| (Mark one) | |
| [ X ] | Quarterly Report Under Section 13 or 15(d) of the Securities Exchange Act of 1934 For the Quarterly Period Ended September 30, 2004 |
| [ ] | Transition Report Under Section 13 or 15(d) of the Securities Exchange Act of 1934 For the Transition Period from .......... to .......... |
Commission File Number .......... 1-12508
MAGNUM HUNTER
RESOURCES, INC.
Exact name of registrant as specified in its charter
| Nevada | 87-0462881 | |
|---|---|---|
| State or other jurisdiction of incorporation or organization |
IRS employer identification No. |
600 East Las Colinas
Blvd., Suite 1100, Irving, Texas 75039
Address of principal
executive offices
(972)
401-0752
Indicate by check mark whether the
registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period
that the registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).
Yes [ X ] No [ ]
State the number of shares outstanding of each of the issuer's classes of common equity, as of November 3, 2004: 87,105,717.
| September 30, 2004 |
December 31, 2003 | |||||||
|---|---|---|---|---|---|---|---|---|
| ASSETS | ||||||||
| Current Assets | ||||||||
| Cash and cash equivalents | $ | 26,006 | $ | 18,693 | ||||
| Accounts receivable - trade, net of allowance of $4,315 and $4,331 | ||||||||
| respectively | 73,866 | 46,716 | ||||||
| Deferred income taxes, current | 14,174 | 8,263 | ||||||
| Deposits | 1,391 | 2,713 | ||||||
| Land held for sale | 6,067 | 7,563 | ||||||
| Prepaid drilling costs | 8,801 | 8,770 | ||||||
| Other current assets | 11,065 | 7,619 | ||||||
| Total Current Assets | 141,370 | 100,337 | ||||||
| Property, Plant, and Equipment | ||||||||
| Oil and gas properties, full cost method | ||||||||
| Unproved | 89,693 | 110,467 | ||||||
| Proved | 1,734,623 | 1,292,388 | ||||||
| Gas processing plants and pipelines | 35,395 | 34,149 | ||||||
| Other property | 9,875 | 7,805 | ||||||
| Total Property, Plant and Equipment | 1,869,586 | 1,444,809 | ||||||
| Accumulated depreciation, depletion, amortization and impairment | (435,068 | ) | (348,926 | ) | ||||
| Net Property, Plant and Equipment | 1,434,518 | 1,095,883 | ||||||
| Other Assets | ||||||||
| Deferred financing costs and other | 12,167 | 13,205 | ||||||
| Goodwill | 56,467 | 56,467 | ||||||
| Total Assets | $ | 1,644,522 | $ | 1,265,892 | ||||
| LIABILITIES AND STOCKHOLDERS' EQUITY | ||||||||
| Current Liabilities | ||||||||
| Trade payables | $ | 50,957 | $ | 28,793 | ||||
| Accrued interest | 951 | 8,909 | ||||||
| Accrued liabilities | 17,300 | 11,228 | ||||||
| Other current liabilities | 7,893 | 8,802 | ||||||
| Revenues payable | 10,712 | 7,860 | ||||||
| Suspended revenue payable | 20,974 | 16,049 | ||||||
| Derivative liabilities, current | 37,423 | 21,853 | ||||||
| Current maturities of long-term debt | 2,884 | 2,009 | ||||||
| Total Current Liabilities | 149,094 | 105,503 | ||||||
| Long-Term Liabilities | ||||||||
| Long-term debt, less current maturities | 663,114 | 595,503 | ||||||
| Asset retirement obligations | 37,519 | 32,489 | ||||||
| Derivative liabilities, non-current | 12,405 | 1,198 | ||||||
| Deferred income taxes payable | 169,861 | 141,000 | ||||||
| Other non-current liabilities | 460 | 523 | ||||||
| Stockholders' Equity | ||||||||
| Preferred stock - $.001 par value; 10,000,000 shares authorized, 216,000 | ||||||||
| designated as Series A; 80,000 issued and outstanding, liquidation | ||||||||
| amount $0 | 1 | 1 | ||||||
| Common Stock - $.002 par value; 200,000,000 shares authorized, | ||||||||
| 90,934,596 and 71,977,759 shares issued, respectively | 182 | 144 | ||||||
| Additional paid-in capital | 609,900 | 429,446 | ||||||
| Accumulated other comprehensive loss | (31,358 | ) | (13,576 | ) | ||||
| Retained earnings | 66,459 | 5,003 | ||||||
| Common stock in deferred compensation plan, at cost (34,416 shares) | (192 | ) | (192 | ) | ||||
| Unearned common stock in KSOP, at cost (1,156,302 and 1,012,203 shares, | ||||||||
| respectively) | (7,883 | ) | (6,110 | ) | ||||
| 637,109 | 414,716 | |||||||
| Treasury stock, at cost (3,942,294 shares) | (25,040 | ) | (25,040 | ) | ||||
| Total Stockholders' Equity | 612,069 | 389,676 | ||||||
| Total Liabilities and Stockholders' Equity | $ | 1,644,522 | $ | 1,265,892 | ||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
1
| Three Months Ended September 30, |
Nine Months Ended September 30, | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2004 |
2003 |
2004 |
2003 | |||||||||||
| Operating Revenues: | ||||||||||||||
| Oil and gas sales | $ | 115,646 | $ | 73,390 | $ | 302,376 | $ | 211,450 | ||||||
| Gas gathering, marketing and processing | 10,332 | 8,075 | 30,168 | 26,515 | ||||||||||
| Oil field services | 2,482 | 1,110 | 6,330 | 3,102 | ||||||||||
| Total Operating Revenues | 128,460 | 82,575 | 338,874 | 241,067 | ||||||||||
| Operating Costs and Expenses: | ||||||||||||||
| Oil and gas production lifting costs | 15,695 | 16,463 | 43,853 | 42,909 | ||||||||||
| Production taxes and other costs | 11,898 | 7,976 | 29,846 | 25,083 | ||||||||||
| Gas gathering, marketing and processing | 7,128 | 5,832 | 21,046 | 19,260 | ||||||||||
| Oil field services | 1,411 | 724 | 3,755 | 2,174 | ||||||||||
| Depreciation, depletion, amortization and accretion | 35,226 | 26,682 | 88,351 | 73,184 | ||||||||||
| Gain on sale of assets | (116 | ) | (12 | ) | (264 | ) | (152 | ) | ||||||
| General and administrative | 4,963 | 3,757 | 14,461 | 10,098 | ||||||||||
| Total Operating Costs and Expenses | 76,205 | 61,422 | 201,048 | 172,556 | ||||||||||
| Operating Profit | 52,255 | 21,153 | 137,826 | 68,511 | ||||||||||
| Equity in gain (loss) of affiliate | -- | 173 | -- | (64 | ) | |||||||||
| Other income | 67 | 231 | 2,293 | 609 | ||||||||||
| Non-cash hedging adjustments | 351 | 701 | 815 | 1,237 | ||||||||||
| Costs associated with early retirement of debt | (12,250 | ) | (19 | ) | (12,250 | ) | (4,085 | ) | ||||||
| Interest expense | (9,302 | ) | (11,483 | ) | (28,618 | ) | (36,445 | ) | ||||||
| Income Before Income Tax | 31,121 | 10,756 | 100,066 | 29,763 | ||||||||||
| Provision for income tax expense | ||||||||||||||
| Current | (669 | ) | -- | (1,441 | ) | -- | ||||||||
| Deferred | (11,488 | ) | (4,087 | ) | (37,169 | ) | (11,333 | ) | ||||||
| Total Provision for Income Tax Expense | (12,157 | ) | (4,087 | ) | (38,610 | ) | (11,333 | ) | ||||||
| Income Before Cumulative Effect of a Change in Accounting Principle | 18,964 | 6,669 | 61,456 | 18,430 | ||||||||||
| Cumulative effect of a change in accounting principle, | ||||||||||||||
| net of income tax expense of $244 | -- | -- | -- | 399 | ||||||||||
| Net Income | $ | 18,964 | $ | 6,669 | $ | 61,456 | $ | 18,829 | ||||||
| Income per Common Share - Basic | ||||||||||||||
| Income before cumulative effect of a change in | ||||||||||||||
| accounting principle | $ | 0.22 | $ | 0.10 | $ | 0.83 | $ | 0.27 | ||||||
| Cumulative effect of a change in accounting principle . | -- | -- | -- | 0.01 | ||||||||||
| Income per Common Share - Basic | $ | 0.22 | $ | 0.10 | $ | 0.83 | $ | 0.28 | ||||||
| Income per Common Share - Diluted | ||||||||||||||
| Income before cumulative effect of a change in | ||||||||||||||
| accounting principle | $ | 0.22 | $ | 0.10 | $ | 0.81 | $ | 0.27 | ||||||
| Cumulative effect of a change in accounting principle . | -- | -- | -- | 0.01 | ||||||||||
| Income per Common Share - Diluted | $ | 0.22 | $ | 0.10 | $ | 0.81 | $ | 0.28 | ||||||
| Common Shares Used in Per Share Calculation | ||||||||||||||
| Basic | 85,451 | 66,007 | 73,925 | 66,205 | ||||||||||
| Diluted | 87,215 | 67,547 | 75,686 | 67,247 | ||||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
2
| Preferred Stock |
Common Stock |
Treasury Stock |
Additional Paid in Capital |
Retained Earnings |
Deferred Compensation |
Unearned Shares in KSOP |
Accumulated Other Comprehensive Income (Loss) |
Total Stockholders' Equity |
Total Comprehensive Income (Loss) | |||||||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Balance at December 31, 2003 | $ | 1 | $ | 144 | $ | (25,040 | ) | $ | 429,446 | $ | 5,003 | $ | (192 | ) | $ | (6,110 | ) | $ | (13,576 | ) | $ | 389,676 | ||||||||||
| Issuance of 1,707 shares of common stock pursuant to | ||||||||||||||||||||||||||||||||
| employee stock option plan | 3 | 7,804 | 7,807 | |||||||||||||||||||||||||||||
| Issuance of 17,250 shares through secondary offering, | ||||||||||||||||||||||||||||||||
| net of offering costs | 35 | 169,282 | 169,317 | |||||||||||||||||||||||||||||
| Deferred tax benefit on exercise of warrants and | ||||||||||||||||||||||||||||||||
| employee stock options | 2,528 | 2,528 | ||||||||||||||||||||||||||||||
| Stock compensation | 428 | 428 | ||||||||||||||||||||||||||||||
| Loan of 225 shares to KSOP plan | (2,259 | ) | (2,259 | ) | ||||||||||||||||||||||||||||
| Employee salary deferrals to KSOP, representing 81 shares | 412 | 486 | 898 | |||||||||||||||||||||||||||||
| Net Income | 61,456 | 61,456 | $ | 61,456 | ||||||||||||||||||||||||||||
| Reclassification adjustment related to derivative | ||||||||||||||||||||||||||||||||
| contracts, net of income tax expense of $10,382 | 17,030 | 17,030 | 17,030 | |||||||||||||||||||||||||||||
| Change in fair value of outstanding hedge positions, net | ||||||||||||||||||||||||||||||||
| of income tax benefit of $20,998 | (34,443 | ) | (34,443 | ) | (34,443 | ) | ||||||||||||||||||||||||||
| Amortization of purchased hedge positions, net of income | ||||||||||||||||||||||||||||||||
| tax benefit of $225 | (369 | ) | (369 | ) | (369 | ) | ||||||||||||||||||||||||||
| Balance at September 30, 2004 | $ | 1 | $ | 182 | $ | (25,040 | ) | $ | 609,900 | $ | 66,459 | $ | (192 | ) | $ | (7,883 | ) | $ | (31,358 | ) | $ | 612,069 | $ | 43,674 | ||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
3
| Nine Months Ended September 30, | ||||||||
|---|---|---|---|---|---|---|---|---|
| 2004 |
2003 | |||||||
| CASH FLOW FROM OPERATING ACTIVITIES: | ||||||||
| Net Income | $ | 61,456 | $ | 18,829 | ||||
| Adjustments to reconcile net income to cash provided by operating | ||||||||
| activities: | ||||||||
| Cumulative effect of a change in accounting principle | -- | (399 | ) | |||||
| Depreciation, depletion, amortization and accretion | 88,351 | 73,184 | ||||||
| Amortization of deferred financing costs | 1,998 | 1,779 | ||||||
| Costs associated with early retirement of debt | 12,250 | 4,085 | ||||||
| Increase in allowance for doubtful accounts | 361 | -- | ||||||
| Deferred income taxes | 37,169 | 11,333 | ||||||
| Equity in losses of unconsolidated affiliate | -- | 64 | ||||||
| Excess of fair value over cost of shares released from KSOP | 412 | 65 | ||||||
| Gain on sale of assets | (264 | ) | (152 | ) | ||||
| Minority interest in consolidated subsidiary | (63 | ) | 52 | |||||
| Non-cash hedging adjustments | (815 | ) | (1,237 | ) | ||||
| Stock compensation | 428 | 1,728 | ||||||
| Changes in certain assets and liabilities: | ||||||||
| Accounts receivable | (27,511 | ) | 3,846 | |||||
| Deposits and other current assets | (2,602 | ) | 8,013 | |||||
| Derivative liabilities | (996 | ) | ||||||
| Accounts payable and accrued liabilities | 22,728 | 14,788 | ||||||
| (Payment) refund of income taxes | (1,508 | ) | 7,865 | |||||
| Net Cash Provided by Operating Activities | 191,394 | 143,843 | ||||||
| CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||
| Proceeds from sale of assets, net of purchase price adjustments | 11,677 | 14,623 | ||||||
| Additions to property and equipment | (194,696 | ) | (144,243 | ) | ||||
| Cash paid for New Mexico property acquisition | (232,090 | ) | -- | |||||
| Proceeds from sale of unconsolidated affiliate | -- | 5,160 | ||||||
| Deposit of funds into escrow for pending acquisition of properties . | (2,023 | ) | -- | |||||
| (Increase) decrease in other assets | (143 | ) | 46 | |||||
| Payment received on note receivable | 350 | -- | ||||||
| Distribution from unconsolidated affiliate | -- | 1,510 | ||||||
| Investment in unconsolidated affiliate | -- | (600 | ) | |||||
| Net Cash Used in Investing Activities | (416,925 | ) | (123,504 | ) | ||||
| CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||
| Proceeds from issuance of debt | 432,500 | 320,075 | ||||||
| Redemption of notes payable | (115,080 | ) | (77,292 | ) | ||||
| Fees paid related to financing activities | (913 | ) | (456 | ) | ||||
| Payments of principal on debt and production payment | (259,014 | ) | (253,202 | ) | ||||
| Increase in notes receivable from affiliate | -- | (225 | ) | |||||
| Loan made to KSOP | (2,259 | ) | (2,711 | ) | ||||
| Repayment of loan to KSOP | 486 | 296 | ||||||
| Proceeds from issuance of common stock | 7,807 | 215 | ||||||
| Proceeds from public offering of common stock, net of offering costs | 169,317 | -- | ||||||
| Purchase of common stock for deferred compensation plan | -- | (295 | ) | |||||
| Purchase of treasury stock | -- | (7,413 | ) | |||||
| Increase in restricted cash for payment of notes payable | -- | (227 | ) | |||||
| Net Cash Provided by (Used in) Financing Activities | 232,844 | (21,235 | ) | |||||
| NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | 7,313 | (896 | ) | |||||
| CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD | 18,693 | 3,069 | ||||||
| CASH AND CASH EQUIVALENTS AT END OF PERIOD | $ | 26,006 | $ | 2,173 | ||||
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | ||||||||
| Cash paid for interest | $ | 45,541 | $ | 44,750 | ||||
| Cash paid (refunded) for income taxes | $ | 1,508 | $ | (7,865 | ) | |||
| Non-cash accruals for employee incentives | $ | 2,319 | $ | 840 | ||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
4
In this quarterly report on Form 10-Q, the words “Magnum Hunter,” “company,” “we,” “our,” and “us” refer to Magnum Hunter Resources, Inc. and its consolidated subsidiaries unless otherwise stated or the context otherwise requires. The condensed consolidated balance sheet of Magnum Hunter Resources, Inc. and subsidiaries as of September 30, 2004, the condensed consolidated statements of income for the three and nine months ended September 30, 2004 and 2003, the condensed consolidated statement of stockholders’ equity and comprehensive income for the nine months ended September 30, 2004, and the condensed consolidated statements of cash flows for the nine months ended September 30, 2004 and 2003, are unaudited. The December 31, 2003 condensed consolidated balance sheet information is derived from audited financial statements. In the opinion of management, all necessary adjustments (which include only normal recurring adjustments) have been made to present fairly the financial position at September 30, 2004, and the results of operations for the three and nine-month periods ended September 30, 2004 and 2003, changes in stockholders’ equity and comprehensive income for the nine months ended September 30, 2004, and cash flows for the nine-month periods ended September 30, 2004 and 2003.
Certain information and footnote 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. It is suggested that these condensed financial statements be read in conjunction with the financial statements and notes thereto included in our December 31, 2003 annual report and in our Form 10-K. The results of operations for the three and nine-month periods ended September 30, 2004 are not necessarily indicative of the operating results that will occur for the full year.
The accompanying condensed consolidated financial statements include the accounts of the company and our subsidiaries. All significant intercompany transactions and balances have been eliminated in consolidation. Certain items have been reclassified to conform with the current presentation.
Magnum Hunter is a holding company with no significant assets or operations other than our investments in our subsidiaries. The wholly-owned subsidiaries of the company, except for Canvasback Energy, Inc., Redhead Energy Inc. and Metrix Networks, Inc., an 80% owned subsidiary of the company, collectively referred to as Canvasback, are direct guarantors of each of our 9.6% Senior Notes, our Senior Bank Credit Facility (“Facility”) and our Floating Rate Convertible Senior Notes (“Convertible Notes”), and have fully and unconditionally guaranteed these obligations on a joint and several basis. The guarantors comprise all of our direct and indirect subsidiaries (other than Canvasback), and we have presented separate condensed consolidating financial statements and other disclosures concerning the guarantors and Canvasback (See Note 10). Except for Canvasback, there is no restriction on the ability of consolidated or unconsolidated subsidiaries to transfer funds to the company in the form of loans or advances.
The Financial Accounting Standards Board (“FASB”) has issued FASB Staff Position (“FSP”) No. 142-2, “Application of FASB Statement 142, Goodwill and Other Intangible Assets, to Oil- and Gas-Producing Entities” after evaluating an issue involving the classification of mineral rights. In June 2001, FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 141, “Business Combinations,” which requires the purchase method of accounting for business combinations initiated after June 30, 2001 and eliminates the pooling-of-interests method. In July 2001, the FASB also issued SFAS No. 142, “Goodwill and Other Intangible Assets,” which discontinues the practice of amortizing goodwill and indefinite lived intangible assets and initiates an annual review of impairment. Intangible assets with a determinable useful life will continue to be amortized over that period. The amortization provisions apply to goodwill and intangible assets acquired after June 30, 2001. SFAS No. 141 and 142 clarify that more assets should be distinguished and classified between tangible and intangible. We did not change or reclassify contractual mineral rights included in proved and unproved oil and gas properties on our balance sheet upon adoption of SFAS No. 142. We believe the treatment of such mineral rights as tangible assets under the full cost method of accounting for oil and gas properties is appropriate. An issue was raised to the FASB regarding whether these mineral rights should be classified as tangible or intangible assets. FSP No. 142-2 addressed this issue and supports our current accounting treatment of mineral rights and will not impact our financial statements. This FSP is effective for reporting periods beginning after September 2, 2004.
5
FASB issued FSP FAS 129-1, “Disclosure Requirements Under FASB Statement No. 129, Disclosure of Information About Capital Structure,” in April 2004. This FSP provides additional guidance on the disclosure requirements of contingently convertible securities. We have made the required disclosures related to the terms of our Convertible Notes in our Annual Report on Form 10-K and have provided explanations in Note 6 of this Form 10-Q about the dilutive effects of these notes on our earnings per share (“EPS”).
FASB’s Emerging Issues Task Force (“EITF”) has recently issued a Draft EITF Abstract for EITF Issue No. 04-8, “The Effect of Contingently Convertible Debt on Diluted Earnings per Share,” which addresses the issue of when the dilutive effects of contingently convertible debt instruments should be included in diluted earnings per share. This guidance would require companies to include the dilutive effect of convertible debt securities in diluted earnings per share regardless of whether or not the contingent conversion features have been triggered. The comment period for this draft ended in September 2004. The Task Force has reached a final consensus and affirmed their position in the Draft EITF Abstract as it relates to market contingencies. The adoption of this guidance would not have an impact on any of our reported earnings per share because the stock price has not exceeded the conversion price of our Convertible Notes. The principal of our Convertible Notes must be settled in cash, with the conversion spread settled in stock. Since the conversion price has not been exceeded in the market, no incremental shares would have been issued. This guidance is expected to be effective at the same time as the FASB Statement No. 128(R), “Earnings per Share”, which has yet to be issued, but is expected to be effective for periods ending after December 15, 2004 and will require retroactive restatement of earnings per share.
The SEC Staff Accounting Bulletin (“SAB”) 106 was released in September 2004. SAB 106 expresses the SEC staff’s views on the interaction of SFAS No. 143 and the full cost method and provides guidance on computing the full cost ceiling as well as depreciation, depletion, and amortization. The SAB also requires additional disclosures regarding how the application of SFAS No. 143 has affected the ceiling test and depreciation, depletion and amortization. This guidance is effective for the first fiscal quarter beginning after its publication. We do not expect the application of these guidelines to have a significant impact on our ceiling test or depletion expense.
Beginning June 1, 2003, and effective January 1, 2003, we began expensing the fair market value of stock options newly granted, modified or settled pursuant to SFAS No. 123, “Accounting for Stock-Based Compensation,” and as allowed under the prospective method of SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure, an amendment to SFAS No. 123.” The fair value of each option granted after December 31, 2002 is estimated on the grant date, using the Black-Scholes option-pricing model. For the three and nine months ended September 30, 2004, we recorded pre-tax stock compensation expense of $369 thousand and $428 thousand, respectively, which is reflected in our general and administrative expenses. We recorded $1.3 million and $1.7 million, respectively, of pre-tax stock compensation expense for the three and nine months ended September 30, 2003. For options granted prior to January 1, 2003, we continue to use the intrinsic method under APB No. 25, “Accounting for Stock Issued to Employees and Related Interpretations,” whereby no compensation expense is recognized for stock options granted with an exercise price equal to the market value of our stock on the grant date.
6
If we had recorded stock option expense under the fair value provisions of SFAS No. 123 for all prior and current grants, our net income and EPS would have been as shown in the below pro forma tables (in thousands):
| Three Months Ended September 30, |
Nine Months Ended September 30, | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2004 |
2003 |
2004 |
2003 | |||||||||||
| Net income, as reported | $ | 18,964 | $ | 6,669 | $ | 61,456 | $ | 18,829 | ||||||
| Total stock-based employee compensation | ||||||||||||||
| expense included in reported net income, | ||||||||||||||
| net of income taxes of $140, $491, $162 | ||||||||||||||
| and $654 | 229 | 805 | 266 | 1,073 | ||||||||||
| Deduct: Total stock-based employee | ||||||||||||||
| compensation determined under fair | ||||||||||||||
| value-based method for all awards, net of | ||||||||||||||
| income taxes of $558, $931, $1,408 and $1,944 | (915 | ) | (1,526 | ) | (2,309 | ) | (3,189 | ) | ||||||
| Pro forma net income | $ | 18,278 | $ | 5,948 | $ | 59,413 | $ | 16,713 | ||||||
| Earnings per share: | ||||||||||||||
| Basic - as reported | $ | 0.22 | $ | 0.10 | $ | 0.83 | $ | 0.28 | ||||||
| Basic - pro forma | $ | 0.21 | $ | 0.09 | $ | 0.80 | $ | 0.25 | ||||||
| Diluted - as reported | $ | 0.22 | $ | 0.10 | $ | 0.81 | $ | 0.28 | ||||||
| Diluted - pro forma | $ | 0.21 | $ | 0.09 | $ | 0.79 | $ | 0.25 | ||||||
Exposure Draft No. 1102-100, “Share-Based Payment, an amendment of FASB Statements No. 123 and 95,” which was issued by the FASB on March 31, 2004, may impact our future accounting for stock-based compensation. If we are required to adopt this amendment in its current form, we would be required to discontinue the prospective method of expensing stock options which we currently follow. Under this proposed literature, we would be required to expense all unvested grants issued prior to January 1, 2003, which would result in higher compensation costs.
In June 2001, SFAS No. 141, “Business Combinations,” and SFAS No. 142, “Goodwill and Other Intangible Assets,” were issued to be effective for fiscal years beginning after December 15, 2001. Under these statements, goodwill is no longer amortized, but is subject to annual impairment tests. We completed our annual test as of December 31, 2003 and found no impairment. There were no changes to the carrying value of goodwill during the nine months ended September 30, 2004.
Our goodwill results from our merger with Prize Energy Corp. (“Prize”), which was completed on March 15, 2002, and the purchase price allocation was finalized as of June 30, 2003. The goodwill has been fully allocated to our Exploration and Production segment.
Our asset retirement obligations include plugging, abandonment, decommission and remediation costs, which are included in developed oil and gas properties, production and distribution facilities and natural gas processing plants.
The following is a reconciliation of the asset retirement obligation liability at September 30, 2004 (in thousands):
| Balance at January 1, 2004 | $ | 32,489 | |||
| Liabilities incurred | 5,118 | ||||
| Liabilities settled | (784 | ) | |||
| Liabilities sold | (366 | ) | |||
| Accretion expense | 2,160 | ||||
| Change in retirement cost estimates | 486 | ||||
| Balance at September 30, 2004 | $ | 39,103 | |||
7
Of the $39.1 million in asset retirement obligations, $1.6 million is included in other current liabilities on our condensed consolidated balance sheet at September 30, 2004.
SEC Staff Accounting Bulletin (“SAB”) 106 was released in September 2004. SAB 106 expresses the SEC staff’s views on the interaction of SFAS No. 143 and the full cost method of accounting and provides guidance on computing the full cost ceiling as well as depreciation, depletion, and amortization. The SAB also requires additional disclosures regarding how the application of SFAS No. 143 has affected the ceiling test and depreciation, depletion and amortization. This guidance is effective for the first fiscal quarter beginning after its publication. We do not expect the application of these guidelines to have a significant impact on our ceiling test or depletion expense.
The following is a reconciliation of the basic and diluted earnings per share computations (in thousands, except for per share amounts):
| Three Months Ended | ||||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| September 30, 2004 |
September 30, 2003 | |||||||||||||||||||
| Income |
Weighted Average Shares |
Per Share Amount |
Income |
Weighted Average Shares |
Per Share Amount | |||||||||||||||
| Basic EPS | ||||||||||||||||||||
| Income available to common | ||||||||||||||||||||
| stockholders | $ | 18,964 | 85,451 | $ | 0.22 | $ | 6,669 | 66,007 | $ | 0.10 | ||||||||||
| Effect of Dilutive Securities | ||||||||||||||||||||
| Warrants | -- | 83 | ||||||||||||||||||
| Options | 1,764 | 1,457 | ||||||||||||||||||
| Diluted EPS | ||||||||||||||||||||
| Income available to common stock-holders and assumed conversions | $ | 18,964 | 87,215 | $ | 0.22 | $ | 6,669 | 67,547 | $ | 0.10 | ||||||||||
| Nine Months Ended | ||||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| September 30, 2004 |
September 30, 2003 | |||||||||||||||||||
| Income |
Weighted Average Shares |
Per Share Amount |
Income |
Weighted Average Shares |
Per Share Amount | |||||||||||||||
| Basic EPS | ||||||||||||||||||||
| Income available to common | ||||||||||||||||||||
| stockholders | $ | 61,456 | 73,925 | $ | 0.83 | $ | 18,829 | 66,205 | $ | 0.28 | ||||||||||
| Effect of Dilutive Securities | ||||||||||||||||||||
| Warrants | -- | 28 | ||||||||||||||||||
| Options | 1,761 | 1,014 | ||||||||||||||||||
| Diluted EPS | ||||||||||||||||||||
| Income available to common stock- | ||||||||||||||||||||
| holders and assumed conversions | $ | 61,456 | 75,686 | $ | 0.81 | $ | 18,829 | 67,247 | $ | 0.28 | ||||||||||
At September 30, 2004, warrants representing 7,228,457 shares of common stock and options representing 6,418,377 shares of common stock were outstanding. At September 30, 2003, warrants representing 7,873,206 shares of common stock and options representing 6,876,913 shares of common stock were outstanding. For the three- and nine-month periods ended September 30, 2004, 7,228,457 shares of common stock representing warrants, and 1,428,000 shares and 499,333 shares of common stock representing options, respectively, were excluded from the diluted earnings per share calculations because the exercise price exceeded the average market price of our common stock for these periods. For the three- and nine-month periods ended September 30, 2003, 7,228,457 shares and 7,658,290 shares of common stock representing warrants, respectively, and 2,913,800 shares and 3,050,733 shares of common stock representing options, respectively, were excluded from the diluted earnings per share calculations because the exercise price exceeded the average market price of our common stock for these periods. There was no dilutive effect from our Convertible Notes at September 30, 2004, because their conversion price exceeded the average market price of our common stock during the period and only the conversion spread is issuable in shares.
8
Notes payable and long-term debt at September 30, 2004 and December 31, 2003 consisted of the following (in thousands):
| September 30, 2004 |
December 31, 2003 | |||||||
|---|---|---|---|---|---|---|---|---|
| Long-Term Debt: | ||||||||
| Bank debt under revolving credit agreements, due | ||||||||
| May 2, 2007, 3.34% at September 30, 2004 | $ | 340,000 | $ | 165,000 | ||||
| Capital lease obligations | 5,998 | 7,500 | ||||||
| 9.6% Senior unsecured notes, due March 15, 2012 | 195,000 | 300,000 | ||||||
| Floating rate convertible senior notes, due December 15, | ||||||||
| 2023, 1.88% at September 30, 2004 | 125,000 | 125,000 | ||||||
| Production payment liability, non-recourse | -- | 12 | ||||||
| 665,998 | 597,512 | |||||||
| Less: Current portion of capital lease obligations | 2,884 | 2,009 | ||||||
| Total Long-Term Debt | $ | 663,114 | $ | 595,503 | ||||
We have a Facility which provides for total borrowings of $750 million, on which our borrowing base was limited to $480 million at September 30, 2004. The level of the borrowing base is dependent on the valuation by the lenders of the assets pledged, which are primarily oil and gas reserves.
On April 30, 2004, we amended our Facility to receive a more favorable rate structure and to increase the borrowing base to $275 million. We also extended the expiration date of the Facility by one year, resulting in a new maturity date of May 2, 2007. On July 15, 2004, we amended our Facility to increase the borrowing base to $480 million upon consummation of the New Mexico property acquisition (see Note 12), an increase of $205 million, and to allow us to use proceeds from our secondary common stock offering to redeem and retire up to $105 million in principal of our 9.6% Senior Notes outstanding. On October 18, 2004, we amended our Facility to increase the borrowing base from $480 million to $525 million and to increase our maximum borrowings from $500 million to $750 million.
On a semi-annual basis, our borrowing base under our Facility is redetermined by the financial institutions who have committed to the company based on their review of our proved oil and gas reserves and other assets. If the outstanding senior bank debt exceeds the redetermined borrowing base, the company must repay the excess. As a result of the redetermination completed on October 15, 2004, our borrowing base was increased by $45 million to $525 million, and the maximum borrowings were increased from $500 million to $750 million, as discussed above. The next redetermination date will have an effective date of December 31, 2004 and will have a completion date of no later than May 9, 2005.
On August 27, 2004, we redeemed $105 million in principal of our 9.6% Senior Notes at a redemption price of 109.6% of par. We paid the holders of these redeemed notes $115.1 million plus accrued and unpaid interest of $4.5 million. We used a portion of the proceeds from our secondary offering to fund this redemption. We recorded $12.3 million in costs associated with this redemption comprised of $10.1 million in premiums and $2.2 million in unamortized deferred financing fees which were written off.
We were obligated to nine crude oil derivatives and fourteen natural gas derivatives on September 30, 2004. All outstanding derivatives qualify for cash flow hedge accounting treatment as defined within SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” which requires derivative assets and liabilities to be recorded at their fair value on the balance sheet with an offset for the effective portion of the hedge to other comprehensive income. Hedge ineffectiveness on cash-flow hedges is recorded in earnings.
9
At September 30, 2004, the fair value of the company’s derivatives were as follows (in thousands):
| Derivative Liabilities | |||||
| Natural gas collars | $ | (30,821 | ) | ||
| Natural gas swaps | (5,190 | ) | |||
| Crude oil collars | (9,642 | ) | |||
| Crude oil swaps | (4,175 | ) | |||
| Net Derivative Liability | $ | (49,828 | ) | ||
Of the $49.8 million of derivative liabilities, $37.4 million is included in other current liabilities and $12.4 million is included in long-term liabilities on our condensed consolidated balance sheet at September 30, 2004.
For the three and nine-month periods ended September 30, 2004, the condensed consolidated statement of income includes non-cash hedging adjustment gains of $351 thousand and $815 thousand, respectively. These gains are comprised of hedge ineffectiveness gains of $153 thousand and $221 thousand, respectively, related to the crude oil and natural gas derivatives as well as non-cash gains of $198 thousand and $594 thousand, respectively, related to the amortization of hedge contracts acquired in the Prize merger. The remaining amortization amount relating to hedge contracts acquired in the Prize merger that will be reclassified into the consolidated statement of income in 2004 is a $198 thousand gain. It is estimated at this time that $24 million, net of income tax, of other comprehensive loss will be reclassified into the consolidated statement of income during the next 12 months.
On July 12, 2004, we terminated a natural gas collar for 10,000 Mmbtu per day for the period August through December 2004. In closing this contract we realized a $1.3 million loss, which will be recognized in earnings with the underlying forecasted commodity sales transactions for the months August through December 2004. After this contract was terminated, our remaining natural gas production hedged for October through December 2004 decreased to approximately 85.0 Mmcf/day with a weighted average floor price of $4.03 and a weighted average ceiling price of $6.00.
We have three reportable segments. The Exploration and Production segment is engaged in exploratory and developmental drilling and acquisition, production, and sale of crude oil, condensate, and natural gas. The Gas Gathering, Marketing, and Processing segment is engaged in the gathering and compression of natural gas from the wellhead, the purchase and resale of natural gas that it gathers, and the processing of natural gas liquids. The Oil Field Services segment is engaged in the managing and operation of producing oil and gas properties for interest owners.
Our reportable segments are strategic business units that offer different products and services. They are managed separately because each business requires different technology and marketing strategies. The Exploration and Production segment has six geographic areas that are aggregated. The Gas Gathering, Marketing, and Processing segment includes the activities of the four gathering systems and four natural gas liquids processing plants located in two geographic areas that are aggregated. The Oil Field Services segment has six geographic areas that are aggregated. The reason for aggregating the segments, in each case, is due to the similarity in nature of the products, the production processes, the type of customers, the method of distribution, and the regulatory environments.
The accounting policies of the segments are the same as those for the company as a whole. We evaluate performance based on profit or loss from operations before income taxes. The accounting for intersegment sales and transfers is done as if the sales or transfers were to third parties — that is, at current market prices.
10
Segment data for the periods ended September 30, 2004 and 2003 follows (in thousands):
| Three Months Ended September 30, 2004: |
Exploration & Production |
Gas Gathering, Marketing & Processing |
Oil Field Services |
All Other |
Elimination |
Consolidated | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Revenue from external customers | $ | 115,646 | $ | 10,332 | $ | 2,482 | $ | -- | $ | -- | $ | 128,460 | ||||||||
| Intersegment revenues | 545 | 6,387 | 3,737 | -- | (10,669 | ) | -- | |||||||||||||
| Depreciation, depletion, amortization | ||||||||||||||||||||
| and accretion | 34,336 | 589 | 280 | 21 | -- | 35,226 | ||||||||||||||
| Segment profit (loss) | 53,717 | 2,615 | 791 | (4,868 | ) | -- | 52,255 | |||||||||||||
| Interest expense | (9,302 | ) | (9,302 | ) | ||||||||||||||||
| Costs relating to early retirement of debt | (12,250 | ) | (12,250 | ) | ||||||||||||||||
| Other income | 418 | 418 | ||||||||||||||||||
| Income before income taxes | 31,121 | |||||||||||||||||||
| Provision for income tax expense | (12,157 | ) | (12,157 | ) | ||||||||||||||||
| Net income | $ | 18,964 | ||||||||||||||||||
| Three Months Ended September 30, 2003: |
Exploration & Production |
Gas Gathering, Marketing & Processing |
Oil Field Services |
All Other |
Elimination |
Consolidated | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Revenue from external customers | $ | 73,390 | $ | 8,075 | $ | 1,110 | $ | -- | $ | -- | $ | 82,575 | ||||||||
| Intersegment revenues | 437 | 5,712 | 3,308 | -- | (9,457 | ) | -- | |||||||||||||
| Depreciation, depletion, amortization | ||||||||||||||||||||
| and accretion | 25,831 | 577 | 146 | 128 | -- | 26,682 | ||||||||||||||
| Segment profit (loss) | 23,120 | 1,666 | 240 | (3,873 | ) | -- | 21,153 | |||||||||||||
| Equity in losses of affiliates | 173 | 173 | ||||||||||||||||||
| Interest expense | (11,483 | ) | (11,483 | ) | ||||||||||||||||
| Costs relating to early retirement of debt | (19 | ) | (19 | ) | ||||||||||||||||
| Other income | 932 | 932 | ||||||||||||||||||
| Income before income taxes | 10,756 | |||||||||||||||||||
| Provision for income tax expense | (4,087 | ) | (4,087 | ) | ||||||||||||||||
| Net income | $ | 6,669 | ||||||||||||||||||
| Nine Months Ended September 30, 2004: |
Exploration & Production |
Gas Gathering, Marketing & Processing |
Oil Field Services |
All Other |
Elimination |
Consolidated | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Revenue from External customers | $ | 302,376 | $ | 30,168 | $ | 6,330 | $ | -- | $ | -- | $ | 338,874 | ||||||||
| Intersegment revenues | 1,439 | 18,684 | 10,920 | -- | (31,043 | ) | -- | |||||||||||||
| Depreciation, depletion, amortization, | ||||||||||||||||||||
| and accretion | 85,639 | 1,758 | 853 | 101 | 88,351 | |||||||||||||||
| Segment profit (loss) | 143,038 | 7,364 | 1,722 | (14,298 | ) | 137,826 | ||||||||||||||
| Interest expense | (28,618 | ) | (28,618 | ) | ||||||||||||||||
| Costs relating to early retirement of debt | (12,250 | ) | (12,250 | ) | ||||||||||||||||
| Other income | 3,108 | 3,108 | ||||||||||||||||||
| Income before income taxes | 100,066 | |||||||||||||||||||
| Provision for income tax expense | (38,610 | ) | (38,610 | ) | ||||||||||||||||
| Net income | $ | 61,456 | ||||||||||||||||||
11
| Nine Months Ended September 30, 2003: |
Exploration & Production |
Gas Gathering, Marketing & Processing |
Oil Field Services |
All Other |
Elimination |
Consolidated | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Revenue from external customers | $ | 211,450 | $ | 26,515 | $ | 3,102 | $ | -- | $ | -- | $ | 241,067 | ||||||||
| Intersegment revenues | 1,280 | 17,907 | 10,164 | -- | (29,351 | ) | -- | |||||||||||||
| Depreciation, depletion, amortization, | ||||||||||||||||||||
| and accretion | 70,529 | 1,730 | 441 | 484 | 73,184 | |||||||||||||||
| Segment profit (loss) | 72,929 | 5,525 | 487 | (10,430 | ) | 68,511 | ||||||||||||||
| Equity in losses of affiliates | (64 | ) | (64 | ) | ||||||||||||||||
| Interest expense | (36,445 | ) | (36,445 | ) | ||||||||||||||||
| Costs associated with early retirement | ||||||||||||||||||||
| of debt | (4,085 | ) | (4,085 | ) | ||||||||||||||||
| Other income | 1,846 | 1,846 | ||||||||||||||||||
| Income before income taxes | 29,763 | |||||||||||||||||||
| Provision for income tax expense | (11,333 | ) | (11,333 | ) | ||||||||||||||||
| Cumulative effect of a change in | ||||||||||||||||||||
| accounting principle | 399 | 399 | ||||||||||||||||||
| Net income | $ | 18,829 | ||||||||||||||||||
The company and its wholly-owned subsidiaries, except Canvasback, are direct guarantors of our 9.6% Senior Notes, Convertible Notes and Facility and have fully and unconditionally guaranteed these obligations on a joint and several basis. In addition to not being a guarantor of the company’s 9.6% Senior Notes, Convertible Notes and Facility, Canvasback cannot be included in determining compliance with certain financial covenants under the company’s Facility. We have not included separate financial statements related to the guarantors because management has determined that they are not material to investors. Condensed consolidating financial information for Magnum Hunter Resources, Inc. and subsidiaries as of September 30, 2004 and December 31, 2003, and for the three- and nine-month periods ended September 30, 2004 and 2003, was as follows:
| As of September 30, 2004 | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Amounts in Thousands |
Magnum Hunter Resources, Inc. and Guarantor Subs |
Canvasback Energy, Inc. (Non Guarantor) |
Eliminations |
Magnum Hunter Resources, Inc. Consolidated | ||||||||||
| ASSETS | ||||||||||||||
| Current assets | $ | 148,338 | $ | 5,043 | $ | (12,011 | ) | $ | 141,370 | |||||
| Property and equipment | ||||||||||||||
| (using full cost accounting) | 1,428,212 | 6,306 | -- | 1,434,518 | ||||||||||
| Investment in subsidiaries | ||||||||||||||
| (equity method) | 18,785 | -- | (18,785 | ) | -- | |||||||||
| Investment in Parent | -- | 34,127 | (34,127 | ) | -- | |||||||||
| Other assets | 68,483 | 151 | -- | 68,634 | ||||||||||
| Total assets | $ | 1,663,818 | $ | 45,627 | $ | (64,923 | ) | $ | 1,644,522 | |||||
| LIABILITIES AND STOCKHOLDERS' | ||||||||||||||
| EQUITY | ||||||||||||||
| Current liabilities | $ | 148,378 | $ | 12,727 | $ | (12,011 | ) | $ | 149,094 | |||||
| Long-term liabilities | 869,244 | 14,115 | -- | 883,359 | ||||||||||
| Stockholders' equity | 646,196 | 18,785 | (52,912 | ) | 612,069 | |||||||||
| Total liabilities and stockholders' equity | $ | 1,663,818 | $ | 45,627 | $ | (64,923 | ) | $ | 1,644,522 | |||||
12
| As of December 31, 2003 | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Amounts in Thousands |
Magnum Hunter Resources, Inc. and Guarantor Subs |
Canvasback Energy, Inc. (Non Guarantor) |
Eliminations |
Magnum Hunter Resources, Inc. Consolidated | ||||||||||
| ASSETS | ||||||||||||||
| Current assets | $ | 108,801 | $ | 18,163 | $ | (26,627 | ) | $ | 100,337 | |||||
| Property and equipment | ||||||||||||||
| (using full cost accounting) | 1,089,366 | 6,517 | -- | 1,095,883 | ||||||||||
| Investment in subsidiaries | ||||||||||||||
| (equity method) | 17,875 | -- | (17,875 | ) | -- | |||||||||
| Investment in Parent | -- | 34,127 | (34,127 | ) | -- | |||||||||
| Other assets | 69,672 | -- | -- | 69,672 | ||||||||||
| Total assets | $ | 1,285,714 | $ | 58,807 | $ | (78,629 | ) | $ | 1,265,892 | |||||
| LIABILITIES AND STOCKHOLDERS' | ||||||||||||||
| EQUITY | ||||||||||||||
| Current liabilities | $ | 104,806 | $ | 27,324 | $ | (26,627 | ) | $ | 105,503 | |||||
| Long-term liabilities | 757,105 | 13,608 | -- | 770,713 | ||||||||||
| Stockholders' equity | 423,803 | 17,875 | (52,002 | ) | 389,676 | |||||||||
| Total liabilities and stockholders' equity | $ | 1,285,714 | $ | 58,807 | $ | (78,629 | ) | $ | 1,265,892 | |||||
| For the Three Months Ended September 30, 2004 | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Amounts in Thousands |
Magnum Hunter Resources, Inc. and Guarantor Subs |
Canvasback Energy, Inc. (Non Guarantor) |
Eliminations |
Magnum Hunter Resources, Inc. Consolidated | ||||||||||
| Revenues | $ | 125,995 | $ | 2,696 | $ | (231 | ) | $ | 128,460 | |||||
| Expenses | 95,760 | 1,784 | (205 | ) | 97,339 | |||||||||
| Income before equity in net income of | 30,235 | 912 | (26 | ) | 31,121 | |||||||||
| subsidiary | ||||||||||||||
| Equity in net income of subsidiary | 550 | -- | (550 | ) | -- | |||||||||
| Income before income taxes | 30,785 | 912 | (576 | ) | 31,121 | |||||||||
| Income tax (expense) benefit | (11,821 | ) | (345 | ) | 9 | (12,157 | ) | |||||||
| Net income | $ | 18,964 | $ | 567 | $ | (567 | ) | $ | 18,964 | |||||
| For the Three Months Ended September 30, 2003 | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Amounts in Thousands |
Magnum Hunter Resources, Inc. and Guarantor Subs |
Canvasback Energy, Inc. (Non Guarantor) |
Eliminations |
Magnum Hunter Resources, Inc. Consolidated | ||||||||||
| Revenues | $ | 81,529 | $ | 1,046 | $ | -- | $ | 82,575 | ||||||
| Expenses | 71,468 | 351 | -- | 71,819 | ||||||||||
| Income before equity in net earnings of subsidiary | 10,061 | 695 | -- | 10,756 | ||||||||||
| Equity in net earnings of subsidiary | 432 | -- | (432 | ) | -- | |||||||||
| Income before income taxes | 10,493 | 695 | (432 | ) | 10,756 | |||||||||
| Income tax expense | (3,824 | ) | (263 | ) | -- | (4,087 | ) | |||||||
| Net income | $ | 6,669 | $ | 432 | $ | (432 | ) | $ | 6,669 | |||||
13
| For the Nine Months Ended September 30, 2004 | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Amounts in Thousands |
Magnum Hunter Resources, Inc. and Guarantor Subs |
Canvasback Energy, Inc. (Non Guarantor) |
Eliminations |
Magnum Hunter Resources, Inc. Consolidated | ||||||||||
| Revenues | $ | 333,503 | $ | 6,144 | $ | (773 | ) | $ | 338,874 | |||||
| Expenses | 234,730 | 4,731 | (653 | ) | 238,808 | |||||||||
| Income before equity in net earnings of subsidiary | 98,773 | 1,413 | (120 | ) | 100,066 | |||||||||
| Equity in net earnings of subsidiary | 803 | -- | (803 | ) | -- | |||||||||
| Income before income taxes | 99,576 | 1,413 | (923 | ) | 100,066 | |||||||||
| Income tax (expense) benefit | (38,120 | ) | (535 | ) | 45 | (38,610 | ) | |||||||
| Net income | $ | 61,456 | $ | 878 | $ | (878 | ) | $ | 61,456 | |||||
| For the Nine Months Ended September 30, 2003 | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Amounts in Thousands |
Magnum Hunter Resources, Inc. and Guarantor Subs |
Canvasback Energy, Inc. (Non Guarantor) |
Eliminations |
Magnum Hunter Resources, Inc. Consolidated | ||||||||||
| Revenues | $ | 237,131 | $ | 3,936 | $ | -- | $ | 241,067 | ||||||
| Expenses | 210,499 | 805 | -- | 211,304 | ||||||||||
| Income before equity in net earnings of subsidiary | 26,632 | 3,131 | -- | 29,763 | ||||||||||
| Equity in net earnings of subsidiary | 1,945 | -- | (1,945 | ) | -- | |||||||||
| Income before income taxes | 28,577 | 3,131 | (1,945 | ) | 29,763 | |||||||||
| Income tax expense | (10,147 | ) | (1,186 | ) | -- | (11,333 | ) | |||||||
| Net income | 18,430 | 1,945 | (1,945 | ) | 18,430 | |||||||||
| Cumulative effect of a change in accounting | ||||||||||||||
| principle | 399 | -- | -- | 399 | ||||||||||
| Net income | $ | 18,829 | $ | 1,945 | $ | (1,945 | ) | $ | 18,829 | |||||
| For the Nine Months Ended September 30, 2004 | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Amounts in Thousands |
Magnum Hunter Resources, Inc. and Guarantor Subs |
Canvasback Energy, Inc. (Non Guarantor) |
Eliminations |
Magnum Hunter Resources, Inc. Consolidated | ||||||||||
| Cash flow from operating activities | $ | 204,714 | $ | (13,320 | ) | $ | -- | $ | 191,394 | |||||
| Cash flow from investing activities | (416,450 | ) | (475 | ) | -- | (416,925 | ) | |||||||
| Cash flow from financing activities | 232,844 | -- | -- | 232,844 | ||||||||||
| Net increase (decrease) in cash | 21,108 | (13,795 | ) | -- | 7,313 | |||||||||
| Cash at beginning of period | 3,482 | 15,211 | -- | 18,693 | ||||||||||
| Cash at end of period | $ | 24,590 | $ | 1,416 | $ | -- | $ | 26,006 | ||||||
| For the Nine Months Ended September 30, 2003 | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Amounts in Thousands |
Magnum Hunter Resources, Inc. and Guarantor Subs |
Canvasback Energy, Inc. (Non Guarantor) |
Eliminations |
Magnum Hunter Resources, Inc. Consolidated | ||||||||||
| Cash flow from operating activities | $ | 130,067 | $ | 13,978 | $ | (202 | ) | $ | 143,843 | |||||
| Cash flow from investing activities | (123,429 | ) | 500 | (575 | ) | (123,504 | ) | |||||||
| Cash flow from financing activities | (15,492 | ) | (6,520 | ) | 777 | (21,235 | ) | |||||||
| Net increase in cash | (8,854 | ) | 7,958 | -- | (896 | ) | ||||||||
| Cash at beginning of period | 2,540 | 529 | -- | 3,069 | ||||||||||
| Cash at end of period | $ | (6,314 | ) | $ | 8,487 | $ | -- | $ | 2,173 | |||||
14
On June 30, 2004, we sold 15 million shares of Magnum Hunter common stock at $10.25 per share under a previously filed universal shelf registration statement. The proceeds from this issuance were $147.2 million, net of offering costs. We also granted the underwriters an option to purchase an additional 2.25 million shares to cover over-allotments, which they exercised on July 2, 2004. The net proceeds from this sale were approximately $22.1 million. We used proceeds from these issuances to finance a portion of our acquisition of oil and gas properties in the state of New Mexico (see Note 12) and to redeem a portion of our 9.6% Senior Notes (see Note 7).
On July 30, 2004, we purchased oil and gas properties located in the state of New Mexico, primarily in Lea and Eddy counties for $239.1 million, subject to certain purchase price adjustments. The properties include both proved producing oil and gas wells and proved undeveloped leasehold mineral interests. The effective date of the acquisition was May 1, 2004. We purchased additional properties related to this acquisition during September 2004 for a purchase price of $1.4 million, net of certain purchase price adjustments. We also recorded additional asset retirement obligations of $1.5 million as a result of the acquisition.
On August 30, 2004, we entered into an agreement to purchase approximately 171 producing wells located in the Permian Basin of West Texas for $40 million, net of certain purchase price adjustments. Closing occurred on October 29, 2004 and had an effective date of September 1, 2004.
15
The following discussion and analysis should be read in conjunction with our consolidated financial statements and the notes associated with them contained in our Form 10-K for the year ended December 31, 2003. This discussion should not be construed to imply that the results discussed herein will necessarily continue into the future or that any conclusion reached herein will necessarily be indicative of actual operating results in the future. Such discussion represents only the best present assessment by our management.
There have been no changes to our critical accounting policies for the nine-month period ended September 30, 2004. Exposure Draft No. 1102-100, “Share-Based Payment, an amendment of FASB, Statements No. 123 and 95,” issued by the Financial Accounting Standards Board (“FASB”) on March 31, 2004, may impact our future accounting for stock-based compensation. If we are required to adopt this amendment in its current form, we would be required to discontinue the prospective method of expensing stock options which we currently follow. Under this proposed literature, we would be required to expense all unvested grants issued prior to January 1, 2003, which would result in higher compensation costs. In June 2003, effective January 1, 2003, we began expensing stock-based compensation pursuant to SFAS No. 123, “Accounting for Stock-Based Compensation,” as allowed under the prospective method of SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure, an amendment to SFAS No. 123.” Under these statements, all stock options granted, modified or settled after December 31, 2002 are expensed based on their fair values determined by the Black-Scholes option-pricing model. For a discussion of our other critical accounting policies, refer to our Form 10-K for the year ended December 31, 2003.
In June 2004, we announced the execution of a purchase and sale agreement to acquire proved oil and gas properties located primarily in Lea and Eddy Counties of New Mexico. The geographical area in which these properties are located is one of our most active and successful onshore areas of focus. The purchase included both producing oil and gas wells and proved undeveloped leasehold mineral interests. The transaction closed on July 30, 2004 with a purchase price of $239.1 million before certain purchase price adjustments. To finance a portion of this acquisition, we sold 15 million shares of our common stock in a secondary offering on June 30, 2004. An additional 2.25 million shares of our common stock were subsequently sold in July 2004, pursuant to an over-allotment option granted to the underwriters. These common stock sales resulted in net proceeds of $169.3 million. We purchased additional related New Mexico properties during September 2004 for $1.4 million, subject to certain purchase price adjustments.
On July 15, 2004, we amended our Senior Bank Credit Facility (“Facility”) to increase our borrowing base by up to $100 million upon consummation of the New Mexico property acquisition. As a result of our equity offerings, the amendment to the Facility also allowed for an additional increase of the borrowing base on July 15, 2004 of $105 million for the purpose of redeeming $105 million in principal value of our 9.6% Senior Notes outstanding. On August 27, 2004, we redeemed $105 million principal value of our 9.6% Senior Notes at 109.6% of par, or $115.1 million plus accrued and unpaid interest of approximately $4.5 million through the redemption date. On October 18, 2004 we amended our Facility again to increase the borrowing base from $480 million to $525 million, and to increase our maximum borrowings from $500 million to $750 million.
In August 2004, we announced the execution of a purchase and sale agreement to acquire proved oil and gas properties in the Permian Basin of West Texas for $40 million, subject to certain purchase adjustments. The 171 producing wells are located predominantly in Reagan and Irion Counties, and all of the properties being acquired are in close proximity to areas of existing operations. We funded this acquisition through borrowings under our recently amended $525 million Facility. The acquisition closed October 29, 2004 and has an effective date of September 1, 2004.
Throughout this document, we make statements that are classified as “forward-looking.” Please refer to the “Forward-Looking Statements” section of this document for an explanation of these types of assertions.
Our results of operations have been significantly affected by our past success in acquiring oil and gas properties at or near the bottom of the commodity price cycles and our ability to maintain or increase oil and natural gas production through our exploration and exploitation activities. Recent acquisitions, in a higher commodity price environment, have been made in anticipation of increasing the recognized reserves associated with the properties. Fluctuations in oil and gas prices and commodity hedging activities have also significantly affected the results of our operations.
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The following table sets forth certain information with respect to our business segments:
| Three Months Ended September 30, |
Nine Months Ended September 30, | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2004 |
2003 |
2004 |
2003 | |||||||||||
| Exploration and Production Operations | ||||||||||||||
| Reported Production: | ||||||||||||||
| Oil (Mbbls) | 1,064 | 961 | 2,985 | 2,918 | ||||||||||
| Gas (Mmcf) | 15,192 | 12,962 | 39,899 | 36,806 | ||||||||||
| Oil and Gas (Mmcfe) | 21,574 | 18,730 | 57,808 | 54,311 | ||||||||||
| Equivalent Daily Rate (Mmcfe per day) | 234.5 | 203.6 | 211.0 | 198.9 | ||||||||||
| Average Sale Prices (after hedging) | ||||||||||||||
| Oil (per Bbl) | $ | 35.85 | $ | 26.34 | $ | 32.57 | $ | 26.68 | ||||||
| Gas (per Mcf) | 5.09 | 3.68 | 5.13 | 3.62 | ||||||||||
| Oil and Gas (per Mcfe) | 5.36 | 3.90 | 5.22 | 3.89 | ||||||||||
| Hedging losses (thousands) | $ | (10,039 | ) | $ | (15,115 | ) | $ | (27,412 | ) | $ | (61,863 | ) | ||
| Effect of hedging losses (per Mcfe) | $ | (0.47 | ) | $ | (0.81 | ) | $ | (0.47 | ) | $ | (1.14 | ) | ||
| Lease Operating Expense (per Mcfe) | ||||||||||||||
| Lifting costs | $ | 0.73 | $ | 0.88 | $ | 0.76 | $ | 0.79 | ||||||
| Production tax and other costs | 0.55 | 0.42 | 0.51 | 0.46 | ||||||||||
| Gross margin (per Mcfe) (a) | $ | 4.08 | $ | 2.60 | $ | 3.95 | $ | 2.64 | ||||||
| Depreciation, depletion, amortization and accretion (per Mcfe) | $ | 1.59 | $ | 1.38 | $ | 1.48 | $ | 1.30 | ||||||
| Segment profit (thousands) | $ | 53,717 | $ | 23,120 | $ | 143,038 | $ | 72,929 | ||||||
Gas Gathering, Marketing and Processing Operations | ||||||||||||||
| Throughput Volumes (Mcf per day) | ||||||||||||||
| Gathering | 20,016 | 15,787 | 16,924 | 15,891 | ||||||||||
| Processing | 25,477 | 24,165 | 25,767 | 24,588 | ||||||||||
| Gross margin (thousands) (a) | $ | 3,204 | $ | 2,243 | $ | 9,122 | $ | 7,255 | ||||||
| Gathering (per Mcf throughput) | $ | 0.15 | $ | 0.20 | $ | 0.16 | $ | 0.15 | ||||||
| Processing (per Mcf throughput) | $ | 1.21 | $ | 0.86 | $ | 1.15 | $ | 0.97 | ||||||
| Segment profit (thousands) | $ | 2,615 | $ | 1,666 | $ | 7,364 | $ | 5,525 | ||||||
Oil Field Management Services | ||||||||||||||
| Segment profit (thousands) | $ | 791 | $ | 240 | $ | 1,722 | $ | 487 | ||||||
(a) Excludes depreciation, depletion, amortization and accretion.
We reported net income of $19.0 million for the three months ended September 30, 2004, as compared to net income of $6.7 million for the same period in 2003, an increase of 184%. Total operating revenues increased 56% to $128.5 million in 2004 from $82.6 million in 2003. Operating profit increased 147% to $52.3 million in 2004 from $21.2 million in 2003, and net income before income taxes increased 189% to $31.1 million in 2004 from $10.8 million in 2003. The growth in operating revenues and operating profit was generated across all of our business segments, but especially in our exploration and production segment, as the result of higher realized oil and gas prices (after hedging effects) and higher production levels in the 2004 period compared to the 2003 period. We recorded $19 thousand in costs associated with early retirement of debt in the 2003 period due to the repurchasing of $381 thousand of our 10% Senior Notes during the 2003 period compared to $12.3 million in the 2004 period due to the redemption of $105 million in principal of our 9.6% Senior Notes during August 2004. The growth in pretax income was additionally impacted by a 19% reduction in interest expense which declined to $9.3 million in the 2004 period from $11.5 million in the 2003 period, principally due to the redemption of all of our remaining 10% Senior Notes during the year 2003 and the redemption of our 9.6% Senior Notes previously mentioned. We recorded a 197% increase in income tax expense to $12.2 million ($11.5 million of which was deferred) for the three months in 2004 versus $4.1 million for the same period in 2003, due to the increase in pre-tax income. Basic and diluted earnings per share were $0.22 each in the 2004 period versus basic and diluted earnings per share of $0.10 each in the 2003 period, an increase of 120%. The increase in net income was the primary factor causing the increase in basic and diluted earnings per share in the 2004 period. Common shares used in both the basic and diluted earnings per share calculation increased by 29% in the 2004 period compared to the 2003 period, partially due to the exercise of employee stock options and warrants and the 35% increase in the average market price of our common stock in the 2004 period compared to the 2003 period, resulting in a higher calculated number of diluted shares outstanding in the 2004 period. The common shares also increased due to the issuance of 15 million shares during June and 2.25 million shares during July of 2004 pursuant to a secondary offering.
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Exploration and Production Operations:
For the three months ended September 30, 2004, we reported oil production of approximately 1.1 million barrels and gas production of approximately 15.2 billion cubic feet, which represents an increase of 11% in oil produced and an increase of 17% in gas produced from the comparable period in 2003. Our reported equivalent daily rate of production, on a million cubic feet per day basis (Mmcfe per day), increased 15% to 234.5 Mmcfe per day in the 2004 period from 203.6 Mmcfe per day in the 2003 period. We recorded 13.3 Mmcfe per day as a result of the New Mexico property acquisition. Hurricane Ivan, mechanical problems, and other weather-related down time resulted in lost production estimated at 9.2 Mmcfe per day during the third quarter of 2004 in our offshore region. Substantially all of the production was reinstated at October 31, 2004.
Oil revenues increased 51% to $38.1 million in the third quarter of 2004 compared to $25.3 million for the same period in 2003. The oil price received, after hedging effects, was $35.85 per Bbl in the 2004 period compared to $26.34 per Bbl in the 2003 period, an increase of 36%. The price received for oil before the effect of hedging was $41.30 per Bbl in the 2004 period versus $29.07 per Bbl in the 2003 period, an increase of 42%. Gas revenues increased 62% to $77.4 million in the third quarter of 2004 versus $47.7 million for the same period in 2003. The gas price received, after hedging effects, was $5.09 per Mcf in the 2004 period compared to $3.68 per Mcf for the same period in 2003, an increase of 38%. The price received for gas before the effect of hedging was $5.37 per Mcf in the 2004 period versus $4.64 per Mcf in the 2003 period, an increase of 16%. We realized a $10.0 million loss from hedging activities in the 2004 period versus a loss of $15.1 million in the 2003 period, an improvement of $5.1 million, due to the expiration of lower-priced commodity hedging contracts. The hedge loss per equivalent unit produced was $0.47 per Mcfe in the 2004 period versus $0.81 per Mcfe in the 2003 period, a decline of 42% in the realized loss per Mcfe. The price received per equivalent unit produced before the effect of hedging was $5.83 per Mcfe in the 2004 period versus $4.71 in the 2003 period, an increase of 24%. Total oil and gas revenues increased 58% to $115.6 million in 2004 from $73.4 million in 2003. The increase in oil and gas revenues is attributable to the 24% increase in price per Mcfe before hedge losses, the $5.1 million decrease in hedge losses, and the 15% increase in Mcfe sold in the 2004 period versus the 2003 period.
From time to time, we enter into various commodity hedging contracts in order to reduce our exposure to the volatility of oil and gas prices, which provides a base level of cash flow to fund capital expenditures. During the third quarter of 2004 period, hedging decreased the average price we received for oil by $5.45 per Bbl and decreased the average price we received for gas by $0.28 per Mcf. During the third quarter of 2004, we had approximately 88.4 Mmcf/day of gas hedged through cost-less collars with a weighted average floor price of $4.02 per Mmbtu and a weighted average ceiling price of $5.99 per Mmbtu. Approximately 54% of third quarter 2004 natural gas production was hedged. On the crude side, we had approximately 4,000 Bbls/day hedged through cost-less collars with a weighted average floor price of $23.25 per Bbl and a weighted average ceiling price of $28.36 per Bbl. Approximately 35% of third quarter 2004 crude oil production was hedged. For the remainder of 2004, we have approximately 4,000 Bbls/day of crude oil production hedged through cost-less collars with a weighted average floor price of $23.25 per Bbl and a weighted average ceiling price of $28.36 per Bbl. On July 12, 2004, we terminated a natural gas collar for 10,000 Mmbtu per day for the period August through December 2004. In closing this contract, we realized a $1.3 million loss, which will be recognized in earnings with the underlying forecasted commodity sales transactions for the months August through December 2004. After this contract was terminated, our remaining natural gas production hedged for October through December 2004 was approximately 85.0 Mmcf/day with a weighted average floor price of $4.03 and a weighted average ceiling price of $6.00.
Lease operating expense consists of lifting costs and production taxes and other costs. For the 2004 period, lifting costs were $15.7 million versus $16.5 million in the 2003 period, a decrease of 5%. Production taxes and other costs increased 49% to $11.9 million in the 2004 period from $8.0 million in the 2003 period. The decrease in lifting costs was primarily attributable to lower workover, remedial, utility, and service costs in the 2004 period when compared to the 2003 period. For the 2004 period, lifting costs, on a unit of production basis, were $0.73 per Mcfe as compared to $0.88 per Mcfe in the 2003 period, a decrease of 17%. Production taxes and other costs were $0.55 per Mcfe produced in the 2004 period compared to $0.42 per Mcfe produced in the 2003 period, an increase of 31%. The increase in production taxes per Mcfe produced was caused by the increase in crude oil and natural gas prices received before hedging effects during the 2004 period compared to the 2003 period.
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Our gross margin realized from exploration and production operations (oil and gas revenues less lease operating expenses) for the 2004 period was $88.1 million, or $4.08 per Mcfe, compared to $49 million, or $2.60 per Mcfe in the 2003 period, an increase of 57% on a per unit of production basis, as a result of a 37% increase in hedge adjusted revenue per Mcfe produced, combined with a 2% decrease in lease operating expense per Mcfe produced.
Depreciation, depletion, amortization and accretion of oil and gas properties was $34.3 million in the 2004 period versus $25.8 million in the 2003 period, an increase of 33%. The 2004 period included accretion expense related to asset retirement obligations of $735 thousand ($0.03 per Mcfe) compared to $613 thousand ($0.03 per Mcfe) in the 2003 period. On a unit of production basis, depreciation and depletion expense (excluding accretion expense) was $1.56 per Mcfe produced in the 2004 period versus $1.35 per Mcfe produced in the 2003 period. This 16% increase in the equivalent unit cost per Mcfe produced was due primarily to an increase in development costs and shorter reserve life properties associated with our activities in the Gulf of Mexico as well as the New Mexico property acquisition.
Segment profit for exploration and production operations was $53.7 million for the three months ended September 30, 2004 versus $23.1 million for the same period in 2003, an increase of 132%, principally due to higher realized crude oil and natural gas prices, offset by higher lease operating expenses and higher depreciation, depletion, amortization and accretion expense.
Gathering, Marketing, and Processing Operations:
For the three months ended September 30, 2004, our gas gathering system throughput was 20.0 Mmcf/day versus 15.8 Mmcf/day for the same period in 2003, an increase of 27%, due to the operations of a new gathering system beginning in August 2004. Gas processing throughput was 25.5 Mmcf/day in 2004 versus 24.2 Mmcf/day in 2003, an increase of 5% due to the partial shutdown of one plant for most of one month during the 2003 period for scheduled maintenance on a products pipeline.
Revenues from gas gathering, marketing, and processing increased 28% to $10.3 million in the 2004 period versus $8.1 million in the 2003 period. Operating costs for the gas gathering, marketing and processing segment were $7.1 million in the 2004 period and $5.8 million in the 2003 period, an increase of 22%. The revenue increase was the result of higher natural gas and natural gas liquids prices in the 2004 period compared to the 2003 period as well as the partial shutdown of one processing plant for most of one month during the 2003 period for scheduled maintenance on a products pipeline.
The gross margin realized from gas gathering, marketing, and processing for the 2004 period was $3.2 million versus $2.2 million in the 2003 period, an increase of 43%. The gas gathering margin was $0.15 per Mcf gathered in 2004 versus $0.20 per Mcf in 2003 due to lower margins per Mcfe on the new gathering system. The gas processing margin was $1.21 per Mcf in 2004 compared to $0.86 per Mcf in 2003 due to higher commodities pricing.
Depreciation expense for gas gathering, marketing, and processing operations was 2% higher for the 2004 period at $589 thousand versus $577 thousand for the same period in 2003 due to the new gathering system and other capital additions.
Segment profit for gas gathering, marketing, and processing operations was $2.6 million in the 2004 period versus $1.7 million for the 2003 period, an increase of 57%, principally due to higher commodity prices.
Oil Field Management Services Operations:
Revenues from oil field management services increased 124% to $2.5 million in the third quarter of 2004 versus $1.1 million in the third quarter of 2003. Substantially all of this increase is due to three months’ worth of revenues generated by our majority-owned subsidiary, Metrix Networks, Inc. (“Metrix”). We purchased an 80% controlling interest in this entity during December 2003. Prior to this purchase, we included our approximately 32% share of their profits in the equity in earnings of affiliate section of our income statement.
Operating costs increased 95% to $1.4 million in 2004 from $724 thousand in 2003, again primarily due to the Metrix purchase.
The gross margin for this segment in 2004 was $1.1 million versus $386 thousand in 2003, an increase of 177%, due to increased revenues.
19
Depreciation expense was $280 thousand in the 2004 period versus $146 thousand in the 2003 period, an increase of 92%, due to capital additions.
Segment profit was $791 thousand for the three months in 2004 versus $240 thousand for the same period in 2003.
Depreciation, Depletion, Amortization and Accretion:
Total depreciation, depletion, amortization and accretion expense was $35.2 million in the 2004 period versus $26.7 million in the 2003 period, an increase of 32%. This is primarily the result of the increased depletion and accretion rates in our exploration and production segment due to the New Mexico property acquisition, higher development costs, and shorter reserve life properties offshore.
General and Administrative Expenses:
General and administrative expense for the 2004 period increased 32% to $5.0 million from $3.8 million in the 2003 period. The principal reasons for this increase were a $322 thousand decrease in salaries and incentive compensation expenses principally due to lower stock compensation, $574 thousand of expenses due to Metrix recorded in the 2004 period, a $242 thousand increase in accounting fees, $182 thousand of increases in our bad debt provision in the 2004 period, and $181 thousand of expenses related to Sarbanes-Oxley compliance.
Other Income and Expenses:
We recorded no equity in earnings of affiliate in the 2004 period versus earnings of $173 thousand in the 2003 period due to the sale of our interest in NGTS and the acquisition of a majority interest in Metrix. Other income was $67 thousand for the 2004 period versus $231 thousand in the 2003 period, a decrease of 71%, primarily the result of receipts for seismic fees in 2003. The company recognized a $351 thousand gain in other non-cash hedging adjustments in the 2004 period versus a $701 thousand gain in the 2003 period. In the 2004 period, $198 thousand of the hedging gain relates to the amortization of commodity hedge assets acquired in the Prize merger, while a gain of $153 thousand was due to recording hedge ineffectiveness.
We incurred costs associated with the early retirement of debt of $12.3 million in the three months of 2004 versus $19 thousand in the 2003 period. The 2003 period costs were associated with Canvasback’s purchase of $381 thousand in principal amount of our 10% Senior Notes, while the 2004 costs were associated with our redemption of $105 million in principal amount of our 9.6% Senior Notes during August 2004.
Interest expense was $9.3 million for the 2004 period versus $11.5 million for the 2003 period, a reduction of 19%. This was the result of the redemption in 2003 of our 10% Senior Notes and the partial redemption of our 9.6% Senior Notes during 2004, offset by interest on our Floating Rate Convertible Senior Notes (“Convertible Notes”) issued in December 2003, which have a floating interest rate based on three-month LIBOR, initially set at 1.17% and currently set at 1.88%. Our weighted average interest rate paid under our Facility was 4.0% in the 2004 period versus 3.7% in the 2003 period. Our overall effective interest rate (excluding costs associated with the early retirement of debt) was 6.2% in the 2004 period versus 7.6% in the 2003 period.
The effective tax rate was 39.1% and 38.0% for the three months ended September 30, 2004 and 2003, respectively. The variance from the statutory rate of 35% was primarily due to state income taxes and permanent tax differences associated with our KSOP Plan.
We reported net income of $61.5 million for the nine months ended September 30, 2004, as compared to net income of $18.8 million for the same period in 2003, an increase of 226%. Total operating revenues increased 41% to $338.9 million in 2004 from $241.1 million in 2003. Operating profit increased 101% to $137.8 million in 2004 from $68.5 million in 2003, and net income before income taxes increased 236% to $100.1 million in 2004 from $29.8 million in 2003. The growth in operating revenues and operating profit was generated across all of our business segments, but especially in our exploration and production segment, principally the result of lower hedging losses in the 2004 period compared to the 2003 period due to the roll-off of lower-priced commodity hedging contracts as well as production and pricing increases. We recorded $4.1 million in costs associated with early retirement of debt in the 2003 period versus $12.3 million in the 2004 period due to the redemption of $80.4 million of our 10% Senior Notes during January and June 2003 and the redemption of $105 million in principal of our 9.6% Senior Notes in August 2004. The growth in pretax income was additionally impacted by a 21% reduction in interest expense which declined to $28.6 million in the 2004 period from $36.4 million in the 2003 period, principally due to the redemption of all of our remaining 10% Senior Notes during the year 2003. We recorded a 241% increase in income tax expense to $38.6 million ($37.2 million of which was deferred) for the nine months in 2004 versus $11.3 million for the same period in 2003, due to the increase in pre-tax income. Basic and diluted earnings per share were $0.83 and $0.81, respectively, in the 2004 period versus basic and diluted earnings per share of $0.28 each in the 2003 period, an increase of 196% and 189%, respectively. The increase in net income was the primary factor causing the increase in basic and diluted earnings per share. Common shares used in the basic and diluted earnings per share calculation increased by 12% and 13%, respectively, in the 2004 period compared to the 2003 period, principally due to the exercise of employee stock options and warrants, the increase in the average market price of our common stock in the 2004 period compared to the 2003 period, and the issuance of 17.25 million shares during June and July 2004 pursuant to a secondary offering, resulting in a higher calculated number of basic and diluted shares outstanding in the 2004 period.
20
Exploration and Production Operations:
For the nine months ended September 30, 2004, we reported oil production of approximately 3.0 million barrels and gas production of approximately 39.9 billion cubic feet, which represents an increase of 2% in oil produced and an increase of 8% in gas produced from the comparable period in 2003. Our reported equivalent daily rate of production, on a million cubic feet per day basis (Mmcfe per day), increased 6% to 211.0 Mmcfe per day in the 2004 period from 198.9 Mmcfe per day in the 2003 period. We recorded 4.5 Mmcfe per day as a result of the New Mexico property acquisition. Production for the nine months of 2004 was also lower by an estimated 3.1 Mmcfe per day due to start-up delays, mechanical problems, and weather-related down time in our offshore Gulf of Mexico region. Substantially all of this production was re-instated by October 31, 2004.
Oil revenues increased 25% to $97.2 million in the first nine months of 2004 compared to $77.9 million for the same period in 2003. The oil price received, after hedging effects, was $32.57 per Bbl in the 2004 period compared to $26.68 per Bbl in the 2003 period, an increase of 22%. The price received for oil before the effect of hedging was $37.39 per Bbl in the 2004 period versus $29.84 per Bbl in the 2003 period, an increase of 25%. Gas revenues increased 54% to $204.6 million in the first nine months of 2004 versus $133.2 million for the same period in 2003. The gas price received, after hedging effects, was $5.13 per Mcf in the 2004 period compared to $3.62 per Mcf for the same period in 2003, an increase of 42%. The price received for gas before the effect of hedging was $5.46 per Mcf in the 2004 period versus $5.05 per Mcf in the 2003 period, an increase of 8%. We realized a $27.4 million loss from hedging activities in the 2004 period versus a loss of $61.9 million in the 2003 period, an improvement of $34.5 million, due to the expiration of lower priced commodity hedging contracts. The hedge loss per equivalent unit produced was $0.47 per Mcfe in the 2004 period versus $1.14 per Mcfe in the 2003 period, a decline of 59% in the realized loss per Mcfe. The price received per equivalent unit produced before the effect of hedging was $5.69 per Mcfe in the 2004 period versus $5.03 in the 2003 period, an increase of 13%, due to the increase in the pre-hedge price received for crude oil and natural gas. Total oil and gas revenues increased 43% to $302.4 million in 2004 from $211.5 million in 2003. The increase in oil and gas revenues is attributable to the $34.5 million decrease in hedge losses, the 13% increase in pre-hedge price per Mcfe, and the 6% increase in Mcfe sold in the 2004 period versus the 2003 period.
From time to time, we enter into various commodity hedging contracts in order to reduce our exposure to the volatility of oil and gas prices, which provides a base level of cash flow to fund capital expenditures. During the 2004 period, hedging decreased the average price we received for oil by $4.82 per Bbl and decreased the average price we received for gas by $0.33 per Mcf. During the first nine months of 2004, we had approximately 87.2 Mmcf/day of gas hedged through cost-less collars with a weighted average floor price of $3.88 per Mmbtu and a weighted average ceiling price of $5.87 per Mmbtu. Approximately 60% of our first nine months 2004 natural gas production was hedged. On the crude side, we had approximately 6,491 Bbls/day hedged through cost-less collars with a weighted average floor price of $24.00 per Bbl and a weighted average ceiling price of $30.16 per Bbl. Approximately 60% of our first nine months 2004 crude oil production was hedged. For the remainder of 2004, we have approximately 4,000 Bbls/day of crude oil production hedged through cost-less collars with a weighted average floor price of $23.25 per Bbl and a weighted average ceiling price of $28.36 per Bbl. On July 12, 2004, we terminated a natural gas collar for 10,000 Mmbtu per day for the period August through December 2004. In closing this contract we realized a $1.3 million loss, which will be recognized in earnings with the underlying forecasted commodity sales transactions for the months August through December 2004. After this contract was terminated, our remaining natural gas production hedged for October through December 2004 was approximately 85.0 Mmcf/day with a weighted average floor price of $4.03 and a weighted average ceiling price of $6.00.
21
Lease operating expense consists of lifting costs and production taxes and other costs. For the 2004 period, lifting costs were $43.9 million versus $42.9 million in the 2003 period, an increase of 2%. Production taxes and other costs increased 19% to $29.8 million in the 2004 period from $25.1 million in the 2003 period. For the 2004 period, lifting costs, on a unit of production basis, were $0.76 per Mcfe as compared to $0.79 per Mcfe in the 2003 period, a decrease of 4% due to lower workover, remedial, utility and service costs. Production taxes and other costs were $0.51 per Mcfe produced in the 2004 period compared to $0.46 per Mcfe produced in the 2003 period, an increase of 11%. The increase in production taxes per Mcfe produced was caused by the increase in crude oil and natural gas prices received before hedging effects during the 2004 period compared to the 2003 period.
Our gross margin realized from exploration and production operations (oil and gas revenues less lease operating expenses) for the 2004 period was $228.7 million, or $3.95 per Mcfe, compared to $143.5 million, or $2.64 per Mcfe in the 2003 period, an increase of 50% on a per unit of production basis, as a result of a 34% increase in hedge adjusted revenue per Mcfe produced, partially offset by an 11% increase in production taxes and other expenses per Mcfe produced.
Depreciation, depletion, amortization and accretion of oil and gas properties was $85.6 million in the 2004 period versus $70.5 million in the 2003 period, an increase of 21%. The 2004 period included accretion expense related to asset retirement obligations of $2.2 million ($0.04 per Mcfe) compared to $1.9 million ($0.03 per Mcfe) in the 2003 period. On a unit of production basis, depreciation and depletion expense (excluding accretion expense) was $1.44 per Mcfe produced in the 2004 period versus $1.26 per Mcfe produced in the 2003 period. This 14% increase in the equivalent unit cost per Mcfe produced was due primarily to an increase in development costs and shorter reserve life properties associated with our activities in the Gulf of Mexico as well as the New Mexico property acquisition.
Segment profit for exploration and production operations was $143.0 million for the nine months ended September 30, 2004, versus $72.9 million for the same period in 2003, an increase of 96%, principally due to higher realized crude oil and natural gas prices, offset by higher production tax and other expenses and higher depreciation, depletion, amortization and accretion expense.
Gathering, Marketing, and Processing Operations:
For the nine months ended September 30, 2004, our gas gathering system throughput was 16.9 Mmcf/day versus 15.9 Mmcf/day for the same period in 2003, an increase of 6%, due to operations of a new gathering system beginning in August 2004. Gas processing throughput was 25.8 Mmcf/day in 2004 versus 24.6 Mmcf/day in 2003, an increase of 5%, due primarily to the partial shutdown of one processing plant for most of one month during the third quarter of the 2003 period for scheduled maintenance on a products pipeline.
Revenues from gas gathering, marketing, and processing increased 14% to $30.2 million in the 2004 period versus $26.5 million in the 2003 period. Operating costs for the gas gathering, marketing and processing segment increased 9% to $21.0 million in the 2004 period from $19.3 million in the 2003 period. The revenue increase was the result of higher natural gas and natural gas liquids prices and the effect of the processing plant shutdown in 2003, while the operating cost increase was due to higher costs of gas purchases.
The gross margin realized from gas gathering, marketing, and processing for the 2004 period was $9.1 million versus $7.3 million in the 2003 period, an increase of 26%. The gas gathering margin was $0.16 per Mcf gathered in 2004 versus $0.15 per Mcf in 2003 due to higher gathering fees. The gas processing margin was $1.15 per Mcf in 2004 compared to $0.97 per Mcf in 2003 due to higher natural gas liquids prices realized partially offset by higher costs of gas purchased.
Depreciation expense for gas gathering, marketing, and processing operations was $1.8 million for the 2004 period compared to $1.7 million for the 2003 period due to the new gathering system and other capital additions.
Segment profit for gas gathering, marketing and processing operations was $7.4 million in the 2004 period versus $5.5 million for the 2003 period, an increase of 33%, principally due to higher commodity prices.
Oil Field Management Services Operations:
Revenues from oil field management services increased 104% to $6.3 million in the first nine months of 2004 versus $3.1 million in the comparable period in 2003. Approximately $3.0 million of this increase is due to nine months’ worth of revenues generated by our majority-owned subsidiary, Metrix. We purchased an 80% controlling interest in this entity during December 2003. Prior to this purchase, we included our approximately 32% share of their profits in the equity in earnings of affiliate section of our income statement. We also received revenues of approximately $310 thousand from equipment rental fees charged to outside owners under a new program in which we purchase completion equipment to be used on multiple projects and charges rental fees to the owners.
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Operating costs increased 73% to $3.8 million in 2004 from $2.2 million in 2003. Of this increase, $1.3 million was attributable to the Metrix purchase, and approximately $289 thousand was due to increases in compensation and related expenses.
The gross margin for this segment in 2004 was $2.6 million versus $928 thousand in 2003, an increase of 177%, due to increased revenues.
Depreciation expense was $853 thousand in the 2004 period versus $441 thousand in the 2003 period, an increase of 93%, due to capital additions.
Segment profit was $1.7 million for the nine months in 2004 versus $487 thousand for the same period in 2003.
Depreciation, Depletion, Amortization and Accretion:
Total depreciation, depletion, amortization and accretion expense was $88.4 million in the 2004 period versus $73.2 million in the 2003 period, an increase of 21%. This is primarily the result of the increased depletion and accretion rates in our exploration and production segment due to higher development costs, the New Mexico property acquisition and shorter reserve life properties offshore.
General and Administrative Expenses:
General and administrative expense for the 2004 period increased 43% to $14.5 million from $10.1 million in the 2003 period. The principal reasons for this increase were a $645 thousand increase in salaries and incentive compensation expenses and $1.8 million of expenses due to Metrix being recorded in the 2004 period. Other contributors to the increase were $267 thousand in higher fees for consulting paid during the first nine months of 2004, an increase of $538 thousand in our bad debt provision, and the recovery in 2003 of $170 thousand of notes receivable previously reserved. We also had $357 thousand more in accounting and auditing fees during the 2004 period and $216 thousand in expenses related to Sarbanes-Oxley compliance.
Other Income and Expenses:
We recorded no equity in earnings of affiliate in the 2004 period versus a loss of $64 thousand in the 2003 period due to the sale of our interest in NGTS and the acquisition of a majority interest in Metrix. Other income was $2.3 million for the 2004 period versus $609 thousand in the 2003 period, an increase of 277%, primarily the result of proceeds collected from a lawsuit judgment issued in our favor. The company recognized a $815 thousand gain in other non-cash hedging adjustments in the 2004 period versus a $1.2 million gain in the 2003 period. In the 2004 period, $594 thousand of the hedging gain relates to the amortization of commodity hedge assets acquired in the Prize merger, and $221 thousand was due to recording hedge ineffectiveness.
We incurred costs associated with the early retirement of debt of $12.3 million in the nine months of 2004 versus $4.1 million in 2003. The 2003 period costs were associated with the redemption of $80.4 million in principal of our 10% Senior Notes in January and June 2003, while the 2004 period costs were associated with the redemption of $105 million in principal of our 9.6% Senior Notes in August 2004.
Interest expense was $28.6 million for the 2004 period versus $36.4 million for the 2003 period, principally the result of the redemption in 2003 of our 10% Senior Notes, partially offset by interest on our Convertible Notes issued in December 2003, which have a floating interest rate based on three-month LIBOR, initially set at 1.17% and currently set at 1.88%. Our weighted average interest rate paid under our Facility was 3.98% in the 2004 period versus 3.85% in the 2003 period. Our overall effective interest rate (excluding costs associated with early retirement of debt) was 6.4% in the 2004 period versus 8.1% in the 2003 period.
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The effective tax rate was 38.6% and 38.1% for the nine months ended September 30, 2004 and 2003, respectively. The variance from the statutory rate of 35% was primarily due to state income taxes as well as permanent tax differences related to our KSOP Plan.
CASH FLOW AND WORKING CAPITAL. Net cash provided by operating activities for the nine months ended September 30, 2004 increased $47.6 million to $191.4 million, from $143.8 million for the same period during 2003. The main contributor of this increase was our substantial increase in net income in the 2004 period. Please refer to our period to period comparisons in the above sections for an analysis of this increase by operating segment.
Our net working capital position at September 30, 2004 was a deficit of $7.7 million. On that date, we had $137.5 million available to be drawn under our $480 million Facility. A large factor in our working capital deficit at September 30, 2004 is our current derivative liability of $37.4 million, partially offset by current deferred tax assets of $14.2 million, which we have recorded on our hedged positions for the next twelve months due to continued increases in commodities prices over our hedged ceiling prices. If actual commodities prices realized remain higher than our hedged ceiling prices on these positions, our resulting higher cash proceeds received on our production should offset any actual amounts paid out related to these liabilities.
INVESTING ACTIVITIES. Net cash used in investing activities was $416.9 million in the 2004 nine month period. We made capital expenditures of $194.7 million under our capital budget during 2004. In addition, we paid $232.1 million, net of certain purchase price adjustments, for our acquisition of New Mexico properties during July 2004. Our capital expenditures are discussed in further detail below. For 2004, we also received proceeds from the sales of property and equipment of $11.7 million, net of certain purchase price adjustments related to both 2003 and 2004 divestitures. We received $350 thousand in payments on a note receivable and placed $2.0 million on deposit in connection with a pending acquisition.
In the 2003 nine-month period, net cash used in investing activities was $123.5 million. We made capital expenditures of $144.2 million under our capital budget during 2003. Additionally during 2003, we made an investment of $600 thousand in an affiliate, received proceeds from sale of assets of $14.6 million, received distributions from an affiliate of $1.5 million, and received $5.2 million from the sale of our investment in NGTS.
FINANCING ACTIVITIES. Net cash provided by financing activities was $232.8 million for the nine-month period ending September 30, 2004. We borrowed a total of $432.5 million, and we repaid borrowings of $259.0 million. We paid $913 thousand in fees related to amendments to our Facility, received net proceeds from the issuance of common stock pursuant to our employee stock option plans of $7.8 million, and received net proceeds from a secondary offering of our common stock of $169.3 million under our Facility. We also paid $115.1 million to redeem $105 million in principal amount of our 9.6% Senior Notes at 109.6% of par. We also loaned $2.3 million to our KSOP to purchase 224,600 shares of common stock and received payments on our loan to the KSOP of $486 thousand.
Net cash used in financing activities was $21.2 million for the nine-month period in 2003. We borrowed a total of $320.1 million during the period and repaid borrowings of $253.2 million. We paid $77.3 million, net of Canvasback redemptions, to redeem $80.4 million in principal of our 10% Senior Notes. We also loaned our KSOP $2.7 million to purchase shares of our common stock and paid $7.4 million to purchase an additional 1.3 million shares of treasury stock. We also spent $295 thousand to purchase stock for our deferred compensation plan. We paid $456 thousand in fees related to our amended Facility, made a loan to an unconsolidated affiliate of $225 thousand, had an increase in restricted cash of $227 thousand, received payments on our loan to KSOP of $296 thousand, and received $215 thousand from the exercise of stock options.
CAPITAL RESOURCES. The following discussion of Magnum Hunter’s capital resources refers to the company and our affiliates. Internally generated cash flow and the borrowing capacity under our Facility are our major sources of liquidity. From time to time, we may also sell non-strategic properties in order to increase liquidity. In addition, we may use other sources of capital, including the issuance of additional debt securities or equity securities, as sources to fund acquisitions or other specific needs. In the past, we have accessed both the public and private capital markets to provide liquidity for specific activities and general corporate purposes. We currently have approximately $23.2 million available remaining under our current shelf registration with the Securities and Exchange Commission.
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At September 30, 2004, we had $137.5 million available under our Facility which had a borrowing base of $480 million.
On April 30, 2004, we amended our Facility to receive a more favorable rate structure and to increase the borrowing base to $275 million. The level of the borrowing base is dependent on the valuation by the lenders of the assets pledged, which are primarily oil and gas reserves. We also extended the expiration date of the Facility by one year, resulting in a new maturity date of May 2, 2007.
On July 15, 2004, we amended our Facility to increase the borrowing base to $480 million upon the consummation of our New Mexico property acquisition, an increase of $205 million, and to allow us to use proceeds from our secondary common stock offering to redeem and retire up to $105 million in principal value of our 9.6% Senior Notes outstanding.
On October 18, 2004, we amended our Facility to increase the borrowing base by $45 million from $480 million to $525 million and to increase our maximum borrowings from $500 million to $750 million.
On a semi-annual basis, our borrowing base under our Facility is redetermined by the financial institutions who have committed to the company based on their review of our proved oil and gas reserves and other assets. If the outstanding senior bank debt exceeds the redetermined borrowing base, the company must repay the excess. As a result of the redetermination completed on October 15, 2004, our borrowing base was increased by $45 million to $525 million, and the maximum borrowings were increased from $500 million to $750 million. The next redetermination date will have an effective date of December 31, 2004 and will have a completion date of no later than May 9, 2005.
We sold 15 million shares of our common stock in a secondary offering on June 30, 2004, resulting in net proceeds after expenses of $147.2 million. An additional 2.25 million shares of our common stock were sold in July 2004, pursuant to an over-allotment option granted to the underwriters, resulting in additional net proceeds of $22.1 million. We ultimately used these proceeds to finance a portion of our acquisition of properties in New Mexico and to fund our August 2004 Note redemption.
Our internally generated cash flow, results of operations, and financing for our operations are substantially dependent on oil and gas prices. To the extent that oil and gas prices decline, our earnings and cash flows may be adversely affected. This adverse effect may be mitigated by our commodity hedging activities. We believe that our cash flow from operations, existing working capital, and availability under our Facility will be sufficient to meet interest payments and to fund the capital expenditure budget for the year 2004.
CAPITAL EXPENDITURES. During the nine-month period in 2004, our total capital expenditures, exclusive of the New Mexico property acquisition, were $194.7 million. Exploration activities accounted for $33.9 million, development activities accounted for $127.6 million, unproved property acquisitions accounted for $17.2 million, proved property acquisitions accounted for $14.2 million, and additions to other assets accounted for $1.8 million of the capital expenditures. We participated in the drilling of 134 wells during the 2004 period, of which 129 were deemed commercial, for a 96% overall success rate. Of the 134 wells drilled, 28 were exploratory wells, of which 24 were successful, and 106 were development wells, 105 of which were successful. As of September 30, 2004, we had total unproved oil and gas property costs of $89.7 million.
In July 2004, we completed the acquisition of proved and unproved oil and gas properties located primarily in Lea and Eddy Counties of New Mexico. The geographical area in which these properties are located is one of our most active and successful onshore areas of focus. The purchase included both producing oil and gas wells and undeveloped leasehold mineral interests. The transaction closed on July 30, 2004 with a purchase price of $239.1 million, subject to certain purchase price adjustments. As of September 30, 2004, the adjusted price for the properties was $232.1 million. This purchase price is subject to further purchase price adjustments. We financed this acquisition with a portion of the proceeds from our secondary offering of 17.25 million shares as well as borrowings under our amended Facility.
Our Board of Directors previously approved a capital budget of up to $185 million for calendar year 2004. In connection with the New Mexico property acquisition and the equity offering, we have raised our 2004 capital budget to $220 million. We are not contractually obligated to proceed with any of our material budgeted capital expenditures. The amount and allocation of future capital expenditures will depend on a number of factors that are not entirely within our control or ability to forecast, including drilling results, oilfield service costs, partner capital plans, and changes in oil and gas prices. As a result, actual capital expenditures may vary significantly from current expectations. We anticipate that this budget will be funded by our cash flow from operations as well as utilization of our Facility. In the normal course of business, we review opportunities for the possible acquisition of oil and gas reserves and activities related thereto. When potential acquisition opportunities are deemed consistent with our growth strategy, bids or offers in amounts and with terms acceptable to us may be submitted. It is uncertain whether any such bids or offers which may be submitted by us from time to time will be acceptable to the sellers. In the event of a future significant acquisition, utilizing cash, we may require additional financing in connection therewith.
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RECENT TRENDS. The following is a discussion of recent trends we consider important and our assessment of the impact of these trends on our business plan.
Commodity prices. Since mid-year 2002, crude oil and natural gas commodity prices have increased significantly. We believe that natural gas prices (NYMEX index) will average between $4.00 and $7.00 per Mcf over the next several years and will likely remain volatile. We have based our 2004 capital and operating budgets on prices of approximately $5.40 per Mcf. Crude oil prices have recently increased significantly, but in our view are much more variable due to worldwide political and economic factors. For 2004 budgeting purposes, we have assumed crude prices will average approximately $32.00 per Bbl (NYMEX index). Our production mix is largely natural gas, and therefore our gross margins are largely driven by natural gas prices.
Interest rates. We have experienced an unusually low interest rate environment for the past several years. We expect interest rates to increase moderately over the next several years. By December 31, 2004, we expect that approximately 30% of our debt will be fixed at 9.6% through at least 2007 and potentially 2012, with the remaining 70% to be variable rate debt.
Depreciation, depletion, amortization and accretion (DD&A). Our exploration and production segment DD&A rate has increased an annual average of 14% per year since 1999. This increase is primarily attributable to our increased capital expenditures in the offshore Gulf of Mexico region, where our finding and development costs per unit are higher than our average finding and development costs per unit have been historically onshore. We expect to continue to spend a significant percentage of our total capital expenditures budget on offshore Gulf of Mexico projects due to economic parameters experienced in that region. Assuming similar results in our drilling activities and reserve recognition to what we have been achieving, we would expect our DD&A rate to continue to increase.
Management’s assessment of the impact of these trends on our business plan. We have concentrated our capital budget in areas where we expect to realize the highest financial benefits, including rate of return and return on capital deployed. As such, we have dedicated significant portions of our capital expenditure budget to the offshore Gulf of Mexico region and onshore in the Southeast New Mexico area over the past several years.
We have significant exploration, development and exploitation opportunities both onshore and offshore. Management continues to monitor commodity prices, finding and development costs and interest rates, among other factors, to determine both the total dollars to be spent and the allocation of these dollars among alternative projects within the capital budget. Even if DD&A rates and interest rates continue to increase, and commodity price increases in turn offset these expenses, then we would expect to continue our current business plan. We believe we have significant flexibility in the management of our cash flows.
FORWARD-LOOKING STATEMENTS. This Form 10-Q and the information incorporated by reference contain statements that constitute “forward-looking statements” within the meaning Section 27A of the Securities Act and Section 21E of the Securities Exchange Act. The words “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “forecast,” “predict,” and other similar expressions are intended to identify forward-looking statements. These statements appear in a number of places and include statements regarding our plans, beliefs, or current expectations, including the plans, beliefs, and expectations of our officers and directors.
When considering any forward-looking statement, one should keep in mind the risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in commodity prices for oil and gas, operating risks and other risk factors as described in our Annual Report on Form 10-K as filed with the Securities and Exchange Commission. Furthermore, the assumptions that support our forward-looking statements are based upon information that is currently available and is subject to change. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages.
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All forward-looking statements attributable to Magnum Hunter Resources, Inc. are expressly qualified in their entirety by this cautionary statement.
Our results of operations and cash flow have been, and will continue to be, affected by the volatility in oil and gas prices. Should we experience a significant increase in oil and gas prices that is sustained over a prolonged period, we would expect that there would also be a corresponding increase in oil and gas finding costs, lease acquisition costs, and operating expenses.
We market oil and gas for our own account, which exposes us to the attendant commodities risk. A significant portion of our gas production is currently sold to end-users either (i) on the spot market on a month-to-month basis at prevailing spot market prices or (ii) under long-term contracts based on current spot market prices. We normally sell our oil under month-to-month contracts to a variety of purchasers.
We were obligated to nine crude oil derivatives and fourteen natural gas derivatives on September 30, 2004. All outstanding derivatives qualify for cash flow hedge accounting treatment as defined within SFAS No. 133, which requires derivative assets and liabilities to be recorded at their fair value on the balance sheet with an offset for the effective part of the hedge to other comprehensive income. Hedge ineffectiveness on cash-flow hedges is recorded in earnings.
At September 30, 2004, the fair value of the company’s derivatives were as follows (in thousands):
| Derivative Liabilities | |||||
| Natural gas collars | $ | (30,821 | ) | ||
| Natural gas swaps | (5,190 | ) | |||
| Crude oil collars | (9,642 | ) | |||
| Crude oil swaps | (4,175 | ) | |||
| Net Derivative Liability | $ | (49,828 | ) | ||
For the three and nine-month periods ended September 30, 2004, the statement of operations includes non-cash hedging adjustment gains of $351 thousand and $815 thousand, respectively. These gains are made up of hedging ineffectiveness gains of $153 thousand and $221 thousand, respectively, related to the crude oil and natural gas derivatives as well as non-cash gains of $198 thousand and $594 thousand, respectively, related to the amortization of hedge contracts acquired in the Prize merger. The remaining amortization amount relating to hedge contracts acquired in the Prize merger that will be reclassified into the operations statement in 2004 is a $198 thousand gain. It is estimated at this time that $23.7 million, net of income tax, of other comprehensive loss will be reclassified into the income statement during the next 12 months.
New Accounting Standards
The Financial Accounting Standards Board ("FASB") has issued FASB Staff Position ("FSP") No. 142-2, "Application of FASB Statement 142, Goodwill and Other Intangible Assets, to Oil-and-Gas Producing Entities after evaluating an issue involving the classification of mineral rights. In June 2001, FASB issued Statement of Financial Accounting Standards ("SFAS") No. 141, "Business Combinations," which requires the purchase method of accounting for business combinations initiated after June 30, 2001 and eliminates the pooling-of-interests method. In July 2001, the FASB also issued SFAS No. 142, "Goodwill and Other Intangible Assets," which discontinues the practice of amortizing goodwill and indefinite lived intangible assets and initiates an annual review of impairment. Intangible assets with a determinable useful life will continue to be amortized over that period. The amortization provisions apply to goodwill and intangible assets acquired after June 30, 2001. SFAS No. 141 and 142 clarify that more assets should be distinguished and classified between tangible and intangible. We did not change or reclassify contractual mineral rights included in proved and unproved oil and gas properties on our balance sheet upon adoption of SFAS No. 142. We believe the treatment of such mineral rights as tangible assets under the full cost method of accounting for oil and gas properties is appropriate. An issue was raised regarding whether these mineral rights should be classified as tangible or intangible assets. FSP No. 142-2 addressed this issue and supports our current accounting treatment of mineral rights and will not impact our financial statements. This FSP is effective for reporting periods beginning after September 2, 2004.
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FASB issued FSP FAS 129-1, "Disclosure Requirements Under FASB Statement No. 129, Disclosure of Information About Capital Structure," in April 2004. This FSP provides additional guidance on the disclosure requirements of contingently convertible securities. We have made the required disclosures related to the terms of our Convertible Notes in our Annual Report on Form 10-K and have provided explanations in Note 6 of this Form 10-Q about the dilutive effects of these notes on our EPS.
FASB's Emerging Issues Task Force ("EITF") has recently issued a Draft EITF Abstract for EITF Issue No. 04-8, "The Effect of Contingently Convertible Debt on Diluted Earnings per Share," which addresses the issue of when the dilutive effects of contingently convertible debt instruments should be included in diluted earnings per share. This guidance would require companies to include the dilutive effect of convertible debt securities in diluted earnings per share regardless of whether or not the contingent conversion features have been triggered. The comment period for this draft ended in September 2004. The Task Force has reached a final consensus and affirmed their position in the Draft EITF Abstract as it relates to market contingencies. The adoption of this guidance would not have an impact on any of our reported earnings per share because the stock price has not exceeded the conversion price of our Convertible Notes. The principal of our Convertible Notes must be settled in cash, with the conversion spread settled in stock. Since the conversion price has not been exceeded in the market, no incremental shares would have been issued. This guidance is expected to be effective at the same time as the FASB Statement No. 128(R), "Earnings per Share", which has yet to be issued, but is expected to be effective for periods ending after December 15, 2004 and will require retroactive restatement of earnings per share.
The SEC Staff Accounting Bulletin ("SAB") 106 was released in September 2004. SAB 106 expresses the SEC staff's views on the interaction of SFAS No. 143 and the full cost method and provides guidance on computing the full cost ceiling as well as depreciation, depletion, and amortization. The SAB also requires additional disclosures regarding how the application of SFAS No. 143 has affected the ceiling test and depreciation, depletion and amortization. This guidance is effective for the first fiscal quarter beginning after its publication. We do not expect the application of these guidelines to have a significant impact on our ceiling test or depletion expense.
Item 3. Qualitative and Quantitative Disclosure About Market Risk
Our operations are exposed to market risks primarily as a result of changes in commodity prices and interest rates. We do not use derivative financial instruments for speculative or trading purposes.
Commodity Price Hedging Contracts. We produce, purchase, and sell crude oil, natural gas, condensate, and natural gas liquids. As a result, our financial results can be significantly impacted as these commodity prices fluctuate widely in response to changing market forces and conditions. We have previously engaged in oil and gas hedging activities and intend to continue to consider various hedging arrangements to realize commodity prices that we consider favorable. The company engages in hedging contracts for a portion of its oil and gas production through various contracts ("Hedging Agreements"). The primary objective of these activities is to protect against significant decreases in price during the term of the hedge.
The Hedging Agreements provide for separate contracts tied to the New York Mercantile Exchange ("NYMEX") light sweet crude oil and Henry Hub natural gas, and the Inside FERC natural gas index price posting ("Index"). In addition to fixed price swaps, we have combined option contracts that have agreed upon price floors and ceilings ("Cost-less collars"). To the extent the Index price exceeds the contract ceiling, we pay the spread between the ceiling and the Index price applied to the related contract volumes. To the extent the contract floor exceeds the Index, we receive the spread between the contract floor and the Index price applied to the related contract volumes.
To the extent we receive the spread between the contract price and the Index price applied to related contract volumes, we have a credit risk in the event of nonperformance of the counterparty to the agreement. We do not anticipate any material impact to our results of operations as a result of nonperformance by such parties.
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The following is a summary of the company's open commodity hedge contracts as of September 30, 2004:
| Commodity |
Type |
Volume/Day |
Duration |
Weighted Average Price |
|---|---|---|---|---|
| Natural Gas | Collar | 85,000 MMBTU | Oct 04 - Dec 04 | $4.03 - $6.00 |
| Natural Gas | Collar | 60,000 MMBTU | Jan 05 - Dec 05 | $4.21 - $6.85 |
| Natural Gas | Swap | 20,000 MMBTU | Jan 05 - Dec 05 | $ 6.25 |
| Natural Gas | Collar | 20,000 MMBTU | Jan 06 - Dec 06 | $5.25 - $6.30 |
| Crude Oil | Collar | 4,000 BBL | Oct 04 - Dec 04 | $23.25 - $28.36 |
| Crude Oil | Swap | 1,000 BBL | Jan 05 - Dec 05 | $ 34.90 |
| Crude Oil | Collar | 1,000 BBL | Jan 05 - Dec 05 | $35.00 - $55.00 |
| Crude Oil | Collar | 1,000 BBL | Jan 06 - Dec 06 | $30.00 - $35.85 |
On July 12, 2004, we terminated a natural gas collar for 10,000 Mmbtu per day for the period August through December 2004. In closing this contract we realized a $1.3 million loss, which will be recognized in earnings with the underlying forecasted commodity sales transactions for the months August through December 2004. After this contract was terminated, our remaining natural gas production hedged for October through December 2004 decreased to approximately 85.0 Mmcf/day with a weighted average floor price of $4.03 and a weighted average ceiling price of $6.00.
Based on future market prices at September 30, 2004, the fair value of open commodity hedging contracts was a net liability of $49.8 million. If future market prices were to increase 10% from those in effect at September 30, 2004, the fair value of open contracts would be a net liability of $77.3 million. If future market prices were to decline 10% from those in effect at September 30, 2004, the fair value of the open contracts would be a net liability of $19.9 million.
At inception, due to company policy, commodity hedge positions may not exceed 75% of natural gas and 90% of crude oil forecasted current (18 months) commodity production. For non-current (greater than 18 months) commodity production, at inception, commodity hedge positions for natural gas and crude oil may not exceed 75% of forecasted production for each product. Unhedged portions of our natural gas and crude oil production will be subject to market price fluctuations. There are restrictions on our hedging programs under our Facility.
Fixed and Variable Rate Debt. The company uses fixed and variable rate debt to partially finance budgeted expenditures. These agreements expose the company to market risk related to changes in interest rates.
The following table presents the carrying and fair value of the company’s debt along with average interest rates as of September 30, 2004. Fair values are calculated as the net present value of the expected cash flows of the financial instruments, except for the fixed rate Senior Notes and the Convertible Notes, which are valued at their last traded value before September 30, 2004.
| Expected Maturity Dates |
2004 |
2005-7 |
2012 |
2023 |
Total |
Fair Value | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (in thousands of dollars) | ||||||||||||||||||||
| Variable Rate Debt: | ||||||||||||||||||||
| Facility (a) | $ | -- | $ | 340,000 | $ | -- | $ | -- | $ | 340,000 | $ | 340,000 | ||||||||
| Convertible Notes (b) | -- | -- | -- | 125,000 | 125,000 | 149,375 | ||||||||||||||
| Capital Leases (c) | 511 | 5,487 | -- | -- | 5,998 | 5,998 | ||||||||||||||
| Fixed Rate Debt: | ||||||||||||||||||||
| Senior Notes (d) | $ | -- | $ | -- | $ | 195,000 | $ | -- | $ | 195,000 | $ | 220,350 | ||||||||
______________
| (a) | The average interest rate on the Facility is 3.34%. | |
| (b) | The average interest rate on the convertible notes is 1.88%. | |
| (c) | The average interest rate on the two capital leases is 4.9905%. | |
| (d) | The interest rate on the senior notes due 2012 is a fixed 9.6%. |
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Item 4. Controls and Procedures
Our chief executive officer and chief financial officer have reviewed and evaluated the effectiveness of the company's disclosure controls and procedures [as defined in Rules 240.13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934] as of the end of the period covered by this quarterly report. Based on that review and evaluation, which included inquiries made to certain other employees of the company, the chief executive officer and chief financial officer have concluded that our current disclosure controls and procedures, as designed and implemented, are effective to ensure that they are provided with material information relating to the company required to be disclosed in the reports the company files or submits under the Securities Exchange Act of 1934. There have not been any significant changes in our internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation. However, we have been reviewing all of our significant internal controls and are in the process of improving some of our procedures and processes related to our internal controls.
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PART II - OTHER INFORMATION
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
During August 2004, the Magnum Hunter Resources employee KSOP purchased 224,600 shares of Magnum Hunter common stock at an average price of $10.06 on behalf of participants of the plan.
Item 4. Submission of Matters to a Vote of Security Holders
On September 22, 2004, Magnum Hunter held its annual meeting of stockholders. The shareholders voted on the following three items:
| i) | The vote upon the proposal to elect three Board members as stated in the proxy statement. Matthew C. Lutz, John H. Trescot, Jr. and Donald A. Erickson were elected at the meeting. Gary C. Evans, James R. Latimer, III, Gerald W. Bolfing, Jerry Box and Jody Powers remained directors. The votes for the nominees were as follows: | |
| Matthew C. Lutz 53,431,697 shares voted in favor of the nominee. 33,482,155 shares voted against the nominee. 0 shares abstained from voting. | ||
| John H. Trescot, Jr. 74,140,963 shares voted in favor of the nominee. 12,772,889 shares voted against the nominee. 0 shares abstained from voting. | ||
| Donald A. Erickson 77,074,342 shares voted in favor of the nominee. 9,839,510 shares voted against the nominee. 0 shares abstained from voting. | ||
| ii) | The vote upon the proposal to approve the company's 2004 Long-Term Incentive Compensation Plan. The votes for the proposal were as follows: | |
| 24,416,609 shares voted in favor of the proposal. 39,051,088 shares voted against the proposal. 397,739 shares abstained from voting. 23,056,356 broker non-votes. | ||
| iii) | The vote upon the proposal to ratify the appointment of Deloitte & Touche LLP as the corporation's independent auditors. The votes for the proposal were as follows: | |
| 84,547,427 shares voted in favor of the proposal. 2,093,730 shares voted against the proposal. 272,695 shares abstained from voting. 7,940 broker non-votes. |
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Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
| Number |
Description of Exhibit | ||
|---|---|---|---|
| 3.1 & 4.1 | Articles of Incorporation (Incorporated by reference to Registration Statement on Form S-18, File No. | ||
| 33-30298-D). | |||
| 3.2 & 4.2 | Articles of Amendment to Articles of Incorporation (Incorporated by reference to Form 10-K for the year | ||
| ended December 31, 1990). | |||
| 3.3 & 4.3 | Articles of Amendment to Articles of Incorporation (Incorporated by reference to Registration Statement on | ||
| Form SB-2, File No. 33-66190). | |||
| 3.4 & 4.4 | Articles of Amendment to Articles of Incorporation (Incorporated by reference to Registration Statement on | ||
| Form S-3, File No. 333-30453). | |||
| 3.5 & 4.5 | Articles of Amendment to Articles of Incorporation (Incorporated by reference to Form 10-K for the year | ||
| ended December 31, 2001). | |||
| 3.6 & 4.6* | Amended and Restated By-Laws | ||
| 3.7 & 4.7 | Certificate of Designation of 1996 Series A Preferred Stock (Incorporated by reference to Form 8-K dated | ||
| December 26, 1996, filed January 3, 1997). | |||
| 3.8 & 4.8 | Amendment to Certificate of Designation for 1996 Series A Convertible Preferred Stock (Incorporated by | ||
| reference to Registration Statement on Form S-3, File No. 333-30453). | |||
| 4.9 | Form of Warrant Agreement by and between Magnum Hunter Resources, Inc. and American Stock Transfer & Trust | ||
| Company, as warrant agent (Incorporated by reference to Registration Statement on Form S-3, File No. | |||
| 333-82552). | |||
| 4.10 | Indenture, dated March 15, 2002, between Magnum Hunter Resources, Inc., the subsidiary guarantors named | ||
| therein and Bankers Trust Company, as Trustee (Incorporated by reference to Form 10-K for the year ended | |||
| December 31, 2001). | |||
| 4.11 | Form of 9.6% Senior Note due 2007 (included in Exhibit 4.10). | ||
| 4.12 | Indenture dated December 15, 2003 between Magnum Hunter Resources, Inc., the subsidiary guarantors named | ||
| therein and Deutsche Bank Trust Company Americas, as Trustee. | |||
| 4.13 | Form of Floating Rate Convertible Senior Notes due 2023 (included in Exhibit 4.12). | ||
| 4.14 | Shareholder Rights Agreement dated as of January 6, 1998 by and between Magnum Hunter Resources, Inc. and | ||
| Securities Transfer Corporation, as Rights Agent (Incorporated by reference to Form 8-K dated January 7, | |||
| 1998, filed January 9, 1998). | |||
| 10.1 | Fourth Amended and Restated Credit Agreement dated March 15, 2002, as amended, between | ||
| Magnum Hunter Resources, Inc. and Bankers Trust Company, et al (Incorporated by reference to Form 10-K for | |||
| the year ended December 31, 2001). | |||
| 10.2 | First Amendment to Fourth Amended and Restated Credit Agreement, dated April 19, 2002 between | ||
| Magnum Hunter Resources, Inc. and Deutsche Bank Trust Company Americas, et al. (Incorporated by reference | |||
| to Form 10-K for the year ended December 31, 2003). | |||
| 10.3 | Second Amendment to Fourth Amended and Restated Credit Agreement, dated July 3, 2002 between | ||
| Magnum Hunter Resources, Inc. and Deutsche Bank Trust Company Americas, et al (Incorporated by reference | |||
| to Form 10-K for the year ended December 31, 2003). | |||
| 10.4 | Third Amendment to Fourth Amended and Restated Credit Agreement, dated August 28, 2002 between Magnum | ||
| Hunter Resources, Inc. and Deutsche Bank Trust Company Americas, et al. (Incorporated by reference to | |||
| Form 10-K for the year ended December 31, 2003). | |||
| 10.5 | Fourth Amendment to Fourth Amended and Restated Credit Agreement, dated September 6, 2002 between Magnum | ||
| Hunter Resources, Inc. and Deutsche Bank Trust Company Americas, et al. (Incorporated by reference to | |||
| Form 10-K for the year ended December 31, 2003). | |||
| 10.6 | Waiver and Fifth Amendment to Fourth Amended and Restated Credit Agreement, dated November 20, 2002 | ||
| between Magnum Hunter Resources, Inc. and Deutsche Bank Trust Company Americas, et al. (Incorporated by | |||
| reference to Form 10-K for the year ended December 31, 2003). | |||
| 10.7 | Waiver and Sixth Amendment to Fourth Amended and Restated Credit Agreement, dated May 2, 2003 between | ||
| Magnum Hunter Resources, Inc. and Deutsche Bank Trust Company Americas, et al (Incorporated by reference | |||
| to Form 10-K for the year ended December 31, 2003). | |||
| 10.8 | Seventh Amendment to Fourth Amended and Restated Credit Agreement, dated August 8, 2003 between Magnum | ||
| Hunter Resources, Inc. and Deutsche Bank Trust Company Americas, et al. (Incorporated by reference to | |||
| Form 10-K for the year ended December 31, 2003). | |||
32
| 10.9 | Waiver and Eighth Amendment to Fourth Amended and Restated Credit Agreement, dated October 31, 2003 | ||
| between Magnum Hunter Resources, Inc. and Deutsche Bank Trust Company Americas, et al. (Incorporated by | |||
| reference to Form 10-K for the year ended December 31, 2003). | |||
| 10.10 | Ninth Amendment to Fourth Amended and Restated Credit Agreement, dated December 10, 2003 | ||
| between Magnum Hunter Resources, Inc. and Deutsche Bank Trust Company Americas, et al (Incorporated by | |||
| reference to Form 10-K for the year ended December 31, 2003). | |||
| 10.11 | Tenth Amendment to Fourth Amended and Restated Credit Agreement, dated April 30, 2004 between | ||
| Magnum Hunter Resources, Inc. and Deutsche Bank Trust Company Americas, et al (Incorporated by reference | |||
| to Form 10-Q for the period ended March 31, 2004). | |||
| 10.12 | Eleventh Amendment to Fourth Amended and Restated Credit Agreement, dated July 15, 2004 between Magnum | ||
| Hunter Resources, Inc. and Deutsche Bank Trust Company Americas, et al. (Incorporated by reference to | |||
| Form 10-Q for the period ended June 30, 2004.) | |||
| 10.13* | Twelfth Amendment to Fourth Amended and Restated Credit Agreement, dated October 15, 2004 between Magnum | ||
| Hunter Resources, Inc. and Deutsche Bank Trust Company Americas, et al. | |||
| 10.14†* | Employment Agreement for Gary C. Evans as amended. | ||
| 10.15†* | Employment Agreement for Richard R. Frazier. | ||
| 10.16† | Employment Agreement for Chris Tong (Incorporated by reference to Form 10-K for the fiscal year- | ||
| end December 31, 2002). | |||
| 10.17† | Employment Agreement for R. Douglas Cronk (Incorporated by reference to Form 10-K for the fiscal | ||
| year-end December 31, 2002). | |||
| 10.18† | Employment Agreement for Charles Erwin (Incorporated by reference to Form 10-K for the fiscal | ||
| year-end December 31, 2002). | |||
| 10.19† | Employment Agreement for Morgan F. Johnston. | ||
| 10.20 | Purchase and Sale Agreement, dated February 27, 1997 among Burlington Resources Oil and Gas | ||
| Company, Glacier Park Company and Magnum Hunter Production, Inc. (Incorporated by reference to | |||
| Form 8-K, dated April 30, 1997, filed May 12, 1997). | |||
| 10.21 | Purchase and Sale Agreement dated November 25, 1998, between Magnum Hunter Production, Inc. and Unocal Oil | ||
| Company of California (Incorporated by reference to Form 10-K for the fiscal year-end December 31, 1998, | |||
| filed April 14, 1999). | |||
| 10.22 | Agreement of Limited Partnership of Mallard Hunter, L.P., dated May 23, 2000 (Incorporated by reference to | ||
| Form 10-Q/A for the period ended June 30, 2000, filed November 30, 2000). | |||
| 21 | Subsidiaries of the Registrant (Incorporated by reference to Form 10-K for the period ended December 31, | ||
| 2001. | |||
| 31.1* | Certification pursuant to Section 302 of Sarbanes-Oxley Act of 2002, signed by Gary C. Evans | ||
| 31.2* | Certification pursuant to Section 302 of Sarbanes-Oxley Act of 2002, signed by Chris Tong | ||
| 32.1* | Certification pursuant to Section 906 of Sarbanes-Oxley Act of 2002 signed by Gary C. Evans | ||
| 32.2* | Certification pursuant to Section 906 of Sarbanes-Oxley Act of 2002 signed by Chris Tong | ||
_______________
* Filed herewith
33
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
MAGNUM HUNTER RESOURCES, INC.
| By /s/ Gary C. Evans | November 9, 2004 | |
| Gary C. Evans President and Chief Executive Officer |
||
| By /s/ Chris Tong | November 9, 2004 | |
| Chris Tong Senior Vice President and Chief Financial Officer |
||
| By /s/ Morgan F. Johnston | November 9, 2004 | |
| Morgan F. Johnston Senior Vice President, General Counsel and Secretary |
||
| By /s/ David S. Krueger | November 9, 2004 | |
| David S. Krueger Vice President and Chief Accounting Officer |
34