EVERGREEN RESOURCES INC, 424B2, 2000-11-03

EVERGREEN RESOURCES INC
424B2, 2000-11-03
CRUDE PETROLEUM & NATURAL GAS

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<PAGE>
FILED PURSUANT TO RULE 424(B)(2)
REGISTRATION NUMBER 333-78203

PROSPECTUS SUPPLEMENT
(TO PROSPECTUS DATED MAY 24, 1999)
2,840,000 SHARES

[LOGO]

COMMON STOCK
--------------

Evergreen Resources, Inc. is offering 2,840,000 shares of common stock. Our
common stock is listed on the New York Stock Exchange under the symbol "EVG." On
November 2, 2000, the last reported sale price of our common stock on the NYSE
was $29.375 per share.

-------------------

INVESTING IN OUR COMMON STOCK INVOLVES RISKS.
SEE "RISK FACTORS" BEGINNING ON PAGE S-8.
-----------------

PRICE $29.375 A SHARE

-----------------

<TABLE>
<CAPTION>
PER SHARE TOTAL
--------- -----------
<S> <C> <C>
Public offering price....................................... $29.375 $83,425,000
Underwriting discount....................................... $1.440 $ 4,089,600
Proceeds, before expenses, to Evergreen..................... $27.935 $79,335,400
</TABLE>

Evergreen has granted the underwriters the right to purchase up to an
additional 426,000 shares of common stock to cover over-allotments. The
underwriters expect to deliver the shares to purchasers on November 8, 2000.

Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or determined if this
prospectus supplement or the accompanying prospectus is truthful or complete.
Any representation to the contrary is a criminal offense.
-------------------

A.G. EDWARDS & SONS, INC.
ING BARINGS
PAINEWEBBER INCORPORATED
HOWARD WEIL
A DIVISION OF LEGG MASON WOOD WALKER, INC.

BREAN MURRAY & CO., INC. HIBERNIA SOUTHCOAST CAPITAL

Prospectus supplement dated November 2, 2000
<PAGE>
[Map]

[Included immediately following the cover page of the prospectus supplement is a
map of our Raton Basin coal bed methane project that identifies the location of
our acreage, including recently acquired properties, completed gas wells,
compressor stations, our field collection system and the Colorado Interstate Gas
Co. pipeline.]
<PAGE>
SUMMARY

THIS SUMMARY HIGHLIGHTS SELECTED INFORMATION FROM THIS DOCUMENT BUT DOES NOT
CONTAIN ALL OF THE INFORMATION YOU NEED TO CONSIDER IN MAKING YOUR INVESTMENT
DECISION. TO UNDERSTAND ALL OF THE TERMS OF THIS OFFERING AND FOR A MORE
COMPLETE UNDERSTANDING OF OUR BUSINESS, YOU SHOULD CAREFULLY READ THIS ENTIRE
PROSPECTUS SUPPLEMENT, THE ACCOMPANYING PROSPECTUS AND THE DOCUMENTS
INCORPORATED BY REFERENCE, PARTICULARLY THE SECTION ENTITLED "RISK FACTORS."
WHEN WE USE THE TERMS "EVERGREEN," "WE," "US" OR "OUR," WE ARE REFERRING TO
EVERGREEN RESOURCES, INC. AND ITS SUBSIDIARIES, UNLESS THE CONTEXT OTHERWISE
REQUIRES. THE TERM "YOU" REFERS TO A PROSPECTIVE INVESTOR. WE HAVE INCLUDED
TECHNICAL TERMS IMPORTANT TO AN UNDERSTANDING OF OUR BUSINESS UNDER "GLOSSARY OF
COMMON OIL AND GAS TERMS" BEGINNING ON PAGE S-49.

EVERGREEN

Evergreen Resources, Inc. is an independent energy company engaged in the
development, production, operation, exploration and acquisition of natural gas
properties. We are one of the leading developers of coal bed methane reserves in
the United States. Our current operations are principally focused on developing
and expanding our coal bed methane project located in the Raton Basin in
southern Colorado. We have also begun a coal bed methane project in the United
Kingdom and own additional interests in other domestic and international areas.

We are one of the largest holders of oil and gas leases in the Raton Basin.
Including our most recent acquisition, we now hold interests in approximately
240,000 gross acres of coal bed methane properties in the basin. At
September 1, 2000, we had estimated net proved reserves of 822 Bcf, 62% of which
were proved developed, with an estimated present value of future net revenues,
discounted at 10% (or PV-10), of approximately $1.17 billion. Our net daily gas
sales at September 30, 2000 were approximately 75 MMcf from a total of 473 net
producing wells. Total production from our wells accounts for approximately 88%
of the gas currently sold from the Raton Basin. Our Raton Basin drilling program
has enabled us to build an extensive inventory of additional drilling locations.
We have identified over 750 additional drilling locations on our Raton Basin
acreage, of which 218 were included in our estimated proved reserve base at
September 1, 2000. We operate and have a 100% working interest in substantially
all of our Raton Basin acreage and wells.

We have an established track record for significantly growing our reserve
base through development drilling and acquisitions. Since we began our drilling
efforts in the Raton Basin, we have drilled more than 300 wells and achieved a
success rate of approximately 98%. In addition, we have acquired 194 net
producing wells. From March 31, 1995 through September 1, 2000, we grew our
estimated proved reserves from 58 Bcf to 822 Bcf, which represents a compound
annual growth rate of approximately 63%. During the same period, our net daily
gas sales increased from 1.3 MMcf to approximately 75 MMcf.

We believe that we have gained significant experience in coal bed methane
exploration and development, including the use of enhanced drilling, completion
and production techniques developed over a number of years. This has enabled us
to become one of the lowest-cost finders, developers and producers among U.S.
publicly-traded independent oil and gas companies. From the beginning of our
Raton Basin project through September 30, 2000, we have spent approximately
$137 million on the drilling and completion of our wells, pipelines, gas
collection systems and compression equipment, and $220 million on the
acquisition of additional properties. This represents a total finding and
development cost of $0.23 per Mcf excluding acquisitions and $0.41 per Mcf
including acquisitions.

S-1
<PAGE>
RECENT DEVELOPMENTS

KLT PROPERTY ACQUISITION

Effective September 1, 2000, we acquired interests in approximately 24,000
gross acres of producing coal bed methane properties in the Raton Basin from an
affiliate of KLT Gas Inc., which is an indirect wholly owned subsidiary of
Kansas City Power & Light Company. The acquired properties are located adjacent
to our existing properties in the southern Colorado portion of the Raton Basin.
We paid approximately $70 million in cash, $100 million in mandatory redeemable
preferred stock and $6 million in common stock and will make certain contingent
payments in connection with this acquisition.

At September 1, 2000, the acquired properties contained estimated net proved
reserves of 153 Bcf, 93% of which were proved developed, with a PV-10 of
approximately $246 million. Almost all of the estimated reserves are assigned to
the Vermejo coal formation. We believe that additional potential may exist in
deeper formations that are currently unevaluated. Immediately prior to the
acquisition, the acquired properties were generating net daily sales of 28 MMcf
of gas from a total of 151 net wells.

We believe the KLT property acquisition is a strategic fit with our existing
properties that strengthens our competitive position within the Raton Basin and
will:

- provide an attractive return for our shareholders and be accretive to our
cash flow and earnings on a per-share basis;

- reduce our general and administrative expenses significantly on a per Mcf
basis;

- afford us the opportunity to achieve field operating efficiencies and
production increases through the application of our technical skills to
the recompletion of existing wells; and

- increase our net daily gas production by approximately 60%, which, in
turn, significantly increases our cash flows and ability to internally
fund our current drilling programs and pursue new growth opportunities.

QUARTERLY EARNINGS ANNOUNCEMENT

On October 18, 2000, we announced results for the quarter and nine months
ended September 30, 2000. Results included the KLT properties from September 1,
2000, the effective date of the acquisition. We reported quarterly earnings of
$2.4 million in the third quarter, or $0.15 per diluted share, compared to
$1.4 million, or $0.09 per diluted share, in the third quarter of 1999. With
increased production and a higher gas price realization, natural gas revenues in
the third quarter increased to $12.0 million, an increase of 107% over 1999's
third quarter total of $5.8 million. Cash flow before changes in operating
assets and liabilities in the third quarter totaled $7.5 million, or $0.47 per
diluted share, compared to $3.7 million, or $0.24 per diluted share, in the
third quarter of 1999.

Net gas sales in the third quarter of 2000 averaged 54 MMcf per day, up 41%
from 39 MMcf per day in the corresponding 1999 period. We had 473 net gas wells
connected to pipeline at September 30, 2000, including 151 net producing wells
from the KLT property acquisition. At September 30, 1999, we were producing
natural gas from a total of 220 net gas wells. We drilled 21 coal bed methane
wells in the Raton Basin during the third quarter. Our realized net gas price of
$2.41 per Mcf in the third quarter represented a 47% improvement over last
year's third quarter average of $1.64 per Mcf. We realized a lower than current
market price due to approximately 77% of our net daily gas sales being hedged at
approximately $2.00 per Mcf. A substantial portion of these fixed-price gas
sales will expire in the fourth quarter, which will reduce our hedged gas sales
to approximately 45% in the fourth quarter and to approximately 20% in 2001.

Lease operating expenses, or LOE, for the three months ended September 30,
2000 were $2.2 million or $0.44 per Mcf compared to $1.3 million or $0.36 per
Mcf for the same period in 1999.

S-2
<PAGE>
This increase in LOE was due to increased contract labor costs and additional
field personnel. Production taxes increased to $0.11 per Mcf for the three
months ended September 30, 2000, compared to $0.03 cents per Mcf in the third
quarter of 1999. The increase in production taxes was due to higher gas prices
in 2000.

For the first nine months of 2000, net income totaled $6.5 million, compared
to $3.3 million for the first nine months of 1999. Earnings in the first nine
months of 1999 included a one-time, after-tax gain of $452,000 or $0.03 per
diluted share from the sale of our 49% ownership in a well service company. Net
income in the first nine months of 2000 rose to $0.41 per diluted share, versus
$0.25 per diluted share in the corresponding 1999 period. Natural gas revenues
in the first nine months of 2000 increased to $27.7 million, up 78% from
$15.5 million in the corresponding 1999 period, while cash flow before changes
in operating assets and liabilities totaled $17.0 million or $1.08 per diluted
share, up from $8.7 million or $0.66 per diluted share in the first nine months
of 1999. Net gas sales in the first nine months of 2000 totaled 12.6 Bcf or 46
MMcf per day, an increase of 27% over the volumes reported for the first nine
months of 1999, during which net gas sales totaled 9.9 Bcf or 36 MMcf per day.

UNITED KINGDOM PROJECT

We hold exploration licenses covering approximately 470,000 acres in the
United Kingdom. In April 2000, we began drilling activities on these coal bed
methane properties using our own purpose-built equipment and personnel. A total
of nine wells have been drilled year to date, and we anticipate that our
evaluation of the results of the drilling program will be completed sometime in
early 2001. If the project is successful, we believe initial gas sales could
begin by the end of 2001. During the first nine months of 2000, we invested
approximately $8 million in this project, including approximately $3 million for
drilling and fracture stimulation equipment, and expect to invest up to an
additional $4 million through year end 2000.

BUSINESS STRATEGY

Our objective is to enhance shareholder value by increasing reserves,
production, cash flow, earnings and net asset value per share. To accomplish
this objective, we intend to capitalize on our experience and operating
expertise in coal bed methane properties and on our other competitive strengths,
which include:

- our inventory of drilling locations in the Raton Basin,

- our track record for significantly growing our reserve base through
development drilling and acquisitions, and

- our position as a low-cost finder, developer and producer of natural gas.

To implement our strategy, we seek to:

- CONTINUE DEVELOPMENT OF THE RATON BASIN. We have a current inventory of
approximately 750 drilling locations in the Raton Basin. In 1999, we
drilled 85 wells in the basin. During 2000, we intend to drill a total of
100 wells, of which 78 have been drilled through September 30, 2000. In
2001, we intend to drill approximately 100 wells. As part of this
development program, we have made a substantial investment in our gas
collection systems and compression facilities.

S-3
<PAGE>
wells. To date, we have drilled and completed 35 Raton formation wells. In
some instances, we can drill and complete Raton wells and use our existing
gas collection infrastructure from our Vermejo wells, which should reduce
the total cost of a producing Raton well. Based on our preliminary
evaluation, we believe that we can profitably develop the Raton formation
coal seams in certain areas of the basin.

- ESTABLISH NEW PROJECT AREAS. We have commenced drilling activity on our
exploration licenses in the United Kingdom, where we believe significant
coal bed methane reserve potential exists. In addition to evaluating this
project, we are looking at other opportunities where we can capitalize on
the operating expertise we have developed in the Raton Basin.

- MAINTAIN CONTROL OF OPERATIONS. We have a 100% working interest in and
operate substantially all of our properties, thereby controlling all
phases of drilling, completion and well stimulation. We also construct,
own and operate all of our gas collection systems, which we have
specifically designed to optimize production from coal bed methane wells.
By operating our producing properties, we believe we have greater control
over our expenses and the timing of exploration and development of our
properties.

- LOWER OPERATING COSTS THROUGH VERTICAL INTEGRATION. We have developed the
internal capabilities both in personnel and equipment to perform key well
services, such as drilling, completion and workovers, gas collection,
water disposal and gas marketing. We believe these internal capabilities
enable us to maintain quality control, lower our costs and avoid
operational delays.

- PURSUE SELECTED ADDITIONAL ACQUISITIONS. We will continue to pursue
acquisitions of oil and gas properties located in our principal areas of
operation and in other areas that provide attractive investment
opportunities, particularly where we can add value through our coal bed
methane expertise.

THE OFFERING

<TABLE>
<S> <C>
Common stock offered by Evergreen............ 2,840,000 shares (1)

Common stock outstanding after the 18,016,051 shares (1)(2)
offering...................................

Use of proceeds.............................. To repay outstanding indebtedness under our
credit facility, including indebtedness
incurred in connection with the KLT property
acquisition.

NYSE symbol.................................. EVG
</TABLE>

------------

(1) Does not include up to 426,000 shares of common stock that the underwriters
may purchase if they exercise their over-allotment option.

(2) Does not include 1,493,736 shares of common stock issuable upon exercise of
outstanding options and warrants.

S-4
<PAGE>
SUMMARY FINANCIAL DATA
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

You should read the following information together with "Selected
Consolidated Financial Data," "Management's Discussion and Analysis of Financial
Condition and Results of Operations," and the historical and pro forma financial
statements and related notes included or incorporated by reference in this
prospectus supplement and the accompanying prospectus. The results of operations
for the six months ended June 30, 2000 should not be regarded as indicative of
results for the full year.

<TABLE>
<CAPTION>
SIX MONTHS
YEARS ENDED DECEMBER 31, ENDED JUNE 30,
------------------------------ -------------------
1997 1998 1999 1999 2000
-------- -------- -------- -------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA
Revenues:
Natural gas revenues...................................... $ 12,138 $ 19,063 $ 22,721 $ 9,712 $ 15,649
Interest and other........................................ 136 178 207 114 162
-------- -------- -------- -------- --------
Total revenues.......................................... 12,274 19,241 22,928 9,826 15,811
-------- -------- -------- -------- --------
Expenses:
Lease operating expenses.................................. 1,433 2,481 4,697 2,125 3,073
Production taxes.......................................... 574 876 694 238 653
Depreciation, depletion and amortization.................. 2,794 3,860 4,757 2,298 2,564
General and administrative................................ 1,286 1,933 3,024 1,272 1,902
Interest.................................................. 777 1,870 1,927 1,541 802
Other..................................................... 259 286 175 62 84
-------- -------- -------- -------- --------
Total expenses.......................................... 7,123 11,306 15,274 7,536 9,078
-------- -------- -------- -------- --------
Income from continuing operations before income taxes....... 5,151 7,935 7,654 2,290 6,733
Income tax provision -- deferred............................ -- 3,062 2,979 887 2,626
-------- -------- -------- -------- --------
Income from continuing operations........................... 5,151 4,873 4,675 1,403 4,107
Discontinued operations:
Gain on disposal of discontinued operations, net.......... -- -- 452 452 --
Equity in earnings of discontinued operations, net........ 313 339 -- -- --
-------- -------- -------- -------- --------
Net income.................................................. 5,464 5,212 5,127 1,855 4,107
Preferred stock dividends................................... (400) -- -- -- --
-------- -------- -------- -------- --------
Net income attributable to common stock..................... $ 5,064 $ 5,212 $ 5,127 $ 1,855 $ 4,107
======== ======== ======== ======== ========
Basic income per common share:
From continuing operations................................ $ 0.50 $ 0.47 $ 0.36 $ 0.12 $ 0.28
From discontinued operations.............................. 0.03 0.03 0.03 0.04 --
-------- -------- -------- -------- --------
Basic income per common share............................. $ 0.53 $ 0.50 $ 0.39 $ 0.16 $ 0.28
======== ======== ======== ======== ========
Diluted income per common share:
From continuing operations................................ $ 0.48 $ 0.44 $ 0.34 $ 0.11 $ 0.26
From discontinued operations.............................. 0.03 0.03 0.03 0.04 --
-------- -------- -------- -------- --------
Diluted income per common share........................... $ 0.51 $ 0.47 $ 0.37 $ 0.15 $ 0.26
======== ======== ======== ======== ========

STATEMENT OF CASH FLOWS DATA
Net cash provided by (used in):
Operating activities...................................... $ 6,457 $ 12,147 $ 12,731 $ 4,721 $ 8,796
Investing activities...................................... (19,259) (47,202) (43,864) (19,696) (30,584)
Financing activities...................................... 12,253 34,260 30,471 16,259 24,405

OTHER FINANCIAL DATA
Capital expenditures (1).................................. $ 18,847 $ 55,050 $ 52,003 $ 23,072 $ 35,187
EBITDA (2)................................................ 8,635 14,221 15,079 6,870 10,099
Cash flow (3)............................................. 8,129 12,523 13,126 4,962 9,512
</TABLE>

S-5
<PAGE>

<TABLE>
<CAPTION>
AS OF DECEMBER 31,
------------------------------
1997 1998 1999 AS OF JUNE 30, 2000
-------- -------- -------- -------------------
(UNAUDITED)
<S> <C> <C> <C> <C>
BALANCE SHEET DATA
Cash and cash equivalents................................. $ 2,103 $ 1,334 $ 651 $ 3,236
Working capital........................................... (118) (468) (62) 3,520
Total assets.............................................. 87,306 139,626 184,369 218,731
Total long-term debt...................................... 14,841 47,045 15,500 39,500
Total stockholders' equity................................ 64,152 79,679 153,510 162,462
</TABLE>

---------------

(1) Capital expenditures include all cash and non-cash expenditures.

(2) EBITDA is defined as net income attributable to common stock, plus interest,
income taxes, depreciation, depletion and amortization. EBITDA is a
financial measure commonly used in our industry and should not be considered
in isolation or as a substitute for net income, net cash provided by
operating activities or other income or cash flow data prepared in
accordance with generally accepted accounting principles or as a measure of
a company's profitability or liquidity. Because EBITDA excludes some, but
not all, items that affect net income and may vary among companies, the
EBITDA presented above may not be comparable to similarly titled measures of
other companies.

(3) Cash flow represents cash flow from operating activities prior to changes in
assets and liabilities.

SUMMARY OPERATING DATA

The following table sets forth summary data with respect to our production
and sales of natural gas for the periods indicated.

<TABLE>
<CAPTION>
SIX MONTHS
ENDED
YEARS ENDED DECEMBER 31, JUNE 30,
------------------------------ -------------------
1997 1998 1999 1999 2000
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
SALES DATA

Natural gas sales (MMcf)............................. 6,402 10,021 13,656 6,361 7,577

AVERAGE SALES PRICE PER UNIT

Natural gas (per Mcf)................................ $1.90 $ 1.90 $ 1.66 $1.53 $2.07

COSTS PER MCF

Lease operating expenses............................. $0.22 $ 0.25 $ 0.34 $0.33 $0.41

Production taxes..................................... 0.09 0.09 0.05 0.04 0.09

General and administrative........................... 0.20 0.19 0.22 0.20 0.25

Depreciation, depletion and amortization............. 0.44 0.39 0.35 0.36 0.34
</TABLE>

The following table sets forth finding and development costs with respect to
our United States properties for the periods indicated.

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31, JANUARY 1, 1995
------------------------------------ THROUGH
1997 1998 1999 SEPTEMBER 30, 2000
-------- -------- -------- -------------------
<S> <C> <C> <C> <C>
FINDING AND DEVELOPMENT COSTS PER MCF

Drilling........................................... $0.24 $0.17 $0.24 $0.23

Acquisition........................................ n/a 0.36 0.32 0.81

All sources........................................ 0.24 0.23 0.25 0.41
</TABLE>

S-6
<PAGE>
SUMMARY RESERVE AND ACREAGE DATA

The reserve estimates and present value data at December 31, 1999, 1998 and
1997 for our properties were audited by both Netherland, Sewell &
Associates, Inc. and Resource Services International, Inc., independent
petroleum engineering consultants. Netherland Sewell and Resource Services also
audited the reserve estimates for our properties at September 1, 2000 (excluding
the KLT properties), and Resource Services audited the reserve estimates at
September 1, 2000 for the KLT properties. The summaries of their reserve reports
at September 1, 2000 are included as Appendix A, Appendix B and Appendix C,
respectively, to this prospectus supplement. You should read the following table
along with the sections entitled "Risk Factors -- Information in this prospectus
supplement concerning our reserves and future net revenue estimates is
uncertain," "Business and Properties -- Natural Gas Reserves" and note 16 to our
consolidated financial statements.

<TABLE>
<CAPTION>
AS OF DECEMBER 31, AS OF SEPTEMBER 1, 2000
--------------------------------- ------------------------------------
EVERGREEN KLT
1997 1998 1999 PROPERTIES PROPERTIES TOTAL
--------- --------- --------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
ESTIMATED PROVED RESERVES

Natural gas (MMcf)......... 224,414 404,936 559,418 668,936 153,461 822,397

Percent proved developed... 64% 60% 60% 55% 93% 62%

PV-10 (1)(2) (in
thousands)............... $ 159,326 $ 214,675 $ 331,383 $919,571 $245,868 $1,165,439
</TABLE>

<TABLE>
<CAPTION>
AS OF SEPTEMBER 30, 2000
-----------------------------------
RATON BASIN OTHER TOTAL
----------- --------- ---------
<S> <C> <C> <C>
ACREAGE
Gross acres:
Developed............................................... 99,400 1,800 101,200
Undeveloped............................................. 140,700 3,295,300 3,436,000

Net acres:
Developed............................................... 88,300 900 89,200
Undeveloped............................................. 102,200 2,448,800 2,551,000
</TABLE>

------------

(1) These amounts reflect the future effects of our period end prices and/or
open hedging contracts at the end of the periods presented. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Hedging Transactions."

(2) Weighted average natural gas prices used in the estimation of net proved
reserves and the calculation of PV-10 were $1.87, $1.60, $2.01 and $4.01 per
Mcf at December 31, 1997, 1998, 1999 and September 1, 2000, respectively. At
October 11, 2000, we were receiving a net wellhead price of $4.50 per Mcf.

S-7
<PAGE>
RISK FACTORS

You should carefully consider the following risk factors, in addition to the
other information included or incorporated by reference in this prospectus
supplement and the accompanying prospectus, before purchasing shares of our
common stock. In addition, please read "Forward-Looking Statements" on
page S-15 of this prospectus supplement, where we describe additional
uncertainties associated with our business and the forward-looking statements
included or incorporated by reference in this prospectus supplement and the
accompanying prospectus. Each of these risk factors could adversely affect our
business, operating results and financial condition, as well as adversely affect
the value of an investment in our common stock.

OIL AND GAS PRICES ARE VOLATILE, AND AN EXTENDED DECLINE IN PRICES WOULD HURT
OUR PROFITABILITY AND FINANCIAL CONDITION.

Our revenues, operating results, profitability, future rate of growth and
the carrying value of our oil and gas properties depend heavily on prevailing
market prices for oil and gas. We expect the markets for oil and gas to continue
to be volatile. Any substantial or extended decline in the price of oil or gas
would have a material adverse effect on our financial condition and results of
operations. It could reduce our cash flow and borrowing capacity, as well as the
value and the amount of our gas reserves. All of our proved reserves are natural
gas. Therefore, we are more directly impacted by volatility in the price of
natural gas. Various factors beyond our control will affect prices of oil and
gas, including:

- worldwide and domestic supplies of oil and gas,

- the ability of the members of the Organization of Petroleum Exporting
Countries to agree to and maintain oil price and production controls,

- political instability or armed conflict in oil or gas producing regions,

- the price and level of foreign imports,

- worldwide economic conditions,

- marketability of production,

- the level of consumer demand,

- the price, availability and acceptance of alternative fuels,

- the availability of pipeline capacity,

- weather conditions, and

- actions of federal, state, local and foreign authorities.

These external factors and the volatile nature of the energy markets make it
difficult to estimate future prices of oil and gas.

We periodically review the carrying value of our oil and gas properties
under the full cost accounting rules of the Securities and Exchange Commission.
Under these rules, capitalized costs of proved oil and gas properties may not
exceed the present value of estimated future net revenues from proved reserves,
discounted at 10%. Application of the ceiling test generally requires pricing
future revenue at the unescalated prices in effect as of the end of each fiscal
quarter and requires a write-down for accounting purposes if the ceiling is
exceeded, even if prices were depressed for only a short period of time. We may
be required to write down the carrying value of our oil and gas properties when
oil and gas prices are depressed or unusually volatile. If a write-down is
required, it would result in a charge to earnings, but would not impact cash
flow from operating activities. Once incurred, a write-down of oil and gas
properties is not reversible at a later date.

S-8
<PAGE>
OUR OPERATIONS REQUIRE LARGE AMOUNTS OF CAPITAL.

Our current development plans will require us to make large capital
expenditures for the exploration and development of our natural gas properties.
Also, we must secure substantial capital to explore and develop our
international projects. Historically, we have funded our capital expenditures
through a combination of funds generated internally from sales of production or
properties, the issuance of equity, long-term debt financing and short-term
financing arrangements. We currently do not have any sources of additional
financing other than our credit facility. After giving effect to this offering,
we expect to have approximately $101.7 million available for borrowing under
this $150 million facility. In addition, we are discussing with our lenders an
increase in this facility to $200 million. We cannot be sure that we will
receive a commitment for this facility or that the terms will be acceptable to
us. Future cash flows and the availability of financing will be subject to a
number of variables, such as:

- the success of our coal bed methane project in the Raton Basin,

- our success in locating and producing new reserves,

- the level of production from existing wells, and

- prices of oil and natural gas.

Issuing equity securities to satisfy our financing requirements could cause
substantial dilution to our existing shareholders. Debt financing could lead to:

- a substantial portion of our operating cash flow being dedicated to the
payment of principal and interest,

- our being more vulnerable to competitive pressures and economic downturns,
and

- restrictions on our operations.

If our revenues were to decrease due to lower oil and natural gas prices,
decreased production or other reasons, and if we could not obtain capital
through our credit facility or otherwise, our ability to execute our development
plans, replace our reserves or maintain production levels could be greatly
limited.

INFORMATION IN THIS PROSPECTUS SUPPLEMENT CONCERNING OUR RESERVES AND FUTURE NET
REVENUE ESTIMATES IS UNCERTAIN.

There are numerous uncertainties inherent in estimating quantities of proved
oil and natural gas reserves and their values, including many factors beyond our
control. Estimates of proved undeveloped reserves, which comprise a significant
portion of our reserves, are by their nature uncertain. The reserve information
included or incorporated by reference in this prospectus supplement and the
accompanying prospectus are only estimates. Although we believe they are
reasonable, actual production, revenues and reserve expenditures will likely
vary from estimates, and these variances may be material.

Estimates of oil and natural gas reserves, by necessity, are projections
based on geologic and engineering data, and there are uncertainties inherent in
the interpretation of such data as well as the projection of future rates of
production and the timing of development expenditures. Reserve engineering is a
subjective process of estimating underground accumulations of oil and natural
gas that are difficult to measure. The accuracy of any reserve estimate is a
function of the quality of available data, engineering and geological
interpretation and judgment. Estimates of economically recoverable oil and
natural gas reserves and future net cash flows necessarily depend upon a number
of variable factors and assumptions, such as historical production from the area
compared with production from other producing areas, the assumed effects of
regulations by governmental agencies and assumptions governing future oil and
natural gas prices, future operating costs, severance and excise taxes,

S-9
<PAGE>
development costs and workover and remedial costs, all of which may in fact vary
considerably from actual results. For these reasons, estimates of the
economically recoverable quantities of oil and natural gas attributable to any
particular group of properties, classifications of such reserves based on risk
of recovery, and estimates of the future net cash flows expected therefrom may
vary substantially. Any significant variance in the assumptions could materially
affect the estimated quantity and value of the reserves. Actual production,
revenues and expenditures with respect to our reserves will likely vary from
estimates, and such variances may be material. See "Business and Properties --
Natural Gas Reserves."

In addition, you should not construe PV-10 as the current market value of
the estimated oil and natural gas reserves attributable to our properties. We
have based the estimated discounted future net cash flows from proved reserves
on prices and costs as of the date of the estimate, in accordance with
applicable regulations, whereas actual future prices and costs may be materially
higher or lower. For example, our reserve reports included in this prospectus
supplement were estimated using a calculated weighted average sales price of
$4.01 per Mcf, which was based on gas prices of $4.04 per Mcf, the market price
for our gas on September 1, 2000. During 2000, our net realized gas prices have
been as high as $4.73 per Mcf and as low as $1.71 per Mcf. Many factors will
affect actual future net cash flows, including:

- the amount and timing of actual production,

- supply and demand for natural gas,

- curtailments or increases in consumption by natural gas purchasers, and

- changes in governmental regulations or taxation.

The timing of the production of oil and natural gas properties and of the
related expenses affect the timing of actual future net cash flows from proved
reserves and, thus, their actual present value. In addition, the 10% discount
factor, which we are required to use to calculate PV-10 for reporting purposes,
is not necessarily the most appropriate discount factor given actual interest
rates and risks to which our business or the oil and natural gas industry in
general are subject.

WE DEPEND HEAVILY ON EXPANSION AND DEVELOPMENT OF THE RATON BASIN.

All of our proved reserves are in the Raton Basin, and our future growth
plans rely heavily on increasing production and reserves in the Raton Basin. Our
proved reserves will decline as reserves are depleted, except to the extent we
conduct successful exploration or development activities or acquire other
properties containing proved reserves.

At September 1, 2000, we had estimated net proved undeveloped reserves of
approximately 309 Bcf, which constituted approximately 38% of our total
estimated net proved reserves. Our development plan includes increasing our
reserve base through continued drilling and development of our existing
properties in the Raton Basin. We cannot be sure, though, that our planned
projects in the Raton Basin will lead to significant additional reserves or that
we will be able to continue drilling productive wells at anticipated finding and
development costs.

OUR PRODUCING PROPERTY ACQUISITIONS CARRY SIGNIFICANT RISKS.

Our recent growth is due in part to acquisitions of producing properties.
The successful acquisition of producing properties requires an assessment of a
number of factors beyond our control. These factors include recoverable
reserves, future oil and gas prices, operating costs and potential environmental
and other liabilities. These assessments are inexact and their accuracy is
inherently uncertain. In connection with these assessments, we perform a review
of the subject properties that we believe is generally consistent with industry
practices. However, such a review will not reveal all existing or potential
problems. In addition, the review will not permit a buyer to become sufficiently
familiar with the properties to fully assess their deficiencies and
capabilities. We do not inspect every well. Even

S-10
<PAGE>
when a well is inspected, structural and environmental problems are not
necessarily discovered. Normally, we acquire interests in properties on an "as
is" basis with limited remedies for breaches of representations and warranties.
In addition, competition for producing oil and gas properties is intense and
many of our competitors have financial and other resources substantially greater
than those available to us. Therefore, we cannot assure you that we will be able
to acquire oil and gas properties that contain economically recoverable reserves
or that we will acquire such properties at acceptable prices.

OUR INDUSTRY IS HIGHLY COMPETITIVE.

Major oil companies, independent producers, institutional and individual
investors are actively seeking oil and gas properties throughout the world,
along with the equipment, labor and materials required to operate properties.
Many of our competitors have financial and technological resources vastly
exceeding those available to us. Many oil and gas properties are sold in a
competitive bidding process in which we may lack technological information or
expertise available to other bidders. We cannot be sure that we will be
successful in acquiring and developing profitable properties in the face of this
competition.

THE OIL AND GAS EXPLORATION BUSINESS INVOLVES A HIGH DEGREE OF BUSINESS AND
FINANCIAL RISK.

The business of exploring for and, to a lesser extent, developing oil and
gas properties is an activity that involves a high degree of business and
financial risk. Property acquisition decisions generally are based on various
assumptions and subjective judgments that are speculative. Although available
geological and geophysical information can provide information about the
potential of a property, it is impossible to predict accurately the ultimate
production potential, if any, of a particular property or well. Moreover, the
successful completion of an oil or gas well does not ensure a profit on
investment. A variety of factors, both geological and market-related, can cause
a well to become uneconomic or only marginally economic.

OUR BUSINESS IS SUBJECT TO OPERATING HAZARDS THAT COULD RESULT IN SUBSTANTIAL
LOSSES.

The oil and natural gas business involves operating hazards such as well
blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or
well fluids, fires, formations with abnormal pressures, pipeline ruptures or
spills, pollution, releases of toxic gas and other environmental hazards and
risks, any of which could cause us substantial losses. In addition, we may be
liable for environmental damage caused by previous owners of property we own or
lease. As a result, we may face substantial liabilities to third parties or
governmental entities, which could reduce or eliminate funds available for
exploration, development or acquisitions or cause us to incur losses. An event
that is not fully covered by insurance -- for instance, losses resulting from
pollution and environmental risks, which are not fully insurable -- could have a
material adverse effect on our financial condition and results of operations.

EXPLORATORY DRILLING IS AN UNCERTAIN PROCESS WITH MANY RISKS.

Exploratory drilling involves numerous risks, including the risk that we
will not find any commercially productive natural gas or oil reservoirs. The
cost of drilling, completing and operating wells is often uncertain, and a
number of factors can delay or prevent drilling operations, including:

- unexpected drilling conditions,

- pressure or irregularities in formations,

- equipment failures or accidents,

- adverse weather conditions,

S-11
<PAGE>
- compliance with governmental requirements, and

- shortages or delays in the availability of drilling rigs and the delivery
of equipment.

Our future drilling activities may not be successful, nor can we be sure that
our overall drilling success rate or our drilling success rate for activity
within a particular area will not decline. Unsuccessful drilling activities
could have a material adverse effect on our results of operations and financial
condition. Also, we may not be able to obtain any options or lease rights in
potential drilling locations that we identify. Although we have identified
numerous potential drilling locations, we cannot be sure that we will ever drill
them or that we will produce natural gas from them or any other potential
drilling locations.

HEDGING TRANSACTIONS MAY LIMIT OUR POTENTIAL GAINS.

To manage our exposure to price risks in the marketing of our natural gas,
we enter into natural gas price hedging arrangements from time to time with
respect to a portion of our current or future production. Although in the past
these arrangements have provided solely for future physical deliveries of
natural gas, in the future these arrangements may include futures contracts on
the New York Mercantile Exchange. While intended to reduce the effects of
volatile natural gas prices, these transactions may limit our potential gains if
natural gas prices were to rise substantially over the price established by the
hedge. In addition, such transactions may expose us to the risk of financial
loss in certain circumstances, including instances in which:

- our production is less than expected,

- there is a widening of price differentials between delivery points for our
production and the delivery point assumed in the hedge arrangement,

- the counterparties to our futures contracts fail to perform the contracts,
or

- a sudden, unexpected event materially impacts natural gas prices.

WE MAY FACE UNANTICIPATED WATER DISPOSAL COSTS.

Based on our previous experience with coal bed methane gas production in the
Raton Basin, we believe that the groundwater produced from the Raton Basin coal
seams will not exceed permit levels and in many cases will meet state and
federal primary drinking water standards. This means that we can lawfully
discharge the water into arroyos, surface water, well-site pits and evaporation
ponds pursuant to permits obtained from the State of Colorado. These disposal
options require an extensive third-party water sampling and laboratory analysis
program to ensure compliance with state permit standards. These monitoring costs
are directly related to the number of well-site pits, evaporation ponds and
discharge points.

If water of lesser quality is discovered or our wells produce water in
excess of the applicable permit limits, we may have to drill additional disposal
wells to re-inject the produced water back into the underground rock formations
next to the coal seams or to lower sandstone horizons. This would also have to
be accomplished through an appropriately issued permit. If we cannot obtain
future permits from the State of Colorado, water of lesser quality is
discovered, our wells produce excess water or new laws or regulations require
water to be disposed of in a different manner, the costs to dispose of this
produced water may increase, which could have a material adverse effect on our
operations in this area.

We have been the defendant in a lawsuit under the federal Water Pollution
Control Act, or Clean Water Act, relating to regulatory requirements for our
water disposal from certain of our Raton Basin wells. See "Business and
Properties -- Legal Proceedings" for additional information with respect to this
lawsuit.

S-12
<PAGE>
OUR INDUSTRY IS HEAVILY REGULATED.

Federal, state and local authorities extensively regulate the oil and gas
industry. Legislation and regulations affecting the industry are under constant
review for amendment or expansion, raising the possibility of changes that may
affect, among other things, the pricing or marketing of oil and gas production.
Noncompliance with statutes and regulations may lead to substantial penalties,
and the overall regulatory burden on the industry increases the cost of doing
business and, in turn, decreases profitability. State and local authorities
regulate various aspects of oil and gas drilling and production activities,
including the drilling of wells (through permit and bonding requirements), the
spacing of wells, the unitization or pooling of oil and gas properties,
environmental matters, safety standards, the sharing of markets, production
limitations, plugging and abandonment, and restoration.

WE MUST COMPLY WITH COMPLEX ENVIRONMENTAL REGULATIONS.

Our operations are subject to complex and constantly changing environmental
laws and regulations adopted by federal, state and local governmental
authorities. New laws or regulations, or changes to current requirements, could
have a material adverse effect on our business. State, federal and local
environmental agencies have relatively little experience with the regulation of
coal bed methane operations, which are technologically different from
conventional oil and gas operations. This inexperience has created uncertainty
regarding how these agencies will interpret air, water and waste requirements
and other regulations to coal bed methane drilling, fracture stimulation
methods, production and water disposal operations. We will continue to be
subject to uncertainty associated with new regulatory interpretations and
inconsistent interpretations between state and federal agencies. We could face
significant liabilities to the government and third parties for discharges of
oil, natural gas or other pollutants into the air, soil or water, and we could
have to spend substantial amounts on investigations, litigation and remediation.
We cannot be sure that existing environmental laws or regulations, as currently
interpreted or enforced, or as they may be interpreted, enforced or altered in
the future, will not materially adversely affect our results of operations and
financial condition. As a result, we may face material indemnity claims with
respect to properties we own or have owned.

OUR BUSINESS DEPENDS ON TRANSPORTATION FACILITIES OWNED BY OTHERS.

The marketability of our gas production depends in part on the availability,
proximity and capacity of pipeline systems owned by third parties. Although we
have some contractual control over the transportation of our product, material
changes in these business relationships could materially affect our operations.
Federal and state regulation of gas and oil production and transportation, tax
and energy policies, changes in supply and demand and general economic
conditions could adversely affect our ability to produce, gather and transport
natural gas.

MARKET CONDITIONS COULD CAUSE US TO INCUR LOSSES ON OUR TRANSPORTATION
CONTRACTS.

We have gas transportation contracts that require us to transport minimum
volumes of natural gas. If we ship smaller volumes, we may be liable for the
shortfall. Unforeseen events, including production problems or substantial
decreases in the price of natural gas, could cause us to ship less than the
required volumes, resulting in losses on these contracts.

OUR INTERNATIONAL OPERATIONS ARE SUBJECT TO RISKS OF DOING BUSINESS ABROAD.

We hold exploration licenses onshore in the United Kingdom and in northern
Chile and an interest in a consortium exploring offshore in the Falkland
Islands. International operations are subject to political, economic and other
uncertainties, including, among others, risk of war, revolution, border
disputes, expropriation, re-negotiation or modification of existing contracts,
import, export and transportation regulations and tariffs, taxation policies,
including royalty and tax increases and retroactive tax claims, exchange
controls, limits on allowable levels of production, currency fluctuations, labor
disputes and other uncertainties arising out of foreign government sovereignty
over our international operations.

S-13
<PAGE>
WE DEPEND ON KEY PERSONNEL.

Our success will continue to depend on the continued services of our
executive officers and a limited number of other senior management and technical
personnel. Loss of the services of any of these people could have a material
adverse effect on our operations. We do not have employment agreements with any
of our executive officers.

OUR SHARES THAT ARE ELIGIBLE FOR FUTURE SALE MAY HAVE AN ADVERSE EFFECT ON THE
PRICE OF OUR COMMON STOCK.

After this offering, 18,016,051 shares of common stock will be outstanding
(18,442,051 shares if the underwriters' over-allotment option is exercised in
full). In addition, options and warrants to purchase 1,493,736 shares are
outstanding, of which 818,986 are exercisable. These options and warrants are
exercisable at prices ranging from $4.25 to $27.44 per share. Of the shares to
be outstanding after this offering, approximately 14,686,842 shares (15,112,842
shares if the underwriters' over-allotment option is exercised in full) will be
freely tradeable without substantial restriction or the requirement of future
registration under the Securities Act. In addition, various shareholders have
registration rights with respect to a total of 1,833,363 shares of common stock.
Our officers and directors have entered into lock-up agreements under which they
have agreed not to offer or sell any shares of common stock or similar
securities for a period of 120 days from the date of this prospectus supplement
without the prior written consent of A.G. Edwards & Sons, Inc., on behalf of the
underwriters (except that we may issue or grant additional shares, warrants or
options under our employee benefit plans). Also, A.G. Edwards & Sons, Inc. may
at any time waive the terms of these lock-up agreements as specified in the
underwriting agreement. Sales of substantial amounts of common stock, or a
perception that such sales could occur, and the existence of options or warrants
to purchase shares of common stock at prices that may be below the then current
market price of the common stock could adversely affect the market price of the
common stock and could impair our ability to raise capital through the sale of
our equity securities.

OUR ARTICLES OF INCORPORATION AND BYLAWS HAVE PROVISIONS THAT DISCOURAGE
CORPORATE TAKEOVERS AND COULD PREVENT SHAREHOLDERS FROM REALIZING A PREMIUM ON
THEIR INVESTMENT.

Our articles of incorporation and bylaws contain provisions that may have
the effect of delaying or preventing a change in control. These provisions,
among other things, provide for noncumulative voting in the election of the
board and impose procedural requirements on shareholders who wish to make
nominations for the election of directors or propose other actions at
shareholders' meetings. Also, our articles of incorporation authorize the board
to issue up to 25,000,000 shares of preferred stock without shareholder approval
and to set the rights, preferences and other designations, including voting
rights, of those shares as the board may determine. These provisions, alone or
in combination with each other and with the rights plan described below, may
discourage transactions involving actual or potential changes of control,
including transactions that otherwise could involve payment of a premium over
prevailing market prices to shareholders for their common stock.

On July 7, 1997, our board of directors adopted a shareholder rights
agreement, pursuant to which uncertificated stock purchase rights were
distributed to our shareholders at a rate of one right for each share of common
stock held of record as of July 22, 1997. The rights plan is designed to enhance
the board's ability to prevent an acquirer from depriving shareholders of the
long-term value of their investment and to protect shareholders against attempts
to acquire Evergreen by means of unfair or abusive takeover tactics. However,
the existence of the rights plan may impede a takeover of Evergreen not
supported by the board, including a takeover that may be desired by a majority
of our shareholders or involving a premium over the prevailing stock price.

S-14
<PAGE>
FORWARD-LOOKING STATEMENTS

This prospectus supplement, the accompanying prospectus and the documents
incorporated by reference herein contain forward-looking statements within
meaning of section 27A of the Securities Act of 1933 and section 21E of the
Securities Exchange Act of 1934, including statements regarding, among other
items, our growth strategies, anticipated trends in our business and our future
results of operations, market conditions in the oil and gas industry, our
ability to make and integrate acquisitions and the outcome of litigation and the
impact of governmental regulation. These forward-looking statements are based
largely on our expectations and are subject to a number of risks and
uncertainties, many of which are beyond our control. Actual results could differ
materially from these forward-looking statements as a result of, among other
things:

- a decline in natural gas production or natural gas prices,

- incorrect estimates of required capital expenditures,

- increases in the cost of drilling, completion and gas collection or other
costs of production and operations,

- an inability to meet growth projections, and

- other risk factors set forth under "Risk Factors" in this prospectus
supplement.

In addition, the words "believe," "may," "will," "estimate," "continue,"
"anticipate," "intend," "expect" and similar expressions, as they relate to
Evergreen, our business or our management, are intended to identify
forward-looking statements.

We undertake no obligation to publicly update or revise any forward-looking
statements, whether as a result of new information, future events or otherwise
after the date of this prospectus supplement. In light of these risks and
uncertainties, the forward-looking events and circumstances discussed in this
prospectus supplement and the accompanying prospectus may not occur and actual
results could differ materially from those anticipated or implied in the
forward-looking statements.

S-15
<PAGE>
PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY

Our common stock has been listed on the New York Stock Exchange under the
market symbol "EVG" since September 8, 2000. Before then it was included for
quotation in the Nasdaq National Market under the symbol "EVER." The following
table sets forth the range of high and low sales prices per share of common
stock for the periods indicated.

<TABLE>
<CAPTION>
HIGH LOW
-------- --------
<S> <C> <C>
YEAR ENDED DECEMBER 31, 1998
First Quarter........................................... $18.75 $12.88
Second Quarter.......................................... 20.00 16.25
Third Quarter........................................... 22.88 13.25
Fourth Quarter.......................................... 26.25 16.38
YEAR ENDED DECEMBER 31, 1999
First Quarter........................................... $21.63 $14.50
Second Quarter.......................................... 25.75 19.00
Third Quarter........................................... 28.50 21.38
Fourth Quarter.......................................... 24.06 14.84
YEAR ENDING DECEMBER 31, 2000
First Quarter........................................... $26.31 $17.75
Second Quarter.......................................... 30.06 21.00
Third Quarter........................................... 34.94 24.75
Fourth Quarter (through November 2, 2000)............... 36.94 27.13
</TABLE>

On November 2, 2000, the last reported sale price of the common stock on the
NYSE was $29.375 per share. As of October 12, 2000, there were 1,536 holders of
record of the common stock.

We have not declared or paid and do not anticipate declaring or paying any
dividends on our common stock in the near future. Any future determination as to
the declaration and payment of dividends will be at the discretion of our board
of directors and will depend on then existing conditions, including our
financial condition, results of operations, contractual restrictions, capital
requirements, business prospects, and such other factors as our board deems
relevant, as well as the approval of the holders of a majority of the
outstanding shares of mandatory redeemable preferred stock.

S-16
<PAGE>
USE OF PROCEEDS

We expect to receive approximately $78.7 million of net proceeds from this
offering ($90.6 million if the underwriters' over-allotment option is exercised
in full) after deducting the underwriting discount and estimated offering
expenses of $600,000.

We will use the net proceeds of this offering to repay outstanding
indebtedness under our credit facility, including indebtedness incurred in
connection with the KLT property acquisition.

At November 2, 2000, we had $127 million of borrowings outstanding under our
credit facility bearing interest at an average rate of 7.79%. This indebtedness
was incurred primarily to fund the KLT property acquisition and the continued
development of our Raton Basin properties. The credit facility is available
through July 2003.

CAPITALIZATION

The following table sets forth (1) our actual capitalization as of June 30,
2000, (2) our pro forma capitalization giving effect to the issuance of 201,748
shares of common stock and 100,000 shares of mandatory redeemable preferred
stock and to the incurrence of $70 million in additional indebtedness under our
credit facility in connection with the KLT property acquisition, and (3) our pro
forma capitalization as adjusted to reflect the sale of 2,840,000 shares of
common stock in this offering and the application of the net proceeds as set
forth under "Use of Proceeds." The following table should be read in conjunction
with "Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the historical and pro forma financial statements and related
notes included or incorporated by reference in this prospectus supplement and
the accompanying prospectus.

<TABLE>
<CAPTION>
JUNE 30, 2000
----------------------------------
PRO FORMA
ACTUAL PRO FORMA AS ADJUSTED
-------- --------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Long-term debt:
Credit facility........................................... $ 39,500 $109,500 $ 30,765
-------- -------- --------
Mandatory redeemable preferred stock, $1,000 liquidation
preference; no shares issued and outstanding, actual;
100,000 shares issued and outstanding, pro forma and pro
forma as adjusted......................................... -- 100,000 100,000
-------- --------
Stockholders' equity:
Common stock, $0.01 stated value; 50,000,000 shares
authorized; 14,943,106 shares issued and outstanding,
actual; 15,144,854 shares issued and outstanding, pro
forma; 17,984,854 shares issued and outstanding, pro
forma as adjusted (1)................................... 149 151 179
Additional paid-in capital................................ 152,884 158,882 237,589
Retained earnings......................................... 10,312 10,312 10,312
Accumulated other comprehensive loss...................... (883) (883) (883)
-------- -------- --------
Total stockholders' equity.................................. 162,462 168,462 247,197
-------- -------- --------
Total capitalization........................................ $201,962 $377,962 $377,962
======== ======== ========
</TABLE>

------------

(1) Does not include 1,493,736 shares of common stock issuable upon exercise of
outstanding options and warrants. Also does not include an estimated 116,000
shares of common stock that may become issuable in January 2001 as
contingent additional consideration for the KLT property acquisition.

S-17
<PAGE>
SELECTED CONSOLIDATED FINANCIAL DATA
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

The selected consolidated financial data presented below is derived from our
consolidated financial statements. The selected consolidated financial data
presented below for the six month periods ended June 30, 1999 and 2000 is
derived from our unaudited consolidated financial statements and includes, in
the opinion of management, all normal and recurring adjustments necessary to
present fairly the data for such periods. The results of operations for the six
months ended June 30, 2000 should not be regarded as indicative of results for
the full year.

You should read the following information in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
the historical and pro forma financial statements and the notes thereto included
or incorporated by reference in this prospectus supplement and the accompanying
prospectus.

<TABLE>
<CAPTION>
YEAR ENDED SIX MONTHS
DECEMBER 31, ENDED JUNE 30,
------------------------------ -------------------
1997 1998 1999 1999 2000
-------- -------- -------- -------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA
Revenues:
Natural gas and oil revenues.............................. $ 12,138 $ 19,063 $ 22,721 $ 9,712 $ 15,649
Interest and other........................................ 136 178 207 114 162
-------- -------- -------- -------- --------
Total revenues.......................................... 12,274 19,241 22,928 9,826 15,811
-------- -------- -------- -------- --------
Expenses:
Lease operating expenses.................................. 1,433 2,481 4,697 2,125 3,073
Production taxes.......................................... 574 876 694 238 653
Depreciation, depletion and amortization.................. 2,794 3,860 4,757 2,298 2,564
General and administrative................................ 1,286 1,933 3,024 1,272 1,902
Interest.................................................. 777 1,870 1,927 1,541 802
Other..................................................... 259 286 175 62 84
-------- -------- -------- -------- --------
Total expenses.......................................... 7,123 11,306 15,274 7,536 9,078
-------- -------- -------- -------- --------
Income from continuing operations before income taxes....... 5,151 7,935 7,654 2,290 6,733
Income tax provision -- deferred............................ -- 3,062 2,979 887 2,626
-------- -------- -------- -------- --------
Income from continuing operations........................... 5,151 4,873 4,675 1,403 4,107
Discontinued operations:
Gain on disposal of discontinued operations, net.......... -- -- 452 452 --
Equity in earnings of discontinued operations, net........ 313 339 -- -- --
-------- -------- -------- -------- --------
Net income.................................................. 5,464 5,212 5,127 1,855 4,107
Preferred stock dividends................................... (400) -- -- -- --
-------- -------- -------- -------- --------
Net income attributable to common stock..................... $ 5,064 $ 5,212 $ 5,127 $ 1,855 $ 4,107
======== ======== ======== ======== ========

Basic income per common share
From continuing operations................................ $ 0.50 $ 0.47 $ 0.36 $ 0.12 $ 0.28
From discontinued operations.............................. 0.03 0.03 0.03 0.04 --
-------- -------- -------- -------- --------
Basic income per common share............................. $ 0.53 $ 0.50 $ 0.39 $ 0.16 $ 0.28
======== ======== ======== ======== ========

Diluted income per common share
From continuing operations................................ $ 0.48 $ 0.44 $ 0.34 $ 0.11 $ 0.26
From discontinued operations.............................. 0.03 0.03 0.03 0.04 --
-------- -------- -------- -------- --------
Diluted income per common share........................... $ 0.51 $ 0.47 $ 0.37 $ 0.15 $ 0.26
======== ======== ======== ======== ========

S-18
<PAGE>

<TABLE>
<CAPTION>
AS OF DECEMBER 31,
------------------------------ AS OF
1997 1998 1999 JUNE 30, 2000
-------- -------- -------- --------------
(UNAUDITED)
<S> <C> <C> <C> <C>
BALANCE SHEET DATA:
Cash and cash equivalents................................. $ 2,103 $ 1,334 $ 651 $ 3,236
Working capital........................................... (118) (468) (62) 3,520
Total assets.............................................. 87,306 139,626 184,369 218,731
Total long-term debt...................................... 14,841 47,045 15,500 39,500
Total stockholders' equity................................ 64,152 79,679 153,510 162,462
</TABLE>

---------------

(1) Capital expenditures include all cash and non-cash expenditures.

(3) Cash flow represents cash flows from operating activities prior to changes
in assets and liabilities.

S-19
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion and analysis in conjunction with
our consolidated and pro forma financial statements and notes thereto included
and incorporated by reference in this prospectus supplement and the accompanying
prospectus. The following information contains forward-looking statements. We
refer you to "Forward-Looking Statements."

GENERAL

We are an independent energy company engaged in the development, production,
operation, exploration and acquisition of natural gas properties. Our primary
focus is on developing and expanding our coal bed methane properties located on
approximately 240,000 gross acres in the Raton Basin in southern Colorado. We
also hold exploration licenses on approximately 470,000 acres onshore in the
United Kingdom, an interest in a consortium exploring offshore in the Falkland
Islands, an oil and gas exploration contract on approximately 2.4 million gross
acres in northern Chile and exploratory acreage in northwestern Colorado. We
operate substantially all of our producing properties.

We currently have 473 net producing gas wells. Our net daily natural gas
sales are currently approximately 75 MMcf.

The following table sets forth certain of our operating data for the periods
presented:

<TABLE>
<CAPTION>
YEARS ENDED SIX MONTHS ENDED
DECEMBER 31, JUNE 30,
------------------------------ -------------------
1997 1998 1999 1999 2000
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
Natural gas sales (MMcf)............................ 6,402 10,021 13,656 6,361 7,577
Average realized sales price per Mcf................ $ 1.90 $ 1.90 $ 1.66 $ 1.53 $ 2.07

COST PER MCF
Lease operating expense........................... $ 0.22 $ 0.25 $ 0.34 $ 0.33 $ 0.41
Production taxes.................................. 0.09 0.09 0.05 0.04 0.09
Depreciation, depletion and amortization.......... 0.44 0.39 0.35 0.36 0.34
General and administrative........................ 0.20 0.19 0.22 0.20 0.25
</TABLE>

RESULTS OF OPERATIONS

SIX MONTHS ENDED JUNE 30, 2000 COMPARED TO SIX MONTHS ENDED JUNE 30, 1999

For the six months ended June 30, 2000, we reported net income of $4,107,000
or $0.26 per diluted share compared to net income of $1,855,000 or $0.15 per
diluted share in 1999. The six months earnings in 1999 included a one-time,
after tax gain of $452,000 or $0.04 per diluted share, resulting from the sale
of our 49% interest in Maverick Stimulation Company. The increase in net income
during the six months ended June 30, 2000, as compared to the prior year was
attributable to increases in gas sales volumes and prices.

During the six months ended June 30, 2000, natural gas revenues increased to
$15,649,000 from $9,712,000 for the same period in the prior year. The increase
in natural gas revenues for the six month period ended June 30, 2000 compared to
the same period in 1999 was due to a 19% increase in natural gas sales volumes
and a 35% increase in natural gas prices. At June 30, 2000, the number of
producing Raton Basin wells increased to 299 net producing wells from 201 net
producing wells at June 30, 1999.

During the six months ended June 30, 2000, lease operating expenses
excluding production taxes were $3,073,000 or $0.41 per Mcf as compared to
$2,125,000 or $0.33 per Mcf for the same period in the prior year. The increase
in lease operating expense in 2000 as compared to 1999 was due to the increase
in the number of producing wells, additional compressor expense, water
management costs for hauling and testing, increase in field personnel and
workover costs related to well repairs and

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maintenance costs for compressors. For the six months ended June 30, 2000,
production taxes were $653,000 or $0.09 per Mcf as compared to $238,000 or $0.04
per Mcf for the same period in the prior year, due to higher natural gas prices.

During the six months ended June 30, 2000, depreciation, depletion and
amortization expense was $2,564,000 or $0.34 per Mcf as compared to $2,298,000
or $0.36 per Mcf for the same period in the prior year. The decrease in the cost
per Mcf for the six months in 2000 as compared to 1999 was due to the
significant increase in the estimated units of proved reserves as a result of
the number of new wells that have been drilled in 2000.

For the six months ended June 30, 2000, general and administrative expenses
were $1,902,000 as compared to $1,272,000 for the same period in the prior year.
The increase over 1999 was due to the increase in administrative staff,
salaries, and related benefits and other corporate expenses as a result of our
significant growth. Also, through March 1999, Evergreen Operating Corporation,
one of our wholly owned subsidiaries, operated properties for various third
party working interest owners. In January 1999, the working interest owners sold
those properties. As such, EOC did not receive overhead payments for the
operation of those properties after March 1999, which increased our general and
administrative expenses by $192,000 for the six months ended June 30, 2000 as
compared to the same period in 1999.

During the six months ended June 30, 2000, interest expense was $802,000
compared to $1,541,000 for the same period in the prior year. The decrease in
interest expense in 2000 was due to lower average debt balances in the first six
months of 2000 compared to the same period in 1999. In June 1999, we paid off
all outstanding debt with proceeds received from the public offering of common
stock completed in June 1999.

YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998

For the year ended December 31, 1999, we reported income from continuing
operations of $4,675,000 or $0.34 per diluted share compared to income from
continuing operations of $4,873,000 or $0.44 per diluted share in 1998. Net
income was $5,127,000 or $0.37 per diluted share for the year ended
December 31, 1999 versus net income of $5,212,000 or $0.47 per diluted share for
the same period in 1998. Net income for 1999 included a one-time, after tax gain
of $452,000 or $0.03 per diluted share, resulting from the sale of our 49%
interest in Maverick. Net income in 1998 included $339,000 in equity in earnings
for Maverick. The decrease in net income for the year ended December 31, 1999 as
compared to the prior year was attributable to a decrease in gas prices, and
increases in lease operating expense, depreciation, depletion and amortization,
general and administrative and interest expense.

During the year ended December 31, 1999, natural gas revenues increased to
$22,721,000 from $19,063,000 in the prior year. The increase in natural gas
revenues for the year ended December 31, 1999 was due to an increase in sales
volumes of 36%, which was partially offset by a 13% decrease in gas prices to
$1.66 in 1999 from $1.90 in 1998. At December 31, 1999, the number of net
producing Raton Basin wells increased to 252 from 159 net producing wells at
December 31, 1998. The increase in the number of producing wells in 1999 as
compared to 1998 is due to the drilling and completion of 83 wells in the
Spanish Peaks Unit and Cottontail Pass Unit, and our increase in our working
interest to 75% from 25% in Long Canyon (or 12 net producing wells).

On February 18, 1999, we sold our 49% interest in Maverick to the managing
members of Maverick. The closing date was April 14, 1999. On that date, we
received $2,258,000 in cash and were released from our debt guarantee with
Maverick's bank. We recorded an after tax gain on the sale of our 49% interest
of $452,000.

During the year ended December 31, 1999, lease operating expenses excluding
production taxes were $4,697,000 or $0.34 per Mcf as compared to $2,481,000 or
$0.25 per Mcf in the prior year. The

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increase in lease operating expense for the year ended December 31, 1999 as
compared to 1998 was due to the following: significant increase in water
management costs due to additional wells with high water volumes and increased
water testing costs, increase in Raton field personnel and related expense and
workover cost for on-going maintenance and repairing tubing leaks. For the year
ended December 31, 1999, production taxes were $694,000 or $0.05 per Mcf as
compared to $876,000 or $0.09 per Mcf for the prior year.

During the year ended December 31, 1999, depreciation, depletion and
amortization expense was $4,757,000 as compared to $3,860,000 in the prior year.
For the year ended December 31, 1999, depreciation, depletion and amortization
expense was $0.35 per Mcf as compared to $0.39 per Mcf in 1998. The decrease in
cost per Mcf in 1999 as compared to 1998 is due to the significant increase in
the estimated units of proved reserves as a result of the number of new wells
that have been drilled in 1999.

General and administrative expenses for the year ended December 31, 1999
were $3,024,000 as compared to $1,933,000 in the prior year. The increase in
general and administrative expenses of $1,091,000 for the year ended
December 31, 1999 is due to the increase in administrative staff, salaries and
related benefits, bonus payments and the value of stock issued for services and
other corporate expenses as a result of our significant growth. Through
March 1999, EOC operated properties for various third party working interest
owners. In January 1999, the working interest owners sold those properties. As
such, EOC did not receive overhead charges for the operation of those properties
for approximately nine months during 1999, which had been netted against general
and administrative in prior periods. Accordingly, our general and administrative
expenses increased by approximately $416,000 in 1999. General and administrative
expense per Mcf was $0.22 during the year ended December 31, 1999 compared to
$0.19 during the year ended December 31, 1998.

During the year ended December 31, 1999, interest expense was $1,927,000 as
compared to $1,870,000 in the prior year. The $57,000 increase for the year
ended December 31, 1999 is due to increased average borrowings on our line of
credit in 1999. At June 22, 1999, we paid off the outstanding balance under the
line of credit and the obligations under the capital leases with the proceeds
received from the public offering of our common shares.

YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997

We reported income from continuing operations of $4,873,000 or $0.44 per
diluted share for the year ended December 31, 1998, compared to income from
continuing operations of $5,151,000 or $0.48 per diluted share for the same
period in 1997. Pretax net income from continuing operations increased
significantly to $7,935,000 in 1998, versus $5,151,000 in 1997. As a result of a
deferred income tax provision of $3,062,000 in 1998 as compared to no deferred
income tax provision in 1997, our 1998 net income increased slightly as compared
to 1997. Net income was $5,212,000 or $0.47 per diluted share for the year ended
December 31, 1998 versus net income of $5,064,000 or $0.51 per diluted share for
the same period in 1997.

Natural gas revenues increased to $19,063,000 during the year ended
December 31, 1998 from $12,138,000 for the same period in the prior year. The
significant increase of $6,925,000 (or 57%) in 1998 compared to 1997 was due to
the increase in production and the acquisition of certain properties in the
Raton Basin. We had 159 net producing wells at the end of 1998, versus 89 at
December 31, 1997. The number of producing wells in the Spanish Peaks Unit
increased to 127 in 1998, versus 89 at December 31, 1997. We acquired
approximately 32 net producing wells in two separate transactions in 1998. Gas
production volumes in the Spanish Peaks Unit increased to 9,458,000 Mcf in 1998
versus 6,402,000 Mcf in 1997, or 48%. Gas production volumes from the acquired
properties were 563,000 Mcf in 1998. The average gas price for 1998 and 1997 was
$1.90 per Mcf.

Equity in earnings of discontinued operations, net of income taxes increased
to $339,000 during the year ended December 31, 1998 as compared to $313,000 in
1997. We accounted for the investment

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in Maverick under the equity method of accounting. The year to year increase was
offset by deferred income taxes of $217,000 in 1998, as compared to no deferred
income taxes in 1997. The pre-tax increase was due to Maverick's increase in
sales volume and profitability in 1998 as compared to 1997. As discussed
earlier, effective February 1999, we sold our 49% ownership in Maverick.

Interest and other income increased to $178,000 during the year ended
December 31, 1998 as compared to $136,000 in 1997. The increase was due to
changes in cash management in 1998.

Lease operating expenses excluding production taxes for the year ended
December 31, 1998 were $2,481,000 or $0.25 per Mcf as compared to $1,433,000 or
$0.22 per Mcf for the same period in 1997. The $0.03 increase for 1998 over the
prior year was primarily due to an increase in water management costs due to
drilling wells where there was a significant increase in water production. For
the year ended December 31, 1998, production taxes were $876,000 or $0.09 per
Mcf as compared to $574,000 or $0.09 per Mcf for the prior year.

Depreciation, depletion and amortization expense for the year ended
December 31, 1998 was $3,860,000 versus $2,794,000 in 1997. Depreciation,
depletion and amortization expense declined to $0.39 per Mcf in 1998 as compared
to $0.44 per Mcf in 1997. The decrease in cost per Mcf in 1998 as compared to
1997 was due to amortizing capital costs over a significantly greater number of
units of proved reserves.

General and administrative expenses were $1,933,000 during the year ended
December 31, 1998 versus $1,286,000 in 1997. The increase in 1998 of $647,000
was due to the expected increase in the overall growth in corporate activity.
During 1998, personnel costs increased due to the addition of new staff, salary
increases, related benefits and insurance costs. Also, office rent and other
miscellaneous operating expense items increased. Although the overall general
and administrative expenses increased for the year ended December 31, 1998, the
cost per Mcf decreased to $0.19 in 1998 from $0.20 in 1997. Through March 1999,
EOC operated properties for various third party working interest owners and the
related overhead charges received by EOC were netted against general and
administrative expenses. As discussed earlier, the working interest owners sold
those properties in January 1999.

Interest expense was $1,870,000 during the year ended December 31, 1998 as
compared to $777,000 in 1997. The $1,093,000 increase for 1998 over the same
period in the prior year was due to increased borrowings under our line of
credit to $44,139,000 from $10,812,000 in 1997. The increase in borrowings was
due to the continuing development in the Raton Basin along with the acquisition
of the Cottontail Pass Unit on July 2, 1998 at a cost of $13.1 million. On
July 1, 1998, we increased our line of credit to $50 million and also changed
the interest rate from a prime rate based loan to a LIBOR based rate. The change
in interest rates decreased our effective interest rate in the last half of 1998
by 142 basis points to 7.25%.

Other expenses were $286,000 for the year ended December 31, 1998 as
compared to $259,000 in 1997. Other expenses in 1998 included a write-off of
offering expenses of $220,000 related to the withdrawal of a registration on
file with the Securities and Exchange Commission due to unfavorable market
conditions. Other expenses in 1997 included a write-off of a receivable in the
amount of approximately $150,000 that was deemed uncollectable and gas
collection costs of $112,000.

LIQUIDITY AND CAPITAL RESOURCES

We currently have a $150 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 and Bank of Scotland (the "Banks"). The credit
facility is available through July 2003. Advances pursuant to this credit
facility are limited to a borrowing base, which is presently $150 million. At
our election, we may use either the London interbank offered rate, or LIBOR,
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. No more than four LIBOR tranches can be

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outstanding at any time under the credit facility. The borrowing base is
redetermined semi-annually by the Banks based upon reserve evaluations of our
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 oil and gas properties and also contains certain net worth,
leverage and ratio requirements. As of November 2, 2000, we had $127 million of
outstanding borrowings under this credit facility, with a current average
interest rate of 7.79%. We are currently in discussions with the Banks to
increase our credit facility to $200 million by year end.

In connection with the KLT property acquisition, we paid approximately
$70 million in cash borrowed under our credit facility, $100 million in
mandatory redeemable preferred stock and $6 million in Evergreen common stock.
In addition to the consideration paid at the closing of the acquisition, we will
be required on or before January 5, 2001 to deliver additional shares of common
stock valued at $4 million, in the event the average of the monthly settle
prices for the 2001 NYMEX natural gas contracts equals or exceeds $4.465 per
MMBtu. As additional purchase consideration, we are required to pay a monthly
net profits interest payment estimated at approximately $500,000 through the
earlier of the redemption of the preferred stock or January 1, 2003. The
purchase allocation is preliminary and will be finalized upon completion of
management's review and resolution of these purchase contingencies.

In connection with the acquisition, we issued 100,000 shares of mandatory
redeemable preferred stock, with an aggregate liquidation value of
$100 million. Each share has a liquidation and redemption value of $1,000, plus
accrued dividends. We can elect to redeem the stock at any time, and the holder
can require us to redeem it at any time after June 30, 2001, or earlier if we
complete a stock offering meeting certain conditions. The preferred stock earns
dividends from September 1, 2000 at an annual rate of 9.5% until December 31,
2000. From January 1, 2001 to March 31, 2001, the annual dividend rate would be
21.5%, and after March 31, 2001, the annual dividend rate would be 27.5%. We
intend to redeem the preferred stock on or before December 31, 2000, using new
borrowings under our credit facility. The preferred stock is not convertible.
The preferred stock has voting rights only with respect to (1) certain
extraordinary corporate transactions such as a merger, consolidation or sale of
all or substantially all of our assets; (2) the issuance of debt or equity
securities that are senior to or on par with the preferred stock; (3) the
redemption of our common stock or any other stock ranking junior to or on par
with the preferred stock; (4) the payment of dividends with respect to our
common stock; and (5) certain other matters that would affect its holders. In
addition to the special voting rights provided above, the holders of the
preferred stock shall also have the right to vote as a separate class on any
matter if required by the Colorado Business Corporation Act or any successor
statute.

During the nine months ended September 30, 2000, we spent a total of
approximately $53 million on capital expenditures, excluding the KLT property
acquisition. Activities during this period included: the drilling of 78 Raton
Basin wells (65 wells targeting the Vermejo coal formation and 13 wells
targeting the Raton coal formation), the addition of a new compressor, the
completion of the Cottontail Pass Unit 24-inch line and other large diameter
pipe, the purchase of fracture stimulation equipment to be used in our U.K.
drilling program and the costs incurred in the drilling of 5 coal bed methane
wells, 3 mine-gas interaction wells and one gob gas well in the United Kingdom.

Our capital expenditure budget for the last three months of 2000 is
approximately $29 million, of which we expect to use approximately $4 million to
drill 22 Raton Basin wells, approximately $16 million for compression and
gathering projects and approximately $4 million for well completion and testing
in our U.K. project.

We expect the increased gas production from the KLT property acquisition to
significantly increase cash flows in the fourth quarter of 2000 and in 2001. As
a result of our increased reserves from the acquisition, we also anticipate that
we will be able to increase our bank credit facility to up to $250 million by
the end of the year. The combination of these two factors should enable us to
fund the redemption of the mandatory redeemable preferred stock and our ongoing
drilling projects in the

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Raton Basin and the United Kingdom. Proceeds from this offering will be used to
reduce amounts outstanding under our credit facility, thereby increasing our
financial flexibility.

Cash flows provided by operating activities were $8,796,000 for the six
months ended June 30, 2000, as compared to cash flows provided by operating
activities of $4,721,000 for the same period in 1999. The increase was primarily
due to the increase in natural gas production and natural gas prices in 2000.

Cash flows used in investing activities were $30,584,000 during the six
months ended June 30, 2000, versus $19,696,000 for the same period in 1999. The
increase in 2000 was primarily due to the costs associated with the continued
development of the Raton Basin, including an upgrade of the gas collection
system.

Cash flows provided by financing activities were $24,405,000 during the six
months ended June 30, 2000, as compared to $16,259,000 in the same period during
1999. The increase was primarily due to increased borrowings on our line of
credit as a result of higher capital expenditures in 2000 as compared to 1999.
In June 1999, we paid off all outstanding debt with proceeds received from the
public offering of common stock completed in June 1999.

Cash flows provided by operating activities were $12,731,000 for the year
ended December 31, 1999 as compared to cash flows provided by operating
activities of $12,147,000 for the year ended December 31, 1998.

Cash flows used in investing activities were $43,864,000 during the year
ended December 31, 1999, versus $47,202,000 in 1998. The decrease in 1999 was
primarily due to proceeds of $2,258,000 received from the sale of Maverick.

Cash flows provided by financing activities were $30,471,000 during the year
ended December 31, 1999, as compared to cash flows provided by financing
activities of $34,260,000 in 1998. The decrease is primarily due to the reduced
borrowings on our line of credit given the decrease in cash used in investing
activities in 1999 as compared to 1998.

HEDGING TRANSACTIONS

Our production is generally sold at prevailing market prices. However, we
periodically enter into hedging transactions for a portion of our production
when market conditions are deemed favorable and natural gas prices exceed our
minimum internal price targets. See "-- Quantitative and Qualitative Disclosure
About Market Risk."

Our objective in entering into hedging transactions is to manage price
fluctuations and achieve a more predictable cash flow. These transactions limit
our exposure to declines in prices, but also limit the benefits we would realize
if prices increase. As of September 30, 2000, we had entered into the following
contracts to sell our gas production (our hedging contracts are denoted in
MMBtu, which convert on an approximately 1-for-1 basis into Mcf):

- 45 MMcf per day for October 2000 at an average price of $2.00 per Mcf,

- 10 MMcf per day from October 1, 2000 through December 31, 2000 at a price
of $2.10 per Mcf,

- 10 MMcf per day from November 1, 2000 through October 31, 2001 at a price
of $2.28 per Mcf, and

- 10 MMcf per day from November 1, 2000 through October 31, 2001 at a price
of NYMEX less $0.20 less fuel and transportation costs.

In addition, we have also extended a contract to sell 10 MMcf per day from
November 1, 2000 through March 31, 2001 for the lesser of then current market
price or a gross price of $2.45 per Mcf. In consideration for this contract, we
will receive $1,762,000 over the 12-month period ended

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October 31, 2000, which will be amortized over the contract term including the
extended term through March 31, 2003. As of September 30, 2000 we had received
$1,468,000, of which $980,200 has been recognized as deferred revenue and will
be recognized as revenue in future periods.

TRANSPORTATION COMMITMENTS

Due to increasing production in the Raton Basin, Colorado Interstate Gas
Company is completing a 20-inch loop of its Picketwire Lateral pipeline, which
is scheduled to be operational by December 1, 2000. This pipeline will increase
takeaway capacity by 34 MMcf per day to 134 MMcf per day. Our current firm
transportation commitments, including a recent increase and commitments assumed
with the KLT property acquisition, are 74 MMcf of gross gas sales per day,
increasing to 85 MMcf per day starting December 1, 2000. Other projects are
scheduled by CIG to further increase takeaway capacity in 2001. We have
committed to an additional 40 MMcf per day, subject to a ramp-up schedule
increasing 5 MMcf per day every four months starting October 1, 2001 through
February 2004. Thus, our total transportation obligations committed to will
increase in increments to 125 MMcf per day by February 2004. If we are unable to
fulfill our transportation commitments, amounts paid will be credited toward
future transportation costs through August 2006.

INCOME TAXES AND NET OPERATING LOSSES

As discussed in Note 7 of the notes to our consolidated financial
statements, we have net operating loss carryforwards for income tax purposes of
approximately $25 million, which expire beginning in 2004.

Prior to 1998, we were not required to record income tax expense, primarily
due to the availability of net operating loss carryforwards. However, as a
result of the recently reported profitability and the significant difference
between the book and tax basis of assets, we have been required to provide for
deferred income taxes in the statements of income in 1998 and subsequent years.
We estimate that we will utilize all of our net operating loss carryforwards in
2001 or 2002, at which time we will start to pay current income tax.

RECENT ACCOUNTING PRONOUNCEMENTS

In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for
Derivative Instruments and Hedging Activities," which establishes accounting and
reporting standards for derivative instruments, including certain derivative
instruments embedded in other contracts and for hedging activities. SFAS
No. 133, as amended by SFAS No. 137, is effective for all fiscal quarters of
fiscal years beginning after June 15, 2000. Our management believes the adoption
of this statement will not have a material impact on our financial statements.

In 1999, the SEC issued Staff Accounting Bulletin No. 101, which deals with
revenue recognition and is effective in the fourth quarter of 2000. We do not
expect its adoption to have a material effect on our financial statements.

In March 2000, the FASB issued FASB Interpretation No. 44, "Accounting for
Certain Transactions Involving Stock Compensation" ("FIN 44"), which is
effective July 1, 2000, except that certain conclusions in this Interpretation
that cover specific events that occur after either December 15, 1998 or
January 12, 2000 are recognized on a prospective basis from July 1, 2000.
FIN 44 clarifies the application of APB Opinion 25 for certain issues related to
stock issued to employees. We believe our existing stock-based compensation
policies and procedures are in compliance with FIN 44 and, therefore, that the
adoption of FIN 44 will have no material impact on our financial condition,
results of operations or cash flows.

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QUANTATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

COMMODITY RISK. Our major market risk exposure is in the pricing applicable
to our gas production. Realized pricing is primarily driven by the prevailing
price for crude oil and spot prices applicable to our United States natural gas
production. Historically, prices received for gas production have been volatile
and unpredictable. Pricing volatility is expected to continue.

We periodically enter into contractual obligations that require future
delivery of our natural gas production to attempt to manage price risk with
regard to a portion of our natural gas production. A 10% improvement in year-end
spot market prices would not have affected our physical gas contracts in place
as those contracts were lower than the spot plus 10%. A 10% decline in mid-year
spot market prices on mid-year production not covered under contractual
obligations would reduce 2000 revenues, assuming production volumes remain the
same.

INTEREST RATE RISK. At November 2, 2000, we had long-term debt outstanding
of $127 million. The interest rates on the outstanding debt range from LIBOR
plus 1.125% to prime. Interest rates are variable, however, they may be fixed at
our 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 November 2,
2000 would equal approximately 78 basis points. Such an increase in interest
rates would not materially impact our 2000 interest expense assuming borrowed
amounts remain outstanding at current levels.

FOREIGN CURRENCY RISK. Our net assets, revenue and expense accounts from
our UK subsidiary are based on the U.S. dollar equivalent of such amounts
measured in the British pound sterling. Assets and liabilities of the UK
subsidiaries 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.

We have not had any significant operations in the United Kingdom for the
past several years. In 2000, we started a drilling program consisting of 5
conventional coal bed methane wells and 4 interaction and gob gas wells. Any
significant change in the exchange rate for the pound sterling would have an
impact on the cost of the drilling program.

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BUSINESS AND PROPERTIES

GENERAL

We are an independent energy company engaged in the development, production,
operation, exploration and acquisition of natural gas properties. We are one of
the leading developers of coal bed methane reserves in the United States. Our
current operations are principally focused on developing and expanding our coal
bed methane project located in the Raton Basin in southern Colorado. We have
also begun a coal bed methane project in the United Kingdom and own additional
interests in other domestic and international areas.

We are one of the largest holders of oil and gas leases in the Raton Basin.
Including our most recent acquisition, we now hold interests in approximately
240,000 gross acres of coal bed methane properties in the basin. At
September 1, 2000, we had estimated net proved reserves of 822 Bcf, 62% of which
were proved developed, with a PV-10 of approximately $1.17 billion. Our net
daily gas sales at September 30, 2000 were approximately 75 MMcf from a total of
473 net producing wells. Total production from our wells accounts for
approximately 88% of the gas currently sold from the Raton Basin. Our Raton
Basin drilling program has enabled us to build an extensive inventory of
additional drilling locations. We have identified over 750 additional drilling
locations on our Raton Basin acreage, of which 218 were included in our
estimated proved reserve base at September 1, 2000. We operate and have a 100%
working interest in substantially all of our Raton Basin acreage and wells.

RECENT DEVELOPMENTS

KLT PROPERTY ACQUISITION

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We believe the KLT property acquisition is a strategic fit with our exising
properties that strengthens our competitive position within the Raton Basin and
will:

- provide an attractive return for our shareholders and be accretive to our
cash flow and earnings on a per-share basis;

- reduce our general and administrative expenses significantly on a per Mcf
basis;

- afford us the opportunity to achieve field operating efficiencies and
production increases through the application of our technical skills to
the recompletion of existing wells; and

UNITED KINGDOM PROJECT

BUSINESS STRATEGY

- our inventory of drilling locations in the Raton Basin,

- our track record for significantly growing our reserve base through
development drilling and acquisitions, and

- our position as a low-cost finder, developer and producer of natural gas.

To implement our strategy, we seek to:

- EXPLOIT THE RATON FORMATION. The Raton Basin contains two coal bearing
formations, the Vermejo formation coals located at depths of between 450
and 3,500 feet, and the shallower Raton formation coals located at depths
from the surface to approximately 2,000 feet. To date, substantially all
of our production and reserves have been attributable to the Vermejo
formation coals. Because the Raton formation is shallower than the Vermejo
formation, we have gathered considerable information with respect to Raton
targets in the process of drilling our Vermejo wells. To date, we have
drilled and completed 35 Raton formation wells. In some instances, we can
drill and complete Raton wells and use our existing gas collection
infrastructure from our Vermejo wells, which should reduce the total cost
of a producing Raton well. Based on our

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preliminary evaluation, we believe that we can profitably develop the
Raton formation coal seams in certain areas of the basin.

COAL BED METHANE VERSUS TRADITIONAL NATURAL GAS

Methane is the primary commercial component of the natural gas stream
produced from traditional gas wells. Methane also exists in its natural state in
coal seams. Natural gas produced from traditional wells also contains, in
varying amounts, other hydrocarbons. However, the natural gas produced from coal
beds generally contains only methane and, after simple water dehydration, is
pipeline-quality gas.

Coal bed methane production is similar to traditional natural gas production
in terms of the physical producing facilities and the product produced. However,
the subsurface mechanisms that allow the gas to move to the wellbore and the
producing characteristics of coal bed methane wells are very different from
traditional natural gas production. Unlike conventional gas wells, which require
a porous and permeable reservoir, hydrocarbon migration and a natural structural
and/or stratigraphic trap, the coal bed methane gas is trapped in the molecular
structure of the coal itself until released by pressure changes resulting from
the removal of IN SITU water.

Methane is created as part of the coalification process, though coals vary
in their methane content per ton. In addition to being in open spaces in the
coal structure, methane is absorbed onto the inner coal surfaces. When the coal
is hydraulically fracture stimulated and exposed to lower pressures through the
de-watering process, the gas leaves (desorbs from) the coal. Whether a coal bed
will produce commercial quantities of methane gas depends on the coal quality,
its original content of gas per ton of coal, the thickness of the coal beds, the
reservoir pressure and the existence of natural fractures (permeability) through
which the released gas can flow to the wellbore. Frequently, coal beds are
partly or completely saturated with water. As the water is produced, internal
pressures on the coal are decreased, allowing the gas to desorb from the coal
and flow to the wellbore. Unlike traditional gas wells, new coal bed methane
wells often produce water for several months and then, as the water production
decreases, natural gas production increases as the coal seams de-water.

In order to establish commercial gas production rates, a permanent conduit
between the individual coal seams and the wellbore must be created. This is
accomplished by hydraulically creating and propping open with special quality
sand, artificial fractures within the coal seams (known as "fracing"

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in the industry) so the pathway for water and gas migration to the wellbore is
enhanced. These fractures are filled (propped) with uniform sized sand and
become the conduits for water and methane to reach the well. The ability of gas
to move through the coal or rocks to the wellbore from its place of origination
in the formation is the key determinant of the rate at which a well will
produce.

RATON BASIN PROPERTIES AND OPERATIONS

The Raton Basin is approximately 80 miles long and 50 miles wide, located in
southern Colorado and northern New Mexico. The Raton Basin contains two coal
bearing formations, the Vermejo formation coals located at depths of between 450
and 3,500 feet and the shallower Raton formation coals, located at depths from
the surface to approximately 2,000 feet. To date, the majority of our production
has been from the Vermejo formation coals; however, the Raton formation coal
seams are now being successfully developed as well.

DEVELOPMENT HISTORY. Exploration for coal bed methane began in the Raton
Basin in the late 1970s and continued through the late 1980s, with several
companies drilling and testing over 100 wells during this period. The absence of
a pipeline to transport gas out of the Raton Basin prevented full-scale
development until January 1995, when Colorado Interstate Gas constructed the
Picketwire Lateral.

Since December 1991, we have acquired oil and gas leases covering
approximately 240,000 gross acres in the Raton Basin. The initial 70,000 acres
were acquired in 1991 with additional acreage purchased from individual owners
under various lease terms. Additional acreage positions and production have been
increased by purchases in July 1998, December 1998 and September 2000.

Currently, we have a 100% working interest in three federal units, the
Spanish Peaks Unit, the Cottontail Pass Unit and the Sangre de Cristo Unit. The
total gross acreage in the federal units is approximately 134,000 acres. We have
been named the operator for all three of these units. Formation of a unit
simplifies lease maintenance so that we, as the operator, can base development
decisions within the unit on technical, geologic and geophysical data and
operational and cultural considerations rather than on the fulfillment of lease
term obligations.

Because of the inclusion of federal leases in the unit, operation and
production within a federal unit is governed by federal rules. Production from
any well in the unit area will maintain all of the leases beyond their primary
terms. In October 1997, the first "participating area" was designated by the
federal Bureau of Land Management under the Unit Agreement. Gas production in
the participating area will be pooled and shared by the royalty owners,
overriding royalty owners and working interest owners in that area in proportion
to their acreage ownership of the mineral estate in the area. The participating
area will be adjusted annually to encompass additional acreage as additional
wells are completed.

We also have working interests of between 50% and 100% in areas adjacent to
the federal units, which include the Long Canyon and Lorencito areas and the
Primero, Rita and Westin tracks. These areas comprise approximately 106,000
acres.

RATON BASIN GEOLOGY. In the Raton Basin, we produce methane almost entirely
from the Vermejo coals, consisting of several individual seams ranging in
thickness between 1 and 12 feet, and at drilling depths between 450 and 3,500
feet below the surface. The Vermejo total coal thickness ranges from 5 to 50
feet thick through the Raton Basin, being thickest in the center of the Basin,
which our acreage surrounds. The coal beds and surrounding sedimentary rocks
formed during the late Cretaceous to early Tertiary period, between 65 and
40 million years ago. The Raton Basin is a highly asymmetric downward fold in
the earth's crust that is approximately 80 miles long north to south and about
50 miles wide east to west. Plant material accumulated in thick layers within
coastal swamps in the Raton Basin and was subsequently buried and subjected to
heat and pressure, which formed the coals. Since these coals were buried,
continued mountain building, in combination with basin downwarping, created

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an extensive series of faults and fractures in the coals and surrounding rocks.
Later, the area was intruded by hot liquid rock or "magma" from lower in the
earth's crust, which cooled to form two large mountain structures in the center
of the Raton Basin known as the Spanish Peaks. The magma moved up through
existing faults and fractures and created additional fractures that radiate
outward from the Spanish Peaks. As the magma cooled, its heat altered the
surrounding rocks, including the Vermejo and Raton coal beds. We believe that
the simultaneous downwarping of the Raton trough and Larimide age mountain
building with subsequent relaxation (extension) and the subsequent magmatic
intrusions into the Raton Basin have matured the coals and enhanced the ability
of the Vermejo and Raton coals to yield coal bed methane gas.

In the Raton Basin, we have found some coal seams to be continuous between
wells over distances of several miles, though the thickness of these beds are
variable. Individual wells are often completed to produce gas from 5 to 15
individual coal beds with individual thickness between 1 and 12 feet.

COAL BED METHANE TECHNOLOGY. We have developed what we believe to be
effective procedures for fracing the Vermejo and Raton coals in our Raton Basin
wells. In addition, we have developed well completion and specialized drilling
techniques that are suited to the Raton Basin. Traditional gas wells are drilled
with the use of rotary drill bits cooled and lubricated by drilling fluids or
"mud." Coal bed methane production is particularly sensitive to the natural
permeability of the coals. Exposing the Raton Basin coals to drilling mud
appears to significantly reduce the permeability of the coals by plugging the
coal cleat system and natural fractures in the coals. Therefore, we use
percussion air drilling (similar to a jackhammer) without traditional drilling
muds in drilling our wells.

WATER PRODUCTION AND DISPOSAL. Based on our previous experience in coal bed
methane production in the Raton Basin and extensive laboratory analysis of water
samples taken from our coal bed methane wells, we believe that the groundwater
produced from the Raton Basin coal seams will not exceed permit levels and will
continue to be low in total dissolved solids and show a general absence of
hydrocarbon contaminants such as benzene, in many cases meeting state and
federal primary drinking water standards. Recent gas analyses confirm that the
gas stream is 99% pure methane and lacks other hydrocarbon sources of
contamination. This means that we can lawfully discharge the water into well-
site pits and evaporation ponds pursuant to permits obtained from the State of
Colorado. In some cases the water is of such quality that it can be discharged
to arroyos and surface water under a general water discharge permit issued to us
by the State of Colorado. This permit gives us the flexibility to add water
discharge points on an as-needed basis with minimal administrative paperwork and
within 30 days or less of application. We currently have in excess of 200
approved discharge points. However, these and other surface disposal options
require an extensive third-party water sampling and laboratory analysis program
to ensure compliance with state permit standards. These monitoring costs are
directly related to the number of well-site pits, evaporation ponds and
discharge points. There is some uncertainty whether water currently being
discharged to streams and arroyos will continue to meet permit standards.

RATON BASIN PRODUCTION. Our natural gas sales from the Raton Basin did not
commence until the completion of a pipeline system in January 1995, which
connected our Raton Basin wells to the CIG pipelines. From January 1995 through
September 2000, we sold an aggregate of approximately 45 Bcf of coal bed methane
gas from the Raton Basin. Our net daily gas sales are currently approximately 75
MMcf per day. Because of the importance of removing water from the coal seams to
enhance gas production, we expect to continue production from more modest wells
because of the beneficial ambient effect of pressure reduction in adjacent, more
productive wells. Each well creates its own "cone of depression" around the
wellbore. We believe that some of our Raton Basin wells on adjacent

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160-acre drill sites have already created overlapping cones of depression,
enhancing gas production in each well within this pattern.

The Raton Basin gas does not contain significant amounts of contaminants,
such as hydrogen sulfide, carbon dioxide or nitrogen, that are sometimes present
in traditional natural gas production. Therefore, the properties of the Raton
Basin gas, such as heat content per unit volume (Btu), are very close to the
average properties of pipeline gas from conventional gas wells.

UNITED KINGDOM

In 1991 and 1992, our wholly owned subsidiary, Evergreen Resources
(U.K.) Ltd. ("ERUK"), was awarded seven onshore United Kingdom hydrocarbon
exploration licenses for the development of coal bed methane gas and
conventional hydrocarbons. These original licenses provided ERUK with the
largest onshore acreage position in the United Kingdom, covering substantially
all of six distinct onshore United Kingdom basins.

Selection of the licensed areas was made after evaluating geological,
geophysical, petrophysical and measured methane gas content data bases. The
majority of the original data base was acquired through technology sharing
agreements with British Coal Corporation, which shared relevant available data
on the six basins and granted use of this data to ERUK. ERUK has augmented this
data with proprietary seismic and coal bed methane well data and also geologic
data from the British Geologic Survey, and other sources.

During the period from 1992 to 1994, we conducted seismic work and drilled
three wells under two of the original licenses. The wells encountered 30 feet to
80 feet of gross coal. Two of the wells were hydraulically fracture stimulated
and one was tested for permeability. Following extensive production testing,
none of the three wells produced gas in economic quantities. The three wells are
presently shut-in.

In 1997, under a new onshore licensing regime implemented by the U.K.
Department of Trade and Industry, we converted our original licenses to new
onshore licenses, called Petroleum Exploration and Development Licenses. Under
these new licenses, we retain approximately 470,000 acres, which were
high-graded for coal bed methane and conventional hydrocarbon potential. These
licenses provide up to a 30-year term with optional periodic relinquishment of
portions of the licenses, subject to future development plans. There are no
royalties or burdens encumbering these licenses.

We believe that a major coal bed methane resource exists within the areas
subject to the current licenses. However, further evaluation will be required to
confirm such belief and determine the economic viability of extracting any
reserves. Evaluation is expected to occur on a license-by-license basis because
success or lack of success on one license may not be translated to similar
results on other licenses or separate geologic basins.

In April 2000, we began drilling activities on our coal bed methane gas
project in the United Kingdom. A total of nine wells have been drilled to date,
of which five were coal bed methane wells, three were mine-gas interaction wells
and one was a gob gas well. Total well depth ranged from 2,213 feet to 3,960
feet for coal bed methane wells and 1,485 feet to 2,156 feet for the mine-gas
interaction wells. Total coal thickness ranged from 75 feet to 97 feet of coal.
Through October 2000, we have fracture stimulated the five coal bed methane
wells using our own pumping equipment in conjunction with a new completion
technology utilizing "coiled tubing." We believe this is the first time that
nitrified foam fracs using coiled tubing technology have been used in the United
Kingdom. Coiled tubing completions isolate individual coal seams that are to be
fraced versus fracing a group of coals using current technology. Coiled tubing
also provides for a better in-zone propped fracture with increased length at
lower overall costs.

We anticipate that our evaluation of the results of the drilling program
will be completed sometime in early 2001. If the project is successful, we
believe initial gas sales could begin by the end of 2001. During the first nine
months of 2000, we invested approximately $8 million in this project and expect
to invest up to an additional $4 million through year end 2000.

S-33
<PAGE>
OTHER DOMESTIC AND INTERNATIONAL PROJECTS

We also hold interests in two international projects located in northern
Chile and the Falkland Islands. We are currently evaluating the hydrocarbon
potential of these prospects and anticipate that they will require only modest
capital expenditures through 2001. We also hold interests in northern Colorado
and are continuously evaluating additional domestic properties.

CUSTOMERS AND MARKETS

GAS MARKETING

Primero Gas Marketing Company, our wholly owned subsidiary, was formed to
market and sell natural gas for us and third parties. To date, Primero has
marketed and sold gas only on our behalf and on behalf of royalty interests and
working interest partners. Primero also operates our gas collection systems and
purchases all our production from our Raton Basin wells.

Gas production from the Raton Basin is transported by Colorado Interstate
Gas through the Campo Lateral, a 115 mile, 16-inch pipeline that connects to
CIG's main pipeline system and permits us to sell our gas into Midwest and East
Coast markets.

Current Raton Basin gas sales total approximately 100 MMcf per day. Takeaway
capacity on the CIG system from the Raton Basin is currently being expanded from
approximately 100 MMcf per day to 134 MMcf per day. This expansion is expected
to go on-line by December 2000. In addition, CIG is planning an additional 150
MMcf per day expansion in 2001. We believe that these expansions will provide
sufficient transportation capacity to accommodate significant growth in our gas
sales volumes in the future.

Our current firm transportation commitments, including a recent increase and
commitments assumed through the KLT property acquisition, are 74 MMcf of gross
gas sales per day, increasing to 85 MMcf per day starting December 1, 2000. In
addition, we have committed to an additional 40 MMcf per day, subject to a
ramp-up schedule increasing 5 MMcf per day every four months from October 1,
2001 through February 2004. Thus, our total transportation obligations committed
to will increase in increments to 125 MMcf gross per day by February 2004. If we
are unable to fulfill our transportation commitments, amounts paid will be
credited toward future transportation costs through August 2006.

MAJOR CUSTOMERS

We have three major customers, Natural Gas Transmission Services, Inc.,
E Prime Inc. and Aquila Energy Corporation, which purchased approximately 51%,
28% and 18%, respectively, of our gas sales for the nine months ended
September 30, 2000. Based on the general demand for gas, the loss of all of
these customers would not be expected to have a material adverse effect on our
business. As our base of production grows in the Raton Basin, we hope to be able
to enter into long-term contracts with end users at favorable prices. Currently,
our gas is sold at spot market prices or under contracts for terms of up to 29
months.

NATURAL GAS RESERVES

The table below sets forth our quantities of proved reserves, as audited as
of December 31, 1999, 1998 and 1997 by independent petroleum engineers
Netherland, Sewell & Associates, Inc. and Resource Services International, Inc.
Netherland Sewell and Resource Services also audited the reserve estimates for
our properties at September 1, 2000 (excluding the KLT properties) and Resource
Services audited the reserve estimates at September 1, 2000 for the KLT
properties. All of these proved reserves were located in the continental U.S.,
and the present value of estimated future net revenues from these reserves on a
non-escalated basis discounted at 10 percent per year as of periods indicated.

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<PAGE>
There has been no major discovery or other favorable or adverse event that is
believed to have caused a significant change in estimated proved reserves
subsequent to September 1, 2000.

<TABLE>
<CAPTION>
AS OF SEPTEMBER 1, 2000
AS OF DECEMBER 31, ------------------------------------
------------------------------ EVERGREEN KLT
1997 1998 1999 PROPERTIES PROPERTIES TOTAL
-------- -------- -------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Proved Developed Gas Reserves (MMcf)......... 143,554 242,987 334,804 371,319 142,327 513,646
Proved Undeveloped Gas Reserves (MMcf)....... 80,860 161,949 224,614 297,617 11,134 308,751
-------- -------- -------- ---------- -------- ----------
Total Proved Gas Reserves (MMcf)............. 224,414 404,936 559,418 668,936 153,461 822,397
======== ======== ======== ========== ======== ==========
Future Net Revenues (before future income tax
expenses) (in thousands)................... $345,410 $493,146 $820,983 $2,323,519 $539,362 $2,862,881
Present Value of Future Net Revenues (before
future income tax expenses) (in
thousands)................................. $159,326 $214,675 $331,383 $ 919,571 $245,868 $1,165,439
</TABLE>

Summaries of the reports with respect to our reserves at September 1, 2000 of
Netherland Sewell and Resource Services and the report with respect to the KLT
property reserves at September 1, 2000 of Resource Services are included as
Appendix A, Appendix B and Appendix C, respectively, to this prospectus
supplement. See also note 16 to the consolidated financial statements.

We have not filed the September 1, 2000 reserve reports of Netherland Sewell
and Resource Services with any federal agency other than the SEC.

SALES

The following table sets forth our net natural gas sales for the periods
indicated.

<TABLE>
<CAPTION>
SIX MONTHS
YEAR ENDED DECEMBER 31, ENDED JUNE 30,
------------------------------ -------------------
1997 1998 1999 1999 2000
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
Natural Gas (MMcf)..................................... 6,402 10,021 13,656 6,361 7,577
</TABLE>

AVERAGE SALES PRICES, LOE AND PRODUCTION TAXES

The following table sets forth the average sales price and the average LOE
and production taxes per Mcf for the periods indicated.

<TABLE>
<CAPTION>
SIX MONTHS
YEAR ENDED DECEMBER 31, ENDED JUNE 30,
------------------------------ -------------------
1997 1998 1999 1999 2000
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
Average sales price of natural gas (per Mcf)............. $1.90 $1.90 $1.66 $1.53 $2.07
Lease operating expenses................................. 0.22 0.25 0.34 0.33 0.41
Production taxes......................................... 0.09 0.09 0.05 0.04 0.09
</TABLE>

PRODUCTIVE WELLS

As of September 30, 2000, we had 500 gross and 473 net productive wells. We
had no productive oil wells as of that date. Productive wells are producing
wells and wells capable of production, including shut-in wells.

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<PAGE>
ACREAGE

At September 30, 2000, we held developed and undeveloped acreage as set
forth below:

<TABLE>
<CAPTION>
DEVELOPED ACRES UNDEVELOPED ACRES TOTAL
------------------- --------------------- ---------------------
LOCATION GROSS NET GROSS NET GROSS NET
-------- -------- -------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Raton Basin.......................... 99,400 88,300 140,700 102,200 240,100 190,500
United Kingdom....................... -- -- 473,400 473,400 473,400 473,400
Falkland Islands..................... -- -- 400,600 160,200 400,600 160,200
Chile................................ -- -- 2,400,000 1,800,000 2,400,000 1,800,000
Other................................ 1,800 900 21,300 15,200 23,100 16,100
------- ------ --------- --------- --------- ---------
Total................................ 101,200 89,200 3,436,000 2,551,000 3,537,200 2,640,200
======= ====== ========= ========= ========= =========
</TABLE>

The following table sets forth the expiration dates of the gross and net
acres subject to Colorado leases summarized in the table of undeveloped acreage.

<TABLE>
<CAPTION>
ACRES EXPIRING
-------------------
GROSS NET
-------- --------
<S> <C> <C>
Twelve Months Ended:
December 31, 2000........................................... -- --
December 31, 2001 and later................................. 14,700 10,200
</TABLE>

DRILLING ACTIVITIES

Our drilling activities for the periods indicated are set forth below:
<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
--------------------------------------------------------------- ---------------------
1997 1998 1999 2000
------------------- ------------------- ------------------- ---------------------
GROSS NET GROSS NET GROSS NET GROSS NET
-------- -------- -------- -------- -------- -------- -------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
EXPLORATORY WELLS
Productive............................. 4 4 0 0 0 0 0 0
Dry.................................... 0 0 0 0 0 0 0 0
-- -- -- -- -- -- -- ----------
Total.................................... 4 4 0 0 0 0 0 0

DEVELOPMENT WELLS
Productive............................. 56 56 50 50 85 83 57 57
Dry.................................... 0 0 0 0 0 0 0 0
-- -- -- -- -- -- -- ----------
Total.................................... 56 56 50 50 85 83 57 57

<CAPTION>
SIX MONTHS ENDED
JUNE 30,
---------------------
1999
---------------------
GROSS NET
-------- ----------
<S> <C> <C>
EXPLORATORY WELLS
Productive............................. 0 0
Dry.................................... 0 0
-- ----------
Total.................................... 0 0
DEVELOPMENT WELLS
Productive............................. 39 39
Dry.................................... 0 0
-- ----------
Total.................................... 39 39
</TABLE>

COMPETITION

We compete with numerous other companies in virtually all facets of our
business, including many that have significantly greater resources. Such
competitors may be able to pay more for desirable leases and to evaluate, bid
for and purchase a greater number of properties than our financial or personnel
resources permit. Our ability to increase reserves in the future will be
dependent on our ability to select and acquire suitable producing properties and
prospects for future exploration and development. The availability of a market
for oil and natural gas production depends upon numerous factors beyond the
control of producers, including but not limited to the availability of other
domestic or imported production, the locations and capacity of pipelines, and
the effect of federal and state regulation on such production.

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<PAGE>
GOVERNMENT REGULATION OF THE OIL AND GAS INDUSTRY

GENERAL

Our business is affected by numerous laws and regulations, including energy,
environmental, conservation, tax and other laws and regulations relating to the
energy industry. Failure to comply with these laws and regulations may result in
the assessment of administrative, civil and criminal penalties, the imposition
of injunctive relief or both. Moreover, changes in any of these laws and
regulations could have a material adverse effect on our business. In view of the
many uncertainties with respect to current and future laws and regulations,
including their applicability to us, we cannot predict the overall effect of
such laws and regulations on our future operations.

We believe that our operations comply in all material respects with
applicable laws and regulations and that the existence and enforcement of such
laws and regulations have no more restrictive an effect on our operations than
on other similar companies in the energy industry.

The following discussion contains summaries of certain laws and regulations
and is qualified in its entirety by the foregoing.

FEDERAL REGULATION OF THE SALE AND TRANSPORTATION OF OIL AND GAS

Various aspects of our oil and natural gas operations are regulated by
agencies of the federal government. The Federal Energy Regulatory Commission, or
FERC, regulates the transportation and sale for resale of natural gas in
interstate commerce pursuant to the Natural Gas Act of 1938, or NGA, and the
Natural Gas Policy Act of 1978, or NGPA. In the past, the federal government has
regulated the prices at which oil and gas could be sold. While "first sales" by
producers of natural gas, and all sales of crude oil, condensate and natural gas
liquids can currently be made at uncontrolled market prices, Congress could
reenact price controls in the future. Deregulation of wellhead sales in the
natural gas industry began with the enactment of the NGPA in 1978. In 1989,
Congress enacted the Natural Gas Wellhead Decontrol Act. The Decontrol Act
removed all NGA and NGPA price and non-price controls affecting wellhead sales
of natural gas effective January 1, 1993.

Commencing in April 1992, the FERC issued Order Nos. 636, 636-A, 636-B,
636-C and 636-D ("Order No. 636"), which require interstate pipelines to provide
transportation services separate, or "unbundled," from the pipelines' sales of
gas. Also, Order No. 636 requires pipelines to provide open access
transportation on a nondiscriminatory basis that is equal for all natural gas
shippers. Although Order No. 636 does not directly regulate our production
activities, the FERC has stated that it intends for Order No. 636 to foster
increased competition within all phases of the natural gas industry. It is
unclear what impact, if any, increased competition within the natural gas
industry under Order No. 636 will have on our activities.

The courts have largely affirmed the significant features of Order No. 636
and numerous related orders pertaining to the individual pipelines, although
certain appeals remain pending and the FERC continues to review and modify their
open access regulations. In particular, the FERC is conducting a broad review of
their transportation regulations, including how they operate in conjunction with
state proposals for retail gas market restructuring, whether to eliminate
cost-of-service rates for short-term transportation, whether to allocate all
short-term capacity on the basis of competitive auctions, and whether changes to
long-term transportation policies may also be appropriate to avoid a market bias
toward short-term contracts. In February 2000, the FERC issued Order No. 637
amending certain regulations governing interstate natural gas pipeline companies
in response to the development of more competitive markets for natural gas and
natural gas transportation. The goal of Order No. 637 is to "fine tune" the open
access regulations implemented by Order No. 636 to accommodate subsequent
changes in the market. Key provisions of Order No. 637 include: (1) waiving the
price ceiling for short-term capacity release transactions until September 30,
2002, subject to review and possible extension of the program at that time;
(2) permitting value-oriented peak/off peak rates to better allocate revenue

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<PAGE>
responsibility between short-term and long-term markets; (3) permitting
term-differentiated rates, in order to better allocate risks between shippers
and the pipeline; (4) revising the regulations related to scheduling procedures,
capacity, segmentation, imbalance management, and penalties; (5) retaining the
right of first refusal ("ROFR") and the 5 year matching cap for long-term
shippers at maximum rates, but significantly narrowing the ROFR for customers
that the FERC does not deem to be captive; and (6) adopting new web site
reporting requirements that include daily transactional data on all firm and
interruptible contracts and daily reporting of scheduled quantities at points or
segments. The new reporting requirements became effective September 1, 2000. We
cannot predict what action the FERC will take on these matters in the future,
nor can we accurately predict whether the FERC's actions will, over the long
term, achieve the goal of increasing competition in markets in which our natural
gas is sold. However, we do not believe that we will be affected by any action
taken materially differently than other natural gas producers and marketers with
which we compete.

Commencing in October 1993, the FERC issued a series of rules (Order Nos.
561 and 561-A) establishing an indexing system under which oil pipelines are
able to change their transportation rates, subject to prescribed ceiling levels.
The indexing system, which allows pipelines to make rate changes to track
changes in the Producer Price Index for Finished Goods, minus one percent,
became effective January 1, 1995. We do not believe that these rules affect us
any differently than other oil producers and marketers with which we compete.

The FERC has also issued numerous orders confirming the sale and abandonment
of natural gas gathering facilities previously owned by interstate pipelines and
acknowledging that if the FERC does not have jurisdiction over services provided
thereon, then such facilities and services may be subject to regulation by state
authorities in accordance with state law. A number of states have either enacted
new laws or are considering the adequacy of existing laws affecting gathering
rates and/or services. Other state regulation of gathering facilities generally
includes various safety, environmental, and in some circumstances,
nondiscriminatory take requirements, but does not generally entail rate
regulation. Thus, natural gas gathering may receive greater regulatory scrutiny
of state agencies in the future. Our gathering operations could be adversely
affected should they be subject in the future to increased state regulation of
rates or services, although we do not believe that we would be affected by such
regulation any differently than other natural gas producers or gatherers. In
addition, the FERC's approval of transfers of previously-regulated gathering
systems to independent or pipeline affiliated gathering companies that are not
subject to FERC regulation may affect competition for gathering or natural gas
marketing services in areas served by those systems and thus may affect both the
costs and the nature of gathering services that will be available to interested
producers or shippers in the future.

We own certain natural gas pipeline facilities that we believe meet the
traditional tests the FERC has used to establish a pipeline's status as a
gatherer not subject to the FERC jurisdiction. Whether on state or federal land,
natural gas gathering may receive greater regulatory scrutiny in the post-Order
No. 636 environment.

We conduct certain operations on federal oil and gas leases, which are
administered by the Minerals Management Service, or MMS. Federal leases contain
relatively standard terms and require compliance with detailed MMS regulations
and orders, which are subject to change. Among other restrictions, the MMS has
regulations restricting the flaring or venting of natural gas, and has proposed
to amend such regulations to prohibit the flaring of liquid hydrocarbons and oil
without prior authorization. Under certain circumstances, the MMS may require
any of our operations on federal leases to be suspended or terminated. Any such
suspension or termination could materially and adversely affect our financial
condition, cash flows and operations. The MMS recently issued a final rule that
amended its regulations governing the valuation of crude oil produced from
federal leases. This new rule, which became effective June 1, 2000, provides
that the MMS will collect royalties based on the market value of oil produced
from federal leases. The lawfulness of the new rule has been challenged in
federal court. We cannot predict whether this new rule will be upheld in federal
court,

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<PAGE>
nor can we predict whether the MMS will take further action on this matter.
However, we do not believe that this new rule will affect us any differently
than other producers and marketers of crude oil.

Additional proposals and proceedings that might affect the oil and gas
industry are pending before Congress, the FERC, the MMS, state commissions and
the courts. We cannot predict when or whether any such proposals may become
effective. In the past, the natural gas industry has been heavily regulated.
There is no assurance that the regulatory approach currently pursued by various
agencies will continue indefinitely. Notwithstanding the foregoing, we do not
anticipate that compliance with existing federal, state and local laws, rules
and regulations will have a material or significantly adverse effect upon our
capital expenditures, earnings or competitive position. No material portion of
our business is subject to re-negotiation of profits or termination of contracts
or subcontracts at the election of the federal government.

BUREAU OF LAND MANAGEMENT

Of our Raton Basin acreage, approximately 134,000 gross acres are held
within three federal units that we operate and that are administered by the
federal Bureau of Land Management. See "-- Raton Basin Properties and
Operations." Inclusion of property within a unit simplifies lease maintenance
for us and promotes orderly development of our coal bed methane project.

On September 30, 1999, the BLM advised us of their intent to withdraw as the
administrator of the Spanish Peaks Unit effective January 1, 2000. After a
hearing in October 1999 where we opposed the BLM's withdrawal, the agency
vacated its initial decision and commended us for our exemplary development of
this natural resource. Subsequently, certain interested parties appealed the
BLM's decision to remain the administrator of the unit on the grounds that we
did not give proper notice of the decision to all interested parties. As a
result of this procedural deficiency, the matter was remanded to the BLM. At our
request, a new hearing was held on October 18, 2000, and on October 27, 2000 the
BLM again vacated its initial decision.

STATE REGULATION -- UNITED STATES

Our operations are also subject to regulation at the state and in some
cases, county, municipal and local governmental levels. Such regulation includes
requiring permits for the drilling of wells, maintaining bonding requirements in
order to drill or operate wells and regulating the location of wells, the method
of drilling and casing wells, the surface use and restoration of properties upon
which wells are drilled, the plugging and abandonment of wells and the disposal
of fluids used and produced in connection with operations. Our operations are
also subject to various conservation laws and regulations. These include
(1) the size of drilling and spacing units or proration units, (2) the density
of wells that may be drilled and (3) the unitization or pooling of oil and gas
properties. In addition, state conservation laws, which frequently establish
maximum rates of production from oil and gas wells, generally prohibit the
venting or flaring of gas and impose certain requirements regarding the
ratability of production. State regulation of gathering facilities generally
includes various safety, environmental and, in some circumstances,
nondiscriminatory take requirements, but (except as noted above) does not
generally entail rate regulation. These regulatory burdens may affect
profitability, but we are unable to predict the future cost or impact of
complying with such regulations.

ENVIRONMENTAL MATTERS

We are subject to extensive federal, state and local environmental laws that
regulate the discharge or disposal of materials or substances into the
environment and otherwise are intended to protect the environment. Numerous
governmental agencies issue rules and regulations to implement and enforce such
laws, which are often difficult and costly to comply with and which carry
substantial administrative, civil and criminal penalties and in some cases
injunctive relief for failure to comply. Some laws, rules and regulations
relating to the protection of the environment may, in certain circumstances,
impose

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"strict liability" for environmental contamination. Such laws render a person or
company liable for environmental and natural resource damages, cleanup costs
and, in the case of oil spills in certain states, consequential damages without
regard to negligence or fault. Other laws, rules and regulations may require the
rate of oil and natural gas production to be below the economically optimal rate
or may even prohibit exploration or production activities in environmentally
sensitive areas. In addition, state laws often require some form of remedial
action, such as closure of inactive pits and plugging of abandoned wells, to
prevent pollution from former or suspended operations. Legislation has been
proposed in the past and continues to be evaluated in Congress from time to time
that would reclassify certain oil and gas exploration and production wastes as
"hazardous wastes." This reclassification would make such wastes subject to much
more stringent storage, treatment, disposal and clean-up requirements. If such
legislation were to be enacted, it could have a significant adverse impact on
our operating costs, as well as those of the oil and gas industry in general.
Initiatives to further regulate the disposal of oil and gas wastes are also
proposed in certain states from time to time and may include initiatives at the
county, municipal and local government levels. These various initiatives could
have a similar adverse impact on us. The regulatory burden on the oil and
natural gas industry increases our cost and risk of doing business and
consequently affects our profitability.

Compliance with these environmental requirements, including financial
assurance requirements and the costs associated with the cleanup of any spill,
could have a material adverse effect upon our capital expenditures, earnings or
competitive position. We believe that we are in substantial compliance with
current applicable environmental laws and regulations and that continued
compliance with existing requirements will not have a material adverse impact on
us. Nevertheless, changes in environmental laws have the potential to adversely
affect our operations. For example, the federal Comprehensive Environmental
Response, Compensation and Liability Act, or CERCLA, also known as the
"Superfund" law, imposes liability, without regard to fault or the legality of
the original conduct, on certain classes of persons with respect to the release
of a "hazardous substance" into the environment. These persons include the
current or prior owner or operator of the disposal site or sites where the
release occurred and companies that transported, disposed or arranged for the
transport or disposal of the hazardous substances found at the site. Persons who
are or were responsible for releases of hazardous substances under CERCLA may be
subject to joint and several liability for the costs of cleaning up the
hazardous substances that have been released into the environment and for
damages to natural resources, and it is not uncommon for the federal or state
government to pursue such claims. It is also not uncommon for neighboring
landowners and other third parties to file claims for personal injury or
property or natural resource damages allegedly caused by the hazardous
substances released into the environment. Under CERCLA, certain oil and gas
materials and products are, by definition, excluded from the term "hazardous
substances." At least two federal courts have held that certain wastes
associated with the production of crude oil may be classified as hazardous
substances under CERCLA. Similarly, under the federal Resource, Conservation and
Recovery Act, or RCRA, which governs the generation, treatment, storage and
disposal of "solid wastes" and "hazardous wastes," certain oil and gas materials
and wastes are exempt from the definition of "hazardous wastes." This exemption
continues to be subject to judicial interpretation and increasingly stringent
state interpretation. During the normal course of our operations, we generate or
have generated in the past exempt and non-exempt wastes, including hazardous
wastes, that are subject to RCRA and comparable state statutes and implementing
regulations. The federal Environmental Protection Agency and various state
agencies continue to promulgate regulations that limit the disposal and
permitting options for certain hazardous and non-hazardous wastes.

We currently own or lease, and have in the past owned or leased, several
properties that have long been used to store and maintain oil and gas
exploration and production equipment. In particular, our current and prior
operations included oil and gas production in the Rocky Mountain states and the
portion of the Permian Basin that lies within the State of New Mexico. Although
we utilized operating and disposal practices that were standard for the industry
at the time, hydrocarbons, materials or other wastes may in the past have been
disposed of or released on or under the properties owned or leased

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by us or on or under other locations where such wastes have been taken for
disposal. In addition, many of these properties have from time to time been
operated by third parties whose management of hydrocarbons, hazardous materials
and wastes was not under our control. These properties and the waste disposed
thereon may be subject to CERCLA, RCRA, and analogous state laws and
regulations. Under such laws and regulations, we could be required to remove or
remediate previously disposed wastes (including wastes disposed of or released
by prior owners or operators) or property contamination (including groundwater
contamination).

In connection with our coal bed methane gas production, we from time to time
conduct production enhancement techniques, including various activities designed
to induce hydraulic fracturing of the coal bed. While we perform our production
enhancement techniques in substantial compliance with the requirements set forth
by the State of Colorado, neither Colorado nor the EPA regulates this coal bed
formation fracturing as a form of underground injection. On August 7, 1997, the
U.S. Court of Appeals for the Eleventh Circuit held, in a case brought by a
citizen environmental organization, that hydraulic fracturing performed in coal
bed methane gas production in Alabama falls within the definition of
"underground injection" as defined in the federal Safe Drinking Water Act and,
therefore, that the EPA is required to regulate this activity. As a consequence
of this holding, the Eleventh Circuit also granted a petition filed by the
plaintiff in the case to review the EPA's refusal to initiate proceedings that
would withdraw federal approval of Alabama's Underground Injection Control
program. The EPA has recently commenced a comprehensive study of environmental
risks associated with coal bed methane hydraulic fracturing techniques and
anticipates that its final report will be completed by winter 2002. It is
possible that hydraulic fracturing of coal beds for methane gas production will
become regulated within the United States as a form of underground injection,
resulting in the imposition of stricter performance standards (which, if not
met, could result in diminished opportunities for methane gas production
enhancement) and increased administrative and operating costs for us. Our
management cannot predict at this time whether potential future regulation of
hydraulic fracturing as a form of underground injection would have an adverse
material effect on our operations or financial position. However, such
regulation is not expected to be any more burdensome to us than it would be to
other similarly situated companies involved in coal bed methane gas production
or tight gas sands production within the United States.

In our coal bed methane gas production, we typically bring naturally
occurring groundwater to the surface as a by-product of the production of
methane gas. This "produced groundwater" is either re-injected into the
subsurface or stored or disposed of in evaporation ponds or permitted natural
collection features located on the surface at or near the well-site in
compliance with federal and state statutes and regulations. In some cases, the
produced groundwater is used for stock watering, agricultural or dust
suppression purposes, also in substantial compliance with federal, state and
local laws and regulations. The legal and regulatory classification of this
produced groundwater under the environmental laws discussed above as well as
under the Clean Water Act, a strict liability statute that governs the discharge
of "pollutants" to "waters of the United States," has been a source of dispute,
as discussed below and in the section entitled "Legal Proceedings." Under the
Clean Water Act and various other state requirements and regulations, the EPA,
the State of Colorado Department of Public Health and the Environment, or CDPHE,
and the Colorado Oil and Gas Conservation Commission each continue to assert
administrative and regulatory enforcement authority over the storage and
disposal of such produced groundwater. The EPA and the CDPHE have recently
clarified their classification of either: (1) produced groundwater as a
"pollutant," and (2) the storage, use and disposal of such water on the surface
as a "discharge to waters of the United States." This regulatory determination
could have a significant impact on the regulatory treatment of this groundwater
management practice and on our understanding of our past and future compliance
in connection with the Clean Water Act. On January 7, 2000, EOC, one of our
wholly owned subsidiaries, agreed to a Compliance Order on Consent from the
CDPHE that resolved certain water storage and discharge issues between the CDPHE
and EOC. Under the Consent Order, EOC has obtained additional permits and has
the option to install a water supply system as a Supplemental Environmental
Project ("SEP"),

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in lieu of civil penalties, that will benefit rural landowners in the areas in
which we operate. We may process a portion of our produced water to meet
potability standards. Under the Consent Order, the maximum cost of the SEP is
$360,000. The Consent Order resolves all outstanding issues between EOC and
Colorado state regulatory agencies, particularly the CDPHE, governing the
discharge of produced water from our coal bed methane operations in the Raton
Basin.

Our operations involve the use of gas fired compressors to transport
collected gas; these compressors are subject to federal and state regulations
for the control of air emissions. We have submitted a Title V permit application
for our Burro Canyon compressor facility and construction permits for other
gas-fired compressors and facilities, as applicable. Title V status for a
facility results in significant increased testing, monitoring and administrative
and compliance costs. To date, other compressor facilities have not triggered
Title V requirements due to the design of the facility and the use of
state-of-the-art engines and pollution control equipment that serve to reduce
air emissions. We have obtained construction permits for additional compression
in excess of current needs in anticipation of increased production from Raton
Basin. However, in the future, additional facilities could become subject to
Title V requirements as compressor facilities are expanded or if regulatory
interpretations of Title V applicability change. Stack testing and emissions
monitoring costs will grow as these facilities are expanded and if they trigger
Title V. We recently received a Compliance Order on Consent resolving the CDPHE
Air Pollution Control Division's allegations that we violated certain air
permitting requirements. As settlement of these claims, we have agreed to pay a
$52,000 civil penalty and perform a SEP, including the installation of pollution
control equipment, at a combined cost of approximately $100,000. We believe that
we are in substantial compliance with applicable laws, rules and regulations
relating to the control of air emissions at all of our facilities. We are
exploring the possibility of favorable tax treatment from the State of Colorado
for the installation of oxidizing catalysts to reduce carbon monoxide emissions
from our compressor facilities.

Although we maintain insurance against some, but not all, of the risks
described above, including insuring the costs of clean-up operations, public
liability and physical damage, there is no assurance that such insurance will be
adequate to cover all such costs, that such insurance will continue to be
available in the future or that such insurance will be available at premium
levels that justify our purchase. The occurrence of a significant event not
fully insured or indemnified against could have a material adverse effect on our
financial condition and operations.

Our oil and gas operations outside of the United States are subject to
similar foreign governmental controls and restrictions pertaining to the
environment. We believe that compliance with existing requirements of such
governmental bodies has not had a material adverse effect on our operations.

At this time, we have no plans to make any material capital expenditures for
environmental control facilities.

LEGAL PROCEEDINGS

Except as provided below, we are not engaged in any material legal
proceedings to which we or our subsidiaries are a party or to which any of our
property is subject.

On July 13, 1998, a localized group of citizens, Southern Colorado C.U.R.E.,
filed a lawsuit against EOC under the citizen suit provision of the Clean Water
Act in the U.S. District Court for the District of Colorado, related to EOC's
water production associated with coal bed methane drilling operations in the
Raton Basin near Trinidad, Colorado. EOC also coordinated with the EPA and the
State of Colorado in the investigation of certain practices in connection with
these operations. On January 7, 2000, EOC entered into a Compliance Order on
Consent with the CDPHE that resolved water quality/ discharge issues between the
CDPHE and EOC. As a result, as anticipated, the U.S. District Court granted our
Motion to Dismiss the citizen suit, with prejudice, on the grounds that the
Consent Order moots the federal case and bars C.U.R.E. from seeking further
penalties for the same alleged violations. The only outstanding matter related
to this case pertains to the assertion by C.U.R.E. that it

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is entitled to attorneys fees and costs, which we dispute and have vigorously
contested. Even if fees are granted, payment of C.U.R.E.'s fees will not have a
material adverse effect on our operations.

TITLE TO PROPERTIES

As is customary in the oil and gas industry, only a preliminary title
examination is conducted at the time we acquire leases of properties believed to
be suitable for drilling operations. Prior to the commencement of drilling
operations, a thorough title examination of the drill site tract is conducted by
independent attorneys. Once production from a given well is established, we
prepare a division order title report indicating the proper parties and
percentages for payment of production proceeds, including royalties. We believe
that titles to our leasehold properties are good and defensible in accordance
with standards generally acceptable in the oil and gas industry.

EMPLOYEES

At September 30, 2000, we had 111 full time employees.

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MANAGEMENT

Our executive officers and directors and their respective positions and ages
are set forth below:

<TABLE>
<CAPTION>
NAME AGE POSITION
---- -------- ------------------------------------------
<S> <C> <C>
Mark S. Sexton............................ 44 President, Chief Executive Officer and
Director
Dennis R. Carlton......................... 50 Senior Vice President of Exploration &
Operations and Director
Kevin R. Collins.......................... 43 Vice President Finance, Chief Financial
Officer and Treasurer
Alain G. Blanchard........................ 60 Director
Larry D. Estridge......................... 56 Director
John J. Ryan III.......................... 73 Director
Scott D. Sheffield........................ 48 Director
Arthur L. Smith........................... 48 Director
</TABLE>

MARK S. SEXTON joined Evergreen in 1989, through a merger of companies, and
initially managed the daily operating activities of EOC, Evergreen's operating
subsidiary. He has been a director of Evergreen since March 1995 and was named
President and CEO in June 1995. Mr. Sexton is a registered professional engineer
in Colorado. He graduated in 1978 from Stanford University with a B.S. degree in
mechanical engineering. He was previously employed in various technical,
financial, and management positions with Amoco Production Company, Norwest Bank,
and energy companies specifically targeting coal bed methane development.
Mr. Sexton is also a director of KFX, Inc.

DENNIS R. CARLTON joined Evergreen in 1981 and was named a director in
March 1995. He is currently Evergreen's Senior Vice President of Exploration and
Operations and also manages the daily activities of EOC. He received a B.S.
degree in geology in 1972 and a masters of science degree in geology in 1975
from Wichita State University. Mr. Carlton was also a director of Evergreen from
1985 to 1989.

KEVIN R. COLLINS joined Evergreen as Vice President and Treasurer in
June 1995. He has over 13 years of public accounting experience. Mr. Collins
received a B.S. in business administration and accounting from the University of
Arizona in 1980, and, before working with Evergreen, was employed by BDO
Seidman, LLP, where he was a senior manager.

ALAIN G. BLANCHARD was named director of Evergreen in May 1989. He has
managed discretionary funds for private and institutional clients for over
20 years and continues to do so. Mr. Blanchard graduated from the University of
Paris with a doctorate in economics and a degree in political science.

LARRY D. ESTRIDGE was named a director of Evergreen in May 1989. He received
an A.B. degree from Furman University in 1966 and a J.D. from Harvard University
School of Law in 1969. He is a partner in the law firm Womble Carlyle
Sandridge & Rice, PLLC. Mr. Estridge joined Womble Carlyle in January 1999.
Prior to January 1999, he was a partner with Wyche, Burgess, Freeman & Parham,
P.A. from July 1972 through December 31, 1998. He has represented Evergreen and
a number of affiliated companies for over 14 years.

JOHN J. RYAN III was named a director of Evergreen in May 1989. Since 1982
he has been engaged in international tax and investment activities through
Corporate Investment Services, of which he is a principal. Mr. Ryan is also
Chairman of Evergreen Resources (U.K.) Ltd., a wholly owned subsidiary of
Evergreen. Mr. Ryan serves as a director of Vail Resorts, Inc.

SCOTT D. SHEFFIELD was named a director of Evergreen in September 1996.
Since April 1985, Mr. Sheffield has served as President and Chief Executive
Officer of Pioneer Natural Resources Company, an energy company traded on the
New York Stock Exchange, and its predecessor company, Parker & Parsley Petroleum
Company. From 1979 to April 1985 he was employed by Parker & Parsley

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in various engineering positions, including serving from 1981 to 1985 as Vice
President of Engineering. Mr. Sheffield obtained a bachelor of science degree in
petroleum engineering from the University of Texas in 1975.

ARTHUR L. SMITH was named a director of Evergreen in June 2000. Since 1984,
Mr. Smith has been Chairman and Chief Executive Officer of John S.
Herold, Inc., an energy research and consulting firm based in Norwalk,
Connecticut. Prior to joining John S. Herold, Inc., he was involved in
institutional equity research and corporate finance for Oppenheimer and Co.,
Inc., The First Boston Corp. and Argus Research Corp. Mr. Smith received a B.A.
from Duke University and an MBA from New York University's Stern School of
Business. Mr. Smith is also a director of Cabot Oil & Gas Corporation and Plains
All American Inc.

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<PAGE>
UNDERWRITING

Subject to the terms and conditions of the underwriting agreement between
Evergreen and the underwriters, the underwriters have agreed severally to
purchase from Evergreen the following number of shares of common stock at the
offering price less the underwriting discount set forth on the cover page of
this prospectus supplement.

<TABLE>
<S> <C>
NUMBER
UNDERWRITER OF SHARES
------------------------------------------------------------ ---------
A.G. Edwards & Sons, Inc.................................... 994,000
ING Barings LLC............................................. 639,000
PaineWebber Incorporated.................................... 639,000
Howard Weil, a division of Legg Mason Wood Walker, Inc...... 284,000
Brean Murray & Co., Inc..................................... 142,000
Hibernia Southcoast Capital................................. 142,000
---------
Total....................................................... 2,840,000
=========
</TABLE>

The underwriting agreement provides that the obligations of the underwriters
are subject to certain conditions precedent and that the underwriters will
purchase all such shares of the common stock if any of such shares are
purchased. The underwriters are obligated to take and pay for all of the shares
of common stock offered hereby (other than those covered by the over-allotment
option described below) if any are taken.

The underwriters have advised Evergreen that they propose to offer such
shares of common stock to the public at the offering price set forth on the
cover page of this prospectus supplement and to certain dealers at such price
less a concession not in excess of $0.85 per share. The underwriters may allow,
and such dealers may re-allow, a concession not in excess of $0.10 per share to
certain other dealers. After the offering, the offering price and other selling
terms may be changed by the underwriters.

Pursuant to the underwriting agreement, Evergreen has granted to the
underwriters an option, exercisable for thirty (30) days after the date of this
prospectus supplement, to purchase up to 426,000 additional shares of common
stock at the offering price, less the underwriting discount set forth on the
cover page of this prospectus supplement, solely to cover over-allotments.

To the extent that the underwriters exercise such option, the underwriters
will become obligated, subject to certain conditions, to purchase approximately
the same percentage of such additional shares as the number set forth next to
such underwriter's name in the preceding table bears to the total number of
shares in such table, and Evergreen will be obligated, pursuant to the option,
to sell such shares to the underwriters.

Evergreen and each of its directors and executive officers have agreed not
to sell or otherwise dispose of any shares of common stock for a period of 120
days after the date of this prospectus without the prior written consent of A.G.
Edwards & Sons, Inc. A.G. Edwards may, in its sole discretion, allow any of
these parties to dispose of common stock or other securities prior to the
expiration of such 120-day period. There are, however, no agreements between
A.G. Edwards and these parties that would allow them to do so as of the date of
this prospectus supplement.

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<PAGE>
The following table summarizes the discounts that Evergreen will pay to the
underwriters in the offering. These amounts assume both no exercise and full
exercise of the underwriters' option to purchase additional shares of common
stock.

<TABLE>
<CAPTION>
NO EXERCISE FULL EXERCISE
----------- -------------
<S> <C> <C>
Per Share................................................... $ 1.44 $ 1.44
Total....................................................... $4,089,600 $4,703,040
</TABLE>

Evergreen expects to incur expenses of approximately $600,000 in connection
with this offering.

Evergreen has agreed to indemnify the underwriters against certain
liabilities, including liabilities under the Securities Act.

Until the distribution of the common stock is completed, rules of the SEC
may limit the ability of the underwriters and certain selling group members to
bid for and purchase the common stock. As an exception to these rules, the
underwriters are permitted to engage in certain transactions that stabilize,
maintain or otherwise affect the price of the common stock.

If the underwriters create a short position in the common stock in
connection with the offering, i.e., if they sell a greater aggregate number of
shares of common stock than is set forth on the cover page of this prospectus
supplement, the underwriters may reduce the short position by purchasing shares
of common stock in the open market. This is known as a "syndicate covering
transaction." The underwriters may also elect to reduce any short position by
exercising all or part of the over-allotment option described above.

The underwriters may also impose a penalty bid on certain selling group
members. This means that if the underwriters purchase common stock in the open
market to reduce the selling group members' short position or to stabilize the
price of the common stock, it may reclaim the amount of the selling concession
from the selling group members who sold those shares of common stock as part of
the offering.

In general, purchases of a security for the purpose of stabilization or to
reduce a short position could cause the price of the security to be higher than
it might be in the absence of such purchases. The imposition of a penalty bid
might also have an effect on the price of a security to the extent that it were
to discourage resales of the security.

Neither Evergreen nor the underwriters makes any representation or
prediction as to the direction or magnitude of any effect that the transactions
described above may have on the price of the common stock. In addition, neither
Evergreen nor the underwriters makes any representation that the underwriters
will engage in these transactions or that these transactions, once commenced,
will not be discontinued without notice.

Hibernia National Bank, which is affiliated with Hibernia Southcoast
Capital, one of the underwriters, is a lender under Evergreen's existing credit
facility and has received customary fees in connection with this credit
facility. The net proceeds of this offering will be used to repay part of
Evergreen's indebtedness under the credit facility. Hibernia Southcoast Capital
is participating in the offering on the same terms as the other underwriters and
will not receive any benefit in connection with the offering other than
customary managing, underwriting and selling fees.

Each of A.G. Edwards & Sons, Inc. and Howard Weil, a division of Legg Mason
Wood Walker, Inc., has provided, and may in the future provide, financial
advisory and investment banking services to Evergreen from time to time.

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<PAGE>
LEGAL MATTERS

Berenbaum, Weinshienk & Eason, P.C., Denver, Colorado has provided us with a
legal opinion on the validity of the common stock offered by this prospectus
supplement. Certain other matters will be passed upon for us by Womble Carlyle
Sandridge & Rice, PLLC, Washington, D.C. One of our directors, Larry D.
Estridge, is a partner with Womble Carlyle. Certain matters will be passed upon
for the underwriters by Vinson & Elkins L.L.P., Houston, Texas.

EXPERTS

The financial statements included and incorporated by reference in this
prospectus supplement and the accompanying prospectus have been audited by BDO
Seidman, LLP, independent certified public accountants, to the extent and for
the periods set forth in their report included herein, and are included herein
in reliance upon such report given upon the authority of said firm as experts in
auditing and accounting.

The estimated reserve evaluations and related calculations of Netherland,
Sewell & Associates, Inc., independent petroleum engineering consultants,
included and incorporated by reference in this prospectus supplement and the
accompanying prospectus have been included herein in reliance upon the authority
of said firm as experts in petroleum engineering.

The estimated reserve evaluations and related calculations of Resource
Services International, Inc., independent petroleum engineering consultants,
included and incorporated by reference in this prospectus supplement and the
accompanying prospectus have been included herein in reliance upon the authority
of said firm as experts in petroleum engineering.

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<PAGE>
GLOSSARY OF COMMON OIL AND GAS TERMS

The following are definitions of terms commonly used in the oil and natural
gas industry and this document.

Unless otherwise indicated in this document, natural gas volumes are stated
at the legal pressure base of the state or area in which the reserves are
located at 60 degrees Fahrenheit. As used in this document, the following terms
have the following specific meanings: "Mcf" means thousand cubic feet, "MMcf"
means million cubic feet, "Bcf" means billion cubic feet, "Btu" means British
Thermal Unit, or the quantity of heat required to raise the temperature of one
pound of water by one degree Fahrenheit, and "MMBtu" means million British
thermal units.

CAPITAL EXPENDITURES. Costs associated with exploratory and development
drilling (including exploratory dry holes); leasehold acquisitions; seismic data
acquisitions; geological, geophysical and land related overhead expenditures;
delay rentals; producing property acquisitions; other miscellaneous capital
expenditures; compression equipment and pipeline costs.

DEVELOPED ACREAGE. The number of acres that are allocated or assignable to
producing wells or wells capable of production.

DEVELOPMENT WELL. A well drilled within the proved area of an oil or
natural gas reservoir to the depth of a stratigraphic horizon known to be
productive.

EXPLORATORY WELL. A well drilled to find and produce oil or natural gas in
an unproved area, to find a new reservoir in a field previously found to be
productive of oil or natural gas in another reservoir, or to extend a known
reservoir.

FINDING AND DEVELOPMENT COST. The total capital expenditures, including
acquisition costs, and exploration and abandonment costs, for oil and natural
gas activities divided by the amount of proved reserves added in the specified
period.

GOB GAS. Gob gas is methane gas that has collected in abandoned underground
coal mines.

GROSS ACRES OR GROSS WELLS. The total acres or wells, as the case may be,
in which we have a working interest.

INTERACTION WELL. A well drilled into the fractured area surrounding an
abandoned coal mine.

LOE. Lease operating expenses, which includes, among other things,
extraction costs and property taxes, but not production taxes.

NET ACRES OR NET WELLS. A net acre or well is deemed to exist when the sum
of our fractional ownership working interests in gross acres or wells, as the
case may be, equals one. The number of net acres or wells is the sum of the
fractional working interests owned in gross acres or wells, as the case may be,
expressed as whole numbers and fractions thereof.

OPERATOR. The individual or company responsible to the working interest
owners for the exploration, development and production of an oil or natural gas
well or lease.

PRESENT VALUE OF FUTURE NET REVENUES OR PV-10. The present value of
estimated future net revenues to be generated from the production of proved
reserves, net of estimated production and ad valorem taxes, future capital costs
and operating expenses, using prices and costs in effect as of the date
indicated, without giving effect to federal income taxes. The future net
revenues have been discounted at an annual rate of 10% to determine their
"present value." The present value is shown to indicate the effect of time on
the value of the revenue stream and should not be construed as being the fair
market value of the properties.

S-49
<PAGE>
RECOMPLETION. The completion of an existing well for production from a
formation that exists behind the casing of the well.

RESERVES. Natural gas and crude oil, condensate and natural gas liquids on
a net revenue interest basis, found to be commercially recoverable. "Proved
developed reserves" includes proved developed producing reserves and proved
developed behind-pipe reserves. "Proved developed producing reserves" includes
only those reserves expected to be recovered from existing completion intervals
in existing wells. "Proved undeveloped reserves" includes those reserves
expected to be recovered from new wells on proved undrilled acreage or from
existing wells where a relatively major expenditure is required for
recompletion.

UNDEVELOPED ACREAGE. Lease acres on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and natural gas regardless of whether or not such acreage contains proved
reserves.

WORKING INTEREST. An interest in an oil and natural gas lease that gives
the owner of the interest the right to drill and produce oil and natural gas on
the leased acreage and requires the owner to pay a share of the costs of
drilling and production operations. The share of production to which a working
interest owner is entitled will always be smaller than the share of costs that
the working interest owner is required to bear, with the balance of the
production accruing to the owners of royalties.

S-50
<PAGE>
INDEX TO FINANCIAL STATEMENTS
FINANCIAL STATEMENTS OF EVERGREEN RESOURCES, INC. AND SUBSIDIARIES

<TABLE>
<CAPTION>
PAGE
--------
<S> <C>
Overview of Pro Forma Financial Statements.................. F-2

Pro Forma Consolidated Condensed Balance Sheet, June 30,
2000 (Unaudited).......................................... F-3

Pro Forma Consolidated Condensed Statement of Operations for
the Six Months Ended June 30, 2000 (Unaudited)............ F-4

Pro Forma Consolidated Condensed Statement of Operations for
the Year Ended December 31, 1999 (Unaudited).............. F-5

Report of Independent Certified Public Accountants.......... F-6

Consolidated Balance Sheets, June 30, 2000 (Unaudited),
December 31, 1999 and 1998................................ F-7

Consolidated Statements of Income for the Six Months Ended
June 30, 2000 and 1999 (Unaudited) and the Years Ended
December 31, 1999, 1998 and 1997.......................... F-8

Consolidated Statements of Stockholders' Equity for the Six
Months Ended June 30, 2000 (Unaudited) and the Years Ended
December 31, 1999, 1998 and 1997.......................... F-9

Consolidated Statements of Cash Flows for the Six Months
Ended June 30, 2000 and 1999 (Unaudited) and the Years
Ended December 31, 1999, 1998 and 1997.................... F-10

Consolidated Statements of Comprehensive Income for the Six
Months Ended June 30, 2000 and 1999 (Unaudited) and the
Years Ended December 31, 1999, 1998 and 1997.............. F-11

Notes to Consolidated Financial Statements.................. F-12
</TABLE>

F-1
<PAGE>
EVERGREEN RESOURCES, INC.

UNAUDITED PRO FORMA FINANCIAL STATEMENTS

OVERVIEW

On September 20, 2000, Evergreen Resources, Inc. ("Evergreen") acquired
interests in approximately 24,000 acres of producing coal bed methane properties
in the Raton Basin from Apache Canyon Gas, L.L.C., an affiliate of KLT
Gas, Inc., an indirect wholly owned subsidiary of Kansas City Power and Light
Company. The total consideration paid by Evergreen on closing was approximately
$70 million in cash borrowed under its credit facility, $100 million of its
mandatory redeemable preferred stock and $6 million of its common stock. The
transaction was effective September 1, 2000.

The acquired properties, estimated to contain 153 billion cubic feet (Bcf)
of net proved gas reserves, are located in the southern Colorado portion of the
Raton Basin. As of September 20, 2000, the acquired properties were generating
net daily sales of 28 million cubic feet (MMcf) of gas from a total of 151 net
wells.

The number of shares of common stock issued upon the closing of the
acquisition was 201,748 and was calculated based on a per-share price equal to
the average closing price of the common stock during the fifteen-trading-day
period ending on the day prior to the closing.

In addition to the consideration paid at the closing of the acquisition,
Evergreen will be required at January 5, 2001 to deliver additional shares of
its common stock valued at $4 million, in the event the average of the monthly
settle prices for the 2001 NYMEX natural gas futures contracts equals or exceeds
$4.465 per MMBtu. The number of shares of stock issuable would be calculated
based on a per-share price equal to the average closing price of Evergreen's
common stock during the fifteen-trading-day period ending on the day prior to
the date of delivery of such stock. As additional purchase consideration,
Evergreen is required to pay a monthly net profits interest payment estimated at
approximately $500,000 through the redemption of the preferred stock or
January 1, 2003, whichever comes earlier.

The unaudited pro forma consolidated condensed statements of operations for
the year ended December 31, 1999 and the six months ended June 30, 2000 give
effect to the acquisition by Evergreen of certain producing gas properties
located in the state of Colorado (the "Acquisition Properties") as if the
acquisition, accounted for as a purchase, had occurred on January 1, 1999. The
pro forma information is based on the historical consolidated financial
statements of Evergreen Resources, Inc. and the historical statements of Natural
Gas Revenues and Direct Operating Expenses of the Acquisition Properties for the
year ended December 31, 1999 and six months ended June 30, 2000 after giving
effect to the acquisition and the assumptions and adjustments in the
accompanying notes to the unaudited pro forma consolidated condensed financial
statements. The unaudited pro forma consolidated condensed balance sheet as of
June 30, 2000 gives effect to the acquisition as if it had occurred on June 30,
2000. The pro forma financial statements reflect the preliminary allocation of
the purchase price.

The unaudited pro forma consolidated condensed financial statements may not
be indicative of the results that actually would have occurred if the
acquisition had been effective on the date indicated or which may be obtained in
the future. The pro forma financial statements should be read in conjunction
with the historical consolidated financial statements of Evergreen and the
historical statements of Natural Gas Revenues and Direct Operating Expenses of
the Acquisition Properties.

F-2
<PAGE>
EVERGREEN RESOURCES, INC.

UNAUDITED PRO FORMA CONSOLIDATED CONDENSED BALANCE SHEET

JUNE 30, 2000
(IN THOUSANDS)

<TABLE>
<CAPTION>
EVERGREEN ACQUISITION
HISTORICAL ADJUSTMENTS PRO FORMA
---------- ----------- ---------
<S> <C> <C> <C>
Current assets.............................................. $ 9,179 $ -- $ 9,179
Property, plant and equipment, net.......................... 206,814 176,000(a) 382,814
Other assets, net........................................... 2,738 -- 2,738
-------- -------- --------
$218,731 $176,000 $394,731
======== ======== ========
Current liabilities......................................... $ 5,659 $ -- $ 5,659
Note payable................................................ 39,500 70,000(a) 109,500
Deferred taxes and other liabilities........................ 11,110 -- 11,110
Mandatory Redeemable Preferred Stock........................ -- 100,000(a) 100,000
Stockholders' Equity........................................ 162,462 6,000(a) 168,462
-------- -------- --------
Total Liabilities and Stockholders' Equity.............. $218,731 $176,000 $394,731
======== ======== ========
</TABLE>

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED CONDENSED BALANCE SHEET

(a) To record purchase price of the oil and gas properties for consideration of
$70 million in cash funded through Evergreen's line of credit, $100 million
in mandatory redeemable preferred stock and $6 million in common stock.

The acquisition adjustments do not reflect additional contingent purchase
consideration. Evergreen will be required at January 5, 2001 to deliver
additional shares of common stock valued at $4 million in the event the
average of the monthly settle prices for the 2001 NYMEX natural gas futures
contracts equals or exceeds $4.465 per MMBtu. As additional purchase
consideration, Evergreen is required to pay a monthly net profits interest
estimated at approximately $500,000 through the redemption of the preferred
stock or January 1, 2003, whichever comes earlier.

F-3
<PAGE>
EVERGREEN RESOURCES, INC.

UNAUDITED PRO FORMA CONSOLIDATED CONDENSED STATEMENT OF OPERATIONS

SIX MONTHS ENDED JUNE 30, 2000
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

<TABLE>
<CAPTION>
EVERGREEN ACQUISITION
HISTORICAL ADJUSTMENTS PRO FORMA
---------- ----------- ---------
<S> <C> <C> <C>
Revenues:
Natural gas revenues...................................... $15,649 $10,911(a) $26,560
Interest and other........................................ 162 -- 162
------- ------- -------
Total revenues.......................................... 15,811 10,911 26,722
------- ------- -------
Expenses:
Lease operating expense................................... 3,073 2,564(a) 5,637
Production taxes.......................................... 653 634(a) 1,287
Depreciation, depletion and amortization.................. 2,564 3,036(b) 5,600
General and administrative expenses....................... 1,902 -- 1,902
Interest expense.......................................... 802 2,888(c) 3,690
Other..................................................... 84 -- 84
------- ------- -------
Total expenses.......................................... 9,078 9,122 18,200
------- ------- -------
Income before income taxes.................................. 6,733 1,789 8,522
Income tax provision -- deferred............................ 2,626 667(d) 3,293
------- ------- -------
Net income.................................................. 4,107 1,122 5,229
Preferred stock dividends................................... -- 4,750(e) 4,750
------- ------- -------
Net income (loss) attributable to common stock.............. $ 4,107 $(3,628) $ 479
======= ======= =======
Income per common share:
Basic..................................................... $ 0.28 $ 0.03
======= =======
Diluted................................................... $ 0.26 $ 0.03
======= =======
Weighted average shares outstanding:
Basic..................................................... 14,905 15,107
======= =======
Diluted................................................... 15,596 15,798
======= =======
</TABLE>

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED CONDENSED STATEMENT OF OPERATIONS

(a) To record the incremental effect of natural gas sales and the related
operating expenses from the Acquisition Properties.

(b) To record additional depreciation, depletion and amortization expense.

(c) To record interest expense relating to the debt incurred in connection with
the acquisition at an effective rate of 8.25%.

(d) To record the incremental tax effect of the acquisition adjustments at an
effective tax rate of 37.3%.

(e) To record preferred stock dividends at a rate of 9.5%.

F-4
<PAGE>
EVERGREEN RESOURCES, INC.

UNAUDITED PRO FORMA CONSOLIDATED CONDENSED STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 1999
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

<TABLE>
<CAPTION>
EVERGREEN ACQUISITION
HISTORICAL ADJUSTMENTS PRO FORMA
---------- ----------- ---------
<S> <C> <C> <C>
Revenues:
Natural gas revenues...................................... $22,721 $ 12,824 (a) $35,545
Interest and other........................................ 207 -- 207
------- -------- -------
Total revenues.......................................... 22,928 12,824 35,752
------- -------- -------
Expenses:
Lease operating expense................................... 4,697 5,288 (a) 9,985
Production taxes.......................................... 694 681 (a) 1,375
Depreciation, depletion and amortization.................. 4,757 5,771 (b) 10,528
General and administrative expenses....................... 3,024 -- 3,024
Interest expense.......................................... 1,927 5,950 (c) 7,877
Other..................................................... 175 -- 175
------- -------- -------
Total expenses.......................................... 15,274 17,690 32,964
------- -------- -------
Income (loss) from continuing operations before income
taxes..................................................... 7,654 (4,866) 2,788
Income tax provision -- deferred............................ 2,979 (1,815)(d) 1,164
------- -------- -------
Income (loss) from continuing operations.................... 4,675 (3,051) 1,624
Preferred stock dividends................................... -- 9,500 (e) 9,500
------- -------- -------
Net income (loss) from continuing operations attributable to
common stock.............................................. $ 4,675 $(12,551) $(7,876)
======= ======== =======
Income (loss) per common share:
Basic..................................................... $ 0.36 $ (0.60)
======= =======
Diluted................................................... $ 0.34 $ (0.60)
======= =======
Weighted average shares outstanding:
Basic..................................................... 12,953 13,155
======= =======
Diluted................................................... 13,633 13,155
======= =======
</TABLE>

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED CONDENSED STATEMENT OF OPERATIONS

(a) To record the incremental effect of natural gas sales and the related
operating expenses from the Acquisition Properties.

(b) To record additional depreciation, depletion and amortization expense.

(c) To record interest expense relating to the debt incurred in connection with
the acquisition at an effective rate of 8.5%.

(d) To record the incremental tax effect of the acquisition adjustments at an
effective tax rate of 37.3%.

(e) To record preferred stock dividends at a rate of 9.5%.

F-5
<PAGE>
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS

To the Stockholders and Board of Directors
Evergreen Resources, Inc.
Denver, Colorado

We have audited the accompanying consolidated balance sheets of Evergreen
Resources, Inc. and subsidiaries as of December 31, 1999 and 1998, and the
related consolidated statements of income, stockholders' equity, cash flows, and
comprehensive income for each of the three years in the period ended
December 31, 1999. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.

We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Evergreen
Resources, Inc. and subsidiaries at December 31, 1999 and 1998 and the results
of their operations and their cash flows for each of the years in the period
ended December 31, 1999 in conformity with generally accepted accounting
principles.

BDO SEIDMAN, LLP

Denver, Colorado
February 11, 2000

F-6
<PAGE>
EVERGREEN RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
DECEMBER 31,
JUNE 30, ----------------------
2000 1999 1998
----------- ----------- --------
(UNAUDITED)
(IN THOUSANDS)
<S> <C> <C> <C>
ASSETS

Current:
Cash and cash equivalents............................... $ 3,236 $ 651 $ 1,334
Accounts receivable (Note 2)............................ 4,586 5,021 4,728
Other current assets.................................... 1,357 749 295
-------- -------- --------
Total current assets.................................. 9,179 6,421 6,357
Property and equipment, at cost, (Notes 1, 3, 4, 5, and
16): based on the full cost method of accounting for oil
and gas properties...................................... 234,366 199,179 147,176
Less accumulated depreciation, depletion and
amortization.......................................... 27,552 24,845 19,400
-------- -------- --------
Net property and equipment............................ 206,814 174,334 127,776
Designated cash (Note 6).................................. 1,271 2,313 2,782
Other assets (Notes 1 and 15)............................. 1,467 1,301 2,711
-------- -------- --------
$218,731 $184,369 $139,626
======== ======== ========

LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:
Accounts payable........................................ $ 2,848 $ 3,659 $ 1,240
Amounts payable to oil and gas property owners.......... 1,691 1,424 2,947
Accrued expenses and other.............................. 1,120 1,400 1,515
Current portion -- capital lease (Note 5)............... -- -- 1,123
-------- -------- --------
Total current liabilities............................. 5,659 6,483 6,825
Production taxes payable (Note 6)......................... 1,271 2,313 2,782
Deferred revenue (Note 13)................................ 650 -- --
Note payable (Note 4)..................................... 39,500 15,500 44,139
Obligations under capital lease, less current portion
(Note 5)................................................ -- -- 2,906
Deferred income taxes (Note 7)............................ 9,189 6,563 3,295
-------- -------- --------
Total liabilities..................................... 56,269 30,859 59,947
-------- -------- --------
Commitments and contingencies (Notes 3, 4, 13 and 14)
Stockholders' equity (Notes 3, 8, 9 and 10):
Preferred stock, $1.00 par value; shares authorized,
25,000; none outstanding.............................. -- -- --
Common stock, $.01 stated value; shares authorized,
50,000; shares issued and outstanding 14,943, 14,621
and 11,143............................................ 149 146 111
Additional paid-in capital.............................. 152,884 147,326 78,380
Retained earnings....................................... 10,312 6,205 1,078
Accumulated other comprehensive income (loss)........... (883) (167) 110
-------- -------- --------
Total stockholders' equity............................ 162,462 153,510 79,679
-------- -------- --------
$218,731 $184,369 $139,626
======== ======== ========
</TABLE>

See accompanying notes to consolidated financial statements.

F-7
<PAGE>
EVERGREEN RESOURCES, INC.

CONSOLIDATED STATEMENTS OF INCOME

<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30, YEARS ENDED DECEMBER 31,
------------------- ------------------------------
2000 1999 1999 1998 1997
-------- -------- -------- -------- --------
(UNAUDITED)
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C>
Revenues:
Natural gas revenues (Note 11)................ $15,649 $9,712 $22,721 $19,063 $12,138
Interest and other............................ 162 114 207 178 136
------- ------ ------- ------- -------
Total revenues.................................. 15,811 9,826 22,928 19,241 12,274
------- ------ ------- ------- -------
Expenses:
Lease operating expense....................... 3,073 2,125 4,697 2,481 1,433
Production taxes.............................. 653 238 694 876 574
Depreciation, depletion and amortization...... 2,564 2,298 4,757 3,860 2,794
General and administrative expenses........... 1,902 1,272 3,024 1,933 1,286
Interest expense.............................. 802 1,541 1,927 1,870 777
Other......................................... 84 62 175 286 259
------- ------ ------- ------- -------
Total expenses.................................. 9,078 7,536 15,274 11,306 7,123
------- ------ ------- ------- -------
Income from continuing operations before income
taxes......................................... 6,733 2,290 7,654 7,935 5,151
Income tax provision -- deferred (Note 7)....... 2,626 887 2,979 3,062 --
------- ------ ------- ------- -------
Income from continuing operations............... 4,107 1,403 4,675 4,873 5,151
Discontinued operations (Notes 1 and 15)
Gain on disposal of discontinued operations,
net......................................... -- 452 452 -- --
Equity in earnings of discontinued operations,
net......................................... -- -- -- 339 313
------- ------ ------- ------- -------
Net income...................................... 4,107 1,855 5,127 5,212 5,464
Preferred stock dividends (Notes 8 and 9)....... -- -- -- -- 400
------- ------ ------- ------- -------
Net income attributable to common stock......... $ 4,107 $1,855 $ 5,127 $ 5,212 $ 5,064
======= ====== ======= ======= =======
Basic income per common share:
From continuing operations.................... $ 0.28 $ 0.12 $ 0.36 $ 0.47 $ 0.50
From discontinued operations.................. -- 0.04 0.03 0.03 0.03
------- ------ ------- ------- -------
Basic income per common share................. $ 0.28 $ 0.16 $ 0.39 $ 0.50 $ 0.53
======= ====== ======= ======= =======
Diluted income per common share:
From continuing operations.................... $ 0.26 $ 0.11 $ 0.34 $ 0.44 $ 0.48
From discontinued operations.................. -- 0.04 0.03 0.03 0.03
------- ------ ------- ------- -------
Diluted income per common share............... $ 0.26 $ 0.15 $ 0.37 $ 0.47 $ 0.51
======= ====== ======= ======= =======
</TABLE>

See accompanying notes to consolidated financial statements.

F-8
<PAGE>
EVERGREEN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
SIX MONTHS ENDED JUNE 30, 2000 (UNAUDITED)
AND THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997

<TABLE>
<CAPTION>
COMMON STOCK
$.01 STATED
VALUE ADDITIONAL RETAINED OTHER TOTAL
------------------- PAID-IN EARNINGS COMPREHENSIVE STOCKHOLDERS'
SHARES AMOUNT CAPITAL (DEFICIT) INCOME (LOSS) EQUITY
-------- -------- ---------- --------- -------------- -------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
Balance, January 1, 1997.......................... 9,336 $ 94 $ 61,369 $(9,198) $ 99 $ 52,364
Issuance of common stock in exchange for
redeemable preferred stock (Note 8)............. 906 9 5,973 -- -- 5,982
Issuance of common stock for services (Note 9).... 64 1 239 -- -- 240
Exercise of stock purchase warrants (Notes 9 and
10)............................................. 89 -- 367 -- -- 367
Preferred stock dividends (Note 8)................ -- -- -- (400) -- (400)
Other comprehensive income........................ -- -- -- -- 135 135
Net income........................................ -- -- -- 5,464 -- 5,464
------ ---- -------- ------- ----- --------
Balance December 31, 1997......................... 10,395 104 67,948 (4,134) 234 64,152

Issuance of common stock for services (Note 9).... 15 -- 190 -- -- 190
Exercise of stock purchase warrants (Note 10)..... 277 2 2,182 -- -- 2,184
Issuance of common stock for property interests
(Note 9)........................................ 450 5 7,495 -- -- 7,500
Issuance of warrants (Note 10).................... -- -- 479 -- -- 479
Issuances of common stock for acquisitions and
other........................................... 6 -- 86 -- -- 86
Other comprehensive loss.......................... -- -- -- -- (124) (124)
Net income........................................ -- -- -- 5,212 -- 5,212
------ ---- -------- ------- ----- --------
Balance December 31, 1998......................... 11,143 111 78,380 1,078 110 79,679

Issuance of common stock for services (Note 9).... 51 1 800 -- -- 801
Exercise of stock purchase warrants (Note 10)..... 188 2 1,361 -- -- 1,363
Issuance of common stock for property interests
(Note 9)........................................ 56 1 920 -- -- 921
Issuance of common stock for subsidiary
(Notes 3 and 9)................................. 120 1 2,499 -- -- 2,500
Issuance of common stock pursuant to public
offering (Note 9)............................... 3,163 31 65,041 -- -- 65,072
Common stock buyback (Note 9)..................... (100) (1) (1,708) -- -- (1,709)
Issuance of warrants.............................. -- -- 33 -- -- 33
Other comprehensive loss.......................... -- -- -- -- (277) (277)
Net income........................................ -- -- -- 5,127 -- 5,127
------ ---- -------- ------- ----- --------
Balance December 31, 1999......................... 14,621 146 147,326 6,205 (167) 153,510

Issuance of common stock for services (Unaudited)
(Note 9)........................................ 2 -- 15 -- -- 15
Exercise of stock purchase warrants (Unaudited)
(Note 10)....................................... 19 -- 128 -- -- 128
Issuance of common stock for property interests
(Unaudited) (Note 9)............................ 301 3 5,415 -- -- 5,418
Other comprehensive loss (Unaudited).............. -- -- -- -- (716) (716)
Net income (Unaudited)............................ -- -- -- 4,107 -- 4,107
------ ---- -------- ------- ----- --------
Balance, June 30, 2000 (Unaudited)................ 14,943 $149 $152,884 $10,312 $(883) $162,462
====== ==== ======== ======= ===== ========
</TABLE>

See accompanying notes to consolidated financial statements.

F-9
<PAGE>
EVERGREEN RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30, YEARS ENDED DECEMBER 31,
------------------- ------------------------------
2000 1999 1999 1998 1997
-------- -------- -------- -------- --------
(UNAUDITED)
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Increase (Decrease) in Cash and Cash Equivalents
Operating activities:
Net income...................................... $ 4,107 $ 1,855 $ 5,127 $ 5,212 $ 5,464
Adjustments to reconcile net income to cash
provided by operating activities:
Depreciation, depletion and amortization.... 2,564 2,298 4,757 3,860 2,794
Deferred income taxes....................... 2,626 887 2,979 3,062 --
Gain on disposal of discontinued operations,
net....................................... -- (452) (452) -- --
Equity in earnings of discontinued
operations, net........................... -- -- -- (339) (313)
Non-cash compensation....................... 123 241 545 225 159
Other....................................... 92 133 170 502 25
Changes in operating assets and liabilities:
Accounts receivable....................... 421 722 (293) (1,118) (1,121)
Other current assets...................... (609) (655) (527) 105 (208)
Accounts payable.......................... (464) 250 (187) 691 (422)
Accrued expenses and other................ (714) (558) 612 (53) 79
Deferred revenue.......................... 650 -- -- -- --
------- ------- ------- ------- -------
Net cash provided by operating activities....... 8,796 4,721 12,731 12,147 6,457
------- ------- ------- ------- -------
Investing activities:
Investment in property and equipment.......... (30,234) (21,622) (43,243) (46,959) (18,603)
Purchase of subsidiary (Note 3)............... -- -- (2,500) -- --
Proceeds from sale of investment.............. -- 2,259 2,258 -- --
Designated cash............................... 1,042 835 468 (639) (650)
Change in production taxes payable............ (1,042) (835) (468) 639 650
Change in other assets........................ (350) (333) (379) (243) (656)
------- ------- ------- ------- -------
Net cash used in investing activities........... (30,584) (19,696) (43,864) (47,202) (19,259)
------- ------- ------- ------- -------
Financing activities:
Net proceeds from (payments on) notes
payable..................................... 24,000 (44,139) (28,639) 33,327 11,189
Principal payments on capital lease
obligations................................. -- (4,028) (4,029) (1,061) (637)
Proceeds from issuance of common stock, net... 138 66,043 66,448 2,158 349
Common stock buyback.......................... -- -- (1,709) -- --
Dividends paid on preferred stock............. -- -- -- -- (400)
Debt issue costs.............................. -- (57) (77) (143) (148)
Change in cash held from operating oil and gas
properties and other........................ 267 (1,560) (1,523) (21) 1,900
------- ------- ------- ------- -------
Net cash provided by financing activities....... 24,405 16,259 30,471 34,260 12,253
------- ------- ------- ------- -------
Effect of exchange rate changes on cash......... (32) (6) (21) 26 12
------- ------- ------- ------- -------
Increase (decrease) in cash and cash
equivalents................................... 2,585 1,278 (683) (769) (537)
Cash and cash equivalents, beginning of year.... 651 1,334 1,334 2,103 2,640
------- ------- ------- ------- -------
Cash and cash equivalents, end of year.......... $ 3,236 $ 2,612 $ 651 $ 1,334 $ 2,103
======= ======= ======= ======= =======
</TABLE>

See accompanying notes to consolidated financial statements.

F-10
<PAGE>
EVERGREEN RESOURCES, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30, YEARS ENDED DECEMBER 31,
------------------- ------------------------------
2000 1999 1999 1998 1997
-------- -------- -------- -------- --------
(UNAUDITED)
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Net income.......................................... $4,107 $1,855 $5,127 $5,212 $5,464
Foreign currency translation adjustments............ (716) (490) (277) (124) 135
------ ------ ------ ------ ------
Comprehensive income................................ $3,391 $1,365 $4,850 $5,088 $5,599
====== ====== ====== ====== ======
</TABLE>

See accompanying notes to consolidated financial statements.

F-11
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(UNAUDITED AS TO THE SIX MONTHS ENDED JUNE 30, 2000 AND 1999)

(1) SUMMARY OF ACCOUNTING POLICIES

BUSINESS

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 coal bed methane properties in the Raton Basin in
southern Colorado consisting of 240,000 gross acres at September 30, 2000. The
Company also holds as of September 30, 2000 exploration licenses on
approximately 470,000 acres onshore in the United Kingdom, an interest in
exploration acreage offshore in the Falkland Islands, an oil and gas exploration
contract on approximately 2.4 million gross acres in northern Chile and
exploratory acreage in northwestern Colorado. Evergreen operates all of its
producing properties.

CONSOLIDATION

The financial statements include the accounts of Evergreen and its
wholly-owned subsidiaries: Evergreen Operating Corporation ("EOC"), Evergreen
Resources (UK) Ltd., Powerbridge, Inc., Evergreen Well Service Company ("EWS"),
Primero Gas Marketing Company ("Primero"), EnviroSeis, LLC ("EnviroSeis") and
XYZ Minerals, Inc. ("XYZ"). All significant intercompany balances and
transactions have been eliminated in consolidation.

The Company has a 40% ownership in Argos Evergreen Limited ("AEL"), a
Falkland Islands company. This investment is accounted for by the equity method
of accounting. Effective February 1999, the Company sold its 49% interest in
Maverick Stimulation Company, LLC ("Maverick"), which had previously been
accounted for using the equity method of accounting. See Note 15 for further
discussion.

FINANCIAL INSTRUMENTS

The Company's financial instruments that are exposed to concentrations of
credit risk consist primarily of cash equivalents. The Company's cash
equivalents are cash investment funds which are placed with a major financial
institution.

The Company manages and controls market and credit risk through established
formal internal control procedures which are reviewed on an ongoing basis. The
Company attempts to minimize credit risk exposure to purchasers of the Company's
natural gas through formal credit policies, monitoring procedures and letters of
credit.

Unless otherwise specified, the Company believes the book value of the
financial instruments approximates their fair value.

USES OF ESTIMATES

The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the consolidated
financial statements and the reported amounts of revenues and expenses during
the reporting period. Actual results could differ from those estimates.
Significant estimates with regard to these financial statements include the
estimate of proved oil and gas reserve volumes and the related present value of
estimated future net cash flows (see Note 16 for supplemental oil and gas
disclosures).

F-12
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(UNAUDITED AS TO THE SIX MONTHS ENDED JUNE 30, 2000 AND 1999)

(1) SUMMARY OF ACCOUNTING POLICIES (CONTINUED)
PROPERTY AND EQUIPMENT

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, including salaries, benefits and other internal salary related costs
directly attributable to these activities. Evergreen capitalized $1,408,000 and
$544,000 for the six months ended June 30, 2000 and 1999 and $1,845,000,
$711,000 and $542,000 of internal costs for the years ended December 31, 1999,
1998 and 1997. 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 (see Note 16), 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.

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 their 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 costs of certain unevaluated 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.

Gas gathering and support equipment are stated at cost. Depreciation and
amortization for the Raton Basin gas gathering system is computed on the
units-of-production method based upon total reserves of the field. Certain gas
gathering system components and other support equipment are depreciated using
the straight-line method over the estimated useful lives of the assets of 3 to
30 years.

Effective January 1, 1999 the Company revised the estimated useful life used
to depreciate its gas compressors from 15 to 30 years to correspond to the
estimated life of the Company's coal bed methane fields. The net effect on
depreciation during the year ended December 31, 1999 was a reduction in
depreciation expense of $307,000 or $.02 per basic and diluted share.

The Company applies Statement of Financial Accounting Standards ("SFAS")
No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed of." Under SFAS No. 121, long-lived assets and certain
intangibles are reported at the lower of the carrying amount or their estimated
recoverable amounts. Long-lived assets subject to the requirements of SFAS
No. 121, are evaluated for possible impairment through review of undiscounted
expected future cash flows. If the sum of undiscounted expected future cash
flows is less than the carrying amount of the asset or if changes in facts and
circumstances indicate, an impairment loss is recognized. No impairment exists
at June 30, 2000 or December 31, 1999.

F-13
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(UNAUDITED AS TO THE SIX MONTHS ENDED JUNE 30, 2000 AND 1999)

(1) SUMMARY OF ACCOUNTING POLICIES (CONTINUED)
AMOUNTS PAYABLE TO OIL AND GAS PROPERTY OWNERS

Amounts payable to oil and gas property owners consist of cash calls from
working interest owners to pay for development costs of properties being
currently developed, production revenue that the Company, as operator, is
collecting and distributing to revenue interest owners and production revenue
taxes that the Company, as operator, has withheld for timely payment to the tax
agencies.

INCOME TAXES

The Company follows the liability method of accounting for income taxes
under which deferred tax assets and liabilities are recognized for the future
tax consequences. Accordingly, deferred tax liabilities and assets are
determined based on the temporary differences between the financial statement
and tax bases of assets and liabilities, using enacted tax rates in effect for
the year in which the differences are expected to reverse.

ENVIRONMENTAL MATTERS

Environmental costs are expensed or capitalized depending on their future
economic benefit. Costs that relate to an existing condition caused by past
operations and have no future economic benefit are expensed. Liabilities for
future expenditures of a noncapital nature are recorded when future
environmental expenditures and/or remediation is deemed probable, and the costs
can be reasonably estimated. Costs of future expenditures for environmental
remediation obligations are not discounted to their present value.

GENERAL AND ADMINISTRATIVE EXPENSES

General and administrative expenses are reported net of amounts allocated to
working interest owners of the oil and gas properties operated by Evergreen, net
of amounts charged for administrative and overhead costs and net of amounts
capitalized pursuant to the full cost method of accounting.

NET INCOME PER SHARE

The Company applies SFAS No. 128, "Earnings Per Share" for the calculation
of "Basic" and "Diluted" earnings per share. Basic earnings per share includes
no dilution and is computed by dividing income available to common stockholders
by the weighted average number of common shares outstanding for the period.
Diluted earnings per share reflects the potential dilution of securities that
could share in the earnings of an entity.

CASH EQUIVALENTS

The Company considers all highly liquid investments with an original
maturity of three months or less to be cash equivalents.

HEDGING TRANSACTIONS

The Company enters into contractual obligations that require future physical
delivery of its natural gas production to attempt to manage price risk with
regard to a portion of its natural gas production. The Company identifies
minimum internal price targets and, assuming other market conditions are deemed
favorable, the Company will enter in hedging contracts to manage price risk.

F-14
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(UNAUDITED AS TO THE SIX MONTHS ENDED JUNE 30, 2000 AND 1999)

(1) SUMMARY OF ACCOUNTING POLICIES (CONTINUED)
REVENUE RECOGNITION

Natural gas sales revenues generally are recorded using the sales method,
whereby the Company recognizes sales revenue based on the amount of gas sold to
purchasers on its behalf.

The Company has received cash payments from a purchaser in consideration for
a contract to sell certain future production. These cash payments are initially
recorded as deferred revenue and are amortized as revenue pro-rata over the
contract term.

COMPREHENSIVE INCOME

The Company has elected to report comprehensive income in a consolidated
statement of comprehensive income. Comprehensive income is comprised of net
income and all changes to stockholders' equity, except those due to investments
by stockholders, changes in paid-in capital and distributions to stockholders.

STOCK OPTIONS

The Company applies APB Opinion 25, "Accounting for Stock Issued to
Employees," and related interpretations in accounting for all stock option
plans. Under APB Opinion 25, compensation cost has been recognized for stock
options granted in situations where the option price is less than the market
price of the underlying common stock on the date of grant.

SFAS No. 123, "Accounting for Stock-Based Compensation," requires the
Company to provide pro forma information regarding net income as if compensation
cost for the Company's stock option plans had been determined in accordance with
the fair value based method prescribed in SFAS No. 123. To provide the required
pro forma information, the Company estimates the fair value of each stock option
at the grant date by using the Black-Scholes option-pricing model.

FOREIGN CURRENCY TRANSLATION

The functional currency for the Company's foreign operations is the
applicable local currency. The translation of the applicable foreign currency
into U.S. dollars is performed for balance sheet accounts using current exchange
rates in effect at the balance sheet date and for revenue and expense accounts
using a weighted average exchange rate during the period. The gains or losses
resulting from such translation are included in stockholders' equity.

RECLASSIFICATIONS

Certain items included in prior years' financial statements have been
reclassified to conform to current year presentation.

DEFERRED OFFERING COSTS

Costs incurred in connection with public offerings are deferred and are
charged against stockholders' equity upon the successful completion of the
offering or charged to expense if the offering is not consumated.

F-15
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(UNAUDITED AS TO THE SIX MONTHS ENDED JUNE 30, 2000 AND 1999)

(1) SUMMARY OF ACCOUNTING POLICIES (CONTINUED)
UNAUDITED PERIODS

The financial information with respect to the six months ended June 30, 2000
and 1999 is unaudited. In the opinion of management, the accompanying unaudited
financial statements contain all adjustments necessary to present fairly the
Company's financial position as of June 30, 2000 and 1999 and the results of its
operations and cash flows for the six months then ended. Management believes all
such adjustments are of a normal recurring nature. The results of operations for
interim periods are not necessarily indicative of results to be expected for a
full year.

RECENT ACCOUNTING PRONOUNCEMENTS

In June 1998, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 133, "Accounting for Derivative Instruments and Hedging Activities" which
establishes accounting and reporting standards for derivative instruments,
including certain derivative instruments embedded in other contracts and for
hedging activities. SFAS No. 133, as extended by SFAS No. 137, is effective for
all fiscal quarters of fiscal years beginning after June 15, 2000. Management
believes the adoption of this statement will not have a material impact on the
Company's financial statements.

In 1999, the SEC issued Staff Accounting Bulletin No. 101 dealing with
revenue recognition which is effective in the fourth quarter of 2000. The
Company does not expect its adoption to have a material effect on the Company's
financial statements.

In March 2000, the FASB issued FASB Interpretation No. 44, "Accounting for
Certain Transactions Involving Stock Compensation" ("FIN 44"), which is
effective July 1, 2000, except that certain conclusions in this Interpretation
which cover specific events that occur after either December 15, 1998 or
January 12, 2000 are recognized on a prospective basis from July 1, 2000. This
Interpretation clarifies the application of APB Opinion 25 for certain issues
related to stock issued to employees. The Company believes its existing
stock-based compensation policies and procedures are in compliance with FIN 44
and, therefore, that the adoption of FIN 44 will have no material impact on the
Company's financial condition, results of operations or cash flows.

(2) ACCOUNTS RECEIVABLE

The components of accounts receivable include the following:

<TABLE>
<CAPTION>
DECEMBER 31,
JUNE 30, -------------------
2000 1999 1998
----------- -------- --------
(UNAUDITED)
(IN THOUSANDS)
<S> <C> <C> <C>
Natural gas sales........................................... $4,151 $3,921 $3,365
Joint interest billings..................................... 435 1,100 1,363
------ ------ ------
$4,586 $5,021 $4,728
====== ====== ======
</TABLE>

F-16
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(UNAUDITED AS TO THE SIX MONTHS ENDED JUNE 30, 2000 AND 1999)

(3) PROPERTY AND EQUIPMENT

Property and equipment includes the following:

<TABLE>
<CAPTION>
DECEMBER 31,
JUNE 30, -------------------
2000 1999 1998
----------- -------- --------
(UNAUDITED)
<S> <C> <C> <C>
(IN THOUSANDS)
Oil and Gas Properties:
Proved oil and gas properties............................. $118,697 $103,659 $ 79,303
Unevaluated properties not subject to amortization........ 36,022 31,748 25,567
Accumulated depreciation, depletion and amortization...... (21,216) (19,312) (16,348)
-------- -------- --------
Net oil and gas properties.............................. 133,503 116,095 88,522
-------- -------- --------
Gas gathering equipment..................................... 55,622 46,201 31,365
Construction in progress.................................... 7,472 6,090 9,227
Support equipment........................................... 16,553 11,481 1,714
Accumulated depreciation and amortization................... (6,336) (5,533) (3,052)
-------- -------- --------
Net other property and equipment.......................... 73,311 58,239 39,254
-------- -------- --------
Property and equipment, net of accumulated depreciation,
depletion and amortization................................ $206,814 $174,334 $127,776
======== ======== ========
</TABLE>

Oil and gas property costs of $36,022,000 and $31,748,000 were not being
amortized at June 30, 2000 and December 31, 1999. These costs, at December 31,
1999, consisted of $18,057,000 for domestic properties, $9,483,000 for the
United Kingdom ("U.K."), $1,651,000 for the Falkland Islands and $2,557,000 for
Chile. The Company will classify the unevaluated costs for the U.K., Falkland
Islands and Chile as evaluated costs when future development of the licenses
relating to such properties determines the viability of the underlying reserves.
The Company anticipates that substantially all of the unevaluated costs related
to domestic properties will be classified as evaluated costs within the next
three to five years.

Effective September 30, 1999, Evergreen acquired XYZ, whose assets consisted
of coal bed methane mineral interests and certain other assets for $5 million.
The purchase was accounted for using the purchase method of accounting. The
purchase price consisted of $2.5 million in cash and 120,000 shares of Evergreen
common stock valued at $2.5 million. Subject to certain terms and conditions,
Evergreen has provided the seller of XYZ with protection of the value of such
stock, for a period of six months from the November 5, 1999 effective date of
the registration statement relating to the resale of the shares. If the sales
price received by the seller upon the sale of the Evergreen stock is less than
the issuance price of $20.83 per share, Evergreen will be required to reimburse
the seller for the price differential. The Company is currently negotiating the
price protection with the seller of XYZ. The coal bed methane interests consist
of a 17.5% royalty interest in more than 20,000 acres in the southern Colorado
portion of the Raton Basin, on acreage Evergreen currently operates. In 1998,
Evergreen acquired a 75% working interest in this same acreage. The purchase
price allocation for the acquisition is preliminary and will be finalized after
the settlement of the potential contingencies.

The Company is in the process of developing properties in the U.K. and is
unable to prepare reserve information in this area. In 1997, under a new onshore
licensing regime implemented by the U.K. Department of Trade and Industry,
Evergreen converted its original licenses to new onshore licenses, called
Petroleum Exploration and Development Licenses. In connection with such
conversion,

F-17
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(UNAUDITED AS TO THE SIX MONTHS ENDED JUNE 30, 2000 AND 1999)

(3) PROPERTY AND EQUIPMENT (CONTINUED)
the Company relinquished rights to approximately 259,000 acres, which were not
considered highly prospective for coal bed methane development. Under the
licenses, the Company retained approximately 377,000 acres, which were
high-graded for coal bed methane and conventional hydrocarbon potential. During
1999, the Company acquired an additional 136,000 acres. The total acreage in the
U.K. was approximately 513,000 acres at December 31, 1999. Subsequent to year
end, the Company relinquished certain acreage and now has approximately 470,000
acres. The licenses provide up to a 30 year term with optional periodic
relinquishment of portions of the license, subject to future development plans.
There are no royalties or burdens encumbering these licenses. Evergreen has
drilled approximately 5 conventional coal bed methane wells and 4 mine-gas
interaction and gob wells during 2000.

In October 1998, the Falkland Islands consortium, in which Evergreen has a
net 2% interest, finished drilling its second well. The two wells on Tranche A
have established good source rock seal and potential reservoir rocks.

The consortium is in the process of assigning the license interests and
operatorship to AEL, in which Evergreen owns a 40% interest, and has requested a
consent from appropriate government authority. Upon approval of the assignments
Evergreen's ownership in the project will increase from 2% to 40%. AEL is
currently evaluating data from all wells drilled to determine the future
strategy for the acreage. AEL has extended the license fees through 2000 and has
no further work obligations through 2001. The total estimated costs for the
program through the year ended December 31, 2001 is approximately $120,000.

During 1999, the Company completed a proprietary 2D seismic program in
Chile. The data is being processed and interpreted. Evergreen has requested the
Ministry of Mining to extend the second exploration period by one year.

Included in construction in progress at June 30, 2000 and December 31, 1999,
are costs for a new compressor station, gas gathering laterals and costs for
well equipment.

(4) FINANCING AGREEMENT

As of June 30, 2000 and December 31, 1999, the Company had a $75 million
revolving line of credit, available through June 2001, with a bank group.
Advances pursuant to this line of credit were limited to a borrowing base, which
was $75 million. The Company could elect to use either the London Interbank
Offered Rate ("LIBOR") plus a margin of 1.38% to 1.75% or the prime rate plus a
margin of 0% to .25%, with margins on both rates determined on the average
outstanding borrowings under the credit facility. An average annual commitment
fee of .375% was charged quarterly for any unused portion of the credit line.
The agreement was collateralized by oil and gas properties and also contained
certain net worth and ratio requirements. The average interest rate (including
the facility fee charged on the unused portion of the credit line) on the line
of credit during the six months ended June 30, 2000 and the year ended
December 31, 1999 was approximately 8.75% and 8.5%. At June 30, 2000,
December 31, 1999 and 1998, $39,500,000, $15,500,000 and $44,139,000 was
outstanding under the line of credit. The Company was in compliance with all
loan covenants at June 30, 2000 and December 31, 1999.

Effective August 15, 2000, the line of credit was amended and restated to
increase the available credit to $125 million and to provide for the
participation by other banks in the credit agreement. The bank group consists of
Hibernia National Bank, as agent, BNP-Paribas, Wells Fargo Bank Texas, NA,

F-18
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(UNAUDITED AS TO THE SIX MONTHS ENDED JUNE 30, 2000 AND 1999)

(4) FINANCING AGREEMENT (CONTINUED)
Bank One, NA, Fleet National Bank and Bank of Scotland. The new line of credit
is available through July 1, 2003 and advances are limited to the borrowing base
($125 million at August 15, 2000) that is to be redetermined semi-annually by
the bank group based upon reserve evaluations of the Company's oil and gas
properties. At the Company's election, it may use either LIBOR plus a margin of
1.125% to 1.50% or the prime rate plus a margin of 0% to .25%, with margins on
both rates determined on the average outstanding borrowings under the credit
facility. No more than four LIBOR tranches can be outstanding at any time under
the credit facility. An average annual commitment fee of .375% is charged
quarterly for any unused portion of the credit line. The agreement is
collateralized by all domestic oil and gas properties and guaranteed by
substantially all of the Company's subsidiaries. The credit agreement contains
certain net worth, leverage and ratio requirements. The Company paid a
commitment fee of $312,500 in connection with the restated credit facility.
Effective September 15, 2000, the credit agreement was amended to increase the
available credit to $150 million and the Company paid a commitment fee of
$62,500 to the bank group. As of November 2, 2000, $127 million was outstanding
under this credit facility.

(5) CAPITAL LEASE OBLIGATIONS

At December 31, 1998, the Company had a capital equipment lease with a bank
with interest at 8.5%. In conjunction with the completion of a public offering
of its common shares on June 22, 1999 (see Note 9), the Company paid off the
capital lease obligation and purchased the equipment for a nominal amount.

Included in the Company's property and equipment at December 31, 1998 was
$6,999,500 of net fixed assets under the capital lease. The equipment leased
consisted primarily of compressors for the Raton Basin gas gathering system and
other related production equipment.

(6) DESIGNATED CASH AND RELATED PRODUCTION TAXES PAYABLE

Designated cash represents the cash withheld for payment of production taxes
from the Company and third party revenue interest owners. The production taxes
payable relates to ad valorem taxes collected for production through June 30,
2000 and December 1999 which are not payable until fiscal 2001 or later. The
related cash collected from the Company and third party revenue interest owners
designated for payment of ad valorem taxes is reflected as a non-current asset.

(7) INCOME TAXES

The provision for deferred income taxes consisted of the following:

<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30, YEARS ENDED DECEMBER 31,
------------------- -------------------------------
2000 1999 1999 1998 1997
-------- -------- -------- -------- ---------
(UNAUDITED)
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Federal............................................... $2,274 $1,019 $2,830 $2,839 $ --
State................................................. 352 157 438 440 --
------ ------ ------ ------ ---------
$2,626 $1,176 $3,268 $3,279 $ --
====== ====== ====== ====== =========
Income tax for continuing operations.................. $2,626 $ 887 $2,979 $3,062 $ --
Income tax for discontinued operations................ -- 289 289 217 --
------ ------ ------ ------ ---------
Total income tax provision -- deferred.............. $2,626 $1,176 $3,268 $3,279 $ --
====== ====== ====== ====== =========
</TABLE>

F-19
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(UNAUDITED AS TO THE SIX MONTHS ENDED JUNE 30, 2000 AND 1999)

(7) INCOME TAXES (CONTINUED)
A reconciliation between the deferred income tax provision computed at the
statutory rate on income before taxes and the income tax provision is as
follows:

<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30, YEARS ENDED DECEMBER 31,
------------------- ------------------------------
2000 1999 1999 1998 1997
-------- -------- -------- -------- --------
(UNAUDITED)
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Federal income tax provision at statutory rate...... $2,309 $1,040 $2,854 $2,887 $1,858
State income taxes.................................. 201 91 277 280 180
Reduction in valuation allowance.................... -- -- -- -- (1,788)
Other............................................... 116 45 137 112 (250)
------ ------ ------ ------ ------
Total income tax provision -- deferred............ $2,626 $1,176 $3,268 $3,279 $ --
====== ====== ====== ====== ======
</TABLE>

The components of the net deferred tax assets and liabilities are shown
below:

<TABLE>
<CAPTION>
SIX MONTHS
ENDED DECEMBER 31,
JUNE 30, ----------------------
2000 1999 1998
----------- ----------- --------
(UNAUDITED)
(IN THOUSANDS)
<S> <C> <C> <C>
Net operating loss carryforwards........................... $ 9,287 $ 8,981 $10,392
Percentage depletion carryforwards......................... 1,303 1,303 1,303
Other...................................................... 196 296 252
------- ------- -------
Net deferred tax assets.................................... 10,786 10,580 11,947
Deferred tax liability -- depreciation, depletion and
amortization............................................. (19,975) (17,143) (15,242)
------- ------- -------
Net deferred tax liability................................. $(9,189) $(6,563) $(3,295)
======= ======= =======
</TABLE>

As of December 31, 1999, the Company has net operating loss carryforwards
for tax purposes of approximately $25 million, which expire beginning in 2004
through 2020.

(8) REDEEMABLE PREFERRED STOCK

Effective November 1, 1997, all of the Company's outstanding 8% Convertible
Preferred Stock, was converted into 905,660 shares of common stock. During the
year ended December 31, 1997, the Company paid $400,000 in dividends on the
preferred stock.

F-20
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(UNAUDITED AS TO THE SIX MONTHS ENDED JUNE 30, 2000 AND 1999)

(9) STOCKHOLDERS' EQUITY

EARNINGS PER SHARE

The following table sets forth the computation of basic and diluted earnings
per share:

<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30, YEARS ENDED DECEMBER 31,
------------------- ------------------------------
2000 1999 1999 1998 1997
-------- -------- -------- -------- --------
(UNAUDITED)
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
Numerator:
Net income from continuing operations.............. $ 4,107 $ 1,403 $ 4,675 $ 4,873 $ 5,151
Gain on disposal of discontinued operations, net... -- 452 452 -- --
Equity in earnings of discontinued operations,
net.............................................. -- -- -- 339 313
Preferred stock dividends.......................... -- -- -- -- (400)
------- ------- ------- ------- -------
Numerator for basic earnings per share -- income
available to common stockholders................. 4,107 1,855 5,127 5,212 5,064
------- ------- ------- ------- -------
Effect of dilutive securities:
Preferred stock dividends.......................... -- -- -- -- 400
------- ------- ------- ------- -------
Numerator for dilutive earnings per share -- income
available to common stockholders after assumed
conversions...................................... $ 4,107 $ 1,855 $ 5,127 $ 5,212 $ 5,464
======= ======= ======= ======= =======
Denominator:
Denominator for basic earnings per share --
weighted average shares.......................... 14,905 11,347 12,953 10,522 9,575
Effect of dilutive securities:
Stock warrants................................... 691 675 680 647 335
8% Convertible preferred stock................... -- -- -- -- 755
------- ------- ------- ------- -------
Dilutive potential common shares................... 691 675 680 647 1,090
------- ------- ------- ------- -------
Denominator for diluted earnings per share --
adjusted weighted average shares and assumed
conversions...................................... 15,596 12,022 13,633 11,169 10,665
======= ======= ======= ======= =======
BASIC INCOME PER COMMON SHARE:
From continuing operations......................... $ 0.28 $ 0.12 $ 0.36 $ 0.47 $ 0.50
From discontinued operations....................... -- 0.04 0.03 0.03 0.03
------- ------- ------- ------- -------
Basic income per common share........................ $ 0.28 $ 0.16 $ 0.39 $ 0.50 $ 0.53
======= ======= ======= ======= =======
DILUTED INCOME PER COMMON SHARE:
From continuing operations......................... $ 0.26 $ 0.11 $ 0.34 $ 0.44 $ 0.48
From discontinued operations....................... -- 0.04 0.03 0.03 0.03
------- ------- ------- ------- -------
Diluted income per common share...................... $ 0.26 $ 0.15 $ 0.37 $ 0.47 $ 0.51
======= ======= ======= ======= =======
</TABLE>

For the six months ended June 30, 2000 and 1999 and the years ended
December 31, 1999, 1998 and 1997 all common stock equivalents were included in
the computation of diluted earnings per share.

F-21
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(UNAUDITED AS TO THE SIX MONTHS ENDED JUNE 30, 2000 AND 1999)

(9) STOCKHOLDERS' EQUITY (CONTINUED)
STOCK ISSUED FOR SERVICES

During the six months ended June 30, 2000 and the years ended December 31,
1999 and 1997, the Company issued common stock valued at $15,000, $801,000 and
$240,000 as bonuses to certain employees. During the year ended December 31,
1998, the Company issued common stock to directors for directors fees valued at
$190,000.

STOCK ISSUED FOR PROPERTY INTERESTS

Effective December 31, 1998, the Company purchased coal bed methane gas
interests from a company for $8.5 million. The purchase price consisted of
450,000 shares of Evergreen common stock valued at $16.67 per share for a total
of $7.5 million and the assumption of $750,000 in debt and cash of $250,000.

Effective September 30, 1999, Evergreen acquired XYZ for $5 million. The
purchase price consisted of $2.5 million in cash and 120,000 shares of Evergreen
stock valued at $2.5 million. (See Note 3).

During the year ended December 31, 1999, miscellaneous property interests
and surface rights were acquired with 55,996 shares of the Company's common
stock valued at $921,000.

On January 20, 2000, the Company acquired additional interests in the Raton
Basin for 300,955 shares of Evergreen common stock valued at approximately
$5.4 million.

OTHER EQUITY TRANSACTIONS

During the year ended December 31, 1997, pursuant to the exercise of stock
purchase warrants, 30,900 shares of common stock were issued at $3.63, in
exchange for 7,677 shares of common stock currently issued and outstanding at
various market values. In addition, 58,466 shares of common stock were issued
under terms of warrants previously granted, resulting in proceeds to the Company
of $367,000.

During the year ended December 31, 1999, the Company repurchased 100,000
shares of its common stock on the market at prices ranging from $16 to $19.19
per share for a total of $1.7 million.

SHELF REGISTRATION STATEMENT

In May 1999, the Company filed a shelf registration statement with the
Securities and Exchange Commission 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 $150 million.

On June 22, 1999, the Company completed a public offering of its common
shares, whereby it sold 3,162,500 shares at $22.00 per share. Proceeds, net of
underwriters' commissions and expenses of $4.4 million, were $65.1 million, of
which $58 million and $3.6 million were used to pay off the Company's line of
credit and capital lease obligation.

The Company plans to complete a public offering in the fourth quarter of
2000. The net proceeds would be used to reduce amounts outstanding under its
credit facility.

F-22
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(UNAUDITED AS TO THE SIX MONTHS ENDED JUNE 30, 2000 AND 1999)

(9) STOCKHOLDERS' EQUITY (CONTINUED)
SHAREHOLDER RIGHTS PLAN

On July 7, 1997, the Board of Directors adopted a Shareholder Rights Plan
("Rights Plan"), pursuant to which stock purchase rights (the "Rights") were
distributed as a dividend to the Company's common stockholders at a rate of one
Right for each share of common stock held of record as of July 22, 1997. The
Rights Plan is designed to enhance the Board's ability to prevent an acquirer
from depriving stockholders of the long-term value of their investment and to
protect shareholders against attempts to acquire the Company by means of unfair
or abusive takeover tactics that have been prevalent in many unsolicited
takeover attempts. Under the Rights Plan, the Rights will become exercisable
only if a person or a group (except for existing 20% shareholders) acquires or
commences a tender offer for 20% or more of the Company's common stock. Until
they become exercisable, the Rights attach to and trade with the Company's
common stock. The Rights will expire July 22, 2007. The Rights may be redeemed
by the continuing members of the Board at $.001 per Right prior to the day after
a person or group has accumulated 20% or more of the Company's common stock.

(10) STOCK OPTIONS AND WARRANTS

On May 12, 1997, the Board of Directors adopted, and the Company's
shareholders subsequently approved, an Initial Stock Option Plan (the "Plan"),
whereby employees may be granted incentive options to purchase up to 500,000
shares of the common stock of the Company. The exercise price of incentive
options must be equal to at least the fair market value of the common stock as
of the date of grant. As of December 31, 1999, the Company has granted all
500,000 options under the plan.

Under the terms of the Company's Key Employee Equity Plan, options and/or
warrants are granted to key employees at not less than the market price of the
Company's common stock on the date of grant. However, during 1998, the Board of
Directors and the shareholders approved the issuance of warrants for 79,990
shares of the Company's common stock to officers and directors at an exercise
price of $7.00. The market price for the stock was $13.00 at the time of the
grant. The value of these options was $478,764 of which $224,600 was recorded as
compensation expense. The purpose of the warrants was to reward directors and
key personnel for past performance and to give them an incentive to remain with
the Company and to induce directors to take all or part of their non-executive
directors' compensation in the form of common stock.

On June 16, 2000, the Company's shareholders approved the 2000 Stock
Incentive Plan (the "2000 Plan"). Under the 2000 Plan, the Company may grant
options to purchase up to 1,000,000 shares of its common stock, plus an annual
increase equal to the lesser of either 150,000 shares or an amount determined by
the Board of Directors. Awards which may be granted under the 2000 Plan include
incentive stock options, non qualified stock options, stock appreciation rights
("SARs"), restricted stock awards and restricted units. As of June 30, 2000, no
awards had been granted under the 2000 plan.

During the six months ended June 30, 2000, the Company granted 272,080
options to its directors, officers and employees at an exercise price of $18.50.
During the six months ended June 30, 1999 and the year ended December 31, 1999,
the Company granted 221,301 options to its directors and officers at an exercise
price of $14.625. During the year ended December 31, 1998, the Company granted
264,990 options to its directors, officers and employees at an exercise prices
ranging from $7.00 to

F-23
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(UNAUDITED AS TO THE SIX MONTHS ENDED JUNE 30, 2000 AND 1999)

(10) STOCK OPTIONS AND WARRANTS (CONTINUED)
$13.00. During the year ended December 31, 1997, the Company granted 145,000
warrants at exercise prices ranging from $8.75 to $9.88.

<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30,
---------------------------------------------
2000 1999
--------------------- ---------------------
WEIGHTED WEIGHTED
AVERAGE AVERAGE
EXERCISE EXERCISE
SHARES PRICE SHARES PRICE
---------- -------- ---------- --------
(UNAUDITED)
<S> <C> <C> <C> <C>
Outstanding,
Beginning of period.............................. 1,106,281 $ 9.57 1,083,218 $ 8.17
Granted.......................................... 272,080 18.50 221,301 14.625
Exercised........................................ (18,625) 6.90 (53,863) 8.25
Expirations and forfeitures...................... (3,500) 13.00 (10,000) 12.58
---------- ------ ---------- -------
Outstanding,
end of period.................................... 1,356,236 $11.39 1,240,656 $ 9.28
---------- ------ ---------- -------
Options and warrants exercisable, end of period.... 831,486 $ 8.29 853,156 $ 7.51
---------- ------ ---------- -------
Weighted average fair value of options and warrants
granted during the period........................ $ 11.32 $ 9.48
========== ==========
</TABLE>

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
---------------------------------------------------------------------
1999 1998 1997
--------------------- --------------------- ---------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
---------- -------- ---------- -------- ---------- --------
<S> <C> <C> <C> <C> <C> <C>
Outstanding,
Beginning of period................. 1,083,218 $ 8.17 1,094,783 $ 7.41 1,182,301 $7.21
Granted............................. 221,301 14.625 264,990 11.18 145,000 8.83
Exercised........................... (188,238) 7.24 (276,555) 8.06 (97,518) 4.81
Expired............................. (10,000) 12.58 -- -- (135,000) 8.75
---------- ------- ---------- ------ ---------- -----
Outstanding,
end of period....................... 1,106,281 $ 9.57 1,083,218 $ 8.17 1,094,783 $7.41
---------- ------- ---------- ------ ---------- -----
Options and warrants
exercisable, end of period.......... 762,781 $ 7.94 853,468 $ 7.51 956,086 $7.47
---------- ------- ---------- ------ ---------- -----
Weighted average fair value of options
and warrants granted during the
period.............................. $ 9.48 $ 7.80 $ 4.58
========== ========== ==========
</TABLE>

SFAS No. 123, "Accounting for Stock-Based Compensation," requires the
Company to provide pro forma information regarding net income and net income per
share as if compensation costs for the Company's stock option plans and other
stock awards had been determined in accordance with the fair value based method
prescribed in SFAS No. 123. The Company estimated the fair value of each stock
award at the grant date by using the Black-Scholes option-pricing model with the
following weighted-

F-24
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(UNAUDITED AS TO THE SIX MONTHS ENDED JUNE 30, 2000 AND 1999)

(10) STOCK OPTIONS AND WARRANTS (CONTINUED)
average assumptions used for grants in the year ended December 31, 1997:
dividend yield at 0%; expected volatility of approximately 45%; risk free
interest rate of 6%; and expected lives of between two and five years for the
warrants. Assumptions used for the year ending December 31, 1998: dividend yield
at 0%; expected volatility of approximately 58%; risk free interest rate of 5.6%
and expected lives of five years for the warrants and options. Assumptions used
for the six months ended June 30, 1999 and the year ending December 31, 1999:
dividend yield at 0%; expected volatility of approximately 43%; risk free
interest rate of 4.5% and expected lives of five and ten years for the warrants
and options. Assumptions used for the six months ended June 30, 2000: dividend
yield at 0%; expected volatility of approximately 43%; risk free interest rate
of 4.9% and expected lives of five to ten years for the warrants and options.

Under the accounting provisions for SFAS No. 123, the Company's net income
and net income per share would have been adjusted to the following pro forma
amounts:

<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30,
-------------------------------------------------
2000 1999
----------------------- -----------------------
AS REPORTED PRO FORMA AS REPORTED PRO FORMA
----------- --------- ----------- ---------
(UNAUDITED)
(IN THOUSANDS EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C>
BASIC NET INCOME:
Income from continuing operations............... $4,107 $2,229 $1,403 $ 859
Discontinued operations......................... -- -- 452 452
------ ------ ------ ------
Net income...................................... $4,107 $2,229 $1,855 $1,311
====== ====== ====== ======
BASIC INCOME PER COMMON SHARE:
From continuing operations...................... $ 0.28 $ 0.15 $ 0.12 $ 0.08
From discontinued operations.................... -- -- 0.04 0.04
------ ------ ------ ------
Basic income per common share................... $ 0.28 $ 0.15 $ 0.16 $ 0.12
====== ====== ====== ======
DILUTED NET INCOME:
Income from continuing operations............... $4,107 $2,229 $1,403 $ 859
Discontinued operations......................... -- -- 452 452
------ ------ ------ ------
Net income...................................... $4,107 $2,229 $1,855 $1,311
====== ====== ====== ======
DILUTED INCOME PER COMMON SHARE:
From continuing operations...................... $ 0.26 $ 0.14 $ 0.11 $ 0.07
From discontinued operations.................... -- -- 0.04 0.04
------ ------ ------ ------
Diluted income per common share................. $ 0.26 $ 0.14 $ 0.15 $ 0.11
====== ====== ====== ======
</TABLE>

F-25
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(UNAUDITED AS TO THE SIX MONTHS ENDED JUNE 30, 2000 AND 1999)

(10) STOCK OPTIONS AND WARRANTS (CONTINUED)

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
---------------------------------------------------------------------------
1999 1998 1997
----------------------- ----------------------- -----------------------
AS REPORTED PRO FORMA AS REPORTED PRO FORMA AS REPORTED PRO FORMA
----------- --------- ----------- --------- ----------- ---------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C>
BASIC NET INCOME:
Income from continuing
operations...................... $4,675 $4,131 $4,873 $4,416 $4,751 $4,117
Discontinued operations........... 452 452 339 339 313 313
------ ------ ------ ------ ------ ------
Net income........................ $5,127 $4,583 $5,212 $4,755 $5,064 $4,430
====== ====== ====== ====== ====== ======
BASIC INCOME PER COMMON SHARE:
From continuing operations........ $ 0.36 $ 0.32 $ 0.47 $ 0.42 $ 0.50 $ 0.43
From discontinued operations...... 0.03 0.03 0.03 0.03 0.03 0.03
------ ------ ------ ------ ------ ------
Basic income per common share..... $ 0.39 $ 0.35 $ 0.50 $ 0.45 $ 0.53 $ 0.46
====== ====== ====== ====== ====== ======
DILUTED NET INCOME:
Income from continuing
operations...................... $4,675 $4,131 $4,873 $4,416 $5,151 $4,517
Discontinued operations........... 452 452 339 339 313 313
------ ------ ------ ------ ------ ------
Net income........................ $5,127 $4,583 $5,212 $4,755 $5,464 $4,830
====== ====== ====== ====== ====== ======
DILUTED INCOME PER COMMON SHARE:
From continuing operations........ $ 0.34 $ 0.31 $ 0.44 $ 0.40 $ 0.48 $ 0.42
From discontinued operations...... 0.03 0.03 0.03 0.03 0.03 0.03
------ ------ ------ ------ ------ ------
Diluted income per common share... $ 0.37 $ 0.34 $ 0.47 $ 0.43 $ 0.51 $ 0.45
====== ====== ====== ====== ====== ======
</TABLE>

The following table summarizes information about stock options and warrants
outstanding at June 30, 2000 (Unaudited):

<TABLE>
<CAPTION>
OUTSTANDING EXERCISABLE
----------------------------------------------------- ----------------------------
NUMBER WEIGHTED AVERAGE WEIGHTED NUMBER WEIGHTED
OUTSTANDING AT REMAINING AVERAGE EXERCISE EXERCISABLE AVERAGE
RANGE OF EXERCISE PRICES 6/30/00 CONTRACTUAL LIFE PRICE AT 6/30/00 EXERCISE PRICE
------------------------ -------------- ----------------- ---------------- ----------- --------------
<S> <C> <C> <C> <C> <C>
$ 4.25........... 10,000 0.48 $ 4.25 10,000 $ 4.25
6.90........... 14,029 1.31 6.90 14,029 6.90
7.00........... 544,240 2.29 7.00 544,240 7.00
7.80 - 9.50......... 122,086 1.42 8.06 122,086 8.06
13.00........... 172,500 7.51 13.00 86,250 13.00
14.63........... 221,301 8.57 14.63 46,301 14.63
18.50........... 272,080 9.45 18.50 8,580 18.50
--------- ---- ------ ------- ------
$4.25 - 18.50......... 1,356,236 5.31 $11.39 831,486 $ 8.29
========= ==== ====== ======= ======
</TABLE>

F-26
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(UNAUDITED AS TO THE SIX MONTHS ENDED JUNE 30, 2000 AND 1999)

(10) STOCK OPTIONS AND WARRANTS (CONTINUED)

The following table summarizes information about stock options and warrants
outstanding at December 31, 1999:

<TABLE>
<CAPTION>
OUTSTANDING EXERCISABLE
----------------------------------------------------- ----------------------------
NUMBER WEIGHTED AVERAGE WEIGHTED NUMBER WEIGHTED
OUTSTANDING AT REMAINING AVERAGE EXERCISE EXERCISABLE AVERAGE
RANGE OF EXERCISE PRICES 12/31/99 CONTRACTUAL LIFE PRICE AT 12/31/99 EXERCISE PRICE
------------------------ -------------- ----------------- ---------------- ----------- --------------
<S> <C> <C> <C> <C> <C>
$ 4.25........... 10,000 1.00 $ 4.25 10,000 $ 4.25
6.90........... 32,654 1.83 6.90 32,654 6.90
7.00........... 544,240 2.69 7.00 498,740 7.00
7.80 - 9.50......... 122,086 1.91 8.06 122,086 8.06
13.00........... 176,000 8.00 13.00 88,000 13.00
14.63........... 221,301 9.00 14.63 11,301 14.63
--------- ---- ------ ------- ------
$4.25 - 14.63......... 1,106,281 4.62 $ 9.57 762,781 $ 7.94
========= ==== ====== ======= ======
</TABLE>

(11) MAJOR CUSTOMERS

During the six months ended June 30, 2000 and 1999 and the years ended
December 31, 1999, 1998 and 1997, the Company made sales to certain unrelated
entities which individually comprised greater than 10% of total oil and gas
sales. The following is a table summarizing the percentage provided by each
customer:

<TABLE>
<CAPTION>
CUSTOMER A B C D
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C>
Six months ended June 30, 2000 (Unaudited)........... 46% --% 21% --%
Six months ended June 30, 1999 (Unaudited)........... 46% 25% 26% --%
Year ended December 31, 1999......................... 49% 18% 24% --%
Year ended December 31, 1998......................... 44% --% 45% --%
Year ended December 31, 1997......................... 48% --% 17% 17%
</TABLE>

(12) SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

Cash paid during the six months ended June 30, 2000 and 1999 and the years
ended December 31, 1999, 1998 and 1997, for interest was approximately $974,000,
$1,800,000, $2,194,000, $2,317,000, and $817,000. During the six months ended
June 30, 2000 and 1999 and the years ended December 31, 1999 and 1998,
approximately $158,000, $351,000, $351,000 and $448,000 of interest paid was
capitalized.

See Notes 3, 8, 9, and 10 for additional non-cash transactions during the
six months ended June 30, 2000 and 1999 and the years ended December 31, 1999,
1998 and 1997.

(13) COMMITMENTS AND CONTINGENCIES

In August 1997, the Company entered into an agreement with Colorado
Interstate Gas Co. ("CIG") pursuant to which CIG built a new, 115-mile, 16-inch
pipeline, the Campo Lateral. This agreement has a term of 15 years and entitles
the Company to firm transportation of its Raton Basin gas from the field to the
CIG interconnection with other interstate pipelines in Texas. At that time the

F-27
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(UNAUDITED AS TO THE SIX MONTHS ENDED JUNE 30, 2000 AND 1999)

(13) COMMITMENTS AND CONTINGENCIES (CONTINUED)
Company committed to transport 41 MMcf per day through CIG's pipelines. During
1998, the Company acquired certain properties in the Raton Basin. In addition to
the properties, the Company assumed additional firm transportation commitments
with CIG of 12 MMcf per day bringing the Company's total firm transportation
commitments to 53 MMcf per day at December 31, 1999.

The Company expects to meet its volume obligations with respect to the Raton
Basin transportation agreement. If the Company is unable to meet its firm
transportation commitments, the commitment must be paid for but can be deferred
and utilized at a later date.

Under terms of the transportation agreements, the Company has committed to
pay the following transportation reservation charges with CIG to provide firm
transportation capacity rights:

<TABLE>
<CAPTION>
RESERVATION
YEARS ENDING DECEMBER 31, CHARGES
------------------------- --------------
(IN THOUSANDS)
<S> <C>
2000........................................................ $ 5,539
2001........................................................ 5,644
2002........................................................ 5,644
2003........................................................ 5,644
2004........................................................ 5,592
Thereafter.................................................. 42,984
-------
$71,047
=======
</TABLE>

Subsequent to June 30, 2000, the Company committed an additional 11 MMcf per
day of firm transportation, bringing its total commitment to 64 MMcf per day
starting December 1, 2000. On September 20, 2000, the Company also assumed firm
transportation of approximately 21 MMcf per day from a company in conjunction
with an acquisition of producing coal bed methane properties as discussed in
Note 14. Additionally, the Company has committed to an additional 40 MMcf per
day starting in October 2001. The 40 MMcf per day is subject to a ramp-up
schedule increasing 5 MMcf per day every four months from October 1, 2001
through February 2004. If the Company is unable to fulfill its transportation
commitments, amounts paid will be credited toward future transportation costs
through August 2006.

In May 1998, the Company entered into a new ten-year office lease for
approximately $267,500 per year. Rental expense, net of sublease income, was
approximately $137,000, 132,000, $268,000, $234,000, and $138,000, for the six
months ended June 30, 2000 and 1999 and the years ended December 31, 1999, 1998
and 1997.

F-28
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(UNAUDITED AS TO THE SIX MONTHS ENDED JUNE 30, 2000 AND 1999)

(13) COMMITMENTS AND CONTINGENCIES (CONTINUED)
The Company also leases equipment under noncancelable operating leases with
maturity dates through the year ending December 31, 2002. The following table
summarizes the future minimum lease payments under all noncancelable operating
lease obligations.

<TABLE>
<CAPTION>
FUTURE
MINIMUM
LEASE
YEARS ENDING DECEMBER 31, PAYMENTS
------------------------- --------------
(IN THOUSANDS)
<S> <C>
2000........................................................ $ 413
2001........................................................ 372
2002........................................................ 303
2003........................................................ 268
2004........................................................ 268
2005 and Thereafter......................................... 892
------
$2,516
======
</TABLE>

Effective January 1, 1997, the Company implemented a 401(k) plan (the
"Plan") for all eligible employees. The Company provides a matching contribution
up to a certain percentage of the employees' contributions. The Plan also
provides for a profit sharing contribution determined at the discretion of the
Company. The total matching contributions and profit sharing contribution for
the six months ended June 30, 2000 and 1999 and the years ended December 31,
1999, 1998 and 1997 were approximately $10,000, $60,000, $46,000, $34,000 and
$134,000.

In connection with the Chilean oil and gas exploration contract, the Company
has substantially completed its obligation for the seismic program in 1999. In
connection with the seismic obligation, the Company had issued letters of credit
totaling $1.5 million which expired in June 2000. See Note 3 for work
commitments in the UK and Falkland Islands.

On July 13, 1998, a localized group of citizens, Southern Colorado C.U.R.E.,
filed a lawsuit against EOC under the citizen suit provision of the Clean Water
Act in the U.S. District Court for the District of Colorado, related to EOC's
water production associated with its coal bed methane drilling operations in the
Raton Basin near Trinidad, Colorado. EOC also coordinated with the EPA and the
State of Colorado in the investigation of certain practices in connection with
these operations. On January 7, 2000, EOC entered into a Compliance Order on
Consent with the State of Colorado Department of Public Health and the
Environment ("CDPHE") that resolved water quality/ discharge issues between the
CDPHE and EOC. As a result, as anticipated, the U.S. District Court granted the
Company's Motion to Dismiss the citizen suit, with prejudice, on the grounds
that the Consent Order moots the federal case and bars C.U.R.E. from seeking
further penalties for the same alleged violations. The only outstanding matter
related to this case pertains to the assertion by C.U.R.E. that it is entitled
to attorneys fees, which the Company disputes and has vigorously contested.
Management believes that in the event attorney fees are granted, it would not
have a material adverse effect on the Company's operations.

EOC is also subject to federal, state and local environmental laws and
regulations, and participated with the EPA and the State of Colorado in the
investigation of certain practices in connection with these operations. On
January 7, 2000, EOC agreed to a Consent Order with the CDPHE that resolved

F-29
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(UNAUDITED AS TO THE SIX MONTHS ENDED JUNE 30, 2000 AND 1999)

(13) COMMITMENTS AND CONTINGENCIES (CONTINUED)
certain water storage and discharge issues between the CDPHE and EOC. Under the
Consent Order, EOC has obtained additional permits and will install a water
supply system as a Supplemental Environmental Project, in lieu of civil
penalties, that will benefit rural landowners in the areas in which the Company
operates. Evergreen may process a portion of its produced water to meet
potability standards. The estimated cost of the water supply system is $360,000.
The Consent Order resolves all outstanding issues between EOC and Colorado state
regulatory agencies, particularly the CDPHE, governing the discharge of produced
water from Evergreen's coal bed methane operations in the Raton Basin.

As of December 31, 1999, the Company had entered into contracts to sell
approximately 40,000 MMBtu per day from January 1, 2000 through March 31, 2000,
45,000 MMBtu per day from April 1, 2000 through October 31, 2000, for $1.99 per
Mcf, 20,000 MMBtu per day at NYMEX less $0.20 less fuel and transportation costs
for the period November 1, 2000 through October 31, 2001 and 10,000 MMBtu per
day from October 1, 2000 through December 31, 2000 at $2.10 per Mcf. The Company
has also extended a contract to sell 10,000 MMBtu per day from November 1, 2000
through March 31, 2003 for the lessor of $2.45 per Mcf or the current market
price. In consideration for this contract, the Company will receive $1,762,000,
which will be amortized as revenue pro-rata over the extended contract term.

Subsequent to December 31, 1999, the Company converted 10,000 MMBtu's of the
20,000 MMBtu per day contract discussed above to a fixed price of $2.28 per Mcf
versus the NYMEX less $0.20 and fuel and transportation costs. In addition, the
Company also assumed a contract to sell 10,000 MMBtu per day from October 1,
2000 through December 31, 2000 at a price of $2.10 per Mcf in conjunction with
the purchase of coal bed methane properties on September 20, 2000 as discussed
in Note 14.

(14) SUBSEQUENT EVENTS

On September 20, 2000, the Company acquired interests in approximately
24,000 acres of producing coal bed methane properties in the Raton Basin from
Apache Canyon Gas, L.L.C., an affiliate of KLT Gas, Inc., an indirect wholly
owned subsidiary of Kansas City Power & Light Company. The total consideration
paid by the Company on closing was approximately $70 million in cash,
$100 million of its redeemable preferred stock and $6 million of its Company's
common stock. The transaction was effective September 1, 2000. The acquisition
has been accounted for as a purchase and the results of operations for the
acquired properties will be included in the Company's results of operations
beginning September 1, 2000. The Company will reflect the preliminary purchase
price allocation in its financial statements. The final purchase price will be
determined following management review and resolution of the contingencies
discussed below.

The Company financed the cash portion of the purchase price through an
increase in its revolving line of credit (see Note 4 for further discussion).
The Company issued 100,000 shares of Series A redeemable preferred stock, with
an aggregate liquidation value of $100 million. Each share has a liquidation and
redemption value of $1,000, plus accrued dividends. The Company can elect to
redeem

F-30
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(UNAUDITED AS TO THE SIX MONTHS ENDED JUNE 30, 2000 AND 1999)

(14) SUBSEQUENT EVENTS (CONTINUED)
the stock at any time, and the holder can require it to redeem the stock at any
time after June 30, 2001, or earlier if a stock offering meeting certain
conditions is completed. The preferred stock earns dividends at a rate of 9.5%
until December 31, 2000. From January 1, 2001 to March 31, 2001 the dividend
rate would be 21.5%, and after April 1, 2001, the dividend rate would be 27.5%.
The preferred stock is not convertible, and has voting rights only with respect
to (1) certain extraordinary corporate transactions such as a merger,
consolidation or sale of all or substantially all of the Company's assets;
(2) the issuance of debt or equity securities that are senior to or on par with
the preferred stock; (3) the redemption of the Company's common stock or any
other stock ranking junior to or on par with the preferred stock; (4) the
payment of dividends with respect to the Company's common stock; and
(5) certain other matters that would affect its holders. In addition to the
special voting rights provided above, the holders of the preferred stock shall
also have the right to vote as a separate class on any matter if required by the
Colorado Business Corporation Act or any successor statute. The number of shares
of the Company's common stock issued upon the closing of the acquisition was
201,748 and was calculated based on a per-share price equal to the average
closing price of the Company's common stock during the fifteen-trading-day
period ending on the day prior to the closing.

In addition to the consideration paid at the closing of the acquisition, the
Company will be required at January 5, 2001 to deliver additional shares of its
common stock valued at $4 million, in the event the average of the monthly
settle prices for the 2001 NYMEX natural gas futures contracts equals or exceeds
$4.465 per MMBtu. The number of shares of stock issuable would be calculated
based on a per-share price equal to the average closing price of the Company's
common stock during the fifteen-trading-day period ending on the day prior to
the date of delivery of such stock. As additional purchase consideration, the
Company is required to pay a monthly net profits interest payment estimated at
approximately $500,000 through the earlier of the redemption of the preferred
stock or January 1, 2003.

See Note 13 for discussion of firm transportation commitments assumed in
conjunction with this purchase.

(15) DISCONTINUED OPERATIONS

Effective February 18, 1999, Evergreen sold its 49% interest in Maverick to
the managing members of Maverick for $2,260,000. The sale resulted in a gain,
net of tax, of approximately $452,000 or $0.03 per diluted share. The Company
was also released from its guarantee of certain debt obligations of Maverick.
This transaction has been accounted for as a discontinued operation and the
results of operations have been excluded from continuing operations in the
consolidated statements of income for all periods presented.

Maverick provided pressure pumping and other oilfield services to the
petroleum industry in the Rocky Mountain region. Maverick provided certain well
stimulation services to the Company and during 1998 and 1997 such services
amounted to $2,381,000 and $2,636,000. The investment in Maverick, including
equity in earnings, was $1,458,500 at December 31, 1998, and is included in
other assets in the accompanying consolidated financial statements as of
December 31, 1998.

F-31
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(UNAUDITED AS TO THE SIX MONTHS ENDED JUNE 30, 2000 AND 1999)

(16) SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

COSTS INCURRED IN OIL AND GAS EXPLORATION AND DEVELOPMENT ACTIVITIES

The Company's oil and gas activities are conducted in the United States,
United Kingdom, the Falkland Islands and Chile. See Note 3 for additional
information regarding the Company's oil and gas properties. The following costs
were incurred in oil and gas acquisition, exploration, development, gas
gathering and producing activities during the following periods:

<TABLE>
<CAPTION>
UNITED UNITED FALKLAND
STATES KINGDOM ISLANDS CHILE TOTAL
-------- -------- -------------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Year ended December 31, 1999
Acquisition costs:
Proved..................................... $ 2,020 $ -- $ -- $ -- $ 2,020
Unproved................................... 3,057 -- -- -- 3,057
Development.................................. 21,597 -- -- -- 21,597
Gas collection............................... 14,835 -- -- -- 14,835
Exploration.................................. 792 1,032 78 1,962 3,864
------- ------ ---- ------ -------
$42,301 $1,032 $ 78 $1,962 $45,373
------- ------ ---- ------ -------
Year ended December 31, 1998
Acquisition costs:
Proved..................................... $ 9,000 $ -- $ -- $ -- $ 9,000
Unproved................................... 11,600 -- -- -- 11,600
Gas collection............................. 1,000 -- -- -- 1,000
Development.................................. 11,366 -- -- -- 11,366
Gas collection............................... 8,729 -- -- -- 8,729
Exploration.................................. 1,762 724 972 432 3,890
------- ------ ---- ------ -------
$43,457 $ 724 $972 $ 432 $45,585
------- ------ ---- ------ -------
Year ended December 31, 1997
Development.................................. $10,194 $ -- $ -- $ -- $10,194
Gas collection............................... 9,915 -- -- -- 9,915
Exploration.................................. 603 385 141 133 1,262
------- ------ ---- ------ -------
$20,712 $ 385 $141 $ 133 $21,371
------- ------ ---- ------ -------
</TABLE>

OIL AND GAS RESERVES (UNAUDITED)

The estimates of the Company's proved natural gas reserves and related
future net cash flows that are presented in the following tables are based upon
estimates made by independent petroleum engineering consultants for the United
States only.

The Company's reserve information was prepared as of December 31, 1999, 1998
and 1997. The Company cautions that there are many inherent uncertainties in
estimating proved reserve quantities, projecting future production rates, and
timing of development expenditures. Accordingly, these estimates are likely to
change as future information becomes available. Proved oil and gas reserves are
the estimated quantities of crude oil, condensate, natural gas and natural gas
liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from

F-32
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(UNAUDITED AS TO THE SIX MONTHS ENDED JUNE 30, 2000 AND 1999)

(16) SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (CONTINUED)
known reservoirs under existing economic and operating conditions. Proved
developed reserves are those reserves expected to be recovered through existing
wells, with existing equipment and operating methods.

Estimated quantities of proved reserves and proved developed reserves of
natural gas (all of which are located within the United States), as well as the
changes in proved reserves, are as follows:

<TABLE>
<CAPTION>
1999 1998 1997
PROVED RESERVES: GAS (MMCF) GAS (MMCF) GAS (MMCF)
---------------- ---------- ---------- ----------
<S> <C> <C> <C>
Beginning of year.......................................... 404,936 224,414 150,720
Revisions of previous estimates............................ 3,723 (25,046) (3,988)
Extensions and discoveries................................. 148,570 155,205 89,721
Production................................................. (13,656) (10,021) (6,402)
Purchase of reserves....................................... 15,845 60,384 --
Sale of minerals in place.................................. -- -- (5,637)
------- ------- -------
End of year................................................ 559,418 404,936 224,414
======= ======= =======
Proved developed reserves.................................. 334,804 242,987 143,554
======= ======= =======
</TABLE>

The following table sets forth a standardized measure of the estimated
discounted future net cash flows attributable to the Company's proved gas
reserves. Gas prices have fluctuated widely in recent years. The calculated
weighted average sales prices utilized for the purposes of estimating the
Company's proved reserves and future net revenues were $2.01, $1.60 and $1.87
per Mcf of gas at December 31, 1999, 1998 and 1997. The future production and
development costs represent the estimated future expenditures to be incurred in
developing and producing the proved reserves, assuming continuation of existing
economic conditions. Future income tax expense was computed by applying
statutory income tax rates to the difference between pretax net cash flows
relating to the Company's proved reserves and the tax basis of proved properties
and available operating loss carryovers.

<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------------------
1999 1998 1997
----------- -------------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows..................................... $ 1,126,668 $ 647,898 $ 418,532
Future production costs................................. (247,908) (109,217) (55,332)
Future development costs................................ (57,777) (45,535) (17,790)
Future income taxes..................................... (298,798) (163,665) (90,128)
----------- --------- ---------
Future net cash flows................................... 522,185 329,481 255,282
10% discount to reflect timing of cash flows............ (311,409) (186,052) (137,529)
----------- --------- ---------
Standardized measure of discounted future net cash
flows................................................. $ 210,776 $ 143,429 $ 117,753
=========== ========= =========
</TABLE>

F-33
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(UNAUDITED AS TO THE SIX MONTHS ENDED JUNE 30, 2000 AND 1999)

(16) SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (CONTINUED)
The following summarizes the principal factors comprising the changes in the
standardized measure of discounted future net cash flows for the years ended
December 31, 1999, 1998 and 1997.

<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------------
1999 1998 1997
-------- -------------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Standardized measure, beginning of period.................. $143,429 $117,753 $ 56,244

Sales of natural gas, net of production costs.............. (17,330) (15,706) (10,131)
Extensions and discoveries................................. 66,120 60,403 52,587
Net change in sales prices, net of production costs........ 54,802 (38,366) 30,171
Purchase of reserves....................................... 8,740 31,165 --
Sale of reserves........................................... -- -- (2,150)
Revisions of quantity estimates............................ 3,000 (15,837) (3,131)
Accretion of discount...................................... 21,468 15,933 7,050
Net change in income taxes................................. (49,361) (29,673) (27,318)
Changes in future development costs........................ (2,620) 10,199 8,596
Changes in rates of production and other................... (17,472) 7,558 5,835
-------- -------- --------
Standardized measure, end of period........................ $210,776 $143,429 $117,753
======== ======== ========
</TABLE>

(17) SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

<TABLE>
<CAPTION>
REVENUES FROM
REVENUES FROM DISCONTINUED BASIC DILUTED
CONTINUING OPERATIONS, NET EARNINGS EARNINGS
OPERATIONS (NOTE 15) EXPENSES NET INCOME PER SHARE PER SHARE
------------- --------------- -------- ---------- --------- ---------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C>
2000
First quarter...................... $ 7,436 $ -- $ 5,575 $1,861 $0.13 $0.12
Second quarter..................... 8,375 -- 6,129 2,246 0.15 0.14
------- ---- ------- ------ ----- -----
$15,811 $ -- $11,704 $4,107 $0.28 $0.26
======= ==== ======= ====== ===== =====
1999
First quarter...................... $ 4,623 $452 $ 4,088 $ 987 $0.09 $0.08
Second quarter..................... 5,203 -- 4,335 868 0.08 0.07
Third quarter...................... 5,856 -- 4,418 1,438 0.10 0.10
Fourth quarter..................... 7,246 -- 5,412 1,834 0.12 0.12
------- ---- ------- ------ ----- -----
$22,928 $452 $18,253 $5,127 $0.39 $0.37
======= ==== ======= ====== ===== =====
1998
First quarter...................... $ 4,357 $ 62 $ 3,019 $1,400 $0.13 $0.13
Second quarter..................... 4,504 73 3,245 1,332 0.13 0.12
Third quarter...................... 5,460 127 4,138 1,449 0.14 0.13
Fourth quarter..................... 4,920 77 3,966 1,031 0.10 0.09
------- ---- ------- ------ ----- -----
$19,241 $339 $14,368 $5,212 $0.50 $0.47
======= ==== ======= ====== ===== =====
</TABLE>

F-34
<PAGE>
Appendix A

[LETTERHEAD]

September 27, 2000

Mr. Mark S. Sexton
Evergreen Resources, Inc.
1401 Seventeenth Street, Suite 1200
Denver, Colorado 80202

Dear Mr. Sexton:

In accordance with your request, we have audited the estimates prepared
by Evergreen Resources, Inc. (Evergreen), as of September 1, 2000, of the
proved reserves and future net revenue to the Evergreen interest in certain
oil and gas properties located in the Raton Basin, Las Animas County,
Colorado. These estimates are based on constant prices and costs in
accordance with Securities and Exchange Commission (SEC) guidelines. The
following table sets forth Evergreen's estimates of the proved reserves and
future net revenue, as of September 1, 2000, for the audited properties:

<TABLE>
<CAPTION>
Net Reserves Future Net Revenue (M$)
-------------------- ------------------------------
Oil Gas Present Worth
Category (MBBL) (MMCF) Total at 10%
------------------ ------ --------- ----------- -------------
<S> <C> <C> <C> <C>
Proved Developed 0.0 371,319.1 1,315,238.0 602,262.3
Proved Undeveloped 0.0 297,617.0 1,008,281.0 317,308.9
--- --------- ----------- ---------
Total Proved (1) 0.0 668,936.2 2,323,519.0 919,571.1
</TABLE>

(1) Totals may not add due to rounding.

Gas volumes are expressed in millions of standard cubic feet (MMCF) at
the contract temperature and pressure bases. These properties have never
produced commercial volumes of condensate.

When compared on a property-by-property basis, some of the estimates of
Evergreen are greater and some are lesser than the estimates of Netherland,
Sewell & Associates, Inc.; however, in our opinion, Evergreen's estimates of
net proved oil and gas reserves and future net revenue, as shown herein and
in certain computer printouts on file in our office, are in the aggregate
reasonable and have been prepared in accordance with generally accepted
petroleum engineering and evaluation principles. These principles are set
forth in the Standards Pertaining to the Estimating and Auditing of Oil and
Gas Reserve Information promulgated by the Society of Petroleum Engineers. We
are satisfied with the methods and procedures utilized by Evergreen in
preparing the September 1, 2000 reserve and future revenue estimates, and we
saw nothing of an unusual nature that would cause us to take exception with
the estimates, in the aggregate, as prepared by Evergreen.

The estimated reserves and future revenue shown herein are for proved
developed and proved undeveloped reserves. Evergreen's estimates do not
include value for probable or possible reserves

A-1
<PAGE>

[LOGO]

which may exist for these properties, nor do they include any consideration
of undeveloped acreage beyond those tracts for which undeveloped reserves
have been estimated.

The gas price used by Evergreen is based on an August 31, 2000 average
NYMEX spot market price, adjusted for regional price differentials and BTU
content, and is held constant in accordance with SEC guidelines. Gas prices
are also adjusted to reflect existing hedges during 2000, 2001, and 2002.
Evergreen's estimates of lease and well operating costs are based on
historical operating expense records. These costs include direct lease and
field level costs and a gathering fee of $0.06 per MCF, but do not include
overhead expenses above the field level. Headquarters general and
administrative overhead expenses of Evergreen are not included. Lease and
well operating costs are held constant in accordance with SEC guidelines.
Lease and well operating costs are reduced after 5 years of production for
each well to reflect reduced water production. Evergreen's estimates of
capital costs are included as required for workovers, new development wells,
and production equipment.

It should be understood that our audit does not constitute a complete
reserve study of Evergreen's oil and gas properties. Our audit consisted of a
detailed review of properties making up 80 percent of the present worth for
the total proved reserves. In our audit, we accepted without independent
verification the accuracy and completeness of the historical information and
data furnished by Evergreen with respect to ownership interest, oil and gas
production, well test data, oil and gas prices, operating and development
costs, and any agreements relating to current and future operations of the
properties and sales of production. However, if in the course of our
examination something came to our attention which brought into question the
validity or sufficiency of any such information or data, we did not rely on
such information or data until we had satisfactorily resolved our questions
relating thereto or had independently verified such information or data.

We are independent petroleum engineers, geologists, and geophysicists with
respect to Evergreen Resources, Inc. as provided in the Standards Pertaining
to the Estimating and Auditing of Oil and Gas Reserve Information promulgated
by the Society of Petroleum Engineers. We no not own an interest in these
properties and are not employed on a contingent basis.

Very truly yours,

/s/ Frederic D. Sewell

A-2
<PAGE>
Appendix B

September 26, 2000

[LOGO]

Evergreen Resources, Inc.
1401 17th St., Suite 1200
Denver, Colorado 80202

Gentlemen:

We have audited the estimates, prepared by Evergreen Resources, Inc.
("Evergreen"), of the extent and value of the proved reserves of natural gas
for certain leases owned by Evergreen, as of September 1, 2000. The appraised
properties are located in Colorado. The reserve estimates are prepared
according to applicable SEC rules and utilize conventional and generally
accepted engineering methods.

Our review of Evergreen's reserve estimates is based upon a study of
Evergreen's properties. During this investigation, we consulted with the
officers and employees of Evergreen and were given access to such accounts,
records, geological and engineering reports, and other data as were desired
for examination. We previously prepared studies of gas properties in areas
where Evergreen's properties are located. Property interests owned,
production from such properties, current prices for production, agreements
relating to current and future operations and sale of production, gas tax
credit sales agreements, and various other information and data were
furnished to Resource Services International, Inc. ("RSII") by Evergreen and
are accepted as factual without independent verification of such facts. We
did not make a field examination of the operations or physical condition of
the appraised properties.

Definitions of proved reserves used in this evaluation are those set
forth in Rule 4-10(a) of Regulation S-X, as adopted by the SEC:

"PROVED OIL AND GAS RESERVES. Proved oil and gas reserves are the
estimated quantities of crude oil, natural gas, and natural gas liquids
which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under
existing economic and operating conditions, i.e., prices and costs as of
the date the estimate is made. Prices include consideration of changes
in existing prices provided only by contractual arrangements, but not
on escalations based upon future conditions.

B-1
<PAGE>

Evergreen Resources, Inc.
September 26, 2000
Page 2

"(i) Reserves are considered proved if economic producibility is
supported by either actual production or conclusive formation tests. The
area of a reservoir considered proved includes (A) that portion
delineated by drilling and defined by gas-oil and/or oil-water contacts,
if any, and (B) the immediately adjoining portions not yet drilled, but
which can be reasonably judged as economically productive on the basis
of available geological and engineering data. In the absence of
information on fluid contacts, the lowest known structural occurrence of
hydrocarbons controls the lower proved limit of the reservoir.

"(ii) Reserves which can be produced economically through application
of improved recovery techniques (such as fluid injection) are included in
the 'proved' classification when successful testing by a pilot project,
or the operation of an installed program in the reservoir, provides
support for the engineering analysis on which the project or program was
based.

"(iii) Estimates of proved reserves do not include the following: (A)
oil that may become available from known reservoirs but is classified
separately as 'indicated additional reserves'; (B) crude oil, natural
gas, and natural gas liquids, the recovery of which is subject to
reasonable doubt because of uncertainty as to geology, reservoir
characteristics, or economic factors; (C) crude oil, natural gas, and
natural gas liquids, that may occur in undrilled prospects; and (D) crude
oil, natural gas, and natural gas liquids, that may be recovered from oil
shales, gilsonite and other such sources.

"PROVED DEVELOPED OIL AND GAS RESERVES. Proved developed oil and gas
reserves are reserves that can be expected to be recovered through existing
wells with existing equipment and operating methods. Additional oil and
gas expected to be obtained through the application of fluid injection or
other improved recovery techniques for supplementing the natural forces
and mechanisms of primary recovery should be included as 'proved developed
reserves' only after testing by a pilot project or after the operation of
an installed program has confirmed through production response that
increased recovery will be achieved."

"PROVED UNDEVELOPED OIL AND GAS RESERVES. Proved undeveloped oil and
gas reserves are reserves that are expected to be recovered from new wells
on undrilled acreage, or from existing wells where a relatively major
expenditure is required for recompletion. Reserves on undrilled acreage
shall be limited to those drilling units offsetting productive units that
are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated
with certainty that there is continuity of production from the existing

B-2
<PAGE>

Evergreen Resources, Inc.
September 26, 2000
Page 3

productive formation. Under no circumstances should estimates for
proved undeveloped reserves be attributable to any acreage for which
an application of fluid injection or other improved recovery technique
is contemplated unless such techniques have been proved effective by
actual tests in the area and in the same reservoir."

Natural gas volumes are expressed at standard conditions of
temperature and pressure applicable in the area the gas is purchased.

Estimated net proved reserves of natural gas as of September 1, 2000
follow:

<TABLE>
<CAPTION>
NATURAL GAS
-----------
MMCF
<S> <C>

Total Proved Developed Producing Reserves 315,189

Total Proved Developed Non-Producing Reserves 56,130

Total Proved Undeveloped Reserves 297,617
-------
TOTAL PROVED RESERVES 668,936
=======

</TABLE>

Value of net proved reserves is expressed in terms of estimated future
net revenue and present value of future net revenue. Future net revenue is
calculated by deducting estimated operating expenses, future development
costs, and severance and ad valorem taxes from the future gross revenue.

Present value of future net revenue is calculated by discounting the
future net revenue at the arbitrary rate of 10 percent per year compounded
monthly over the expected period of realization. Present value, as expressed
herein, should not be construed as fair market value since no consideration
has been given to many factors which influence the prices at which petroleum
properties are traded, such as taxes on operating profits, allowance for
return on the investment, and normal risks incident to the oil business.

B-3
<PAGE>

Evergreen Resources, Inc.
September 26, 2000
Page 4

Estimated future net revenue and net present value of future net
revenue from proved natural gas, as of September 1, 2000 follow:

10% DISC.
FUTURE NET FUTURE NET
REVENUE M$ REVENUE M$
<S> <C> <C>

Total Proved Developed Producing Reserves 1,118,357 530,061

Total Proved Developed Non-Producing Reserves 196,881 72,201

Total Proved Undeveloped Reserves 1,008,281 317,308
--------- -------
TOTAL PROVED RESERVES 2,323,519 919,571
========= =======

</TABLE>

Evergreen's gas reserves are coal gas located in the Raton Basin,
Colorado. Projection of coalbed methane gas reserves is generally more
complicated than projection of conventional hydrocarbon reservoirs due to
complex reservoir properties and the dewatering process required to develop
producible natural gas reservoirs. Therefore, reserve estimates and gas
production rates for coalbed methane wells are modified frequently as gas and
water production data becomes available.

Resource Services International, Inc. and its principals are unrelated
to Evergreen, its officers, shareholders, and properties evaluated in this
report.

Submitted,

RESOURCE SERVICES INTERNATIONAL, INC.

B-4
<PAGE>

Appendix C

October 2, 2000 [LOGO]

Evergreen Resources, Inc.
1401 17th St., Suite 1200
Denver, Colorado 80202

Gentlemen:

We have audited the estimates, prepared by Evergreen Resources, Inc.
("Evergreen"), of the extent and value of the proved reserves of natural gas
for leases Evergreen has acquired from KLT Gas, Inc. ("KLT"). The reserves
are prepared as of September 1, 2000. The appraised properties are located in
the Raton Basin and are adjacent to leases owned and operated by Evergreen in
Colorado. Our audit has determined that the reserve estimates are prepared
according to applicable SEC rules and utilize conventional and generally
accepted engineering methods.

Our review of the reserve estimates for Evergreen's acquired KLT
interests is based upon a study of the acquired properties. During this
investigation, we consulted with the officers and employees of Evergreen and
were given access to such accounts, records, geological and engineering
reports, and other data as were desired for examination. We previously have
prepared studies of gas properties in areas where Evergreen's properties are
located. Property interests owned, production from such properties, current
prices for production, agreements relating to current and future operations
and sale of production, gas tax credit sales agreements, and various other
information and data were furnished to Resource Services International, Inc.
("RSII") by Evergreen and are accepted as factual without independent
verification of such facts. We did not make a field examination of the
operations or physical condition of the appraised properties.

Natural gas reserves included in this report are classified as proved
and are judged to be economically producible in future years from known
reservoirs under existing economic and operating conditions, assuming
continuation of the current regulatory practices, and using conventional
production methods and equipment. Further, the quantities of the estimated
future gas recovery are based upon the existing performance of the acquired
properties and do not reflect any changes as a result of Evergreen operating
the leases.

Definitions of proved reserves used in this evaluation are those set
forth in Rule 4-10(a) of Regulation S-X, as adopted by the SEC:

"PROVED OIL AND GAS RESERVES. Proved oil and gas reserves are
the estimated quantities of crude oil, natural gas, and natural gas
liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions, i.e.,
prices and costs as of the date the estimate is made. Prices include
consideration of

C-1
<PAGE>

Evergreen Resources, Inc.
October 2, 2000
Page 2

changes in existing prices provided only by contractual arrangements,
but not on escalations based upon future conditions.

"(i) Reserves are considered proved if economic producibility
is supported by either actual production or conclusive formation
tests. The area of a reservoir considered proved includes (A) that
portion delineated by drilling and defined by gas-oil and/or
oil-water contacts, if any, and (B) the immediately adjoining portions
not yet drilled, but which can be reasonably judged as economically
productive on the basis of available geological and engineering data.
In the absence of information on fluid contacts, the lowest known
structural occurrence of hydrocarbons controls the lower proved limit
of the reservoir.

"(ii) Reserves which can be produced economically through
application of improved recovery techniques (such as fluid injection)
are included in the 'proved' classification when successful testing by
a pilot project, or the operation of an installed program in the
reservoir, provides support for the engineering analysis on which the
project or program was based.

"(iii) Estimates of proved reserves do not include the
following: (A) oil that may become available from known reservoirs but
is classified separately as 'indicated additional reserves'; (B) crude
oil, natural gas, and natural gas liquids, the recovery of which is
subject to reasonable doubt because of uncertainty as to geology,
reservoir characteristics, or economic factors; (C) crude oil, natural
gas, and natural gas liquids, that may occur in undrilled prospects;
and (D) crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, gilsonite and other such sources.

"PROVED DEVELOPED OIL AND GAS RESERVES. Proved developed oil
and gas reserves are reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application
of fluid injection or other improved recovery techniques for
supplementing the natural forces and mechanisms of primary recovery
should be included as 'proved developed reserves' only after testing by
a pilot project or after the operation of an installed program has
confirmed through production response that increased recovery will be
achieved."

C-2
<PAGE>

Evergreen Resources, Inc.
October 2, 2000
Page 3

offsetting productive units that are reasonably certain of production
when drilled. Proved reserves for other undrilled units can be claimed
only where it can be demonstrated with certainty that there is
continuity of production from the existing productive formation. Under
no circumstances should estimates for proved undeveloped reserves be
attributable to any acreage for which an application of fluid injection
or other improved recovery technique is contemplated unless such
techniques have been proved effective by actual tests in the area and
in the same reservoir."

Natural gas volumes are expressed at standard conditions of
temperature and pressure applicable in the area the gas is purchased.

Estimated net proved reserves of natural gas as of September 1, 2000
follow:

<TABLE>
<CAPTION>
NATURAL GAS
-----------
MMCF
<S> <C>

Total Proved Developed Producing Reserves 139,764

Total Proved Developed Non-Producing Reserves 2,563

Total Proved Undeveloped Reserves 11,134
-------
TOTAL PROVED RESERVES 153,461
=======

</TABLE>

C-3
<PAGE>

Evergreen Resources, Inc.
October 2, 2000
Page 4

Estimated future net revenue and net present value of future net
revenue from proved natural gas, as of September 1, 2000 follow:

10% DISC.
FUTURE NET FUTURE NET
REVENUE M$ REVENUE M$
<S> <C> <C>

Total Proved Developed Producing Reserves 496,815 229,872

Total Proved Developed Non-Producing Reserves 7,404 4,015

Total Proved Undeveloped Reserves 35,141 11,980
--------- -------
TOTAL PROVED RESERVES 539,362 245,868
========= =======

</TABLE>

Evergreen's gas reserves are coal gas located in the Raton Basin,
Colorado. Projection of coal bed methane gas reserves is generally more
complicated than projection of conventional hydrocarbon reservoirs due to
complex reservoir properties and the de-watering process required to develop
producible natural gas reservoirs. Therefore, reserve estimates and gas
production rates for coal bed methane wells are modified frequently as gas
and water production data becomes available.

Resource Services International, Inc. and its principals are unrelated
to Evergreen, its officers, shareholders, and properties evaluated in this
report.

Submitted,

RESOURCE SERVICES INTERNATIONAL, INC.

C-4
<PAGE>
PROSPECTUS
--------------------------------------------------------------------------------

$150,000,000

[LOGO]

Debt Securities, Common Stock, Preferred Stock, Depositary
Shares, Warrants, Subscription Rights and Guarantees

----------------------------------------------------------------------

By this prospectus, we may offer from time to time, in one or more series or
classes, the following securities:

- unsecured debt securities consisting of senior notes and debentures and
subordinated notes and debentures, and other unsecured evidences of
indebtedness in one or more series, including guarantees of our debt
securities by certain of our subsidiaries,

- shares of common stock,

- shares of preferred stock, in one or more series, which may be convertible
into or exchangeable for common stock or debt securities,

- warrants to purchase debt securities, preferred stock or common stock,

- depositary shares representing fractional interests in preferred stock,
and

- subscription rights evidencing the right to purchase any of the above
securities.

The aggregate initial offering price of the securities that we offer will not
exceed $150,000,000. We will offer the securities in amounts, at prices and on
terms to be determined by market conditions at the time of our offering.

We will provide the specific terms of the securities in supplements to this
prospectus. You should read this prospectus and the prospectus supplements
carefully before you invest in the securities. This prospectus may not be used
to consummate sales of securities unless accompanied by a prospectus supplement.

--------------------------------------------------------------------------------
--------------------------------------------------------------------------------

Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or passed upon the
accuracy or adequacy of this prospectus. Any representation to the contrary is a
criminal offense.
--------------------------------------------------------------------------------

The date of this prospectus is May 24, 1999.
<PAGE>
FORWARD-LOOKING STATEMENTS

This prospectus, including the information incorporated by reference,
contains forward-looking statements within meaning of section 27A of the
Securities Act of 1933 and section 21E of the Securities Exchange Act of 1934,
including statements regarding, among other items, our growth strategies,
anticipated trends in our business and our future results of operations, market
conditions in the oil and gas industry, our ability to make and integrate
acquisitions and the outcome of litigation and the impact of governmental
regulation. These forward-looking statements are based largely on our
expectations and are subject to a number of risks and uncertainties, many of
which are beyond our control, including those described in the applicable
prospectus supplement under "Risk Factors." Actual results could differ
materially from these forward-looking statements as a result of, among other
things:

- A decline in natural gas production or natural gas prices.

- Incorrect estimates of required capital expenditures.

- Increases in the cost of drilling, completion and gas collection or other
costs of production and operations.

- An inability to meet growth projections.

- Changes in general economic conditions.

In light of these risks and uncertainties, there can be no assurance that actual
results will be as projected in the forward-looking statements.

2
<PAGE>
THE COMPANY

Evergreen Resources, Inc. is an independent energy company engaged in the
exploration, production, development and acquisition of oil and gas properties.
Our current operations are principally focused on developing and expanding our
coalbed methane project located in the Raton Basin in southern Colorado. We also
hold exploration licenses onshore in the United Kingdom, a net 2% interest in a
group exploring offshore in the Falkland Islands, and an oil and gas license on
approximately 2.4 million acres in northern Chile.

We are one of the largest holders of oil and gas leases in the Raton Basin
with approximately 200,000 gross acres of coal bed methane properties and almost
200 producing gas wells. Our daily gas sales represent approximately 65% of the
gas currently sold from the Raton Basin. As of December 31, 1998, we had 173 net
producing gas wells on our Raton Basin properties. We have identified over 800
drilling locations on our Raton Basin acreage, of which 132 were included in our
proved reserve base at December 31, 1998. We intend to spend approximately
$35 million during 1999 on drilling and gas collection systems, $5 million on
well service equipment and $5 million on international and other projects.

Evergreen Operating Corporation, a wholly owned subsidiary, operates
approximately 196 oil and gas wells on behalf of its parent company. Evergreen
Operating Corporation is primarily responsible for drilling, evaluation,
production and sales activities associated with the Company's properties.

Primero Gas Marketing Company constructs and operates the Company's gas
collection systems and markets and sells the Company's gas.

Evergreen Well Service Company provides fracture stimulation services,
cement work, drilling and workovers to the Company.

We were incorporated in Colorado on January 14, 1981. Our principal
executive offices are at 1401 17th Street, Suite 1200, Denver, Colorado 80202,
and our telephone number is (303) 298-8100.

USE OF PROCEEDS

Except as otherwise described in any prospectus supplement, the net proceeds
from the sale of securities offered from time to time using this prospectus (the
"Securities") will be used for general corporate purposes, which may include
repayment or refinancing of indebtedness, working capital, capital expenditures,
acquisitions and repurchases and redemptions of securities.

3
<PAGE>
RATIOS OF EARNINGS TO FIXED CHARGES

The following table sets forth the computation of ratio of earnings to fixed
charges for the periods shown.

<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS
YEARS ENDED ENDED YEARS ENDED MARCH 31,
MARCH 31, DECEMBER 31, DECEMBER 31,
-------------------- -------------------- --------------- ------------------------
1999 1998 1998 1997 1996 1996 1995
--------- --------- --------- --------- --------------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
a) 1.71 7.10 4.23 6.76 4.50 (c) (c)
b) 1.71 7.10 4.23 4.87 2.07 (c) (c)
</TABLE>

------------

(a) The ratio of earnings to fixed charges has been computed by dividing
earnings available for fixed charges (earnings from continuing operations
before income taxes plus fixed charges less capitalized interest) by fixed
charges (interest expense plus capitalized interest).

(b) The ratio of earnings to fixed charges has been computed by dividing
earnings available for fixed charges (earnings from continuing operations
before income taxes plus fixed charges less capitalized interest) by fixed
charges (interest expense plus capitalized interest and preferred stock
dividends).

(c) Earnings did not cover fixed charges for the years ended March 31, 1996 and
1995, by $607,000 and $704,000 respectively.

DESCRIPTION OF DEBT SECURITIES

The following description of Evergreen Resources' unsecured Debt Securities
sets forth certain general terms and provisions of the Debt Securities to which
any prospectus supplement may relate. The particular terms of the Debt
Securities and the extent to which such general provisions may apply will be
described in a prospectus supplement relating to the Debt Securities.
Capitalized terms not otherwise defined in this prospectus or any prospectus
supplement will have the meanings given to them in the applicable indenture
described below. Evergreen is referred to in this description as the "Company."

The Debt Securities will be general unsecured obligations of the Company and
will constitute either Senior Debt Securities or Subordinated Debt Securities.
Senior Debt Securities will be issued under an indenture (the "Senior
Indenture") among the Company, the Subsidiary Guarantors and a trustee under the
Senior Indenture (the "Senior Trustee"). Subordinated Debt Securities will be
issued under an indenture (the "Subordinated Indenture") among the Company, the
Subsidiary Guarantors and a trustee under the Subordinated Indenture (the
"Subordinated Trustee"). The Senior Trustee and the Subordinated Trustee, as the
case may be, will be identified in the applicable prospectus supplement. The
Senior Indenture and the Subordinated Indenture are sometimes hereinafter
referred to herein individually as an "Indenture" and collectively as the
"Indentures," and the Senior Trustee and the Subordinated Trustee are sometimes
referred to as the "Trustee." The statements under this caption relating to the
Debt Securities and the Indentures are summaries only and do not purport to be
complete. Wherever such terms are used herein or particular provisions of the
Indentures are referred to, such terms or provisions, as the case may be, are
incorporated by reference as part of the statements made herein, and such
statements are qualified in their entirety by such reference.

PROVISIONS APPLICABLE TO BOTH SENIOR AND SUBORDINATED DEBT SECURITIES

GENERAL

The Indentures do not limit the aggregate principal amount of Debt
Securities which can be issued thereunder and provide that Debt Securities may
be issued from time to time thereunder in one or more series, each in an
aggregate principal amount authorized by the Company prior to issuance. The

4
<PAGE>
Indentures do not currently limit the amount of other unsecured indebtedness or
securities which may be issued by the Company. Unless otherwise indicated in a
prospectus supplement, the Debt Securities will not benefit from any covenant or
other provision that would afford Holders of such Debt Securities special
protection in the event of a highly leveraged transaction involving the Company.

If specified in the prospectus supplement, certain of the Company's
subsidiaries (the "Subsidiary Guarantors") will unconditionally guarantee on a
joint and several basis the Debt Securities as described under "Subsidiary
Guarantees" and in the prospectus supplement (the "Subsidiary Guarantees"). The
Subsidiary Guarantees will be unsecured obligations of each Subsidiary
Guarantor.

The applicable prospectus supplement will set forth the price or prices at
which the Debt Securities of a particular series will be issued and will
describe the following terms of the Debt Securities:

(1) the title of the Debt Securities, whether the Debt Securities are Senior
Debt Securities or Subordinated Debt Securities and, if Subordinated Debt
Securities, the subordination terms relating thereto;

(2) any limit on the aggregate principal amount of the Debt Securities;

(3) whether the Subsidiary Guarantors will provide Subsidiary Guarantees;

(4) whether such Debt Securities will be issued in the form of one or more
global securities and whether such global securities are to be issuable in
temporary global form or permanent global form;

(5) the date or dates on which the principal of and premium, if any, on the
Debt Securities are payable or the method of determination thereof;

(6) the rate or rates, or the method of determination thereof, at which the
Debt Securities will bear interest, if any;

(7) whether and under what circumstances Additional Amounts with respect to
the Debt Securities will be payable;

(8) the date or dates from which such interest will accrue;

(9) the interest payment dates on which such interest will be payable and
the record date for the interest payable on any Debt Securities on any interest
payment date;

(10) the place or places where the principal of, premium and interest, if
any, on and any Additional Amounts with respect to the Debt Securities will be
payable;

(11) the period or periods within which, the price or prices at which and the
terms and conditions upon which Debt Securities may be redeemed, in whole or in
part, at the option of the Company, if the Company is to have that option;

(12) the obligation, if any, of the Company to redeem or purchase Debt
Securities pursuant to any sinking fund or analogous provisions or at the option
of a holder thereof and the period or periods within which, the price or prices
at which and the terms and conditions upon which Debt Securities will be
redeemed or purchased in whole or in part pursuant to such obligation;

(13) the denomination in which any Debt Securities shall be issuable, if
other than denominations of $1,000 and any integral multiple thereof;

(14) the currency or currencies (including composite currencies), if other
than U.S. dollars, or the form, including equity securities, other debt
securities (including Debt Securities), warrants or any other securities or
property of the Company or any other Person, in which payment of principal of,
premium (if any) and interest on and any Additional Amounts with respect to the
Debt Securities will be payable;

5
<PAGE>
(15) if such payments are to be payable, at the election of the Company or a
holder thereof, in a currency or currencies other than that in which the Debt
Securities are stated to be payable, the currency or currencies in which such
payments as to which such election is made will be payable, and the periods
within which and the terms and conditions upon which such election is to be
made;

(16) if the amount of such payments may be determined with reference to any
commodities, currencies or indices, values, rates or prices or any other index
or formula, the manner in which such amounts will be determined;

(17) if other than the entire principal amount thereof, the portion of the
principal amount of Debt Securities that will be payable upon declaration of
acceleration of the maturity thereof;

(18) whether the Debt Securities are defeasible, and any additional means of
and conditions to satisfaction and discharge of the applicable Indenture with
respect to the Debt Securities;

(19) any deletions or modifications of or additions to the definitions,
Events of Default or covenants of the Company pertaining to the Debt Securities;

(20) if the Debt Securities are to be convertible into or exchangeable for
equity securities, other debt securities (including Debt Securities), warrants
or any other securities or property of the Company or any other Person, at the
option of the Company or the Holder or upon the occurrence of any condition or
event, the terms and conditions for such conversion or exchange;

(21) whether any of the Debt Securities will be subject to certain optional
interest rate reset provisions;

(22) the additions or changes, if any, to the Indenture with respect to the
Debt Securities as shall be necessary to permit or facilitate the issuance of
the Debt Securities in bearer form, registered or not registrable as to
principal, and with or without interest coupons; and

(23) any other terms of the Debt Securities.

Reference is also made to the prospectus supplement for information with respect
to any material United States federal income tax consequences with respect to
the ownership and disposition of Debt Securities.

No service charge will be made for any registration of transfer or exchange
of the Debt Securities, but the Company may require payment of a sum sufficient
to cover any tax or other governmental charge payable in connection therewith.

The Company conducts some of its operations through Subsidiaries. The
Holders of Debt Securities will have a junior position to any creditors of
Subsidiaries, unless such Subsidiaries are Subsidiary Guarantors of the Debt
Securities.

Debt Securities may be sold at a discount (which may be substantial) below
their stated principal amount bearing no interest or interest at a rate that at
the time of issuance is below market rates. Any material United States federal
income tax consequences and other special considerations applicable thereto will
be described in the prospectus supplement relating to any such Debt Securities.

If any of the Debt Securities are sold for any foreign currency or currency
unit or if the principal of, or premium or interest, if any, on, or any
Additional Amounts with respect to any of the Debt Securities is payable in any
foreign currency or foreign currency unit, the restrictions, elections, tax
consequences, specific terms and other information with respect to such Debt
Securities and such foreign currency or foreign currency unit will be set forth
in the prospectus supplement relating thereto.

6
<PAGE>
SUBSIDIARY GUARANTEES

If specified in the prospectus supplement, the Subsidiary Guarantors will
guarantee the Debt Securities of a series. Unless otherwise indicated in the
prospectus supplement, the following provisions will apply to the Subsidiary
Guarantees of the Subsidiary Guarantors.

Subject to the limitations described below and in the prospectus supplement,
the Subsidiary Guarantors will, jointly and severally, unconditionally guarantee
the performance and punctual payment when due, whether at Stated Maturity, by
acceleration or otherwise, of all the Company's obligations under the Indentures
and the Debt Securities of a series, whether for principal of, premium, if any,
or interest on the Debt Securities or otherwise (all such obligations guaranteed
by a Subsidiary Guarantor being herein called the "Guaranteed Obligations"). The
Subsidiary Guarantors will also pay, in addition to the amount stated above, any
and all expenses (including reasonable counsel fees and expenses) incurred by
the applicable Trustee in enforcing any rights under a Subsidiary Guarantee with
respect to a Subsidiary Guarantor.

In the case of Subordinated Debt Securities, the Subsidiary Guarantee will
be subordinated in right of payment to the Senior Indebtedness of the Subsidiary
Guarantor on the same basis as the Subordinated Debt Securities are subordinated
to the Company's Senior Indebtedness. No payment will be made by any Subsidiary
Guarantor under its Subsidiary Guarantee during any period in which payments by
the Company on the Subordinated Debt Securities are suspended by the
subordination provisions of the Subordinated Indenture.

Each Subsidiary Guarantee will be limited in amount to an amount not to
exceed the maximum amount that can be guaranteed by the relevant Subsidiary
Guarantor without rendering such Subsidiary Guarantee voidable under applicable
law relating to fraudulent conveyance or fraudulent transfer or similar laws
affecting the rights of creditors generally. Each Subsidiary Guarantee will be a
continuing guarantee and will:

(1) remain in full force and effect until either (a) payment in full of all
the Guaranteed Obligations (or the applicable Debt Securities are defeased and
discharged in accordance with the defeasance provisions of the Indentures) or
(b) released as described in the following paragraph,

(2) be binding upon each Subsidiary Guarantor, and

(3) inure to the benefit of and be enforceable by the applicable Trustee,
the Holders and their successors, transferees and assigns.

In the event that a Subsidiary Guarantor ceases to be a Restricted
Subsidiary, whether as a result of a disposition of all of the assets or all the
Capital Stock of such Subsidiary Guarantor, by way of sale, merger,
consolidation or otherwise, such Subsidiary Guarantor will be deemed released
and relieved of its obligations under its Subsidiary Guarantee without any
further action required on the part of the Trustee or any Holder and no other
Person acquiring or owning the assets or Capital Stock of such Subsidiary
Guarantor (if not otherwise a Restricted Subsidiary) will be required to enter
into a Subsidiary Guarantee; provided, in each case, that the transaction or
transactions resulting in such Subsidiary Guarantor's ceasing to be a Restricted
Subsidiary are carried out pursuant to and in compliance with all of the
applicable covenants in the Indenture. In addition, the prospectus supplement
may specify additional circumstances under which a Subsidiary Guarantor can be
released from its Subsidiary Guarantee.

EVENTS OF DEFAULT

Unless otherwise provided with respect to any series of Debt Securities, the
following are or will be Events of Default under each Indenture with respect to
the Debt Securities of such series issued under such Indenture:

(1) failure to pay principal of or premium, if any, on any Debt Security of
such series when due;

7
<PAGE>
(2) failure to pay any interest on or any Additional Amounts with respect to
any Debt Security of such series when due, continued for 30 days;

(3) failure to deposit any sinking fund payment, when due, in respect of the
Debt Securities of such series, continued for 30 days;

(4) failure to perform any other covenant of the Company in the applicable
Indenture (other than a covenant included in such Indenture for the benefit of a
series of Debt Securities other than such series), continued for 90 days after
written notice as provided in such Indenture;

(5) default under the terms of any instrument evidencing or securing any
Indebtedness of the Company or any Restricted Subsidiary having an outstanding
principal amount of $10 million individually or in the aggregate which default
results in the acceleration of the payment of all or any portion of such
Indebtedness (which acceleration is not rescinded within a period of 10 days
from the occurrence of such acceleration) or constitutes the failure to pay all
or any portion of the principal amount of such Indebtedness when due;

(6) the rendering of a final judgment or judgments (not subject to appeal)
against the Company or any Restricted Subsidiary in an amount in excess of
$10 million which remains undischarged or unstayed for a period of 60 days after
the date on which the right to appeal has expired;

(7) certain events of bankruptcy, insolvency or reorganization with respect
to the Company or any Significant Restricted Subsidiary or any group of
Restricted Subsidiaries that together would constitute a Significant Restricted
Subsidiary;

(8) in the case of Debt Securities guaranteed by any Subsidiary Guarantor,
the Subsidiary Guarantee of any Subsidiary Guarantor is held by a final
non-appealable order or judgment of a court of competent jurisdiction to be
unenforceable or invalid or ceases for any reason to be in full force and effect
(other than in accordance with the terms of the applicable Indenture) or any
Subsidiary Guarantor or any Person acting on behalf of any Subsidiary Guarantor
denies or disaffirms such Subsidiary Guarantor's obligations under its
Subsidiary Guarantee (other than by reason of a release of such Subsidiary
Guarantor from its Subsidiary Guarantee in accordance with the applicable
Indenture); and

(9) any other Event of Default as may be specified with respect to Debt
Securities of such series.

If an Event of Default with respect to any outstanding series of Debt
Securities occurs and is continuing, either the Trustee or the Holders of at
least 25% in principal amount of the outstanding Debt Securities of such series
(in the case of an Event of Default described in clause (1), (2), (3), (8) or
(9) above) or at least 25% in principal amount of all outstanding Debt
Securities under the applicable Indenture (in the case of an Event of Default
described in clause (4), (5) or (6) above) may declare the principal amount of
all the Debt Securities of the applicable series (or of all outstanding Debt
Securities under the applicable Indenture, as the case may be) to be due and
payable immediately. If an Event of Default described in clause (7) above
occurs, the principal amount of the outstanding Debt Securities of all series
ipso facto shall become immediately due and payable without any declaration or
other act on the part of the Trustee or any Holder. At any time after a
declaration of acceleration has been made, but before a judgment has been
obtained, the Holders of a majority in principal amount of the outstanding Debt
Securities of such series (or of all outstanding Debt Securities under the
applicable Indenture, as the case may be) may, under certain circumstances,
rescind and annul such acceleration. Depending on the terms of other
indebtedness of the Company outstanding from time to time, an Event of Default
under the Indentures may give rise to cross defaults on such other indebtedness
of the Company.

8
<PAGE>
Each Indenture provides that, within 90 days after the occurrence of a
default with respect to any series of Debt Securities, the Trustee will give to
the Holders of the Debt Securities of such series notice of all uncured and
unwaived defaults known to it; provided, however, that, except in the case of a
default in the payment of the principal of or premium, if any, or any interest
on, or any Additional Amounts with respect to, any Debt Securities of such
series, the Trustee will be protected in withholding such notice if it in good
faith determines that the withholding of such notice is in the interest of the
Holders of the Debt Securities of such series; and provided, further, that such
notice shall not be given until at least 30 days after the occurrence of a
default in the performance or breach of any covenant of the Company under such
Indenture other than for the payment of the principal of or premium, if any, or
any interest on, or any Additional Amounts with respect to, any Debt Securities
of such series. For the purpose of this provision, "default" with respect to
Debt Securities of any series means any event that is, or after notice or lapse
of time, or both, would become, an Event of Default with respect to the Debt
Securities of such series.

The Holders of a majority in principal amount of the outstanding Debt
Securities of any series (or, in certain cases, all outstanding Debt Securities
under the applicable Indenture) have the right to direct the time, method and
place of conducting any proceeding for any remedy available to the Trustee or
exercising any trust or power conferred on the Trustee with respect to the Debt
Securities of such series (or of all outstanding Debt Securities under the
applicable Indenture), subject to certain limitations specified in the
applicable Indenture. Each Indenture provides that in case an Event of Default
shall occur and be continuing, the Trustee shall exercise such of its rights and
powers under the applicable Indenture and use the same degree of care and skill
in its exercise as a prudent man would exercise or use under the circumstances
in the conduct of his own affairs. Subject to such provisions, the Trustee will
not be under an obligation to exercise any of its rights or powers under the
respective Indenture at the request of any of the Holders of the Debt Securities
unless they have offered to the Trustee reasonable security or indemnity against
the costs, expenses and liabilities that might be incurred by it in compliance
with such request.

The Holders of a majority in principal amount of the outstanding Debt
Securities of any series (or, in certain cases, all outstanding Debt Securities
under the applicable Indenture) may on behalf of the Holders of all Debt
Securities of such series (or of all outstanding Debt Securities under the
applicable Indenture) waive any past default under the applicable Indenture,
except (1) a default in the payment of the principal of or premium, if any, or
interest on or any Additional Amounts with respect to any Debt Security or
(2) in respect of a provision that under the applicable Indenture cannot be
modified or amended without the consent of the Holder of each outstanding Debt
Security affected. The Holders of a majority in principal amount of the
outstanding Debt Securities affected thereby may on behalf of the Holders of all
such Debt Securities waive compliance by the Company with certain restrictive
provisions of the Indentures.

The Company is required to furnish to the Trustee annually a statement as to
the performance by the Company of certain of its obligations under the
applicable Indenture and as to any default in such performance.

REMEDIES

The Indentures provide that no Holder of any Debt Security of any series
will have any right to institute any proceeding, judicial or otherwise, with
respect to the respective Indenture, or for the appointment of a receiver or
trustee, or for any other remedy thereunder, unless

(1) an Event of Default with respect to Debt Securities of that series has
occurred and continues and such Holder has previously given written notice to
the Trustee of the continuing Event of Default,

(2) the Holders of not less than 25% in principal amount of the outstanding
Debt Securities of that series have made written request to the Trustee to
institute proceedings in respect of such Event of Default in its own name as
Trustee,

9
<PAGE>
(3) such Holder or Holders have offered to the Trustee reasonable indemnity
against the costs, expenses and liabilities to be incurred in compliance with
such request,

(4) the Trustee for 60 days after its receipt of such notice, request and
offer of indemnity has failed to institute any such proceeding, and

(5) no direction inconsistent with such written request has been given to
the Trustee during such 60-day period by the Holders of a majority in principal
amount of the outstanding Debt Securities of that series.

MODIFICATION

Modifications and amendments of each Indenture may be made by the Company,
the Subsidiary Guarantors and the Trustee with the consent of the Holders of a
majority in principal amount of the outstanding Debt Securities under the
applicable Indenture affected thereby; provided, however, that no such
modification or amendment may, without the consent of the Holder of each
outstanding Debt Security affected thereby,

(1) change the stated maturity date of the principal of, or any installment
of principal of or interest on, or any Additional Amounts with respect to any
Debt Security,

(2) reduce the principal amount of, or the premium (if any) or interest on,
or any Additional Amounts with respect to any Debt Security,

(3) change the place or currency, currencies, or currency unit or units of
payment of principal of, or premium (if any) or interest on, or any Additional
Amounts with respect to any Debt Security,

(4) impair the right to institute suit for the enforcement of any payment on
or with respect to any Debt Security,

(5) reduce the percentage in principal amount of outstanding Debt
Securities, the consent of the Holders of which is required for modification or
amendment of the Indenture or for waiver of compliance with certain provisions
of the Indentures or for waiver of certain defaults,

(6) in the case of Subordinated Debt Securities, modify the subordination
provisions in a manner adverse to the Holders of the Subordinated Debt
Securities, or

(7) except as provided in the applicable Indenture, release the Subsidiary
Guarantee of a Subsidiary Guarantor.

Each Indenture provides that the Company and the Trustee may, without the
consent of any Holders of Debt Securities, enter into supplemental indentures
for the purposes, among other things, of adding to the Company's covenants,
adding additional Events of Default, establishing the form or terms of Debt
Securities or curing ambiguities or inconsistencies in the applicable Indenture,
provided that such action to cure ambiguities or inconsistencies shall not
adversely affect the interests of the Holders of the Debt Securities in any
material respect.

CONSOLIDATION, MERGER AND SALE OF ASSETS

Without the consent of any Holders of outstanding Debt Securities, the
Company may consolidate with or merge into, or convey, transfer or lease its
properties and assets substantially as an entirety to, any Person, provided
that:

(1) the Person formed by such consolidation or into which the Company is
merged or that acquires or leases the properties and assets of the Company
substantially as an entirety is a corporation, partnership or other Person
organized and existing under the laws of any domestic jurisdiction that assumes
by supplemental indenture the Company's obligations on the Debt Securities and
under each Indenture,

10
<PAGE>
(2) after giving effect to the transaction, no Event of Default and no event
that, after notice or lapse of time or both, would become an Event of Default
has occurred and is continuing, and

(3) certain other conditions are met, including any additional conditions
with respect to any particular Debt Securities specified in the applicable
prospectus supplement.

Upon compliance with these provisions by a successor Person, the Company
will (except in the case of a lease) be relieved of its obligations under each
Indenture and the Debt Securities.

DEFEASANCE AND COVENANT DEFEASANCE

If and to the extent indicated in the applicable prospectus supplement, the
Company may elect, at its option at any time, to have the provisions of Section
16.02 relating to defeasance and discharge of indebtedness, or Section 16.03
relating to defeasance of certain restrictive covenants, applied to the Debt
Securities of any series, or to any specified part of a series.

DEFEASANCE AND DISCHARGE. The Indentures provide that, upon the Company's
exercise of its option (if any) to have Section 16.02 applied to any Debt
Securities, the Company and, if applicable, each Subsidiary Guarantor will be
discharged from all of their obligations, and, if such Debt Securities are
Subordinated Debt Securities, the provisions of the Subordinated Indenture
relating to subordination will cease to be effective, with respect to such Debt
Securities (except for certain obligations to exchange or register the transfer
of Debt Securities, to replace stolen, lost or mutilated Debt Securities, to
maintain paying agencies and to hold moneys for payment in trust) upon the
deposit in trust for the benefit of the Holders of such Debt Securities of money
or U.S. Government Obligations, or both, which, through the payment of principal
and interest in respect thereof in accordance with their terms, will provide
money in an amount sufficient to pay the principal of and any premium and
interest on such Debt Securities or the respective Stated Maturities in
accordance with the terms of the applicable Indenture and such Debt Securities.
Such defeasance or discharge may occur only if, among other things,

(1) the Company has delivered to the applicable Trustee an Opinion of
Counsel to the effect that the Company has received from, or there has been
published by, the United State Internal Revenue Service a ruling, or there has
been a change in tax law, in either case to the effect that Holders of such Debt
Securities will not recognize gain or loss for federal income tax purposes as a
result of such deposit, defeasance and discharge and will be subject to federal
income tax on the same amount, in the same manner and at the same time as would
have been the case if such deposit, defeasance and discharge were not to occur;

(2) no Event of Default or event that with the passing of time or the giving
of notice, or both, shall constitute an Event of Default shall have occurred or
be continuing;

(3) such deposit, defeasance and discharge will not result in a breach or
violation of, or constitute a default under, any agreement or instrument to
which the Company or any Restricted Subsidiary is a party or by which the
Company or any Restricted Subsidiary is bound;

(4) in the case of Subordinated Debt Securities, at the time of such
deposit, no default in the payment of all or a portion of principal of (or
premium, if any) or interest on or other obligations in respect of any Senior
Indebtedness shall have occurred and be continuing and no other event of default
with respect to any Senior Indebtedness permitting, after notice or the lapse of
time, or both, the acceleration thereof shall have occurred and be continuing;
and

(5) the Company has delivered to the Trustee an Opinion of Counsel to the
effect that such deposit shall not cause the Trustee or the trust so created to
be subject to the Investment Company Act of 1940.

DEFEASANCE OF CERTAIN COVENANTS. The Indentures provide that, upon the
Company's exercise of its option (if any) to have Section 16.03 applied to any
Debt Securities, the Company may omit to comply

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with certain restrictive covenants, including those that may be described in the
applicable prospectus supplement, the occurrence of certain Events of Default,
which are described above in clause (4) (with respect to such restrictive
covenants ) and clauses (5) and (6) under "Events of Default" and any that may
be described in the applicable prospectus supplement will not be deemed to
either be or result in an Event of Default and, if such Debt Securities are
Subordinated Debt Securities, the provisions of the Subordinated Indenture
relating to subordination will cease to be effective, in each case with respect
to such Debt Securities. In order to exercise such option, the Company must
deposit, in trust for the benefit of the Holders of such Debt Securities, money
or U.S. Government Obligations, or both, which, through the payment of principal
and interest in respect thereof in accordance with their terms, will provide
money in an amount sufficient to pay the principal of and any premium and
interest on such Debt Securities on the respective Stated Maturities in
accordance with the terms of the applicable Indenture and such Debt Securities.
Such covenant defeasance may occur only if the Company has delivered to the
applicable Trustee an Opinion of Counsel that in effect says that Holders of
such Debt Securities will not recognize gain or loss for federal income tax
purposes as a result of such deposit and defeasance of certain obligations and
will be subject to federal income tax on the same amount, in the same manner and
at the same time as would have been the case if such deposit and defeasance were
not to occur and the requirements set forth in clauses (2), (3), (4) and (5)
above are satisfied. If the Company exercises this option with respect to any
Debt Securities and such Debt Securities were declared due and payable because
of the occurrence of any Event of Default, the amount of money and U.S.
Government Obligations so deposited in trust would be sufficient to pay amounts
due on such Debt Securities at the time of their respective Stated Maturities
but may not be sufficient to pay amounts due on such Debt Securities upon any
acceleration resulting from such Event of Default. In such case, the Company
would remain liable for such payments.

FORM, EXCHANGE, REGISTRATION AND TRANSFER

Debt Securities of any series will be exchangeable for other Debt Securities
of the same series and of a like aggregate principal amount and tenor of
different authorized denominations. Debt Securities may be presented for
registration of transfer (with the form of transfer endorsed thereon duly
executed), at the office of the Security Registrar or at the office of any
transfer agent designated by the Company for such purpose with respect to any
series of Debt Securities and referred to in an applicable prospectus
supplement, without service charge and upon payment of any taxes and other
governmental charges as described in the applicable Indenture. Such transfer or
exchange will be effected upon the Security Registrar or such transfer agent, as
the case may be, being satisfied with the documents of title and identity of the
Person making the request. The Company will appoint the Trustee under each
Indenture as Security Registrar for Debt Securities issued thereunder. If a
prospectus supplement refers to any transfer agents (in addition to the Security
Registrar) initially designated by the Company with respect to any series of
Debt Securities, the Company may at any time rescind the designation of any such
transfer agent or approve a change in the location through which any such
transfer agent acts. The Company is required to maintain an office or agency for
registration of transfer or exchange in each Place of Payment for such series.
The Company may at any time designate additional offices or agencies for
registration of transfer or exchange with respect to any series of Debt
Securities.

In the event of any redemption in part, the Company shall not be required to
(1) issue, register the transfer of or exchange Debt Securities of any series
during a period beginning at the opening of business 15 days prior to the
selection of Debt Securities of that series for redemption and ending on the
close of business on the day of mailing of the relevant notice of redemption or
(2) register the transfer of or exchange any Debt Security, or portion thereof,
called for redemption, except the unredeemed portion of any Debt Security being
redeemed in part.

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PAYMENT AND PAYING AGENTS

Unless otherwise indicated in an applicable prospectus supplement, payment
of principal of, premium, if any, and interest on and any Additional Amounts
with respect to Debt Securities will be made in the designated currency or
currency unit at the office of such Paying Agent or Paying Agents as the Company
may designate from time to time, except that, at the option of the Company,
payment of any interest may be made by check mailed to the address of the Person
entitled thereto as such address appears in the Security Register. Unless
otherwise indicated in an applicable prospectus supplement, payment of any
installment of interest on Debt Securities will be made to the Person in whose
name such Debt Security is registered at the close of business on the Regular
Record Date for such interest.

Unless otherwise indicated in an applicable prospectus supplement, the
Corporate Trust Office of the Trustee in New York, New York will be designated
as a Paying Agent for the Company for payments with respect to Debt Securities
issued under the applicable Indenture. The Company may at any time designate
additional Paying Agents or rescind the designation of any Paying Agent or
approve a change in the office through which any Paying Agent acts, except that
the Company will be required to maintain a Paying Agent in each Place of Payment
for such series.

All moneys paid by the Company to a Paying Agent for the payment of
principal of, premium, if any, or interest on and any Additional Amounts with
respect to any Debt Security that remain unclaimed at the end of three years
after such principal, premium, interest or Additional Amounts have become due
and payable will (subject to applicable escheat laws) be repaid to the Company,
and the Holder of such Debt Security or any coupon will thereafter look only to
the Company for payment thereof.

SECURITIES IN GLOBAL FORM

The Debt Securities of a series may be issued, in whole or in part, in the
form of one or more global Debt Securities that would be deposited with a
depositary or its nominee identified in the applicable prospectus supplement.
Global Debt Securities may be issued in either temporary or permanent form. The
specific terms of any depositary arrangement with respect to any portion of a
series of Debt Securities and the rights of, and limitations on, owners of
beneficial interests in any such global Debt Security representing all or a
portion of a series of Debt Securities will be described in the applicable
prospectus supplement.

MEETINGS

Each Indenture contains provisions for convening meetings of the Holders of
Debt Securities of a series. A meeting may be called at any time by the Trustee,
and also, upon request, by the Company or the Holders of at least 10% in
principal amount of the Outstanding Debt Securities of such series, in any such
case upon notice given as described under "-- Notices" below. Except for any
consent that must be given by the Holder of each Outstanding Debt Security
affected thereby, as described under "-- Modification" above, any resolution
presented at a meeting or adjourned meeting at which a quorum is present may be
adopted by the affirmative vote of the Holders of a majority in principal amount
of the Outstanding Debt Securities of that series; provided, however, that,
except for any consent that must be given by the Holder of each Outstanding Debt
Security affected thereby, as described under "-- Modification" above, any
resolution with respect to any request, demand, authorization, direction,
notice, consent, waiver or other action that may be made, given or taken by the
Holders of a specified percentage, which is less than a majority in principal
amount of the Outstanding Debt Securities of a series, may be adopted at a
meeting or adjourned meeting duly reconvened at which a quorum is present by the
affirmative vote of the Holders of such specified percentage in principal amount
of the Outstanding Debt Securities of that series. Subject to the proviso set
forth above, any resolution passed or decision taken at any meeting of Holders
of Debt Securities

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of any series duly held in accordance with the applicable Indenture will be
binding on all Holders of Debt Securities of that series and any related
coupons. The quorum at any meeting called to adopt a resolution, and at any
reconvened meeting, will be Persons holding or representing a majority in
principal amount of the Outstanding Debt Securities of a series.

GOVERNING LAW

Each Indenture and the Debt Securities will be governed by and construed in
accordance with the laws of the State of New York.

NOTICES

Notices to Holders of Debt Securities will be given by mail to the addresses
of such Holders as they appear in the Security Register.

TRUSTEE

Each Indenture contains certain limitations on the right of the Trustee, as
a creditor of the Company, to obtain payment of claims in certain cases and to
realize on certain property received with respect to any such claims, as
security or otherwise. The Trustee is or will be permitted to engage in other
transactions, except that, if it acquires any conflicting interest (as defined),
it must eliminate such conflict or resign.

The Trustee may make loans to the Company and its subsidiaries and
affiliates from time to time in the ordinary course of business and at
prevailing interest rates under agreements with commercial bank groups. In
addition, the Trustee may from time to time serve as a depositary of funds of,
and perform other services for, the Company.

PROVISIONS APPLICABLE SOLELY TO SUBORDINATED DEBT SECURITIES

The indebtedness evidenced by the Subordinated Debt Securities will, to the
extent set forth in the Subordinated Indenture with respect to each series of
Subordinated Debt Securities, be subordinate in right of payment to the prior
payment in full of the Company's Senior Indebtedness, including the Senior Debt
Securities. The prospectus supplement relating to any Subordinated Debt
Securities will summarize the subordination provisions of the Subordinated
Indenture applicable to that series including:

(1) the applicability and effect of such provisions upon any payment or
distribution of the Company's assets to creditors upon any liquidation,
dissolution, winding-up, reorganization, assignment for the benefit of creditors
or marshaling of assets or any bankruptcy, insolvency and similar proceedings;

(2) the applicability and effect of such provisions in the event of
specified defaults with respect to any or certain Senior Indebtedness, including
the circumstances under which and the periods in which the Company will be
prohibited from making payments on the Subordinated Debt Securities; and

(3) the definition of Senior Indebtedness applicable to the Subordinated
Debt Securities of that series.

The prospectus supplement will also describe as of a recent date the
approximate amount of Senior Indebtedness to which the Subordinated Debt
Securities of that series will be subordinated.

The failure to make any payment of any of the Subordinated Debt Securities
by reason of the subordination provisions of the Subordinated Indenture
described in the prospectus supplement will not be construed as preventing the
occurrence of an Event of Default with respect to the Subordinated Debt
Securities arising from any such failure to make payment.

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The subordination provisions described above will not be applicable to
payments in respect of the Subordinated Debt Securities from a defeasance trust
established in connection with any defeasance or covenant defeasance of the
Subordinated Debt Securities as described under "-- Defeasance and Covenant
Defeasance."

DESCRIPTION OF PREFERRED STOCK

Our board of directors is authorized to issue up to 25,000,000 shares of
preferred stock in one or more series and has the authority to fix the voting,
conversion, dividend, redemption, liquidation and other rights, preferences,
privileges and qualifications of the preferred stock, all without any further
vote or action by the stockholders. The issuance of preferred stock could
decrease the amount of earnings and assets available for distribution to holders
of common stock, and adversely affect the rights and powers, including voting
rights, of such holders. The particular terms of any series of preferred stock
will be described in the applicable prospectus supplement. No shares of
preferred stock are currently outstanding. When issued, the shares of preferred
stock will be fully paid and nonassessable.

Although we have no present intention to issue shares of preferred stock,
the issuance of shares of the preferred stock, or the issuance of rights to
purchase such shares, could be used to discourage an unsolicited acquisition
proposal. For instance, the issuance of a series of preferred stock might impede
a business combination by including class voting rights that would enable the
holders to block such a transaction; or such issuance might facilitate a
business combination by including voting rights that would provide a required
percentage vote of the stockholders. In addition, under certain circumstances,
the issuance of preferred stock could adversely affect the voting power of the
holders of the common stock. Although the board of directors is required to make
any determination to issue such stock based on its judgment as to the best
interests of our stockholders, the board could act in a manner that would
discourage an acquisition attempt or other transaction that some or even a
majority of the stockholders might believe to be in their best interests or in
which stockholders might receive a premium for their stock over the then market
price of such stock. The board of directors does not at present intend to seek
stockholder approval prior to any issuance of currently authorized stock, unless
otherwise required by law or the rules of any market on which our securities are
traded.

DESCRIPTION OF DEPOSITARY SHARES

The description set forth below and in any prospectus supplement of certain
provisions of the deposit agreement and of the depositary shares and depositary
receipts does not purport to be complete and is subject to and qualified in its
entirety by reference to the forms of deposit agreement and depositary receipts
relating to each series of preferred stock which have been or will be filed with
the SEC in connection with the offering of such series of preferred stock.

GENERAL

At our option, we may elect to offer fractional interests in shares of
preferred stock, rather than shares of preferred stock. If we exercise this
option, we will provide for the issuance by a depositary to the public of
receipts for depositary shares. Each depositary share will represent fractional
interests of a particular series of preferred stock (which will be set forth in
the prospectus supplement relating to a particular series of preferred stock).

The shares of any series of preferred stock underlying the depositary shares
will be deposited under a separate deposit agreement between us and a bank or
trust company selected by us having its principal office in the United States
and having a combined capital and surplus of at least $50,000,000. The
prospectus supplement relating to a series of depositary shares will set forth
the name and address of the depositary. Subject to the terms of the deposit
agreement, each owner of depositary shares will be entitled, in proportion to
the applicable fractional interests in shares of preferred stock underlying such
depositary shares, to all the rights and preferences of the preferred stock
underlying such depositary shares including dividend, voting, redemption,
conversion and liquidation rights.

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The depositary shares will be evidenced by depositary receipts issued
pursuant to the deposit agreement. Depositary receipts will be distributed to
those persons purchasing the fractional interests in shares of the related
series of preferred stock in accordance with the terms of the offering described
in the related prospectus supplement.

DIVIDENDS AND OTHER DISTRIBUTIONS

The depositary will distribute all cash dividends or other cash
distributions received in respect of preferred stock to the record holders of
depositary shares relating to such preferred stock in proportion to the numbers
of such depositary shares owned by such holders on the relevant record date. The
depositary shall distribute only such amount, however, as can be distributed
without attributing to any holder of depositary shares a fraction of one cent,
and any balance not so distributed shall be added to and treated as part of the
next sum received by the depositary for distribution to record holders of
depositary shares.

In the event of a distribution other than in cash, the depositary will
distribute property received by it to the record holders of depositary shares
entitled thereto, unless the depositary determines that it is not feasible to
make such distribution. If this happens, the depositary may, with our approval,
sell the property and distribute the net sale proceeds to the holders.

The deposit agreement will also contain provisions relating to the manner in
which any subscription or similar rights offered by us to holders of the
preferred stock shall be made available to the holders of depositary shares.

REDEMPTION OF DEPOSITARY SHARES

If a series of the preferred stock underlying the depositary shares is
subject to redemption, the depositary shares will be redeemed from the proceeds
received by the depositary resulting from the redemption, in whole or in part,
of such series of the preferred stock held by the depositary. The depositary
shall mail notice of redemption not less than 30 and not more than 60 days prior
to the date fixed for redemption to the record holders of the depositary shares
to be so redeemed at their respective addresses appearing in the depositary's
books. The redemption price per depositary share will be equal to the applicable
fraction of the redemption price per share payable with respect to such series
of the preferred stock. Whenever we redeem shares of preferred stock held by the
depositary, the depositary will redeem as of the same redemption date the number
of depositary shares relating to shares of preferred stock so redeemed. If less
than all of the depositary shares are to be redeemed, the depositary shares to
be redeemed will be selected by lot or pro rata as may be determined by the
depositary.

After the date fixed for redemption, the depositary shares called for
redemption will no longer be deemed to be outstanding and all rights of the
holders of the depositary shares will cease, except the right to receive the
moneys, securities or other property payable upon such redemption and any money,
securities or other property to which the holders of such depositary shares were
entitled upon such redemption upon surrender to the depositary of the depositary
receipts evidencing such depositary shares.

VOTING THE PREFERRED STOCK

Upon receipt of notice of any meeting at which the holders of the preferred
stock are entitled to vote, the depositary will mail the information contained
in such notice of meeting to the record holders of the depositary shares
relating to such preferred stock. Each record holder of depositary shares on the
record date, which will be the same date as the record date for the preferred
stock, will be entitled to instruct the depositary as to the exercise of the
voting rights pertaining to the number of shares of preferred stock underlying
such holder's depositary shares. The depositary will endeavor, insofar as
practicable, to vote the number of shares of preferred stock underlying such
depositary shares in

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accordance with such instructions, and we will agree to take all action which
may be deemed necessary by the depositary in order to enable the depositary to
do so.

AMENDMENT AND TERMINATION OF DEPOSITARY AGREEMENT

We may enter into an agreement with the depositary at any time to amend the
form of depositary receipt evidencing the depositary shares and any provision of
the deposit agreement. However, the holders of a majority of the depositary
shares must approve any amendment which materially and adversely alters the
rights of the existing holders of depositary shares. A deposit agreement may be
terminated by us or by the depositary only if (1) all outstanding depositary
shares relating thereto have been redeemed or (2) there has been a final
distribution in respect of the preferred stock of the relevant series in
connection with any liquidation, dissolution or winding up and such distribution
has been distributed to the holders of the related depositary shares.

CHARGES OF DEPOSITARY

We will pay all transfer and other taxes and governmental charges arising
solely from the existence of the depositary arrangements. We will also pay
charges of the depositary in connection with the initial deposit of the
preferred stock and any redemption of the preferred stock. Holders of depositary
shares will pay transfer and other taxes and governmental charges and such other
charges as are expressly provided in the deposit agreement to be for their
accounts.

RESIGNATION AND REMOVAL OF DEPOSITARY

The depositary may resign at any time by delivering to us notice of its
election to do so, and we may at any time remove the depositary, any such
resignation or removal to take effect upon the appointment of a successor
depositary and its acceptance of such appointment. Such successor depositary
must be appointed within 60 days after delivery of the notice of resignation or
removal and must be a bank or trust company having its principal office in the
United States and having a combined capital and surplus of at least $50,000,000.

MISCELLANEOUS

The depositary will forward to the holders of depositary shares all reports
and communications from us which are delivered to the depositary and which we
are required to furnish to the holders of the preferred stock.

Neither the depositary nor Evergreen will be liable if it is prevented or
delayed by law or any circumstance beyond its control in performing its
obligations under the deposit agreement. The obligations of Evergreen and the
depositary under the deposit agreement will be limited to performance in good
faith of their duties thereunder and they will not be obligated to prosecute or
defend any legal proceeding in respect of any depositary shares or preferred
stock unless satisfactory indemnity is furnished. They may rely upon written
advice of counsel or accountants, or information provided by persons presenting
preferred stock for deposit, holders of depositary shares or other persons
believed to be competent and on documents believed to be genuine.

DESCRIPTION OF COMMON STOCK

GENERAL

We are authorized to issue 50,000,000 shares of common stock, no par value.
As of May 7, 1999, 11,252,009 shares of common stock were outstanding.

Holders of shares of common stock are entitled to one vote for each share
held of record on all matters submitted to a vote of stockholders. There are no
cumulative voting rights with respect to the election of directors. Accordingly,
the holder or holders of a majority of the outstanding shares of common stock
will be able to elect our entire board of directors. Holders of common stock
have no

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preemptive rights and are entitled to such dividends as may be declared by the
board of directors out of legally available funds. The common stock is not
entitled to any sinking fund, redemption or conversion provisions. If Evergreen
liquidates, dissolves or winds up its business, the holders of common stock will
be entitled to share ratably in our net assets remaining after the payment of
all creditors, if any, and the liquidation preferences of any preferred
stockholders. When issued, the shares of common stock will be fully paid and
nonassessable. The common stock is quoted on the Nasdaq National Market. The
transfer agent and registrar for the common stock is American Securities
Transfer & Trust, Inc.

ANTI-TAKEOVER MATTERS

Our articles of incorporation and bylaws contain provisions that may have
the effect of delaying, deferring or preventing a change in control of
Evergreen. These provisions, among other things, provide for a board of
directors with staggered terms and noncumulative voting in the election of
directors and impose certain procedural requirements on shareholders who wish to
make nominations for the election of directors or propose other actions at
shareholders' meetings.

In addition, our articles of incorporation authorize the board to issue up
to 25,000,000 shares of preferred stock without shareholder approval and to set
the rights, preferences and other designations, including voting rights, of
those shares as the board of directors may determine. These provisions, alone or
in combination with each other and with the shareholder rights plan described
below, may discourage transactions involving actual or potential changes of
control of Evergreen, including transactions that otherwise could involve
payment of a premium over prevailing market prices to holders of common stock.

On July 7, 1997, the board of directors adopted a shareholder rights plan
pursuant to which stock purchase rights were distributed as a dividend to our
common shareholders at a rate of one right for each share of common stock held
of record as of July 22, 1997 and for each share of stock issued thereafter.

The rights plan is designed to enhance the board's ability to prevent an
acquiror from depriving shareholders of the long-term value of their investment
and to protect shareholders against attempts to acquire Evergreen by means of
unfair or abusive takeover tactics that have been prevalent in many unsolicited
takeover attempts.

Under the rights plan, the rights will become exercisable only if a person
or a group (except for existing 20% shareholders) acquires or commences a tender
offer for 20% or more of our common stock. Until they become exercisable, the
rights attach to and trade with the common stock. The rights will expire
July 22, 2007. The rights may be redeemed by the continuing members of the board
at $.001 per right prior to the day after a person or group has accumulated 20%
or more of the common stock.

If a person or group acquired 20% of our common stock, the rights would then
be modified to represent the right to receive, for the exercise price, common
stock having a value worth twice the exercise price.

If Evergreen were involved in a merger or other business combination at any
time after a person or group has acquired 20% or more of our common stock, the
rights would be modified so as to entitle a holder to buy a number of shares of
common stock of the acquiring entity having a market value of twice the exercise
price of each right.

All rights held or acquired by a person or group holding 20% or more of our
shares are void. The rights are not triggered by continued stock ownership of
our existing 20% shareholders, unless these shareholders increase their holdings
in Evergreen above 30%.

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DESCRIPTION OF WARRANTS

We may issue warrants including warrants to purchase debt securities,
warrants to purchase common stock or preferred stock, and warrants to purchase
equity securities issued by an unaffiliated corporation or other entity and held
by us. Warrants may be issued independently of or together with any other
Securities and may be attached to or separate from such Securities. Each series
of warrants will be issued under a separate warrant agreement to be entered into
between us and a warrant agent. The warrant agent will act solely as our agent
in connection with the warrant of such series and will not assume any obligation
or relationship of agency for or with holders or beneficial owners of warrants.
The following sets forth certain general terms and provisions of the warrants
offered hereby. Further terms of the warrants and the applicable warrant
agreement will be set forth in the applicable prospectus supplement.

DEBT WARRANTS

The applicable prospectus supplement will describe the terms of any debt
warrants, including the following:

(1) the title of such debt warrants;

(2) the offering price for such debt warrants, if any;

(3) the aggregate number of such debt warrants;

(4) the designation and terms of such debt securities purchasable upon
exercise of such debt warrants;

(5) if applicable, the designation and terms of the Securities with which
such debt warrants are issued and the number of such debt warrants issued with
each such Security;

(6) if applicable, the date from and after which such debt warrants and any
Securities issued therewith will be separately transferable;

(7) the principal amount of debt securities purchasable upon exercise of a
debt warrant and the price at which such principal amount of debt securities may
be purchased upon exercise;

(8) the date on which the right to exercise such debt warrants shall
commence and the date on which such right shall expire;

(9) if applicable, the minimum or maximum amount of such debt warrants which
may be exercised at any one time;

(10) whether the debt warrants represented by the debt warrant certificates
or debt securities that may be issued upon exercise of the debt warrants will be
issued in registered or bearer form;

(11) information with respect to book-entry procedures, if any;

(12) the currency, currencies or currency units in which the offering price,
if any, and the exercise price are payable;

(13) if applicable, a discussion of certain United States federal income tax
considerations;

(14) the antidilution provisions of such debt warrants, if any;

(15) the redemption or call provisions, if any, applicable to such debt
warrants; and

(16) any additional terms of the debt warrants, including terms, procedures
and limitations relating to the exchange and exercise of such debt warrants.

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STOCK AND OTHER WARRANTS

The applicable prospectus supplement will describe the terms of any stock
warrants or other warrants to purchase equity securities issued by an
unaffiliated corporation or other entity and held by us, including the
following:

(1) the title of such stock warrants or other warrants;

(2) the offering price of such stock warrants or other warrants, if any;

(3) the aggregate number of such stock warrants or other warrants;

(4) the designation and terms of the common stock, preferred stock or equity
securities issued by an unaffiliated corporation or other entity and held by us
purchasable upon exercise of such stock warrants or other warrants;

(5) if applicable, the designation and terms of the Securities with which
such stock warrants or other warrants are issued and the number of such stock
warrants or other warrants issued with each such Security;

(6) if applicable, the date from and after which such stock warrants or
other warrants and any Securities issued therewith will be separately
transferrable;

(7) the number of shares of common stock, preferred stock or equity
securities issued by an unaffiliated corporation or other entity and held by us
purchasable upon exercise of a stock warrant or other warrant and the price at
which such shares may be purchased upon exercise;

(8) the date on which the right to exercise such stock warrants or other
warrants shall commence and the date on which such right shall expire;

(9) if applicable, the minimum or maximum amount of such stock warrants or
other warrants which may be exercised at any one time;

(10) the currency, currencies or currency units in which the offering price,
if, any, and the exercise price are payable;

(11) if applicable, a discussion of certain United States federal income tax
considerations;

(12) the antidilution provisions of such stock warrants or other warrants, if
any;

(13) the redemption or call provisions, if any, applicable to such stock
warrants or other warrants; and

(14) any additional terms of such stock warrants or other warrants, including
terms, procedures and limitations relating to the exchange and exercise of such
stock warrants or other warrants.

DESCRIPTION OF SUBSCRIPTION RIGHTS

GENERAL

We may issue subscription rights to purchase our debt securities, common
stock, preferred stock, depositary shares or warrants to purchase debt
securities, preferred stock or common stock. We may issue subscription rights
independently or together with any other offered security. The subscription
rights may or may not be transferable by the purchaser receiving the
subscription rights. In connection with any subscription rights offering to our
shareholders, we may enter into a standby underwriting arrangement with one or
more underwriters pursuant to which the underwriter(s) will purchase any offered
securities remaining unsubscribed for after the subscription rights offering.
Certificates evidencing such subscription rights and a prospectus supplement
will be distributed to our shareholders on the record date for receiving
subscription rights in the subscription rights offering.

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The applicable prospectus supplement will describe the following terms of
the subscription rights:

(1) the title of the subscription rights;

(2) the securities for which the subscription rights are exercisable;

(3) the exercise price for the subscription rights;

(4) the number of subscription rights issued to each shareholder;

(5) the extent to which the subscription rights are transferable;

(6) if applicable, a discussion of the material United States income tax
considerations applicable to the issuance or exercise of the subscription
rights;

(7) any other terms of the subscription rights, including terms, procedures
and limitations relating to the exchange and exercise of the subscription
rights;

(8) the date on which the right to exercise the subscription rights shall
commence and the date on which the right shall expire;

(9) the extent to which the subscription rights include an over-subscription
privilege with respect to unsubscribed securities; and

(10) if applicable, the material terms of any standby underwriting
arrangement between us and our stand-by underwriters.

EXERCISE OF SUBSCRIPTION RIGHTS

Each subscription right will entitle the holder to purchase for cash the
principal amount of debt securities, shares of preferred stock, depositary
shares, shares of shares of common stock, warrants, or any combination thereof,
at the exercise price as shall in each case be set forth in, or be determinable
as set forth in, the prospectus supplement relating to the subscription rights
offered thereby. Subscription rights may be exercised at any time up to the
close of business on the expiration date for such subscription rights set forth
in the prospectus supplement. After the close of business on the expiration
date, all unexercised subscription rights will become void.

Subscription rights may be exercised as set forth in the prospectus
supplement relating to the subscription rights offered thereby. Upon receipt of
payment and the subscription rights certificate properly completed and duly
executed at the corporate trust office of the subscription rights agent or any
other office indicated in the prospectus supplement, the Company will, as soon a
practicable, forward the debt securities, shares of preferred stock or common
stock, depositary shares or warrants purchasable upon such exercise. In the
event that not all of the subscription rights issued in any offering are
exercised, the Company may determine to offer any unsubscribed offered
securities directly to persons other than shareholders, to or through agents,
underwriters or dealers or through a combination of such methods, including
pursuant to standby underwriting arrangements, as set forth in the applicable
prospectus supplement.

PLAN OF DISTRIBUTION

We may offer and sell the Securities (i) through underwriters or dealers,
(ii) through agents, (iii) directly to purchasers, including existing
shareholders in an offering of subscription rights, or (iv) through a
combination of any such methods of sale. Any such underwriter, dealer or agent
may be deemed to be an underwriter within the meaning of the Securities Act.

Each prospectus supplement will set forth the terms of the offering of the
particular series of Securities to which the prospectus supplement relates,
including the name or names of any underwriters, dealers or agents, the purchase
price or prices of the Securities, the proceeds to Evergreen from the sale of
such series of Securities, the use of such proceeds, any initial public offering

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price or purchase price of such series of Securities, any underwriting discount
or commission, any discounts, concessions or commissions allowed or reallowed or
paid by any underwriters to other dealers, any commissions paid to any agents
and the securities exchanges, if any, on which such Securities will be listed.
Any initial public offering price or purchase price and any discounts,
concessions or commissions allowed or reallowed or paid by any underwriter to
other dealers may be changed from time to time.

Sales of common stock offered pursuant to any prospectus supplement may be
effected from time to time in one or more transactions through Nasdaq, or in
negotiated transactions or any combination of such methods of sale, at market
prices prevailing at the time of sale, at prices related to such prevailing
market prices, or at other negotiated prices.

Any underwriter may engage in stabilizing and syndicate covering
transactions in accordance with Rule 104 of Regulation M under the Securities
Exchange Act. Rule 104 permits stabilizing bids to purchase the underlying
security so long as the stabilizing bids do not exceed a specified maximum. The
underwriters may over-allot shares of the common stock in connection an offering
of common stock, thereby creating a short position in the underwriters' account.
Syndicate covering transactions involve purchases of the debt securities in the
open market after the distribution has been completed in order to cover
syndicate short positions. Stabilizing and syndicate covering transactions may
cause the price of the debt securities to be higher than it would otherwise be
in the absence of such transactions. These transactions, if commenced, may be
discontinued at any time.

In connection with the sale of Securities, underwriters or agents may
receive compensation from Evergreen, or from purchasers of Securities for whom
they may act as agents in the form of discounts, concessions or commissions.
Underwriters may sell Securities to or through dealers, and such dealers may
receive compensation in the form of discounts, concessions or commissions from
the underwriters and/or commissions from the purchasers for whom they may act as
agents. Underwriters, dealers and agents that participate in the distribution of
Securities may be deemed to be underwriters, and any discounts or commissions
received by them from us and any profit on the resale of Securities by them may
be deemed to be underwriting discounts and commissions under the Securities Act.
Any such underwriter or agent will be identified, and any such compensation
received from Evergreen will be described, in the applicable prospectus
supplement.

Securities may be sold directly by Evergreen or through agents designated by
us from time to time. Any agent involved in the offer or sale of the Securities
in respect of which this prospectus is delivered will be named, and any
commissions payable by us to such agent will be set forth, in the prospectus
supplement. Unless otherwise indicated in the prospectus supplement, any such
agent will be acting on a best efforts basis for the period of its appointment.

Under agreements which we may enter into, underwriters and agents who
participate in the distribution of Securities may be entitled to indemnification
by us against certain liabilities, including liabilities under the Securities
Act. The terms and conditions of such indemnification will be described in an
applicable prospectus supplement. Underwriters, dealers and agents may be
customers of, engage in transactions with, or perform services for, Evergreen in
the ordinary course of business.

If so indicated in the applicable prospectus supplement, we will authorize
underwriters or other persons acting as our agent to solicit offers by certain
institutions to purchase debt securities, preferred stock or common stock from
us pursuant to contracts providing for payment and delivery on a future date.
Institutions with which such contracts may be made include commercial and
savings banks, insurance companies, pension funds, investment companies,
educational and charitable institutions and others, but in all cases we must
approve such institutions. The obligations of any purchaser under any such
contract will be subject to the condition that the purchase of the Debt
Securities, preferred stock, depositary shares or common stock shall not at the
time of delivery be prohibited under the laws of the jurisdiction to which such
purchaser is subject. The underwriters and such other agents will not have any
responsibility in respect of the validity or performance of such contracts.

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<PAGE>
We also may sell Securities directly to purchasers, in which event no
underwriters or agents would be involved. We may sell Securities upon the
exercise of subscription rights issued to our securityholders.

The place and date of delivery for the Securities in respect of which this
prospectus is being delivered will be set forth in the applicable prospectus
supplement.

Unless otherwise indicated in the applicable prospectus supplement, the
Securities in respect of which this prospectus is being delivered (other than
common stock) will be a new issue of securities, will not have an established
trading market when issued and will not be listed on any securities exchange.
Any underwriters or agents to or through whom such Securities are sold by us for
public offering and sale may make a market in such Securities, but such
underwriters or agents will not be obligated to do so and may discontinue any
market making at any time without notice. No assurance can be given as to the
liquidity of the trading market for any such Securities.

Certain of the underwriters and their affiliates may from time to time
perform various commercial banking and investment banking services for us, for
which customary compensation is received.

EXPERTS

The financial statements incorporated by reference in this prospectus have
been audited by BDO Seidman, LLP, independent certified public accountants, to
the extent and for the periods set forth in their report incorporated herein by
reference, and are incorporated herein in reliance upon such report given upon
the authority of said firm as experts in auditing and accounting.

The estimated reserve evaluations and related calculations of Resource
Services International, Inc., independent petroleum engineering consultants,
incorporated by reference in this prospectus have been included herein in
reliance upon the authority of said firm as experts in petroleum engineering.

The estimated reserve evaluations and related calculations of Netherland,
Sewell & Associates, Inc., independent petroleum engineering consultants,
incorporated by reference in this prospectus have been included herein in
reliance upon the authority of said firm as experts in petroleum engineering.

LEGAL MATTERS

John B. Wills, Esq., Denver, Colorado has provided us with a legal opinion
on the validity of the Securities offered by this prospectus. The validity of
the Securities offered hereby will be passed upon for any agents, dealers or
underwriters by counsel named in the applicable prospectus supplement.

WHERE YOU CAN FIND MORE INFORMATION

We file reports, proxy statements and other information with the Securities
and Exchange Commission. You may read and copy any document we have filed at the
SEC's public reference rooms located at 450 Fifth Street, N.W., Judiciary Plaza,
Room 1024, Washington, D.C. 20549, and at regional offices of the SEC at the
Northwestern Atrium Center, 500 West Madison Street, Suite 1400, Chicago,
Illinois 60661-2511 and at 7 World Trade Center, New York, New York 10048. For
further information on the SEC's public reference rooms, please call
1-800-SEC-0330. Our filings are also available to the public from the SEC's
Internet web site at http://www.sec.gov. Information about us also may be
inspected at the offices of the National Association of Securities
Dealers, Inc., 1735 K Street, N.W., Washington, D.C. 20006.

This prospectus is part of a registration statement that we filed with the
SEC utilizing a "shelf" registration process. Under this shelf registration
process, we may sell any combination of the Securities described in this
prospectus in one or more offerings up to a total dollar amount of $150 million.
This prospectus provides you with a general description of the Securities we may
offer. Each time we sell

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<PAGE>
Securities, we will provide a prospectus supplement that will contain specific
information about the terms of the offering and the Securities. The prospectus
supplement may also add, update or change information contained in this
prospectus. Any statement that we make in this prospectus will be modified or
superseded by any inconsistent statement made by us in a prospectus supplement.
You should read both this prospectus and any prospectus supplement together with
additional information described under the heading "Incorporation of Certain
Documents by Reference."

INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE

The SEC allows us to "incorporate by reference" the information we file with
the SEC, which means that we can disclose important information to you by
referring you to those documents that are considered part of this prospectus.
Information filed with the SEC after the date of this prospectus will
automatically update and supersede this information. The following documents
filed with the SEC are incorporated by reference:

(1) Annual report on Form 10-K for the year ended December 31, 1998;

(2) Quarterly report on Form 10-Q for the quarter ended March 31, 1999;

(3) The description of the common stock that is contained in our
registration statement on Form 8-A filed with the SEC on or about
December 21, 1981, including any amendment or report filed for the
purpose of updating the description; and

(4) The description of our Shareholders Rights Agreement that is contained
in our registration statement on Form 8-A filed with the SEC on
December 18, 1998.

Any future filings we make with the SEC under Section 13(a), 13(c), 14 or
15(d) of the Securities Exchange Act are incorporated by reference in this
prospectus until we complete the offering of the Securities.

We will provide each person to whom a copy of this prospectus has been
delivered, without charge, a copy of any of the documents referred to above as
being incorporated by reference. You may request a copy by writing or
telephoning Kevin R. Collins, 1401 17th Street, Suite 1200, Denver, Colorado
80202 (telephone 303-298-8100).

You should rely only on the information incorporated by reference or
provided in this prospectus or any prospectus supplement. We have not authorized
anyone else to provide you with different information. We are not making an
offer of these Securities in any state where the offer is not permitted. You
should not assume that the information in this prospectus or any prospectus
supplement is accurate as of any date other than the date on the front of those
documents.

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WE HAVE NOT AUTHORIZED ANYONE TO PROVIDE INFORMATION DIFFERENT FROM THAT
CONTAINED IN THIS PROSPECTUS SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS. NEITHER
THE DELIVERY OF THIS PROSPECTUS SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS NOR
SALE OF THE COMMON STOCK MEANS THAT INFORMATION CONTAINED IN THIS PROSPECTUS
SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS IS CORRECT AFTER THE DATES OF THIS
PROSPECTUS SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS. THIS PROSPECTUS
SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS ARE NOT AN OFFER TO SELL OR A
SOLICITATION OF AN OFFER TO BUY THESE SHARES OF COMMON STOCK IN ANY
CIRCUMSTANCES UNDER WHICH THE OFFER OR SOLICITATION IS UNLAWFUL.

------------------------

TABLE OF CONTENTS

<TABLE>
<S> <C>
PROSPECTUS SUPPLEMENT PAGE
Summary......................................... S-1
Risk Factors.................................... S-8
Forward-Looking Statements...................... S-15
Price Range of Common Stock and Dividend
Policy........................................ S-16
Use of Proceeds................................. S-17
Capitalization.................................. S-17
Selected Consolidated Financial Data............ S-18
Management's Discussion and Analysis of
Financial Condition and Results of
Operations.................................... S-20
Business and Properties......................... S-28
Management...................................... S-44
Underwriting.................................... S-46
Legal Matters................................... S-48
Experts......................................... S-48
Glossary of Common Oil and Gas Terms............ S-49
Index to Financial Statements................... F-1
Report of Independent Petroleum Engineers....... A-1
Report of Independent Petroleum Engineers....... B-1
Report of Independent Petroleum Engineers....... C-1

PROSPECTUS
Forward-Looking Statements...................... 2
The Company..................................... 3
Use of Proceeds................................. 3
Ratios of Earnings to Fixed Charges............. 4
Description of Debt Securities.................. 4
Description of Preferred Stock.................. 15
Description of Depositary Shares................ 15
Description of Common Stock..................... 17
Description of Warrants......................... 19
Description of Subscription Rights.............. 20
Plan of Distribution............................ 21
Experts......................................... 23
Legal Matters................................... 23
Where You Can Find More Information............. 23
Incorporation of Certain Documents by
Reference..................................... 24
</TABLE>

2,840,000 SHARES

[LOGO]

COMMON STOCK
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PROSPECTUS SUPPLEMENT

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A.G. EDWARDS & SONS, INC.
ING BARINGS
PAINEWEBBER INCORPORATED
HOWARD WEIL
A DIVISION OF LEGG MASON WOOD WALKER, INC.
BREAN MURRAY & CO., INC.
HIBERNIA SOUTHCOAST CAPITAL

November 2, 2000

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