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UNITED STATES SECURITIES AND EXCHANGE COMMISSION |
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Washington, D.C. 20549 |
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FORM 10-K |
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF |
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THE SECURITIES EXCHANGE ACT OF 1934 |
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For the Fiscal Year Ended December 31, 2002 |
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Commission File Number 0-9120 |
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THE EXPLORATION COMPANY OF DELAWARE, INC. |
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(Exact name of Registrant as specified in its charter) |
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Delaware |
84-0793089 |
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(State or other jurisdiction of |
(I.RS. Employer |
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incorporation or organization) |
Identification No.) |
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500 North Loop 1604 East, Suite 250, San Antonio, Texas 78232 |
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(Address of principal executive offices) |
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Registrant's telephone number, including area code: (210) 496-5300 |
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Securities registered pursuant to Section 12(b) of the Act: None |
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Securities registered pursuant to Section 12(g) of the Act: |
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Common Stock, par value $0.01 per share |
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Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. |
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Yes |
[X] |
No |
[ ] |
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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]. |
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Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the act). Yes [X] |
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The aggregate market value of the voting stock (which consists solely of shares of Common Stock) held by non-affiliates of the registrant was $116.5 million based upon the closing price of $6.77 per share of such stock as reported by the NASDAQ Small-Cap Market under the symbol TXCO on June 28, 2002. |
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The number of shares outstanding of the Registrant's Common Stock as of March 24, 2003 was 20,009,716 of which 17,323,638 shares were held by non-affiliates. |
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Documents Incorporated by Reference: None |
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For more information and a print friendly version of this document go to www.txco.com.
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Dec-2002 |
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Dec-2001 |
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Dec-2000 |
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Aug-1999 |
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No. of new gas wells completed |
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16 |
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54 |
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6 |
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6 |
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No. of new oil wells completed |
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14 |
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9 |
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3 |
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2 |
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No. of new gas wells purchased |
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- |
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- |
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- |
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6 |
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No. of new oil wells purchased |
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94 |
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- |
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- |
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- |
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Gas production (Mcf) |
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2,487,000 |
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2,673,000 |
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2,965,000 |
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2,813,000 |
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Gas reserve additions from drilling (Mcf) |
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5,103,000 |
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8,664,000 |
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2,126,000 |
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2,803,000 |
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Oil production (Bbl) |
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314,000 |
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50,000 |
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60,000 |
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82,000 |
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Oil reserves additions from drilling (Bbl) |
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600,000 |
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66,000 |
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5,000 |
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32,000 |
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Gas equivalent production (Bcfe) |
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4.37 |
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2.97 |
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3.33 |
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3.30 |
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Reserve additions (Bcfe) |
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Drilling |
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8.70 |
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9.06 |
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2.16 |
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3.00 |
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Revisions of previous estimates |
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2.44 |
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1.02 |
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.41 |
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.15 |
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Purchased |
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4.04 |
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- |
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.35 |
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Total reserves added (Bcfe)(2) |
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15.18 |
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10.08 |
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2.57 |
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3.50 |
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Reserve replacement rate |
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Drill bit |
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255% |
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339% |
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77% |
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95% |
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Drill bit plus purchases (all sources) |
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347% |
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339% |
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77% |
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106% |
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Operating revenues |
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$18,958,364 |
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$13,758,920 |
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$14,361,357 |
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$7,235,391 |
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Net Income (Loss) |
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$ (310,970 |
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$ (50,283 |
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$ 6,761,935 |
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$ 931,545 |
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Net cash provided from operations |
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$ 7,389,430 |
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$ 8,564,022 |
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$ 6,529,838 |
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$3,858,204 |
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Non-developed Texas acreage leased (1) |
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408,992 |
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372,000 |
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365,000 |
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95,000 |
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Non-developed Williston Basin acreage leased |
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91,804 |
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105,000 |
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302,000 |
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380,000 |
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(1) 479,761 acres as of January 2003 |
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(2) Reserve make-up at year end 2002: 62% gas, 52% proved developed |
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Over the last four years, TXCO has developed its natural gas production base significantly. This overall growth is primarily attributable to ongoing drilling activities and the acquisition of new non-developed leasehold acreage as well as the acquisition of a producing field with significant undeveloped potential 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 Basin acreage primarily in North Dakota through expiration or sales of maturing leases. During the same periods, operating revenues were significantly impacted by commodity price fluctuations. |
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TXCO's established operating strategy includes the pursuit of multiple growth opportunities, accelerated in 2001, based on diversification in exploration targets within its core area of operations. By aggressively expanding its surrounding lease holdings where geology indicates the likely continuation of known or prospective oil and gas producing formations, TXCO is well positioned to pursue new oil and gas reserves and expand its production base. The Maverick Basin offers this diversity in its multiple hydrocarbon bearing horizons. During 2002, the Company expanded its Maverick Basin lease block to 408,992 essentially contiguous acres and successfully completed 16 new gas wells in diverse horizons including the Glen Rose, the Olmos coals, the Escondido sands, the McKnight and the Georgetown intervals. Additionally, 14 new oil wells were completed in varying horizons including the Glen Rose, Georgetown, and the San Miguel formations. In January 2003 TXCO acquired an additi
onal 70,769-acre lease in the Maverick Basin, contiguous to its existing acreage, bringing its overall position to almost 480,000 acres in the basin. |
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During 2002, the Company made significant strides in diversifying its oil and gas exploration efforts by identifying and pursuing the exploration of at least 6 new exploration targets in addition to targeting new Glen Rose oil production on the Company's Comanche lease. The Comanche oil discovery alone produced over 600,000 gross barrels of oil by year-end, largely responsible for the 83% increase in ending reserves. The Company believes that the Comanche lease will contribute significant new oil reserves in 2003 and future years. Following up on its 30 new oil and gas well completions in 2002, new exploration targets for 2003, in descending depth order, are: first, developing additional gas production from the Escondido sands; second, accelerating Coalbed Methane (CBM) gas production from dewatering Olmos coals; third, expanding waterflood oil production from the San Miguel interval; fourth, Georgetown deviated wells; fifth, continuing horizontal drilling for Glen Rose sho
al gas production; sixth, Comanche lease oil wells targeting the high porosity complex; and seventh, consulting with operating partners in pursuit of deep Jurassic formation gas. As 2002 results confirmed, each of these high impact exploration targets has the potential to establish meaningful additions to TXCO's oil and gas reserves and significant numbers of new proved undeveloped and lower risk drilling locations. The enhanced risk profile and growth potential of the Company's exploration and development plans are evidenced by two years of record back to back reserve replacement rates. |
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Should its exploration and development plans progress as intended, the Company expects to continue the rapid growth of its oil and gas reserves in 2003 and to attain meaningful growth in oil and gas production levels. As the Company expected, at year-end 2002 and in early 2003, there has been significant improvements in oil and gas prices. Subject to prices remaining above 2002 levels and the establishment of meaningful new levels of oil and gas production from its 1st and 2nd quarter 2003 drilling results, TXCO has designed a capital expenditure budget ("CAPEX budget") of $27.4 million for 2003. The budget calls for drilling 93 new wells primarily aimed at expanding production and proved gas reserves from the newly discovered Comanche oil field, as well as the Georgetown, San Miguel and Glen Rose intervals. This level of expenditure is dependent on TXCO maintaining sufficient positive operating cash flow levels, and also relies on funding from the Co
mpany's $25 million revolving credit facility with Hibernia National Bank (the "Credit Facility"). The borrowing base, initially established at $5 million and increased to $12 million by year end, is determined as a percentage of the discounted value of the Company's oil and natural gas reserves. Based on TXCO's continuing drilling success in 2003, the Company expects it will have sufficient working capital available to minimize required borrowings, continue growing its oil and gas reserve base and expects to be profitable in 2003. Although there is no assurance the Company will be successful in maintaining its ongoing drilling success at sufficient levels to fund its capital needs during 2003, Management retains its ability to modify its capital expenditure program consistent with its available liquidity in order to continue to meet its ongoing operating and debt service obligations. |
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PRINCIPAL AREAS OF ACTIVITY |
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Oil and Gas Operations |
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Throughout 2002, the Company actively developed its core mineral interests in the Maverick Basin in South Texas, and re-evaluated its economic alternatives related to its remaining properties in the Williston Basin, primarily in North Dakota. These activities included the drilling or re-entry of 41 wells in South Texas during 2002, as compared to 73 in 2001. The 73 wells in the prior year included 44 re-entered coalbed methane (CBM) wells, and 29 non-CBM wells. There were 36 non-CBM wells drilled or re-entered in 2002, a 24% increase over the prior year. 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. Marginally decreasing Maverick Basin gas production during 2002, combined with lower natural gas prices, resulted in
a decrease in net cash provided by operating activities from $8.6 million in 2001 to $7.4 million in 2002. Approximately 46% of the $7.4 million in cash flow was realized during the fourth quarter of 2002, reflecting higher oil and natural gas prices. |
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Although crude oil and natural gas prices have increased significantly during the fourth quarter of 2002 and the first quarter of 2003, industry activity or interest has not returned to pre-1998 levels in the Williston Basin, which is the only significant interest the Company has outside the Maverick Basin. The Company's strategy remains focused on its core oil and natural gas producing wells and higher margin exploration activities in the Maverick Basin. TXCO has continued efforts to either locate a suitable joint venture partner, farmout, or sell its interest in the Williston Basin. |
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Maverick Basin |
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The Company has owned a 50% or greater leasehold interest in at least 50,000 contiguous acres in the Maverick Basin, Texas, since 1989. These holdings have increased to 408,992 acres through 2002, and to 479,761 in January 2003 when the Company leased the remaining portion of the Burr Ranch. The contiguous 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. Ten years ago, 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. |
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Company geologists and geophysicists conclusively identified and mapped numerous geological formations at various depths on its leases. The mapping 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, while the shallower intervals have provided alternative completion targets for these underlying reefs. While 100% successful in locating Glen Rose patch reefs, the Company's geologists and geophysicists can not distinguish between those containing hydrocarbons and those containing water. Management continues 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 a
rea known as the Prickly Pear Field. |
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Maverick Basin 2002 Drilling Activity Summary |
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TXCO participated in drilling a total of 37 gross wells and 4 re-entries during 2002. Of the 41 drilled wells, 29 were successfully completed, one was a dry hole and 11 remained in progress at year end. Completed wells include 7 Comanche oil wells, 6 Chittim horizontal gas wells, 5 CBM wells, 2 Briscoe-Saner gas wells, 2 Burr lease oil wells, 1 Paloma gas well, 1 Briscoe-Saner oil well and 1 Alkek gas well, while 1 well was dry. A total of 22 drilling wells remained in progress at year-end. All 4 re-entry attempts resulted in San Miguel oil well completions. At year-end, 38 CBM gas wells continued de-watering in the ongoing CBM pilot program on the Comanche lease, while 10 San Miguel oil wells were involved in the initial stages of the Comanche San Miguel water flood project. |
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TXCO's approximate working interest ownership in some of its Maverick Basin projects are detailed below by formation in descending depth order: |
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Working Interest Range |
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1 |
Escondido - Gas |
100 |
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Olmos - CBM Gas |
100 |
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San Miguel - Oil Waterflood |
100 |
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Georgetown - Gas |
2% to 100 |
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Glen Rose - Oil Porosity Zone |
50 |
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Glen Rose - Gas Shoal Horizontal |
48% to 100 |
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7 |
Jurassic - Gas |
2% to 100 |
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At year-end 2002 TXCO's net production reached 7.8 MMcf per day (gross 18.8 MMcf per day) from 83 net gas wells plus 1,000 barrels of oil per day (gross 5,800 barrels of oil per day) from 149 net oil wells. At current gas prices, this production level would not allow the Company to generate sufficient working capital to entirely fund its 2003 capital expenditure program from internally generated operating cash flow alone. The Company expects to have adequate capital available through its Credit Facility, and from new production from successful current year drilling activities. The expanding geophysical database, historical drilling results and the growing number of prospective formations targeted by the Company and its partners reaffirmed the Company's longstanding belief that it has very significant exploration and development possibilities on its growing Maverick Basin lease block. |
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At year-end 2002 the Company had accumulated 455 square miles of 3-D seismic data covering most of its Maverick Basin lease block. This represents an increase of 145 square miles of 3-D data over year end 2001, all of which is attributable to the eastern portion of its 95,000 acre Comanche lease plus the Pena Creek field, which is an eastern extension to the Comanche data set. |
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During the fourth quarter, TXCO made its initial interpretation of the 145 square mile data set. To date, interpretation of the eastern data set has yielded over 50 additional drillable locations in the highly productive Comanche Glen Rose porosity zone. The 3-D data set shows that the porosity zone overlays a layer of numerous identified Glen Rose reefs that have yet to be quantified, and that there are multiple layers of these reefs. The oil bearing porosity zone extends over a 20 square mile area of the Comanche and Pena Creek lease block. A portion of these locations has been included in the 2003 capital expenditure budget. The 3-D data set also shows that the Jurassic interval extends to this large, southern portion of TXCO's Maverick Basin acreage. |
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CBM Gas Pilot Program |
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At year end 2002 TXCO remained firmly entrenched at the forefront of Texas-based exploration for CBM gas production. The United States Geological Survey (USGS) credited TXCO with the establishment of the first CBM field in Texas, recognizing the Company's Farias #5-110 well, completed in April 2001, as the discovery well. The Texas Railroad Commission assigned the name "Sacatosa (CBM Olmos) Field" to the extensive coal deposits which extend across approximately 250,000 acres of TXCO's lease block under its Comanche and Chittim leases. Eager to encourage the continuing development of this potential new source of CBM gas, the USGS formed a cooperative research effort with TXCO to determine the gas in place, rank, quality, extent and thickness of the Olmos coals in order to fully assess the resource potential of the new CBM field. The USGS drilled two CBM wells on the Comanche lease with TXCO under their agreement, collecting extensive amounts of samples and data for further
laboratory testing and evaluation. Extensive desorption and adsorption tests on these wells as well as 10 additional core tests confirmed the coals were gas-saturated. Published coal quality data confirmed the Olmos coals are classified as having the favorable ranking of high-volatile C bituminous coal, which is preferable for potential CBM production. Additional measurements indicated samples of Olmos coal from the Sacatosa (CBM Olmos) Field from varying depths contained quantities of CBM gas ranging to as much as 350 standard cubic feet per ton of coal. Further study confirmed the thickness, depth and gas content of the Olmos coals were similar to coals in other established and commercially productive CBM basins such as the Black Warrior in Alabama, the Cherokee Basin in Oklahoma and the Raton Basin in New Mexico and Colorado. |
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Through 2001, TXCO drilled or re-entered, and successfully completed, 34 wells on its Comanche lease. Based on the encouraging results of its exploratory core and well drilling program for CBM gas, TXCO significantly expanded its CBM activities in 2002 by advancing the project into its preliminary development stage, justifying the costs of drilling optimized wells. Optimized wells are wells drilled using air-drilling techniques and completed selectively with advanced fracture stimulation techniques designed to maximize coal formation response. Additionally, the wells are completed with larger-diameter tubulars, allowing for more rapid dewatering. During the last half of 2002, the Company drilled 5 optimized wells. After fracture stimulating 2 of the 5 wells, production from the new wells increased over 40% to 57 Mcfd with a corresponding drop in water production. While the actual CBM producing amounts are not significant in themselves, the marked increase in post-fracture v
olumes is encouraging in confirming the applicability of the optimized drilling technique. |
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TXCO exited 2002 with 38 wells in its CBM pilot program targeting production from the multiple seams of high-volatile bituminous coal present under its leases. As of February 2003, the total CBM production rate was 200 Mcfd with 2,200 BWD. The Company believes that the next phase of this project will require 25 to 50 wells initially, during which the Company expects to establish economic production quantities. The Company is in the process of arranging project type financing, which it believes is more suitable for this project due to its cash flow profile, as well as complimenting the Company's existing capital structure. There are no CBM wells included in the 2003 CAPEX budget. The Company expects that this project will add significant reserves in the coming years. |
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San Miguel Oil Waterflood Projects |
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Comanche Lease : The large volume of water typically produced in the dewatering phase of CBM production normally represents a significant component of the operating expense in the production of CBM gas. In conjunction with its CBM dewatering projects, TXCO has engineered a synergistic water disposal cost reduction program to dispose of the CBM water into a neighboring formation. In 2001, TXCO initiated a waterflood injection pilot program targeting oil production from the San Miguel formation, located about 400 feet below the base of the Olmos coal interval. A proven San Miguel waterflood oil-field directly offsets the northern boundary of TXCO's Comanche lease. Conoco's Sacatosa (San Miguel) Field has produced over 40 million barrels of oil and 19 Bcf of gas since its discovery in 1956. Conoco began waterflooding the San Miguel sand interval in 1966 and continues to successfully operate the huge field. Initial geologic and engineering studies indicate the San Miguel
sand interval under the Comanche lease is a look-a-like structure in size and structural position relative to Conoco's adjacent San Miguel waterflood field. Using its growing volume of CBM water production, TXCO added a second San Miguel waterflood pilot in 2002. Additional operating efficiencies were gained by re-entering existing vertical well bores acquired from previous operators. Company engineers selected and re-entered existing horizontal well bores in close proximity to the vertical wells in each of the pilots for recompletion as water injection wells. To date, initial response from these early stage water injection pilots has been very encouraging. The development of this project is pending expansion of the CBM project that would provide injection water. |
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Pena Creek : In May 2002, the Company acquired the Pena Creek oil field in Dimmit County, Texas. The purchase was effective April 1, 2002, and consisted of 94 producing oil wells, 94 injection wells and 28 shut-in wells. At year end 2002 the field was producing approximately 265 barrels of oil per day from the San Miguel formation, and contains an estimated 674,000 barrels of proved reserves, net to the Company on an SEC PV-10 basis. The 10,000 acre lease is contiguous to the Company's Comanche lease acreage block and contains potential for oil and natural gas production from the underlying Glen Rose formation. Since acquisition, the Company has been addressing deferred repair and maintenance work left by the previous owner and conducting engineering and geologic evaluations of the property. |
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During the last half of 2002, TXCO, along with its partner, Saxet Energy, completed a 3-D seismic survey covering the Pena Creek field and surrounding acreage. The Company has completed geologic interpretation of some of the 3-D seismic and the extensive historic well data acquired. These evaluations have yielded numerous drillable Glen Rose locations, as well as identified bypassed infill reserves that are not presently included in the Company's reserve base. In January 2003 the Company spudded the first of 15 infill, San Miguel wells targeting bypassed reserves. This first well was completed in February after it was successfully fracture stimulated, resulting in initial production of 60 barrels of oil per day. It is currently producing 30 barrels per day and the decline has appeared to have flattened. A second well was recently put on production at an initial rate of 120 barrels of oil per day. Both wells are still returning the load water injected into the wells during frac
ture stimulation. Subsequently, TXCO has drilled four additional San Miguel wells, which are in various stages of completion. The Company's 2003 CAPEX budget includes $2.6 million for San Miguel development. |
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Georgetown Deviated Wells |
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During the fourth quarter, TXCO engineers designed a drilling and completion technique that has proved well suited for the Georgetown interval. The target intervals underlie most of TXCO's Maverick Basin lease block. The faults, which are nearly vertical, can be mapped by 3-D seismic. To increase drilling success, TXCO has employed directional drilling to enter the Georgetown at deviated angles, cutting through the targeted faults at an optimized position. During 2002, wells drilled with this method have much-improved hydrocarbon recovery, allowing an entire fault or reservoir to be drained. Previously, the Georgetown had been typically a secondary target when lower zones proved unproductive. The three wells currently produce a combined 1.5 MMcfe per day. TXCO sees this as an economically attractive way to add to production and has proposed 25 additional wells in this year's drilling program. During the first quarter of 2003, the Company spudded three deviated wells, one we
ll being completed while two are drilling. The 2003 CAPEX budget includes $6.9 million for this project. |
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Glen Rose Porosity Zone |
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During 2002, the Company significantly advanced its joint venture with Saxet Energy, Ltd. (Saxet), a privately held Houston exploration company, and Tom Brown, Inc. (Nasdaq: TMBR), a large Denver based independent, covering TXCO's 100,000 acre Comanche prospect. In 2001 the Company sold a 50% working interest (Saxet 20% and Tom Brown 30%) in its rights below the base of the San Miguel formation. Also in 2001 the joint venture partners completed the acquisition of a proprietary, 100-square mile, 3-D seismic survey covering the western half of the Comanche prospect, including Saxet's Cinco Ranch lease on the western flank of the Comanche acreage. Based on early interpretation of the western-most portion of the seismic survey, a well targeting the Glen Rose formation was spudded in June 2001 on the Cinco Ranch portion of the prospect. Unfortunately the reef was water bearing. By year-end 2002, the partners completed the acquisition and processing of the entire 3-D survey. An
additional 30 seismically defined Glen Rose reefs were identified and a second well was planned targeting a particularly attractive prospect on TXCO's Comanche lease, which contained evidence of multiple Glen Rose reefs stacked over a previously unidentified structure. |
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The first exploratory well to target a Glen Rose reef on the Company's Comanche lease since its acquisition was the Comanche 1-111 and resulted in a significant Glen Rose oil well. The well spudded in February 2002 and encountered significant oil flows from a depth of approximately 6,500 feet and produced approximately 5,000 barrels of light crude oil in a 24-hour period. The well was subsequently completed and tested rates up to 3,600 barrels of oil per day (bopd) on a 28/64" choke with tubing pressure of 495 psi before being curtailed due to a lack of surface facilities to handle the large volume of oil. |
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TXCO (50% WI) and its partner, Saxet Energy (50% WI), initially established the oil discovery appeared to be associated with a large porosity complex of approximately 850 acres in size with 55 feet of net pay. Pursuant to Texas Railroad Commission guidelines, the operator initiated 30 days of testing to establish the Maximum Effective Rate (MER) for the well, which was established at 2,200 bopd as the initial well in the newly designated Comanche-Halsell (6500) Field. After 60 days of oil production, the well began to produce some water. Subsequently, oil production rates have been reduced. Currently, the well is producing about 200 bopd and 970 bwpd. |
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From March through September 2002, the partners drilled 13 additional exploratory Comanche wells utilizing 3-D seismic to identify the presence of a high porosity complex. These wells were drilled to depths ranging from 6,600 feet to 8,200 feet. Initial oil production rates ranged from zero to 1,000 bopd. Initial water production rates ranged from zero up to 250 barrels of water per day (bwpd). |
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Prior to experiencing significant water production encountered in later wells, Saxet, as operator, continued its initial completion procedure of drilling through the high porosity interval to test the underlying formations for their hydrocarbon potential. During July, completion procedures were modified to drill only to the top of the targeted porosity zone. The modified completion procedure was applied to all subsequent wells. |
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Current Comanche lease gross daily oil production from the seven currently producing wells has declined to about 1,300 barrels of oil per day while water production has increased to about 3,500 barrels per day. Cumulative gross oil production for the Comanche lease has climbed to over 716,000 BO through mid-March 2003, while the water cut, the water to total production ratio, has increased to 72%. |
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At year end seven wells were not producing and remained shut in. Two of these wells failed to locate the targeted high porosity interval and were pending further evaluation for additional completion techniques. In March 2003, one of these wells was successfully sidetracked, encountering the adjacent porosity interval with an initial production rate of 60 Bopd, and no significant water production. In addition, the 3-111H is currently being drilled as a horizontal well. The four remaining wells that made mostly water await being reworked, sidetracked, drilled horizontally or conversion for use as water disposal wells. The Company has obtained a surface discharge permit that allows it to dispose of the water production at relatively low cost. Initial interpretation of Comanche lease water production surveys indicates that the majority of the water production comes from zones encountered below the main oil producing horizon. |
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Although 14 exploratory Saxet operated Comanche wells have now been drilled, and to date, seven producing wells are spread over a six-mile area, the productive and areal extent of the porosity interval is not yet fully defined. Because the 40 degree gravity oil is consistent over the entire area and contains no gas, the Company's engineers believe that all the productive wells will eventually be determined to be one field. The partners' engineering staffs have completed extensive reviews of the porosity intervals and its oil and water production profiles. Additionally, extensive seismic has been integrated with the Comanche Halsell field production profile. Management believes that significant additional proved reserves will be established. Until such time that water production issues are fully resolved for affected wells and adequate production profiles are established for newly completed wells, the Company's ongoing engineering estimates will be un
able to reflect the full reserve potential attributable to the Comanche lease oil discovery. |
| |
|
The Company and its partner have received the analysis of the recently completed 3-D seismic survey covering the eastern half of the 95,000 acre Comanche lease in addition to a contiguous 27,000 acre area including the Company's Pena Creek oil field to the east. Based on the data, TXCO's exploration staff believes the oil producing high porosity interval appears to extend as much as 14 miles into the eastern half of the Comanche and Pena Creek leases providing numerous additional drilling prospects for its 2003 drilling program. The Company's 2003 CAPEX budget includes a total of 26 Comanche wells, 13 exploratory and 13 developmental, at a total cost of $7.8 million to this growing project. |
| |
|
Horizontal Glen Rose Shoal Gas Wells |
| |
|
In late 2001, TXCO announced the discovery of a horizontal Glen Rose shoal gas play on a portion of its Chittim lease. Company geologists detected the presence of a large carbonate shoal (or carbonate "sand" bar) located within the Glen Rose interval. The target area provided good well control from nearby vertical producing wells which had logged or otherwise penetrated the structure while attempting completions in other oil or gas-bearing horizons. Based on their knowledge of the interval, Company engineers designed a well with a horizontal displacement of 3,750 feet in a promising and well-defined section of a large Glen Rose shoal at a vertical depth of 5,300 feet. The Chittim 1-141 gas well (48% WI) was completed in September 2001 with a calculated absolute open flow rate (AOF) of 4,690 MMcfpd with flowing pressure of 1,300 psi. The well was placed on production on October 2, 2001 at a rate of 2,042 MMcfpd with flowing pressure of 1, 360 psi. |
| |
|
Based on drilling results thus far, Company engineers identified 17 proved, undeveloped locations from the targeted Glen Rose shoal. At December 31, 2002 the Company's independent engineering firm estimated the proved undeveloped reserves represented by the 17 locations to be 7.9 Bcf of natural gas, net to TXCO. This represents an increase over the prior year's estimated reserves of 5.3 Bcf from 12 locations. |
| |
|
Plans for 2003 include drilling 17 low-risk horizontal Glen Rose shoal wells at a total cost of $6.1 million, net to TXCO. Subsequent to year end, 3 of the 17 wells have been spudded. The initial production rate on the first well is 1.3 MMcf of natural gas and 15 barrels of oil per day. The second well is waiting on a pipeline connection, and the third well is currently drilling. |
| |
|
Jurassic Formation |
| |
|
Fiscal 1999 marked the year that the Company's concerted efforts resulted in a new joint venture to explore the potential of the Jurassic formation under its growing lease block. During the 2000-2002 period, the Company, together with industry partners, made significant progress in expanding its 3-D seismic database over a much larger portion of the Maverick Basin. |
| |
|
Commencing in September 1999, Blue Star Oil and Gas, Ltd. (Blue Star), a Dallas based privately held exploration company, designed a 3-D seismic acquisition program over the 426 square mile area of the Maverick Basin targeted by the joint venture. The initiation of field data acquisition work continued throughout the year. The extensive data acquisition portion of the project was completed late in the third quarter of 2000. In November 2000, pursuant to its exploration joint venture with the Company, Blue Star confirmed that it had completed the seismic data acquisition phase and began processing the seismic data on the entire 426 square miles of 3-D seismic data, including 37,000 acres of TXCO leases and Blue Star's 190,000 acre Chittim lease. By year-end 2000, Blue Star had shared with TXCO's Jurassic project management team the preliminary results from the data migration, processing and initial interpretation of the seismic study. In March 2001 Blue Star contacted TXCO
and announced Blue Star's decision to apply additional, enhanced 3-D seismic processing techniques on their entire Jurassic seismic database. Blue Star further advised that the prospective seismic processing would likely take several months to finalize and could cost an additional $1 million. By year end 2001, Blue Star had completed its enhanced 3-D seismic processing, had provided TXCO with a digitized seismic data set covering 164 square miles of the Maverick Basin and a proposed drilling location on the Paloma lease. |
| |
|
During the first quarter of 2002, Blue Star's team of geoscientists met with TXCO's exploration team on several occasions to obtain the Company's expertise in interpreting the final results of the long-awaited, newly-enhanced 3-D seismic processing. Blue Star also requested TXCO's expertise in the identification and final ranking of multiple proposed Jurassic drilling locations on TXCO's affected acreage. In March, Blue Star delivered a nearly final processed data set containing over 80 square miles of digitized seismic data for TXCO's ongoing review. In August, Blue Star provided TXCO with a comprehensive review of the latest seismic imagery resulting from recently completed, state-of-the-art processing techniques. The findings confirmed the presence and ranking of numerous drilling locations on TXCO's acreage. |
| |
|
Through year-end 2002, Blue Star continued its efforts to obtain proposals from qualified drilling contractors, conducted field inspections and obtained current title opinions on multiple drilling locations under evaluation. On October 8, 2002, the partners signed an amendment, restatement and ratification of the existing joint venture agreement committing Blue Star to begin drilling the initial Jurassic test well on TXCO's Paloma or Kincaid lease no later than March 31, 2003. |
| |
|
On March 27, 2003, Blue Star spudded the Taylor 132-1, on TXCO's Paloma lease. The well, targeting natural gas, is permitted to a depth of 18,500' and is expected to take from 90 to 120 days to reach total depth. A second well on the Paloma lease, the McKinney 106-1, has been staked and permitted to a depth of 20,200'. Under the terms of the agreement, TXCO (62.5%) and its partners (37.5%) will share an 18.75% overriding royalty interest in any production associated with the well, reverting to a shared 25% working interest upon payout. In exchange for the carried interest in the Taylor well, Blue Star will earn a 25% working interest in the deep rights below the Silgo formation in the 50,000 acres under the Paloma and Kincaid leases. Blue Star retains the right to carry TXCO for an identical interest in a second well to earn an additional 25% under the two leases. |
| |
|
Williston Basin |
| |
|
Through 2002, the Company continued to re-evaluate all of its Williston Basin lease obligations, making lease extension payments on a selective basis, emphasizing those leases with particular geologic attributes or with adequate remaining primary lease terms. Consistent with Management's strategy to focus exploration efforts and resources on the development of its core producing area in South Texas, TXCO has maintained marketing efforts offering its remaining Williston Basin holdings to other exploration companies with a focus on this area. |
| |
|
For the year ended December 31, 2002, the Company's interests produced an average of 68 net barrels of crude oil per day from 5.2 net wells. At December 31, 2002 TXCO retained approximately 87,000 net acres of its original position. |
| |
|
PRINCIPAL PRODUCTS AND COMPETITION |
| |
|
The Company's principal products are natural gas and crude oil. The production and marketing of oil and gas are affected by a number of factors that are beyond the Company's control, the effects of which cannot be accurately predicted. These factors include crude oil imports, actions by foreign oil-producing nations, the availability of adequate pipeline and other transportation facilities, the marketing of competitive fuels and other matters affecting the availability of a ready market, such as fluctuating supply and demand. During 2002 the Company sold all of its oil and gas under short-term contracts that can be terminated with 30 days notice, or less. None of the Company's production was sold under long-term contracts with specific purchasers. Consequently, the Company was able to market its oil and gas production to the highest bidder each month. As discussed in Item 7, Contractual Obligations and Contin
gent Liabilities and Commitments, in January 2003 the Company entered into a fixed price contract for approximately 30% of the its net gas production rate at year-end 2002. As a forward sale of part of its physical production, the Company was able to lock-in relatively high, by historical standards, prices without being subject to risks associated with derivative instruments. |
| |
|
The Company operates and directs the drilling of oil and gas wells and participates in non-operated wells. As operator, it contracts service companies, such as drilling contractors, cementing contractors, etc., for specific tasks. In other wells, the Company only participates as an overriding royalty interest owner. |
| |
|
During 2002, four purchasers of the Company's oil and gas production accounted for 42%, 25%, 18% and 11% of total oil and gas sales. In the event any of these major customers declined to purchase future production, the Company believes that alternative purchasers could be found for such production at comparable prices. |
| |
|
The oil and gas industry is highly competitive in the search for and development of oil and gas reserves. The Company competes with a substantial number of major integrated oil companies and other companies having materially greater financial resources and manpower than the Company. These competitors, having greater financial resources than the Company, have a greater ability to bear the economic risks inherent in all phases of this industry. In addition, unlike the Company, many competitors produce large volumes of crude oil that may be used in connection with their operations. These companies also possess substantially larger technical staffs, which puts the Company at a significant competitive disadvantage compared to others in the industry. |
| |
|
EMPLOYEES |
| |
|
As of December 31, 2002, the Company employed 35 full-time employees including management. The Company believes its relations with its employees are good. None of the Company's employees are covered by union contracts. |
| |
|
GENERAL REGULATIONS |
| |
|
The extraction, production, transportation, and sale of oil, gas, and minerals are regulated by both state and federal authorities. The executive and legislative branches of government at both the state and federal levels have periodically proposed and considered proposals for establishment of controls on alternative fuels, energy conservation, environmental protection, taxation of crude oil imports, limitation of crude oil imports, as well as various other related programs. If any proposals relating to the above subjects were to be enacted, the Company is unable to predict what effect, if any, implementation of such proposals would have upon the Company's operations. A listing of the more significant current state and federal statutory authority for regulation of the Company's current operations and business are provided herein below. |
| |
|
Federal Regulatory Controls |
| |
|
Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938 (the "NGA"), the Natural Gas Policy Act of 1978 (the "NGPA") and the regulations promulgated thereunder by the Federal Energy Regulatory Commission ("FERC"). Maximum selling prices of certain categories of natural gas sold in "first sales," whether sold in interstate or intrastate commerce, were regulated pursuant to the NGPA. On July 26, 1989, the Natural Gas Wellhead Decontrol Act (the "Decontrol Act") was enacted, which removed, as of January 1, 1993, all remaining federal price controls from natural gas sold in "first sales." The FERC's jurisdiction over natural gas transportation was unaffected by the Decontrol Act. |
| |
|
Commencing in April 1992, the FERC issued Order Nos. 636, 636-A and 636-B (collectively "Order No. 636"), which required interstate pipelines to provide transportation, separate or "unbundled," from the pipelines' sales of gas. Although Order No. 636 did not directly regulate the Company's activities, it fostered increased competition within all phases of the natural gas industry. |
| |
|
In December 1992, the FERC issued Order No. 547, governing the issuance of blanket marketer sales certificates to all natural gas sellers other than interstate pipelines. The order applies to non-first sales that remain subject to the FERC's NGA jurisdiction. The FERC Order No. 547, in tandem with Order No. 636, has fostered a competitive market for natural gas by giving natural gas purchasers access to multiple supply sources at market-driven prices. Order No. 547 has increased competition in markets in which the Company's natural gas is sold. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach pursued by the FERC and Congress will continue. |
| |
|
State Regulatory Controls |
| |
|
In each state where the Company conducts or contemplates conducting oil and gas activities, such activities are subject to various state regulations. In general, the regulations relate to the extraction, production, transportation and sale of oil and natural gas, the issuance of drilling permits, the methods of developing new production, the spacing and operation of wells, the conservation of oil and natural gas reservoirs and other similar aspects of oil and gas operations. In particular, the State of Texas (where the Company has conducted the majority of its oil and gas operations to date) regulates the rate of daily production allowable from both oil and gas wells on a market demand or conservation basis. At the present time, no significant portion of the Company's production has been curtailed due to reduced allowables. The Company knows of no newly proposed regulations, which will significantly curtail its production. |
| |
|
Environmental Regulation |
| |
|
The Company's extraction, production and drilling operations are subject to environmental protection regulations established by federal, state, and local agencies. To the best of its knowledge, the Company believes that it is in compliance with the applicable environmental regulations established by the agencies with jurisdiction over its operations. The Company is acutely aware that the applicable environmental regulations currently in effect could have a material detrimental effect upon its earnings, capital expenditures, or prospects for profitability. The Company's competitors are subject to the same regulations and therefore, the existence of such regulations does not appear to have any material effect upon the Company's position with respect to its competitors. The Texas Legislature has mandated a regulatory program for the management of hazardous wastes generated during crude oil and natural gas exploration and production, gas processing, oil and gas waste reclamati
on and transportation operations. The disposal of these wastes, as governed by the Railroad Commission of Texas, is becoming an increasing burden on the industry. The Company's leases in Montana, North Dakota and South Dakota are subject to similar environmental regulations including archeological and botanical surveys as most of the leases are on federal and state lands. |
| |
|
Federal and State Tax Considerations |
| |
|
Revenues from oil and gas production are subject to taxation by the state in which the production occurred. In Texas, the state receives a severance tax of 4.6% for oil production and 7.5% for gas production. North Dakota production taxes typically range from 9.0% to 11.5% while Montana's taxes range up to 17.2%. These high percentage state taxes can have a significant impact upon the economic viability of marginal wells that the Company may produce and require plugging of wells sooner than would be necessary in a less arduous taxing environment. For Federal Income Tax purposes, the Company has net operating loss carry forwards of $13,600,000 which are scheduled to expire from 2008 to 2019. During 2000, the Company recognized a deferred federal income tax benefit of $5,231,000 reflecting the cumulative estimated future tax benefit of a portion of its net operating loss carry forwards from past losses. For 2001and 2002, this benefit was unchanged. See Notes to the Audited
Consolidated Financial Statements. |
| |
|
CERTAIN BUSINESS RISKS |
| |
|
Reliance on Estimates of Proved Reserves and Future Net Revenues: Depletion of Reserves |
| |
|
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and the timing of development expenditures, including many factors beyond the control of the Company. The reserve data set forth in this report represent only estimates. In addition, the estimates of future net revenues from proved reserves of the Company and the present value thereof are based on certain assumptions about future production levels, prices and costs that may not prove to be correct over time. In particular, estimates of crude oil and natural gas reserves, future net revenue from proved reserves and the present value of proved reserves for the crude oil and natural gas properties described in this report are based on the assumption that future crude oil and natural gas prices remain constant based on prices in effect at December 31, 2002. The following table details the prices used for these estimates for the respective dates pre
sented: |
| |
| |
|
12/31/02 |
|
12/31/01 |
|
12/31/00 |
|
12/31/99 |
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
Gas price per Mcf |
|
$ 4.90 |
|
$ 2.72 |
|
$11.04 |
|
$ 1.99 |
|
|
Oil price per Bbl |
|
$28.71 |
|
$17.31 |
|
$25.67 |
|
$25.39 |
|
| |
|
|
|
|
|
|
|
|
|
|
Any significant variance in these assumptions could materially affect the estimated quantity and value of reserves set forth herein. See "Management's Discussion and Analysis of Financial Condition and Results of Operation - Liquidity and Capital Resources" and "Properties". |
| |
|
Depletion of Reserves |
| |
|
The rate of production from crude oil and natural gas properties declines as reserves are depleted. Except to the extent the Company acquires additional properties containing proved reserves, conducts successful exploration and development activities or through engineering studies identifies additional behind-pipe zones or secondary recovery reserves, the proven reserves of the Company will decline as reserves are produced. Future crude oil and natural gas production is highly dependent upon the Company's level of success in acquiring or finding additional reserves. |
| |
|
Title to Properties |
| |
|
As is customary in the crude oil and natural gas industry, the Company performs a preliminary title investigation before acquiring undeveloped properties that generally consists of obtaining a title report from outside counsel or due diligence reviews by independent landmen. The Company believes that it has satisfactory title to such properties in accordance with standards generally accepted in the oil and gas industry. A title opinion from counsel is obtained before the commencement of any drilling operations on such properties. The Company's properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens, none of which the Company believes materially interferes with the use of, or affect the value of, such properties. |
| |
|
Net Income or Loss from Operations |
| |
|
In its recent history, the Company has recorded both net income and net losses. For the year ended December 31, 2002 the Company recorded a net loss of $310,970; for the year ended December 31, 2001 the Company recorded a net loss of $50,283; for the year ended December 31, 2000, the Company recorded net income of $6.76 million. There can be no assurance that the Company will not experience operating losses in the future. |
| |
|
Operating Hazards; Uninsured Risks |
| |
|
The nature of the crude oil and natural gas exploration and production business involves certain operating hazards such as crude oil and natural gas well blowouts, explosions, formations with abnormal pressures, cratering and crude oil spills and fires. Any of these could result in damage to or destruction of crude oil and natural gas wells, destruction of producing facilities, damage to life or property, suspension of operations, environmental damage and possible liability to the Company. In accordance with customary industry practices, the Company maintains insurance against some, but not all, of such risks and some, but not all, of such losses. The occurrence of such an event not fully covered by insurance could have a material adverse effect on the financial condition and results of operations of the Company. |
| |
|
Substantial Capital Requirements |
| |
|
The Company makes, and will continue to make, substantial capital expenditures for the acquisition, exploitation, development, exploration, and production of crude oil and natural gas reserves. Historically, the Company has financed these expenditures primarily from debt and equity offerings, supplemented by available cash flow from operations and the sale of interests in its properties. The Company is hopeful that it will continue to be able to obtain sufficient capital to finance planned capital expenditures. However, if revenues decrease because of lower crude oil and natural gas prices, operating difficulties or declines in reserves, the Company may have limited ability to finance planned capital expenditures in the future. Therefore, there can be no assurance that additional debt or equity financing or cash generated by operations will be available to meet its capital requirements. |
| |
|
Certain Corporate Defensive Matters |
| |
|
The Company's Articles of Incorporation, Bylaws and Delaware law contain provisions that may have the effect, together or separately, of delaying, deferring, or preventing a change in control of the Company. In particular, the Company may issue up to 10 million shares of preferred stock with rights and privileges that could be senior to its outstanding common stock, without the consent of the holders of the common stock. The Company's Certificate of Incorporation and Bylaws provide, among other things, for advance notice of stockholder's proposals and director nominations, and provide for non-cumulative voting in the election of Directors. On June 29, 2000, the Company's Board of Directors adopted a Stockholder Rights Plan (Rights Plan) under which uncertificated preferred stock purchase rights were distributed as a stock dividend to its common shareholders at a rate of one right for each share of common stock held of record as of July 19, 2000. Unless previously redeemed b
y the Company, the rights will expire on June 29, 2010. 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. On May 25, 2001, a majority of the Company's shareholders approved an amendment to its Certificate of Incorporation providing for the establishment of a classified board of directors. The classified board provision established three classes of directors, with each class to be elected for a three-year term on a staggered basis. The classified board provision is intended to promote management continuity and stability and to afford time and flexibility in responding to unsolicited tender offers. |
| |
|
Available Information |
| |
|
The Company files annual, quarterly and current reports, proxy statements and other information with the Commission. These filings are available free of charge through our internet website at www.txco.com as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Commission. |
| |
| |
|
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 13,500 square feet, are leased through August 2007 at $21,300 per month with annual escalations each February 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. |
| |
|
CAPITAL RESOURCES AND LIQUIDITY |
| |
|
Year Ended December 31, 2002 |
| |
|
During 2002 beginning cash reserves of $2 million were increased by net cash provided from operating activities of $7.4 million resulting in a total of $9.4 million in internally generated working capital for use in funding ongoing expansion, development and exploration of the Company's oil and gas properties. Additionally, cash of $21 million from other sources listed below resulted in total cash of $31.3 million available for use in meeting the Company's ongoing operational and development needs. Included in the $21 million cash received from other sources, is approximately $14.1 million from a private placement of 2,499,667 shares of restricted common stock at a price of $6.00 per share to a group of 10 institutional investors. The amount raised, net of offering costs of $0.9 million, was used for acquisitions, to accelerate the development of the Company's extensive Maverick Basin acreage holdings and for general corporate purposes. Pursuant to the placement agreement,
the Company filed a Form S-3 Registration Statement dated June 6, 2002, covering the issued shares on behalf of the investors. |
| |
|
2002 Cash Available to the Company |
| |
|
|
|
|
|
|
Beginning cash reserves, January 1, 2002 |
|
|
$ |
2,019,164 |
|
|
Net cash provided by operating activities |
|
|
|
7,389,430 |
|
|
|
|
|
|
|
|
Sub-total |
|
|
|
9,408,594 |
|
|
Private placement of 2,499,667 shares of
common stock |
$ |
14,051,893 |
|
|
|
|
Borrowings on the new Credit Facility |
|
5,800,000 |
|
|
|
|
Other debt obligations |
|
1,639,915 |
|
|
|
|
Exercise of outstanding options for the Company's common stock |
|
172,755 |
|
|
|
|
Proceeds from sale of oil and gas properties |
|
200,000 |
|
|
|
|
|
|
|
|
|
|
Total other sources of cash |
|
|
$ |
21,864,563 |
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
2002 Cash Available |
|
|
$ |
31,273,157 |
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
The Company applied $27.4 million of its working capital to fund the expansion and ongoing development of its oil and gas properties. Included were drilling, completion, seismic and acquisition costs totaling $17.4 million, primarily targeting TXCO's core area, the Maverick Basin. This represented expenditures for the drilling, completion and re-entry of 41 oil and gas wells and the acquisition of Maverick Basin mineral leases. In addition, the Company acquired a 69-mile pipeline system. The pipeline system has and continues to gather most of the Company's natural gas in the Maverick Basin. The following table summarizes uses of cash during 2002. |
| |
|
2002 Uses of Cash |
| |
|
|
|
|
Drilling and completion costs, 3-D seismic, and leasehold acquisitions |
$
|
17,410,942 |
|
|
Natural gas pipeline and facilities |
|
5,767,291 |
|
|
Pena Creek acquisition and improvements |
|
3,681,902 |
|
|
Well service equipment |
|
183,145 |
|
|
Upgrade information system and related infrastructure |
|
337,967 |
|
|
Other |
|
39,036 |
|
|
|
|
|
|
Sub-total |
|
27,420,283 |
|
|
Net distributions to minority interests |
|
434,325 |
|
|
Debt principal payments |
|
1,084,861 |
|
|
|
|
|
| |
$ |
28,939,469 |
|
|
|
|
|
| |
|
|
|
|
The Company made timely payments of $1,084,861 on its long-term debt obligations during 2002, while payments on interest totaled $273,213. |
| |
|
Acquisition - Pipelines : In May 2002, the Company completed the acquisition of The Maverick Pipeline System from Aquila Southwest Pipeline Corporation for a total purchase price of $4.9 million. TXCO's initial 80% interest ($3.9 million) was purchased through its newly formed Maverick-Dimmit Pipeline, Ltd. Partnership (the Partnership). The remaining 20% of the Partnership was held by an unaffiliated private energy concern. This acquisition was funded with proceeds from a $15 million private placement also closed in May. |
| |
|
In June, the Partnership acquired an additional 10 miles of pipeline from TXCO's 62.5% owned subsidiary, the Paloma Pipeline L.P. for $1 million. During the third quarter, the Partnership began construction of a 3 mile, $300,000 pipeline extension to connect the Company's growing Chittim lease production to the pipeline system. This extension was placed in service early in the fourth quarter. |
| |
|
During the fourth quarter 2002, TXCO consolidated its position by acquiring the outstanding 20% minority interest in Maverick-Dimmit Pipeline, Ltd., at its book value of $1.3 million. The consolidation was funded through TXCO's available Credit Facility. |
| |
|
Acquisition - Pena Creek: Also in May 2002, the Company acquired the Pena Creek oil field in Dimmit County, Texas from Merit Energy Company for $3.75 million. The purchase was effective April 1, 2002. The acquisition consisted of 94 producing oil wells, 94 injection wells and 28 shut-in wells. |
| |
|
As a result of these activities, the Company ended the year 2002 with a negative working capital of $1,884,507 and a current ratio of .81 to 1. This year-end position compares to negative working capital of $1,554,454 and a current ratio of .73 to 1 at December 31, 2001. The Company ended 2002 with an unused borrowing base of $6.2 million. The Company's ending working capital for years ended 2002 and 2001 was significantly impacted by the high level of drilling activity during the two year period. |
|
|
|
Bank Credit Facility: On March 4, 2002 the Company entered into a $25 million oil and gas reserve based Revolving Credit Facility with Hibernia National Bank providing a credit line with an initial borrowing base set at $5 million. The borrowing base was subsequently increased to $13 million as of September 30, 2002, with quarterly reductions of $1 million. At December 31, 2002, the borrowing base was $12 million with an outstanding balance of $5.8 million, resulting in an unused borrowing base of $6.2 million. The unused borrowing base at March 17, 2003, was $3.5 million. Interest is payable monthly, with principal due at maturity in March 2005. Uses of proceeds are for the acquisition and development of oil and gas properties and general corporate working capital purposes. The Facility provides the lender with semiannual scheduled redeterminations, at mid-year and each subsequent anniversary date, while providing for two unscheduled redeterminations per year, at the
Company's discretion. Borrowings under the Facility are secured by a first priority mortgage covering the Company's working and other interests in the majority of its oil and gas leases. The interest rate under the facility will initially be based on the Wall Street Journal Prime Rate plus applicable margin. A Eurodollar Rate plus applicable margin may be utilized at the election of the Company. The interest rate at December 31, 2002, was 4.25%, and the rate was unchanged at March 10, 2003. The Facility also provides the lender with a commitment fee equal to 0.5%, per annum on the unused borrowing base. The Facility contains certain financial covenants and other negative restrictions common for a financing of this type. Any unused borrowing base is a net increase to working capital for purposes of the Current Ratio covenant. |
| |
|
Management believes that the Facility, along with the Company's positive cash flow from existing production and anticipated production increases from new drilling, will provide adequate capital to fund ongoing operating cash requirements for 2003 and to complete its scheduled exploration and development goals as targeted by its 2003 capital expenditure program. |
| |
|
However, there is no assurance that the Company will re-establish profitability in 2003 nor that expected increases in new oil and natural gas production will be realized, nor that sufficient debt capital will remain available from its new borrowing Facility. Should these concerns be realized or should commodity prices weaken significantly, the Company's financial condition could be adversely affected and could cause the Company to defer planned capital expenditures consistent with its available capital resources. |
| |
|
Year Ended December 31, 2001 |
| |
|
During 2001 beginning cash reserves were increased by net cash provided from operating activities resulting in a total of $14.5 million in internally generated working capital, and $2.2 million from other sources, listed below, for a total of $16.7 million in cash available for use in funding the ongoing expansion, development and exploration of the Company's oil and gas properties. |
| |
|
2001 Cash Available to the Company |
| |
|
|
|
|
|
|
Beginning cash reserves, January 1, 2001 |
|
|
$ |
5,898,015 |
|
|
Net cash provided by operating activities |
|
|
|
8,564,022 |
|
|
|
|
|
|
|
|
Sub-total |
|
|
|
14,462,037 |
|
|
Other debt obligations |
$ |
153,231 |
|
|
|
|
Exercise of outstanding options for the Company's common stock |
|
31,250 |
|
|
|
|
Sale of oil and gas properties |
|
2,005,133 |
|
|
|
|
|
|
|
|
|
|
Total other sources of cash |
|
|
|
2,189,614 |
|
|
|
|
|
|
|
|
2001 Cash Available |
|
|
$ |
16,651,651 |
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
The Company applied $13.8 million of its working capital to fund the expansion and ongoing development of its oil and gas properties. Included were drilling, completions, seismic and leasehold acquisition costs totaling $13.4 million primarily targeting TXCO's core area, the Maverick Basin. This represented expenditures for the drilling, completion and re-entry of 73 oil and gas wells and new Maverick Basin mineral lease purchases of approximately 158,000 acres. Also included were expenditures for the expansion of the Company's Paloma lease gas gathering facilities and for vehicles and other equipment used in the field. |
| |
|
2001 Uses of Cash |
| |
|
|
|
|
Drilling and completion costs, 3-D seismic, and leasehold acquisitions |
$
|
13,360,347
|
|
|
Expansion of natural gas gathering facilities |
|
94,271 |
|
|
Other property and equipment |
|
220,709 |
|
|
Other |
|
116,007 |
|
|
|
|
|
|
Sub-total |
|
13,791,334 |
|
|
Purchase of 99,800 shares of treasury stock |
|
246,007 |
|
|
Debt principal payments |
|
486,244 |
|
|
Net distributions to minority interests |
|
108,902 |
|
|
|
|
|
| |
$ |
14,632,487 |
|
|
|
|
|
| |
|
|
|
|
The Company made timely payments of $486,244 on its long-term debt obligations during 2001, while payments on interest totaled $128,373. Additionally, the Company purchased 99,800 shares of its common stock for its treasury at a cost of $246,007 under its common share buyback program approved by the Board of Directors on June 27, 2001. |
| |
|
As a result of these activities, the Company ended the year 2001 with a negative working capital of $1,554,454 and a current ratio of .73 to 1. This year-end position compares to positive working capital of $6,349,625 and a current ratio of 2.36 to 1 at December 31, 2000. The decrease in ending working capital was attributable to the increased levels of development activities through the third quarter coupled with the sharp decline in realized gas prices during the second half of 2001. |
| |
|
2003 Capital Requirements |
| |
|
The major components of the Company's plans, and the requirements for additional capital for 2003, include the following: |
| |
|
Maverick Basin Activity : |
| |
|
Initial capital expenditures planned for 2003 total over $27.4 million and target the Company's Maverick Basin core properties. The primary component of these expenditures is $24.9 million for drilling wells, while over $2.5 million is earmarked for seismic and leasehold and gas gathering system enhancements and other infrastructure expansion activities. The Company's budgeted capital expenditures are intended to be flexible. Overall budgeted capital outlays are subject to substantial increase should the Company's key exploration targets, development activities or special situations or opportunities warrant higher capital outlays than originally planned. |
| |
|
The Company initially plans to drill 93 wells, including 26 Glen Rose porosity zone oil wells, 17 Glen Rose shoal horizontal gas wells, 25 Georgetown gas wells, 15 San Miguel waterflood oil wells in the Pena Creek field, and 10 shallow Escondido gas wells. Some of these wells will be operated by other companies and, therefore, TXCO does not have direct control over when they will be drilled or what final costs will actually be incurred. The following table details typical gross well costs for 2003 budgeted wells. |
| |
| |
|
Typical Gross Well Costs |
|
|
|
|
|
| |
|
Dry Hole |
|
Completed |
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
Glen Rose oil porosity zone well |
|
$500,000 |
|
$750,000 |
|
|
Glen Rose shoal gas well |
|
500,000 |
|
650,000 |
|
|
Georgetown gas well |
|
150,000 |
|
275,000 |
|
|
San Miguel waterflood oil well |
|
100,000 |
|
175,000 |
|
|
Escondido gas well |
|
100,000 |
|
150,000 |
|
| |
|
|
|
|
|
|
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 2003 delay rentals of $180,000 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 |
| |
|
The Company expects it will have a continuing ability to further increase its borrowing base commensurate with the expected additional growth of its proved oil and gas reserves throughout the base term of the new Facility. Management remains confident that financial resources will remain available, enabling the Company to continue the rapid development of its oil and gas properties and continue to meet its normal operational and debt service obligations on a timely basis. |
| |
|
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 coming year, there is no assurance that energy prices or other market factors will continue to improve. Should prices weaken, or should expected new oil and gas production levels from planned 2003 drilling not be attained, the resulting reduction in projected revenues would cause the Company to re-evaluate its expected sources of working capital and would adversely affect the Company's ability to carry out its current operating plans. |
| |
|
RESULTS OF OPERATIONS |
| |
|
2002 Compared to 2001 |
| |
|
The Company reported a net loss of $310,970 or $0.016 per basic and diluted share for the year ended December 31, 2002, compared to a net loss of $50,283 or $0.003 per basic and diluted share for the prior year. |
| |
|
Revenues for 2002 increased by 38% compared to 2001. Oil production increased by 528% while natural gas production declined by 7% as compared with the prior year. The increase in oil production is due to the new Comanche lease oil wells, along with production from the May 2002 acquisition of the Pena Creek field. The decline in 2002 gas production compared to the prior year reflects the general production decline of the Company's existing mix of maturing gas wells. This decline was partially offset by new gas production from the 16 new gas wells drilled and completed during the year. Included in the number of gas wells classified as producing at December 31, 2002, were 38 CBM gas wells, which are still in their initial dewatering stage, and are not yet contributing a significant amount of new gas production. On an equivalent unit basis, prices averaged 18% lower in 2002 as compared to 2001. Crude oil prices averaged 4% higher while natural gas prices fell 27%. Average lowe
r prices for 2002, as compared to 2001, had a $3.6 million negative impact on revenues in 2002. Commodity prices have been and continue to be volatile. During 2001, realized gas prices ranged from over $10.50 per Mcf in January to a low of $1.26 per Mcf in October. During 2002 realized natural gas prices ranged from over $4.71 per Mcf in November to a low of $1.75 in February. During the first three months of 2003 crude oil and natural gas prices have increased significantly. |
| |
|
Average daily net gas production rates in 2002 decreased to 6.8 MMcf, a 7% decline from the prior year, while average daily net oil production rates in 2002 increased to 860 Bbls, a 528% over the prior year. The Company expects to reverse the declining natural gas production rates based on its year 2003 drilling success to date and expected results from ongoing drilling projects. |
| |
|
Lease operating expense for 2002 increased $1.8 million, from $2.4 million in 2001 to $4.2 million in 2002, a 76% increase. This increase is primarily due to the addition of 16 new natural gas wells and 14 new oil wells during 2002 and the acquisition of 188 active Pena Creek wells. The increase reflects the incremental direct costs of operating the new wells, including typical costs such as pumper, electricity, water disposal, and other direct overhead charges, as added during 2002 to the Company's existing lease operating expense levels. Operating expense per Mcfe increased $0.06, from $1.13 in 2001 to $1.19 in 2002. The increase in the rate is due to the Pena Creek field, which consists of three waterflood units. Typically, waterfloods incur higher costs of operations. Excluding the Pena Creek field, operating expense per Mcfe for 2002 is $1.07, a decrease of $0.06 from the prior year. Also, included in operating costs is the cost of operating the CBM wells. These costs to
taled $583,852 in 2002 and $446,006 in 2001. The CBM wells are in the dewatering phase and therefore have little production relative to their operating costs. Operating cost per Mcfe excluding the CBM wells and Pena Creek averaged $0.93 in 2002 and $0.99 in 2001. |
| |
|
Pursuant to the successful efforts method of accounting for mineral properties, the Company periodically assesses its producing and non-producing properties for impairment. Impairment and abandonments decreased by 53% primarily due to lower impairment rates on non-producing acreage in the Williston Basin during 2002 versus 2001. Depreciation, depletion and amortization increased by almost $2.9 million, or 123%, over 2001 due primarily to the increased number of producing wells being depleted for wells added through the drill bit and the Pena Creek acquisition. The increase in depreciation was due to increased investments in other equipment including the pipeline and well service equipment acquisitions. The increase in amortization was primarily due to the full year amortization related to the 3-D seismic survey on the Comanche lease acquired during 2001. |
| |
|
General and administrative costs increased 37% compared to 2001 reflecting the higher sustained level of Company operations. The increase is due primarily to increased salaries, wages and benefits associated with staff increases including 6 engineering and administrative staff additions and 8 new field personnel during 2002. Also contributing to the increase were higher costs for property and liability insurance and increased investor relations expenses. |
| |
|
The 75% decrease in interest income reflects the declining cash levels in interest bearing accounts and declining interest rates during 2002 versus 2001. Interest expense increased by $144,840 in 2002 from 2001 due to higher debt levels. |
| |
|
2001 Compared to 2000 |
| |
|
The Company reported a net loss of $50,283 or $0.003 per basic and diluted share for the year ended December 31, 2001, compared to net income of $6,761,935 or $0.39 per basic and diluted share for the prior year. Net income in 2000 included a deferred tax benefit of $5,232,700 while no similar benefit was recognized in 2001. |
| |
|
Although, 2001 revenues decreased by 1.5% compared to year 2000 levels, 2001 oil and gas production declined by 9.8% and 17.5% respectively as compared with 2000. The 17.5% decline in oil production primarily reflects the advancing decline curve of maturing oil wells in the Williston Basin. In addition, a 15.4 % decline in the average price of oil was offset somewhat by an 11% increase in the average price of gas as compared to 2000 prices for both commodities. The decline in 2001 gas production compared to the prior year reflects the general production decline of the Company's existing mix of maturing gas wells. This decline was partially offset by new gas production from the 54 new gas wells drilled and completed during 2001. Included in the number of gas wells classified as producing in 2001 were 34 CBM gas wells, which were still in their initial dewatering stage and not yet contributing a significant amount of new gas production. A significant contribution of new CBM
gas production is expected from these wells upon their reaching Phase 2 of the dewatering process. |
| |
|
Average daily net gas production rates in 2001 decreased to 7.3 MMcf, an 11% decline over the prior year, while average daily net oil production rates in 2001 decreased to 136 Bbls, a 26% decline over the prior year. |
| |
|
Lease operations expense for 2001 increased 108% compared to 2000. This increase was primarily due to the addition of 54 new gas wells and 9 new oil wells during 2001. The increase reflects the incremental direct costs of operating the new wells, including typical costs such as pumper, electricity, water disposal, and other direct overhead charges, as added during 2001 to the Company's existing lease operating expense levels. The 7 new Burr wells increased overall annual lease operating costs by approximately $469,000 due to the higher costs of chemical treatment for H 2S removal and related costs of operating an amine plant for these gas wells plus costs associated with salt water disposal. The 34 newly connected CBM wells in the dewatering pilot project added $419,000 in incremental operating costs in 2001 and reflect the high operating costs associated with the de-watering phase of the CBM pilot program initiated in 2001. Addit
ionally, ad valorem taxes increased approximately 30% in 2001 compared to 2000 reflecting increased appraised values for new oil and gas properties as well as increased valuations of exiting wells due to higher oil and gas prices over the prior year. Exploration expenses remained consistent with 2000. |
| |
|
Pursuant to the successful efforts method of accounting for mineral properties, the Company periodically assesses its producing and non-producing properties for impairment. Impairment and abandonment decreased by 15% primarily due to lower impairment rates on non-producing acreage in the Williston Basin during 2001 versus 2000. This decrease was somewhat offset by an increase in impairments of producing properties resulting from lower oil and gas prices at year end and the resultant decreased property values in the year-end reserve report. Depreciation, depletion and amortization increased by almost $500,000 or 18% over calendar 2000 levels due primarily to the increased number of producing wells being depleted and higher depletion rates for 2001 caused by lower year-end reserve volumes as a result of lower oil and gas prices at December 31, 2001. The increase in depreciation was due to increased investments in other equipment including the expansion of the Paloma lease ga
thering system throughout the year. The increase in amortization was primarily due to the additional amortization related to the 78-square mile 3-D seismic survey on the Comanche lease acquired during 2001. |
| |
|
General and administrative costs increased 19% compared to 2000 reflecting the higher sustained level of Company operations. 68% of the increase was due primarily to increased salaries, wages and benefits associated with staff increases including 2 engineering and administrative staff additions and 6 new field personnel during 2001. Also contributing to the increase were higher costs for property and liability insurance, increased accounting and auditing fees and increased state franchise tax expenses. |
| |
|
The 19% decrease in interest income reflects the declining cash levels in interest bearing accounts and declining interest rates during 2001 versus 2000. Interest expense decreased by $51,000 in 2001 from 2000 due to the retirement of the Range debt during the second quarter of 2000. Income tax expensed decreased by $5,216,800 due to the recognition of a deferred federal tax benefit of $5,232,700 in 2000, while no similar benefit was recognized in 2001. |
| |
|
CONTRACTUAL OBLIGATIONS AND CONTINGENT LIABILITIES AND COMMITMENTS |
| |
|
The following is a summary of the Company's future payments on obligations as of December 31, 2002. |
| |
| |
Payments Due by Period |
|
|
|
|
| |
|
|
2-3 |
4-5 |
After 5 |
|
|
|
|
Contractual Obligations |
1 Year |
Years |
Years |
Years |
Total |
|
|
|
|
|
| |
|
|
|
|
|
|
|
Long-term debt |
$ |
1,073,773 |
$ |
6,143,458 |
$ |
- |
|
- |
$ |
7,217,231 |
|
|
Operating lease obligations |
|
300,000 |
|
610,000 |
|
486,000 |
|
- |
|
1,396,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Contractual Cash Obligations |
$
|
1,373,773 |
$
|
6,753,458 |
$
|
486,000 |
|
- |
$
|
8,613,231 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
In addition to the above, in January 2003 the Company entered into a $2.8 million unsecured installment obligation. Imputed interest due on the obligation is 4.25% per annum. Payments are due in two equal installments: $1.4 million in January 2004 and January 2005. |
| |
|
In January 2003 the Company entered into a contract to deliver natural gas at a fixed price. The volumes to be delivered under the contract are as follows: |
| |
| |
Commitment by Period |
|
|
|
|
| |
|
|
2-3 |
4-5 |
After 5 |
|
|
|
Fixed Price Contract |
1 Year |
Years |
Years |
Years |
Total |
|
|
|
|
|
| |
|
|
|
|
|
|
|
Natural Gas |
|
|
|
|
|
|
|
|
|
|
|
|
Volume, MMBtu * |
|
901,800 |
|
- |
|
- |
|
- |
|
901,800 |
|
|
Fixed price per MMBtu** |
$ |
4.45 |
|
- |
|
- |
|
- |
$ |
4.45 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
* Approximately 2,700 MMBtu per day for the period February 1, 2003 through December 31, 2003. |
|
** Net of transportation and marketing costs. |
| |
|
The volumes to be delivered under the contract represented approximately 30% of the Company's natural gas production rate at December 31, 2002. The Company expects to be able to delivery the committed volumes from its Maverick Basin production. |
| |
|
CRITICAL ACCOUNTING POLICIES AND ESTIMATES |
| |
|
The discussion and analysis of the Company's financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Our significant accounting policies are described in Note A to our consolidated financial statements. In response to SEC Release No. 33-8040, "Cautionary Advice Regarding Disclosure About Critical Accounting Policies," we have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management. We analyze our estimates, including those related to oil and gas revenues, oil and gas properties, income taxes, contingencies and litigation, an
d base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of the Company's financial statements: |
| |
|
Successful Efforts Method of Accounting |
| |
|
The Company accounts for its natural gas and crude oil exploration and development activities utilizing the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells, costs to acquire mineral interests and 3-D seismic costs are capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses including 2-D seismic costs and delay rentals for oil and gas leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized. |
| |
|
The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature and an allocation of costs is required to properly account for the results. The evaluation of oil and gas leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with referenc
e to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions. |
| |
|
The successful efforts method of accounting can have a significant impact on the operational results reported when the Company is entering a new exploratory area in hopes of finding an oil and gas field that will be the focus of future development drilling activity. The initial exploratory wells may be unsuccessful and will be expensed. |
| |
|
Reserve Estimates |
| |
|
The Company's estimates of oil and gas reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future oil and gas prices, future operating costs, severance taxes, development costs and w
orkover gas costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to an extent that these reserves may be later |
|
determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of oil and gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected therefrom may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of the Company's oil and gas properties and/or the rate of depletion of the oil and gas properties. Actual production, revenues and expenditures, with respect to the Company's reserves, will likely vary from estimates and such variances may be material. |
| |
|
Impairment of Oil and Gas Properties |
| |
|
The Company reviews its oil and gas properties for impairment at least annually and whenever events and circumstances indicate a decline in the recoverability of their carrying value. The Company estimates the expected future cash flows of its oil and gas properties and compares such future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to their fair value. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected. |
| |
|
Given the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that would require the Company to record an impairment of the recorded book values associated with oil and gas properties. The Company has recognized impairments in prior years and there can be no assurance that impairments will not be required in the future. |
| |
|
New Accounting Standards |
| |
|
In April 2002, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 145, "Revision of FASB Statements No. 4, 44 and 64, and Amendment of FASB Statement No. 13 and Technical Corrections". This Statement changes the presentation and reporting of extinguishments of debt on the Statement of Operations. The required adoption of this Statement in 2003 by the Company is not expected to have a material impact on its operating results or financial position. |
| |
|
In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities". SFAS No. 146 requires that a liability for costs associated with an exit or disposal activity be recognized and measured initially at fair value and only when the liability is incurred. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002. The Company does not expect the adoption of SFAS 146 to have a material impact on its operating results or financial position. |
| |
|
In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure - an Amendment of FASB Statement No. 123". This Statement provides guidance and transition rules for those companies electing to change their method of accounting for stock-based compensation. However, the statement does not require the change in accounting, and TXCO has elected to continue reporting stock-based compensation following SFAS No. 123 and Accounting Principles Board Opinion No. 25. SFAS No. 148 also requires certain enhanced disclosures regarding stock-based compensation, and such disclosures have been included in these footnotes to the financial statements. |
|
PART III |
| |
|
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 24, 2003: |
| |
|
Name |
|
Class |
|
Position |
|
Age |
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
Stephen M. Gose, Jr. |
|
B |
|
Chairman of the Board of Directors
Member Compensation and Nominations Committees |
|
73 |
|
| |
|
|
|
|
|
|
|
|
Michael J. Pint |
|
C |
|
Director, Chairman Audit Committee
Member Compensation and Nominations Committees |
|
59 |
|
| |
|
|
|
|
|
|
|
|
Robert L. Foree, Jr. |
|
A |
|
Director, Chairman Nominations Committee
Member Audit and Compensation Committees |
|
73 |
|
| |
|
|
|
|
|
|
|
|
Alan L. Edgar |
|
B |
|
Director, Chairman Compensation Committee
Member Audit and Nominations Committees |
|
57 |
|
| |
|
|
|
|
|
|
|
|
James E. Sigmon |
|
C |
|
President and Director |
|
54 |
|
| |
|
|
|
|
|
|
|
|
Thomas H. Gose |
|
A |
|
Director and Assistant Secretary
Member Nominations Committee |
|
47 |
|
| |
|
|
|
|
|
|
|
|
Roberto R. Thomae |
|
|
|
Chief Financial Officer
Secretary/Treasurer, Vice President-Finance |
|
52 |
|
| |
|
|
|
|
|
|
|
|
Richard A. Sartor |
|
|
|
Controller |
|
50 |
|
| |
|
|
|
|
|
|
|
|
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 Compensation Committees since June 1997 and served as its Chairman through April 1998. Mr. Gose was a member of the Audit Committee from June 1997 through May 2001 and served as its Chairman from June 1997 through April 1998. He has been a member of the Nominations Committee since its inception in May 2001. Mr. Gose 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 46 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 Committee of the Board of Directors since June 1997 and has served as its Chairman since April 1998. Mr. Pint has been a member of the Compensation Committee since June 1997 and served as its Chairman from April 1998 through May 2001. He has been a member of the Nominations Committee since its inception in May 2001. Mr. Pint has 36 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. Previous bank regulatory and management positions include a four-year term as Commissioner of Banks and Chairman of the Minnesota Commerce Commis
sion 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. He has been a member of the Nominations Committee and served as its Chairman since its inception in May 2001. A geologist by training, he has been active for more than 46 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 served as the Chairman of the Compensation Committee since May 2001. Mr. Edgar has been a member of the Nominations Committee since its inception in May 2001. He has been involved in energy related investment banking and equity analysis for 30 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 1
990 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 31 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 had been a member of the Audit and Nominations Committees since May 2001. During 2002 Mr. Gose resigned from the Audit Committee. Mr. Gose 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 Inc., 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 Directors listed above has been elected by the shareholders to serve until his successor is duly elected. In May 2001 the shareholders of the Company approved the adoption of a classified board. The board is structured with three classes of directors, Classes A, B and C, each having two directors with current terms expiring in the years 2005, 2003 and 2004, respectively. Directors elected at the May 2002 annual meeting and later meetings serve full three-year terms. |
| |
| |
|
SECURITY OWNERSHIP OF MANAGEMENT |
| |
|
The following table sets forth the number of shares of common stock beneficially owned as of March 24, 2003 by 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) |
1,517,877 |
|
7.57 |
% |
|
| |
Thomas H. Gose |
(7) (8) |
824,601 |
|
4.11 |
% |
|
| |
James E. Sigmon |
(2) |
774,400 |
|
3.74 |
% |
|
| |
Michael Pint |
(4) |
325,000 |
|
1.62 |
% |
|
| |
Alan L. Edgar |
(5) |
278,433 |
|
1.38 |
% |
|
| |
Robert L. Foree, Jr. |
(4) |
99,100 |
|
.49 |
% |
|
| |
Roberto R. Thomae |
(6) |
150,000 |
|
.74 |
% |
|
| |
|
|
|
|
|
|
|
| |
All Directors and Executive |
|
|
|
|
|
|
| |
Officers as a group |
|
4,006,911 |
|
18.78 |
% |
|
| |
|
|
|
|
|
|
|
|
(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 74,400 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. Stephen M. Gose, Jr. include his 100% interest, shared equally with his spouse, in 1,467,877 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 24, 2003 plus 250,000 and 24,100 respectively, of directly owned shares. |
|
(5) |
The number of shares beneficially owned by Mr. Edgar includes 95,100 shares owned directly, 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 and 50,000 shares reserved for issuance under non-qualified options issued to outside directors of the Company exercisable at March 24, 2003. |
|
(6) |
The number of shares beneficially owned by Mr. Thomae includes 150,000 shares of the Company's Common Stock reserved for issuance through options issued under the Company's 1995 Flexible Incentive Plan. |
|
(7) |
The number of shares beneficially owned by Mr. Stephen M. Gose, Jr. and Mr. Thomas H. Gose each includes 50,000 shares of the Company's common stock reserved for issuance under non-qualified options issued to outside directors of the Company exercisable at March 24, 2003. |
|
(8) |
The number of shares beneficially owned by Mr. Thomas Gose include 774,601 shares owned directly. |
|
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS |
| |
|
Plan Category
|
Number of Securities to be
Issued Upon Exercise of
Outstanding Options,
Warrants and Rights |
|
Weighted-average
Exercise Price of
Outstanding Options,
Warrants
and Rights |
Number of Securities
Remaining Available for
Future Issuance Under Equity
Compensation Plans
(excluding securities
reflected in column (a) |
|
|
|
|
|
|
|
|
|
|
| |
(a) |
|
(b) |
(c) |
|
|
Equity compensation plans
approved by security holders |
1,463,000 |
|
|
$ |
2.49 |
|
139,000 |
|
|
|
Equity compensation plans not
approved by security holders |
N/A |
|
|
|
N/A |
|
N/A |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
1,463,000 |
|
|
$ |
2.49 |
|
139,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
| |
|
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS |
| |
|
None. |
| |
| |
|
ITEM 14. CONTROLS AND PROCEDURES |
| |
|
The Company's Chief Executive Officer and the Chief Financial Officer have carried out an evaluation of the effectiveness of the design and operation of the Company's disclosure controls and procedures pursuant to Exchange Act Rule 13a-14 and Rule 15d-14. Based upon that evaluation, which took place as of a date within 90 days of the filing of this report, the Company's Chief Executive Officer along with the Chief Financial Officer concluded that the Company's disclosure controls and procedures are effective in timely alerting them to material information relating to the Company (including its consolidated subsidiaries) required to be included in reports it files with the SEC. |
| |
|
There have been no significant changes in the Company's internal controls or in other factors that could significantly affect internal controls subsequent to the date of the above evaluation. |
| |
| |
|
PART IV |
| |
|
ITEM 15. 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 F-1. |
| |
|
(1) |
Consolidated Financial Statements: |
| |
Independent Auditors' Reports. |
| |
Balance Sheets, December 31, 2002 and December 31, 2001. |
| |
Statements of Operations, Years Ended December 31, 2002, 2001 and 2000. |
| |
Statements of Stockholders' Equity, Years Ended December 31, 2002, 2001 and 2000. |
| |
Statements of Cash Flows, Years Ended December 31, 2002, 2001 and 2000. |
| |
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 Incentive Stock 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 registrant's 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 registrant's 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 registrant's 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 of Series A Junior Participating Preferred Stock; as Exhibit B thereto, Form of Right Certificate; as Exhibit C thereto, Summary of Rights to Purchase Preferred Shares. |
|
10.12 |
Loan Agreement dated March 4, 2002, between The Exploration Company and Hibernia National Bank filed herewith. |
|
10.13 |
First Amendment to Loan Agreement dated December 13, 2002 between The Exploration Company and Hibernia National Bank filed herewith. |
|
** 10.14 |
Registrant's Certificate of Amendment of Certificate of Incorporation of The Exploration Company of Delaware, Inc., filed as Appendix B of the registrant's definitive Proxy Statement, dated May 25, 2001. |
|
** 10.15 |
Registrant's Amendment to its Flexible Incentive Plan, filed as Proposal IV of the registrants definitive Proxy Statement, dated May 25, 2001. |
|
** 10.16 |
Registrant's Audit Committee Charter filed as Appendix A of the registrant's definitive Proxy Statement, dated May 25, 2001. |
|
99.1 |
Certification of Chief Executive Officer required pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 filed herewith. |
|
99.2 |
Certification of Chief Financial Officer required pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 filed herewith. |
| |
|
|
** |
Previously filed |
| |
|
| |
| |
|
(B) Reports on Form 8-K: |
| |
|
No reports on Form 8-K were filed during the quarter ended Dec. 31, 2002. |
| |
|
Form of Sarbanes-Oxley Section 302(a) Certification |
| |
|
I, James E. Sigmon, certify that: |
| |
|
1. |
I have reviewed this annual report on Form 10-K of The Exploration Company of Delaware, Inc.; |
| |
|
|
2. |
Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; |
| |
|
|
3. |
Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present, in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; |
| |
|
|
4. |
The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have |
| |
|
| |
i) |
designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; |
| |
|
|
| |
ii) |
evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and |
| |
|
|
| |
iii) |
presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; |
| |
|
|
|
5. |
The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): |
| |
|
|
| |
i) |
all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and |
| |
|
|
| |
ii) |
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and |
| |
|
|
|
6. |
|
The registrant's other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. |
| |
|
|
| |
|
|
|
Date: |
March 28, 2003 |
/s/ James E. Sigmon |
|
|
|
|
|
| |
|
James E. Sigmon |
| |
|
Chief Executive Officer |
| |
|
|
|
Form of Sarbanes-Oxley Section 302(a) Certification |
| |
|
I, Roberto R. Thomae, certify that: |
| |
|
1. |
I have reviewed this annual report on Form 10-K of The Exploration Company of Delaware, Inc.; |
| |
|
|
2. |
Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; |
| |
|
|
3. |
Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present, in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; |
| |
|
|
4. |
The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have |
| |
|
| |
i) |
designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; |
| |
|
|
| |
ii) |
evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and |
| |
|
|
| |
iii) |
presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; |
| |
|
|
|
5. |
The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): |
| |
|
|
| |
i) |
all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and |
| |
|
|
| |
ii) |
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and |
| |
|
|
|
6. |
|
The registrant's other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. |
| |
|
|
| |
|
|
|
Date: |
March 28, 2003 |
/s/ Roberto R. Thomae |
|
|
|
|
|
| |
|
Roberto R. Thomae |
| |
|
Chief Financial Officer |
| |
|
|
|
THE EXPLORATION COMPANY |
|
Notes to Audited Consolidated Financial Statements |
|
Years Ended December 31, 2002, 2001 and 2000 |
| |
|
NOTE A - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES |
| |
|
Organization and Operations: The Exploration Company of Delaware, Inc., d.b.a. The Exploration Company ("TXCO" or "Company") is an independent energy company engaged in the acquisition, exploration, development and production of oil and gas properties. The Company's primary focus is on developing oil and gas reserves on properties located in Texas. The Company also owns properties in South Dakota, North Dakota and Montana. |
| |
|
Consolidation: The financial statements include the accounts of the Company and its majority-owned subsidiaries. The subsidiaries own and operate a gas gathering system which is utilized by the Company for delivery of natural gas from its Texas properties. All significant intercompany balances and transactions have been eliminated in consolidation. |
| |
|
Revenue Recognition: The Company recognizes oil and gas revenue from its interest in producing wells as the oil and gas is sold to third parties. Pipeline revenues are recognized upon delivery of the product to third parties. |
| |
|
Cash and Equivalents: The Company considers all highly liquid investments with an original maturity of three months or less to be cash and equivalents. |
| |
|
Accounts Receivable: Accounts receivable are reported at outstanding principal net of an allowance for doubtful accounts of approximately $27,000 at December 31, 2002 and December 31, 2001. The Company normally does not charge interest on accounts receivable. The allowance for doubtful accounts is generally determined based on the Company's historical losses, as well as a review of certain accounts. Accounts are charged off when collection efforts have failed and the account is deemed uncollectible. |
| |
|
Oil and Gas Properties: The Company uses the successful efforts method of accounting for its oil and gas activities. Costs to acquire mineral interests, 3-D seismic costs, development wells, and costs to drill and equip exploratory wells that find proved reserves are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, 2-D seismic 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. Depletion of coalbed methane properties begins following the dewatering phase of each coalbed methane project. 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 assets and liabilities are determined based on the temporary differences between the financial statement and tax basis of assets and liabilities, using enacted tax rates in effect for the year in which the differences are expected to reverse. |
| |
|
THE EXPLORATION COMPANY |
|
Notes to Audited Consolidated Financial Statements |
|
Years Ended December 31, 2002, 2001 and 2000 |
| |
|
NOTE A - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - continued |
| |
|
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: In April 2002, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 145, "Revision of FASB Statements No. 4, 44 and 64, and Amendment of FASB Statement No. 13 and Technical Corrections". This Statement changes the presentation and reporting of extinguishments of debt on the Statement of Operations. The required adoption of this Statement in 2003 by the Company is not expected to have a material impact on its operating results or financial position. |
| |
|
In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities". SFAS No. 146 requires that a liability for costs associated with an exit or disposal activity be recognized and measured initially at fair value and only when the liability is incurred. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002. The Company does not expect the adoption of SFAS 146 to have a material impact on its operating results or financial position. |
| |
|
In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure - an Amendment of FASB Statement No. 123". This Statement provides guidance and transition rules for those companies electing to change their method of accounting for stock-based compensation. However, the statement does not require the change in accounting, and TXCO has elected to continue reporting stock-based compensation following SFAS No. 123 and Accounting Principles Board Opinion No. 25. SFAS No. 148 also requires certain enhanced disclosures regarding stock-based compensation, and such disclosures have been included in these footnotes to the financial statements. |
| |
|
Reclassifications: Certain amounts for 2001 and 2000 have been reclassified to conform to the 2002 presentation. |
| |
|
NOTE B - PROPERTY AND EQUIPMENT |
| |
|
Property and equipment consists of the following at December 31: |
| |
|
|
|
|
|
|
| |
|
|
2002 |
|
2001 |
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
Oil and gas properties |
|
|
$56,994,583 |
|
$31,277,727 |
|
|
Other property and equipment |
|
|
1,407,171 |
|
707,532 |
|
|
|
|
|
|
|
|
|
Total Property and Equipment |
|
|
58,401,754 |
|
31,985,259 |
|
|
Accumulated depreciation, depletion and amortization |
|
|
(17,585,395 |
) |
(11,230,206 |
) |
|
Reserve for impairment on unproved properties |
|
|
(1,488,492 |
) |
(861,313 |
) |
|
|
|
|
|
|
|
|
Net Property and Equipment |
|
|
$39,327,867 |
|
$19,893,740 |
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
| |
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
THE EXPLORATION COMPANY |
|
Notes to Audited Consolidated Financial Statements |
|
Years Ended December 31, 2002, 2001 and 2000 |
| |
|
NOTE C - LONG-TERM DEBT - continued |
| |
|
Bank Credit Facility: On March 4, 2002 the Company entered into a $25 million oil and gas reserve based Revolving Credit Facility (the Facility) with Hibernia National Bank providing a credit line with an initial borrowing base set at $5 million. The borrowing base was subsequently increased to $13 million as of September 30, 2002, with quarterly reductions of $1 million. At December 31, 2002, the borrowing base was $12 million with an outstanding balance of $5.8 million, resulting in an unused borrowing base of $6.2 million. Interest is payable monthly, with principal due at maturity in March 2005. Uses of proceeds are for the acquisition and development of oil and gas properties and general corporate working capital purposes. The Facility provides the lender with semiannual scheduled redeterminations at mid-year and each subsequent anniversary date. The facility provides for two unscheduled redeterminations per year at the Company's discretion. Borrowin
gs under the Facility are secured by a first priority mortgage covering the Company's working and other interests in the majority of its oil and gas leases. The interest rate under the facility will initially be based on the Wall Street Journal Prime Rate plus applicable margin. A Eurodollar Rate plus applicable margin may be utilized at the election of the Company. The interest rate at December 31, 2002, is 4.25%. The Facility also provides the lender with a commitment fee equal to 0.5% per annum on the unused borrowing base. The Facility contains certain financial covenants and other negative restrictions, which are customary for similar credit facilities. The Company is in compliance with all such covenants and negative restrictions. |
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Subsequent Installment Obligation: In January, 2003, the Company entered into an unsecured installment obligation related to additions to its oil and gas properties. Imputed interest due on the obligation is 4.25% per annum. Payments are due in two installments of $1,406,421 each in January 2004 and 2005. |
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NOTE D - STOCKHOLDERS' EQUITY |
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Preferred Stock: The Company has authorized 10,000,000 shares of preferred stock, none of which has been issued at December 31, 2002. Terms of the stock have not been established by the Board of Directors. |
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Private Placement: In May 2002, the Company closed the sale through a private placement of 2,499,667 shares of restricted common stock at a price of $6.00 per share to a group of 10 institutional investors. The Company raised $14,051,893, net of offering costs of $946,112, to be used for oil and gas property acquisition and development, and for general corporate purposes. Pursuant to the placement agreement, the Company filed a Form S-3 Registration Statement dated June 6, 2002, covering the issued shares on behalf of the investors. |
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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. 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. |
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THE EXPLORATION COMPANY |
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Notes to Audited Consolidated Financial Statements |
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Years Ended December 31, 2002, 2001 and 2000 |
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NOTE D - STOCKHOLDERS' EQUITY-continued |
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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. |
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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, 2002. |
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Stock Repurchase: On June 27, 2001, the Company's Board of Directors approved a common share buyback program to purchase up to $2 million of the Company's common shares in the open market or privately negotiated treasury purchases. The timing and amount of these stock repurchases are determined at the discretion of management. During 2001, the Company purchased 99,800 shares of its common stock at a cost of $246,007 under this program. The Company did not purchase any common stock under this program during 2002. |
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Stock Based Employee Compensation Plan: The Company grants options to its officers, directors, and key employees under its 1995 Flexible Incentive Plan (The "Plan"), as amended. The Plan, as amended, is authorized to grant options to management, directors, and key employees for up to 1,700,000 shares of the Company's common stock. All options granted have ten year terms that vest and become fully exercisable based on the specific terms imposed at the date of grant. |
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Pro forma information included in Note A regarding net income and earnings per share as required by SFAS No. 123 is computed using a Black-Scholes option pricing model. The fair value for these options was estimated at the date of grant with the following weighted-average assumptions as of the year ended December 31: |
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2002 |
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2001 |
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2000 |
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Risk-free interest rate |
3.12% |
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4.40% |
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5.11% |
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Expected dividend yield |
0% |
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0% |
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0% |
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Expected volatility of common stock |
.90 |
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.79 |
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.67 |
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Expected weighted-average life of option |
4 years |
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5 years |
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5 years |
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The Black-Scholes option valuation model was developed for use in estimating the fair value of traded 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. |
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