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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For The Fiscal Year Ended December 31, 1999
or
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the Transition Period From to
---- ----
COMMISSION FILE NUMBER 0-13171
EVERGREEN RESOURCES, INC.
(Exact name of registrant as specified in its charter)
COLORADO 84-0834147
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1401 17TH STREET
SUITE 1200
DENVER, COLORADO 80202
(Address of principal executive offices) (Zip Code)
(303) 298-8100
(Registrant's telephone number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
(None)
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
COMMON STOCK, NO PAR VALUE PER SHARE
Title of Class
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days
/x/ Yes / / No
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K, is not contained herein and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. /x/
As of March 15, 2000, the Registrant had 14,921,981 common shares
outstanding, and the aggregate market value of the common shares held by
non-affiliates was approximately $263,637,000 based upon the closing price of
$22.06 per share for the common stock on March 15, 2000, as reported on the
NASDAQ National Market.
DOCUMENTS INCORPORATED BY REFERENCE: DEFINITIVE PROXY MATERIALS FOR 2000 ANNUAL
MEETING OF STOCKHOLDERS - PART III, ITEMS 10, 11, 12, AND 13.
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TABLE OF CONTENTS
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PART I PAGE
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Item 1. Business..................................................................... 4
Item 2. Properties................................................................... 17
Item 3. Legal Proceedings............................................................ 23
Item 4. Submission of Matters to a Vote of Security Holders.......................... 23
PART II
Item 5. Market for Registrant's Common Equity
and Related Stockholder Matters....................................... 24
Item 6. Selected Financial Data...................................................... 25
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations......................... 26
Item 7A. Quantitative and Qualitative Disclosure about Market Risk.................... 31
Item 8. Financial Statements and Supplementary Data.................................. 32
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure................................ 32
PART III
Item 10. Directors and Executive Officers of the
Registrant............................................................ 32
Item 11. Executive Compensation....................................................... 32
Item 12. Security Ownership of Certain Beneficial
Owners and Management................................................. 32
Item 13. Certain Relationships and Related Transactions............................... 32
PART IV
Item 14. Exhibits, Consolidated Financial Statement Schedules
and Reports on Form 8-K............................................... 33
Signatures................................................................................ 34
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CERTAIN DEFINITIONS
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. Natural gas equivalents are determined using the
ratio of six Mcf of natural gas to one barrel of crude oil, condensate or
natural gas liquids so that one barrel of oil is referred to as six Mcf of
natural gas equivalent or "Mcfe." 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, "Bbl" means barrel,
"MBbl" means thousand barrels, "Mcfe" means thousand cubic feet equivalent,
"MMcfe" means million cubic feet equivalent, "Bcfe" means billion cubic feet
equivalent, and "MMBtu" means million British thermal units.
AVERAGE FINDING COST. The amount of 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.
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 which 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.
GROSS ACRES OR GROSS WELLS. The total acres or wells, as the case may be, in
which the Company has a working interest.
LOE. Lease operating expenses, which includes, among other things, extraction
costs and property taxes.
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.
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.
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PART I
ITEM 1. BUSINESS
GENERAL
Evergreen Resources, Inc. ("Evergreen" or "the Company") is a Colorado
corporation organized on January 14, 1981. Evergreen is an independent energy
company engaged in the exploration, development, production, operation and
acquisition of oil and gas properties. Evergreen's primary focus is on
developing and expanding its coal bed methane properties located on
approximately 207,000 gross acres in the Raton Basin in southern Colorado. The
Company also holds exploration licenses on approximately 513,000 acres onshore
in the United Kingdom, an interest in exploratory 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 northwest
Colorado. Evergreen operates all of its producing properties.
Evergreen maintains its principal executive offices at 1401 17th
Street, Suite 1200, Denver, Colorado 80202, and its telephone number is (303)
298-8100.
The authorized capitalization of the Company is 50,000,000 shares of no
par value common stock, of which 14,621,026 shares were issued and outstanding
at December 31, 1999, and 25,000,000 shares of $1.00 par value preferred stock,
none of which were issued and outstanding at December 31, 1999.
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 balances on the
Company's line of credit and capital lease obligations. The remainder of the
proceeds were used for general corporate purposes.
This report on Form 10-K contains forward-looking statements within the
meaning of Section 27A of the Securities Act of 1933, as amended (the
"Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as
amended (the "Exchange Act"), including statements regarding, among other items,
(i) the Company's growth strategies, (ii) anticipated trends in the Company's
business and its future results of operations, (iii) market conditions in the
oil and gas industry, (iv) the ability of the Company to make and integrate
acquisitions and (v) the outcome of litigation and the impact of governmental
regulation. These forward-looking statements are based largely on the Company's
expectations and are subject to a number of risks and uncertainties, many of
which are beyond the Company's control. Actual results could differ materially
from those implied by these forward-looking statements as a result of, among
other things, a decline in natural gas production, a decline in natural gas
prices, incorrect estimations of required capital expenditures, increases in the
cost of drilling, completion and gas gathering, an increase in the cost of
production and operations, an inability to meet growth projections, or changes
in general economic conditions. These and other risks are discussed under the
heading "Business - Certain Risks"." In light of these and other risks and
uncertainties of which we may be unaware or which we currently deem immaterial,
there can be no assurance that actual results will be as projected in the
forward-looking statements.
For a discussion of the development of the Company's business, see Item
2.
FOCUS - RATON BASIN
The Company's current operations are principally focused on developing
and expanding its coal bed methane project located in the Raton Basin in
southern Colorado.
Evergreen is one of the largest holders of oil and gas leases in the
Raton Basin with approximately 207,000 gross acres. In addition, the Company's
daily gas sales at March 15, 2000 represent approximately 58% of the gas
currently sold from the Raton Basin. Evergreen currently has 267 net producing
gas wells on its Raton Basin properties and other exploratory wells which are
subject to further evaluation. The Company has identified approximately 700 -
800 additional drilling locations on its Raton Basin acreage, of which 183 were
included in the Company's proved reserve base at December 31, 1999.
At December 31, 1999, Evergreen had estimated net proved reserves of
559 Bcf with a PV-10, before future income tax expense, of approximately $331
million. Natural gas constituted all of Evergreen's estimated net proved
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reserves, all of which were located in the Raton Basin and 60% of which were
developed. Evergreen has a 100% working interest in the majority of its Raton
Basin acreage and wells, and also owns the gas collection systems and related
equipment associated with these wells. Evergreen operates all of its producing
properties.
From March 31, 1995 through December 31, 1999, Evergreen added a net
496 Bcf of estimated proved reserves principally through its drilling in the
Raton Basin. This represents a compound annual growth rate in excess of 50%. The
company has an established track record for significantly growing its reserve
base. Since the Company began its drilling efforts in the Raton Basin, it has
drilled and tested approximately 250 producing wells and achieved a 98% success
rate. In addition, the Company acquired 43 net producing wells through property
acquisitions in 1998. Since early 1995, the Company's average gross daily
production has increased from 1.5 MMcf to over 54 MMcf at March 15, 2000.
Evergreen believes that it has gained significant experience in coal
bed methane exploration and development, including the utilization of enhanced
drilling, completion and production techniques developed over a number of years.
From inception of its Raton Basin project through December 31, 1999, the Company
spent approximately $134 million on the drilling and completion of its wells,
pipelines, gathering systems, compression equipment and the acquisition of
additional working interests, which represents a total finding and development
cost of $0.23 per Mcfe.
The Raton Basin is an onshore depositional and structural basin that 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 Evergreen's production has
been from the Vermejo formation coals; however, the Raton formation coal seams
are now being successfully developed as well.
Approximately 133,900 acres of the Company's 207,000 gross acres in the
Raton Basin have been included in three federal units, which simplifies lease
maintenance for the Company. Formation of these federal units allows Evergreen,
as unit operator, to base development decisions within the unit on technical,
geologic and geophysical data, rather than on the fulfillment of lease term
obligations.
INTERNATIONAL PROJECTS
UNITED KINGDOM. Evergreen holds licenses on approximately 513,000 acres
onshore in the United Kingdom. The Company believes that there are potential
opportunities to develop coal bed methane reserves within these license areas.
To date, Evergreen has spent approximately $9.5 million on this project and will
commence drilling coal bed methane wells in April 2000. Evergreen will spend
approximately $8 million to $9 million in 2000 to drill conventional coal bed
methane, interaction and gob gas wells and maintain the licenses. Gob gas is
methane gas that has collected in abandoned underground coal mines.
The Company plans to initially drill approximately 5 conventional coal
bed methane wells starting in late April 2000. The Company also plans to drill 7
gob and interaction gas wells during 2000. The Company has applied for several
planning permits and has received 5 approvals and is waiting for approval from
local authorities for the remaining permits.
FALKLAND ISLANDS. 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 rocks seal and potential
reservoir rocks.
The consortium is in the process of assigning the license interests and
operatorship to Argos Evergreen Ltd. ("AEL"), in which Evergreen owns a 40%
interest, and has requested a consent from the 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 over the next two years is approximately
$120,000.
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CHILE. In March 1997, the Government of Chile awarded an oil and gas exploration
license to Evergreen on two 5,000 square kilometer (each are approximately 1.2
million gross acres) blocks in northern Chile. Evergreen has a 75% working
interest in the blocks and will serve as operator. Empresa Nacional del Petroleo
("ENAP"), the Chilean government - owned energy company, holds the remaining 25%
working interest. A proprietary 2D seismic program was completed. The data is
being processed and interpreted. Upon completion, Evergreen will notify the
Ministry of Mining as to its intent to proceed to the next exploration period
which involves the drilling of an exploratory well on each block..
BUSINESS STRATEGY
The Company's objective is to enhance shareholder value by increasing
reserves, production, cash flow, earnings and net asset value per share. To
accomplish this objective, the Company intends to capitalize on its experience
and operating expertise in coal bed methane properties and on its other
competitive strengths, which include:
- its inventory of drilling locations in the Raton Basin,
- its track record for discovering new reserves and
significantly growing its reserve base, and
- its position as a low-cost finder, developer and producer of
natural gas.
CUSTOMERS AND MARKETS
GAS MARKETING. Primero Gas Marketing Company ("Primero") is a
wholly-owned subsidiary of the Company that was formed to market and sell
natural gas for the Company and third parties. To date, Primero has only
marketed and sold gas on behalf of the Company, royalty interests and working
interest partners. Primero also operates the Company's gas collection systems
and purchases all the Company's production from its Raton Basin wells.
The expanding production in the Raton Basin led Colorado Interstate Gas
Company ("CIG") to file with the Federal Energy Regulatory Commission (the
"FERC") for approval to construct a new, 115-mile, 16-inch pipeline connecting
CIG's Picketwire Lateral pipeline near Trinidad, Colorado to its mainline
compressor station at Campo, Colorado (the "Campo Lateral"). Now completed, the
Campo Lateral has initial capacity of up to approximately 100 MMcf per day,
which more than doubles the pipeline capacity previously available from the
Raton Basin. The pipeline capacity may be further expanded through the use of
additional compression facilities. In August 1997, the Company entered into a
new agreement with CIG having a term of 15 years which entitles the Company to
firm transportation of its Raton Basin gas through the Campo Lateral and which
also commits the Company to transport minimum amounts of natural gas from the
Raton Basin through the Campo Lateral. As of March 1, 2000, the Company had
total firm commitments of 53 MMcf per day. The CIG contract provides for
delivery of the Company's gas into interstate pipelines in Texas, from which it
can be transported to Midwest and East Coast markets. Absent the Campo Lateral,
the Company would be restricted in the total production that could be
transported from the Raton Basin.
MAJOR CUSTOMERS. Evergreen has three major customers Aquila Energy
Corporation, Natural Gas Transmission Services, Inc. and Columbia Energy, which
purchased approximately 24%, 49% and 18%, respectively, of the Company's gas
production for the year ended December 31, 1999. 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 Evergreen's business. As the Company's base of production
grows in the Raton Basin, the Company hopes to be able to enter into long-term
contracts with end users at favorable prices. Currently, the Company's gas is
sold at spot market prices or under contracts for terms of up to 41 months.
COMPETITION. The Company competes with numerous other companies in
virtually all facets of its 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 the
financial or personnel resources of the Company permit. The ability of the
Company to increase reserves in the future will be dependent on its 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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GOVERNMENT REGULATION OF THE OIL AND GAS INDUSTRY
GENERAL. The Company's business is affected by numerous governmental
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 and/or injunctive relief. Moreover, changes in any
of these laws and regulations could have a material adverse effect on the
Company's business. In view of the many uncertainties with respect to current
and future laws and regulations, including their applicability to the Company,
the Company cannot predict the overall effect of such laws and regulations on
its future operations.
The Company believes that its 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 effect on
the Company's method of 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 the Company's oil and natural gas operations are regulated by
agencies of the Federal government. The FERC regulates the transportation and
sale for resale of natural gas in interstate commerce pursuant to the Natural
Gas Act of 1938 ("NGA") and the Natural Gas Policy Act of 1978 ("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"). 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 the Company's
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 the Company's 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 its
open access regulations. In particular, the FERC has recently begun a broad
review of its transportation regulations, including how they operate in
conjunction with state proposals for retail gas marketing 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 its long-term transportation policies may also be appropriate
to avoid a market bias toward short-term contracts. The Company cannot predict
what action the FERC will take on these matters, nor can it accurately predict
whether the FERC's actions will, over the long term, achieve the goal of
increasing competition in markets in which the Company's natural gas is sold.
However, the Company does not believe that it will be affected by any action
taken materially differently than other natural gas producers and marketers with
which it competes.
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
will be able to change their transportation rates, subject to prescribed ceiling
levels. The indexing system, which allows or may require pipelines to make rate
changes to track changes in the Producer Price Index for Finished Goods, minus
one percent, became effective January 1, 1995. The Company does not believe that
these rules affect it any differently than other oil producers and marketers
with which it competes.
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
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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. The Company's gathering operations could be adversely affected should
they be subject in the future to increased state regulation of rates or
services, although the Company does not believe that it 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.
The Company owns certain natural gas pipeline facilities that it
believes 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.
The Company conducts certain operations on federal oil and gas leases,
which are administered by the Minerals Management Service (the "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 Company operations on federal
leases to be suspended or terminated. Any such suspension or termination
could materially and adversely affect the Company's financial condition, cash
flows and operations. The MMS has issued a notice of proposed rulemaking in
which it proposes to amend its regulations governing the calculation of
royalties and the valuation of crude oil produced from federal leases. This
proposed rule would modify the valuation of procedures for both arm's length
and non-arm's length crude oil transactions to decrease reliance on oil
posted prices and assign a value to crude oil that better reflects market
value, establish a new MMS form for collecting value differential data, and
amend the valuation procedure for the sale of federal royalty oil. The
Company cannot predict what action the MMS will take on this matter, nor can
it predict at this stage of the rulemaking proceeding how the Company might
be affected by this amendment to the MMS' regulations.
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. The Company 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,
the Company does not anticipate that compliance with existing federal, state and
local laws, rules and regulations will have a material or significantly adverse
effect upon the capital expenditures, earnings or competitive position of the
Company or its subsidiaries. No material portion of Evergreen's business is
subject to re-negotiation of profits or termination of contracts or subcontracts
at the election of the Federal government.
STATE REGULATION - UNITED STATES. The Company's 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 abandoning of wells and the disposal of fluids used
and produced in connection with operations. The Company's operations are also
subject to various conservation laws and regulations. These include the size of
drilling and spacing units or proration units and the density of wells which may
be drilled and the unitization or pooling of oil and gas properties. In
addition, state conservation laws 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, and the Company is unable to predict the future cost or
impact of complying with such regulations.
ENVIRONMENTAL MATTERS. Extensive federal, state and local environmental
laws affecting oil and natural gas operations, including those carried on by the
Company, regulate the discharge of materials into the environment or otherwise
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/or
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 "strict liability" for environmental
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contamination, rendering a person 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 on the part of such
person. Other laws, rules and regulations may restrict the rate of oil and
natural gas production below the rate that would otherwise exist or even
prohibit exploration or production activities in environmentally sensitive
areas. In addition, state laws often require some form of remedial action to
prevent pollution from former or suspended operations, such as closure of
inactive pits and plugging of abandoned wells. Legislation has been and
continues to be proposed in Congress from time to time that would reclassify
certain exempt 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
the operating costs of the Company, as well as 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
county, municipal and local government levels. These various initiatives could
have a similar adverse impact on the Company. The regulatory burden on the oil
and natural gas industry increases its cost and risk of doing business and
consequently affects its 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 the capital expenditures, earnings or
competitive position of the Company and its subsidiaries. The Company believes
that it is 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 the Company. Nevertheless, changes in
environmental law have the potential to adversely affect the Company's
operations. For example, the U.S. Comprehensive Environmental Response,
Compensation and Liability Act ("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 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 ("RCRA"), which governs the
generation and disposal of "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 regulation. During the normal course of its operations, the Company
generates or has generated in the past exempt and non-exempt wastes, including
hazardous wastes, that are subject to the RCRA and comparable state statutes.
The U.S. Environmental Protection Agency ("EPA") and various state agencies
continue to promulgate regulations that limit the disposal and permitting
options for certain hazardous and non-hazardous wastes.
The Company currently owns or leases, and has in the past owned or
leased, several properties that for many years have been used to store and
maintain equipment that was regularly used to explore for and produce oil and
gas. In particular, current and prior operations of the Company included oil and
gas production in the Rocky Mountain states and the portion of the Permian Basin
within the State of New Mexico. Although the Company utilized operating and
disposal practices that were standard for the industry at the time,
hydrocarbons, materials or other wastes may have been disposed of or released on
or under the properties owned or leased by the Company 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
treatment and disposal or release of hydrocarbons, materials or other wastes was
not under the Company's control. These properties and the waste disposed thereon
may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, the
Company 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 its coal bed methane gas production, the Company
from time to time conducts production enhancement techniques, including various
activities designed to hydraulic fracturing of the coals. While production
enhancement techniques are performed by the Company 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
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<PAGE>
by a citizens 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, 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. It is not known whether the EPA will apply the court's ruling in this
decision outside of the Eleventh Circuit (Alabama, Georgia, and Florida).
Nevertheless, 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 the Company. Management of the Company cannot predict at this time
whether regulation of hydraulic fracturing as a form of underground injection
will have an adverse material effect on the Company's operations or financial
position. However, such regulation is not expected to be any more burdensome to
the Company 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 its coal bed methane gas production, the Company may produce
naturally occurring groundwater 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 pursuant to federal,
state and local statutes and regulations. In some cases, the produced
groundwater is used for stock watering, agricultural or dust suppression
purposes, also pursuant to and 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 federal Clean Water Act ("CWA"), a strict liability
statute, which governs the permitted and unpermitted discharge of
"pollutants" to "waters of the United States" is a source of dispute, as
discussed below and in the section entitled "Legal Proceedings." Under the
CWA and various other state requirements, the EPA, the State of Colorado
Department of Public Health and the Environment ("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. These agencies' classification or characterization of
either: (1) such produced groundwater as a "pollutant," or (2) the storage,
use and disposal of such water on the surface as a "discharge to waters of
the United States" could have a significant impact on the regulatory
treatment of this groundwater management practice and Evergreen's
understanding of its past compliance in connection with the CWA. On January
7, 2000 Evergreen Operating Corporation, a wholly owned subsidiary of the
Company ("EOC") received a Compliance Order on Consent ("Consent Order") from
the CDPHE, that resolved the water discharge issues between the CDPHE and
EOC. Under the Consent Order, EOC will obtain additional permits from the
CDPHE for its water disposal practice and 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.
Operations of the Company involve the use of gas fired compressors to
transport collected gas, which compressors are subject to federal and state
regulations for the control of emissions. The Company has submitted Title V
permit applications and construction permits for its gas fired compressors as
applicable. The Company is presently involved in discussions with the
enforcement section of the CDPHE regarding the timeliness of its Title V
application at one of its compressor sites even though it has received
written notice from the permitting section that such applications were timely
made. In any event, the Company believes that it is in substantial compliance
with these applicable laws, rules and regulations relating to the control of
emissions at all of its facilities. The Company has encountered a few
exceedances of carbon monoxide during stack testing of certain of its
compressors due to manufacturer's defect or erroneous specifications but does
not expect these exceedances to have a material adverse effect on the
Company's operations.
Although the Company maintains 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 its purchase. The occurrence of a significant event not
fully insured or indemnified against could have a material adverse effect on the
Company's financial condition and operations.
10
<PAGE>
The Company's oil and gas operations outside of the United States are
subject to similar foreign governmental controls and restrictions pertaining to
the environment. The Company believes that compliance with existing requirements
of such governmental bodies has not had a material adverse effect on the
Company's operations.
At this time, the Company has no plans to make any material capital
expenditures for environmental control facilities. See Item 3- Legal Proceedings
regarding Southern Colorado C.U.R.E. v. Evergreen Operating Corporation.
TITLE TO PROPERTIES
As is customary in the oil and gas industry, only a preliminary title
examination is conducted at the time leases of properties believed to be
suitable for drilling operations are acquired by the Company. 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, the Company prepares a division order title report
indicating the proper parties and percentages for payment of production
proceeds, including royalties. The Company believes that titles to its leasehold
properties are good and defensible in accordance with standards generally
acceptable in the oil and gas industry.
EMPLOYEES
At March 15, 2000, the Company had 93 full time employees.
CERTAIN RISKS
OIL AND GAS PRICES ARE VOLATILE, AND AN EXTENDED DECLINE IN PRICES
WOULD HURT THE COMPANY'S PROFITABILITY AND FINANCIAL CONDITION.
Evergreen's revenues, operating results, profitability, future rate of
growth and the carrying value of its oil and gas properties depend heavily on
prevailing market prices for oil and gas. Management of the Company expects 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 the
Company's financial condition and results of operations. It could reduce the
Company's cash flow and borrowing capacity, as well as the value and the amount
of its gas reserves. All of Evergreen's proved reserves are natural gas.
Therefore, the Company is more directly impacted by volatility in the price of
natural gas. Various factors beyond the Company's 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.
11
<PAGE>
The Company periodically reviews the carrying value of its 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. The Company may be required to write down the carrying
value of its 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.
THE COMPANY'S OPERATIONS REQUIRE LARGE AMOUNTS OF CAPITAL.
Evergreen's current development plans will require it to make large
capital expenditures for the exploration and development of its natural gas
properties. Also, the Company must secure substantial capital to explore and
develop its international projects. Historically, Evergreen has funded its
capital expenditures through a combination of funds generated internally from
sales of production or properties, sales of common stock, long-term debt
financing and short-term financing arrangements. The Company currently does not
have any sources of additional financing other than its credit facility.
Management cannot be sure that any additional financing will be available to the
Company on acceptable terms. Future cash flows and the availability of financing
will be subject to a number of variables, such as:
- the success of its coal bed methane project in the Raton
Basin,
- the Company's 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 the Company's financing
requirements could cause substantial dilution to existing shareholders. Debt
financing could lead to:
- a substantial portion of the Company's operating cash flow
being dedicated to the payment of principal and interest,
- the Company being more vulnerable to competitive pressures and
economic downturns, and
- restrictions on the Company's operations.
If the Company's revenues were to decrease due to lower oil and natural gas
prices, decreased production or other reasons, and if it could not obtain
capital through its credit facility or otherwise, the Company's ability to
execute its development plans, replace its reserves or maintain production
levels could be greatly limited.
INFORMATION CONCERNING THE COMPANY'S 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 the control of the Company. Estimates of proved undeveloped reserves,
which comprise a significant portion of the Company's reserves, are by their
nature uncertain. The reserve data included in this Form 10-K is estimated.
Although management believes 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,
development costs and workover and
12
<PAGE>
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 the Company's reserves will likely vary from estimates, and such variances
may be material. See "Properties - Oil and Gas Reserves."
In addition, readers should not construe PV-10 as the current market
value of the estimated oil and natural gas reserves attributable to the
Company's properties. Management has 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. 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 the Company is 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 Evergreen's business or the oil and natural
gas industry in general are subject.
THE COMPANY DEPENDS HEAVILY ON EXPANSION AND DEVELOPMENT OF THE
RATON BASIN.
Evergreen's future success depends on its ability to find, develop and
acquire additional natural gas reserves that are economically recoverable in the
Raton Basin. All of the Company's proved reserves are in the Raton Basin, and
the Company's development plans make its future growth highly dependent on
increasing production and reserves in the Raton Basin. The Company's proved
reserves will decline as reserves are depleted, except to the extent it conducts
successful exploration or development activities or acquires other properties
containing proved reserves.
At December 31, 1999, the Company had estimated net proved undeveloped
reserves of approximately 225 Bcf, which constituted approximately 40% of
Evergreen's total estimated net proved reserves. The Company's development plan
includes increasing its reserve base through continued drilling and development
of its existing properties in the Raton Basin. Evergreen management cannot be
sure, though, that the Company's planned projects in the Raton Basin will lead
to significant additional reserves or that the Company will be able to continue
drilling productive wells at anticipated finding and development costs. In
particular, to date the majority of the Company's entire production has been
from the Vermejo coal bearing formation, which is one of two formations in the
Raton Basin. The Company recently began to exploit the Raton formation, which is
the second coal bearing formation in the Raton Basin.
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.
THE COMPANY'S 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
13
<PAGE>
spills, pollution, releases of toxic gas and other environmental hazards and
risks, any of which could cause the Company substantial losses. In addition, the
Company may be liable for environmental damage caused by previous owners of
property it owns or leases. As a result, the Company may face substantial
liabilities to third parties or governmental entities, which could reduce or
eliminate funds available for exploration, development or acquisitions or cause
Evergreen 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 the Company's
financial condition and results of operations.
EXPLORATORY DRILLING IS AN UNCERTAIN PROCESS WITH MANY RISKS.
Exploratory drilling involves numerous risks, including the risk that
the Company 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,
- compliance with governmental requirements, and
- shortages or delays in the availability of drilling rigs and
the delivery of equipment.
The Company's future drilling activities may not be successful, nor can
Evergreen management be sure that the Company's overall drilling success rate or
its drilling success rate for activity within a particular area will not
decline. Unsuccessful drilling activities could have a material adverse effect
on the Company's results of operations and financial condition. Also, Evergreen
may not be able to obtain any options or lease rights in potential drilling
locations that it identifies. Although the Company has identified numerous
potential drilling locations, management cannot be sure that Evergreen will ever
drill them or that it will produce natural gas from them or any other potential
drilling locations.
THE COMPANY MAY FACE UNANTICIPATED WATER DISPOSAL COSTS.
Based on the Company's previous experience with coal bed methane gas
production in the Raton Basin, management believes that the water produced from
the Raton Basin coal seams will not exceed certain levels and will continue to
be low in total dissolved solids, in many cases meeting state and federal
potable water standards. This means that Evergreen can lawfully discharge the
water into well-site pits and evaporation ponds using permits obtained from the
State of Colorado. If water of lesser quality is discovered or the Company's
wells produce water in excess of the limits of its permitted facilities, the
Company 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. If the Company cannot obtain permits from the State of
Colorado in the future, water of lesser quality is discovered, the Company's
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
will increase, which could have a material adverse effect on Evergreen's
operations in this area.
Evergreen is the defendant in a lawsuit under the federal Clean Water
Act relating to regulatory requirements for its water disposal from certain of
its Raton Basin wells. Management cannot be sure of the outcome of this
litigation. See " Legal Proceedings" for additional information with respect to
this lawsuit.
14
<PAGE>
THE COMPANY HAS LIMITED PROTECTION FOR ITS TECHNOLOGY AND DEPENDS
ON TECHNOLOGY OWNED BY OTHERS.
The Company uses operating practices that management believes are of
significant value in developing coal bed methane resources. In most cases,
patent or other intellectual property protection is unavailable for this
technology. The Company's use of independent contractors in most aspects of its
drilling and completion operations makes the protection of such technology more
difficult. Moreover, the Company relies on technological know-how of the
independent contractors that it retains for its oil and gas operations. The
Company has no long-term agreements with these contractors and management cannot
be sure that the Company will continue to have access to this know-how.
THE COMPANY'S BUSINESS DEPENDS ON TRANSPORTATION FACILITIES OWNED
BY OTHERS.
The marketability of the Company's gas production depends in part on
the availability, proximity and capacity of pipeline systems owned by third
parties. Although the Company has some contractual control over the
transportation of its product, material changes in these business relationships
could materially affect its operations. Federal and state regulation of gas and
oil production and transportation, tax and energy policies, changes in supply
and demand, pipeline pressures, and general economic conditions could adversely
affect the Company's ability to produce, gather and transport natural gas.
MARKET CONDITIONS COULD CAUSE THE COMPANY TO INCUR LOSSES ON ITS
TRANSPORTATION CONTRACTS.
The Company has gas transportation contracts that require it to
transport minimum volumes of natural gas. If the Company ships smaller volumes,
it may be liable for the shortfall. Unforeseen events, including production
problems or substantial decreases in the price for natural gas, could cause the
Company to ship less than the required volumes, resulting in losses on these
contracts. (See Note 13 to consolidated financial statements).
THE COMPANY'S 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.
THE COMPANY'S INTERNATIONAL OPERATIONS ARE SUBJECT TO RISKS OF
DOING BUSINESS ABROAD.
Evergreen holds exploration licenses onshore in the United Kingdom and
in northern Chile and an interest in offshore exploration 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 Evergreen's international operations.
THE COMPANY MUST COMPLY WITH COMPLEX ENVIRONMENTAL REGULATIONS.
The Company's 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 the Company's business.
The Company could face significant liabilities to the government and third
parties for discharging oil, natural gas or other pollutants into the air, soil
or water, and it could have to spend substantial amounts on investigations,
litigation and remediation. Evergreen management cannot be sure that existing
environmental laws or regulations, as currently interpreted or reinterpreted in
the future, or future laws or regulations will not materially adversely affect
the Company's results of operations and financial condition or that the Company
will not face material indemnity claims with respect to properties it owns or
has owned.
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<PAGE>
THE COMPANY'S 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 Evergreen's competitors have financial and technological
resources vastly exceeding those available to the Company. Many oil and gas
properties are sold in a competitive bidding process in which the Company may
lack technological information or expertise available to other bidders.
Evergreen's management cannot be sure that the Company will be successful in
acquiring and developing profitable properties in the face of this competition.
THE COMPANY DEPENDS ON KEY PERSONNEL.
Evergreen's success will continue to depend on the continued services
of its 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 the Company's operations. Evergreen maintains "key
man" insurance on the lives of Mark S. Sexton and Dennis R. Carlton in the
amount of $1,000,000 each. The Company does not have employment agreements with
any of its executive officers.
THE COMPANY'S HEDGING ARRANGEMENTS MIGHT LIMIT THE BENEFIT OF
INCREASES IN NATURAL GAS PRICES.
To reduce its exposure to short-term fluctuations in the price of
natural gas, the Company enters into hedging arrangements from time to time with
regard to a portion of its natural gas production. These hedging arrangements
limit the benefit of increases in the price of natural gas while providing only
partial protection against declines in natural gas prices.
THE COMPANY DOES NOT PAY DIVIDENDS.
The Company has never declared or paid any cash dividends on its common
stock and management has no intention to do so in the near future.
THE COMPANY'S ARTICLES OF INCORPORATION AND BYLAWS HAVE PROVISIONS
THAT DISCOURAGE CORPORATE TAKEOVERS AND COULD PREVENT SHAREHOLDERS
FROM REALIZING A PREMIUM ON THEIR INVESTMENT.
The Company's 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, the Company's 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 Evergreen's Board of Directors adopted a shareholder
rights agreement, pursuant to which uncertificated stock purchase rights were
distributed to shareholders of the Company 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 the Company's shareholders or involving a premium
over the prevailing stock price.
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ITEM 2. PROPERTIES
OPERATIONS
The Company's wholly-owned operating subsidiary, EOC, is primarily
responsible for drilling, evaluation and production activities associated with
various properties. As of March 15, 2000, EOC was serving as operator for
approximately 274 gross producing wells owned by the Company.
The Company believes that, as operator, it is in a better position to
control costs, safety, and timeliness of work as well as other critical factors
affecting the economics of a well or a property, including maintaining good
community relations.
EOC presently operates wells which represent 100% of Evergreen's proved
reserves.
OIL AND GAS RESERVES
The table below sets forth the Company's quantities of proved reserves,
as audited by independent petroleum engineers Netherland Sewell & Associates,
Inc. and Resource Services International, Inc. 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. 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 December 31, 1999.
<TABLE>
<CAPTION>
December 31,
------------------------------------------------------------
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Estimated Proved Gas Reserves (MMcf) 559,418 404,936 224,414
Estimated Proved Oil Reserves (Bbls) --- --- ---
Present Value of Future Net Revenues
(before future income tax expense) (in thousands) $331,383 $214,675 $159,326
</TABLE>
Reference should be made to Note 16 (Supplemental Oil and Gas
Information) to the consolidated financial statements for additional information
pertaining to the Company's proved oil and gas reserves. During fiscal 1999, the
Company did not file any reports that include estimates of total proved net oil
or gas reserves with any federal agency other than the Securities and Exchange
Commission.
PRODUCTION
The following table sets forth the Company's net oil and gas production
for the periods indicated.
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------------------------
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Natural Gas (MMcf) 13,656 10,021 6,402
Crude Oil & Condensate (Bbls) --- --- ---
</TABLE>
17
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AVERAGE SALES PRICES, LEASE OPERATING EXPENSES AND PRODUCTION TAXES
The following table sets forth the average sales price and the average
lease operating expenses and production taxes per Mcfe, for the periods
indicated.
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------------------
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Average sales price
Natural gas (per Mcf) $1.66 $1.90 $1.90
Oil (per Bbl) -- --- ---
Lease operating expenses $0.34 $0.25 $0.22
Production taxes $0.05 $0.09 $0.09
</TABLE>
PRODUCTIVE WELLS
The following table sets forth, as of December 31, 1999, the number of
gross and net productive oil and gas wells. Productive wells are producing wells
and wells capable of production, including shut-in wells.
<TABLE>
<CAPTION>
OIL GAS
Gross Net Gross Net
------------------ ---------------- ---------------- -----------------
<S> <C> <C> <C> <C>
-- -- 258 252
</TABLE>
ACREAGE
At December 31, 1999, Evergreen held developed and undeveloped acreage
as set forth below:
<TABLE>
<CAPTION>
LOCATION
- --------
DEVELOPED ACRES UNDEVELOPED ACRES TOTAL
--------------- ----------------- -----------------
GROSS NET GROSS NET GROSS NET
---------- ---------- ---------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Colorado 71,100 64,500 154,100 132,100 225,200 196,600
United Kingdom -- -- 513,000 513,000 513,000 513,000
Falkland Islands -- -- 400,600 160,200 400,600 160,200
Chile -- -- 2,400,000 1,800,000 2,400,000 1,800,000
---------- ---------- ----------- ----------- ----------- -----------
Total 71,100 64,500 3,467,700 2,605,300 3,538,800 2,669,800
========== ========== =========== =========== =========== ===========
</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, 2001 and later........................................................... 14,700 10,200
</TABLE>
18
<PAGE>
DRILLING ACTIVITIES
The Company's drilling activities for the periods indicated are set
forth below:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------------
1999 1998 1997
---- ---- ----
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C>
Exploratory Wells:
Productive ................................. 0 0 0 0 4 4
Dry ........................................ 0 0 0 0 0 0
-- -- -- -- -- --
0 0 0 0 4 4
Development Wells:
Productive ................................. 85 83 50 50 56 56
Dry ........................................ 0 0 0 0 0 0
-- -- -- -- -- --
85 83 50 50 56 56
</TABLE>
PRINCIPAL PROPERTIES
The following are brief descriptions of Evergreen's principal
properties:
RATON BASIN PROPERTIES AND OPERATIONS
The Raton Basin is an onshore depositional and structural basin that 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, Evergreen's primary production has been from
the Vermejo formation coal seams; however, Evergreen believes that the Raton
formation coal seams may be profitably exploited as well.
DEVELOPMENT HISTORY AND EXPECTED FUTURE DEVELOPMENT. 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 CIG's
Picketwire Lateral became operational.
Since December 1991, Evergreen has acquired oil and gas leases covering
approximately 206,000 gross acres in the Raton Basin. The initial 70,000 acres
were acquired from Amoco Production Company ("Amoco") in 1991 by direct purchase
without overriding royalties. The majority of the acreage remaining was
purchased during 1992 and 1993 from individual owners under various lease terms.
Generally, the lease terms provide for a 12 1/2% royalty interest to the owner
of the mineral rights. In August 1993, a four well evaluation program was
conducted by the Company. Based on positive results from the initial four wells,
the Company made the decision, in August 1994, to focus all domestic efforts on
development of the Raton Basin. Evergreen currently has 267 net producing gas
wells on its Raton Basin properties.
In March 1995, the Federal Bureau of Land Management ("BLM") designated
approximately 67,000 acres of Evergreen's leases in the Raton Basin as a federal
unit called the Spanish Peaks Unit. In December 1997, the BLM approved an
additional 6,300 acres of leases to be included in the Spanish Peaks Unit, for a
total of 73,300 acres. In January 1997, the BLM designated an additional 33,000
acres of Evergreen's leases as a federal unit called the Sangre de Cristo Unit.
Additionally, in July 1998, the Company acquired a 100% working interest in
27,600 gross acres in the Cottontail Pass Federal Unit from Amoco. The
Cottontail Pass Unit is situated between Evergreen's Spanish Peaks and Sangre de
Cristo Units. Evergreen has been named the operator for all three of these
units. Formation of a unit simplifies lease maintenance so that Evergreen, as
the operator, can base development decisions within the unit on geologic,
operational and cultural considerations rather than 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 BLM
under the Unit Agreement. Gas production in the participating area will be
pooled and shared by the royalty owners, overriding royalty owners and
19
<PAGE>
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.
Prior to the acquisitions of the Cottontail Pass Unit and acreage in
the Long Canyon and Lorencito areas (discussed below), the Company's principal
development activities in the Raton Basin had been in the Spanish Peaks Unit.
The Company currently has 203 producing wells in this Unit and expects to drill
approximately 49 wells there in 2000. Current production from the Spanish Peaks
Unit is approximately 44 MMcf per day. The Company has identified approximately
400 drilling locations in its Spanish Peaks Unit. The Company has also drilled
two exploratory wells in the northern portion of the Spanish Peaks Unit to
determine the development potential for commercial production of the shallower
Raton formation coals, as well as the Vermejo formation coals.
The Company's development activities in the Sangre de Cristo Unit have
consisted solely of the drilling of six exploratory wells. These exploratory
wells will test production levels, provide additional geologic control, and also
will fulfill unit obligations. The Company expects to drill approximately 5
wells during 2000 in this Unit. No reserves from wells in the Sangre de Cristo
Unit are included in the Company's reserve base.
In July 1998, Evergreen acquired approximately 100% of the working interest in
27,600 acres in Amoco's Cottontail Pass Federal Unit. The Company currently has
44 producing wells in this unit and expects to drill approximately 26 wells
during 2000. Total daily production is approximately 5 MMcf per day. The Company
estimates that there are approximately 80-100 additional drilling locations in
this Unit.
In December 1998, the Company acquired 41,000 gross acres in the Long Canyon and
Lorencito areas located in the southern Colorado portion of the Raton Basin. The
Company currently has 27 gross producing wells in the Long Canyon area and
expects to drill approximately 20 wells in 2000. Total daily production from the
Long Canyon area is approximately 3.2 MMcf per day Evergreen has identified 160
potential drilling locations on the acreage, in which it will hold working
interests of between 53% and 75%.
RATON BASIN GEOLOGY. In the Raton Basin, Evergreen produces 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 entire Vermejo coal interval ranges from 5
to 50 feet thick through the Raton Basin, being thickest in the center of the
Basin, which the Company's 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 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. The Company
believes 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, the Company has 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 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
20
<PAGE>
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 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 insitu water.
Methane is a common component of coal since 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. Contrary to 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 because the coal seams are being de-watered and
the resultant pressure on the coal decreases.
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" in the
industry) so the pathway for gas migration to the wellbore is enhanced. These
fractures are filled (propped) with uniformed sized sand and become the conduits
for 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.
COAL BED METHANE TECHNOLOGY. The Company, working in conjunction with
its contractors, has developed what it believes to be effective procedures for
fracing the Vermejo and Raton coals in its Raton Basin wells. In addition, the
Company has developed well completion and specialized drilling techniques that
are suited to its Raton Basin wells. 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 cleat system
and natural fractures in the coals. The Company, therefore, uses percussion air
drilling (similar to a jackhammer) without traditional drilling muds in drilling
its wells.
WATER PRODUCTION AND DISPOSAL. To date, the majority of the water
produced from the Company's Raton Basin coal seams has been low in total
dissolved solids, allowing the Company, operating under permits issued by the
State of Colorado, to discharge the water into well-site pits and off well-site
evaporation ponds. If more brackish water is encountered in subsequent wells, it
may be necessary to drill specialized injection wells to re-inject the produced
water back into the underground rock formations. See "Business- Certain Risks-
The Company may face unanticipated water disposal costs".
RATON BASIN PRODUCTION. Evergreen's natural gas sales from the Raton
Basin did not commence until the completion of a pipeline system in January
1995, which connected the Company's Raton Basin wells to the CIG pipelines. From
January 1995 through December 1999, Evergreen sold an aggregate of approximately
32.2 Bcf of coal bed methane gas from the Raton Basin. Gross daily production
from the field currently exceeds 54 MMcf per day. Because of the importance of
removing water from the coal seams to enhance gas production, Evergreen expects
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" in the water saturation around the
wellbore. The Company believes that some of its Raton Basin wells on adjacent
160-acre drill sites have already created overlapping cones of depression,
enhancing gas production in each well.
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.
21
<PAGE>
INTERNATIONAL PROPERTIES AND OPERATIONS
UNITED KINGDOM. In 1991 and 1992, the Company's 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 (the "Original Licenses"). The
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, Evergreen 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, Evergreen converted its Original Licenses to
new onshore licenses, called Petroleum Exploration and Development Licenses (the
"Licenses"). In connection with such conversion, 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
retains approximately 513,000 acres, which were high-graded for coal bed methane
and conventional hydrocarbon potential. The 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. Work commitments for acreage retained will include the drilling of
five wells in 2000.
Evergreen believes 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, since success or lack of success on one License may
not be translated to similar results on other Licenses or separate geologic
basins. Evergreen will spend approximately $8 million to $9 million in 2000
to drill 5 conventional coal bed methane wells and 7 interaction and gob gas
wells and to maintain the Licenses.
The Company plans to initially drill approximately 5 conventional coal
bed methane wells starting in late April 2000. The drilling and completion of
the wells will take approximately 3-4 months. Initially, Evergreen was seeking a
partner prior to initiating the drilling of the 5 well coal bed methane pilot
program. The Company, however, will complete the initial development drilling
using its own financial resources. The Company is currently in negotiations with
various entities to provide for the development of marketing, transmission and
sales of the natural gas.
FALKLAND ISLANDS. 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 rocks 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 the 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 over the next two years is approximately
$120,000.
CHILE. In March 1997, the Government of Chile awarded an oil and gas
exploration license to Evergreen on two 5,000 square kilometer (each are
approximately 1.2 million gross acres) blocks in northern Chile. Evergreen
has a 75% working interest in the blocks and will serve as operator. ENAP,
the Chilean government-owned energy company, holds the remaining 25% working
interest. The Chilean government will initially receive a 10% royalty on
production up to 10,000 barrels per day, which increases up to a maximum of
35% on production in excess of 100,000 barrels per day.
22
<PAGE>
Evergreen and ENAP will share work commitments proportionately for the
periods of time stated as Exploration Periods for each block as set forth in the
table below:
<TABLE>
<CAPTION>
EXPLORATION
PERIOD TERM WORK COMMITMENT
----------- ---- ---------------
<S> <C> <C>
2 2 years 200 km seismic data
3 2 years 1 exploratory well
4-9 1 year each 1 exploratory well
</TABLE>
Evergreen and ENAP may relinquish up to 100% of the blocks at the end
of each exploration period. If the blocks go into production, the contracts will
last 35 years.
As part of the work commitment for exploration period 2, a proprietary
2D seismic program was completed before year end. The data is being processed
and analyzed. Upon completion, Evergreen will notify the Ministry of Mining as
to its intent to drill an exploratory well on each block.
OFFICE AND OPERATIONS FACILITIES
The Company leases its corporate offices in Denver, Colorado. Effective
May 1, 1998, the Company entered into a new ten- year office lease for
approximately $267,500 per year. The Company believes the new office space will
be sufficient for the foreseeable future.
ITEM 3. LEGAL PROCEEDINGS
Except as provided below, the Company is not engaged in any material
legal proceedings to which the Company or its subsidiaries is a party or to
which any of its property is subject.
On July 13, 1998, a localized group of citizens, Southern Colorado
C.U.R.E., filed a lawsuit under the citizen suit provision of the Clean Water
Act in the U.S. District Court for the District of Colorado against EOC,
related to its coal bed methane drilling operations in the Raton Basin near
Trinidad, Colorado. The Company's gas production produces naturally occurring
groundwater as a by-product of its coal bed methane gas production
operations. The storage, use and disposal of the produced groundwater in
evaporative ponds and natural collection features located on the surface at
or near the wellsite, and the legal and regulatory treatment of this
practice, underlie the lawsuit. The Company believes the lawsuit to be
without merit and responded by filing a Motion to Dismiss all of Southern
Colorado C.U.R.E.'s alleged claims on substantive grounds. A renewed Motion
to Dismiss is currently pending before the court, although a magistrate to
whom the judge presiding over the matter referred the original Motion to
Dismiss has indicated that she would recommend to the judge that the motion
be denied with respect to certain of the allegations. The resolution of these
issues with the CDPHE, however, should moot any of the claims that remain if
the substantive Motion to Dismiss is denied. The Company does not expect that
the lawsuit or the investigation, or the environmental costs or contingent
liabilities of either, if any, will have a material adverse effect on its
consolidated financial position or its results of 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 entered into a Consent Order with the CDPHE, that
resolved the water discharge issues between the CDPHE and EOC. Under the
Consent Order, EOC 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,
governing the discharge of produced water from Evergreen's coal bed methane
operations in the Raton Basin.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable.
23
<PAGE>
PART II
ITEM 5. MARKET FOR EVERGREEN'S COMMON STOCK AND RELATED SECURITY HOLDER
MATTERS
PRINCIPAL MARKET
The Company's Common Stock is included for quotation in the NASDAQ
National Market under the market symbol "EVER." The following table sets
forth the range of high and low sales prices per share for the periods
indicated, as reported by the NASDAQ National Market:
<TABLE>
<CAPTION>
HIGH LOW
---- ---
<S> <C> <C>
Year Ended December 31, 1997
First Quarter................................................ $8.50 $7.38
Second Quarter............................................... 10.50 6.75
Third Quarter................................................ 16.13 9.75
Fourth Quarter............................................... 20.75 12.62
Year Ended December 31, 1998
First Quarter................................................ $18.38 $13.25
Second Quarter............................................... 19.62 16.31
Third Quarter................................................ 22.75 13.75
Fourth Quarter............................................... 24.13 16.63
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
</TABLE>
On March 15, 2000, the last reported sales price for the Common Stock
as reported on the NASDAQ National Market was $22.06 per share. At March 15,
2000, there were approximately 4,600 holders of record of the Company's
Common Stock.
DIVIDEND POLICY
Holders of Common Stock are entitled to dividends when, as and if
declared by the Company's Board of Directors, subject to any preferential rights
of any outstanding preferred stock and any contractual agreements of the Company
limiting the payment of dividends. The Company has not declared or paid any cash
dividends since its inception. The Company anticipates that future earnings will
be retained for the development of its business and that no cash dividends will
be declared or paid in the foreseeable future.
RECENT SALES OF UNREGISTERED SECURITIES
On October 8, 1999, the Company issued 120,000 shares of Common Stock
to a corporation, believed to be an accredited investor, in connection with a
property acquisition. The Company issued these shares of Common Stock in
reliance on the exemption from registration provided by Section 4(2) of the
Securities Act.
24
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
The selected consolidated financial information presented below for the
years ended December 31, 1999, 1998 and 1997, the nine months ended December 31,
1996, and the year ended March 31, 1996 is derived from the consolidated
financial statements of the Company. Effective with the period ended December
31, 1996, the Company began utilizing a December 31 year-end.
This information should be read in conjunction with the Consolidated
Financial Statements and Notes thereto and Management's Discussion and Analysis
of Financial Condition and Results of Operations. As discussed in Note 15 to the
Consolidated Financial Statements, effective February 18, 1999, Evergreen sold
its 49% interest in Maverick Stimulation Company ("Maverick") to the managing
members of Maverick for $2.26 million. The sale resulted in a gain net of tax of
approximately $452,200 or $0.03 per diluted share. 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. Certain reclassifications have been made to
prior financial statements to conform with current presentation.
<TABLE>
<CAPTION>
Nine Months YEAR ENDED
Ended ----------
YEARS ENDED DECEMBER 31, DECEMBER 31, MARCH 31,
------------------------ ------------ ---------
1999 1998 1997 1996 1996
---------- ---------- ---------- ---------- ---------
(in thousands, except per share amounts)
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA
Revenues:
Natural gas and oil revenues $ 22,721 $ 19,063 $ 12,138 $ 3,502 $ 1,393
Interest and other 207 178 136 181 763
---------- ---------- ---------- ---------- ---------
Total revenues 22,928 19,241 12,274 3,683 2,156
---------- ---------- ---------- ---------- ---------
Expenses:
Lease operating expenses 4,697 2,481 1,433 529 580
Production taxes 694 876 574 172 77
Depreciation, depletion and amortization 4,757 3,860 2,794 966 590
General and administrative 3,024 1,933 1,286 581 767
Interest 1,927 1,870 777 193 36
Other 175 286 259 127 208
---------- ---------- ---------- ---------- ---------
Total expenses 15,274 11,306 7,123 2,568 2,258
---------- ---------- ---------- ---------- ---------
Income (loss) from continuing operations before
income taxes 7,654 7,935 5,151 1,115 (102)
Income tax provision - deferred 2,979 3,062 -- -- --
---------- ---------- ---------- ---------- ---------
Income (loss) from continuing operations 4,675 4,873 5,151 1,115 (102)
Discontinued operations
Gain on disposal of discontinued operations, net 452 -- -- -- --
Equity in earnings of discontinued -- 339 313 -- --
operations, net
---------- ---------- ---------- ---------- ---------
Net income (loss) 5,127 5,212 5,464 1,115 (102)
Preferred stock dividends -- -- (400) (440) (505)
---------- ---------- ---------- ---------- ---------
Net income (loss) attributable to common stock $ 5,127 5,212 $ 5,064 $ 675 $ (607)
========== ========== ========== ========== =========
Basic income (loss) per common share
From continuing operations $ 0.36 $ 0.47 $ 0.50 $ 0.10 $ (0.10)
From discontinued operations 0.03 0.03 0.03 -- --
---------- ---------- ---------- ---------- ---------
Basic income per common share $ 0.39 0.50 $ 0.53 $ 0.10 $ (0.10)
========== ========== ========== ========== =========
Diluted income (loss) per common share
From continuing operations $ 0.34 $ 0.44 $ 0.48 $ 0.10 $ (0.10)
From discontinued operations 0.03 0.03 0.03 -- --
---------- ---------- ---------- ---------- ---------
Diluted income per common share $ 0.37 0.47 $ 0.51 $ 0.10 $ (0.10)
========== ========== ========== ========== =========
</TABLE>
25
<PAGE>
<TABLE>
<CAPTION>
Nine Months
Ended Year Ended
----------
Years Ended December 31, December 31, March 31,
------------------------ ------------ ----------
1999 1998 1997 1996 1996
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
STATEMENT OF CASH FLOWS DATA
Net cash provided by (used in):
Operating activities $ 12,731 $ 12,147 $ 6,457 $ 1,524 $ 1,130
Investing activities (43,864) (47,202) (19,259) (8,559) (2,764)
Financing activities 30,471 34,260 12,253 5,978 3,329
</TABLE>
<TABLE>
December 31, March 31,
---------------------------------------- ---------
1999 1998 1997 1996 1996
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
BALANCE SHEET DATA
Cash and cash equivalents $ 651 $ 1,334 $ 2,103 $ 2,640 $ 3,703
Total assets 184,369 139,626 87,306 68,244 44,172
Total long term obligations 15,500 47,045 14,841 1,174 191
Redeemable preferred stock -- -- -- 6,000 7,500
Total stockholders' equity 153,510 79,679 64,152 52,364 31,589
</TABLE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following information should be read in conjunction with the
Consolidated Financial Statements and Notes thereto presented elsewhere in this
Form 10-K. The Company follows the full-cost method of accounting for oil and
gas properties. See "Summary of Accounting Policies," included in Note 1 to the
Consolidated Financial Statements.
GENERAL
Evergreen is an independent energy company engaged in the exploration,
development, operation, production and acquisition of oil and gas properties.
Evergreen's primary focus is on developing coalbed methane properties located on
approximately 207,000 gross acres in the Raton Basin in southern Colorado. The
Company also holds exploration licenses on approximately 513,000 acres onshore
in the United Kingdom, an interest in exploratory acreage offshore in the
Falkland Islands, and an oil and gas exploration contract on approximately 2.4
million gross acres in northern Chile and exploratory acreage in northwest
Colorado. Evergreen operates all of its producing properties.
The following table sets forth certain operating data of the Company
for the periods presented.
<TABLE>
<CAPTION>
Nine Months
Years Ended Ended Year Ended
December 31, December 31, March 31,
---------------------------------------- ------------- ---------
1999 1998 1997 1996 1996
---------- ------------ ---------- ------------- ---------
<S> <C> <C> <C> <C> <C>
PRODUCTION DATA:
Natural gas (MMcf) 13,656 10,021 6,402 2,104 941
Oil (MBbls) -- -- -- -- 10
Total (Mcfe) 13,656 10,021 6,402 2,104 999
AVERAGE SALES PRICE PER UNIT:
Natural gas (per Mcf) $ 1.66 $ 1.90 $ 1.90 $ 1.66 $ 1.29
Oil (per Bbl) -- -- -- -- 18.40
Mcfe 1.66 1.90 1.90 1.66 1.39
COST PER MCFE:
Lease operating expenses $ 0.34 $ 0.25 $ 0.22 $ 0.25 $ 0.58
Production taxes 0.05 0.09 0.09 0.08 0.07
General and administrative 0.22 0.19 0.20 0.28 0.77
Depreciation, depletion and
amortization 0.35 0.39 0.44 0.46 0.59
</TABLE>
26
<PAGE>
LIQUIDITY AND CAPITAL RESOURCES
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 balances on the
Company's line of credit and capital lease obligations. The remainder of the
proceeds were used for general corporate purposes.
The Company has a $75 million revolving line of credit with a bank
group consisting of Hibernia National Bank, as agent, Chase Bank of Texas and
Paribas ("the Banks"). The line is available through June 2001. Advances
pursuant to this line of credit are limited to a borrowing base, which is
presently $75 million. At the Company's election, it may 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 0.25%, with margins on both rates determined on the
average outstanding borrowings under the credit facility. The borrowing base is
redetermined semi-annually by the Banks based upon reserve evaluations of the
Company's oil and gas properties. An average annual facility 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 and
ratio requirements. At December 31, 1999, $15.5 million was outstanding under
the line of credit. The Company anticipates increasing its credit facility to
$125 million by June 30, 2000.
In February 1999, the Company sold its 49% interest in Maverick, a well
service company, for approximately $2.3 million and formed a new well service
company, Evergreen Well Service ("EWS"). The well service company is currently
providing fracture stimulation services, cement work, drilling and workovers.
Evergreen anticipates an increase in quality control and cost savings from the
services performed by EWS.
During 2000, the Company plans to spend approximately $80 million on
its total exploration and development program. The Company's drilling program
will include approximately 100 wells in the Raton Basin. The total estimated
cost for drilling and completion is approximately $17 million. In 2000, the
Company is also upgrading the compressor stations in the Cottontail Pass Unit
and the Long Canyon area that were acquired in 1998. The infrastructure costs
incurred in 2000 will reduce future years capital expenditures. The total costs
for compression and collection systems in 2000 will be approximately $34
million. Other costs for recompletions, exploration, equipment and mineral
acquisitions total approximately $17 million.
During 2000, the Company will start the development of the United
Kingdom project with the drilling of 5 conventional coal bed methane pilot
program in late April 2000. Additionally, the Company anticipates drilling 7 gob
and interaction gas wells and has applied for planning permits and has received
5 approvals and is waiting for approval from local authorities for the remaining
permits. The Company has also ordered fracture stimulation equipment for use in
the development of the UK project. The total estimated capital expenditures for
the UK in 2000 are approximately $12 million.
The Company believes that cash flow from operations and available
borrowings under its line of credit will be sufficient to fund 2000 capital
expenditures. Future development of the Company's projects will require
additional capital. The Company believes it will have sufficient capacity to
fund all of its projects for the foreseeable future through its anticipated cash
flow and its lines of credit.
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 the Company's line of credit given the decrease in cash used in
investing activities in 1999 as compared to 1998.
27
<PAGE>
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
For the year ended December 31, 1999, the Company 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 Evergreen's
49% interest in Maverick Stimulation Company ("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 Evergreen's increase in its
working interest to 75% from 25% in Long Canyon (or 12 net producing wells).
On February 18, 1999, the Company sold its 49% interest in Maverick to
the managing members of Maverick. The closing date was April 14, 1999. On that
date, the Company received $2,258,000 in cash and was released from its debt
guarantee with Maverick's bank. The Company recorded an after tax gain on the
sale of its 49% interest of $452,000.
During the year ended December 31, 1999, lease operating expenses
excluding production taxes were $4,697,000 or $.34 per Mcf as compared to
$2,481,000 or $0.25 per Mcf in the prior year. The 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.
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 the significant growth of the Company. Through
March 1999, EOC, a wholly owned subsidiary of the Company, 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, the Company's general and administrative expenses
increased by approximately $416,000 in 1999.
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 the
Company's line of credit in 1999. At June 22, 1999, the Company 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 its common
shares. Since June 1999, the Company has borrowed $15.5 million under the line
of credit.
28
<PAGE>
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
The Company 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, the Company's 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 in 1998 compared to 1997 or 57% was due to
the increase in production and the acquisition of certain properties in the
Raton Basin. The Company 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. The Company 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. The Company accounted for the investment 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, the Company sold its 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 for the year ended December 31, 1998 were
$2,481,000 as compared to $1,433,000 for the same period in 1997. Lease
operating expenses were $0.25 per Mcf in 1998 versus $0.22 per Mcf 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.
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 the Company's
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, the Company increased its 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 the Company's effective
interest rate in the last half of 1998 by 142 basis points to 7.25%.
29
<PAGE>
Prior to 1998, the Company was 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, the Company is required to
provide for deferred income taxes in the statements of income in 1998 and
subsequent years. The Company estimates that it will not be required to pay
current income tax in the near future due to the availability of net operating
loss carryforwards of approximately $27 million and current deductions for
intangible drilling costs. For the year ended December 31, 1998, the Company
recorded a deferred tax provision of $3,062,000.
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.
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. 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 and 20,000 MMBtu per day at NYMEX less $0.20
for the period November 1, 2000 through October 31, 2001. 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.
The Company identifies minimum internal price targets and, assuming
other market conditions are deemed favorable, the Company will enter into
hedging contracts to manage price risk. See "Quantitative and Qualitative
Disclosure About Market Risk."
INCOME TAXES AND NET OPERATING LOSSES
As discussed in Note 7 of the Notes to the Company's Consolidated
Financial Statements, the Company has net operating loss carryforwards for
income tax purposes of approximately $22 million which expire beginning in 2004.
Prior to 1998, the Company was not been 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, the Company is required to
provide for deferred income taxes in the statements of income in 1998 and
subsequent years. The Company estimates that it will not be required to pay
current income tax in the near future due to the availability of net operating
loss carryforwards of approximately $22 million and current deductions for
intangible drilling costs.
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 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.
30
<PAGE>
IMPACT OF THE YEAR 2000 ISSUE
The following Year 2000 statement constitutes a Year 2000 Readiness
Disclosure within the meaning of the Year 2000 Information and Readiness
Disclosure Act of 1998. The Year 2000 Issue is the result of computer programs
and embedded computer chips being written or manufactured using two digits
rather than four, or other methods, to define the applicable year. Computer
programs and embedded chips that are date-sensitive may recognize a date using
"00" as the year 1900 rather than the year 2000. This could result in a system
failure or miscalculations causing disruptions of operations, including, among
other things, a temporary inability to process transactions, operate equipment
or engage in normal business activities. Failure to correct a material Year 2000
compliance problem could result in an interruption in, or inability to conduct
normal business activities or operations. Such failures could materially and
adversely affect a company's results of the operations, cash flow and financial
condition. Beginning in 1999, the Company developed and implemented a formal
plan to mitigate the impact of Year 2000 compliance. The plan was fully
implemented before December 31, 1999. To date the Company has not encountered
any material Year 2000 compliance problems and has suffered no material adverse
effects from this issue.
Through December 31, 1999, the Company spent approximately $50,000 on
its Year 2000 efforts. This includes the cost of consultants as well as the cost
of repair or replacement of non-compliant hardware and software systems. The
Company did not specifically track its internal costs of addressing the Year
2000 issue. However, management does not believe these internal costs were
material.
The Company currently has no reason to believe that any Year 2000
compliance failures occurred or will occur or that its principal vendors,
customers and business partners are not Year 2000 compliant. However, there can
be no assurance that all Year 2000 problems have been identified and corrected.
Therefore, there can be no assurance that all Year 2000 problems have been
identified and corrected or that currently unknown Year 2000 issues will not
materially impact the Company's results of operations or adversely affect its
relationships with vendors, customers and other business partners in the year
2000.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
COMMODITY RISK. The Company's major market risk exposure is in the
pricing applicable to its gas production. Realized pricing is primarily driven
by the prevailing price for crude oil and spot prices applicable to Evergreen's
United States natural gas production. Historically, prices received for gas
production have been volatile and unpredictable. Pricing volatility is expected
to continue.
The Company periodically enters into contractual obligations that
require future delivery of its natural gas production to attempt to manage price
risk with regard to a portion of its natural gas production. A 10 percent
improvement in year-end spot market prices would not have affected the Company's
physical gas contracts in place as those contracts were higher than the spot
plus 10%. A 10% decline in year-end spot market prices on year-end production
not covered under contractual obligations would reduce 2000 revenues by
$603,000, assuming production volumes remain the same.
INTEREST RATE RISK. At December 31, 1999, Evergreen had long-term debt
outstanding of $15.5 million. The interest rates on the outstanding debt range
from LIBOR plus 1.38% to prime. Interest rates are variable, however, they may
be fixed at Evergreen's option for periods of time between 30 to 90 days. A 10%
increase in short-term interest rates on the floating-rate debt outstanding at
the end of 1999 would equal approximately 85 basis points. Such an increase in
interest rates would not materially impact Evergreen's 2000 interest expense
assuming borrowed amounts remain outstanding at current levels.
FOREIGN CURRENCY RISK. Evergreen's net assets, revenue and expense
accounts from its UK subsidiary are based on the U.S. dollar equivalent of such
amounts measured in the UK dollar. 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.
The Company has not had any significant operations in the UK for the
past several years. In 2000, the Company plans to start a drilling program
consisting of 5 conventional coal bed methane wells and 7 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.
31
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Report of Independent Certified Public Accountants.........................................F-1
Consolidated Balance Sheets, December 31, 1999 and 1998....................................F-2
Consolidated Statements of Income for the Years ended
December 31, 1999, 1998 and 1997...........................................................F-3
Consolidated Statements of Stockholders' Equity for the Years ended
December 31, 1999, 1998 and 1997...........................................................F-4
Consolidated Statements of Cash Flows for the Years ended
December 31, 1999, 1998 and 1997...........................................................F-5
Consolidated Statements of Comprehensive Income for the Years ended
December 31, 1999, 1998 and 1997...........................................................F-6
Notes to Consolidated Financial Statements.........................................F-7 to F-32
</TABLE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURES
Not Applicable.
PART III
The information required by Part III of Form 10-K is incorporated
herein by reference to Registrant's definitive Proxy Statement to be filed in
connection with the Annual Meeting of Shareholders to be held on May 12, 2000.
32
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a)(1) See Index to Consolidated Financial Statements at Item 8.
(a)(2) All other schedules have been omitted because the required
information is inapplicable or is shown in the notes to the financial
statements.
(a)(3) EXHIBITS:
---------
3.1 Articles of Incorporation as amended: Incorporated by reference
to Exhibit 3.1 of the Company's Registration Statement on Form
S-1, Commission File No. 33-273035, by reference to Exhibit I of
the Company's Current Report on Form 8-K dated December 9, 1994
and by reference to Exhibit 3.1 to the Company's Current Report
on Form 8-K filed June 8, 1998.
3.2 Bylaws: Incorporated by reference to Exhibit 3.1 to the Company's
Current Report on Form 8-K filed June 8, 1998.
4.1 Shareholders' Rights Agreement: Incorporated by reference to
Exhibit 2 of the Company's Current Report on Form 8-K dated
July 7, 1997.
10.1 Amended and Restated Credit Agreement by and among Evergreen
Resources, Inc. and Hibernia National Bank, Banque Paribas and
Chase Bank of Texas, N.A., dated July 1, 1998: Incorporated by
reference to Exhibit 10.1 to the Company's Annual Report on Form
10-K for the fiscal year ended December 31, 1998.
10.2 Firm Transportation Service Agreement Rate Schedule TF-1 between
Colorado Interstate Gas Company and Primero Gas Marketing
Company, Dated August 22, 1997: Incorporated by reference to
Exhibit 10.2 of the Company's Registration Statement on Form S-3
filed on November 21, 1997, Commission File No. 333-40817.
10.3 Deeds of Variation between The Secretary of State for Trade and
Industry and Evergreen Resources (UK) Limited dated January 9,
1997: Incorporated by reference to Exhibit 10.6 of the Company's
Registration Statement on Form S-3 filed on November 21, 1997,
Commission File No. 333-40817.
10.4 Evergreen Resources, Inc. Initial Stock Option Plan: Incorporated
by reference to the exhibit accompanying the Company's Definitive
Proxy Statement on Schedule 14A filed on April 20, 1998.
10.5 Firm Transportation Service Agreement Rate Schedule TF-1 between
Colorado Interstate Gas Company and Consolidated Industrial
Services, Inc., dated March 20, 1997: Incorporated by reference
to Exhibit 10.5 to the Company's Annual Report on Form 10-K for
the fiscal year ended December 31, 1998.
10.6 Firm Transportation Service Agreement Rate Schedule TF-1 between
Colorado Interstate Gas Company and Amoco Energy Trading
corporation, dated November 1, 1997: Incorporated by reference to
Exhibit 10.6 to the Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 1998.
21.0 Subsidiaries of registrant: Incorporated by reference to
Note 1 of the Notes to Consolidated Financial Statements
included herein.
22.0 Reserve Audit Reports prepared by Netherland Sewell &
Associates, Inc. and Resource Services International, Inc.
23.0 Consent of Independent Certified Public Accountants
24.1 Power of Attorney: contained on signature page.
27.0 Financial Data Schedule.
(b) No reports on Form 8-K were filed by the Company during the last
quarter of the fiscal year ended December 31, 1999.
33
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
EVERGREEN RESOURCES, INC.
Date: March 29, 2000 By: /s/ Mark S. Sexton
----------------------
Mark S. Sexton
President and Chief Executive Officer
(Principal Executive Officer)
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature
appears below constitutes and appoints Mark S. Sexton and Kevin R. Collins, and
each of them, as true and lawful attorneys-in-fact and agents, with full power
of substitution and resubstitution for him and in his name, place and stead, in
any and all capacities, to sign any and all amendments to this report, and to
file the same, with all exhibits thereto, and other documents in connection
therewith, with the Securities and Exchange Commission, granting unto said
attorneys-in-fact and agents, and each of them, full power and authority to do
and perform each and every act and thing requisite and necessary to be done in
and about the premises, as fully to all intents and purposes as he might or
could do in person, hereby ratifying and confirming all which said
attorneys-in-fact and agents or any of them, or their or his substitute or
substitutes, may lawfully do or cause to be done by virtue hereof.
34
<PAGE>
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the date indicated.
Date: March 29, 2000 /s/ Mark S. Sexton
-----------------------------
Mark S. Sexton
President, Chief Executive Officer and Director
(Principal Executive Officer)
Date: March 29, 2000 /s/ Kevin R. Collins
-----------------------------
Kevin R. Collins, Vice President - Finance
CFO and Treasurer
(Principal Financial and Accounting Officer)
Date: March 29, 2000 /s/ Alain Blanchard
-----------------------------
Alain Blanchard, Director
Date: March 29, 2000 /s/ Dennis R. Carlton
-----------------------------
Dennis R. Carlton, Director
Date: March 29, 2000 /s/ Larry D. Estridge
-----------------------------
Larry D. Estridge, Director
Date: March 29, 2000 /s/ John J. Ryan III
-----------------------------
John J. Ryan III, Director
Date: March 29, 2000 /s/ Scott D. Sheffield
-----------------------------
Scott D. Sheffield, Director
35
<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 years in the period ended December
31, 1999 in conformity with generally accepted accounting principles.
BDO SEIDMAN, LLP
Denver, Colorado
February 11, 2000
F-1
<PAGE>
EVERGREEN RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
December 31,
--------------------------------
1999 1998
---- ----
(IN THOUSANDS)
<S> <C> <C>
ASSETS
Current:
Cash and cash equivalents $ 651 $ 1,334
Accounts receivable (Note 2) 5,021 4,728
Other current assets 749 295
-------- --------
Total current assets 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 199,179 147,176
Less accumulated depreciation, depletion and amortization 24,845 19,400
-------- --------
Net property and equipment 174,334 127,776
Designated cash (Note 6) 2,313 2,782
Other assets (Notes 1 and 15) 1,301 2,711
-------- --------
$184,369 $139,626
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 3,659 $ 1,240
Amounts payable to oil and gas property owners 1,424 2,947
Accrued expenses and other 1,400 1,515
Current portion - capital lease (Note 5) -- 1,123
-------- --------
Total current liabilities 6,483 6,825
Production taxes payable (Note 6) 2,313 2,782
Note payable (Note 4) 15,500 44,139
Obligations under capital lease, less current portion (Note 5) -- 2,906
Deferred income taxes (Note 7) 6,563 3,295
-------- --------
Total liabilities 30,859 59,947
Commitments and contingencies (Notes 3, 4 and 13)
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 14,621 and 11,143 146 111
Additional paid-in capital 147,326 78,380
Retained earnings 6,205 1,078
Accumulated other comprehensive income (loss) (167) 110
--------- --------
Total stockholders' equity 153,510 79,679
--------- --------
$184,369 $139,626
========= ========
</TABLE>
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
F-2
<PAGE>
EVERGREEN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
Years Ended December 31,
1999 1998 1997
---------- --------- ---------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C>
Revenues:
Natural gas revenues (Note 11) $ 22,721 $ 19,063 $ 12,138
Interest and other 207 178 136
---------- --------- ---------
Total revenues 22,928 19,241 12,274
---------- --------- ---------
Expenses:
Lease operating expense 4,697 2,481 1,433
Production taxes 694 876 574
Depreciation, depletion and amortization 4,757 3,860 2,794
General and administrative expenses 3,024 1,933 1,286
Interest expense 1,927 1,870 777
Other 175 286 259
---------- --------- ---------
Total expenses 15,274 11,306 7,123
---------- --------- ---------
Income from continuing operations before income taxes 7,654 7,935 5,151
Income tax provision - deferred (Note 7) 2,979 3,062 --
---------- --------- ---------
Income from continuing operations 4,675 4,873 5,151
Discontinued Operations (Notes 1 and 15)
Gain on disposal of discontinued operations, net 452 -- --
Equity in earnings of discontinued operations, net -- 339 313
---------- --------- ---------
Net income 5,127 5,212 5,464
Preferred stock dividends (Notes 8 and 9) -- -- 400
---------- --------- ---------
Net income attributable to common stock $ 5,127 $ 5,212 $ 5,064
========== ========= =========
BASIC INCOME PER COMMON SHARE:
From continuing operations $ 0.36 $ 0.47 $ 0.50
From discontinued operations 0.03 0.03 0.03
---------- --------- ---------
Basic income per common share $ 0.39 $ 0.50 $ 0.53
========== ========= =========
DILUTED INCOME PER COMMON SHARE:
From continuing operations $ 0.34 $ 0.44 $ 0.48
From discontinued operations 0.03 0.03 0.03
---------- --------- ---------
Diluted income per common share $ 0.37 $ 0.47 $ 0.51
========== ========= =========
</TABLE>
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
F-3
<PAGE>
EVERGREEN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
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 (Note 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
====== ====== ======== ======= ============== ==========
</TABLE>
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
F-4
<PAGE>
EVERGREEN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
<TABLE>
<CAPTION>
Years Ended December 31,
1999 1998 1997
---------- ----------- ----------
Operating activities: (in thousands)
<S> <C> <C> <C>
Net income $ 5,127 $ 5,212 $ 5,464
Adjustments to reconcile net income to cash
provided by operating activities:
Depreciation, depletion and amortization 4,757 3,860 2,794
Deferred income taxes 2,979 3,062 --
Gain on disposal of discontinued operations, net (452) -- --
Equity in earnings of discontinued operations, net -- (339) (313)
Non Cash Compensation 545 225 159
Other 170 502 25
Changes in operating assets and liabilities:
Accounts receivable (293) (1,118) (1,121)
Other current assets (527) 105 (208)
Accounts payable (187) 691 (422)
Accrued expenses and other 612 (53) 79
---------- ----------- ----------
Net cash provided by operating activities 12,731 12,147 6,457
---------- ----------- ----------
Investing activities:
Investment in property and equipment (43,243) (46,959) (18,603)
Purchase of subsidiary (Note 3) (2,500) -- --
Proceeds from sale of investment 2,258 -- --
Designated cash 468 (639) (650)
Change in production taxes payable (468) 639 650
Change in other assets (379) (243) (656)
---------- ----------- ----------
Net cash used in investing activities (43,864) (47,202) (19,259)
---------- ----------- ----------
Financing activities:
Net proceeds from (payments on) notes payable (28,639) 33,327 11,189
Principal payments on capital lease obligations (4,029) (1,061) (637)
Proceeds from issuance of common stock, net 66,448 2,158 349
Common stock buyback (1,709) -- --
Dividends paid on preferred stock -- -- (400)
Debt issue costs (77) (143) (148)
Change in cash held from operating oil and gas properties (1,523) (21) 1,900
---------- ----------- ----------
Net cash provided by financing activities 30,471 34,260 12,253
---------- ----------- ----------
Effect of exchange rate changes on cash (21) 26 12
---------- ----------- ----------
Decrease in cash and cash equivalents (683) (769) (537)
Cash and cash equivalents, beginning of year 1,334 2,103 2,640
---------- ----------- ----------
Cash and cash equivalents, end of year $ 651 $ 1,334 $ 2,103
========== =========== ==========
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
</TABLE>
F-5
<PAGE>
EVERGREEN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
<TABLE>
<CAPTION>
Years Ended December 31,
1999 1998 1997
---------- ----------- ----------
(in thousands)
<S> <C> <C> <C>
Net income $ 5,127 $ 5,212 $ 5,464
Foreign currency translation adjustments (277) (124) 135
---------- ----------- ----------
Comprehensive income $ 4,850 $ 5,088 $ 5,599
========== =========== ==========
</TABLE>
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
F-6
<PAGE>
EVERGREEN RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(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 located on
approximately 207,000 gross acres in the Raton Basin in southern Colorado. The
Company also holds exploration licenses on approximately 513,000 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).
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 $1,845,000,
$711,000 and $542,000 of internal costs in 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
F-7
<PAGE>
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 December 31, 1999.
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.
F-8
<PAGE>
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.
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.
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.
F-9
<PAGE>
RECLASSIFICATIONS
Certain items included in prior years' financial statements have been
reclassified to conform to current year presentation.
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.
(2) ACCOUNTS RECEIVABLE
The components of accounts receivable include the following:
<TABLE>
<CAPTION>
December 31,
---------------------------
1999 1998
---- ----
(IN THOUSANDS)
<S> <C> <C>
Natural gas sales $ 3,921 $ 3,365
Joint interest billings 1,100 1,363
--------- ---------
$ 5,021 $ 4,728
========= =========
</TABLE>
(3) PROPERTY AND EQUIPMENT
Property and equipment includes the following:
<TABLE>
<CAPTION>
December 31,
---------------------------
1999 1998
---- ----
(IN THOUSANDS)
<S> <C> <C>
Oil and Gas Properties:
Proved oil and gas properties $ 103,659 $ 79,303
Unevaluated properties not subject to amortization 31,748 25,567
Accumulated depreciation, depletion and amortization (19,312) (16,348)
---------- ----------
Net oil and gas properties 116,095 88,522
---------- ----------
Gas gathering equipment 46,201 31,365
Construction in progress 6,090 9,227
Support equipment 11,481 1,714
Accumulated depreciation and amortization (5,533) (3,052)
---------- ----------
Net other property and equipment 58,239 39,254
---------- ----------
Property and equipment, net of accumulated
depreciation, depletion and amortization $ 174,334 $ 127,776
========== ==========
</TABLE>
F-10
<PAGE>
Oil and gas property costs of $31,748,000 were not being amortized at
December 31, 1999. These costs 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 of Evergreen
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 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
a review of the property components and 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 (the "licenses"). In
connection with such conversion, 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. is approximately
513,000 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. Work commitments for acreage retained will include the drilling of
five wells in 2000. Evergreen plans to drill approximately 5 conventional
coal bed methane wells starting in late April 2000 and 7 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 over the next two years is approximately $120,000.
During 1999, the Company completed a proprietary 2D seismic program in
Chile. The data is being processed and interpreted. Upon completion, Evergreen
will notify the Ministry of Mining as to its intent to proceed to the next
exploration period which involves the drilling of an exploratory well on each
block.
Included in construction in progress at December 31, 1999, are costs
for a new compressor station, gas gathering laterals and costs for well
equipment. The Company estimates that it will spend approximately $3 million to
complete these projects.
F-11
<PAGE>
(4) FINANCING AGREEMENT
The Company currently has a $75 million revolving line of credit with a
bank group consisting of Hibernia National Bank, as agent, Chase Bank of Texas
and Paribas (the "Banks"). The line is available through June 2001. Advances
pursuant to this line of credit are limited to a borrowing base, which is
presently $75 million. At the Company's election, it may use either the London
Interbank Offered Rate 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. The borrowing base is
redetermined semi-annually by the Banks based upon reserve evaluations of the
Company's oil and gas properties. The current borrowing base is less than the
total borrowing base that could have been requested under the terms of the
agreement. An average annual facility fee of .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 and ratio requirements. The
average interest rate (including the facility fee charged on the unused portion
of the credit line) on the revolving line-of-credit during the year ended
December 31, 1999 was approximately 8.5%. At December 31, 1999 and 1998,
$15,500,000 and $44,139,000 were outstanding under the line of credit. The
Company was in compliance with all loan covenants at December 31, 1999.
(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
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.
F-12
<PAGE>
(7) INCOME TAXES
The provision for income taxes consisted of the following:
<TABLE>
<CAPTION>
Years Ended December 31,
DEFERRED 1999 1998 1997
---------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Federal $ 2,830 $ 2,839 $ --
State 438 440 --
---------- --------- ----------
$ 3,268 $ 3,279 $ --
========== ========= ==========
Income tax for continuing operations $ 2,979 $ 3,062 $ --
Income tax for discontinued operations 289 217 --
---------- --------- ----------
Total income tax expense $ 3,268 $ 3,279 $ --
========== ========= ==========
</TABLE>
A reconciliation between the income tax provision computed at the
statutory rate on income before taxes and the income tax provision is
as follows:
<TABLE>
<CAPTION>
Years Ended December 31,
1999 1998 1997
---------- -------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Federal income tax provision at statutory rate
$ 2,854 $ 2,887 $ 1,858
State income taxes 277 280 180
Reduction in valuation allowance -- (1,788)
Other 137 112 (250)
---------- --------- ----------
Total income tax expense $ 3,268 $ 3,279 $ --
========== ========= ==========
</TABLE>
The components of the net deferred tax assets and liabilities are shown below:
<TABLE>
<CAPTION>
December 31,
------------------
1999 1998
---- ----
(IN THOUSANDS)
<S> <C> <C>
Net operating loss carryforwards $ 8,361 $ 10,392
Percentage depletion carryforwards 1,303 3,454
Other 296 252
---------- -----------
Net deferred tax assets 9,960 14,098
Deferred tax liability- depreciation, depletion and amortization
(16,523) (17,393)
---------- -----------
Net deferred tax liability $ (6,563) $ (3,295)
========== ===========
</TABLE>
As of December 31, 1999, the Company has net operating loss
carryforwards for tax purposes of approximately $22 million which
expire beginning in 2004 through 2019.
F-13
<PAGE>
(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.
(9) STOCKHOLDERS' EQUITY
EARNINGS PER SHARE
The following table sets forth the computation of basic and diluted earnings per
share:
<TABLE>
<CAPTION>
(IN THOUSANDS EXCEPT PER SHARE DATA) 1999 1998 1997
----------------- ------------------ -------------------
Weighted Per- Weighted Per- Weighted Per-
Income Shares Share Income Shares Share Income Shares Share
------ -------- ------ ------- -------- ------ ------ -------- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Basic income per common share
Net income from continuing
operations $4,675 12,953 $ 4,873 10,522 $5,151 9,575
Preferred Stock Dividends -- -- -- -- (400) --
------ ------ ------ ------- ------ ------ -----
Basic income per share from
continuing operations 4,675 12,953 $ 0.36 4,873 10,522 $ 0.47 4,751 9,575 $ 0.50
====== ====== =====
Discontinued Operations, net 452 12,953 0.03 339 10,522 0.03 313 9,575 0.03
------ ====== ------ ------- ====== ------ ------ ===== ------
$5,127 12,953 $ 0.39 $ 5,212 10,522 $ 0.50 $5,064 9,575 $ 0.53
====== ====== ====== ======= ====== ====== ====== ===== ======
Diluted income per common share
Net income from continuing
operations $4,675 12,953 $ 4,873 10,522 $5,151 9,575
Stock Options -- 680 -- 647 -- 335
8% Convertible Preferred Stock -- -- -- -- -- 755
------ ------ ------ ------- ------ ------ ------ -----
Diluted income per share from
continuing operations 4,675 13,633 $ 0.34 4,873 11,169 $ 0.44 5,151 10,665 $ 0.48
====== ====== ======
Discontinued Operations, net 452 13,633 0.03 339 11,169 0.03 313 10,665 0.03
------ ====== ------ ------- ====== ------ ------ ====== ------
$5,127 13,633 $ 0.37 $ 5,212 11,169 $ 0.47 $5,464 10,655 $ 0.51
====== ====== ====== ======= ====== ====== ====== ===== ======
</TABLE>
For the years ended December 31, 1999, 1998 and 1997 all common stock
equivalents were included in the computation of diluted earnings per share.
STOCK ISSUED FOR SERVICES
During the years ended December 31, 1999 and 1997, the Company issued
common stock valued at $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.
F-14
<PAGE>
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.
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 remainder of the proceeds were used for
general corporate purposes. The Company plans to use any additional proceeds
from possible sales of securities for general corporate purposes, which could
include debt repayment, working capital, capital expenditures or acquisitions.
SHAREHOLDERS 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.
F-15
<PAGE>
(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 February 11, 2000, 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.
During 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
$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>
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-average assumptions used for grants in the year ended
December 31, 1997: dividend yield at 0 percent; expected volatility of
approximately 45 percent; risk free interest rate of 6 percent; 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 percent; expected volatility
of approximately 58 percent; risk free interest rate of 5.6% and expected lives
of five years for the warrants and options. Assumptions used for the year ending
December 31, 1999: dividend yield at 0 percent; expected volatility of
approximately 43 percent; risk free interest rate of 4.5% and expected lives of
five and ten years for the warrants and options.
F-16
<PAGE>
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>
Years Ended December 31,
1999 1998 1997
---------------- --------------- ----------------
(in thousands, except per share data)
As reported Pro forma As reported Pro forma As reported Pro forma
----------- --------- ----------- --------- ----------- ---------
<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 December 31, 1999:
<TABLE>
<CAPTION>
Outstanding Exercisable
- ------------------- ------------------------------------------------------ ------------- -----------------
Number Weighted Average Weighted Number Weighted
Range of Exercise Outstanding Remaining Average Exercisable Average
Prices at 12/31/99 Contractual Life Exercise 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>
F-17
<PAGE>
(11) MAJOR CUSTOMERS
During 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>
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 years ended December 31, 1999, 1998 and 1997, for
interest was approximately $2,194,000, $2,317,000, and $817,000. During the
years ended December 31, 1999 and 1998, approximately $351,000 and $448,000 of
interest paid was capitalized.
See Notes 3, 8, 9 and 10 for additional non-cash transactions during
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
Company committed to transport 41 MMcf per day through CIG's pipelines. 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.
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. The total transportation commitments are 12
MMcf per day, with 6 MMcf per day expiring in 2004 and 6 MMcf per day expiring
2012.
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
Year 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>
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 $268,000, $234,000, and $138,000, for the years ended December 31,
1999, 1998 and 1997.
F-18
<PAGE>
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
Year ending December 31, Lease 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 years ended December 31, 1999, 1998 and 1997 were approximately $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 has issued
letters of credit totaling $1.5 million which expire 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 under the citizen suit provision of the Clean Water
Act in the U.S. District Court for the District of Colorado against EOC,
related to its coal bed methane drilling operations in the Raton Basin near
Trinidad, Colorado. The Company's gas production produces naturally occurring
groundwater as a by-product of its coal bed methane gas production
operations. The storage, use, and disposal of the produced groundwater in
evaporative ponds and natural collection features located on the surface at
or near the wellsite, and the legal and regulatory treatment of this
practice, underlie the lawsuit. The Company believes the lawsuit to be
without merit and responded by filing a Motion to Dismiss all Southern
Colorado C.U.R.E.'s alleged claims on substantive grounds. A renewed Motion
to Dismiss is currently pending before the court, although a magistrate to
whom the judge presiding over the matter referred the original Motion to
Dismiss has indicated that she would recommend to the judge that the motion
be denied with respect to certain of the allegations. The resolution of these
issues with the CDPHE, however, should moot any of the claims that remain if
the substantive Motion to Dismiss is denied. The Company does not expect that
the lawsuit or the investigation, or the environmental costs, or contingent
liabilities of either, if any, will have a material adverse effect on its
consolidated financial position or its results of 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 entered into a Consent Order with the CDPHE, that
resolved the water discharge issues between the CDPHE and EOC. Under the
Consent Order, EOC 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
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 and 20,000
MMBtu per day at NYMEX less $0.20 for the period November 1, 2000 through
October 31, 2001. 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.
F-19
<PAGE>
(14) SUBSEQUENT EVENTS
On January 20, 2000, Evergreen acquired additional net mineral
interests in the Raton Basin from a company for 300,955 shares of its common
stock valued at $18.02 per share, or approximately $5.6 million.
(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-20
<PAGE>
(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>
F-21
<PAGE>
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 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 3,724 (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 559,419 404,936 224,414
============== ============== =============
Proved developed reserves 334,804 242,987 143,554
============== ============== =============
</TABLE>
F-22
<PAGE>
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>
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>
F-23
<PAGE>
(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>
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>
(18) SUBSIDIARY GUARANTORS
In May 1999, the Company filed a Shelf Registration Statement with the
Securities and Exchange Commission with an aggregate offering amount of up to
$150 million. The Shelf Registration Statement provided for the offering to the
public from time to time of (a) debt securities of the Company, which may be
wholly and unconditionally guaranteed by certain wholly-owned subsidiaries of
the Company (the "Subsidiary Guarantors"), (b) common stock of the Company, (c)
preferred stock of the Company, (d) depositary shares representing fractional
interests in shares of the Company's preferred stock, (e) warrants to purchase
the Company's debt securities, preferred stock or common stock and/or (f)
subscription rights to purchase any of the foregoing securities. The Company has
not issued any debt securities under the Shelf Registration Statement. However,
because of the potential for a guarantee of debt securities by the Subsidiary
Guarantors, the Company has presented the following condensed consolidating
financial data with respect to (i) the Company on a stand-alone basis, (ii) the
Subsidiary Guarantors as a group, (iii) the non-guarantor subsidiaries of the
Company as a group, (iv) elimination entries for purposes of consolidation and
(v) the Company and all of its subsidiaries combined. The Company has not
presented separate financial statements for each of the Subsidiary Guarantors
because it believes that such information is not material to potential
investors. All significant intercompany balances and transactions have been
eliminated in consolidation. The Subsidiary Guarantors are not subject to any
restrictions on their ability to pay dividends to the Company.
F-24
<PAGE>
EVERGREEN RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
Consolidating Balance Sheets
December 31, 1999
<TABLE>
<CAPTION>
Combined Combined
ASSETS Parent Guarantor Non-Guarantor
Company Subsidiaries Subsidiaries Eliminations Consolidated
------- ------------ ------------ ------------ ------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Current:
Cash and cash equivalents $ 760 $ (133) $ 24 $ -- $ 651
Accounts receivable 374 4,269 378 -- 5,021
Other current assets 424 315 10 -- 749
------- -------- -------- -------- --------
TOTAL CURRENT ASSETS 1,558 4,451 412 -- 6,421
------- -------- -------- -------- --------
Property and equipment 126,618 61,227 11,334 -- 199,179
Less accumulated depreciation, depletion and 19,881 4,934 30 -- 24,845
amortization ------- -------- -------- -------- -------
NET PROPERTY AND EQUIPMENT 106,737 56,293 11,304 -- 174,334
------- -------- -------- -------- -------
Designated cash -- 2,313 -- -- 2,313
Investment in subsidiaries 11,680 5,094 -- (16,774) --
Other assets 1,237 10 54 -- 1,301
Intercompany 56,152 (44,942) (11,210) -- --
------- -------- -------- -------- -------
$ 177,364 $ 23,219 $ 560 $ (16,774) $ 184,369
======= ======== ======== ======== =======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 1,925 $ 1,486 $ 248 $ -- $ 3,659
Amounts payable to oil and gas property owners -- 1,424 -- -- 1,424
Accrued expenses and other 819 581 -- -- 1,400
Current portion - capital leases -- -- -- -- --
------- -------- -------- -------- --------
TOTAL CURRENT LIABILITIES 2,744 3,491 248 -- 6,483
Production taxes payable -- 2,313 -- -- 2,313
Notes payable 15,500 -- -- -- 15,500
Obligations under capital leases -- -- -- -- --
Other -- -- -- -- --
Deferred income tax liability 5,443 798 322 -- 6,563
------- -------- -------- -------- --------
TOTAL LIABILITIES 23,687 6,602 570 -- 30,859
------- -------- -------- -------- --------
Stockholders' equity:
Common stock 146 100 -- (100) 146
Partnership capital -- 10,190 -- (10,190) --
Additional paid-in capital 147,326 -- -- -- 147,326
Retained earnings 6,205 6,327 157 (6,484) 6,205
Accumulated other comprehensive loss -- -- (167) -- (167)
------- -------- -------- -------- --------
TOTAL STOCKHOLDERS' EQUITY(DEFICIT) 153,677 16,617 (10) (16,774) 153,510
------- -------- -------- -------- --------
$ 177,364 $ 23,219 $ 560 $ (16,774) $ 184,369
======= ======== ======== ======== ========
</TABLE>
F-25
<PAGE>
Consolidating Balance Sheets
December 31, 1998
<TABLE>
<CAPTION>
Combined Combined
ASSETS Parent Guarantor Non-Guarantor
Company Subsidiaries Subsidiaries Eliminations Consolidated
------- ------------ ------------ ------------ ------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Current:
Cash and cash equivalents $ 1,200 $ 124 $ 10 $ -- $ 1,334
Accounts receivable 392 4,287 49 -- 4,728
Other current assets 290 3 2 -- 295
--------- --------- --------- --------- ---------
TOTAL CURRENT ASSETS 1,882 4,414 61 -- 6,357
--------- --------- --------- --------- ---------
Property and equipment 96,239 41,033 9,904 -- 147,176
Less accumulated depreciation, depletion and 16,724 2,676 -- -- 19,400
amortization
--------- --------- --------- --------- ---------
NET PROPERTY AND EQUIPMENT 79,515 38,357 9,904 -- 127,776
--------- --------- --------- --------- ---------
Designated cash -- 2,782 -- -- 2,782
Investment in subsidiaries 10,285 5,094 -- (15,379) --
Other assets 2,437 274 -- -- 2,711
Intercompany 32,122 (21,968) (10,154) -- --
--------- --------- --------- --------- ---------
$ 126,241 $ 28,953 $ (189) $ (15,379) $ 139,626
========= ========= ========= ========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 190 $ 1,028 $ 22 $ -- $ 1,240
Amounts payable to oil and gas property owners -- 2,947 -- -- 2,947
Accrued expenses and other 1,364 151 -- -- 1,515
Current portion - capital leases -- 1,123 -- -- 1,123
--------- --------- --------- --------- ---------
Total current liabilities 1,554 5,249 22 -- 6,825
Production taxes payable -- 2,782 -- -- 2,782
Notes payable 42,400 1,739 -- -- 44,139
Obligations under capital leases -- 2,906 -- -- 2,906
Deferred income tax liability 2,718 577 -- -- 3,295
--------- --------- --------- --------- ---------
TOTAL LIABILITIES 46,672 13,253 22 -- 59,947
--------- --------- --------- --------- ---------
Stockholders' equity:
Common stock 111 100 -- (100) 111
Partnership capital -- 10,190 -- (10,190) --
Additional paid-in capital 78,380 -- -- -- 78,380
Retained earnings 1,078 5,410 (321) (5,089) 1,078
Accumulated other comprehensive income -- -- 110 -- 110
--------- --------- --------- --------- ---------
TOTAL STOCKHOLDERS' EQUITY (DEFICIT) 79,569 15,700 (211) (15,379) 79,679
--------- --------- --------- --------- ---------
$ 126,241 $ 28,953 $ (189) $ (15,379) $ 139,626
========= ========= ========= ========= =========
</TABLE>
F-26
<PAGE>
Consolidating Statements of Income
Year Ended December 31, 1999
<TABLE>
<CAPTION>
Combined
Combined Non-
Parent Guarantor Guarantor
Company Subsidiaries Subsidiaries Eliminations Consolidated
------- ------------ ------------ ------------ ------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Revenues:
Natural gas revenues $17,722 $ 4,921 $ 78 $ -- $22,721
Oil and gas services -- 4,965 143 (5,108) --
Interest and other 591 100 1,000 (1,484) 207
-------- -------- -------- -------- --------
Total revenues 18,313 9,986 1,221 (6,592) 22,928
-------- -------- -------- -------- --------
Expenses:
Lease operating expenses 3,448 1,339 4 (94) 4,697
Production taxes 694 -- -- -- 694
Cost of oil and gas services 1,191 1,231 171 (2,593) --
Depreciation, depletion and amortization 3,158 1,950 30 (381) 4,757
General and administrative expenses 2,366 2,147 216 (1,705) 3,024
Interest expense and other 828 1,604 -- (329) 2,103
-------- -------- -------- -------- --------
Total expenses 11,685 8,271 421 (5,102) 15,275
-------- -------- -------- -------- --------
Income from continuing operations
before income taxes 6,628 1,715 800 (1,490) 7,654
Income tax provision - deferred 1,859 798 322 -- 2,979
-------- -------- -------- -------- --------
Income from continuing operations 4,769 917 478 (1,490) 4,675
Discontinued operations
Gain from disposal of discontinued operations, 452 -- -- -- 452
net
Equity in undistributed income of subsidiaries 1,395 -- -- (1,395) --
-------- -------- -------- -------- --------
Net income $ 6,616 $ 917 $ 478 $(2,885) $ 5,127
======== ======== ======== ======== ========
</TABLE>
F-27
<PAGE>
Consolidating Statements of Income
Year Ended December 31, 1998
<TABLE>
<CAPTION>
Combined
Combined Non-
Parent Guarantor Guarantor
Company Subsidiaries Subsidiaries Eliminations Consolidated
------- ------------ ------------ ------------ ------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Revenues:
Natural gas revenues $15,471 $ 3,592 $ -- $ -- $19,063
Oil and gas services -- 1,738 -- (1,738) --
Interest and other 62 114 -- 2 178
------- ------- ------- ------- -------
Total revenues 15,533 5,444 -- (1,736) 19,241
------- ------- ------- ------- -------
Expenses:
Lease operating expenses 1,776 705 -- -- 2,481
Production taxes 876 -- -- -- 876
Cost of oil and gas services 718 358 -- (1,076) --
Depreciation, depletion and amortization 2,818 1,042 -- -- 3,860
General and administrative expenses 1,976 580 30 (653) 1,933
Interest expense 911 1,245 -- -- 2,156
------- ------- ------- ------- -------
Total expenses 9,075 3,930 30 (1,729) 11,306
------- ------- ------- ------- -------
Income from continuing operations
before income taxes 6,458 1,514 (30) (7) 7,935
Income tax provision - deferred 2,485 577 -- -- 3,062
------- ------- ------- ------- -------
Income from continuing operations 3,973 937 (30) (7) 4,873
Discontinued operations
Equity in earnings of discontinued operations, 339 -- -- -- 339
net
Equity in undistributed income of subsidiaries 907 -- -- (907) --
------- ------- ------- ------- -------
Net income $ 5,219 $ 937 $ (30) $ (914) $ 5,212
======= ======= ======= ======= =======
</TABLE>
F-28
<PAGE>
Consolidating Statements of Income
Year Ended December 31, 1997
<TABLE>
<CAPTION>
Combined
Combined Non-
Parent Guarantor Guarantor
Company Subsidiaries Subsidiaries Eliminations Consolidated
------- ------------ ------------ ------------ ------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Revenues:
Natural gas revenues $ 8,969 $ 3,169 $ -- $ -- $ 12,138
Oil and gas services -- 1,129 -- (1,129) --
Interest and other 667 125 -- (656) 136
-------- -------- -------- -------- --------
Total revenues 9,636 4,423 -- (1,785) 12,274
-------- -------- -------- -------- --------
Expenses:
Lease operating expenses 1,311 471 -- (349) 1,433
Production taxes 574 -- -- -- 574
Cost of oil and gas services -- 842 -- (842) --
Depreciation, depletion and amortization 1,952 842 -- -- 2,794
General and administrative expenses 1,792 82 6 (594) 1,286
Interest and other expense 314 722 -- -- 1,036
-------- -------- -------- -------- --------
Total expenses 5,943 2,959 6 (1,785) 7,123
-------- -------- -------- -------- --------
Income from continuing operations
before income taxes 3,693 1,464 (6) -- 5,151
Income tax provision - deferred -- -- -- -- --
-------- -------- -------- -------- --------
Income from continuing operations 3,693 1,464 (6) -- 5,151
Discontinued operations
Equity in earnings of discontinued operations, 313 -- -- -- 313
net
Preferred Stock Dividend (400) -- -- -- (400)
Equity in undistributed income of subsidiaries 1,458 -- -- (1,458) --
-------- -------- -------- -------- --------
Net income $ 5,064 $ 1,464 $ (6) $ (1,458) $ 5,064
======== ======== ======== ======== ========
</TABLE>
F-29
<PAGE>
Consolidating Statements of Cash Flows
Year Ended December 31, 1999
<TABLE>
<CAPTION>
Combined
Combined Non-
Parent Guarantor Guarantor
Company Subsidiaries Subsidiaries Eliminations Consolidated
---------- ------------ ------------ ------------ ------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Cash flows from operating activities:
Net income $ 5,127 $ 917 $ 478 $ (1,395) $ 5,127
Adjustments to reconcile net income to cash
provided by operating activities:
Equity in undistributed income of subsidiaries (1,395) -- -- 1,395 --
Depreciation, depletion and amortization 3,096 1,631 30 -- 4,757
Deferred income taxes 1,859 798 322 -- 2,979
Gain on disposal of discontinued operations, net (452) -- -- -- (452)
Non-cash compensation 545 -- -- -- 545
Other 170 -- -- -- 170
Changes in operating assets and liabilities:
Accounts receivable 20 18 (331) -- (293)
Other current assets (208) (311) (8) -- (527)
Accounts payable 134 (548) 227 -- (187)
Accrued expenses 182 430 -- -- 612
-------- -------- ------- ------- --------
NET CASH PROVIDED BY OPERATING ACTIVITIES 9,078 2,935 718 -- 12,731
-------- -------- ------- ------- --------
Cash flows from investing activities:
Intercompany (advances) proceeds (23,284) 22,385 899 -- --
Investment in property and equipment (23,275) (18,440) (1,528) -- (43,243)
Purchase of subsidiary (2,500) -- -- -- (2,500)
Proceeds from the sale of investment 2,258 -- -- -- 2,258
Designated cash -- 468 -- -- 468
Change in production taxes payable -- (468) -- -- (468)
Decrease (Increase) in other assets (481) 156 (54) -- (379)
-------- -------- ------- ------- --------
NET CASH PROVIDED (USED) BY INVESTING ACTIVITIES (47,282) 4,101 (683) -- (43,864)
-------- -------- ------- ------- --------
Cash flows from financing activities:
Payments on notes payable (26,900) (1,739) -- -- (28,639)
Proceeds from sale of common stock, net 66,448 -- -- -- 66,448
Common stock buyback (1,709) -- -- -- (1,709)
Principal payments on capital lease obligations -- (4,029) -- -- (4,029)
Debt issue costs (75) (2) -- -- (77)
Cash held from operating oil and gas properties -- (1,523) -- -- (1,523)
-------- -------- ------- ------- --------
NET CASH PROVIDED (USED) BY FINANCING ACTIVITIES 37,764 (7,293) -- -- 30,471
-------- -------- ------- ------- --------
Effect of exchange rate changes on cash -- -- (21) -- (21)
-------- -------- ------- ------- --------
Increase in cash and cash equivalents (440) (257) 14 -- (683)
Cash and cash equivalents, beginning of the period 1,200 124 10 -- 1,334
-------- -------- ------- ------- --------
Cash and cash equivalents, end of the period $ 760 $ (133) $ 24 $ -- $ 651
======== ======== ======= ======= ========
</TABLE>
F-30
<PAGE>
Consolidating Statements of Cash Flows
Year Ended December 31, 1998
<TABLE>
<CAPTION>
Combined
Combined Non-
Parent Guarantor Guarantor
Company Subsidiaries Subsidiaries Eliminations Consolidated
------- ------------ ------------ ------------ ------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Cash flows from operating activities:
Net income $ 5,212 $ 937 $ (30) $ (907) $ 5,212
Adjustments to reconcile net income to cash
provided by operating activities:
Equity in undistributed income of subsidiaries (907) -- -- 907 --
Depreciation, depletion and amortization 2,818 1,042 -- -- 3,860
Deferred income taxes 2,485 577 -- -- 3,062
Equity in earnings of discontinued operations, net (339) -- -- -- (339)
Non-cash compensation 225 -- -- -- 225
Other 502 -- -- -- 502
Changes in operating assets and liabilities:
Accounts receivable 1,440 (2,514) (44) -- (1,118)
Other current assets 77 25 3 -- 105
Accounts payable 116 577 (2) -- 691
Accrued expenses (43) (10) -- -- (53)
-------- ------- ------- ------- -------
NET CASH PROVIDED (USED) BY OPERATING ACTIVITIES 11,586 634 (73) -- 12,147
-------- ------- ------- ------- -------
Cash flows from investing activities:
Intercompany (advances) proceeds (17,983) 16,279 1,704 -- --
Investment in property and equipment (26,235) (19,074) (1,650) -- (46,959)
Designated cash -- (639) -- -- (639)
Change in production taxes payable -- 639 -- -- 639
Increase in other assets (198) (45) -- -- (243)
-------- ------- ------- ------- -------
NET CASH PROVIDED (USED) BY INVESTING ACTIVITIES (44,416) (2,840) 54 -- (47,202)
-------- ------- ------- ------- -------
Cash flows from financing activities:
Net proceeds from notes payable 31,588 1,739 -- -- 33,327
Proceeds from sale of common stock, net 2,158 -- -- -- 2,158
Principal payments on capital lease obligations -- (1,061) -- -- (1,061)
Debt issue costs (135) (8) -- -- (143)
Cash held from operating oil and gas properties -- (21) -- -- (21)
-------- ------- ------- ------- -------
NET CASH PROVIDED BY FINANCING ACTIVITIES 33,611 649 -- -- 34,260
-------- ------- ------- ------- -------
Effect of exchange rate changes on cash -- -- 26 -- 26
-------- ------- ------- ------- -------
Increase in cash and cash equivalents 781 (1,557) 7 -- (769)
Cash and cash equivalents, beginning of the period 419 1,681 3 -- 2,103
-------- ------- ------- ------- -------
Cash and cash equivalents, end of the period $ 1,200 $ 124 $ 10 $ -- $ 1,334
======== ======= ======= ======= =======
</TABLE>
F-31
<PAGE>
Consolidating Statements of Cash Flows
Year Ended December 31, 1997
<TABLE>
<CAPTION>
Combined
Combined Non-
Parent Guarantor Guarantor
Company Subsidiaries Subsidiaries Eliminations Consolidated
-------- ----------- ------------ ------------ ------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Cash flows from operating activities:
Net income $ 5,464 $ 1,464 $ (6) $ (1,458) $ 5,464
Adjustments to reconcile net income to cash
provided by operating activities:
Equity in undistributed income of subsidiaries (1,458) -- -- 1,458 --
Depreciation, depletion and amortization 1,952 842 -- -- 2,794
Deferred income taxes -- -- -- -- --
Equity in earnings of discontinued operations, net (313) -- -- -- (313)
Non-cash compensation 159 -- -- -- 159
Other -- 25 -- -- 25
Changes in operating assets and liabilities:
Accounts receivable (717) (403) (1) -- (1,121)
Other current assets (775) 570 (3) -- (208)
Accounts payable 23 (460) 15 -- (422)
Accrued expenses 128 (49) -- -- 79
-------- -------- -------- ------- ---------
NET CASH PROVIDED BY OPERATING ACTIVITIES 4,463 1,989 5 -- 6,457
-------- -------- -------- ------- ---------
Cash flows from investing activities:
Intercompany (advances) proceeds (6,071) 5,685 386 -- --
Investment in property and equipment (9,721) (8,615) (267) -- (18,603)
Designated cash -- (650) -- -- (650)
Change in production taxes payable -- 650 -- -- 650
Increase in other assets (511) (4) (141) -- (656)
-------- -------- -------- ------- ---------
NET CASH USED BY INVESTING ACTIVITIES (16,303) (2,934) (22) -- (19,259)
-------- -------- -------- ------- ---------
Cash flows from financing activities:
Net proceeds from notes payable 11,189 -- -- -- 11,189
Proceeds from sale of common stock, net 349 -- -- -- 349
Payment on preferred stock dividends (400) -- -- -- (400)
Principal payments on capital lease obligations -- (637) -- -- (637)
Debt issue costs (141) (7) -- -- (148)
Cash held from operating oil and gas properties -- 1,900 -- -- 1,900
-------- -------- -------- ------- ---------
NET CASH PROVIDED BY FINANCING ACTIVITIES 10,997 1,256 -- -- 12,253
-------- -------- -------- ------- ---------
Effect of exchange rate changes on cash -- -- 12 -- 12
-------- -------- -------- ------- ---------
Increase in cash and cash equivalents (843) 311 (5) -- (537)
Cash and cash equivalents, beginning of the period 1,262 1,370 8 -- 2,640
-------- -------- -------- ------- ---------
Cash and cash equivalents, end of the period $ 419 $ 1,681 $ 3 $ -- $ 2,103
======== ======== ======== ======= =========
</TABLE>
F-32
<PAGE>
[LETTERHEAD]
February 10, 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 December 31, 1999, 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
December 31, 1999, 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 0.0 334,804.2 519,986.8 250,079.6
Proved Undeveloped 0.0 224,614.1 300,996.3 81,303.7
-------- --------- --------------- -------------
Total Proved(1) 0.0 559,418.4 820,983.0 331,383.3
</TABLE>
(1) Totals may not add due to computer 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 December 31, 1999 net reserve and future net
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.
<PAGE>
[LOGO]
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 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 the actual price received in
December 1999 and is held constant in accordance with SEC guidelines.
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, but do not include overhead expenses above the field level. Evergreen
used direct lease and field level costs of $1,075 per well per month and a
gathering fee of $0.07 per MCF. Headquarters general and administrative overhead
expenses of Evergreen are not included. Lease and well operating costs are held
constant in accordance with SEC guidelines. 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 do not own an interest in
these properties and are not employed on a contingent basis.
Very truly yours,
/s/ Frederic D. Sewell
DDS:PJA
<PAGE>
February 4, 2000
[LETTERHEAD]
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 December 31, 1999. 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 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.
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.
<PAGE>
Evergreen Resources, Inc.
February 4, 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
<PAGE>
Evergreen Resources, Inc.
February 4, 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 December 31, 1999
follow:
<TABLE>
<CAPTION>
NATURAL GAS
-----------
MMCF
<S> <C>
Total Proved Developed Producing Reserves 311,407
Total Proved Developed Non-Producing Reserves 23,397
Total Proved Undeveloped Reserves 224,614
-------
TOTAL PROVED RESERVES 559,418
=======
</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.
<PAGE>
Evergreen Resources, Inc.
February 4, 2000
Page 4
Estimated future net revenue and net present value of future net revenue from
proved natural gas, as of December 31, 1999 follow:
<TABLE>
<CAPTION>
10% DISC.
FUTURE NET FUTURE NET
REVENUE M$ REVENUE MS
<S> <C> <C>
Total Proved Developed Producing Reserves 488,250 239,732
Total Proved Developed Non-Producing Reserves 31,737 10,347
Total Proved Undeveloped Reserves 300,996 81,304
------- -------
TOTAL PROVED RESERVES 820,983 331,383
======= =======
</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,
/s/ RESOURCE SERVICES INTERNATIONAL, INC.
RESOURCE SERVICES INTERNATIONAL, INC.
<PAGE>
EXHIBIT 23.0
CONSENT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
Evergreen Resources, Inc.
1401 17th Street, Suite 1200
Denver, Colorado 80202
We hereby consent to the incorporation by reference in the registration
statement of Evergreen Resources, Inc. on Form S-3 (File Nos. 333-78203 and
333-89617) of our report dated February 11, 2000 on our audits of the
consolidated financial statements and financial statement schedules of
Evergreen Resources, Inc. as of December 31, 1999 and 1998 and for each of
the three years in the period ended December 31, 1999, which report is
included in this Annual Report on Form 10-K.
/s/ BDO Seidman, LLP
- ----------------------------------
BDO Seidman, LLP
Denver, Colorado
March 29, 2000
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<RESTATED>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
<CASH> 651
<SECURITIES> 0
<RECEIVABLES> 5,021
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 749
<PP&E> 199,179
<DEPRECIATION> 24,845
<TOTAL-ASSETS> 184,369
<CURRENT-LIABILITIES> 6,483
<BONDS> 15,500
0
0
<COMMON> 146
<OTHER-SE> 153,364
<TOTAL-LIABILITY-AND-EQUITY> 184,369
<SALES> 22,721
<TOTAL-REVENUES> 22,928
<CGS> 10,148
<TOTAL-COSTS> 13,172
<OTHER-EXPENSES> 175
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 1927
<INCOME-PRETAX> 7,654
<INCOME-TAX> 2,979
<INCOME-CONTINUING> 4,675
<DISCONTINUED> 452
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 5,127
<EPS-BASIC> .39
<EPS-DILUTED> .37
</TABLE>
