UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 2007
OR
p TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from _____________ to _________________
Commission File No. 0-9120
TXCO RESOURCES INC.
(Exact Name of Registrant as Specified in its Charter)
DELAWARE | 84-0793089 |
(State or other jurisdiction of | (I.R.S. Employer I.D. No.) |
incorporation or organization) |
777 E. SONTERRA BLVD., SUITE 350 SAN ANTONIO, TEXAS 78258
(Address of principal executive offices)
Registrant's telephone number, including area code: (210) 496-5300
THE EXPLORATION COMPANY OF DELAWARE, INC.
(Former Name)
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes þ | No p |
Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act.
Large accelerated filer p | Accelerated filer þ | Non-accelerated filer p |
Indicate by check mark if the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes | p | No | þ |
Indicate the number of shares outstanding of each of the issuer's classes of common stock as of August 3, 2007.
Common Stock $0.01 par value | 34,125,292 |
(Class of Stock) | (Number of Shares) |
For more information go to www.txco.com.
The information at www.txco.com is not incorporated into this report.
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PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
TXCO RESOURCES INC.
Consolidated Balance Sheets
(Unaudited)
($ in thousands) | June 30, 2007 | December 31, 2006 | |||||
Assets | |||||||
Current Assets | |||||||
Cash and equivalents | $ | 6,825 | $ | 3,882 | |||
Accounts receivable, net | 15,029 | 9,132 | |||||
Federal income tax receivable | 9,718 | 4,468 | |||||
Prepaid expenses and other | 3,284 | 887 | |||||
Total Current Assets | 34,856 | 18,369 | |||||
Property and Equipment, net - successful efforts method of accounting for oil and gas properties | 261,468 | 119,574 | |||||
Other Assets | |||||||
Deferred tax asset | 1,095 | 5,310 | |||||
Deferred financing fees | 2,216 | 60 | |||||
Other assets | 544 | 488 | |||||
Total Other Assets | 3,855 | 5,858 | |||||
Total Assets | $ | 300,179 | $ | 143,801 |
2
TXCO RESOURCES INC.
Consolidated Balance Sheets
(Unaudited)
($ in thousands) | June 30, 2007 | December 31, 2006 | |||||
Liabilities and Stockholders' Equity | |||||||
Current Liabilities | |||||||
Accounts payable, trade | $ | 14,229 | $ | 7,969 | |||
Undistributed revenue | 759 | 1,035 | |||||
Notes payable | 125 | 267 | |||||
Derivative settlements payable | - | 70 | |||||
Accrued derivative obligation - short-term | - | 321 | |||||
Other payables and accrued liabilities | 5,859 | 6,433 | |||||
Total Current Liabilities | 20,972 | 16,095 | |||||
Long-Term Liabilities | |||||||
Long-term debt | 133,600 | 2,351 | |||||
Deferred income taxes - long-term | 15,140 | - | |||||
Asset retirement obligation | 4,100 | 1,703 | |||||
Total Long-Term Liabilities | 152,840 | 4,054 | |||||
Stockholders' Equity | |||||||
Preferred stock, Series A & Series B; authorized 10,000,000 shares; issued and outstanding -0- shares | - | - | |||||
Common stock, par value $.01 per share; authorized 100,000,000 shares; issued 34,204,711 and 33,290,698 shares, outstanding 34,086,292 and 33,190,898 shares | 342 | 333 | |||||
Additional paid-in capital | 127,077 | 122,108 | |||||
Retained earnings | (587 | ) | 2,619 | ||||
Accumulated other comprehensive loss, net of tax | - | (1,162 | ) | ||||
Less treasury stock, at cost, 118,419 and 99,800 shares | (465 | ) | (246 | ) | |||
Total Stockholders' Equity | 126,367 | 123,652 | |||||
Total Liabilities and Stockholders' Equity | $ | 300,179 | $ | 143,801 |
3
TXCO RESOURCES INC.
Consolidated Statements Of Operations
(Unaudited)
Three Months Ended | Three Months Ended | |||||||
(in thousands, except earnings per share data) | June 30, 2007 | June 30, 2006 | ||||||
Revenues | ||||||||
Oil and gas sales | $ | 19,136 | $ | $15,854 | ||||
Gas gathering operations | 3,152 | 3,678 | ||||||
Other operating income | 48 | 20 | ||||||
Total Revenues | 22,336 | 19,552 | ||||||
Costs and Expenses | ||||||||
Lease operations | 4,238 | 1,869 | ||||||
Production taxes | 1,103 | 779 | ||||||
Exploration expenses, including dry hole costs | 279 | 195 | ||||||
Impairment and abandonments | 696 | 618 | ||||||
Gas gathering operations | 3,356 | 3,625 | ||||||
Depreciation, depletion and amortization | 8,669 | 3,627 | ||||||
General and administrative | 3,081 | 1,888 | ||||||
Total Costs and Expenses | 21,422 | 12,601 | ||||||
Income from Operations | 914 | 6,951 | ||||||
Other Income (Expense) | ||||||||
Derivative mark-to-market loss | - | 474 | ||||||
Derivative settlements loss | - | (958 | ) | |||||
Interest expense | (2,863 | ) | (49 | ) | ||||
Interest income | 77 | 175 | ||||||
Loan fee amortization | (159 | ) | (49 | ) | ||||
Loss on sale of assets | - | (11 | ) | |||||
Total Other Income (Expense) | (2,945 | ) | (418 | ) | ||||
(Loss) income before income taxes | (2,031 | ) | 6,533 | |||||
Income tax (benefit) expense -- current | 16 | 2,952 | ||||||
deferred | (733 | ) | (400 | ) | ||||
Net (Loss) Income | $ | (1,314 | ) | $ | $3,981 | |||
(Loss) Earnings Per Share | ||||||||
Basic (loss) earnings per share | $ | (0.04 | ) | $ | $0.12 | |||
Diluted (loss) earnings per share | $ | (0.04 | ) | $ | $0.12 |
4
TXCO RESOURCES INC.
Consolidated Statements Of Operations
(Unaudited)
Six Months Ended | Six Months Ended | |||||||
(in thousands, except earnings per share data) | June 30, 2007 | June 30, 2006 | ||||||
Revenues | ||||||||
Oil and gas sales | $ | 27,861 | $ | $26,323 | ||||
Gas gathering operations | 5,646 | 9,218 | ||||||
Other operating income | 49 | 35 | ||||||
Total Revenues | 33,556 | 35,576 | ||||||
Costs and Expenses | ||||||||
Lease operations | 6,898 | 3,512 | ||||||
Production taxes | 1,597 | 1,290 | ||||||
Exploration expenses, including dry hole costs | 654 | 640 | ||||||
Impairment and abandonments | 1,382 | 1,094 | ||||||
Gas gathering operations | 6,237 | 9,376 | ||||||
Depreciation, depletion and amortization | 13,585 | 6,353 | ||||||
General and administrative | 4,885 | 3,561 | ||||||
Total Costs and Expenses | 35,238 | 25,826 | ||||||
(Loss) Income from Operations | (1,682 | ) | 9,750 | |||||
Other Income (Expense) | ||||||||
Derivative mark-to-market loss | - | 468 | ||||||
Derivative settlements loss | - | (1,591 | ) | |||||
Interest expense | (3,140 | ) | (136 | ) | ||||
Interest income | 103 | 213 | ||||||
Loan fee amortization | (169 | ) | (122 | ) | ||||
Loss on sale of assets | - | (11 | ) | |||||
Total Other Income (Expense) | (3,206 | ) | (1,179 | ) | ||||
(Loss) income before income taxes | (4,888 | ) | 8,571 | |||||
Income tax (benefit) expense -- current | (5,250 | ) | 3,715 | |||||
deferred | 3,568 | (400 | ) | |||||
Net (Loss) Income | $ | (3,206 | ) | $ | $5,256 | |||
(Loss) Earnings Per Share | ||||||||
Basic (loss) earnings per share | $ | (0.10 | ) | $ | $0.17 | |||
Diluted (loss) earnings per share | $ | (0.10 | ) | $ | $0.16 |
5
TXCO RESOURCES INC.
Consolidated Statements Of Cash Flows
(Unaudited)
Six Months Ended | Six Months Ended | |||||||
(in thousands, except earnings per share data) | June 30, 2007 | June 30, 2006 | ||||||
Operating Activities | ||||||||
Net (loss) income | $ | (3,206 | ) | $ | $5,256 | |||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||
Depreciation, depletion and amortization | 13,754 | 6,475 | ||||||
Impairment, abandonments and dry hole costs | 1,836 | 1,094 | ||||||
Deferred tax expense (benefit) | 3,568 | (400 | ) | |||||
Loss on sale of asset | - | 11 | ||||||
Non-cash stock compensation expense | 571 | 616 | ||||||
Non-cash derivative mark-to-market loss | - | (468 | ) | |||||
Non-cash change in components of Other Comprehensive Income | 1,524 | - | ||||||
Changes in operating assets and liabilities: | ||||||||
Receivables | (5,897 | ) | 555 | |||||
Prepaid expenses and other | (4,752 | ) | (1,670 | ) | ||||
Accounts payable and accrued expenses | 5,615 | (1,569 | ) | |||||
Current income taxes (receivable) payable | (5,527 | ) | - | |||||
Net cash provided by operating activities | 7,486 | 9,900 | ||||||
Investing Activities | ||||||||
Development and purchases of oil and gas properties | (37,291 | ) | (18,632 | ) | ||||
Purchase of other equipment | (2,554 | ) | (4,894 | ) | ||||
Purchase of subsidiary | (95,994 | ) | - | |||||
Proceeds from sale of assets | - | 19 | ||||||
Net cash used by investing activities | (135,839 | ) | (23,507 | ) | ||||
Financing Activities | ||||||||
Proceeds from issuance of common stock, net of expenses | 407 | 30,233 | ||||||
Purchase of treasury shares | (219 | ) | - | |||||
Proceeds from bank credit facility | 154,100 | 9,300 | ||||||
Payments on bank credit facility | (22,851 | ) | (9,300 | ) | ||||
Proceeds from installment and other obligations | 119 | 178 | ||||||
Payments on installment and other obligations | (260 | ) | (211 | ) | ||||
Net cash provided by financing activities | 131,296 | 30,200 | ||||||
Change in Cash and Equivalents | 2,943 | 16,593 | ||||||
Cash and equivalents at beginning of period | 3,882 | 6,083 | ||||||
Cash and Equivalents at End of Period | $ | 6,825 | $ | $22,676 |
6
Notes To Consolidated Financial Statements
Periods Ended June 30, 2007, and June 30, 2006(Unaudited)
1. Basis of Presentation
The accompanying unaudited consolidated financial statements of TXCO Resources Inc. ("TXCO" or "the Company") have been prepared in accordance with U.S. generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. generally accepted accounting principles for complete financial statements. The accounting policies followed by the Company are set forth in Note A to the audited consolidated financial statements contained in the Company's Annual Report on Form 10-K for the year ended December 31, 2006.
In the opinion of management, all adjustments (consisting of normal recurring adjustments) considered necessary for a fair presentation have been included. Certain reclassifications have been made to the prior period to conform to current presentation. For further information, refer to the consolidated financial statements and footnotes thereto included in the Company's Annual Report on Form 10-K for the year ended December 31, 2006.
2. Stock-based Compensation
The Company has stock-based employee compensation plans that are described more fully in Note F, "Stockholders' Equity," to the audited consolidated financial statements contained in the Company's Annual Report on Form 10-K for the year ended December 31, 2006. Total stock-based compensation expense recognized was $571,000 and $616,000, in the first six months of 2007 and 2006, respectively.
Stock Options: In prior years, the Company issued stock options as compensation to employees and non-employee directors under its 1995 Flexible Incentive Plan. Generally, these options had a ten-year life and vested over two years for employees and three years for directors. Upon exercise, newly issued shares are utilized to fulfill the obligation. No options have been granted since 2004.
As of June 30, 2007, the Company had outstanding options to purchase 823,750 shares of common stock at prices ranging from $2.125 to $5.00 per share. The options expire at various dates through September 2014. Of these, 723,750 were exercisable at quarter end.
Stock Option Activity: | Number Outstanding | Weighted Average Exercise Price | Weighted Average Remaining Contractual Term | Aggregate Intrinsic Value | ||
1995 Flexible Incentive Plan:* | (in thousands) | (in years) | (in thousands) | |||
Outstanding at December 31, 2006 | 956 | $2.90 | 3.3 | $9,974 | ||
Exercised | 132 | 3.30 | ||||
Outstanding at June 30, 2007 ** | 824 | $2.85 | 2.7 | $6,120 | ||
Exercisable at June 30, 2007 | 724 | $2.95 | 2.9 | $5,304 |
* There have been no options awarded under the 2005 Stock Incentive Plan.
** 100,000 shares become exercisable upon attaining a stock price target of $15.00
Restricted Stock: During 2006 and 2007, the Company granted restricted stock as compensation to employees and non-employee directors under its 2005 Stock Incentive Plan. During 2007 shares with an aggregate fair value of $564,000 and a vesting term of one year were granted to non-employee directors, while shares with an aggregate fair value of $3.4 million and a three-year vesting period were granted to employees ($1.1 million aggregate fair value per year). The fair value is recognized as stock compensation expense (included in general and administrative expense on the Consolidated Statements of Operations) over the vesting periods.
7
2. Stock-based Compensation - continued
Restricted Stock Activity: | Shares | Weighted Average Grant Date Fair Value | ||
2005 Stock Incentive Plan: | (in thousands) | |||
Unvested restricted stock at December 31, 2006 | 330 | $9.01 | ||
Granted | 349 | 11.28 | ||
Vested | 130 | 8.97 | ||
Forfeited | 2 | 8.79 | ||
Unvested restricted stock at June 30, 2007 | 547 | $10.47 |
Warrants: Additionally, at June 30, 2007, the Company had outstanding exercisable warrants to purchase 766,500 shares of common stock at $4.25 per share. The warrants, which expire in May 2008, were issued as part of the private placement of 4.3 million shares in May 2004.
Stock Used to Acquire Goods or Services: During April 2007, the Company issued 338,983 shares of its common stock, with an aggregate fair value of $4.0 million, in a private placement as partial payment for its acquisition of Output Exploration LLC, a privately held, Houston-based exploration and production firm. See Note 8 "Output Acquisition" for additional information regarding this transaction.
3. Common Stock and Basic Income Per Share
The following is a reconciliation of the numerator and denominator of the basic and diluted earnings per share computation:
2007 | 2006 | ||||||||||||
(In thousands, except per share data) | Shares * | Income | Per Share Amount | Shares * | Income | Per Share Amount | |||||||
Three Months Ended June 30 | |||||||||||||
Basic EPS: | |||||||||||||
Net (loss) income | 33,496 | $ | (1,314 | ) | $ | (0.04 | ) | 32,921 | $ | 3,981 | $ | 0.12 | |
Effect of dilutive options | n/a** | - | 1,170 | - | - | ||||||||
Dilutive EPS | 33,496 | $ | (1,314 | ) | $ | (0.04 | ) | 34,091 | $ | 3,981 | $ | 0.12 | |
Six Months Ended June 30 | |||||||||||||
Basic EPS: | |||||||||||||
Net (loss) income | 33,242 | $ | (3,206 | ) | $ | (0.10 | ) | 31,340 | $ | 5,256 | $ | 0.17 | |
Effect of dilutive options | n/a** | - | 1,146 | - | 0.01 | ||||||||
Dilutive EPS | 33,242 | $ | (3,206 | ) | $ | (0.10 | ) | 32,486 | $ | 5,256 | $ | 0.16 |
* Weighted average shares outstanding ** Not applicable due to net loss for the period
4. Income Taxes
The Company recognizes deferred tax assets on differences in its basis for book and tax purposes. The Company's effective tax rate was 35.3% and 34.4% for the three- and six-month periods ended June 30, 2007, respectively. The comparable rates for the three- and six-month periods ended June 30, 2006, were 39.1% and 38.7%, respectively. The Company's effective tax rates have lowered due primarily to a change in the laws in the State of Texas.
In July 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109.” FIN 48 prescribes a comprehensive model for how companies should recognize, measure, present and disclose in their financial statements uncertain tax positions taken or expected to be taken on a tax return. Under FIN 48, tax positions are recognized in our consolidated financial statements as the largest amount of tax benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with tax authorities assuming full knowledge of the position and all relevant facts. These amounts are subsequently reevaluated and changes are recognized as adjustments to current period tax expense. FIN 48 also revised disclosure requirements to include an annual tabular rollforward of unrecognized tax benefits.
8
The Company adopted the provisions of FIN 48 on January 1, 2007. The adoption did not result in a material adjustment to its tax liability for unrecognized income tax benefits.
If applicable, we would recognize interest and penalties related to uncertain tax positions in interest expense. As of June 30, 2007, we had not accrued interest related to uncertain tax positions because we have no tax positions that we believe are uncertain. The tax years 2002-2006 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which we are subject.
5. Commodity Hedging Contracts and Activity
Due to the volatility of oil and natural gas prices, the Company, from time to time, enters into price-risk management transactions (e.g., swaps, collars and floors) for a portion of its oil and natural gas production. In certain cases, this allows it to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. When used, 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 may partially limit the Company's potential gains from future increases in prices. None of these instruments were 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 were considered derivative instruments and accounted for in accordance with SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." These derivative instruments were intended to hedge the Company's price risk and could 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 were recorded on the Consolidated Balance Sheets at fair value. The Company elected to account for certain of its derivative contracts as investments as set out under SFAS No. 133. Therefore, the changes in fair value in those contracts were recorded immediately as unrealized gains or losses on the Consolidated Statement of Operations. The change in fair value for the effective portion of contracts designated as cash flow hedges was reflected in Other Comprehensive Income (Loss) in the Stockholders' Equity section of the Consolidated Balance Sheets. The gain or loss in Other Comprehensive Income was reported on the Consolidated Statement of Operations as the hedged transactions occurred (November 2006 through April 2007). The hedges were highly effective, and therefore, no hedge ineffectiveness was recorded.
The Company had cash flow hedges in place during January through April of 2007, which have now expired. There were no outstanding hedges at June 30, 2007. TXCO expects to enter into derivative agreements this week to cover not less than 50% of the Company's and its subsidiaries' aggregate projected oil and gas production anticipated to be sold in the ordinary course of its business during the upcoming three-year period, in accordance with terms of our term loan and revolving credit facilities.
Comprehensive income includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. The components of comprehensive income are as follows for the three- and six-month periods ended June 30, 2007, and 2006:
Three Month Period | Six Month Period | |||||||||||
(in thousands) | 2007 | 2006 | 2007 | 2006 | ||||||||
Net (loss) income | $ | (1,314 | ) | $ | 3,981 | $ | (3,206 | ) | $ | 5,256 | ||
Other comprehensive income (loss): | ||||||||||||
Deferred hedge gain (loss) | 506 | (508 | ) | 1,845 | (933 | ) | ||||||
Income tax (expense) benefit of cash flow hedges | (187 | ) | 188 | (683 | ) | 357 | ||||||
Total comprehensive (loss) income | $ | (995 | ) | $ | 3,661 | $ | (2,044 | ) | $ | 4,680 |
9
Senior Credit Agreement -- At June 30, 2007, the Company had a $125 million senior revolving credit facility with the Bank of Montreal (the "SCA"). The SCA was entered into in April 2007 and expires in April 2011.
At June 30, 2007, the borrowing base was $60.0 million, $53.6 million was outstanding at an interest rate of 7.375% and the unused borrowing base was $6.4 million. The SCA is secured by a first-priority security interest in TXCO's and certain of its subsidiaries' proved oil and natural gas reserves and in the equity interests of such subsidiaries. In addition, TXCO's obligations under the SCA are guaranteed by such subsidiaries.
The SCA was amended on July 25, 2007, decreasing the borrowing base to $50.0 million and adding a requirement to hedge a portion of TXCO's projected oil and gas production. A portion of the funds received from the increase in the Term Loan Agreement (the "TLA," described below) was used to pay down the balance on the SCA. As of July 31, 2007, the balance outstanding under the SCA was $38.0 million with a weighted average interest rate of 7.41%.
Loans under the SCA are subject to floating rates of interest based on (1) the total amount outstanding under the SCA in relation to the borrowing base and (2) whether the loan is a LIBOR loan or a base rate loan. LIBOR loans bear interest at the LIBOR rate plus the applicable margin, and base rate loans bear interest at the base rate plus the applicable margin. The applicable margin varies with the ratio of total outstanding to the borrowing base. For base rate loans it ranges from zero to 100 basis points and for LIBOR rate loans it ranges from 150 to 250 basis points.
Under the amended SCA, TXCO is required to pay a commitment fee on the difference between amounts available under the borrowing base and amounts actually borrowed. The commitment fee is (1) 0.375%, so long as the ratio of amounts outstanding under the SCA to the borrowing base is less than 30%, and (2) 0.50%, in the event such ratio is 30% or greater. Borrowings under the SCA may be repaid and reborrowed from time to time without penalty.
Term Loan Agreement -- At June 30, 2007, the Company had an $80 million five-year term loan agreement with Bank of Montreal and certain other financial institutions party thereto with an interest rate of 9.875%.
Loans under the TLA are subject to floating rates of interest equal to, at TXCO’s option, the LIBOR rate plus 4.50% or the base rate plus 3.50%. The "LIBOR rate" and the base rate are calculated in the same manner as under the SCA.
The TLA was amended on July 25, 2007, increasing the principal amount to $100 million and extending the prepayment penalty date to July 25, 2008. The interest rate on the TLA remains at 9.875%.
Borrowings under the TLA may be repaid (but not reborrowed) subject to a prepayment premium equal to (i) 1.0%, if prepaid prior to July 25, 2008 and (ii) 0.0%, thereafter. Additionally, no prepayments are permitted if the ratio of the total amount outstanding under the SCA to the borrowing base thereunder exceeds 75% or if any default exists under the SCA.
Both the SCA and the TLA contain certain restrictive covenants which, among other things, limit the incurrence of additional debt, investments, liens, dividends, redemptions of capital stock, prepayments of indebtedness, asset dispositions, mergers and consolidations, transactions with affiliates, derivative contracts, sale leasebacks and other matters customarily restricted in such agreements. The amended SCA and TLA require TXCO and its subsidiaries to meet a maximum consolidated leverage ratio of 3.00 to 1.00, a minimum current assets to current liabilities ratio of 1.00 to 1.00, a minimum interest coverage ratio of 2.00 to 1.00 and a minimum net present value to consolidated total debt ratio of 1.50 to 1.00. Both agreements also contain customary events of default. The ratios are calculated on a quarterly basis. If an event of default occurs and is continuing, lenders with a majority of the aggregate outstanding term loans may require Bank of Montreal to declare all amounts outstanding under the SCA and TLA to be immediately due and payable.
10
8. | Output Acquisition |
On April 2, 2007, TXCO's acquisition of Output Exploration, LLC, a Delaware limited liability company ("Output"), was closed and became effective. Accordingly, the results of operations are consolidated in these financial statements since that date. Pursuant to the terms of the Agreement and Plan of Merger, dated as of February 20, 2007, as amended (the "Merger Agreement"), by and among TXCO, Output Acquisition Corp., a Texas corporation and wholly-owned subsidiary of TXCO ("Merger Sub"), and Output, Output merged with and into Merger Sub (the "Merger"), with Merger Sub continuing as the surviving corporation and a wholly-owned subsidiary of TXCO.
In connection with the Merger, TXCO paid to the holders of Output equity interests an aggregate of approximately $95.6 million, consisting of $91.6 million in cash and approximately 339,000 shares of TXCO common stock (the "Reserve Shares"). The Reserve Shares are being held by an escrow agent to be released to TXCO to the extent necessary to satisfy indemnity claims made by TXCO under the Merger Agreement during the one-year period following the Merger. Any Reserve Shares not released to TXCO will be liquidated by the escrow agent and the net proceeds paid to the holders of Output equity interests converted in the Merger.
BMO Capital Markets served as financial advisor to TXCO. The Merger was funded through borrowings under a new Senior Credit Agreement and Term Loan Agreement described in Item 1.01 of the Current Report on Form 8-K, that was filed with the SEC on April 5, 2007, and summarized in Note 7 hereto. Concurrent with the closing, TXCO elected to terminate all hedges assumed in the acquisition with a payment of $4.8 million
Management believes that one of the most attractive aspects of Output Exploration is the similarity of its Fort Trinidad Basin prospects to those in TXCO's core Maverick Basin operating area, allowing TXCO's technical and operations team to apply its knowledge of these formations to East Texas. The acquisition essentially doubles the Company's reserves and creates growth opportunities and greater exposure to the natural gas market.
The following table summarizes the final purchase price allocation to the acquired assets and liabilities based on their relative fair values:
Allocation of Purchase Price (in thousands) | ||||
Oil and gas properties: | Proved | $ | 114,235 | |
Unproved | 726 | |||
Pipeline equipment | 189 | |||
Other assets | 5,873 | |||
Total | $ | 121,023 |
The following unaudited pro forma data includes the results of operations as if the Output acquisition had been consummated on January 1, 2006. The unaudited pro forma results do not purport to represent what our results of operations actually would have been if this acquisition had been completed on such date or to project our results of operations for any future date or period.
Three Month Period | Six Month Period | |||||||||||
Pro Forma Income Statement Data (in thousands) | 2007 | 2006 | 2007 | 2006 | ||||||||
Revenues | $ | 22,336 | $ | 27,368 | $ | 50,737 | $ | 51,676 | ||||
(Loss) income from continuing operations, after pro forma provision for income taxes | $ | (1,314 | ) | $ | 3,182 | $ | (6,860 | ) | $ | 4,519 | ||
(Loss) income from continuing operations, per share: | ||||||||||||
Basic | $ | (0.04 | ) | $ | 0.10 | $ | (0.20 | ) | $ | 0.14 | ||
Diluted | $ | (0.04 | ) | $ | 0.09 | $ | (0.20 | ) | $ | 0.13 |
11
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Certain statements in this report that 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, and Management's Discussion and Analysis, as reported in its Form 10-K for the year ended December 31, 2006. See the "Disclosure Regarding Forward Looking Statements" section at the end of this Item 2.
Overview
Unless the context requires otherwise, when we refer to "TXCO", "the Company", "we", "us" or "our", we are describing TXCO Resources Inc. The following discussion of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and the notes thereto included in this Form 10-Q.
We are an independent oil and gas enterprise with interests primarily in the Maverick Basin, the onshore Gulf Coast region, the Marfa Basin of Texas and the Midcontinent region of western Oklahoma. We have a consistent record of long-term growth in proved oil and gas reserves, leasehold acreage position, production and cash flow through our established exploration, exploitation and development programs. Our 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. We account for our oil and gas operations under the successful efforts method of accounting and trade our common stock on Nasdaq's Global Select Market under the symbol "TXCO."
We currently have seven drilling rigs under contract and in operation on our Maverick Basin acreage, and one additional rig in another area. Our emphasis thus far this year has been on the Glen Rose and San Miguel formations. We began 34 new wells and 13 re-entries in the Maverick Basin through July 31, including 23 in the Glen Rose Porosity. Through July 31, 2007, we participated in one new well and two re-entries in the Williston Basin and six wells on acreage obtained in the Output Exploration acquisition, discussed below. Our revised 2007 capital expenditures budget ("CAPEX") calls for $85 million to $90 million to be invested in drilling operations. This includes funds for the drilling or re-entry of about 90 wells in the Maverick Basin (more than 35 in the Glen Rose Porosity), and about 30 wells in other areas, as well as funds for completion of a number of wells in progress at year-end 2006 and for infrastructure improvements. We believe the unused borrowing base on our revolving credit facility, along with our current working capital and positive cash flow from existing production and anticipated production increases from new drilling, will provide adequate capital to fund operating cash requirements and complete our scheduled exploration and development goals for 2007.
Due to the number of promising prospects on our Maverick Basin acreage, as well as high oil and gas prices, drilling activity has remained high during the last several years. (For further discussion of this activity, see "Principal Areas of Activity" and "Drilling Activity" in Part I, Item 1 of our Annual Report on Form 10-K for the year ended December 31, 2006). The resulting increased expenditures continue to translate into increased reserves as we establish adequate production history. Recognition of additional reserves on newly drilled wells requires a period of sustained production, causing a delay between the expenditures and the recognition of reserves.
On April 2, 2007, we closed on the acquisition of Output Exploration LLC ("Output"). Our second-quarter 2007 results include three months of Output's activity. This acquisition impacted many of our income statement and balance sheet accounts significantly, rendering comparisons to the prior year periods less meaningful. The acquisition nearly doubled our proved reserves and significantly increased our natural gas sales volumes. The consideration for the purchase was $91.6 million in cash, subject to certain adjustments, and $4.0 million of our common stock. Concurrent with the closing, we elected to terminate all hedges assumed in the acquisition with a payment of $4.8 million. BMO Capital Markets served as financial advisor to TXCO. See the "Bank Credit Facilities" section below for discussion of the related financing.
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Oil and gas sales revenues increased by 20.7% for second-quarter 2007, and 5.8% for first-half 2007, compared to the same periods of 2006. Sales volumes were up 35.6% and 21.0% on a thousand cubic feet equivalent ("mcfe"), for the same periods. Average realized prices for second-quarter 2007 were down $4.77 per barrel of oil ("bo") and up $0.41 per thousand cubic feet of natural gas ("mcf") compared to second-quarter 2006. Average realized prices for first-half 2007 were down $4.37 per bo and $0.15 per mcf compared with the same period last year. Total costs and expenses increased 70.0% for second-quarter 2007 and 36.4% for first-half 2007 compared with the prior year periods. Lease operating expenses increased by 126.7% for the quarter and 96.4% for the year-to-date period from the prior year periods. Depreciation, depletion and amortization increased by 139% for the second quarter and 113.8% for first-half 2007 compared with the prior year periods. These factors contributed to the net loss of $1.3 million and $3.2 million, for the three- and six-month periods ended June 30, 2007, respectively. In the prior year periods, we recorded net income of $4.0 million and $5.3 million, respectively.
Net cash provided by operating activities for first-half 2007 was $7.5 million, down from $9.9 million for the same period in 2006. Net cash provided by operating activities excluding changes in operating assets and liabilities was $18.0 million for first-half 2007, up from $12.6 million during the comparable 2006 period. In spite of higher non-cash charges in this period when compared with the comparable period from the prior year, we had higher cash flows than we did a year ago, excluding changes in working capital.
Three Months | Six Months | ||||||||
Operational Data for the periods ending June 30 | 2007 | 2006 | % Change | 2007 | 2006 | % Change | |||
Oil sales volumes (mbbls) | 241 | 208 | + | 15.8 | 392 | 346 | + | 13.5 | |
Gas sales volumes (mmcf) | 644 | 293 | + | 119.9 | 865 | 586 | + | 47.8 | |
Combined sales volumes (mmcfe) | 2,088 | 1,540 | + | 35.6 | 3,218 | 2,659 | + | 21.0 | |
Net residue and NGL sales volumes (mmbtu) | 341 | 395 | - | 13.5 | 608 | 1,047 | - | 41.9 | |
Oil average realized sales price bbl | $61.58 | $66.35 | - | 7.2 | $59.03 | $63.40 | - | 6.9 | |
Gas average realized sales price per mcf | $7.44 | $7.03 | + | 5.8 | $7.39 | $7.54 | - | 2.0 | |
Residue & NGL average realized sales price per mmbtu | $8.84 | $8.65 | + | 2.1 | $8.62 | $8.41 | + | 2.5 | |
Oil - average daily sales (bopd) | 2,644 | 2,284 | + | 15.8 | 2,166 | 1,909 | + | 13.5 | |
Gas - average daily sales (mcfd) | 7,082 | 3,221 | + | 119.9 | 4,781 | 3,236 | + | 47.8 | |
Combined average daily sales (mmcfed) | 22,947 | 16,928 | + | 35.6 | 17,778 | 14,689 | + | 21.0 |
As mentioned earlier the acquisition of Output had a significant impact on many of our income statement and balance sheet accounts. A list of some of the significant changes from first-quarter 2007 follows:
· | Net property and equipment were up 91.0%. |
· | Total assets were up 80.4%. |
· | Oil and gas revenues were up 119.3%, while related volumes were up 84.9% on a mcfe basis. |
· | Lease operating expenses were up 59.3%. |
· | Production taxes were up 123.1%. |
· | Depreciation, depletion and amortization were up 76.4%. |
· | General and administrative expenses were up 70.8%. |
· | Total costs and expenses were up 55.0%. |
· | Net loss was down 30.6%. |
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Liquidity is a measure of ability to access cash. Our primary needs for cash are for exploration, exploitation, development and acquisition of oil and gas properties, repayment of contractual obligations and working capital funding. We have historically addressed our long-term liquidity requirements through cash provided by operating activities, the issuance of debt and equity securities when market conditions permit, sale of non-strategic assets, and more recently through our credit facilities. 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. We continue to examine alternative sources of long-term capital, including bank borrowings, the issuance of debt instruments, the sale of common stock, the sales of strategic and non-strategic assets, and joint-venture financing. Availability of these sources of capital and, therefore, our ability to execute our operating strategy will depend upon a number of factors, some of which are beyond our control.
Bank Credit Facilities: In connection with our acquisition of Output, we replaced our credit facility with Guaranty Bank with the following two facilities. Both of these facilities were amended in July 2007, as described below.
Senior Credit Agreement -- At June 30, 2007, we had a $125 million senior revolving credit facility with the Bank of Montreal (the "SCA"). The SCA was entered into in April 2007 and expires in April 2011.
At June 30, 2007, the borrowing base was $60.0 million, $53.6 million was outstanding at an interest rate of 7.375% and the unused borrowing base was $6.4 million. The SCA is secured by a first-priority security interest in TXCO's and certain of its subsidiaries' proved oil and natural gas reserves and in the equity interests of such subsidiaries. In addition, TXCO’s obligations under the SCA are guaranteed by such subsidiaries.
The SCA was amended on July 25, 2007, decreasing the borrowing base to $50.0 million and adding a requirement to hedge a portion of our projected oil and gas production. A portion of the funds received from the increase in the Term Loan Agreement (the "TLA," described below) was used to pay down the balance on the SCA. As of July 31, 2007, the balance outstanding under the SCA was $38.0 million with a weighted average interest rate of 7.41%.
Loans under the SCA are subject to floating rates of interest based on (1) the total amount outstanding under the SCA in relation to the borrowing base and (2) whether the loan is a LIBOR loan or a base rate loan. LIBOR loans bear interest at the LIBOR rate plus the applicable margin, and base rate loans bear interest at the base rate plus the applicable margin. The applicable margin varies with the ratio of total outstanding to the borrowing base. For base rate loans it ranges from zero to 100 basis points and for LIBOR rate loans it ranges from 150 to 250 basis points.
Under the amended SCA, we are required to pay a commitment fee on the difference between amounts available under the borrowing base and amounts actually borrowed. The commitment fee is (1) 0.375%, so long as the ratio of amounts outstanding under the SCA to the borrowing base is less than 30%, and (2) 0.50%, in the event such ratio is 30% or greater. Borrowings under the SCA may be repaid and reborrowed from time to time without penalty.
Term Loan Agreement -- At June 30, 2007, we had an $80 million five-year term loan agreement with Bank of Montreal and certain other financial institutions party thereto with an interest rate of 9.875%.
Loans under the TLA are subject to floating rates of interest equal to, at our option, the LIBOR rate plus 4.50% or the base rate plus 3.50%. The "LIBOR rate" and the base rate are calculated in the same manner as under the SCA.
The TLA was amended on July 25, 2007, increasing the principal amount to $100 million and extending the prepayment penalty date to July 25, 2008. The interest rate on the TLA remains at 9.875%.
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Borrowings under the TLA may be repaid (but not reborrowed) subject to a prepayment premium equal to (i) 1.0%, if prepaid prior to July 25, 2008 and (ii) 0.0%, thereafter. Additionally, no prepayments are permitted if the ratio of the total amount outstanding under the SCA to the borrowing base thereunder exceeds 75% or if any default exists under the SCA.
Both the SCA and the TLA contain certain restrictive covenants which, among other things, limit the incurrence of additional debt, investments, liens, dividends, redemptions of capital stock, prepayments of indebtedness, asset dispositions, mergers and consolidations, transactions with affiliates, derivative contracts, sale leasebacks and other matters customarily restricted in such agreements. The amended SCA and TLA require TXCO and its subsidiaries to meet a maximum consolidated leverage ratio of 3.00 to 1.00, a minimum current assets to current liabilities ratio of 1.00 to 1.00, a minimum interest coverage ratio of 2.00 to 1.00 and a minimum net present value to consolidated total debt ratio of 1.50 to 1.00. Both agreements also contain customary events of default. The ratios are calculated on a quarterly basis. If an event of default occurs and is continuing, lenders with a majority of the aggregate outstanding term loans may require Bank of Montreal to declare all amounts outstanding under the SCA and TLA to be immediately due and payable.
Outlook: We believe the Bank Credit Facilities, along with our current working capital and positive cash flow from existing production and anticipated production increases from new drilling, will provide adequate capital to fund operating cash requirements and complete our scheduled exploration and development goals for 2007. We expect to further increase our borrowing base commensurate with the expected growth of our proved oil and gas reserves throughout the base term of the Bank Credit Facilities. Should product prices weaken, or expected new oil and gas production levels not be attained, the resulting reduction in projected revenues would cause us to re-evaluate our working capital options and would adversely affect our ability to carry out our current operating plans.
Risk Management Activities -- Commodity Hedging Contracts: Due to the volatility of oil and natural gas prices and requirements under our Bank Credit Facilities, we periodically enter into price-risk management transactions (e.g., swaps, collars and floors) for a portion of our oil and natural gas production. In certain cases, this allows us to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. These arrangements apply to only a portion of our production, and provide only partial price protection against declines in oil and natural gas prices, and may partially limit our potential gains from future increases in prices. None of these instruments are used for trading purposes. On a quarterly basis, management sets all of our 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 the Board of Directors. Our Board of Directors monitors our price-risk management policies and trades.
All of our price-risk management transactions were considered derivative instruments and accounted for in accordance with SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." When used, these derivative instruments are intended to hedge our 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 were recorded on the balance sheet at fair value. We elected to account for certain of our derivative contracts as investments as permitted under SFAS No. 133. Therefore, the changes in fair value in those contracts were recorded immediately as unrealized gains or losses on the Consolidated Statement of Operations. The change in fair value for the effective portion of contracts designated as cash flow hedges was recognized as Other Comprehensive Income (Loss) as a component in the Stockholders' Equity section of the Consolidated Balance Sheets, and was reclassified to income as the hedged transactions occurred (November 2006 through April 2007). The hedges were highly effective, and therefore, no hedge ineffectiveness was recorded.
There were no outstanding hedges at June 30, 2007. However, we expect to enter into derivative agreements in the near future in accordance with terms of our Bank Credit Facilities, as amended.
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Sources and Uses of Cash: At December 31, 2006, our cash reserves were $3.9 million. During first-half 2007, cash provided by operating activities was $7.5 million. In addition, borrowings under the bank credit facilities of $154.1 million, proceeds from installment obligations of $0.1 million, and proceeds from the exercise of options totaling $1.4 million, resulted in total cash available of $167.0 million for use in meeting our ongoing operational and development needs.
Payments on bank credit facilities during first-half 2007 totaled $22.9 million in principal, while payments on installment debt were $0.3 million, and interest payments on debt were $3.1 million. There were no federal income taxes paid during the second quarter. We applied $96.0 million for the purchase of Output and $37.3 million to fund the ongoing development of our oil and gas producing properties.
We ended first-half 2007 with positive working capital of $13.9 million, compared to $2.7 million at December 31, 2006 adjusted for the impact of the derivative liabilities on current liabilities. There were no derivative liabilities in current liabilities at June 30, 2007. At June 30, 2007, our current ratio was 1.66 to 1 compared to 1.17 to 1 at year-end 2006, with the same adjustment. At year-end 2006, including the $0.4 million of derivative current liabilities, working capital was $2.3 million, while the current ratio was 1.14 to 1.
We completed first-half 2007 with an unused borrowing base of $6.4 million under the Bank Credit Facilities. First-half 2007 net cash provided by operating activities was $7.5 million, compared to $9.9 million in first-half 2006. Before changes in operating assets and liabilities, first-half 2007 net cash provided by operating activities was $18.0 million compared to $12.6 million for the same 2006 period. Changes in operating assets and liabilities include increases or decreases in current receivables, payables and prepaid expenses from the prior year-end balances.
The following table highlights the change for 2007 from the comparable periods in 2006:
Selected Income Statement Items | Three Months | Six Months | |||||||
for the periods ending June 30 | $ thousands | % | $ thousands | % | |||||
Oil and gas revenues | + | 3,282 | + | 20.7 | + | 1,538 | + | 5.8 | |
Lease operating expense | + | 2,369 | + | 126.7 | + | 3,386 | + | 96.4 | |
Depreciation, depletion & amortization | + | 5,043 | + | 139.0 | + | 7,232 | + | 113.8 | |
Loss from operations | - | 6,036 | n/m | - | 11,432 | n/m | |||
Net loss | - | 5,295 | n/m | - | 8,462 | n/m |
n/m - % change not meaningful due to a move from income to loss for the period
The following table summarizes the change for 2007 from the comparable periods in 2006:
Change in Gas Gathering Results: | Three Months | Six Months | |||||||
for the periods ending June 30 | $ thousands | % | $ thousands | % | |||||
Gas gathering revenues | - | 526 | - | 14.3 | - | 3,572 | - | 38.8 | |
Gas gathering operations expense | - | 268 | - | 7.4 | - | 3,138 | - | 33.5 | |
Gross margin | - | 258 | - | 483.9 | + | 434 | + | 275.9 | |
Operational data: | |||||||||
Total sales volumes (mmbtu) | - | 53.4 | - | 13.5 | - | 438.4 | - | 41.9 | |
Average sales price ($ per mmbtu) | + | 0.18 | + | 2.1 | + | 0.21 | + | 2.5 |
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Three Months Ended June30, 2007, Compared with Three Months Ended June30, 2006:
Revenues
The 20.7% increase in oil and gas revenue is primarily due to the Output acquisition (32.2% of current revenue) along with higher average realized prices for natural gas and higher volumes for both products, partially offset by lower average realized prices for crude oil. Sales volumes increased 35.6% on a mcfe basis. Natural gas sales volumes were up 119.9% due to Output volumes, partially offset by reductions in Maverick Basin gas volumes reflecting normal maturing gas well decline curves and our emphasis on drilling oil wells this year. Oil sales volumes increased 15.8% primarily due to Glen Rose Porosity wells put on production since June 30, 2006. Excluding the impact of hedging, average realized sales prices for oil were down 7.2%, while those for natural gas were up 5.8%. Derivative losses of a non-cash nature reduced revenues by $0.5 million for second-quarter 2007, of which $0.4 million was a non-cash charge allocating the cost of the 2005 termination of gas hedges for transactions in this period. Prior year revenues were not impacted by hedging, since the derivatives in place for transactions in that time period were treated as investments.
Lease Operations ("LOE")
The 126.7% increase reflects costs related to wells acquired in the Output acquisition (39.2% of current LOE), as well as 56 oil wells and four gas wells placed on production since June 30, 2006, and increasing costs due to greater demand for third-party services in the field.
Exploration Expenses
The 42.2% increase primarily reflects higher dry hole costs, partially offset by lower delay rentals.
Gas Gathering
The 14.3% decrease in gas gathering revenues (and 7.4% decrease in related expenses) reflects lower volumes for third-party natural gas sales and lower transportation and other revenues. The impact was partially offset by higher natural gas liquids sales and realized prices on residue gas sales. Lower third-party natural gas sales volumes are coming through the system due to declining production on area leases and a partner's election to market its gas rather than sell it through TXCO.
Impairment
Impairment accruals increased 12.5% primarily due to impairment recorded on certain in-progress wells from prior periods.
Depreciation, Depletion and Amortization ("DD&A")
The 139.0% increase is due to the Output acquisition (28.9% of DD&A), higher finding costs, depletion rates and costs related to new wells placed on production over the last year.
General and Administrative ("G&A")
The $1.2 million increase was primarily due to the Output acquisition (30.8% of G&A) and higher salaries. G&A expense as a percentage of revenue increased to 13.8%, from 9.7% last year.
Excluding Output, salary-related costs were up $0.3 million related to accrual of year-end bonus and merit increases across the organization.
Derivative Gain / Loss
No mark-to-market ("MTM") or settlement gains or losses were recorded in second-quarter 2007 as the remaining hedges were designated as cash flow hedges. Settlements on cash flow hedges are reflected in revenues. Our hedges expired on April 30, 2007. For the MTM hedges in the prior year quarter -- a pre-tax hedging loss of $0.5 million was recorded, reflecting settlement costs partially offset by a MTM gain.
Interest Expense
The $2.8 million increase was due to our long-term financing related primarily to the Output acquisition.
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Six Months Ended June30, 2007, Compared with Six Months Ended June30, 2006:
Revenues
The 5.8% increase in oil and gas revenue is primarily due to the Output acquisition (22.1% of revenues) along with higher oil sales volumes, partially offset by non-cash losses on derivatives designated as cash flow hedges and lower average realized prices. Sales volumes increased 21.0% on a mcfe basis. Oil sales volumes increased 13.5% primarily due to Glen Rose Porosity wells put on production since June 30, 2006. Natural gas volumes were up 47.8%, reflecting volumes from Output properties partially offset by normal maturing gas well decline curves. Additionally, due to our current focus on drilling oil wells in the Maverick Basin, we are not replacing gas-specific reserves at the present time. Excluding the impact of hedging, average realized sales prices for oil were down 6.9%, while those for natural gas were down 2.0%. Derivative losses of a non-cash nature reduced revenues by $1.7 million for first-half 2007, of which $1.5 million was a non-cash charge allocating the cost of the 2005 termination of gas hedges for transactions in this period. Prior year revenues were not impacted by hedging, since the derivatives in place for transactions in that time period were mark-to-market hedges.
Lease Operations ("LOE")
The 96.4% increase reflects the Output acquisition (24.4% of LOE) and costs related to 56 oil wells and two gas wells placed on production since June 30, 2006, and increasing costs due to greater demand for third-party services in the field.
Exploration Expenses
The 2.2% increase primarily reflects higher dry hole costs, partially offset by lower delay rentals.
Gas Gathering
The 38.8% decrease in gas gathering revenues (and 33.5% decrease in related expenses) is primarily due to lower volumes for third-party natural gas sales. The impact was partially offset by higher realized prices on residue gas sales. Lower third-party natural gas sales volumes are coming through the system due to declining production on area leases and a partner's election to market its gas rather than sell it through TXCO.
Impairment
Impairment accruals increased 26.3% primarily due to impairment recorded on certain in-progress wells from prior periods.
Depreciation, Depletion and Amortization ("DD&A")
Depreciation, depletion and amortization increased 113.8% due to the Output acquisition (18.4% of DD&A), higher finding costs, depletion rates and costs related to new wells placed on production over the last year.
General and Administrative ("G&A")
The $1.3 million increase was primarily due to the Output acquisition (19.4% of G&A), and higher salaries. G&A expense as a percentage of revenue increased to 14.6%, from 10.0% last year.
Excluding Output, salary-related costs were up $0.7 million related to accrual of year-end bonus, merit increases across the organization and a one-time adjustment upon the conversion to a bi-weekly payroll schedule.
Derivative Gain / Loss
No mark-to-market ("MTM") or settlement gains or losses were recorded in first-half 2007 as the hedges were designated as cash flow hedges. Settlements on cash flow hedges are reflected in revenues. Our hedges expired on April 30, 2007. For the MTM hedges in the prior year quarter, a pre-tax hedging loss of $1.1 million was recorded, primarily reflecting settlement costs.
Interest Expense
The $3.0 million increase was due to our long-term financing related to the Output acquisition.
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Drilling Activities
We drilled or participated in drilling 49 wells in the first six months of 2007. Of these wells, 41 were in the Maverick Basin, three were in the Williston Basin, and five were on Output holdings. At July 31, 2007, 29 of these wells were on production, 17 wells were in completion or being evaluated for recompletion, and two wells remained drilling, while one well was plugged and abandoned. Additionally, two wells that were in progress at year-end 2006 were placed on production in first-half 2007. We have focused primarily on the Glen Rose and San Miguel formations thus far in 2007. By comparison, we participated in 30 wells during first-half 2006. The following table shows net daily sales for the periods presented:
Quarter Ended | % Change from | |||||
Average net daily sales volumes : | June 30, 2007 | March 31, 2007 | June 30, 2006 | 1st Qtr 2007 | 2nd Qtr 2006 | |
Oil, bopd | 2,644 | 1,683 | 2,284 | 57.1 | 15.8 | |
Natural gas, mcfd | 7,082 | 2,454 | 3,221 | 188.6 | 119.9 | |
Oil equivalent, boed | 3,825 | 2,092 | 2,821 | 82.8 | 35.6 |
In July 2007, TXCO spud or re-entered seven wells, of which four target the Glen Rose formation, bringing total wells spud in 2007 to 56. As of July 31, 2007, two of the July 2007 spuds continued drilling, while five were in the completion phase. Additionally, one Oklahoma well spud prior to our acquisition began producing natural gas in July 2007.
Normal production declines were experienced on natural gas wells in first-half 2007 and only two new gas wells were put on production in the Maverick Basin to offset declines on maturing wells. Additionally, one gas well was put on production in late June on former Output acreage. Oil sales during first-half 2007 did not reach their potential for three major reasons:
· | heavy rains in our Maverick Basin operating area during the first half, |
· | impact of fourth-quarter 2006 drilling technique issues, and |
· | unscheduled third-party oil pipeline repairs. |
Maverick Basin
There are seven rigs under contract to facilitate drilling or re-entry of about 90 wells on our Maverick Basin acreage during 2007. The drilling rig we purchased in March 2006 was placed in service in January of this year and is being used primarily on wells in which TXCO has a 100% WI. During first-half 2007 we acquired two low-horsepower shallow rigs that are currently undergoing refurbishment and will be put into service late this year or early next year on shallow Maverick Basin targets.
Glen Rose Porosity - During first-half 2007, we drilled or re-entered 19 Porosity wells, up from 15 in the same period of 2006. Four additional Porosity wells were begun in July 2007. As of July 31, 2007, of the 23 total 2007 Porosity wells, 15 are on production, seven are in completion, and one continues drilling. Glen Rose Porosity average daily sales for second-quarter 2007 were 1,775 bopd, compared to 1,370 bopd for the prior quarter and 2,019 bopd for the comparable prior-year quarter. See the discussion above for causes of the decline in oil production from the prior year.
Glen Rose Porosity targets represent more than half of our 2007 CAPEX budget. We currently plan to drill or re-enter over 35 wells in the Porosity during 2007. We have engaged Schlumberger to conduct a comprehensive reservoir optimization study. The study is focused on multiple aspects of the GRP project, including the establishment of higher reserve levels, higher recovery rates, evaluating secondary recovery opportunities and overall operating efficiencies, and should be completed next spring.
Glen Rose Shoal/Reefs - During first-half 2007, we drilled three shoal and three reef wells. As of July 31, 2007, two are producing natural gas, one is in completion, while three are being evaluated for re-completion. Two wells targeting a Glen Rose reef or shoal were started in first-half 2006.
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Glen Rose average daily sales for second-quarter 2007, excluding Porosity production, were 1 bopd and 2.3 mmcfd, compared to 13 bopd and 2.2 mmcfd for the prior quarter and 26 bopd and 2.9 mmcfd for the prior-year quarter. We currently plan to drill 12 shoal/reef wells during 2007.
Georgetown - We started three Georgetown wells during first-half 2007. One of these wells is producing oil, while the other two are awaiting completion. A Georgetown well was spud during July and awaited completion at July 31. For comparison, we participated in two Georgetown wells in the comparable prior year period. Our 2007 CAPEX budget includes five Georgetown wells. Georgetown average daily sales for second-quarter 2007 were 18.0 bopd and 110mcfd, compared to 21.9 bopd and 111 mcfd for the prior quarter, and 40.1 bopd and 165 mcfd for the prior-year quarter.
San Miguel - San Miguel average daily sales for second-quarter 2007 were 219 bopd, compared to 215 bopd for the prior quarter, and 140 bopd for the prior-year quarter. We started 10 San Miguel wells during first-half 2007. As of July 31, 2007, six wells are producing oil, three are in completion and one was plugged and abandoned. Eight San Miguel wells were begun in the prior year period. Our CAPEX budget calls for 11 San Miguel wells in 2007.
San Miguel Oil Sands - The two-well cyclic steam pilot test of the Oil Sands formation with our partner, Pearl Exploration and Production Ltd., involves a steam injection, soak and production cyclical process designed to heat the oil (0 degree API gravity) and allow it to be produced. Both of the pilot wells are in the third steam injection cycle. Production rates as high as 48 bopd were achieved for short periods during the second production cycle. We hope to see higher production rates in the third production cycle for both wells that is expected to begin later in August. Oil produced from the project was sent to prospective refiners to establish a pricing differential. We have received a preliminary estimate that our heavy oil will receive about a $15 per barrel discount to West Texas Intermediate prices, comparable to prices for similar quality crudes produced elsewhere. Additional steam generation equipment is on order for the expansion of this pilot. We expect to drill three additional wells on this pilot later this year.
Drilling on a second pilot with 16 wells is scheduled to start later this year updip of the existing pilot. We expect the second pilot will accelerate the overall project and establishment of reserves. We have ordered steam generation equipment for this pilot that will probably arrive late this year or early next year. We are considering using fracture-assisted steamflood technology recovery ("FAST") methods with a few modifications to compare its results with the cyclical process used on the first pilot. TXCO has a 50% WI and serves as operator. We believe that our net interest in these oil sands amounts to roughly two to three billion barrels of total oil in place. Our CAPEX budget calls for 21 Oil Sands wells in 2007.
Heavy Oil - Separately, we have begun a shallow pilot in an area (100% WI) that our geologists and engineers estimate contains 100 million barrels of heavy (10- to 14-degree API gravity) oil at 100-300 feet in depth. Two parallel horizontal wells with 2,000 feet laterals have been drilled through the zone, as well as five adjacent vertical wells. Our engineers have ordered steam generation equipment to begin heating the formation in the new pilot. We hope to begin injecting steam in the fourth quarter this year. Costs incurred to date on this project are about $0.5 million.
Pearsall - The horizontal well (50%WI) drilled with our partner, EnCana Oil & Gas (USA) Inc., in the Maverick Basin's Pearsall formation is currently in completion. A second lateral was drilled after the drill pipe, motor and bit became stuck in the first lateral and could not be retrieved. This lateral will be fracture stimulated in four intervals. We hope to have it tested and on production by the end of the third quarter. This is the second well in an ongoing program by the partners targeting this gas resource play. Our CAPEX budget calls for up to three Pearsall wells to be drilled in 2007 with EnCana as operator.
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We are preparing to fracture the Simpson 1 well during the third quarter 2007. We are currently working to obtain landowner permission to install a tiltmeter array around the well prior to the fracture stimulation. This array will provide micro-seismic information on the direction and distance of the fracture, enabling us to determine the best drilling plan for a future horizontal well. Continental Resources Inc., our 50% partner in this acreage who serves as operator for the lease block, has elected to go non-consent on this fracture procedure. TXCO will initiate and monitor this fracture stimulation.
Output Properties
Operations are ongoing on former Output properties. Two new wells and four re-entries have been spudded since we acquired Output on April 2. Two of the re-entries came on production during second quarter 2007, including a sidetrack on South Marsh Island Block 281 (6.8% WI) that is producing 3,000 mcfd and 425 bopd, and one in Oklahoma (12% WI) that is producing natural gas. Additionally, one Oklahoma well (12%WI) spud before our acquisition was put on production for natural gas in July with a rate of 4.5 mmcfd. We expect this rate to increase after the well is fracture-stimulated. An offset well is currently drilling in which we will also have a 12% WI. Drilling continues on a new well targeting the Vinton Dome in Louisiana (55% WI). We expect to participate in about 30 wells this year on prospects acquired through Output.
We are now wrapping up land and title work and preparing locations to submit to our partners to drill horizontally in the undeveloped Glen Rose shoals that we have identified in the Fort Trinidad field in East Texas. We believe there are five shoals that can be drilled horizontally covering several thousand acres each. We plan to focus on the B-level shoal initially that currently has five vertical producing wells scattered across the lease block and expect drilling to start in September.
Disclosure Regarding Forward Looking Statements
Statements in this 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 forwarding-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 estimated financial results, or expected prices, production volumes, reserve levels and number of drilling locations, expected drilling plans, including the 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. These risks and uncertainties include: the costs and accidental risks inherent in exploring and developing new oil and natural gas reserves, the price for which such reserves and production can be sold, environmental concerns affecting the drilling of oil and natural gas wells, impairment of oil and gas properties due to depletion or other causes, the uncertainties inherent in estimating quantities of proved reserves and cash flows, as well as general market conditions, competition and pricing. Please refer to the "Risk Factors" section of our Form 10-K for the year ended December 31, 2006. This and all our previously filed documents are on file at the Securities and Exchange Commission and can be viewed on our Web site at www.txco.com. Copies of the filings are available from our Corporate Secretary without charge.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market risk represents the risk of loss that may impact the financial position, results of operations, or cash flows due to adverse changes in financial market prices, including interest rate risk, and other relevant market rate or price increases.
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We are exposed to market risk through interest rates related to our credit facility borrowing. Our credit facility borrowings are based on the LIBOR or prime rate plus an applicable margin and are used to assist in meeting our working capital needs. As of June 30, 2007, we had borrowings under our SCA of $53.6 million at a rate of 7.375% per annum. Assuming an increase in either the LIBOR or prime rate of interest of 100 basis points, interest expense would increase by approximately $536,000 per year. The interest rate on the amounts borrowed under the TLA is fixed at 9.875% per annum for the duration of the loan. The interest rate variability on all other debt would not have a material adverse effect on our financial position.
Our major market-risk exposure is the commodity pricing applicable to our oil and natural gas production. Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas. Prices have fluctuated significantly during the last five years and such volatility is expected to continue, and the range of such price movement is not predictable with any degree of certainty. In the normal course of business we periodically enter into hedging transactions, 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, we put in place natural gas and crude oil swaps for a portion of our 2005 through 2007 production. These derivatives expired on April 30, 2007. TXCO expects to enter into derivative agreements this week to cover not less than 50% of the Company's and its subsidiaries' aggregate projected oil and gas production anticipated to be sold in the ordinary course of its business during the upcoming three-year period, in accordance with terms of our term loan and revolving credit facilities. Please refer to Note 5 to the consolidated financial statements included herein for additional information.
For additional information, see also our Annual Report on Form 10-K for the year ended December 31, 2006, "Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk."
ITEM 4. CONTROLS AND PROCEDURES
The SEC has adopted rules requiring reporting companies to maintain disclosure controls and procedures to provide reasonable assurance that a registrant is able to record, process, summarize and report the information required in the registrant's quarterly and annual reports under the Securities Exchange Act of 1934 (the "Exchange Act"). While we believe that our existing disclosure controls and procedures have been effective to accomplish these objectives, we intend to continue to examine, refine and formalize our disclosure controls and procedures and to monitor ongoing developments in this area.
Based on their evaluation as of June 30, 2007, our chief executive officer and chief financial officer have concluded that our disclosure controls and procedures (as defined in Rule 13a-15(e) or 15d-15(e) under the Exchange Act) are effective to ensure that the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is: (1) recorded, processed, summarized and reported within the time periods as specified in the SEC's rules and forms, and (2) accumulated and communicated to our management, including our chief executive and chief financial officers, to allow timely decisions regarding required disclosure.
Except for the potential changes noted in the following paragraph relating to the Output acquisition, there have not been any changes in our internal control over financial reporting (as such term is defined in Rule 13a-15(f) or 15d-15(f) under the Exchange Act) during the fiscal quarter to which this report relates that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
In April 2007, we completed the acquisition of Output Exploration, LLC. We are in the process of transferring all accounting for the new acquisition to our headquarters and into our existing internal control processes. The integration will lead to changes in these controls in future fiscal periods but we do not expect these changes to materially affect our internal controls over financial reporting. Consistent with published guidance of the SEC, our management excluded the acquired companies from the scope of its assessment of internal control over financial reporting as of June 30, 2007. Total assets and total revenues from the acquisition represented approximately 40% and 19%, respectively, of the related consolidated financial statement amounts of TXCO as of the six months ended June 30, 2007.
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ITEM 1. LEGAL PROCEEDINGS
From time to time, we are involved in litigation arising out of our operations in the ordinary course of business. We maintain liability insurance, including product liability coverage, in amounts deemed adequate by management. To date, aggregate costs to us for claims, including product liability actions, have not been material. However, an uninsured or partially insured claim, or claim for which indemnification is not available, could have a material adverse effect on our financial condition or results of operations. We believe that there are no claims or litigation p, the outcome of which could have a material adverse effect on our financial position or results of operations. However, due to the inherent uncertainty of litigation, there can be no assurance that the resolution of any particular claim or proceeding will not have a material adverse effect on our results of operations for the fiscal period in which such resolution occurs.
ITEM 1A. RISK FACTORS
Please see the risk factors previously disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2006.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
On April 2, 2007, approximately 339,000 shares of TXCO's common stock were issued to the holders of equity interests in Output Exploration, LLC as part of the consideration for our acquisition of that entity. Such issuance was not registered under the Securities Act based on the exemption from registration under Section 4(2) of the Securities Act, or Regulation D thereunder, for transactions by an issuer not involving a public offering. See Note 8 to the financial statements included in this Form 10-Q for further information regarding the acquisition.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
On May 11, 2007, 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 2, 2007. 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.
1. Election of two Class C Directors to serve for three-year terms expiring in 2010:
Nominee | For | Withheld | |
Class C: | |||
Michael J. Pint | 29,229,210 | 192,985 | |
James E. Sigmon | 29,299,862 | 122,333 |
There were no changes in Directors of the Company. In addition to the foregoing, the terms of the following Directors of the Company continued after the Annual Meeting: Dennis B. Fitzpatrick (Class A), Jon Michael Muckleroy (Class A), Robert L. Foree (Class A), and Alan L. Edgar (Class B).
2. Proposal to approve the amendment to the Company's Restated Certificate of Incorporation to change the Company's name to "TXCO Resources Inc."
For | Against | Abstain | |
29,229,437 | 53,221 | 139,534 |
3. Proposal to amend the Company's Restated Certificate of Incorporation to increase the amount of authorized Common Stock to 100,000,000 shares.
For | Against | Abstain | |
26,072,101 | 3,173,000 | 177,090 |
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4. 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, 2007:
For | Against | Abstain | |
29,171,080 | 100,944 | 150,170 |
ITEM 5. OTHER INFORMATION
None
ITEM 6. EXHIBITS
a) | ||
b) | ||
c) | ||
d) | ||
e) |
SIGNATURES
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.
TXCO RESOURCES INC. | |
(Registrant) | |
/s/ P. Mark Stark | |
P. Mark Stark, | |
Chief Financial Officer |
Date: August 9, 2007
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