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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 September 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) |
801 Cherry Street, Suite 3700, Unit 19, Fort Worth, Texas | 76102 | |
(Address of principal executive offices) | (Zip Code) |
(817) 665-5000
(Registrant’s telephone number, including area code)
(Registrant’s telephone number, including area code)
777 West Rosedale, Fort Worth, Texas, 76104
(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. Yesþ Noo
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). Yesþ Noo
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 filerþ | Accelerated filero | Non-accelerated filero | Smaller reporting companyo | |||
(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). Yeso Noþ
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:
Title of Class | Outstanding as of October 22, 2010 | |
Common Stock, $0.01 par value | 170,316,266 |
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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 our oil and natural gas operations 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 Holdings LLC
“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 theFASB 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
“HCDS” means Hill County Dry System
“KGS” means Quicksilver Gas Services LP, a publicly traded partnership, which we formerly owned that traded under the ticker symbol of “KGS” and subsequent to the Crestwood Transaction renamed itself Crestwood Midstream Partners LP and trades under the ticker symbol “CMLP”
“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 the Lake Arlington area of Tarrant County that we have developed and also includes an additional 25% working interest we purchased on May 11, 2010
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“Mercury” means Mercury Exploration Company, which is owned by members of the Darden family
“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
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QUICKSILVER RESOURCES INC.
INDEX TO FORM 10-Q
For the Period Ending September 30, 2010
INDEX TO FORM 10-Q
For the Period Ending September 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.
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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; | ||
• | failure to receive a proposal for a transaction to pursue strategic alternatives for us or that any transaction will be approved or consummated; | ||
• | costs and expenses associated with our consideration of potential strategic alternatives, including without limitation, any related litigation expense; 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 and8-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.
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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 Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Revenue | ||||||||||||||||
Natural gas, NGL and oil | $ | 218,249 | $ | 198,287 | $ | 631,499 | $ | 581,156 | ||||||||
Sales of purchased natural gas | 16,982 | 5,964 | 50,027 | 11,181 | ||||||||||||
Other | 2,469 | 2,406 | 6,902 | 6,293 | ||||||||||||
Total revenue | 237,700 | 206,657 | 688,428 | 598,630 | ||||||||||||
Operating expense | ||||||||||||||||
Oil and gas production expense | 39,402 | 29,064 | 113,593 | 92,938 | ||||||||||||
Production and ad valorem taxes | 9,170 | 6,630 | 26,542 | 18,437 | ||||||||||||
Costs of purchased natural gas | 14,638 | 2,964 | 51,701 | 11,546 | ||||||||||||
Other operating costs | 1,320 | 2,066 | 3,544 | 5,337 | ||||||||||||
Depletion, depreciation and accretion | 52,542 | 44,548 | 149,968 | 155,210 | ||||||||||||
General and administrative | 24,005 | 17,682 | 61,745 | 59,452 | ||||||||||||
Total expense | 141,077 | 102,954 | 407,093 | 342,920 | ||||||||||||
Impairment expense | (31,531 | ) | - | (31,531 | ) | (967,126 | ) | |||||||||
Operating income (loss) | 65,092 | 103,703 | 249,804 | (711,416 | ) | |||||||||||
Income (loss) from earnings of BBEP - net | 17,024 | (43,685 | ) | 24,203 | (24,669 | ) | ||||||||||
Other income (expense) - net | 14,253 | (645 | ) | 67,646 | (739 | ) | ||||||||||
Interest expense | (51,532 | ) | (41,619 | ) | (142,171 | ) | (149,901 | ) | ||||||||
Income (loss) before income tax | 44,837 | 17,754 | 199,482 | (886,725 | ) | |||||||||||
Income tax (expense) benefit | (18,268 | ) | (15,595 | ) | (71,569 | ) | 301,125 | |||||||||
Net income (loss) | 26,569 | 2,159 | 127,913 | (585,600 | ) | |||||||||||
Net income attributable to noncontrolling interests | (4,766 | ) | (1,429 | ) | (11,119 | ) | (4,411 | ) | ||||||||
Net income (loss) attributable to Quicksilver | $ | 21,803 | $ | 730 | $ | 116,794 | $ | (590,011 | ) | |||||||
Other comprehensive income (loss), net of income tax | ||||||||||||||||
Reclassification adjustments related to settlements of derivative contracts | (45,356 | ) | (63,196 | ) | (117,714 | ) | (160,183 | ) | ||||||||
Net change in derivative fair value | 59,217 | 1,030 | 171,910 | 113,333 | ||||||||||||
Foreign currency translation adjustment | 6,993 | 11,937 | 4,238 | 18,719 | ||||||||||||
Comprehensive income (loss) | $ | 42,657 | $ | (49,499 | ) | $ | 175,228 | $ | (618,142 | ) | ||||||
Income (loss) per common share - basic | 0.13 | - | 0.69 | (3.49 | ) | |||||||||||
Income (loss) per common share - diluted | 0.13 | - | 0.68 | (3.49 | ) | |||||||||||
Basic weighted average shares outstanding | 170,307 | 169,021 | 170,242 | 168,917 | ||||||||||||
Diluted weighted average shares outstanding | 171,037 | 170,657 | 180,847 | 168,917 |
The accompanying notes are an integral part of these condensed consolidated financial statements.
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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
September 30, | December 31, | |||||||
2010 | 2009 | |||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 15,078 | $ | 1,037 | ||||
Accounts receivable - net of allowance for doubtful accounts | 35,757 | 63,738 | ||||||
Derivative assets at fair value | 142,389 | 97,957 | ||||||
Other current assets | 32,663 | 54,652 | ||||||
Total current assets | 225,887 | 217,384 | ||||||
Investment in BBEP | 95,124 | 112,763 | ||||||
Property, plant and equipment | ||||||||
Oil and gas properties, full cost method (including unevaluated costs of $404,783 and $458,037, respectively) | 2,707,785 | 2,338,244 | ||||||
Other property and equipment | 205,903 | 204,601 | ||||||
Property, plant and equipment - net | 2,913,688 | 2,542,845 | ||||||
Assets of midstream operations held for sale | 561,924 | 548,508 | ||||||
Derivative assets at fair value | 84,870 | 14,427 | ||||||
Deferred income taxes | 45,179 | 133,051 | ||||||
Other assets | 37,447 | 43,904 | ||||||
$ | 3,964,119 | $ | 3,612,882 | |||||
LIABILITIES AND EQUITY | ||||||||
Current liabilities | ||||||||
Accounts payable | $ | 113,509 | $ | 149,766 | ||||
Accrued liabilities | 109,897 | 153,598 | ||||||
Derivative liabilities at fair value | - | 395 | ||||||
Deferred income taxes | 51,598 | 51,675 | ||||||
Total current liabilities | 275,004 | 355,434 | ||||||
Long-term debt | 2,396,705 | 2,302,123 | ||||||
Liabilities of midstream operations held for sale | 267,117 | 148,191 | ||||||
Asset retirement obligations | 52,435 | 48,472 | ||||||
Other liabilities | 28,461 | 20,691 | ||||||
Deferred income taxes | 50,988 | 41,149 | ||||||
Commitments and contingencies (Note 8) | - | - | ||||||
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; 175,543,699 and 174,469,836 shares issued, respectively | 1,755 | 1,745 | ||||||
Paid in capital in excess of par value | 753,944 | 730,265 | ||||||
Treasury stock of 5,046,039 and 4,704,448 shares, respectively | (41,428 | ) | (36,363 | ) | ||||
Accumulated other comprehensive income | 179,770 | 121,336 | ||||||
Retained deficit | (64,191 | ) | (180,985 | ) | ||||
Quicksilver stockholders’ equity | 829,850 | 635,998 | ||||||
Noncontrolling interests | 63,559 | 60,824 | ||||||
Total equity | 893,409 | 696,822 | ||||||
$ | 3,964,119 | $ | 3,612,882 | |||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
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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) | - | - | - | - | (590,011 | ) | 4,411 | (585,600 | ) | |||||||||||||||||||
Hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income, net of income tax of $74,629 | - | - | - | (160,183 | ) | - | - | (160,183 | ) | |||||||||||||||||||
Net change in derivative fair value, net of income tax of $52,317 | - | - | - | 113,333 | - | - | 113,333 | |||||||||||||||||||||
Foreign currency translation adjustment | - | - | - | 18,719 | - | - | 18,719 | |||||||||||||||||||||
Issuance and vesting of stock compensation | 23 | 14,695 | (868 | ) | - | - | 1,228 | 15,078 | ||||||||||||||||||||
Stock option exercises | - | 822 | - | - | - | - | 822 | |||||||||||||||||||||
Distributions paid on KGS common units | - | - | - | - | - | (7,344 | ) | (7,344 | ) | |||||||||||||||||||
Balances at September 30, 2009 | $ | 1,740 | $ | 672,475 | $ | (36,309 | ) | $ | 156,973 | $ | (213,523 | ) | $ | 25,032 | $ | 606,388 | ||||||||||||
Balances at December 31, 2009 | $ | 1,745 | $ | 730,265 | $ | (36,363 | ) | $ | 121,336 | $ | (180,985 | ) | $ | 60,824 | $ | 696,822 | ||||||||||||
Net income | - | - | - | - | 116,794 | 11,119 | 127,913 | |||||||||||||||||||||
Hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income, net of income tax of $61,975 | - | - | - | (117,714 | ) | - | - | (117,714 | ) | |||||||||||||||||||
Net change in derivative fair value, net of income tax of $87,312 | - | - | - | 171,910 | - | - | 171,910 | |||||||||||||||||||||
Foreign currency translation adjustment | - | - | - | 4,238 | - | - | 4,238 | |||||||||||||||||||||
Issuance and vesting of stock compensation | 8 | 15,333 | (4,851 | ) | - | - | 858 | 11,348 | ||||||||||||||||||||
Stock option exercises | 2 | 1,600 | (214 | ) | - | - | - | 1,388 | ||||||||||||||||||||
Issuance of KGS common units | - | 6,746 | - | - | - | 4,308 | 11,054 | |||||||||||||||||||||
Distributions paid on KGS common units | - | - | - | - | - | (13,550 | ) | (13,550 | ) | |||||||||||||||||||
Balances at September 30, 2010 | $ | 1,755 | $ | 753,944 | $ | (41,428 | ) | $ | 179,770 | $ | (64,191 | ) | $ | 63,559 | $ | 893,409 | ||||||||||||
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 Nine Months Ended | ||||||||
September 30, | ||||||||
2010 | 2009 | |||||||
Operating activities: | ||||||||
Net income (loss) | $ | 127,913 | $ | (585,600 | ) | |||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||
Impairment expense | 31,531 | 967,126 | ||||||
Depletion, depreciation and accretion | 149,968 | 155,210 | ||||||
Deferred income tax expense (benefit) | 71,569 | (313,556 | ) | |||||
Stock-based compensation | 17,343 | 16,007 | ||||||
Non-cash (gain) loss from commodity derivative activities | (45,801 | ) | 2,845 | |||||
Non-cash interest expense | 13,372 | 40,553 | ||||||
(Income) loss from BBEP in excess of cash distributions, net of impairment | (9,416 | ) | 35,770 | |||||
Gain on sale and disposition of BBEP units | (49,850 | ) | - | |||||
Other | (337 | ) | 684 | |||||
Changes in assets and liabilities | ||||||||
Accounts receivable | 25,101 | 67,555 | ||||||
Derivative assets at fair value | 30,816 | 54,896 | ||||||
Other assets | 4,974 | 4,490 | ||||||
Accounts payable | (18,793 | ) | (34,543 | ) | ||||
Accrued and other liabilities | (1,000 | ) | 39,156 | |||||
Net cash provided by operating activities | 347,390 | 450,593 | ||||||
Investing activities: | ||||||||
Purchases of property, plant and equipment | (494,338 | ) | (561,120 | ) | ||||
Proceeds from sale of BBEP units | 22,498 | - | ||||||
Proceeds from sales of property and equipment | 1,030 | 221,038 | ||||||
Net cash used for investing activities | (470,810 | ) | (340,082 | ) | ||||
Financing activities: | ||||||||
Issuance of debt | 661,232 | 1,377,525 | ||||||
Repayments of debt | (491,043 | ) | (1,507,137 | ) | ||||
Debt issuance costs paid | (109 | ) | (30,995 | ) | ||||
Gas Purchase Commitment assumed | - | 58,294 | ||||||
Gas Purchase Commitment repayments | (25,900 | ) | (3,804 | ) | ||||
Issuance of KGS common units - net of offering costs | 11,054 | - | ||||||
Distributions paid on KGS common units | (13,550 | ) | (7,344 | ) | ||||
Proceeds from exercise of stock options | 1,388 | 822 | ||||||
Taxes paid for equity-based compensation vesting | (1,144 | ) | (63 | ) | ||||
Purchase of treasury stock for stock-based compensation vesting | (4,851 | ) | (868 | ) | ||||
Net cash provided by (used for) financing activities | 137,077 | (113,570 | ) | |||||
Effect of exchange rate changes on changes in cash | (306 | ) | 1,779 | |||||
Net increase (decrease) in cash and cash equivalents | 13,351 | (1,280 | ) | |||||
Cash and cash equivalents at beginning of period | 1,785 | 2,848 | ||||||
Cash and cash equivalents at end of period | $ | 15,136 | $ | 1,568 | ||||
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 management’s opinion, the accompanying condensed consolidated interim financial statements contain all adjustments necessary to fairly present our financial position as of September 30, 2010 and our results of operations for the three and nine months ended September 30, 2010 and 2009 and cash flows for the nine months ended September 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. KGS, CRESTWOOD TRANSACTION AND MIDSTREAM OPERATIONS
In July 2010, we entered into a definitive agreement to sell all of our interests in KGS. We completed the sale to Crestwood in October 2010. The Crestwood Transaction included our conveying:
• | a 100% ownership interest in Quicksilver Gas Services Holdings LLC, which owned; |
• | 5,696,752 common units of KGS; | ||
• | 11,513,625 subordinated units of KGS representing limited partner interests in KGS; | ||
• | 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; and, |
• | a subordinated promissory note issued to us by KGS with a carrying value of $58 million at September 30, 2010. |
We received $701 million in cash at closing and recognized a gain of approximately $540 million after consideration of approximately $2.6 million in transaction costs. We have the right to earn up to an additional $72 million in future earn-out payments in 2012 and 2013.
Under the agreements governing the Crestwood Transaction, both parties agreed for two years not to solicit employees of the other party and we agreed not to compete with KGS with respect to the 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 are entitled to appoint a director to KGS’ general partner’s board of directors until the later of the second anniversary of the closing and such time as we generate less than 50% of their consolidated revenue in any fiscal year. Pursuant to this right, we have appointed Thomas F. Darden as a director of KGS’ general partner’s board of directors.
In connection with the closing of the Crestwood Transaction, we are providing transitional services to KGS for up to six months on customary terms. KGS and we also entered into an agreement for the joint development of areas governed by certain of our existing commercial agreements and further we amended our existing commercial agreements. The most significant amendments include extending the terms of all gathering agreements with KGS through 2020 and establishing a fixed gathering rate of $0.55 per Mcf in the Alliance gathering system.
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In September 2010, our board of directors approved a plan for disposal of our HCDS, a gathering system in Hill County, Texas, which gathers natural gas and delivers it to unaffiliated pipelines for further transport and sale downstream. As a result of this decision, we conducted an impairment analysis of the HCDS and recognized a charge for impairment.
We have continued to report our interests sold in the Crestwood Transaction and the HCDS as part of our continuing operating results because their providing midstream services to us constitutes a “continuation of service” that precludes presentation of those businesses as discontinued operations under GAAP. The assets and liabilities of these midstream operations have been reclassified and are separately reported in our consolidated balance sheets.
The operating results of these midstream operations, as classified in our statement of income, are summarized below:
For the Three Months Ended | For the Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
(In thousands) | ||||||||||||||||
Revenues | $ | 4,669 | $ | 1,476 | $ | 12,836 | $ | 5,186 | ||||||||
Oil and gas production expense(1) | (22,425 | ) | (18,956 | ) | (57,003 | ) | (56,694 | ) | ||||||||
Production and ad valorem taxes | 1,770 | 917 | 3,724 | 2,804 | ||||||||||||
Cost of natural gas sold | 9 | 17 | 64 | 71 | ||||||||||||
Other operating costs | 1,229 | 1,951 | 3,325 | 4,108 | ||||||||||||
DD&A | 6,453 | 6,332 | 18,984 | 17,583 | ||||||||||||
General and administrative | 3,294 | 696 | 5,040 | 2,190 | ||||||||||||
Impairment expense | 31,531 | - | 31,531 | - | ||||||||||||
Operating results of midstream operations | (17,192 | ) | 10,519 | 7,171 | 35,124 | |||||||||||
Interest and other expense | (2,527 | ) | (1,001 | ) | (6,917 | ) | (3,014 | ) | ||||||||
Results of midstream operations before income tax | (19,719 | ) | 9,518 | 254 | 32,110 | |||||||||||
Income tax (expense) benefit | 6,981 | (3,718 | ) | (91 | ) | (11,975 | ) | |||||||||
Results of midstream operations, net of income tax | $ | (12,738 | ) | $ | 5,800 | $ | 163 | $ | 20,135 | |||||||
(1) | Our midstream operations earn revenue from processing and gathering our natural gas. These revenues are consolidated as reductions of oil and gas production expense for purposes of presenting our consolidated statements of income. |
Details of balance sheet items for these midstream operations are summarized below:
As of | As of | |||||||
September 30, | December 31, | |||||||
2010 | 2009 | |||||||
Assets: | (In thousands) | |||||||
Cash | $ | 58 | $ | 748 | ||||
Accounts receivable, net | 4,716 | 1,515 | ||||||
Other current assets | 14,085 | 291 | ||||||
Property, plant and equipment, net | 540,869 | 543,095 | ||||||
Other assets | 2,196 | 2,859 | ||||||
Total | $ | 561,924 | $ | 548,508 | ||||
Liabilities | ||||||||
Current liabilities | $ | 16,032 | $ | 11,226 | ||||
Long-term debt | 238,500 | 125,400 | ||||||
Other non-current liabilities | 12,585 | 11,565 | ||||||
Total | $ | 267,117 | $ | 148,191 | ||||
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Prior to the Crestwood Transaction, we completed the KGS Secondary Offering as part of the funding strategy for the drop-down of the Alliance Midstream Assets. The underwriters purchase of 549,200 newly issued common units in January 2010 yielded cash proceeds of $11.0 million. We completed the drop-down transaction in January 2010 for $84.4 million.
3. DERIVATIVES AND FAIR VALUE MEASUREMENTS
The following table details the estimated fair value of all derivative instruments where “Level 2” inputs are the basis of our fair value estimates at September 30, 2010 and December 31, 2009:
Significant Other Observable | ||||||||
Inputs - Level 2 | ||||||||
September 30, | December 31, | |||||||
2010 | 2009 | |||||||
(in thousands) | ||||||||
Commodity contracts | $ | 227,259 | $ | 107,881 | ||||
Interest rate contracts | - | 4,108 | ||||||
Gas Purchase Commitment | (665 | ) | (6,625 | ) | ||||
Total | $ | 226,594 | $ | 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 reported 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 September 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. We have hedged our anticipated 2010 and 2011 NGL production 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 during 2010 further increased the carrying value. Monthly settlements received during 2010 have partially offset these increases.
Interest Rate Derivatives
In February 2010, we executed the early settlement of the 2009 interest rate swaps that were designated as fair value hedges of our senior notes due 2015 and our senior subordinated notes. We received cash of $18.0 million in the settlement, including $3.7 million for interest previously accrued and earned, and recognized the remaining $14.3 million as a fair value adjustment to our debt.
In February 2010, we entered into new interest swaps to hedge the same debt instruments. We executed early settlement of a portion of the 2010 interest rate swaps in May 2010 and the remaining 2010 interest swaps in July 2010 for $6.8 million and $16.7 million, respectively. These settlements included $7.0 million for interest previously accrued and earned. The remaining cash of $16.5 million was recognized as a fair value adjustment to our debt, which will be recognized as a reduction of interest expense over the life of the associated underlying debt instruments.
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These early settlements of all interest rate swaps 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) | $ | 3,181 | ||
2011 | 4,897 | |||
2012 | 5,315 | |||
2013 | 5,769 | |||
2014 | 6,261 | |||
2015 | 4,824 | |||
2016 | 569 | |||
$ | 30,816 | |||
(1) | Includes $2.0 million recognized through September 30, 2010 |
The average effective interest rates on the senior notes due 2015 and the senior subordinated notes were approximately 5.03% and 6.18%, respectively, for the first nine months of 2010. At September 30, 2010, we had no interest rate swaps outstanding.
Gas Purchase Commitment
The Gas Purchase Commitment, which is effective through December 31, 2010, contains an embedded derivative, which we revalue for changes to estimated volumes and prices from June 19, 2009 to September 30, 2010. At September 30, 2010, we have estimated the remaining liability at $18.9 million, including an embedded derivative liability for cumulative changes in estimates for remaining production months of $0.7 million. The derivative reflects a 4.4 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 the Gas Purchase Commitment activity during 2010:
(In thousands) | ||||
Liability fair value at December 31, 2009 | $ | 50,744 | ||
Decrease due to gas volumes purchased | (25,900 | ) | ||
Embedded derivative increase (decrease) due to: | ||||
Price changes | 6,384 | |||
Volume changes | (12,344 | ) | ||
Total increase (decrease) in embedded derivative | (5,960 | ) | ||
Liability fair value at September 30, 2010(1) | $ | 18,884 | ||
(1) | The liability for the Gas Purchase Commitment was valued using estimated Eni production volumes from October 2010 through December 2010 and published future market prices and risk-adjusted interest rates as of September 30, 2010. |
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The estimated fair value of our derivatives at September 30, 2010 and December 31, 2009 were as follows:
Asset Derivatives | Liability Derivatives | ||||||||||||||||
September 30, | December 31, | September 30, | December 31, | ||||||||||||||
2010 | 2009 | 2010 | 2009 | ||||||||||||||
(In thousands) | (In thousands) | ||||||||||||||||
Derivatives designated as hedges: | |||||||||||||||||
Commodity contracts reported in: | |||||||||||||||||
Current derivative assets | $ | 148,334 | $ | 97,883 | $ | 5,771 | $ | 638 | |||||||||
Noncurrent derivative assets | 84,696 | 11,031 | - | - | |||||||||||||
Current derivative liabilities | - | 243 | - | 638 | |||||||||||||
Interest rate contracts reported in: | |||||||||||||||||
Current derivative assets | - | 712 | - | - | |||||||||||||
Noncurrent derivative assets | - | 3,396 | - | - | |||||||||||||
Total derivatives designated as hedges | $ | 233,030 | $ | 113,265 | $ | 5,771 | $ | 1,276 | |||||||||
Derivatives not designated as hedges: | |||||||||||||||||
Gas Purchase Commitment reported in accrued liabilities | $ | - | $ | - | $ | 665 | $ | 6,625 | |||||||||
Total derivatives not designated as hedges | $ | - | $ | - | $ | 665 | $ | 6,625 | |||||||||
Total derivatives | $ | 233,030 | $ | 113,265 | $ | 6,436 | $ | 7,901 | |||||||||
The changes in the carrying value of our derivatives for the three and nine months ended September 30, 2010 and 2009 are presented below:
For the Three Months Ended September 30, 2010 | ||||||||||||||||
Gas Purchase | Interest Rate | Commodity | ||||||||||||||
Commitment | Swaps | Hedges | Total | |||||||||||||
(In thousands) | ||||||||||||||||
Derivative fair value at June 30, 2010 | $ | (6,161 | ) | $ | 13,240 | $ | 193,394 | $ | 200,473 | |||||||
Net change in amounts receivable/payable | - | (4,392 | ) | (240 | ) | (4,632 | ) | |||||||||
Net settlements reported in revenue | - | - | (54,716 | ) | (54,716 | ) | ||||||||||
Cash settlements reported in long-term debt | - | (12,134 | ) | - | (12,134 | ) | ||||||||||
Change in fair value of Gas Purchase Commitment reported in costs of purchased gas | 5,496 | - | - | 5,496 | ||||||||||||
Change in fair value of interest rate swaps | - | 3,286 | - | 3,286 | ||||||||||||
Ineffectiveness reported in other revenue | - | - | (806 | ) | (806 | ) | ||||||||||
Unrealized gains reported in OCI | - | - | 89,627 | 89,627 | ||||||||||||
Derivative fair value at September 30, 2010 | $ | (665 | ) | $ | - | $ | 227,259 | $ | 226,594 | |||||||
For the Three Months Ended September 30, 2009 | ||||||||||||||||
Gas Purchase | Interest Rate | Commodity | ||||||||||||||
Commitment | Swaps | Hedges | Total | |||||||||||||
(In thousands) | ||||||||||||||||
Derivative fair value at June 30, 2009 | $ | (3,818 | ) | $ | (266 | ) | $ | 257,548 | $ | 253,464 | ||||||
Net settlements reported in revenue | - | - | (92,687 | ) | (92,687 | ) | ||||||||||
Net settlements reported in interest expense | - | (6,537 | ) | - | (6,537 | ) | ||||||||||
Change in fair value of Gas Purchase Commitment reported in costs of purchased gas | 2,630 | - | - | 2,630 | ||||||||||||
Change in fair value of interest rate swaps | - | 22,845 | - | 22,845 | ||||||||||||
Ineffectiveness reported in other revenue | - | - | 77 | 77 | ||||||||||||
Unrealized gains reported in OCI | - | - | 134 | 134 | ||||||||||||
Derivative fair value at September 30, 2009 | $ | (1,188 | ) | $ | 16,042 | $ | 165,072 | $ | 179,926 | |||||||
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For the Nine Months Ended September 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 | - | (9,180 | ) | (1,101 | ) | (10,281 | ) | |||||||||||||
Net settlements reported in revenue | - | - | (136,349 | ) | (136,349 | ) | ||||||||||||||
Net settlements reported in interest expense | - | (10,848 | ) | - | (10,848 | ) | ||||||||||||||
Cash settlements reported in long-term debt | - | (30,816 | ) | - | (30,816 | ) | ||||||||||||||
Change in fair value of Gas Purchase Commitment reported in costs of purchased gas | 5,960 | - | - | 5,960 | ||||||||||||||||
Change in fair value of interest rate swaps | - | 46,736 | - | 46,736 | ||||||||||||||||
Ineffectiveness reported in other revenue | - | - | (2,394 | ) | (2,394 | ) | ||||||||||||||
Unrealized gains reported in OCI | - | - | 259,222 | 259,222 | ||||||||||||||||
Derivative fair value at September 30, 2010 | $ | (665 | ) | $ | - | $ | 227,259 | $ | 226,594 | |||||||||||
For the Nine Months Ended September 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 | ) | - | - | - | (3,518 | ) | |||||||||||||
Net settlements | 16,479 | - | - | - | 16,479 | |||||||||||||||
Net settlements reported in revenue | - | - | - | (234,812 | ) | (234,812 | ) | |||||||||||||
Net settlements reported in interest expense | - | - | (7,200 | ) | - | (7,200 | ) | |||||||||||||
Change in fair value of Gas Purchase Commitment reported in costs of purchased gas | - | (1,188 | ) | - | - | (1,188 | ) | |||||||||||||
Change in fair value of interest rate swaps | - | - | 23,242 | - | 23,242 | |||||||||||||||
Ineffectiveness reported in other revenue | (60 | ) | - | - | (1,589 | ) | (1,649 | ) | ||||||||||||
Cash settlement reported in OCI | - | - | - | (54,896 | ) | (54,896 | ) | |||||||||||||
Unrealized gains reported in OCI | - | - | - | 165,650 | 165,650 | |||||||||||||||
Derivative fair value at September 30, 2009 | $ | - | $ | (1,188 | ) | $ | 16,042 | $ | 165,072 | $ | 179,926 | |||||||||
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 $94.5 million, net of income taxes. An additional $8.2 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 $2.4 million and $1.7 million recorded in other revenue for the nine months ended September 30, 2010 and 2009, respectively.
4. INVESTMENT IN BREITBURN
At September 30, 2010, we owned approximately 16.3 million common units, or 31%, of BBEP, a publicly traded limited partnership, whose price closed at $18.27 per unit as of that date. Note 5 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. We further reduced our ownership of BBEP in September 2010 when we sold approximately 1.4 million common units at a unit price of $16.22, net of fees paid. We recognized a gain of $14.4 million as other income for the difference between our carrying value at the time of the sale of $5.82 per BBEP unit and the net sales proceeds. In October 2010, we sold an additional 650,000 units at a unit price of $17.72 and recognized a gain of $7.7 million.
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We account for our investment in BBEP units using the equity method, utilizing a one-quarter lag from BBEP’s publicly available information. When we sell BBEP units, we do not utilize the subsequently available financial information to adjust the carrying value of the units sold or to amend the previously recognized gain or loss on sale. Summarized estimated financial information for BBEP is as follows:
For the Three Months Ended | For the Nine Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
(In thousands) | ||||||||||||||||
Revenues(1) | $ | 134,216 | $ | (36,994 | ) | $ | 305,645 | $ | 534,192 | |||||||
Operating expenses | 73,621 | 67,352 | 216,170 | 307,391 | ||||||||||||
Operating income (loss) | 60,595 | (104,346 | ) | 89,475 | 226,801 | |||||||||||
Interest and other(2) | 6,437 | 4,988 | 18,130 | 37,458 | ||||||||||||
Income tax (benefit) expense | 561 | (809 | ) | (469 | ) | 336 | ||||||||||
Net income | 53,597 | (108,525 | ) | 71,814 | 189,007 | |||||||||||
Noncontrolling interests | 28 | (5 | ) | 118 | 15 | |||||||||||
Net income attributable to BBEP | $ | 53,569 | $ | (108,520 | ) | $ | 71,696 | $ | 188,992 | |||||||
(1) | The three months ended June 30, 2010 and 2009 include commodity derivative unrealized gains of $33.2 million and unrealized losses of $148.7 million, respectively. The nine months ended June 30, 2010 and 2009 include commodity derivative unrealized gains of $18.4 million and unrealized gains $193.5 million, respectively. | |
(2) | The three months ended June 30, 2010 and 2009 include interest rate swap derivative unrealized gains of $1.5 million and $3.5 million, respectively. The nine months ended June 30, 2010 and 2009 include interest rate swap derivative unrealized gains of $3.9 million and $10.6 million, respectively. |
As of | As of | |||||||
June 30, | December 31, | |||||||
2010 | 2009 | |||||||
(In thousands) | ||||||||
Current assets | $ | 147,678 | $ | 142,441 | ||||
Property, plant and equipment | 1,725,827 | 1,741,089 | ||||||
Other assets | 118,214 | 87,499 | ||||||
Current liabilities | 68,477 | 91,890 | ||||||
Long-term debt | 534,000 | 559,000 | ||||||
Other non-current liabilities | 61,282 | 91,338 | ||||||
Total equity | 1,327,960 | 1,228,801 |
For the nine months ended September 30, 2010, we recognized income of $24.2 million of BBEP’s income for the nine months ended June 30, 2010. For the comparable 2009 period, we recognized income of $77.4 million and impairment expense of $102.1 million.
Changes in the balance of our investment in BBEP for the nine months ended September 30, 2010 were as follows:
(In thousands, except unit data) | ||||
Balance at December 31, 2009 | $ | 112,763 | ||
Equity income from BBEP | 24,203 | |||
Distributions from BBEP | (14,785 | ) | ||
Conveyance of 3,619,901 BBEP units | (18,981 | ) | ||
Sale of 1,387,050 BBEP units | (8,075 | ) | ||
Balance at September 30, 2010 | $ | 95,125 | ||
Note 8 contains additional information regarding the April 2010 settlement of our lawsuit against BBEP and other parties.
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5. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment, excluding the property, plant and equipment of our midstream operations held for sale, consisted of the following:
September 30, | December 31, | |||||||
2010 | 2009 | |||||||
(In thousands) | ||||||||
Oil and gas properties | ||||||||
Subject to depletion | $ | 4,496,290 | $ | 3,947,676 | ||||
Unevaluated costs | 404,783 | 458,037 | ||||||
Accumulated depletion | (2,193,288 | ) | (2,067,469 | ) | ||||
Net oil and gas properties | 2,707,785 | 2,338,244 | ||||||
Other plant and equipment | ||||||||
Pipelines and processing facilities | 208,451 | 201,880 | ||||||
General properties | 68,451 | 64,893 | ||||||
Accumulated depreciation | (70,999 | ) | (62,172 | ) | ||||
Net other property and equipment | 205,903 | 204,601 | ||||||
Property, plant and equipment, net of accumulated depletion and depreciation | $ | 2,913,688 | $ | 2,542,845 | ||||
Ceiling Test Analysis
Our U.S. and Canadian ceiling tests for each of the first three 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 nine months 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.
Note 10 to our consolidated financial statements in our 2009 Annual Report on Form 10-K contains additional information regarding our property, plant and equipment and our 2009 full cost ceiling impairments.
Lake Arlington Acquisition
In May 2010, we completed the acquisition of an additional 25% working interest in our company-operated Lake Arlington Project, for which we conveyed $62.1 million in cash and 3,619,901 BBEP common units owned by us with a market value of $54.4 million 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 on the date of the transaction.
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6. LONG-TERM DEBT
Long-term debt consisted of the following:
September 30, | December 31, | |||||||
2010 | 2009 | |||||||
(In thousands) | ||||||||
Senior Secured Credit Facility | $ | 529,274 | $ | 467,569 | ||||
Senior notes due 2015, net of unamortized discount | 470,641 | 469,964 | ||||||
Senior notes due 2016, net of unamortized discount | 583,026 | 581,359 | ||||||
Senior notes due 2019, net of unamortized discount | 293,374 | 293,004 | ||||||
Senior subordinated notes due 2016 | 350,000 | 350,000 | ||||||
Convertible debentures, net of unamortized discount | 141,591 | 136,119 | ||||||
Total debt | 2,367,906 | 2,298,015 | ||||||
Unamortized deferred gain - terminated interest rate swaps | 28,799 | - | ||||||
Fair value of interest rate swaps | - | 4,108 | ||||||
Long-term debt | $ | 2,396,705 | $ | 2,302,123 | ||||
Senior Secured Credit Facility
The $1.0 billion borrowing base on our Senior Secured Credit Facility was re-affirmed in May 2010. In October 2010, using proceeds from the Crestwood Transaction, we repaid all of our outstanding borrowings under the Senior Secured Credit Facility.
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 October 1, 2010, the debentures were not convertible based on share prices for the quarter ended September 30, 2010. Additionally, holders of the debentures can require us to repurchase all or a portion of their debentures for cash on November 1, 2011, 2014 or 2019 at a price equal to the principal amount plus accrued and unpaid interest. We can require the holders of the debentures to redeem all or a portion of their debentures for cash at any time on or after November 8, 2011 and prior to maturity at a price equal to the principal amount plus accrued and unpaid interest.
At September 30, 2010 and December 31, 2009, the remaining unamortized discount on the debentures was $8.4 million and $13.9 million, respectively, resulting in a carrying value of $141.6 million and $136.1 million, respectively. The remaining discount will be accreted to face value through October 2011. For the nine months ended September 30, 2010 and 2009, interest expense on our convertible debentures, recognized at an effective interest rate of 6.75%, was $7.6 million and $7.2 million, respectively, including contractual interest of $2.1 million for each period.
KGS Credit Facility
As discussed in Note 2, the balance due by KGS under the KGS Credit Agreement is reported in liabilities of midstream operations held for sale. Upon completion of the Crestwood Transaction, any borrowings outstanding under the KGS Credit Agreement, are excluded from our balance sheet entirely.
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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) | |||||||||||||||||||||||||
Highest priority | Lowest priority | ||||||||||||||||||||||||
Equal priority | |||||||||||||||||||||||||
Senior Secured | 2015 | 2016 | 2019 | Senior | Convertible | ||||||||||||||||||||
Credit Facility | Senior Notes | Senior Notes | Senior Notes | Subordinated Notes | Debentures | ||||||||||||||||||||
Scheduled maturity date | February 9, 2012 | August 1, 2015 | January 1, 2016 | August 15, 2019 | April 1, 2016 | November 1, 2024 | |||||||||||||||||||
Interest rate at September 30, 2010(2) | 3.812 | % | 8.25 | % | 11.75 | % | 9.125 | % | 7.125 | % | 1.875 | % | |||||||||||||
Base interest rate options(3) | LIBOR, ABR or specified(4) | N/A | N/A | N/A | N/A | N/A | |||||||||||||||||||
Financial covenants(5) | - Minimum current ratio of 1.0 | N/A | N/A | N/A | N/A | N/A | |||||||||||||||||||
- Minimum EBITDA to interest expense ratio of 2.5 | |||||||||||||||||||||||||
Significant restrictive covenants(5) | - Incurrence of debt - - Incurrence of liens - - Payment of dividends - - Equity purchases - - Asset sales - - Affiliate transactions - - Limitations on derivatives | - Incurrence of debt - - Incurrence of liens - - Payment of dividends - - Equity purchases - - Asset sales - - Affiliate transactions | - Incurrence of debt - - Incurrence of liens - - Payment of dividends - - Equity purchases - - Asset sales - - Affiliate transactions | - Incurrence of debt - - Incurrence of liens - - Payment of dividends - - Equity purchases - - Asset sales - - Affiliate transactions | - Incurrence of debt - - Incurrence of liens - - Payment of dividends - - Equity purchases - - Asset sales - - Affiliate transactions | N/A | |||||||||||||||||||
Estimated fair value(6) | $529.3 million | $498.8 million | $700.5 million | $327.8 million | $344.3 million | $159.1 million |
(1) | The Senior Secured Credit Facility is secured by a first perfected lien on substantially all our assets, including BBEP units. The other debt presented is based upon structural seniority and priority of payment. | |
(2) | Represents the weighted average borrowing rate payable to lenders and excludes effects of interest rate derivatives. | |
(3) | Interest rate options include a base rate plus a spread. | |
(4) | 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%. | |
(5) | 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. | |
(6) | 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. |
Note 13 to the consolidated financial statements in our 2009 Annual Report on Form 10-K contains a more complete description of our long-term debt.
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7. ASSET RETIREMENT OBLIGATIONS
The following table provides information about our estimated asset retirement obligation activity for the nine months ended September 30, 2010 excluding such obligations of our midstream operations held for sale:
(In thousands) | ||||
Beginning asset retirement obligations | $ | 48,581 | ||
Incremental liability incurred | 1,549 | |||
Accretion expense | 1,893 | |||
Asset retirement costs incurred | (677 | ) | ||
Gain on settlement of liability | 436 | |||
Currency translation adjustment | 762 | |||
Ending asset retirement obligations | 52,544 | |||
Less current portion | (109 | ) | ||
Long-term asset retirement obligations | $ | 52,435 | ||
8. COMMITMENTS AND CONTINGENCIES
In the litigation filed by us against Eagle Drilling LLC (“Eagle”), which includes counter claims filed by Eagle against us and disclosed in our 2009 Annual Report on Form 10-K, on October 19, 2010, the U.S. District Court granted our motion for summary judgment directed to Eagle’s breach of contract claims, although other claims remain outstanding.
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 we 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 have named two directors to the board of directors of BBEP’s general partner.
In April 2010, Quicksilver entered into a lease of office space for a term of 12 years that commenced August 2010. Aggregate rentals over the life of the lease will total $34.8 million.
As of September 2010, we had surety bonds outstanding of $39.2 million. Our outstanding letters of credit at September 30, 2010 totaled $46.0 million, which includes $28.9 million issued in support of surety bonds.
Note 3 contains information regarding the Gas Purchase Commitment.
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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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. We recognized expense of $5.2 million for all unvested stock options in the first nine 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 | — |
The following table summarizes stock option activity during the nine months ended September 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 | (270,250 | ) | 5.93 | |||||||||||||
Cancelled | (94,312 | ) | 9.09 | |||||||||||||
Outstanding at September 30, 2010 | 3,551,766 | $ | 10.96 | 8.6 | $ | 14,790 | ||||||||||
Exercisable at September 30, 2010 | 1,041,859 | $ | 11.83 | 7.5 | $ | 4,937 | ||||||||||
Vested at September 30, 2010 or expected to vest in the future | 3,356,417 | $ | 11.03 | |||||||||||||
Cash received from the exercise of stock options was $1.4 million for the nine months ended September 30, 2010 and the total fair value of those options exercised was $2.2 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 | 205,244 | 15.24 | ||||||||||||
Vested | (1,097,937 | ) | 12.27 | (109,602 | ) | 6.22 | ||||||||||
Cancelled | (85,300 | ) | 11.47 | (63,187 | ) | 10.21 | ||||||||||
Outstanding at September 30, 2010 | 2,431,707 | $ | 11.34 | 361,150 | $ | 10.65 | ||||||||||
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At January 1, 2010, we had total unvested compensation cost of $15.1 million. During the first nine months of 2010, we recognized compensation expense for all unvested restricted stock and RSUs of $10.1 million. Grants of restricted stock and stock-settled RSUs during the nine months ended September 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 September 30, 2010 for restricted stock and stock-settled RSUs was $17.9 million, which will be recognized through March 2013. The fair value of unvested RSUs settled in cash was $4.5 million at September 30, 2010. The total fair value of restricted shares and RSUs vested during the nine months ended September 30, 2010 was $15.2 million.
Upon closing the Crestwood Transaction, options representing 127,797 shares and 68,546 restricted shares granted to Quicksilver employees prior to their becoming KGS employees were cancelled. A portion of the October payments made to these employees was determined using the October 1, 2010 estimated fair value of the cancelled grants of approximately $2.1 million. This payment resulted in a charge of $1.0 million after consideration of the previously recognized compensation expense prior to forfeiture of the unvested awards.
KGS Phantom Units
The following table summarizes information regarding KGS phantom unit activity:
Payable in units | Payable in cash | |||||||||||||||
Wtd Avg | Wtd Avg | |||||||||||||||
Grant Date | 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 | (25,925 | ) | 22.37 | ||||||||||
Cancelled | (1,690 | ) | 16.75 | - | - | |||||||||||
Outstanding at September 30, 2010 | 515,696 | $ | 15.83 | 7,315 | $ | 19.04 | ||||||||||
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 $2.8 million during the nine months ended September 30, 2010. Grants of phantom units during the nine months ended September 30, 2010 had an estimated grant date fair value of $4.5 million. Phantom units that vested during the nine months ended September 30, 2010 had a fair value of $3.1 million on their vesting date.
On October 1, 2010, compensation expense of $3.6 million was recognized upon closing of the Crestwood Transaction in accordance with the change of control provisions of KGS’ amended 2007 Equity Plan.
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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 | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
(In thousands, except per share | (In thousands, except per share | |||||||||||||||
data) | data) | |||||||||||||||
Net earnings (loss) attributable to Quicksilver | $ | 21,803 | $ | 730 | $ | 116,794 | $ | (590,011 | ) | |||||||
Impact of assumed conversions – interest on 1.875% convertible debentures, net of income taxes(1) | - | - | 5,361 | - | ||||||||||||
Net earnings (loss) available to stockholders assuming conversion of convertible debentures | $ | 21,803 | $ | 730 | $ | 122,155 | $ | (590,011 | ) | |||||||
Weighted average common shares – basic | 170,307 | 169,021 | 170,242 | 168,917 | ||||||||||||
Effect of dilutive securities(1): | ||||||||||||||||
Employee stock options | 704 | 1,452 | 764 | - | ||||||||||||
Employee stock unit awards | 26 | 184 | 25 | - | ||||||||||||
Contingently convertible debentures | - | - | 9,816 | - | ||||||||||||
Weighted average common shares – diluted | 171,037 | 170,657 | 180,847 | 168,917 | ||||||||||||
Net earnings (loss) per common share - basic | 0.13 | - | 0.69 | (3.49 | ) | |||||||||||
Net earnings (loss) per common share - diluted | 0.13 | - | 0.68 | (3.49 | ) |
(1) | For the three and nine months ended September 30, 2009, the effects of our convertible debt, stock options and unvested RSUs representing 9.8 million and 11.1 million shares, respectively, were antidilutive and excluded from the diluted share calculations. For the three months ended September 30, 2010, the effects of our convertible debt, stock options and unvested RSUs representing 11.0 million shares were antidilutive and excluded from the diluted share calculation. For the nine months ended September 30, 2010, the effects of stock options and unvested RSUs representing 1.2 million shares were antidilutive and excluded from the diluted share calculation. |
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 to present the 2009 financial information including the effects of the purchase of the Alliance Midstream Assets by KGS and the Crestwood Transaction whereby we sold all of our interests in the unrestricted subsidiaries. Note 2 provides additional information regarding the Crestwood Transaction.
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September 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 | |||||||||||||||||||||||||
ASSETS | (In thousands) | |||||||||||||||||||||||||||||||
Current assets | $ | 199,590 | $ | 85,657 | $ | 50,908 | $ | (110,268 | ) | $ | 225,887 | $ | - | $ | - | $ | 225,887 | |||||||||||||||
Property and equipment | 2,317,382 | 69,315 | 526,991 | - | 2,913,688 | - | - | 2,913,688 | ||||||||||||||||||||||||
Investment in subsidiaries (equity method) | 539,169 | - | - | (444,045 | ) | 95,124 | - | - | 95,124 | |||||||||||||||||||||||
Assets of midstream operations held for sale | 57,608 | 181,783 | - | - | 239,391 | 551,474 | (228,941 | ) | 561,924 | |||||||||||||||||||||||
Other assets | 154,395 | - | 6,892 | - | 161,287 | 6,208 | - | 167,495 | ||||||||||||||||||||||||
Total assets | $ | 3,268,144 | $ | 336,755 | $ | 584,791 | $ | (554,313 | ) | $ | 3,635,377 | $ | 557,682 | $ | (228,941 | ) | $ | 3,964,118 | ||||||||||||||
LIABILITIES AND EQUITY | ||||||||||||||||||||||||||||||||
Current liabilities | $ | 247,349 | $ | 108,895 | $ | 29,028 | $ | (110,268 | ) | $ | 275,004 | $ | - | $ | - | $ | 275,004 | |||||||||||||||
Liabilities of midstream operations held for sale | - | 1,935 | - | - | 1,935 | 342,295 | (77,113 | ) | 267,117 | |||||||||||||||||||||||
Long-term liabilities | 2,190,945 | 19,822 | 317,821 | - | 2,528,588 | - | - | 2,528,588 | ||||||||||||||||||||||||
Quicksilver stockholders’ equity | 829,850 | 206,103 | 237,942 | (444,045 | ) | 829,850 | 151,828 | (151,828 | ) | 829,850 | ||||||||||||||||||||||
Noncontrolling interests | - | - | - | - | - | 63,559 | - | 63,559 | ||||||||||||||||||||||||
Total liabilities and equity | $ | 3,268,144 | $ | 336,755 | $ | 584,791 | $ | (554,313 | ) | $ | 3,635,377 | $ | 557,682 | $ | (228,941 | ) | $ | 3,964,118 | ||||||||||||||
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 | |||||||||||||||||||||||||
ASSETS | (In thousands) | |||||||||||||||||||||||||||||||
Current assets | $ | 296,233 | $ | 109 | $ | 42,622 | $ | (121,580 | ) | $ | 217,384 | $ | - | $ | - | $ | 217,384 | |||||||||||||||
Property and equipment | 1,980,053 | 71,264 | 491,528 | - | 2,542,845 | - | - | 2,542,845 | ||||||||||||||||||||||||
Investment in subsidiaries (equity method) | 549,200 | - | - | (436,437 | ) | 112,763 | - | - | 112,763 | |||||||||||||||||||||||
Assets of midstream operations held for sale | 55,717 | 291,104 | - | - | 346,821 | 502,401 | (300,714 | ) | 548,508 | |||||||||||||||||||||||
Other assets | 182,062 | - | 3,112 | - | 185,174 | 6,208 | - | 191,382 | ||||||||||||||||||||||||
Total assets | $ | 3,063,265 | $ | 362,477 | $ | 537,262 | $ | (558,017 | ) | $ | 3,404,987 | $ | 508,609 | $ | (300,714 | ) | $ | 3,612,882 | ||||||||||||||
LIABILITIES AND EQUITY | ||||||||||||||||||||||||||||||||
Current liabilities | $ | 334,638 | $ | 117,055 | $ | 25,321 | $ | (121,580 | ) | $ | 355,434 | $ | - | $ | - | $ | 355,434 | |||||||||||||||
Liabilities of midstream operations held for sale | - | 1,120 | - | - | 1,120 | 217,564 | (70,493 | ) | 148,191 | |||||||||||||||||||||||
Long-term liabilities | 2,092,629 | 9,966 | 309,840 | - | 2,412,435 | - | - | 2,412,435 | ||||||||||||||||||||||||
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 | $ | 3,063,265 | $ | 362,477 | $ | 537,262 | $ | (558,017 | ) | $ | 3,404,987 | $ | 508,609 | $ | (300,714 | ) | $ | 3,612,882 | ||||||||||||||
For the Three Months Ended September 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 | $ | 204,389 | $ | 1,802 | $ | 28,609 | $ | (894 | ) | $ | 233,906 | $ | 30,366 | $ | (26,572 | ) | $ | 237,700 | ||||||||||||||
Operating expense | 132,704 | 30,776 | 21,689 | (894 | ) | 184,275 | 14,905 | (26,572 | ) | 172,608 | ||||||||||||||||||||||
Equity in net earnings of subsidiaries | (10,600 | ) | 7,465 | - | 10,600 | 7,465 | - | (7,465 | ) | - | ||||||||||||||||||||||
Operating income | 61,085 | (21,509 | ) | 6,920 | 10,600 | 57,096 | 15,461 | (7,465 | ) | 65,092 | ||||||||||||||||||||||
Income from earnings of BBEP | 17,024 | - | - | - | 17,024 | - | - | 17,024 | ||||||||||||||||||||||||
Interest expense and other | (32,266 | ) | - | (1,828 | ) | - | (34,094 | ) | (3,185 | ) | - | (37,279 | ) | |||||||||||||||||||
Income tax (expense) benefit | (24,040 | ) | 7,528 | (1,711 | ) | - | (18,223 | ) | (45 | ) | - | (18,268 | ) | |||||||||||||||||||
Net income | $ | 21,803 | $ | (13,981 | ) | $ | 3,381 | $ | 10,600 | $ | 21,803 | $ | 12,231 | $ | (7,465 | ) | $ | 26,569 | ||||||||||||||
Net income attributable to noncontrolling interests | - | - | - | - | - | (4,766 | ) | - | (4,766 | ) | ||||||||||||||||||||||
Net income attributable Quicksilver | $ | 21,803 | $ | (13,981 | ) | $ | 3,381 | $ | 10,600 | $ | 21,803 | $ | 7,465 | $ | (7,465 | ) | $ | 21,803 | ||||||||||||||
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For the Three Months Ended September 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 | $ | 157,407 | $ | (33 | ) | $ | 47,648 | $ | 91 | $ | 205,113 | $ | 23,236 | $ | (21,692 | ) | $ | 206,657 | ||||||||||||||
Operating expense | 90,053 | 653 | 20,224 | 91 | 111,021 | 13,777 | (21,844 | ) | 102,954 | |||||||||||||||||||||||
Equity in net earnings of subsidiaries | 23,685 | 5,709 | - | (23,685 | ) | 5,709 | - | (5,709 | ) | - | ||||||||||||||||||||||
Operating income (loss) | 91,039 | 5,023 | 27,424 | (23,685 | ) | 99,801 | 9,459 | (5,557 | ) | 103,703 | ||||||||||||||||||||||
Income from earnings of BBEP | (43,685 | ) | - | - | - | (43,685 | ) | - | - | (43,685 | ) | |||||||||||||||||||||
Interest expense and other | (38,525 | ) | 814 | (2,315 | ) | - | (40,026 | ) | (1,738 | ) | (500 | ) | (42,264 | ) | ||||||||||||||||||
Income tax (expense) benefit | (8,099 | ) | (2,043 | ) | (5,218 | ) | - | (15,360 | ) | (235 | ) | - | (15,595 | ) | ||||||||||||||||||
Discontinued operations | - | - | - | - | - | (348 | ) | 348 | - | |||||||||||||||||||||||
Net income (loss) | $ | 730 | $ | 3,794 | $ | 19,891 | $ | (23,685 | ) | $ | 730 | $ | 7,138 | $ | (5,709 | ) | $ | 2,159 | ||||||||||||||
Net income attributable to noncontrolling interests | - | - | - | - | - | (1,429 | ) | - | (1,429 | ) | ||||||||||||||||||||||
Net income (loss) attributable to Quicksilver | $ | 730 | $ | 3,794 | $ | 19,891 | $ | (23,685 | ) | $ | 730 | $ | 5,709 | $ | (5,709 | ) | $ | 730 | ||||||||||||||
For the Nine Months Ended September 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 | $ | 582,283 | $ | 5,013 | $ | 93,158 | $ | (2,219 | ) | $ | 678,235 | $ | 82,299 | $ | (72,106 | ) | $ | 688,428 | ||||||||||||||
Operating expenses | 364,202 | 35,129 | 68,831 | (2,219 | ) | 465,943 | 44,787 | (72,106 | ) | 438,624 | ||||||||||||||||||||||
Equity in net earnings of subsidiaries | 5,546 | 17,414 | - | (5,546 | ) | 17,414 | - | (17,414 | ) | - | ||||||||||||||||||||||
Operating income (loss) | 223,627 | (12,702 | ) | 24,327 | (5,546 | ) | 229,706 | 37,512 | (17,414 | ) | 249,804 | |||||||||||||||||||||
Income from earnings of BBEP | 24,203 | - | - | - | 24,203 | - | - | 24,203 | ||||||||||||||||||||||||
Interest expense and other | (60,667 | ) | - | (5,050 | ) | - | (65,717 | ) | (8,808 | ) | - | (74,525 | ) | |||||||||||||||||||
Income tax (expense) benefit | (70,369 | ) | 4,446 | (5,475 | ) | - | (71,398 | ) | (171 | ) | (71,569 | ) | ||||||||||||||||||||
Net income (loss) | $ | 116,794 | $ | (8,256 | ) | $ | 13,802 | $ | (5,546 | ) | $ | 116,794 | $ | 28,533 | $ | (17,414 | ) | $ | 127,913 | |||||||||||||
Net income attributable to noncontrolling interests | - | - | - | - | - | (11,119 | ) | - | (11,119 | ) | ||||||||||||||||||||||
Net income (loss) attributable to Quicksilver | $ | 116,794 | $ | (8,256 | ) | $ | 13,802 | $ | (5,546 | ) | $ | 116,794 | $ | 17,414 | $ | (17,414 | ) | $ | 116,794 | |||||||||||||
For the Nine Months Ended September 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 | $ | 452,403 | $ | 184 | $ | 140,786 | $ | 57 | $ | 593,430 | $ | 70,540 | $ | (65,340 | ) | $ | 598,630 | |||||||||||||||
Operating expenses | 1,094,552 | 2,091 | 240,063 | 57 | 1,336,763 | 38,529 | (65,246 | ) | 1,310,046 | |||||||||||||||||||||||
Equity in net earnings of subsidiaries | (65,113 | ) | 19,137 | - | 65,113 | 19,137 | - | (19,137 | ) | - | ||||||||||||||||||||||
Operating income | (707,262 | ) | 17,230 | (99,277 | ) | 65,113 | (724,196 | ) | 32,011 | (19,231 | ) | (711,416 | ) | |||||||||||||||||||
Income from earnings of BBEP | (24,669 | ) | - | - | - | (24,669 | ) | - | - | (24,669 | ) | |||||||||||||||||||||
Interest expense and other | (139,682 | ) | 3,389 | (6,424 | ) | - | (142,717 | ) | (6,215 | ) | (1,708 | ) | (150,640 | ) | ||||||||||||||||||
Income tax (expense) benefit | 281,602 | (7,217 | ) | 27,186 | - | 301,571 | (446 | ) | - | 301,125 | ||||||||||||||||||||||
Discontinued operations | - | - | - | - | - | (1,802 | ) | 1,802 | - | |||||||||||||||||||||||
Net income | $ | (590,011 | ) | $ | 13,402 | $ | (78,515 | ) | $ | 65,113 | $ | (590,011 | ) | $ | 23,548 | $ | (19,137 | ) | $ | (585,600 | ) | |||||||||||
Net income attributable to noncontrolling interests | - | - | - | - | - | (4,411 | ) | - | (4,411 | ) | ||||||||||||||||||||||
Net income attributable to Quicksilver | $ | (590,011 | ) | $ | 13,402 | $ | (78,515 | ) | $ | 65,113 | $ | (590,011 | ) | $ | 19,137 | $ | (19,137 | ) | $ | (590,011 | ) | |||||||||||
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For the Nine Months Ended September 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 | $ | 257,090 | $ | 593 | $ | 59,704 | $ | - | $ | 317,387 | $ | 44,873 | $ | (14,870 | ) | $ | 347,390 | |||||||||||||||
Purchases of property, plant and equipment | (380,507 | ) | (593 | ) | (53,362 | ) | - | (434,462 | ) | (52,470 | ) | (7,406 | ) | (494,338 | ) | |||||||||||||||||
Distribution to parent | 80,276 | - | - | - | 80,276 | (80,276 | ) | - | - | |||||||||||||||||||||||
Proceeds from sale of BBEP units | 22,498 | - | - | - | 22,498 | 22,498 | ||||||||||||||||||||||||||
Proceeds from sales of property and equipment | 1,030 | - | - | - | 1,030 | - | - | 1,030 | ||||||||||||||||||||||||
Net cash flow used for investing activities | (276,703 | ) | (593 | ) | (53,362 | ) | - | (330,658 | ) | (132,746 | ) | (7,406 | ) | (470,810 | ) | |||||||||||||||||
Issuance of debt | 478,500 | - | 39,532 | - | 518,032 | 143,200 | - | 661,232 | ||||||||||||||||||||||||
Repayments of debt | (414,500 | ) | - | (46,443 | ) | - | (460,943 | ) | (30,100 | ) | - | (491,043 | ) | |||||||||||||||||||
Debt issuance costs | (109 | ) | - | - | - | (109 | ) | - | - | (109 | ) | |||||||||||||||||||||
Gas Purchase Commitment - net | (25,900 | ) | - | - | - | (25,900 | ) | - | - | (25,900 | ) | |||||||||||||||||||||
Issuance of KGS common units | - | - | - | - | - | 11,054 | - | 11,054 | ||||||||||||||||||||||||
Distributions to parent | - | - | - | - | - | (22,276 | ) | 22,276 | - | |||||||||||||||||||||||
Distributions to noncontrolling interests | - | - | - | - | - | (13,550 | ) | - | (13,550 | ) | ||||||||||||||||||||||
Proceeds from exercise of stock options | 1,388 | - | - | - | 1,388 | - | - | 1,388 | ||||||||||||||||||||||||
Treasury transactions - equity | (4,851 | ) | - | - | - | (4,851 | ) | (1,144 | ) | - | (5,995 | ) | ||||||||||||||||||||
Net cash flow provided by financing activities | 34,528 | - | (6,911 | ) | - | 27,617 | 87,184 | 22,276 | 137,077 | |||||||||||||||||||||||
Effect of exchange rates on cash | - | - | (306 | ) | - | (306 | ) | - | - | (306 | ) | |||||||||||||||||||||
Net decrease in cash and equivalents | 14,915 | - | (875 | ) | - | 14,040 | (689 | ) | - | 13,351 | ||||||||||||||||||||||
Cash and equivalents at beginning of period | 5 | - | 1,034 | - | 1,039 | 746 | - | 1,785 | ||||||||||||||||||||||||
Cash and equivalents at end of period | $ | 14,920 | $ | - | $ | 159 | $ | - | $ | 15,079 | $ | 57 | $ | - | $ | 15,136 | ||||||||||||||||
For the Nine Months Ended September 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 | $ | 260,402 | $ | 47,666 | $ | 121,102 | $ | - | $ | 429,170 | $ | 51,268 | $ | (29,845 | ) | $ | 450,593 | |||||||||||||||
Purchases of property, plant and equipment | (387,938 | ) | (47,666 | ) | (79,745 | ) | - | (515,349 | ) | (55,712 | ) | 9,941 | (561,120 | ) | ||||||||||||||||||
Proceeds from sales of property and equipment | 220,270 | - | 768 | - | 221,038 | - | - | 221,038 | ||||||||||||||||||||||||
Net cash flow used for investing activities | (167,668 | ) | (47,666 | ) | (78,977 | ) | - | (294,311 | ) | (55,712 | ) | 9,941 | (340,082 | ) | ||||||||||||||||||
Issuance of debt | 1,278,138 | - | 52,887 | - | 1,331,025 | 46,500 | - | 1,377,525 | ||||||||||||||||||||||||
Repayments of debt | (1,396,105 | ) | - | (96,532 | ) | - | (1,492,637 | ) | (14,500 | ) | - | (1,507,137 | ) | |||||||||||||||||||
Debt issuance costs | (29,870 | ) | - | (1,125 | ) | - | (30,995 | ) | - | - | (30,995 | ) | ||||||||||||||||||||
Gas Purchase Commitment -net | 54,488 | - | - | - | 54,488 | - | - | 54,488 | ||||||||||||||||||||||||
Distributions to parent | - | - | - | - | - | (19,904 | ) | 19,904 | - | |||||||||||||||||||||||
Distributions to noncontrolling interests | - | - | - | - | - | (7,344 | ) | - | (7,344 | ) | ||||||||||||||||||||||
Other | (44 | ) | - | - | - | (44 | ) | (63 | ) | - | (107 | ) | ||||||||||||||||||||
Net cash flow provided by (used for) financing activities | (93,393 | ) | - | (44,770 | ) | - | (138,163 | ) | 4,689 | 19,904 | (113,570 | ) | ||||||||||||||||||||
Effect of exchange rates on cash | - | - | 1,779 | - | 1,779 | - | - | 1,779 | ||||||||||||||||||||||||
Net decrease in cash and equivalents | (659 | ) | - | (866 | ) | - | (1,525 | ) | 245 | - | (1,280 | ) | ||||||||||||||||||||
Cash and equivalents at beginning of period | 1,679 | - | 866 | - | 2,545 | 303 | - | 2,848 | ||||||||||||||||||||||||
Cash and equivalents at end of period | $ | 1,020 | $ | - | $ | - | $ | - | $ | 1,020 | $ | 548 | $ | - | $ | 1,568 | ||||||||||||||||
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, prior to the Crestwood Transaction, we operated in the midstream segment, where we provided natural gas processing and gathering services in the United States. On a consolidated basis, we eliminated revenues earned for the processing and gathering by our midstream operations and the fees paid for these services by our exploration and production segment. We evaluate performance of our operations based on operating income and property and equipment costs incurred. Note 2 provides additional information regarding the Crestwood Transaction and our midstream operations.
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Exploration & Production | Corporate | Quicksilver | ||||||||||||||||||||||
United States | Canada | Midstream | and Other | Elimination | Consolidated | |||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
For the Three Months Ended September 30, 2010 | ||||||||||||||||||||||||
Revenues | $ | 204,389 | $ | 28,609 | $ | 31,590 | $ | - | $ | (26,888 | ) | $ | 237,700 | |||||||||||
Depletion, depreciation and accretion | 33,963 | 10,676 | 7,387 | 516 | - | 52,542 | ||||||||||||||||||
Operating income | 93,266 | 7,850 | (11,503 | ) | (24,521 | ) | - | 65,092 | ||||||||||||||||
Property and equipment costs incurred | 100,678 | 20,140 | 12,209 | 1,056 | - | 134,083 | ||||||||||||||||||
For the Three Months Ended September 30, 2009 | ||||||||||||||||||||||||
Revenues | $ | 157,407 | $ | 47,648 | $ | 24,287 | $ | - | $ | (22,685 | ) | $ | 206,657 | |||||||||||
Depletion, depreciation and accretion | 27,957 | 9,321 | 6,836 | 434 | - | 44,548 | ||||||||||||||||||
Operating income | 82,747 | 28,354 | 10,718 | (18,116 | ) | - | 103,703 | |||||||||||||||||
Property and equipment costs incurred | 80,852 | 13,925 | 43,946 | 362 | - | 139,085 | ||||||||||||||||||
For the Nine Months Ended September 30, 2010 | ||||||||||||||||||||||||
Revenue | $ | 582,283 | $ | 93,158 | $ | 85,576 | $ | - | $ | (72,589 | ) | $ | 688,428 | |||||||||||
Depletion, depreciation and accretion | 93,620 | 33,114 | 21,799 | 1,435 | - | 149,968 | ||||||||||||||||||
Operating income | 272,186 | 27,118 | 13,680 | (63,180 | ) | - | 249,804 | |||||||||||||||||
Property and equipment costs incurred | 424,962 | 55,274 | 49,160 | 3,023 | - | 532,419 | ||||||||||||||||||
For the Nine Months Ended September 30, 2009 | ||||||||||||||||||||||||
Revenue | $ | 452,403 | $ | 140,786 | $ | 73,682 | $ | - | $ | (68,241 | ) | $ | 598,630 | |||||||||||
Depletion, depreciation and accretion | 106,338 | 29,284 | 18,346 | 1,242 | - | 155,210 | ||||||||||||||||||
Operating income | (589,707 | ) | (96,487 | ) | 35,472 | (60,694 | ) | - | (711,416 | ) | ||||||||||||||
Property and equipment costs incurred | 308,905 | 70,440 | 92,226 | 2,018 | - | 473,589 | ||||||||||||||||||
Property, Plant and Equipment-net(1) | ||||||||||||||||||||||||
September 30, 2010 | $ | 2,373,395 | $ | 526,991 | $ | - | $ | 13,302 | $ | - | $ | 2,913,688 | ||||||||||||
December 31, 2009 | 2,039,694 | 491,528 | - | 11,623 | - | 2,542,845 |
(1) | Property, plant and equipment of our midstream operations are included in assets of midstream operations held for sale, which is further discussed in Note 2. |
13. SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid (received) for interest and income taxes is as follows:
Nine Months Ended September 30, | ||||||||
2010 | 2009 | |||||||
(In thousands) | ||||||||
Interest | $ | 120,989 | $ | 111,549 | ||||
Income taxes | (6,917 | ) | (41,267 | ) |
Other non-cash transactions include:
Nine Months Ended September 30, | ||||||||
2010 | 2009 | |||||||
(In thousands) | ||||||||
Working capital related to acquisition of property, plant and equipment | $ | 98,989 | $ | 126,520 | ||||
Conveyance of 3,619,901 BBEP common units for producing properties | 54,407 | - | ||||||
Quicksilver common shares received for cashless exercise of 34,415 stock options | 214 | - |
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14. RELATED-PARTY TRANSACTIONS
In October 2010, members of the Darden family (“the Darden Investor Group”) sent a letter to our board of directors in which they expressed an interest in pursuing strategic alternatives for Quicksilver, including potentially taking us private. Our board of directors has formed a committee of independent directors to consider any transaction that may be proposed by the Darden Investor Group, as well as alternative transactions. The transaction committee retained independent legal and financial advisors. We are presently unable to assess the most likely outcome from this process or its impact on our stock price, financial position or results of operations.
As of September 30, 2010, members of the Darden family and entities controlled by them beneficially owned a significant amount of our outstanding common stock. Thomas F. Darden, Glenn Darden and Anne Darden Self are also officers and directors of Quicksilver.
Quicksilver and its associated entities paid $0.7 million and $0.6 million in the first nine months of 2010 and 2009, respectively, 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 $0.6 million and $0.2 million during the first nine months of 2010 and 2009, respectively, 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 nine months of 2010 and 2009 totaled $0.3 million and $0.2 million, respectively. During the third quarter of 2010, we entered into a lease agreement with Mercury to sublease a portion of the office space in Burnett Plaza on terms substantially the same as our office lease in Burnett Plaza.
In connection with our lease of office space, beginning in August 2010, an entity affiliated with Mercury received a $1.3 million commission from the lessor.
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ITEM 2. | Management’s 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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our 2009 Annual Report onForm 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.
2010 HIGHLIGHTS
Strategic Alternatives for Quicksilver
In October 2010, members of the Darden family (“the Darden Investor Group”) sent a letter to our board of directors in which they expressed an interest in pursuing strategic alternatives for Quicksilver, including potentially taking us private. In response, our board of directors has formed a committee of independent directors to consider any transaction that may be proposed by the Darden Investor Group, as well as alternative transactions. The transaction committee retained independent legal and financial advisors. We are presently unable to assess the most likely outcome from this process or its impact on our stock price, financial position or results of operations.
Crestwood Transaction, Hill County Dry System and Midstream Operations
In July 2010, we entered into a definitive agreement to sell all of our interests in our publicly traded midstream partnership. We completed the sale to Crestwood in October 2010. The Crestwood Transaction included our conveying:
• | a 100% ownership interest in Quicksilver Gas Services Holdings LLC, which owned: |
• | 5,696,752 common units of KGS; |
• | 11,513,625 subordinated units of KGS representing limited partner interests in KGS; |
• | 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; and, |
• | a subordinated promissory note issued to us by KGS with a carrying value of $58 million at September 30, 2010. |
We received $701 million in cash at closing and recognized a gain of approximately $540 million after consideration of approximately $2.6 million in transaction costs. We have the right to earn up to an additional $72 million in future earn-out payments in 2012 and 2013.
Under the agreements governing the Crestwood Transaction, both parties agreed for two years not to solicit employees of the other party and we agreed not to compete with KGS with respect to the 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 are entitled to appoint a director to KGS’ general partner’s board of directors until the later of the second anniversary of the closing and such time as we generate less than 50% of their consolidated revenue in any fiscal year. Pursuant to this right, we have appointed Thomas F. Darden as a director of KGS’ general partner’s board of directors.
In connection with the closing of the Crestwood Transaction, we are providing transitional services to KGS for up to six months on customary terms. KGS and we also entered into an agreement for the joint development of areas governed by certain of our existing commercial agreements and further, we amended our existing commercial agreements. The most significant amendments include extending the terms of all gathering agreements with KGS through 2020 and establishing a fixed gathering rate of $0.55 per Mcf in the Alliance gathering system.
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In September 2010, our board of directors approved a plan for disposal of our HCDS, a gathering system in Hill County, Texas, which gathers natural gas and delivers it to unaffiliated pipelines for further transport and sale downstream. As a result of the decision, we conducted an impairment analysis of the HCDS and recognized impairment expense of $31.5 million.
We have continued to report our interests sold in the Crestwood Transaction and the HCDS as part of our continuing operating results because their providing midstream services to us constitutes a “continuation of service” that precludes presentation of those businesses as discontinued operations under GAAP. The assets and liabilities of these operations have been reclassified and are segregated in our consolidated balance sheets. The following summarizes the significant items related to our midstream operations:
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Income (loss) before income tax for: | (in thousands) | (in thousands) | ||||||||||||||
Midstream operations - KGS | $ | 14,253 | $ | 10,164 | $ | 34,401 | $ | 32,755 | ||||||||
Midstream operations - HCDS | 119 | (645 | ) | (56 | ) | (645 | ) | |||||||||
Midstream impairment expense | (31,531 | ) | - | (31,531 | ) | - | ||||||||||
Transaction costs | (2,560 | ) | - | (2,560 | ) | - | ||||||||||
Results of midstream operations before income tax | (19,719 | ) | 9,519 | 254 | 32,110 | |||||||||||
Income tax expense (benefit) | (6,981 | ) | 3,719 | 91 | 11,975 | |||||||||||
Results of midstream operations, net of income tax | $ | (12,738 | ) | $ | 5,800 | $ | 163 | $ | 20,135 | |||||||
Lake Arlington Acquisition
In May 2010, we completed the acquisition of an additional 25% working interest in our company-operated Lake Arlington Project. We acquired the additional working interests in the Lake Arlington Project for which we conveyed $62.1 million in cash and 3,619,901 of the BBEP common units that we owned. The acquired interests include proved natural gas reserves of approximately 125 Bcf of which 82% are proved developed. 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 have named two directors to the board of directors of BBEP’s 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. We have also received quarterly distributions totaling $14.8 million in 2010. Completion of additional working interests in the Lake Arlington project in May 2010 and the sale of 1.4 million units in September 2010 reduced our ownership of BBEP to approximately 31%. In October 2010, we sold an additional 650,000 units at a unit price of $17.72 and a recognized a gain of $7.7 million. Subsequent to the October unit sale, our ownership of BBEP decreased to approximately 29%.
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 Crestwood Transaction, which causes our exit from the midstream business. We may possibly redeploy additional capital toward our exploration and production activities. We currently expect that our 2010 capital program will total approximately $560 million, excluding approximately $170 million for 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 $475 million for exploration and development activities. Our 2010 capital program has $85 million for midstream facilities of which $37 million will be spent in Canada and $48 million was spent in the U.S. directly by KGS prior to the closing of the Crestwood Transaction. On a regional basis, approximately $460 million is forecasted to be spent in Texas to drill approximately 82 net wells on operated properties and to complete and tie-in approximately 105 net wells. Canadian spending for
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2010 is forecasted to be approximately $90 million chiefly to explore the Horn River Basin and develop midstream infrastructure for that project 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 September 30, 2010 and 2009
The following discussion compares the results of operations for the three months ended September 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 | $ | 85.0 | $ | 45.7 | $ | 37.5 | $ | 36.1 | $ | 2.7 | $ | 3.3 | $ | 125.2 | $ | 85.1 | ||||||||||||||||
Other U.S. | 0.4 | 0.2 | (0.1 | ) | 0.2 | 2.6 | 2.2 | 2.9 | 2.6 | |||||||||||||||||||||||
Hedging | 63.5 | 63.1 | (1.7 | ) | - | - | - | 61.8 | 63.1 | |||||||||||||||||||||||
Total U.S. | 148.9 | 109.0 | 35.7 | 36.3 | 5.3 | 5.5 | 189.9 | 150.8 | ||||||||||||||||||||||||
Canada | 21.0 | 18.0 | - | - | - | - | 21.0 | 18.0 | ||||||||||||||||||||||||
Hedging | 7.3 | 29.5 | - | - | - | - | 7.3 | 29.5 | ||||||||||||||||||||||||
Total Canada | 28.3 | 47.5 | - | - | - | - | 28.3 | 47.5 | ||||||||||||||||||||||||
Total Company | $ | 177.2 | $ | 156.5 | $ | 35.7 | $ | 36.3 | $ | 5.3 | $ | 5.5 | $ | 218.2 | $ | 198.3 | ||||||||||||||||
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 | 217.3 | 153.0 | 12,567 | 13,971 | 409 | 565 | 295.1 | 240.2 | ||||||||||||||||||||||||
Other U.S. | 1.1 | 0.4 | (10 | ) | 49 | 425 | 416 | 3.7 | 3.2 | |||||||||||||||||||||||
Total U.S. | 218.4 | 153.4 | 12,557 | 14,020 | 834 | 981 | 298.8 | 243.4 | ||||||||||||||||||||||||
Canada | 63.6 | 67.8 | 5 | 4 | - | - | 63.6 | 67.8 | ||||||||||||||||||||||||
Total Company | 282.0 | 221.2 | 12,562 | 14,024 | 834 | 981 | 362.4 | 311.2 | ||||||||||||||||||||||||
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 | $ | 4.25 | $ | 3.25 | $ | 32.37 | $ | 28.11 | $ | 72.21 | $ | 62.46 | $ | 4.61 | $ | 3.85 | ||||||||||||||||
Other U.S. | 3.64 | 3.22 | 86.14 | 35.27 | 66.37 | 57.76 | 8.65 | 8.47 | ||||||||||||||||||||||||
Hedging - U.S. | 3.16 | 4.48 | (1.43 | ) | - | - | - | 2.25 | 2.82 | |||||||||||||||||||||||
Total U.S. | 7.41 | 7.73 | 30.90 | 28.14 | 69.32 | 60.55 | 6.91 | 6.73 | ||||||||||||||||||||||||
Canada | 3.59 | 2.88 | 61.62 | 69.88 | - | - | 3.60 | 2.88 | ||||||||||||||||||||||||
Hedging - Canada | 1.25 | 4.73 | - | - | - | - | 1.25 | 4.73 | ||||||||||||||||||||||||
Total Canada | 4.84 | 7.61 | 61.62 | 69.88 | - | - | 4.85 | 7.61 | ||||||||||||||||||||||||
Total Company | $ | 6.83 | $ | 7.69 | $ | 30.91 | $ | 28.15 | $ | 69.32 | $ | 60.55 | $ | 6.55 | $ | 6.93 |
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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 September 30, 2009 | $ | 156,500 | $ | 36,323 | $ | 5,464 | $ | 198,287 | ||||||||
Volume variance | 17,550 | (3,786 | ) | (816 | ) | 12,948 | ||||||||||
Hedge settlement variance | (21,925 | ) | (1,657 | ) | - | (23,582 | ) | |||||||||
Price variance | 25,076 | 4,847 | 673 | 30,596 | ||||||||||||
Revenue for the quarter ended September 30, 2010 | $ | 177,201 | $ | 35,727 | $ | 5,321 | $ | 218,249 | ||||||||
Natural gas revenue increased due to higher natural gas production and higher market prices in the 2010 quarter as compared to the 2009 quarter but was 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 Barnett Shale interests acquired or new wells placed into service since the 2009 quarter despite natural production declines from existing wells.
NGL revenue was flat due to higher market prices that were offset by payments made to settle hedges during the 2010 quarter and a 10% decrease in Texas 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 and NGL oil resulted in realized prices that varied from market prices received from the sale of our production. Our production revenue from natural gas and NGL production was $69.1 million and $92.6 million higher because of our hedging activities for the 2010 quarter and the 2009 quarter, respectively.
Sales of Purchased Natural Gas and Costs of Purchased Natural Gas
Three Months Ended | ||||||||
September 30, | ||||||||
2010 | 2009 | |||||||
(In thousands) | ||||||||
Sales of purchased natural gas: | ||||||||
Purchases from Eni | $ | 14,840 | $ | 2,168 | ||||
Purchases from others | 2,142 | 3,796 | ||||||
Total | 16,982 | 5,964 | ||||||
Costs of purchased natural gas sold: | ||||||||
Purchases from Eni | 18,711 | 1,301 | ||||||
Purchases from others | 1,424 | 3,814 | ||||||
Unrealized valuation (gain) loss on | ||||||||
Gas Purchase Commitment | (5,497 | ) | (2,151 | ) | ||||
Total | 14,638 | 2,964 | ||||||
Net sales and purchases of natural gas | $ | 2,344 | $ | 3,000 | ||||
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. The additional volumes purchased under the Gas Purchase Commitment are the result of new wells placed into production in the Alliance area, in which Eni owns a 27.5% working interest. The Gas Purchase Commitment is more fully described in Note 3 to our condensed consolidated financial statements.
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Oil and Gas Production Expense
Three Months Ended September 30, | ||||||||||||||||
2010 | 2009 | |||||||||||||||
(In thousands, except per unit amounts) | ||||||||||||||||
Per | Per | |||||||||||||||
Texas | Mcfe | Mcfe | ||||||||||||||
Lease operating expense | $ | 28,214 | $ | 1.04 | $ | 18,051 | $ | 0.82 | ||||||||
Equity compensation | 201 | 0.01 | 270 | 0.01 | ||||||||||||
$ | 28,415 | $ | 1.05 | $ | 18,321 | $ | 0.83 | |||||||||
Other U.S. | ||||||||||||||||
Lease operating expense | $ | 1,227 | $ | 3.71 | $ | 1,633 | $ | 5.53 | ||||||||
Equity compensation | 45 | 0.13 | 49 | 0.17 | ||||||||||||
$ | 1,272 | $ | 3.84 | $ | 1,682 | $ | 5.70 | |||||||||
Total U.S. | ||||||||||||||||
Lease operating expense | $ | 29,441 | $ | 1.07 | $ | 19,684 | $ | 0.88 | ||||||||
Equity compensation | 246 | 0.01 | 319 | 0.01 | ||||||||||||
$ | 29,687 | $ | 1.08 | $ | 20,003 | $ | 0.89 | |||||||||
Total Canada | ||||||||||||||||
Lease operating expense | $ | 9,439 | $ | 1.61 | $ | 8,594 | $ | 1.38 | ||||||||
Equity compensation | 276 | 0.05 | 467 | 0.07 | ||||||||||||
$ | 9,715 | $ | 1.66 | $ | 9,061 | $ | 1.45 | |||||||||
Total Company | ||||||||||||||||
Lease operating expense | $ | 38,880 | $ | 1.16 | $ | 28,278 | $ | 0.99 | ||||||||
Equity compensation | 522 | 0.02 | 786 | 0.03 | ||||||||||||
$ | 39,402 | $ | 1.18 | $ | 29,064 | $ | 1.02 | |||||||||
The increase in U.S. production expense was primarily associated with new wells placed into service, primarily in the Alliance and Lake Arlington areas. Production expense associated with processing and gathering costs borne by our midstream operations also increased because of the operation of the Alliance midstream assets placed into service in the fourth quarter of 2009.
Canadian production expense for the 2010 quarter increased from the 2009 quarter due to an additional $1.5 million for costs to operate our Horn River wells that we placed into production in the last half of 2009. Alberta production expense partially offset the Horn River increase due to lower lease operating expense primarily attributable to lower levels of maintenance activities in the Alberta area and lower production overhead. Production overhead decreased in part, because of lower staffing levels and a decrease in office rent that resulted from a new lease executed in 2010 at lower rental rates.
Production and Ad Valorem Taxes
Three Months Ended September 30, | ||||||||||||||||
2010 | 2009 | |||||||||||||||
(In thousands, except per unit amounts) | ||||||||||||||||
Per | Per | |||||||||||||||
Production taxes | Mcfe | Mcfe | ||||||||||||||
U.S. | $ | 2,265 | $ | 0.08 | $ | 1,648 | $ | 0.07 | ||||||||
Canada | 131 | 0.02 | 190 | 0.03 | ||||||||||||
Total production taxes | 2,396 | 0.08 | 1,838 | 0.06 | ||||||||||||
Ad valorem taxes | ||||||||||||||||
U.S. | $ | 6,537 | $ | 0.24 | $ | 4,070 | $ | 0.18 | ||||||||
Canada | 237 | 0.04 | 722 | 0.12 | ||||||||||||
Total ad valorem taxes | 6,774 | 0.20 | 4,792 | 0.17 | ||||||||||||
Production and ad valorem tax expense | $ | 9,170 | $ | 0.28 | $ | 6,630 | $ | 0.23 | ||||||||
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Fort Worth Basin production tax increases from the 2009 quarter were due to a 23% increase in production and a 20% increase in realized prices before hedge settlements. Higher ad valorem taxes for the 2010 quarter were the result of new wells placed into production in Texas during the full year of 2009. Ad valorem taxes also increased due to Alliance midstream assets placed into service during the fourth quarter of 2009.
Depletion, Depreciation and Accretion
Three Months Ended September 30, | ||||||||||||||||
2010 | 2009 | |||||||||||||||
(In thousands, except per unit amounts) | ||||||||||||||||
Per | Per | |||||||||||||||
Depletion | Mcfe | Mcfe | ||||||||||||||
U.S. | $ | 32,456 | $ | 1.17 | $ | 26,365 | $ | 1.18 | ||||||||
Canada | 9,079 | 1.55 | 7,985 | 1.28 | ||||||||||||
Total depletion | 41,535 | 1.24 | 34,350 | 1.20 | ||||||||||||
Depreciation of other fixed assets | ||||||||||||||||
U.S. | $ | 9,066 | $ | 0.33 | $ | 8,576 | $ | 0.38 | ||||||||
Canada | 1,141 | 0.20 | 1,039 | 0.17 | ||||||||||||
Total depreciation | 10,207 | 0.31 | 9,615 | 0.34 | ||||||||||||
Accretion | 800 | 0.03 | 583 | 0.02 | ||||||||||||
DD&A Expense | $ | 52,542 | $ | 1.58 | $ | 44,548 | $ | 1.56 | ||||||||
Depletion expense for the 2010 quarter increased from the 2009 quarter due to an increase in production and a higher Canadian depletion rate. Both our U.S. and Canadian depletion rates reflect the effects of impairment charges recognized during 2009. Total U.S. and Canadian impairment charges of $786.9 million and $192.7 million were recognized in 2009 and significantly reduced the depletion rates. Additional U.S. depreciation was primarily associated with Alliance midstream assets placed into service in the fourth quarter of 2009.
Impairment Expense
We recognized impairment expense of $31.5 million in the 2010 quarter related to our assessment of our midstream operations.
General and Administrative Expense
Three Months Ended September 30, | ||||||||||||||||
2010 | 2009 | |||||||||||||||
(In thousands, except per unit amounts) | ||||||||||||||||
Per | Per | |||||||||||||||
General and administrative expense | Mcfe | Mcfe | ||||||||||||||
Litigation settlement | $ | 2,400 | $ | 0.07 | $ | 1,000 | $ | 0.03 | ||||||||
Cash expense | 16,566 | 0.50 | 12,968 | 0.46 | ||||||||||||
Equity compensation | 5,039 | 0.15 | 3,714 | 0.13 | ||||||||||||
Total general and administrative expense | $ | 24,005 | $ | 0.72 | $ | 17,682 | $ | 0.62 | ||||||||
We recognized additional expense of $1.4 million for litigation settlement for the 2010 quarter when compared to the 2009 quarter. Compensation expense increased $2.1 million, including a $1.3 million increase in stock-based compensation expense. In connection with the Crestwood Transaction, transaction costs of $2.5 million, principally investment banking and legal fees, were recognized in the 2010 quarter. A further increase of $0.6 million was primarily the result of increased moving expense associated with our relocation to new office space.
BBEP-Related Income
During the 2010 quarter, we recognized income of $17.0 million for equity earnings from our investment in BBEP based upon its reported earnings for the quarter ended June 30, 2010 as compared to a loss of $43.7 million recognized in the 2009 quarter. BBEP continues to experience significant volatility in its net earnings due to changes in the value of its derivative instruments for which it does not employ hedge accounting.
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Other Income (Expense) – Net
In the 2010 quarter, we recognized a gain of $14.4 million from the sale of 1.4 million BBEP common units.
Interest Expense
Three Months Ended | ||||||||
September 30, | ||||||||
2010 | 2009 | |||||||
(in thousands) | ||||||||
Interest costs on debt outstanding | $ | 48,850 | $ | 38,676 | ||||
Add: Non-cash interest(1) | 4,080 | 4,705 | ||||||
Less: Interest capitalized | (1,398 | ) | (1,762 | ) | ||||
Interest expense | $ | 51,532 | $ | 41,619 | ||||
(1) | Amortization of deferred financing costs and original issue discounts |
Interest costs for the 2010 quarter were higher than the 2009 quarter primarily because of a $5.2 million decrease in gains recognized from interest rate hedges and a small increase in the average interest rate charged on our outstanding indebtedness, which was also slightly higher than the 2009 quarter average.
Income Tax Expense
Three Months Ended | ||||||||
September 30, | ||||||||
2010 | 2009 | |||||||
Income tax expense (in thousands) | $ | 18,268 | $ | 15,595 | ||||
Effective tax rate | 40.7 | % | 87.8 | % |
Our provision for income taxes for the 2010 quarter increased from the 2009 quarter due to higher income before taxes. The effective tax rate for the 2010 quarter includes $2.2 million attributable to the 6 months ended June 30, 2010 for changes in our estimated annual effective tax rate for 2010, which had been forecasted at a rate of 34.5% through June 30, 2010. We now expect a rate of 35.9% based on changes to the expected earnings mix between the U.S. and Canada. The change in the expected rate for 2010 required third quarter recognition of the cumulative amount to bring the year to date income tax provision to the 35.9% level. The effective tax rate for the 2009 quarter also included $9.6 million for an increase in the full-year effective income tax rate for 2009 attributable to earlier quarters.
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RESULTS OF OPERATIONS – Nine Months Ended September 30, 2010 and 2009
The following discussion compares the results of operations for the nine months ended September 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 | $ | 241.1 | $ | 170.5 | $ | 115.8 | $ | 94.2 | $ | 8.9 | $ | 10.5 | $ | 365.8 | $ | 275.2 | ||||||||||||||||
Other U.S. | 1.9 | 0.2 | 0.4 | 0.1 | 7.4 | 5.5 | 9.7 | 5.8 | ||||||||||||||||||||||||
Hedging | 179.7 | 159.4 | (15.3 | ) | - | - | - | 164.4 | 159.4 | |||||||||||||||||||||||
Total U.S. | 422.7 | 330.1 | 100.9 | 94.3 | 16.3 | 16.0 | 539.9 | 440.4 | ||||||||||||||||||||||||
Canada | 76.1 | 65.0 | 0.1 | 0.1 | - | - | 76.2 | 65.1 | ||||||||||||||||||||||||
Hedging | 15.3 | 75.6 | - | - | - | - | 15.3 | 75.6 | ||||||||||||||||||||||||
Total Canada | 91.4 | 140.6 | 0.1 | 0.1 | - | - | 91.5 | 140.7 | ||||||||||||||||||||||||
Total Company | $ | 514.1 | $ | 470.7 | $ | 101.0 | $ | 94.4 | $ | 16.3 | $ | 16.0 | $ | 631.4 | $ | 581.1 | ||||||||||||||||
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 | 198.8 | 166.3 | 11,869 | 14,038 | 448 | 794 | 272.7 | 255.3 | ||||||||||||||||||||||||
Other U.S. | 1.6 | 0.3 | 19 | 31 | 403 | 440 | 4.2 | 3.2 | ||||||||||||||||||||||||
Total U.S. | 200.4 | 166.6 | 11,888 | 14,069 | 851 | 1,234 | 276.9 | 258.5 | ||||||||||||||||||||||||
Canada | 66.8 | 66.1 | 7 | 5 | - | 2 | 66.8 | 66.1 | ||||||||||||||||||||||||
Total Company | 267.2 | 232.7 | 11,895 | 14,074 | 851 | 1,236 | 343.7 | 324.6 | ||||||||||||||||||||||||
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 | $ | 4.44 | $ | 3.76 | $ | 35.75 | $ | 24.57 | $ | 72.96 | $ | 48.33 | $ | 4.91 | $ | 3.95 | ||||||||||||||||
Other U.S. | 4.31 | 3.33 | 63.30 | 26.08 | 67.28 | 45.82 | 8.48 | 6.93 | ||||||||||||||||||||||||
Hedging - U.S. | 3.28 | 3.50 | (4.71 | ) | - | - | - | 2.17 | 2.26 | |||||||||||||||||||||||
Total U.S. | 7.72 | 7.26 | 31.09 | 24.56 | 70.31 | 47.42 | 7.14 | 6.24 | ||||||||||||||||||||||||
Canada | 4.18 | 3.61 | 66.78 | 63.37 | - | - | 4.18 | 3.61 | ||||||||||||||||||||||||
Hedging - Canada | 0.84 | 4.19 | - | - | - | - | 0.84 | 4.19 | ||||||||||||||||||||||||
Total Canada | 5.01 | 7.80 | 66.78 | 63.37 | - | - | 5.02 | 7.80 | ||||||||||||||||||||||||
Total Company | $ | 7.05 | $ | 7.41 | $ | 31.12 | $ | 24.57 | $ | 70.31 | $ | 47.44 | $ | 6.73 | $ | 6.56 |
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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 nine months ended September 30, 2009 | $ | 470,724 | $ | 94,421 | $ | 16,011 | $ | 581,156 | ||||||||
Volume variance | 34,980 | (14,616 | ) | (4,987 | ) | 15,377 | ||||||||||
Hedge settlement variance | (39,853 | ) | (15,271 | ) | - | (55,124 | ) | |||||||||
Price variance | 48,264 | 36,511 | 5,315 | 90,090 | ||||||||||||
Revenue for the nine months ended September 30, 2010 | $ | 514,115 | $ | 101,045 | $ | 16,339 | $ | 631,499 | ||||||||
Increases in 2010 period natural gas market prices compared to the 2009 period and increases in natural gas volumes produced from the Barnett Shale were partially offset by a decrease in revenue from hedge settlements for the 2010 period as compared to the 2009 period. An increase in natural gas volumes in Texas was the result of Barnett Shale interests acquired or new wells placed into service after September 2009 partially offset by the 9.3 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 a 15% decrease in Texas 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 and NGL 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 $179.7 million and $234.8 million higher because of our hedging activities for the 2010 period and the 2009 period, respectively.
We expect our average production for the fourth quarter of 2010 to range between 385 MMcfed to 395 MMcfed, which would yield average production for all of 2010 between 354 MMcfed to 357 MMcfed.
Sales of Purchased Natural Gas and Costs of Purchased Natural Gas
Nine Months Ended | ||||||||
September 30, | ||||||||
2010 | 2009 | |||||||
(In thousands) | ||||||||
Sales of purchased natural gas: | ||||||||
Purchases from Eni | $ | 41,405 | $ | 2,642 | ||||
Purchases from others | 8,622 | 8,539 | ||||||
Total | 50,027 | 11,181 | ||||||
Costs of purchased natural gas sold: | ||||||||
Purchases from Eni | 49,112 | 2,204 | ||||||
Purchases from others | 8,549 | 7,675 | ||||||
Unrealized valuation (gain) loss on | ||||||||
Gas Purchase Commitment | (5,960 | ) | 1,667 | |||||
Total | 51,701 | 11,546 | ||||||
Net sales and purchases of natural gas | $ | (1,674 | ) | $ | (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 nine months of activity. Purchases of natural gas made under the Gas Purchase Commitment have also increased because of additional natural gas volumes that have resulted from new wells placed into production in the Alliance area that is covered by the Gas Purchase Commitment. The Gas Purchase Commitment is more fully described in Note 3 to our condensed consolidated financial statements.
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Oil and Gas Production Expense
Nine Months Ended September 30, | ||||||||||||||||
2010 | 2009 | |||||||||||||||
(In thousands, except per unit amounts) | ||||||||||||||||
Per | Per | |||||||||||||||
Texas | Mcfe | Mcfe | ||||||||||||||
Lease operating expense | $ | 77,828 | $ | 1.04 | $ | 61,112 | $ | 0.88 | ||||||||
Equity compensation | 630 | 0.01 | 785 | 0.01 | ||||||||||||
$ | 78,458 | $ | 1.05 | �� $ | 61,897 | $ | 0.89 | |||||||||
Other U.S. | ||||||||||||||||
Lease operating expense | $ | 4,435 | $ | 3.01 | $ | 4,913 | $ | 5.70 | ||||||||
Equity compensation | 131 | 0.11 | 147 | 0.17 | ||||||||||||
$ | 4,566 | $ | 3.12 | $ | 5,060 | $ | 5.87 | |||||||||
Total U.S. | ||||||||||||||||
Lease operating expense | $ | 82,263 | $ | 1.09 | $ | 66,025 | $ | 0.94 | ||||||||
Equity compensation | 761 | 0.01 | 932 | 0.01 | ||||||||||||
$ | 83,024 | $ | 1.10 | $ | 66,957 | $ | 0.95 | |||||||||
Total Canada | ||||||||||||||||
Lease operating expense | $ | 29,692 | $ | 1.63 | $ | 24,399 | $ | 1.37 | ||||||||
Equity compensation | 877 | 0.05 | 1,582 | 0.07 | ||||||||||||
$ | 30,569 | $ | 1.68 | $ | 25,981 | $ | 1.44 | |||||||||
Total Company | ||||||||||||||||
Lease operating expense | $ | 111,955 | $ | 1.19 | $ | 90,424 | $ | 1.02 | ||||||||
Equity compensation | 1,638 | 0.02 | 2,514 | 0.03 | ||||||||||||
$ | 113,593 | $ | 1.21 | $ | 92,938 | $ | 1.05 | |||||||||
The increase in U.S. production expense was primarily the result of additional wells, largely in the Alliance and Lake Arlington areas, and placing the Alliance midstream assets into service in the fourth quarter of 2010.
Canadian production expense for the 2010 period increased from the 2009 period due to a $5.1 million increase in production expense to operate our Horn River wells in British Columbia that were placed into production in the last half of 2009. Production expense for our operations in Alberta remained steady although there was a decrease of $3.8 million on a Canadian dollar-basis and resulted from decreased levels of maintenance, repairs and workovers. Canadian production overhead was also lower on a Canadian dollar-basis due to a decrease in Canadian staff and lower office expense that resulted from the inception of a new lease in early 2010.
Production and Ad Valorem Taxes
Nine Months Ended September 30, | ||||||||||||||||
2010 | 2009 | |||||||||||||||
(In thousands, except per unit amounts) | ||||||||||||||||
Per | Per | |||||||||||||||
Production taxes | Mcfe | Mcfe | ||||||||||||||
U.S. | $ | 7,183 | $ | 0.10 | $ | 4,230 | $ | 0.06 | ||||||||
Canada | 479 | 0.03 | 94 | 0.01 | ||||||||||||
Total production taxes | 7,662 | 0.08 | 4,324 | 0.05 | ||||||||||||
Ad valorem taxes | ||||||||||||||||
U.S. | $ | 17,001 | 0.22 | $ | 12,459 | 0.18 | ||||||||||
Canada | 1,879 | 0.10 | 1,654 | 0.09 | ||||||||||||
Total ad valorem taxes | 18,880 | 0.20 | 14,113 | 0.16 | ||||||||||||
Production and ad valorem tax expense | $ | 26,542 | $ | 0.28 | $ | 18,437 | $ | 0.21 | ||||||||
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Ad valorem tax increases were due in part to additional wells placed into service in Texas in 2009. Ad valorem taxes in Texas also increased because of the Alliance midstream assets placed into service in the fourth quarter of 2009. Texas production tax increases were due to a 24% increase in realized prices before hedge settlements, a 7% increase in production volumes and a reduction in the number of new wells that qualified for exemptions or rate reductions.
Depletion, Depreciation and Accretion
Nine Months Ended September 30, | ||||||||||||||||
2010 | 2009 | |||||||||||||||
(In thousands, except per unit amounts) | ||||||||||||||||
Per | Per | |||||||||||||||
Depletion | Mcfe | Mcfe | ||||||||||||||
U.S. | $ | 89,301 | $ | 1.17 | $ | 101,045 | $ | 1.43 | ||||||||
Canada | 28,395 | 1.56 | 25,494 | 1.41 | ||||||||||||
Total depletion | 117,696 | 1.25 | 126,539 | 1.43 | ||||||||||||
Depreciation of other fixed assets | ||||||||||||||||
U.S. | $ | 26,574 | $ | 0.35 | $ | 24,093 | $ | 0.34 | ||||||||
Canada | 3,384 | 0.19 | 2,856 | 0.16 | ||||||||||||
Total depreciation | 29,958 | 0.32 | 26,949 | 0.30 | ||||||||||||
Accretion | 2,314 | 0.03 | 1,722 | 0.02 | ||||||||||||
Total DD&A | $ | 149,968 | $ | 1.60 | $ | 155,210 | $ | 1.75 | ||||||||
Depletion expense for the 2010 period decreased from the 2009 period due to a decrease in U.S. depletion rate. Increased production and a higher Canadian depletion rate partially offset the effects of a lower U.S. depletion rate. Both our U.S. and Canadian depletion rates have been impacted by impairment charges recognized 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 was the result of placing the Alliance midstream assets into service over the fourth quarter of 2009.
Impairment Expense
We recognized impairment expense of $31.5 million in the 2010 quarter related to our assessment of our midstream operations. Impairment expense in the 2009 period relates to our ceiling tests for our oil and gas properties.
General and Administrative Expense
Nine Months Ended September 30, | ||||||||||||||||
2010 | 2009 | |||||||||||||||
(In thousands, except per unit amounts) | ||||||||||||||||
Per | Per | |||||||||||||||
General and administrative expense | Mcfe | Mcfe | ||||||||||||||
Litigation settlement | $ | 2,400 | $ | 0.03 | $ | 6,000 | $ | 0.07 | ||||||||
Cash expense | 44,368 | 0.47 | 40,483 | 0.45 | ||||||||||||
Equity compensation | 14,977 | 0.16 | 12,969 | 0.15 | ||||||||||||
Total general and administrative expense | $ | 61,745 | $ | 0.66 | $ | 59,452 | $ | 0.67 | ||||||||
Compensation expense increased $5.5 million, including a $2.0 million increase in stock-based compensation expense. Additionally, legal and professional fees were almost unchanged as the decrease of expenses related to our litigation with BBEP in April 2010 was nearly offset by $2.5 million incurred for transaction costs, principally investment banking and legal fees, related to the Crestwood Transaction. Those increases were partially offset by a $3.6 million decrease for litigation settlement.
BBEP-Related Income
During the 2010 period, we recognized income of $24.2 million for equity earnings from our investment in BBEP based upon its reported earnings for the nine-month period ended June 30, 2010 as compared to income of $77.4 million recognized in the 2009 period. BBEP continues to experience significant volatility in its net earnings due to changes in the value of its
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derivative instruments for which it does not employ hedge accounting. Additionally, we have reduced our ownership of BBEP common units in the 2010 period.
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 September 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 period, 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. A gain of $14.4 million was recognized in the 2010 quarter from the sale of 1.4 million BBEP common units. Notes 4, 5 and 8 to the condensed consolidated financial statements found in this quarterly report contain additional information about these transactions.
Interest Expense
Nine Months Ended | ||||||||
September 30, | ||||||||
2010 | 2009 | |||||||
(in thousands) | ||||||||
Interest costs on debt outstanding | $ | 133,003 | $ | 113,972 | ||||
Add: Non-cash interest(1) | 13,372 | 13,431 | ||||||
Loss on early debt extinguishment | - | 27,122 | ||||||
Less: Interest capitalized | (4,204 | ) | (4,624 | ) | ||||
Interest expense | $ | 142,171 | $ | 149,901 | ||||
(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 $7.7 million in the 2010 period. These decreases were partially offset by an increase in the average interest rate charged on our outstanding indebtedness.
We anticipate a marked decrease in interest expense for the fourth quarter as a result of our repayment of all our outstanding borrowings under the Senior Secured Credit Facility using a portion of the proceeds from the Crestwood Transaction.
Income Tax Expense
Nine Months Ended | ||||||||
September 30, | ||||||||
2010 | 2009 | |||||||
Income tax (benefit) expense (in thousands) | $ | 71,569 | $ | (301,125 | ) | |||
Effective tax rate | 35.9 | % | 34.0 | % |
Our provision for income taxes for the 2010 period increased from the 2009 period due to higher income before taxes. Also, the impact of permanent items for non-deductible expenses impact the income tax rate applied to pretax income in 2010 and pretax loss in 2009. The effective tax rate for the 2010 period was 35.9%, which we expect to be our effective income tax rate for all of 2010.
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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 do not materially differ from our consolidated results of operations from continuing operations. The combined financial position of the Company and its restricted subsidiaries and our consolidated financial position are materially the same except for the assets and liabilities of our midstream operations. 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 inLiquidity, Capital Resources and Financial Condition.
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 affected by instability in the capital markets.
Nine Months Ended | ||||||||
September 30, | ||||||||
2010 | 2009 | |||||||
(In thousands) | ||||||||
Net cash provided by operating activities | $ | 347,390 | $ | 450,593 | ||||
Net cash used for investing activities | (470,810 | ) | (340,082 | ) | ||||
Net cash provided by (used for) financing activities | 137,077 | (113,570 | ) |
Operating Cash Flows
Net cash provided by operations for the 2010 period decreased from the comparable 2009 period, including a $154.3 million decrease in cash receipts for settlements of commodity derivatives and a $34.3 million decrease in cash receipts from income tax refunds. Interest payments made to lenders increased $58.7 million before consideration of an additional $49.5 million in cash receipts from interest rate swap settlements, including $30.8 million in 2010 for early settlements. These reductions of operating cash were partially offset by additional revenue of $105.5 million from higher production volumes and higher market prices during 2010 partially offset by increased operating expense. We also received $18.0 million for resolution of our BBEP litigation.
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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:
Production | Daily Production | |||
Year | Gas | NGL | ||
MMcfd | MBbld | |||
2010 | 200 | 10 | ||
2011 | 150 | 8 | ||
2012 | 90 | - | ||
2013 - 2015 | 30 | - |
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:
Nine Months Ended | ||||||||
September 30, | ||||||||
2010 | 2009 | |||||||
Exploration and development: | (In thousands) | |||||||
Texas | $ | 401,633 | $ | 281,674 | ||||
Other U.S. | 20,782 | 23,582 | ||||||
Total U.S. | 422,415 | 305,256 | ||||||
British Columbia | 41,228 | 53,040 | ||||||
Alberta | 13,604 | 17,076 | ||||||
Total Canada | 54,832 | 70,116 | ||||||
Total exploration and development | 477,247 | 375,372 | ||||||
Corporate and field office | 6,012 | 5,991 | ||||||
Total ongoing operations | 483,259 | 381,363 | ||||||
Midstream - Texas | 49,160 | 92,226 | ||||||
532,419 | 473,589 | |||||||
Capital expenditures, including non-cash expenditures, for exploration and development in the 2010 period increased from the 2009 period primarily due to our $125.6 million acquisition of additional working interests in our Lake Arlington Project partially offset by lower expenditures in Canada. Decreases in Canadian expenditures from the 2009 period consisted of a $3.4 million decrease in development costs for our Alberta CBM properties and an $11.8 million decrease in costs for Horn River Basin exploration. There was also a $43.1 million decrease from 2009 period capital expenditures for our midstream operations. U.S. capital expenditures increased slightly because of capital expenditures directed toward reducing our inventory of drilled-but-uncompleted wells in the Fort Worth Basin. We partially funded our capital expenditures with the sale of 1.4 million of BBEP common units for $22.5 million. Proceeds of $11.5 million from our October 2010 sale of 650,000 common units of BBEP will impact our fourth quarter investing cash flows.
Financing Cash Flows
During the 2010 period, our borrowings under our Senior Secured Credit Facility increased $61.7 million, including a $4.6 million increase due to changes in the U.S.-Canadian exchange rates. The increase in borrowings was primarily the result of the timing of capital expenditures, including additional working interests in our Lake Arlington Project. The lenders under our Senior Secured Credit Facility re-affirmed our $1.0 billion borrowing base in May 2010.
Crestwood Transaction and Proceeds
After closing the Crestwood Transaction in October 2010, we fully repaid our borrowings under the Senior Secured Credit Facility. We expect the remaining proceeds will be used principally to fund our fourth quarter income tax liability of approximately $130 million.
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Financial Position
The following summarizes the significant changes to our balance sheet as of September 30, 2010, as compared to our December 31, 2009 balance sheet:
• | Our current and non-current derivative assets and liabilities increased $115.3 million on a net basis. The valuation of our remaining open commodity derivative positions increased $259.2 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 and 2011 anticipated NGL production. Monthly settlements for the 2010 period were $137.4 million, which partially offset these increases. | ||
• | Our net property, plant and equipment balance increased $370.8 million over the nine-month period ended September 30, 2010. During the 2010 period, we have incurred $125.6 million for the acquisition of additional working interests in our Lake Arlington Project and $357.7 million for ongoing exploration and development activities that have been partially offset by DD&A of $131.0 million net of DD&A from our midstream operations and the effects of changes in U.S.-Canadian exchange rates from December 31, 2009 to September 30, 2010. | ||
• | Assets and liabilities of our midstream operations held for sale were $561.9 million and $267.1 million, respectively, and are presented separately in our consolidated balance sheets. The liabilities of midstream operations held for sale have increased $118.9 million since December 31, 2009 principally related to borrowings made by KGS to acquire the Alliance midstream assets from us during 2010. |
Contractual Obligations and Commercial Commitments
As of September 30, 2010, our estimates of Eni Production covered by the Gas Purchase Commitment have been reduced 4.4 Bcf from December 31, 2009 estimates. At September 30, 2010, we estimated a remaining liability of $18.9 million, including an embedded derivative liability of $0.7 million. Valuation of the liability was based on the most recent estimate of 2010 fourth quarter Eni Production volumes and natural gas prices at September 30, 2010.
In April 2010, Quicksilver entered into a lease of office space with a term of 12 years that commenced August 2010. Aggregate rentals over the life of the lease will total $34.8 million.
As of September 30, 2010, we had surety bonds outstanding of $39.2 million. Our letters of credit outstanding at September 30, 2010 were $46.0 million, which includes $28.9 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
Management’s discussion and analysis of financial condition and results of operations are based on our condensed consolidated interim financial statements and related footnotes contained within this report. The process of preparing financial statements in conformity with GAAP requires the use of estimates and assumptions to determine certain of the assets, liabilities, revenue and expense. Our more critical accounting estimates used in the preparation of the consolidated financial statements were discussed in our 2009 Annual Report on Form 10-K. These critical estimates, for which no significant changes occurred during the nine months ended September 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 we make the estimate or assumption. The estimates and assumptions could change materially as conditions within and beyond our control change. Accordingly, actual results could differ materially from those estimates and assumptions.
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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 onForm 10-K.
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 September 30, 2010.
Utilization of our hedging program may result in natural gas and NGL realized prices varying from market prices that we receive from the sale of natural gas and NGL. Our revenue from natural gas and NGL production was $179.7 million and $234.8 million higher because of our hedging program for the 2010 period and 2009 period, respectively. Other revenue was $2.4 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 individual commodity derivative positions as of September 30, 2010:
Weighted Avg | ||||||||||||||
Remaining Contract | Price Per Mcf or | |||||||||||||
Product | Type | Period | Volume | Bbl | Fair Value | |||||||||
(In thousands) | ||||||||||||||
Gas | Collar | Oct 2010-Dec 2010 | 20 MMcfd | $ | 8.00-11.00 | $ | 7,465 | |||||||
Gas | Collar | Oct 2010-Dec 2010 | 20 MMcfd | 8.00-11.00 | 7,465 | |||||||||
Gas | Collar | Oct 2010-Dec 2010 | 20 MMcfd | 8.00-12.20 | 7,465 | |||||||||
Gas | Collar | Oct 2010-Dec 2010 | 20 MMcfd | 8.00-12.20 | 7,465 | |||||||||
Gas | Collar | Oct 2010-Dec 2010 | 10 MMcfd | 8.50-12.05 | 4,190 | |||||||||
Gas | Collar | Oct 2010-Dec 2010 | 20 MMcfd | 8.50-12.05 | 8,380 | |||||||||
Gas | Collar | Oct 2010-Dec 2010 | 10 MMcfd | 8.50-12.08 | 4,190 | |||||||||
Gas | Collar | Oct 2010-Dec 2011 | 10 MMcfd | 6.00- 7.00 | 7,838 | |||||||||
Gas | Collar | Oct 2010-Dec 2011 | 10 MMcfd | 6.00- 7.00 | 7,838 | |||||||||
Gas | Collar | Oct 2010-Dec 2011 | 20 MMcfd | 6.00- 7.00 | 15,677 | |||||||||
Gas | Collar | Oct 2010-Dec 2012 | 20 MMcfd | 6.50- 7.15 | 30,962 | |||||||||
Gas | Collar | Oct 2010-Dec 2012 | 20 MMcfd | 6.50- 7.18 | 31,092 | |||||||||
Gas | Collar | Jan 2011-Dec 2011 | 10 MMcfd | 6.25- 7.50 | 6,826 | |||||||||
Gas | Collar | Jan 2011-Dec 2011 | 10 MMcfd | 6.25- 7.50 | 6,826 | |||||||||
Gas | Collar | Jan 2011-Dec 2011 | 20 MMcfd | 6.25- 7.50 | 13,652 | |||||||||
Gas | Collar | Jan 2012-Dec 2012 | 20 MMcfd | 6.50- 8.01 | 11,473 | |||||||||
Gas | Basis | Oct 2010-Dec 2010 | 20 MMcfd | (1) | (105 | ) | ||||||||
Gas | Basis | Oct 2010-Dec 2010 | 20 MMcfd | (1) | (105 | ) | ||||||||
Gas | Basis | Oct 2010-Dec 2010 | 20 MMcfd | (2) | (60 | ) | ||||||||
Gas | Basis | Oct 2010-Dec 2010 | 10 MMcfd | (2) | 11 | |||||||||
Gas | Basis | Oct 2010-Dec 2010 | 10 MMcfd | (2) | 14 | |||||||||
Gas | Basis | Jan 2011-Dec 2011 | 20 MMcfd | (1) | 1,702 | |||||||||
Gas | Basis | Jan 2011-Dec 2011 | 10 MMcfd | (1) | 851 | |||||||||
Gas | Basis | Jan 2011-Dec 2011 | 10 MMcfd | (1) | 851 | |||||||||
Gas | Swap | Jan 2011-Dec 2015 | 10 MMcfd | $ | 6.00 | 14,908 | ||||||||
Gas | Swap | Jan 2011-Dec 2015 | 20 MMcfd | 6.00 | 29,816 | |||||||||
NGL | Swap | Oct 2010-Dec 2010 | 2 MBbld | 32.65 | (1,170 | ) | ||||||||
NGL | Swap | Oct 2010-Dec 2010 | 3 MBbld | 32.98 | (1,663 | ) | ||||||||
NGL | Swap | Oct 2010-Dec 2010 | 1 MBbld | 33.63 | (495 | ) | ||||||||
NGL | Swap | Oct 2010-Dec 2010 | 1 MBbld | 34.15 | (447 | ) | ||||||||
NGL | Swap | Oct 2010-Dec 2010 | 3 MBbld | 34.22 | (1,321 | ) | ||||||||
NGL | Swap | Jan 2011-Dec 2011 | 3 MBbld | 36.06 | (350 | ) | ||||||||
NGL | Swap | Jan 2011-Dec 2011 | 2 MBbld | 36.31 | (55 | ) | ||||||||
NGL | Swap | Jan 2011-Dec 2011 | 3 MBbld | 41.95 | 6,073 | |||||||||
Total | $ | 227,259 | ||||||||||||
(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 September 30, 2010.
We also have recorded a liability for the Gas Purchase Commitment, which is more fully described in Note 3 to the condensed consolidated financial statements.
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Interest Rate Risk
In February 2010, we executed the early settlement of the 2009 interest rate swaps that were designated as fair value hedges of our senior notes due 2015 and our senior subordinated notes. We received cash of $18.0 million in the settlement, including $3.7 million for interest previously accrued and earned, and recognized the remaining $14.3 million as a fair value adjustment to our debt.
In February 2010, we entered into new interest swaps to hedge the same debt instruments. We executed early settlement of a portion of the 2010 interest rate swaps in May 2010 and the remaining 2010 interest swaps in July 2010 for $6.8 million and $16.7 million, respectively. These settlements included $7.0 million for interest previously accrued and earned. The remaining cash of $16.5 million was recognized as a fair value adjustment to our debt, which will be recognized as a reduction of interest expense over the life of the associated underlying debt instruments.
For the 2010 period and 2009 period, interest expense decreased $12.9 million and $7.2 million, respectively, because of our interest rate swaps.
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 September 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 SEC’s rules and forms and that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Changes in Internal Control Over Financial Reporting
There has been no change in our internal control over financial reporting during the quarter ended September 30, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings
In the litigation filed by us against Eagle Drilling LLC (“Eagle”), which includes counter claims filed by Eagle against us and disclosed in our 2009 Annual Report on Form 10-K, on October 19, 2010, the U.S. District Court granted our motion for summary judgment directed to Eagle’s breach of contract claims, although other claims remain outstanding.
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 and in Part II, Item 1 included in our Quarterly Report on Form 10-Q for the period ended June 30, 2010.
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ITEM 1A. Risk Factors
There have been no material changes in the risk factors from those described in Part I, Item 1A of our 2009 Annual Report on Form 10-K with the exception of the risk factors listed below:
The absence of an acquisition proposal would likely have an adverse impact on the market price of our common stock.
On October 18, 2010, we announced that our board of directors had received a letter from Quicksilver Energy, L.P., an entity controlled by members of the Darden family, indicating that a group of investors consisting of Quicksilver Energy, L.P. and members of the Darden family (the “Darden Investor Group”) is interested in exploring strategic alternatives for us, which might include a “take private” transaction. On the last trading day prior to this announcement, our common stock closed at $12.61 per share. At the closing on the day of the announcement, the stock price had risen approximately 16% to $14.65 per share. If no proposal is forthcoming from the Darden Investor Group or from any other potential acquirer, the stock price might retreat from its current trading range. There can be no assurance that any proposal for a transaction will be received or that any transaction will be approved or consummated.
The difficulties associated with any attempt to gain control of our company may discourage other potential bidders from emerging.
As of October 25, 2010, the Darden Investor Group beneficially owned shares representing approximately 26.6% of the outstanding shares of our common stock. The Darden Investor Group has substantial influence over the likelihood of consummating a change in control transaction for us.
Uncertainty regarding the future of our company may divert the attention of our management and employees and impact our relationships with counterparties.
The announcement that the Darden Investor Group is interested in exploring strategic alternatives for the Company may divert the attention of our management and employees from our day-to-day operations and impact our relationships with counterparties.
We could incur material costs and expenses in connection with any proposal for a transaction.
Our board of directors has formed a Transaction Committee of independent directors to consider any transaction that may be proposed by the Darden Investor Group, as well as alternative transactions. The costs and expenses of the Transaction Committee, including the fees and expenses of the Transaction Committee’s independent financial and legal advisors, will be payable by us whether or not any proposal is received or any transaction is consummated, and these costs and expenses could be material. In addition, shortly after the announcement with respect to the Darden Investor Group, a number of law firms announced that they are investigating potential claims against us and our directors alleging breaches of fiduciary duties. If any such lawsuits are filed, we will incur additional costs and expenses.
Consummation of a transaction that results in substantially more debt to us could have an adverse effect on us, such as a downgrade of the ratings of our debt securities.
We can provide no assurance that the consummation of any particular transaction will not result in incurrence of substantial additional debt by us. Such additional debt could have significant adverse effects on us, such as further restricting our flexibility, negatively affecting our liquidity and a downgrade in the ratings of our debt securities.
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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 September 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) | ||||||||||||
July 2010 | 19,341 | $ | 12.59 | - | - | |||||||||||
August 2010 | 164 | $ | 11.36 | - | - | |||||||||||
September 2010 | 1,197 | $ | 12.89 | - | - | |||||||||||
Total | 20,702 | $ | 12.60 | - | - |
(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
The following unaudited pro forma condensed consolidated statements of operations and explanatory notes present how our financial statements may have appeared had the Crestwood Transaction occurred on January 1, 2010.
The unaudited pro forma condensed consolidated statements of operations have been derived and should be read together with our historical consolidated financial statements and related notes included in our 2009 Annual Report on Form 10-K and Item I of this document.
The unaudited pro forma condensed consolidated statements of operations are presented for illustrative purposes only and do not purport to represent what our results of operations would actually have been had the Crestwood Transaction occurred on the date noted above, or to project our results of operations for any future periods. The pro forma adjustments are based on available information and certain assumptions that we believe are reasonable. The pro forma adjustments are directly attributable to the Crestwood Transaction and are expected to have a continuing impact on our results of operations. We believe we have made all adjustments necessary to fairly present the unaudited pro forma condensed consolidated statements of operations.
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QUICKSILVER RESOURCES INC.
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2010
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2010
Crestwood | ||||||||||||||||
As | Transaction | |||||||||||||||
Presented | Adjustments | Pro Forma | ||||||||||||||
(In thousands, except per share amounts) | ||||||||||||||||
Revenue | ||||||||||||||||
Natural gas, NGL and crude oil | $ | 218,249 | $ | - | $ | 218,249 | ||||||||||
Sales of purchased natural gas | 16,982 | (1,960 | ) | (a) | 15,022 | |||||||||||
Other | 2,469 | (2,708 | ) | (a) | (239 | ) | ||||||||||
Total revenue | 237,700 | (4,668 | ) | 233,032 | ||||||||||||
Operating expense | ||||||||||||||||
Oil and gas production expense | 39,402 | 21,724 | (a) | 61,126 | ||||||||||||
Production and ad valorem taxes | 9,170 | (1,069 | ) | (a) | 8,101 | |||||||||||
Costs of purchased natural gas | 14,638 | (9 | ) | (a) | 14,629 | |||||||||||
Other operating expense | 1,320 | (1,229 | ) | (a) | 91 | |||||||||||
Depletion, depreciation and accretion | 52,542 | (6,453 | ) | (b) | 46,089 | |||||||||||
General and administrative expense | 24,005 | (872 | ) | (a) | 23,133 | |||||||||||
Total expense | 141,077 | 12,092 | 153,169 | |||||||||||||
Impairment expense | (31,531 | ) | - | (31,531 | ) | |||||||||||
Operating income | 65,092 | (16,760 | ) | 48,332 | ||||||||||||
Income from earnings of BBEP - net | 17,024 | - | 17,024 | |||||||||||||
Other income - net | 14,253 | - | 14,253 | |||||||||||||
Interest expense | (51,532 | ) | 6,292 | (c) | (45,240 | ) | ||||||||||
Income before income taxes | 44,837 | (10,468 | ) | 34,369 | ||||||||||||
Income tax expense | (18,268 | ) | 3,768 | (d) | (14,500 | ) | ||||||||||
Net income | 26,569 | (6,700 | ) | 19,869 | ||||||||||||
Net income attributable to noncontrolling interests | (4,766 | ) | 4,766 | (e) | - | |||||||||||
Net income attributable to Quicksilver | $ | 21,803 | $ | (1,934 | ) | $ | 19,869 | |||||||||
Earnings per common share - basic | $ | 0.13 | $ | 0.12 | ||||||||||||
Earnings per common - diluted | $ | 0.13 | $ | 0.12 | ||||||||||||
Basic weighted average shares outstanding | 170,307 | 170,307 | ||||||||||||||
Diluted weighted average shares outstanding | 171,037 | 171,037 | ||||||||||||||
Unit expenses, on a Mcfe basis: | ||||||||||||||||
Oil and gas production expense | $ | 1.18 | $ | 1.83 | ||||||||||||
Production and ad valorem taxes | $ | 0.28 | $ | 0.24 | ||||||||||||
Depletion, depreciation and accretion | $ | 1.58 | $ | 1.38 | ||||||||||||
General and administrative expense | $ | 0.72 | $ | 0.69 | ||||||||||||
Total Production (Mcfe) | 33,338,687 | 33,338,687 |
See accompanying notes to unaudited pro forma condensed consolidated financial statements.
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QUICKSILVER RESOURCES INC.
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2010
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2010
Crestwood | ||||||||||||||||
As | Transaction | |||||||||||||||
Presented | Adjustments | Pro Forma | ||||||||||||||
(In thousands, except per share amounts) | ||||||||||||||||
Revenue | ||||||||||||||||
Natural gas, NGL and crude oil | $ | 631,499 | $ | - | $ | 631,499 | ||||||||||
Sales of purchased natural gas | 50,027 | (5,417 | ) | (a) | 44,610 | |||||||||||
Other | 6,902 | (6,808 | ) | (a) | 94 | |||||||||||
Total revenue | 688,428 | (12,225 | ) | 676,203 | ||||||||||||
Operating expense | ||||||||||||||||
Oil and gas production expense | 113,593 | 56,062 | (a) | 169,655 | ||||||||||||
Production and ad valorem taxes | 26,542 | (3,634 | ) | (a) | 22,908 | |||||||||||
Costs of purchased natural gas | 51,701 | (64 | ) | (a) | 51,637 | |||||||||||
Other operating expense | 3,544 | (3,172 | ) | (a) | 372 | |||||||||||
Depletion, depreciation and accretion | 149,968 | (17,502 | ) | (b) | 132,466 | |||||||||||
General and administrative expense | 61,745 | (2,617 | ) | (a) | 59,128 | |||||||||||
Total expense | 407,093 | 29,073 | 436,166 | |||||||||||||
Impairment expense | (31,531 | ) | - | (31,531 | ) | |||||||||||
Operating income | 249,804 | (41,298 | ) | 208,506 | ||||||||||||
Income from earnings of BBEP - net | 24,203 | - | 24,203 | |||||||||||||
Other income - net | 67,646 | - | 67,646 | |||||||||||||
Interest expense | (142,171 | ) | 15,654 | (c) | (126,517 | ) | ||||||||||
Income before income taxes | 199,482 | (25,644 | ) | 173,838 | ||||||||||||
Income tax expense | (71,569 | ) | 9,232 | (d) | (62,337 | ) | ||||||||||
Net income | 127,913 | (16,412 | ) | 111,501 | ||||||||||||
Net income attributable to noncontrolling interests | (11,119 | ) | 11,119 | (e) | - | |||||||||||
Net income attributable to Quicksilver | $ | 116,794 | $ | (5,293 | ) | $ | 111,501 | |||||||||
Earnings per common share - basic | $ | 0.69 | $ | 0.65 | ||||||||||||
Earnings per common - diluted | $ | 0.68 | $ | 0.65 | ||||||||||||
Basic weighted average shares outstanding | 170,242 | 170,242 | ||||||||||||||
Diluted weighted average shares outstanding | 180,847 | 180,847 | ||||||||||||||
Unit expenses, on a Mcfe basis: | ||||||||||||||||
Oil and gas production expense | $ | 1.21 | $ | 1.81 | ||||||||||||
Production and ad valorem taxes | $ | 0.28 | $ | 0.24 | ||||||||||||
Depletion, depreciation and accretion | $ | 1.60 | $ | 1.41 | ||||||||||||
General and administrative expense | $ | 0.66 | $ | 0.63 | ||||||||||||
Total Production (Mcfe) | 93,834,719 | 93,834,719 |
See accompanying notes to unaudited pro forma condensed consolidated financial statements.
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QUICKSILVER RESOURCES INC.
NOTES TO UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2010
NOTES TO UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2010
Note 1 Basis of Presentation
The accompanying unaudited pro forma condensed consolidated statements of operations and explanatory notes present how our statements of operations may have appeared had the sale of our interests in KGS to Crestwood occurred on January 1, 2010.
Following are descriptions of certain columns included in the accompanying unaudited pro forma condensed consolidated financial statements:
As Historically Presented –Represents our historical condensed consolidated statements of operations for the three and nine months ended September 30, 2010.
Crestwood Transaction Adjustments –Represents the adjustments to our historical condensed consolidated statements of operations necessary to eliminate the direct effect of KGS to arrive at our pro forma results of our operations for the three and nine months ended September 30, 2010.
Note 2 Pro Forma Adjustments
(a) | To eliminate the revenues and operating expenses directly attributable to KGS. | ||
(b) | To eliminate depreciation associated with assets disposed in the Crestwood Transaction. | ||
(c) | To adjust interest expense to give effect to the absence of outstanding borrowings under our Senior Secured Credit Facility and borrowings outstanding under the KGS Credit Facility. | ||
(d) | To record income tax expense for the effects of the pro forma adjustments at statutory rates. | ||
(e) | To record the elimination of net income attributable to noncontrolling interests as a result of the Crestwood Transaction. |
ITEM 6. Exhibits:
Exhibit No. | Description | |
2.1 | Purchase Agreement, dated as of July 22, 2010, among First Reserve Crestwood Holdings LLC, Cowtown Gas Processing L.P., Cowtown Pipeline L.P. and Quicksilver Resources Inc. (filed as Exhibit 2.1 to the Company’sForm 8-K, filed on July 23, 2010, and included herein by reference) | |
* 2.2 | Purchase Agreement Amendment No. 1, dated as of September 17, 2010, among First Reserve Crestwood Holdings LLC, Cowtown Gas Processing L.P., Cowtown Pipeline L.P. and Quicksilver Resources Inc. | |
* 10.1 | Ninth Amendment to the Combined Credit Agreements, dated as of September 17, 2010, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and combined lenders identified therein | |
* 10.2 | Form of Director and Officer Indemnification Agreement | |
* 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 |
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Dated: November 8, 2010
Quicksilver Resources Inc. | ||||
By: | /s/ Philip Cook | |||
Philip Cook | ||||
Senior Vice President - Chief Financial Officer |
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EXHIBIT INDEX
Exhibit No. | Description | |
2.1 | Purchase Agreement, dated as of July 22, 2010, among First Reserve Crestwood Holdings LLC, Cowtown Gas Processing L.P., Cowtown Pipeline L.P. and Quicksilver Resources Inc. (filed as Exhibit 2.1 to the Company’sForm 8-K, filed on July 23, 2010, and included herein by reference) | |
* 2.2 | Purchase Agreement Amendment No. 1, dated as of September 17, 2010, among First Reserve Crestwood Holdings LLC, Cowtown Gas Processing L.P., Cowtown Pipeline L.P. and Quicksilver Resources Inc. | |
* 10.1 | Ninth Amendment to the Combined Credit Agreements, dated as of September 17, 2010, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and combined lenders identified therein | |
* 10.2 | Form of Director and Officer Indemnification Agreement | |
* 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 |