 47,209 | $ | 24,386 | $ | 5,217 | $ | (22,822 | ) | $ | 206,041 | |||||||||||
Depletion, depreciation and accretion |
34,490 | 9,671 | 6,323 | 482 | - | 50,966 | ||||||||||||||||||
Operating income |
70,725 | (42,765 | ) | 11,084 | (28,471 | ) | - | 10,573 | ||||||||||||||||
Property and equipment costs incurred |
90,422 | 13,738 | 30,383 | 1,130 | - | 135,673 | ||||||||||||||||||
For the Six Months Ended June 30, 2010 |
||||||||||||||||||||||||
Revenue |
$ | 377,894 | $ | 64,549 | $ | 53,985 | $ | - | $ | (45,700 | ) | $ | 450,728 | |||||||||||
Depletion, depreciation and accretion |
59,656 | 22,437 | 14,413 | 920 | - | 97,426 | ||||||||||||||||||
Operating income |
178,921 | 19,267 | 25,183 | (38,659 | ) | - | 184,712 | |||||||||||||||||
Property and equipment costs incurred |
324,284 | 35,134 | 36,951 | 1,967 | - | 398,336 | ||||||||||||||||||
For the Six Months Ended June 30, 2009 |
||||||||||||||||||||||||
Revenue |
$ | 289,779 | $ | 93,138 | $ | 49,394 | $ | 5,217 | $ | (45,555 | ) | $ | 391,973 | |||||||||||
Depletion, depreciation and accretion |
78,381 | 19,964 | 11,509 | 808 | - | 110,662 | ||||||||||||||||||
Operating income |
(669,154 | ) | (124,841 | ) | 24,819 | (45,943 | ) | - | (815,119 | ) | ||||||||||||||
Property and equipment costs incurred |
228,053 | 56,516 | 48,280 | 1,656 | - | 334,505 | ||||||||||||||||||
Property, Plant and Equipment-net |
||||||||||||||||||||||||
June 30, 2010 |
$ | 2,244,634 | $ | 499,328 | $ | 637,376 | $ | 1,564 | $ | - | $ | 3,382,902 | ||||||||||||
December 31, 2009 |
1,968,430 | 491,528 | 614,359 | 11,623 | - | 3,085,940 |
13. SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid (received) for interest and income taxes is as follows:
Six Months Ended June 30, | ||||||||
2010 | 2009 | |||||||
(In thousands) | ||||||||
Interest |
$ | 58,519 | $ | 85,772 | ||||
Income taxes |
(6,917 | ) | (41,265 | ) |
Other non-cash transactions include:
Six Months Ended June 30, | ||||||||
2010 | 2009 | |||||||
(In thousands) | ||||||||
Working capital related to acquisition
of property, plant and equipment |
$ | 102,878 | $ | 111,868 | ||||
Conveyance of 3,619,901 BBEP common
units for producing properties |
54,407 | - |
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14. RELATED-PARTY TRANSACTIONS
As of June 30, 2010, members of the Darden family and entities controlled by them beneficially
owned approximately 30% of our outstanding common stock. Thomas F. Darden, Glenn Darden and Anne
Darden Self are officers and directors of Quicksilver.
Quicksilver and its associated entities paid $0.5 million in the first six months of both 2010
and 2009 for rent on buildings owned or property services performed by entities affiliated with
Mercury. Rental rates have been determined based on comparable rates charged by third parties.
We paid $0.2 million during the first six months of both 2010 and 2009 for use of an airplane
owned by an entity controlled by members of the Darden family. Usage rates are determined based on
comparable rates charged by third parties.
Payments received from Mercury for sublease rentals, employee insurance coverage and
administrative services during the first six months of 2010 and 2009 each totaled $0.2 million.
In connection with our lease of office space, beginning in August 2010, an entity affiliated
with Mercury expects to receive a $1.3 million commission from the lessor.
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ITEM 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our consolidated financial condition and results of
operations should be read in conjunction with our condensed consolidated financial statements, and
notes thereto, and the other financial data included elsewhere in this quarterly report. The
following discussion should also be read in conjunction with our audited consolidated financial
statements, and notes thereto, and Managements Discussion and Analysis of Financial Condition and
Results of Operations included in our 2009 Annual Report on Form 10-K.
EXECUTIVE OVERVIEW
We are an independent energy company engaged primarily in exploration, development and
production of unconventional natural gas onshore in North America. We own producing oil and
natural gas properties in the United States, principally in Texas, and in Alberta, Canada, where we
had total estimated aggregate proved reserves of approximately 2.4 Tcfe at December 31, 2009. We
also have properties in the Horn River Basin of Northeast British Columbia and the Green River
Basin of Colorado where we are exploring for additional reserves, but have recognized only
immaterial proved reserves based upon drilling activity to date. Additionally as of June 30, 2010,
we own 61% of KGS, which we control and consolidate, and we own 33% of the limited partner units of
BBEP, a publicly traded oil and natural gas exploration and production master limited partnership,
which we account for using the equity method.
2010 HIGHLIGHTS
Lake Arlington Acquisition
In May 2010, we completed the acquisition of an approximate 25% working interest in our
company-operated Lake Arlington Project. We acquired the additional working interests in the Lake
Arlington Project, subject to customary adjustments as provided in the purchase agreement, for
which we conveyed $62.0 million in cash and 3,619,901 of the BBEP common units we owned to the
seller on the date of closing. The acquired interests include proved natural gas reserves of
approximately 125 Bcf of which 82% are proved developed. We expect to finalize adjustments to the
purchase price in the third quarter of 2010. As a result of our conveyance of the 3.6 million BBEP
common units for the acquired properties, we recognized a $35.4 million gain as other income in the
second quarter of 2010.
BBEP Update
In April 2010, we finalized a global settlement agreement with BBEP and all other parties to
our lawsuit whereby we received $18.0 million in cash. Pursuant to the agreement, we retained full
voting rights for our units held in BBEP subject to the provisions of a limited standstill
agreement and the ability to name two directors to the board of directors of BBEPs general
partner. BBEP also agreed to the reinstitution of the BBEP quarterly distributions and other
governance accommodations. The $18.0 million settlement was recognized as other income in the
second quarter of 2010. Additionally, we received a quarterly distribution of $8.0 million for the
first quarter of 2010. Completion of the Lake Arlington acquisition in May 2010 reduced our
ownership of BBEP to 33%.
Crestwood Transaction
In July 2010, we entered into a purchase agreement to sell all of our interests in KGS to
Crestwood. The Crestwood Transaction will include the sale of a 100% ownership interest in
Quicksilver Gas Services Holdings LLC, which owns (a) 5,696,752 common units of KGS, (b) 11,513,635
subordinated units of KGS representing limited partner interests in KGS and (c) 100% of the
outstanding membership interests in Quicksilver Gas Services GP LLC including 469,949 general
partner units in KGS and 100% of the outstanding incentive distribution rights in KGS. Crestwood
will also purchase a $57 million subordinated promissory note issued to us by KGS. We expect to
receive $701 million in cash at closing and up to $72 million in future earn-out payments in 2012
and 2013. The Crestwood Transaction is expected to close in the fourth quarter 2010, subject to
customary closing conditions.
Under the agreements governing the Crestwood Transaction, we have agreed for two years not to
solicit employees of KGS and not to compete with KGS with respect to gathering, treating and
processing of natural gas and the transportation of natural gas liquids in Denton, Hood, Somervell,
Johnson, Tarrant, Parker, Bosque and Erath counties in Texas. We will be entitled to appoint a
director to KGS general partners board of directors until the later of the second anniversary of
the closing and such time as we generate less than 50% of KGS consolidated revenue in any fiscal
year.
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In connection with the closing of the Crestwood Transaction, we will provide transitional
services to KGS for up to six months on customary terms. We and KGS will also enter into an
agreement for the joint development of areas governed by certain of our existing commercial
agreements and amend certain of our existing commercial agreements. The most significant
amendments include extending the terms of all gathering agreements with KGS to 2020 and
establishing a fixed gathering rate of $0.55 per MMcf in the Alliance gathering system.
2010 CAPITAL OUTLOOK
Commodity prices, drilling and well completion costs and access to capital and services are
the most significant drivers of our business. As of the date of this report, natural gas prices
have remained depressed and we continue to focus on ways to optimize our 2010 capital program. Our
2010 capital program will also be influenced by the closing of the Crestwood Transaction, which
will cause us to reduce our midstream program and to possibly redirect additional capital toward
our exploration and production activities. We currently expect that our 2010 capital program will
total approximately $470 million, excluding acquisitions. Our focus remains on the continued
development of our properties in the Barnett Shale and exploration in the Horn River and Greater
Green River Basins. For 2010, we expect to spend approximately $393 million for exploration and
development activities. Our 2010 capital program has $75 million for midstream facilities of which
$22 million will be spent in the Horn River Basin in Canada and $53 million will be spent in the
U.S. directly by KGS prior to the closing of the Crestwood Transaction. On a regional basis, approximately
$390 million is forecasted to be spent in Texas to drill approximately 80 net wells on operated
properties, to complete and tie-in approximately 105 net wells and on midstream
infrastructure. Canadian spending for 2010 is forecasted to be approximately $73 million chiefly
to explore the Horn River Basin and develop midstream infrastructure and, to a lesser extent,
maintain current production levels in our CBM projects in Alberta. The remaining capital program
is spread among our other operating areas.
Our remaining 2010 capital program described above is dynamic and there are a number of
factors that could affect our decision to invest capital. Commodity prices, well costs, hedging
programs and program performance are a few factors that individually or in combination could change
the scale or relative allocation of our remaining capital program for 2010.
RESULTS OF OPERATIONS Three Months Ended June 30, 2010 and 2009
The following discussion compares the results of operations for the three months ended June
30, 2010 and 2009, or the 2010 quarter and 2009 quarter, respectively.
Natural Gas, NGL and Crude Oil Revenue
Production Revenue:
Natural Gas | NGL | Oil and Condensate | Total | |||||||||||||||||||||||||||||
2010 | 2009 | 2010 | 2009 | 2010 | 2009 | 2010 | 2009 | |||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||
Texas |
$ | 74.5 | $ | 52.1 | $ | 37.3 | $ | 32.7 | $ | 3.1 | $ | 3.9 | $ | 114.9 | $ | 88.7 | ||||||||||||||||
Other U.S. |
0.5 | 0.1 | 0.3 | - | 2.4 | 2.0 | 3.2 | 2.1 | ||||||||||||||||||||||||
Hedging |
67.9 | 61.2 | (4.0 | ) | - | - | - | 63.9 | 61.2 | |||||||||||||||||||||||
Total U.S. |
142.9 | 113.4 | 33.6 | 32.7 | 5.5 | 5.9 | 182.0 | 152.0 | ||||||||||||||||||||||||
Alberta |
21.2 | 20.3 | - | - | - | - | 21.2 | 20.3 | ||||||||||||||||||||||||
British Columbia |
1.9 | - | - | - | - | - | 1.9 | - | ||||||||||||||||||||||||
Hedging |
6.5 | 27.0 | - | - | - | - | 6.5 | 27.0 | ||||||||||||||||||||||||
Total Canada |
29.6 | 47.3 | - | - | - | - | 29.6 | 47.3 | ||||||||||||||||||||||||
Total Company |
$ | 172.5 | $ | 160.7 | $ | 33.6 | $ | 32.7 | $ | 5.5 | $ | 5.9 | $ | 211.6 | $ | 199.3 | ||||||||||||||||
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Average Daily Production Volumes:
Natural Gas | NGL | Oil and Condensate | Equivalent Total | |||||||||||||||||||||||||||||
2010 | 2009 | 2010 | 2009 | 2010 | 2009 | 2010 | 2009 | |||||||||||||||||||||||||
(MMcfd) | (Bbld) | (Bbld) | (MMcfed) | |||||||||||||||||||||||||||||
Texas |
205.5 | 169.0 | 11,762 | 14,818 | 461 | 805 | 278.8 | 262.7 | ||||||||||||||||||||||||
Other U.S. |
1.4 | 0.2 | 52 | 15 | 403 | 428 | 4.2 | 3.0 | ||||||||||||||||||||||||
Total U.S. |
206.9 | 169.2 | 11,814 | 14,833 | 864 | 1,233 | 283.0 | 265.7 | ||||||||||||||||||||||||
Alberta |
60.8 | 65.6 | 5 | 4 | - | 5 | 60.8 | 65.6 | ||||||||||||||||||||||||
British Columbia |
6.1 | - | - | - | - | - | 6.1 | - | ||||||||||||||||||||||||
Total Canada |
66.9 | 65.6 | 5 | 4 | - | 5 | 66.9 | 65.6 | ||||||||||||||||||||||||
Total Company |
273.8 | 234.8 | 11,819 | 14,837 | 864 | 1,238 | 349.9 | 331.3 | ||||||||||||||||||||||||
Average Realized Prices:
Natural Gas | NGL | Oil and Condensate | Equivalent Total | |||||||||||||||||||||||||||||
2010 | 2009 | 2010 | 2009 | 2010 | 2009 | 2010 | 2009 | |||||||||||||||||||||||||
(per Mcf) | (per Bbl) | (per Bbl) | (per Mcfe) | |||||||||||||||||||||||||||||
Texas |
$ | 3.99 | $ | 3.39 | $ | 34.90 | $ | 24.20 | $ | 72.96 | $ | 53.45 | $ | 4.53 | $ | 3.71 | ||||||||||||||||
Other U.S. |
3.73 | 3.00 | 60.09 | 34.49 | 67.11 | 50.75 | 8.55 | 7.82 | ||||||||||||||||||||||||
Hedging - U.S. |
3.61 | 3.97 | (3.76 | ) | - | - | - | 2.48 | 2.53 | |||||||||||||||||||||||
Total U.S. |
7.59 | 7.36 | 31.25 | 24.21 | 70.24 | 52.51 | 7.07 | 6.29 | ||||||||||||||||||||||||
Alberta |
3.84 | 3.40 | 62.58 | 52.00 | - | 45.01 | 3.84 | 3.40 | ||||||||||||||||||||||||
British Columbia |
3.49 | - | - | - | - | - | 3.49 | - | ||||||||||||||||||||||||
Hedging - Canada |
1.06 | 4.53 | - | - | - | - | 1.06 | 4.53 | ||||||||||||||||||||||||
Total Canada |
4.87 | 7.93 | 62.58 | 52.00 | - | 45.01 | 4.87 | 7.93 | ||||||||||||||||||||||||
Total Company |
$ | 6.93 | $ | 7.52 | $ | 31.27 | $ | 24.22 | $ | 70.24 | $ | 52.48 | $ | 6.65 | $ | 6.61 |
The following table summarizes the changes in our production revenue during the 2010
quarter compared with the 2009 quarter:
Natural | ||||||||||||||||
Gas | NGL | Oil | Total | |||||||||||||
(In thousands) | ||||||||||||||||
Revenue for the quarter ended June 30, 2009 |
$ | 160,701 | $ | 32,701 | $ | 5,913 | $ | 199,315 | ||||||||
Volume variance |
12,024 | (6,653 | ) | (1,785 | ) | 3,586 | ||||||||||
Hedge settlement variance |
(13,912 | ) | (4,040 | ) | - | (17,952 | ) | |||||||||
Price variance |
13,722 | 11,619 | 1,397 | 26,738 | ||||||||||||
Revenue for the quarter ended June 30, 2010 |
$ | 172,535 | $ | 33,627 | $ | 5,525 | $ | 211,687 | ||||||||
Higher natural gas production and market prices in the 2010 quarter as compared to the 2009
quarter were partially offset by decreased revenue from hedge settlements for the 2010 quarter as
compared to the 2009 quarter. Canadian natural gas production increased primarily from new Horn
River wells placed into service during the last half of 2009. U.S. natural gas production was also
higher because of new wells purchased or placed into service since the 2009 quarter despite lower
production of 11.8 MMcfd due to the sale of 27.5% of our Alliance properties sold in 2009 and
natural production declines from existing Fort Worth Basin wells. The impact of an unaffiliated
pipeline explosion in the Fort Worth Basin had no significant impact on our natural gas volumes for
the 2010 quarter.
The increase in NGL revenue was due to higher market prices partially offset by payments made
to settle hedges during the 2010 quarter and a 21% decrease in Fort Worth Basin production for the
2010 quarter compared to the 2009 quarter. NGL production decreased primarily because we have
focused our capital spending in areas of the Barnett Shale where dry natural gas is prevalent.
Utilization of derivatives to hedge our sales of natural gas, NGL and crude oil resulted in
realized prices that varied from market prices received from the sale our production. Our
production revenue from natural gas, NGL and oil production was $70.4 million and $88.2 million
higher because of our hedging activities for the 2010 quarter and the 2009 quarter, respectively.
29
Table of Contents
Sales of Purchased Natural Gas and Costs of Purchased Natural Gas
Three Months Ended | ||||||||
June 30, | ||||||||
2010 | 2009 | |||||||
Sales of purchased natural gas: | (In thousands) | |||||||
Purchases from Eni |
$ | 13,946 | $ | 474 | ||||
Purchases from others |
2,875 | 4,743 | ||||||
Total |
16,821 | 5,217 | ||||||
Costs of purchased natural gas sold: |
||||||||
Purchases from Eni |
17,883 | 903 | ||||||
Purchases from others |
2,975 | 3,861 | ||||||
Unrealized valuation (gain) loss on |
||||||||
Gas Purchase Commitment |
(17,102 | ) | 3,818 | |||||
Total |
3,756 | 8,582 | ||||||
Net sales and purchases of natural gas |
$ | 13,065 | $ | (3,365 | ) | |||
Our marketing activities related to the purchase and sale of natural gas have increased in
Texas because of our natural gas sales and purchases made under the Gas Purchase Commitment.
Natural gas purchases and sales made under the Gas Purchase Commitment began in June 2009 while the
2010 quarter includes three months of activity. The Gas Purchase Commitment is more fully
described in Note 2 to our condensed consolidated financial
statements.
30
Table of Contents
Oil and Gas Production Expense
Three Months Ended June 30, | ||||||||||||||||
2010 | 2009 | |||||||||||||||
(In thousands, except per unit amounts) | ||||||||||||||||
Per | Per | |||||||||||||||
Texas |
Mcfe | Mcfe | ||||||||||||||
Cash expense |
$ | 26,226 | $ | 1.03 | $ | 20,747 | $ | 0.87 | ||||||||
Equity compensation |
218 | 0.01 | 212 | 0.01 | ||||||||||||
$ | 26,444 | $ | 1.04 | $ | 20,959 | $ | 0.88 | |||||||||
Other U.S. |
||||||||||||||||
Cash expense |
$ | 1,244 | $ | 3.30 | $ | 1,449 | $ | 5.39 | ||||||||
Equity compensation |
44 | 0.12 | 46 | 0.17 | ||||||||||||
$ | 1,288 | $ | 3.42 | $ | 1,495 | $ | 5.56 | |||||||||
Total U.S. |
||||||||||||||||
Cash expense |
$ | 27,470 | $ | 1.07 | $ | 22,196 | $ | 0.92 | ||||||||
Equity compensation |
262 | 0.01 | 258 | 0.01 | ||||||||||||
$ | 27,732 | $ | 1.08 | $ | 22,454 | $ | 0.93 | |||||||||
Alberta |
||||||||||||||||
Cash expense |
$ | 8,408 | $ | 1.52 | $ | 8,729 | $ | 1.46 | ||||||||
Equity compensation |
274 | 0.05 | 520 | 0.09 | ||||||||||||
$ | 8,682 | $ | 1.57 | $ | 9,249 | $ | 1.55 | |||||||||
British Columbia |
||||||||||||||||
Cash expense |
$ | 1,788 | $ | 3.20 | $ | - | $ | - | ||||||||
Equity compensation |
- | - | - | - | ||||||||||||
$ | 1,788 | $ | 3.20 | $ | - | $ | - | |||||||||
Total Canada |
||||||||||||||||
Cash expense |
$ | 10,196 | $ | 1.67 | $ | 8,729 | $ | 1.46 | ||||||||
Equity compensation |
274 | 0.05 | 520 | 0.09 | ||||||||||||
$ | 10,470 | $ | 1.72 | $ | 9,249 | $ | 1.55 | |||||||||
Total Company |
||||||||||||||||
Cash expense |
$ | 37,666 | $ | 1.18 | $ | 30,925 | $ | 1.02 | ||||||||
Equity compensation |
536 | 0.02 | 778 | 0.03 | ||||||||||||
$ | 38,202 | $ | 1.20 | $ | 31,703 | $ | 1.05 | |||||||||
The increase in U.S. production expense was primarily associated with the increase in
production from new wells and the cost of operating additional compression in the Alliance area.
Canadian production expense for the 2010 quarter increased from the 2009 quarter due to $1.8
million for costs to operate our Horn River wells that were placed into production in the third and
fourth quarters of 2009. Alberta production expense decreased only $0.6 million despite a $1.5 million
reduction of production expense on a Canadian dollar-basis because of changes in U.S.-Canadian
exchange rates for the 2010 quarter when compared to the 2009 quarter. The Canadian dollar-basis
expense decrease was primarily due to lower lease operating expense and processing fees.
31
Table of Contents
Production and Ad Valorem Taxes
Three Months Ended June 30, | ||||||||||||||||
2010 | 2009 | |||||||||||||||
(In thousands, except per unit amounts) | ||||||||||||||||
Per | Per | |||||||||||||||
Production taxes |
Mcfe | Mcfe | ||||||||||||||
U.S. |
$ | 2,696 | $ | 0.10 | $ | 1,463 | $ | 0.06 | ||||||||
Canada |
209 | 0.03 | (83 | ) | (0.01 | ) | ||||||||||
Total production
taxes |
2,905 | 0.09 | 1,380 | 0.05 | ||||||||||||
Ad valorem taxes |
||||||||||||||||
U.S. |
$ | 4,948 | $ | 0.19 | $ | 5,566 | $ | 0.23 | ||||||||
Canada |
1,036 | 0.17 | 495 | 0.08 | ||||||||||||
Total ad valorem
taxes |
5,984 | 0.19 | 6,061 | 0.20 | ||||||||||||
Production and ad
valorem tax expense |
$ | 8,889 | $ | 0.28 | $ | 7,441 | $ | 0.25 | ||||||||
Fort Worth Basin production tax increases were due to a 22% increase in realized prices before
hedge settlements and a reduction in the number of new wells that qualified for exemptions or rate
reductions.
Depletion, Depreciation and Accretion
Three Months Ended June 30, | ||||||||||||||||
2010 | 2009 | |||||||||||||||
(In thousands, except per unit amounts) | ||||||||||||||||
Per | Per | |||||||||||||||
Depletion |
Mcfe | Mcfe | ||||||||||||||
U.S. |
$ | 30,411 | $ | 1.17 | $ | 32,809 | $ | 1.36 | ||||||||
Canada |
9,542 | 1.57 | 8,406 | 1.41 | ||||||||||||
Total depletion |
39,953 | 1.25 | 41,215 | 1.37 | ||||||||||||
Depreciation of other fixed assets |
||||||||||||||||
U.S. |
$ | 8,781 | $ | 0.34 | $ | 8,208 | $ | 0.34 | ||||||||
Canada |
1,160 | 0.19 | 994 | 0.17 | ||||||||||||
Total depreciation |
9,941 | 0.31 | 9,202 | 0.31 | ||||||||||||
Accretion |
775 | 0.03 | 549 | 0.01 | ||||||||||||
DD&A Expense |
$ | 50,669 | $ | 1.59 | $ | 50,966 | $ | 1.69 | ||||||||
Depletion expense for the 2010 quarter decreased slightly from the 2009 quarter due to a
decrease in our depletion rates. Higher production partially offset the depletion rate decrease,
as did the increase in Canadian depletion that resulted from changes in U.S.-Canadian dollar
exchange rates. Both our U.S. and Canadian depletion rates have been impacted by impairment
charges. During 2009, total U.S and Canadian impairment charges of $786.9 million and $192.7
million were recognized including $70.6 million in the 2009 quarter, which significantly reduced
the depletion rates.
General and Administrative Expense
Three Months Ended June 30, | ||||||||||||||||
2010 | 2009 | |||||||||||||||
(In thousands, except per unit amounts) | ||||||||||||||||
Per | Per | |||||||||||||||
General and administrative expense |
Mcfe | Mcfe | ||||||||||||||
Litigation settlement |
$ | - | $ | - | $ | 5,000 | $ | 0.17 | ||||||||
Cash expense |
12,143 | 0.38 | 14,849 | 0.49 | ||||||||||||
Equity compensation |
5,074 | 0.16 | 4,540 | 0.15 | ||||||||||||
Total general and administrative expense |
$ | 17,217 | $ | 0.54 | $ | 24,389 | $ | 0.81 | ||||||||
We recognized expense of $5.0 million for litigation settlement in the 2009 quarter, but had
none in the 2010 quarter. In addition, legal and professional fees decreased $2.4 million for the
2010 quarter, primarily as a result of resolution and conclusion of our litigation with BBEP in
April 2010.
32
Table of Contents
BBEP-Related Income
During the 2010 quarter, we recognized income of $23.2 million for equity earnings from our
investment in BBEP based upon its reported earnings for the quarter ended March 31, 2010 as
compared to income of $19.0 million recognized in the 2009 quarter. BBEP continues to experience
significant volatility in its net earnings due to changes in value of its derivative instruments
for which it does not employ hedge accounting.
Other Income (Expense) Net
In the 2010 quarter, we finalized settlement of our litigation against BBEP and received $18.0
million from BBEP and another third party. We also recognized a gain of $35.4 million from the
conveyance of 3.6 million BBEP common units as partial consideration in the acquisition of
additional working interests in our Lake Arlington Project in May 2010. See Notes 4 and 7 to the
condensed consolidated financial statements found in this quarterly report.
Interest Expense
Three Months Ended | ||||||||
June 30, | ||||||||
2010 | 2009 | |||||||
(in thousands) | ||||||||
Interest costs on debt outstanding |
$ | 42,392 | $ | 37,924 | ||||
Add: Non-cash interest (1) |
5,103 | 4,587 | ||||||
Loss on early debt extinguishment |
- | 27,122 | ||||||
Less: Interest capitalized |
(1,373 | ) | (1,552 | ) | ||||
Interest expense |
$ | 46,122 | $ | 68,081 | ||||
(1) Amortization of deferred financing costs and original issue discounts
Interest costs for the 2010 quarter were lower than the 2009 quarter primarily because of the
absence of $27.1 million of interest expense related to debt retirement. Settlements of our
interest rate swaps further reduced interest expense by $4.4 million in the 2010 quarter when
compared to the 2009 quarter.
Income Tax Expense
Three Months Ended | ||||||||
June 30, | ||||||||
2010 | 2009 | |||||||
Income tax (benefit) expense (in thousands) |
$ | 48,219 | $ | (18,897) | ||||
Effective tax rate |
34.7% | 48.0% |
Our provision for income taxes for the 2010 quarter increased from the 2009 quarter due to
higher income before taxes. The 48% effective tax rate for the 2009 quarter was the result of
reductions to deferred Texas Margin tax because of recognition of book impairment charges.
33
Table of Contents
RESULTS OF OPERATIONS Six Months Ended June 30, 2010 and 2009
The following discussion compares the results of operations for the six months ended June 30,
2010 and 2009, or the 2010 period and 2009 period, respectively.
Natural Gas, NGL and Crude Oil Revenue
Production Revenue:
Natural Gas | NGL | Oil and Condensate | Total | |||||||||||||||||||||||||||||
2010 | 2009 | 2010 | 2009 | 2010 | 2009 | 2010 | 2009 | |||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||
Texas |
$ | 156.1 | $ | 124.8 | $ | 78.4 | $ | 58.0 | $ | 6.2 | $ | 7.2 | $ | 240.7 | $ | 190.0 | ||||||||||||||||
Other U.S. |
1.5 | 0.2 | 0.4 | - | 4.8 | 3.3 | 6.7 | 3.5 | ||||||||||||||||||||||||
Hedging |
116.2 | 96.1 | (13.6 | ) | - | - | - | 102.6 | 96.1 | |||||||||||||||||||||||
Total U.S. |
273.8 | 221.1 | 65.2 | 58.0 | 11.0 | 10.5 | 350.0 | 289.6 | ||||||||||||||||||||||||
Alberta |
50.1 | 47.1 | 0.1 | 0.1 | - | - | 50.2 | 47.2 | ||||||||||||||||||||||||
British Columbia |
5.0 | - | - | - | - | - | 5.0 | - | ||||||||||||||||||||||||
Hedging |
8.0 | 46.1 | - | - | - | - | 8.0 | 46.1 | ||||||||||||||||||||||||
Total Canada |
63.1 | 93.2 | 0.1 | 0.1 | - | - | 63.2 | 93.3 | ||||||||||||||||||||||||
Total Company |
$ | 336.9 | $ | 314.3 | $ | 65.3 | $ | 58.1 | $ | 11.0 | $ | 10.5 | $ | 413.2 | $ | 382.9 | ||||||||||||||||
Average Daily Production Volumes:
Natural Gas | NGL | Oil and Condensate | Equivalent Total | |||||||||||||||||||||||||||||
2010 | 2009 | 2010 | 2009 | 2010 | 2009 | 2010 | 2009 | |||||||||||||||||||||||||
(MMcfd) | (Bbld) | (Bbld) | (MMcfed) | |||||||||||||||||||||||||||||
Texas |
189.5 | 173.1 | 11,514 | 14,072 | 467 | 911 | 261.4 | 263.0 | ||||||||||||||||||||||||
Other U.S. |
1.8 | 0.2 | 35 | 23 | 393 | 451 | 4.4 | 3.1 | ||||||||||||||||||||||||
Total U.S. |
191.3 | 173.3 | 11,549 | 14,095 | 860 | 1,362 | 265.8 | 266.1 | ||||||||||||||||||||||||
Alberta |
61.6 | 65.3 | 8 | 5 | - | 4 | 61.6 | 65.3 | ||||||||||||||||||||||||
British Columbia |
6.8 | - | - | - | - | - | 6.8 | - | ||||||||||||||||||||||||
Total Canada |
68.4 | 65.3 | 8 | 5 | - | 4 | 68.4 | 65.3 | ||||||||||||||||||||||||
Total Company |
259.7 | 238.6 | 11,557 | 14,100 | 860 | 1,366 | 334.2 | 331.4 | ||||||||||||||||||||||||
Average Realized Prices:
Natural Gas | NGL | Oil and Condensate | Equivalent Total | |||||||||||||||||||||||||||||
2010 | 2009 | 2010 | 2009 | 2010 | 2009 | 2010 | 2009 | |||||||||||||||||||||||||
(per Mcf) | (per Bbl) | (per Bbl) | (per Mcfe) | |||||||||||||||||||||||||||||
Texas |
$ | 4.55 | $ | 3.98 | $ | 37.63 | $ | 22.78 | $ | 73.30 | $ | 43.88 | $ | 5.09 | $ | 3.99 | ||||||||||||||||
Other U.S. |
4.52 | 3.42 | 66.51 | 14.11 | 67.78 | 40.18 | 8.41 | 6.13 | ||||||||||||||||||||||||
Hedging - U.S. |
3.36 | 3.06 | (6.51 | ) | - | - | - | 2.13 | 1.99 | |||||||||||||||||||||||
Total U.S. |
7.91 | 7.04 | 31.20 | 22.75 | 70.79 | 42.64 | 7.28 | 6.01 | ||||||||||||||||||||||||
Alberta |
4.49 | 3.99 | 68.69 | 58.49 | - | 47.25 | 4.50 | 3.99 | ||||||||||||||||||||||||
British Columbia |
4.09 | - | - | - | - | - | 4.09 | - | ||||||||||||||||||||||||
Hedging - Canada |
0.64 | 3.90 | - | - | - | - | 0.64 | 3.90 | ||||||||||||||||||||||||
Total Canada |
5.10 | 7.89 | 68.69 | 58.49 | - | 47.25 | 5.10 | 7.89 | ||||||||||||||||||||||||
Total Company |
$ | 7.17 | $ | 7.28 | $ | 31.23 | $ | 22.77 | $ | 70.79 | $ | 42.65 | $ | 6.83 | $ | 6.38 |
34
Table of Contents
The following table summarizes the changes in our production revenue during the 2010
period compared with the 2009 period:
Natural | ||||||||||||||||
Gas | NGL | Oil | Total | |||||||||||||
(In thousands) | ||||||||||||||||
Revenue for the six months ended June 30, 2009 |
$ | 314,225 | $ | 58,097 | $ | 10,547 | $ | 382,869 | ||||||||
Volume variance |
15,242 | (10,479 | ) | (3,910 | ) | 853 | ||||||||||
Hedge settlement variance |
(17,928 | ) | (13,613 | ) | - | (31,541 | ) | |||||||||
Price variance |
25,376 | 31,313 | 4,380 | 61,069 | ||||||||||||
Revenue for the six months ended June 30, 2009 |
$ | 336,915 | $ | 65,318 | $ | 11,017 | $ | 413,250 | ||||||||
Increases in 2010 period natural gas market prices compared to the 2009 period were partially
offset by a decrease in revenue from hedge settlements for the 2010 period as compared to the 2009
period. Canadian natural gas production increased primarily from new Horn River wells placed into
service during the last half 2009. An increase in U.S. natural gas volumes was the result of wells
purchased or placed into service after June 2009 partially offset by the 14.1 MMcfd decrease in
production from 27.5% of our Alliance properties sold in June 2009.
The increase in NGL revenue was due to increased market prices partially offset by payments
made to settle hedges during the 2010 period and an 18% decrease in Fort Worth Basin production for
the 2010 period compared to the 2009 period. NGL production decreased primarily because we have
focused our capital spending in areas of the Barnett Shale where dry natural gas is prevalent.
Utilization of derivatives to hedge our sales of natural gas, NGL and crude oil resulted in
realized prices that varied from market prices received from the sale our production. Our
production revenue from natural gas, NGL and oil production was $110.6 million and $142.2 million
higher because of our hedging activities for the 2010 period and the 2009 period, respectively.
We
expect our average production for the third and fourth quarters of 2010 to range between 365 MMcfed to 370
MMcfed and 395 MMcfed
to 405 MMcfed, respectively. We currently anticipate our average
production for all of 2010 will range between 355 MMcfed to 360 MMcfed.
Sales of Purchased Natural Gas and Costs of Purchased Natural Gas
Six Months Ended June 30, | ||||||||
2010 | 2009 | |||||||
(In thousands) | ||||||||
Sales of purchased natural gas: |
||||||||
Purchases from Eni |
$ | 26,565 | $ | 474 | ||||
Purchases from others |
6,480 | 4,743 | ||||||
Total |
33,045 | 5,217 | ||||||
Costs of purchased natural gas sold: |
||||||||
Purchases from Eni |
30,401 | 903 | ||||||
Purchases from others |
7,126 | 3,861 | ||||||
Unrealized valuation (gain) loss on |
||||||||
Gas Purchase Commitment |
(464 | ) | 3,818 | |||||
Total |
37,063 | 8,582 | ||||||
Net sales and purchases of natural gas |
$ | (4,018 | ) | $ | (3,365 | ) | ||
Our marketing activities related to the purchase and sale of natural gas have increased in
Texas. Our purchases and sales of natural gas made under the Gas Purchase Commitment began in June
2009 while the 2010 period includes six months of activity. The Gas Purchase Commitment is more
fully described in Note 2 to our condensed consolidated financial statements.
35
Table of Contents
Oil and Gas Production Expense
Six Months Ended June 30, | ||||||||||||||||
2010 | 2009 | |||||||||||||||
(In thousands, except per unit amounts) | ||||||||||||||||
Per | Per | |||||||||||||||
Texas |
Mcfe | Mcfe | ||||||||||||||
Cash expense |
$ | 49,614 | $ | 1.05 | $ | 43,062 | $ | 0.91 | ||||||||
Equity compensation |
429 | 0.01 | 515 | 0.01 | ||||||||||||
$ | 50,043 | $ | 1.06 | $ | 43,577 | $ | 0.92 | |||||||||
Other U.S. |
||||||||||||||||
Cash expense |
$ | 3,208 | $ | 3.98 | $ | 3,280 | $ | 5.79 | ||||||||
Equity compensation |
86 | 0.11 | 97 | 0.17 | ||||||||||||
$ | 3,294 | $ | 4.09 | $ | 3,377 | $ | 5.96 | |||||||||
Total U.S. |
||||||||||||||||
Cash expense |
$ | 52,822 | $ | 1.10 | $ | 46,342 | $ | 0.96 | ||||||||
Equity compensation |
515 | 0.01 | 612 | 0.01 | ||||||||||||
$ | 53,337 | $ | 1.11 | $ | 46,954 | $ | 0.97 | |||||||||
Alberta |
||||||||||||||||
Cash expense |
$ | 16,684 | $ | 1.50 | $ | 15,804 | $ | 1.34 | ||||||||
Equity compensation |
601 | 0.05 | 1,116 | 0.09 | ||||||||||||
$ | 17,285 | $ | 1.55 | $ | 16,920 | $ | 1.43 | |||||||||
British Columbia |
||||||||||||||||
Cash expense |
$ | 3,569 | $ | 2.92 | $ | - | $ | - | ||||||||
Equity compensation |
- | - | - | - | ||||||||||||
$ | 3,569 | $ | 2.92 | $ | - | $ | - | |||||||||
Total Canada |
||||||||||||||||
Cash expense |
$ | 20,253 | $ | 1.63 | $ | 15,804 | $ | 1.34 | ||||||||
Equity compensation |
601 | 0.05 | 1,116 | 0.09 | ||||||||||||
$ | 20,854 | $ | 1.68 | $ | 16,920 | $ | 1.43 | |||||||||
Total Company |
||||||||||||||||
Cash expense |
$ | 73,075 | $ | 1.21 | $ | 62,146 | $ | 1.03 | ||||||||
Equity compensation |
1,116 | 0.02 | 1,728 | 0.03 | ||||||||||||
$ | 74,191 | $ | 1.23 | $ | 63,874 | $ | 1.06 | |||||||||
The increase in U.S. production expense was primarily associated additional production from
new wells and the cost of operating additional compression in the Alliance area.
Canadian production expense for the 2010 period increased from the 2009 period due to expense
of $3.6 million to operate our Horn River wells in British Columbia that were placed into
production in the last half of 2009. Alberta production expense increased $0.4 million despite a
$1.7 million reduction of production expense incurred on a Canadian dollar-basis caused by changes
in U.S.-Canadian exchange rates for the 2010 period when compared to the 2009 period. The Canadian
dollar-basis expense decrease was primarily due to lower lease operating expense and processing
fees.
36
Table of Contents
Production and Ad Valorem Taxes
Six Months Ended June 30, | ||||||||||||||||
2010 | 2009 | |||||||||||||||
(In thousands, except per unit amounts) | ||||||||||||||||
Per | Per | |||||||||||||||
Production taxes |
Mcfe | Mcfe | ||||||||||||||
U.S. |
$ | 4,919 | $ | 0.10 | $ | 2,582 | $ | 0.05 | ||||||||
Canada |
348 | 0.03 | (96 | ) | (0.01 | ) | ||||||||||
Total production
taxes |
5,267 | 0.09 | 2,486 | 0.04 | ||||||||||||
Ad valorem taxes |
||||||||||||||||
U.S. |
$ | 10,462 | 0.22 | $ | 8,389 | 0.17 | ||||||||||
Canada |
1,643 | 0.13 | 932 | 0.08 | ||||||||||||
Total ad valorem
taxes |
12,105 | 0.20 | 9,321 | 0.16 | ||||||||||||
Production and ad
valorem tax expense |
$ | 17,372 | $ | 0.29 | $ | 11,807 | $ | 0.20 | ||||||||
Ad valorem tax increases were primarily because of the addition of wells and midstream
facilities placed into service in the Fort Worth Basin over the past twelve months and the
expiration of finite-lived tax abatements. Fort Worth Basin production tax increases were due to a
28% increase in realized prices before hedge settlements and a reduction in the number of new wells
that qualified for exemptions or rate reductions.
Depletion, Depreciation and Accretion
Six Months Ended June 30, | ||||||||||||||||
2010 | 2009 | |||||||||||||||
(In thousands, except per unit amounts) | ||||||||||||||||
Per | Per | |||||||||||||||
Depletion |
Mcfe | Mcfe | ||||||||||||||
U.S. |
$ | 56,845 | $ | 1.17 | $ | 74,681 | $ | 1.55 | ||||||||
Canada |
19,316 | 1.56 | 17,509 | 1.48 | ||||||||||||
Total depletion |
76,161 | 1.25 | 92,190 | 1.54 | ||||||||||||
Depreciation of other fixed assets |
||||||||||||||||
U.S. |
$ | 17,508 | $ | 0.36 | $ | 15,516 | $ | 0.32 | ||||||||
Canada |
2,243 | 0.18 | 1,818 | 0.15 | ||||||||||||
Total depreciation |
19,751 | 0.33 | 17,334 | 0.29 | ||||||||||||
Accretion |
1,514 | 0.03 | 1,138 | 0.01 | ||||||||||||
Total DD&A |
$ | 97,426 | $ | 1.61 | $ | 110,662 | $ | 1.84 | ||||||||
Depletion expense for the 2010 period decreased from the 2009 period due to a decrease in our
depletion rates. Increased production partially offset the effects of lower depletion rates, as
did a $2.7 million increase that resulted from changes in U.S.-Canadian dollar exchange rates.
Both our U.S. and Canadian depletion rates have been impacted by impairment charges. During 2009,
total U.S and Canadian impairment charges of $786.9 million and $192.7 million were recognized
during 2009, which significantly reduced the depletion rates.
The increase in U.S. depreciation for the 2010 period as compared to the 2009 period was
primarily associated with additions to U.S. field compression and midstream assets placed into
service since June 30, 2009.
37
Table of Contents
General and Administrative Expense
Six Months Ended June 30, | ||||||||||||||||
2010 | 2009 | |||||||||||||||
(In thousands, except per unit amounts) | ||||||||||||||||
Per | Per | |||||||||||||||
General and administrative expense |
Mcfe | Mcfe | ||||||||||||||
Litigation settlement |
$ | - | $ | - | $ | 5,000 | $ | 0.08 | ||||||||
Cash expense |
27,802 | 0.46 | 27,514 | 0.47 | ||||||||||||
Equity compensation |
9,938 | 0.16 | 9,256 | 0.15 | ||||||||||||
Total general and administrative expense |
$ | 37,740 | $ | 0.62 | $ | 41,770 | $ | 0.70 | ||||||||
We recognized $5.0 million for litigation settlement in the 2009 period, but had none in the
2010 period. Additionally, legal and professional fees decreased $2.8 million, primarily a result
of the resolution and conclusion of our litigation with BBEP in April 2010. Those decreases were
partially offset by higher compensation expense of $3.8 million, including a $0.7 million increase
in stock-based compensation expense.
BBEP-Related Income
During the 2010 period, we recognized income of $7.2 million for equity earnings from our
investment in BBEP based upon its reported earnings for the period ended March 31, 2010 as compared
to income of $121.1 million recognized in the 2009 period. BBEP continues to experience
significant volatility in its net earnings due to changes in value of its derivative instruments
for which it does not employ hedge accounting.
For the 2009 period, we performed an impairment analysis that utilized the March 31, 2009
closing price of $6.53 per BBEP unit, which resulted in an aggregate fair value of $139.4 million
for the portion of BBEP units that we owned. The estimated fair value of our investment in BBEP
was $102.1 million less than the $241.5 million carrying value of our investment in BBEP. The
$102.1 million difference was recognized as an impairment charge during the 2009 period. A similar
analysis was performed as of June 30, 2010, which resulted in no further impairment. Note 5 to the
condensed consolidated financial statements contains additional information regarding our
investment in BBEP.
Other Income (Expense) Net
In the 2010 quarter, we finalized settlement of our litigation against BBEP and received $18.0
million from BBEP and another third party. We also recognized a gain of $35.4 million from the
conveyance of 3.6 million BBEP common units as consideration in the acquisition of additional
working interests in our Lake Arlington Project in May 2010. See Notes 4 and 7 to the condensed
consolidated financial statements found in this quarterly report.
Interest Expense
Six Months Ended June 30, | ||||||||
2010 | 2009 | |||||||
(in thousands) | ||||||||
Interest costs on debt outstanding |
$ | 83,267 | $ | 75,297 | ||||
Add: Non-cash interest (1) |
10,178 | 8,726 | ||||||
Loss on early debt extinguishment |
- | 27,122 | ||||||
Less: Interest capitalized |
(2,806 | ) | (2,863 | ) | ||||
Interest expense |
$ | 90,639 | $ | 108,282 | ||||
(1) Amortization of deferred financing costs and original issue discounts
Interest costs for the 2010 period were lower than the 2009 period primarily because of the
absence of $27.1 million of expense related to the June 2009 early retirement of a portion of our
debt. Settlements of our interest rate swaps further reduced interest expense by $10.8 million in
the 2010 period.
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Income Tax Expense
Six Months Ended June 30, | ||||||||
2010 | 2009 | |||||||
Income tax (benefit) expense (in
thousands) |
$ | 53,301 | $ | (316,720 | ) | |||
Effective tax rate |
34.5% | 35.0% |
Our provision for income taxes for the 2010 period increased from the 2009 period due to
higher income before taxes. The effective tax rate for the 2010 period was 34.5%, which we expect
to be our effective income tax rate for all of 2010.
Outlook for the Remainder of 2010
Upon closing of the Crestwood Transaction, our consolidated expense will change from our 2010
historical trends because of the absence of KGS intercompany revenue earned from gathering and
processing production and KGS operating expense. Beginning with our September 30, 2010 Quarterly
Report on Form 10-Q, all prior historical financial results will reflect KGS as discontinued
operations. The following summarizes, on a Mcfe-basis, historical and pro forma operating expense
and other costs for the six months ended June 30, 2010 and their projected equivalents for the
remaining six months of 2010.
Six Months Ended | ||||||||||||
June 30, 2010 | ||||||||||||
As | Remainder | |||||||||||
Reported | Pro Forma (1) | 2010 (2) | ||||||||||
(Per Mcfe) | ||||||||||||
Oil and gas production expense |
$ | 1.23 | $ | 1.79 | $ | 1.65 to $1.70 | ||||||
Production and ad valorem taxes |
0.29 | 0.24 | $ | 0.22 to $0.25 | ||||||||
DD&A |
1.61 | 1.43 | $ | 1.40 to $1.45 | ||||||||
General and administrative |
0.62 | 0.59 | $ | 0.45 to $0.50 | ||||||||
Interest expense |
1.50 | 1.34 | $ | 1.24 to $1.28 | ||||||||
5.25 | 5.39 | $ | 4.96 to $5.18 | |||||||||
Income tax benefit on the above |
(1.84 | ) | (1.89 | ) | ($1.74 to $1.81) | |||||||
Net income attributable to
noncontrolling interests |
0.11 | - | - | |||||||||
Net loss from the above
attributable to Quicksilver |
$ | 3.52 | $ | 3.50 | $ | 3.22 to $3.37 | ||||||
(1) | Assumes that the historical as reported expenses reflect KGS financial results as discontinued operations and that the interest expense from the Senior Secured Credit Facility is eliminated from the beginning of 2010. | ||
(2) | Remainder of 2010 reflects the elimination of the interest on our Senior Secured Credit Facility beginning on October 1, 2010. |
Quicksilver Resources Inc. and its Restricted Subsidiaries
Note 11 to our condensed consolidated financial statements contains information about the
Company and its restricted and unrestricted subsidiaries.
The combined results of operations for the Company and its restricted subsidiaries differ from
our consolidated results of operations to the extent our U.S. oil and gas properties are charged by
KGS for gathering and processing of natural gas. KGS revenue is eliminated to the extent KGS
revenue is charged to our U.S. oil and gas properties, which are identified in the combined results
of operations and discussed above under Results of Operations. The combined financial position of
the Company and its restricted subsidiaries and our consolidated financial position are materially
the same except for the property, plant and equipment purchased by the unrestricted subsidiaries
since the KGS initial public offering, the borrowings under the KGS Credit Facility and the equity
of the unrestricted subsidiaries. The other balance sheet items are discussed below in Financial
Position. The combined operating cash flows, financing cash flows and investing cash flows for
the Company and its restricted subsidiaries are substantially similar to our consolidated operating
cash flows, financing cash flows and investing cash flows, which are discussed below in Liquidity,
Capital Resources and Financial Condition. Upon completion of the Crestwood Transaction, we expect
our consolidated results of operations, consolidated financial position and cash flows will be
similar to our combined results of operations, consolidated financial position and cash flows for
the Company and its restricted subsidiaries.
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Table of Contents
LIQUIDITY, CAPITAL RESOURCES AND FINANCIAL CONDITION
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, NGL 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 market prices for
natural gas, NGL and oil 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 significantly affected by instability in the credit
and financial markets.
Six Months Ended June 30, | ||||||||
2010 | 2009 | |||||||
(In thousands) |
||||||||
Net cash provided by operating activities |
$ | 246,507 | $ | 310,341 | ||||
Net cash used for investing activities |
(355,538 | ) | (207,696 | ) | ||||
Net cash provided by (used for) financing
activities |
111,225 | (104,961 | ) | |||||
Effect of exchange rate changes in cash |
(671 | ) | 125 |
Operating Cash Flows
Net cash provided by operations for the 2010 period decreased $63.8 million from the
comparable 2009 period. Significant decreases include a $116.5 million decrease in cash receipts for settlements of
commodity derivatives and a $34.3 million decrease in cash receipts
from income tax refunds. Partially offsetting these
decreases was the $18.0 million cash receipt for resolution of our BBEP litigation, improvements due to a $27.3 million
decrease in interest payments, net of interest swap settlements, and additional revenue of $30.3 million from higher
production volumes and prices for the 2010 period compared to the 2009 period.
For the remainder of 2010 through 2015, price collars and swaps hedge a portion of our
anticipated natural gas and NGL production. The following summarizes future production hedged with
commodity derivatives:
Daily Production | ||||||||
Year | Gas | NGL | ||||||
MMcfd | Bbld | |||||||
2010 |
200 | 10 | ||||||
2011 |
150 | 8 | ||||||
2012 |
90 | - | ||||||
2013 |
30 | - | ||||||
2014 |
30 | - | ||||||
2015 |
30 | - |
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Investing Cash Flows
Our expenditures for property and equipment (payments for property and equipment plus non-cash
changes in working capital associated with property and equipment) consisted of the following:
Six Months Ended June 30, | ||||||||
2010 | 2009 | |||||||
(In thousands) | ||||||||
Exploration and development: |
||||||||
Texas |
$ | 316,160 | $ | 209,208 | ||||
Other U.S. |
6,405 | 18,723 | ||||||
Total U.S. |
322,565 | 227,931 | ||||||
British Columbia |
25,585 | 33,972 | ||||||
Alberta |
9,245 | 22,216 | ||||||
Total Canada |
34,830 | 56,188 | ||||||
Total exploration and development |
357,395 | 284,119 | ||||||
Midstream - Texas |
36,857 | 48,280 | ||||||
Corporate and field office |
4,084 | 2,106 | ||||||
Total plant and equipment costs incurred |
$ | 398,336 | $ | 334,505 | ||||
Our capital expenditures for the 2010 period, excluding the $125.2 million acquisition of
additional working interests in our Lake Arlington Project, have decreased from the 2009 period
principally due to a reduction of our expenditures for development of our Barnett Shale and
Canadian CBM properties of $18.4 million and $13.0 million, respectively. Expenditures for
exploration in the Horn River and Greater Green River Basins decreased by $8.4 million and $12.3
million, respectively. Midstream capital expenditures, primarily through KGS, have been reduced
$11.4 million for the 2010 period as compared to the 2009 period. We currently expect to spend
approximately $450 million for capital expenditures, exclusive of acquisitions, for 2010.
Financing Cash Flows
During the 2010 period, we have increased borrowings under our Senior Secured Credit Facility
$29.0 million while KGS has increased borrowings $101 million under the KGS Credit Facility.
Increased borrowings under our Senior Secured Credit Facility were primarily the result of the
timing of capital expenditures, including $70.8 million for additional working interests in our
Lake Arlington project. Changes in U.S.-Canadian exchange rates reduced the outstanding balance
under the Canadian portion of the Senior Secured Credit Facility by $3.4 million. Borrowings under
the KGS Credit Facility increased primarily as a result of the $84.4 million purchase of the
Alliance Midstream Assets from us. As a result of our borrowings under the Senior Secured Credit
Facility and KGS Credit Facility, we had $493 million and $227 million, respectively, outstanding
at June 30, 2010. The lenders under our Senior Secured Credit Facility re-affirmed our $1.0
billion borrowing base in May 2010.
Crestwood Transaction and Proceeds
We expect that the $701 million of proceeds from the Crestwood Transaction will be utilized to
completely repay outstanding borrowings under the Senior Secured Credit Facility, to fund our
fourth quarter income tax liability of approximately $130 million and to pay for
transaction-related costs.
Financial Position
The following summarizes the significant changes to our balance sheet as of June 30, 2010, as
compared to our December 31, 2009 balance sheet:
| Our current and non-current derivative assets and liabilities increased $94.6 million on a net basis. The valuation of our remaining open derivative positions increased $168.0 million as a result of natural gas price decreases relative to our commodity derivative pricing during the 2010 period and the addition of derivatives during 2010 that hedge anticipated 2011 through 2015 natural gas production |
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and 2011 anticipated NGL production. Additonally, valuation of our interest rate swaps increased $9.1 million. Monthly settlements of $82.6 million received during the 2010 period partially offset these increases. |
| Our net property, plant and equipment balance increased $297.0 million over the six-month period ended June 30, 2010. During the 2010 period, we have incurred $125.2 million for the acquisition of additional working interests in our Lake Arlington Project and $273.1 million for ongoing exploration and development activities and midstream expansion that have been partially offset by DD&A of $95.9 million and the effects of changes in U.S.-Canadian exchange rates from December 31, 2009 to June 30, 2010. |
| Our net deferred tax position asset has decreased $60.0 million as a result of U.S. income before income taxes for the six-month period ended June 30, 2010. |
Contractual Obligations and Commercial Commitments
As of June 30, 2010, our estimates of Eni Production covered by the Gas Purchase Commitment
have been reduced 3.3 Bcf from December 31, 2009 estimates. At June 30, 2010, we estimated a
remaining liability of $33.7 million, including an embedded derivative liability of $6.2 million. Valuation of the liability was based on the most recent estimate of 2010 Eni Production volumes and
natural gas prices at June 30, 2010.
In April 2010, Quicksilver entered into a lease of office space with a term of 12 years that
is scheduled to commence August 2010. Aggregate rentals over the life of the lease will total
$29.8 million.
In June 2010, we structured a portion of the credit support for our surety bonds to include a
$15.0 million cash deposit. We have the option to replace the cash deposit with a letter of credit
in the future. As of July 2010, our letters of credit were reduced to $25.2 million, which
includes $13.9 million issued in support of surety bonds.
There have been no other significant changes to our contractual obligations and commercial
commitments as disclosed in Item 7 in our 2009 Annual Report on Form 10-K.
Critical Accounting Estimates
Managements 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 2009 Annual Report on Form 10-K. These critical
estimates, for which no significant changes occurred during the six months ended June 30, 2010,
include estimates and assumptions for:
|
oil and gas reserves full cost ceiling calculations derivative instruments | |
stock-based compensation income taxes |
These estimates and assumptions are based upon what we believe is the best information
available at the time of the estimates or assumptions. The estimates and assumptions could change
materially as conditions within and beyond our control change. Accordingly, actual results could
differ materially from those estimates.
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
No pronouncements materially affecting our financial statements have been issued since the
filing of our 2009 Annual Report on Form 10-K.
42
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ITEM 3. Quantitative and Qualitative Disclosures About Market Risk
We have established policies and procedures for managing risk within our organization,
including internal controls. The level of risk assumed by us is based on our objectives and
capacity to manage risk.
Our primary risk exposure is from fluctuations in natural gas, oil and NGL commodity prices. We have mitigated the risk of adverse price movements with swaps and collars; however, we have also
limited future gains from favorable price movements.
Commodity Price Risk
Item 2 contains additional information regarding our hedging positions as of June 30, 2010.
Utilization of our hedging program may result in natural gas, NGL and crude oil realized
prices varying from market prices that we receive from the sale of natural gas, NGL and crude oil. Our revenue from natural gas, NGL and crude oil production was $110.6 million and $142.2 million
higher because of our hedging program for the 2010 period and 2009 period, respectively. Other
revenue was $1.6 million and $1.7 million lower as a result of derivative and hedging
ineffectiveness for the 2010 period and 2009 period, respectively.
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The following table lists our commodity derivative positions as of June 30, 2010:
Weighted Avg | ||||||||||||||
Remaining Contract | Price Per Mcf or | |||||||||||||
Product | Type | Period | Volume | Bbl | Fair Value | |||||||||
(In thousands) | ||||||||||||||
Gas |
Collar | Jul 2010-Dec 2010 | 20 MMcfd | $ | 8.00-11.00 | $ | 11,713 | |||||||
Gas |
Collar | Jul 2010-Dec 2010 | 20 MMcfd | 8.00-11.00 | 11,713 | |||||||||
Gas |
Collar | Jul 2010-Dec 2010 | 20 MMcfd | 8.00-12.20 | 11,767 | |||||||||
Gas |
Collar | Jul 2010-Dec 2010 | 20 MMcfd | 8.00-12.20 | 11,767 | |||||||||
Gas |
Collar | Jul 2010-Dec 2010 | 20 MMcfd | 8.50-12.05 | 13,570 | |||||||||
Gas |
Collar | Jul 2010-Dec 2010 | 10 MMcfd | 8.50-12.05 | 6,785 | |||||||||
Gas |
Collar | Jul 2010-Dec 2010 | 10 MMcfd | 8.50-12.08 | 6,790 | |||||||||
Gas |
Collar | Jul 2010-Dec 2011 | 10 MMcfd | 6.00- 7.00 | 5,501 | |||||||||
Gas |
Collar | Jul 2010-Dec 2011 | 10 MMcfd | 6.00- 7.00 | 5,501 | |||||||||
Gas |
Collar | Jul 2010-Dec 2011 | 20 MMcfd | 6.00- 7.00 | 11,001 | |||||||||
Gas |
Collar | Jul 2010-Dec 2012 | 20 MMcfd | 6.50- 7.15 | 22,576 | |||||||||
Gas |
Collar | Jul 2010-Dec 2012 | 20 MMcfd | 6.50- 7.18 | 22,671 | |||||||||
Gas |
Collar | Jan 2011-Dec 2011 | 10 MMcfd | 6.25- 7.50 | 4,094 | |||||||||
Gas |
Collar | Jan 2011-Dec 2011 | 10 MMcfd | 6.25- 7.50 | 4,094 | |||||||||
Gas |
Collar | Jan 2011-Dec 2011 | 20 MMcfd | 6.25- 7.50 | 8,187 | |||||||||
Gas |
Collar | Jan 2012-Dec 2012 | 20 MMcfd | 6.50- 8.01 | 8,026 | |||||||||
Gas |
Basis | Jul 2010-Dec 2010 | 20 MMcfd | (1) | 1,328 | |||||||||
Gas |
Basis | Jul 2010-Dec 2010 | 20 MMcfd | (1) | 1,328 | |||||||||
Gas |
Basis | Jul 2010-Dec 2010 | 20 MMcfd | (2) | 229 | |||||||||
Gas |
Basis | Jul 2010-Dec 2010 | 10 MMcfd | (2) | 197 | |||||||||
Gas |
Basis | Jul 2010-Dec 2010 | 10 MMcfd | (2) | 202 | |||||||||
Gas |
Basis | Jan 2011-Dec 2011 | 20 MMcfd | (1) | 1,825 | |||||||||
Gas |
Basis | Jan 2011-Dec 2011 | 10 MMcfd | (1) | 912 | |||||||||
Gas |
Basis | Jan 2011-Dec 2011 | 10 MMcfd | (1) | 912 | |||||||||
Gas |
Swap | Jan 2011-Dec 2015 | 10 MMcfd | $ | 6.00 | 2,331 | ||||||||
Gas |
Swap | Jan 2011-Dec 2015 | 20 MMcfd | 6.00 | 4,662 | |||||||||
NGL |
Swap | Jul 2010-Dec 2010 | 2 MBbld | 32.65 | (490 | ) | ||||||||
NGL |
Swap | Jul 2010-Dec 2010 | 3 MBbld | 32.98 | (552 | ) | ||||||||
NGL |
Swap | Jul 2010-Dec 2010 | 1 MBbld | 33.63 | (65 | ) | ||||||||
NGL |
Swap | Jul 2010-Dec 2010 | 1 MBbld | 34.15 | 31 | |||||||||
NGL |
Swap | Jul 2010-Dec 2010 | 3 MBbld | 34.22 | 132 | |||||||||
NGL |
Swap | Jan 2011-Dec 2011 | 3 MBbld | 36.06 | 3,025 | |||||||||
NGL |
Swap | Jan 2011-Dec 2011 | 2 MBbld | 36.31 | 2,195 | |||||||||
NGL |
Swap | Jan 2011-Dec 2011 | 3 MBbld | 41.95 | 9,436 | |||||||||
Total | $ | 193,394 | ||||||||||||
(1) | AECO Basis swaps hedge the AECO basis adjustment for 40 MMcfd at a deduction of $0.45 per Mcf from NYMEX for the remainder of 2010 and 40 MMcfd at a deduction of $0.39 Mcf from NYMEX for 2011. | |
(2) | Basis swaps for 40 MMcfd hedge the Houston Ship Channel basis adjustment at a weighted average deduction of $0.067 Mcf from NYMEX for the remainder of 2010. |
We have entered into no new commodity derivatives positions since June 30, 2010.
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We also have recorded a liability for the Gas Purchase Commitment, which is more fully
described in Note 2 to the condensed consolidated financial statements.
Interest Rate Risk
In February 2010, we executed the early settlement of our 2009 interest rate swaps that hedged
our senior notes due 2015 and our senior subordinated notes. We received cash of $18.0 million in the settlement, including $3.7 million for interest previously earned unsettled
amounts, and recognized an adjustment of $14.3 million to the carrying value of the debt. In May 2010, we executed an early settlement of a portion of our 2010 interest rate swaps that hedged our
senior notes due 2015 and our senior subordinated notes. We received cash of $6.8 million in the settlement, including $2.4 million for interest previously accrued and earned,
and recognized an additional adjustment of $4.4 million to the carrying value of the debt. The $18.7 million from these early settlements will be recognized as a reduction of interest expense
over the life of the associated underlying debt instruments. We have subsequently recognized $0.9 million as a reduction of interest expense in 2010.
Our remaining interest rate swaps were entered into during February 2010 and cover $295
million of our senior notes due 2015 and $155 million of our senior subordinated notes. The remaining 2010 interest rate swaps convert the interest paid on those issues from a fixed to a
floating rate indexed to six-month LIBOR. The maturity dates and all other significant terms are the same as those of the underlying debt. As a result, these remaining 2010 interest rate swaps
qualified for hedge accounting treatment as fair value hedges. The value of the remaining 2010 interest rate swaps, excluding the net interest accrual, amounted to a net asset of $13.2 million
as of June 30, 2010. The offsetting fair value adjustment to the debt hedged decreased the carrying value of the debt. There was no ineffectiveness recorded in connection with the fair
value hedges.
For the 2010 period and 2009 period, interest expense decreased $11.5 million and $0.8
million, respectively, because of our open and settled interest rate swaps.
In July 2010, we executed the early settlement of our remaining 2010 interest rate swaps. We
received cash of $16.7 million, including $4.6 million for interest previously accrued and earned. We will recognize the remaining $12.1 million as an adjustment to the carrying value of the debt
that will be recognized as a reduction of interest expense over the life of the associated underlying debt instruments.
The fair value of all derivative instruments included in these disclosures was estimated using
prices quoted in active 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.
ITEM 4. Controls and Procedures
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
We carried out an evaluation, under the supervision and with the participation of management,
including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the
design and operation of our disclosure controls and procedures as of the end of the period covered
by this report pursuant to Securities Exchange Act Rule 13a-15. Based upon that evaluation, our
Chief Executive Officer and Chief Financial Officer concluded that, as of June 30, 2010, our
disclosure controls and procedures were effective 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 SECs 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
There has been no change in our internal control over financial reporting during the quarter
ended June 30, 2010 that has materially affected, or is reasonably likely to materially affect, our
internal control over financial reporting.
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PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings
On April 5, 2010, we entered into a global settlement agreement with BBEP and all parties to
the BBEP litigation disclosed in our 2009 Annual Report on Form 10-K on the same terms as the February 3, 2010 settlement agreement disclosed in our 2009 Annual Report on Form 10-K. Pursuant
to that agreement, the District Court entered its Final Judgment and Order of Dismissal on April 6, 2010.
There have been no other material changes in legal proceedings from those described in Part I,
Item 3 included in our 2009 Annual Report on Form 10-K.
ITEM 1A. Risk Factors
There have been no material changes in the risk factors from those described in Item 1A of our
2009 Annual Report on Form 10-K with the exception of the addition of risk factors related to the proposed Crestwood Transaction. Some of the risks which may be relevant to us include:
The Crestwood Transaction purchase agreement limits our ability to pursue alternatives to sell our
interest in KGS to Crestwood.
The Crestwood Transaction purchase agreement contains provisions that make it more difficult
for us to sell our interests in KGS to a party other than Crestwood. These provisions include a
general prohibition on us soliciting alternative transactions with respect to a sale of our
interests in KGS. Further, there are only limited circumstances that permit us to respond to, and
negotiate with a third party making an unsolicited offer that our board of directors reasonably
believes would be expected to lead to a superior proposal for our interests in KGS. Although we
can terminate the Crestwood Transaction purchase agreement to enter into such a proposal so long as
it complies with certain notice and other conditions set forth in the
Crestwood Transaction purchase agreement, we will be required to pay Crestwood a termination fee of $23.3 million and reimbursement of expenses up to a specified limit.
While we believe these provisions are reasonable and not preclusive of other offers, the
provisions might discourage a third party that has an interest in acquiring all or a significant
part of our interests in KGS from considering or proposing that acquisition, even if that party
were prepared to pay consideration with a higher value than the currently proposed purchase
consideration.
Failure to complete the sale of our interests in KGS could negatively impact our stock price and
future business and financial results.
If the Crestwood Transaction is not completed, our ongoing business may be adversely affected
and, without realizing any of the benefits of the Crestwood Transaction, we would be subject to a
number of risks, including the following:
| we may experience negative reactions from the financial markets; |
| we will be required to pay certain costs relating to the Crestwood Transaction, whether or not the sale is completed; and, |
| we will not be able to repay our outstanding borrowing under the Senior Secured Credit Facility or deploy proceeds toward exploration and development activities. |
There can be no assurance that the risks described above will not materialize, and if any of
them do, they may adversely affect our stock price, business and financial results.
In order to complete the Crestwood Transaction, we and Crestwood must obtain certain governmental
approvals, and if such approvals are not granted, the completion of the Crestwood Transaction may
be jeopardized.
Completion of the Crestwood Transaction is conditioned upon the expiration or termination of
the applicable waiting period relating to the transaction under the Hart-Scott-Rodino Antitrust
Improvements Act of 1976, as amended, or HSR Act. Although Quicksilver and Crestwood have agreed
in the Crestwood Transaction purchase agreement to use their reasonable best efforts to obtain
approval under the HSR Act, there can be no assurance that these approvals will be obtained.
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ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds
Issuer Purchases of Equity Securities
The following table summarizes our repurchases of Quicksilver common stock during the quarter
ended June 30, 2010.
Total Number of | Maximum Number of | |||||||||||||||
Total Number | Shares Purchased as | Shares that May Yet | ||||||||||||||
of Shares | Average Price | Part of Publicly | Be Purchased Under | |||||||||||||
Period | Purchased (1) | Paid per Share | Announced Plan(2) | the Plan(2) | ||||||||||||
April 2010 |
869 | $ | 13.87 | - | - | |||||||||||
May 2010 |
218 | $ | 13.87 | - | - | |||||||||||
June 2010 |
2,006 | $ | 11.09 | - | - | |||||||||||
Total |
3,093 | $ | 12.07 | - | - |
(1) | Represents shares of common stock surrendered by employees to satisfy our income tax withholding obligations arising upon the vesting of restricted stock issued under our Amended and Restated 2006 Equity Plan. | |
(2) | We do not currently have in place any publicly announced, specific plans or programs to purchase equity securities. |
ITEM 3. Defaults Upon Senior Securities
None.
ITEM 4. [Removed and Reserved]
ITEM 5. Other Information
None.
ITEM 6. Exhibits:
Exhibit No. | Description | |
10.1
|
Asset Purchase Agreement, dated May 11, 2010, between Marshall R. Young Oil Co., as Seller, and Quicksilver Resources Inc., as Buyer (filed as Exhibit 10.1 to the Companys Form 8-K filed May 12, 2010 and included herein by reference) | |
* 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 |
* | Filed herewith |
47
Table of Contents
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Dated: August 9, 2010
Quicksilver Resources Inc. |
|||||
By: |
/s/ Philip Cook | ||||
Philip Cook Senior Vice President - Chief Financial Officer |
48
Table of Contents
EXHIBIT INDEX
Exhibit No. | Description | |
10.1
|
Asset Purchase Agreement, dated May 11, 2010, between Marshall R. Young Oil Co., as Seller, and Quicksilver Resources Inc., as Buyer (filed as Exhibit 10.1 to the Companys Form 8-K filed May 12, 2010 and included herein by reference) | |
* 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 |
* | Filed herewith |
49