UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
| x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 2005
or
| ¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number: 001-14837
Quicksilver Resources Inc.
(Exact name of registrant as specified in its charter)
| Delaware | 75-2756163 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
| 777 West Rosedale, Suite 300, Fort Worth, Texas | 76104 | |
| (Address of principal executive offices) | (Zip Code) |
(817) 665-5000
(Registrant’s telephone number, including area code)
None
(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 at least the past 90 days. Yesx No¨
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yesx No¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes¨ Nox
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:
Title of Class | Outstanding as of October 31, 2005 | |
| Common Stock, $.01 par value | 75,956,126 |
INDEX TO FORM 10-Q
For the Period Ending September 30, 2005
| Page | ||
PART I. FINANCIAL INFORMATION | ||
Item 1. Financial Statements (Unaudited) | ||
| 3 | ||
Condensed Consolidated Balance Sheets at September 30, 2005 and December 31, 2004 | 4 | |
| 5 | ||
| 6 | ||
Notes to Condensed Consolidated Interim Financial Statements | 7 | |
Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations | 14 | |
Item 3.Quantitative and Qualitative Disclosures About Market Risk | 22 | |
Item 4.Controls and Procedures | 24 | |
PART II. OTHER INFORMATION | ||
Item 1.Legal Proceedings | 25 | |
Item 6. Exhibits | 25 | |
| 26 | ||
2
PART I. FINANCIAL INFORMATION
| Item 1. | Financial Statements (Unaudited) |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Quicksilver Resources Inc.
Fort Worth, Texas
We have reviewed the accompanying condensed consolidated balance sheet of Quicksilver Resources Inc. and subsidiaries (the Company) as of September 30, 2005, and the related condensed consolidated statements of income and comprehensive (loss) income for the three- and nine-month periods ended September 30, 2005 and 2004 and of cash flows for the nine-month periods ended September 30, 2005 and 2004. These interim financial statements are the responsibility of the Company’s management.
We conducted our reviews in accordance with standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our reviews, we are not aware of any material modifications that should be made to such condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.
We have previously audited, in accordance with standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Quicksilver Resources Inc. and subsidiaries as of December 31, 2004, and the related consolidated statements of income and comprehensive (loss) income, stockholders’ equity and cash flows for the year then ended (not presented herein); and in our report dated March 16, 2005 (August 8, 2005 as to the effects of certain reclassifications), we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2004, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
| /s/ DELOITTE & TOUCHE LLP |
| Fort Worth, Texas |
| November 8, 2005 |
3
CONDENSED CONSOLIDATED BALANCE SHEETS
In thousands, except for share data – Unaudited
| September 30, 2005 | December 31, 2004(1) | |||||||
| ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 29,742 | $ | 15,947 | ||||
Accounts receivable | 70,783 | 38,037 | ||||||
Current deferred income taxes | 30,696 | 3,523 | ||||||
Inventories and other current assets | 9,046 | 8,689 | ||||||
Total current assets | 140,267 | 66,196 | ||||||
Investments in and advances to equity affiliates | 7,918 | 8,254 | ||||||
Property, plant and equipment – net (“full cost”) | 997,075 | 802,610 | ||||||
Other assets | 9,042 | 11,274 | ||||||
| $ | 1,154,302 | $ | 888,334 | |||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
Current liabilities | ||||||||
Current portion of long-term debt | $ | 356 | $ | 356 | ||||
Accounts payable | 35,365 | 28,407 | ||||||
Accrued derivative obligations | 85,358 | 12,784 | ||||||
Accrued liabilities | 44,880 | 41,904 | ||||||
Total current liabilities | 165,959 | 83,451 | ||||||
Long-term debt | 547,697 | 399,134 | ||||||
Derivative obligations | 11,679 | — | ||||||
Asset retirement obligations | 19,939 | 17,967 | ||||||
Deferred income taxes | 98,070 | 83,506 | ||||||
Stockholders’ equity | ||||||||
Preferred stock, $0.01 par value, 10,000,000 shares authorized, 1 share issued and outstanding | — | — | ||||||
Common stock, $0.01 par value, 100,000,000 shares authorized 78,519,540 and 77,752,151 shares issued, respectively | 785 | 778 | ||||||
Paid in capital in excess of par value | 212,431 | 200,690 | ||||||
Deferred compensation | (4,200 | ) | — | |||||
Treasury stock of 2,568,611 shares | (10,258 | ) | (10,258 | ) | ||||
Accumulated other comprehensive (loss) income | (46,780 | ) | 6,762 | |||||
Retained earnings | 158,980 | 106,304 | ||||||
Total stockholders’ equity | 310,958 | 304,276 | ||||||
| $ | 1,154,302 | $ | 888,334 | |||||
| (1) | Share amounts have been adjusted to reflect a three-for-two stock split effected in the form of a stock dividend in June 2005. The split did not affect treasury shares. |
The accompanying notes are an integral part of these condensed consolidated interim financial statements.
4
CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE (LOSS) INCOME
In thousands, except for per share data – Unaudited
| For the Three Months Ended September 30, (1) | For the Nine Months Ended September 30,(1) | |||||||||||||||
| 2005 | 2004 | 2005 | 2004 | |||||||||||||
Revenues | ||||||||||||||||
Oil, gas and related product sales | $ | 82,204 | $ | 44,743 | $ | 204,887 | $ | 125,467 | ||||||||
Other revenue | 1,569 | 801 | 2,675 | 1,834 | ||||||||||||
Total revenues | 83,773 | 45,544 | 207,562 | 127,301 | ||||||||||||
Expenses | ||||||||||||||||
Oil and gas production costs | 23,272 | 16,407 | 63,208 | 48,226 | ||||||||||||
Other operating costs | 249 | 65 | 1,364 | 571 | ||||||||||||
Depletion, depreciation and accretion | 13,873 | 9,982 | 39,262 | 28,801 | ||||||||||||
Provision for bad debts | — | — | 88 | — | ||||||||||||
General and administrative | 5,381 | 3,281 | 13,112 | 9,290 | ||||||||||||
Total expenses | 42,775 | 29,735 | 117,034 | 86,888 | ||||||||||||
Income from equity affiliates | 230 | 300 | 669 | 880 | ||||||||||||
Operating income | 41,228 | 16,109 | 91,197 | 41,293 | ||||||||||||
Other (income) expense-net | (253 | ) | (44 | ) | (457 | ) | (137 | ) | ||||||||
Interest expense | 5,589 | 4,204 | 15,022 | 11,246 | ||||||||||||
Income from continuing operations before income taxes | 35,892 | 11,949 | 76,632 | 30,184 | ||||||||||||
Income tax expense | 11,199 | 4,060 | 24,000 | 8,858 | ||||||||||||
Income from continuing operations | 24,693 | 7,889 | 52,632 | 21,326 | ||||||||||||
Discontinued operations | ||||||||||||||||
Gain from discontinued drilling operations, net of income tax of $ 34 | 62 | — | 62 | — | ||||||||||||
Net income | $ | 24,755 | $ | 7,889 | $ | 52,694 | $ | 21,326 | ||||||||
Other comprehensive (loss) income, net of income taxes | ||||||||||||||||
Reclassification adjustments – hedge settlements | 4,379 | 6,392 | 13,017 | 20,540 | ||||||||||||
Unrealized loss on derivative instruments | (63,433 | ) | (3,726 | ) | (69,363 | ) | (13,833 | ) | ||||||||
Foreign currency translation adjustments | 4,013 | 3,740 | 2,805 | (361 | ) | |||||||||||
Comprehensive (loss) income | $ | (30,286 | ) | $ | 14,295 | $ | (847 | ) | $ | 27,672 | ||||||
Basic net income per common share: | ||||||||||||||||
Continuing operations | $ | 0.33 | $ | 0.11 | $ | 0.70 | $ | 0.29 | ||||||||
Discontinued operations | — | — | — | — | ||||||||||||
Net income | $ | 0.33 | $ | 0.11 | $ | 0.70 | $ | 0.29 | ||||||||
Diluted net income per common share: | ||||||||||||||||
Continuing operations | $ | 0.31 | $ | 0.10 | $ | 0.66 | $ | 0.28 | ||||||||
Discontinued operations | — | — | — | — | ||||||||||||
Net income | $ | 0.31 | $ | 0.10 | $ | 0.66 | $ | 0.28 | ||||||||
Weighted average common shares outstanding | ||||||||||||||||
Basic | 75,931 | 74,638 | 75,777 | 74,530 | ||||||||||||
Diluted | 82,668 | 76,288 | 82,403 | 76,037 | ||||||||||||
| (1) | Share and per share amounts have been adjusted to reflect a three-for-two stock split effected in the form of a stock dividend in June 2005. The split did not affect treasury shares. |
The accompanying notes are an integral part of these condensed consolidated interim financial statements.
5
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
In thousands – Unaudited
| For the Nine Months Ended September 30, | ||||||||
| 2005 | 2004 | |||||||
Operating activities: | ||||||||
Net income | $ | 52,694 | $ | 21,326 | ||||
Charges and credits to net income not affecting cash | ||||||||
Depletion, depreciation and accretion | 39,262 | 28,801 | ||||||
Deferred income taxes | 23,620 | 8,528 | ||||||
Amortization of deferred loan costs | 1,061 | 907 | ||||||
Non-cash compensation | 932 | — | ||||||
Income from equity affiliates | (669 | ) | (880 | ) | ||||
Non-cash gain from hedging activities | (305 | ) | (618 | ) | ||||
Other non-cash items | 71 | (37 | ) | |||||
Changes in assets and liabilities, net of acquisition | ||||||||
Accounts receivable | (32,834 | ) | (1,822 | ) | ||||
Inventory, prepaid expenses and other | (2,991 | ) | (31 | ) | ||||
Accounts payable | 6,084 | 3,011 | ||||||
Accrued liabilities and other | (1,528 | ) | (4,824 | ) | ||||
Net cash from operating activities | 85,397 | 54,361 | ||||||
Investing activities: | ||||||||
Purchase of properties and equipment | (226,376 | ) | (141,168 | ) | ||||
Distributions and advances from equity affiliates – net | 1,005 | 1,604 | ||||||
Proceeds from sales of properties | 9,301 | 8,591 | ||||||
Net cash used for investing activities | (216,070 | ) | (130,973 | ) | ||||
Financing activities: | ||||||||
Issuance of debt | 143,094 | 329,406 | ||||||
Repayments of debt | (245 | ) | (237,234 | ) | ||||
Deferred financing costs | (223 | ) | (2,958 | ) | ||||
Payment of fractional shares | (18 | ) | — | |||||
Proceeds from exercise of stock options | 1,721 | 1.920 | ||||||
Net cash from financing activities | 144,329 | 91,134 | ||||||
Effect of exchange rates on cash | 139 | (646 | ) | |||||
Net increase in cash and cash equivalents | 13,795 | 13,876 | ||||||
Cash and cash equivalents at beginning of period | 15,947 | 4,116 | ||||||
Cash and cash equivalents at end of period | $ | 29,742 | $ | 17,992 | ||||
Supplemental disclosures of cash flow information | ||||||||
Interest paid | $ | 12,162 | $ | 10,286 | ||||
Income taxes paid | $ | 875 | $ | 77 | ||||
Noncash investing activities | ||||||||
Changes in working capital associated with property and equipment | $ | 5,289 | $ | 7,815 | ||||
The accompanying notes are an integral part of these condensed consolidated interim financial statements.
6
NOTES TO CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS
| 1. | ACCOUNTING POLICIES AND DISCLOSURES |
The accompanying condensed consolidated interim financial statements of Quicksilver Resources Inc. (“Quicksilver” or the “Company”) have not been audited by an independent registered public accounting firm. In the opinion of Company management, the accompanying condensed consolidated interim financial statements contain all adjustments necessary to present fairly the financial position of the Company as of September 30, 2005 and its income, comprehensive income and cash flows for the three- and nine-month periods ended September 30, 2005 and 2004. All such adjustments are of a normal recurring nature. The results for interim periods are not necessarily indicative of annual results.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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 revenues and expenses during each reporting period. Management believes its estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties, which may cause actual results to differ materially from the Company’s estimates.
Certain disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted. Accordingly, these financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Form 10-K/A for the year ended December 31, 2004.
Reclassification
Subsequent to the issuance of the September 30, 2004 Form 10-Q, the Company determined that certain of its liabilities associated with the acquisition of property, plant and equipment were incorrectly reflected as cash inflows for operating activities and cash outflows for investing activities. Management has concluded that the misclassification was not material to the condensed consolidated financial statements, and accordingly the prior period presented has been corrected by reducing net cash from operating activities and net cash used for investing activities by $7.8 million and disclosing a noncash investing activity of the same amount.
Stock Split
On June 1, 2005, Quicksilver announced that its Board of Directors declared a three-for-two stock split of Quicksilver’s outstanding common stock effected in the form of a stock dividend. The stock dividend was payable on June 30, 2005, to holders of record at the close of business on June 15, 2005. The split did not affect treasury shares.
The share and earnings per share data included in these notes and the accompanying condensed consolidated financial statements for all periods presented have been adjusted to retroactively reflect the stock split.
7
Net Income per Common Share
Basic net income or loss per common share is computed by dividing the net income or loss attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted net income or loss per common share is computed using the treasury stock method, which considers the impact to net income and common shares from the potential issuance of common shares underlying stock options, stock warrants and outstanding convertible securities. The following is a reconciliation of the weighted average common shares used in the basic and diluted net income per common share calculations for the three and nine-month periods ended September 30, 2005 and 2004.
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
| 2005 | 2004 | 2005 | 2004 | |||||||||
| (in thousands) | (in thousands) | |||||||||||
Income from continuing operations | $ | 24,693 | $ | 7,889 | $ | 52,632 | $ | 21,326 | ||||
Impact of assumed conversions – interest on 1.875% contingently convertible debentures, net of income taxes | 475 | — | 1,425 | — | ||||||||
Income from continuing operations available to stockholders assuming conversion of contingently convertible debentures | $ | 25,168 | $ | 7,889 | $ | 54,057 | $ | 21,326 | ||||
Weighted average common shares-basic | 75,931 | 74,638 | 75,777 | 74,530 | ||||||||
Effect of dilutive securities: | ||||||||||||
Stock options outstanding | 1,829 | 1,650 | 1,718 | 1,507 | ||||||||
Contingently convertible debentures | 4,908 | — | 4,908 | — | ||||||||
Weighted average common shares-diluted | 82,668 | 76,288 | 82,403 | 76,037 | ||||||||
Basic income from continuing operations per common share | $ | 0.33 | $ | 0.11 | $ | 0.70 | $ | 0.29 | ||||
Diluted income from continuing operations per common share | $ | 0.31 | $ | 0.10 | $ | 0.66 | $ | 0.28 | ||||
Stock-Based Compensation
The following table reflects pro forma income from continuing operations and the associated earnings per share as if the Company had applied the fair value recognition provisions of Statement of Financial Accounting Standards (“SFAS”) No. 123,Accounting for Stock-based Compensation, to stock-based employee compensation.
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
| 2005 | 2004 | 2005 | 2004 | |||||||||||||
| (in thousands, except for per share amounts) | ||||||||||||||||
Income from continuing operations | $ | 24,693 | $ | 7,889 | $ | 52,632 | $ | 21,326 | ||||||||
Deduct: Total stock – based compensation expense determined under fair value based method for all awards, net of related tax effect | (1,709 | ) | (394 | ) | (5,546 | ) | (1,140 | ) | ||||||||
Pro forma income from continuing operations | $ | 22,984 | $ | 7,495 | $ | 47,086 | $ | 20,186 | ||||||||
Income from continuing operations per common share as reported | ||||||||||||||||
Basic | $ | 0.33 | $ | 0.11 | $ | 0.70 | $ | 0.29 | ||||||||
Diluted | 0.31 | 0.10 | 0.66 | 0.28 | ||||||||||||
Pro forma income from continuing operations per common share | ||||||||||||||||
Basic | $ | 0.30 | $ | 0.10 | $ | 0.62 | $ | 0.27 | ||||||||
Diluted | 0.28 | 0.10 | 0.57 | 0.27 | ||||||||||||
8
Recently Issued Accounting Standards
In December 2004, the Financial Accounting Standards Boards (“FASB”) issued SFAS No. 123 (revised 2004),Share-Based Payment (“SFAS No. 123(R)”).This statement requires the cost resulting from all share-based payment transactions be recognized in the financial statements at their fair value on the grant date. SFAS No. 123(R) is effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. In April 2005, the Securities and Exchange Commission issued a rule that amends the date for compliance with SFAS No. 123(R). As a result, the Company will adopt this statement on January 1, 2006, using the modified prospective application method described in the statement. Under the modified prospective application method, the Company will apply the standard to new awards and to awards modified, repurchased, or cancelled after the required effective date. Additionally, compensation cost for the unvested portion of awards outstanding as of the required effective date will be recognized as compensation expense as the requisite service is rendered after the required effective date. The compensation cost for earlier awards shall be attributed to periods beginning January 1, 2006 using the attribution method that was used under SFAS No. 123. The adoption of this statement is not expected to have a material impact on the Company’s consolidated financial position, results of operations or cash flows.
The FASB issued FASB Interpretation No. 47 (“FIN 47”),Accounting for Conditional Asset Retirement Obligations, in March 2005. FIN 47 clarifies that the term ‘conditional asset retirement obligation’ as used in SFAS No. 143,Accounting for Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. Under FIN 47, the fair value of a liability for a conditional asset retirement obligation should be recognized when incurred. SFAS No. 143 notes that in some cases, sufficient information may not be available to reasonably estimate the fair value of the asset retirement obligation. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. Management is analyzing FIN 47 and believes there will not be any significant impact on the Company’s financial position, results of operations or cash flows.
In May 2005, the FASB issued SFAS No. 154,Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3(“SFAS No. 154”). SFAS No. 154 requires retrospective application to prior period financial statements for changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS No. 154 also requires that retrospective application of a change in accounting principle be limited to the direct effects of the change. Indirect effects of a change in accounting principle should be recognized in the period of the accounting change. SFAS No. 154 will become effective for the Company’s fiscal year beginning January 1, 2006. The impact of SFAS No. 154 will depend on the nature and extent of any voluntary accounting changes and correction of errors after the effective date, but management does not currently expect SFAS No. 154 to have a material impact on the Company’s consolidated financial position, results of operations or cash flows.
| 2. | DRILLING OPERATIONS |
On July 28, 2005, Quicksilver purchased three drilling rigs and other associated assets for $5.6 million. Thereafter, the Company took over drilling operations and began construction of two additional drilling rigs. The Company sold the drilling assets and drilling rigs under construction on September 29, 2005 for $8.2 million. The purchaser of these assets agreed to conduct drilling operations on the Company’s Barnett Shale properties, using the acquired rigs at market rates and on other customary contract terms. At the time of the sale, the drilling assets had an estimated book value of $8.1 million and the Company continued to be obligated under an operating lease with an estimated value of $0.2 million. As a result, the Company recorded a $0.1 million loss before income tax expense. During the two-month operating period when the rigs were owned by Quicksilver, revenue earned in the drilling operations was $1.9 million and operating income before income taxes was $0.2 million. At September 30, 2005, Quicksilver recorded to its balance sheet accounts receivable and payable associated with these operations $0.6 million and $1.4 million, respectively.
| 3. | ASSET RETIREMENT OBLIGATIONS |
The Company records the fair value of the liability for asset retirement obligations in the period in which it is incurred. Upon initial recognition of the asset retirement liability, an asset retirement cost is capitalized by increasing the carrying amount of the long-lived asset by the same amount as the liability. In periods subsequent to initial measurement, the asset retirement cost is allocated to expense using a systematic method over the asset’s useful life. Changes in the liability for the asset retirement obligation are recognized for (a) the passage of time and (b) revisions to either the timing or the amount of the original estimate of undiscounted cash flows.
During the nine-month periods ended September 30, 2005 and 2004, accretion expense was recognized and included in depletion, depreciation and accretion expense reported in the consolidated statement of income for the period. There have not been any revisions to either the timing or the amount of the original estimate of undiscounted cash flows during 2005. At September 30, 2005 and December 31, 2004, retirement obligations classified as current were $0.5 million.
9
The following table provides a reconciliation of the changes in the estimated asset retirement obligation for the nine-month periods ended September 30, 2005 and 2004.
| Nine Months Ended September 30, | ||||||||
| 2005 | 2004 | |||||||
| (in thousands) | ||||||||
Beginning asset retirement obligation | $ | 18,471 | $ | 15,189 | ||||
Additional liability incurred | 1,066 | 4,286 | ||||||
Accretion expense | 847 | 736 | ||||||
Loss on settlement of liability | 27 | 113 | ||||||
Sale of properties | (41 | ) | (700 | ) | ||||
Asset retirement costs incurred | (89 | ) | (230 | ) | ||||
Currency translation adjustment | 162 | 273 | ||||||
Ending asset retirement obligation | $ | 20,443 | $ | 19,667 | ||||
| 4. | HEDGING |
The estimated fair values of all hedge derivatives and the associated fixed price firm sale and purchase commitments as of September 30, 2005 and December 31, 2004 are provided below. The associated carrying values of these financial instruments and firm commitments are equal to the estimated fair values for each period presented. The assets and liabilities recorded in the balance sheet are netted where derivatives with both gain and loss positions are held by a single third party.
| September 30, 2005 | December 31, 2004 | |||||
| (in thousands) | ||||||
Derivative assets: | ||||||
Fixed price natural gas financial swaps | $ | 222 | $ | — | ||
Crude oil financial collars | — | 106 | ||||
Fixed price sale commitments | — | 314 | ||||
Natural gas financial collars | — | 3,563 | ||||
| $ | 222 | $ | 3,983 | |||
Derivative liabilities: | ||||||
Fixed price natural gas financial swaps | $ | 3,048 | $ | 12,066 | ||
Floating price natural gas financial swaps | — | 322 | ||||
Fixed price sale commitments | 212 | — | ||||
Crude oil financial collars | 1,382 | 5 | ||||
Natural gas financial collars | 92,391 | 158 | ||||
Floating to fixed interest rate swap | — | 233 | ||||
| $ | 97,033 | $ | 12,784 | |||
The fair values of all natural gas and crude oil financial instruments and firm sale and purchase commitments as of September 30, 2005 and December 31, 2004 were estimated based on market prices of natural gas and crude oil for the periods covered by the hedge derivatives. The net differential between the contractual prices in each hedge derivative and commitment and market prices for future periods, as adjusted for estimated basis, has been applied to the volumes 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. As a result, the estimated fair value of the Company’s hedge derivatives and sales commitments does not necessarily represent the value a third party would pay or be paid to assume the Company’s contract positions.
At September 30, 2005, derivative assets of $0.2 million and derivative liabilities of $85.4 million have been classified as current based on the maturity of the derivative instruments. The Company estimates $54.5 million of after-tax losses will be reclassified from other comprehensive income over the next twelve months.
10
| 5. | LONG-TERM DEBT |
Long-term debt consists of:
| September 30, 2005 | December 31, 2004 | |||||||
| (in thousands) | ||||||||
Senior secured credit facility | $ | 329,227 | $ | 180,422 | ||||
Contingently convertible debentures, net of unamortized discount | 147,853 | 147,769 | ||||||
Second mortgage notes | 70,000 | 70,000 | ||||||
Other loans | 828 | 1,073 | ||||||
Deferred gain – fair value interest hedge | 145 | 226 | ||||||
| 548,053 | 399,490 | |||||||
Less current maturities | (356 | ) | (356 | ) | ||||
| $ | 547,697 | $ | 399,134 | |||||
As of September 30, 2005, the Company’s borrowing base under its senior secured credit facility was $400 million, of which approximately $69.9 million was available for borrowing. The loan agreements for the senior credit facility prohibit the declaration or payment of dividends by the Company and contain certain financial covenants, which, among other things, require the maintenance of a minimum current ratio and a minimum earnings (before interest, taxes, depreciation, depletion, amortization, non-cash income and expense and exploration costs) to interest ratio. The Company was in compliance with all such covenants at September 30, 2005.
Effective June 25, 2005, the fifth amendment to the note purchase agreement was completed. Included in the amendment to the note agreement was a change to the floating interest rate. Under the amendment, the $30 million of variable rate notes will bear interest at a variable annual rate based upon the three-month LIBOR rate plus 4.06%, a decrease from the previous variable annual rate of LIBOR rate plus 5.48%. The $40 million fixed rate notes continue to bear interest at the fixed rate of 7.5% per annum. Additionally, the Second Mortgage Notes contain restrictive covenants, which, among other things, require maintenance of a minimum current ratio of at least 1.0, a ratio of net present value of proved reserves to total debt of at least 1.8 to 1.0, and a ratio of earnings before interest, taxes, depreciation, depletion and amortization, non-cash income and expense to interest expense (consolidated net interest expense and current maturities of debt) of at least 1.25 (calculated in accordance with provisions of the Second Mortgage Notes). The Company was in compliance with all such covenants at September 30, 2005.
On September 11, 2003, the Company entered into a fair value interest swap covering $40 million of the fixed rate Second Mortgage Notes. The swap converted the debt’s 7.5% fixed-rate to a floating six-month LIBOR base rate plus 4.07% through the termination of the notes. In January 2004, the swap position was cancelled, and the Company received $0.3 million. The gain on the swap settlement will be recognized over the period remaining to the original maturity date of the swap, December 31, 2006.
| 6. | COMMITMENTS AND CONTINGENCIES |
On October 6, 2004, Quicksilver entered into an Incentive Arrangements Agreement (the “Agreement”) with three executives of the Company’s Canadian subsidiary, MGV Energy Inc., and one employee of Quicksilver. The Agreement provides for the amendment and restatement of employment agreements with two MGV executives and terminates incentive agreements with the other two individuals. The Agreement provides for awards of cash bonuses based upon the achievement of specified proved reserve targets, as well as options granted under the Company’s Amended and Restated 1999 Stock Option and Retention Stock Plan covering 1,775,135 shares of common stock at an exercise price of $20.85. In addition, the Agreement provides for payment of $4.0 million no later than January 1, 2006 as compensation for a two-year non-compete period to commence at the date an individual executive or employee should end their employment with MGV or QRI. If third-party reserve engineers determine that MGV attained proved reserves of 400 billion cubic feet equivalent (Bcfe) at December 31, 2005, the aggregate bonus amount will be $5 million. Proved reserves in excess of 400 Bcfe, but not exceeding 1,000 Bcfe, will increase the cash bonuses earned by $0.05 per Mcfe. Presently, the Company has not recognized an obligation for the cash bonuses as management does not believe that the payment thereof is probable.
In July 2005, the Company entered into a contract for the use of a drilling rig in its Barnett Shale development program for a period of 365 days. As a result, the Company was obligated for payments of approximately $5.7 million.
In August 2001, a group of royalty owners, Athel E. Williams et al., brought suit against the Company and three of its subsidiaries in the Circuit Court of Otsego County, Michigan. The suit alleges that Terra Energy Ltd, one of Quicksilver’s subsidiaries, underpaid royalties or overriding royalties to the 13 named plaintiffs and to a class of plaintiffs who have yet to be determined. The pleadings of the plaintiffs seek damages in an unspecified amount and injunctive relief against future underpayments. The court heard arguments on class certification on November 8, 2002, and on December 6, 2002 the court issued a
11
memorandum opinion granting class certification in part and denying it in part. On December 20, 2002, the Company filed a motion for clarification and reconsideration of the court’s order. That motion was denied on March 9, 2003. After an extended delay resulting from the retention of new counsel by the plaintiffs and the initiation of settlement discussions, on January 21, 2005, the Circuit Court issued an order certifying certain claims to proceed on behalf of a class. The Circuit Court also entered a scheduling order setting trial for January 2007, and declined Defendants’ request to stay proceedings in that court pending an appeal of the certification order.
Defendants have sought leave to appeal the certification order by filing an Application for Leave to Appeal on February 11, 2005 with the Michigan Court of Appeals. Defendants have also requested that the Court of Appeals stay proceedings in the Circuit Court pending the consideration of its appeal, and have requested that the Court of Appeals consider all matters in an expedited manner. On April 22, 2005, the Court of Appeals vacated the certification order and remanded the case to the trial court with instructions to address several particular issues by way of a new order. After limited discovery relating to those issues, the trial court held a follow-up certification hearing on June 1, 2005 and on August 18, 2005, the court again entered new findings and conclusions again favoring certification. The Company is currently awaiting a ruling from the Court of Appeals on its challenge to those findings and conclusions, the trial court on the certification motion, and the case (including the appeal) is stayed in the meantime.
Based on information currently available to the Company, the Company’s management believes that the final resolution of this matter will not have a material effect on its financial position, results of operations or cash flows.
The Company is subject to various possible contingencies, which arise primarily from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry. Such contingencies include differing interpretations as to the prices at which natural gas and crude oil sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Although management believes it has complied with the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued. In addition, production rates, marketing and environmental matters are subject to regulation by various federal and state agencies.
| 7. | STOCKHOLDERS’ EQUITY |
Quicksilver has two stock-based compensation plans, the Amended and Restated 1999 Stock Option and Stock Retention Plan and the Amended and Restated 2004 Non-Employee Director Equity Plan. The Company accounts for the plans under the recognition and measurement principles of APB Opinion No. 25,Accounting for Stock Issued to Employees, and related interpretations.
Stock Options
On January 3, 2005, the non-employee directors of the Company received options to purchase a total of 11,654 shares of stock at a strike price of $23.42. Additional options to purchase 2,456 shares at a stock price of $32.89 were granted to a newly appointed non-employee director of the Company on March 8, 2005. No compensation expense was recognized at the dates of grant, as the exercise price was equal to the market value of the common stock at the dates of grant.
Restricted Stock Grants
Executive officers received a grant of 50,473 restricted shares, valued at $29.67 per share, on February 9, 2005. The Company also granted 7,488 restricted shares, valued at $33.19 per share, to executive officers of MGV on February 28, 2005. On April 21, 2005, all other employees of Quicksilver were granted restricted shares totaling 78,040 shares valued at $35.64 while MGV employees received 23,212 restricted stock units. The restricted stock and restricted stock unit grants provide for vesting at a rate of one-third per year over the proceeding three years and immediate vesting for employees retiring with five or more years of service with the Company who are at least 55 years of age at retirement. As of September 30, 2005, the Company had cancelled 5,055 shares granted to Quicksilver executive officers and 2,574 shares granted to Quicksilver employees. The Company had also cancelled 2,725 restricted stock units that had been granted to MGV employees.
On May 17, 2005, the non-employee directors of the Company received a grant of 2,960 restricted shares valued at $33.80 per share. These restricted shares will become fully vested one year from the date of grant provided the non-employee director remains a member of the Board of Directors of the Company.
Expense for the grants of restricted stock was initially recorded as deferred compensation on the consolidated balance sheet and has been recognized in the consolidated statement of operations as vested from the date of grant for those restricted shares and restricted stock units outstanding or vested due to retirement.
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| 8. | RELATED PARTY TRANSACTIONS |
As of September 30, 2005, members of the Darden family, Mercury Exploration Company and Quicksilver Energy L.P., entities that are owned by members of the Darden family, beneficially own approximately 36% of Quicksilver’s shares outstanding. Thomas Darden, Glenn Darden and Anne Darden Self are officers and directors of the Company.
Quicksilver and its associated entities paid $0.7 million and $0.6 million for rent during the nine-month periods ended September 30, 2005 and 2004, respectively, for office space in buildings which are owned by Pennsylvania Avenue Limited Partnership, a partnership owned by members of the Darden family and Mercury. Rental rates were determined based on comparable rates charged by third parties. Quicksilver is in the process of negotiating an amendment to our lease with Pennsylvania Avenue to increase the amount of office space covered thereby. Pending such amendment, Quicksilver is occupying the additional office space under a license agreement at an incremental cost of approximately $20,000 per month.
| 9. | GEOGRAPHIC INFORMATION |
The Company operates in two geographic segments, the United States and Canada. Both areas are engaged in the exploration and production segment of the oil and gas industry. The Company evaluates performance based on operating income and property and equipment costs incurred (purchases of property and equipment plus noncash changes in working capital associated with property and equipment).
For the Three Months Ended | United States | Canada | Corporate | Consolidated | |||||||||
| (in thousands) | |||||||||||||
September 30, 2005 | |||||||||||||
Revenues | $ | 59,658 | $ | 24,115 | $ | — | $ | 83,773 | |||||
Depletion, depreciation and accretion | 8,943 | 4,772 | 158 | 13,873 | |||||||||
Operating income | 31,738 | 15,029 | (5,539 | ) | 41,228 | ||||||||
Property and equipment costs incurred | 66,164 | 30,910 | 461 | 97,535 | |||||||||
September 30, 2004 | |||||||||||||
Revenues | $ | 35,206 | $ | 10,338 | $ | — | $ | 45,544 | |||||
Depletion, depreciation and accretion | 7,658 | 2,187 | 137 | 9,982 | |||||||||
Operating income | 14,065 | 5,462 | (3,418 | ) | 16,109 | ||||||||
Property and equipment costs incurred | 35,237 | 26,119 | 294 | 61,650 | |||||||||
For the Nine Months Ended | United States | Canada | Corporate | Consolidated | |||||||||
| (in thousands) | |||||||||||||
September 30, 2005 | |||||||||||||
Revenues | $ | 143,283 | $ | 64,279 | $ | — | $ | 207,562 | |||||
Depletion, depreciation and accretion | 25,466 | 13,344 | 452 | 39,262 | |||||||||
Operating income | 65,444 | 39,317 | (13,564 | ) | 91,197 | ||||||||
Property and equipment costs incurred | 150,232 | 80,676 | 757 | 231,665 | |||||||||
September 30, 2004 | |||||||||||||
Revenues | $ | 100,297 | $ | 27,004 | $ | — | $ | 127,301 | |||||
Depletion, depreciation and accretion | 22,776 | 5,702 | 323 | 28,801 | |||||||||
Operating income | 36,728 | 14,178 | (9,613 | ) | 41,293 | ||||||||
Property and equipment costs incurred | 78,978 | 69,636 | 369 | 148,983 | |||||||||
Fixed Assets - net | |||||||||||||
September 30, 2005 | $ | 698,268 | $ | 296,838 | $ | 1,969 | $ | 997,075 | |||||
December 31, 2004 | $ | 581,575 | $ | 219,369 | $ | 1,666 | $ | 802,610 | |||||
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| ITEM 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
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 may relate to a variety of matters not currently ascertainable, such as future capital expenditures, drilling activity, acquisitions and dispositions, development or exploratory activities, cost savings efforts, production activities and volumes, hydrocarbon reserves, hydrocarbon prices, hedging activities and the results thereof, financing plans, liquidity, competition and our ability to realize efficiencies related to certain transactions or organizational changes. Forward-looking statements reflect our current views, assumptions and expectations with respect to future events, outcomes, results or performance. Words such as “may,” “could,” “should,” “assume,” “anticipate,” “believe,” “estimate,” “expect,” “intend,” “plan,” “project,” “forecast,” “budget,” “strategy,” “predict,” “potential,” “continue,” or “future,” and similar expressions are used to identify forward-looking statements. Forward-looking statements can be affected by assumptions upon which they are based and by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. Actual events, outcomes, results or performance 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 you should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause actual events, outcomes, results or performance to differ materially from the results contemplated by such forward-looking statements, or which could otherwise materially affect our financial condition, results of operations or cash flows, include:
| • | changes in general economic conditions; |
| • | fluctuations in natural gas and crude oil prices; |
| • | failure or delays in achieving expected production from natural gas and crude oil exploration and development projects; |
| • | uncertainties inherent in estimates of natural gas and crude oil reserves and predicting natural gas and crude oil reservoir performance; |
| • | effects of hedging natural gas and crude oil prices; |
| • | competitive conditions in our industry; |
| • | actions taken by third-party operators, processors and transporters; |
| • | changes in the availability and cost of capital; |
| • | 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; |
| • | the effects of existing or future litigation; and |
| • | factors discussed in our Form 10-K/A for the year ended December 31, 2004. |
All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements.
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RESULTS OF OPERATIONS
Summary Financial Data
Three Months Ended September 30, 2005 Compared with the Three Months Ended September 30, 2004
| Three Months Ended September 30, | ||||||
| 2005 | 2004 | |||||
| (in thousands) | ||||||
Total operating revenues | $ | 83,773 | $ | 45,544 | ||
Total operating expenses | 42,775 | 29,735 | ||||
Operating income | 41,228 | 16,109 | ||||
Income from continuing operations | 24,693 | 7,889 | ||||
Net income | 24,755 | 7,889 | ||||
We recorded net income of $24.8 million ($0.31 per diluted share) for the three months ended September 30, 2005, compared to net income of $7.9 million ($0.10 per diluted share) for the third quarter of 2004.
Operating Revenues
Revenues for the third quarter of 2005 were $83.8 million; a $38.3 million increase from the $45.5 million reported for the three months ended September 30, 2004. Production revenue increased $37.5 million as a result of a 15% increase in sales volumes and a 60% increase in realized sales prices.
Gas, Oil and Related Product Sales
Sales volumes, revenues and average realized sales prices for the three months ended September 30, 2005 and 2004 are as follows:
| Three Months Ended September 30, | ||||||
| 2005 | 2004 | |||||
Natural gas, oil and NGL sales (in thousands) | ||||||
United States | $ | 58,101 | $ | 34,556 | ||
Canada | 24,103 | 10,187 | ||||
Total | $ | 82,204 | $ | 44,743 | ||
Product sale revenues (in thousands) | ||||||
Natural gas sales | $ | 71,974 | $ | 37,386 | ||
Crude oil sales | 7,943 | 6,514 | ||||
NGL sales | 2,287 | 843 | ||||
Total | $ | 82,204 | $ | 44,743 | ||
Average daily sales volume | ||||||
Natural gas - Mcfd | ||||||
United States | 87,114 | 85,018 | ||||
Canada | 40,732 | 23,795 | ||||
Total | 127,846 | 108,813 | ||||
Crude oil - Bbld | ||||||
United States | 1,507 | 2,042 | ||||
Canada | — | — | ||||
Total | 1,507 | 2,042 | ||||
NGL - Bbld | ||||||
United States | 684 | 303 | ||||
Canada | 7 | — | ||||
Total | 691 | 303 | ||||
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| Three Months Ended September 30, | ||||||
| 2005 | 2004 | |||||
Total sales - Mcfed | ||||||
United States | 100,255 | 99,085 | ||||
Canada | 40,778 | 23,798 | ||||
Total | 141,033 | 122,883 | ||||
Unit prices - including impact of hedges | ||||||
Natural gas - per Mcf | ||||||
United States | $ | 5.98 | $ | 3.48 | ||
Canada | 6.42 | 4.65 | ||||
Consolidated | 6.12 | 3.73 | ||||
Crude oil - per Bbl | ||||||
United States | $ | 57.31 | $ | 34.67 | ||
Canada | — | — | ||||
Consolidated | 57.31 | 34.67 | ||||
NGL - per Bbl | ||||||
United States | $ | 35.75 | $ | 30.29 | ||
Canada | 55.44 | — | ||||
Consolidated | 35.96 | 30.29 | ||||
Natural gas sales of $72.0 million for the third quarter of 2005 were over 90% higher than the $37.4 million for the 2004 third quarter. A $2.39 per Mcf increase in average realized sales prices increased natural gas revenue $23.9 million, including $8.1 million resulting from the expiration of our $2.79 per Mcf fixed-swaps as of April 30, 2005. Natural gas revenue also increased $10.7 million because of a 17% increase in sales volumes as compared to the third quarter of 2004. Production from our coal bed methane (“CBM”) projects and conventional properties in Canada increased for the third quarter of 2005 by approximately 2,190,000 Mcf from the 2004 third quarter as a result of new wells placed into production since September 30, 2004. Natural production declines partially offset the Canadian production increases. New productive wells in the Barnett Shale and New Albany Shale increased sales volumes by approximately 820,000 Mcf and 145,000 Mcf, respectively, for the third quarter of 2005 compared to the third quarter of 2004. Michigan natural gas volumes included about115,000 Mcf from new Antrim wells. These U.S. production increases were partially offset by natural production declines.
Crude oil sales were $7.9 million for the three months ended September 30, 2005 compared to $6.5 million in the third quarter of 2004. Lower production reduced revenue by $2.8 million compared to the prior year quarter. The absence of production from Wyoming and Michigan crude oil properties sold in the third quarter of 2004 lowered volumes by about 48,000 barrels for the third quarter of 2005. The average realized crude oil sales price for the third quarter of 2005 was $57.31 per Bbl compared to $34.67 per Bbl in the third quarter of 2004. Higher realized sales prices increased revenue by $4.2 million.
Our third quarter 2005 NGL sales increased $1.4 million to $2.3 million when compared to the 2004 period. We began processing our natural gas production from the Barnett Shale in Texas late in the second quarter, and sold approximately 22,000 barrels of Barnett Shale NGLs in the third quarter.
Other Revenue
Other revenue increased $0.8 million from the 2004 third quarter to $1.6 million for the 2005 quarter. Revenue earned by our Barnett Shale gas processing facility, which started operations late in June 2005, was $1.3 million for the third quarter of 2005. Partially offsetting the increase were decreases in Canadian gas processing and U.S. marketing revenue.
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Operating Expenses
Third quarter operating expenses for 2005 were $42.8 million; an increase of $13.1 million over the $29.7 million of expenses incurred in the third quarter of 2004.
Oil and Gas Production Costs
| Three Months Ended September 30, | ||||||
| 2005 | 2004 | |||||
| (in thousands, except per unit amounts) | ||||||
Production expenses | ||||||
United States | $ | 18,958 | $ | 13,718 | ||
Canada | 4,314 | 2,689 | ||||
Total | $ | 23,272 | $ | 16,407 | ||
Production expenses - per Mcfe | ||||||
United States | $ | 2.06 | $ | 1.50 | ||
Canada | 1.15 | 1.23 | ||||
Consolidated | 1.79 | 1.44 | ||||
Oil and gas production costs were $23.3 million for the 2005 third quarter. The $6.9 million increase over the prior year quarter included a $1.6 million increase in Canadian production costs. Canadian production increased approximately 1,562,000 Mcfe, net, primarily as a result of CBM and conventional wells placed in production since the third quarter of 2004. Canadian production expenses decreased $.08 per Mcfe to $1.15 per Mcfe as a result of the improving economies of scale.
Oil and gas production costs for U.S. operations increased $5.3 million from the prior year quarter to $19.0 million for the third quarter of 2005. Production expenses for Barnett Shale wells placed into production over the past twelve months resulted in $2.0 million of the increase from the 2004 third quarter. Costs for water disposal, equipment rental and contract labor made up almost $1.3 million of the cost increase. These well costs are typically greater when production begins as initial production contains high water production from the fracture stimulations and well operations require greater monitoring. These operating costs for each well tend to decrease following the period of initial production. Transportation and processing costs for Barnett Shale natural gas production added $1.5 million of expense for the third quarter of 2005. Production expenses in Michigan increased approximately $2.9 million from the 2004 quarter. Compressor overhaul costs and repairs and maintenance expense also increased by nearly $1.7 million. The number of compressors undergoing routine, periodic overhauls was greater in the current year quarter. Additional property values and insurance rates increased U.S. insurance expense approximately $0.2 million while production taxes increased $0.8 million from the 2004 third quarter. Partially offsetting these increases was a $0.7 million decrease in production expense that resulted from the 2004 third quarter sale of Wyoming crude oil properties. These items increased U.S. production expense by approximately $0.60 per Mcfe for the third quarter of 2005.
Depletion, Depreciation and Accretion
| Three Months Ended September 30, | ||||||
| 2005 | 2004 | |||||
| (in thousands, except per unit amounts) | ||||||
Depletion | $ | 11,374 | $ | 8,353 | ||
Depreciation of other fixed assets | 2,205 | 1,341 | ||||
Accretion | 294 | 288 | ||||
Total depletion, depreciation and accretion | $ | 13,873 | $ | 9,982 | ||
Average depletion cost per Mcfe | $ | 0.88 | $ | 0.74 | ||
Third quarter 2005 depletion of $11.4 million was $3.0 million higher than depletion for the 2004 quarter primarily as a result of an increase in the depletion rate as well as additional sales volumes. Our depletion rate increased over the prior year period as a result of the significant capital expenditures and proved reserves added for our Canadian CBM and Texas Barnett Shale properties. The $0.9 million increase in depreciation for the third quarter of 2005 is associated with new gas processing facilities in Canada and gas processing and transportation assets located in the Barnett Shale.
General and Administrative Expense
General and administrative costs incurred during the three months ended September 30, 2005 were $5.4 million. The $2.1 million increase over third quarter of 2004 expense was primarily the result of a $1.3 million increase in employee compensation
17
and benefits including almost $0.5 million for retention and hiring of key personnel, $0.2 million for executive severance and approximately $0.2 million of expense for restricted stock grants. In addition, legal costs for litigation and various corporate matters were approximately $0.5 million higher for the quarter ended September 30, 2005.
Interest Expense
Interest expense for the third quarter of 2005 was $5.6 million, net of capitalized interest of $0.3 million, an increase of $1.4 million compared to the third quarter of 2004. Interest expense increased as a result of higher debt levels in 2005. Capitalized interest recorded in 2005 was associated with the construction of transportation and processing facilities in the Barnett Shale and in Canada.
Income Tax Expense
Our provision for income taxes increased $7.1 million from the prior year period as a result of higher pretax income for the third quarter of 2005. Our U.S. income tax provision of $8.0 million was established using the statutory U.S. federal rate of 35%. The Canadian tax provision of approximately $3.2 million was accrued at a Canadian combined federal and provincial statutory rate of 33.6% and included a current tax provision of $0.1 million.
Summary Financial Data
Nine Months Ended September 30, 2005 Compared with the Nine Months Ended September 30, 2004
| Nine Months Ended September 30, | ||||||
| 2005 | 2004 | |||||
| (in thousands) | ||||||
Total operating revenues | $ | 207,562 | $ | 127,301 | ||
Total operating expenses | 117,034 | 86,888 | ||||
Operating income | 91,197 | 41,293 | ||||
Income from continuing operations | 52,632 | 21,326 | ||||
Net income | 52,694 | 21,326 | ||||
We recorded net income of $52.7 million ($0.66 per diluted share) for the nine months ended September 30, 2005, compared to net income of $21.3 million ($0.28 per diluted share) for the first nine months of 2004.
Operating Revenues
Revenues for the first nine months of 2005 were $207.6 million; a $80.3 million increase from the $127.3 million reported for the 2004 nine-month period as a result of a 15% increase in sales volumes and a 41% increase in realized sales prices.
Gas, Oil and Related Product Sales
Sales volumes, revenues and average realized prices for the nine months ended September 30, 2005 and 2004 are as follows:
| Nine Months Ended September 30, | ||||||
| 2005 | 2004 | |||||
Natural gas, oil and NGL sales (in thousands) | ||||||
United States | $ | 141,036 | $ | 98,622 | ||
Canada | 63,851 | 26,845 | ||||
Total | $ | 204,887 | $ | 125,467 | ||
Product sale revenues (in thousands) | ||||||
Natural gas sales | $ | 179,755 | $ | 105,231 | ||
Crude oil sales | 20,284 | 17,743 | ||||
NGL sales | 4,848 | 2,493 | ||||
Total | $ | 204,887 | $ | 125,467 | ||
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| Nine Months Ended September 30, | ||||||
| 2005 | 2004 | |||||
Average daily sales volume | ||||||
Natural gas - Mcfd | ||||||
United States | 86,229 | 83,596 | ||||
Canada | 39,366 | 20,878 | ||||
Total | 125,595 | 104,474 | ||||
Crude oil - Bbld | ||||||
United States | 1,501 | 2,040 | ||||
Canada | — | — | ||||
Total | 1,501 | 2,040 | ||||
NGL - Bbld | ||||||
United States | 509 | 353 | ||||
Canada | 7 | 1 | ||||
Total | 516 | 354 | ||||
Total sales - Mcfed | ||||||
United States | 98,284 | 97,948 | ||||
Canada | 39,415 | 20,890 | ||||
Total | 137,699 | 118,838 | ||||
Unit prices - including impact of hedges | ||||||
Natural gas - per Mcf | ||||||
United States | $ | 4.93 | $ | 3.42 | ||
Canada | 5.93 | 4.69 | ||||
Consolidated | 5.24 | 3.68 | ||||
Crude oil - per Bbl | ||||||
United States | $ | 49.50 | $ | 31.75 | ||
Canada | — | — | ||||
Consolidated | 49.50 | 31.75 | ||||
NGL - per Bbl | ||||||
United States | $ | 34.27 | $ | 25.71 | ||
Canada | 44.36 | 18.08 | ||||
Consolidated | 34.41 | 25.68 | ||||
Natural gas sales of $179.8 million for the nine-month period ending September 30, 2005 were over 70% higher than the $105.2 million for the 2004 period. Nine-month 2005 gas revenue increased $44.8 million as a result of a $1.57 per Mcf increase in the average realized sales price, which included a $14.0 million increase due to the expiration of our $2.79 per Mcf natural gas swaps as of April 2005. A 20% increase in sales volumes added $29.7 million of revenue for the first nine months of 2005 as compared to the 2004 period. Production from our CBM and conventional properties in Canada increased for the nine-month period of 2005 by approximately 6,575,000 Mcf from the 2004 period as a result of new wells placed into production since January 2004. Natural production declines partially offset the Canadian production increases. New productive wells in the Texas Barnett Shale and New Albany Shale increased sales volumes by approximately 1,850,000 Mcf and 625,000 Mcf, respectively, for the first nine months of 2005 compared to the 2004 period. Michigan natural gas volumes includedover 500,000 Mcf from new Antrim wells and 250,000 Mcf from Prairie du Chien wells placed into production during 2004. Antrim Shale interests purchased in the third quarter of 2005 added approximately 185,000 Mcf of natural gas volumes during the first nine months of 2005. These U.S. production increases were partially offset by natural production declines.
Crude oil sales were $20.3 million for the nine months ended September 30, 2005 compared to $17.7 million in the 2004 period. Average realized sales prices for the 2005 nine-month period increased from the 2004 period over 55% to $49.50. The increase in realized sales prices increased revenue $9.9 million while lower production reduced revenue $7.4 million compared to the prior year. The absence of production from Wyoming and Michigan crude oil properties sold in the third quarter of 2004 lowered volumes by approximately 153,000 barrels for the first nine months of 2005.
19
Sales of NGLs increased $2.4 million from the 2004 nine-month period. Late in June of 2005, we began processing our natural gas production from the Barnett Shale in Texas and sold nearly 28,000 barrels in 2005.
Other Revenue
Other revenue increased $0.8 million from 2004 to $2.7 million for 2005. Revenue earned by our Barnett Shale gas processing facility, which started operations late in the second quarter, was $1.7 million for 2005. Partially offset the increase were decreases in Canadian gas processing and U.S. marketing revenue.
Operating Expenses
Operating expenses for the nine-month period of 2005 were $117.0 million; an increase of $30.1 million over the $86.9 million of expenses incurred in the nine-month period of 2004.
Oil and Gas Production Costs
| Nine Months Ended September 30, | ||||||
| 2005 | 2004 | |||||
| (in thousands, except per unit amounts) | ||||||
Production expenses | ||||||
United States | $ | 51,590 | $ | 41,102 | ||
Canada | 11,618 | 7,124 | ||||
Total | $ | 63,208 | $ | 48,226 | ||
Production expenses – per Mcfe | ||||||
United States | $ | 1.92 | $ | 1.52 | ||
Canada | 1.08 | 1.25 | ||||
Consolidated | 1.68 | 1.47 | ||||
Oil and gas production costs were $63.2 million for the 2005 nine-month period. The $15.0 million increase over the prior period included a $4.5 million increase in Canadian production costs. Canadian production increased approximately 5,036,000 Mcfe, net, primarily as a result of CBM and conventional wells placed into production since the beginning of 2004. Canadian production expenses decreased $0.17 per Mcfe to $1.08 per Mcfe as a result of the improving economies of scale.
U.S. production expenses increased $10.5 million for the first nine months of 2005 compared to the prior year period. Operating expenses for Barnett Shale wells increased production expenses approximately $3.7 million, which included $2.3 million of costs for contract labor, water disposal and equipment rentals. Initial operating expenses for these items are typically greater when production begins as initial production includes high water production from the fracture stimulations. Operating costs for each well tend to decrease following the period of initial production. Transportation and processing expense for natural gas production from the Barnett Shale was $2.4 million for the 2005 nine-month period. In Michigan, compressor overhauls, workovers and repair and maintenance increased production expense $2.2 million for the nine-month period of 2005. An additional $1.1 million of expense was incurred in 2005 for environmental compliance in Michigan. Other increases included a $0.4 million increase in ad valorem tax and insurance expense as a result of additional property value and $0.5 million for employee compensation including $0.2 million of expense from restricted stock grants in 2005. Production taxes also increased $1.2 million for the 2005 period as a result of higher sales values. Partially offsetting these increases was a $1.9 million decrease in Wyoming production expense as a result of the 2004 third quarter sale of Wyoming crude oil properties. These items increased U.S. production expenses by approximately $0.38 per Mcfe for the first nine months of 2005.
Depletion, Depreciation and Accretion
| Nine Months Ended September 30, | ||||||
| 2005 | 2004 | |||||
| (in thousands, except per unit amounts) | ||||||
Depletion | $ | 32,972 | $ | 24,288 | ||
Depreciation of other fixed assets | 5,443 | 3,777 | ||||
Accretion | 847 | 736 | ||||
Total depletion, depreciation and accretion | $ | 39,262 | $ | 28,801 | ||
Average depletion cost per Mcfe | $ | 0.88 | $ | 0.74 | ||
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Nine-month 2005 depletion of $33.0 million was $8.7 million higher than depletion for the 2004 period primarily as a result of an increase in the depletion rate as well as additional sales volumes. Our depletion rate increased over the prior year period as a result of the significant capital expenditures and proved reserves added for our Canadian CBM and Texas Barnett Shale properties. The $1.7 million increase in depreciation expense as compared to the 2004 period is primarily the result of depreciation taken on new gas processing facilities in Canada and gas processing and transportation assets located in the Barnett Shale.
General and Administrative Expense
General and administrative costs incurred during the nine months ended September 30, 2005 were $13.1 million. The $3.8 million increase over 2004 expense was primarily the result of a $1.2 million increase in legal fees due largely to various corporate matters and litigation, $2.7 million for employee compensation and benefits including almost $0.6 million for retention and hiring of key personnel, $0.2 million for executive severance and approximately $0.5 million of expense recorded for restricted stock granted to executives and employees during 2005.
Interest Expense
Interest expense for the first nine months of 2005 was $15.0 million, after interest capitalization of $0.8 million; an increase of $3.8 million compared to the 2004 nine-month period. Interest expense increased as a result of higher debt levels in 2005; however, a decrease in our overall effective interest rate partially offset that increase. The decrease in our effective interest rate was primarily the result of the 1.875% interest rate borne by our $150.0 million contingently convertible debentures issued in November 2004. Capitalized interest recorded in 2005 was associated with the construction of transportation and processing facilities in the Barnett Shale of Texas and in Canada.
Income Tax Expense
Our provision for income taxes increased $15.1 million from the prior year period as a result of higher pretax income for the 2005 nine-month period. Our U.S. income tax provision of $14.9 million was established using the statutory U.S. federal rate of 35%. The Canadian tax provision of approximately $9.1 million was accrued at a Canadian combined federal and provincial statutory rate of 33.6% and included a current tax provision of $0.4 million.
LIQUIDITY, CAPITAL RESOURCES AND FINANCIAL POSITION
Net cash from operations was $85.4 million for the nine months ended September 30, 2005, an increase of $31.0 million compared to the same period in 2004. The 57% increase was due primarily to additional net income for the nine months of 2005 as compared to the 2004 period. Net income of $52.7 was $31.4 million higher from the 2004 nine-month period primarily as a result of a 15% increase in sales volumes and a 41% increase in realized sales prices. Approximately 25% of the increase in realized sales prices resulted from the April expiration of our $2.79 per Mcf fixed-price natural gas swaps. Non-cash expense including depletion, depreciation and amortization, deferred taxes and stock-based compensation increased for 2005, but were mostly offset by the use of working capital associated with additional operating activities.
Our principal sources of cash include sales of natural gas, crude oil and NGLs and revenues from natural gas transportation and processing. During the nine months ended September 30, 2005, we sold approximately 17% of our natural gas production using price swaps including 8% covered by the $2.79 per Mcf fixed-price swaps. Sales under our long-term contracts with price floors covered 24% of our natural gas production. Additionally, price collars covered 21% of our 2005 production-to-date. Our current hedges consist of $7.35 per Mcf fixed-price swaps hedging 5,050 Mcfd of our U.S. production and price collars hedging approximately 33,300 Mcfd of both our U.S. and Canadian production, respectively, for the remainder of 2005. The U.S. and Canadian price collars have weighted average price floors of $7.05 per Mcf and $7.06 per Mcf, respectively, and weighted average price caps of $9.44 per Mcf and $10.29 per Mcf, respectively. An average of approximately 38,000 Mcfd and 22,000 Mcfd of our 2006 projected gas sales for the U.S. and Canada, respectively, have been hedged using price collars with average price floors of $7.25 per Mcf and $7.10 per Mcf, respectively, and cap prices of $9.48 per Mcf and $9.80 per Mcf, respectively.
In the first nine months of 2005, we purchased $226.4 million of property and equipment, an increase of $85.2 million when compared to the first nine months of 2004. Property and equipment costs incurred (purchases of property and equipment plus noncash changes in working capital associated with property and equipment) for the 2005 period totaled $231.7 million, which consisted of $178.8 million expended for exploration and development activities, $23.3 million expended for construction of the Cowtown Pipeline’s first phase and a gas processing plant in Hood County, Texas and $18.9 million expended for Canadian gas processing facilities. Of the $117.6 million incurred for U.S. exploration and development, $99.0 million was spent in Texas, including $31.5 million for leasehold acquisitions. Canadian leasehold acquisition costs were $4.5 million of the $61.2 million spent on Canadian exploration and development. During the third quarter, we spent $7.5 million for the purchase and construction of drilling rigs that we subsequently sold September 29, 2005.
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Nine Months Ended 2005 | |||
| (in thousands) | |||
Exploration and development | |||
United States | $ | 117,653 | |
Canada | 61,184 | ||
Total exploration and development | 178,837 | ||
Gas processing and transportation | |||
United States | 23,338 | ||
Canada | 18,854 | ||
Total gas processing and transportation | 42,192 | ||
Drilling rigs and associated assets | 7,490 | ||
Corporate and office | 3,146 | ||
Total plant and equipment costs incurred | $ | 231,665 | |
Net cash provided by financing activities for the nine months ended September 30, 2005 was $144.3 million. During the 2005 period, we increased borrowings under our senior credit facility by $143.1 million. We also received $1.7 million in proceeds from the exercise of employee stock options. As of September 30, 2005, we had approximately $69.9 million of borrowing capacity available under our $400 million senior credit facility, and we were in compliance with the restrictive covenants contained in our senior credit facility.
Effective June 25, 2005, the fifth amendment to the note purchase agreement was completed. Included in the amendment to the note purchase agreement was a change to the floating interest rate. Under the amendment, the $30 million of variable rate notes will bear interest at a variable annual rate based upon the three-month LIBOR rate plus 4.06%, a decrease from the previous variable annual rate of LIBOR rate plus 5.48%. The $40 million fixed rate notes continue to bear interest at the fixed rate of 7.5% per annum. As of September 30, 2005, we were in compliance with the covenants contained in the second mortgage notes payable.
As of September 30, 2005 and December 31, 2004, our total capitalization was as follows:
| September 30, 2005 | December 31, 2004 | |||||
| (in thousands) | ||||||
Senior secured credit facility | $ | 329,227 | $ | 180,422 | ||
Convertible subordinated debentures | 147,853 | 147,769 | ||||
Second mortgage notes | 70,000 | 70,000 | ||||
Other loans | 828 | 1,073 | ||||
Deferred gain – fair interest hedge | 145 | 226 | ||||
Total debt | 548,053 | 399,490 | ||||
Stockholders’ equity | 310,958 | 304,276 | ||||
| $ | 859,011 | $ | 703,766 | |||
| 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 related to natural gas and crude oil commodity prices. We have mitigated the risk of adverse price movements through the use of swaps and collars; however, we have also limited future gains from favorable movements.
Commodity Price Risk
We enter into financial contracts to hedge our exposure to commodity price risk associated with anticipated future natural gas production. These contracts have included no-cost collars and fixed price swaps. We sell approximately 25,000 Mcfd and 10,000 Mcfd of natural gas for floor prices of $2.49 per Mcf and $2.47 per Mcf, respectively, under long-term contracts that extend through March 2009. Approximately 4,900 Mcfd sold under these contracts during the first nine months of 2005 were third-party volumes controlled by us.
We have used price collars to hedge natural gas volumes of 66,000 Mcfd and $7.35 per Mcf fixed-price swaps hedging 5,050 Mcfd for the fourth quarter of 2005. We also hedged 750 Bbld of our crude oil production with price collars for the remainder of 2005. Price collars have been put in place to hedge 2006 U.S. production of approximately 38,000 Mcfd and Canadian production
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of approximately 22,000 Mcfd. U.S. natural gas production of approximately 30,000 Mcfd has also been hedged for the first quarter of 2007 using price collars.
The following table summarizes our open financial hedge positions as of September 30, 2005 related to natural gas and crude oil production.
Product | Type | Contract Period | Volume | Weighted Avg Mcf or Bbl | Fair Value | ||||||||
| (in thousands) | |||||||||||||
Gas | Swap | Oct 2005 | 10,000 Mcfd | $ | 7.35 | $ | (2,033 | ) | |||||
Gas | Swap | Oct 2005 | 5,000 Mcfd | 7.36 | (1,015 | ) | |||||||
Gas | Collar | Oct 2005 | 10,000 Mcfd | 5.50 - 6.75 | (2,218 | ) | |||||||
Gas | Collar | Oct 2005 | 5,000 Mcfd | 5.50 - 6.75 | (1,109 | ) | |||||||
Gas | Collar | Oct 2005 | 15,000 Mcfd | 5.50 - 7.15 | (3,142 | ) | |||||||
Gas | Collar | Oct 2005 | 5,000 Mcfd | 6.50 - 8.15 | (892 | ) | |||||||
Gas | Collar | Oct 2005 | 5,000 Mcfd | 6.50 - 8.22 | (882 | ) | |||||||
Gas | Collar | Nov 2005-Mar 2006 | 10,000 Mcfd | 6.50 - 11.20 | (5,291 | ) | |||||||
Gas | Collar | Nov 2005-Mar 2006 | 10,000 Mcfd | 6.50 - 11.20 | (5,291 | ) | |||||||
Gas | Collar | Nov 2005-Mar 2006 | 5,000 Mcfd | 7.00 - 10.00 | (3,370 | ) | |||||||
Gas | Collar | Nov 2005-Mar 2006 | 5,000 Mcfd | 7.00 - 10.00 | (3,370 | ) | |||||||
Gas | Collar | Nov 2005-Mar 2006 | 5,000 Mcfd | 7.00 - 10.10 | (3,306 | ) | |||||||
Gas | Collar | Nov 2005-Mar 2006 | 5,000 Mcfd | 7.00 - 10.17 | (3,262 | ) | |||||||
Gas | Collar | Nov 2005-Mar 2006 | 10,000 Mcfd | 7.50 - 9.55 | (7,317 | ) | |||||||
Gas | Collar | Nov 2005-Mar 2006 | 5,000 Mcfd | 7.50 - 9.55 | (3,658 | ) | |||||||
Gas | Collar | Nov 2005-Mar 2006 | 5,000 Mcfd | 7.50 - 9.60 | (3,625 | ) | |||||||
Gas | Collar | Nov 2005-Mar 2006 | 5,000 Mcfd | 7.50 - 10.55 | (3,018 | ) | |||||||
Gas | Collar | Nov 2005-Mar 2006 | 5,000 Mcfd | 7.50 - 10.60 | (2,988 | ) | |||||||
Gas | Collar | Nov 2005-Mar 2006 | 10,000 Mcfd | 9.50 - 12.01 | (4,253 | ) | |||||||
Gas | Collar | Apr 2006-Oct 2006 | 5,000 Mcfd | 5.50 - 8.10 | (2,943 | ) | |||||||
Gas | Collar | Apr 2006-Oct 2006 | 5,000 Mcfd | 5.50 - 8.25 | (2,825 | ) | |||||||
Gas | Collar | Apr 2006-Oct 2006 | 10,000 Mcfd | 6.50 - 8.25 | (5,553 | ) | |||||||
Gas | Collar | Apr 2006-Oct 2006 | 5,000 Mcfd | 6.50 - 8.25 | (2,776 | ) | |||||||
Gas | Collar | Apr 2006-Oct 2006 | 5,000 Mcfd | 7.00 - 8.35 | (2,653 | ) | |||||||
Gas | Collar | Apr 2006-Oct 2006 | 5,000 Mcfd | 7.00 - 8.35 | (2,653 | ) | |||||||
Gas | Collar | Apr 2006-Oct 2006 | 5,000 Mcfd | 7.00 - 8.35 | (2,653 | ) | |||||||
Gas | Collar | Apr 2006-Oct 2006 | 5,000 Mcfd | 8.00 - 10.10 | (1,387 | ) | |||||||
Gas | Collar | Apr 2006-Oct 2006 | 5,000 Mcfd | 8.00 - 10.10 | (1,387 | ) | |||||||
Gas | Collar | Apr 2006-Oct 2006 | 10,000 Mcfd | 8.00 - 10.20 | (2,676 | ) | |||||||
Gas | Collar | Nov 2006-Mar 2007 | 10,000 Mcfd | 7.50 - 9.65 | (3,633 | ) | |||||||
Gas | Collar | Nov 2006-Mar 2007 | 10,000 Mcfd | 8.50 - 11.35 | (2,168 | ) | |||||||
Gas | Collar | Nov 2006-Mar 2007 | 10,000 Mcfd | 8.50 - 11.50 | (2,092 | ) | |||||||
Oil | Collar | Oct 2005-Dec 2005 | 250 Bbld | 38.00 - 47.75 | (427 | ) | |||||||
Oil | Collar | Oct 2005-Jun 2006 | 500 Bbld | 47.00 - 62.20 | (955 | ) | |||||||
| Total | $ | (96,821 | ) | ||||||||||
Commodity price fluctuations affect our remaining natural gas and crude oil volumes as well as our NGL volumes. Up to 4,500 Mcfd of natural gas is committed at market price through May 2006. Additional gas volumes of 16,500 Mcfd are committed at market price through September 2008. Approximately 14,700 Mcfd sold under these contracts are third-party volumes controlled by us.
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We also enter into financial contracts to hedge our exposure to commodity price risk associated with future contractual natural gas sales and purchases. These contracts consist of fixed price sales to third parties. As a result of these firm sale commitments the associated financial price swaps have qualified as fair value hedges. The following table summarizes our open financial derivative positions and hedged firm commitments as of September 30, 2005 related to natural gas marketing.
Product | Type | Contract Period | Volume | Weighted Avg Price per Mcf | Fair Value | ||||||||
| (in thousands) | |||||||||||||
Fixed price sale contracts | |||||||||||||
Gas | Sale | Oct 2005 | 956 Mcfd | $ | 6.73 | $ | (212 | ) | |||||
Financial derivatives | |||||||||||||
Gas | Floating Price | Oct 2005 | 968 Mcfd | 222 | |||||||||
| Total-net | $ | 10 | |||||||||||
Utilization of our hedging program may result in natural gas and crude oil realized prices varying from market prices that we receive from the sale of natural gas and crude oil. Our revenue from natural gas and crude oil production was $20.2 million and $30.8 million lower as a result of the hedging programs for the first nine months of 2005 and 2004, respectively. Marketing revenue was $0.2 million lower and $0.4 million higher as a result of hedging activities in the first nine months of 2005 and 2004, respectively.
Interest Rate Risk
Our interest rate swap covering $75.0 million notional variable-rate debt ended on March 31, 2005. The interest rate swap converted a floating three-month LIBOR base to a 3.74% fixed-rate.
We terminated an interest rate swap hedging $40.0 million of fixed-rate second lien notes in January 2004. We received a cash settlement of $0.3 million that will continue to be recognized over the period remaining to original maturity date for the swap, December 31, 2006.
Interest expense was $0.3 million lower and $0.5 million higher, respectively, for the nine months ended September 30, 2005 and 2004 as a result of our interest hedging activities.
| 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 the end of the third quarter of 2005, 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 on a timely basis.
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, 2005 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
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PART II – OTHER INFORMATION
| ITEM 1. | Legal Proceedings |
In August 2001, a group of royalty owners, Athel E. Williams et al., brought suit against us and three of our subsidiaries in the Circuit Court of Otsego County, Michigan. The suit alleges that Terra Energy Ltd, one of our subsidiaries, underpaid royalties or overriding royalties to the 13 named plaintiffs and to a class of plaintiffs who have yet to be determined. The pleadings of the plaintiffs seek damages in an unspecified amount and injunctive relief against future underpayments. The court heard arguments on class certification on November 8, 2002, and on December 6, 2002 the court issued a memorandum opinion granting class certification in part and denying it in part. On December 20, 2002, we filed a motion for clarification and reconsideration of the court’s order. That motion was denied on March 9, 2003. After an extended delay resulting from the retention of new counsel by the plaintiffs and the initiation of settlement discussions, on January 21, 2005, the Circuit Court issued an order certifying certain claims to proceed on behalf of a class. The Circuit Court also entered a scheduling order setting trial for January 2007, and declined Defendants’ request to stay proceedings in that court pending an appeal of the certification order.
Defendants have sought leave to appeal the certification order by filing an Application for Leave to Appeal on February 11, 2005 with the Michigan Court of Appeals. Defendants have also requested that the Court of Appeals stay proceedings in the Circuit Court pending the consideration of its appeal, and have requested that the Court of Appeals consider all matters in an expedited manner. On April 22, 2005, the Court of Appeals vacated the certification order and remanded the case to the trial court with instructions to address several particular issues by way of a new order. After limited discovery relating to those issues, the trial court held a follow-up certification hearing on June 1, 2005 and on August 18, 2005, the court again entered new findings and conclusions again favoring certification. We are currently awaiting a ruling from the Court of Appeals on our challenge to those findings and conclusions, the trial court on the certification motion, and the case (including the appeal) is stayed in the meantime.
Based on information currently available to us, our management believes that the final resolution of this matter will not have a material effect on our financial position, results of operations or cash flows.
We are subject to various possible contingencies, which arise primarily from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry. Such contingencies include differing interpretations as to the prices at which natural gas and crude oil sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Although our management believes it has complied with the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued. In addition, production rates, marketing and environmental matters are subject to regulation by various federal and state agencies.
| ITEM 6. | Exhibits: |
| Exhibit No. | Description | |
| 10.1 | Form of Director and Officer Indemnification Agreement (filed as Exhibit 10.1 to the Company’s Form 8-K filed August 26, 2005 and included herein by reference) | |
| 10.2 | Separation, Settlement and Complete Release Agreement, dated August 31, 2005, between Quicksilver Resources Inc. and Mark D. Whitley (filed as Exhibit 10.1 to the Company’s Form 8-K filed September 26, 2005 and included herein by reference) | |
| *15.1 | Awareness Letter of Deloitte & Touche LLP | |
| *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 | |
| * | Filed herewith |
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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 9, 2005
| Quicksilver Resources Inc. | ||
By: | /s/ GLENN DARDEN | |
| Glenn Darden | ||
| President and Chief Executive Officer | ||
By: | /s/ PHILIP W. COOK | |
| Philip W. Cook | ||
| Senior Vice President – Chief Financial Officer | ||
26
EXHIBIT INDEX
| Exhibit No. | Description | |
| 10.1 | Form of Director and Officer Indemnification Agreement (filed as Exhibit 10.1 to the Company’s Form 8-K filed August 26, 2005 and included herein by reference) | |
| 10.2 | Separation, Settlement and Complete Release Agreement, dated August 31, 2005, between Quicksilver Resources Inc. and Mark D. Whitley (filed as Exhibit 10.1 to the Company’s Form 8-K filed September 26, 2005 and included herein by reference) | |
| *15.1 | Awareness Letter of Deloitte & Touche LLP | |
| *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 | |
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