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EVERGREEN RESOURCES, INC. INDEX
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-Q
ý |
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended: September 30, 2002. |
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o |
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to |
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Commission file number: 001-13171
EVERGREEN RESOURCES, INC.
(Exact name of registrant as specified in its charter)
| Colorado (State or Other Jurisdiction of Incorporation or Organization) |
84-0834147 (I.R.S. Employer Identification Number) |
|
1401 17th Street Suite 1200 Denver, Colorado (Address of Principal Executive Offices) |
80202 (Zip Code) |
Registrant's Telephone Number, Including Area Code: (303) 298-8100
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. ý Yes o No
As of October 31, 2002, 18,990,551 shares of the Registrant's Common Stock, no par value, were outstanding.
EVERGREEN RESOURCES, INC.
INDEX
EVERGREEN RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
| |
September 30, 2002 |
December 31, 2001 |
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|---|---|---|---|---|---|---|---|---|---|
| |
(unaudited) |
|
|||||||
| |
(in thousands) |
||||||||
| ASSETS | |||||||||
| Current: | |||||||||
| Cash and cash equivalents | $ | 782 | $ | 3,024 | |||||
| Accounts receivable | 13,865 | 10,119 | |||||||
| Other current assets (Note 4) | 2,468 | 1,455 | |||||||
| Total current assets | 17,115 | 14,598 | |||||||
| Property and equipment, at cost, based on full-cost accounting for oil and gas properties (Note 2) | 650,776 | 584,150 | |||||||
| Less accumulated depreciation, depletion and amortization | 69,094 | 51,561 | |||||||
| Net property and equipment | 581,682 | 532,589 | |||||||
| Other assets (Note 4) | 7,865 | 8,838 | |||||||
| $ | 606,662 | $ | 556,025 | ||||||
| LIABILITIES AND STOCKHOLDERS' EQUITY | |||||||||
| Current liabilities: | |||||||||
| Accounts payable | $ | 12,694 | $ | 7,355 | |||||
| Amounts payable to oil and gas property owners | 4,150 | 4,080 | |||||||
| Accrued expenses and other (Note 4) | 12,827 | 9,956 | |||||||
| Total current liabilities | 29,671 | 21,391 | |||||||
| Note payable (Note 7) | 133,000 | 81,000 | |||||||
| Senior convertible notes (Note 7) | 100,000 | 100,000 | |||||||
| Deferred income tax liabilities | 28,937 | 34,702 | |||||||
| Production taxes payable and other | 2,480 | 3,287 | |||||||
| Total liabilities | 294,088 | 240,380 | |||||||
| Minority interest in subsidiary | 693 | 705 | |||||||
| Stockholders' equity: | |||||||||
| Preferred stock, $1.00 par value; shares authorized, 24,900; none outstanding | — | — | |||||||
| Common stock, $0.01 stated value; shares authorized, 50,000; shares issued and outstanding 18,990 and 18,847 | 190 | 188 | |||||||
| Additional paid-in capital | 259,662 | 256,978 | |||||||
| Retained earnings | 49,473 | 58,795 | |||||||
| Accumulated other comprehensive income (loss) | 2,556 | (1,021 | ) | ||||||
| Total stockholders' equity | 311,881 | 314,940 | |||||||
| $ | 606,662 | $ | 556,025 | ||||||
See accompanying notes to consolidated financial statements.
EVERGREEN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
| |
Three Months Ended September 30, |
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|---|---|---|---|---|---|---|---|---|
| |
2002 |
2001 |
||||||
| |
(in thousands, except per share data) |
|||||||
| Revenues: | ||||||||
| Natural gas revenues | $ | 29,465 | $ | 25,314 | ||||
| Interest and other | 225 | 321 | ||||||
| Total revenues | 29,690 | 25,635 | ||||||
| Expenses: | ||||||||
| Lease operating expense | 4,318 | 3,373 | ||||||
| Transportation costs | 3,135 | 2,344 | ||||||
| Production and property taxes | 1,294 | 1,031 | ||||||
| Depreciation, depletion and amortization | 5,470 | 4,096 | ||||||
| General and administrative expense | 2,113 | 1,730 | ||||||
| Interest expense | 2,153 | 1,987 | ||||||
| Other expense (income) | 286 | (5 | ) | |||||
| Impairment of international properties (Note 2) | 34,170 | — | ||||||
| Total expenses | 52,939 | 14,556 | ||||||
| (Loss) income before income taxes | (23,249 | ) | 11,079 | |||||
| Income tax (benefit) provision—deferred | (8,253 | ) | 3,933 | |||||
| Net (loss) income | $ | (14,996 | ) | $ | 7,146 | |||
| Basic (loss) income per common share (Note 3) | $ | (0.79 | ) | $ | 0.38 | |||
| Diluted (loss) income per common share (Note 3) | $ | (0.79 | ) | $ | 0.37 | |||
See accompanying notes to consolidated financial statements.
EVERGREEN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
| |
Nine Months Ended September 30, |
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|---|---|---|---|---|---|---|---|
| |
2002 |
2001 |
|||||
| |
(in thousands, except per share data) |
||||||
| Revenues: | |||||||
| Natural gas revenues | $ | 72,974 | $ | 95,688 | |||
| Interest and other | 458 | 667 | |||||
| Total revenues | 73,432 | 96,355 | |||||
| Expenses: | |||||||
| Lease operating expense | 11,955 | 8,651 | |||||
| Transportation costs | 9,026 | 6,674 | |||||
| Production and property taxes | 3,927 | 3,856 | |||||
| Depreciation, depletion and amortization | 15,470 | 11,549 | |||||
| General and administrative expense | 6,724 | 5,283 | |||||
| Interest expense | 6,105 | 6,494 | |||||
| Other expense | 508 | 627 | |||||
| Impairment of international properties (Note 2) | 34,170 | — | |||||
| Total expenses | 87,885 | 43,134 | |||||
| (Loss) income before income taxes | (14,453 | ) | 53,221 | ||||
| Income tax (benefit) provision — deferred | (5,131 | ) | 19,947 | ||||
| Net (loss) income | $ | (9,322 | ) | $ | 33,274 | ||
| Basic (loss) income per common share (Note 3) | $ | (0.49 | ) | $ | 1.80 | ||
| Diluted (loss) income per common share (Note 3) | $ | (0.49 | ) | $ | 1.72 | ||
See accompanying notes to consolidated financial statements.
EVERGREEN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| |
Nine Months Ended September 30, |
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|---|---|---|---|---|---|---|---|---|---|---|
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2002 |
2001 |
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(in thousands) |
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| Operating activities: | ||||||||||
| Net (loss) income | $ | (9,322 | ) | $ | 33,274 | |||||
| Adjustments to reconcile net (loss) income to cash provided by operating activities: | ||||||||||
| Depreciation, depletion and amortization | 15,470 | 11,549 | ||||||||
| Impairment of international properties (Note 2) | 34,170 | — | ||||||||
| Deferred income taxes | (5,131 | ) | 19,947 | |||||||
| Unrealized commodity hedging loss | 596 | — | ||||||||
| Unamortized commodity swap proceeds | — | 5,308 | ||||||||
| Non-cash compensation and other | 751 | 339 | ||||||||
| Changes in operating assets and liabilities: | ||||||||||
| Accounts receivable | (3,431 | ) | 5,389 | |||||||
| Other current assets | (511 | ) | (758 | ) | ||||||
| Accounts payable | 324 | 2,587 | ||||||||
| Accrued expenses and other | 627 | 5,084 | ||||||||
| Net cash provided by operating activities | 33,543 | 82,719 | ||||||||
| Investing activities: | ||||||||||
| Investment in property and equipment | (90,308 | ) | (101,725 | ) | ||||||
| Proceeds from sale (purchase) of investment in affiliated company (Note 5) | 2,000 | (1,515 | ) | |||||||
| Repurchase of common stock | — | (354 | ) | |||||||
| Increase in other assets | (120 | ) | (350 | ) | ||||||
| Net cash used by investing activities | (88,428 | ) | (103,944 | ) | ||||||
| Financing activities: | ||||||||||
| Net proceeds from note payable | 52,000 | 21,252 | ||||||||
| Proceeds from sale of common stock, net | 1,306 | 473 | ||||||||
| Debt issue costs | (727 | ) | (33 | ) | ||||||
| Cash held from operating oil and gas properties | 71 | 531 | ||||||||
| Net cash provided by financing activities | 52,650 | 22,223 | ||||||||
| Effect of exchange rate changes on cash | (7 | ) | (24 | ) | ||||||
| (Decrease) increase in cash and cash equivalents | (2,242 | ) | 974 | |||||||
| Cash and cash equivalents, beginning of the period | 3,024 | 4,034 | ||||||||
| Cash and cash equivalents, end of the period | $ | 782 | $ | 5,008 | ||||||
See accompanying notes to consolidated financial statements.
EVERGREEN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME
(Unaudited)
| |
Three Months Ended September 30, |
Nine Months Ended September 30, |
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|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
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2002 |
2001 |
2002 |
2001 |
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(in thousands) |
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| Net (loss) income | $ | (14,996 | ) | $ | 7,146 | $ | (9,322 | ) | $ | 33,274 | ||||
| Cumulative effect of change in accounting principle, net of tax of $273 for the nine months ended September 30, 2001 | — | — | — | (446 | ) | |||||||||
| Derivative instruments: | ||||||||||||||
| Change in fair value | 115 | (264 | ) | (5,009 | ) | 14,251 | ||||||||
| Reclassification adjustment for losses (gains) included in net (loss) income | (77 | ) | (5,533 | ) | 6,146 | (8,499 | ) | |||||||
| Derivative instruments, before tax | 38 | (5,797 | ) | 1,137 | 5,752 | |||||||||
| Related income tax effect | (14 | ) | 2,203 | (404 | ) | (2,185 | ) | |||||||
| Derivative instruments, net of tax | 24 | (3,594 | ) | 733 | 3,567 | |||||||||
| Available for sale securities: | ||||||||||||||
| Change in fair value | (410 | ) | (1,061 | ) | (389 | ) | 467 | |||||||
| Related income tax effect | 145 | 403 | 138 | (177 | ) | |||||||||
| Available for sale securities, net of tax | (265 | ) | (658 | ) | (251 | ) | 290 | |||||||
| Foreign currency translation adjustments | 661 | 1,025 | 3,095 | (204 | ) | |||||||||
| Comprehensive (loss) income | $ | (14,576 | ) | $ | 3,919 | $ | (5,745 | ) | $ | 36,481 | ||||
See accompanying notes to consolidated financial statements.
EVERGREEN RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of September 30, 2002
(Unaudited)
1. Basis of Presentation
Evergreen Resources, Inc. ("Evergreen" or the "Company") is an independent energy company engaged in the operation, development, production, exploration and acquisition of unconventional natural gas properties. Evergreen is one of the leading developers of coal bed methane reserves in the United States. Its current operations are principally focused on developing and expanding its coal bed methane project located in the Raton Basin in southern Colorado. The Company also has begun operations and started drilling coal bed methane wells in Alaska.
The financial statements include the accounts of Evergreen and its wholly-owned subsidiaries, Evergreen Operating Corporation, Evergreen Resources (UK) Ltd, Evergreen Well Service Company, Primero Gas Marketing Company, Primero Gas Company, LLC, XYZ Minerals, Inc., Evergreen Resources (Alaska) Corporation, Long Canyon Gas Company, LLC and Evergreen Supply and Distribution Company. The Company also has a majority-owned subsidiary, Lorencito Gas Gathering, LLC.
The Company has a 40% ownership in Argos Evergreen Limited, a Falkland Islands company which owns offshore drilling rights in the North Falklands basin. This investment is accounted for by the equity method of accounting. The Company has no interests in any other unconsolidated entities, nor does it have any off-balance sheet financing arrangements (other than operating leases) or any unconsolidated special purpose entities.
The accompanying financial statements should be read in conjunction with the Company's audited consolidated financial statements for the year ended December 31, 2001. In the opinion of management, the accompanying unaudited financial statements include all adjustments, consisting only of normal recurring items, necessary to present fairly the Company's financial position as of September 30, 2002 and 2001 and the results of its operations and statements of comprehensive income for the three and nine months then ended and the cash flows for the nine months then ended. Certain reclassifications have been made to prior periods to conform to the classifications used in the current period. The results of operations for interim periods are not necessarily indicative of results to be expected for a full year.
2. Oil and Gas Properties
Property and equipment includes the following:
| |
September 30, 2002 |
December 31, 2001 |
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|---|---|---|---|---|---|---|---|---|---|
| |
(in thousands) |
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| Oil and gas properties (full-cost accounting): | |||||||||
| Proven oil and gas properties | $ | 420,329 | $ | 376,092 | |||||
| Unproven properties not subject to amortization (net of impairment of $34,170 and $0) | 37,627 | 56,480 | |||||||
| Accumulated depletion | (50,026 | ) | (38,353 | ) | |||||
| Net oil and gas properties | 407,930 | 394,219 | |||||||
| Gas collection system | 149,409 | 121,100 | |||||||
| Construction in progress | 7,529 | 3,674 | |||||||
| Support equipment | 35,882 | 26,804 | |||||||
| Accumulated depreciation and amortization | (19,068 | ) | (13,208 | ) | |||||
| Net other property and equipment | 173,752 | 138,370 | |||||||
| Property and equipment, net of accumulated depreciation, depletion and amortization | $ | 581,682 | $ | 532,589 | |||||
The Company follows the full-cost method of accounting for oil and gas properties. Under this method, all productive and nonproductive costs incurred in connection with the exploration for and development of oil and gas reserves are capitalized. Such capitalized costs include lease acquisition, geological and geophysical work, delay rentals, drilling, completing and equipping oil and gas wells, and include salaries, benefits and other internal costs directly attributable to the activities. Costs associated with production and general corporate activities are expensed in the period incurred. Interest costs related to unproved properties and properties under development are also capitalized to oil and gas properties. If the net investment in oil and gas properties exceeds an amount equal to the sum of (1) the standardized measure of discounted future net cash flows from proved reserves and (2) the lower of cost or fair market value of properties in process of development and unexplored acreage, the excess is charged to expense as additional depletion. Normal dispositions of oil and gas properties are accounted for as adjustments of capitalized costs, with no gain or loss recognized.
Depletion of proven oil and gas properties is computed on the units-of-production method based upon estimates of proven reserves with oil and gas being converted to a common unit of measure based on the relative energy content. Unproven oil and gas properties, including any related capitalized interest expense, are not amortized, but are assessed for impairment either individually or on an aggregated basis.
The costs of certain unproven leasehold acreage, wells drilled and international concession rights are not being amortized. Costs not being amortized are periodically assessed for possible impairments or reductions in value. If a reduction in value has occurred, costs being amortized are increased or a charge is made against earnings for those international operations where a reserve base is not yet established.
In September 2002, the Company recorded impairment to certain unevaluated international oil and gas properties of approximately $34.2 million. Of this amount, approximately $15.9 was related to the coal bed methane project in the United Kingdom, $13.6 million was related to wells drilled in Northern Ireland and the Republic of Ireland and $4.7 million was related to undeveloped acreage held in the Falkland Islands and Chile. The Company will maintain licenses on existing international leaseholdings, well sites and areas where work commitments have been completed.
Gas collection and support equipment are stated at cost. Depreciation and amortization for the Raton Basin gas collection system, with the exception of the gas compressor facilities, is computed on the units-of-production method based on total reserves of the field. Gas compressor facilities and other support equipment are depreciated using the straight-line method over the estimated useful lives of the assets of 3 to 30 years.
3. Earnings (loss) per Share
The following table sets forth the computation of basic and diluted earnings (loss) per common share. Stock options and warrants were not included in the calculation of diluted loss per share for the three and nine months ending September 30, 2002 as their inclusion would have an antidilutive effect.
| |
Three Months Ended September 30, |
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|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
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2002 |
2001 |
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(Loss) |
Weighted Shares |
Per- Share Amt. |
Income |
Weighted Shares |
Per- Share Amt. |
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| |
(in thousands, except per share data) |
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| Basic (loss) income per common share: | |||||||||||||||||
| Net (loss) income | $ | (14,996 | ) | 18,980 | $ | (0.79 | ) | $ | 7,146 | 18,562 | $ | 0.38 | |||||
| Diluted (loss) income per common share: | |||||||||||||||||
| Net (loss) income | (14,996 | ) | 18,980 | $ | 7,146 | 18,562 | |||||||||||
| Stock options and warrants | — | — | — | 883 | |||||||||||||
| $ | (14,996 | ) | 18,980 | $ | (0.79 | ) | $ | 7,146 | 19,445 | $ | 0.37 | ||||||
| |
Nine Months Ended September 30, |
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|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
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2002 |
2001 |
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| |
(Loss) |
Weighted Shares |
Per- Share Amt. |
Income |
Weighted Shares |
Per- Share Amt. |
|||||||||||
| |
(in thousands, except per share data) |
||||||||||||||||
| Basic (loss) income per common share: | |||||||||||||||||
| Net (loss) income | $ | (9,322 | ) | 18,936 | $ | (0.49 | ) | $ | 33,274 | 18,459 | $ | 1.80 | |||||
| Diluted (loss) income per common share: | |||||||||||||||||
| Net (loss) income | $ | (9,322 | ) | 18,936 | $ | 33,274 | 18,459 | ||||||||||
| Stock options and warrants | — | — | — | 936 | |||||||||||||
| $ | (9,322 | ) | 18,936 | $ | (0.49 | ) | $ | 33,274 | 19,395 | $ | 1.72 | ||||||
4. Derivatives and Hedging Activities
The Company may use derivative instruments to manage exposures to commodity prices, foreign currency and interest rate risks. The Company's objectives for holding derivatives are to achieve a consistent level of cash flow to support its capital budgeting and expenditure plans and to maximize internal rates of return for capital projects including property acquisition investments.
The Company periodically enters into fixed-price physical delivery contracts and commodity derivative contracts to manage price risk with regard to a portion of its natural gas production. At September 30, 2002, the Company had entered into the following natural gas swap and costless collar contracts by contract period. ("MMBtu" means million British thermal units.) The contracts are based on regional price indexes where the Company physically delivers its natural gas.
| Contract Period |
Type of Instrument(s) |
Volume in MMBtu/day |
Weighted Average $/MMBtu |
Unrealized Gains (Losses) at September 30, 2002 |
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|---|---|---|---|---|---|---|---|---|---|---|---|
| |
|
|
|
(in thousands |
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| Oct 02—Dec 02 | Costless Collars | 60,000 | $ | 2.59/3.87* | $ | (1,557 | ) | ||||
| Jan 03—Dec 03 | Costless Collar | 20,000 | $ | 3.35/5.16* | 536 | ||||||
| Jan 04—Dec 04 | Costless Collar | 20,000 | $ | 3.30/5.05* | 958 | ||||||
| Jan 04—Dec 04 | Swap | 10,000 | $ | 3.86* | 400 | ||||||
| $ | 337 | ||||||||||
As of September 30, 2002, the Company had recorded net unrealized gains of $337,000 which represented the estimated aggregate fair values of the Company's open derivative contracts as of that date. These gains are presented on the Consolidated Balance Sheet as a current asset of $467,000, a non-current asset of $1,427,000 and a current liability of $1,557,000. The fair values of the costless collar contracts were calculated using the Black-Scholes option-pricing model which factors in such variables as the term of the derivative contracts, the volatility of the gas market and the current risk free rates of return on similar-termed investments. The value of the natural gas swap was determined using expected discounted future cash flow. Based on the calculated fair values at September 30, 2002, the Company expects to reclassify net losses of $494,000 into earnings related to the derivative contracts during the next twelve months. Actual gains or losses recognized may be materially different than what was estimated at September 30, 2002 and will depend solely on the regional price indexes of the commodities on the specified settlement dates provided by the derivative contracts.
The Company's commodity derivative contracts are generally designated as cash flow hedges. To qualify as a cash flow hedge, these derivative contracts must be designated as cash flow hedges and changes in their fair value must correlate with changes in the price of anticipated future production such that the Company's exposure to the effects of commodity price changes is reduced. When cash flow hedge accounting is applied, the effective portion of changes in the fair values of the derivative instrument are recorded in other comprehensive income. In July 2002, to take advantage of a spike in natural gas prices, the Company sold a portion of its physical production at a different date than as designated in the costless collar agreements. As a result, the Company discontinued the use of cash flow hedge accounting on the 60,000 MMBtu of costless collars which required the Company to record a non-cash unrealized loss of $596,000 in the third quarter of 2002. This unrealized loss will be recorded as an unrealized gain in the fourth quarter of 2002.
For the nine months ended September 30, 2002, the Company recognized $6,604,000 of net losses (including the $596,000 non cash loss discussed above) related to its natural gas hedging activities. Hedging gains equal to $5,612,000 and $8,587,000 were recognized during the three and nine months ended September 30, 2001 on the natural gas swaps the Company had in place in 2001. These gains and losses are included in natural gas revenues in the Consolidated Statements of Operations for each period presented.
In April 2001, the Company entered into an interest rate swap designated as a cash flow hedge to manage fluctuations in cash flows resulting from interest rate risk. The interest rate swap had a notional amount of $25 million at a London InterBank Offered ("LIBO") rate of 4.4% and was effective April 23, 2001 through April 23, 2002. The Company recognized a loss $215,000 on the contract through April 23, 2002 and recognized a loss of $79,000 and $88,000 during the three and nine months ended September 30, 2001. These losses are included in interest expense in the Consolidated Statements of Operations for each period presented.
The Company is exposed to credit risk in the event of nonperformance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate nonperformance by the counterparties.
5. Related Party Transaction
On February 9, 2001, Evergreen completed a transaction with KFx Inc. ("KFx"), a provider of technology and service solutions to the electric power generation industry, under which KFx sold to Evergreen a portion of its convertible preferred stock investment in its subsidiary, Pegasus Technologies, Inc. ("Pegasus"), representing an approximate 8.8% as converted interest in Pegasus, for $1.5 million. Under the terms of the agreement, KFx was required to repurchase the interest on January 31, 2002 unless Evergreen elected to extend it to January 1, 2003. Evergreen extended the repurchase date to January 1, 2003 in consideration for the option to purchase additional convertible preferred stock in Pegasus for $1.2 million through January 1, 2003. On May 1, 2002, KFx repurchased the convertible preferred stock from the Company for $2.0 million plus accrued interest.
In connection with the purchase of the convertible preferred on February 9, 2001, Evergreen was provided with a five-year warrant to purchase 1 million shares of KFx common stock at $3.65 per share, subject to certain adjustments, which included a reduction in the warrant price to $2.25 per share upon KFx's retirement of certain outstanding debentures. These debentures were retired in full by KFx in July of 2002; accordingly, the warrant exercise price was reduced to $2.25 per share.
The President and Chief Executive Officer of Evergreen is on the board of directors of KFx, and the Chief Financial Officer of Evergreen is on the board of directors of Pegasus.
6. Supplemental Disclosures of Cash Flow Information
Cash paid during the nine months ended September 30, 2002 and 2001 for interest was approximately $4.9 million and $6.0 million. During the nine months ended September 30, 2002 and 2001, approximately $1.1 million and $0.8 million of interest was capitalized.
7. Notes Payable and Senior Convertible Notes
The Company currently has a $200 million revolving credit facility with a bank group (the "Banks"). The credit facility is available through July 1, 2005. Advances pursuant to this credit facility are limited to a borrowing base, which is presently $200 million. The Company may elect to use either the LIBO rate, plus a margin of 1.125% to 1.50%, or the prime rate plus a margin of 0% or 0.25%, with margins on both rates determined on the average outstanding borrowings under the credit facility. The borrowing base is redetermined semi-annually by the Banks based upon reserve evaluations of Evergreen's oil and gas properties. An unused facility fee equal to 0.375% is charged quarterly for any unused portion of the credit line. The agreement is collateralized by all of the Company's domestic oil and gas properties and guaranteed by substantially all of the Company's subsidiaries. The credit agreement also contains certain net worth, leverage and ratio requirements. At September 30, 2002, Evergreen had $133 million of outstanding borrowings under this credit facility, with an average interest rate of 3.3%. The Company was in compliance with all loan covenants for all periods presented.
In December 2001, the Company issued $100 million in senior unsecured convertible notes. The notes are due in 2021 and bear interest at a fixed annual rate of 4.75%, which is to be paid in cash on June 15 and December 15 of each year. In addition to the interest discussed above, the Company will pay contingent interest to the holders of the notes if the average trading price of the notes for an established number of days exceeds 120% or more of the principal amount of the notes. The rate of contingent interest payable in respect to any six-month period will equal the greater of (1) a per annum rate equal to 5% of the Company's estimated per annum borrowing rate for senior non-convertible fixed-rate debt with a maturity date comparable to the notes or (2) 0.30% per annum. In no event may the contingent interest rate exceed 0.40% per annum.
The notes are general unsecured obligations, ranking on a parity in right of payment with all of Evergreen's existing and future senior indebtedness, and senior in right of payment with all of Evergreen's future subordinated indebtedness. The notes are due on December 15, 2021 but are redeemable at either the Company's option or the holder's option on other specified dates. The Company may redeem the notes at its option in whole or in part beginning on December 20, 2006, at 100% of their principal amount plus accrued and unpaid interest (including contingent interest). Holders of the notes may require the Company to repurchase the notes if a change in control of the Company occurs. Holders may also require the Company to repurchase all or part of the notes on December 20, 2006, December 15, 2011 and December 15, 2016 at a repurchase price of 100% of the principal amount of the notes plus accrued and unpaid interest (including contingent interest). On December 20, 2006, the Company may pay the repurchase price in cash, in shares of common stock, or in any combination of cash and common stock. On December 15, 2011 and December 15, 2016, the Company must pay the repurchase price in cash.
The notes are convertible into common stock of Evergreen under certain circumstances as discussed below at a conversion price of $50 per share, subject to certain adjustments. The notes can be converted at the option of the holder if for a specified period of time, the closing price of the Company's common stock exceeds 110% of the $50 conversion price or if the average trading value of the notes for a specified period of time is less than 105% of an average conversion value as defined by the indenture governing the notes. The notes may also be converted into common shares of the Company at the election of the holder upon notice of redemption, or at any time the notes are rated by either Moody's Investors Service Inc. or Standard and Poor's Rating Group and the credit rating initially assigned to the notes by either such rating agency is reduced by two or more ratings levels, or upon the occurrence of certain corporate transactions including a change in control or the distribution to current holders of the Company's common stock, certain purchase rights or any other asset that has a value exceeding 10% of the sale price of the common stock on the day preceding the declaration date of the distribution of such assets.
8. Recent Accounting Pronouncements
On January 1, 2002, the Company adopted Financial Accounting Standards Board ("FASB") Statement of Financial Accounting Standards ("SFAS") No. 142, "Goodwill and Other Intangible Assets" and SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." The adoption of these statements has not had a material effect on the Company's financial statements.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires the fair value of a liability for an asset retirement obligation to be recognized 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. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. Management is currently evaluating the impact of the adoption of this statement and accordingly has not quantified the impact on the Company's financial statements.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB No. 4, 44 and 64, Amendment of FASB No. 13, and Technical Corrections." SFAS No. 145 rescinds FASB No. 4 "Reporting Gains and Losses from Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements." This statement also rescinds SFAS No. 44 "Accounting for Intangible Assets of Motor Carriers" and amends SFAS No. 13, "Accounting for Leases." This statement also amends other existing authoritative pronouncements to make various technical corrections, clarify meanings, or describe their applicability under changed conditions. This statement is effective for fiscal years beginning after May 15, 2002. The Company does not expect the adoption of this statement to have a material effect on its financial statements.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS No. 146 addresses accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force 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)." SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized and measured initially at fair value when the liability is incurred. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002, with early application encouraged. The Company does not expect the adoption of this statement to have a material effect on its financial statements.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This Quarterly Report on Form 10-Q may contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), including statements regarding, among other items, (i) the Company's growth strategies, (ii) anticipated trends in the Company's business and its future results of operations, (iii) market conditions in the oil and gas industry, (iv) the ability of the Company to make and integrate acquisitions and (v) the impact of government regulation. These forward-looking statements are based largely on the Company's expectations and are subject to a number of risks and uncertainties, many of which are beyond the Company's control. Actual results could differ materially from those implied by these forward-looking statements as a result of, among other things, a decline in natural gas production, a decline in natural gas prices, incorrect estimations of required capital expenditures, increases in the cost of drilling and completion and gas collection, an increase in the cost of production and operations, an inability to meet growth projections, or changes in general economic conditions. These and other risks and uncertainties are described in more detail in the Company's most recent Annual Report on Form 10-K filed with the Securities and Exchange Commission. In light of these and other risks and uncertainties of which the Company may be unaware or which the Company currently deems immaterial, there can be no assurance that actual results will be as projected in the forward-looking statements.
General
Evergreen Resources, Inc. ("Evergreen" or the "Company") is an independent energy company engaged in the operation, development, production, exploration and acquisition of unconventional natural gas properties. Evergreen is one of the leading developers of coal bed methane reserves in the United States. Its current operations are principally focused on developing and expanding its coal bed methane project located in the Raton Basin in southern Colorado. The Company also has begun operations and started drilling coal bed methane wells in Alaska.
Developments
Domestic Operations
Raton Basin
Evergreen drilled a total of 143 gas wells in the Raton Basin from the beginning of the year through September 30, 2002. During October 2002, the Company drilled an additional eight gas wells and two water disposal wells, bringing the year-to-date total to 151 gas wells as of October 31, 2002. Evergreen originally planned to drill a total of 152 wells in 2002; however, Evergreen increased its 2002 drilling program to as many as 162 wells due in part to the results of production testing and gas shows encountered during drilling operations on the Company's five deeper test wells drilled in the Raton Basin during 2001. The additional wells will be targeted to deeper unconventional gas formations, which include upper and middle Cretaceous-age targets, and will be drilled in the fourth quarter of 2002 and early 2003. The total depth of the deeper wells will be approximately 4,000 feet to 7,000 feet. In addition, several wells will be drilled to develop the Raton Sandstone potential. Daily net sales from the Raton Basin for the month of October 2002 were approximately 113 MMcf of gas.
Alaska
In 2001, the Company acquired a 100% working interest in approximately 64,000 gross acres of prospective coal bed methane properties in Alaska. The acreage is located in the Cook Inlet-Susitna Basin approximately 30 miles north of Anchorage. The Company has begun operations in the Pioneer Unit in the third quarter of 2002. Continuous drilling began on October 28, 2002. Evergreen plans to drill a total of eight wells. The wells will be drilled in two pilot areas in groups of four wells each. Completion and production testing operations are expected to follow in the fourth quarter of 2002, weather permitting. The completion and production testing will be completed in the spring of 2003 if weather conditions are not favorable in 2002.
International Operations
Impairment of International Properties
In September 2002, the Company impaired approximately $34.2 million of certain international oil and gas properties. Of this amount, approximately $15.9 was related to the coal bed methane project in the United Kingdom, $13.6 million was related to wells drilled in Northern Ireland and the Republic of Ireland and $4.7 million was related to undeveloped acreage held in the Falkland Islands and Chile. The Company will maintain licenses on most of its existing well sites, areas where work commitments have been completed and other potential prospects.
United Kingdom
As a result of production testing and other analysis completed on a number of wells in the United Kingdom, the Company recorded an impairment equal to $15.9 million against the carrying value of United Kingdom properties. The Company has two coal mine methane (gob gas) wells that are capable of commercial production, with estimated daily rates in the range of 500 thousand cubic feet (Mcf) to 750 Mcf of gas per well. The conventional cased, perforated and hydraulically fracture stimulated coal bed methane wells and mine gas interaction wells have had mixed results. These wells have gas production potential but at rates that would not generate the required returns to the Company or in a timeframe that would have a meaningful positive impact on the Company's financial position. Evergreen is actively pursuing a spin out of the assets or a merger of these assets with another entity. The Company will maintain licenses on most of its existing well sites and also on other potential prospects with an estimated asset value of approximately $15 million to $16 million at September 30, 2002.
Ireland
In the third quarter, Evergreen completed its evaluation of the five wells drilled in Northern Ireland and the Republic of Ireland and determined that estimated gas production from the Dowra sandstone was not at a level that would provide an adequate return to the Company. Additional drilling and completion techniques could potentially enhance production. However, the Company elected to take an impairment against the carrying value of approximately $13.6 million. The Company will maintain licenses in areas where it has completed work commitments.
Other
Evergreen is maintaining its interests and licenses in the Falkland Islands and in Chile but was unable to determine when these projects may be drilled or monetized as of September 30, 2002. As a result, an impairment of $4.7 million was taken against the carrying value of these assets.
Results of Operations—Three and Nine Months Ended September 30, 2002 Compared to the Three and Nine Months Ended September 30, 2001
The following table sets forth certain operating data of the Company for the periods presented ("Mcf" means thousand cubic feet, "MMcf" means million cubic feet and "Bcf" means billion cubic feet):
| |
Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
2002 |
2001 |
2002 |
2001 |
|||||||||
| Natural gas production (Bcf) | 10.192 | 7.892 | 28.518 | 22.117 | |||||||||
| Average realized sales price per Mcf* | $ | 2.89 | $ | 3.21 | $ | 2.56 | $ | 4.33 | |||||
| Cost per Mcf: | |||||||||||||
| Lease operating expenses | $ | 0.42 | $ | 0.43 | $ | 0.42 | $ | 0.39 | |||||
| Transportation costs | $ | 0.31 | $ | 0.30 | $ | 0.32 | $ | 0.30 | |||||
| Production and property taxes | $ | 0.13 | $ | 0.13 | $ | 0.14 | $ | 0.17 | |||||
| Depreciation, depletion and amortization | $ | 0.54 | $ | 0.52 | $ | 0.54 | $ | 0.52 | |||||
| General and administrative | $ | 0.21 | $ | 0.22 | $ | 0.24 | $ | 0.24 | |||||
| Interest expense | $ | 0.21 | $ | 0.25 | $ | 0.21 | $ | 0.29 | |||||
The Company recorded a net loss of $15.0 million or $0.79 per diluted share for the three months ended September 30, 2002, compared to net income of $7.1 million or $0.37 per diluted share for the same period in 2001. For the nine months ended September 30, 2002, the Company recorded a net loss of $9.3 million or $0.49 per diluted share compared to net income of $33.3 million or $1.72 per diluted share in 2001. The decrease in net income during the three and nine months ended September 30, 2002, as compared to the prior year periods, was due primarily to an impairment charge of $34.2 million related to the Company's international properties.
Natural gas revenues increased to $29.5 million during the three months ended September 30, 2002, from $25.3 million for the same period in the prior year. This increase was due to a 29% increase in production which was partially offset by a 10% decline in average realized natural gas prices from $3.21 per Mcf during the third quarter of 2001 to $2.89 per Mcf in the third quarter of 2002. During the nine months ended September 30, 2002, natural gas revenues decreased to $73.0 million from $95.7 million for the same period in the prior year. This decrease was due to a 41% decrease in average realized natural gas prices to $2.56 per Mcf in 2002 from $4.33 per Mcf in 2001. The decrease in average realized natural gas prices during the nine months ended September 30, 2002 was partially offset by a 29% increase in production compared to the same period in the prior year.
Net gas production for the three and nine months ended September 30, 2002 increased to 10.2 Bcf and 28.5 Bcf or an average of 110.8 and 104.5 MMcf per day, from 7.9 Bcf and 22.1 Bcf or an average of 85.8 MMcf and 81.0 MMcf per day for the comparable periods in 2001.
Approximately 11% of Evergreen's net production during the third quarter of 2002 was sold under fixed-price contractual arrangements resulting in an average hedged price of $2.38 per Mcf. An additional 54% of the Company's production was hedged in the third quarter of 2002 using costless collar contracts with a weighted average floor and ceiling of $2.59 and $3.87. The Company recorded a non-cash unrealized loss of $0.6 million in the third quarter of 2002 and a $6.6 million net loss (including the $0.6 million unrealized loss) related to its natural gas hedging activities during the nine months ended September 30, 2002. Hedging gains equal to $5.6 million and $8.6 million were recognized during the three and nine months ended September 30, 2001 on the natural gas swaps the Company had in place in 2001.
Evergreen had 802 net producing gas wells at September 30, 2002 compared to 646 at September 30, 2001. Evergreen drilled 143 coal bed methane wells and one water disposal well in the Raton Basin during the first nine months of this year compared to 132 coal bed methane wells in the first nine months of 2001.
Lease operating expenses for the three months ended September 30, 2002 were $4.3 million or $0.42 per Mcf compared to $3.4 million or $0.43 per Mcf for the same period in 2001. During the nine months ended September 30, 2002, lease operating expenses were $12.0 million or $0.42 per Mcf as compared to $8.7 million or $0.39 per Mcf for the same period in the prior year. The increases of $0.9 million and $3.3 million for the three and nine months ended September 30, 2002 from 2001 were primarily due to increases in personnel, well repairs, and compressor maintenance for 28 compressors (including three major overhauls). These increases were partially offset by decreases in water disposal costs and contract labor.
Transportation costs were $3.1 million or $0.31 per Mcf for the three months ended September 30, 2002 compared to $2.3 million or $0.30 per Mcf for the three months ended September 30, 2001. For the nine months ended September 30, 2002 transportation costs were $9.0 million or $0.32 per Mcf compared to $6.7 million or $0.30 per Mcf for the nine months ended September 30, 2001.
Production and property taxes for the three and nine months ended September 30, 2002 were $1.3 million and $3.9 million compared to $1.0 million and $3.9 million during the three and nine months ended September 30, 2001. Production and property taxes as a percentage of natural gas revenues for the three and nine months ended September 30, 2002 were 4.4% and 5.4% compared to 4.1% and 4.0% during the three and nine months ended September 30, 2001. Production taxes as a percentage of sales were lower than the Company's statutory production and property tax rate of 5.5% to 6.0% of sales during each period in 2002 primarily due to severance tax credits the Company expects to receive. Production and property taxes were lower as a percentage of sales during each period in 2001 due to the hedging gains recognized in 2001.
Depreciation, depletion and amortization expense for the three months ended September 30, 2002 was $5.5 million compared to $4.1 million for the same period in 2001. On an equivalent Mcf basis, depreciation, depletion and amortization expense was $0.54 per Mcf for the three months ended September 30, 2002 as compared to $0.52 per Mcf for the same period in the prior year. During the nine months ended September 30, 2002, depreciation, depletion and amortization expense was $15.5 million or $0.54 per Mcf as compared to $11.5 million or $0.52 per Mcf for the same period in the prior year.
In September 2002, the Company recorded an impairment of approximately $34.2 million of certain international oil and gas properties. Of this amount, approximately $15.9 was related to the coal bed methane project in the United Kingdom, $13.6 million was related to wells drilled in Northern Ireland and the Republic of Ireland and $4.7 million was related to undeveloped acreage held in the Falkland Islands and Chile. The Company will maintain licenses on certain of its existing international leaseholdings, well sites and areas where work commitments have been completed.
General and administrative expenses were $2.1 million during the three months ended September 30, 2002, as compared to $1.7 million during the same period in 2001. For the nine months ended September 30, 2002, general and administrative expenses were $6.7 million as compared to $5.3 million for the same period in the prior year. The increase over 2001 was due to an increase in general and administrative personnel, salaries, related benefits, an increase in rent expense due to additional office space leased in April 2001 and various other professional services and travel items. General and administrative expense on a per-unit of production basis was $0.21 and $0.24 per Mcf for the three and nine months ended September 30, 2002, compared to $0.22 and $0.24 per Mcf in the same periods in 2001.
Interest expense was $2.2 million and $2.0 million for the three months ended September 30, 2002 and 2001. During the nine months ended September 30, 2002, interest expense was $6.1 million compared to $6.5 million in the nine months of the prior year. Although average debt balances were higher in each period of 2002 compared to 2001, interest expense remained relatively consistent due to a reduction in average interest rates from approximately 6.6% during the first nine months of 2001 to 4.5% during the first nine months of 2002.
The Company provided for a deferred tax benefit for the three and nine months ended September 30, 2002 at an effective rate of 35.5%. The Company expects to receive a reduction in future taxes as a result of the impairment of the international assets.
For the first six months of 2001, the Company provided for deferred income taxes at an effective rate of 38% and reduced the percentage to 35.5% in the third of quarter of 2001 primarily due to Colorado income tax credits the Company expects to be able to utilize. The tax credits resulted from the Company's development activities in the Raton Basin.
Liquidity and Capital Resources
The Company currently has a $200 million revolving credit facility with a bank group (the "Banks"). The credit facility is available through July 1, 2005. Advances pursuant to this credit facility are limited to a borrowing base, which is presently $200 million. The Company may elect to use either the LIBO rate plus a margin of 1.125% to 1.50% or the prime rate plus a margin of 0% to 0.25%, with margins on both rates determined on the average outstanding borrowings under the credit facility. The borrowing base is redetermined semi-annually by the Banks based upon reserve evaluations of Evergreen's oil and gas properties. An average annual commitment fee of 0.375% is charged quarterly for any unused portion of the credit line. The agreement is collateralized by substantially all domestic oil and gas properties and guaranteed by substantially all of the Company's subsidiaries. The credit agreement also contains certain net worth, leverage and ratio requirements. At September 30, 2002, Evergreen had $133 million of outstanding borrowings under this credit facility, with a current average interest rate of approximately 3.3%. The Company was in compliance with all loan covenants for all periods presented.
As the Company continues to grow and expand, management believes that additional capital may be required to fund development of its projects. On April 23, 2002, the Company filed a shelf registration statement with the SEC providing for the offering to the public from time to time of debt securities, common or preferred stock or other securities with an aggregate offering amount of up to $300 million. The Company plans to use the proceeds from possible sales of securities for general corporate purposes, which could include debt repayment, working capital, capital expenditures or acquisitions.
The Company also filed an acquisition shelf registration statement on April 23, 2002 with the SEC providing for the offering of the Company's common stock in connection with acquisitions of other businesses and assets. The aggregate offering amount under the acquisition shelf registration statement is $50 million.
The Company has no off-balance sheet financing arrangements (other than operating leases) or any unconsolidated special purpose entities.
Capital Requirements
The Company expects to continue to utilize cash from operations as well as its available funds under its revolving credit facility to fund capital expenditures and working capital obligations during 2002. As of October 31, 2002, the Company had $56 million available under its revolving credit facility. Future cash flows will be influenced, among other factors, by the market price of natural gas as well as the number of producing properties on line. To the extent that gas prices decline, the Company's revenues, cash flows and earnings would be adversely affected, which may require the Company to rely more heavily on its revolving credit facility to fund its future capital projects.
The Company's original 2002 capital budget was $106.1 million. However, due to the increased drilling activity and other expenditures, total capital costs are now estimated to be approximately $113 million. The Company expects the remaining portion of its 2002 capital budget to be spent primarily on drilling and completion activities in the Raton Basin and Alaska.
Capital additions in the first nine months of 2002 totaled $98.0 million. These additions included $35.7 million on drilling and completion activities in the Raton Basin, $9.6 million primarily for recompletions, $31.0 million for the Raton Basin gas collection system, $2.0 million for domestic exploration projects and $11.8 million for international exploration projects. The remaining amount of $7.9 million was primarily related to the Company's wholly-owned well service company, including the subsidiary's purchase of a second fleet of fracture stimulating and cementing units.
Cash Flows
Net cash provided by operating activities was $33.5 million for the nine months ended September 30, 2002, as compared to $82.7 million for the same period in 2001. The decrease of $49.2 million was primarily due to a $33.5 million decrease in net income before taxes and before the impairment of international properties in the first nine months of 2002 as compared to the first nine months of 2001. This $33.5 million decrease was primarily due to the reduction of realized gas prices in 2002 as compared to 2001. The remaining difference in net cash provided by operating activities was primarily attributable to the $15.3 million fluctuation in the changes in operating assets and liabilities.
Net cash used in investing activities was $88.4 million during the nine months ended September 30, 2002, versus $103.9 million in the first nine months of 2001. The decrease in 2002 was primarily due to an approximate $20.0 million cash acquisition of additional ownership interests in producing coal bed methane properties and gas collection facilities in the Raton Basin during 2001.
Net cash provided by financing activities during the nine months ended September 30, 2002 was $52.7 million compared to $22.2 million in the first nine months of 2001. The increase of $30.5 million was primarily attributable to the decrease in net cash provided by operating activities of $49.2 million offset by the decrease in net cash used in investing activities of $15.5 million. The reduction in net cash provided by operating activities resulted in the Company having to use proceeds from its revolving credit facility to fund its investment in property and equipment.
Derivatives and Hedging
The Company may use derivative instruments to manage exposures to commodity prices, foreign currency and interest rate risks. The Company's objectives for holding derivatives are to achieve a consistent level of cash flow to support its capital budgeting and expenditure plans and to maximize internal rates of return for capital projects including property acquisition investments. The Company does not enter into derivative instruments for trading purposes.
At September 30, 2002, the Company had the following open derivative contracts in place: ("MMBtu" means million British thermal units.)
| Contract Period |
Type of Instrument(s) |
Volume in MMBtu/day |
Weighted Average $/MMBtu |
Unrealized Gains (Losses) at September 30, 2002 |
|||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| |
|
|
|
(in thousands |
|||||||
| Oct 02—Dec 02 | Costless Collars | 60,000 | $ | 2.59/3.87* | $ | (1,557 | ) | ||||
| Jan 03—Dec 03 | Costless Collar | 20,000 | $ | 3.35/5.16* | 536 | ||||||
| Jan 04—Dec 04 | Costless Collar | 20,000 | $ | 3.30/5.05* | 958 | ||||||
| Jan 04—Dec 04 | Swap | 10,000 | $ | 3.86* | 400 | ||||||
| $ | 337 | ||||||||||
As of September 30, 2002, the Company had recorded net unrealized gains of $337,000 which represented the estimated aggregate fair values of the Company's open derivative contracts as of that date. The fair values of the costless collar contracts were calculated using the Black-Scholes option-pricing model which factors in such variables as the term of the derivative contracts, the volatility of the gas market and the current risk free rates of return on similar-termed investments. The value of the natural gas swap was determined using expected discounted future cash flow. Based on the calculated fair values at September 30, 2002, the Company expects to reclassify net losses of $494,000 into earnings related to the derivative contracts during the next twelve months. Actual gains or losses recognized may be materially different than what was estimated at September 30, 2002 and will depend solely on the regional price indexes of the commodities on the specified settlement dates provided by the derivative contracts.
The following table provides a reconciliation of the fair value of the Company's open derivative commodity contracts at December 31, 2001 to the fair value at September 30, 2002:
| |
Fair Value of Commodity Contracts |
|||||
|---|---|---|---|---|---|---|
| |
(in thousands) |
|||||
| Fair value of contracts as of December 31, 2001 | $ | — | ||||
| Net changes in contract fair value | (6,267 | ) | ||||
| Net contract losses recognized: | ||||||
| Realized | 6,008 | |||||
| Unrealized | 596 | |||||
| Fair value of contracts as of September 30, 2002 | $ | 337 | ||||
In addition to the derivative contracts discussed above, the Company had the following physical delivery contracts in place at September 30, 2002.
Recent Accounting Pronouncements
On January 1, 2002, the Company adopted Financial Accounting Standards Board ("FASB") Statement of Financial Accounting Standards ("SFAS") No. 142, "Goodwill and Other Intangible Assets" and SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." The adoption of these statements has not had a material effect on the Company's financial statements.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires the fair value of a liability for an asset retirement obligation to be recognized 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. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. Management is currently evaluating the impact of the adoption of this statement and accordingly has not quantified the impact on the Company's financial statements.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB No. 4, 44 and 64, Amendment of FASB No. 13, and Technical Corrections." SFAS No. 145 rescinds FASB No. 4 "Reporting Gains and Losses from Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements." This Statement also rescinds SFAS No. 44 "Accounting for Intangible Assets of Motor Carriers" and amends SFAS No. 13, "Accounting for Leases." This statement also amends other existing authoritative pronouncements to make various technical corrections, clarify meanings, or describe their applicability under changed conditions. This statement is effective for fiscal years beginning after May 15, 2002. The Company does not expect the adoption of this statement to have a material effect on its financial statements.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS No. 146 addresses accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force 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)." SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized and measured initially at fair value when the liability is incurred. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002, with early application encouraged. The Company does not expect the adoption of this statement to have a material effect on its financial statements.
ITEM 3. QUANTATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK.
Commodity Risk. The Company's major market risk exposure is in the pricing applicable to its natural gas production. Realized pricing is primarily driven by the prevailing price for crude oil and spot prices applicable to Evergreen's United States natural gas production. Historically, prices received for gas production have been volatile and unpredictable. Pricing volatility is expected to continue.
The Company periodically enters into agreements to hedge its natural gas production when market conditions are deemed favorable in order to manage price fluctuations and achieve a more predictable cash flow. The Company may use fixed-price physical delivery contracts and derivative instruments to manage exposures to commodity prices. The Company does not enter into derivative instruments for trading purposes.
Assuming production, the percent of gas hedged and the average market price of the unhedged gas sold remained unchanged, a hypothetical 10% decline in the average market price the Company realized during the first nine months of 2002 on unhedged production would reduce the Company's natural gas revenues by approximately $5.4 million on an annual basis.
Interest Rate Risk. At September 30, 2002, Evergreen had long-term debt outstanding of $233 million. The interest rates on the Company's revolving credit facility, under which $133 million in indebtedness was outstanding at September 30, 2002, range from LIBO rate plus 1.375% to prime and are variable; however, they may be fixed at Evergreen's option for periods of time between 30 to 90 days. A 10% increase in short-term interest rates on the floating-rate debt outstanding at September 30, 2002 would equal approximately 33 basis points. Such an increase in interest rates would impact Evergreen's annual interest expense by approximately $0.4 million assuming borrowed amounts under the credit facility remained at $133 million.
The $100 million convertible notes have a fixed interest rate of 4.75%; however, up to an additional 0.40% may be paid as contingent interest if certain conditions are met. Accordingly, the Company's annual interest payment on the $100 million convertible notes will be a minimum of $4.75 million and a maximum of $5.15 million.
Foreign Currency Risk. Evergreen's net assets, revenue and expense accounts from its foreign operations are based on the U.S. dollar equivalent of such amounts measured in the British pound sterling or euro. Assets and liabilities of the foreign operations are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using the average exchange rates during the reporting period.
The Company expects to spend only nominal amounts of its future capital budget on its coal bed methane project in the United Kingdom so any significant change in the exchange rate for the British pound sterling would not have a material impact on the cost of the foreign exploration projects
ITEM 4. CONTROLS AND PROCEDURES
Within 90 days prior to the date of this report, Evergreen management, including the Chief Executive Officer and Chief Financial Officer, have conducted an evaluation of the effectiveness of disclosure controls and procedures pursuant to Exchange Act Rule 13a-14. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the disclosure controls and procedures enable the Company to record, process, summarize and report in a timely manner the information that the Company is required to disclose in its Exchange Act reports. There have been no significant changes in internal controls, or in factors that could significantly affect internal controls, subsequent to the date the Chief Executive Officer and Chief Financial Officer completed their evaluation.
There are no material pending legal proceedings to which the Company or any of its subsidiaries is a party to or which any of their property is subject.
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS.
Not applicable.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES.
Not applicable.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
Not applicable
Not applicable.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
Not Applicable
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.
EVERGREEN RESOURCES, INC. (Registrant) |
Date: November 12, 2002 |
By: |
/s/ KEVIN R. COLLINS |
| Kevin R. Collins VP—Finance, Chief Financial Officer and Secretary (Principal Financial and Accounting Officer) |
CERTIFICATION PURSUANT TO
SECTION 302 OF
THE SARBANES-OXLEY ACT OF 2002
I, Mark S. Sexton, certify that:
/s/ MARK S. SEXTON Mark S. Sexton President and CEO |
||
| Date | November 12, 2002 |
CERTIFICATION PURSUANT TO
SECTION 302 OF
THE SARBANES-OXLEY ACT OF 2002
I, Kevin R. Collins, certify that:
/s/ KEVIN R. COLLINS Kevin R. Collins Vice President—Finance, CFO and Treasurer |
||
| Date | November 12, 2002 |