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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 exploration, development and acquisitions 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 cannot be predicted with any 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 joint-ve
nture 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 private, U.S.-based investment funds. Proceeds from the private placement will be 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: On June 30, 2004, the Company closed on a $50 million senior secured revolving credit facility with Guaranty Bank (the "Facility" or "credit facility"). The new facility has a three-year term expiring in 2007. It replaces TXCO's prior $25 million credit facility with Hibernia National Bank, scheduled to mature in 2006. |
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The credit facility is collateralized by all of the Company's proven oil and gas properties, with an initial borrowing base of $12.3 million, based on current levels of TXCO's oil and gas reserves, and features bi-annual redeterminations. The borrowing base may be increased to $14.6 million if TXCO chooses to hedge 50% of its production. If borrowing under the agreement exceeds 50% of the borrowing base, the Company will be required to hedge 50% of its production. At closing, approximately $6.1 million was advanced under the new credit facility to repay the outstanding balance of the prior facility. Interest under the new facility will be as much as 0.25 percentage point less than the former credit agreement, 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%. At June 30, 2004, the effective interest rate was 4.25%. During early
July the Company took advantage of its LIBOR options for $6 million of its outstanding loan amount. |
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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. |
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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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11
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Sources and Uses of Cash: During the first half of 2004, TXCO increased cash reserves from $6.2 million at December 31, 2003, through cash provided by operating activities of $5.2 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 $29.9 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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As a result of these activities, the Company ended the second quarter of 2004 with positive working capital of $348,000, compared to negative working capital of $2.3 million at December 31, 2003, while its current ratio improved to 1.02 to 1 compared to 0.83 to 1 at year end. The Company exited the second quarter with an unused borrowing base of $6.2 million available under its new credit facility. Its ending working capital was impacted by higher cash and accounts receivable balances, partially offset by an increase in current liabilities. Cash flow from operating activities for the first half of 2004 decreased to $5.2 million from $11.3 million in the comparative prior-year period, reflecting the impact of the working capital changes. Adjusting for changes in operating assets and liabilities, first-half 2004 cash flow from operating activities was $6.7 million in 2004 compared to $6.1 million for the first half of 2003, a 9.8% increase over the same period a year ago. Cha
nges 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: |
| |
|
Change in Selected Items: |
Second Quarter |
First Half |
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
Income Statement items: |
|
|
|
|
|
|
|
|
|
Oil and gas revenues |
+382,226 |
+5.8 |
% |
+$654,691 |
+5.3 |
% |
|
|
|
Lease operations |
+450,274 |
+46.0 |
% |
+623,311 |
+30.4 |
% |
|
|
|
Impairment & abandonments |
-20,175 |
-3.8 |
% |
+157,650 |
+18.0 |
% |
|
|
|
Depreciation, depletion & amortization |
-384,005 |
-13.6 |
% |
+277,972 |
+6.2 |
% |
|
|
|
Income from operations |
+944,586 |
+474.6 |
% |
+867,315 |
+80.1 |
% |
|
|
|
Net income |
+362,721 |
+3,783.1 |
% |
-292,897 |
-39.9 |
% |
|
|
| |
|
|
|
|
|
|
|
|
|
Operational data |
|
|
|
|
|
|
|
|
|
Gas production (Mcf) |
+287,132 |
+57.9 |
% |
+374,463 |
+35.8 |
% |
|
|
|
Oil production (Bbls) |
-75,466 |
-53.5 |
% |
-75,022 |
-33.8 |
% |
|
|
|
Combined production (Mcfe) |
-165,664 |
-12.3 |
% |
-75,669 |
-3.2 |
% |
|
|
|
Gas sales price per Mcf |
+$0.29 |
+5.1 |
% |
-$0.09 |
-1.5 |
% |
|
|
|
Oil sales price per Bbl |
+$8.09 |
+30.4 |
% |
+$4.82 |
+17.0 |
% |
|
|
| |
|
Oil and gas revenues increased 5.8% and 5.3%, respectively, for the second quarter and first half of 2004, over the comparable prior-year periods. These increases are attributable to increased natural gas production volumes and higher oil and natural gas prices, partially offset by a decline in oil production. Gas sales volumes increased 57.9% and 35.8%, respectively, for the second quarter and first half of 2004, respectively, primarily due to Georgetown and Glen Rose shoal wells put on production since June 30, 2003. This increase was offset by lower oil production, primarily related to a decline in the number of oil wells drilled by an operating partner, compared to the same 2003 periods. The lower operating levels in the first half contributed to a 3.2% decline in overall |
| |
| |
| |
|
12
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|
production levels from the first half of 2003. While average gas sales prices increased during the second quarter of 2004 and exceeded the comparable 2003 levels, year-to-date averages remain lower than those for the first half 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 half of 2004 over the prior period primarily reflects costs related to 44 additional Maverick Basin oil and gas wells placed on production since June 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 is generally operated on a break-even basis. It sells gas at several points along the system with a significant portion being delivered to purchasers through the El Paso/Gulf Terra Pipeline System ("El Paso"). El Paso 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 second quarter and first half of 2004, gas gathering operations revenues increased 132.9% and 98.1%, 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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|
The following table summarizes the change from comparable periods in 2003: |
| |
|
Change in Gas Gathering Results: |
Second Quarter |
First Half |
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
Third-party natural gas sales |
+$3,445,000 |
+129.7 |
% |
+$5,006,000 |
+96.6 |
% |
|
|
|
Natural gas liquids sales |
+939,000 |
+167.9 |
% |
+1,383,000 |
+121.8 |
% |
|
|
|
Transportation and other revenue |
-9,000 |
-10.8 |
% |
-13,000 |
-7.7 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
Total gas gathering revenues |
+4,375,000 |
+132.9 |
% |
+6,376,000 |
+98.1 |
% |
|
|
| |
|
|
|
|
|
|
|
|
|
Expense : |
|
|
|
|
|
|
|
|
|
Third-party gas purchases |
+3,491,000 |
+110.0 |
% |
+4,734,000 |
+72.5 |
% |
|
|
|
Transportation and marketing expenses |
+78,000 |
+86.4 |
% |
+85,000 |
+50.5 |
% |
|
|
|
Direct operating costs |
+54,000 |
+35.3 |
% |
+101,000 |
+31.8 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
Total gas gathering operations expense |
+3,623,000 |
106.0 |
% |
+4,920,000 |
+70.1 |
% |
|
|
| |
|
|
|
|
|
|
|
|
|
Gross margin |
+752,000 |
+597.2 |
% |
+1,456,000 |
+282.8 |
% |
|
|
| |
|
|
|
|
|
|
|
|
|
Operational data |
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
Total sales volumes (MMbtu) |
+534,308 |
+87.0 |
% |
+788,768 |
+65.9 |
% |
|
|
|
Average sales price (per MMbtu) |
+$1.38 |
+26.4 |
% |
+$1.12 |
+21.2 |
% |
|
|
| |
|
Depreciation, depletion and amortization (DD&A) increased 6.2% for the first six months of 2004 over the comparable prior-year period. The increase was primarily in higher depletion, up $207,000, 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. DD&A for the second quarter of 2004 decreased 13.6% from the prior-year quarter, reflecting higher depletion recorded in 2003's second quarter due to an increase in production levels during that time period. |
| |
|
General and administrative expense increased 24.6% for the first half of 2004 as compared to the same period in 2003, while declining slightly as a percentage of total revenues (7.8% in 2004 vs. 8.6% in 2003). The increase in expense was primarily due to five additional employees hired across the organization since June 30, 2003, with their associated salaries, wages, benefits and office-related expenses. Staffing at June 30, 2004, was 46, as compared with 41 at mid-year 2003. In addition, higher costs were incurred for information systems, independent engineers services, franchise taxes and increased investor communications activities. Partially offsetting these higher costs were lower consulting costs, down $63,000, primarily due to bringing in-house |
| |
| |
|
13
|
|
certain functions that were 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 half of 2004, management estimates its total direct costs associated with SOA compliance to be approximately $60,000. Management also anticipates these costs to increase in the final two quarters of 2004 in conjunction with consulting costs incurred for SOA section 404 compliance. |
| |
|
Interest expense for the first half of 2004 increased by $1,245,000 over the same period of 2003 primarily due to the issuance of $16 million in redeemable preferred stock debt in August 2003. Of this, $446,000 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 second quarter of 2004, interest on the preferred was $588,000, of which $228,000 represented non-cash charges. The income tax expense recorded in the first half of 2004 reflects corporate alternative minimum taxes expected to be incurred for 2004. |
| |
|
Drilling Activities |
| |
|
The Company drilled or participated in drilling 28 new wells on its lease block in the Maverick Basin in the first half of 2004. At June 30, 2004, 14 of these wells were producing, seven wells were in completion, two wells were awaiting pipeline connection, four wells remained drilling and one well was shut in pending further evaluation. By comparison, the Company drilled 42 wells during first half of 2003. The Company exited the second quarter of 2004 with total net daily production of 837 barrels of oil per day (BOPD) and 10.1 million cubic feet per day (MMcfd) of natural gas, equal to 2,522 BOE or 15.1 MMcfe. The comparable daily production rates at year-end 2003 were 1,200 BOPD and 8.9 MMcfd, equal to 2,674 BOE or 16,041 MMcfe. TXCO also participated in one new well, which is awaiting completion, and two re-entries on its Williston Basin acreage. |
| |
|
The Company expects drilling activity to increase substantially in the third quarter of 2004 with seven rigs currently drilling on our Maverick Basin leases. 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. During July 2004, TXCO drilled or participated in seven new wells. The Company projects a total of 65 new wells and four re-entries on its Maverick Basin lease block for 2004. At July 31, 2004, total net daily production was 18.0 MMcfe. |
| |
|
Georgetown - The Company's success continues with its Georgetown horizontal drilling program through the application of improved seismic processing techniques. The 28 wells targeting the Georgetown represents the largest share of TXCO's drilling program for 2004. The Company spudded six new Georgetown wells in the second quarter in addition to two re-entries, bringing total wells spudded to 14 of the 28 Georgetown wells now projected for this year. Two additional Georgetown horizontal wells were spudded in July 2004. |
| |
|
TXCO placed nine Georgetown horizontal gas wells on production in the first half of 2004, including two spudded in December 2003. At June 30, 2004, two additional Georgetown horizontal gas wells awaited pipeline connections, one was pending completion, two were shut-in for further evaluation and two remained drilling. Net Georgetown production at June 30, 2004, was 4.2 MMcfd and 117 BOPD. In July, one well drilling at quarter end flow tested at rates as high as 3.3 MMcfd, while a re-entry well flow tested at rates as high as 456 BOPD. Georgetown gas wells typically have hyperbolic production profiles with high initial flow rates that provide a quick payout potential, followed by a comparatively sharp decline, then longer-term production at lower rates. Net Georgetown production at July 31, 2004 was 4.4 MMcfd and 251 BOPD. |
| |
|
Glen Rose Shoal - Through June 30, TXCO has spudded seven Glen Rose shoal wells, with five producing, one awaiting completion and one currently drilling. Production began in mid-July from the Chittim 3-130H, 49.9% working interest (WI). In tests, the well flowed at rates as high as 1.7 MMcfd (gross) from the Glen Rose C shoal. Completion has begun on the Chittim 3-142H (38.1% WI). In tests, this well flowed as much as 1.05 MMcfd and 2 BOPD (gross). An eighth Glen Rose shoal well was spudded in July. Net Glen Rose shoal production at June 30, 2004, was 4.1 MMcfd and 12 BOPD, and at July 31 it was 4.5 MMcfd and 17 BOPD. |
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| |
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|
14
|
|
Glen Rose Reefs - To date, four new reef wells have been spudded, including three in the expanded 15-well Glen Rose reef drilling program on the Burr/Wipff prospect (100% WI) announced in May. Initial drilling had been delayed by a lack of rig availability and inclement weather. The 15 reefs were identified using new 3-D seismic data and are on trend with similarly situated gas-producing Glen Rose reefs on TXCO's lease block nearby. |
| |
|
Meanwhile, the Paloma E 1-54 (62.4% WI), went on production in mid July at 721 Mcfd and 10 BOPD. In initial tests, the well flowed at rates as high as 1.6 MMcfd and 5 BOPD (gross). Net Glen Rose reef production at June 30 was 1.4 MMcfd and 13 BOPD. At July 31, net Glen Rose reef production was 1.6 MMcfd and 53 BOPD. |
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|
Glen Rose Oil - TXCO (50% WI) and its operating partner, CMR Energy L.P., Houston, spudded the first new Glen Rose oil porosity well of 2004 in mid July, the Comanche 2-39H. Petrohawk Energy Corp. (Nasdaq:HAWK), Houston, is acting operator under contract to CMR. The vertical well may be converted to a horizontal completion depending on test results. Third-quarter plans include re-entering two existing vertical Glen Rose porosity wells for horizontal re-completions as a workover rig becomes available. |
| |
|
CMR's recent corporate restructuring has delayed 2004 Glen Rose drilling activity to date. By comparison, six Glen Rose porosity wells were drilled during the first half of 2003 while none were drilled in the first half of 2004. Glen Rose oil production has continued to decline since the last porosity well was spudded in September 2003. TXCO's budget now calls for four new Glen Rose porosity wells and four re-entries prior to the end of 2004. Net Glen Rose porosity production at June 30, 2004 was 252 BOPD. At July 31, net Glen Rose porosity production had risen to 307 BOPD. |
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|
San Miguel Waterflood - TXCO spudded five San Miguel oil wells on its Pena Creek unit (100% WI) in the second quarter. At June 30, 2004, two were on production while three were in completion. These three wells were put on production in July. Four additional wells have been spudded thus far in the third quarter with one currently on production, two in completion and one still drilling. To date, 11 water injection well workovers have been completed as part of a program to enhance water injection efficiency and increase oil output. The Company has budgeted 10 new San Miguel oil wells this year. Severe weather and flooding interrupted Pena Creek-area operations multiple times during the first-half of 2004, temporarily reducing net San Miguel oil production at June 30, 2004 to 293 BOPD. By July 31, net San Miguel production had reached 333 BOPD as wells continued to be placed back on production. |
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|
Sligo/Pearsall - The Taylor 132-1 (62.5% WI) has been producing gas through temporary production facilities from Sligo perforations while Company engineers evaluated the formation. They have determined Sligo production could not be enhanced with stimulation. Consequently, TXCO plans to perforate and test the overlying Pearsall formation. Both of these lower Cretaceous intervals lie below the Glen Rose formation but above 7,500 feet. |
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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. |
| |
|
Coalbed Methane - New horizontal well technology may increase gas production from TXCO's Olmos/coalbed methane (CBM) project by year-end. The Company is re-entering an existing CBM dewatering well (100% WI), to attempt a horizontal re-completion using new multiple short-radius lateral (MSRL) technology. If successful, the MSRL technique could significantly increase dewatering volumes and associated CBM gas production. |
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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 June 30, 2004, the net total CBM production rate was approximately 127 Mcfd with 1,300 barrels of water per day. 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 |
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15
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|
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 included in the 2004 CAPEX budget. The Company expects 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 (0.24% WI) and two re-entries (30% and 0.24% WI), all horizontal laterals, in the Williston Basin with its operating partner Luff Exploration Company. All three are currently producing. Net Williston Basin production at June 30, 2004, was 132 BOPD and 71 Mcfd. |
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Seismic Acquisition: In late June 2004, TXCO acquired a 75% WI in existing seismic option agreements on approximately 62,000 gross acres, in exchange for 187,500 shares of its common stock, from Pedernales Energy LLC, Verus Energy Inc. and Texas Hondo Petroleum LLC, all of Houston. TXCO will serve as operator. The agreements give the Company an option to purchase oil and gas leases on the acreage after acquiring and interpreting 3-D seismic data. The parcels are adjacent to TXCO's existing Burr and Wipff leases. This acquisition increased the Company's Maverick Basin leasehold acreage block to over 860 square miles. The new acreage is on trend with the existing lease block and appears prospective for many of the same formations and plays. |
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Disclosure Regarding Forward Looking Statements |
| |
|
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. |
| |
|
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 June 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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16
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PART II - OTHER INFORMATION |
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|
ITEM 1. LEGAL PROCEEDINGS |
| |
|
None |
| |
| |
|
ITEM 2. CHANGES IN SECURITIES |
| |
|
In May 2004, the Company completed the placement of a $16 million equity offering with accredited private investors. Included were 4,266,668 shares of common stock issued at a price of $3.75, along with warrants to purchase an additional 1,280,000 common shares. The warrants are exercisable at $4.25 per share and within a window, from six-months to 3.5 years after closing of the transaction. Net proceeds from the private placement of $15.0 million will be 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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|
In June 2004, the Company filed a registration statement on Form S-3 that registers a total of 9,229,347 common shares. The shares registered were issued in conjunction with private placements in May 2004 and August 2003, warrants exercised during the first quarter of 2004, and for seismic options and producing property and leasehold acquisitions. |
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| |
|
ITEM 3. DEFAULTS UPON SENIOR SECURITIES |
| |
|
None |
| |
| |
|
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS |
| |
|
On May 14, 2004, the Company held its Annual Meeting of Shareholders at the Petroleum Club of San Antonio, pursuant to the notice mailed to shareholders of record on April 23, 2004. The following matters were submitted for approval by vote at the meeting. All matters were approved by the shareholders vote and the results of the voting is shown below for each matter. |
| |
|
1. |
Election of two Class C Directors to serve for three-year terms expiring in 2007: |
| |
| |
Nominee |
For |
Against |
|
|
|
|
|
|
| |
Michael J. Pint |
19,742,528 |
138,271 |
|
| |
James E. Sigmon |
19,742,528 |
138,271 |
|
| |
|
There were no changes in Directors of the Company. |
| |
|
2. |
Proposal to ratify the appointment of Akin, Doherty, Klein & Feuge, P.C., certified public accountants, as independent auditors of the Company and its subsidiaries for the calendar year ending December 31, 2004: |
| |
|
| |
For |
Against |
Abstain |
|
|
|
|
|
|
| |
19,799,502 |
51,870 |
29,427 |
|
| |
|
| |
|
ITEM 5. OTHER INFORMATION |
| |
|
None |
| |
| |
| |
| |
| |
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ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K |
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a) Exhibit 4 Credit Agreement between The Exploration Company of Delaware, Inc. and Guaranty Bank, FSB, dated June 30, 2004, filed herewith. |
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b) 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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c) 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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d) 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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e) 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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f) Form 8-K dated April 5, 2004; regarding the press release dated April 2, 2004 with respect to the Registrant's first quarter 2004 operations update. |
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g) Form 8-K dated April 23, 2004; regarding the press release dated April 19, 2004 with respect to the Registrant's presentation at the IPAA Oil & Gas Investment Symposium. |
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h) Form 8-K dated May 6, 2004; regarding the press release dated May 5, 2004 with respect to the Registrant's first quarter 2004 earnings. |
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i) Form 8-K dated May 20, 2004; regarding the presentation at its shareholders meeting held May 14, 2004, and the press release dated May 18, 2004 announcing a private placement of common stock. |
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j) Form 8-K dated June 10, 2004; regarding the press release dated June 7, 2004, announcing the Registrants webcast at the RBC Capital Markets' North American Energy and Power Conference, and an outline of slides used in that presentation. |
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k) Form 8-K dated June 18, 2004; regarding the press release of the same date entitled "The Exploration Company Updates Maverick Basin Operations." |
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l) Form 8-K dated July 28, 2004; regarding the press release dated July 27, 2004, entitled "The Exploration Company Updates First-Half 2004 Operations; Signs New $50 Million Credit Facility; Adds to Maverick Basin Rig Count and Acreage Position." |
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m) Form 8-K dated August 3, 2004; regarding the press release dated July 30, 2004, entitled "The Exploration Company to Webcast 9th Oil & Gas Conference Presentation" and providing an outline of the slides used in said presentation on August 2, 2004. |
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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: August 9, 2004 |
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