(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, 2003
[ ] 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 October 31, 2003: 67,299,054.
| September 30, 2003 |
December 31, 2002 | |||||||
|---|---|---|---|---|---|---|---|---|
| ASSETS | ||||||||
| Current Assets | ||||||||
| Cash and cash equivalents | $ | 2,173 | $ | 3,069 | ||||
| Restricted cash | 909 | 682 | ||||||
| Accounts receivable - trade, net of allowance of $4,521 and $4,573, | 49,905 | 53,741 | ||||||
| respectively | ||||||||
| Deposits | 549 | 8,856 | ||||||
| Deferred income taxes, current | 6,801 | 15,500 | ||||||
| Income tax refund receivable | -- | 9,966 | ||||||
| Other current assets | 6,563 | 6,159 | ||||||
| Total Current Assets | 66,900 | 97,973 | ||||||
| Property, Plant, and Equipment | ||||||||
| Oil and gas properties, full cost method | ||||||||
| Unproved | 181,592 | 165,676 | ||||||
| Proved | 1,190,911 | 1,053,426 | ||||||
| Gas processing plants and pipelines | 34,136 | 33,951 | ||||||
| Other property | 7,048 | 6,636 | ||||||
| Total Property, Plant and Equipment | 1,413,687 | 1,259,689 | ||||||
| Accumulated depreciation, depletion, amortization and impairment | (323,671 | ) | (258,080 | ) | ||||
| Net Property, Plant and Equipment | 1,090,016 | 1,001,609 | ||||||
| Other Assets | ||||||||
| Goodwill | 58,463 | 50,710 | ||||||
| Investment in unconsolidated affiliates | 541 | 6,722 | ||||||
| Other assets | 10,377 | 12,642 | ||||||
| Total Assets | $ | 1,226,297 | $ | 1,169,656 | ||||
| LIABILITIES AND STOCKHOLDERS' EQUITY | ||||||||
| Current Liabilities | ||||||||
| Trade payables and accrued liabilities | $ | 93,355 | $ | 72,595 | ||||
| Accrued interest | 3,893 | 10,327 | ||||||
| Derivative liabilities, current | 17,956 | 42,777 | ||||||
| Due to affiliates | 1,773 | 1,432 | ||||||
| Current portion of long-term debt | 2,006 | 1,865 | ||||||
| Total Current Liabilities | 118,983 | 128,996 | ||||||
| Long-Term Liabilities | ||||||||
| Long-term debt, less current maturities | 561,505 | 569,086 | ||||||
| Asset retirement obligations | 30,838 | -- | ||||||
| Derivative liabilities, noncurrent | 2,965 | 3,316 | ||||||
| Deferred income taxes payable | 137,317 | 118,062 | ||||||
| Other non-current liabilities | 244 | -- | ||||||
| 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, | ||||||||
| 71,760,280 and 71,707,897 shares issued, respectively | 144 | 143 | ||||||
| Additional paid-in capital | 425,500 | 423,364 | ||||||
| Accumulated other comprehensive loss | (13,652 | ) | (26,902 | ) | ||||
| Accumulated deficit | (2,285 | ) | (21,114 | ) | ||||
| Common stock in deferred compensation plan at cost (34,416 shares) | (192 | ) | -- | |||||
| Unearned common stock in KSOP, at cost (1,197,124 and 757,246 shares, respectively) | (7,303 | ) | (4,888 | ) | ||||
| 402,213 | 370,604 | |||||||
| Treasury stock, at cost (4,489,992 and 3,168,013 shares, respectively) . | (27,768 | ) | (20,408 | ) | ||||
| Total Stockholders' Equity | 374,445 | 350,196 | ||||||
| Total Liabilities and Stockholders' Equity | $ | 1,226,297 | $ | 1,169,656 | ||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
1
| Three Months Ended September 30, |
Nine Months Ended September 30, | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2003 |
2002 |
2003 |
2002 | |||||||||||
| Operating Revenues: | ||||||||||||||
| Oil and gas sales | $ | 73,390 | $ | 66,364 | $ | 211,450 | $ | 176,057 | ||||||
| Gas gathering, marketing and processing | 8,075 | 5,456 | 26,515 | 13,634 | ||||||||||
| Oil field services | 1,110 | 1,013 | 3,102 | 2,456 | ||||||||||
| Total Operating Revenues | 82,575 | 72,833 | 241,067 | 192,147 | ||||||||||
| Operating Costs and Expenses: | ||||||||||||||
| Oil and gas production lifting costs | 16,463 | 14,031 | 42,909 | 38,417 | ||||||||||
| Production taxes and other costs | 7,976 | 8,123 | 25,083 | 20,348 | ||||||||||
| Gas gathering, marketing and processing | 5,832 | 4,026 | 19,260 | 10,172 | ||||||||||
| Oil field services | 724 | 728 | 2,174 | 1,547 | ||||||||||
| Depreciation, depletion, amortization and accretion | 26,682 | 24,309 | 73,184 | 62,947 | ||||||||||
| Gain on sale of assets | (12 | ) | (29 | ) | (152 | ) | (29 | ) | ||||||
| General and administrative | 3,757 | 2,872 | 10,098 | 9,619 | ||||||||||
| Total Operating Costs and Expenses | 61,422 | 54,060 | 172,556 | 143,021 | ||||||||||
| Operating Profit | 21,153 | 18,773 | 68,511 | 49,126 | ||||||||||
| Equity in earnings (loss) of affiliate | 173 | 534 | (64 | ) | 916 | |||||||||
| Other income | 231 | 93 | 609 | 258 | ||||||||||
| Provision for impairment of investments | -- | -- | -- | (621 | ) | |||||||||
| Costs associated with early retirement of debt | (19 | ) | -- | (4,085 | ) | (1,000 | ) | |||||||
| Other non-cash hedging adjustments | 701 | (1,507 | ) | 1,237 | (5,430 | ) | ||||||||
| Interest expense | (11,483 | ) | (13,474 | ) | (36,445 | ) | (34,649 | ) | ||||||
| Income Before Income Tax | 10,756 | 4,419 | 29,763 | 8,600 | ||||||||||
| Deferred income tax (expense) benefit | (4,087 | ) | (1,673 | ) | (11,333 | ) | 3,843 | |||||||
| Income Before Cumulative Effect of a Change in Accounting | ||||||||||||||
| Principle | 6,669 | 2,746 | 18,430 | 12,443 | ||||||||||
| Cumulative effect of a change in accounting principle, net | ||||||||||||||
| of income tax expense of $244 | -- | -- | 399 | -- | ||||||||||
| Net Income | $ | 6,669 | $ | 2,746 | $ | 18,829 | $ | 12,443 | ||||||
| Income per Common Share - Basic | ||||||||||||||
| Income before cumulative effect of a change in accounting | ||||||||||||||
| principle | $ | 0.10 | $ | 0.04 | $ | 0.27 | $ | 0.21 | ||||||
| Cumulative effect of a change in accounting principle | -- | -- | 0.01 | -- | ||||||||||
| Income per Common Share - Basic | $ | 0.10 | $ | 0.04 | $ | 0.28 | $ | 0.21 | ||||||
| Income per Common Share - Diluted | ||||||||||||||
| Income before cumulative effect of a change in accounting | ||||||||||||||
| principle | $ | 0.10 | $ | 0.04 | $ | 0.27 | $ | 0.21 | ||||||
| Cumulative effect of a change in accounting principle | -- | -- | 0.01 | -- | ||||||||||
| Income per Common Share - Diluted | $ | 0.10 | $ | 0.04 | $ | 0.28 | $ | 0.21 | ||||||
| Common Shares Used in Per Share Calculation | ||||||||||||||
| Basic | 66,007 | 67,679 | 66,205 | 59,411 | ||||||||||
| Diluted | 67,547 | 68,553 | 67,247 | 60,524 | ||||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
2
| Preferred Stock |
Common Stock |
Treasury Stock |
Additional Paid in Capital |
Accumulated Deficit |
Deferred Compensation |
Unearned Shares in KSOP |
Accumulated Other Comprehensive Income (Loss) |
Total Stockholders' Equity |
Total Comprehensive Income (Loss) | |||||||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Balance at December 31, 2002 | $ | 1 | $ | 143 | $ | (20,408 | ) | $ | 423,364 | $ | (21,114 | ) | $ | -- | $ | (4,888 | ) | $ | (26,902 | ) | $ | 350,196 | ||||||||||
| Issuance of 52 shares of common stock pursuant to employee stock option plan | 1 | 214 | 215 | |||||||||||||||||||||||||||||
| Deferred tax benefit on exercise of employee stock options | 82 | 82 | ||||||||||||||||||||||||||||||
| Purchase of 1,340 shares of treasury stock | (7,413 | ) | (7,413 | ) | ||||||||||||||||||||||||||||
| Loan to KSOP to purchase 486 shares | (2,711 | ) | (2,711 | ) | ||||||||||||||||||||||||||||
| Employee salary deferrals to KSOP, representing 46 shares | 65 | 296 | 361 | |||||||||||||||||||||||||||||
| Contribution of 18 treasury shares to deferred compensation plan | 53 | 47 | (100 | ) | -- | |||||||||||||||||||||||||||
| Release 36 shares from deferred compensation plan | 203 | 203 | ||||||||||||||||||||||||||||||
| Stock compensation | 1,728 | 1,728 | ||||||||||||||||||||||||||||||
| Purchase of 53 shares for deferred compensation plan | (295) | (295) | ||||||||||||||||||||||||||||||
| Net Income | 18,829 | 18,829 | $ | 18,829 | ||||||||||||||||||||||||||||
| Reclassification adjustment related to derivative contracts, net of income tax expense of $23,797 | 39,033 | 39,033 | 39,033 | |||||||||||||||||||||||||||||
| Change in fair value of outstanding hedge positions, net of income tax benefit of $15,351 | (25,179 | ) | (25,179 | ) | (25,179 | ) | ||||||||||||||||||||||||||
| Amortization of purchased hedge positions, net ofb income tax benefit of $368 | (604 | ) | (604 | ) | (604 | ) | ||||||||||||||||||||||||||
| Balance at September 30, 2003 | $ | 1 | $ | 144 | $ | (27,768 | ) | $ | 425,500 | $ | (2,285 | ) | $ | (192 | ) | $ | (7,303 | ) | $ | (13,652 | ) | $ | 374,445 | $ | 32,079 | |||||||
The accompanying notes are an integral part of these condensed consolidated financial statements
3
| Nine Months Ended September 30, | ||||||||
|---|---|---|---|---|---|---|---|---|
| 2003 |
2002 | |||||||
| CASH FLOW FROM OPERATING ACTIVITIES: | ||||||||
| Net Income | $ | 18,829 | $ | 12,443 | ||||
| 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 | 73,184 | 62,947 | ||||||
| Amortization of deferred financing fees | 1,779 | 1,431 | ||||||
| Imputed interest on debt due to merger | -- | 108 | ||||||
| Excess of fair value over shares released from KSOP | 65 | -- | ||||||
| Costs associated with early retirement of debt | 4,085 | 1,000 | ||||||
| Deferred income taxes (benefits) | 11,333 | (3,843 | ) | |||||
| Equity in (income) loss of unconsolidated affiliate | 64 | (916 | ) | |||||
| Gain on sale of assets | (152 | ) | (29 | ) | ||||
| Provision for impairment of investments | -- | 621 | ||||||
| Non-cash hedging adjustments | (1,237 | ) | 5,430 | |||||
| Stock compensation | 1,728 | -- | ||||||
| Changes in certain assets and liabilities, net of the effect of | ||||||||
| acquisitions: | ||||||||
| Accounts and notes receivable | 3,846 | (9,711 | ) | |||||
| Derivative assets | -- | 3,600 | ||||||
| Refund of income taxes | 7,865 | 87 | ||||||
| Deposits and other current assets | 8,013 | (7,695 | ) | |||||
| Accounts payable and accrued liabilities | 14,840 | (26,196 | ) | |||||
| Net Cash Provided by Operating Activities | 143,843 | 39,277 | ||||||
| CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||
| Proceeds from sale of assets, net of purchase price adjustments | 14,623 | 56,592 | ||||||
| Additions to property and equipment | (144,243 | ) | (98,241 | ) | ||||
| Proceeds from sale of unconsolidated affiliate | 5,160 | -- | ||||||
| Cash paid in Prize merger net of cash acquired | -- | (41,097 | ) | |||||
| Increase in note receivable | -- | (2,450 | ) | |||||
| Decrease in other assets | 46 | -- | ||||||
| Distribution from unconsolidated affiliate | 1,510 | 161 | ||||||
| Investment in unconsolidated affiliate | (600 | ) | (765 | ) | ||||
| Net Cash Used in Investing Activities | (123,504 | ) | (85,800 | ) | ||||
| CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||
| Proceeds from issuance of debt | 320,075 | 610,683 | ||||||
| Redemption of notes payable | (77,292 | ) | -- | |||||
| Fees paid related to financing activities | (456 | ) | (11,899 | ) | ||||
| Payments of principal on debt and production payment | (253,202 | ) | (534,496 | ) | ||||
| Loan made to stockholder | -- | (300 | ) | |||||
| Increase in note receivable from affiliate | (225 | ) | -- | |||||
| Repayment of note receivable from affiliate | -- | 300 | ||||||
| Loan made to KSOP | (2,711 | ) | (2,683 | ) | ||||
| Repayment of loan to KSOP | 296 | -- | ||||||
| Proceeds from issuance of common stock, net of offering costs | 215 | 1,421 | ||||||
| Purchase of common stock for deferred compensation plan | (295 | ) | -- | |||||
| Purchase of warrants | -- | (98 | ) | |||||
| Purchase of treasury stock | (7,413 | ) | (14,185 | ) | ||||
| Increase in restricted cash for payment of notes payable | (227 | ) | (329 | ) | ||||
| Net Cash (Used in) Provided By Financing Activities | (21,235 | ) | 48,414 | |||||
| NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS | (896 | ) | 1,891 | |||||
| CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD | 3,069 | 2,755 | ||||||
| CASH AND CASH EQUIVALENTS AT END OF PERIOD | $ | 2,173 | $ | 4,646 | ||||
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | ||||||||
| Cash paid for interest | $ | 44,266 | $ | 40,222 | ||||
| Cash paid for income taxes | $ | 1,500 | $ | -- | ||||
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, 2003, the condensed consolidated statements of income for the three and nine months ended September 30, 2003 and 2002, the condensed consolidated statement of stockholders’ equity and comprehensive income for the nine months ended September 30, 2003, and the condensed consolidated statements of cash flows for the nine months ended September 30, 2003 and 2002, are unaudited. 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, 2003, results of operations for the three and nine month periods, changes in stockholders’ equity and comprehensive income and cash flows for the nine month periods.
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, 2002 annual report and on our Form 10-K. The results of operations for the three and nine month periods ended September 30, 2003, 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.
During the first quarter of 2002, we merged with Prize Energy Corp. (“Prize”), a publicly traded independent oil and gas development and production company. The merger with Prize closed on March 15, 2002, but for operating and financial reporting purposes, was effective as of March 1, 2002.
Subsequent to the Prize merger, we have divested of approximately 85.8 billion cubic feet equivalent of non-strategic proved producing oil and gas reserves for total proceeds of approximately $110.6 million, net of purchase price adjustments. Almost all of the properties sold were acquired in the Prize merger, and the proceeds have been used to reduce our overall indebtedness and fund our capital program.
On July 29, 2003, we exercised our option to sell our 30% interest in NGTS, LLC (“NGTS”). We reduced the carrying value and recorded a charge to equity in earnings of affiliate of approximately $719 thousand at June 30, 2003, to state our investment at its estimated fair value. The sale closed on September 30, 2003, and we received proceeds of $5.2 million on that date, which were used to repay indebtedness. No gain or loss was recorded on the sale.
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. and Redhead Energy, Inc., collectively referred to as Canvasback, are direct guarantors of each of our 10% Senior Notes and 9.6% Senior Notes, and have fully and unconditionally guaranteed these Senior Notes 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 cash dividends, loans, or advances.
5
Statement of Financial Accounting Standards (“SFAS”) No. 143 — SFAS No. 143, “Accounting for Asset Retirement Obligations,” became effective beginning January 1, 2003. SFAS No. 143 requires the recognition of a fair value liability for any retirement obligation associated with long-lived assets in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset and depreciated over the asset’s useful life. See Note 5 for additional information on our asset retirement obligations. Upon adoption of SFAS No. 143, we recorded an addition to oil and gas properties of $25.4 million, an asset retirement obligation of $30.4 million, a reduction of accumulated depletion of $5.6 million, and a pre-tax gain of $643 thousand.
SFAS No. 145 — SFAS No. 145 “Recission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections,” became effective beginning January 1, 2003. The Statement rescinds, updates, clarifies and simplifies various existing accounting pronouncements. SFAS No. 145 rescinds SFAS No. 4, “Reporting Gains and Losses from Extinguishment of Debt,” which required all gains and losses from extinguishment of debt to be aggregated and, if material, classified as an extraordinary item, net of related income tax effect. As a result, SFAS No. 145 requires us to reclassify as additional expense any extraordinary items for debt extinguishment costs which did not meet the criteria as described in APB Opinion No. 30, “Reporting the Results of Operations — Reporting the Effects of Disposal of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions,” as additional expense. As a result, for the nine months ended September 30, 2002, we reclassified our previously reported $621 thousand extraordinary loss as costs associated with early retirement of debt of $1 million and increased our deferred income tax benefit by $379 thousand.
SFAS No. 146 — In July 2002, the Financial Accounting Standards Board, (“FASB”) issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS No. 146 requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. SFAS No. 146 supercedes EITF Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” Statement 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002.
SFAS No. 148 – The FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure, an Amendment to FASB Statement No. 123,” in December 2002. SFAS No. 148 provides alternative methods of transition for a voluntary change to the fair value method of accounting for stock-based employee compensation and amends the disclosure requirements of SFAS No. 123. On 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 nine months ended September 30, 2003, we recorded stock compensation expense of $1.7 million, which is reflected in our general and administrative expenses. 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. For additional information on our stock compensation, please see Note 3.
FIN No. 45 – FIN No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees,” was issued in November 2002. This interpretation addresses the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees. It also clarifies the requirements related to the recognition of a liability by a guarantor at the inception of a guarantee for the obligations the guarantor has undertaken in issuing that guarantee. We adopted this statement in January 2003.
In the past, we have provided trade guarantees on behalf of NGTS. The last of these guarantees expired in July 2003. Further, we have sold our 30% ownership interest in NGTS, and, therefore, no longer maintain any equity interest in this affiliate (see Note 1). We have provided no other guarantees on behalf of any unconsolidated entities and do not intend to issue any at this time.
6
FIN No. 46 – FIN No. 46, “Consolidation of Variable Interest Entities,” addresses consolidation by business enterprises of variable interest entities with certain defined characteristics. This interpretation applies to the first fiscal year or interim period ending after December 15, 2003, to variable interest entities created or obtained before February 1, 2003. For variable interest entities created after January 31, 2003 the consolidation provisions apply immediately. We do not have any variable interest entities that would be subject to these provisions and, accordingly, FIN 46 will not have an impact on our financial statements.
In June 2001, FASB issued 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 has been raised regarding whether these mineral rights should be classified as tangible or intangible assets. If it is determined that reclassification is necessary, we will reduce our proven properties by $352.7 million, decrease unproved properties by $154.5 million and report intangible mineral rights related to proved properties of $352.7 million and intangible mineral rights related to unproved properties of $154.5 million at December 31, 2002. At September 30, 2003, we will reduce our proven properties by $336.2 million, reduce our unproved properties by $166 million, and report intangible mineral rights related to proved properties of $336.2 million and intangible mineral rights related to unproved properties of $166 million. These reclassifications represent the cost of acquiring proved and unproved mineral use rights from the effective date of June 30, 2001. The provisions of SFAS No. 141 and SFAS No. 142 impact only the balance sheet and any associated footnote disclosures. Any reclassifications potentially required would not impact our cash flows or statements of income.
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, 2003, we recorded pre-tax stock compensation expense of $1.3 million and $1.7 million, respectively, which is reflected in our general and administrative expenses. 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.
7
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, | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2003 |
2002 |
2003 |
2002 | |||||||||||
| Net income, as reported | $ | 6,669 | $ | 2,746 | $ | 18,829 | $ | 12,443 | ||||||
| Total Stock-based employee compensation expense | ||||||||||||||
| included in reported net income, net of income | ||||||||||||||
| taxes of $490 and $654, respectively | 804 | -- | 1,073 | -- | ||||||||||
| Deduct: Total stock-based employee compensation | ||||||||||||||
| determined under fair value-based method for all | ||||||||||||||
| awards, net of income taxes of $930, $756, | ||||||||||||||
| $1,944, and $1,583, respectively | (1,526 | ) | (1,239 | ) | (3,188 | ) | (2,597 | ) | ||||||
| Pro forma net income | $ | 5,947 | $ | 1,507 | $ | 16,714 | $ | 9,846 | ||||||
| Earnings per share: | ||||||||||||||
| Basic - as reported | $ | 0.10 | $ | 0.04 | $ | 0.28 | $ | 0.21 | ||||||
| Basic - pro forma | $ | 0.09 | $ | 0.02 | $ | 0.25 | $ | 0.17 | ||||||
| Diluted - as reported | $ | 0.10 | $ | 0.04 | $ | 0.28 | $ | 0.21 | ||||||
| Diluted - pro forma | $ | 0.09 | $ | 0.02 | $ | 0.25 | $ | 0.16 | ||||||
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 the new rules in these statements, goodwill is no longer amortized, but is subject to annual impairment tests. We completed the first of these tests at December 31, 2002 and found no impairment. Changes to the carrying value of goodwill during the nine months ended September 30, 2003 were as follows (in thousands):
| Balance at December 31, 2002 | $ | 50,710 | |||
| Purchase price adjustments | 7,753 | ||||
| Balance at September 30, 2003 | $ | 58,463 | |||
Our goodwill results from our merger with Prize, and the purchase price allocation was finalized as of June 30, 2003. The goodwill has been fully allocated to our Exploration and Production segment.
SFAS No. 143, “Accounting for Asset Retirement Obligations,” became effective beginning January 1, 2003. SFAS No. 143 requires the recognition of a fair value liability for any legal retirement obligations associated with long-lived assets in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset and depreciated over the asset’s useful life. Prior to adopting SFAS No. 143 on January 1, 2003, we accounted for asset retirement obligations in accordance with SFAS No. 19.
Our long-lived assets captured under SFAS No. 143 are developed oil and gas properties, production and distribution facilities, and natural gas processing plants. Our asset retirement obligations include plugging, abandonment, decommission and remediation costs.
8
The following is a reconciliation of the asset retirement obligation liability at September 30, 2003 (in thousands):
| Beginning balance at January 1, 2003 | $ | -- | |||
| Cumulative effect adjustment | 30,391 | ||||
| Liabilities incurred | 1,217 | ||||
| Liabilities settled | (1,195 | ) | |||
| Liabilities sold | (1,091 | ) | |||
| Accretion expense | 1,852 | ||||
| Change in retirement cost estimates | (336 | ) | |||
| Ending balance at September 30, 2003 | $ | 30,838 | |||
The following pro forma data summarizes our net income and net income per share as if we had adopted SFAS No. 143 on January 1, 2002. The associated pro forma asset retirement obligation was $16.9 million on January 1, 2002 and an additional asset retirement obligation of $12.9 million would have been recorded at March 1, 2002 in conjunction with the Prize merger. Values in the pro forma summary are in thousands, except for the per share amounts.
| Three Months Ended September 30, |
Nine Months Ended September 30, | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2003 |
2002 |
2003 |
2002 | |||||||||||
| Net income, as reported | $ | 6,669 | $ | 2,746 | $ | 18,829 | $ | 12,443 | ||||||
| Pro forma adjustment to reflect retroactive | ||||||||||||||
| adoption of SFAS No. 143, net of related tax effects | -- | (28 | ) | (399 | ) | 37 | ||||||||
| Pro forma net income | $ | 6,669 | $ | 2,718 | $ | 18,430 | $ | 12,480 | ||||||
| Earnings per share: | ||||||||||||||
| Basic - as reported | $ | 0.10 | $ | 0.04 | $ | 0.28 | $ | 0.21 | ||||||
| Basic - pro forma | $ | 0.10 | $ | 0.04 | $ | 0.27 | $ | 0.21 | ||||||
| Diluted - as reported | $ | 0.10 | $ | 0.04 | $ | 0.28 | $ | 0.21 | ||||||
| Diluted - pro forma | $ | 0.10 | $ | 0.04 | $ | 0.27 | $ | 0.21 | ||||||
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, 2003 |
September 30, 2002 | |||||||||||||||||||
| Income |
Shares |
Per Share Amount |
Income |
Shares |
Per Share Amount | |||||||||||||||
| Basic EPS | ||||||||||||||||||||
| Income available to common stockholders | $ | 6,669 | 66,007 | $ | 0.10 | $ | 2,746 | 67,679 | $ | 0.04 | ||||||||||
| Effect of Dilutive Securities | ||||||||||||||||||||
| Warrants | 83 | -- | ||||||||||||||||||
| Options | 1,457 | 874 | ||||||||||||||||||
| Diluted EPS | ||||||||||||||||||||
| Income available to common stockholders and | ||||||||||||||||||||
| assumed conversions | $ | 6,669 | 67,547 | $ | 0.10 | $ | 2,746 | 68,553 | $ | 0.04 | ||||||||||
9
| Nine Months Ended | ||||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| September 30, 2003 |
September 30, 2002 | |||||||||||||||||||
| Income |
Shares |
Per Share Amount |
Income |
Shares |
Per Share Amount | |||||||||||||||
| Basic EPS | ||||||||||||||||||||
| Income available to common stockholders | $ | 18,829 | 66,205 | $ | 0.28 | $ | 12,443 | 59,411 | $ | 0.21 | ||||||||||
| Effect of Dilutive Securities | ||||||||||||||||||||
| Warrants | 28 | -- | 46 | |||||||||||||||||
| Options | 1,014 | -- | 1,067 | |||||||||||||||||
| Diluted EPS | ||||||||||||||||||||
| Income available to common stockholders and | ||||||||||||||||||||
| assumed conversions | $ | 18,829 | 67,247 | $ | 0.28 | $ | 12,443 | 60,524 | $ | 0.21 | ||||||||||
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. At September 30, 2002, warrants representing 12,091,294 shares of common stock and options representing 6,791,534 shares of common stock were outstanding. For the three and nine month periods ended September 30, 2003, 7,228,457 shares and 7,658,290 shares of stock representing warrants, respectively, and 2,913,800 shares and 3,050,733 shares of stock representing options, respectively, were excluded from the diluted earnings per share calculations because the exercise price exceeded the average market price of our stock for these periods. For the three and nine month periods ended September 30, 2002, 12,091,394 shares and 11,661,563 shares of stock representing warrants, respectively, and 3,289,600 shares and 3,286,767 shares of stock representing options, respectively, were excluded from the diluted earnings per share calculations because the exercise price exceeded the average market price of our stock for these periods.
NOTE 7 — DEBT
Notes payable and long-term debt at September 30, 2003 and December 31, 2002 consisted of the following (in thousands):
| 9/30/2003 |
12/31/2002 | |||||||
|---|---|---|---|---|---|---|---|---|
| Long-Term Debt: | ||||||||
| Bank debt under revolving credit agreements due | ||||||||
| May 2, 2006 | $ | 199,500 | $ | 125,000 | ||||
| Term note payable due May 31, 2005, non-recourse | 932 | 7,000 | ||||||
| Production payment liability, non-recourse | 29 | 114 | ||||||
| Capital lease obligations | 7,897 | 9,371 | ||||||
| 10% Senior unsecured notes, due June 1, 2007 | 55,153 | 129,466 | ||||||
| 9.6% Senior unsecured notes, due March 15, 2012 | 300,000 | 300,000 | ||||||
| 563,511 | 570,951 | |||||||
| Less: Current portion of capital lease obligations | 2,006 | 1,865 | ||||||
| Total Long-Term Debt | $ | 561,505 | $ | 569,086 | ||||
On January 27, 2003, we redeemed $30 million in principal of our 10% Senior Notes at a redemption price of 105% of par. We paid the holders of these redeemed notes $31.5 million plus accrued and unpaid interest of $467 thousand. Of the $30 million redeemed, Canvasback received $2.3 million. On June 2, 2003, we redeemed an additional $50 million in principal of our 10% Senior Notes at a redemption price of 103.333% of par. We paid the holders of these redeemed notes $51.7 million including accrued and unpaid interest of $14 thousand. Of the $50 million redeemed during the second quarter, Canvasback received $3.7 million.
We amended our Senior Bank Credit Facility (the “Facility”) on May 2, 2003. The amended Facility provides for a borrowing base increase of $50 million to $300 million, up from $250 million previously. Additionally, the expiration date of the Facility was extended to May 2, 2006. We used the increased borrowing capacity to fund the June 2, 2003 note redemption.
10
We amended our Facility again on October 31, 2003. The amended Facility provides for an additional borrowing base increase of $50 million to $350 million, up from $300 million previously. We will use the increased borrowing capacity to redeem the remaining $55.2 million (net of $4.8 million owned by Canvasback) of our 10% Senior Notes on December 3, 2003 at 103.333% of par plus accrued interest.
We amended our term note payable (the “Term Loan”) on July 2, 2003. The amended Term Loan allows for additional advances of up to $5 million for the purpose of additional 10% Senior Note repurchases. The maturity date was also extended to May 31, 2005. In conjunction with the upcoming December 3, 2003 redemption of our outstanding 10% Senior Notes, this loan will be paid in full. At that time, we will determine whether this credit agreement will be kept in place.
On August 8, 2003, we purchased $381 thousand in principal of our 10% Senior Notes at 103.75% of par through Canvasback. These notes were held by Canvasback at September 30, 2003.
SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as extended by SFAS No. 137 (June 1999) and amended by SFAS No. 138 (June 2000), was effective beginning January 2001. SFAS No. 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It requires the recognition of derivatives in the balance sheet and the measurement of those instruments at fair value.
We were obligated to eleven crude oil derivatives and thirteen natural gas derivatives on September 30, 2003. 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 to other comprehensive income. Hedge ineffectiveness on cash-flow hedges is recorded in earnings.
At September 30, 2003, the fair value of the company’s derivatives were as follows (in thousands):
| Derivative Assets | |||||
| Crude oil collars | $ | 96 | |||
| Total derivative assets | $ | 96 | |||
| Derivative Liabilities | |||||
| Natural gas collars | $ | 16,722 | |||
| Natural gas swaps | 1,235 | ||||
| Crude oil collars | 2,164 | ||||
| Crude oil swaps | 800 | ||||
| Total derivative liabilities | $ | 20,921 | |||
| Net derivative liabilities | $ | 20,825 | |||
The $96 thousand derivative asset is included other current assets. Of the $20.9 million derivative liability, $17.9 million is classified as a current liability on our condensed consolidated balance sheet at September 30, 2003.
For the three and nine month periods ended September 30, 2003, the statement of operations includes a non-cash hedging ineffectiveness gain of $377 thousand and $265 thousand, respectively, related to the crude oil and natural gas derivatives. Additionally, during this similar period, our statement of operations includes a non-cash gain of $324 thousand and $972 thousand, respectively, related to the amortization of hedge contracts acquired in the Prize merger. The remaining amortization amounts relating to hedge contracts acquired in the Prize merger that will be reclassified into the operations statement in years 2003 and 2004 are a $324 thousand gain and $792 thousand gain, respectively. It is estimated at this time that $12.0 million of other comprehensive loss will be reclassified into the income statement during the next 12 months.
11
On May 1, 2003, we closed out 20,000 Mmbtu/day of natural gas collar hedges for the period June through December 2003. In closing these contracts, we locked in a $5.7 million loss, which will be recognized in earnings with the underlying forecasted commodity sales transactions for the months of June through December 2003. At September 30, 2003, the remaining balance was $2.6 million.
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 three gathering systems and four natural gas liquids processing plants in four 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.
Segment data for the periods ended September 30, 2003 and 2002 follows (in thousands):
| 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 | 1,667 | 238 | (3,872 | ) | -- | 21,153 | |||||||||||||
| Equity in earnings of affiliates | 173 | 173 | ||||||||||||||||||
| Interest expense | (11,483 | ) | (11,483 | ) | ||||||||||||||||
| Costs associated with early retirement | ||||||||||||||||||||
| of debt | (19 | ) | (19 | ) | ||||||||||||||||
| Other income (expense) | 932 | 932 | ||||||||||||||||||
| Income before income taxes | 10,756 | |||||||||||||||||||
| Provision for income tax expense | (4,087 | ) | (4,087 | ) | ||||||||||||||||
| Net income | $ | 6,669 | ||||||||||||||||||
12
| Three Months Ended September 30, 2002: |
Exploration & Production |
Gas Gathering, Marketing & Processing |
Oil Field Services |
All Other |
Elimination |
Consolidated | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Revenue from external customers | $ | 66,364 | $ | 5,456 | $ | 1,013 | $ | -- | $ | 72,833 | ||||||||||
| Intersegment revenues | 1,206 | 3,480 | 4,199 | -- | (8,885 | ) | -- | |||||||||||||
| Depreciation, depletion and amortization | 23,360 | 576 | 133 | 240 | 24,309 | |||||||||||||||
| Segment profit (loss) | 20,849 | 854 | 152 | (3,082 | ) | 18,773 | ||||||||||||||
| Equity in earnings of affiliates | 534 | 534 | ||||||||||||||||||
| Interest expense | (13,474 | ) | (13,474 | ) | ||||||||||||||||
| Other income (expense) | (1,414 | ) | (1,414 | ) | ||||||||||||||||
| Income before income taxes | 4,419 | |||||||||||||||||||
| Provision for income tax expense | (1,673 | ) | (1,673 | ) | ||||||||||||||||
| Net income | $ | 2,746 | ||||||||||||||||||
| 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 | 486 | (10,429 | ) | 68,511 | ||||||||||||||
| Equity in earnings of affiliates | (64 | ) | (64 | ) | ||||||||||||||||
| Interest expense | (36,445 | ) | (36,445 | ) | ||||||||||||||||
| Costs associated with early retirement | ||||||||||||||||||||
| of debt | (4,085 | ) | (4,085 | ) | ||||||||||||||||
| Other income (expense) | 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 | ||||||||||||||||||
13
| Nine Months Ended September 30, 2002: |
Exploration & Production |
Gas Gathering, Marketing & Processing |
Oil Field Services |
All Other |
Elimination |
Consolidated | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Revenue from external customers | $ | 176,057 | $ | 13,634 | $ | 2,456 | $ | -- | $ | 192,147 | ||||||||||
| Intersegment revenues | 1,206 | 9,440 | 10,594 | -- | (21,240 | ) | -- | |||||||||||||
| Depreciation, depletion and amortization | 60,420 | 1,490 | 371 | 666 | 62,947 | |||||||||||||||
| Segment profit (loss) | 56,871 | 1,972 | 538 | (10,255 | ) | 49,126 | ||||||||||||||
| Equity in earnings of affiliates | 916 | 916 | ||||||||||||||||||
| Interest expense | (34,649 | ) | (34,649 | ) | ||||||||||||||||
| Costs associated with early retirement | ||||||||||||||||||||
| of debt | (1,000 | ) | (1,000 | ) | ||||||||||||||||
| Other income (expense) | (5,793 | ) | (5,793 | ) | ||||||||||||||||
| Income before income taxes | $ | 8,600 | ||||||||||||||||||
| Provision for income tax benefit | 3,843 | 3,843 | ||||||||||||||||||
| Net income | $ | 12,443 | ||||||||||||||||||
The company and its wholly-owned subsidiaries, except Canvasback, are direct guarantors of our 10% Senior Notes and 9.6% Senior Notes and have fully and unconditionally guaranteed these notes on a joint and several basis. In addition to not being a guarantor of the company’s 10% Senior Notes and 9.6% Senior Notes, Canvasback cannot be included in determining compliance with certain financial covenants under the company’s credit agreements. We have concluded that separate financial statements related to the guarantors are not included 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, 2003 and December 31, 2002, and for the three and nine month periods ended September 30, 2003 and 2002, was as follows:
| As of September 30, 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 | $ | 80,697 | $ | 12,777 | $ | (26,574 | ) | $ | 66,900 | |||||
| Property and equipment | ||||||||||||||
| (using full cost accounting) | 1,084,073 | 5,943 | -- | 1,090,016 | ||||||||||
| Investment in subsidiaries | ||||||||||||||
| (equity method) | 17,595 | -- | (17,595 | ) | -- | |||||||||
| Investment in Parent | -- | 38,974 | (38,974 | ) | -- | |||||||||
| Other assets | 68,816 | 565 | -- | 69,381 | ||||||||||
| Total assets | $ | 1,251,181 | $ | 58,259 | $ | (83,143 | ) | $ | 1,226,297 | |||||
| LIABILITIES AND STOCKHOLDERS' | ||||||||||||||
| EQUITY | ||||||||||||||
| Current liabilities | $ | 118,981 | $ | 26,576 | $ | (26,574 | ) | $ | 118,983 | |||||
| Long-term liabilities | 723,628 | 14,088 | (4,847 | ) | 732,869 | |||||||||
| Stockholders' equity | 408,572 | 17,595 | (51,722 | ) | 374,445 | |||||||||
| Total liabilities and stockholders' equity | $ | 1,251,181 | $ | 58,259 | $ | (83,143 | ) | $ | 1,226,297 | |||||
14
| As of December 31, 2002 | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Amounts in Thousands |
Magnum Hunter Resources, Inc. and Guarantor Subs |
Canvasback Energy, Inc. (Non Guarantor) |
Eliminations |
Magnum Hunter Resources, Inc. Consolidated | ||||||||||
| ASSETS | ||||||||||||||
| Current assets | $ | 110,461 | $ | 4,036 | $ | (16,524 | ) | $ | 97,973 | |||||
| Property and equipment | ||||||||||||||
| (using full cost accounting) | 994,766 | 6,843 | -- | 1,001,609 | ||||||||||
| Investment in subsidiaries | ||||||||||||||
| (equity method) | 15,650 | -- | (15,650 | ) | -- | |||||||||
| Investment in Parent | -- | 39,563 | (39,563 | ) | -- | |||||||||
| Other assets | 69,345 | 729 | -- | 70,074 | ||||||||||
| Total assets | $ | 1,190,222 | $ | 51,171 | $ | (71,737 | ) | $ | 1,169,656 | |||||
| LIABILITIES AND STOCKHOLDERS' | ||||||||||||||
| EQUITY | ||||||||||||||
| Current liabilities | $ | 128,969 | $ | 16,551 | $ | (16,524 | ) | $ | 128,996 | |||||
| Long-term liabilities | 682,028 | 18,970 | (10,534 | ) | 690,464 | |||||||||
| Stockholders' equity | 379,225 | 15,650 | (44,679 | ) | 350,196 | |||||||||
| Total liabilities and stockholders' equity | $ | 1,190,222 | $ | 51,171 | $ | (71,737 | ) | $ | 1,169,656 | |||||
| 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 | |||||
| For the Three Months Ended September 30, 2002 | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Amounts in Thousands |
Magnum Hunter Resources, Inc. and Guarantor Subs |
Canvasback Energy, Inc. (Non Guarantor) |
Eliminations |
Magnum Hunter Resources, Inc. Consolidated | ||||||||||
| Revenues | $ | 72,138 | $ | 695 | $ | -- | $ | 72,833 | ||||||
| Expenses | 68,199 | 215 | -- | 68,414 | ||||||||||
| Income before equity in net earnings of subsidiary | 3,939 | 480 | -- | 4,419 | ||||||||||
| Equity in net earnings of subsidiary | 298 | -- | (298 | ) | -- | |||||||||
| Income before income taxes | 4,237 | 480 | (298 | ) | 4,419 | |||||||||
| Income tax expense | (1,491 | ) | (182 | ) | -- | (1,673 | ) | |||||||
| Net income | $ | 2,746 | $ | 298 | $ | (298 | ) | $ | 2,746 | |||||
15
| 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, 2002 | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Amounts in Thousands |
Magnum Hunter Resources, Inc. and Guarantor Subs |
Canvasback Energy, Inc. (Non Guarantor) |
Eliminations |
Magnum Hunter Resources, Inc. Consolidated | ||||||||||
| Revenues | $ | 190,783 | $ | 1,364 | $ | -- | $ | 192,147 | ||||||
| Expenses | 183,070 | 477 | -- | 183,547 | ||||||||||
| Income before equity in net earnings of subsidiary | 7,713 | 887 | -- | 8,600 | ||||||||||
| Equity in net earnings of subsidiary | 551 | -- | (551 | ) | -- | |||||||||
| Income before income taxes | 8,264 | 887 | (551 | ) | 8,600 | |||||||||
| Income tax benefit (expense) | 4,179 | (336 | ) | -- | 3,843 | |||||||||
| Net income | $ | 12,443 | $ | 551 | $ | (551 | ) | $ | 12,443 | |||||
| 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 (decrease) 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 | |||||
16
| For the Nine Months Ended September 30, 2002 | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 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 | $ | 30,053 | $ | 9,224 | $ | -- | $ | 39,277 | ||||||
| Cash flow from investing activities | (82,633 | ) | (3,167 | ) | -- | (85,800 | ) | |||||||
| Cash flow from financing activities | 55,569 | (6,826 | ) | (329 | ) | 48,414 | ||||||||
| Net increase (decrease) in cash | 2,989 | (769 | ) | (329 | ) | 1,891 | ||||||||
| Cash at beginning of period | 730 | 2,025 | -- | 2,755 | ||||||||||
| Cash at end of period | $ | 3,719 | $ | 1,256 | $ | (329 | ) | $ | 4,646 | |||||
On October 1, 2003, we entered into a Letter Agreement to acquire an additional ownership interest in Metrix Networks, Inc., (“Metrix”), an internet-based field marketing service company, through the settlement of outstanding litigation in our favor as well as the conversion of our $325 thousand loan to Metrix into equity of the company. As a result of this settlement, we will increase our ownership of Metrix from approximately 32% to 80%. At September 30, 2003, our investment in Metrix was reflected as an investment in unconsolidated affiliate of $541 thousand.
17
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, 2002. 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, 2003, except for accounting for asset retirement obligations, accounting for gains and losses from extinguishment of debt, and accounting for stock-based compensation. SFAS No. 143, “Accounting for Asset Retirement Obligations,” became effective for us beginning January 1, 2003. SFAS No. 143 requires the recognition of a fair value liability for any retirement obligations associated with long-lived assets. The offset to any liability recorded is added to the recorded asset, and the additional amount is depreciated over the same period as the long-lived asset for which the retirement obligation is established. SFAS No. 145, “Recission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections,” was effective for us beginning January 1, 2003. SFAS No. 145 requires us to classify gains and losses from debt extinguishment as additional interest expense. In June 2003, effective January 1, 2003, we began expensing stock-based compensation expense 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 will be 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 period ended December 31, 2002.
During the first quarter of 2002, we merged with Prize Energy Corp. (“Prize”), an independent oil and gas development and production company based in Grapevine, Texas. The merger with Prize closed on March 15, 2002, but for operating and financial reporting purposes, was effective as of March 1, 2002. As such, the results for the three and nine month periods ended September 30, 2002 include three months and seven months of operating contributions from Prize, respectively.
Subsequent to the Prize merger, we have divested of approximately 85.8 billion cubic feet equivalent of non-strategic proved producing oil and gas reserves for total proceeds of approximately $110.6 million, net of purchase price adjustments. Almost all of the properties sold were acquired in the Prize merger, and the proceeds have been used to reduce our overall indebtedness and fund our capital expenditure program. The impact of these non-strategic divestitures are described below in our results of operations.
On July 29, 2003, we exercised our option to sell our 30% interest in NGTS, LLC (“NGTS”). We reduced the carrying value and recorded a charge to equity in earnings of affiliate by approximately $719 thousand at June 30, 2003, to state our investment at its estimated fair value. The sale closed on September 30, 2003, and we received proceeds of $5.2 million on that date, which were used to repay indebtedness. No gain or loss was recorded on the sale.
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. Fluctuations in oil and gas prices and commodity hedging activities have also significantly affected the results of operations.
18
The following table sets forth certain information with respect to our oil and gas operations and our gas gathering, marketing and processing operations:
| Three Months Ended September 30, |
Nine Months Ended September 30, | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Exploration and Production Operations |
2003 |
2002 |
2003 |
2002 | ||||||||||
| Reported Production: | ||||||||||||||
| Oil (Mbbls) | 961 | 1,100 | 2,918 | 2,902 | ||||||||||
| Gas (Mmcf) | 12,962 | 13,164 | 36,806 | 35,663 | ||||||||||
| Oil and Gas (Mmcfe) | 18,730 | 19,764 | 54,311 | 53,076 | ||||||||||
| Equivalent Daily Rate (Mmcfe/day) | 203.6 | 214.8 | 198.9 | 194.4 | ||||||||||
| Average Sale Prices (after hedging) | ||||||||||||||
| Oil (per Bbl) | $ | 26.34 | $ | 25.14 | $ | 26.68 | $ | 23.90 | ||||||
| Gas (per Mcf) | 3.68 | 2.94 | 3.62 | 2.99 | ||||||||||
| Oil and Gas (per Mcfe) | 3.90 | 3.36 | 3.89 | 3.32 | ||||||||||
| Effect of hedging activities (per Mcfe) | (0.81 | ) | (0.10 | ) | (1.14 | ) | 0.07 | |||||||
| Lease Operating Expense (per Mcfe) | ||||||||||||||
| Lifting costs | $ | 0.88 | $ | 0.71 | $ | 0.79 | $ | 0.73 | ||||||
| Production tax and other costs | 0.42 | 0.41 | 0.46 | 0.38 | ||||||||||
| Gross margin (per Mcfe) | $ | 2.60 | $ | 2.24 | $ | 2.64 | $ | 2.21 | ||||||
Gas Gathering, Marketing and Processing Operations | ||||||||||||||
Throughput Volumes (Mcf per day) | ||||||||||||||
| Gathering | 15,787 | 15,673 | 15,891 | 15,381 | ||||||||||
| Processing | 24,165 | 25,926 | 24,588 | 21,852 | ||||||||||
| Gross margin (in thousands) | $ | 2,243 | $ | 1,430 | $ | 7,255 | $ | 3,462 | ||||||
| Gathering (per Mcf throughput) | $ | 0.20 | $ | 0.17 | $ | 0.15 | $ | 0.14 | ||||||
| Processing (per Mcf throughput) | $ | 0.86 | $ | 0.49 | $ | 0.97 | $ | 0.44 | ||||||
We reported net income of $6.7 million for the three months ended September 30, 2003, as compared to net income of $2.7 million for the same period in 2002, an increase of 143%. Total operating revenues increased 13% to $82.6 million in 2003 from $72.8 million in 2002. Operating profit increased 13% to $21.2 million in 2003 from $18.8 million in 2002, and net income before income taxes increased 143% to $10.8 million in 2003 from $4.4 million in 2002. The growth in operating revenues and operating profit was generated across all of our business segments. The growth in pretax income was additionally impacted by a $701 thousand non-cash hedging adjustment gain in the 2003 period versus a $1.5 million loss recorded in the 2002 period, and a 15% reduction in interest expense to $11.5 million in the 2003 period from $13.5 million in the 2002 period. We recorded a 144% increase in deferred income tax expense of $4.1 million for the three months in 2003 versus $1.7 million for the same period in 2002, due to the increase in pre-tax income. Basic and diluted earnings per share were $0.10 in the 2003 period versus basic and diluted earnings per share of $0.04 in the 2002 period, a gain of 147%. 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 declined by 2% and 1%, respectively, in the 2003 period compared to the 2002 period, principally due to our stock repurchase program.
Exploration and Production Operations:
For the three months ended September 30, 2003, we reported oil production of approximately 961 thousand barrels and gas production of approximately 13.0 billion cubic feet, which represents a decrease of 13% in oil produced and a decrease of 2% in gas produced from the comparable period in 2002. Our reported equivalent daily rate of production, on a million cubic feet per day basis (Mmcfe/day), decreased 5% to 203.6 Mmcfe/day in the 2003 period from 214.8 Mmcfe/day in the 2002 period. These decreases were primarily the result of the sale of non-strategic oil and gas properties which occurred after the Prize acquisition, which closed in March 2002. These non-strategic property sales continued into September 2003. The impact of these property sales on reported production was a decrease of 29.1 Mmcfe/day in the three month period in 2003 compared to the similar period in 2002. Additionally, we experienced an interruption in our offshore Gulf of Mexico production in July 2003 due to bad weather. This interruption caused a reduction in our reported production of 2.7 Mmfce/day for the three month period in 2003.
19
Oil revenues decreased 8% to $25.3 million in the third quarter of 2003 compared to $27.6 million for the same period in 2002. The oil price received, after hedging effects, was $26.34 per Bbl in the 2003 period compared to $25.14 per Bbl in the 2002 period, an increase of 5%. Gas revenues increased 23% to $47.7 million in the third quarter of 2003 versus $38.7 million for the same period in 2002. The gas price received, after hedging effects, was $3.68 per Mcf in the 2003 period compared to $2.94 per Mcf for the same period in 2002, an increase of 25%. Total oil and gas revenues increased 11% to $73.4 million in 2003 from $66.4 million in 2002. The increase in oil and gas revenues is attributable to the increase in oil and gas prices, offsetting the production loss resulting from the sale of non-strategic oil and gas properties. We also recorded $399 thousand in income in the 2003 period from business interruption insurance proceeds resulting from claims filed in 2002 as a result of Hurricane Lili.
From time to time, we enter into various commodity hedging contracts in order to reduce our exposure to the possibility of declining oil and gas prices which provides a base level of cash flow to fund capital expenditures. During the 2003 period, hedging decreased the average price we received for oil by $2.74 per Bbl and decreased the average price we received for gas by $0.96 per Mcf. During the third quarter of 2003, we had approximately 10.0 Mmcf/day of gas hedged through fixed price swaps with a weighted average price of $3.65 per Mmbtu and approximately 70.0 Mmcf/day of gas hedged through cost-less collars with a weighted average floor price of $2.82 per Mmbtu and a weighted average ceiling price of $3.78 per Mmbtu. Approximately 57% of third quarter 2003 natural gas production was hedged. On the crude side, we had approximately 1,000 Bbls/day hedged through fixed price swaps with a weighted average price of $21.25 per barrel and approximately 6,000 Bbls/day hedged through cost-less collars with a weighted average floor price of $23.00 per Bbl and a weighted average ceiling price of $27.00 per Bbl. Approximately 67% of third quarter 2003 crude oil production was hedged. For the remainder of 2003, we have approximately 10.0 Mmcf/day hedged through fixed price swaps with a weighted average price of $3.65 per Mmbtu and approximately 70.0 Mmcf/day hedged through cost-less collars with a weighted average floor price of $2.82 per Mbtu and a weighted average ceiling price of $3.78 per Mmbtu. In addition, for the remainder of 2003, we have hedged 1,000 Bbls/day of crude oil production through a fixed price swap with a price of $21.25 per Bbl and 6,000 Bbls/day of crude oil production hedged through cost-less collars with a weighted average floor price of $23.00 per Bbl and a weighted average ceiling price of $27.00 per Bbl.
On May 1, 2003, we closed out 20,000 Mmbtu/day of natural gas collar hedges for the period June through December 2003. In closing these contracts, we locked in a $5.7 million loss, which will be recognized in earnings with the underlying forecasted commodity sales transactions for the months of June through December 2003. At September 30, 2003, the remaining balance was $2.6 million.
Lease operating expense consists of lifting costs and production taxes and other costs. For the 2003 period, lifting costs were $16.5 million versus $14.0 million in the 2002 period, an increase of 17%. Production taxes and other costs declined 2% to $8.0 million in the 2003 period from $8.1 million in the 2002 period. The increase in lifting costs was primarily attributable to higher costs for power and fuel and increased workover and remedial operations in the 2003 period compared to the 2002 period. For the 2003 period, lifting costs, on a unit of production basis, were $0.88 per Mcfe as compared to $0.71 per Mcfe in the 2002 period, an increase of 24%. Based on current production estimates, we expect lifting costs for the fourth quarter of 2003 to return to the range of $0.75 to $0.80 per Mcfe produced. Production taxes and other costs were $0.42 per Mcfe produced in the 2003 period compared to $0.41 per Mcfe produced in the 2002 period, an increase of 2%. The increase in production taxes per Mcfe produced was caused by an increase in crude oil and natural gas prices received during the 2003 period.
Our gross margin realized from exploration and production operations (oil and gas revenues less lease operating expenses) for the 2003 period was $49.0 million, or $2.60 per Mcfe, compared to $44.2 million, or $2.24 per Mcfe in the 2002 period, an increase of 16% on a per unit of production basis, as a result of a 16% increase in revenue per Mcfe produced, partially offset by a 16% increase in lease operating expense per Mcfe produced.
Depreciation, depletion, amortization and accretion of oil and gas properties was $25.8 million in the 2003 period versus $23.4 million in the 2002 period. The 2003 period included accretion expense related to asset retirement obligations (due to the adoption of SFAS No. 143) of $613 thousand. On a unit of production basis, depreciation and depletion expense (excluding accretion expense) was $1.35 per Mcfe produced in the 2003 period versus $1.18 per Mcfe produced in the 2002 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.
20
Segment profit for exploration and production operations was $23.1 million for the three months ended September 30, 2003 versus $20.8 million for the same period in 2002, an increase of 11%, principally due to higher realized crude oil and natural gas prices.
Gathering, Marketing and Processing Operations:
For the three months ended September 30, 2003, our gas gathering system throughput was 15.8 Mmcf/day versus 15.7 Mmcf/day for the same period in 2002, an increase of 1%, due to increased production from development drilling activities conducted by the company behind the gathering systems. Gas processing throughput was 24.2 Mmcf/day in 2003 versus 25.9 Mmcf/day in 2002, a decrease of 7%. This decrease is primarily due to the partial shutdown of one processing plant for most of one month in the 2003 period for scheduled maintenance on a products pipeline.
Revenues from gas gathering, marketing and processing increased 48% to $8.1 million in the 2003 period versus $5.5 million in the 2002 period. Operating costs for the gas gathering, marketing and processing segment increased 45% to $5.8 million in 2003 from $4.0 million in 2002. Both the revenues and operating cost increases were the result of higher natural gas and natural gas liquids prices.
The gross margin realized from gas gathering, marketing and processing for the 2003 period was $2.2 million versus $1.4 million in the 2002 period, an increase of 57%. The gas gathering margin was $0.20 per Mcf gathered in 2003 versus $0.17 per Mcf in 2002 due to higher gas marketing profits. The gas processing margin was $0.86 per Mcf in 2003 compared to $0.49 per Mcf in 2002, due to improved plant processing economics and higher plant product prices.
Depreciation expense for gas gathering, marketing and processing operations was basically unchanged for the 2003 period at $577 thousand versus $576 thousand for the same period in 2002.
Segment profit for gas gathering, marketing and processing operations was $1.7 million in the 2003 period versus $854 thousand for the 2002 period, an increase of 99%, principally due to higher throughput and improved processing economics at our natural gas processing plants.
Oil Field Management Services Operations:
Revenues from oil field management services increased 9% to $1.1 million in the third quarter of 2003 versus $1.0 million in the third quarter of 2002. This increase is primarily due to management fees charged to a partnership created in the third quarter of 2002, which provided three months of management income in 2003 as compared to one month in the 2002 period. This was partially offset by lower charges in 2003 allowed under our operating agreements. Operating costs decreased 1% to $724 thousand in 2003 from $728 thousand in 2002. The gross margin for this segment in 2003 was $386 thousand versus $285 thousand in 2002, an increase of 35%, due to increased revenues. Depreciation expense was $146 thousand in the 2003 period versus $133 thousand in the 2002 period, an increase of 10%, due to capital additions. Segment profit was $238 thousand for the three months in 2003 versus $152 thousand for the same period in 2002.
Other Income and Expenses:
Total depreciation, depletion, amortization and accretion expense was $26.7 million in the 2003 period versus $24.3 million in the 2002 period, an increase of 10%. This is primarily the result of the increased depletion and accretion rates in our exploration and production segment.
General and administrative expense for the 2003 period increased 31% to $3.8 million from $2.9 million in the 2002 period. The principal reason for this increase was the $1.3 million cost of expensing employee stock options recorded in the 2003 period as a result of the adoption of SFAS No. 123 in June 2003, with an effective date of January 1, 2003. We recorded equity in earnings of affiliate of $173 thousand in the 2003 period versus earnings of $534 thousand in the 2002 period. This decrease was mainly due to equity in lower earnings generated by NGTS. Other income was $231 thousand for the 2003 period versus $93 thousand in the 2002 period, caused by an increase in interest income. The company recognized a $701 thousand gain in other non-cash hedging adjustments in the 2003 period versus a $1.5 million loss in the 2002 period. In the 2003 period, $324 thousand of the hedging gain relates to the amortization of commodity hedge assets acquired in the Prize merger, while a gain of $377 thousand was due to recording hedge ineffectiveness.
21
We incurred costs associated with the early retirement of debt of $19 thousand in the three months of 2003 versus none in the same period of 2002. The 2003 period costs were associated with Canvasback’s purchase of $381 thousand in principal of our 10% Senior Notes in August 2003 at 103.75% of par.
Interest expense was $11.5 million for the 2003 period versus $13.5 million for the 2002 period, as a result of a decrease in our 10% Senior Notes outstanding and lower interest rates on our Senior Bank Credit Facility (the “Facility”). Our weighted average interest rate paid under our Facility was 3.4% in the 2003 period versus 4.0% in the 2002 period.
The effective tax rate was 38% for the three months ended September 30, 2003 and 2002. The variance from the statutory rate of 35% was primarily due to state income taxes.
We reported net income of $18.8 million for the nine months ended September 30, 2003, as compared to net income of $12.4 million for the same period in 2002, an increase of 51%. Total operating revenues increased 25% to $241.1 million in 2003 from $192.1 million in 2002. Operating profit increased 39% to $68.5 million in 2003 from $49.1 million in 2002, and net income before income tax and cumulative effect of a change in accounting principle increased 246% to $29.8 million in 2003 from $8.6 million in 2002, due primarily to the Prize merger and increases in crude oil, natural gas, and natural gas liquids prices in the 2003 period compared to the 2002 period. We recorded deferred income tax expense of $11.3 million for the nine months of 2003 versus a deferred tax benefit of $3.8 million for the same period in 2002. The 2002 period income tax benefit resulted from the elimination of the $7.1 million valuation allowance that had been carried against deferred tax assets derived from net operating loss carryovers generated by Magnum Hunter in prior years. As a result of the Prize merger, we believe that this tax asset can be fully realized. Additionally, the 2003 period includes the cumulative effect on prior years of a change in accounting principle due to the adoption of SFAS No. 143 relating to asset retirement obligations. The cumulative effect was a gain of $399 thousand, net of income tax expense of $244 thousand, or $0.01 per share, both basic and diluted. Basic and diluted earnings per share were $0.28 in the 2003 period versus basic and diluted earnings per share of $0.21 in the 2002 period. Basic and diluted shares outstanding increased 11% in the 2003 period primarily as a result of new shares issued in the Prize merger. The change in basic and diluted earnings per share was a result of increased net income reduced by the effect of an increase in total shares outstanding.
Exploration and Production Operations:
For the nine months ended September 30, 2003, we reported oil production of approximately 2.9 million barrels and gas production of approximately 36.8 billion cubic feet, which represents no change in oil produced and an increase of 3% in gas produced from the 35.7 billion cubic feet of gas reported in the comparable period during 2002. Our reported equivalent daily rate of production on a million cubic feet per day basis (Mmcfe/day) increased 2% to 198.9 Mmcfe/day in the 2003 period from 194.4 Mmcfe/day in the 2002 period. These increases were primarily the result of the merger with Prize and the success of our drilling program offsetting both normal production declines and the sale of non-strategic oil and gas properties subsequent to the Prize merger. The impact of these non-strategic property sales on reported production was a decrease of 23.5 Mmcfe/day in the 2003 period compared to the 2002 period. The 2003 period was also impacted by bad weather in the Gulf of Mexico during the month of July 2003, resulting in lowered production of approximately 900 Mcfe/day for the nine month period.
Oil revenues increased 12% to $77.9 million in the nine months of 2003 compared to $69.4 million for the same period in 2002. The oil price received, after hedging effects, was $26.68 per Bbl in the 2003 period compared to $23.90 per Bbl for the same period in 2002, an increase of 12%. Gas revenues increased 25% to $133.2 million in the nine months of 2003 versus $106.7 million for the same period in 2002. The gas price received, after hedging effects, was $3.62 per Mcf in the 2003 period compared to $2.99 per Mcf for the same period in 2002, an increase of 21%. We also recorded $399 thousand in oil and gas sales in the 2003 period from business interruption insurance proceeds resulting from claims filed in 2002 due to Hurricane Lili.
22
From time to time, we enter into various commodity hedging contracts in order to reduce our exposure to the possibility of declining oil and gas prices which provides a base level of cash flow to fund capital expenditures. During the 2003 period, hedging decreased the average price we received for oil by $3.16 per Bbl and decreased the average price we received for gas by $1.43 per Mcf. During the 2003 period, we had approximately 43.2 Mmcf/day of gas hedged through fixed price swaps with a weighted average price of $3.06 per Mmbtu and approximately 50.1 Mmcf/day of gas hedged through cost-less collars with a weighted average floor price of $2.95 per Mmbtu and a weighted average ceiling price of $4.06 per Mmbtu. Approximately 69% of the nine months of 2003 natural gas production was hedged. On the crude side, we had approximately 1,000 Bbls/day hedged through fixed price swaps with a weighted average price of $21.25 per barrel and approximately 7,000 Bbls/day hedged through cost-less collars with a weighted average floor price of $23.00 per Bbl and a weighted average ceiling price of $27.00 per Bbl. Approximately 65% of the nine months of 2003 crude oil production was hedged. For the remainder of 2003, we have approximately 10.0 Mmcf/day hedged through fixed price swaps with a weighted average price of $3.65 per Mmbtu and approximately 70.0 Mmcf/day hedged through cost-less collars with a weighted average floor price of $2.82 per Mmbtu and a weighted average ceiling price of $3.78 per Mmbtu. In addition, for the remainder of 2003, we have hedged 1,000 Bbls/day of crude oil production through a fixed price swap with a price of $21.25 per Bbl and 7,000 Bbls/day of crude oil production through cost-less collars with a weighted average floor price of $23.00 per Bbl and a weighted average ceiling price of $27.00 per Bbl.
On May 1, 2003, we closed out 20,000 Mmbtu/day of natural gas collar hedges for the period of June through December 2003. In closing these contracts, we locked in a $5.7 million loss which will be recognized in earnings with the underlying forecasted commodity sales transactions for the months of June through December 2003. At September 30, 2003, the remaining balance was $2.6 million.
Lease operating expense consists of lifting costs and production taxes and other costs. For the 2003 period, lifting costs were $42.9 million versus $38.4 million in the 2002 period, an increase of 12%. Production taxes and other costs were $25.1 million in the 2003 period versus $20.3 million in the 2002 period, an increase of 23%. Both increases were primarily attributable to the Prize merger. For the 2003 period, lifting costs, on a unit of production basis, were $0.79 per Mcfe as compared to $0.73 per Mcfe in the 2002 period, an increase of 8%. The increase in lifting costs per Mcfe produced in the 2003 period was due to higher power and fuel costs and increased remedial and workover expense. Production taxes and other costs were $0.46 per Mcfe produced in the 2003 period compared to $0.38 per Mcfe produced in the 2002 period, an increase of 21%. The increase in production taxes per Mcfe produced was caused by an increase in crude oil and natural gas prices received during the 2003 period.
Our gross margin realized from exploration and production operations (oil and gas revenues less lease operating expenses) for the nine months of 2003 was $143.5 million, or $2.64 per Mcfe, compared to $117.3 million, or $2.21 per Mcfe in the 2002 period, an increase of 19% on a per unit of production basis. This is the result of a 17% increase in revenue per Mcfe produced, partially offset by a 13% increase in lease operating expense per Mcfe produced.
Depreciation, depletion, amortization and accretion of oil and gas properties was $70.5 million in the nine months of 2003 versus $60.4 million in 2002. The 2003 period included accretion expense related to asset retirement obligations (due to the adoption of SFAS No. 143) of $1.9 million. On a unit of production basis, depreciation and depletion expense (excluding accretion expense) was $1.26 per Mcfe produced in the 2003 period versus $1.14 per Mcfe produced in the 2002 period. This 11% increase in the equivalent unit cost was due primarily to an increase in development costs and shorter reserve life properties associated with our activities in the Gulf of Mexico.
Segment profit for exploration and production operations was $72.9 million for the first nine months of 2003 versus $56.9 million for the same period in 2002, an increase of 28%, primarily due to properties acquired in the Prize merger and to higher crude oil and natural gas prices realized.
Gathering, Marketing and Processing Operations:
For the nine months ended September 30, 2003, our gas gathering system throughput was 15.9 Mmcf/day versus 15.4 Mmcf/day for the same period in 2002, an increase of 3%, due to increased production from development drilling activities conducted by the company behind the gathering systems. Gas processing throughput was 24.6 Mmcf/day in the 2003 period versus 21.9 Mmcf/day in the 2002 period, an increase of 13%. This increase is primarily due to the acquisition of the 100% owned interest in the Elmore City processing plant as a result of the Prize merger.
23
Revenues from gas gathering, marketing and processing increased 94% to $26.5 million in the 2003 period versus $13.6 million in the 2002 period. Operating costs for the gas gathering, marketing and processing segment increased 89% to $19.3 million in 2003 from $10.2 million in 2002. Both the revenues and operating cost increases were the result of increased gas processing throughput and higher natural gas and natural gas liquids prices.
The gross margin realized from gas gathering, marketing and processing operations for the 2003 period was $7.3 million versus $3.5 million in the 2002 period, an increase of 110%. The gas gathering margin was $0.15 per Mcf gathered in 2003 versus $0.14 in 2002, an increase of 5%. The gas processing margin increased 123% to $0.97 per Mcf in 2003 compared to $0.44 per Mcf in 2002, due to the addition of the Elmore City plant, improved plant processing economics and higher natural gas and natural gas liquids prices realized.
Depreciation expense for gas gathering, marketing and processing operations for the 2003 period was $1.7 million versus $1.5 million for the same period in 2002, an increase of 13%, due to the addition of the Elmore City plant from the Prize merger.
Segment profit for gas gathering, marketing and processing operations was $5.5 million in the nine months of 2003 versus $2.0 million for the same period in 2002, an increase of 175%, principally due to assets acquired in the Prize merger, improved natural gas processing economics and higher natural gas and natural gas liquids prices realized.
Oil Field Management Services Operations:
Revenues from oil field management services increased 26% to $3.1 million in the 2003 period versus $2.5 million in the 2002 period. This increase is primarily due to an increase in the number of properties operated as a result of the Prize merger as well as management fees charged to a partnership created in the third quarter of 2002, which provided nine months of management income in the 2003 period, as compared to one month in the 2002 period. These increases were partially offset by a decrease in charges allowed under our operating agreements in 2003. Operating costs increased 41% to $2.2 million in the 2003 period from $1.5 million in the 2002 period, also due to costs associated with the Prize merger. The gross margin for this segment in the 2003 period was $928 thousand versus $909 thousand in the 2002 period, an increase of 2%, due to higher revenues. Depreciation expense was $441 thousand in the 2003 period versus $371 thousand in the 2002 period, an increase of 19% due to capital additions. Segment profit was $486 thousand for the 2003 period versus $538 thousand for the same period in 2002.
Other Income and Expenses:
Total depreciation, depletion, amortization and accretion expense was $73.2 million in the 2003 period versus $62.9 million in the 2002 period, an increase of 16%, primarily as a result of increased production due to the Prize merger.
General and administrative expense for the 2003 period increased 5% to $10.1 million from $9.6 million in the 2002 period. The 2003 period increase is primarily due to the recording of $1.7 million of expense due to employee stock options as the result of adopting SFAS No. 123 in June 2003, with an effective date of January 1, 2003. We recorded equity in losses of affiliate of $64 thousand in the 2003 period versus earnings of $916 thousand in the 2002 period, principally due to the reduction of the carrying value of our investment in NGTS by $719 thousand to state it at its estimated fair value as well as our equity in losses generated by Metrix Networks, Inc. in 2003. Other income was $609 thousand for the 2003 period versus $258 thousand in the 2002 period, caused by an increase in interest income due to five months of interest earned on a note receivable issued during 2002 versus nine months in 2003. The company recognized a $1.2 million gain in other non-cash hedging adjustments in 2003 versus a $5.4 million loss in 2002. In the 2003 period, $972 thousand of the hedging gain relates to the amortization of commodity hedge assets acquired in conjunction with the Prize merger, while a gain of $265 thousand was due to recording hedge ineffectiveness.
We incurred costs associated with the early retirement of debt of $4.1 million during the nine months of 2003 versus $1.0 million in the same period of 2002. The 2003 period costs were associated with the $30 million and $50 million redemption of our 10% Senior Notes at 105% of par and 103.333% of par in January and June 2003, respectively, as well as Canvasback’s August 2003 purchase of $381 thousand of our 10% Senior Notes at 103.75% of par. The 2002 period costs were associated with the amendment of our Facility in connection with the Prize merger.
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Interest expense was $36.4 million for the 2003 period versus $34.6 million for the 2002 period, an increase of 5%, principally due to the placement of $300 million of 9.6% Senior Notes in March 2002 as a result of the Prize merger. Our weighted average interest rate paid under our Facility was reduced to 3.4% in the 2003 period from 4.1% in the 2002 period.
The effective tax rate was 38% and (45)% for the nine months ended September 30, 2003 and 2002, respectively. The variance from the statutory rate of 35% was primarily due to state income taxes in the 2003 period and to the release of the $7.1 million valuation allowance on previously reserved deferred tax assets in the 2002 period.
CASH FLOW AND WORKING CAPITAL. Net cash provided by operating activities for the nine month periods in 2003 and 2002 was $143.8 million and $39.3 million, respectively. The substantial increase in our operating cash flows in 2003 over 2002 was primarily the result of large payments we made in the first quarter of 2002 related to trade payables which had accumulated at year-end as well as current liabilities acquired in the merger with Prize. We also benefited in the 2003 period from the return of $8.9 million in margins we had been required to post during 2002 on certain commodity hedge positions obtained in the Prize merger and another $7.9 million received in net state and federal tax refunds. We also generated increased cash flows as a result of our higher net income when adjusted for non-cash charges. See our period to period comparisons above for further information on these income items. Our net working capital position at September 30, 2003, was a deficit of $52.1 million. On that date, we had $98 million available to be drawn under our $300 million Facility. A large factor in our working capital deficit at September 30, 2003 is our current derivative liability of $18 million, partially offset by current deferred tax assets of $6.8 million, which we have recorded on our hedged positions for the next twelve months due to continued increases in commodities prices over our hedged prices. If actual commodities prices realized remain higher than our hedged prices on these positions, our resulting higher cash proceeds received on our production will offset any actual amounts paid out related to these liabilities.
INVESTING ACTIVITIES. Net cash used in investing activities was $123.5 million in the 2003 nine month period. We made capital expenditures of $144.2 million under our capital budget during 2003. Our capital expenditures are discussed in further detail below. For 2003, we also received proceeds from the sales of property and equipment of $14.6 million, net of certain purchase price adjustments related to both 2002 and 2003 divestitures, received $5.2 million from the sale of NGTS, invested $600 thousand in NGTS and received distributions of earnings from NGTS of $1.5 million.
In the 2002 nine month period, net cash used in investing activities was $85.8 million. We made cash expenditures of $98.2 million under our capital budget during 2002. Additionally, during 2002, we made a loan of $2.4 million to an affiliate, received proceeds from sale of assets of $56.6 million, made investments in an unconsolidated affiliate of $765 thousand, received distributions of $161 thousand from an unconsolidated affiliate, and used $41.1 million in association with the Prize merger.
FINANCING ACTIVITIES. Net cash used in financing activities was $21.2 million in the 2003 nine month period. We borrowed a total of $320 million, of which we repaid $253 million. We paid $456 thousand in fees related to the amended Senior Bank credit facility, loaned $2.7 million to the KSOP to purchase shares for the plan, purchased treasury stock for $7.4 million, made a loan to an unconsolidated affiliate of $225 thousand, had an increase in restricted cash of $227 thousand, purchased common stock for our deferred compensation plan of $295 thousand, paid $77.3 million (net of Canvasback redemption) to redeem $80.4 million in principal of our 10% Senior Notes, received a repayment on our loan to the KSOP of $296 thousand, and received net proceeds from the issuance of common stock of $215 thousand. Our financing activities are discussed in further detail below.
Net cash provided by financing activities was $48.4 million for the nine months in 2002. We borrowed a total of $610.7 million, including $300 million in new 9.6% Senior Notes during the period. We also repaid borrowings of $534.5 million, including $155.7 million to pay off the company’s previous bank credit facility, $245.8 million to pay off the Prize bank credit facility in connection with the merger, and the remainder to pay other indebtedness. We paid $11.9 million in fees related to the newly issued 9.6% Senior Notes and the new Facility, loaned $2.7 million to the KSOP, purchased treasury stock for $14.2 million, purchased warrants for $98 thousand, made a loan to a stockholder and executive officer for $300 thousand, received payment on a loan to a stockholder and executive officer of $300 thousand, had an increase in restricted cash of $329 thousand, and had net proceeds from the issuance of common stock of $1.4 million. Our financing activities are discussed in further detail below.
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.
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We amended our Facility in May 2003. The amended Facility provides for total borrowings of $300 million, up $50 million from the prior $250 million borrowing base. Additionally, the expiration date of the Facility was extended to May 2, 2006. The increase in borrowing capacity was used to retire an additional $50 million of our 10% Senior Notes at 103.333% of par plus accrued interest, or approximately $51.7 million on June 2, 2003. At September 30, 2003, we had $98 million available under this Facility.
We amended our Facility again on October 31, 2003 in conjunction with our semi-annual borrowing base redetermination. Under the amended Facility, we are allowed total borrowings of $350 million, up $50 million from the previous $300 million. We will use the increased borrowing capacity to fund the redemption of our $55.2 million (net of $4.8 million held by Canvasback) 10% Senior Notes at 103.333% of par plus accrued interest. The redemption will take place on December 3, 2003.
During the nine months of 2003, we sold certain oil and gas properties considered to be non-strategic assets for $14.6 million, subject to certain purchase price adjustments. We also realized $5.2 million in proceeds from the sale of our equity interest in NGTS. Proceeds from both of these sales were used to reduce indebtedness.
On March 7, 2002, Canvasback entered into a $10.0 million revolving credit agreement with a financial institution. This loan is collateralized by our 10% Senior Notes that Canvasback owns. During 2002, this revolving loan was converted into a $7 million term loan. The proceeds of $6.1 million received by Canvasback as a result of the bond redemptions were used to reduce the outstanding balance to $932 thousand. In July 2003, Canvasback amended its term loan to allow for additional advances of up to $5 million for the purpose of additional repurchases of our 10% Senior Notes. The maturity date was also extended to May 31, 2005. In conjunction with the upcoming December 3, 2003 redemption of our outstanding 10% Senior Notes, this loan will be paid in full. At that time, we will determine whether this credit agreement will be kept in place.
On August 8, 2003, Canvasback purchased $381 thousand in principal of our 10% Senior Notes at 103.75% of par.
On May 1, 2002, our Board of Directors announced an expansion of our existing stock repurchase program originally established in June 2001. The company or our affiliates were authorized to repurchase up to two million shares of our common stock. On October 17, 2002, our Board of Directors approved a new three million share repurchase program. Approximately 4.2 million shares have been purchased through September 30, 2003 under these programs, and approximately 818 thousand shares remain authorized for repurchase.
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. The last redetermination date had an effective date of June 30, 2003 and was completed on October 31, 2003. As a result of the redetermination, our borrowing base has been increased by $50 million, up to $350 million from $300 million. The next redetermination date will have an effective date of December 31, 2003 and will have an estimated completion date of May 31, 2003.
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 regardless of 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 2003.
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CAPITAL EXPENDITURES. During the nine month period in 2003, our total capital expenditures were $144.2 million. Our management intentionally “front end” loaded the 2003 budget in an effort to capture lower field service costs and anticipated higher commodity prices. Exploration activities accounted for $29.4 million, development activities accounted for $100.3 million, unproved property acquisitions accounted for $11.5 million, proved property acquisitions accounted for $2.3 million, and additions to other assets accounted for $735 thousand of the capital expenditures. We participated in the drilling of 98 wells during the 2003 period, of which 92 were deemed commercial, for a 94% overall success rate. Of the 98 wells drilled, 17 were exploratory wells, of which 11 were successful, and 81 were development wells, all of which were successful. As of September 30, 2003, we had total unproved oil and gas property costs of $181.6 million.
On September 24, 2003, our Board of Directors increased our capital budget to $165 million for calendar year 2003. 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, and changes in oil and gas prices. As a result, actual capital expenditures may vary significantly from current expectations. 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.
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.
All forward-looking statements attributable to Magnum Hunter Resources, Inc. are expressly qualified in their entirety by this cautionary statement.
During the 2003 period, we experienced substantial increases in the price for oil, gas, and natural gas liquids compared to the same period in the previous year. The results of operations and cash flow of the company have been, and will continue to be, affected by the volatility in commodity prices. Should the company experience a significant increase in commodity 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. Periodically, the company enters into futures, options, and swap contracts to reduce the effects of fluctuations in commodity prices. As mandated by our Board of Directors, at inception, commodity hedge positions may not exceed 75% of the natural gas and 90% of the 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%. A portion of our oil and natural gas production will be subject to price fluctuations unless we enter into additional hedging transactions. For the remainder of 2003, we have approximately 60% of our forecasted combined crude oil and natural gas production hedged. Unhedged portions of our natural gas and crude oil production will be subject to market price fluctuations.
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We market oil, gas, and natural gas liquids for our own account, which exposes us to the attendant commodities risk. Our gas and natural gas liquids production is currently sold either on the spot market on a month-to-month basis at prevailing spot market prices, or 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.
SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as extended by SFAS No. 137 (June 1999) and amended by SFAS No. 138 (June 2000), was effective for the company beginning January 2001. SFAS No. 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It requires the recognition of derivatives in the balance sheet and the measurement of those instruments at fair value.
We were obligated to eleven crude oil derivatives and thirteen natural gas derivatives on September 30, 2003. 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 to other comprehensive income. Hedge ineffectiveness on cash-flow hedges is recorded in earnings.
At September 30, 2003, the fair value of the company’s derivatives were as follows (in thousands):
| Derivative Assets | |||||
| Crude oil collars | $ | 96 | |||
| Total derivative assets | $ | 96 | |||
| Derivative Liabilities | |||||
| Natural gas collars | $ | 16,722 | |||
| Natural gas swaps | 1,235 | ||||
| Crude oil collars | 2,164 | ||||
| Crude oil swaps | 800 | ||||
| Total derivative liabilities | $ | 20,921 | |||
| Net derivative liabilities | $ | 20,825 | |||
The $96 thousand derivative asset is included in other current assets. Of the $20.9 million derivative liability, $17.9 million is classified as a current liability on our condensed consolidated balance sheet at September 30, 2003.
For the three and nine month periods ended September 30, 2003, the statement of operations includes a non-cash hedging ineffectiveness gain of $377 thousand and $265 thousand, respectively, related to the crude oil and natural gas derivatives. Additionally, during this similar period, our statement of operations includes a non-cash gain of $324 thousand and $972 thousand, respectively, related to the amortization of hedge contracts acquired in the Prize merger. The remaining amortization amounts relating to hedge contracts acquired in the Prize merger that will be reclassified into the operations statement in years 2003 and 2004 are a $324 thousand gain and $792 thousand gain, respectively. It is estimated at this time that $12.0 million of other comprehensive loss will be reclassified into the income statement during the next 12 months.
On May 1, 2003, we closed out 20,000 Mmbtu/d of natural gas collar hedges for the period June through December 2003. In closing these contracts, we locked in a $5.7 million loss, which will be recognized in earnings with the underlying forecasted commodity sales transactions for the months of June through December 2003. At September 30, 2003, the remaining balance was $2.6 million.
Statement of Financial Accounting Standards (“SFAS”) No. 143 — SFAS No. 143, “Accounting for Asset Retirement Obligations,” became effective beginning January 1, 2003. SFAS No. 143 requires the recognition of a fair value liability for any retirement obligation associated with long-lived assets in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset and depreciated over the asset’s useful life. Upon adoption of SFAS No. 143, we recorded an addition to oil and gas properties of $25.4 million, an asset retirement obligation of $30.4 million, a reduction of accumulated depletion of $5.6 million, and a pre-tax gain of $643 thousand.
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SFAS No. 145 — SFAS No. 145, “Recission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections,” became effective beginning January 1, 2003. The Statement rescinds, updates, clarifies and simplifies various existing accounting pronouncements. SFAS No. 145 rescinds SFAS No. 4, “Reporting Gains and Losses from Extinguishment of Debt,” which required all gains and losses from extinguishment of debt to be aggregated and, if material, classified as an extraordinary item, net of related income tax effect. As a result, SFAS No. 145 requires us to reclassify as additional expense extraordinary items for debt extinguishment costs which did not meet the criteria as described in APB Opinion No. 30 “Reporting the Results of Operations — Reporting the Effects of Disposal of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions.” As a result, for the nine months ended September 30, 2003, we reclassified our $621 thousand extraordinary loss as costs associated with early retirement of debt of $1.0 million and increased our deferred income tax benefit by $379 thousand.
SFAS No. 146 — In July 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS No. 146 requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. SFAS No. 146 supercedes EITF Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” Statement 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002.
SFAS No. 148 – The FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure, an Amendment to FASB Statement No. 123,” in December 2002. SFAS No. 148 provides alternative methods of transition for a voluntary change to the fair value method of accounting for stock-based employee compensation and amends the disclosure requirements of SFAS No. 123. On 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 nine months ended September 30, 2003, we recorded stock compensation expense of $1.7 million, which is reflected in our general and administrative expenses. 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.
If we had recorded stock option expense under the fair value provisions of SFAS No. 123 for all grants, our net income and EPS would have been as shown in the below pro forma tables (in thousands):
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| Three Months Ended September 30, |
Nine Months Ended September 30, | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2003 |
2002 |
2003 |
2002 | |||||||||||
| Net income, as reported | $ | 6,669 | $ | 2,746 | $ | 18,829 | $ | 12,443 | ||||||
| Total Stock-based employee compensation expense | ||||||||||||||
| included in reported net income, net of related | ||||||||||||||
| tax effects | 804 | -- | 1,073 | -- | ||||||||||
| Deduct: Total stock-based employee compensation | ||||||||||||||
| determined under fair value-based method for all | ||||||||||||||
| awards, net of related tax effects | (1,526 | ) | (1,239 | ) | (3,188 | ) | (2,597 | ) | ||||||
| Pro forma net income | $ | 5,947 | $ | 1,507 | $ | 16,714 | $ | 9,846 | ||||||
| Earnings per share: | ||||||||||||||
| Basic - as reported | $ | 0.10 | $ | 0.04 | $ | 0.28 | $ | 0.21 | ||||||
| Basic - pro forma | $ | 0.09 | $ | 0.02 | $ | 0.25 | $ | 0.17 | ||||||
| Diluted - as reported | $ | 0.10 | $ | 0.04 | $ | 0.28 | $ | 0.21 | ||||||
| Diluted - pro forma | $ | 0.09 | $ | 0.02 | $ | 0.25 | $ | 0.16 | ||||||
FIN No. 45 – FIN No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees,” was issued in November 2002. This interpretation addresses the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees. It also clarifies the requirements related to the recognition of a liability by a guarantor at the inception of a guarantee for the obligations the guarantor has undertaken in issuing that guarantee. We adopted this statement in January 2003.
In the past, we have provided trade guarantees on behalf of NGTS. The last of these guarantees expired in July 2003. Further, we have sold our 30% ownership interest in NGTS, and, therefore, no longer maintain any equity interest in this affiliate. We have provided no other guarantees on behalf of any unconsolidated entities and do not intend to issue any at this time.
FIN No. 46 – FIN No. 46, “Consolidation of Variable Interest Entities.” FIN No. 46 addresses consolidation by business enterprises of variable interest entities with certain defined characteristics. This interpretation applies to the first fiscal year or interim period ending after December 15, 2003, to variable interest entities created or obtained before February 1, 2003. For variable interest entities created after January 31, 2003, the consolidation provisions apply immediately. We do not have any variable interest entities that would be subject to these provisions and, accordingly, FIN 46 will not have an impact on our financial statements.
In June 2001, FASB issued 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 has been raised regarding whether these mineral rights should be classified as tangible or intangible assets. If it is determined that reclassification is necessary, we would have reduced our proven properties by $352.7 million, decreased unproved properties by $154.5 million and reported intangible mineral rights related to proved properties of $352.7 million and intangible mineral rights related to unproved properties of $154.5 million at December 31, 2002. At September 30, 2003, we would have reduced our proven properties by $336.2 million, reduced our unproved properties by $166 million, and reported intangible mineral rights related to proved properties of $336.2 million and intangible mineral rights related to unproved properties of $166 million. These reclassifications represent the cost of acquiring proved and unproved mineral use rights from the effective date of June 30, 2001. The provisions of SFAS No. 141 and SFAS No. 142 impact only the balance sheet and any associated footnote disclosures. Any reclassifications potentially required would not impact our cash flows or statements of income.
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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 Swaps and Options
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 (“Swap Agreements”). The primary objective of these activities is to protect against significant decreases in price during the term of the hedge.
The Swap 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”). We have contracts which contain specific contracted prices (“Swaps”) that are settled monthly based on the differences between the contract prices and the specified Index prices for each month applied to the related contract volumes. To the extent the Index exceeds the contract price, we pay the spread, and to the extent the contract price exceeds the Index price, we receive the spread. In addition, we have combined option contracts that have agreed upon price floors and ceilings (“Costless 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.
We are contractually obligated to a counter-party to provide a margin deposit in the form of cash or bank letter of credit should the aggregate fair value of hedge contracts held with the counter-party exceed a predetermined value. We had no margins posted at September 30, 2003.
The following is a summary of the company’s open commodity hedge contracts as of September 30, 2003:
| Commodity |
Type |
Volume/Day |
Duration |
Weighted Average Price |
|---|---|---|---|---|
| Natural Gas | Swap | 10,000 MMBTU | Oct 03 - Dec 03 | $ 3.65 |
| Natural Gas | Collar | 70,000 MMBTU | Oct 03 - Dec 03 | $2.82 - $3.78 |
| Natural Gas | Collar | 55,000 MMBTU | Jan 04 - Dec 04 | $3.64 - $4.93 |
| Crude Oil | Swap | 1,000 BBL | Oct 03 - Dec 03 | $ 21.25 |
| Crude Oil | Collar | 6,000 BBL | Oct 03 - Dec 03 | $23.00 - $27.00 |
| Crude Oil | Collar | 5,000 BBL | Jan 04 - Jun 04 | $23.40 - $29.20 |
| Crude Oil | Collar | 3,000 BBL | Jul 04 - Dec 04 | $23.00 - $27.33 |
Based on future market prices at September 30, 2003, the fair value of open commodity hedging contracts was a liability of $20.8 million. If future market prices were to increase 10% from those in effect at September 30, 2003, the fair value of open contracts would be a liability of $34.7 million. If future market prices were to decline 10% from those in effect at September 30, 2003, the fair value of the open contracts would be a liability of $7.8 million.
At inception, 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%. Unhedged portions of our natural gas and crude oil production will be subject to market price fluctuations.
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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. 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, which are valued at their last traded value before September 30, 2003.
| Expected Maturity Dates |
2003 |
2004-6 |
2007 |
2012 |
Total |
Fair Value | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (in thousands of dollars) | ||||||||||||||||||||
| Variable Rate Debt: | ||||||||||||||||||||
| Bank Debt with Recourse (a) | $ | -- | $ | 199,500 | $ | -- | $ | -- | $ | 199,500 | $ | 199,500 | ||||||||
| Bank Debt without Recourse (b) | -- | 932 | -- | -- | 932 | 932 | ||||||||||||||
| Capital Leases (c) | 394 | 5,331 | 2,172 | -- | 7,897 | 7,897 | ||||||||||||||
| Fixed Rate Debt: | ||||||||||||||||||||
| Senior Notes (d) | -- | -- | 55,153 | -- | 55,153 | 57,014 | ||||||||||||||
| Senior Notes (e) | -- | -- | -- | 300,000 | 300,000 | 332,250 | ||||||||||||||
| Other | 29 | -- | -- | -- | 29 | 29 | ||||||||||||||
(a) The average interest rate on the bank debt with recourse is 2.966%. (b) The average interest rate on the bank debt without recourse is 5.62%. (c) The average interest rate on the two capital leases is 4.6059%. (d) The interest rate on the senior notes due 2007 is a fixed 10%. (e) The interest rate on the senior notes due 2012 is a fixed 9.6%.
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 reasonably adequate 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. There were no significant deficiencies or material weaknesses and, therefore, no corrective actions were taken.
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(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 | By-Laws, as Amended (Incorporated by reference to Registration Statement on Form SB-2, File No. 33-66190) | ||||
| 3.7&4.7 | Amendment to By-Laws (Incorporated by reference to Registration Statement on Form S-4, File No. 333-76774) | ||||
| 3.8&4.8 | Certificate of Designation of 1996 Series A Preferred Stock (Incorporated by reference to Form 8-K dated December 26, 1996, filed January 3, 1997) | ||||
| 3.9&4.9 | Amendment to Certificate of Designations for 1996 Series A Convertible Preferred Stock (Incorporated by reference to Registration Statement on Form S-3, File No. 333-30453) | ||||
| 4.10 | 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) | ||||
| 4.11 | Form of Warrant Agreement by and between Midland Resources, Inc. and Stock Transfer Company of America, Inc., as warrant agent, dated November 1, 1990 (Incorporated by reference to Registration Statement on Form S-3, File No. 333-83376) | ||||
| 4.12 | Form of Warrant Agreement by and between Vista Energy Resources, Inc. and American Stock Transfer & Trust Company, as warrant agent, dated October 28, 1998 (Incorporated by reference to Registration Statement on Form S-3, File No. 333-83376) | ||||
| 4.13 | Indenture dated May 29, 1997 between Magnum Hunter Resources, the subsidiary guarantors named therein and First Union National Bank of North Carolina, as Trustee (Incorporated by reference to Registration Statement on Form S-4, File No. 333-2290) | ||||
| 4.14 | Supplemental Indenture dated January 27, 1999 between Magnum Hunter Resources, the subsidiary guarantors named therein and First Union National Bank of North Carolina, as Trustee (Incorporated by reference to Form 10-K for the fiscal year-end December 31, 1998 filed April 14, 1999) | ||||
| 4.15 | Form of 10% Senior Note due 2007 (Incorporated by reference to Registration Statement on Form S-4, File No. 333-2290) | ||||
| 4.16 | 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) | ||||
| 4.17 | 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, 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 | Amendment to Fourth Amended and Restated Credit Agreement (Incorporated by reference to Form 10-Q for the period ended June 30, 2002) | ||||
| 10.3 | Amendment to Fourth Amended and Restated Credit Agreement (Incorporated by reference to Form 10-Q for the period ended March 31, 2003) | ||||
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| 10.4 | Employment Agreement for Gary C. Evans (Incorporated by reference to Form 10-K for the fiscal | ||||
| year-end December 31, 1999 filed March 30, 2000) | |||||
| 10.5 | Employment Agreement for Richard R. Frazier (Incorporated by reference to Form 10-K for the | ||||
| fiscal year-end December 31, 1999 filed March 30, 2000) | |||||
| 10.6 | Employment Agreement for Chris Tong (Incorporated by reference to Form 10-K for the year ended | ||||
| December 31, 2002) | |||||
| 10.7 | Employment Agreement for R. Douglas Cronk (Incorporated by reference to Form 10-K for the year | ||||
| ended December 31, 2002) | |||||
| 10.8 | Employment Agreement for Charles Erwin (Incorporated by reference to Form 10-K for the year ended | ||||
| December 31, 2002) | |||||
| 10.9 | 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) | |||||
| 10.10 | Purchase and Sale Agreement between Magnum Hunter Resources, Inc., NGTS, et al, dated December | ||||
| 17, 1997 (Incorporated by reference to Form 8-K, dated December 17, 1997, filed December 29, 1997) | |||||
| 10.11 | 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) | |||||
| 10.12 | 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) | |||||
| 99.1* | Certification pursuant to Section 906 of Sarbanes-Oxley Act of 2002, signed by Gary C. Evans | ||||
| 99.2* | Certification pursuant to Section 906 of Sarbanes-Oxley Act of 2002, signed by Chris Tong | ||||
| 99.3* | Certification pursuant to Section 302 of Sarbanes-Oxley Act of 2002, signed by Gary C. Evans | ||||
| 99.4* | Certification pursuant to Section 302 of Sarbanes-Oxley Act of 2002, signed by Chris Tong |
*Filed herewith
(b) Reports on Form 8-K
1) Form 8-K, filed August 4, 2003 under Item 12.
2) Form 8-K, filed September 30, 2003 under Item 9.
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In accordance with the requirements of the Exchange Act, the Registrant has caused this report to be signed on its behalf by the undersigned, hereunto duly authorized.
| By /s/ Gary C. Evans | November 4, 2003 | |
| Gary C. Evans Chairman, President and Chief Executive Officer |
||
| By /s/ Chris Tong | November 4, 2003 | |
| Chris Tong Senior Vice President and Chief Financial Officer |
||
| By /s/ Morgan F. Johnston | November 4, 2003 | |
| Morgan F. Johnston Senior Vice President, General Counsel and Secretary |
||
| By /s/ David S. Krueger | November 4, 2003 | |
| David S. Krueger Senior Vice President and Chief Accounting Officer |
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