ITEM 1. BUSINESS GENERAL DEVELOPMENT OF BUSINESS
The Exploration Company (the "Company" or "TXCO") was incorporated in the State of Colorado on May 16, 1979, for the purpose of engaging in oil and gas exploration, development and production and became publicly held through an offering of its common stock in November, 1979. In May 1999, the Company changed its state of incorporation from Colorado to Delaware, becoming The Exploration Company of Delaware, Inc. The Company continues doing business as The Exploration Company and its trading symbol on the Nasdaq Stock MarketSM remains TXCO. Effective in January 2000, the Company changed its annual reporting period from a fiscal year ending August 31 to a calendar year ending December 31.
Throughout its history, the Company's primary focus has been oil and gas exploration and production. Its long term business strategy has been to acquire undeveloped mineral interests and to develop a multi-year inventory of drilling prospects internally through the application of state of the art technologies, such as 3-D seismic and enhanced horizontal drilling techniques. The Company strives to discover, develop and/or acquire more oil and gas reserves than it produces each year from these internally-developed prospects, as well as selectively participating with industry partners in prospects generated by TXCO as well as by other parties. The Company also attempts to maximize the value of its technical expertise by contributing its geological, geophysical and operational knowledge base in its core areas through joint ventures or other forms of strategic alliances with well capitalized industry partners in exchange for carried interests in seismic acquisitions, leasehold purchases and/or wells to be drilled. From time to time, the Company offers portions of its developed and undeveloped mineral interests for sale. The Company finances its activities through a combination of internally generated cash flow, debt financing, equity offerings or sale of interests in properties.
Prior to 1992, the Company's revenues were derived principally from the sale of natural gas and oil production from working, royalty and mineral interests, as well as the sale of mineral interests it acquired through its leasing activities. From 1992 through 1996 the Company expanded its activities by entering the then emerging alternative fuels vehicle conversion business through the creation of its ExproFuels division. In 1996, Management redirected its focus and resources to its core oil and gas exploration and production business. Accordingly, the ExproFuels division was incorporated and a majority equity interest spun-off via a stock dividend to TXCO shareholders.
The continued availability of new equity and debt capital in fiscal years 1997 through 2000 reaffirm Management's ongoing strategy for improved shareholder value by maintaining its focus on its core business of gas and oil exploration and production. This strategy has allowed the Company to attract well-capitalized industry partners, expand its core area leasehold acreage, increase its 3-D seismic database, dramatically grow its production base and attain profitability by growing through its drill bit success. During the year ended December 31, 2000, the Company realized the best operating results in its 21 year history, maintaining profitability throughout the year, and ending its record breaking year 2000 with revenues of over $14,731,000 and net income of $6,761,000. Net income for 2000 includes the impact of a deferred federal income tax benefit of $5,231,000 reflecting the cumulative future tax benefit of a portion of its net operating loss carry forwards from past losses.
The following table illustrates various aspects of the Company's growth over the last 4 fiscal years ended:
Over the last four years, TXCO has grown its natural gas production base significantly. This overall growth is primarily attributable to ongoing drilling activities and the acquisition of significant new leasehold acreage in the
Company's core area of operations, the Maverick Basin of South Texas. The growth is also reflected in the changed mix in leasehold: expansion in Texas acreage acquisitions, versus reduction in the Williston acreage through expiration or maturing leases. During the same periods, operating revenues were significantly impacted by commodity price fluctuations, as the industry struggled to regain its momentum after the crash in oil and gas prices in 1997. Average gas prices per Mcf ranged from $2.65 in 1997, dropping steadily to $2.07 per Mcf in 1999, before spiking to record levels, doubling to $4.10 for the current year average. Success in growing the Company's production levels through drilling brought operating profitability for the first time in TXCO's recent history, overcoming 1999's erratic commodity prices. The improvements in gas prices during 2000 and the current winter grew its profitability and provided the Company with record levels of cash flow from operations. While 1999 and 2000 drill bit reserve replacement rates did not keep pace with the respective years' production levels, they compared favorably to the 1999 domestic industry wide replacement rate of 58% as published by the U.S. Department of Energy. The decline in production was also indicative of the maturing profile of the Company's existing Glen Rose reef gas wells, its primary source of gas production.
TXCO is pursuing multiple opportunities in 2001 to diversify its exploration targets within its core area of operations by aggressively expanding its surrounding lease holding where geology indicates the likely continuation of known gas producing formations as well as the strong likelihood of establishing new gas production from additional formations. The Maverick Basin offers this diversity in its multiple hydrocarbon bearing formations. During 1999 and 2000, the Company made significant strides in identifying and pursuing the exploration of two new promising exploration targets, as well as continuing its exploration for Glen Rose reef-based gas production. TXCO has succeeded in positioning itself at the forefront of exploration for CBM (coal bed methane gas) production, and believes it became the largest holder of CBM prospective acreage in Texas by the end of 2000. An exploratory core and well drilling program for CBM was initiated in 2000, with significant expansion plans for 2001, including funding for at least 36 wells and a related gas gathering system targeting multiple seams of high-volitile bituminous coal present under a 250,000 acres portion of its leases.
The second diversification program targets the deep Jurassic interval located under most of TXCO's 365,000 acreage block at the base of the Maverick Basin. A new 3-D seismic acquisition program was completed at year end 2000 by TXCO's operating partner, Blue Star Oil and Gas Ltd. (Blue Star), further delineating the world class hydrocarbon potential of this under explored rift basin. The Company cautiously expects significant progress towards the drilling of the initial well on its Paloma lease to test this deep interval during the year 2001. In February 2001, the Company unveiled a new partnership restricted to the deep rights below the San Miguel under its 100,000 acre Comanche prospect with an additional set of industry partners, including Saxet Energy (20% WI) of Houston and a large Denver-based publicly traded independent exploration company (30% WI). The immediate focus of the venture is the ongoing acquisition of 3-D seismic data across 78 square miles of the acreage. Drilling for significant gas-bearing Glen Rose reefs should follow prior to year end. Should these exploration and development plans progress as intended, The Exploration Company expects these programs to cause it to resume its growth in gas reserves and production levels, while insuring ongoing increases in revenues and profitability.
PRINCIPAL AREAS OF ACTIVITY
OIL AND GAS OPERATIONS
Throughout the year, the Company has been actively developing its core mineral interests in the Maverick Basin in South Texas, while evaluating its economic alternatives related to its remaining properties in the Williston Basin in North Dakota, South Dakota and Montana. These activities included participation in the drilling or recompletion of 26 gas wells in South Texas during 2000 and 1 well in the Williston Basin. The increase in Maverick Basin drilling activity reflects the Company's continued ability to generate sufficient working capital from profitable internal operations and from industry sources, allowing for expansion of its Texas-based lease acreage holdings and natural gas exploration and production activities. Stable Maverick Basin gas production during 2000 combined with dramatically increasing gas prices resulted in improved positive cash flows for the year. Although crude oil prices also stabilized during the year, industry activity or interest has not returned to pre-1998 levels in the area of the Williston Basin where the Company's leases are located. The Company's strategy remains focused on its core gas producing and exploration activities in the Maverick Basin.
MAVERICK BASIN
The Company has owned at least a 50% leasehold interest in a minimum of 50,000 contiguous acres in Maverick County, Texas since 1989. These holdings have
increased to 365,000 acres through 2000. Originally the lease block consisted of two leases, the Paloma with 33,000 acres and the Kincaid with 17,000 acres. The lease block is situated on the Chittim Anticline, a large regional structure, under which hydrocarbons have been found in as many as seven separate horizons dating back over 65 years. One of these zones is the Lower Glen Rose or Rodessa interval. It is a carbonate formation that has produced billions of cubic feet of natural gas from patch reefs within the zone. Past development in the area was halted due to the inability of previous operators to accurately predict the location of these porosity-bearing reefs. Utilizing new technological advances, the Company applied an innovative processing method to the 2-D seismic available in the area and confirmed a method of locating these porosity intervals.
Between 1993 and 1998, the Company expanded its in-house geophysical database to include multiple 3-D seismic surveys totaling over 55 square miles, covering approximately 36,000 acres of its Maverick Basin leases. Company geologists and geophysicists conclusively identified and mapped numerous geological formations at various depths on its leases. The mapping has provided numerous drilling alternatives for future evaluation of the multiple horizons known to be productive for oil and/or gas within and around its leases in the Maverick Basin. Consistent with the capital resources available, the Company has been selectively developing the Glen Rose interval. The shallower intervals provide alternative completion targets while pursuing the underlying reefs.
From 1989 to 1998, TXCO participated in the drilling of 26 wells in the Maverick Basin, with increasing degrees of drilling success. By the end of 1998, TXCO's daily net gas production from its Maverick Basin properties reached 1.96 MMcf (million cubic feet) from 16 gas wells. While successful in locating Glen Rose patch reefs, the Company's geologists and geophysicists could not distinguish between those containing hydrocarbons and those containing water. Management continued to review technical data gained with the drilling of each well, to modify its seismic interpretation model and improve its ability to distinguish between water-filled reefs and gas-filled reefs in expanding the geologically defined area known as the Prickly Pear Field. During 1998, 6 new gas well discoveries in succession on the Paloma Lease extended the Prickly Pear Field by several miles north and east of its previous recognized boundaries. The 6 wells produced gross daily production volumes ranging from 1 MMcf to 4 MMcf per well.
Fiscal year 1999 brought a continuation of growth in new production and revenues for the Company, as well as the expansion of TXCO's leasehold position over the Maverick Basin. During 1999, the Company acquired interests in over 39,000 acres of additional oil and gas leases in the immediate areas surrounding its Maverick Basin production, bringing its total lease position to approximately 90,000 acres at year end. During the year, TXCO participated in drilling 10 gas prospects, resulting in 5 new gas wells, further expanding the known producing area of the Prickly Pear Field on the Company's Paloma lease. Four of the other wells were drilled on leases acquired during fiscal 1999, while one was located on the Company's Kincaid lease. All 5 of these stepout wells were at least 5 to 9 miles from the nearest Prickly Pear Field production. Their drilling resulted in 2 completed oil wells and 1 completed gas well during 1999. Of the other 2 step out wells, one was completed as a marginal gas producer in 2000, while the other completion was not economic and remains shut-in pending its conversion for use as a salt water disposal well.
The turn of the century brought many changes for TXCO. Effective January 1, 2000 the Company adopted a calendar year end of December 31, leaving the fiscal year end of August 31. During the 4 month transition period from August 31 thru December 31, 1999, TXCO initiated drilling on 3 gas prospects, one each on the Paloma, Chittim and Alkek leases. This drilling resulted in 1 new gas reef well on the Paloma lease, 1 marginal gas well on the Chittim lease and 1 non-economic well on the Alkek lease which was plugged and abandoned. 3-D seismic acquisition also progressed during this period, as the Company completed the acquisition of an additional 31,700 acres of seismic data over a portion of newly leased acreage contiguous and north of its Paloma lease. At January 1, 2000, leased acreage totaled approximately 115,000 acres. During the transition period, TXCO also completed negotiations and entered into a joint operating agreement with Blue Star Oil and Gas, Ltd., for the development of its deep Jurassic prospect underlying its Paloma and Kincaid leases.
Calendar year 2000 marked a year of dramatic growth in numerous directions for TXCO as leasehold acreage, operating revenues and operating profits all reached record levels. During 2000, the Company's Maverick Basin core area lease block grew to over 365,000 acres primarily due to two transactions. The Company acquired lease interests consisting of all depths under 95,000 acres on the Comanche Ranch in March plus an option to lease the shallow depths above the base of the San Miguel formation on 150,000 acres on the adjoining Chittim Ranch in June. Both leases are prospective for CBM production and various shallow oil and gas bearing zones above the base of the San Miguel formation. In addition, the Comanche lease covers all depths including the deep Jurassic interval. The Chittim lease option was exercised in January, 2001.
TXCO expanded its exploration efforts by participating in drilling a total of 25 new gas, oil or CBM prospects and 2 re-entries during the 2000. Of the drilling wells, 5 have been completed as producers, with 2 Paloma gas wells, 1 marginal Kincaid oil well, 1 marginal Chittim gas well and 1 marginal Chittim oil well. Both of the re-entry attempts resulted in marginal completions, including 1 Chittim gas well and 1 Paloma oil well. A total of 14 wells remained in progress at year end. Included were 7 new CBM wells involved in the initial stages of an ongoing dewatering pilot program on the Comanche lease. Of the remaining 7 wells, 1 Burr gas well and 1 Burr oil well were completed during the first quarter of 2001, while the remaining 5 wells are in varying stages of completion and include 2 Paloma wells, and 1 well each on the Alkek and Wipff lease in Texas and the Hutzenbiler lease in North Dakota.
At year end December 2000, TXCO's daily net gas production from its Maverick Basin properties was 7.4 MMcf of the total gross operated production of 17.0 MMcf from 29 gas wells. At current gas prices, this production level should allow the Company to internally generate sufficient working capital to fund its fiscal year 2001 development plans. The expanding geophysical database, historical drilling results and the evolving family of prospective formations targeted by the Company and its partners continue to support the Company's longstanding belief that it has significant exploration and development possibilities remaining on its expanding Maverick Basin lease block. At year end 2000, the Company owned leases and options totaling over 365,000 acres. Included in this total were options for 150,000 acres which were exercised in January 2001. Through 2000, the Company has accumulated 231 square miles of 3-D seismic data over much of its Maverick Basin lease block, with evidence of 40 additional porosity-bearing Glen Rose patch reefs scattered across its extensive acreage position. The Company's Comanche Ranch acreage acquisition in the first quarter of 2000 included access to 70 miles of 2-D seismic data that indicate the existence of 45 additional Glen Rose Reef locations. Based on current drilling activity rate, these 85 patch reefs represent a potential four to five year drilling inventory of new gas well prospects .
JURASSIC FORMATION
Fiscal 1999 marked the year that the Company's concerted efforts resulted in a new partnership to explore the potential of the Jurassic formation under its lease block. Fiscal 2000 showed marked progress in expanding the 3-D seismic database over a much larger portion of the Maverick Basin.
Commencing in September 1999, Blue Star designed the 3-D seismic acquisition program over the 426 square mile area of the Maverick Basin targeted by the venture. The initiation of field data acquisition work followed and continued through the year. While interrupted by unseasonably wet conditions through part of the year, the extensive data acquisition portion of the project was completed late in the third quarter of 2000. In November, pursuant to its exploration joint venture with the Company, Blue Star confirmed that it had completed its seismic data acquisition phase and was performing the required seismic processing on the entire 426 square miles of 3-D seismic data, including all of the intended TXCO leases and Blue Star's Chittim Ranch lease. By year end, Blue Star had also shared with TXCO's Jurassic project management team its preliminary results from the data migration, processing and initial interpretation of the new data. Based on the encouraging preliminary interpretations of the 3-D seismic data available to it, Blue Star continued to indicate it anticipated beginning preparations to drill the first Jurassic test well on TXCO's Maverick Basin acreage during the first or second quarter of 2001. On March 13, 2001 Blue Star's senior executives contacted TXCO management and announced they were applying enhanced 3-D seismic processing techniques on the seismic field data. Blue Star further advised that the expanded seismic processing would take several months to finalize and could cost them an additional $1 million. See further discussion on the most recent developments relating to the Jurassic Blue Star project as set forth in ITEM 2.
ITEM 2. PROPERTIES
PHYSICAL PROPERTIES
The Company's administrative offices are located at 500 North Loop 1604 East, Suite 250, San Antonio, Texas. These offices, consisting of approximately 7,850 square feet, are leased through February 28, 2005 at $11,791 per month with annual escalations each March 1.
All the Company's oil and gas properties, reserves, and activities are located onshore in the continental United States. There are no quantities of oil or gas subject to long-term supply or similar agreements with foreign government authorities.
PROVED RESERVES, FUTURE NET REVENUE AND PRESENT VALUE OF ESTIMATED FUTURE NET REVENUES
The following unaudited information as of December 31, 2000, relates to the Company's estimated proved oil and gas reserves, estimated future net revenues attributable to such reserves and the present value of such future net revenues using a 10% discount factor (PV-10 Value), as estimated by Netherland Sewell & Associates, Inc., a Dallas, Texas engineering firm. Estimates of proved developed oil and gas reserves attributable to the Company's interest at December 31, 2000 and August 31, 1999 and 1998 are set forth in Notes to the Audited Financial Statements included in this Annual Report on Form 10-K. The PV-10 Value was prepared in accordance with SEC requirements using constant prices as of the calculation date, discounted at 10% per year on a pretax basis, and is not intended to represent the current market value of the estimated oil and natural gas reserves owned by the Company.
PV-10 Value of Years Ending Estimated Future December 31 Net Revenues ----------- -------------- 2001 $ 20,370,000 2002 8,335,000 2003 3,795,000 2004 1,882,000 2005 983,000 Thereafter 1,670,000 --------------
TOTAL $ 37,035,000 ==============
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas liquids and natural gas 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 oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. No reserve estimates have been filed with or included in reports to any federal or foreign government authority or agency, other than the Securities and Exchange Commission, since the Company's latest Form 10-K filing.
PRODUCTION
The following table summarizes the Company's net oil and gas production, average sales prices, and average production costs per unit of production for the periods indicated. With respect to newly drilled wells, there can be no assurance that current production levels can be sustained. Depending upon reservoir characteristics, such levels of production could decline significantly.
(1) Oil and gas were combined by converting oil to gas Mcf equivalent on the basis of 1 barrel of oil = 6 Mcf of gas. Production costs include direct lease operations and production taxes.
PRODUCING PROPERTIES - WELLS AND ACREAGE
The following table sets forth the Company's producing wells and developed acreage assignable to such wells at December 31, 2000:
Productive wells consist of producing wells and wells capable of production, including shut-in wells and wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities.
A "gross well" or "gross acre" is a well or acre in which a working interest is held. The number of gross wells or gross acres is the total number of wells or acres in which working interests are owned. A "net well" or "net acre" is deemed to exist when the sum of fractional ownership interest in gross wells or gross acres equals one. The number of net wells or net acres is the sum of fractional working interests owned in gross wells or gross acres expressed as whole numbers and fractions thereof.
UNDEVELOPED ACREAGE
As of December 31, 2000, the Company owned, by lease or in fee, the following undeveloped acres, all of which are located in the Continental United States, as follows: Estimated FY2001 United States Gross Acres Net Acres Delay Rentals - ------------- ----------- --------- ------------- Texas 214,000 172,000 $ 281,000 North Dakota 277,000 201,000 125,000 South Dakota 15,000 12,000 4,000 Montana 10,000 6,000 1,000 --------- --------- --------- Totals 516,000 391,000 $ 411,000 ======== ======= =======
In addition, at December 31, 2000 the Company held under option 150,939 gross and 131,716 net acres in Maverick and Zavala County in South Texas. In January 2001 the Company exercised this option and purchased a lease covering this acreage.
Five large Texas leases totaling approximately 66,000 gross acres contain varying requirements to drill a well every 90 to 150 days to keep the respective lease in effect. The Company is presently drilling under the terms of the leases and expects to keep the leases in force by continuous development during the year.
DRILLING ACTIVITY
During calendar 2000, the Company's drilling activity increased to 27 wells drilled or re-entered compared to 10 in fiscal 1999. In addition, current year activity included ongoing drilling operations on 2 wells that were in progress at the end of year 1999. The following table sets forth the Company's drilling activity for the last three fiscal years:
Included in the respective year 2000 columns were 2 producing (1.63 net) gas wells and 1 (0.25 net) dry well drilled during the four month transition period ended December 31, 1999, plus 1 producing (0.5 net) gas well spudded in the prior fiscal year. In addition to the wells detailed in the table above, the Company had an interest in 14 wells (11.81 net) in progress at December 31, 2000 from current year drilling and 1 well (0.88 net) from the prior fiscal year.
During the year 2000 the Company re-entered 2 (1.84 net) existing wells, of which one well is currently producing, while the other well was in progress at December 31. Re-entry wells are not classified as current year drilling wells and accordingly are not included in the above table.
MAVERICK BASIN
Throughout the 1990's, the Company pursued a strategy to expand its core Maverick Basin producing properties. In addition to using internally generated working capital for exploration and development activities, TXCO accelerated its growth, where possible, by entering into strategic joint ventures or operating agreements targeted at leveraging the Company's increased leasehold values, recognized technical abilities and exploration success in its core area of interest. TXCO entered into several new joint venture or joint operating agreements during 2000 while advancing on ventures entered into in past years, whereby the Company successfully teamed with qualified industry partners who contributed investment capital, mineral leases, 3-D seismic data and/or offered the Company a carried interest in mineral leases, 3-D seismic acquisition programs and wells to be drilled. These contributions were made in exchange for TXCO's geophysical, geological and operational expertise, and in certain instances, in exchange for an interest in a portion of the Company's non-producing oil and gas lease interests .
During September 1998, the Company entered into two separate joint operating agreements (JOA), one with Ashtola Exploration Company, Inc. and the second with Picosa Creek Partnership. In the first, TXCO earned a 63% working interest in Ashtola's 8,800 acre Alkek lease adjoining TXCO's Paloma lease, together with rights to an existing 3-D seismic survey over the subject block. The acreage was contributed to a new JOA dated May, 1999 with Castle Exploration Company and is being developed in conjunction with the new JOA discussed below. Two wells were drilled under the Picosa Creek JOA during 2000. Both were placed on production by year end, one as a gas well, and the other as an oil producer.
In November 1998, the Company finalized a JOA with Ameritex Ventures, II Ltd., a joint venture owned 85% by Enron Capital, allowing Ameritex and its partners to earn a 50% interest in the shallow and intermediate depths in TXCO's existing 17,000 acre Kincaid lease by their funding 100% of a 27 square mile 3-D seismic program over 17,000 acre in 1999. During 2000, three gas prospects were drilled under the agreement resulting in one marginal oil completion and two non-economic wells which were plugged and abandoned.
In May 1999, the Company finalized a JOA with Castle Exploration Company, a subsidiary of Castle Energy Corporation, (Nasdaq:CECX) whereby Castle committed up to $5,300,000 to fund 100% of the costs of purchasing leases, acquire 3-D seismic and drill up to 12 Glen Rose reef wells on targeted acreage contiguous to TXCO's productive Paloma lease. TXCO was named as operator, and contributed its 8,800 acre Alkek lease in exchange for shared rights to all 3-D seismic acquired, a 25% carried interest in the initial 12 wells, a 50% interest in future lease acquisitions and up to a 50% interest in all wells to be drilled on the leases. Pursuant to the agreement, Castle funded 100% of TXCO's costs to lease 31,700 acres and complete a 3-D seismic acquisition program by November
1999. During 2000, the partners drilled two wells under the agreement. Neither well encountered economic quantities of gas and both were plugged and abandoned. Accordingly, Castle exercised its option under the agreement not to carry the Company on subsequent wells. Under the current phase of the agreement, TXCO retains its 50% interest in all acreage and 3-D seismic acquired and can participate with a 50% interest in all future wells to be drilled on the leases.
In August 1999, the Company purchased from Peacock-Maverick Drilling and Peacock Exploration their interests in producing wells and oil and gas leases covering in aggregate 24,500 acres in exchange for 325,000 shares of TXCO common stock valued at $493,594. The purchase included a 12.5 % working interest in a 12,800 acre tract out of the 190,000+ acre Chittim Ranch, including 6 producing gas wells located thereon. The acreage is contiguous to the eastern flank of TXCO's Paloma lease. In addition, the Company received a 100% working interest in the Wipff/Shaw lease, totaling 11,700 acres located within 5 miles to the west of TXCO's Paloma lease.
In September 1999, the Company finalized a JOA with Blue Star for an exploration project targeting the deep Jurassic interval underlying TXCO's Maverick Basin lease block. Blue Star paid TXCO a cash consideration upon closing and agreed to fund 100% of a 426 square mile 3-D seismic acquisition program including over 37,000 acres of TXCO's Paloma and Kincaid leases. Blue Star was also obligated to provide the Company approximately 50,000 acres of new 3-D seismic survey data, of TXCO's selection from the completed 426 square mile survey. In addition, Blue Star agreed to fund 100% of the costs of drilling 2 exploratory wells to test the deep Jurassic interval. Should both wells be drilled timely, Blue Star would earn a 50% interest in the deep rights in TXCO's Paloma and Kincaid leases covering in aggregate 50,000 acres. TXCO and its partners would keep a 50% working interest in future Jurassic wells drilled under the agreement. According to the original agreement, should initial drilling not occur within certain deadlines, Blue Star could be obligated to reimburse TXCO up to $900,000 for certain expenditures in order for Blue Star to maintain its rights under the agreement.
As of year end 2000, Blue Star had completed the acquisition of 3-D seismic data over 426 square miles of the Maverick Basin, including TXCO's related 37,000 acres. Preliminary results of the initial processing and interpretation of the Blue Star seismic data were extremely encouraging to the partners, and appear to corroborate the geologic model defined in the original 3-D seismic study completed by TXCO in 1999 which supports the premise that structures that could contain hydrocarbons are present in the Jurassic interval under its acreage block. Based on these encouraging results, Blue Star had continued to indicate it anticipated beginning preparations to drill the first Jurassic test well on TXCO's Maverick Basin acreage during the first or second quarter of 2001.
On March 13, 2001 Blue Star's senior executives contacted TXCO management and stated they were applying enhanced 3-D seismic processing techniques on the seismic field data. Blue Star advised that the expanded seismic processing could cost an additional $1 million and would take several months to finalize in order to better define their geologic model of the interval. Blue Star hopes to enhance its process of selecting the initial drilling locations to test the 18,000+ feet deep structure underlying the targeted acreage block. They further advised TXCO that the results of the expanded processing should reduce the initial drilling risk for the benefit of all its partners, enhancing the overall success of the venture while reducing exploration costs in the long term. Blue Star also advised TXCO they may not be able to complete their interpretation of the new processing and begin drilling activities before the end of 2001.
While the advent of new, more advanced technology may serve to reduce the overall drilling risks involved in this highly technical drilling project, undue delays in drilling the first well could cause the expiration of Blue Star's original option to drill on TXCO's acreage. By early March, 2001 the parties were pursuing discussions in an attempt to reach agreement on the status of Blue Star's compliance with the terms and intent of the original agreement. While discussions are continuing TXCO is reviewing it's options under the agreement in order to confirm the project is not being unreasonably delayed and to further assure the ultimate development of the project under Blue Stars' proposed new timetable.
During 2000, the Company continued to expand its core Maverick Basin properties. During the first quarter of 2000, the Company acquired a lease covering over 95,000 acres on the Comanche Ranch contiguous to the south of Blue Star's Chittim Ranch Lease and southeast of TXCO's existing Maverick Basin acreage block. The lease was granted by the Ewing Halsell Foundation giving the Company a 100% leasehold interest to all depths not reserved under any existing leases or held by production by other operators. There were no drilling obligations for six years and initial geologic interpretation indicated that multi-zone production potential existed, including a deep Jurassic structure below 16,000
feet. Other progressively deepening targets and intervals include CBM gas from the shallow Olmos formation, oil from the San Miguel and Austin Chalk formations, above 4,000 feet, and primarily natural gas from the mid-depth Georgetown, Glen Rose, Pearsall, and Sligo formations above 8,000 feet.
Early in the fourth quarter of 2000, the Company acquired 42 shut-in well bores from previous operators on its new Comanche Ranch Lease. Todate, 35 of these well bores have been identified as locations for re-entry prospective for coalbed methane (CBM) production. The Company believes CBM production will eventually make up a significant portion of the future gas production from this acreage.
Subsequent to year end, the Company sold 50% of its rights below the base of the San Miguel formation to Saxet Energy, Ltd., a privately held exploration company from Houston, Texas for a cash consideration. Saxet in turn later notified the Company that it sold 30% of its interest to a large publicly-traded independent energy company based in Denver. Saxet will be the operator of the new venture with the remaining 20% working interest. By year end, the new partners hired Dawson Geophysical (Nasdaq: DWSN) to acquire a proprietary, 100-square-mile 3-D survey over 78 square miles of the Comanche Ranch and 22 square miles of an adjoining property owned by Saxet.
In January 2001, the Company exercised its option to purchase a five-year oil and gas mineral lease for the shallow rights above the base of the San Miguel Formation on 150,000 acres of the Chittim Ranch acreage in Maverick County, Texas. The acreage is contiguous to and between the Company's Paloma/Kincaid lease block to the northwest and the Comanche Ranch Lease to the south. With some exceptions, the Company controls drilling rights from the surface to the base of the San Miguel Formation ranging from 2,700 to 3,500 feet in depth. TXCO's average working interest on the new Chittim lease is 88.8 %. This purchase increased the Company's leasehold position in the Maverick Basin to over 365,000 acres, and established the largest single leasehold position in the County. Within its holdings, the Company owns more than 250,000 acres of prospective CBM acreage covering portions of three South Texas counties, including Maverick, Dimmit and Zavala Counties, and believes this constitutes the largest block of CBM prospective acreage in the state of Texas.
At December 31, 2000, the Company's 3-D seismic database grew to approximately 231 square miles as compared to the 148 square miles last reported in 1999. During 2000, the Company received new seismic data totaling approximately 83 square miles over a portion of Blue Star's Chittim Ranch lease, contiguous to TXCO's Paloma/Kincaid lease block. The Company has engaged two consulting geophysicists to interpret the new data.
WILLISTON BASIN
TXCO was not active in the Williston Basin in 2000. While oil prices have stabilized during the year, industry interest has not returned to the level it reached prior to the price collapse of late 1997. No new drilling had been pursued since exploration activities were suspended in 1998. The Company did elect to participate in one outside operated drilling well proposed on a spacing unit in which TXCO owned a minor interest which it contributed to the unit. This was the only opportunity to contribute acreage to a drilling prospect identified during the year. TXCO contributed 10 net acres contiguous to a neighboring operator's prospect and joined in drilling the Hutzenbiler 1-19H. TXCO has a 1.60% working interest in this well which at December 31, 2000, was still in progress.
Throughout calendar 2000, the Company continued to evaluate its existing operations in the Williston Basin. Even with the higher oil prices during 2000, the Company's properties were still faced with high unit production costs and declining production volumes. The Company has continued to review the valuation of its properties through out the year, with particular emphasis on their continued economics. During the year, management identified one marginal producing property for impairment whose capitalized costs were in excess of anticipated future reserve potential. The Company also continued its selective lease maintenance program targeting primarily those leases not covered under existing 3-D seismic programs or otherwise not possessing known distinguishing features of particular geologic significance. During 2000, the Company evaluated the estimated fair value of the Williston Basin leases and after assessing the likelihood of recovering its cost on expiring acreage, charged to impairment expense a total of 123,400 acres whose lease terms are not expected to be renewed and will expire through April 2001.
Forward-looking statements in this 10-K are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Investors are cautioned that all forward-looking statements involve risks and uncertainty, including without limitation, the costs of exploring and developing new oil and natural gas reserves, the price for which such reserves can be sold, environmental concerns effecting the drilling of oil and natural gas wells, as well as general market conditions, competition and pricing. Please refer to all of TXCO's Securities and Exchange Commission filings, copies of which are available from the Company without charge, for additional information.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
The Company is not involved in any matters of litigation incidental to its business of a significant nature.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of the security holders of the Company during the 4th quarter of fiscal year 2000. During the 2nd quarter, on March 10, 2000, the Company held its Annual Meeting of Shareholders. The following matters were submitted for approval by vote at the meeting. All matters were approved by the shareholders vote and the results of the voting is shown below for each matter.
1. Election of Directors: For Against -------- ------- Stephen M. Gose, Jr. 11,376,969 271,959 Thomas H. Gose 11,377,069 271,859 James E. Sigmon 11,381,069 267,859 Michael Pint 11,381,069 267,859 Robert L. Foree, Jr. 11,381,069 267,859
The members of the Board of Directors do not serve staggered terms of office. There were no changes in Directors of the Company at the annual meeting.
2. Proposal for ratification of the adoption of Akin, Doherty, Klein & Feuge, P.C., as independent Auditors for the Company for the fiscal year 2000.
For Against Abstain --- ------- ------- 11,634,939 1,332 12,657
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The following is a range of high and low bid prices for the Company's common stock for each quarter presented based upon bid prices reported by the National Association of Securities Dealers Quotations system under the call symbol "TXCO": Range of Bid Prices Quarter Ended: High Low -------------- ---- ---
December 2000 $ 3.53 $ 2.50 September 2000 3.19 2.38 June 2000 3.22 1.88 March 2000 3.88 1.78
December 1999 (Four month Transition Period) 3.06 1.53
August 1999 $ 2.94 $ 1.00 May 1999 1.41 .75 February 1999 1.50 .62 November 1998 1.41 .75
As of March 1, 2001, there were approximately 1,650 holders of record of the Company's Common Stock. The transfer agent for the Company is EquiServe, Boston, Massachusetts. The Company has not paid any cash dividends on its Common Stock in past years and does not expect to do so in the foreseeable future.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial information is derived from and qualified in its entirety by the Audited Consolidated Financial Statements of the Company and the Notes thereto as set forth in this Annual Report on Form 10-K commencing on page.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following is a discussion of the Company's financial condition and results of operations. This discussion should be read in conjunction with the Financial Statements of the Company and Notes thereto.
CAPITAL RESOURCES AND LIQUIDITY
CALENDAR YEAR ENDED DECEMBER 31, 2000
During the year ended December 31, 2000, beginning cash reserves of $3,381,793 were increased by net cash provided from operating activities of $6,529,838 resulting in a total of $9,911,631 in internally generated working capital for use in funding the ongoing expansion, development and exploration of the Company's oil and gas properties. Strengthening gas prices were reflected in ongoing positive cash flow from operations in the latter half of the year and contributed significantly to the Company's ability to expand its planned activities. In February 2000, $2,810,248, net of offering costs, was provided through a private placement of common stock with Swisspartners Investment Network AG, a private investment firm based in Zurich, Switzerland. Proceeds from the placement were for general corporate purposes, but the timing of its receipt early in the year, allowed the Company to complete the acquisition of significant additional acreage in its core Maverick Basin area. The funding also provided additional flexibility to accelerate ongoing exploration activities. An additional $1,173,642 was provided during the year from new equipment purchase financing, while $100,000 was provided from the exercise of outstanding warrants for the purchase of shares of the Company's commons stock.
The Company applied $6,290,260 of its working capital to fund the expansion and ongoing development of its oil and gas properties. Included were drilling, completion and leasehold acquisition costs totaling $4,865,807 primarily targeting TXCO's core area, the Maverick Basin. Included in these costs were expenditures for the drilling, completion and re-entry of 29 gas and oil wells, new Maverick Basin mineral lease purchases of approximately 100,000 acres for the year. Also included was $1,347,505 applied in the expansion of the Company's Paloma lease gas gathering facilities, including the purchase of two new natural gas compressors at a total cost of $1,012,404.
The Company made timely payments of $1,658,386 on its long term debt obligations during 2000, while payments on interest totaled $179,036. These payments led to the early retirement in May, 2000, of the then remaining $1,015,731 due under the original 1998 financing agreement with Range Energy Finance Corporation (NYSE:RRC).
As a result of these activities, the Company ended the year 2000 with a positive working capital of $6,349,625 and a current ratio of 2.36 to 1. This greatly improved year end position compares to positive working capital of $207,660 and a current ratio of 1.04 at December 31, 1999. The dramatic increase in working capital is attributable to the growth in operating cash flow from ongoing operations, the Company's ability to raise equity capital and the improvements in commodity prices throughout the year. Management is confident of the Company's ability to continue to generate positive cash flow from operations and to meet its ongoing operating cash requirements for 2001 and beyond..
FOUR MONTH TRANSITION PERIOD ENDED DECEMBER 31, 1999
The Company changed its fiscal year from August 31 to December 31, effective for the calendar year beginning January 1, 2000. The four month transition period from September 1 through December 31, 1999 preceded the start of the new calendar year 2000 as presented above. The following discussion relates only to this four month transition period.
Cash reserves of $968,516 at August 31, 1999 were increased by cash provided from operating activities of $3,952,602 resulting in $4,921,118 in working capital available for use in meeting the Company's ongoing operational and development needs during the four month transition period ended December 31, 1999.
During this four month period, portions of this capital were used to fund payments on debt of $1,435,004 and interest of $131,872. The Company applied $196,103 to the expansion and ongoing development of its core oil and gas properties. These costs included drilling and completion costs for wells drilled or completed during the period and 3-D seismic acquisition and reprocessing costs.
As a result of these activities, working capital improved from a negative $1,524,594 at August 31, 1999 to a positive $207,660 at December 31,1999. The current ratio improved to a 1.04 to 1 compared to a current ratio of .70 to 1 at the beginning of the period. The improvement in working capital and current ratio levels were primarily due to sustained gas and oil production levels and continued strength in these commodity prices.
FISCAL YEAR ENDED AUGUST 31, 1999
During the year ended August 31, 1999, beginning cash reserves of $2,329,236 were increased by net cash provided from operating activities of $3,858,204 resulting in a total of $6,187,440 in working capital available for use in funding the Company's ongoing development and exploration of its oil and gas properties. The ongoing positive cash flow from operations throughout the year significantly improved the Company's ability to increase its core revenues from oil and gas operations, thereby enhancing its ability to overcome the impact of weak oil and gas prices through most of 1999. An additional $900,000 was obtained during the year, under the existing financing agreement with Range Energy Finance Corporation, bringing total borrowings from Range to $4,400,000. The financing was specifically for ongoing development of the Company's natural gas producing properties in Maverick County, Texas.
The Company applied $3,448,320 of its working capital to fund the expansion and ongoing development of its oil and gas properties. Included were drilling and completion costs of $2,791,544 for current year drilling of 10 Maverick Basin gas and oil wells, plus costs associated with 2 wells drilled during the last quarter of 1998. Also included were $211,101 in 3-D seismic acquisition and reprocessing costs and $390,000 in lease extension payments to maintain non-producing lease acreage in the Company's growing Maverick Basin lease block.
The Company made timely payments on long term debt of $2,629,118 during 1999, including $1,966,956 paid on the Range financing agreement. Scheduled payments totaling $662,162 were made on the Company's remaining long-term notes during the remainder of the year.
During the 3rd quarter of 1999, TXCO successfully entered into a joint venture agreement with Castle Exploration Company, (Castle) a wholly owned subsidiary of Castle Energy Corporation (Nasdaq:CECX), whereby Castle agreed to fund up to $5,300,000 for 100% of all costs to acquire approximately 25,000 acres of additional leases, fund a 42 square mile 3-D seismic survey and drill up to 12 gas wells. In exchange, TXCO contributed its interest in an 8,800 lease to the venture, was named operator and will be carried at no cost, for a 25% interest in the first 12 wells drilled. Additionally, TXCO will be licensed to share in all seismic data gathered and will earn a 50% working interest in all leases acquired with the funds. At year end, all 3-D seismic acquisition and processing had been completed, and Company geologists and geophysicists were in process of interpreting and evaluating the new data.
During the 4th quarter of 1999, the Company successfully closed another non-cash transaction to acquire various oil and gas mineral interests near or adjoining TXCO's Maverick Basin leasehold. In exchange for 325,000 shares of its restricted common stock valued at $493,594, the Company purchased a 12.5% interest in 12,800 acres known as the Chittim Lease, including a 12.5% working interest in 6 producing oil and gas wells and associated equipment. In addition, TXCO also received a 100% working interest in two separate leases totaling approximately 11,700 acres.
As a result of these activities, the Company ended fiscal year 1999 with negative working capital of $1,525,594 and a current ratio of .70 to 1. This compares to positive working capital of $516,693 and a current ratio of 1.19 to 1 at August 31, 1998. Working capital weakened during 1999 primarily due to cash outlays for its aggressive ongoing development activities and due to timely payments made under the terms of the Range financing agreement. Although the Company had a working capital deficit at year end, included in current liabilities is $2,110,620 estimated as the debt payment for fiscal 2000 under the Range financing agreement. The Range debt payments are only due and payable out of each future month's net cash flow from the collateralized producing wells.
FISCAL YEAR ENDED AUGUST 31, 1998
During the year ended August 31, 1998, beginning cash reserves of $6,198,069 were reduced by net cash used in operating activities of $1,185,050 resulting in a total of $5,013,019 in working capital available for use in funding the Company's ongoing development and exploration of its oil and gas properties, significantly improving the Company's potential to increase its core revenues from oil and gas operations, and enhancing its ability to overcome the impact of continued weakness in oil and gas prices.
Throughout fiscal 1998, the Company pursued opportunities to enhance its liquidity by the conversion of existing short term trade payables to long-term debt and the conversion of debentures into common stock. Management successfully converted 4 separate accounts totaling $1,684,000 in current trade payables into separate notes, with payment terms ranging from 12 to 36 months and interest accruing at rates ranging from 8% to 14%. Further improvements to the Company's debt structure were realized by Management's election to exercise the Company's option to convert its outstanding $4,000,000 debentures to equity. Effective January 1, 1998, the Company issued 844,318 shares of its common stock in exchange for the outstanding debentures, including accrued interest of $221,590, at the conversion price of $5.00 per share. In addition to the extremely favorable conversion price for the new issuance, and the elimination of $240,000 in future annual interest expense, Management's elimination of its primary long-term debt significantly enhanced the Company's ability to pursue additional sources of equity or debt-based working capital.
Late in the final quarter of 1998, the Company entered into a financing agreement with Range Energy Finance Corporation, a subsidiary of Range Resources Corporation (NYSE:RRC), (formerly Domain Energy Corporation) to initially establish a borrowing ceiling of $4,000,000. During fiscal year 1999 the borrowing ceiling was increased to $4,400,000. The financing was specifically for ongoing development of the Company's natural gas producing properties in Maverick County, Texas. Funds were advanced in exchange for a limited term overriding royalty interest tied to existing and future production from specified depths underlying certain of the Company's oil and gas leases in Maverick County. Terms provided for repayment of the funds, with interest at 18%, from a specified portion of sales proceeds from all existing and future wells to be drilled on the Paloma lease. By August 31, 1998 the Company had borrowed $3,500,000 under the agreement.
Throughout the year ended August 31, 1998, the Company applied $4,806,505 of its available working capital to fund the ongoing development of its oil and gas properties. This included drilling and completion costs of $3,385,720 associated with the current year drilling of four new Maverick Basin gas wells, three new Williston Basin oil wells and costs associated with 4 wells drilled prior to the current fiscal year, plus $188,785 for completion of the newest segment of the Company's new gas gathering system in Maverick County during 1998. Also included were 1998 3-D seismic acquisitions totaling $711,294 over Company leases in North Dakota and $153,845 on the Paloma lease in South Texas. Additional investments in non-producing lease acreage totaled $366,861 for the year.
Additionally, the Company made payments on its long-term debt during the year of $1,500,990. Included in the total was $940,481 paid during the first quarter, in full prepayment of the Company's outstanding line of credit with Luzerner Kantonalbank. Scheduled payments totaling $560,509 were made on the Company's remaining long-term notes during the remainder of 1998.
As a result of these activities, the Company ended fiscal year 1998 with positive working capital of $516,693 and a current ratio of 1.19 to 1. This compared to positive working capital of $3,760,648 and a current ratio of 2.32 to 1 at August 31, 1997. While the Company's working capital position weakened from the previous year, the results of the Company's dramatic 100% drilling success ratio during 1998 for new Glen Rose wells became evident during the first quarter of fiscal year 1999.
2001 CAPITAL REQUIREMENTS
The major components of the Company's plans, and the requirements for additional capital for 2001 include the following:
MAVERICK BASIN ACTIVITY:
Initial capital expenditures planned for 2001 total over $11,100,000, are presented net to the Company's interest, and are primarily on its Maverick Basin core properties . Included is $1,000,000 for targeted lease acquisitions in Maverick County during the first quarter of 2001. Additional 3-D seismic acquisition plans total $900,000 and consist primarily of a 78 square mile program commenced in February 2001 on the western most portion of the Comanche lease. Gas gathering infrastructure expansion plan expenditures total $1,400,000 for the 2001, including $1,100,000 for the Company's shallow CBM project in the Comanche lease, plus $300,000 for pipeline additions its Paloma lease pipeline system.
The largest component of 2001 planned capital expenditures total $7,350,000 for exploratory drilling wells and for an expanding number of re-entry targets available to the company due to its October 2000 acquisition of 42 shallow shut-in well bores prospective for CBM (coal bed methane) on the Comanche lease.
The Company plans to drill or re-enter a minimum of 51 wells, including 15 new Glen Rose reef prospects and 36 CBM new or re-entry prospects. A total of $3,750,000 is reserved for Glen Rose reef prospects, while $3,600,000 is planned for CBM exploration. Three of the Glen Rose wells are planned on the Comanche lease on a 50% WI basis under the Company's recently announced Comanche lease operating agreement, with Saxet Energy as operator. Drilling is expected to occur late in 2001, after 3-D seismic processing is completed on the ongoing seismic data acquisition program currently underway on the Comanche lease. The remaining 12 Glen Rose wells are targeted at reef prospects already defined by existing 3-D seismic on the remaining portion of the Company's Maverick Basin lease block. A typical Paloma lease Glen Rose reef well costs the Company approximately $225,000 to 275,000 to complete or $160,000 as a dry hole, on a net basis. Comanche lease Glen Rose prospects net drilling costs are expected to average $50,000 more than Paloma lease wells, as the Glen Rose interval trends deeper downdip when encountered under the Comanche lease.
The Company continues to benefit from its 25% carried interest in the ongoing 3-D seismic processing and interpretation activities continuing on its deep Jurassic project under its Paloma/Kincaid lease block, as all costs have been funded 100% todate by its partner and operator, Blue Star Oil and Gas, Ltd No substantial funding requirements are required of TXCO nor are any planned for 2001for the project.
Estimated expenditures required to maintain the Company's interest in all of its remaining undeveloped South Texas leasehold acreage for fiscal 2001 are approximately $280,000 exclusive of required drilling obligations.
WILLISTON BASIN ACTIVITY:
The Company plans to maintain its existing producing properties and the payment of delay rentals and lease extensions on selected undeveloped leases, with scheduled 2001 delay rentals of $130,000 and will continue in its efforts to offer remaining acreage, seismic data, and identified prospects to other industry operators.
SUMMARY OF CAPITAL RESOURCES AND LIQUIDITY
While management is confident it has identified sufficient sources of working capital to carry out its current exploration and development plans on its Texas leaseholds, as well as to meet its obligations in the ordinary course of business through the end of the new year, there is no assurance that energy prices will continue to improve. Should prices weaken, the reduction in revenues could cause the Company to re-evaluate its expected sources of working capital and may cause the Company to reduce its current operating plans.
Management is actively involved in ongoing discussions with various industry partners and domestic and foreign based sources of debt and equity financing. These parties could provide favorably structured drilling arrangements that, along with the Company's internally generated cash flow would provide funding as required to increase the Company's planned drilling activity during year 2001. Management remains confident that financial resources will remain available, enabling the Company to continue the rapid development of its gas and oil properties and continue to meet its normal operational and debt service obligations.
CHANGE IN FISCAL YEAR
A Form 8-K was filed on December 29, 1999, in order to report that the Board of Directors of the Company had elected to change its annual reporting period from a fiscal year ending August 31 to a calendar year ending December 31 effective for the calendar year beginning January 1, 2000. The transition period for this change was reported on February 4, 2000, on the Company's Transition Report on Form 10-Q for the four month period ended December 31, 1999.
RESULTS OF OPERATIONS
2000 COMPARED TO 1999
The Company reported net income of $6,761,935 or $0.39 per basic and diluted share for the fiscal year ended December 31, 2000, compared to a net income of $ 931,545 or $0.06 per basic and diluted share for the fiscal year ended August 31, 1999. The 626% increase included the result of recognition in the current year of a deferred tax asset of $5,232,718. The deferred tax asset reflects the cumulative future tax benefit of a portion of the Company's net operating loss carryforwards. The deferred tax benefit was recognized by a reduction to the valuation allowance established in prior years against the Company's deferred tax assets. Management believes it is now more likely than not that a significant portion of its deferred tax asset will be realized. Therefore, the valuation allowance was reduced and a deferred tax asset recognized for the amount expected to be realized through taxable earnings over the next three year period. Additionally, revenues increased 96% over 1999 levels due primarily to the substantial increase in prices received during the year. Average realized prices for gas rose to $4.10 per Mcf, a 98% increase, while average realized prices for oil rose to $27.85, a 127% increase. Total net gas production for the year 2000 was 2,965,000 Mcf, an increase of 152,000 Mcf over 1999. This increase resulted from 4 new gas wells being brought on line through the year, but was partially offset by the general production decline of the existing older gas wells. Total net oil production for the same periods decreased 12,000 Bbls to 60,000 Bbls in year 2000. This decline was primarily caused by the reduced production in the Williston Basin attributable to increased water production. Average daily net gas production in year 2000 increased 5% to 8,100 Mcf compared to fiscal 1999, while average daily net oil production in year 2000 decreased to 164 Bbls, a 27% decline compared to fiscal 1999.
Exploration expenses increased $2,787,000 compared to 1999 levels primarily due to the high dry hole expense resulting from accelerated exploration activities initiated during the current year. Current year charge-offs included the costs of 7 drilling wells to dry hole expense while the were no dry holes in the prior year.
Pursuant to the Successful Efforts Method of accounting for mineral properties, the Company periodically assesses its producing and non-producing properties for impairment. Abandoned leases and equipment expense increased by 224% primarily due to recognition of the expiration of 43,700 acres in the Williston Basin during year 2000 versus much fewer incidents of acreage costs being charged off during 1999. Similarly, impairment expense increased by 593% due to a 79,702 acres block of non-producing acreage in the Williston Basin expected to expire in early 2001. Depreciation, depletion and amortization increased by 16% over 1999 levels due primarily to the higher depletion rate resulting from decreased reserves for specific producing properties. The increase in depreciation was due to investment in equipment expanding the Paloma Lease Gathering System completed at mid-year.
General and administrative costs increased 30% compared to 1999 levels reflecting the higher sustained level of Company operations. Increased salaries and related costs due primarily to the addition of two employees and increased compensation levels over the comparable period in 1999. An increase in investor communications of $86,000 reflects the increased level of presentations and associated print and electronic material design and preparation costs incurred by the Company in conjunction with domestic and international investor and industry conferences during 2000.
The 214% increase in interest income reflects the higher cash levels in interest bearing accounts during 2000 versus 1999 levels. Interest expense decreased by $449,000 in 2000 from 1999 due to the retirement of the Range debt during the second quarter of 2000.
The minority interest in income of subsidiaries is a new line item resulting from the consolidation of TXCO's majority-owned subsidiaries. There were no consolidated subsidiaries in the prior year.
1999 COMPARED TO 1998
The Company reported net income of $931,545 or $0.06 per diluted share for the year ended August 31, 1999, compared to a net loss of ($ 8,417,218) or ($0.55) per diluted share for the same period in 1998. The attainment of profitability was primarily the result of a 146% increase in revenues over 1998 levels due primarily to significant new production from 9 new wells placed on line during the year, including 2 gas wells completed late in the last quarter of the prior year. While very positive, the increases were significantly offset by the weakness in oil and gas prices through the first half of 1999. Gas sales volume increases also reflect the impact of the first full year of operation of the expanded gas gathering system completed during the latter part of 1998.
Exploration expenses decreased by 88% compared to 1998 levels due to the high drilling success in the Maverick Basin compared to multiple Williston Basin dry holes drilled or abandoned during the prior year. Abandoned leases and equipment expense decreased by 78% primarily to the non-recurring nature of the one time charge off of uneconomical producing properties during 1998 due to the oil and gas price collapse during 1998. Impairment expense decreased by 92% also due to the non-recurring nature of the initially large impairment provisions required due to the oil price collapse in the prior year, while lower 1999 impairment provisions proved adequate in light of the improvement in realized oil and gas prices during the last half of the current year. Depreciation, depletion and amortization increased by 61% over 1998 levels due primarily to an increase in depletion. The change in depletion was due to the adverse impact on year end reserve estimates caused by declining oil production and increasing water disposal costs associated with Williston Basin production.
The decrease in loan fee amortization expense as compared to 1998, reflects the non-recurring nature of the prior period's recognition of $180,000 in previously capitalized prepaid loan fees due to the conversion of a $4,000,000 debenture in January 1998. Fiscal 1998 loan fee amortization expense has been reclassified for comparative purposes with current year expense. Interest expense increased by 142% over 1998, reflecting a full year of interest charges on borrowings under the Range financing agreement entered into during the last quarter of the prior year.
1998 COMPARED TO 1997
Revenues from oil and gas sales increased 195% over 1997 as a result of significant new production from the successful completion of the nine new wells during the last part of the 1997, plus the additional production from 4 new gas wells added during 1998. Lease operating expenses, related directly to the costs of operating the newly producing Williston Basin oil wells with very high production associated water disposal costs, increased by 297% over 1997. The disproportionately higher increase in lease operating expense increases reflects the difference in the Company's normal natural gas production expense level versus the significantly higher per unit production cost associated with its Williston Basin oil production.
Exploration expenses, including the costs of unsuccessful wells increased by 47% due to the write-off of two high working interest dry holes during the year compared to two very low working interest dry-holes in the previous year. The 40% fall of oil prices at mid-year rendered the completion of the wells uneconomical. Abandoned leases and equipment increased to $1,451,880, reflecting the ongoing impact of the 40% fall of oil prices during the year that rendered marginal properties uneconomic to maintain or renew. Included in the non-cash charge off for the current year are $608,573 in Williston Basin leases, $156,670 in Zavala County leases (South Texas), and $26,757 in Canadian Crown leases, all determined to be uneconomic and expiring during the current year due to the continued impact of low oil and gas prices. Also included in the 1998 non-cash writeoff was the remaining capitalized costs $659,880 for the Kincaid #1-99, a horizontal Georgetown test well drilled in Maverick County during the third quarter of 1997 that failed to produce economic quantities of gas.
Pursuant to the Successful Efforts Method of accounting for mineral properties, the Company periodically assesses its producing properties and non-producing mineral leases for impairment. Based on the 40% fall in oil prices during the year and the resulting impact on the updated reserve estimates at year end, the Company identified certain producing properties which required impairment. Additionally, non-producing leaseholds were reviewed for potential impairment. Certain leases, with expiration dates through December 1999, were identified which would not be renewed. Non-cash impairment charges totaling $3,655,342 were recorded at year end including $1,580,820 of Williston Basin and Texas non-producing leases set to expire through calendar year 1999. Additionally, a $2,194,522 impairment was recorded reflecting the excess of unamortized book value over the future realizable reserves primarily related to certain of its Williston Basin wells. Additional expenses during the year include depreciation, depletion and amortization of $1,446,726, plus current year exploration expenses of $2,290,649.
Except for the statutory, intangible (non-cash) expenses required for compliance reporting purposes described above and current year exploration expenses, actual operating activities for the year ended August 31, 1998 resulted in positive cash flow from producing operations of $989,484. This level of positive cash flow, if sustained, is sufficient to provide for funding of the Company's primary administrative operations. Management feels confident this source of internally generated working capital will continue to grow as the Company's Texas gas production levels expand through fiscal 1999 and beyond.
General and administrative costs increased to $1,278,270 from $938,000. Increases in salaries totaling approximately $211,000 were due primarily to a full twelve months of wages in 1998 for the increased number of new employee positions required by the Company's expansion in operations as a result of the Williston Basin lease acquisition versus only a partial year for the previous year. The $184,692 decrease in interest income in 1998 reflects the lower cash levels in interest bearing accounts during 1998 versus the prior year.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
COMMODITY RISK. The Company's major market risk exposure is the commodity pricing applicable to its oil and natural gas production. Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas. Prices have fluctuated significantly over the last four years and such volatility is expected to continue, and the range of such price movement is not predictable with any degree of certainty. A 10% fluctuation in the price received for oil and gas production would have an approximate $1.5 million impact on the Company's annual revenues and operating income.
INTEREST RATE RISK. The Company's exposure to interest rate risk is minimal as all of its debt at December 31, 2000 is at fixed rates.
FINANCIAL INSTRUMENTS: The Company's financial instruments consist of cash equivalents and accounts receivable. Its cash equivalents are cash investment funds which are placed with a major financial institution. Substantially all of the Company's accounts receivable result from oil and gas sales or joint interest billings to third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact the Company's overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Historically, the Company has not experienced any significant credit losses on such receivables. See Certain Business Risks section.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Consolidated Financial Statements and Notes thereto are set out in this Form 10-K commencing on page.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
None
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth certain information regarding the directors and executive officers of the Company, as of March 1, 2001:
Name Position Age ---- -------- ---
Stephen M. Gose, Jr. Chairman of the Board of Directors 71 Member Audit and Compensation Committees
Michael J. Pint Director, Chairman Audit and Compensation Committees 57
Robert L. Foree, Jr. Director, Member Audit and Compensation Committees 71
Alan L. Edgar Director, Member Audit and Compensation Committees 55
James E. Sigmon President and Director 52
Thomas H. Gose Director and Assistant Secretary 45
Roberto R. Thomae Chief Financial Officer 50 Secretary/Treasurer, Vice President-Finance
Richard A. Sartor Controller 48
Stephen M. Gose, Jr., has served as Chairman of the Board of Directors of the Company since July 1984. He has been a member of the Audit and Compensation Committees since June 1997 and served as their Chairman through April 1998. He served as a Director of the Company's former subsidiary ExproFuels, Inc. from 1994 through 1999. A geologist by training, he has been active for more than 45 years in exploration and development of oil and gas properties, in real estate development, and in ranching through the operations of Retamco Operating, Inc., its predecessors and affiliates.
Michael J. Pint has served as a Director since May, 1997. He has been a member of the Audit and Compensation Committees of the Board of Directors since June, 1997 and has served as their Chairman since April, 1998. Mr. Pint has 35 years banking experience, serving in the bank regulatory arena as well as in the capacity of chairman, president and director of 38 different banks and bank holding companies throughout the country. Since 1995, Mr. Pint has served as a Director of Valley Bancorp, Inc. and Valley Bank of Arizona, Inc. of Phoenix, Arizona and Midway National Bank of St. Paul, Minnesota. Previous bank regulatory and management positions include a four year term as Commissioner of Banks and Chairman of the Minnesota Commerce Commission from 1979 to 1983 and Senior Vice-President and Chief Financial Officer of the Federal Reserve Bank of Minneapolis, Minnesota through 1983.
Robert L. Foree, Jr. has served as a Director since May, 1997 and as a member of the Audit and Compensation Committees of the Board of Directors since June, 1997. A geologist by training, he has been active for more than 45 years in the exploration and development of oil and gas properties. Since 1992, Mr. Foree has served as President of Foree Oil Company, a privately held Dallas, Texas based independent oil and gas exploration and production company.
Alan L. Edgar, has served as a Director of the Company since May 2000 and as a member of the Audit and Compensation Committees of the Board of Directors since that time. He has been involved in energy related investment banking and equity analysis for over 28 years. Since 1998, Mr. Edgar has served as President of Cochise Capital, Inc. a privately held Dallas, Texas based company specializing in exploration and production related mergers and acquisitions advisory and financing. Previous public company mergers and acquisitions, investment banking and energy financing experience includes serving as Managing Director and Co-Head of the Energy Group of Donaldson, Lufkin & Jenrette Securities, Inc., from 1990 to 1997, serving as Managing Director of the Energy Group of Prudential-Bache Capital Funding from 1987 to 1990 and serving as Corporate and Research Director of Schneider, Bernet & Hickman, Inc. (Thompson, McKinnon) from 1972 through 1986.
James E. Sigmon has served as the Company's President since February 1985. He has been a Director of the Company since July 1984. He served as a Director of ExproFuels, Inc. through November 1998. As an engineer, Mr. Sigmon has been active for 30 years in the exploration and development of oil and gas properties. Prior to joining the Company, Mr. Sigmon served in the management of a private oil and gas exploration company active in drilling oil and gas wells in South Texas.
Thomas H. Gose has served as a Director of the Company since February, 1989, as Secretary from 1992 through March, 1997 and as Assistant Secretary since March, 1997. He served as President and Director of the Company's former subsidiary ExproFuels, Inc. from 1994 through 1999. Since October, 2000 he has served as President of NEOgas Ltd. a Houston based subsidiary of NEOppg International Ltd. NEOgas develops and markets technologies to transport and deliver compressed natural gas to markets with stranded gas production or stranded customer bases. He formerly served as Director, CEO and President of Retamco Operating, Inc., (a large shareholder of the Company) its predecessors and affiliates from 1987 to 1999. Thomas H. Gose is the son of Stephen M. Gose, Jr.
Roberto R. Thomae has served as Chief Financial Officer and Vice President-Finance of the Company since September 1996 and as Secretary/Treasurer since March 1997. From September 1995 through September 1996 he was a consultant to the Company in a financial management capacity. From 1989 through 1995 Mr. Thomae was self- employed as a management consultant primarily involved in the development of domestic and international oil and gas exploration projects and the marketing of refined products.
Richard A. Sartor has served as Controller of the Company since April 1997. A Certified Public Accountant since 1980, Mr. Sartor owned his own private accounting practice from 1989 through March 1997.
Each of the aforementioned Executive Officers and/or Directors have been elected by the shareholders to serve for one year or until his successor is duly elected except for Mr. Edgar who was appointed by the Board in May 2000 to serve until the next annual meeting of shareholders.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Summary Compensation Information: The following table contains certain information for each of the calendar and fiscal years and the 4 month transition period ended as indicated with respect to the chief executive officer and those executive officers of the Company as to whom the total annual salary and bonuses exceed $100,000:
(1) Amounts represent income from an overriding royalty interest. (2) Represent four month transition period for respective officer.
(1) The fair value for all options granted, whether vested or not, was estimated at the date of grant using the Black-Scholes option pricing model with the following weighted-average assumption: risk-free interest rate of 6.48%; dividend yield of 0%; volatility factors of the expected market price of the Company's common stock of 1.21 and a weighted-average expected life of the option of five years.
(1) Value of unexercised options calculated as the difference in the stock price at period end and the option price.
(2) 100,000 of Mr. Sigmon's unexercised options were exercisable as of December 31, 2000, and the remaining 600,000 options vest and are exercisable in specified amounts upon the Company's common stock attaining the following price levels: 200,000 shares at $5.00; 100,000 shares at $7.50; 100,000 shares at $10.00; 100,000 shares at $12.50 and 100,000 shares at $15.00.
COMPENSATION OF DIRECTORS
Members of the Board of Directors who serve as Executive Officers of the Company are not compensated for any services provided as a Director. Outside (non-employee) Directors of the Company are paid a fee of $1,000 plus reimbursement of related travel expenses for each board meeting physically attended or $250 for telephonic attendance. Beginning in 1997, upon assuming Director status, new outside directors have been awarded 10 year options ( Directors Options) for the purchase of 75,000 shares of Company common stock at 110% of the stock's market value on the date of grant, with such options vesting equally over their first three years of service. During 2000, the Board of Directors unanimously approved a two component strategy intended to re-align long term incentives for all of its directors. This strategy was the result of the expansion of the number of seats on the board by one and the election of a sixth director in May 2000. The strategy provided for the issuance of Directors Options to the two directors whose election to the Board predated the 1997 award regimen thereby precluding their previous receipt of Directors Options. The second component included a repricing of the exercise prices of existing Directors Options (those issued to directors elected prior to 2000) equal to the exercise prices as granted the newest outside director elected in May 2000.
EMPLOYMENT CONTRACTS
The Company has an employment agreement with its president, Mr. James E. Sigmon, which sets his salary at a minimum of $175,000 annually, and includes the grant of a proportionately reduced 1% overriding royalty interest under all leases the Company has or acquires during his term as President. The agreement is cancelable with 90 days notice by the Company.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
No Compensation Committee interlocks existed during the Company's last completed year. The Compensation Committee of the Board of Directors of the Company was established in June, 1997 and currently consists of Michael J. Pint (Chairman), Robert L. Foree, Jr., Stephen M. Gose, Jr. and Alan L. Edgar, upon his election in May 2000. The principal function of the Committee is to approve the compensation of all executive officers of the Company, to recommend to the Board the terms of principal compensation plans requiring stockholder approval and to direct the administration of the Company's 1995 Flexible Incentive Plan.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following tables set forth beneficial ownership of the Company's common stock, its only class of equity security. The percent owned is based on 17,471,849 shares outstanding and 20,472,078 fully diluted shares which includes 3,000,229 shares under options and warrants as of March 15,2001.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
The following table sets forth information concerning all persons known to the Company to beneficially own 5% or more if its common stock, including information filed pursuant to Rule 13d filings made available to the company during the year.
Name and Address of Number of Shares Beneficial Owner Beneficially Owned Percent Owned ---------------- ------------------ -------------
Thomas H. Gose 916,601 5.25% 517 Morningside San Antonio, TX 78209
Stephen M. Gose, Jr. 1,080,127 6.18% HCR Box 1010 Hwy 212 Roberts, Montana 59070
Trianon Opus One, Inc. 1,350,500 7.73% Fohrenstrasse 25 CH-8703 Erlenbach Switzerland
Swisspartners Investment Network AG 1,333,333 7.63% Am Schanzengraben 23 Postfach 970 Switzerland
Tahoe Invest 1,190,000 6.81% Innere Guterstrasse 4 6304 Zug Switzerland
SECURITY OWNERSHIP OF MANAGEMENT
The following table sets forth the number of shares of common stock beneficially owned as of March 15, 2001by each director, each executive officer named in the Summary Compensation Table and by all directors and executive officers as a group. Information provided is based on Forms 3,4, 5, stock records of the Company and the Company's transfer agent.
Number of Shares Percent Name Beneficially Owned Owned(1) ---- ------------------ --------
Stephen M. Gose, Jr. (3)(7) 1,080,127 5.83% James E. Sigmon (2) 750,000 4.13% Thomas H. Gose (7) 916,601 5.25% Michael Pint. (4) 350,000 1.99% Alan L. Edgar (5) 258,333 1.47% Robert L. Foree, Jr. (4) 86,000 .49% Roberto R. Thomae (6) 100,000 .57%
All Directors and Executive Officers as a group 3,578,561 18.21%
(1) Except as otherwise noted, the Company believes that each named individual has sole voting and investment power over the shares beneficially owned.
(2) The number of shares beneficially owned by Mr. Sigmon includes 50,000 shares owned directly and 700,000 shares of the Company's Common Stock reserved for issuance through options issued under the Company's 1995 Flexible Incentive Plan.
(3) The number of shares beneficially owned by Mr. Gose, Jr. include 20,000 shares owned directly, plus his 100% interest, shared equally with his spouse, in 1,060,127 shares owned by Retamco Operating, Inc.
(4) The number of shares beneficially owned by Mr. Pint and Mr. Foree each includes 75,000 shares of the Company's Common Stock reserved for issuance under non-qualified options issued to outside directors of the Company exercisable at March 15, 2001 plus 275,000 and 11,000 respectively, of directly owned shares.
(5) The number of shares beneficially owned by Mr. Edgar includes 125,000 shares owned directly and 133,333 shares of the Company's Common Stock reserved for issuance under 5 year warrants, granted in February 2000, for services rendered prior to his election as a director.
(6) The number of shares beneficially owned by Mr. Thomae includes 100,000 shares of the Company's Common Stock reserved for issuance through options issued under the Company's 1995 Flexible Incentive Plan exercisable at March 15, 2001.
(7) None of the 75,000 shares reserved for issuance under non-qualified options received respectively by Mr. Gose Jr. or Mr.Thomas Gose during the year were vested at March 1, 2001 and accordingly are not included in their beneficially owned share total above
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
In December 1999, the Company retained the consulting advisory services of Mr. Alan L. Edgar for the identification of and negotiation assistance with potential sources of debt or equity capital investment in the Company. In February 2000 the Company completed the private placement of 1,333,333 shares of new common stock at a price of $2.25 per share, with Mr. Edgar's assistance. Pursuant to the terms of his consulting agreement, upon closing, Mr. Edgar received a 6% advisory fee totaling $180,000 and 5 year warrants, exercisable at $3.00 per share, to purchase 133,333 shares of the Company's common stock. Mr. Edgar was appointed to the Company's Board of Directors in May, 2000
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(A) The following documents are being filed as part of this annual report on Form 10-K after the signature page, commencing on page.
(1) Consolidated Financial Statements:
Independent Auditors' Reports. Balance Sheets, December 31, 2000 and December 31, 1999. Statements of Operations, Years Ended December 31, 2000, August 31, 1999 and 1998, and the Four Month Transition Period Ended December 31, 1999. Statements of Stockholders' Equity, Years Ended December 31, 2000, August 31, 1999 and 1998, and the Four Month Transition Period Ended December 31, 1999. Statements of Cash Flows, Years Ended December 31, 2000, August 31, 1999 and 1998, and the Four Month Transition Period Ended December 31, 1999. Notes to Audited Consolidated Financial Statements.
(2) Financial Statement Schedules.
Schedule II - Valuation and Qualifying Reserves.
All other schedules for which provision is made in the applicable accounting regulations of the Securities and Exchange Commission are omitted as the required information is inapplicable or the information is presented in the Consolidated Financial Statements or Notes thereto.
(3) Exhibits:
** 3.1 Articles of Incorporation of the Registrant filed as Exhibit 3(B) to the registration statement on Form S-1; Reg. No. 2-65661. ** 3.2 Articles of Amendment to Articles of Incorporation of The Exploration Company, dated July 27, 1984, filed as Exhibit 3.2 to Registrant's Annual report on Form 10-K, dated February 4, 1985. ** 3.3 Articles of Amendment to the Articles of Incorporation of the Exploration Company dated April 2, 1985. ** 3.4 By-Laws of the Registrant filed as Exhibit 5(A) to the Registration Statement on Form S-1; Reg. 2-65661. ** 3.5 Amendment to By-Laws of registrant,dated September 1, 1985. ** 3.6 Articles of Amendment to the Articles of Incorporation of The Exploration Company dated April 6, 1990. **10.2 Employment Agreement between the Registrant and James E. Sigmon, dated October 1, 1984. **10.3 Registrant's Amended and Restated 1983 IncentiveStock Option Plan filed as Exhibit A to registrant's definitive Proxy Statement, dated February 20, 1985. **10.4 Registrant's 1995 Flexible Incentive Plan, filed as Exhibit A to registrant's definitive Proxy Statement, dated April 28, 1995. **10.5 Registrant's Form S-8 Registration Statement for its 1995 Flexible Incentive Plan, dated November 26, 1996. **10.6 Registrant's Amendment to its 1995 Flexible Incentive Plan, filed as Proposal II of the registrants definitive Proxy Statement, dated January 12, 1999. **10.7 Registrant's Plan and Agreement of Merger of The Exploration Company with and into The Exploration Company of Delaware, Inc., filed as Appendix A of the registrants definitive Proxy Statement, dated January 12, 1999.
**10.8 Registrant's Certificate of Incorporation of The Exploration Company of Delaware, Inc., filed as Appendix B of the registrants definitive Proxy Statement, dated January 12, 1999. **10.9 Registrant's Certificate of Amendment of Certificate of Incorporation of The Exploration Company of Delaware, Inc., filed as Appendix C of the registrants definitive Proxy Statement, dated January 12, 1999. **10.10 Registrant's Bylaws of The Exploration Company of Delaware, Inc., filed as Appendix D of the registrants definitive Proxy Statement, dated January 12, 1999. **10.11 Registrant's Rights Agreement, filed as Exhibit 4.1 of the registrants Form 8-K, dated June 29,2000 which includes: as Exhibit A thereto, the Certificate of Designation ofSeries A Junior Participating Preferred Stock;as Exhibit B thereto,Form of Right Certificate; as Exhibit C thereto, Summary of Rights to Purchase Preferred Shares.
** Previously filed
(B) Reports on Form 8-K:
No reports on Form 8-K were filed during the quarter ended Dec. 31, 2000.
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.
THE EXPLORATION COMPANY OF DELAWARE, INC. Registrant
March 15, 2001 By: /s/James E. Sigmon ---------------------- James E. Sigmon, President
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders The Exploration Company of Delaware, Inc. and Subsidiaries San Antonio, Texas
We have audited the consolidated balance sheets of The Exploration Company of Delaware, Inc. and Subsidiaries (collectively referred to as "The Exploration Company") as of December 31, 2000 and 1999, and the related consolidated statements of operations, stockholders' equity and cash flows for the years ended December 31, 2000, August 31, 1999 and 1998, and the four months ended December 31, 1999. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of The Exploration Company as of December 31, 2000 and 1999, and the results of its operations and cash flows for the years ended December 31, 2000, August 31, 1999 and 1998, and the four months ended December 31, 1999, in conformity with generally accepted accounting principles.
We have also audited Schedule II of The Exploration Company for the years ended December 31, 2000, August 31, 1999 and 1998, and the four months ended December 31, 1999. In our opinion, this schedule presents fairly, in all material respects, the information required to be set forth therein.
AKIN, DOHERTY, KLEIN & FEUGE, P.C.
San Antonio, Texas March 2, 2001
THE EXPLORATION COMPANY Consolidated Balance Sheets
See notes to audited consolidated financial statements.
THE EXPLORATION COMPANY Consolidated Balance Sheets
See notes to audited consolidated financial statements.
THE EXPLORATION COMPANY Consolidated Statements of Operations
See notes to audited consolidated financial statements.
THE EXPLORATION COMPANY Consolidated Statements of Stockholders' Equity
See notes to audited consolidated financial statements.
THE EXPLORATION COMPANY Consolidated Statements of Cash Flows
See notes to audited consolidated financial statements.
THE EXPLORATION COMPANY Notes to Audited Consolidated Financial Statements
NOTE A - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION AND OPERATIONS: The Exploration Company (TXCO or Company) is an independent energy company engaged in the exploration, development, production and acquisition of oil and gas properties. The Company's primary focus is on developing gas reserves on properties located in Texas, and oil reserves on properties located in South Dakota, North Dakota and Montana.
During 1999, the Company changed its State of Incorporation from Colorado to Delaware and, as a result, changed its legal name to The Exploration Company of Delaware, Inc. However, the Company continues to conduct all business under the name The Exploration Company.
CONSOLIDATION: The financial statements include the accounts of the Company and its majority-owned subsidiaries. The subsidiaries own and operate a gas pipeline which is utilized by the Company for delivery of natural gas from some of its Texas properties. All significant intercompany balances and transactions have been eliminated in consolidation.
CHANGE IN FISCAL YEAR: The Company changed its fiscal year end from August 31 to December 31, effective for the fiscal year beginning January 1, 2000. The four-month transition period from September 1 through December 31, 1999 preceded the start of the new year. The fiscal years ended August 31, 1999 and 1998 have not been recast to conform to the new year end of December 31.
REVENUE RECOGNITION: The Company recognizes oil and gas revenue from its interest in producing wells as the oil and gas is sold from the wells.
CASH EQUIVALENTS: The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.
OIL AND GAS PROPERTIES: The Company uses the successful efforts method of accounting for its oil and gas activities. Costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells that find proved reserves, and to drill and equip development wells are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed as incurred.
DEPRECIATION, DEPLETION AND AMORTIZATION (DD&A) of oil and gas properties is computed using the unit-of-production method based upon recoverable reserves as determined by the Company's independent reservoir engineers. Oil and gas properties are periodically assessed for impairment. If the unamortized capitalized costs of proved properties are in excess of the undiscounted future cash flows before income taxes, the property is impaired. Future cash flows are determined based on management's best estimate and may consider changes in prices for the product as considered most likely to occur in future periods. Unproved properties are also evaluated periodically and if the unamortized cost is in excess of estimated fair value an impairment is recognized.
OTHER PROPERTY AND EQUIPMENT: Transportation and other equipment are recorded at cost. Depreciation is computed using the straight-line method over the estimated useful lives of the assets ranging from five to fifteen years. Major renewals and betterments are capitalized while repairs are expensed as incurred.
FEDERAL INCOME TAXES: The Company follows the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the future tax consequences. Accordingly, deferred tax liabilities and assets are determined based on the temporary differences between the financial statement and tax bases of assets and liabilities, using enacted tax rates in effect for the year in which the differences are expected to reverse.
NOTE A - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - continued
EARNINGS (LOSS) PER COMMON SHARE: The Company applies SFAS No. 128, Earnings Per Share, for 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 the Company.
FINANCIAL INSTRUMENTS: The Company's financial instruments that are exposed to concentrations of credit risk consist primarily of cash equivalents and accounts receivable. The Company's cash equivalents are cash investment funds which are placed with a major financial institution. Substantially all of the Company's accounts receivable result from oil and gas sales or joint interest billings to third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact the Company's overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Historically, the Company has not experienced credit losses on such receivables.
Unless otherwise specified, the Company believes the book value of the financial instruments approximates their fair value.
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 financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserve volumes and the related present value of estimated future net cash flows, and the estimate of future years' earnings used as a basis to record the deferred tax asset.
STOCK OPTIONS: The Company applies Accounting Principle Board (APB) No. 25, Accounting for Stock Issued to Employees, and related interpretations in accounting for all stock option plans. Statement of Financial Accounting Standards (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.
GOVERNMENT REGULATIONS: The Company's oil and gas operations are subject to Federal, state and local provisions regulating the discharge of materials into the environment. Management believes that its current practices and procedures for the control and disposition of such wastes substantially comply with applicable federal and state requirements.
RESTORATION, REMOVAL AND ENVIRONMENTAL MATTERS: The estimated costs of restoration and removal of producing property well sites is generally less than the estimated salvage value of the respective property; accordingly, the Company has not provided for a liability accrual. The estimated future costs for known environmental remediation requirements are accrued when it is probable that a liability has been incurred and the amount of remediation costs can be reasonably estimated. The Company is not aware of any such remediation requirements material to its operations.
RECENT ACCOUNTING PRONOUNCEMENTS: The Financial Accounting Standards Board has not issued any recent pronouncements not previously implemented by the Company which would have a significant impact its financial position or on the reporting of its operations.
NOTE B - LONG TERM DEBT
Long-term debt consists of the following at:
The following is a schedule of maturities of long-term debt as of December 31, 2000:
NOTE C - STOCKHOLDERS' EQUITY
PREFERRED STOCK: The Company has authorized 10,000,000 shares of preferred stock, none of which has been issued at December 31, 2000. Terms of the stock have not been established by the Board of Directors.
STOCKHOLDER RIGHTS PLAN: On June 29, 2000, the Company adopted a Rights Plan (the "Rights Plan") whereby a dividend of one preferred share purchase right (a "Right") was paid for each outstanding share of TXCO common stock. 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. The Rights will be exercisable only if a person acquires beneficial ownership of 15% or more of TXCO common stock (an "Acquiring Person"), or commences a tender offer which would result in beneficial ownership of 15% or more of such stock. When they become exercisable, each Right entitles the registered holder to purchase from TXCO .001 share of Series A Preferred Stock ("Series A Preferred Stock"), subject to adjustment under certain circumstances.
Upon the occurrence of certain events specified in the Rights Plan, each holder of a Right (other than an Acquiring Person) may purchase, at the Right's then current exercise price, shares of TXCO common stock having a value of twice the Right's exercise price. In addition, if, after a person becomes an Acquiring Person, TXCO is involved in a merger or other business combination transaction with another person in which TXCO is not the surviving corporation, or under certain other circumstances, each Right will entitle its holder to purchase, at the Right's then current exercise price, shares of common stock of the other person having a value of twice the Right's exercise price. The Rights Plan generally may be amended by the Company without the approval of the holders of the Rights prior to the public announcement by TXCO or an Acquiring Person that a person has become an Acquiring Person.
Unless redeemed by TXCO earlier, the Rights will expire on June 29, 2010. The Company will generally be entitled to redeem the Rights in whole, but not in part, at $0.01 per Right, subject to adjustment. No Rights were exercisable under the Rights Agreement at December 31, 2000.
STOCK OPTIONS: The Company grants options to its officers, directors, and key employees under its 1995 Flexible Incentive Plan. In 1998, the Company also issued options for the purchase of 600,000 shares of common stock under a nonqualified plan. The Company has elected to follow Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," (APB 25) and related Interpretations in accounting for its employee stock options because, as discussed below, the alternative fair value accounting provided for under FASB Statement No. 123, "Accounting for Stock-Based Compensation," (FASB 123) requires use of option valuation models that were not developed for use in valuing employee stock options. Under APB 25, because the exercise price of the Company's employee stock options equals or exceeds the market price of the underlying stock on the date of grant, no compensation expense is recognized.
The Company's 1995 Flexible Incentive Plan, as amended, was authorized to grant options to management, directors, and key personnel for up to 1,500,000 shares of the Company's common stock. All options granted have ten year terms and vest and become fully exercisable based on the specific terms imposed at the date of grant.
NOTE C - STOCKHOLDERS' EQUITY - continued
Pro forma information regarding net income and earnings per share is required by FASB 123, which also requires that the information be determined as if the Company has accounted for its employee stock options granted subsequent to 1994 under the fair value method of that Statement. The fair value for these options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted-average assumptions:
The Black-Scholes option valuation model was developed for use in estimating the fair value of trade options which have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. Because the Company's employee stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management's opinion, the existing models do not necessarily provide a reliable single measure of the fair value of its employee stock options.
For purposes of pro forma disclosures, the estimated fair value of the options is amortized to expense over the options' vesting period. The Company's pro forma information is as follows:
NOTE C - STOCKHOLDERS' EQUITY - continued
A summary of the status of the Company's stock option activity and related information is as follows:
The following table summarizes information about the options outstanding at December 31, 2000:
NOTE C - STOCKHOLDERS' EQUITY - continued
Stock Warrants: The following is a summary of warrants outstanding at December 31, 2000:
NOTE D - EARNINGS PER SHARE
The following is a reconciliation of the numerator and denominators of the basic and diluted earnings per share computation:
NOTE E - OPERATING LEASES
The Company leases its primary office space through February 2005. The Company incurred rent expense of $133,000, $95,000 and $94,000 for the years ended December 31, 2000 and August 31, 1999 and 1998, and $33,000 for the four months ended December 31, 1999. Future minimum rentals under all noncancelable real estate leases are as follows:
Year Ended December 31, Amount ----------------------- -------- 2001 $ 145,000 2002 149,000 2003 153,000 2004 156,000 2005 26,000
NOTE F - INCOME TAXES
In prior years, the Company did not incur a federal or state income tax expense due to the utilization of tax net operating losses, nor did it receive a tax benefit as its deferred tax assets were fully reserved.
For the year ended December 31, 2000, the components of the Company's income taxes were as follows:
Current federal tax expense $ 90,918 Deferred federal tax (benefit) (5,232,718) ------------ Income tax (benefit), net $ (5,141,800) ============
The following items give rise to the deferred tax assets and liabilities:
NOTE F - INCOME TAXES - continued
The differences between the statutory federal income taxes and the Company's effective taxes are as follows:
Prior to 2000, the Company provided a valuation allowance equal to its net deferred tax asset, since it had a history of financial and tax losses. SFAS 109 required the valuation allowance since it was more likely than not such deferred tax assets would not be realized.
However, the Company has undergone significant strategic changes during the last few years. It has impaired or abandoned over $5.4 million on certain unproved leasehold acreage during the past three and a half years, minimizing its remaining exposure on its unproved acreage positions. At the same time, it has significantly increased its revenues from its producing acreage. As a result, the Company is now in position to take advantage of the economic recovery which began in the oil and gas industry several years ago. The Company has consistently increased income before income taxes for the last two and one-half years and management now believes it is more likely than not that a significant portion of its deferred income tax asset will be realized. Therefore, the valuation allowance has been reduced and a deferred tax asset recognized for the amount expected to be realized through taxable earnings. In determining the valuation allowance, the Company uses three year income projections reduced by graduating percentages to compensate for uncertainties inherent in future years' projections. Regardless of management's expectations, there can be no assurance that the Company will generate any specific level of continuing earnings.
The Company has available net operating loss carryforwards of approximately $16,100,000 ($5,480,000 tax benefit) at December 31, 2000, which expire from 2006 to 2015.
NOTE G - MAJOR CUSTOMERS
Sales to unrelated entities which individually comprised greater than 10% of total oil and gas sales as follows:
NOTE H - SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
YEAR ENDED DECEMBER 31, 2000 The Company issued 150,000 shares of its common stock for commissions it was charged related to the acquisition of leasehold acreage.
YEAR ENDED AUGUST 31, 1999 The Company issued 325,000 shares of its common stock in exchange for oil and gas properties (valued at the market price per share for unregistered stock).
YEAR ENDED AUGUST 31, 1998 The Company converted $4,000,000 of convertible notes payable and $221,590 of accrued interest into 844,318 shares of its common stock.
The Company converted $1,684,000 of accounts payable into long-term debt.
NOTE I - OIL AND GAS PRODUCING ACTIVITIES AND PROPERTIES
Capitalized Costs and Costs Incurred Relating to Oil and Gas Activities
The Company's investment in oil and gas properties is as follows at:
Costs incurred, capitalized, and expensed in oil and gas producing activities are as follows:
NOTE I - OIL AND GAS PRODUCING ACTIVITIES AND PROPERTIES - continued
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.
The Company's reserve information was prepared as of each respective period end. 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 developed 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.
Estimated quantities of proved developed reserves of oil and gas (all of which are located within the United States) as well as the changes in proved reserves, are as follows:
Oil Gas (Barrels) (Mcf) --------- -------
Reserves at August 31, 1997 ....................... 245,700 2,156,100
Discoveries ................................... 70,700 4,541,500 Revisions of previous estimates ............... (136,662) 117,852 Production .................................... (79,138) (713,752) --------- ----------
Reserves at August 31, 1998 ....................... 100,600 6,101,700
Discoveries ................................... 32,000 2,803,000 Purchases of minerals in place ................ 1,600 338,000 Revisions of previous estimates ............... 53,800 (166,700) Production .................................... (82,000) (2,813,000) --------- ----------
Reserves at August 31, 1999 ....................... 106,000 6,263,000
Discoveries ................................... 4,500 461,000 Revision of previous estimates ................ 6,500 218,000 Production .................................... (24,000) (1,119,000) --------- ----------
Reserves at December 31, 1999 ..................... 93,000 5,823,000
Discoveries ................................... 5,593 2,126,000 Revisions of previous estimates ............... 144,407 (452,000) Production .................................... (60,000) (2,965,000) --------- ----------
Reserves at December 31, 2000 ..................... 183,000 4,532,000 ========= ==========
NOTE I - OIL AND GAS PRODUCING ACTIVITIES AND PROPERTIES - continued
The following table sets forth a standardized measure of the estimated discounted future net cash flows attributable to the Company's proved developed oil and gas reserves. Prices used to determine future cash inflows were based on the respective year end weighted average sales prices utilized for the Company's proved developed reserves which were $11.04, $1.99, $2.58 and $1.84 per Mcf of gas and $25.67, $25.39, $19.03 and $10.23 per barrel of oil as of December 31, 2000 and 1999 and August 31, 1999 and 1998. 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 reserves and the tax basis of proved oil and gas properties and available operating loss and temporary differences.
The principal factors comprising the changes in the standardized measure of discounted future net cash flows is as follows:
THE EXPLORATION COMPANY Schedule II - Valuation and Qualifying Reserves