Evergreen Resources 10-Q 2001 Q2 Quarterly report

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:  June 30, 2001.

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                           to

Commission file number:  001-13171

EVERGREEN  RESOURCES,  INC.
(Exact name of registrant as specified in its charter)
Colorado	84-0834147
(State or Other Jurisdiction	(I.R.S. Employer Identification
of Incorporation or Organization)	Number)
1401 17th Street Suite 1200
Denver, Colorado	80202
(Address of Principal Executive	(Zip Code)
Offices)
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 August 6, 2001, 18,537,038 shares of the Registrant’s Common Stock, no par value, were outstanding.

EVERGREEN RESOURCES,  INC.
INDEX

PART I.   FINANCIAL INFORMATION
	Consolidated Balance Sheets as of June 30, 2001 and December 31, 2000
	Consolidated Statements of Income for the Three and Six Months Ended June 30, 2001 and 2000
	Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2001 and 2000
	Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2001 and 2000
	Notes to Consolidated Financial Statements
	Management's Discussion and Analysis of Financial Condition and Results of Operations
	Quantitative and Qualitative Disclosure About Market Risk
PART II.   OTHER INFORMATION

PART I.   FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

EVERGREEN RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS

			June 30, 2001		December 31, 2000
			(unaudited)
			(in thousands)
ASSETS
Current:
	Cash and cash equivalents		$	7,022	$	4,034
	Accounts receivable		12,282		15,194
	Investment in affiliated company		1,709		--
	Other current assets		12,409		1,156
		Total current assets	33,422		20,384
Property and equipment, at cost, based on full-cost accounting  for oil and gas properties			532,779		446,001
	Less accumulated depreciation, depletion and amortization		42,188		34,052
		Net property and equipment	490,591		411,949
Designated cash			2,435		2,376
Other assets			3,817		16,036
			$	530,265	$	450,745
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
	Accounts payable		$	4,941	$	5,408
	Amounts payable to oil and gas property owners		4,557		3,183
	Accrued expenses and other		11,801		4,943
		Total current liabilities	21,299		13,534
Production taxes payable and other			2,435		2,376
Deferred revenue			791		1,017
Notes payable			148,500		149,748
Other long-term liability (Note 2)			17,000		--
Deferred income tax liability			36,459		17,218
		Total liabilities	226,484		183,893
Minority interest in subsidiary			747		--
Stockholders' equity:
	Preferred stock, $1.00 par value; shares authorized, 24,900; none outstanding		--		--
	Common stock, $.01 stated value; shares authorized, 50,000; shares issued and outstanding 18,530 and 18,328		185		183
	Additional paid-in capital		250,995		247,377
	Retained earnings		46,396		20,268
	Accumulated other comprehensive income (loss)		5,458		(976		)
		Total stockholders' equity	303,034		266,852
			$	530,265	$	450,745

See accompanying notes to consolidated financial statements.

EVERGREEN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

		Three Months Ended June 30,
		2001		2000
		(in  thousands, except per share data)
Revenues:
	Natural gas revenues	$	32,585	$	9,411
	Interest and other	191		121
Total revenues		32,776		9,532
Expenses:
	Lease operating expenses	2,793		1,454
	Transportation costs	2,213		1,157
	Production and property taxes	1,189		452
	Depreciation, depletion and amortization	3,918		1,340
	General and administrative expenses	2,119		920
	Interest expense	2,019		495
	Other expense	522		33
Total expenses		14,773		5,851
Income before income taxes		18,003		3,681
Income tax provision – deferred		6,841		1,435
Net income		$	11,162	$	2,246
Basic income per common share		$	0.61	$	0.15
Diluted income per common share		$	0.57	$	0.14

See accompanying notes to consolidated financial statements.

EVERGREEN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

		Six Months Ended June 30,
		2001		2000
		(in  thousands, except per share data)
Revenues:
	Natural gas revenues	$	70,374	$	17,883
	Interest and other	346		162
Total revenues		70,720		18,045
Expenses:
	Lease operating expenses	5,278		2,905
	Transportation costs	4,330		2,234
	Production and property taxes	2,826		821
	Depreciation, depletion and amortization	7,454		2,564
	General and administrative expenses	3,553		1,902
	Interest expense	4,506		802
	Other expense	631		84
Total expenses		28,578		11,312
Income before income taxes		42,142		6,733
Income tax provision – deferred		16,014		2,626
Net income		$	26,128	$	4,107
Basic income per common share		$	1.42	$	0.28
Diluted income per common share		$	1.35	$	0.26

See accompanying notes to consolidated financial statements.

EVERGREEN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

		Six Months Ended June 30,
		2001			2000
		(in thousands)
Cash flows from operating activities:
Net income		$	26,128		$	4,107
Adjustments to reconcile net income to cash provided by operating activities:
	Depreciation, depletion and amortization	7,454			2,564
	Deferred income taxes	16,014			2,626
	Non-cash compensation and other	115			215
Changes in operating assets and liabilities:
	Accounts receivable	3,421			421
	Other current assets	(354		)	(609		)
	Accounts payable	899			(464		)
	Accrued expenses and other	3,545			(714		)
	Deferred revenue	(226		)	650
Net cash provided by operating activities		56,996			8,796
Cash flows from investing activities:
	Investment in property and equipment	(52,659		)	(30,234		)
	Investment of affiliated company	(1,515		)	--
	(Increase) decrease in designated cash	(60		)	1,042
	Change in production taxes payable	60			(1,042		)
	Increase in other assets	(350		)	(350		)
Net cash used by investing activities		(54,524		)	(30,584		)
Cash flows from financing activities:
	Net proceeds from (payments on) notes payable	(1,248		)	24,000
	Proceeds from sale of common stock, net	481			138
	Debt issue costs	(33		)	--
	Increase in cash held from operating oil and gas properties and other	1,375			267
Net cash provided by financing activities		575			24,405
Effect of exchange rate changes on cash		(59		)	(32		)
Increase in cash and cash equivalents		2,988			2,585
Cash and cash equivalents, beginning of the period		4,034			651
Cash and cash equivalents, end of the period		$	7,022		$	3,236

See accompanying notes to consolidated financial statements.

EVERGREEN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

		Three Months Ended June 30,						Six Months Ended June 30,
		2001			2000			2001			2000
		(in thousands)
Net income		$	11,162		$	2,246		$	26,128		$	4,107
Derivative instruments:
	Cumulative effect of change in accounting principle	--			--			(719		)	--
	Unrealized gain on commodity price swaps	10,482			--			14,614			--
	Unrealized loss on interest rate swap	(99		)	--			(99		)	--
	Reclassification adjustment to income	(3,251		)	--			(2,975		)	--
	Reclassification adjustment to expense	9			--			9			--
	Derivative instruments, before taxes	7,141			--			10,830			--
	Income tax expense related to derivative instruments	(2,713		)	--			(4,115		)	--
Derivative instruments, net of taxes		4,428			--			6,715			--
Available for sale investments:
	Unrealized gain	110			--			1,528			--
	Income tax expense related to unrealized gains on available for sale investments	(42		)	--			(580		)	--
Available for sale investments, net of taxes		68			--			948			--
Foreign currency translation adjustments		(203		)	(545		)	(1,229		)	(716		)
Comprehensive income		$	15,455		$	1,701		$	32,562		$	3,391

See accompanying notes to consolidated financial statements.

EVERGREEN RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF JUNE 30, 2001
(Unaudited)

1.          Basis of Presentation

Evergreen Resources, Inc. (“Evergreen” or the “Company”) is an independent energy company engaged in the development, production, operation, exploration, and acquisition of oil and gas properties.  Evergreen’s primary focus is on developing and expanding its coalbed methane properties in the Raton Basin in southern Colorado consisting of approximately 271,000 gross acres.  The Company also holds exploration licenses on approximately 470,000 acres onshore in the United Kingdom, exploration licenses on approximately 1.1 million acres of prospective tight gas sands property in Northern Ireland and the Republic of Ireland, a 100% working interest in about 48,000 acres of prospective coalbed methane properties in Alaska, an interest in a consortium exploring offshore in the Falkland Islands, an oil and gas exploration contract on approximately 1.2 million acres in northern Chile and exploratory acreage in northwestern Colorado.  Evergreen operates all of its own producing properties.

The financial statements include the accounts of Evergreen and its wholly-owned subsidiaries,  Evergreen Operating Corporation, Evergreen Resources (UK) Ltd., Powerbridge, Inc., Evergreen Well Service Company, Primero Gas Marketing Company, Primero Gas Company, LLC, Long Canyon Gas Company, LLC, EnviroSeis, LLC, XYZ Minerals, Inc., and its majority owned subsidiary, Lorencito Gas Gathering Company, LLC (“LGG”).  All significant intercompany balances and transactions have been eliminated in consolidation.

The Company had a 50% ownership in LGG and a 45% working interest in approximately 17,800 acres of producing coalbed methane properties located in the Lorencito Canyon region of the Raton Basin (“Lorencito”) through May 31, 2001.  Effective June 1, 2001, the Company purchased an additional 35% ownership interest in LGG and an additional 35% working interest in Lorencito.   As a result of the above transaction, effective June 1, 2001, the Company began consolidating the accounts of LGG whereas prior to the additional purchase the Company’s investment in LGG was accounted for using the equity method of accounting.  As of March 31, 2001, the Company and another owner of LGG from whom the Company purchased the additional ownership interests had entered into a joint sales agreement to sell LGG and Lorencito.  Accordingly, the March 31, 2001 financial statements reflected the Company’s investment in LGG in Current Assets under the caption “Investment Available for Sale.”  At June 1, 2001, the Company’s initial investment in LGG was reclassified as oil and gas properties.  See Note 2 for more information concerning the purchase of additional LGG and Lorencito interests.

The Company also 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 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.  Normal dispositions of oil and gas properties are accounted for as adjustments of capitalized costs, with no gain or loss recognized.

Depreciation and depletion of proved oil and gas properties is computed on the units-of-production method based upon estimates of proved reserves with oil and gas being converted to a common unit of measure based on the relative energy content.  Unproved 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 accompanying financial statements should be read in conjunction with the Company’s audited consolidated financial statements for the year ended December 31, 2000.  In the opinion of management, the accompanying unaudited financial statements include all adjustments, consisting only of normal recurring items, as well as the accounting change to adopt Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended, necessary to present fairly the Company's financial position as of June 30, 2001 and 2000 and the results of its operations and cash flows for the three and six 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.          Purchase of Oil and Gas Properties

Effective June 1, 2001, the Company purchased an additional 35% ownership interest in LGG and additional working interests in the Lorencito properties for a total of $19.2 million.  The Company paid the purchase consideration in July 2001 utilizing $17 million from its revolving credit facility.  Accordingly, $17 million of the total purchase consideration is included in other long-term liability in the accompanying Consolidated Balance Sheet.  The purchase was accounted for under the purchase method of accounting.  As a result of the purchase, the Company now owns 85% of LGG and approximately an 80% working interest in the Lorencito properties.

The acquired property interests represent an estimated 40 billion cubic feet of proven net gas reserves, (an average cost of 48 cents per thousand cubic feet), which are currently generating daily net gas sales of about 2.5 million cubic feet (MMcf) from 65 producing wells.  The acquisition also includes additional interests in an existing compressor station and associated gas collection system.

Of the reserves attributed to the acquired property interests, approximately 63% are classified as proved developed and 37% are classified as proved undeveloped.  All of the estimated reserves are assigned to the Vermejo and Raton coals.

The results of operations of the acquired properties are included in the Company’s Consolidated Statements of Income from the effective date, June 1, 2001, through June 30, 2001.  The purchase price allocation, which was primarily allocated to proved properties and gathering equipment, is preliminary and will be finalized after management completes its reviews of the relative fair values of the assets purchased.

3.          Earnings per Share

             The following tables set forth the computation of basic and diluted earnings per share:

		Three Months Ended June 30,
		2001					2000
		(in thousands, except per share data)
					Per-					Per-
				Weighted	Share				Weighted	Share
		Income		Shares	Amt.		Income		Shares	Amt.
Basic income per common share:
Net income		$	11,162	18,446	$	0.61	$	2,246	14,943	$	0.15
Diluted income per common share:
	Net income	$	11,162	18,446			$	2,246	14,943
	Stock options	--		981			--		743
		$	11,162	19,427	$	0.57	$	2,246	15,686	$	0.14

		Six Months Ended June 30,
		2001					2000
		(in thousands, except per share data)
					Per-					Per-
				Weighted	Share				Weighted	Share
		Income		Shares	Amt.		Income		Shares	Amt.
Basic income per common share:
	Net income	$	26,128	18,407	$	1.42	$	4,107	14,905	$	0.28
Diluted income per common share:
	Net income	$	26,128	18,407			$	4,107	14,905
	Stock options	--		963			--		691
		$	26,128	19,370	$	1.35	$	4,107	15,596	$	0.26

4.          Derivatives and Hedging Activities

Effective January 1, 2001, Evergreen adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.”  Under SFAS No. 133, all derivative instruments, whether designated in hedging relationships or not, are required to be recorded on the balance sheet at fair value. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in earnings. If the derivative is designated as a cash flow hedge, the effective portions of changes in the fair value of the derivative are recorded in other comprehensive income (“OCI”) and are recognized in the income statement when the hedged item affects earnings. Ineffective portions of changes in the fair value of cash flow hedges are recognized in earnings.

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 minimize these risks using the most effective methods to eliminate or reduce the impacts of these exposures.  Currently, the Company has two outstanding commodity price swap agreements and one interest rate swap agreement.  All three swap agreements are designated as cash flow hedges, and the remaining discussion will relate exclusively to this type of derivative instrument.

The adoption of SFAS No. 133 resulted in a reduction to OCI on a pre-tax basis of $719,000, or $446,000 after-tax, for the cumulative effect of change in accounting principle. The reduction to OCI at January 1, 2001 was attributable to a commodity price swap agreement designated as a cash flow hedge.  The derivative loss included in OCI as of January 1, 2001 has been reclassified into earnings during the six months ended June 30, 2001.

Effective June 29, 2001, the two outstanding commodity price swap agreements the Company had in place were amended to accelerate the termination date from December 31, 2001 to July 31, 2001. In consideration for the amendment, the Company was paid approximately $8,827,000 by the counterparty.  At June 30, 2001, the unrealized gains for two commodity swap contracts were $10,920,000, net of taxes of $4,150,000.  The unrealized gains include the $8,827,000 as discussed above as well as the fair market value for the contracts through the amended termination date of July 31, 2001.  The unrealized gains included in OCI as of June 30, 2001 will be reclassed into earnings ratably through December 31, 2001 as the production that was hedged under the terms of the original contracts is sold.

The Company recognized $3,250,700 and $2,974,700 in gains during the three and six months ended June 30, 2001 and they are included in natural gas revenues in the Consolidated Statements of Income.

To limit the amount of exposure to interest rate fluctuations, 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 swap allows for strategies designed to protect against fluctuations.  The swap exchanges a series of future cash payments, one on a fixed-rate basis and the other on a floating rate-basis, to lock in a specific interest rate that is received by the Company.  The interest rate swap has a notional amount of $25,000,000 at a LIBO rate of 4.4% and is effective April 23, 2001 through April 23, 2002.  At June 30, 2001, the unrealized loss for this contract was $90,000 net of taxes of $34,000.  The Company recognized a $9,000 loss on this contract during the three and six months ended June 30, 2001, which was included in interest expense for the periods presented.

5.          Investment in Affiliated Company

On February 9, 2001, Evergreen closed a transaction with KFx Inc. (“KFx”) under which KFx sold to Evergreen a portion of its convertible preferred stock investment in its Pegasus Technologies, Inc. subsidiary ("Pegasus"), representing an approximate 8.8% as converted interest in Pegasus, for $1.5 million. KFx is obligated to repurchase this preferred stock for $2 million on January 31, 2002, or January 31, 2003 under certain elections available to Evergreen to purchase from KFx an additional interest in Pegasus. In certain circumstances, Evergreen can elect to exchange this interest in Pegasus, valued at $2 million, and any subsequently acquired interest in Pegasus, for common stock of KFx at $3.65 per share, subject to certain adjustments. In addition, 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.  This warrant is considered a derivative but no value has been attributed to it as of June 30, 2001.  The Company will continue to assess whether this derivative has value in the future periods.  The President and Chief Executive Officer of Evergreen is also 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 six months ended June 30, 2001 and 2000 for interest was approximately $3,707,000 and $573,000.  During the six months ended June 30, 2001 and 2000, approximately $528,000 and $158,000 of interest accrued was capitalized.

During the six months ended June 30, 2001 and 2000, there were non-cash transactions resulting in increases in oil and gas properties of approximately $23,781,000 and $6,139,000.  Included in these transactions are common stock issuances for mineral interests of $925,000 and $5,423,000 for the six months ended June 30, 2001 and 2000.

7.          Recent Accounting Pronouncements

In July 2001, the FASB issued SFAS No. 141, “Business Combinations”.  SFAS No. 141 improves the transparency of the accounting and reporting for business combinations by requiring that all business combinations be accounted for under a single method – the purchase method.  This statement is effective for all business combinations initiated after June 30, 2001.

In July 2001, the FASB issued SFAS No. 142, “Goodwill and Other Intangible Assets”.  This statement applies to intangibles and goodwill acquired after June 30, 2001, as well as goodwill and intangibles previously acquired.  Under this statement, goodwill as well as other intangibles determined to have an infinite life will no longer be amortized; however, these assets will be reviewed for impairment on a periodic basis.  This statement is effective for the Company for the first quarter in the fiscal year ended December 2002.  Management does not believe that the adoption of is this statement will have a material effect on the Company’s financial statements.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

This Quarterly Report on Form 10-Q contains 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 regulations.  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, completion and gas collection, an increase in the cost of production and operations, an inability to meet growth projections, and/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 is an independent energy company engaged in the operation, development, production, exploration and acquisition of oil and gas properties.  Evergreen's primary focus is on developing and expanding its coalbed methane properties located on approximately 271,000 gross acres in the Raton Basin in southern Colorado.  The Company also holds exploration licenses on approximately 470,000 acres onshore in the United Kingdom, exploration licenses on approximately 1.1 million acres of prospective tight gas sands property in Northern Ireland and the Republic of Ireland, a 100% working interest in about 48,000 acres of prospective coalbed methane properties in Alaska, an interest in a consortium exploring offshore in the Falkland Islands, an oil and gas exploration contract on approximately 1.2 million acres in northern Chile and exploratory acreage in northwestern Colorado.  Evergreen operates all of its producing properties.

Developments

Mid-Year Proven Reserves

Evergreen increased its proven reserves 14% during the first six months of 2001 to an estimated 1 trillion cubic feet (Tcf) of natural gas as of June 30, 2001, up from 875 billion cubic feet (“Bcf”) at year-end 2000.  Evergreen added 139 Bcf of gas reserves and produced 14.2 Bcf during 2001.  The reserve increase is due to both Evergreen’s successful drilling results and the recent acquisition of producing properties in the Raton Basin, which represented approximately 40 Bcf of the six month net reserve additions.

Natural gas in the southern Colorado portion of the Raton Basin constitutes all of Evergreen’s net proven reserves, 61% of which were classified as developed as of June 30, 2001.  The company drilled 80 gas wells in the Raton Basin during the first six months of 2001 and anticipates drilling a total of approximately 130-140 wells in the Basin this year.  The mid-year 2001 reserve estimate was based on a total of 997 gas wells, including 338 classified as proved undeveloped locations.  Evergreen estimates that it has at least 1,000 additional wells to drill in the Raton Basin, including the proved undeveloped locations.  Independent petroleum engineering consultants Netherland Sewell & Associates, Inc. audited the mid-year reserve estimate.

The present value of estimated future net revenues from Evergreen’s proven reserves, discounted at 10%, was $822 million as of June 30, 2001.  Using guidelines established by the Securities and Exchange Commission, the calculation for the mid-year 2001 reserve estimate was based on an unescalated average net gas price of $2.91 per thousand cubic feet (“Mcf”), reflecting prevailing gas prices at June 30, 2001.  The 2000 year-end calculation used a gas price of $9.18 per Mcf.

Because of the volatile history of natural gas prices, certain hypothetical present value calculations were also performed using various gas price scenarios.  Using an unescalated net gas price of $3.50 per Mcf, the PV10 of Evergreen’s proven reserves at June 30, 2001 would have been $1.07 billion.  At $4.00 per Mcf, Evergreen’s PV10 reserve value would have been $1.28 billion as of June 30, 2001.

Irish Project

In March and April 2001, Evergreen acquired a 100% working interest in 1,085,000 acres of prospective tight gas sand properties in Northern Ireland (605,000 acres) and in the Republic of Ireland (480,000 acres) for total consideration of $1,250,000 (23,200 shares of Evergreen common stock valued at $750,000 and $500,000 in cash).

Evergreen drilled the first well in Northern Ireland to a total depth of approximately 2,700 feet during the second quarter of 2001 and started drilling the Company’s second exploratory well in July 2001.  Evergreen anticipates that its evaluation of this initial drilling program will be completed by year-end 2001.  The Company plans to drill four exploratory wells over the next 12 months in Northern Ireland.  Evergreen also plans to drill at least two exploratory wells on the newly acquired acreage in the Republic of Ireland this year; totaling six wells that the Company plans to drill in the Northwest Carboniferous Basin over the 12-month period beginning in July.  The Company has selected seven drillsites for permitting and has also identified numerous other locations for exploratory and delineation drilling.  Drilling objectives are multiple tight gas sands contained in Carboniferous formations at depths ranging from 2,000 feet to 4,500 feet.  Potential well locations have been identified using data from previously drilled wells, subsurface and surface geologic mapping, and several hundred kilometers of seismic data.  Total anticipated expenditures for the work commitment for all six wells are estimated at $6 to $7 million.

Domestic Projects

Effective June 1, 2001, the Company purchased an additional 35% ownership interest in LGG and additional working interests in approximately 17,800 acres of producing coalbed methane properties in the Lorencito Canyon region of the Raton Basin for a total of $19.2 million.  As a result of the purchase, the Company now owns 85% of LGG and approximately an 80% working interest in the Lorencito properties.

The acquired property interests represent an estimated 40 billion cubic feet of proven net gas reserves, (an average cost of 48 cents per Mcf), which are currently generating daily net gas sales of about 2.5 million cubic feet (“MMcf”) from 65 producing wells.  The acquisition also includes additional interests in an existing compressor station and associated gas collection system.

Of the reserves attributed to the acquired property interests, approximately 63% are classified as proved developed and 37% are classified as proved undeveloped.  The estimated reserves are assigned to the Vermejo and Raton coals.

The results of operations of the acquired properties are included in the Company’s Consolidated Statements of Income from the effective date, June 1, 2001, through June 30, 2001.  The purchase price allocation, which was primarily allocated to proved properties and gathering equipment, is preliminary and will be finalized after management completes its reviews of the relative fair values of the assets purchased.

In May 2001, Evergreen signed a purchase and sale agreement with Ocean Energy and Union Oil of California to acquire a 100% working interest in about 48,000 acres of prospective coalbed methane properties in Alaska for approximately $960,000 in cash.  The acreage, which management believes also contains deeper pay potential in traditional natural gas reservoirs, is located about 30 miles northwest of Anchorage.  The Pioneer Unit contains three existing wellbores which Evergreen intends to fracture stimulate in the first quarter of 2002 for production testing.  The Company intends to drill a group of six wells in a desorption pattern in the second and third quarters of 2002.

In May 2001, Evergreen signed a work commitment with J.M. Huber Corp. covering 38,000 acres of Raton Basin coalbed methane properties in Huerfano County, Colorado.  Under the agreement, Evergreen will spend a minimum of $2 million through March 31, 2002 to earn a 50% working interest in the properties, which currently contain 15 shut-in wells. The properties are located approximately 20 miles north of Evergreen’s existing 271,000 acres of coalbed methane properties in Las Animas County, Colorado.  Evergreen’s planned expenditures will be primarily for drilling, completions, workovers, equipment, gas collection, fracture stimulations, lease acquisition and overhead costs.  The agreement was effective as of January 1, 2001.  Evergreen will begin a workover program in this area in the third quarter of this year by making downhole repairs and fracture stimulating approximately 6 to 8 wells and will start production testing.  The results of the tests will determine where the Company will initiate a drilling program in 2002.

Results of Operations-Three and Six Months Ended June 30, 2001

The following table sets forth certain operating data of the Company for the periods presented
(“Mcf” means thousand cubic feet and “MMcf” means million cubic feet):

		Three Months Ended June 30,				Six Months Ended June 30,
		2001		2000		2001		2000
Natural gas production (MMcf)		7,264		3,892		14,225		7,577
Average realized sales price per Mcf		$	4.49	$	2.42	$	4.95	$	2.36
Cost per Mcf:
	Lease operating expense	$	0.38	$	0.37	$	0.37	$	0.38
	Transportation costs	$	0.30	$	0.30	$	0.30	$	0.29
	Production and property taxes	$	0.16	$	0.12	$	0.20	$	0.11
	Depreciation, depletion and amortization	$	0.54	$	0.34	$	0.52	$	0.34
	General and administrative	$	0.29	$	0.24	$	0.25	$	0.25

The Company reported net income of $11,162,000 or $0.57 per diluted share for the three months ended June 30, 2001, compared to net income of $2,246,000 or $0.14 per diluted share for the same period in 2000.  For the six months ended June 30, 2001, the Company reported net income of $26,128,000 or $1.35 per diluted share compared to net income of $4,107,000 or $0.26 per diluted share in 2000.  The increase in net income during the three and six months ended June 30, 2001, as compared to the prior year periods was attributable to increases in gas sales volumes as a result of the Company’s drilling program and the acquisition of producing properties in September 2000 and increases in gas price as described below.

Natural gas revenues increased to $32,585,000 during the three months ended June 30, 2001, from $9,411,000 for the same period in the prior year.  During the six months ended June 30, 2001, natural gas revenues increased to $70,374,000 from $17,883,000 for the same period in the prior year.  The increases in natural gas revenues for the three and six month periods ended June 30, 2001 compared to the same periods in 2000 were due to 86% and 88% increases in natural gas sales volumes and 86% and 110% increases in average realized natural gas prices to $4.49 and $4.95 per Mcf in 2001 from $2.42 and $2.36 per Mcf in 2000.  Net gas sales for the three and six months ended June 30, 2001 increased to 7.3 billion cubic feet (“Bcf”) and 14.2 Bcf or an average of 79.8 and 78.2 MMcf per day, from 3.9 Bcf and 7.6 Bcf or an average of 42.7 MMcf and 41.6 MMcf per day for the comparable periods in 2000.  The 2001 results were impacted favorably by Evergreen’s acquisition of adjacent producing properties from an affiliate of KLT Gas, Inc., which was effective September 1, 2000.  These properties contributed approximately 29 MMcf and 28 MMcf of gas per day to Evergreen’s three- and six-month gas sales total.  Approximately 42% of Evergreen’s net production during the first six months of 2001 was either sold under fixed-price contractual arrangements or hedged using commodity price swaps, resulting in an average price of about $4.56 per Mcf.

Evergreen had 593 net producing gas wells connected to pipeline at June 30, 2001.  This total included 52 net producing wells in the Lorencito Canyon area acquired on June 1, 2001.  As of June 30, 2000, the Company was producing natural gas from a total of 299 net wells.  Evergreen drilled 80 coalbed methane wells in the Raton Basin during this year’s first six months.

Lease operating expenses for the three months ended June 30, 2001, were $2,793,000 or $0.38 per Mcf compared to $1,454,000 or $0.37 per Mcf for the same period in 2000.  During the six months ended June 30, 2001, lease operating expenses were $5,278,000 or $0.37 per Mcf as compared to $2,905,000 or $0.38 per Mcf for the same period in the prior year.  The increase in lease operating expense in 2001 as compared to 2000 was due to the increase in the number of producing wells and compressors.  While overall expenses increased, lease operating expenses on a per-Mcf basis remained generally consistent, increasing by $0.01 per Mcf for the three months ending June 30, 2001 over June 30, 2000 and decreasing $0.01 per Mcf for the six month period ending June 30, 2001 compared to June 30, 2000.

For the quarter and six months ended June 30, 2001, the Company reclassified property taxes associated with the gas collection system from lease operating expense to production and property taxes.  For the three and six months ended June 30, 2001 this reclassification totaled $180,000 and $360,000 compared to $84,000 and $168,000 for the same periods in 2000.  The reclassification resulted in a reduction in lease operating expense of $0.03 per Mcf for all periods presented.

Included in the property acquisition in September 2000 was a 45% working interest in non-operated properties in the Lorencito Canyon.  The average well in this area is producing substantially below the average Evergreen-operated well in the Basin, and lease operating expenses are also much higher on these properties than other Evergreen operated properties.  Included in lease operating expense for the six months ended June 30, 2001 is approximately $0.05 per Mcf related to the Lorencito properties.  The Company estimates that it can increase production from this area by focusing on recompletions and workovers to the existing wells over the next few months and also decrease the lease operating expenses and cost per Mcf.

Transportation costs for the three and six months ended June 30, 2001 were $2,213,000 and $4,330,000 or $0.30 and $0.30 per Mcf compared to $1,157,000 and $2,234,000 or $0.30 and $0.29 per Mcf for the same periods in 2000.  Effective the fourth quarter of 2000, the accounting classification of transportation costs was required to be included in operating expenses versus netted against natural gas revenues.  Accordingly, natural gas revenues for the three and six months ended June 30, 2000 have been increased to reflect the reclassification of the transportation costs.  The reclassification had no effect on net income for the periods.

Production and property taxes increased for the three months ended June 30, 2001 to $1,189,000 or $0.16 per Mcf as compared to $452,000 or $0.12 per Mcf for the same period in 2000, due to higher natural gas prices.  For the six months ended June 30, 2001, production and property taxes were $2,826,000 or $0.20 per Mcf as compared to $821,000 or $0.11 per Mcf for the same period in the prior year.  The increase was due to the increase in the average realized gas price in 2001 compared with 2000.  As a percent of natural gas sales, production and property taxes for the three and six months ended June 30, 2001 were 3.6% and 4.0% compared to 4.8% and 4.6% for the same periods in 2000.  The decrease in both periods in 2001 as compared to 2000 was due to the financial hedging gains included in natural gas revenues for the three and six months ended June 30, 2001 that are not subject to production taxes.

Depreciation, depletion and amortization expense for the three months ended June 30, 2001, was $3,918,000 compared to $1,340,000 for the same period in 2000.  On an equivalent Mcf basis, depreciation, depletion and amortization expense was $0.54 per Mcf for the three months ended June 30, 2001 compared to $0.34 per Mcf for the same period in the prior year.  During the six months ended June 30, 2001, depreciation, depletion and amortization expense was $7,454,000 or $0.52 per Mcf as compared to $2,564,000 or $0.34 per Mcf for the same period in the prior year.  The increases for 2001 were primarily attributable to the September 2000 property acquisition, which had an average acquisition cost of $1.12 per Mcf.

General and administrative expenses were $2,119,000 during the three months ended June 30, 2001, as compared to $920,000 during the same period in 2000.  For the six months ended June 30, 2001, general and administrative expenses were $3,553,000 as compared to $1,902,000 for the same period in the prior year.  The increase over 2000 was due to an increase in general and administrative staff, salaries and bonuses and related benefits, higher professional fees, higher rent expense as a result of the expansion of the Company’s Denver office, technology expense and expenses related to the Company's project in the United Kingdom.  General and administrative expense on a per-unit of production was $0.29 and $0.25 per Mcf for the three and six months ended June 30, 2001, compared to $0.24 and $0.25 per Mcf in the same periods in 2000.  The three months ended June 30, 2001 included bonuses that are not anticipated to recur in the remainder of 2001.  The Company thus anticipates lower general and administrative expenses during the last six months of 2001.

Interest expense for the three months ended June 30, 2001, was $2,019,000 compared to $495,000 for the same period in 2000.  During the six months ended June 30, 2001, interest expense was $4,506,000 compared to $802,000 in the first half of the prior year.  The increase in interest expense in 2001 was due to higher average debt balances in the first and second quarter of 2001 following the September 2000 property acquisition compared to the same periods in 2000.

Other expense of $522,00 for the three months ended June 30, 2001 includes a $307,000 charge to earnings related to the write-off of the majority of the assets of EnviroSeis, a wholly owned 2-D seismic company.  The expense also includes a reserve of $173,000 for a negotiated penalty to settle an operating issue related to water production in Las Animas County.

The Company provided for deferred taxes for the three and six months ended June 30, 2001, at a rate of 38%.  The Company had originally estimated that it would start to pay estimated taxes in the second quarter of 2001.  Due to the increased drilling program and lower natural gas prices, the Company estimates that beginning with the fourth quarter ending December 31, 2001, the net operating losses will be fully utilized and cash payments for taxes will be required.

Liquidity and Capital Resources

The Company currently has a $200 million revolving credit facility with a bank group consisting of Hibernia National Bank, BNP-Paribas, Wells Fargo Bank Texas, NA, BankOne, NA, Fleet National Bank, Bank of Scotland and First Union National Bank (the “Banks”).  The credit facility is available through July 1, 2003.  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 London interbank offered rate, or 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 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 June 30, 2001, Evergreen had $148.5 million of outstanding borrowings under this credit facility. Due to the recent property acquisition, the Company currently has $154 million of outstanding debt as of August 3, 2001 with a current average interest rate of approximately 6%.  To limit the amount of exposure to interest rate fluctuations, in April 2001, the Company entered into an interest rate swap contract to manage fluctuations in cash flows resulting from interest rate risk.  See Note 4 to the Consolidated Financial Statements for more information.

The Company’s 2001 capital budget excluding the recent Lorencito property acquisition is estimated to be approximately $75 million.  Of this total, approximately $58 million will be directed to Evergreen’s coalbed methane operations in the Raton Basin, which includes about $23 million for infrastructure, approximately $27 million for the drilling and completion of more than 120 wells, and about $8 million primarily for recompletions and equipment.  Approximately $5 million of the 2001 capital budget will be spent on the Company’s coalbed methane project in the United Kingdom, approximately $5 million on the Northern Ireland and the Republic of Ireland tight gas sands project and the remaining $7 million largely will be used for domestic and international exploration projects.  The Company estimates that based on projected production and current gas prices, the anticipated 2001 operating cash flows will exceed estimated capital expenditures.

Capital spending in the first two quarters of 2001 totaled $52 million, excluding the Lorencito transaction.  These additions included $17 million to drill and complete 80 Raton Basin gas wells, $16 million for the Raton Basin gas collection system, $6 million related to other Raton Basin development costs, $4 million for domestic exploration projects, and $3 million for international exploration projects.  The remaining amount of approximately $6 million primarily consisted of capital expenditures by the Company’s wholly-owned well service company including the subsidiary’s purchase of a coil tubing unit and two workover rigs.  The Company anticipates that the capital expenditure budget may be increase due to its accelerated drilling schedule and the Lorencito acquisition.

The Company has reallocated capital expenditures to accelerate the Raton Basin development.  The Company anticipates drilling 130 to 140 wells during 2001.  Through June 30, 2001, the Company had drilled a total of 80 wells in the Raton Basin.  As of August 3, 2001, the Company has drilled a total of 95 wells.

The number of wells anticipated to be drilled in the United Kingdom has been reduced to 5 or 6 wells in 2001, and anticipated capital costs have also been reduced from $10.5 million to $5.2 million.  The reduction in the drilling program is due to the regulatory environment, which includes delays in approvals from local planning commissions for drilling permits.

In July 2001, the Company completed its acquisition of the additional 35% ownership in LGG and 35% working interest in Lorencito.  The total purchase price for the properties was $19.2 million and is subject to post-closing adjustments.  The Company estimates that it will spend approximately $2.5 million on these properties on workovers and recompletions and other costs to stimulate production during 2001.  The Company anticipates that it will commence drilling operations during 2002.

Cash flows provided by operating activities were $56,996,000 for the six months ended June 30, 2001, as compared to cash flows provided by operating activities of $8,796,000 for the same period in 2000.  The increase was primarily due to the increase in natural gas production and natural gas prices in 2001.

Cash flows used in investing activities were $54,524,000 during the six months ended June 30, 2001, versus $30,584,000 for the same period in 2000.  The increase in 2001 was primarily due to the costs associated with the drilling of 80 wells and the addition of various gas collection projects.

Cash flows provided by financing activities were $575,000 during the six months ended June 30, 2001, as compared to $24,405,000 in the same period during 2000.  The decrease was primarily due to a decrease in borrowings on the Company’s line of credit as a result of higher cash flows provided by operating activities.

Effective January 1, 2001, Evergreen adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.”  Under SFAS No. 133, all derivative instruments, whether designated in hedging relationships or not, are required to be recorded on the balance sheet at fair value. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in earnings. If the derivative is designated as a cash flow hedge, the effective portions of changes in the fair value of the derivative are recorded in other comprehensive income (“OCI”) and are recognized in the income statement when the hedged item affects earnings. Ineffective portions of changes in the fair value of cash flow hedges are recognized in earnings.

The adoption of SFAS No. 133 resulted in a reduction to OCI on a pre-tax basis of $719,000, or $446,000 after-tax, for the cumulative effect of change in accounting principle. The reduction to OCI at January 1, 2001 was attributable to a commodity price swap agreement designated as a cash flow hedge.  The derivative loss included in OCI as of January 1, 2001 has been reclassified into earnings during the six months ended June 30, 2001.

Effective June 29, 2001, the two outstanding commodity price swap agreements the Company had in place were amended to accelerate the termination date from December 31, 2001 to July 31, 2001. In consideration for the amendment, the Company was paid approximately $8,827,000 by the counterparty.  At June 30, 2001, the unrealized gains for two commodity swap contracts were $10,920,000, net of taxes of $4,150,000.  The unrealized gains include the $8,827,000 as discussed above as well as the fair market value for the contracts through the amended termination date of July 31, 2001.  The unrealized gains included in OCI as of June 30, 2001 will be reclassed into earnings ratably through December 31, 2001 as the production that was hedged under the terms of the original contracts is sold.  See Note 4 to the Consolidated Financial Statements for more information.

Evergreen’s production is generally sold at prevailing market prices.  However, the Company periodically enters into hedging transactions for a portion of its production when market conditions are deemed favorable and natural gas prices exceed the Company’s minimum internal price targets.  See “Item 3- Quantitative and Qualitative Disclosure About Market Risk.”

The Company’s objective in entering into hedging transactions is to manage price fluctuations and achieve a more predictable cash flow.  These transactions limit Evergreen’s exposure to declines in prices, but also limit the benefits Evergreen would realize if prices increase.  As of June 30, 2001, the Company had entered into the following fixed-price physical delivery contracts to sell its gas production (the Company’s hedging contracts are denoted in MMBtu’s, which convert on an approximately 1-for-1 basis into Mcf):

• 10 MMcf per day from July 1, 2001 through October 31, 2001 at a price of $2.65 per Mcf,

• 10 MMcf per day from July 1, 2001 through October 31, 2001 at a price of NYMEX less $0.20 less fuel and transportation costs,

• a maximum of 4 MMcf per day from July 1, 2001 through April 30, 2003 at a price of $2.40 per Mcf plus transportation costs, and

• 10 MMcf per day from July 1, 2001 through March 31, 2003 for the lesser of then current market price or a gross price of $2.45 per Mcf.

In consideration for the extension of the last contract described above, Evergreen received $1,762,000 over the 12-month period ended October 31, 2000, which is being amortized over the contract term.  As of June 30, 2001, $791,000 was recognized as deferred revenue and will be recognized as revenue in future periods.

As of June 30, 2001, the Company had two outstanding commodity price swap agreements.  The contracts called for the Company to receive or make payments based upon the differential between the hedge price and the market gas price, as defined in the contract, for the notional quantity.  One of the two contracts was for 10 MMcf per day at a hedge price of  $6.10 per Mcf and the other contract was for 10 MMcf per day at a hedge price of $6.43 per Mcf.  Effective June 29, 2001, these two agreements were amended to accelerate the termination date from December 31, 2001 to July 31, 2001. In consideration for the amendment, the Company was paid approximately $8,827,000 from the counterparty.  At June 30, 2001, this $8.8 million is included in OCI and will be recognized as natural gas revenue ratably through December 31, 2001 as the production that was hedged under the terms of the original contracts is sold.  See Note 4 to the Consolidated Financial Statements for more information.

Recent Accounting Pronouncements

In July 2001, the FASB issued SFAS No. 141, “Business Combinations”.  SFAS No. 141 improves the transparency of the accounting and reporting for business combinations by requiring that all business combinations be accounted for under a single method – the purchase method.  This statement is effective for all business combinations initiated after June 30, 2001.

In July 2001, the FASB issued SFAS No. 142, “Goodwill and Other Intangible Assets”.  This statement applies to intangibles and goodwill acquired after June 30, 2001, as well as goodwill and intangibles previously acquired.  Under this statement, goodwill as well as other intangibles determined to have an infinite life will no longer be amortized; however, these assets will be reviewed for impairment on a periodic basis.  This statement is effective for the Company for the first quarter in the fiscal year ended December 2002.  Management does not believe that the adoption of is this statement will have a material effect on the Company’s 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 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.  Gas price realizations ranged from a monthly low of $2.40 per Mcf to a monthly high of $10.02 per Mcf during the six months ended June 30, 2001.

The Company periodically enters into hedging activities on a portion of its projected natural gas production through a variety of financial and physical arrangements intended to support natural gas prices at targeted levels and to manage its exposure to gas price fluctuations.  Evergreen may use futures contracts, swaps, options and fixed-price physical contracts to hedge its commodity prices.  As discussed in Note 4 to the Consolidated Financial Statements, the Company amended its two commodity swap agreements on June 29, 2001 to terminate July 31, 2001.  The Company consequently had no market risk related to the agreements at June 30, 2001.

Assuming gas production and the percentage of gas production not hedged under financial and physical contracts remain at June 30, 2001 levels, a ten percent decrease in spot gas prices would reduce the Company’s annual natural gas revenues by approximately $3.3 million.

Interest Rate Risk.  The Company has risk exposure for interest rates on its outstanding debt.  Historically, interest rates have been somewhat volatile.  Interest rate volatility is expected to continue.  The Company may enter into contractual obligations with a portion of its estimated outstanding debt to attempt to manage interest rate risk.  Evergreen has historically had a very conservative capital structure.  Due to the increased level of debt incurred as a result of the property acquisition in September 2000, management believes that it is appropriate to maintain the lowest interest rate possible.

At June 30, 2001, Evergreen had long-term debt outstanding of $148.5 million.  The interest rates on the outstanding debt range from LIBO rate plus 1.125% to prime.  Interest rates 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 June 30, 2001 would equal approximately 60 basis points.  Such an increase in interest rates would increase Evergreen’s 2001 annual interest expense by approximately $891,000, assuming borrowed amounts remain outstanding at current levels.  To limit the amount of exposure to interest rate fluctuations, in April 2001, the Company entered into an interest rate swap contract to manage fluctuations in cash flows resulting from interest rate risk.  See Note 4 to the Consolidated Financial Statements for more information.

Foreign Currency Risk.  Evergreen’s net assets, revenue and expense accounts from its U.K. subsidiary are based on the U.S. dollar equivalent of such amounts measured in the British pound sterling.  Assets and liabilities of the U.K. subsidiary 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 rate during the reporting period.

In 2000, the Company drilled 5 conventional coalbed methane wells and 4 interaction and gob gas wells in the U.K.  Evergreen plans to drill up to an additional 5 to 6 wells during 2001.  Any significant change in the exchange rate for the pound sterling would have an impact on the cost of the drilling program.

In 2001, the Company plans on drilling 4 tight gas sands wells in Northern Ireland and 2 tight gas sands wells in the Republic of Ireland.  The Company’s assets, revenue and expense accounts are based on the U.S. dollar equivalent of such amounts measured in the British pound sterling and the Irish punt.  The assets and liabilities of these projects are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period.  Revenues, expenses and cash flow will be translated using the average exchange rate for the reporting period.  Any significant change in the exchange rate for the pound sterling and/or punt would have an impact on the cost of this drilling program.

The Company measures its exposure to market risk at any point in time by comparing its open positions to a market risk of fair value.  The market prices the Company uses to determine fair value are based on management’s best estimates, which consider various factors including closing exchange prices, volatility factors and the time value of money.  At June 30, 2001, the Company was exposed to some market risk on its long-term debt, foreign currency and natural gas prices; however, management does not believe that such risk is material.

PART II.  OTHER INFORMATION

ITEM 1.            LEGAL PROCEEDINGS.

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.

The following summarizes the votes at the Company’s Annual Meeting of Shareholders held on May 2, 2001:

Election of Directors – with terms expiring at the Annual Shareholders Meeting in 2004:

Name	For	Withheld
Dennis R. Carlton	13,242,091	50,977
Mark S. Sexton	11,780,589	1,512,479
Arthur L. Smith	13,239,830	53,238

Ratification of the appointment of BDO Seidman, LLP as independent auditors for the year ending December 31, 2001

For	Against	Abstain
13,223,322	57,786	11,960

ITEM 5.            OTHER INFORMATION.

Not Applicable.

ITEM 6.            EXHIBITS AND REPORTS ON FORM 8-K.

(a)         Exhibits.

None.

(b)        Reports on Form 8-K.

Not applicable.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly
caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.

		EVERGREEN RESOURCES, INC.
			(Registrant)
Date:	August 6, 2001	By:	/s/ Kevin R. Collins
			Kevin R. Collins
			VP – Finance, Chief Financial Officer and Secretary
			(Principal Financial and Accounting Officer)