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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS |
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Certain statements in this report are not historical in nature, including statements of TXCO's and management's expectations, intentions, plans and beliefs, are inherently uncertain and are "forward-looking statements" within the meaning of Section 21E of the Securities Exchange Act of 1934. The following discussion should be read in conjunction with the unaudited consolidated financial statements and notes thereto included in this Form 10-Q, and with the Company's latest audited consolidated financial statements and notes thereto, as reported in its Form 10-K for the year ended December 31, 2003. See "Disclosure Regarding Forward Looking Statements." |
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Overview |
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The Exploration Company is an independent oil and gas enterprise with interests primarily in the Maverick Basin in Southwest Texas. The Company has a consistent record of long-term growth in its proved oil and gas reserves, leasehold acreage position, production and cash flow through its established exploration and development programs. Its business strategy is to build shareholder value by acquiring undeveloped mineral interests and internally developing a multi-year drilling inventory through the use of advanced technologies, such as 3-D seismic and horizontal drilling. The Company accounts for its oil and gas operations under the successful efforts method of accounting and trades its common stock on the Nasdaq Stock MarketSM under the symbol "TXCO." |
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At October 31, 2004, the Company had four rigs in operation on its extensive 554,000-acre position in the Maverick Basin, targeting at least seven separate formations for the production of oil and natural gas. Through the first nine months of 2004, drilling operations emphasized the Georgetown and Glen Rose formations. The 2004 CAPEX budget, revised in May 2004, totals just over $33 million and targets 66 new wells, including 27 Glen Rose wells and 28 Georgetown wells, as well as funding completion of a number of wells in progress at year-end 2003 and infrastructure improvements. The 2004 CAPEX is the second-largest drilling program in the Company's history. |
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TXCO reported net income of $600,000 and $1.0 million for the quarter and nine-month periods ended September 30, 2004, compared to $58,000 and $793,000 for the prior-year periods, respectively. While production remained relatively constant on a thousand cubic feet of gas equivalent (Mcfe) basis, oil and gas revenues were up 30.2% and 13.4% as compared to the third-quarter and nine-month periods of 2003, respectively, due to higher commodity price realizations. The increase in net income for the first nine months of 2004 compared to the 2003 period reflects a $2.5 million increase in oil and gas revenues and $1.8 million in higher margins on gas gathering operations. These revenue increases were offset by an increase of $1.5 million in interest expense from redeemable preferred stock debt and $707,000 higher lease operation expenses due to its growing number of producing wells. These factors are discussed in the Results of Operations section. |
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The following table highlights certain operational data for the periods presented: |
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Third Quarter |
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Nine Month Period |
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Operational Data |
2004 |
2003 |
Change |
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2004 |
2003 |
Change |
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Gas production (Mcf) |
806,895 |
475,331 |
+69.8 |
% |
2,228,471 |
1,522,452 |
+46.4 |
% |
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Oil production (Bbls) |
81,602 |
125,778 |
-35.1 |
% |
228,751 |
347,951 |
-34.3 |
% |
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Combined production (Mcfe) |
1,296,507 |
1,229,999 |
+5.4 |
% |
3,600,977 |
3,610,158 |
-0.3 |
% |
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Net residue and NGL sales (MMbtu) |
752,117 |
639,246 |
+17.7 |
% |
2,737,265 |
1,835,626 |
+49.1 |
% |
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Gas sales price per Mcf |
$5.62 |
$5.32 |
+5.7 |
% |
$5.73 |
$5.70 |
+0.5 |
% |
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Oil sales price per Bbl |
$40.61 |
$27.83 |
+45.9 |
% |
$35.84 |
$28.18 |
+27.2 |
% |
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Residue & NGL sales price per MMbtu |
$6.93 |
$5.11 |
+35.7 |
% |
$6.59 |
$5.22 |
+26.2 |
% |
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Gas - daily exit rate (MMcf) |
9.6 |
6.1 |
+57.4 |
% |
9.6 |
6.1 |
+57.4 |
% |
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Oil - daily exit rate (Bbls) |
1,296 |
1,299 |
-0.2 |
% |
1,296 |
1,299 |
-0.2 |
% |
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Combined daily exit rate (MMcfe) |
17.4 |
13.9 |
+25.2 |
% |
17.4 |
13.9 |
+25.2 |
% |
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10
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On October 1, 2004, the Company entered into financial price hedges with Macquarie Bank Ltd. for 15,000 barrels of oil (BO) and 140,000 million British thermal units (MMBtu) of gas, each on a monthly basis for the next 12 months. These hedges are in the form of ratio swaps (the Swaps) and provide floor prices of $39.10 per BO and $5.37 per MMBtu on a basis adjusted to Houston Ship Channel prices for approximately 40% of its then current production levels. The Swaps also allow the Company to participate in 75% of potential upside price movement above the floor levels. For more information see the Form 8-K filed with the Securities and Exchange Commission on October 6, 2004. |
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Liquidity and Capital Resources |
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Liquidity is a measure of ability to access cash. The Company's primary needs for cash are for acquisitions, exploration and development of oil and gas properties, repayment of contractual obligations and working capital requirements. TXCO has historically addressed its long-term liquidity requirements through cash provided by operating activities, issuance of equity securities when market conditions permit, and sale of non-strategic assets. More recently, TXCO has used borrowings under its Credit Facility and cash proceeds from the issuance of its stock to supplement its historical sources of liquidity. The prices for future oil and natural gas production and the level of production have significant impacts on operating cash flows and are difficult to predict with a high degree of certainty. Management continues to examine alternative sources of long-term capital, including bank borrowings, issuance of debt instruments, issuance of stock, sales of non-strategic assets, and j
oint-venture financing. Availability of these sources of capital and, therefore, TXCO's ability to execute its operating strategy will depend upon a number of factors, some of which are beyond its control. Management believes projected operating cash flows, cash on hand, and borrowings under the Credit Facility, will be sufficient to meet the requirements of TXCO's business. However, because future cash flows are subject to a number of variables, no assurances can be made that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures. Conversely, with increased levels of production and prices, capital expenditures could be raised over levels currently budgeted. |
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Private Placement: In May 2004, TXCO closed on a private placement of 4,266,668 shares of its common stock at a purchase price of $3.75 per share for net proceeds of $15.0 million. Included are warrants for an additional 1,280,000 common shares exercisable at $4.25 per share. The warrants become exercisable in November 2004 and expire in May 2008. Purchasers were primarily private, U.S.-based investment funds. Proceeds from the private placement were used to expand the Company's capital expenditure program, restore balance sheet liquidity, complement on-going operations and provide for general corporate purposes. |
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Bank Credit Facility: The Company has a $50 million senior secured revolving credit facility with Guaranty Bank (Facility), which has a three-year term expiring in 2007. |
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The credit facility is collateralized by all of the Company's proven oil and gas properties, with the borrowing base established on current levels of TXCO's oil and gas reserves, and features biannual redeterminations. Interest under the Facility is based on, at TXCO's option, (a) the London Interbank Offered Rate (LIBOR) plus an applicable margin ranging from 2.00% to 2.50% or (b) prime plus an applicable margin ranging from 0.00% to 0.25% (floating rate). The borrowing base was $12,300,000 at September 30, 2004, and was increased to $20,750,000 in October. At September 30, 2004, the Company had outstanding $8.6 million with a weighted average interest rate of 4.22%. |
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On October 1, 2004, TXCO entered into financial price hedges for a portion of its production in compliance with provisions of the Facility requiring hedging when borrowings exceed 50% of the borrowing base. The next semi-annual borrowing base review is currently scheduled for February 2005. At October 31, 2004, total borrowings under this agreement were $10.6 million, up $2.0 million from the quarter end balance of $8.6 million, with an unused borrowing base of $10.2 million available for future capital needs. |
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11
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The Facility contains additional terms and conditions consistent with similarly positioned companies. These conditions include various restrictive covenants such as minimum levels of interest coverage, tangible net worth and current ratio, a maximum debt to EBITDAX ratio, restricting the payment of dividends other than the dividends payable under the redeemable preferred stock, and prohibiting a change of control or incurring additional debt. EBITDAX is defined as earnings before income taxes, interest, depreciation, depletion, amortization, impairment, abandonment and exploration expense. The ratios used for determining compliance with the Facility are defined within that Facility and may not be equivalent to other uses of those terms. At September 30, 2004, the Company was not in technical compliance with the Current Ratio covenant, as the borrowing base redetermination was expected during the month of September. This timing issue was resolved by the increased borrowing b
ase in October and a one-time waiver that was received from Guaranty Bank. |
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Management believes 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 operating cash requirements and complete its scheduled exploration and development goals for 2004. TXCO expects to further increase its borrowing base commensurate with the expected growth of its proved oil and gas reserves throughout the base term of the Facility. |
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Subsequent Events: In connection with the Swaps discussed in the Overview section, the Company entered into a one-year Letter of Credit Agreement (L/C) with Guaranty Bank. This agreement provided for the issuance of a Standby Letter of Credit representing a Hedge Commodity Agreement or Rate Management Transaction issued outside of the original borrowing base as stated in the Facility dated June 30, 2004. The agreement requires the payment of an administrative fee ranging from 2.0% to 2.5% per annum of the face amount of the L/C. The initial L/C amount was set at $1 million and subsequently increased to $2 million. No drafts or advances have been made against these L/C's through October 31, 2004. |
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In late October, TXCO entered into an agreement effective on September 1, 2004, to purchase a 6.1-mile portion of an existing, privately owned pipeline to serve the northwest portion of TXCO's lease block at a net price of $207,000. This purchase, and an associated five-year lease on an additional 1.7-mile segment of existing pipeline effective on November 1, 2004, expands our pipeline infrastructure to bring new Burr lease gas production to the market. |
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Sources and Uses of Cash: During the first nine months of 2004, TXCO increased cash reserves from $6.2 million at December 31, 2003, through cash provided by operating activities of $15.4 million. In addition, proceeds from a private placement of common stock, approximately $15.0 million net of expenses, along with net proceeds totaling $3.5 million from the exercise of warrants (purchasing 1,238,096 shares of common stock), resulted in total cash available of $40.1 million for use in meeting the Company's ongoing operational and development needs. |
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During the first quarter of 2004, TXCO used portions of the available cash to fund payments on debt totaling $2.5 million and related interest of $784,000. The Company applied $6.1 million to fund the ongoing development of its oil and gas producing properties. |
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During the second quarter, payments on debt totaled $7.0 million with $956,000 of related interest. This reflects a $6.8 million payment on bank debt made out of the proceeds from the private placement of common stock and warrants in May. In addition, approximately $6.9 million was invested in drilling activities during this period. |
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During the third quarter, net borrowings on debt totaled $2.4 million and payments for related interest were $609,000. Additionally, during this period, approximately $14.9 million was invested in drilling activities. |
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12
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As a result of the increased drilling in the third quarter, the Company ended the period with negative working capital of $8.0 million, compared to negative $2.3 million at December 31, 2003, while its current ratio declined to 0.63 to 1 compared to 0.83 to 1 at year end. The Company exited the third quarter with an unused borrowing base of $3.7 million available under its new credit facility. After the October increase in borrowing base, and a $2.0 million draw in mid-October, the unused portion is now $10.2 million. Ending working capital was impacted by increases in current liabilities, partially offset by higher accounts receivable and prepaid account balances. Cash flow from operating activities for the first nine months of 2004 increased to $15.4 million from $11.3 million in the comparative prior-year period, reflecting the impact of the working capital changes, higher non-cash expenses and increased net income. Adjusting for
changes in operating assets and liabilities, cash flow from operating activities for the first nine months of 2004 was $10.9 million in 2004 compared to $9.3 million for the first nine months of 2003, a 17.7% increase over the same period a year ago. Changes in operating assets include increases or decreases in accounts receivable, accounts payable and prepaid expenses from the prior year-ends. |
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Results of Operations |
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The following table highlights the change from comparable periods in 2003: |
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Third Quarter |
Nine Month Period |
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Change in Selected Income Statement Items |
$thousands |
% |
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$thousands |
% |
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Oil and gas revenues |
+1,819 |
+30.2 |
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+2,474 |
+13.4 |
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Lease operations |
+84 |
+7.2 |
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+707 |
+22.0 |
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Impairment & abandonments |
-62 |
-9.6 |
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+96 |
+6.3 |
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Depreciation, depletion & amortization (DD&A) |
+348 |
+15.7 |
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+626 |
+9.3 |
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Income from operations |
+892 |
+204.0 |
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+1,760 |
+115.7 |
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Net income |
+541 |
+925.9 |
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+248 |
+31.3 |
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The increases in oil and gas revenues for both 2004 periods presented as compared to the same periods of 2003 are attributable to higher gas production along with higher oil and natural gas prices, partially offset by a decline in oil production. Gas sales volumes increased 69.8% and 46.4% for the third quarter and first nine months of 2004, respectively, primarily due to Georgetown and Glen Rose shoal wells put on production since September 30, 2003. This increase was offset by lower oil production, primarily related to fewer wells drilled with our operating partner on the Comanche lease, compared to the same 2003 periods. Production gains of 5.4% on a Mcfe basis in the 2004 third quarter, over the same 2003 period, offset lower operating levels in the first half of 2004 resulting in essentially flat overall production levels for the nine month periods. While average gas sales prices are up 5.7% for the third quarter of 2004 over 2003, year-to-date averages are flat
with those for the first nine months of 2003 due to lower prices in the first quarter of 2004. |
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The increase in lease operating expenses for the first nine months of 2004 over the prior period primarily reflects costs related to 48 additional Maverick Basin oil and gas wells placed on production since September 30, 2003. Lease operation expenses were impacted by approximately $94,000 in non-recurring charges for repairs related to severe weather and flooding on the southern portion of our lease block in the first half of 2004. |
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The Company's gas gathering system transports its production to various markets. It also transports production for other owners at a set rate per MMbtu. It sells gas at several points along the system with a significant portion being delivered to purchasers through the Enterprise/Gulf Terra Pipeline System (Enterprise). Enterprise processes gas delivered through it to remove natural gas liquids, which it markets separately. The Company receives a share of the revenues for these liquids. Natural gas pricing fluctuations are reflected at the wellhead for the Company's operated gas properties. |
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During the third quarter and first nine months of 2004, gas gathering operations revenues increased 121.9% and 106.2%, respectively, due to higher sales volumes and prices for both residue gas and natural gas liquids, when compared to the same periods of 2003. The increase is consistent with the increased number of gas wells connected to the gathering system compared to the prior period. |
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13
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The following table summarizes the change from comparable periods in 2003: |
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Third Quarter |
Nine Month Period |
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Change in Gas Gathering Results: |
$thousands |
% |
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$thousands |
% |
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Revenues: |
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Third-party natural gas sales |
+2,779 |
+106.2 |
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+7,786 |
+99.8 |
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Natural gas liquids sales |
+1,322 |
+204.0 |
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+2,705 |
+151.6 |
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Transportation and other revenue |
-1 |
-0.6 |
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-15 |
-5.4 |
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Total gas gathering revenues |
+4,100 |
+121.9 |
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+10,476 |
+106.2 |
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Expense : |
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Third-party gas purchases |
+3,598 |
+118.3 |
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+8,333 |
+87.1 |
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Transportation and marketing expenses |
+61 |
+63.3 |
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+146 |
+55.1 |
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Direct operating costs |
+62 |
+35.9 |
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+162 |
+33.2 |
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Total gas gathering operations expense |
+3,721 |
+112.4 |
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+8,641 |
+83.7 |
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Gross margin |
+379 |
+689.1 |
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+1,835 |
+398.9 |
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Operational data |
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Total sales volumes (MMbtu) |
+112,871 |
+17.7 |
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+901,639 |
+2.1 |
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Average sales price (per MMbtu) |
+$1.82 |
+35.7 |
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+$1.37 |
+26.2 |
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The increases in DD&A for the three and nine month periods of 2004 over the comparable prior-year periods resulted primarily from higher depletion, up $318,000 and $525,000, respectively, consistent with the growing number of producing wells subject to depletion and with increased depletion rates due to the maturing profile of existing producing wells. |
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In the third quarter of 2004, the Company recorded $237,000 in non-cash compensation charges relating to the one-year extensions on the expiration date for a non-qualified option and warrant. Excluding this compensation charge, General and administrative expense (G&A) would have been $3.2 million representing 7.8% of revenues for the nine months ended September 20, 2004, and up 23% from $2.6 million for the same period in 2003. Including the charge, G&A increased 32.1% over the prior year period and represented 8.4% of total revenues. G&A for the same period in 2003 was 9.2% of revenues. Other increases in G&A included higher compensation related expense for two additional employees hired since September 30, 2003, with their associated salaries, wages, benefits and office-related expenses, and a full-year of expense related to staff additions during 2003. Staffing at September 30, 2004, was 47, as compared with 44 at September 30, 2003, and 35 at December
31, 2002. In addition, increased activity levels resulted in higher costs for independent engineer's services, franchise taxes and investor communications. Higher costs for information systems reflect a full nine months of the new systems implemented during 2003. Partially offsetting these higher costs were lower consulting costs, down $59,000, primarily due to bringing in-house certain functions previously performed by consultants. The majority of the increases in general and administrative costs are consistent with the expanded compliance burden mandated by the Sarbanes-Oxley Act (SOA). For the first nine months of 2004, management estimates its total costs associated with SOA compliance to be approximately $131,000 including consulting, software and internal payroll-related costs. Management also anticipates these costs to increase in the final quarter of 2004 in conjunction with continuing costs for SOA section 404 compliance. |
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Interest expense for the first nine months of 2004 increased by $1,470,000 over the same period of 2003 primarily due to the issuance of $16 million in redeemable preferred stock debt in August 2003. Of this, $592,000 reflects non-cash charges for accretion of the debt to its full redemption value by August of 2009 and amortization of related issue costs. For the third quarter of 2004, interest on the preferred was $597,000, of which $136,000 represented non-cash charges. The income tax expense recorded in the first nine months of 2004 reflects corporate alternative minimum taxes expected to be incurred for 2004. |
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14
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Drilling Activities |
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Activity increased in the third quarter of 2004 with 23 wells spudded, up from 17 and 11 in the second and first quarters, respectively. The Company drilled or participated in drilling 51 new wells on its lease block in the Maverick Basin in the first nine months of 2004. At September 30, 2004, 32 of these wells were producing, 13 wells were in completion, two wells were awaiting pipeline connection, two wells remained drilling and two wells were shut in pending further evaluation. By comparison, the Company drilled 60 wells during the first nine months of 2003. TXCO also participated in one new well and two re-entries on its Williston Basin acreage, all of which are producing oil. |
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The Company had as many as seven rigs drilling on our Maverick Basin leases during the third quarter of 2004. There were as few as two rigs running during portions of the first half of 2004. A combination of poor weather and corporate restructuring by one of our operating partners reduced drilling activity during the first six months of this year. TXCO also saw an increase in wells put on production in the third quarter, with 20 wells coming on production compared with 14 during the first half of 2004 including one reentry in each period. During October 2004, TXCO drilled or participated in six new wells. |
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The Company exited the third quarter of 2004 with total net daily production of 1,296 barrels of oil per day (BOPD) and 9.6 million cubic feet per day (MMcfd) of natural gas, a combined 17.4 million cubic feet equivalent per day (MMcfed). Six completed wells were curtailed or waiting on pipeline connections at September 30, 2004, that could have added additional production. At October 31, 2004, total net daily production increased to 19.9 MMcfed as wells completed in the third quarter were placed on production. The comparable daily production rates at year-end 2003 were 1,200 BOPD and 8.9 MMcfd, equal to 2,674 BOE or 16.0 MMcfed. |
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Glen Rose - Through September 30, TXCO has spudded 17 Glen Rose wells, with 10 producing, one awaiting a pipeline connection, and three awaiting completion. The wells spudded include nine targeting shoals, seven targeting reefs and one targeting the porosity zone. All of the shoal wells, and the porosity well, were producing at October 31, 2004. For the reef wells at October 31, 2004, two were producing, two await completion, and three had been recompleted to and were producing from the Georgetown formation. Net Glen Rose production at September 30, 2004, was 427 BOPD and 5.4 MMcfd. At October 31, net Glen Rose production had risen to 629 BOPD and 6.0 MMcfd. |
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In the Glen Rose porosity play, a second well, the Comanche 2-14H (50% WI), was drilled and went on production in late October, flowing approximately 500 BOPD and no water. Meanwhile, the Comanche 2-39H (50% WI) continued to flow 370 BOPD in late October and has produced water-free oil since it began production in August. Both wells were drilled using a new technique in which the horizontal wellbore parallels fractures within the formation, minimizing water intrusion from a separate, lower zone. |
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In the Glen Rose reef play, TXCO placed the Burr C 1-56 (100% WI) on production in late October flowing 1.2 MMcfd. Weather and pipeline construction delays postponed the start of production since the well's completion in the third quarter. Meanwhile, three wells originally targeting Glen Rose reefs, which proved wet, have been successfully completed as horizontal Georgetown wells. In the Glen Rose shoal play, the Chittim 1-131H, (52% WI) went on production in late October at 825 Mcfd. One additional Glen Rose shoal well was spudded in late October. |
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Georgetown - The Company spudded six new Georgetown wells in the third quarter, bringing total wells spudded to 20 of the 28 new Georgetown wells planned for this year in addition to the three Georgetown completions originally targeting Glen Rose reefs. Three additional Georgetown wells were spudded in October 2004, with two awaiting completion and one drilling at month end. Net Georgetown production at September 30, 2004, was 3.7 MMcfd and 319 BOPD, and at October 31, 2004 was 5.1 MMcfd and 254 BOPD. |
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15
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Fifteen Georgetown wells were drilled on the southern portion of TXCO's acreage block in the first nine months of 2004, including five spudded in the third quarter. Of these, through October 31, 2004, nine have been placed on production, five are in progress or awaiting completion while one had a mechanical failure. The Comanche W 1-2H (50% WI) flow tested from the Georgetown formation at rates as high as 1.4 MMcfd and 15 BOPD. The well went on production in late October at 1.0 MMcfd. On tests in early November, the Gary 1H well flowed at 240 BOPD and 611 Mcfd. |
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On the northern portion of the Company's acreage block, five Georgetown wells were drilled through September 30, 2004, including one spudded in the third quarter. Three additional wells were spudded in October. Of these eight wells, one is producing, two await completion, and one is drilling while four are shut in pending further evaluation as of October 31, 2004. The Burr A 1-16H tested at a rate of 384 BOPD in early November. |
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As to the three former Glen Rose reef wells, the Burr C 1-231.5H (100% WI) tested at 1.5 MMcfd and was placed on production in October flowing 860 thousand cubic feet per day (Mcfd). The Burr C 1-53H, (100% WI) went on production in early October pumping 157 BOPD. The Burr C 1-60 (100% WI) was placed on production in October at 117 BOPD. |
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San Miguel Waterflood - TXCO spudded 13 San Miguel oil wells this year, including 10 budgeted for its Pena Creek project (100% WI). At September 30, 2004, all 10 Pena Creek wells were on production. San Miguel oil production at September 30, 2004, was 371 BOPD. In the third quarter of 2004, TXCO spudded two wells to begin testing a new San Miguel sand on the west end of the Comanche Ranch. One additional San Miguel well was spudded in mid-October and was awaiting completion at month end. San Miguel production at October 31, 2004, included 344 BOPD and 146 Mcfd. This is a temporary decline in production due to construction of a new tank battery on the northern portion of the Pena Creek lease. |
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To date, 11 water injection well workovers have been completed as part of a program to enhance water injection efficiency and increase oil output in the Pena Creek Unit. |
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Pearsall - The Taylor 132-1 (97.5% WI) is producing gas through temporary production facilities from Pearsall perforations following fracture stimulation. This lower Cretaceous interval lies below the Glen Rose formation and above 7,500 feet. The well was producing approximately 200 Mcfe at October 31. Further testing continues. |
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Jurassic - Blue Star Oil and Gas, Ltd., Dallas, the Company's operating partner in the Jurassic play, has reaffirmed plans to drill a second Jurassic wildcat in the Maverick Basin utilizing formation data gained from the Taylor wildcat to select a location. TXCO's 2004 drilling budget currently includes no provision for a second Jurassic well as Blue Star would pay 100 percent of drilling costs while carrying TXCO for a 25 percent working interest if a second well is drilled on TXCO's lease block. |
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Coalbed Methane - The Company's horizontal re-entry attempts on two existing coalbed methane (CBM) dewatering wells (100% WI), using new multiple short-radius lateral (MSRL) technology, were delayed by mechanical difficulties. Design engineers are working to refine the MSRL tool design. If successful, the MSRL technique could significantly increase dewatering volumes and associated CBM gas production going forward. |
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TXCO exited 2003 with 36 wells dewatering in its CBM pilot program targeting production from the multiple seams of high-volatile bituminous coal present under its leases. At September 30, 2004, the net CBM production rate was approximately 120 Mcfd with 1,389 barrels of water per day after being shut down for some time due to flooding and related electricity interruptions. The Company believes 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 may seek an industry partner or project-type financing, which it believes is more suitable for this project due to its cash flow profile, as well as complementing the Company's existing capital structure. The Company may sell an interest in the CBM project to an industry partner with CBM expertise. To date, several potential industry partners have expressed an interest in TXCO's project. There are no new CBM wells i
ncluded in the 2004 CAPEX budget. The Company continues to believe this project will add significant reserves in the coming years. |
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Red River B Zone - The Company participated in the drilling of one new well (0.58% WI) and two re-entries (30.0% and 0.58% WI), all horizontal laterals, in the Williston Basin with its operating partner Luff Exploration Company. All three wells are currently producing oil. Net Williston Basin production at September 30, 2004, was 150 BOPD and 154 Mcfd. |
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Disclosure Regarding Forward Looking Statements |
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Statements in this Quarterly Report on Form 10-Q which are not historical, including statements regarding TXCO's or management's intentions, hopes, beliefs, expectations, representations, projections, estimations, plans or predictions of the future, are forward-looking statements and are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Such statements include those relating to expected drilling plans, including timing, category, number, depth, cost and/or success of wells to be drilled, expected geological formations or the availability of specific services or technologies. It is important to note that actual results may differ materially from the results predicted in any such forward-looking statements. Investors are cautioned that all forward-looking statements involve risks and uncertainty, including without limitation, the costs of exploring and developing new oil and natural gas reserves, the price for which such rese
rves can be sold, environmental concerns affecting the drilling of oil and natural gas wells, as well as general market conditions, competition and pricing. Please refer to TXCO's Securities and Exchange Commission filings for additional information. This and all TXCO's previously filed documents are on file at the Securities and Exchange Commission and can be viewed on TXCO's website at www.txco.com. Copies of which are available from the Company without charge. |
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. |
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There have been no material changes in the reported market risks faced by the Company since December 31, 2003. See the Company's Annual Report on Form 10-K, "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" |
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ITEM 4. CONTROLS AND PROCEDURES. |
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a. 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 as of September 30, 2004. Based upon that evaluation, the Company's Chief Executive Officer along with the Chief Financial Officer concluded that the 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 our periodic SEC filings. |
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b. 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. |
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PART II - OTHER INFORMATION |
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ITEM 1. LEGAL PROCEEDINGS |
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None |
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ITEM 2. CHANGES IN SECURITIES |
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None |
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ITEM 3. DEFAULTS UPON SENIOR SECURITIES |
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None |
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ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS |
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None |
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ITEM 5. OTHER INFORMATION |
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None |
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ITEM 6. EXHIBITS |
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a) Exhibit 10.1 Energy Option Transaction Confirmation dated October 5, 2004, between the registrant and Macquarie Bank Limited - OBU. |
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b) Exhibit 10.2 Letter of Credit Agreement dated October 7, 2004, between the registrant and Guaranty Bank. |
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c) Exhibit 31.1 Certification of Chief Executive Officer required pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended filed herewith. |
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d) Exhibit 31.2 Certification of Chief Financial Officer required pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended filed herewith. |
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e) Exhibit 32.1 Certification of Chief Executive Officer required pursuant to 18 U.S.C. Section 1350 as required by the Sarbanes-Oxley Act of 2002 filed herewith. |
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f) Exhibit 32.2 Certification of Chief Financial Officer required pursuant to 18 U.S.C. Section 1350 as required by the Sarbanes-Oxley Act of 2002 filed herewith. |
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SIGNATURES |
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Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. |
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THE EXPLORATION COMPANY |
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(Registrant) |
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/s/ P. Mark Stark |
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P. Mark Stark, |
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Chief Financial Officer |
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Date: November 9, 2004 |
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