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.
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.
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.
Reference should be made to Supplemental Oil and Gas Information beginning on page 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.
AVERAGE SALES PRICES AND LOE
The following table sets forth the average sales price and the average LOE per Mcfe, for the periods indicated.
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.
ACREAGE
At December 31, 1997, Evergreen held developed and undeveloped acreage as set forth below:
LOCATION
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.
DRILLING ACTIVITIES
The Company's drilling activities for the periods indicated are set forth below:
* 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.
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
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
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
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:
- ------------- * 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.
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
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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
NOT APPLICABLE.
PART II
ITEM 5.
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:
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
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.
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. The recast consolidated financial data is unaudited and is presented to reflect the results of operations as if the Company had adopted a December 31 year end for the year ended December 31, 1996. 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.
ITEM 7.
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. The recast operating data is presented to reflect the operations as if the Company had adopted a December 31 year end for the twelve months ended December 31, 1996.
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.
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
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.
RESULTS OF OPERATIONS
HISTORICAL YEAR ENDED DECEMBER 31, 1997 COMPARED TO RECAST FISCAL YEAR 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 $545,000 or $0.08 per common share (basic), for the year 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.
Oil and gas revenues were $12,138,000 during the year ended December 31, 1997 as compared to $3,986,000 for the year 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. The average gas prices were $1.90 per Mcf for the year ended December 31, 1997 as compared to $1.63 per Mcf in 1996. Natural gas production increased to 6,401,500 Mcf for the year ended December 31, 1997 as compared to 2,407,800 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 $751,000 for the year ended December 31, 1996. Cost of oil and gas services for the year ended December 31, 1997 increased to $842,000 from $805,000 in 1996.
Interest income decreased to $132,000 for the year ended December 31, 1997 from $207,000 for the year 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 $826,000 for the year ended December 31, 1996. Lease operating expenses per Mcfe declined to $0.31 during the year ended December 31, 1997 from $0.34 in 1996. The decrease in the average lease operating expense per Mcfe was due to the economies 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 $1,137,000 for the year ended December 31, 1996. The increase of $1,657,000 is due to the substantial increase in natural gas production.
General and administrative expenses increased to $1,225,000 for the year ended December 31, 1997 as compared to $717,000 for year ended December 31, 1996. The $508,000 increase was due to the general increase in overall corporate activity, including salaries and professional services. Although the overall expense increased from the year ended December 31, 1997, the cost per Mcfe decreased to $0.19 from the prior year cost per Mcfe of $0.30.
Interest expense increased to $778,000 for the year ended December 31, 1997 from $193,000 for the year ended December 31, 1996. This $585,000 increase was due to increased borrowings under the Company's Credit Facility and an increase in the equipment lease facility. 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 $18,000 for the year ended December 31, 1996. The increase in other expenses was due primarily to the write off of a receivable that was deemed uncollectible.
YEAR ENDED DECEMBER 31, 1997 COMPARED TO THE NINE MONTHS ENDED DECEMBER 31,
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,
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.
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
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.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS PAGE ---- Report of Independent Certified Public Accountants
Consolidated Balance Sheets, December 31, 1997 and 1996
Consolidated Statements of Operations for the Year and Nine Months Ended December 31, 1997 and 1996 and for the Year ended March 31, 1996
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
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
Notes to Consolidated Financial Statements to
ITEM 9.
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.
PART IV
ITEM 14.
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 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.
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.
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
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
EVERGREEN RESOURCES, INC. CONSOLIDATED BALANCE SHEETS
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
EVERGREEN RESOURCES, INC. CONSOLIDATED STATEMENTS OF OPERATIONS
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
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
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
EVERGREEN RESOURCES, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
EVERGREEN RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEAR AND NINE MONTHS ENDED DECEMBER 31, 1997 AND 1996 AND YEAR ENDED MARCH 31,
(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.
EVERGREEN RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEAR AND NINE MONTHS ENDED DECEMBER 31, 1997 AND 1996 AND YEAR ENDED MARCH 31,
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.
EVERGREEN RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEAR AND NINE MONTHS ENDED DECEMBER 31, 1997 AND 1996 AND YEAR ENDED MARCH 31,
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.
EVERGREEN RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEAR AND NINE MONTHS ENDED DECEMBER 31, 1997 AND 1996 AND YEAR ENDED MARCH 31,
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:
EVERGREEN RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEAR AND NINE MONTHS ENDED DECEMBER 31, 1997 AND 1996 AND YEAR ENDED MARCH 31,
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:
Included in fixed assets are the following assets under capital leases:
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:
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:
As of December 31, 1997, the Company has net operating loss carryforwards for tax purposes of approximately $30 million which expire beginning in 2003.
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:
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.
EVERGREEN RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEAR AND NINE MONTHS ENDED DECEMBER 31, 1997 AND 1996 AND YEAR ENDED MARY 31, 1996
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:
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:
(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:
(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
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:
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
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.
Subsequent to December 31, 1997, the Company entered into the following additional natural gas hedges.
(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%.
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:
Aggregate capitalized costs and related accumulated depreciation, depletion and amortization relating to oil and gas producing activities are as follows:
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.
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:
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.
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.