2. Fair Value of Stock Options - continued |
| |
Six Months Ended June 30: | 2005 | | 2004 | | | |
| | | | | |
| | | | | | | |
Net (loss) income as reported | $(4,320,739 | ) | $441,226 | | | |
| | | | | | | |
Deduct: Total stock-based compensation expense determined under the fair value based method for all awards, net of related tax effects |
(123,642
|
)
|
106,007
|
| | |
| | | | | | | | | |
| | | | | | | |
Pro forma (loss) earnings | $(4,197,097 | ) | $335,219 | | | |
| | | | | | | | | |
| | | | | | | |
Earnings (loss) per common share: | | | | | | |
Basic, as reported | $(0.15 | ) | $0.02 | | | |
Basic, pro forma | (0.15 | ) | 0.01 | | | |
Diluted, as reported | (0.15 | ) | 0.02 | | | |
Diluted, pro forma | (0.15 | ) | 0.01 | | | |
| |
The Financial Accounting Standards Board ("FASB") issued Statement No. 123R in December 2004, requiring the expensing of the fair value of unvested options for periods beginning after June 15, 2005. The SEC has further delayed the effective date of this FASB Statement. For the Company, FASB Statement No. 123R will be effective beginning January 1, 2006. |
| |
3. Common Stock and Basic Income Per Share |
| |
As of June 30, 2005, the Company had outstanding warrants and options to purchase 3,012,333 shares of common stock at prices ranging from $0.98 to $5.17 per share. Of these, warrants and options to purchase 2,474,833 shares were exercisable at quarter end. The warrants and options expire at various dates through September 2014. |
| |
The following is a reconciliation of the numerator and denominator of the basic and diluted earnings per share computation: |
| |
| | 2005 | 2004 |
(In thousands, except per share data)
|
Shares
| (Loss) or
Income | Per Share
Amount |
Shares
| (Loss) or
Income | Per Share
Amount |
| | | | | | | | |
Three Months Ended June 30: | | | | | | | |
Basic EPS: | | | | | | | | | | |
Net income | 28,365 | $(1,018 | ) | $(0.04 | ) | 25,388 | $ 372 | | $0.02 | |
Effect of dilutive options | n/a | - | | - | | 620 | - | | (0.01 | ) |
| | | | | | | | | | |
Dilutive EPS | 28,365 | $(1,018 | ) | $(0.04 | ) | 26,008 | $ 372 | | $0.01 | |
| | | | | | | | | | |
| | | | | | | | | | | |
Six Months Ended June 30: | | | | | | | | |
Basic EPS: | | | | | | | | | | |
Net (loss) income | 28,271 | $(4,321 | ) | $(0.15 | ) | 24,137 | $ 441 | | $0.02 | |
Effect of dilutive options | n/a | - | | - | | 839 | - | | - | |
| | | | | | | | | | |
Dilutive EPS | 28,271 | $(4,321 | ) | $(0.15 | ) | 24,976 | $ 441 | | $0.02 | |
| | | | | | | | | | |
| |
n/a - not applicable due to net loss for the period |
| |
4. Income Taxes |
| |
The Company has recorded a deferred tax asset for the amount expected to be realized through taxable earnings. In determining taxable earnings, the Company uses income projections reduced by graduating percentages to compensate for uncertainties inherent in future years' projections. Total income tax expense is computed based on the Company's estimated annualized federal income tax for the year, considering the impact of any change in the amount of deferred tax asset. The Company does not expect to incur regular income tax for 2005 operations due to the availability of net operating loss carryforwards. However, we expect to incur corporate alternative minimum tax for the six months ended June 30, 2005, and have recorded an expense of $49,998. |
| |
| |
8 |
5. Derivative Instruments and Hedging Activity |
| |
Due to the volatility of oil and natural gas prices and requirements under TXCO's bank credit facility, the Company periodically enters into price-risk management transactions (e.g., swaps, collars and floors) for a portion of its oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. These arrangements apply to only a portion of the Company's production, provide only partial price protection against declines in oil and natural gas prices and limit the Company's potential gains from future increases in prices. None of these instruments are used for trading purposes. On a quarterly basis, the Company's management sets all of the Company's price-risk management policies, including volumes, types of instruments and counterparties. |
| |
All of these price-risk management transactions are considered derivative instruments and accounted for in accordance with SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." These derivative instruments are intended to hedge the Company's price risk and may be considered hedges for economic purposes, but certain of these transactions may or may not qualify for cash flow hedge accounting. All derivative instrument contracts are recorded on the balance sheet at fair value. The Company elected to account for its earlier contracts as investments as set out under FAS 133. Therefore, the changes in fair value in those contracts are recorded in revenue immediately as unrealized gains or losses. Management designated the contracts established in June 2005 as cash flow hedges. As a result, the change in fair value for the effective portion of those contracts are reflected in Other Comprehensive Income (Loss) in the Equity section of the Consolidated B alance Sheets and will be reclassified to income as the hedged transactions occur (November 2006 through April 2007). The hedges are highly effective, and therefor, no hedge ineffectiveness was recorded. |
| |
The outstanding hedges at June 30, 2005, and December 31, 2004, impacting the balance sheet were as follows: |
|
| | | | | | | Price | | Volumes | | Fair Value of Outstanding
Derivative Contracts as of | |
Transaction | | Beginning | | Ending | | Per | | Per | | June 30, | | December 31, | |
Date | | Type | | | | Unit | | Month | | 2005 (4) | | 2004(4) | |
| | | | | |
Derivatives treated as investments: | |
Natural gas (1): | | | | | | | | | | | | | |
10/04 | | Ratio Swap | | 11/01/2004 | | 10/31/2005 | | $5.37 | | 140,000 | | $(214,000 | ) | $53,000 | |
03/05 | | Fixed Price | | 11/01/2005 | | 10/31/2006 | | $6.83 | | 140,000 | | (1,437,000 | ) | - | |
Crude oil (2): | | | | | | | | | | | | | |
10/04 | | Ratio Swap | | 11/01/2004 | | 10/31/2005 | | $39.10 | | 15,000 | | (280,000 | ) | 81,000 | |
03/05 | | Fixed Price | | 11/01/2005 | | 10/31/2006 | | $49.40 | | 15,000 | | (1,668,000 | ) | - | |
| | | | | | | | | | | | | | | | | |
Fair value of derivatives not designated as hedges | | | | (3,599,000 | ) | 134,000 | |
| | | | | | | | | | | | | | | | | |
Derivatives treated as cash flow hedges: | | | | | | | |
Natural gas (3): | | | | | | | | | | | | | |
06/05 | | Fixed Price | | 11/01/2006 | | 04/30/2007 | | $7.86 | | 130,000 | | (304,000 | ) | - | |
Crude oil (2): | | | | | | | | | | | | | |
06/05 | | Fixed Price | | 11/01/2006 | | 04/30/2007 | | $56.70 | | 13,000 | | (112,000 | ) | - | |
| | | | | | | | | | | | | | | | | |
Fair value of derivatives designated as cash flow hedges | | | | (416,000 | ) | - | |
| | | | | | | | | | | | | | | | | |
Total fair value of derivative contracts | | | | $(4,015,000 | ) | $134,000 | |
| | | | | | | | | | | | | | | | | |
| |
(1) These natural gas hedges were entered into on a per MMbtu delivered price basis, using the Houston Ship Channel Index, with settlement for each calendar month occurring following the expiration date, as determined by the contracts. |
| |
(2) These crude oil hedges were entered into on a per barrel delivered price basis, using the West Texas Intermediate Index, with settlement for each calendar month occurring following the expiration date, as determined by the contracts. |
| |
| |
9 |
(3) These natural gas hedges were entered into on a per MMbtu delivered price basis, using the Henry Hub Index, with settlement for each calendar month occurring following the expiration date, as determined by the contracts. |
| |
(4) The fair value of the Company's outstanding transactions is presented on the balance sheet by counterparty. The balance is shown as current or long-term based on our estimate of the amounts that will be due in the relevant time periods at currently predicted price levels. Amounts in parenthesis indicate liabilities. |
| |
6. Comprehensive Income (Loss) |
| |
Comprehensive income (loss) includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. The components of comprehensive income for the three and six months ended June 30, 2005, and 2004 are as follows: |
| |
| | Three Months Ended June 30, | Six Months Ended June 30, |
| | 2005 | | 2004 | 2005 | | 2004 |
| | | | | | | |
Net income (loss) | $(1,018,468 | ) | $372,309 | | $(4,320,739 | ) | $441,226 | |
Other comprehensive loss: | | | | | | | | |
Change in fair value of derivatives | (416,423 | ) | - | | (416,423 | ) | - | |
Income tax benefit | 14,158 | | | | 14,158 | | | |
| | | | | | | | |
Total comprehensive loss | $(1,420,733 | ) | $372,309 | | $(4,723,004 | ) | $441,226 | |
| | | | | | | | |
| | | | | | | | | |
7. Long-Term Debt |
| |
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. The 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 bi-annual 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"). At June 30, 2005, the borrowing base was $26.5 million, and the Company had outstanding $24.4 million with a weighted average interest rate of 5.76%. During July 2005, the Company drew an additional $1.8 million on the Facility, leaving an unused borrowing base of approximately $271,000 at July 31, 2005. |
| |
When borrowing under the Facility exceeds 50% of the borrowing base, the Company is required to hedge a portion of its production. As a result, TXCO entered into financial price hedges beginning in October 2004 and entered into additional financial price hedges in March 2005. During first quarter 2005, the Facility's definition of the current ratio was amended to exclude all current assets and liabilities generated by derivative transactions. |
| |
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 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. The Company was in compliance with all such covenants at June 30, 2005, except the current ratio covenant. |
| |
The Company received a waiver related to the current ratio covenant for the June 30, 2005 reporting period, and expects to be in compliance with the covenant at September 30, 2005 and subsequent periods. |
| |
| |
10 |
Letter of Credit Agreement:In connection with the financial price hedges, the Company entered into a Letter of Credit Agreement (L/C) with Guaranty Bank in October 2004. This agreement provides for the issuance of a Standby Letter of Credit (SLC) representing a Hedge Commodity Agreement or Rate Management Transaction issued outside of the original borrowing base as stated in the Facility. The agreement requires the payment of administrative fees ranging from 2.0% to 2.5% per annum of the face amount of the outstanding SLCs. The initial SLC amount was set at $1 million. Subsequently, additional SLC's were required in conjunction with the Company's derivatives such that the total of SLC's outstanding is $5 million. No drafts or advances have been made against the L/C through August 9, 2005. |
| |
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS |
| |
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 and 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 inits Form 10-K for the year ended December 31, 2004. See"Disclosure Regarding Forward Looking Statements." |
| |
Overview |
| |
The following is a discussion of the Company's financial condition and results of operations. This discussion should be read in conjunction with the Financial Statements of the Company and Notes thereto. |
| |
The Exploration Company is an independent oil and gas enterprise with interests primarily in the Maverick Basin in Southwest Texas. Its long-term 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." The Company currently has four drilling rigs in operation on its extensive 723,000-gross acre block in the Maverick Basin, targeting multiple formations for the production of oil and natural gas. Current emphasis is on the Georgetown and Glen Rose formations. The 2005 capital expenditures budget (CAPEX) includes funds for the drilling or re-entry of approximately 60 wells (34 in the Georgetown formation), as w ell as funds for completion of a number of wells in progress at year-end 2004 and for infrastructure improvements. |
| |
Due to the availability of many promising prospects on our Maverick Basin acreage, and higher oil and gas prices, drilling activity has remained brisk over the last three years. (For further discussion of this activity, see the "Principal Areas of Activity" and "Drilling Activity" sections ofTXCO's Annual Report on Form 10-K). The resulting increased expenditures should continue to translate into increased reserves as an adequate sales and production history is established. Recognition of additional reserves on newly drilled wells requires a period of sustained production, causing a delay between the expenditures and the recording of reserves. |
| |
TXCO reported a net loss of $1.0 million or $0.04 per basic and diluted share, and $4.3 million or $0.15 per basic and diluted share, for the quarter and six-month periods ended June 30, 2005, respectively, compared to a net income of $372,000 or $0.02 per basic share, and $0.01 per diluted share, and $441,000 or $0.02 per basic and diluted share, respectively, for the prior year periods. The primary reasons for the losses were non-cash expenses, such as derivative mark-to-market losses and higher depletion costs,coupled with increased dry hole costs. The derivative losses were largely non-cash mark to market adjustments that do not impact cash flow from operations. The Company was not involved in derivatives during first half of 2004. Excluding the derivativelosses, net loss for second quarter 2005 would have been $397,000, and $135,000 for first half 2005. Sales volumes were up 1.5% and 1.4% for the second quarter and first half of 2005, on a billion cubic feet equivalent (Bcfe) basis, and oil and gas revenues were up 27.6% and 26.3%, each respectively, over the 2004 periods. Higher lease operating costs, impairment and depletion charges, interest expense and lower gross margin on gas gathering operations were more than offset by higher oil and gas revenues. These factors are discussed in theResults of Operations section. |
| |
| |
11 |
Net cash provided by operating activities for first half 2005 was $9.6 million, as compared to $5.2 million in the 2004 first half. Net cash provided by operating activities, excluding changes in operating assets and liabilities, was $7.2 million for the first six months of 2005, up from $6.7 million during the 2004 period. |
| |
| | Second Quarter | | | First Half | | |
Operational Data | 2005 | 2004 | Change | | | 2005 | 2004 | Change | | |
| | | | | | |
Gas sales volumes(Mcf) | 710,029 | 782,926 | - | 9.3 | % | | 1,403,500 | 1,421,576 | - | 1.3 | % | |
Oil sales volumes(Bbls) | 80,711 | 65,596 | + | 23.0 | % | | 155,553 | 147,149 | + | 5.7 | % | |
Combined sales volumes(MMcfe) | 1,194,295 | 1,176,502 | + | 1.5 | % | | 2,336,818 | 2,304,470 | + | 1.4 | % | |
Net residue and NGL sales volumes(MMbtu) | 754,860 | 1,148,495 | - | 34.3 | % | | 1,562,559 | 1,985,148 | - | 21.3 | % | |
Gas average realized sales price per Mcf | $6.84 | $5.98 | + | 14.4 | % | | $6.50 | $5.79 | + | 12.3 | % | |
Oil average realized sales price per Bbl | $49.79 | $34.70 | + | 43.5 | % | | $47.86 | $33.20 | + | 44.2 | % | |
Residue & NGL average realized sales
price per MMbtu |
$8.51
|
$6.62
|
+
|
28.6
|
%
| |
$8.45
|
$6.40
|
+
|
32.0
|
%
| |
Gas - average daily sales(MMcfd) | 7,803 | 8,604 | - | 9.3 | % | | 7,754 | 7,811 | - | 0.7 | % | |
Oil - average daily sales(BOPD) | 887 | 721 | + | 23.0 | % | | 859 | 809 | + | 6.2 | % | |
Combined average daily sales(MMcfed) | 13,124 | 12,929 | + | 1.5 | % | | 12,911 | 12,662 | + | 2.0 | % | |
| |
In December 2004, TXCO retained Raymond James & Associates ("RJA") to assist in actively pursuing strategic alternatives designed to enhance shareholder value, including a merger or sale of the Company. No definitive decisions have been made and no agreements have been reached at this time. There can be no assurances that any particular alternative will be pursued or that any transaction will occur, or on what terms. |
| |
Liquidity and Capital Resources |
| |
Liquidity is a measure of ability to access cash. The Company's primary needs for cash are for exploration, development and acquisition of oil and gas properties, repayment of contractual obligations and working capital funding. TXCO has historically addressed its long-term liquidity requirements through cash provided by operating activities, the issuance of equity securities when market conditions permit, sale of non-strategic assets, and more recently through theCredit Facility and issuance of redeemable preferred stock. Management continues to examine alternative sources of long-term capital, including bank borrowings, the issuance of debt instruments, the sale of common stock, the sales of non-strategic assets, and joint venture financing. Availability of these sources of capital and, therefore, TXCO's ability to execute its operating strategy will depend upon a number of fa ctors, some of which are beyond its control. |
| |
Management believes that 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, future cash flows are subject to a number of variables including the level of sales volumes and oil and natural gas prices. No assurances can be made that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures or that increased capital expenditures will not be undertaken. Actual levels of capital expenditures may vary significantly due to a variety of factors, including but not limited to drilling results, product pricing and future acquisition and divestitures of properties. |
| |
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. The 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 bi-annual 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"). At June 30, 2005, the borrowing base was $26.5 million, and the Company had outstanding $24.4 million with a weighted average interest rate of 5.76%. During July 2005, the Company drew an additional $1.8 million on the Facility, leaving an unused borrowing base of approximately $271,000 at July 31, 2005.The Company is presently in discussions with Guaranty about increasing the amount of the bank's commitment. |
| |
| |
12 |
When borrowing under the Facility exceeds 50% of the borrowing base, the Company is required to hedge a portion of its production. As a result, TXCO entered into financial price hedges beginning in October 2004 and entered into additional financial price hedges in March 2005. During first quarter 2005, the Facility's definition of the current ratio was amended to exclude all current assets and liabilities generated by derivative transactions. |
| |
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 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. The Company was in compliance with all such covenants at June 30, 2005, except the current ratio covenant. |
| |
The Company received a waiver related to the current ratio covenant for the June 30, 2005 reporting period, and expects to be in compliance with the covenant at September 30, 2005 and subsequent periods. |
| |
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 2005. 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. Should product prices materially weaken, or expected new oil and gas production levels not be attained, the resulting reduction in projected revenues would cause the Company to re-evaluate its working capital options and would adversely affect the Company's ability to carry out its current operating plans. |
| |
Letter of Credit Agreement:In connection with the financial price hedges, the Company entered into a Letter of Credit Agreement (L/C) with Guaranty Bank in October 2004. This agreement provides for the issuance of a Standby Letter of Credit (SLC) representing a Hedge Commodity Agreement or Rate Management Transaction issued outside of the original borrowing base as stated in the Facility. The agreement requires the payment of administrative fees ranging from 2.0% to 2.5% per annum of the face amount of the outstanding SLCs. The initial SLC amount was set at $1 million. Subsequently, additional SLC's were required in conjunction with the Company's derivatives such that the total of SLC's outstanding is $5 million. No drafts or advances have been made against these L/C's through August 9, 2005. |
| |
Risk Management Activities -- Derivatives and Hedging:Due to the instability of oil and natural gas prices and requirements under TXCO's bank credit facility, the Company enters into, from time to time, price-risk management transactions for a portion of its oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from commodity price fluctuations.These arrangements apply to only a portion of the Company's production, provide only partial price protection against declines in oil and natural gas prices and limit potential gains from future increases in prices. None of these instruments are used for trading purposes. On a quarterly basis, management sets all price-risk management policies, including volumes, types of instruments and counterparties. These policies are implemented by management through the execution of trades by the Chief Financial Officer after consultation with and concurrence by the President and th e Board of Directors. Our Board of Directors monitors the Company's price-risk management policies and trades. |
| |
| |
13 |
Beginning in October 2004, the Company entered into derivative transactions. The Company elected to account for its earlier contracts as investments as set out under FAS 133. Therefore, the changes in fair value in those contracts are recorded in revenue immediately as unrealized gains or losses. Management designated the contracts established in June 2005 as cash flow hedges. As a result, the changes in fair value for the effective portion of those contracts are reflected in Other Comprehensive Income (Loss) in the Equity section of the Consolidated Balance Sheets and will be reclassified to income as the hedged transactions occur (November 2006 through April 2007). The hedges are highly effective, and therefor, no hedge ineffectiveness was recorded. |
| |
Sources and Uses of Cash: During the first half of 2005, cash reserves of $3.1 million at December 31, 2004, were increased by cash provided by operating activities of $9.6 million. In addition, borrowings under the Facility totaled $7.3 million and proceeds from the exercise of warrants totaled $1.3 million, resulting in total cash available of $21.3 million for use in meeting the Company's ongoing operational and development needs. |
| |
During the first quarter of 2005, borrowings under the Facility totaled $3.3 million and proceeds from the exercise of warrants totaled $1.3 million. Payments on installment debt totaled $1.5 million in principal, with interest payments of $613,000, while the Company applied $7.1 million to fund the ongoing development of its oil and gas producing properties. |
| |
During the second quarter of 2005, borrowings under the Facility totaled $4.0 million, while payments of interest on long-term debt totaled $908,000 and TXCO invested $10.8 million in drilling activities. |
| |
Adjusted for the impact of the derivative liabilities on current liabilities, the Company ended the first half of 2005 with negative working capital of $7.8 million compared to negative working capital of $5.5 million at December 31, 2004. At June 30, 2005, with the same adjustment, the Company's current ratio was 0.62 to 1 compared to 0.70 to 1 at year end. Including the estimated $2.6 million current liability for derivative losses at June 30, 2005, negative working capital was $10.4 million, with a current ratio of 0.55 to 1. |
| |
The Company exited first half 2005 with an unused borrowing base of $2.1 million under its Credit Facility. Its ending working capital was impacted by $2.5 million of short-term accrued derivative mark to market obligations related to hedges entered into in connection with the Facility, along with lower cash balances held and increased payables to joint interest owners. First half cash flow from operating activities increased to $9.6 million from $5.2 million in the comparative prior year period. Before changes in operating assets and liabilities, first half cash flow from operating activities was $7.2 million in 2005 compared to $6.7 million for first half 2004, a 6.8 increase over the same period a year ago. Changes in operating assets and liabilities include increases or decreases in receivables, accounts payable and prepaid expenses from the prior year-end balances. |
| |
Results of Operations |
| |
The following table highlights the change from comparable periods in 2004: |
| |
| | Second Quarter | First Half | |
Selected Income Statement Items: | $ thousands | | % | | $ thousands | | % | |
| | | | | | | |
Oil and gas revenues | + | $1,921 | + | 27.6 | + | $3,449 | + | 26.3 | |
Lease operating expense | + | 295 | + | 20.6 | + | 733 | + | 27.4 | |
Depreciation, depletion & amortization | + | 1,191 | + | 48.9 | + | 1,336 | + | 28.0 | |
Income from operations | - | 576 | - | 50.3 | - | 222 | - | 11.4 | |
Derivative mark to market loss | + | 337 | + | 100.0 | + | 3,733 | + | 100.0 | |
Derivative settlements loss | + | 285 | + | 100.0 | + | 453 | + | 100.0 | |
Net income (loss) | - | 1,391 | - | n/m | - | 4,762 | - | n/m | |
n/m - % change not meaningful due to move from an income to a loss |
| |
| |
14 |
The increases in oil and gas revenue for both the second quarter and first half of 2005, as compared to the same periods of 2004, are attributable to higher oil sales volumes along with higher oil and natural gas prices, partially offset by a decline in gas sales volumes. Oil sales volumes increased 23.0% and 5.7% for the quarter and year to date periods over the prior year periods, respectively, primarily due to Glen Rose Porosity and Georgetown oil wells put on production since June 30, 2004. This increase was offset by 9.3% and 1.3% lower gas sales volumes for the quarter and year to date periods over the prior year periods, respectively. This was due to normal declines in maturing gas wells and a lower working interest in wells exchanged in the Asset Exchange Agreement effective in February 2005. These reductions were partially offset by production from new wells. Sales volumes increased slightly on a Mcfe basis in the 2005 second quarter and first half periods over th e same 2004 periods. Average realized sales prices for oil and natural gas were up 43.5% and 14.5%, respectively, for the second quarter of 2005 over the same quarter of 2004, and up 44.2% and 12.2%, respectively, for the first half of 2005 over the prior year period. |
| |
The 20.6% and 27.4% increases in lease operating expenses ("LOE") for the second quarter and first half of 2005 as compared to the same periods of 2004 primarily reflect increased costs experienced due to high demand for services in field operations in 2005, as well as costs related to 42 additional Maverick Basin oil and gas wells placed on production since June 30, 2004. The increase also reflects unusual repairs and reclamation expenses totaling $138,000 in 2005, as compared with $94,000 for similar costs during 2004. |
| |
The Company's gas gathering system transports its natural gas production to various markets. It also transports production for other owners at a set rate per million British thermal units (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 first half of 2005, gas gathering operations revenues increased 4.9%, when compared to the same period of 2004, due to higher natural gas liquids (NGL) sales and transportation income partially offset by lower third party natural gas sales. Decreased sales volumes for natural gas liquids for first half 2005, compared to the prior year period, were more than offset by higher realized prices. Gas gathering operations revenues declined 14.2% for the second quarter of 2005 as compared with the same quarter in 2004, on lower third party natural gas sales volumes coming through the system due to declining production on area leases. |
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The following table summarizes the change for 2005 from comparable periods in 2004: |
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| | Second Quarter | First Half | |
Change in Gas Gathering Results: | $ thousands | | % | | $ thousands | | % | |
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Revenues: | | | | | | | | | | |
Third-party natural gas sales | - | 1,011 | - | 16.6 | | + | 327 | + | 3.2 | |
Natural gas liquids sales | - | 164 | - | 11.0 | | + | 172 | + | 6.8 | |
Transportation and other revenue | + | 88 | + | 128.2 | | + | 133 | + | 79.5 | |
| | | | | | | | | | |
Total gas gathering revenues | - | 1,087 | - | 14.2 | | + | 632 | + | 4.9 | |
| | | | | | | | | | | |
Expense: | | | | | | | | | | |
Third-party gas purchases | - | 708 | - | 10.6 | | + | 977 | + | 8.7 | |
Transportation and marketing expenses | - | 98 | - | 57.9 | | - | 103 | - | 40.7 | |
Direct operating costs | + | 15 | + | 7.4 | | + | 13 | + | 3.2 | |
| | | | | | | | | | |
Total gas gathering operations expense | - | 791 | - | 11.2 | | + | 887 | + | 7.4 | |
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Gross margin | - | 296 | - | 47.3 | | - | 255 | - | 27.2 | |
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Operational data | | | | | | | | | | |
Total residue gas & NGL sales volumes (MMBtu) | - | 393,635 | - | 34.3 | | - | 422,589 | - | 21.3 | |
Average realized sales price (per MMBtu) | + | $1.89 | + | 28.6 | | + | $2.05 | + | 32.0 | |
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Depreciation, depletion and amortization increased 48.9% and 28.0% for the second quarter and first half of 2005, respectively, over the comparable prior year periods. The major component of this increase was higher depletion, up $1.2 million and $1.3 million for the quarter and six month periods. The increase was consistent with the increased number of producing wells subject to depletion. In addition, second quarter 2005 depletion reflects the acceleration of increasing depletion rates due to the maturing profile of existing producing wells. |
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General and administrative expense increased 30.9% and 24.1% for the second quarter and first half of 2005, respectively, as compared to the same periods in 2004, while increasing to approximately 8.7% and 8.4%, respectively, of total revenues from 7.0% and 7.8%, respectively, in the prior year periods. The increase in expense was primarily due to salaries and wages of four additional full-time employees hired across the organization since June 30, 2004, along with the associated increased benefits. TXCO's matching contribution to the 401k plan, implemented in 2004, was $17,000 for the second quarter and $43,000 for the six month period of 2005, with no similar costs incurred during first half 2004. Higher costs for independent engineer's services and franchise taxes were related to increased activity levels. Consulting service charges related to the completion of the initial internal control certifications amortized during the second quarter were $60,000, for a total of $1 12,000 for the first half of 2005, with no similar costs incurred during first half 2004. Legal and accounting consulting expenses, combined, were $27,000 and $38,000 higher for the second quarter and first half of 2005, respectively, due to expanded compliance requirements and the strategic alternatives review begun in December 2004. |
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The net loss for the first half of 2005 resulted from the $3.7 million in non-cash mark to market losses accrued on derivatives that hedge future oil and gas sales volumes, which were treated as investments for accounting purposes. TXCO has hedges in place covering 15,000 barrels of oil (BO) and 140,000 MMBtu of gas on a monthly basis through October 2006, and for 13,000 BO and 130,000 MMBtu of gas per month for November 2006 through April 2007. Derivative losses on the closed periods amounted to $285,000 and $453,000 for the second quarter and first half 2005, respectively, bringing the total recognized hedging loss to $621,000 and $4.2 million, respectively. Additionally, in accordance with FAS 133, an unrecognized hedging loss of $416,000, related to the agreement for which hedge accounting was elected, was recorded in other comprehensive income (OCI) on the balance sheet. The balance in OCI will offset revenues during November 2006 through April 2007, the periods that th e hedged transactions occur, assuming that the current price levels continue. No hedges were in place during the first half of 2004. |
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Interest expense for the second quarter and first half of 2005 increased by $204,000 and $344,000 over the same 2004 periods due to higher levels of borrowings under the Credit Facility. Approximately 30% of the interest expense in 2005 is a non-cash accrual reflecting the accretion of the liability on the redeemable preferred stock to its full redemption value. The comparable percentage for 2004 was 37%. |
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Drilling Activities |
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The Company drilled or participated in drilling 25 new wells and three re-entries on its lease block in the Maverick Basin in the first half of 2005, with 16 of the new wells drilled in the second quarter. Of the 25 new wells, 12 wells were producing oil, three wells were producing natural gas, and 10 wells were in various completion stages at July 31, 2005. Through July 31, 2005, TXCO successfully placed on production wells from the Georgetown, Glen Rose, San Miguel, Edwards, and Austin Chalk formations. By comparison, the Company participated in 29 new wells and two re-entries during first half 2004 primarily targeting the Glen Rose, Georgetown and San Miguel intervals. TXCO spud five new wells in July 2005, targeting four formations, with two in completion while three continue drilling at July 31, 2005. TXCO has also participated in one well on its Williston Basin acreage this year, which is producing oil. There are four rigs under contract for TXCO or its partner's accou nt to facilitate drilling over 60 wells, including four re-entries, during 2005. |
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For the second quarter 2005, Company had net daily sales of 887 barrels of oil per day (BOPD) and 7.8 million cubic feet per day (MMcfd) of natural gas, a combined rate of approximately 13.1 million cubic feet equivalent per day (MMcfed). The comparable figures for first quarter 2005 were 832 BOPD and 7.7 MMcfd, or 12.7 MMcfed, while the second quarter of 2004 was 721 BOPD and 8.6 MMcfd, or 12.9 MMcfed. For the six months ended June 30, 2005, net daily sales averaged 859 BOPD and 7.8 MMcfd, or 12.9 MMcfed, as compared with 809 BOPD, 7.8 MMcfd and 12.7 MMcfed for the same period in 2004. Normal natural gas production declines were experienced in the second quarter and first half, as new wells put on production did not fully replace declines on maturing wells. |
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Glen Rose- The Company spud four new Glen Rose wells during second quarter 2005 in addition to the one porosity well re-entered in the first quarter. At July 31, 2005, three of the four new wells are producing oil, while two wells await completion and three wells spud in July continue drilling. Glen Rose targets represent the second-largest portion of the Company's 2005 CAPEX budget. |
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Second quarter 2005 Glen Rose oil and gas sales were approximately 360 BOPD and 4.2 MMcfd, compared to 300 BOPD and 4.4 MMcfd in the first quarter 2005, and 346 BOPD and 4.8 MMcfd in second quarter 2004. |
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Georgetown- The Company started 13 Georgetown drilling projects during the first half 2005, including 11 new wells and two re-entries. At July 31, 2005, eight of the wells have been placed on production, while five are awaiting completion. TXCO has allocated the largest share of its 2005 CAPEX budget to the Georgetown play with a projected 34 new wells. Second quarter 2005 Georgetown oil and gas sales were approximately 193 BOPD and 3.2 MMcfd, compared to 184 BOPD and 3.0 MMcfd in the first quarter 2005, and 49 BOPD and 3.4 MMcfd in second quarter 2004. |
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Since the Georgetown is a fractured reservoir, it is difficult to predict the type and quantity of ultimate reserves for each well as such reservoirs typically have high initial production rates that rapidly fall to lower sustained rates. In better wells, first year declines typically range from 35% to 70%, while less productive wells may experience a first year decline of approximately 90%. |
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Other Plays- TXCO continued its San Miguel oil play, in which it has a 100% working interest (WI), by spudding six infill wells this year. Five were spud in the second quarter and the sixth in July. At July 31, 2005, three of these wells are producing and three await completion. TXCO's CAPEX budget calls for 12 San Miguel wells this year. Second quarter 2005 San Miguel oil and gas sales were approximately 241 BOPD and 11 thousand cubic feet per day (Mcfd), compared to 231 BOPD and 36 Mcfd in the first quarter 2005, and 211 BOPD with no gas in second quarter 2004. |
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The Company spudded three wells targeting the oil-prone Austin Chalk in the second quarter and a fourth in mid July. The Cage Ranch 1-40H (50% WI) went on production in mid July averaging 70 BOPD while the other two wells were in completion at July 31, 2005. TXCO has drilled one well to the Edwards formation which is producing oil. TXCO plans to drill several other formations in 2005, part of its multi-play/multi-pay strategy in the multi-targeted Maverick Basin. This year's CAPEX calls for six wells to formations besides the Georgetown, Glen Rose and San Miguel. |
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Red River B Zone- The Company participated in drilling one new well (3.1% WI) in the Williston basin with its operating partner Luff Exploration Company during the first half of 2005. The well is producing oil. TXCO did not participate in any wells in this region in 2004's first half. |
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Coalbed Methane (CBM) - TXCO exited the second quarter of 2005 with 31 wells dewatering the multiple seams of bituminous coal present under its Comanche lease. |
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Asset Exchange Agreement -In February 2005, TXCO entered into an asset exchange agreement with Arrow River Energy LP and CMR Energy LP, both of Houston, Texas. TXCO received a 50% working interest in all depths and formations in 174,460 gross acres located in Maverick, Dimmit and Zavala counties of Texas and 140 square miles of 3-D seismic data over a portion of the new acreage. TXCO will serve as operator and Arrow River reserved an after-payout, term net-profits interest in new wells drilled on the new acreage. In exchange, Arrow River and CMR collectively received a 50% working interest in 106,500 acres comprised of three tracts within TXCO's existing acreage block. These include shallow depths to the base of the San Miguel formation (including CBM) under 95,300 acres of the Comanche Ranch lease and beneath 7,900 acres of the Chittim B lease, and all depths under the 3,300-acre Chittim C lease. CMR assumed operations on these tracts including all existing CBM and San Miguel wells. |
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Disclosure Regarding Forward Looking Statements |
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Statements in this Quarterly Report on Form 10-Q that 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 reser ves 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 are available from the Company without charge. |
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. |
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Market risk represents the risk of loss that may impact the financial position, results of operations, or cash flows of the Company due to adverse changes in financial market prices, including interest rate risk, and other relevant market rate or price increases. |
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The Company is exposed to market risk through interest rates related to its bank credit facility borrowing. The credit facility borrowings are based on the LIBOR or prime rate plus an applicable margin and are used to assist in meeting working capital needs. As of June 30, 2005, the Company had borrowings under its bank credit facility of $24.4 million. Assuming an increase in either the LIBOR or prime interest rates of 100 basis points, interest expense could increase by approximately $244,000 per year. The interest rate variability on all other debt would not have a material adverse effect on the Company's financial position. |
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The Company enters into hedging transactions in the normal course of business, including fixed price and ratio swaps to mitigate exposure to commodity price movements, but not for trading or speculative purposes. During 2004 and 2005, due to the instability of prices and to achieve a more predictable cash flow, TXCO put in place natural gas and crude oil swaps for a portion of its production for 2005 through April 2007. Please refer to Note 5 to the consolidated financial statements. While the use of these arrangements limits the benefit of increases in the price of oil and natural gas, it also limits the downside risk of adverse price movements. The following table lists contracts outstanding as of June 30, 2005: |
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18 |
| | | | | | | Price | | Volumes Per | |
Transaction Date | | Transaction Type | | Beginning | | Ending | | Per Unit | | Per Month | |
| | | | | | | | | | | |
Natural Gas: | | | | | | | | | | | |
10/04 (1) | | Ratio Swap | | 11/01/2004 | | 10/31/2005 | | $5.37 | | 140,000 MMbtu | |
03/05 (1) | | Fixed Price Swap | | 11/01/2005 | | 10/31/2006 | | $6.83 | | 140,000 MMbtu | |
06/05 (2) | | Fixed Price Swap | | 11/01/2006 | | 04/30/2007 | | $7.86 | | 130,000 MMbtu | |
Crude Oil (3): | | | | | | | | | | | |
10/04 | | Ratio Swap | | 11/01/2004 | | 10/31/2005 | | $39.10 | | 15,000 Bbl | |
03/05 | | Fixed Price Swap | | 11/01/2005 | | 10/31/2006 | | $49.40 | | 15,000 Bbl | |
06/05 | | Fixed Price Swap | | 11/01/2006 | | 04/30/2007 | | $56.70 | | 13,000 Bbl | |
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(1) These natural gas hedges were entered into on a per MMbtu delivered price basis, using the Houston Ship Channel Index, with settlement for each calendar month occurring following the expiration date, as determined by the contracts. |
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(2) These natural gas hedges were entered into on a per MMbtu delivered price basis, using the Henry Hub Index, with settlement for each calendar month occurring following the expiration date, as determined by the contracts. |
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(3) The fair value of the Company's outstanding transactions is presented on the balance sheet by counterparty. The balance is shown as current or long-term based on management's estimate of the amounts that will be due in the relevant time periods at currently predicted price levels |
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At June 30, 2005, the fair value of the outstanding hedges was a liability of approximately $4.0 million. A 10% change in the commodity price per unit would cause the fair value of the hedges to increase or decrease by approximately $402,000. |
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See also theCompany'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, 2005. 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 the Company's periodic SEC filings. |
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b. There have been no changes in the Company's internal controls that have materially affected, or are reasonably likely to materially affect, the Company's internal controls over financial reporting subsequent to the date of the above evaluation. There were no material weaknesses identified in the course of such review and evaluation and, therefore, no corrective measures were required. |
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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. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS |
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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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On May 13, 2005, 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 1, 2005. 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 are shown below for each matter. |
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1. | Election of two Class A Directors to serve for three-year terms expiring in 2008: |
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| | Nominee | For | Against | |
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| | Robert L. Foree, Jr. | 25,237,663 | 170,956 | |
| | Thomas H. Gose | 22,790,675 | 2,617,944 | |
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There were no changes in Directors of the Company. |
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2. | Proposal to approve the adoption of the Company's 2005 Stock Incentive Plan: |
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| | For | Against | Abstain | |
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| | 12,606,504 | 2,339,857 | 348,978 | |
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3. | 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, 2005: |
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| | For | Against | Abstain | |
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| | 25,301,576 | 75,787 | 31,255 | |
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ITEM 5. OTHER INFORMATION |
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None |
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ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K |
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a) 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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b) 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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c) 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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g) 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 |
| | (Registrant) |
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| | /s/ P. Mark Stark |
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| | P. Mark Stark, |
| | Chief Financial Officer |
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Date: August 9, 2005 | |
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