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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K/A
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
ACT OF 1934
For The Fiscal Year Ended December 31, 1997
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 0-10077
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.)
1000 WRITER SQUARE
1512 LARIMER STREET
DENVER, COLORADO 80202
(Address of principal executive offices) (Zip Code)
(303) 534-0400
(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 17, 1998, the Registrant had 10,455,385 common shares
outstanding, and the aggregate market value of the common shares held by
non-affiliates was approximately $110,112,000 based upon the closing price of
$14.88 per share for the common stock on March 17, 1998 reported by NASDAQ.
DOCUMENTS INCORPORATED BY REFERENCE: DEFINITIVE PROXY MATERIALS FOR 1998 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 . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Item 3. Legal Proceedings. . . . . . . . . . . . . . . . . . . . . . . 20
Item 4. Submission of Matters to a Vote of
Security Holders. . . . . . . . . . . . . . . . . . . . . 21
PART II
Item 5. Market for Registrant's Common Equity
and Related Stockholder Matters . . . . . . . . . . . . . 21
Item 6. Selected Financial Data. . . . . . . . . . . . . . . . . . . . 22
Item 7. Management's Discussion and Analysis of
Financial Condition and Results
of Operations . . . . . . . . . . . . . . . . . . . . . . 23
Item 8. Financial Statements and Supplementary Data. . . . . . . . . . 29
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure. . . . . . . . . . 29
PART III
Item 10. Directors and Executive Officers of the
Registrant. . . . . . . . . . . . . . . . . . . . . . . . 29
Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . 29
Item 12. Security Ownership of Certain Beneficial
Owners and Management . . . . . . . . . . . . . . . . . . 29
Item 13. Certain Relationships and Related Transactions . . . . . . . . 29
PART IV
Item 14. Exhibits, Consolidated Financial Statement Schedules
and Reports on Form 8-K . . . . . . . . . . . . . . . . . 30
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .31-32
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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,
"Bcfe" means billion cubic feet equivalent, "MMcfe" means million cubic feet
equivalent, and "MMBtu" means million British thermal units.
AVERAGE FINDING COST. The average amount of total capital expenditures,
including acquisition cost, 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 production 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, operation and acquisition of
oil and gas properties. The Company's current operations are principally
focused on developing and expanding its coalbed methane project located in the
Raton Basin in southern Colorado. Evergreen also holds exploration licenses
onshore in the United Kingdom, a net 2% interest in a consortium exploring
offshore in the Falkland Islands, and an oil and gas exploration license on
approximately 2.4 million acres in northern Chile.
Evergreen maintains its principal executive offices at Suite 1000, 1512
Larimer Street, Denver, Colorado 80202, and its telephone number is (303)
534-0400. Effective May 1, 1998, the Company will relocate its principal
executive offices to 1401 17th Street, Suite 1200, Denver, CO 80202. Also
effective May 1, 1998, the new telephone number will be (303) 298-8100.
The authorized capitalization of the Company is 50,000,000 shares of no par
value common stock of which 10,395,266 shares were issued and outstanding at
December 31, 1997. Evergreen has an authorized capital of 25,000,000 shares of
$1.00 par value Preferred Stock, none of which were issued and outstanding at
December 31, 1997.
Effective with the period ended December 31, 1996, the Company elected to
begin utilizing a December 31 fiscal year end. Therefore, the period ended
December 31, 1996 represents a nine-month short period as compared to the twelve
month fiscal years ended December 31, 1997 and March 31, 1996.
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 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, and/or changes in general
economic conditions. Actual results could materially differ and could be
adversely affected by the information set forth under the headings "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
"Business and Properties." In light of these risks and uncertainties, 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 coalbed 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 129,000 gross acres. In addition, the Company's daily
gas sales represent approximately 61% of the gas currently sold from the Raton
Basin. Evergreen currently has 95 producing gas wells on its Raton Basin
properties and four exploratory wells which are subject to further evaluation.
The Company has identified approximately 560 drilling locations on its Raton
Basin acreage, of which 150 were included in the Company's proved reserve base
at December 31, 1997. These 150 proven locations comprise approximately 27% of
the Company's total acreage in the Raton Basin. Evergreen intends to spend
approximately $80 million over the next three years on the further development
of the Raton Basin, including drilling approximately 210 wells and expanding and
upgrading its gathering and compression facilities.
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At December 31, 1997, Evergreen had estimated net proved reserves of 224
Bcfe with a PV-10 of approximately $159.3 million. Natural gas constituted all
of Evergreen's estimated net proved reserves, all of which were located in the
Raton Basin and 64% of which were developed. Evergreen has a 100% working
interest in its Raton Basin acreage and wells, and also owns the gathering
systems and related equipment associated with these wells. The Company acts as
operator for all of its Raton Basin properties, as well as for certain third
party producing properties.
Since the completion of a pipeline from the Raton Basin and the
corresponding commencement of Company gas sales in early 1995, the Company has
achieved substantial growth in reserves and production. Evergreen's estimated
net proved reserves have increased from approximately 63 Bcfe at March 31, 1995
to 224 Bcfe at December 31, 1997. Over this period, the number of producing
wells and average gross daily production increased from 9 wells and 1.5 MMcf to
95 wells and 30 MMcf, respectively. Since inception of the Company's drilling
efforts in the Raton Basin, the Company has drilled and tested a total of 95
producing wells and achieved a 98% success rate.
Evergreen believes that it has gained significant experience in coalbed
methane exploration and development, including the utilization of enhanced
drilling, completion and production techniques developed over a number of years.
This experience has enabled the Company to increase per well production and to
achieve low finding and development costs. From inception of its Raton Basin
project through December 31, 1997, the Company has spent approximately $50.1
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 $.22 per
Mcfe.
In addition, the Company's lease operating expenses ("LOE") and general and
administrative costs per Mcfe have declined steadily since Raton Basin gas sales
began in early 1995. For the year ended December 31, 1995, Evergreen's LOE and
general and administrative costs were $0.88 per Mcfe and $0.94 per Mcfe,
respectively, as compared to $0.31 per Mcfe and $0.19 per Mcfe, respectively,
for the year ended December 31, 1997.
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 coals; however, Evergreen believes that the Raton
formation coal seams may be profitably exploited as well.
Approximately 106,000 acres of the Company's 129,000 gross acres in the
Raton Basin have been included in two 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 371,000 acres
onshore in the United Kingdom. The Company believes that there are potential
opportunities to develop coalbed methane reserves within these license areas.
To date, Evergreen has spent approximately $7.5 million on this project and is
holding discussions with potential industry partners for the purpose of further
evaluating and developing the licensed areas. Evergreen will be required to pay
$1.2 million over the next three years to maintain these licenses.
FALKLAND ISLANDS. Evergreen has a net 2% interest in a consortium that has
been awarded an exploration license for an offshore area north of the Falkland
Islands. A subsidiary of Amerada Hess Corporation is the operator of the
consortium, which includes Fina Exploration Atlantic BV, Murphy South Atlantic
Oil Company and Teikoku Oil Co. Ltd. The license covers 626 square miles in
water depths ranging up to 1,575 feet. The first test well of this project is
scheduled to be drilled in May 1998. The Company expects to spend approximately
$1.4 million on this project over the next three years.
CHILE. In March 1997, the Government of Chile awarded an oil and gas
exploration license to Evergreen on two 5,000 square kilometer (approximately
1.2 million acre) 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-owned energy company, holds the remaining 25%
working interest. Evergreen expects to engage in surface, geologic mapping,
ground based magnetic and gravity surveys and conduct a proprietary 2D seismic
program over the next three years at an aggregate cost to the Company of
approximately $1.8 million.
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BUSINESS STRATEGY
Evergreen's objective is to increase reserves, production, cash flow,
earnings and net asset value per share. To accomplish this objective, Evergreen
intends to utilize its competitive strengths, which include (i) its experience
and operating expertise in coalbed methane properties, (ii) its significant
acreage position in the Raton Basin, (iii) its position as a low-cost finder,
developer and producer of natural gas and (iv) the potential of its
international projects.
In order to implement its strategy, Evergreen will seek to:
- ACCELERATE DEVELOPMENT OF THE RATON BASIN. Since commencement of the
Company's drilling program in 1993, the Company has drilled a total of
102 wells in the Raton Basin. Of this total, 95 are currently in
production, and 4 are exploratory and subject to further evaluation.
The Company plans to drill approximately 50 wells in 1998. During
1999 and 2000, the Company plans to drill approximately 160 wells and
expand its gathering and compression facilities. The Company's
capital budget for this three year drilling and expansion program is
approximately $80 million. The expansion program will be funded by
cash flow from operations and available borrowings under the Company's
$30.0 million credit facility.
- MAINTAIN CONTROL OF OPERATIONS. The Company acts as operator for all
of its producing properties within the Raton Basin, and controls all
phases of drilling, completion and well stimulation. The Company also
constructs and operates all of its gas gathering systems, which have
been specifically designed to optimize production from coalbed methane
wells. By operating its producing properties, Evergreen believes it
has greater control over its expenses and the timing of exploration
and development of such properties. The Company is also the
designated operator for its United Kingdom and Chilean projects, and
operates certain third party producing properties.
- IMPROVE AND EXPAND GAS MARKETING CAPABILITIES IN THE RATON BASIN.
Evergreen's natural gas sales from the Raton Basin commenced upon the
completion of a pipeline system in January 1995, which connected the
Company's gathering system to the Colorado Interstate Gas Co. ("CIG")
pipelines. In August 1997, Evergreen entered into an agreement with
CIG pursuant to which CIG will construct a new, 115-mile, 16-inch
pipeline from Trinidad, Colorado to Campo, Colorado. When completed,
this new pipeline will have initial capacity of up to 100 MMcf per day
and may be further expanded through the use of additional compression
facilities.
- PURSUE INTERNATIONAL OPPORTUNITIES. The Company seeks to identify
attractive international oil and gas projects that require relatively
small capital investments but which have potential for favorable
returns. Since 1992, the Company has obtained onshore exploration
licenses covering approximately 371,000 acres in the United Kingdom, a
net 2% interest in a consortium exploring offshore in the Falkland
Islands and an oil and gas exploration license on approximately
2.4 million acres in northern Chile. The Company expects to spend
approximately $5 million over the next three years for the development
of its international projects. Evergreen will seek additional
partners to help minimize the Company's upfront capital requirements
and other costs associated with development of these projects.
- ACQUIRE ADDITIONAL PROPERTY INTERESTS. In August 1996, Evergreen
acquired the remaining 25% working interest in its Raton Basin lease
holdings (representing approximately 37 Bcf of estimated net proved
reserves) at an average acquisition cost of approximately $0.30 per
Mcf. The Company expects that it will continue to evaluate and make
acquisitions of oil and gas properties located in its principal areas
of operation and in other areas that provide attractive investment
opportunities, particularly where the Company can add value through
its technical expertise.
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 and working interest partners. Primero also operates the
Company's gathering system and purchases all the Company's production from its
Raton Basin wells.
The expanding production in the Raton Basin led 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
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near Trinidad, Colorado to its mainline compressor station at Campo, Colorado
(the "Campo Lateral"). When completed, the Campo Lateral will have initial
capacity of up to approximately 100 MMcf per day, which will more than double
the pipeline capacity currently available from the Raton Basin. The pipeline
capacity may be further expanded through the use of additional compression
facilities. The Campo Lateral is expected to be completed by August 1998. 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. The Company has committed to transport natural
gas from the Raton Basin through this new pipeline commencing on or about
August 1998. The initial commitment is 25 MMcf per day, increasing every six
months to 41 MMcf per day, 18 months after the commencement. Subject to
available capacity in the pipeline, the Company has the first right to increase
its volumes up to 100 MMcf per day. Evergreen believes that the CIG agreement
will expand the range of customers to which it can market its gas, thereby
potentially increasing the prices Evergreen will receive for its gas. 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.
In November 1996, Evergreen entered into an agreement with CIG which
provided firm transportation for 10 MMcf per day of the Company's Raton Basin
gas from the field to the CIG interconnection with other interstate pipelines in
Texas. Beginning November 1, 1997, the Company obtained the right to firm
transportation for an additional 10 MMcf per day (reserving total firm
transportation of up to 20 MMcf per day). These transportation agreements will
terminate on the in-service date of the Campo Lateral.
MAJOR CUSTOMERS. Evergreen has three major customers, Natural Gas
Transmission Services, Inc., Enserco Energy, Inc. and Aquila Energy Corporation
which purchased approximately 48%, 17% and 17%, respectively, of the Company's
gas production for the year ended December 31, 1997. Based on the general
demand for gas, the loss of one or more of these customers would not be expected
to have a material adverse effect on Evergreen's business. None of the
Company's existing marketing agreements obligates the Company to continue sales
to any particular gas purchaser for a period longer than 12 months. 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 one year or less.
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.
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. 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 all 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
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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
nonprice 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 and
636-C ("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. Although
Order No. 636, assuming it is upheld in its entirety, could provide the Company
with additional market access and more fairly applied transportation service
rates, Order No. 636 could also subject the Company to more restrictive
pipeline imbalance tolerances and greater penalties for violation of those
tolerances. Order 636 and subsequent FERC orders issued in individual pipeline
restructuring proceedings have been the subject of appeals, the results of which
have generally supported the FERC's open-access policy. Last year, the United
States Court of Appeals for the District of Columbia Circuit largely upheld
Order No. 636. Because further review of certain of these orders is still
possible and other appeals remain pending, it is difficult to predict the
ultimate impact of the orders on the Company and its production efforts.
The FERC has announced several important transportation-related policy
statements and proposed rule changes, including the appropriate manner in which
interstate pipelines release capacity under Order No. 636 and, more recently,
the price which shippers can charge for their released capacity. In addition,
in 1995, FERC issued a policy statement on how interstate natural gas pipelines
can recover the costs of new pipeline facilities. In January 1996, the FERC
issued a policy statement and a request for comments concerning alternatives to
its traditional cost-of-service rate making methodology. A number of pipelines
have obtained FERC authorization to charge negotiated rates as one such
alternative. In February 1997, the FERC announced a broad inquiry into issues
facing the natural gas industry to assist the FERC in establishing regulatory
goals and priorities in the post-Order No. 636 environment. While these
changes would affect the Company only indirectly, they are intended to further
enhance competition in the natural gas markets. The Company cannot predict what
action the FERC will take on these matters, nor can it predict whether the
FERC's actions will achieve its stated goal of increasing competition in natural
gas markets. However, the Company does not believe that it will be treated
materially differently than other natural gas producers and markets 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 is not able at this time
to predict the effects of Order Nos. 561 and 561-A, if any, on the
transportation costs associated with oil production. The effects, if any, of
these policies on the Company's operations are uncertain.
The FERC has also recently issued numerous orders confirming the sale and
abandonment of natural gas gathering facilities previously owned by interstate
pipelines and acknowledging that if the FERC does not have jurisdiction over
services provided thereon, then such facilities and services may be subject to
regulation by state authorities in accordance with state law. A number of
states have either enacted new laws or are considering the adequacy of existing
laws affecting gathering rates and/or services. Other state regulation of
gathering facilities generally includes various safety, environmental, and in
some circumstances, nondiscriminatory take requirements, but does not generally
entail rate regulation. Thus, natural gas gathering may receive greater
regulatory scrutiny of state agencies in the future. 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, 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.
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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 or in offshore waters subject to the Outer Continental Shelf Land Act
("OCSLA"), 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"). The MMS
issued a notice of proposed rule making 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. Similar rule making regarding natural gas royalties have also been
considered by the agency, but there is no current proposed rule on this issue
for natural gas. The Company cannot predict what action the MMS will take on
this matter, nor can it predict at this stage of the rule making 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 level. 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 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. To the extent any
of the Company's natural gas gathering facilities are subject to state
regulation, regulation of gathering facilities generally includes various
safety, environmental, and in some circumstances, nondiscriminatory take
requirements, but 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 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 penalties 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
contamination, rendering a person liable for environmental 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
operations, such as closure of inactive pits and plugging of abandoned wells.
Legislation has been proposed in Congress from time to time that would
reclassify certain oil and gas exploration and production wastes as "hazardous
wastes," which would make the reclassified wastes subject to much more stringent
handling, disposal and clean-up requirements. If such legislation were to be
enacted, it could have a significant 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 pending in certain states,
and these various initiatives could have a similar impact on the Company. The
regulatory burden on the oil and natural gas industry increases its cost 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
9
<PAGE>
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 owner or
operator of the disposal site or sites where the release occurred and companies
that disposed or arranged for the 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 damages allegedly caused by the hazardous substances released
into the environment. 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. In addition, the Company generates or has generated in
the past wastes, including hazardous wastes, that are subject to the federal
Resource Conservation and Recovery Act ("RCRA") and comparable state statutes.
The U.S. Environmental Protection Agency and various state agencies have
promulgated regulations that limit the disposal options for certain hazardous
and non-hazardous wastes.
The Company 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 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 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 coalbed methane gas production, the Company from
time to time conducts production enhancement techniques, including various
activities designed to fracture the coalbed formation. 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 U.S. Environmental Protection Agency ("EPA") regulates this coalbed
formation fracturing as a form of underground injection. On August 7, 1997, the
Eleventh Circuit Court of Appeals held, in a case brought by a citizens
environmental organization, that hydraulic fracturing performed in coalbed
methane gas production in Alabama falls within the definition of "underground
injection" as defined in the federal Safe Drinking Water Act and, therefore, 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 EPA's refusal to initiate proceedings that would withdraw federal
approval of Alabama's UIC program. It is not known whether 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 coalbeds 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 will be to other similarly
situated companies involved in coalbed methane gas production or tight gas sands
production within the United States.
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.
At this time, the Company has no plans to make any material capital
expenditures for environmental control facilities.
10
<PAGE>
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 17, 1998, the Company had 43 full time employees.
CERTAIN RISKS
VOLATILITY OF OIL AND GAS PRICES. The Company's revenues, operating
results, profitability, future rate of growth and the carrying value of its oil
and gas properties are substantially dependent upon prevailing market prices for
oil and gas. Historically, the markets for oil and gas have been volatile and
in certain periods have been depressed by excess domestic and imported supplies.
Such volatility is expected to recur in the future. Various factors beyond the
control of the Company 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, the level of consumer
demand, the price, availability and acceptance of alternative fuels, the
availability of pipeline capacity, and weather conditions. In addition to
market factors, actions of state and local agencies and the United States and
foreign governments affect oil and gas prices. These external factors and the
volatile nature of the energy markets make it difficult to estimate future
prices of oil and gas. 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. Such decline could reduce the Company's cash flow
and borrowing capacity and both the value and the amount of the Company's gas
reserves.
In order to reduce its exposure to short-term fluctuations in the price of
natural gas, the Company enters into hedging arrangements from time to time.
The Company's hedging arrangements apply to only a portion of its production and
provide only partial price protection against declines in natural gas prices.
In addition, the Company's hedging arrangements limit the benefit to the Company
of increases in the price of natural gas. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Hedging
Transactions."
SUBSTANTIAL CAPITAL REQUIREMENTS. The Company's current development plans
will require it to make substantial capital expenditures in connection with the
exploration and development of its natural gas properties. Also, exploration
and development of the Company's international projects is dependent upon the
Company securing the necessary capital. Historically, the Company has funded
its capital expenditures through a combination of funds generated internally
from sales of production or properties, equity contributions, long-term debt
financing and short-term financing arrangements. The Company currently does not
have any arrangements with respect to, or sources of, additional financing other
than the Company's existing $30 million credit facility (the "Credit Facility")
and equipment leases, both with Hibernia National Bank. There can be no
assurance that any additional financing will be available to the Company on
acceptable terms or at all. Future cash flows and the availability of financing
will be subject to a number of variables, such as the level of production from
existing wells, prices of oil and natural gas, the Company's success in locating
and producing new reserves and the success of its coalbed methane project in the
Raton Basin. To the extent that future financing requirements are satisfied
through the issuance of equity securities, the Company's existing shareholders
may experience dilution that could be substantial. The incurrence of debt
financing could result in a substantial portion of the Company's operating cash
flow being dedicated to the payment of principal and interest on such
indebtedness, could render the Company more vulnerable to competitive pressures
and economic downturns and could impose restrictions on the Company's
operations. If revenue were to decrease as a result of lower oil and natural
gas prices, decreased production or otherwise, and the Company had no
availability under the Credit Facility or any other credit facility, the
Company's ability to execute its development plans, replace its reserves or
maintain production levels could be materially limited.
11
<PAGE>
UNCERTAINTY OF RESERVE INFORMATION AND FUTURE NET REVENUE ESTIMATES. There
are numerous uncertainties inherent in estimating quantities of proved oil and
natural gas reserves and their values, including many factors beyond the
Company's control. Estimates of proved undeveloped which comprise a significant
portion of the Company's reserves, are by their nature uncertain. The reserve
information set forth in this Form 10-K represents estimates only. Although the
Company believes such estimates to be reasonable, reserve estimates are
imprecise and may materially change as additional information becomes available.
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 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.
PV-10, as referred to in this Form 10-K, should not be construed as the
current market value of the estimated oil and natural gas reserves attributable
to the Company's properties. In accordance with applicable regulations, the
estimated discounted future net cash flows from proved reserves are based on
prices and costs as of the date of the estimate, whereas actual future prices
and costs may be materially higher or lower. Actual future net cash flows also
will be affected by factors such as 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 actual future net cash flows from proved reserves, and thus their
actual present value, will be affected by the timing of both the production and
the incidence of expenses in connection with development and production of oil
and natural gas properties. In addition, the 10% discount factor, which is
required to be used to calculate PV-10 for reporting purposes, is not
necessarily the most appropriate discount factor based on interest rates in
effect from time to time and risks associated with the Company or the oil and
natural gas industry in general.
SPECULATIVE NATURE OF OIL AND GAS EXPLORATION. The business of exploring
for and, to a lesser extent, of developing oil and gas properties is an
inherently speculative 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 with respect to
the potential of an oil or gas 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 the Company's investment therein. A variety of factors, both
geological and market-related, can cause a well to become uneconomic or
marginally economic.
OPERATING HAZARDS. The oil and natural gas business involves certain
operating hazards such as well blowouts, craterings, explosions, uncontrollable
flows of oil, natural gas or well fluids, fires, formations with abnormal
pressures, pipeline ruptures or spills, pollution, releases of toxic gas and
other environmental hazards and risks, any of which could result in substantial
losses to the Company. The availability of a ready market for the Company's
natural gas production also depends on the proximity of reserves to, and the
capacity of, natural gas gathering systems and pipelines. The Company delivers
natural gas through gas pipelines that it does not own. Federal and state
regulation of natural gas and oil production and transportation, tax and energy
policies, changes in supply and demand and general economic conditions all could
adversely affect the Company's ability to produce and market its oil and natural
gas. In addition, the Company may be liable for environmental damage caused by
previous owners of property purchased or leased by the Company. As a result,
substantial liabilities to third parties or governmental entities may be
incurred, the payment of which could reduce or eliminate the funds available for
exploration, development or acquisitions or result in losses to the Company. In
accordance with customary industry practices, the Company maintains insurance
against some, but not all, of such risks and losses. The Company carries
business interruption insurance in varying amounts based upon the estimated time
to cause the covered facilities to become operational. The Company may elect to
self-insure if management believes that the cost of insurance, although
available, is excessive relative to the risks
12
<PAGE>
presented. The occurrence of an event that is not covered, or not fully
covered, by insurance could have a material adverse effect on the Company's
financial condition and results of operations. In addition, pollution and
environmental risks generally are not fully insurable.
DEPENDENCE UPON EXPANSION AND DEVELOPMENT OF THE RATON BASIN. The
Company's future success presently depends upon its ability to find, develop or
acquire additional oil and natural gas reserves in the Raton Basin that are
economically recoverable. All of the Company's proved reserves are in the Raton
Basin and due to development plans the Company's future growth is highly
dependent on increasing production and reserves in the Raton Basin. The proved
reserves of the Company will generally decline as reserves are depleted, except
to the extent that the Company conducts successful exploration or development
activities or acquires properties containing proved reserves. At December 31,
1997, the Company had proved undeveloped reserves of approximately 81 Bcfe,
which constituted approximately 36% of the Company's total proved reserves. The
Company's current development plan includes increasing its reserve base through
continued drilling and development of its existing properties in the Raton
Basin. There can be no assurance, however, that the Company's planned
development projects in the Raton Basin will result in significant additional
reserves or that the Company will have continuing success drilling productive
wells at anticipated finding and development costs.
DEPENDENCE ON GATHERING AND TRANSPORTATION FACILITIES. Substantially all
of the Company's current production consists of natural gas. The marketability
of the Company's gas production depends in part upon the availability, proximity
and capacity of gas gathering systems, pipelines and processing facilities.
Federal and state regulation of gas and oil production and transportation,
general economic conditions, changes in supply and changes in demand all could
adversely affect the Company's ability to produce, gather and transport its
natural gas. If market factors were to change materially, the financial impact
on the Company could be substantial. The Company is a party to gas
transportation contracts that require the Company to transport minimum volumes.
If the Company ships smaller volumes, it may be liable for damages proportional
to the shortfall. The Company expects to meet its volume obligations with
respect to the Raton Basin transportation agreement. While the Company believes
that its production in the Raton Basin will be more than adequate to meet volume
requirements, 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 the transportation contracts.
RISKS OF INTERNATIONAL OPERATIONS. Evergreen holds exploration licenses
onshore in the United Kingdom and in northern Chile, and an interest in a
consortium exploring offshore in the Falkland Islands. International operations
are subject to political, economic and other uncertainties, including, among
others, risk of war, revolution, border disputes, expropriation, re-negotiation
or modification of existing contracts, import, export and transportation
regulations and tariffs, taxation policies, including royalty and tax increases
and retroactive tax claims, exchange controls, limits on allowable levels of
production, currency fluctuations, labor disputes and other uncertainties
arising out of foreign government sovereignty over the Company's international
operations.
NO DIVIDENDS. The Company has never declared or paid any cash dividends to
the holders of Common Stock and has no present intention to pay cash dividends
to such holders in the foreseeable future.
CERTAIN ANTI-TAKEOVER MATTERS. The Company's Articles of Incorporation and
Bylaws contain provisions that may have the effect of delaying, deferring or
preventing a change in control of the Company. These provisions, among other
things, provide for noncumulative voting in the election of the Board of
Directors and impose certain procedural requirements on shareholders of the
Company who wish to make nominations for the election of directors or propose
other actions at shareholders' meetings. In addition, 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 of Directors
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 of the Company, including transactions
that otherwise could involve payment of a premium over prevailing market prices
to holders of Common Stock
On July 7, 1997 the Board of Directors adopted a Shareholder Rights
Agreement ("Rights Plan"), pursuant to which uncertificated stock purchase
rights were distributed to its common shareholders at a rate of one Right for
each share of Common Stock held of record as of July 22, 1997. The Rights Plan
is designed to enhance the Board's ability to prevent an acquirer from depriving
shareholders of the long-term value of their investment and to protect
shareholders against attempts to acquire the Company by means of unfair or
abusive takeover tactics. However, the existence of the Rights Plan may impede
a takeover of the Company not supported by the Board of Directors, including
13
<PAGE>
a takeover which may be desired by a majority of the Company's shareholders
or involving a premium over the prevailing stock price.
SOUTHERN UTE INDIAN TRIBE V. AMOCO PRODUCTION COMPANY LITIGATION. The
Company extracts coalbed methane from properties to which it owns or leases oil
and gas rights, but recently, the Court of Appeals for the Tenth Circuit has
held that coalbed methane rights for certain lands derive from coal rights
rather than oil and gas rights. On July 16, 1997 the Tenth Circuit in SOUTHERN
UTE INDIAN TRIBE V. AMOCO PRODUCTION COMPANY ("SOUTHERN UTE V. AMOCO") held that
coal reserved to the United States under the Coal Lands Acts of 1909 and 1910
(the "Coal Lands Acts") included coalbed gas. Under the Coal Lands Acts, the
federal government granted title to certain lands to private land holders but
reserved coal rights for the federal government. The rights transferred to
private parties included oil and gas rights. Federal coal rights were in some
cases later transferred to third parties such as the Southern Ute Indian Tribe.
Under a 1981 opinion of the Solicitor for the Department of the Interior,
coalbed methane was excluded from the definition of coal in the Coal Lands Acts
and included under the definition of gas encompassed by oil and gas rights. The
Tenth Circuit has now held that coalbed methane rights are actually part of the
coal rights reserved for the federal government in the Coal Lands Acts.
The Company has drilled 102 coalbed methane gas wells in Las Animas County,
41 of which were drilled on 40 acre drill sites where the (federal) Bureau of
Land Management ("BLM") holds coal rights. The Company either owns or leases
the oil and gas rights to these lands. Although no adverse claims concerning
ownership of coalbed methane on Company's lands have been asserted, if the
holding in SOUTHERN UTE V. AMOCO stands, the BLM may claim to hold the coalbed
methane rights to these lands rather than the Company. Thus, the Company may
have to negotiate to purchase or lease rights to the coalbed methane from the
BLM at some cost to the Company. The additional cost of purchasing or leasing
such rights could have a material adverse impact on the Company's financial
condition and results of operations.
The Company is not a party to SOUTHERN UTE V. AMOCO, nor are any of the
Company's lands subject to that litigation. Any holding in SOUTHERN UTE V.
AMOCO will not automatically change property rights to the Company's lands and
additional litigation may be required as a result of circumstances which may be
unique to the Company's lands as compared to the lands at issue in SOUTHERN UTE
V. AMOCO. Development of coalbed methane on Company lands has progressed with
the full knowledge (and approval) of the BLM. Much of the Company's lands lie
within federal units created for the development of coalbed methane on lands
covered by the Coal Lands Acts. These federal units were subject to and
received the approval of the BLM for coalbed methane development.
The Tenth Circuit has granted a petition by Amoco Production Company
("Amoco") for a rehearing EN BANC OF SOUTHERN UTE V. AMOCO on the issue of
whether "coal" as used in the Coal Lands Acts unambiguously excludes or includes
coalbed methane. If Amoco is ultimately successful, coalbed methane rights will
again be considered part of oil and gas rights and not coal rights to land
covered by the Coal Lands Acts, and the Company will not have to negotiate to
purchase or lease coalbed methane rights from the BLM. There can be no
assurance, however, that Amoco will be successful upon rehearing. The Company
believes that if Amoco is unsuccessful upon rehearing, it will appeal to the
U.S. Supreme Court seeking a reversal of the SOUTHERN UTE V. AMOCO holding;
however, there can be no assurance that Amoco would be successful in obtaining
CERTIORARI from the U.S. Supreme Court, or if the U.S. Supreme Court grants
CERTIORARI, whether Amoco would prevail.
ITEM 2. PROPERTIES
OPERATIONS
The Company's wholly-owned subsidiary, Evergreen Operating Corporation
("EOC"), is primarily responsible for drilling, evaluation and production
activities associated with various properties and for negotiating the sales of
oil and gas production from the properties. As of February 28, 1998, EOC was
serving as operator for approximately 200 producing wells owned by the Company
and also by other affiliated and unaffiliated third parties.
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.
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<PAGE>
OIL AND GAS RESERVES
The table below sets forth the Company's quantities of proved reserves, as
estimated by independent petroleum engineers, all of which 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, 1997.
<TABLE>
DECEMBER 31, DECEMBER 31, MARCH 31,
1997 1996 1996
----------- ----------- ----------
<S> <C> <C> <C>
Estimated Proved Gas Reserves 224,413,800 150,719,700 80,926,000
(Mcf)
Estimated Proved Oil Reserves 0 2,600 4,800
(Bbls)
Present Value of Future Net
Revenues (before future
income tax expense) $159,325,900 $70,498,500 $30,163,400
</TABLE>
Reference should be made to Supplemental Oil and Gas Information beginning
on page F-18 of this report for additional information pertaining to the
Company's proved oil and gas reserves. During fiscal 1997 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>
YEAR NINE MONTHS YEAR
ENDED ENDED ENDED
DECEMBER 31, DECEMBER 31, MARCH 31,
1997 1996 1996
------------ ------------ ---------
<S> <C> <C> <C>
Natural Gas (Mcf) 6,401,500 2,104,400 941,200
Crude Oil & Condensate (Bbls) --- --- 9,700
</TABLE>
AVERAGE SALES PRICES AND LOE
The following table sets forth the average sales price and the average LOE
per Mcfe, for the periods indicated.
<TABLE>
YEAR NINE MONTHS YEAR
ENDED ENDED ENDED
DECEMBER 31, DECEMBER 31, MARCH 31,
1997 1996 1996
------------ ------------ ---------
<S> <C> <C> <C>
Average sales price
Natural gas (per Mcf) $1.90 $1.66 $ 1.29
Oil (per Bbl) --- --- 18.40
Average LOE (per Mcfe) $0.31 $0.33 $ 0.65
</TABLE>
PRODUCTIVE WELLS
The following table sets forth, as of December 31, 1997, 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>
PRODUCTIVE WELLS
----------------
OIL GAS
--- ---
Gross Net Gross Net
-------------------------------------------------
<S> <C> <C> <C>
-- -- 89 89
</TABLE>
15
<PAGE>
ACREAGE
At December 31, 1997, Evergreen held developed and undeveloped acreage as
set forth below:
LOCATION
<TABLE>
DEVELOPED ACRES UNDEVELOPED ACRES TOTAL
--------------- -------------------- --------------------
GROSS NET GROSS NET GROSS NET
------ ------ --------- --------- ---------- ---------
<S> <C> <C> <C> <C> <C> <C>
Colorado 23,300 16,800 106,000 88,900 129,300 105,700
United Kingdom -- -- 371,000 371,000 371,000 371,000
Falkland Islands -- -- 400,600 8,000 400,600 8,000
Chile -- -- 2,400,000 1,800,000 2,400,000 1,800,000
------ ------ --------- --------- ---------- ---------
Total 23,300 16,800 3,277,600 2,267,900 3,300,900 2,284,700
------ ------ --------- --------- ---------- ---------
------ ------ --------- --------- ---------- ---------
</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>
ACRES
EXPIRING
GROSS NET
----- -----
<S> <C> <C>
Twelve Months Ended:
December 31, 1998 2,500 2,500
December 31, 1999 4,500 2,400
December 31, 2000 and later 1,100 1,100
</TABLE>
DRILLING ACTIVITIES
The Company's drilling activities for the periods indicated are set forth
below:
<TABLE>
YEAR NINE MONTHS YEAR
ENDED ENDED ENDED
DECEMBER 31 DECEMBER 31 MARCH 31
-----------------------------------------------
1997 1996 1996
---- ---- ----
GROSS NET GROSS NET GROSS NET
----- ---- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C>
Exploratory Wells:
Productive * 4 * 4 0 0 0 0
Dry 0 0 0 0 0 0
----- ---- ----- --- ----- ---
4 4 0 0 0 0
Development Wells:
Productive 56 56 28 28 12 12
Dry 0 0 0 0 0 0
----- ---- ----- --- ----- ---
56 56 28 28 12 12
</TABLE>
* Currently testing
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.
16
<PAGE>
DEVELOPMENT HISTORY AND EXPECTED FUTURE DEVELOPMENT. Exploration for
coalbed methane began in the Raton Basin in the late 1970's and continued
through the late 1980's, 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 129,000 gross acres in the Raton Basin. The initial 70,000 acres
were acquired from Amoco Production Company in 1991 by direct purchase without
overriding royalties. The remainder of the acreage 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 95 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.
Evergreen has been named the operator for both of these units. Formation of a
unit simplifies lease maintenance so that Evergreen, as the operator, can base
development decisions within the unit on technical, geologic and geophysical
data 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 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.
To date, the Company's principal development activities in the Raton Basin
have been in the Spanish Peaks Unit. It currently has 95 producing wells in
this Unit and expects to drill approximately 50 wells in 1998. Currently, all
of the Company's gas production comes from this Unit, which has the gathering
and compression infrastructure necessary to deliver the gas. The Company has
identified approximately 400 drilling locations in its Spanish Peaks Unit, of
which 150 were included in the Company's proved reserve base at December 31,
1997. These identified locations comprise approximately 38% of the Company's
total acreage in the 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 two exploratory wells. These exploratory
wells will test production levels, provide additional geologic control, and also
will fulfill unit obligations. The Company will be required to construct a
compression facility and a gathering facility to enable gas production and sales
from this unit. No reserves from wells in the Sangre de Cristo Unit are
included in the Company's reserve base.
RATON BASIN GEOLOGY. In the Raton Basin, Evergreen produces methane 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 in
combination with 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 coal 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
intrusion
17
<PAGE>
of magma into the Raton Basin have matured the coals and enhanced the ability
of the Vermejo and Raton coals to yield coalbed methane.
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 the beds
is variable. Evergreen is currently completing its wells in the Vermejo coal
beds. Individual wells are often completed to produce gas from five to fifteen
individual coal beds with individual thickness between 1 and 12 feet.
COALBED 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 seams or deposits in coalbeds. Natural gas produced from traditional wells
also contains, in varying amounts, other hydrocarbons. However, the natural gas
produced from coalbeds generally contains only methane, and after simple
dehydration, is pipeline-quality gas.
Coalbed methane production is similar to traditional natural gas production
in terms of the physical producing facilities and the product produced.
However, the subsurface mechanisms that allow the gas to move to the wellbore
and the producing characteristics of coalbed 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 coalbed 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 coalbed 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, coalbeds are partly or completely
saturated with water. As the water is produced, internal pressures on the coal
are released, allowing the gas to desorb from the coal and flow to the wellbore.
Contrary to traditional gas wells, new coalbed 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 coarse 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.
COALBED METHANE TECHNOLOGY. The Company, working in conjunction with its
contractors, has developed what it believes to be effective procedures for
fracing the Vermejo 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." Coalbed
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 has, therefore, used 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 evaporation ponds. If
more brackish water is discovered in subsequent wells, it may be necessary to
install and operate evaporators or drill specialized injection wells to
re-inject the produced water back into the underground rock formations adjacent
to the coal seams or to lower sandstone horizons.
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
18
<PAGE>
pipelines. From January 1995 through December 1997, Evergreen sold an aggregate
of approximately 8.7 Bcf of coalbed methane gas from the Raton Basin. Gross
daily production from the field currently exceeds 30 MMcf per day, for an
average of approximately 320 Mcf per well 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.
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 coalbed methane
gas and conventional hydrocarbons (the "Original Licenses"). The Original
Licenses provided ERUK with the largest onshore acreage position in the United
Kingdom, and covered 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 coalbed 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
"Current Licenses"). In connection with such conversion, the Company
relinquished rights to approximately 259,000 acres, which were not considered
highly prospective for coalbed methane development. Under the Current Licenses,
the Company retains approximately 371,000 acres, which were high-graded for
coalbed methane and conventional hydrocarbon potential. The Current 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 remote sensing studies, additional seismic studies and the drilling of
three wells, one per year beginning in 1999. Work commitments on the Current
Licenses have been fulfilled through 1997 as a result of Evergreen's prior U.K.
activity.
Evergreen believes that a major coalbed 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 such 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.
The Company expects to pay approximately $1.2 million over the next three years
to maintain the Current Licenses.
Evergreen is holding discussions with potential industry partners for the
purpose of evaluating and developing the Current Licenses.
FALKLAND ISLANDS. Evergreen has a net 2% interest in a consortium that has
been awarded an exploration license for an offshore area north of the Falkland
Islands. A subsidiary of Amerada Hess Corporation is the operator of the
consortium, which includes Fina Exploration Atlantic BV, Murphy South Atlantic
Oil Company, Teikoku Oil Co. Ltd. and Argos Evergreen Limited. Argos
Evergreen Limited, a 5% working interest owner in the consortium, is a joint
venture company formed in the Falkland Islands and owned 60% by Argos Resources
Limited and 40% by ERUK. The license covers 626 square miles and lies
approximately 225 miles to the north of the islands in water
19
<PAGE>
depths ranging up to 1,575 feet. This area incorporates part of a major
unexplored sedimentary basin which has not yet been tested by drilling, and
represents an opportunity for the Company to be involved during the early
phase of exploration in an unexplored basin. The Company expects to incur
capital expenditures of approximately $1.4 million over the next three years
in connection with this project.
The first exploratory well is scheduled to be drilled commencing in May
1998 and will be drilled by the consortium of which Evergreen is a member.
CHILE. In March 1997, the Government of Chile awarded an oil and gas
exploration license to Evergreen on two 5,000 square kilometer (approximately
1.2 million acre) blocks in northern Chile. Evergreen has a 75% working
interest in the blocks and will serve as operator. ENAP, the Chilean-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.
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>
EXPLORATION
PERIOD TERM WORK COMMITMENT
----------- ---- ---------------
<S> <C> <C>
* 1 1 year Geologic mapping, land based magnetic and
gravity surveys
2 2 years 200 km seismic data
3 2 years 1 exploratory well
4-9 1 year each 1 exploratory well
</TABLE>
- -------------
* Commenced June, 1997
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.
Evergreen expects that the foregoing activities will require capital
expenditures over the next three years of approximately $1.8 million.
OFFICE AND OPERATIONS FACILITIES
The Company leases its corporate offices in Denver, Colorado. The lease
covers approximately 11,800 square feet and is month-to-month. The current
monthly rental rate is approximately $12,800. 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.
In the Raton Basin, the Company operates a low pressure gathering system
and a three stage compression station with 306,000 feet of steel pipe ranging in
size from three inches to 24 inches. Currently, the compressor station
discharges at a pressure of 750 psi from four 950 horsepower compressors and two
3,000 horsepower compressors. Current maximum throughput is approximately 35
MMcf per day at a maximum pressure of 1,200 psi. The compressor station is
designed for an anticipated maximum throughput of 50 MMcf per day for sales into
CIG's Picketwire Lateral pipeline.
ITEM 3. LEGAL PROCEEDINGS
Except for the Amoco proceedings referenced below, the Company is not
involved in any material pending legal proceedings to which the Company or its
subsidiary is a party or to which any of its property is subject.
AMOCO JUDGMENT
On June 25, 1997, Evergreen filed an action in the Las Animas County,
Colorado District Court seeking a declaratory judgment against Amoco regarding
the proposed sale by Amoco of certain property located in the Raton Basin, Las
Animas County. Included in this property was approximately 22,000 gross
non-producing acres which is located within the Cottontail Pass Federal Unit,
situated near the center of Evergreen's present 129,000 gross acreage position
in the Raton Basin. Evergreen, as a working interest owner in the unit, had a
preferential right under the
20
<PAGE>
applicable unit operating agreement to purchase these 22,000 gross acres for
$3,179,000. Evergreen tendered to Amoco notice of its intention to exercise
this preferential right to purchase. Amoco contended that it did not receive
valid notice of the preferential purchase rights from Evergreen. In its
action, Evergreen sought a declaratory judgment that Evergreen had properly
exercised its preferential right of purchase, and that Amoco was obligated to
sell the properties covered by that right of purchase to Evergreen. On
November 12, 1997, the court granted Evergreen's motion for summary judgment
and ruled that Evergreen properly exercised its right of purchase for the
subject properties. Amoco has appealed this ruling.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
NOT APPLICABLE.
PART II
ITEM 5. MARKET FOR EVERGREEN'S COMMON STOCK AND RELATED SECURITY HOLDER
MATTERS
PRINCIPAL MARKET OR MARKETS
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>
HIGH LOW
------ ------
<S> <C> <C>
Year Ended December 31, 1995
First Quarter $ 6.00 $ 4.00
Second Quarter 5.75 4.00
Third Quarter 5.75 3.88
Fourth Quarter 5.38 3.50
Year Ended December 31, 1996
First Quarter $ 6.13 $ 4.88
Second Quarter 7.38 5.38
Third Quarter 7.25 5.50
Fourth Quarter 8.38 5.50
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
</TABLE>
On March 17, 1998, the last reported sales price for the Common Stock as
reported by the NASDAQ National Market was $14.88 per share. At March 17, 1998,
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
Effective November 1, 1997 an institutional investor converted all 6
million remaining outstanding shares of the Company's 8% Convertible Preferred
Stock, $1.00 par value (the "Preferred Stock"), into 905,660 shares of the
Company's Common Stock at a conversion price of $6.625 per share. The Company
had issued a total of 7.5 million
21
<PAGE>
shares of the Preferred stock for $7.5 million in two private placements of
3.75 million shares each to a small number of institutional investors of
under Section 4(2) of the Securities Act of 1933, as amended, on December 8,
1994 and July 26, 1995. All proceeds of the private placements were used for
development of the Company's oil and gas leases in the Raton Basin. Under
the terms of the Preferred Stock Agreement, the Company had the right to
convert all of the preferred stock into common stock provided the common
stock closing price was not less that $16 per share for 30 consecutive days.
The closing price of the Company's common stock as reported by NASDAQ was
above $16 per share for the 30 consecutive days ending November 1, 1997.
ITEM 6. SELECTED FINANCIAL DATA
The selected consolidated financial information presented below for the
year ended December 31, 1997 and the nine months ended December 31, 1996 and for
each of the years in the three year period ended March 31, 1996, are 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. Certain reclassifications
have been made to prior financial statements to conform with current
presentation.
<TABLE>
NINE MONTHS
ENDED
YEAR ENDED DECEMBER
DECEMBER 31, 31, YEAR ENDED MARCH 31,
------------ ---------- ----------------------------------
1997 1996 1996 1995 1994
----------- ---------- ------- ------- -------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA
Revenues:
Oil and gas production $ 12,138 $ 3,502 $ 1,393 $ 1,916 $ 2,207
Oil and gas services 781 545 779 858 1,103
Equity in earnings of investment 313 - - - -
Interest and dividends 132 143 207 117 238
Other 4 38 556 460 794
-------- ------- ------- ------- -------
Total revenues 13,368 4,228 2,935 3,351 4,342
-------- ------- ------- ------- -------
Expenses:
Lease operating expenses 2,007 701 657 994 1,040
Gas gathering costs 112 110 219 238 219
Cost of oil and gas services 842 621 727 790 929
Depreciation, depletion and amortization 2,794 966 590 709 660
General and administrative 1,225 505 819 850 1,350
Interest 778 193 36 29 -
Other 146 17 (11) 351 100
-------- ------- ------- ------- -------
Total Expenses 7,904 3,113 3,037 3,961 4,298
-------- ------- ------- ------- -------
Net income (loss) 5,464 1,115 (102) (610) 44
Preferred stock dividends 400 440 505 94 -
-------- ------- ------- ------- -------
Net income (loss) attributable to common stock $ 5,064 $ 675 $ (607) $ (704) $ 44
-------- ------- ------- ------- -------
-------- ------- ------- ------- -------
Net income (loss) per common share
Basic $ .53 $ .10 $ (.10) $ (.13) $ .01
-------- ------- ------- ------- -------
-------- ------- ------- ------- -------
Diluted $ .51 $ .10 $ (.10) $ (.13) $ .01
-------- ------- ------- ------- -------
-------- ------- ------- ------- -------
STATEMENT OF CASH FLOWS DATA
Net cash provided by (used in):
Operating activities $ 6,457 $ 1,524 $ 1,130 $ 408 $ 485
Investing activities (19,259) (8,559) (2,764) (2,958) (307)
Financing activities 12,253 5,978 3,329 3,635 241
BALANCE SHEET DATA:
Cash and cash equivalents $ 2,103 $ 2,640 $ 3,703 $ 2,038 $ 930
Total assets 87,306 68,244 44,172 39,140 32,880
Total long term debt 14,841 1,174 191 - -
Redeemable preferred stock - 6,000 7,500 3,750 -
Total stockholders' equity 64,152 52,364 31,589 32,202 30,413
Cash dividends per share - - - - -
</TABLE>
22
<PAGE>
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 PROSPECTUS. 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 and acquisition of oil and gas properties. Evergreen's primary
focus is on developing coalbed methane properties located on approximately
129,000 gross acres in the Raton Basin in southern Colorado. The Company
also holds exploration licenses on approximately 371,000 acres onshore in the
United Kingdom, a net 2% interest in a consortium exploring offshore in the
Falkland Islands, and an oil and gas exploration contract on approximately
2.4 million acres in northern Chile. Evergreen operates all of its own
producing properties and also acts as operator on a contract basis for
properties owned by others.
The following table sets forth certain operating data of the Company for
the periods presented.
<TABLE>
YEAR NINE MONTHS YEAR YEAR
ENDED ENDED ENDED ENDED
DECEMBER 31, DECEMBER 31, MARCH 31, MARCH 31,
1997 1996 1996 1995
------------ ------------ --------- ---------
<S> <C> <C> <C> <C>
PRODUCTION DATA:
Natural gas (Mcf) 6,401,500 2,104,400 941,200 781,700
Oil (Bbls) -- -- 9,700 36,660
Total (Mcfe) 6,401,500 2,104,400 999,400 1,001,300
AVERAGE SALES PRICE PER UNIT:
Natural gas (per Mcf) $1.90 $1.66 $ 1.29 $ 1.67
Oil (per Bbl) -- -- 18.40 15.97
Mcfe 1.90 1.66 1.39 1.91
COST PER MCFE:
Average LOE $ .31 $ .33 $ .65 $ .99
General and administrative .19 .24 .87 .71
Depreciation, depletion and
amortization .44 .46 .59 .85
</TABLE>
LIQUIDITY AND CAPITAL RESOURCES
During the year ended December 31, 1997, the Company demonstrated
consistent growth over prior years in the areas of net income, cash flow and
gas reserves. These increases are due to the continued development of the
Raton Basin project. The Company anticipates drilling 50 new wells,
expanding and upgrading gas gathering facilities in the Raton Basin and
proceeding with international exploration activities through the end of 1998.
Budgeted capital expenditures for this program are approximately $18
million. The Company believes that cash flow from operations and available
borrowings under its Credit Facility will be sufficient to fund the budgeted
1998 capital expenditures.
The Company may be unable to place all 50 wells into production during
1998 due to existing pipeline capacity. During August 1997, in anticipation
of the existing capacity constraints the Company entered into an agreement
with Colorado Interstate Gas ("CIG") pursuant to which CIG will construct 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. The Company has committed to transport natural gas from
the Raton Basin through CIG's pipelines commencing on or about August 1998.
The initial commitment is 25 MMcf per day, increasing every six months to a
maximum of 41 MMcf per day 18 months after commencement. Subject to
available capacity in the pipeline, the Company has the first right to
increase its volumes up to 100 MMcf per day.
23
<PAGE>
Upon completion of the Campo Lateral, the Company anticipates that it
will drill approximately 160 wells during 1999 and 2000 and will spend
approximately $60 million. During these two years, the Company will also
spend approximately $3.8 million on international projects. The Company
believes that through the continued development of the Raton Basin that cash
flow from operations and borrowings under the Credit Facility will be
sufficient to fund the budgeted 1999 and 2000 capital expenditures.
Management believes that it has the ability to increase its existing credit
facilities, and additionally, the Company may use equity financing for
future cash needs.
On November 21, 1997, the Company filed a public offering of 2,750,000
shares of its common stock. Of these shares, 2,000,000 were being offered on
behalf of the Company and 750,000 were being offered on behalf of certain
non-management selling shareholders. The proceeds to the Company of the
offering were to be used to repay debt and fund the further development of
the Company's Raton Basin natural gas properties. On January 8, 1998, the
Company withdrew its registration on file with the Securities and Exchange
Commission due to unfavorable market conditions.
At year end, Evergreen had a $30.0 million revolving Credit Facility
with Hibernia National Bank ("Bank"). The Credit Facility was set to mature
in May 1999. Advances under the Credit Facility are limited to the borrowing
base, which is presently $30.0 million. Interest accrued at prime (8.5% at
December 31, 1997) plus or minus a margin of .25%, with margins determined on
the average outstanding borrowings under the Credit Facility. The borrowing
base is redetermined semi-annually by the Bank based upon reserve evaluations
of the Company's oil and gas properties. The current borrowing base was less
than the total borrowing base that could have been requested under terms of
the agreement. As of December 31, 1997, the Company had $10.8 million of
borrowings under the line.
The Company has a capital equipment lease with the Bank with interest at
prime (8.5% at December 31, 1997). The capital equipment lease has a term of
five years ending April 2002, with an option to purchase the equipment at
nominal amounts at the end of the lease term. The Company primarily leases
compressors for the Raton Basin gas gathering system and other related
production equipment. At December 31, 1997, the Company had approximately
$5.1 million under the capital lease obligations.
Subsequent to year end the Company entered into a commitment letter with
the Bank for a $30.0 million Credit Facility to extend the maturity date to
April 2001 and to reduce the current interest rate. At the Company's
election, the Company 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 .25%, with margins on both rates determined on the average outstanding
borrowings under the Credit Facility. In addition, the Company will have a
$10.0 million equipment line of credit for Primero. Payments will be level
monthly principal payments, plus interest based on 5 year treasuries plus 2%.
The interest rate will be fixed and the principal payments amortized over 5
years at the time of any drawdown. The Company anticipates that the existing
capital lease obligations will be paid off with the equipment line.
Prior to 1998, the Company has not been required to record income tax
expense, primarily due to the availability of net operating loss carryovers.
However, as a result of the recently reported profitability and the
significant difference between the book and tax basis of assets the Company
estimates that it will be required to provide for deferred income taxes in
the statement of operations 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 $30 million and current deductions for intangible drilling
costs.
The Company is a guarantor of a line of credit and a capital lease for
Maverick Stimulation Company, L.L.C. ("Maverick") for an aggregate amount of
$2.5 million. The guaranteed obligations amounted to $1.1 million at
December 31, 1997.
Effective November 1, 1997, all of the Company's outstanding 8%
Convertible Preferred Stock, $1.00 per value, ("Preferred") was converted
into 905,660 shares of common stock. Under the terms of the Preferred Stock
Agreement, the Company had the right to convert all of the preferred stock
into common stock provided the common stock closing price was not less than
$16 per share for 30 consecutive days. The closing price of the Company's
common stock as reported by NASDAQ was above $16 per share for the 30
consecutive days ending November 1, 1997.
Cash flows provided by operating activities were $6,457,000 for the year
ended December 31, 1997 as compared to cash flows provided by operating
activities of $1,524,000 for the nine months ended December 31, 1996. The
significant increase in the cash flows provided by operating activities was
due primarily to improved operating
24
<PAGE>
results as a result of higher gas production and higher gas prices and a
twelve month reporting period as compared to a nine month reporting period.
Cash flows used by investing activities were $19,259,000 during the year
ended December 31, 1997 versus $8,559,000 during the nine month period ended
December 31, 1996. The increase was due to the continued development of the
Raton Basin including an upgrade of the gas gathering system.
Cash flows provided by financing activities were $12,253,000 during the
year ended December 31, 1997 as compared to cash flows provided by financing
activities of $5,978,000 in the nine month period ended December 31, 1996.
The increase was due primarily to increased borrowings to fund the
development of the drilling and gathering system in the Raton Basin during
the year ended December 31, 1997. During the nine months ended December 31,
1996, the Company completed a common stock offering, resulting in net
proceeds to the Company of $10.3 million, which were used to pay off existing
debt of $3.6 million and fund the continued drilling and gas gathering system
in the Raton Basin.
The Company's production from its San Juan basin properties did not meet
the minimum volume requirements under its transportation agreements with El
Paso Services. As of September 30, 1997, the cumulative obligation of the
Company to El Paso Services resulting from this shortfall was calculated by
the Company to be $2,431,000. At current rates of production, this liability
would have increased to over $3 million by the end of the contract term in
July 1998. The Company's cumulative delivery shortfall through September 30,
1997 was approximately 12.1 million MMbtu. Effective October 1, 1997, the
Company sold all of its San Juan basin properties for $580,000 together with
the assumption by the buyer of EOC's volume commitment to El Paso Services.
As of October 1, 1997, The Company eliminated the obligation to El Paso
Services.
The Company has conducted a comprehensive review of its computer systems
to identify the systems that could be affected by the Year 2000 issue and is
developing an implementation plan to resolve the issue. The "Year 2000"
problem is the result of computer programs being written using two digits
rather than four to define the applicable year. Any of the Company's
programs that have time-sensitive software may recognize a date using "00" as
the year 1900 rather than the year 2000. This could result in a major system
failure or miscalculations. The Company presently believes that, with
modifications to exiting software and converting to new software, the Year
2000 problem will not pose significant operational problems for the Company's
computer systems as so modified and converted. However, if such
modifications and conversions are not timely completed, the Year 2000 problem
may have a material impact on the operations of the Company.
25
<PAGE>
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 1997 COMPARED TO THE NINE MONTHS ENDED DECEMBER 31,
1996
Net income for the year ended December 31, 1997 was $5,064,000 or $0.53
per common share (basic), as compared to $675,000 or $0.10 per common share
(basic), for the nine months ended December 31, 1996. The increase in net
income was primarily the result of the increase in natural gas net revenues
resulting from an increase in gas production and gas prices and a twelve
month reporting period as compared to a nine month reporting period.
Oil and gas revenues were $12,138,000 during the year ended December 31,
1997 as compared to $3,502,000 for the nine months ended December 31, 1996.
The significant increase in oil and gas revenue during 1997, as compared to
1996, was attributable to substantially higher Raton Basin production volumes
and higher natural gas prices and a twelve month reporting period as compared
to a nine month reporting period. The average gas prices were $1.90 per Mcf
for the year ended December 31, 1997 as compared to $1.66 per Mcf in 1996.
Natural gas production increased to 6,401,500 Mcf for the year ended December
31, 1997 as compared to 2,104,400 for 1996.
At December 31, 1997 there were 89 producing Raton Basin wells compared
to 42 producing wells at December 31, 1996.
Equity in earnings of investment was $313,000 for the year ended
December 31, 1997. Equity in earnings of investment is due to the Company's
49% ownership in Maverick, an oil and gas well servicing company. The
Company accounts for the investment in Maverick under the equity method of
accounting. Prior to the current reporting period, the Company's share of
Maverick profits after intercompany elimination was not material. The
increase in Maverick's net income in 1997 was due to the increase in its oil
and gas stimulation services for third party entities.
Oil and gas service revenues were $781,000 during the year ended
December 31, 1997 as compared to $545,000 for the nine months ended December
31, 1996. Cost of oil and gas services for the year ended December 31,
26
<PAGE>
1997 increased to $842,000 from $621,000 in 1996. The increase in oil and
gas service revenue and cost of oil and gas services in 1997 versus 1996 was
due to a twelve month reporting period as compared to a nine month reporting
period.
Interest income decreased to $132,000 for the year ended December 31,
1997 from $143,000 for the nine months ended December 31, 1996. This
decrease was due to less cash to invest as a result of the continued Raton
Basin development.
Lease operating expenses for the year ended December 31, 1997 were
$2,007,000 compared to $701,000 for the nine months ended December 31, 1996.
Lease operating expenses per Mcfe declined to $0.31 during the year ended
December 31, 1997 from $0.33 in 1996. The decrease in the average lease
operating expense per Mcfe was due to the economics of scale resulting from
the increase in producing wells in the Raton Basin.
Depreciation, depletion, and amortization expenses for the year ended
December 31, 1997 increased to $2,794,000 as compared to $966,000 for the
nine months ended December 31, 1996. The increase of $1,828,000 was due to
the substantial increase in natural gas production and a twelve month
reporting period as compared to a nine month reporting period.
General and administrative expenses increased to $1,225,000 for the year
ended December 31, 1997 as compared to $505,000 for the nine months ended
December 31, 1996. The $720,000 increase was due to the general increase in
overall corporate activity, including salaries and professional services and
a twelve month reporting period as compared to a nine month reporting period.
Although the overall expense increased for the twelve months ended December
31, 1997, the cost per Mcfe decreased to $.19 from the prior year cost per
Mcfe of $0.24.
Interest expense increased to $778,000 for the year ended December 31,
1997 from $193,000 for the nine months ended December 31, 1996. This
$585,000 increase was due to increased borrowings under the Company's Credit
Facility and an increase in the capital equipment lease. The increased
borrowings were made to fund the Raton Basin development.
Other expenses increased to $146,000 for the year ended December 31,
1997 from $17,000 for the nine months ended December 31, 1996. The increase
in other expenses was due primarily to the write off of a receivable that was
deemed uncollectible.
NINE-MONTH FISCAL PERIOD ENDED DECEMBER 31, 1996 COMPARED TO THE FISCAL YEAR
ENDED MARCH 31, 1996
The Company reported net income of $675,000, or $0.10 per common share
(basic), for the nine months ended December 31, 1996, compared to a net loss
of $607,000, or $0.10 per common share (basic), for the year ended March 31,
1996. This increase in net income resulted principally from substantial
increases in oil and gas revenues and declining costs per Mcfe.
Oil and gas revenues increased to $3,502,000 for the nine months ended
December 31, 1996 compared to $1,393,000 for the fiscal year ended March 31,
1996. This significant increase was attributable to substantially higher
Raton Basin production volumes, sharply higher natural gas prices, the
acquisition of Powerbridge Inc. ("PBI") (see Notes to Consolidated Financial
Statements, Note 2 for discussion). The average gas prices were $1.66 per
Mcf for the nine month fiscal period ended December 31, 1996 as compared to
$1.29 per Mcf in the fiscal year ended March 31, 1996.
During the nine months ended December 31, 1996, Raton Basin gas
production represented over 88% of the Company's total gas production,
compared to 51% for the year ended March 31, 1996. At December 31, 1996, the
Company had 42 producing Raton Basin wells compared to 21 producing wells at
March 31, 1996. Natural gas production increased to 2,104,400 Mcf for the
nine months ended September 30, 1997 as compared to 941,200 Mcf for the
twelve months ended March 31, 1996.
LOE increased to $701,000 for the nine months ended December 31, 1996
compared to $657,000 for the twelve months ended March 31, 1996. On a Mcfe
basis, however, LOE declined from $0.65 per Mcfe during the twelve month
fiscal year ended March 31, 1996 to $0.33 per Mcfe for the nine months ended
December 31, 1996. The decrease in the average LOE of $0.32 per Mcfe was due
to the sale or shut-in of uneconomical oil and gas properties with high LOE
during the year ended March 31, 1996. Additionally, the significant increase
in production in the Raton Basin over the prior year contributed to the
decrease in LOE per Mcfe.
27
<PAGE>
Oil and gas service revenues decreased to $545,000 for the nine months
ended December 31, 1996 from $779,000 for the twelve months ended March 31,
1996. Costs of oil and gas services also decreased to $621,000 for the nine
months ended December 31, 1996 as compared to $727,000 for the twelve months
ended March 31, 1996. The decrease in both oil and gas service revenues and
cost of oil and gas services expense was due primarily to a nine month
reporting period versus a twelve month reporting period.
Depreciation, depletion and amortization expense increased to $966,000
for the nine months ended December 31, 1996 from $590,000 for the twelve
months ended March 31, 1996. The increase was due to the significantly
higher gas production in the Raton Basin.
General and administrative expenses decreased to $505,000 for the nine
months ended December 31, 1996, from $819,000 for the twelve months ended
March 31, 1996. This decrease was due to expenses incurred during a nine
month reporting period versus a twelve month reporting period.
Interest income decreased to $143,000 for the nine months ended December
31, 1996 from $207,000 for the twelve months ended March 31, 1996. This
decrease was due primarily to the nine month reporting period versus a twelve
month reporting period.
Interest expense increased to $193,000 for the nine months ended
December 31, 1996 from $36,000 for the twelve months ended March 31, 1996.
This increase was due to the debt assumed by the Company as a result of the
PBI acquisition, the interest on the Company's line of credit borrowings, and
the interest on the Company's capital lease obligations.
Other income decreased to $38,000 for the nine months ended December 31,
1996 compared to $556,000 for the twelve months ended March 31, 1996. The
income in the twelve months ended March 31, 1996 resulted primarily from the
sale of the Company's 25% interest in ANGI, Ltd., a United Kingdom gas
marketing company.
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, 1997, the Company had entered into contracts to sell approximately 21.5
MMcf per day (substantially all of its current production available for sale)
for the period January 1998 through March 1998 at prices ranging from $2.04 -
$2.17 per Mcf and approximately 26.5 MMcf per day for the period April 1998
through October 1998 at prices ranging from $1.73-$2.17 per Mcf.
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.
INCOME TAXES AND NET OPERATING LOSSES
As discussed in Note 6 of the Notes to the Company's Consolidated
Financial Statements, the Company has net operating loss carryforwards for
income tax purposes of approximately $30 million which expire beginning in
2003.
The Company recorded a valuation allowance at December 31, 1996 and
March 31, 1996 equal to the excess of deferred tax assets over deferred tax
liabilities as it was unable to determine that the deferred tax assets were
more likely than not to be realized. As of December 31, 1997, the Company did
not record a valuation allowance since management was able to determine that
it was more likely than not that the deferred tax asset would be realized.
Management expects to fully utilize its net operating loss carry forwards
against reversing temporary differences.
Prior to 1998, the Company has not been required to record income tax
expense, primarily due to the availability of net operating loss carryovers.
However, as a result of the recently reported profitability and the
significant difference between the book and tax basis of assets the Company
estimates that it will be required to provide for deferred income taxes in
the statement of operations 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 $30 million and current deductions for intangible drilling
costs.
ACCOUNTING STANDARDS
In June 1997, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 130, "Reporting
Comprehensive Income" which establishes standards for reporting and display
of comprehensive income, its components and accumulated balances.
Comprehensive income is defined to include all changes in equity except those
resulting from investments by owners and distributions to owners. Among
other disclosures, SFAS No. 130 requires that all items that are required to
be recognized under current accounting
28
<PAGE>
standards as components of comprehensive income be reported in a financial
statement that is displayed with the same prominence as other financial
statements.
Also, in June 1997, FASB issued SFAS No. 131, "Disclosures about
Segments of an Enterprise and Related Information" which supersedes SFAS No.
14, "Financial Reporting for Segments of a Business Enterprise." SFAS No.
131 establishes standards for the way that public companies report
information about operating segments in annual financial statements and
requires reporting of selected information about operating segments in
interim financial statements issued to the public. It also establishes
standards for disclosure regarding products and services, geographic areas
and major customers. SFAS No. 131 defines operating segments as components
of a company about which separate financial information is available that is
evaluated regularly by the chief operating decision maker in deciding how to
allocate resources and in assessing performance.
Both SFAS No. 130 and 131 are effective for financial statements for
periods beginning after December 15, 1997 and require comparative information
for earlier years to be restated. Because of the recent issuance of these
standards, management has been unable to fully evaluate the impact, if any,
they may have on future financial statement disclosures. Results of
operations and financial position, however, will be unaffected by
implementation of these standards.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE
----
Report of Independent Certified Public Accountants F-1
Consolidated Balance Sheets, December 31, 1997 and 1996 F-2
Consolidated Statements of Operations for the Year and Nine
Months Ended December 31, 1997 and 1996 and for the Year ended
March 31, 1996 F-3
Consolidated Statements of Stockholders' Equity for the Year and
Nine Months Ended December 31, 1997 and 1996 and for the Year
ended March 31, 1996 F-4
Consolidated Statements of Cash Flows for the Year and Nine
Months Ended December 31, 1997 and 1996 and for the Year ended
March 31, 1996 F-5
Notes to Consolidated Financial Statements F-6 to F-21
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURES
Since the Company's inception, there has not been any Forms 8-K filed
under the Securities and Exchange Act of 1934 reporting a change in
accountants in which there was a reported disagreement on any matter of
accounting principles or practices or financial statement disclosure.
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, 1998.
29
<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 and by
reference to Exhibit I to the Company's Current Report on Form
8-K dated December 9, 1994).
3.2 Bylaws: Incorporated by reference to Exhibit 3.2 to the
Company's Registration Statement on Form S-1, Commission File
No. 33-273035.
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 Revolving Note by and among Evergreen Resources, Inc. and
Hibernia National Bank, Dated June 19, 1997: Incorporated by
reference to Exhibit 10.1 of the Company's Registration
Statement on Form S-3 filed on November 21, 1997, Commission
File No. 333-40817.
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.
21.0 Subsidiaries of registrant: Incorporated by reference to page
F-6 of the Financial Statements included herein.
22.0 Reserve Reports prepared by Netherland Sewell & Associates,
Inc. and Resource Services International, Inc.
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, 1997.
30
<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: By: /s/ Mark S. Sexton
-------------------------------------------
Mark S. Sexton
President and Chief Executive Officer
Date: By: /s/ Kevin R. Collins
-------------------------------------------
Kevin R. Collins, Vice President - Finance
CFO and Treasurer
Principal Accounting 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 or her and in his or her
name, place and stead, in any and all capacities, to sign any and all
amendments (including post-effective 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 or
she 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 or her
substitute or substitutes, may lawfully do, or cause to be done by virtue
hereof.
31
<PAGE>
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
Date: By: /s/ Alain Blanchard
-------------------------------------------
Alain Blanchard, Director
Date: By: /s/ Dennis R. Carlton
-------------------------------------------
Dennis R. Carlton, Director
Date: By: /s/ Larry D. Estridge
-------------------------------------------
Larry D. Estridge, Director
Date: By: /s/ John J. Ryan III
-------------------------------------------
John J. Ryan III, Director
Date: By: /s/ Mark S. Sexton
-------------------------------------------
Mark S. Sexton, Director
Date: By: /s/ Scott D. Sheffield
-------------------------------------------
Scott D. Sheffield, Director
Date: By: /s/ James S. Williams
-------------------------------------------
James S. Williams, Director
32
<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, 1997 and 1996, and the
related consolidated statements of operations, stockholders' equity, and cash
flows for year ended December 31, 1997, the nine month period ended December 31,
1996 and for the year ended March 31, 1996. 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, 1997 and 1996 and the results of their
operations and their cash flows for the year ended December 31, 1997, the nine
month period ended December 31, 1996 and for the year ended March 31, 1996, in
conformity with generally accepted accounting principles.
BDO SEIDMAN, LLP
Denver, Colorado
February 10, 1998
F-1
<PAGE>
EVERGREEN RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
<TABLE>
ASSETS December 31,
--------------------------
1997 1996
----------- -----------
<S> <C> <C>
Current:
Cash and cash equivalents $ 2,103,168 $ 2,640,300
Accounts receivable:
Oil and gas sales 2,298,861 1,182,635
Joint interest billings and other 1,311,587 727,283
Other current assets 321,764 113,964
----------- -----------
Total current assets 6,035,380 4,664,182
Property and equipment (Notes 1,4 and 15):
Proved oil and gas properties, full-cost 58,937,182 49,323,572
accounting
Unevaluated properties not subject to 9,700,838 8,579,220
amortization
Gas gathering equipment 21,635,598 13,952,381
Support equipment 1,851,966 1,422,955
----------- -----------
92,125,584 73,278,128
Less accumulated depreciation, depletion and 15,361,174 12,578,205
amortization ----------- -----------
Net property and equipment 76,764,410 60,699,923
Designated cash (Note 5) 2,142,883 1,493,114
Other assets 2,362,829 1,386,376
----------- -----------
$87,305,502 $68,243,595
----------- -----------
----------- -----------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable (Note 1) $ 1,645,467 $ 3,223,047
Amounts payable to oil and gas property owners 2,968,827 1,068,532
Accrued expenses and other 494,252 415,748
Current portion - capital lease (Note 4) 1,061,090 275,348
----------- -----------
Total current liabilities 6,169,636 4,982,675
Production taxes payable (Note 5) 2,142,883 1,493,114
Note payable (Note 3) 10,812,000 --
Obligations under capital lease (Note 4) 4,028,872 1,173,500
Long-term liabilities (Note 12) -- 2,230,798
----------- -----------
Total liabilities 23,153,391 9,880,087
Redeemable preferred stock (Notes 7 and 8) -- 6,000,000
Commitments and contingencies (Note 12)
Stockholders' equity (Notes 8 and 9):
Common stock, $.01 stated value;
shares authorized, 50,000,000;
shares issued and outstanding, 103,953 93,636
10,395,266 and 9,336,320
Additional paid-in capital 67,948,743 61,369,368
Accumulated deficit (4,134,705) (9,198,780)
Foreign currency translation adjustment 234,120 99,284
----------- -----------
Total stockholders' equity 64,152,111 52,363,508
----------- -----------
$87,305,502 $68,243,595
----------- -----------
----------- -----------
</TABLE>
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
F-2
<PAGE>
EVERGREEN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
NINE MONTHS
YEAR ENDED ENDED YEAR ENDED
DECEMBER 31, DECEMBER 31, MARCH 31,
1997 1996 1996
----------- ------------ -----------
<S> <C> <C> <C>
Revenues:
Oil and gas production (Note 10) $12,137,869 $3,502,385 $1,392,695
Oil and gas services 780,745 545,079 779,146
Equity in earnings of investment (Note 1) 313,179 -- --
Interest 131,823 142,521 206,769
Other (Note 13) 4,709 37,953 556,221
----------- ---------- ----------
Total revenues 13,368,325 4,227,938 2,934,831
----------- ---------- ----------
Expenses:
Lease operating expense 2,007,388 700,875 656,899
Gas gathering costs 112,358 110,363 218,644
Cost of oil and gas services 842,076 621,521 727,121
Depreciation, depletion and amortization 2,793,946 965,794 589,936
General and administrative expenses 1,224,956 504,456 818,805
Interest expense 777,373 192,685 36,620
Other 146,153 17,309 (10,997)
----------- ---------- ----------
Total expenses 7,904,250 3,113,003 3,037,028
----------- ---------- ----------
Net income (loss) 5,464,075 1,114,935 (102,197)
Preferred stock dividends (Note 7) 400,000 440,000 504,620
----------- ---------- ----------
Net income (loss) attributable to common stock $ 5,064,075 $ 674,935 $ (606,817)
----------- ---------- ----------
----------- ---------- ----------
Net income (loss) per common share (Note 8):
Basic $ 0.53 $ 0.10 $ (0.10)
----------- ---------- ----------
----------- ---------- ----------
Diluted $ 0.51 $ 0.10 $ (0.10)
----------- ---------- ----------
----------- ---------- ----------
</TABLE>
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
F-3
<PAGE>
EVERGREEN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
YEAR AND NINE MONTHS ENDED DECEMBER 31, 1997 AND 1996
AND FOR THE YEAR ENDED MARCH 31, 1996
<TABLE>
Common Stock Foreign
----------------------
$.01 Stated Value Additional Currency Total
---------------------- Paid-In Accumulated Translation Stockholders'
Shares Amount Capital Deficit Adjustment Equity
---------- -------- ------------ ----------- ---------- -------------
<S> <C> <C> <C> <C> <C> <C>
Balance, April 1, 1995 5,672,159 $ 56,721 $41,419,179 $(9,266,898) $ (7,140) $32,201,862
Exercise of stock purchase warrants (Note 8) 159,059 1,592 302,315 - - 303,907
Common stock issued to ESOP (Note 12) 10,000 100 19,900 - - 20,000
Issuance of common stock for services (Note 8) 55,000 550 116,840 - - 117,390
Other 3,518 35 (36,208) - - (36,173)
Preferred stock dividends - - - (504,620) - (504,620)
Foreign currency translation - - - - (411,332) (411,332)
Net loss - - - (102,197) - (102,197)
---------- -------- ----------- ----------- --------- -----------
Balance, March 31, 1996 5,899,736 58,998 41,822,026 (9,873,715) (418,472) 31,588,837
Issuance of common stock pursuant to
public offering (Note 8) 2,000,000 20,000 10,226,780 - - 10,246,780
Issuance of common stock for acquisition
of PBI and limited partnership interests
(Note 2) 1,162,266 11,623 7,688,377 - - 7,700,000
Issuance of common stock in exchange for
redeemable preferred stock (Note 7) 230,770 2,308 1,497,692 - - 1,500,000
Issuance of common stock for preferred
stock dividend payment (Note 7) 3,077 307 19,693 - - 20,000
Common stock issued to ESOP (Note 12) 10,000 100 28,700 - - 28,800
Issuance of common stock for services (Note 8) 30,000 300 86,100 - - 86,400
Other 471 - - - - -
Preferred stock dividends - - - (440,000) (440,000)
Foreign currency translation - - - - 517,756 517,756
Net income - - - 1,114,935 - 1,114,935
---------- -------- ----------- ----------- --------- -----------
Balance, December 31, 1996 9,336,320 93,636 61,369,368 (9,198,780) 99,284 52,363,508
Issuance of common stock in exchange for
redeemable preferred stock (Note 7) 905,660 9,057 5,973,443 - - 5,982,500
Issuance of common stock for services (Note 8) 63,940 639 239,226 - - 239,865
Exercise of stock purchase warrants (Note 8) 89,346 621 366,706 - - 367,327
Preferred stock dividends - - - (400,000) - (400,000)
Foreign currency translation - - - - 134,836 134,836
Net income - - - 5,464,075 - 5,464,075
---------- -------- ----------- ----------- --------- -----------
Balance, December 31, 1997 10,395,266 $103,953 $67,948,743 $(4,134,705) $ 234,120 $64,152,111
---------- -------- ----------- ----------- --------- -----------
---------- -------- ----------- ----------- --------- -----------
</TABLE>
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
<PAGE>
EVERGREEN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
<TABLE>
<CAPTION>
Nine Months
YEAR ENDED Ended Year Ended
DECEMBER 31, December 31, March 31,
1997 1996 1996
------------ ------------ -----------
<S> <C> <C> <C>
Operating activities:
Net income (loss) $ 5,464,075 $ 1,114,935 $ (102,197)
Adjustments to reconcile net income (loss) to cash
provided by operating activities:
Depreciation, depletion and amortization 2,793,946 965,794 589,936
Gain on sale of subsidiaries - - (525,287)
Equity in earnings of investment (313,179) - -
Stock issued for services 184,463 86,400 31,555
Changes in operating assets and liabilities:
Accounts receivable (1,120,476) (184,957) 106,209
Other current assets (207,784) 82,712 (56,520)
Accounts payable (422,188) (645,908) 1,010,077
Accrued expenses 78,505 105,012 76,178
------------ ------------ -----------
Net cash provided by operating activities 6,457,362 1,523,988 1,129,951
------------ ------------ -----------
Investing activities:
Investment in property and equipment (18,603,065) (8,342,545) (3,988,233)
Proceeds from sale of oil and gas assets - 420,549 540,413
Proceeds from sale of subsidiary - - 580,000
Designated cash (649,769) (723,038) (177,052)
Change in production taxes payable 649,769 723,038 177,052
Change in other assets (656,097) (636,868) 104,058
------------ ------------ -----------
Net cash used by investing activities (19,259,162) (8,558,864) (2,763,762)
------------ ------------ -----------
Financing activities:
Proceeds from notes payable 11,189,120 - -
Principal payments on long-term debt - (3,596,000) -
Principal payments on capital lease obligations (636,875) (118,705) (46,526)
Proceeds from issuance of common stock, net 348,982 10,246,780 303,904
Proceeds from issuance of redeemable preferred stock - - 3,714,736
Dividends paid on preferred stock (400,000) (420,000) (504,620)
Debt issue costs (148,515) (79,149) (49,037)
Change in cash held from operating oil and gas properties 1,900,295 (54,933) (89,880)
------------ ------------ -----------
Net cash provided by financing activities 12,253,007 5,977,993 3,328,577
------------ ------------ -----------
Effect of exchange rate changes on cash 11,661 (5,328) (30,412)
------------ ------------ -----------
Increase (Decrease) in cash and cash equivalents (537,132) (1,062,211) 1,664,354
Cash and cash equivalents, beginning of period 2,640,300 3,702,511 2,038,157
------------ ------------ -----------
Cash and cash equivalents, end of period $ 2,103,168 $ 2,640,300 $ 3,702,511
------------ ------------ -----------
------------ ------------ -----------
</TABLE>
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
F-5
<PAGE>
EVERGREEN RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEAR AND NINE MONTHS ENDED DECEMBER 31, 1997 AND 1996 AND YEAR ENDED MARCH 31,
1996
(1) SUMMARY OF ACCOUNTING POLICIES
CONSOLIDATION
The financial statements include the accounts of Evergreen Resources,
Inc. ("ERI") and its wholly-owned subsidiaries (the "Company"); Evergreen
Operating Corporation ("EOC") and Evergreen Resources (UK) Ltd., Powerbridge,
Inc., and Primero Gas Marketing Company, ("Primero").
The companies are engaged in the operation, acquisition, exploration and
development of oil and gas properties and also the marketing of natural gas.
All significant intercompany balances and transactions have been eliminated
in consolidation.
The consolidated financial statements also include the Company's 49%
ownership in Maverick Stimulation Company, LLC ("Maverick") and 40% ownership
in Argos Evergreen Limited ("AEL"). The Company accounts for these
investments by the equity method of accounting. All significant intercompany
balances and transactions have been eliminated. Maverick provides pressure
pumping and other oilfield services to the petroleum industry in the Rocky
Mountain region. Maverick provides certain well stimulation services to the
Company and during 1997 such services amounted to $2,636,400 of which
$302,000 was unpaid at year end. The Company guaranteed approximately
$1,100,000 of Maverick's outstanding debt at December 31, 1997. The
investment in Maverick, including equity in earnings for the year of
$313,200, was $1,002,300 at December 31, 1997.
CHANGE IN FISCAL YEAR
Effective with the period ended December 31, 1996, the Company elected
to begin utilizing a December 31 year end. Therefore, the period ended
December 31, 1996 represents a nine month short period and the years ended
December 31, 1997 and March 31, 1996 represent twelve month periods.
CONCENTRATIONS OF CREDIT RISK
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.
USE 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.
F-6
<PAGE>
EVERGREEN RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEAR AND NINE MONTHS ENDED DECEMBER 31, 1997 AND 1996 AND YEAR ENDED MARCH 31,
1996
OIL AND GAS PROPERTIES
The Company follows the full-cost method of accounting for oil and gas
properties. Under this method, all productive and nonproductive costs
incurred in connection with the exploration for and development of oil and
gas reserves are capitalized. Such capitalized costs include lease
acquisition, geological and geophysical work, delay rentals, drilling,
completing and equipping oil and gas wells and other related costs. 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 15), and (2) the lower of cost or fair market value
of properties in process of development and unexplored acreage, the excess is
charged to expense as additional depletion. Normal dispositions of oil and
gas properties are accounted for as adjustments of capitalized costs, with no
gain or loss recognized.
Depreciation and depletion of proved oil and gas properties is computed
on the units-of-production method based upon estimates of proved reserves
with oil and gas being converted to a common unit of measure based on their
relative energy content. Unproved oil and gas properties, including any
related capitalized interest expense, are not amortized, but are assessed for
impairment either individually or on an aggregated basis.
GAS GATHERING AND SUPPORT EQUIPMENT
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 estimated gas production over a
twenty-year life. 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 20 years.
LONG-TERM ASSETS
The Company applies Statement of Financial Accounting Standards ("SFAS")
No. 121, "Accounting for the Impairment of Long-Lived Assets". Under SFAS
No. 121, long-lived assets and certain intangibles are reported at the lower
of the carrying amount or their estimated recoverable amounts.
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 accounts for income taxes in accordance with SFAS No. 109,
"Accounting for Income Taxes" which requires the use of the "liability
method". 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.
OPERATOR FEES
Income from operating wells for third parties is recognized pursuant to
the applicable operating agreements when the services are performed.
F-7
<PAGE>
EVERGREEN RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEAR AND NINE MONTHS ENDED DECEMBER 31, 1997 AND 1996 AND YEAR ENDED MARCH 31,
1996
NET INCOME (LOSS) PER SHARE
At December 31, the Company implemented SFAS No. 128, "Earnings Per
Share". SFAS No. 128 provides 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, similar to fully diluted earnings per share. All
prior period earnings per share data has been restated to reflect the
requirements of SFAS No. 128. See Note 8 for computation of earnings per
share.
CASH EQUIVALENTS
The Company considers all highly liquid investments with an original
maturity of three months or less to be cash equivalents.
FINANCIAL INSTRUMENTS
Unless otherwise specified, the Company believes the book value of the
financial instruments approximates their fair value.
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.
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, no compensation cost has been recognized for
stock options granted as the option price equals or exceeds the market price
of the underlying common stock on the date of grant.
SFAS No. 123, "Accounting for Stock-Based Compensation", requires the
Company to provide pro forma information regarding net income as if
compensation cost for the Company's stock option plans had been determined in
accordance with the fair value based method prescribed in SFAS No. 123. To
provide the required pro forma information, the Company estimates the fair
value of each stock option at the grant date by using the Black-Scholes
option-pricing model.
FOREIGN CURRENCY TRANSLATION
The functional currency for the Company's foreign operations is the
applicable local currency. The translation of the applicable foreign
currency into U.S. dollars is performed for balance sheet accounts using
current exchange rates in effect at the balance sheet date and for revenue
and expense accounts using a weighted average exchange rate during the
period. The gains or losses resulting from such translation are included in
stockholders' equity.
RECLASSIFICATIONS
Certain items included in prior years financial statements have been
reclassified to conform to current year presentation.
F-8
<PAGE>
EVERGREEN RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEAR AND NINE MONTHS ENDED DECEMBER 31, 1997 AND 1996 AND YEAR ENDED MARCH 31,
1996
RECENT ACCOUNTING PRONOUNCEMENTS
In June 1997, FASB issued SFAS No. 130, "Reporting Comprehensive Income"
which establishes standards for reporting and display of comprehensive
income, its components and accumulated balances. Comprehensive income is
defined to include all changes in equity except those resulting from
investments by owners and distributions to owners. Among other disclosures,
SFAS No. 130 requires that all items that are required to be recognized under
current accounting standards as components of comprehensive income be
reported in a financial statement that is displayed with the same prominence
as other financial statements.
Also, in June 1997, FASB issued SFAS No. 131, "Disclosures about
Segments of an Enterprise and Related Information" which supersedes SFAS No.
14, "Financial Reporting for Segments of a Business Enterprise." SFAS No.
131 establishes standards for the way that public companies report
information about operating segments in annual financial statements and
requires reporting of selected information about operating segments in
interim financial statements issued to the public. It also establishes
standards for disclosure regarding products and services, geographic areas
and major customers. SFAS No. 131 defines operating segments as components
of a company about which separate financial information is available that is
evaluated regularly by the chief operating decision maker in deciding how to
allocate resources and in assessing performance.
Both SFAS No. 130 and 131 are effective for financial statements for
periods beginning after December 15, 1997 and require comparative information
for earlier years to be restated. Because of the recent issuance of these
standards, management has been unable to fully evaluate the impact, if any,
they may have on future financial statement disclosures. Results of
operations and financial position, however, will be unaffected by
implementation of these standards.
(2) ACQUISITION AGREEMENT
Effective August 1, 1996, the Company acquired the limited partnership
interests of Energy Investors Fund, LP and Energy Investors Fund II, LP in
PBI Fuels, LP and 100% of the common stock of Powerbridge Inc. for a purchase
price of $11.3 million. The purchase price was comprised of 1,162,266 shares
of restricted common stock valued at $7.7 million and the assumption of $3.6
million of long-term debt. The assets acquired included 37.0 billion cubic
feet (Bcf) of proved natural gas reserves, approximately 24 Bcf of which were
developed, together with 25% working interest in 120,000 gross acres and 50%
interest in an associated gas gathering and marketing system. All of these
assets are located on the Company's present acreage position in the Raton
Basin, Las Animas County, Colorado. The acquisition has been accounted for
under the purchase method of accounting.
Assuming the Company's acquisition as discussed above had been completed
at the beginning of the periods below, pro forma results of operations for
such periods would have been:
<TABLE>
Nine Months
Ended Year Ended
December 31, 1996 March 31, 1996
----------------- --------------
<S> <C> <C>
Revenues $4,599,000 $3,210,400
Net income (loss) 1,201,170 (389,900)
Net income (loss) attributable 761,170 (894,600)
to common stock
Income (loss) per share of
common stock
Basic $0.11 $(0.13)
Diluted $0.11 $(0.13)
</TABLE>
F-9
<PAGE>
EVERGREEN RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEAR AND NINE MONTHS ENDED DECEMBER 31, 1997 AND 1996 AND YEAR ENDED MARCH 31,
1996
The pro forma information is not necessarily indicative of the combined
results of operations that would have occurred had the acquisition been
completed at the beginning of such periods.
(3) FINANCING AGREEMENT
The Company has a $30.0 million revolving line of credit with a bank.
Interest accrues at prime (8.5% at December 31, 1997) plus or minus a margin
of .25%, with margins determined on the average outstanding borrowings under
the line of credit and is paid monthly. The line of credit matures in May
1999. Advances pursuant to this line of credit are limited to the borrowing
base, which is presently $30.0 million. The borrowing base is redetermined
semi-annually by the bank 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 annual facility fee of three-eighths of a percent 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, 1997, $10,812,000 was outstanding
and no amounts were outstanding under the line of credit at December 31, 1996.
(4) CAPITAL LEASE OBLIGATIONS
The Company has capital equipment leases with a bank with interest at
prime (8.5% at December 31, 1997) for a term of five years, including options
to purchase the equipment at a nominal amount at the end of the lease term.
The Company primarily leases compressors for the Raton Basin gas gathering
system and other related production equipment.
Future minimum lease payments are as follows:
<TABLE>
<S> <C>
Years ending December 31:
1998 $1,453,000
1999 1,453,000
2000 1,453,000
2001 1,264,000
2002 461,000
----------
Total future minimum lease payments 6,084,000
Less amount representing interest 994,000
----------
Present value of minimum lease payments 5,090,000
Less current portion 1,061,000
----------
Capital lease obligations less current portion $4,029,000
----------
----------
</TABLE>
Included in fixed assets are the following assets under capital leases:
<TABLE>
December 31,
-----------------------------
1997 1996
---------- ----------
<S> <C> <C>
Gas gathering equipment $5,742,500 $1,652,200
Less accumulated amortization 434,300 92,100
---------- ----------
$5,308,200 $1,560,100
---------- ----------
---------- ----------
</TABLE>
F-10
<PAGE>
EVERGREEN RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEAR AND NINE ENDED DECEMBER 31, 1997 AND 1996 AND YEAR ENDED MARCH 31, 1996
(5) 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 1997 which is not payable until fiscal 1999 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.
(6) INCOME TAXES
Due primarily to the availability of net operating loss carryovers, the
Company had no significant taxable income during the year ended and the nine
months ended December 31, 1997 and 1996 and the year ended March 31, 1996.
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>
Nine Months
Year Ended Ended Year Ended
December 31, December 31, March 31,
1997 1996 1996
------------ ------------ ----------
<S> <C> <C> <C>
Federal income tax provision
at statutory rate $ 1,858,000 $ 379,000 $(35,000)
State income taxes 180,000 37,000 (3,000)
Reduction in valuation allowance (1,788,000) (374,000) -
Other (250,000) (42,000) -
Valuation allowance - - 38,000
----------- --------- --------
$ - $ - $ -
----------- --------- --------
----------- --------- --------
</TABLE>
The Company recorded a valuation allowance at December 31, 1996 and
March 31, 1996 equal to the excess of deferred tax assets over deferred tax
liabilities as it was unable to determine that these tax benefits are more
likely than not to be realized. As of December 31, 1997, the Company did not
record a valuation allowance since management was able to determine that it
was more likely than not that the deferred tax asset would be realized.
The components of the net deferred tax assets and liabilities are shown
below:
<TABLE>
December 31,
------------------------------
1997 1996
------------ -----------
<S> <C> <C>
Net operating loss carryforward $ 11,221,000 $ 9,556,000
Other 501,000 502,000
------------ -----------
Total gross deferred tax assets 11,722,000 10,058,000
Valuation allowance -- (1,788,000)
------------ -----------
Net deferred tax asset 11,722,000 8,270,000
Deferred tax liability - depreciation,
depletion and amortization (11,738,000) (8,270,000)
------------ -----------
Net deferred taxes $ (16,000) $ -
------------ -----------
------------ -----------
</TABLE>
As of December 31, 1997, the Company has net operating loss carryforwards
for tax purposes of approximately $30 million which expire beginning in 2003.
F-11
<PAGE>
EVERGREEN RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEAR AND NINE ENDED DECEMBER 31, 1997 AND 1996 AND YEAR ENDED MARCH 31, 1996
(7) REDEEMABLE PREFERRED STOCK
Effective November 1, 1997, all of the Company's outstanding 8% Convertible
Preferred Stock, $1.00 per value, ("Preferred") was converted into 905,660
shares of common stock. Under the terms of the Preferred Stock Agreement, the
Company had the right to convert all of the preferred stock into common stock
provided the common stock closing price was not less than $16 per share for 30
consecutive days. The closing price of the Company's common stock as reported
by NASDAQ was above $16 per share for the 30 consecutive days ending November 1,
1997.
As of December 1, 1996, 1,500,000 shares of the Preferred were converted to
230,770 shares of common stock and 250,000 five-year stock purchase warrants.
100,000 of the warrants are exercisable at $7.80 per share and 150,000 are
exercisable at $7.00 per share.
Cumulative annual cash dividends of 8% were payable quarterly. During the
year and nine months ended December 31, 1997 and 1996, and the year ended March
31, 1996, the Company paid $400,000, $440,000 and $504,620 in dividends.
(8) STOCKHOLDERS' EQUITY
Earnings per Share
The following table sets forth the computation of basic and diluted earnings per
share:
<TABLE>
Nine Months
Year Ended Ended Year Ended
December 31, December 31, March 31,
1997 1996 1996
------------ ------------- -----------
<S> <C> <C> <C>
Numerator:
Net income (loss) $ 5,464,075 $ 1,114,935 $ (102,197)
Preferred stock dividends (400,000) (440,000) (504,620)
----------- ----------- ----------
Numerator for basic earnings
per share - income (loss)
available to common
stockholders 5,064,075 674,935 (606,817)
Effect of dilutive securities:
Preferred stock dividends 400,000 -- --
----------- ----------- ----------
Numerator for dilutive earnings
per share - income (loss)
available to common
stockholders after assumed
conversions 5,464,075 674,935 (606,817)
----------- ----------- ----------
Denominator:
Denominator for basic earnings
per share - weighted average
shares 9,574,889 7,043,141 5,800,036
Effect of dilutive securities:
Employee stock warrants 335,032 46,133 --
8% Convertible preferred
stock 754,717 -- --
----------- ----------- ----------
Dilutive potential common shares 1,089,749 46,133 --
----------- ----------- ----------
Denominator for diluted
earnings per share - adjusted
weighted average shares and
assumed conversions 10,664,638 7,089,274 5,800,036
----------- ----------- ----------
----------- ----------- ----------
Basic earnings (loss) per share $ .53 $ .10 $ (.10)
----------- ----------- ----------
----------- ----------- ----------
Diluted earnings (loss) per share $ .51 $ .10 $ (.10)
----------- ----------- ----------
----------- ----------- ----------
</TABLE>
F-12
<PAGE>
EVERGREEN RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEAR AND NINE ENDED DECEMBER 31, 1997 AND 1996 AND YEAR ENDED MARCH 31, 1996
For the nine months ended December 31, 1996 and the year ended March 31,
1996, common stock equivalents of 1,136,430 and 921,030, were not included in
the computation of diluted earnings per share because their effect was
antidilutive. For the year ended December 31, 1997, all common stock
equivalents were included in the computation of diluted earnings per share.
On October 28, 1996, the Company completed a public offering of its common
shares, whereby it sold 2,000,000 shares at $5.75 per share. Proceeds, net of
underwriters' commissions and their expenses of $1,253,220, were $10,246,780.
During the year and nine months ended December 31, 1997 and 1996 and the
year ended March 31, 1996, the Company issued common stock valued at $239,900,
$86,400 and $117,390 as a bonus to certain employees.
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, 58,446 shares of common stock were issued
under terms of warrants previously granted, resulting in proceeds to the Company
of $367,300.
During the year ended March 31, 1996, pursuant to the exercise of certain
stock purchase warrants, 71,250 shares of common stock were issued at $2.50 per
share, in exchange for 30,941 shares of common stock currently issued and
outstanding with a market value of approximately $5.50. In addition, 118,750
shares of common stock were issued under terms of warrants previously granted,
resulting in proceeds to the Company of $303,907.
(9) STOCK OPTIONS
In May 1997, the Board of Directors adopted an Initial Stock Option Plan
(the 'Plan'), subject to shareholder approval, 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. Subsequent to
year end, the Company granted 200,000 options under the plan.
Under the terms of its 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. During the year ended December 31, 1997, the
Company granted 145,000 warrants at exercise prices ranging from $8.75 to $9.88.
During the nine months ended December 31, 1996, the Company granted 405,001
warrants to officers and directors at exercise prices ranging from $5.75 to
$7.00. In connection with the 1996 public offering, the Company issued 200,000
warrants to the underwriters at an exercise price of $6.90 per share. The
presently outstanding warrants expire in 1998 to 2002.
F-13
<PAGE>
EVERGREEN RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEAR AND NINE MONTHS ENDED DECEMBER 31, 1997
AND 1996 AND YEAR ENDED MARY 31, 1996
<TABLE>
<CAPTION>
December 31, December 31, March 31,
1997 1996 1996
--------------------- --------------------- ---------------------
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 year 1,182,301 $6.53 327,300 $7.47 497,300 $5.70
Granted 145,000 8.83 855,001 7.06 20,000 4.25
Exercised (99,715) 4.81 - - (190,000) 2.50
Expired (135,000) 8.75 - - - -
--------- ----- --------- ----- -------- -----
Outstanding,
end of year 1,092,586 $7.41 1,182,301 $7.21 327,300 $7.47
--------- ----- --------- ----- -------- -----
Options and warrants
exercisable, end of year 956,086 $7.47 947,800 $7.21 327,300 $7.47
--------- ----- --------- ----- -------- -----
Weighted average fair
value of options and
warrants granted
during the year $ 3.35 $ 1.51
--------- ---------
--------- ---------
</TABLE>
SFAS No. 123, "Accounting for Stock-Based Compensation", require 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
nine months ended December 31, 1996: dividend yield of 0 percent for all
years; expected volatility of 9 percent; risk-free interest rate of 6.6
percent; and expected lives of five years for the warrants. The assumptions
used for grants in the year ended December 31, 1997: dividend yield at 0
percent; expected volatility of approximately 6 percent; risk free interest
rate of 6 percent; and expected lives of between two and five years for the
warrants.
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>
Nine Months
Year Ended Ended Year Ended
December 31, December 31, March 31,
1997 1996 1996
-------------------------------------------
<S> <C> <C> <C>
Net income (loss)
Basic
As reported $5,064,075 $674,935 $(606,817)
Pro forma 4,430,445 597,935 (606,817)
Diluted
As reported $5,464,075 $674,935 $(606,817)
Pro forma 4,830,445 597,935 (606,817)
Net income (loss) per share
Basic
As reported $0.53 $.10 $(.10)
Pro forma 0.46 .08 (.10)
Diluted
As reported $0.51 $.10 $(.10)
Pro forma 0.45 .08 (.10)
</TABLE>
F-14
<PAGE>
EVERGREEN RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEAR AND NINE MONTHS ENDED DECEMBER 31, 1997
AND 1996 AND YEAR ENDED MARY 31, 1996
The following table summarizes information about stock options outstanding at
December 31, 1997:
<TABLE>
<CAPTION>
Outstanding Exercisable
- ----------------- -------------------------------------------------------- --------------------------------
Number Weighted Average Weighted Number Weighted
Range of Exercise Outstanding at Remaining Contractual Average Exercise Exercisable at Average Exercise
Prices 12/31/97 Life Price 12/31/97 Price
- ----------------- -------------------------------------------------------- --------------------------------
<S> <C> <C> <C> <C> <C>
$4.25 - 5.75 30,000 3.15 $4.75 30,000 $4.75
6.90 200,000 3.81 6.90 200,000 6.90
7.00 545,000 4.16 7.00 408,500 7.00
7.80 94,586 3.92 7.80 94,586 7.80
8.75 135,000 1.08 8.75 135,000 8.75
$9.50 - 9.88 88,000 0.97 9.54 88,000 9.54
------------ ----------------------------------------------- ----------------------
$4.25 - 9.88 1,092,586 2.52 $7.41 956,086 $7.47
</TABLE>
(10) MAJOR CUSTOMERS
During the year and nine months ended December 31, 1997 and 1996 and the
year ended March 31, 1996, the Company made sales to 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 E F G
- -------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Year ended December 31, 1997 48% -% 17% 17% -% -% -%
Nine months ended December 31, 1996 59 12 12 - - - -
Year ended March 31, 1996 - - - - 41 11 25
</TABLE>
(11) SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Cash paid during the year ended and nine months ended December 31, 1997 and
1996, and the year ended March 31, 1996, for interest were approximately
$817,000, $193,000, and $37,000. During the year ended December 31, 1997,
approximately $40,000 of interest paid was capitalized. During the year and
nine months ended December 31, 1997 and 1996, the Company incurred capital lease
obligations of $3,900,000 and $841,000 in connection with a master lease
agreement to acquire equipment. Included in accounts payable at December 31,
1997 and 1996 is approximately $1,095,700 and $2,251,000 for drilling and
completion and gas gathering construction costs.
See Notes 2, 7, 8 and 9 for additional noncash transactions at December 31,
1997 and 1996, and at March 31, 1996.
(12) COMMITMENTS AND CONTINGENCIES
In August 1997, the Company entered into an agreement with Colorado
Interstate Gas ('CIG') pursuant to which CIG will construct 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.
The Company has committed to transport natural gas from the Raton Basin
through CIG's pipelines commencing on or about August 1998. The initial
commitment is 25 MMcf per day, increasing every six months to a maximum of 41
MMcf per day 18 months after commencement. Subject to available capacity in
the pipeline, the Company has the first right to increase its volumes up to
100 MMcf per day.
In November 1996, Evergreen entered into an agreement with CIG which
provided firm transportation for 10 MMcf per day of the Company's Raton Basin
gas from the field to the CIG
F-15
<PAGE>
EVERGREEN RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEAR AND NINE MONTHS ENDED DECEMBER 31, 1997
AND 1996 AND YEAR ENDED MARY 31, 1996
interconnection with other interstate pipelines in Texas. Beginning November
1, 1997, the Company obtained the right to firm transportation for an
additional 10 MMcf per day (reserving total firm transportation of up to 20
Mmcf per day). These transportation agreements will terminate on the
in-service date of the Campo Lateral.
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
----------------------- -----------
<S> <C>
1998 $ 1,665,000
1999 3,236,000
2000 4,198,000
2001 4,303,000
2002 4,303,000
Thereafter 45,899,000
-----------
$63,604,000
-----------
-----------
</TABLE>
The Company leases its primary office space for approximately $12,800 a
month under a lease expiring in March 1998. Rental expense, net of sublease
income, was approximately $138,000, $99,900, and $143,000, for the year and nine
months ended December 31, 1997 and 1996 and the year ended March 31, 1996.
Subsequent to year end, the Company entered into a new ten year office lease
commencing on May 1, 1998 for approximately $267,500 per year.
On January 19, 1998, the Company submitted an application to the Internal
Revenue Service to terminate the Employee Stock Ownership Plan ("ESOP"). For
the nine months ended December 31, 1996 and the year ended March 31, 1996, the
Company contributed $28,000 and $20,000 to the plan. There were no
contributions to the plan for the year ended December 31, 1997.
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 year ended December 31, 1997 was approximately $134,000.
In August 1992, the Company entered into a series of agreements with El
Paso Field Services Company ("El Paso Services") concerning the connection of
Evergreen's San Juan Basin wells to El Paso's non-jurisdictional gathering
system. Under the terms of certain gas gathering and tie-in agreements, EOC was
committed to meeting certain minimum volume levels during the term of the
agreement. As of September 30, 1997 and December 31, 1996, the volume levels
were below the required minimums and EOC accrued approximately $2,431,000 and
$2,231,000 for this shortfall, which was included with long-term liabilities.
The Company's cumulative delivery shortfall through September 30, 1997 was
approximately 12.1 million MMbtu. Effective October 1, 1997, the Company sold
all of its San Juan Basin properties for $580,000 along with the assumption of
EOC's volume commitment to El Paso Services. As of October 1, 1997, the Company
eliminated the obligation to El Paso Services.
The Company is a guarantor of a line of credit and a capital lease for
Maverick for an aggregate amount of $2.5 million. The guaranteed obligations
amounted to $1.1 million at December 31, 1997.
In connection with the Chilean oil and gas exploration contract, the
Company will be required to spend approximately $300,000 for geologic mapping,
aeromagnetic and gravity surveys during 1998 and
F-16
<PAGE>
EVERGREEN RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEAR AND NINE MONTHS ENDED DECEMBER 31, 1997
AND 1996 AND YEAR ENDED MARY 31, 1996
approximately $1,500,000 for a seismic program during the years 1999 and 2000.
In connection with the 1998 commitment, the Company has issued letters of
credit totaling $300,000 which expire in June 1998.
The following is a summary of the Company's outstanding natural gas fixed
price hedge as of December 31, 1997.
<TABLE>
<CAPTION>
Duration Volume Fixed Price
-------------------- ---------------- -------------
<S> <C> <C>
January - March 1998 21,500 MMBTU/day $2.04 - $2.17
April - October 1998 21,500 MMBTU/day $1.73 - $2.17
</TABLE>
Subsequent to December 31, 1997, the Company entered into the following
additional natural gas hedges.
<TABLE>
<CAPTION>
Duration Volume Fixed Price
-------------------- ---------------- -------------
<S> <C> <C>
April - October 1998 5,000 MMBTU/day $1.80
</TABLE>
(13) OTHER INCOME
In September 1995, the Company sold its interest in ANGI Limited for
$580,000 which resulted in a gain of approximately $525,000. This amount was
included in "Other Income" in the accompanying Consolidated Statements of
Operations.
(14) SHAREHOLDER RIGHTS PLAN
On July 7, 1997, the Board of Directors adopted a Shareholder Rights Plan
("Rights Plan"), pursuant to which stock purchase rights were distributed as a
dividend to its 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.
In the event that a person or group acquires 20% or more of the Company's
common stock, the Rights would then be modified to represent the right to
receive for the exercise price Company common stock having a value worth twice
the exercise price.
In the event that the Company is involved in a merger or other business
combination at any time after a person or group has acquired 20% or more of the
Company's common stock, the Rights will be modified as to entitle a holder to
buy a number of shares of common stock of the acquiring entity having a market
value of twice the exercise price of each right.
All Rights held or acquired by a person or group holding 20% or more of the
Company's shares are void. The Rights are not triggered by continued stock
ownership of the Company's existing 20% shareholders, unless these Shareholders
increase their holdings in the Company above 30%.
F-17
<PAGE>
EVERGREEN RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEAR AND NINE MONTHS ENDED DECEMBER 31, 1997
AND 1996 AND YEAR ENDED MARCH 31, 1996
(15) 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 and
the United Kingdom. The following costs were incurred in oil and gas
acquisition, exploration, development, gas gathering and producing activities
at:
<TABLE>
<CAPTION>
United United
States Kingdom Total
----------- -------- -----------
<S> <C> <C> <C>
DECEMBER 31, 1997
Development $10,193,600 $ $10,193,600
Gas gathering 9,914,800 - 9,914,800
Exploration 736,800 384,800 1,121,600
DECEMBER 31, 1996
Acquisition costs:
Proved $ 7,215,400 $ $ 7,215,400
Unproved 600, 000 - 600,000
Gas gathering 3,484,600 - 3,484,600
Development 4,229,900 4,229,900
Gas gathering 5,452,400 - 5,452,400
Exploration - 96,000 96,000
MARCH 31, 1996
Development $ 3,476,700 $ $ 3,476,700
Gas gathering 223,000 - 223,000
Exploration 155,000 516,700 671,500
</TABLE>
Aggregate capitalized costs and related accumulated depreciation, depletion
and amortization relating to oil and gas producing activities are as follows:
<TABLE>
<CAPTION>
United United
States Kingdom Total
------------ ---------- ------------
<S> <C> <C> <C>
DECEMBER 31, 1997
Proved properties $ 58,937,182 $ - $ 58,937,182
Unproved properties 1,823,415 7,877,423 9,700,838
------------ ---------- ------------
60,760,597 7,877,423 68,638,020
Accumulated depletion,
depreciation
and amortization (13,668,286) - (13,668,286)
------------ ---------- ------------
Net capitalized costs $ 47,092,311 $7,877,423 $ 54,969,734
------------ ---------- ------------
------------ ---------- ------------
DECEMBER 31, 1996
Proved properties $ 49,323,572 $ - $ 49,323,572
Unproved properties 1,086,629 7,492,591 8,579,220
------------ ---------- ------------
50,410,201 7,492,591 57,902,792
Accumulated depletion,
depreciation and
amortization (11,867,582) - (11,867,582)
------------ ---------- ------------
Net capitalized costs $ 38,542,619 $7,492,591 $ 46,035,210
------------ ---------- ------------
------------ ---------- ------------
</TABLE>
F-18
<PAGE>
EVERGREEN RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEAR AND NINE MONTHS ENDED DECEMBER 31, 1997
AND 1996 AND YEAR ENDED MARCH 31, 1996
Oil and gas property costs of $9,700,800 were not being amortized at
December 31, 1997. These costs consisted of $7,877,400 related to the U.K. and
$1,823,400 related to domestic properties. The Company will classify the
unevaluated costs for the U.K. as evaluated costs when future development of the
Current Licenses 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
years.
The Company is in the process of developing properties in the United
Kingdom ("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 "Current
Licenses"). In connection with such conversion, the Company relinquished rights
to approximately 259,000 acres, which were not considered highly prospective for
coalbed methane development. Under the Current Licenses, the Company retains
approximately 371,000 acres, which were high-graded for coalbed methane and
conventional hydrocarbon potential. The Current 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 Current Licenses. Work commitments for acreage retained will
include remote sensing studies, additional seismic studies and the drilling of
three wells, one per year beginning in 1999. Work commitments on the Current
Licenses have been fulfilled through 1997 as a result of ERI's prior U.K.
activity. The Company is in the process of developing a new seismic program to
identify a new five well drilling project. The drilling project is scheduled
for late 1998 or first quarter of 1999.
Results of operations from United States production activities for the year
and nine months ended December 31, 1997 and 1996 and the year ended March 31,
1996 are presented in accordance with Financial Accounting Standards No. 69,
"Disclosures About Oil and Gas Activities," which excludes consideration of
general and administrative, and interest expense. There was no production
activity in the United Kingdom.
<TABLE>
<CAPTION>
Nine Months
Year Ended Ended Year Ended
December 31, December 31, March 31,
1997 1996 1996
----------- ------------ ----------
<S> <C> <C> <C>
Oil and gas sales $12,137,869 $3,502,385 $1,392,695
----------- ---------- ----------
Lease operating expense 2,007,388 700,875 656,899
Depreciation and depletion 2,793,946 965,794 589,936
Gas gathering costs 112,358 110,363 218,644
----------- ---------- ----------
4,913,692 1,777,032 1,465,479
----------- ---------- ----------
Results of operations
from producing activities $ 7,224,177 $1,725,353 $ 72,784
----------- ---------- ----------
----------- ---------- ----------
Depreciation, depletion and
amortization per equivalent MCF $.44 $.46 $.59
----------- ---------- ----------
----------- ---------- ----------
</TABLE>
F-19
<PAGE>
EVERGREEN RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEAR AND NINE MONTHS ENDED DECEMBER 31, 1997
AND 1996 AND YEAR ENDED MARCH 31, 1996
OIL AND GAS RESERVES (UNAUDITED)
The estimates of the Company's proved 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, 1997 and
1996 and March 31, 1996. 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
crude oil and natural gas (all of which are located within the United States),
as well as the changes in proved reserves, are as follows:
<TABLE>
<CAPTION>
Natural Gas Oil
Proved Reserves (Mcf) (Bbls)
--------------- ----------- --------
<S> <C> <C>
At April 1, 1995 57,882,000 842,900
Revisions of previous estimates (3,482,000) -
Extensions and discoveries 31,163,500 -
Sales (3,696,300) (828,400)
Production (941,200) (9,700)
----------- --------
At March 31, 1996 80,926,000 4,800
Revisions of previous estimates 4,625,400 (2,200)
Extensions and discoveries 30,109,100 -
Purchases of reserves 37,163,600 -
Production (2,104,400) -
----------- --------
At December 31, 1996 150,719,700 2,600
Revisions of previous estimates (3,987,900) -
Extensions and discoveries 89,720,600 -
Sales of reserves (5,637,100) (2,600)
Production (6,401,500) -
----------- --------
At December 31, 1997 224,413,800 -
----------- --------
----------- --------
Proved Developed Reserves as of:
--------------------------------
March 31, 1996 41,359,700 4,800
December 31, 1996 88,751,500 2,600
December 31, 1997 143,553,500 -
</TABLE>
F-20
<PAGE>
EVERGREEN RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEAR AND NINE MONTHS ENDED DECEMBER 31, 1997
AND 1996 AND YEAR ENDED MARCH 31, 1996
The following table sets forth a standardized measure of the estimated
discounted future net cash flows attributable to the Company's proved oil and
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 $1.87 per mcf of gas
at December 31, 1997, $1.61 per Mcf of gas at December 31, 1996 and $1.50 per
Mcf of gas at March 31, 1996. 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 oil and gas reserves and the tax basis of proved oil and gas
properties and available operating loss and excess statutory depletion
carryovers.
<TABLE>
<CAPTION>
Nine Months
Year Ended Ended Year Ended
December 31, December 31, March 31,
1997 1996 1996
------------- ------------ ------------
<S> <C> <C> <C>
Future cash inflows $ 418,531,800 $242,761,200 $121,049,400
Future Production costs (55,331,800) (58,542,800) (30,640,700)
Future Development costs (17,790,000) (11,790,300) (7,389,400)
Future income taxes (90,128,100) (34,865,300) (13,789,400)
------------- ------------ ------------
Future net cash flows 255,281,900 137,562,800 69,229,900
10% discount to reflect timing of cash flows (137,529,000) (81,319,200) (44,076,600)
------------- ------------ ------------
Standardized measure of discounted future
net cash flows $ 117,752,900 $ 56,243,600 $ 25,153,300
------------- ------------ ------------
------------- ------------ ------------
</TABLE>
The following summarizes the principal factors comprising the changes in
the standardized measure of discounted future net cash flows for the year and
nine months ended December 31, 1997 and 1996 and the year ended March 31, 1996.
<TABLE>
<CAPTION>
Nine Months
Year Ended Ended Year Ended
December 31, December 31, March 31,
1997 1996 1996
------------- ------------ ------------
<S> <C> <C> <C>
Standardized measure, beginning of
period $ 56,243,600 $25,153,300 $23,312,300
Sales of oil and gas, net of production
costs (10,018,100) (2,691,200) (517,100)
Extensions and discoveries 52,587,400 10,546,000 10,500,400
Net change in sales prices, net of
production costs 30,171,200 4,434,700 2,866,900
Purchase of reserves - 20,122,700 -
Sale of reserves (2,150,300) - (5,542,300)
Revisions of quantity estimates (3,131,000) 2,478,000 (1,567,000)
Accretion of discount 7,049,900 3,016,300 1,664,300
Net change in income taxes (27,318,000) (9,244,800) (5,010,100)
Changes in future development costs 8,596,100 4,212,800 2,293,900
Changes in rates of production and other 5,722,100 (1,784,200) (2,848,000)
------------ ----------- -----------
Standardized measure, end of period $117,752,900 $56,243,600 $25,153,300
------------ ----------- -----------
------------ ----------- -----------
</TABLE>
F-21
