-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, TNI+kWlUqiv/ItNG25980MwDD1SEkSMT3KIbh94vgcAYFJp2NvHtIbPeXkYJNW5u V8dtOOYqFmdJXuURwo4U8Q== 0000912057-02-020197.txt : 20020514 0000912057-02-020197.hdr.sgml : 20020514 ACCESSION NUMBER: 0000912057-02-020197 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 20020331 FILED AS OF DATE: 20020514 FILER: COMPANY DATA: COMPANY CONFORMED NAME: EXCO RESOURCES INC CENTRAL INDEX KEY: 0000316300 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 741492779 STATE OF INCORPORATION: TX FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 000-09204 FILM NUMBER: 02646277 BUSINESS ADDRESS: STREET 1: 6500 GREENVILLE AVENUE STREET 2: SUITE 600 LB 17 CITY: DALLAS STATE: TX ZIP: 75231 BUSINESS PHONE: 2143682084 MAIL ADDRESS: STREET 1: 6500 GREENVILLE AVENUE STREET 2: SUITE 600 LB 17 CITY: DALLAS STATE: TX ZIP: 75231 10-Q 1 a2079796z10-q.txt 10-Q UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q /X/ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 2002 OR / / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _______ to _______ Commission File Number 0-9204 EXCO RESOURCES, INC. (Exact name of registrant as specified in its charter) TEXAS 74-1492779 (State of incorporation) (I.R.S. Employer Identification No.) 6500 GREENVILLE AVENUE SUITE 600, LB 17 DALLAS, TEXAS 75206 (Address of principal executive offices) (Zip Code) (214) 368-2084 (Registrant's telephone number, including area code) 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 /X/ NO / / The number of shares of common stock, par value $0.02 per share, outstanding at April 30, 2002 was 7,132,222 shares (excludes 65,662 treasury shares) EXCO RESOURCES, INC. INDEX
Page Number ------ PART I. FINANCIAL INFORMATION Item 1. FINANCIAL STATEMENTS (UNAUDITED).............................................................3 Condensed Consolidated Balance Sheets December 31, 2001 and March 31, 2002.........................................................3 Condensed Consolidated Statements of Operations Three Months Ended March 31, 2001 and 2002...................................................4 Condensed Consolidated Statements of Cash Flow Three Months Ended March 31, 2001 and 2002...................................................5 Condensed Consolidated Statements of Comprehensive Income Three Months Ended March 31, 2001 and 2002 ..................................................6 Notes to Condensed Consolidated Financial Statements.........................................7 Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS...............................................16 Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK...................................27 PART II. OTHER INFORMATION Item 5. OTHER INFORMATION...........................................................................30 Item 6. EXHIBITS AND REPORTS ON FORM 8-K............................................................31 Signatures....................................................................................................36 Index to Exhibits.............................................................................................37
PART I - FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS (UNAUDITED) EXCO RESOURCES, INC. CONDENSED CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE DATA)
(UNAUDITED) ------------ -------------- DECEMBER 31, MARCH 31, ------------ -------------- 2001 2002 ------------ -------------- ASSETS Current assets: Cash and cash equivalents...................................................... $ 1,856 $ 2,883 Accounts receivable: Oil and natural gas sales................................................. 6,151 6,012 Joint interest............................................................ 4,156 3,059 Interest and other........................................................ 3,563 2,929 Oil and natural gas hedge derivatives.......................................... 696 -- Other.......................................................................... 4,699 7,703 ------------ -------------- Total current assets................................................. 21,121 22,586 Oil and natural gas properties (full cost accounting method): Unproved oil and natural gas properties........................................ 6,647 5,741 Proved developed and undeveloped oil and natural gas properties................ 233,889 243,705 Allowance for depreciation, depletion and amortization......................... (75,701) (79,102) ------------ -------------- Oil and natural gas properties, net............................................ 164,835 170,344 Office and field equipment, net..................................................... 966 1,040 Deferred financing costs............................................................ 1,249 1,178 Other assets........................................................................ 2,885 2,885 ------------ -------------- Total assets......................................................... $ 191,056 $ 198,033 ============ ============== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable and accrued liabilities....................................... $ 11,008 $ 12,660 Revenues and royalties payable................................................. 2,186 2,329 Accrued interest payable....................................................... 128 66 Oil and natural gas hedge derivatives.......................................... -- 7,034 ------------ -------------- Total current liabilities............................................ 13,322 22,089 Long-term debt...................................................................... 44,994 51,945 Deferred abandonment................................................................ 1,466 1,606 Deferred income taxes............................................................... 10,895 10,883 Oil and natural gas hedge derivatives............................................... -- 434 Commitments and contingencies....................................................... -- -- Stockholders' equity: Preferred stock, $.01 par value: Authorized shares - 10,000,000 Issued and outstanding shares - 5,004,869 at December 31, 2001 and March 31, 2002................................... 101,175 101,175 Common stock, $.02 par value Authorized shares - 25,000,000 Issued and outstanding shares - 7,172,587 and 7,183,882 at December 31, 2001 and March 31, 2002, respectively..................... 143 144 Additional paid-in capital..................................................... 51,138 51,268 Notes receivable-employees..................................................... (1,117) (1,136) Deficit eliminated in quasi-reorganization..................................... (8,799) (8,799) Retained earnings (deficit) since December 31, 1997............................ (29,392) (28,635) Accumulated other comprehensive income......................................... 8,096 (2,100) Treasury stock, at cost: 67,446 and 65,662 shares at December 31, 2001 and March 31, 2002, respectively............................................. (865) (841) ------------ -------------- Total stockholders' equity........................................... 120,379 111,076 ------------ -------------- Total liabilities and stockholders' equity........................... $ 191,056 $ 198,033 ============ ==============
SEE ACCOMPANYING NOTES. 3 EXCO RESOURCES, INC. CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED, IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
THREE MONTHS ENDED MARCH 31, ----------------------------- 2001 2002 ------------ -------------- REVENUES: Oil and natural gas.......................................................... $ 13,479 $ 12,490 Other income................................................................. 184 2,158 ------------ -------------- Total revenues..................................................... 13,663 14,648 COSTS AND EXPENSES: Oil and natural gas production............................................... 5,036 6,410 Depreciation, depletion and amortization..................................... 2,087 3,792 General and administrative................................................... 943 1,872 Interest..................................................................... 896 508 ------------ -------------- Total costs and expenses........................................... 8,962 12,582 ------------ -------------- Income before income taxes........................................................ 4,701 2,066 Income tax expense................................................................ 1,739 -- ------------ -------------- Net income........................................................................ 2,962 2,066 Dividends on preferred stock...................................................... -- 1,314 ------------ -------------- Earnings on common stock.......................................................... $ 2,962 $ 752 ============ ============== Basic earnings per share.......................................................... $ .43 $ .10 ============ ============== Diluted earnings per share........................................................ $ .40 $ .10 ============ ============== Weighted average number of common and common equivalent shares outstanding: Basic........................................................................ 6,871 7,115 ============ ============== Diluted...................................................................... 7,381 7,545 ============ ==============
SEE ACCOMPANYING NOTES. 4 EXCO RESOURCES, INC. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOW (UNAUDITED, IN THOUSANDS)
THREE MONTHS ENDED MARCH 31, ----------------------------- 2001 2002 ------------ -------------- OPERATING ACTIVITIES: Net income ....................................................................... $ 2,962 $ 2,066 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization..................................... 2,087 3,792 Deferred income taxes........................................................ 770 -- Income from derivative ineffectiveness and terminated hedges................. -- (2,020) Other operating activities................................................... -- 1 ------------ -------------- Cash flow before changes in working capital....................................... 5,819 3,839 Effect of changes in: Accounts receivable..................................................... 148 1,870 Other current assets.................................................... 451 (3,004) Accounts payable and other current liabilities.......................... 320 1,733 ------------ -------------- Net cash provided by operating activities......................................... 6,738 4,438 INVESTING ACTIVITIES: Additions to oil and natural gas property and equipment........................... (22,703) (9,218) Other investing activities........................................................ (766) 29 ------------ -------------- Net cash used in investing activities............................................. (23,469) (9,189) FINANCING ACTIVITIES: Proceeds from long-term debt...................................................... 16,000 8,000 Payments on long-term debt........................................................ (2,386) (1,000) Proceeds from exercise of stock options........................................... 172 130 Preferred stock dividends......................................................... -- (1,314) Deferred financing costs.......................................................... (27) (66) Other financing activities........................................................ (73) (19) ------------ -------------- Net cash provided by financing activities......................................... 13,686 5,731 ------------ -------------- Net increase (decrease) in cash................................................... (3,045) 980 Effect of exchange rates on cash and cash equivalents............................. -- 47 Cash at beginning of period....................................................... 8,200 1,856 ------------ -------------- Cash at end of period............................................................. $ 5,155 $ 2,883 ============ ============== SUPPLEMENTAL CASH FLOW INFORMATION: Interest paid..................................................................... $ 933 $ 608 ============ ============== Income taxes paid................................................................. $ 2,582 $ -- ============ ==============
SEE ACCOMPANYING NOTES. 5 EXCO RESOURCES, INC. CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED, IN THOUSANDS)
THREE MONTHS ENDED MARCH 31, ----------------------------- 2001 2002 ------------ -------------- Net income ...................................................................... $ 2,962 $ 2,066 Other comprehensive income (loss): Foreign currency translation adjustments....................................... -- (12) Hedging activities: Cumulative effect of change in accounting principle at January 1, 2001...... (1,068) -- Effective changes in fair value............................................. 5,003 (7,580) Reclassification adjustments for settled contracts.......................... (2,696) (469) Amortization of terminated contracts........................................ -- (2,135) ------------ -------------- Total hedging activities....................................................... 1,239 (10,184) ------------ -------------- Total comprehensive income (loss)................................................ $ 4,201 $ (8,130) ============ ==============
SEE ACCOMPANYING NOTES. 6 EXCO RESOURCES, INC. NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS March 31, 2002 (Unaudited) 1. BASIS OF PRESENTATION In management's opinion, the accompanying consolidated financial statements contain all adjustments (consisting solely of normal recurring accruals) necessary to present fairly the financial position of EXCO Resources, Inc. as of December 31, 2001 and March 31, 2002, the results of operations and cash flows for the three month periods ended March 31, 2001 and 2002. We have prepared the accompanying unaudited financial statements pursuant to the rules and regulations of the Securities and Exchange Commission. We have omitted certain information and disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States pursuant to those rules and regulations, although we believe that the disclosures we have made are adequate to make the information presented not misleading. You should read these financial statements in conjunction with our financial statements and notes included in our Annual Report on Form 10-K for the year ended December 31, 2001. The accompanying condensed consolidated financial statements include the financial statements of EXCO Resources, Inc., and its subsidiaries. The financial statements of Pecos-Gomez, L.P., which ceased operations during 2001 with all remaining assets distributed to the partners, have been consolidated proportionally based on EXCO's aggregate ownership interest in the partnership. The results of operations for the three month period ended March 31, 2002, are not necessarily indicative of the results we expect for the full year. Certain prior year amounts have been reclassified to conform to current year presentation. 2. STOCK TRANSACTIONS On June 29, 2001, we closed our rights offering to existing shareholders that resulted in the sale of 5,004,869 shares of 5% convertible preferred stock at $21.00 per share. We raised a total of approximately $105.1 million in gross proceeds (approximately $101.2 million in net proceeds after fees and commissions), through the exercise of 4,466,869 rights and the sale of 538,000 shares of preferred stock by dealer managers. We applied approximately $97.6 million of the offering proceeds to payoff acquisition financing, and have used the remaining proceeds for general corporate purposes. Each share of 5% convertible preferred stock is convertible into one share of our common stock, at the option of the holder, on or before June 30, 2003. Any share of 5% convertible preferred stock still outstanding on June 30, 2003, will be automatically converted into our common stock. As part of the consideration paid for the acquisition of the Central Resources properties, we issued a warrant to Central Resources, Inc. to purchase 200,000 shares of our common stock for $11.00 per share. This warrant was assigned and then exercised by a new registered holder on May 21, 2001, for the full 200,000 shares at which time we received $2.2 million cash. We filed a registration statement on Form S-3 with the SEC to register the resale of the 200,000 7 shares of common stock issued upon the exercise of the warrant. The registration statement was declared effective by the SEC on October 15, 2001. 3. EARNINGS PER SHARE Statement of Financial Accounting Standards (SFAS) No. 128, "Earnings per Share", requires presentation of two calculations of earnings per common share. Basic earnings per common share equals net income less preferred stock dividends divided by weighted average common shares outstanding during the period. Diluted earnings per common share equals net income divided by the sum of weighted average common shares outstanding during the period plus any dilutive common stock equivalents. Common stock equivalents are shares assumed to be issued if (1) outstanding stock options or warrants were in-the-money and exercised, and (2) our outstanding convertible preferred stock was converted to common stock. For the three months ended March 31, 2002, employee and director stock options would have increased the diluted weighted average number of shares outstanding by 430,000 shares. The assumed conversion of the outstanding convertible preferred stock to common stock is considered to be anti-dilutive for the three month period ended March 31, 2002, and is therefore not included in the diluted earnings per share calculation.
THREE MONTHS ENDED MARCH 31, -------------- ---------------- 2001 2002 -------------- ---------------- (IN THOUSANDS) Weighted average number of basic shares outstanding................................. 6,871 7,115 Effects of: Employee and director stock options............................................ 310 430 Convertible preferred stock.................................................... -- -- Warrant........................................................................ 200 -- -------------- ---------------- Weighted average number of diluted shares outstanding............................... 7,381 7,545 ============== ================
4. OIL AND NATURAL GAS PROPERTIES We have recorded oil and natural gas properties at cost using the full cost method of accounting. Under the full cost method, all costs associated with the acquisition, exploration or development of oil and natural gas properties are capitalized as part of the full cost pool. Unproved oil and natural gas properties are excluded from the calculation of depreciation, depletion and amortization until it is determined whether or not proved reserves can be assigned to such properties. At December 31, 2001 and March 31, 2002, the $6.6 million and $5.7 million, respectively, in unproved oil and natural gas properties resulted from the allocation of the purchase price of Canadian properties to undeveloped acreage and to possible and probable reserves. We assess our unproved oil and natural gas properties on a quarterly basis. During the 8 three months ended March 31, 2002, we reclassified $903,000 from unproved oil and natural gas properties to proved developed and undeveloped oil and natural gas properties. Depreciation, depletion and amortization of evaluated oil and natural gas properties is provided using the unit-of-production method based on total proved reserves, as determined by independent petroleum reservoir engineers. Sales, dispositions and other oil and natural gas property retirements are accounted for as adjustments to the full cost pool, with no recognition of gain or loss unless the disposition would significantly alter the amortization rate. At the end of each quarterly period, the unamortized cost of oil and natural gas properties, net of related deferred income taxes, is limited to the sum of the estimated future net revenues from proved properties using current period-end prices discounted at 10%, adjusted for related income tax effects (ceiling test). This calculation is done separately for the United States and Canadian full cost pools. The calculation of the ceiling test is based upon estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, and plan of development. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision to the estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. 5. GEOGRAPHIC OPERATING SEGMENT INFORMATION We have operations in only one industry segment, that being the oil and natural gas exploration and production industry; however, we are organizationally structured along geographic operating segments. We have reportable operations in the United States and Canada. The following tables provide our interim geographic operating segment data. Operating segment data represents Canadian activity beginning April 26, 2001, when we acquired our Canadian subsidiary, Addison Energy Inc. Geographic operating segment income tax expenses have been determined based on statutory rates existing in the various tax jurisdictions where we have oil and natural gas producing activities. 9
THREE MONTHS ENDED THREE MONTHS ENDED MARCH 31, 2001 MARCH 31, 2002 -------------------------- ---------------------------- UNITED UNITED STATES CANADA STATES CANADA ------------ ------------ ------------ -------------- REVENUES: Oil and natural gas....................................$ 13,479 $ -- $ 8,097 $ 4,393 Other income........................................... 184 -- 2,158 -- ------------ ------------ ------------ -------------- Total revenues.................................... 13,663 -- 10,255 4,393 COSTS AND EXPENSES: Oil and natural gas production......................... 5,036 -- 4,455 1,955 Depreciation, depletion and amortization............... 2,087 -- 2,239 1,553 General and administrative............................. 943 -- 1,486 386 Interest............................................... 896 -- 98 410 ------------ ------------ ------------ -------------- Total costs and expenses.......................... 8,962 -- 8,278 4,304 ------------ ------------ ------------ -------------- Income before income taxes.................................. 4,701 -- 1,977 89 Income tax expense ......................................... 1,739 -- -- -- ------------ ------------ ------------ -------------- Net income .................................................$ 2,962 $ -- $ 1,977 $ 89 ============ ============ ============ ============== Total assets................................................$ 121,421 $ -- $ 106,358 $ 91,675 ============ ============ ============ ==============
6. CREDIT AGREEMENTS On December 18, 2001, as part of the financing of the acquisition of the PrimeWest properties, see "Note 8. Acquisitions - PrimeWest Properties Acquisition", we entered into restated U.S. and Canadian credit agreements. The U.S. credit agreement is with Bank One, NA, as administrative agent, BNP Paribas, as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and certain financial institutions as lenders. The Canadian credit agreement is with Bank One, NA, Canada Branch, as administrative agent, BNP Paribas (Canada), as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and certain financial institutions as lenders. The credit agreements mature on April 30, 2004. U.S. CREDIT AGREEMENT. At March 31, 2002, our restated U.S. credit agreement provided for borrowings of up to $124.0 million under a revolving credit facility with a borrowing base of $58.0 million. At March 31, 2002, we had approximately $10.5 million of outstanding indebtedness, letter of credit commitments of $310,000 and approximately $47.2 million available for borrowing under our U.S. credit agreement. The borrowing base was increased to $65.0 million effective as of April 26, 2002. The borrowing base is to be redetermined as of November 1, 2002, and each May 1 and November 1 thereafter. Borrowings under the credit agreement are secured by a first lien mortgage providing a security interest in 90% of our U.S. oil and natural gas properties. At our election, interest on borrowings may be either (i) the greater of the administrative agent's prime rate or the federal funds effective rate plus an applicable margin or (ii) LIBOR (London InterBank Offered Rate) plus an applicable margin. 10 CANADIAN CREDIT AGREEMENT. At March 31, 2002, our restated Canadian credit agreement provided for borrowings of up to U.S. $48.6 million under a revolving credit facility with a borrowing base of U.S. $45.0 million. At March 31, 2002, we had approximately U.S. $41.4 million of outstanding indebtedness and approximately $3.6 million available for borrowing under our Canadian credit agreement. Effective as of April 26, 2002, the Canadian credit agreement was amended to provide for borrowings of up to U.S. $157.5 million with a borrowing base of U.S. $75.0 million. The borrowing base is to be redetermined as of November 1, 2002, and each May 1 and November 1 thereafter. Borrowings under the credit agreement are secured by a first lien mortgage providing a security interest in 90% of our Canadian oil and natural gas properties. At our election, interest on borrowings may be either (i) the Canadian prime rate plus an applicable margin or (ii) the Banker's Acceptance rate plus an applicable margin. FINANCIAL COVENANTS AND RATIOS. The U.S. and the Canadian credit agreements contain certain financial covenants and other restrictions which require that we: - maintain a ratio of our consolidated current assets to consolidated current liabilities of at least 1.0 to 1.0 at the end of any fiscal quarter; - maintain a minimum consolidated tangible net worth of not less than $48.0 million (adjusted upward by 50% of quarterly net income and 75% of the net proceeds from the issuance of any equity securities after April 26, 2001); - not permit the ratio of consolidated debt to consolidated total capital to be greater than 65% at the end of each fiscal quarter; and - not permit the ratio of indebtedness to earnings before interest expense, state and federal taxes and depreciation, depletion and amortization expense to be more than 2.5 to 1.0 at the end of each fiscal quarter. Additionally, the credit agreements contain a number of other covenants regarding our liquidity and capital resources, including restrictions on our ability to incur additional indebtedness, restrictions on our ability to pledge assets, and prohibit the payment of dividends on our common stock. The U.S. credit agreement further required that we hedge at least 75% of our anticipated production from our U.S. proved developed producing reserves, within ten days of the time we entered into the agreement, for a period of up to 24 months. As of March 31, 2002, we were in compliance with the covenants contained in the U.S. and Canadian credit agreements. DIVIDEND RESTRICTIONS. We have not paid any cash dividends on our common stock, and do not anticipate paying cash dividends on our common stock in the foreseeable future. In addition, our credit agreements currently prohibit us from paying dividends on our common stock. If there is a default under our credit agreements, we will not be able to pay dividends on 11 the shares of our convertible preferred stock. Even if our credit agreements permitted us to pay cash dividends, we can make those payments only from our surplus (the excess of the fair value of our total assets over the sum of our liabilities plus our total paid-in share capital). In addition, we can pay cash dividends only if after paying those dividends we would be able to pay our liabilities as they become due. 7. COMMODITY DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES In connection with the incurrence of debt related to our acquisition activities and to protect against commodity price fluctuations, management has adopted a policy of hedging oil and natural gas prices through the use of commodity futures, options and swap agreements. Effective January 1, 2001, we adopted SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activity," which established accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results from the hedged item on the income statement. Companies must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. For derivatives classified as cash flow hedges, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings. The ineffective portion of any change in the fair value of a derivative designated as a hedge is immediately recognized in earnings. Hedge effectiveness is measured quarterly based on the change in relative fair value between the derivative contract and the hedged item over time. At adoption, we recognized a net derivative liability and a reduction in other comprehensive income of approximately $1.1 million as a cumulative effect of an accounting change for all cash flow hedges. Oil and natural gas revenues for the three months ended March 31, 2001 were decreased $1.4 million while oil and natural gas revenues for the three months ended March 31, 2002 were increased by $645,000 from the settlement of cash flow hedges. During the three months ended March 31, 2001, we recognized an increase in the net derivative asset and an associated increase in accumulated other comprehensive income totaling approximately $2.3 million. For the three months ended March 31, 2002, we recognized an increase in the net derivative liability and an associated decrease in other comprehensive income totaling approximately $8.2 million. During the three months ended March 31, 2002, we recognized $2.1 million in other income for income from derivative ineffectiveness and terminated hedges. There was no such income during the three months ended March 31, 2001. The following table sets forth our oil and natural gas hedging activities as of March 31, 2002. Our contracts are swap arrangements for the sale of oil and natural gas based on NYMEX pricing. The market values at March 31, 2002, are estimated from quotes from the counterparty and represent the amounts that we would expect to receive to terminate the agreements on March 31, 2002. The stated volumes and strike prices are for the remaining portions of the individual contracts at March 31, 2002. 12
NOTIONAL MARKET VALUE AT CONTRACT EFFECTIVE TERMINATION VOLUME/RANGE AGGREGATE MARCH 31, 2002 COMMODITY DATE (1) DATE DATE PER MONTH (2)(3) VOLUME (2) (3) STRIKE PRICE (4) - ---------------------------------------------------------------------------------------------------------------------------------- Oil 12/3/2001 1/1/2002 12/31/2002 60,000 Bbls - 562,000 Bbls $20.77 $ (2,793,000) 66,000 Bbls Natural Gas 12/4/2001 1/1/2002 12/31/2002 300,000 Mmbtus 2,750,000 $ 2.85 $ (1,634,000) 310,000 Mmbtus Mmbtus Natural Gas 12/7/2001 1/1/2002 12/31/2002 295,000 Mmbtus - 2,760,000 $ 2.80 $ (1,770,000) 319,000 Mmbtus Mmbtus Natural Gas 3/12/2002 5/1/2002 12/31/2002 150,000 Mmbtus 1,200,000 $3.165 $ (342,000) Mmbtus Natural Gas 3/12/2002 1/1/2003 12/31/2003 455,000 Mmbtus 5,460,000 $ 3.50 $ (929,000) Mmbtus
- ---------- (1)The counterparty to these contracts is BNP Paribas, a financial lending institution. (2)Bbls - Barrels. (3)Mmbtus - Million British thermal units. (4)On March 31, 2002, the average forward NYMEX oil price for the remainder of 2002 was $25.77 per Bbl, and the average forward NYMEX natural gas prices for the remainder of 2002 and for calendar 2003 were $3.45 per Mmbtu and $3.68 per Mmbtu, respectively. At March 31, 2002, we had approximately $6.9 million in other comprehensive income related to hedges that, as a result of the bankruptcy of Enron North America Corp., were terminated during 2001. This amount will be reclassified into other income as shown in the following table (in thousands):
AMOUNT ------------ DURING 2002: Quarter ending June 30, 2002.................................................... $ 1,649 Quarter ending September 30, 2002............................................... 1,599 Quarter ending December 31, 2002................................................ 1,593 ------------ Total........................................................................ $ 4,841 ============ DURING 2003: Quarter ending March 31, 2003................................................... $ 976 Quarter ending June 30, 2003.................................................... 631 Quarter ending September 30, 2003............................................... 464 ------------ Total........................................................................ $ 2,071 ============
8. ACQUISITIONS STB ENERGY PROPERTIES ACQUISITION In March 2001, we acquired from STB Energy, Inc. oil and natural gas properties located in Louisiana, Oklahoma, Texas and Nebraska. As of January 1, 2001, estimated total proved reserves net to our interest included 694,000 Bbls of oil and 9.5 Bcf of natural gas from 125 13 gross (78.3 net) wells. The purchase price consisted of $15.0 million in cash ($14.8 million after contractual adjustments). ADDISON ENERGY INC. ACQUISITION On April 26, 2001, we acquired all of the outstanding common stock of Addison Energy Inc., (Addison) which is headquartered in Calgary, Alberta, Canada. At the date of acquisition, Addison Energy Inc. owned interests in 95 gross (85.0 net) wells located in Alberta and Addison operated 91 of these wells. The Addison properties included approximately 27,672 gross and 23,994 net developed acres and approximately 38,947 gross and 28,795 net undeveloped acres. As of January 1, 2001, estimated total proved reserves net to our interest acquired in this acquisition included 2.1 million Bbls of oil and NGLs and 36.9 Bcf of natural gas. After adjustments for working capital and long-term debt, we paid approximately $44.4 million (Cdn $68.5 million) for Addison. We paid the adjusted purchase price from the proceeds of borrowings under our new U.S. and Canadian credit agreements, which were in turn paid off with the proceeds from the issue of our convertible preferred stock. PECOS-GOMEZ PROPERTIES ACQUISITION On July 3, 2001, Pecos-Gomez, L.P., of which we were the general partner (the Partnership) conveyed all of its oil and natural gas property interests in Pecos County, Texas, to its partners and began the process to dissolve the partnership. Also on July 3, 2001, we acquired additional interests in the properties from two of the limited partners for $8.8 million (approximately $7.5 million after contractual adjustments). In addition, we received an assignment of the existing Partnership hedge contract. Borrowings under the Partnership credit facility of $3.9 million were also repaid at the time of the acquisition and the credit facility was canceled. PRIMEWEST PROPERTIES ACQUISITION On December 18, 2001, Addison, our Canadian subsidiary, acquired oil and natural gas properties located in Alberta, Canada. As of December 31, 2001, total proved reserves net to our interest included approximately 3.6 million barrels of oil and NGLs, and 27.1 Bcf of natural gas. The effective date of this transaction was December 18, 2001. The purchase price was approximately $33.8 million or CDN $53.6 million cash ($33.6 million or CDN $53.3 million after contractual adjustments), funded with borrowings under our Canadian credit agreement. 14 PRO FORMA RESULTS OF OPERATIONS The following reflects the pro forma results of operations as though the acquisitions during 2001 of the STB Energy Properties, Addison Energy Inc. and the PrimeWest Properties, the related borrowings, and our 5% convertible preferred stock offering had been consummated on January 1, 2001.
THREE MONTHS ENDED MARCH 31, ------------------------------------ 2001 2002 ---------------- ---------------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Revenues............................................................... $ 23,485 $ 14,648 Earnings on common stock............................................... $ 5,112 $ 752 Earnings per share: Basic............................................................... $ 0.72 $ 0.10 Diluted............................................................. $ 0.51 $ 0.10
9. RECENTLY ISSUED ACCOUNTING STANDARDS SFAS No. 143, "Accounting for Asset Retirement Obligations," which was issued by the Financial Accounting Standards Board (FASB) in June 2001, requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. We are currently assessing the impact SFAS No. 143 will have on our financial position and results of operations. 10. SUBSEQUENT EVENT On April 29, 2002, Addison acquired oil and natural gas properties located in Alberta, Canada. As of January 1, 2002, estimated total proved reserves net to our interest included approximately 1.6 million barrels of oil and NGLs, and 19.5 Bcf of natural gas. Estimated daily production from the acquired properties, net to our interest, in December 2001 was approximately 570 barrels of oil and NGLs, and 4,200 Mcf of natural gas. The effective date of this transaction was January 1, 2002. The purchase price was approximately $25.8 million or CDN $40.5 million ($24.7 million or CDN $36.3 million after contractual adjustments), funded with borrowings under our U.S. and Canadian credit agreements. 15 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FORWARD-LOOKING STATEMENTS. The statements contained in this report regarding our future financial and operating performance and results, business strategy and market prices and future hedging activities, and other statements, including, in particular statements about our plans and forecasts that are not historical facts are forward-looking statements, as defined in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Among these forward-looking statements are statements regarding our anticipated performance in the year 2002, specifically statements relating to our production, production costs, depreciation, depletion and amortization expense, general and administrative expenses, interest expense, and capital expenditures. We have based these forward-looking statements on our current assumptions, expectations and projections about future events. We use the words "may," "will," "expect," "anticipate," "estimate," "believe," "continue," "intend," "plan," "budget," or other similar words to identify forward-looking statements. You should read statements that contain these words carefully because they discuss future expectations, contain projections of results of operations or of our financial conditions, and/or state other "forward-looking" information. We do not undertake any obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events, or otherwise. These statements are not guarantees of future performance and involve risks and uncertainties, that could cause our actual results to differ, perhaps materially, from our expectations in this report, including, but not limited to: - estimates of reserves; - market factors; - market prices (including regional basis differentials) of oil and natural gas; - results of future drilling; - marketing activity; - future production and costs; - and other factors discussed in this report and in our other SEC filings. We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. You are cautioned not to place undue reliance on a forward looking statement. When considering our forward-looking statements, keep in mind the risk factors and other cautionary statements in this quarterly report, and the risk factors in our Form 10-K for the year ended December 31, 2001. 16 Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for oil and natural gas. Declines in oil or natural gas prices may materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower oil or natural gas prices also may reduce the amount of oil or natural gas that we can produce economically. The valuations and estimated quantities of our oil and natural gas reserves at December 31, 2001, included in our Form 10-K for the year ended December 31, 2001 are based upon prices in effect at December 31, 2001. Current oil and natural gas prices have increased since that time. A decline in oil and/or natural gas prices, could have a material adverse effect on the estimated value and estimated quantities of our oil and natural gas reserves, our ability to fund our operations and our financial condition, cash flow, results of operations and access to capital. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. 2002 OUTLOOK The following discussion reflects our estimates and expectations for 2002, assuming we do not complete any acquisitions or divestitures (other than the Canadian acquisition completed on April 29, 2002) during 2002. This outlook could be materially impacted by any acquisition or disposition we might complete. COMMODITY PRICES During 2001, commodity prices declined from historically high levels at the beginning of the year to more moderate levels by year end. Our outlook for 2002 commodity prices is uncertain. Significant factors that will impact 2002 commodity prices include the current military activity and political unrest in the Middle East, the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations are able to manage oil supply through export quotas, and the overall North American natural gas supply and demand fundamentals. We will continue to moderate our debt levels, follow cost management measures and strategically hedge oil and natural gas price risk to mitigate the impact of price volatility on our oil, natural gas and NGLs sales. We will continue to review our hedge positions each time we make a material acquisition. As of March 31, 2002, we had a hedge in place covering 562,000 Bbls of our remaining 2002 oil production under a swap contract with a weighted average fixed price to be received of $20.77 per Bbl. In April 2002, we increased our 2002 commodity hedge positions by entering into a hedge covering 14,000 Bbls of oil per month with a fixed price to be received of $24.58 per Bbl covering the period May to December 2002. We have now hedged approximately 67-74% of our forecasted oil production for the remainder of 2002. In April 2002, we also entered into a hedge covering 40,000 Bbls of oil per month for all of 2003 with a fixed price to be received of $22.94 per Bbl. We also had hedges in place covering 6,710,000 Mmbtus of our remaining 2002 natural gas production under swap contracts with a weighted average fixed price to be received of $2.89 per Mmbtu. These hedges cover approximately 59-64% of our forecasted natural gas production for the remainder of 2002. We also had a hedge in place covering 455,000 Mmbtus of natural gas per month for all of 2003 with a fixed price to be 17 received of $3.50 per Mmbtu. Additionally, at March 31, 2002, we had approximately $6.9 million remaining in accumulated other comprehensive income related to our terminated hedge contracts with Enron North America. Of this amount, approximately $4.8 million will be reclassified into earnings during the remainder of 2002 and the balance of approximately $2.1 million will be reclassified into earnings in 2003. For more information regarding our hedging contracts, please review "Item 3 - Quantitative and Qualitative Disclosure About Market Risk". SECOND QUARTER 2002 Based on our current estimates, we expect that our second quarter production will be between 5.2 Bcfe and 5.6 Bcfe. We expect second quarter production costs, including production and ad valorem taxes, to average $1.25 to $1.35 per Mcfe. Depreciation, depletion and amortization expense is expected to be between $.80 and $.85 per Mcfe and general and administrative expense is expected to be between $1.9 million and $2.1 million during the second quarter of 2002. Our interest expense is expected to be between $750,000 and $850,000 during the second quarter of 2002. PRODUCTION GROWTH We currently forecast that our annual 2002 production will be between 23.0 Bcfe and 24.2 Bcfe. This estimate includes approximately 2.3 Bcfe to 2.8 Bcfe of production related to our Canadian acquisition which closed on April 29, 2002. ACQUISITIONS AND CAPITAL EXPENDITURES For 2002, we have budgeted up to $21 million for development efforts plus related facilities. Approximately 50% of our capital budget is allocated to the U.S. and approximately 50% is allocated to Canada. Our capital expenditures budget is based on an expected range of future oil, natural gas and NGL prices as well as the expected cost of the capital additions. Should our price expectations for our future production or rig availability change sufficiently, we may accelerate some projects or defer some projects and, consequently, may increase or decrease total 2002 and future capital expenditures. In addition, if the actual costs of the budgeted items vary significantly from the anticipated amounts, actual capital expenditures could vary materially from our estimates. We funded our April 2002 Canadian acquisition from borrowings under our current credit agreements. As a key element of our growth strategy, we are continuously evaluating and bidding upon potential acquisitions of properties and companies. Although we have completed several major property acquisitions in recent years, these transactions are opportunity driven. Thus, we do not budget, nor can we reasonably predict, the timing or size of any acquisitions we do not describe in this report. CRITICAL ACCOUNTING POLICIES We did not have any changes in our critical accounting policies or in our significant accounting estimates during the three months ended March 31, 2002. Please see our annual 18 report on Form 10-K for the year ended December 31, 2001 for a detailed discussion of our critical accounting policies. OUR RESULTS OF OPERATIONS The following tables present production and average unit prices and costs for the periods and for the geographic segments indicated:
THREE MONTHS ENDED MARCH 31, ------------------ 2001 2002 ------ ------ PRODUCTION: Oil (Mbbls) U.S.................................................................... 213 216 Canada................................................................. -- 72 ------ ------ Total.................................................................. 213 288 Natural gas (Mmcf) U.S.................................................................... 1,299 1,507 Canada................................................................. -- 1,123 ------ ------ Total.................................................................. 1,299 2,630 Natural gas liquids (Mbbls) U.S.................................................................... 22 18 Canada................................................................. -- 42 ------ ------ Total.................................................................. 22 60 Mmcfe U.S.................................................................... 2,709 2,909 Canada................................................................. -- 1,809 ------ ------ Total.................................................................. 2,709 4,718
THREE MONTHS ENDED MARCH 31, ------------------------------- 2001 2002 -------------- --------------- AVERAGE SALES PRICE (INCLUDING HEDGE SETTLEMENTS): Oil (Per Bbl) U.S. (1)............................................................... $ 27.81 $ 18.29 Canada................................................................. $ -- $ 19.62 Total (2).............................................................. $ 27.81 $ 18.63 Natural gas (Per Mcf) U.S. (3)............................................................... $ 5.38 $ 2.60 Canada................................................................. $ -- $ 2.19 Total (4).............................................................. $ 5.38 $ 2.42 Natural gas liquids (Per Bbl) U.S.................................................................... $ 25.98 $ 13.22 Canada................................................................. $ -- $ 12.15 Total.................................................................. $ 25.98 $ 12.47 Total oil and natural gas revenues (Per Mcfe) U.S.................................................................... $ 4.98 $ 2.78 Canada................................................................. $ -- $ 2.43 Total.................................................................. $ 4.98 $ 2.65
(1) Reflects the impact of monthly hedge settlements which increased the U.S. average oil price by $0.86 per Bbl for the three months ended March 31, 2001, and decreased the U.S. average oil price by $0.80 per Bbl for the three months ended March 31, 2002. (2) Reflects the impact of monthly hedge settlements which increased the total average oil price by $0.86 per Bbl for the three months ended March 31, 2001, and decreased the total average oil price by $0.59 per Bbl for the three months ended March 31, 2002. 19 (3) Reflects the impact of monthly hedge settlements which decreased the U.S. average natural gas price by $1.22 per Mcf for the three months ended March 31, 2001, and increased the U.S. average natural gas price by $0.55 per Mcf for the three months ended March 31, 2002. (4) Reflects the impact of monthly hedge settlements which decreased the total average natural gas price by $1.22 per Mcf for the three months ended March 31, 2001, and increased the total average natural gas price by $0.31 per Mcf for the three months ended March 31, 2002.
THREE MONTHS ENDED MARCH 31, ------------------------------ 2001 2002 ------------- --------------- EXPENSES (PER MCFE): Oil and natural gas production U.S...................................................................... $ 1.44 $ 1.22 Canada................................................................... $ -- $ 1.04 Total.................................................................... $ 1.44 $ 1.15 Production and ad valorem taxes U.S...................................................................... $ 0.42 $ 0.31 Canada................................................................... $ -- $ 0.04 Total.................................................................... $ 0.42 $ 0.21 General and administrative U.S...................................................................... $ 0.35 $ 0.51 Canada................................................................... $ -- $ 0.21 Total.................................................................... $ 0.35 $ 0.40 Depreciation, depletion and amortization U.S...................................................................... $ 0.77 $ 0.77 Canada................................................................... $ -- $ 0.86 Total.................................................................... $ 0.77 $ 0.80
COMPARISON OF THREE MONTHS ENDED MARCH 31, 2001 AND 2002 REVENUES. Our revenues from the sale of oil, natural gas and NGLs for the three months ended March 31, 2002, decreased by $1.0 million, or 7%, to $12.5 million from $13.5 million for the same period in 2001. This decrease in revenues is primarily attributable to lower prices received for oil, natural gas and NGLs. Our average oil, natural gas and NGLs prices include the effects of quality, gathering and transportation costs as well as the effect of monthly oil and natural gas hedge settlements. Our average oil price received during the three months ended March 31, 2002, was $18.63 per Bbl as compared to $27.81 per Bbl for the same period in 2001, which decreased revenue by $2.0 million. Our average natural gas price received during the three months ended March 31, 2002, was $2.42 per Mcf as compared to $5.38 per Mcf for the same period in 2001, which decreased revenue by $3.8 million. Our average NGLs price received during the three months ended March 31, 2002, was $12.47 per Bbl as compared to $25.98 per Bbl for the same period in 2001, which decreased revenue by $293,000. The decrease in revenue resulting from lower oil, natural gas and natural gas liquids prices was partially offset by increased production. Our production of oil, natural gas and natural gas liquids increased by 75,000 barrels, 1.33 Bcf, and 38,000 barrels, respectively, for the three months ended March 31, 2002 compared to the three months ended March 31, 2001. These increases are primarily attributable to our acquisitions of the STB Energy properties, completed in March 2001, Addison Energy Inc., completed in April 2001, and the PrimeWest properties, completed in December 2001. 20 Our other income for the three months ended March 31, 2002, was $2.2 million as compared to $184,000 for the same period in 2001. This income primarily consisted of income from derivative ineffectiveness and terminated hedges, interest income, salt water disposal income and well supervision fees. The increase in other income was primarily attributable to $2.1 million in non-cash income from derivative ineffectiveness and terminated hedges. COSTS AND EXPENSES. Our total costs and expenses for the three months ended March 31, 2002, increased by $3.6 million to $12.6 million from $9.0 million for the same period in 2001. This increase was mainly attributable to our acquisitions of the STB Energy properties, Addison Energy Inc. and the PrimeWest properties. Our oil and natural gas production costs for the three months ended March 31, 2002, increased $1.5 million, or 38%, to $5.4 million from $3.9 million in the same period in 2001. Our acquisitions of the STB Energy properties, Addison Energy Inc. and the PrimeWest properties increased oil and natural gas production costs by $2.1 million. This increase was partially offset by reduced oil and natural gas production costs on properties acquired in September 2000. Operating costs on these properties were unusually high during the three months ended March 31, 2001 as a result of workovers and equipment repairs relating to production enhancement projects on these acquired properties. Oil and natural gas production costs on a unit of production basis decreased $0.29 per Mcfe to $1.15 per Mcfe for the three months ended March 31, 2002 from $1.44 per Mcfe during the same period in 2001. This resulted from the reduced costs from the acquired properties, as discussed above, and to the lower costs, on a unit of production basis, of our Canadian properties, which were not included in our results until April 2001. Production and ad valorem taxes for the three months ended March 31, 2002, decreased by $129,000, or 12%, to $972,000 from $1.1 million for the same period last year. This decrease is primarily attributable to lower production taxes in the United States. These taxes are generally based upon the price received for production. As a result, production taxes paid on the significantly reduced prices received for production during the three months ended March 31, 2002 when compared to the three months ended March 31, 2001 more than offset production taxes paid on the increased production. There are no production taxes paid in Canada. Our depreciation, depletion and amortization costs for the three months ended March 31, 2002, increased by $1.7 million, or 81%, to $3.8 million from $2.1 million for the same period in 2001. Our acquisitions of the STB Energy properties, Addison Energy Inc., and the PrimeWest properties increased depreciation, depletion and amortization costs by $1.8 million. Our general and administrative costs for the three months ended March 31, 2002, increased by $957,000, or 101%, to $1.9 million from $943,000 for the same period in 2001. The increase in general and administrative costs was primarily attributable to legal costs incurred in pursuing our bankruptcy claim against Enron North America Corp. and our increased staffing needs as a result of our acquisitions of the STB Energy properties, Addison Energy Inc. and the PrimeWest properties. Our interest expense for the three months ended March 31, 2002, decreased to $508,000 from $896,000 for the same period in 2001 due primarily to lower average outstanding 21 borrowings during the three months ended March 31, 2002 when compared to the same period in 2001. For the three months ended March 31, 2002, we have not recorded any income tax expense. In Canada, our results of operations were approximately break even. In the U.S., it continues to be uncertain whether we will be able to utilize our net deferred tax asset. Accordingly, the tax effects of our U.S. generated income was offset by a reduction in our valuation allowance. Because of the deferred tax asset and resulting valuation allowance in the U.S., management expects tax expense on U.S. operations to be significantly reduced in the near future. NET INCOME. We had net income during the three months ended March 31, 2002 of $2.1 million or $0.10 per basic and diluted share. Substantially all of our net income during this period is attributable to the $2.1 million in other income resulting from the amortization of terminated hedges. This income is a non-cash item. For the three months ended March 31, 2001, we had net income of $3.0 million representing $0.43 per basic share and $0.40 per diluted share. LIQUIDITY AND CAPITAL RESOURCES GENERAL Most of our growth has resulted from recent acquisitions and the success of our development and exploitation program. Consistent with our strategy of acquiring and developing reserves, we have an objective of maintaining financing flexibility. In the past, we have utilized a variety of sources of capital to fund our acquisition, development and exploitation programs and to fund our operations. Our general financial strategy is to use a combination of cash flow from operations, bank financing and the sale or issuance of equity securities to fund our operations, conduct development and exploitation activities and to fund acquisitions. We do not have a set budget for acquisitions as these tend to be opportunity driven. Historically, we have used the proceeds from the issuance of equity securities and borrowings under our credit agreements to raise cash to fund acquisitions. We cannot assure you that funds will be available to us in the future to meet our budgeted capital spending or to fund acquisitions. Furthermore, our ability to borrow other than under our credit agreements is subject to restrictions imposed by our lenders. If we cannot secure additional funds for our planned development and exploitation activities or for future acquisitions, then we will be required to delay or reduce substantially these activities. During the three months ended March 31, 2002, we increased our long-term debt by 15% to approximately $51.9 million at March 31, 2002. We generated cash flow from operations before changes in working capital during the three months ended March 31, 2002 of approximately $3.8 million which helped fund our acquisition, development and exploitation activities. At March 31, 2002, our cash and cash equivalents balances increased 55% from December 31, 2001. Working capital at March 31, 2002 decreased significantly from December 31, 2001. This occurred primarily due to changes in the value of our outstanding hedge positions. As product prices at March 31, 2002 were higher than at December 31, 2001, the value of our hedges have changed from a net asset to a net liability. We also entered into new 22 hedge contracts in March 2002 for additional natural gas volumes to be delivered during the remainder of 2002 and in 2003 that also increased our net oil and natural gas hedge derivative liabilities. ACQUISITIONS AND CAPITAL EXPENDITURES During the three months ended March 31, 2002, we spent approximately $2.6 million on oil and natural gas property acquisitions. We have planned development and exploitation activities for our major operating areas. We have budgeted up to $21.0 million for our development and exploitation activities in 2002, of which $10.5 million is for the United States and $10.5 million is for Canada. Through March 31, 2002, we have spent $1.5 million in the United States and $4.2 million in Canada on these activities. As of March 31, 2002, we are contractually obligated to spend $4.2 million. In addition, we are continuing to evaluate oil and natural gas properties for future acquisitions. We expect to continue to utilize cash from operations as well as our available funds under our credit agreements to fund our acquisitions, capital expenditures and working capital during the remainder of 2002. We believe that our capital resources from existing cash balances, cash flow from operating activities and borrowing capacity under our credit agreements are adequate to meet the cash requirements of our business. However, future cash flows are subject to a number of variables including production volumes and oil and natural gas prices. If cash flows decline we would be required to reduce our capital expenditure budget which in turn may effect our production in future periods. We cannot assure you that operations and other capital resources will provide cash in sufficient amounts to maintain or initiate planned levels of capital expenditures. On April 29, 2002, Addison, our Canadian subsidiary purchased oil and natural gas assets totaling approximately $25.8 million (CDN $40.5 million) ($24.7 million or CDN $36.3 million after contractual adjustments). The transaction was funded with borrowings under our U.S. and Canadian credit agreements. CREDIT AGREEMENTS U.S. CREDIT AGREEMENT. At March 31, 2002, our restated U.S. credit agreement provided for borrowings of up to $124.0 million under a revolving credit facility with a borrowing base of $58.0 million. At March 31, 2002, we had $10.5 million of outstanding indebtedness, letter of credit commitments of $310,000 and approximately $47.2 million available for borrowing under our U.S. credit agreement. The borrowing base has been redetermined to be $65.0 million effective as of April 26, 2002. The borrowing base is to be redetermined as of November 1, 2002, and each May 1 and November 1 thereafter. The U.S. credit agreement contains certain financial covenants and other restrictions that require us to maintain a minimum consolidated tangible net worth as well as certain financial ratios. As of March 31, 2002, we were in compliance with the covenants contained in the U.S. credit agreement. Borrowings under the 23 credit agreement are secured by a first lien mortgage providing a security interest in 90% of our U.S. oil and natural gas properties. At our election, interest on borrowings may be (i) the greater of the administrative agent's prime rate or the federal funds effective rate plus an applicable margin or (ii) LIBOR (London InterBank Offered Rate) plus an applicable margin. At March 31, 2002, the six month LIBOR rate was 2.33%, which would result in an interest rate of approximately 3.33% on any new indebtedness we may incur under the U.S. credit agreement. CANADIAN CREDIT AGREEMENT. At March 31, 2002, our restated Canadian credit agreement provides for borrowings of up to $48.6 million under a revolving credit facility with a borrowing base of $45.0 million. At March 31, 2002, we had $41.4 million of outstanding indebtedness and approximately $3.6 million available for borrowing under our Canadian credit agreement. Effective as of April 26, 2002, the Canadian credit agreement was amended to provide for borrowings of up to $157.5 million with a borrowing base of $75.0 million. The borrowing base is to be redetermined as of November 1, 2002, and each May 1 and November 1 thereafter. The Canadian credit agreement contains certain financial covenants and other restrictions that require us to maintain a minimum consolidated tangible net worth as well as certain financial ratios. As of March 31, 2002, we were in compliance with the covenants contained in the Canadian credit agreement. Borrowings under the credit agreement are secured by a first lien mortgage providing a security interest in 90% of our Canadian oil and natural gas properties. At our election, interest on borrowings may be (i) the Canadian prime rate plus an applicable margin or (ii) the Banker's Acceptance rate plus an applicable margin. At March 31, 2002, the six month Banker's Acceptance rate was 2.77%, which would result in an interest rate of approximately 4.27% on any new indebtedness we incur under the Canadian credit agreement. During April 2002, we borrowed an additional $24.3 million to fund the acquisition of oil and natural gas properties and capital expenditures. This increased total outstanding borrowings to $66.5 million and reduced the amount available for borrowing under our Canadian credit agreement to $8.5 million. FINANCIAL COVENANTS AND RATIOS. The U.S. and Canadian credit agreements contain financial covenants and other restrictions which require that we: - maintain a ratio of our consolidated current assets to consolidated current liabilities of at least 1.0 to 1.0 at the end of any fiscal quarter; - maintain a minimum consolidated tangible net worth of not less that $48.0 million (adjusted upward by 50% of quarterly net income and 75% of the net proceeds from the issuance of any equity securities after April 26, 2001); - not permit the ratio of consolidated debt to consolidated total capital to be greater than 65% at the end of each fiscal quarter; and - not permit the ratio of indebtedness to earnings before interest expense, state and federal taxes and depreciation, depletion and amortization expense to be more than 2.5 to 1.0 at the end of each fiscal quarter. 24 Our current assets to current liabilities ratio as defined under our credit agreements was 4.9 to 1.0 at March 31, 2002. Our consolidated tangible net worth at March 31, 2002 as defined under our credit agreements was approximately $159.5 million, as compared to approximately $130.1 million required under our credit agreements. At March 31, 2002 our consolidated debt to consolidated total capital was 29% and our ratio of indebtedness to earnings before interest expense, state and federal taxes and depreciation, depletion and amortization expense was 1.7 to 1.0. DIVIDEND RESTRICTIONS. We have not paid any cash dividends on our common stock, and do not anticipate paying cash dividends on our common stock in the foreseeable future. In addition, our credit agreements currently prohibit us from paying dividends on our common stock. If there is a default under our credit agreements, we will not be able to pay dividends on the shares of convertible preferred stock. Even if our credit agreements permitted us to pay cash dividends, we can make those payments only from our surplus (the excess of the fair value of our total assets over the sum of our liabilities plus our total paid-in share capital). In addition, we can pay cash dividends only if after paying those dividends we would be able to pay our liabilities as they become due. We cannot assure you that we will have any surplus. CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS The following table presents a summary of our contractual obligations at March 31, 2002, with set and determinable payments:
PAYMENTS DUE BY PERIOD ---------------------------------------------------------------------------------- REMAINDER OF 2007 AND CONTRACTUAL OBLIGATIONS 2002 2003-2004 2005-2006 THEREAFTER TOTAL - ---------------------------------- ---------------- --------------- ---------------- --------------- ---------------- (IN THOUSANDS) Long-term debt.................. $ -- $ 51,945 $ -- $ -- $ 51,945 Operating leases................ 572 1,455 934 210 3,171 Drilling/work commitments....... 4,174 -- -- -- 4,174 Preferred stock dividends....... 3,941 2,628 -- -- 6,569 ---------------- --------------- ---------------- --------------- ---------------- Total contractual cash obligations $ 8,687 $ 56,028 $ 934 $ 210 $ 65,859 ================ =============== ================ =============== ================
We also have $310,000 in letters of credit that have been issued to various state regulatory agencies and all of which expire in 2002. See "Item 3 - Quantitative and Qualitative Disclosure About Market Risk," for discussion of our derivative positions. EFFECTS OF THE 5% CONVERTIBLE PREFERRED STOCK OFFERING On June 29, 2001, we sold 5,004,869 shares of 5% convertible preferred stock. We raised approximately $105.1 million in gross proceeds (approximately $101.2 million in net proceeds after fees and commissions). We applied approximately $97.6 million of the offering proceeds to payoff acquisition financing and used the remaining proceeds for general corporate purposes. 25 Dividends on our preferred stock, which are payable quarterly beginning September 30, 2001, are payable only in cash. Currently, the requirement for such dividend payments is approximately $1.3 million per quarter. The board declared a dividend on March 5, 2002, to shareholders of record as of March 15, 2002. The dividend was paid on March 29, 2002. Each share of our 5% convertible preferred stock is convertible into one share of our common stock on or before June 30, 2003. Any share of 5% convertible preferred stock that has not been converted into our common stock by June 30, 2003, will be automatically converted into our common stock on that date. COMMON STOCK During the three months ended March 31, 2002, employees exercised stock options on a total of 11,295 shares of our common stock resulting in proceeds to us of approximately $130,000. We have not paid any dividends on our common stock and we do not anticipate paying any cash dividends on our common stock in the foreseeable future. HEDGING TRANSACTIONS Our production is generally sold at prevailing market prices. However, we periodically enter into hedging transactions for a portion of our production when market conditions are deemed favorable and oil and natural gas prices exceed our minimum internal price targets. See the discussions in "Item 3 - Quantitative and Qualitative Disclosure About Market Risk." Our objective in entering into hedging transactions is to manage price fluctuations and achieve a more predictable cash flow associated with our acquisition activities and borrowings under our credit agreements. These transactions limit exposure to declines in prices, but also limit the benefits we would realize if prices increase. As of March 31, 2002, we had entered into the following swap contracts to hedge our natural gas and oil production under the following terms: - 619,000-769,000 Mmbtus per month from April 1, 2002 through December 31, 2002, - 455,000 Mmbtus per month from January 1, 2003 through December 31, 2003, and - 60,000-66,000 Bbls per month from April 1, 2002 through December 31, 2002. On April 5, 2002, we entered into an additional swap contract to hedge our oil production under the following terms: - 14,000 Bbls per month from May 1, 2002 through December 31, 2003 at $24.58 per barrel, and - 40,000 Bbls per month from January 1, 2003 through December 31, 2003 at $22.94 per barrel. 26 We may use derivative instruments to manage exposure to commodity prices, foreign currency and interest rate risks. Our objectives for holding derivatives are to minimize risks using the most effective methods to eliminate or reduce the impacts of these exposures. We occasionally enter into fixed-price physical delivery contracts as discussed above as well as commodity price swap derivatives to manage price risk with regard to a portion of our oil and natural gas production. Commodity price swap derivative contracts are designated as cash flow hedges. As a cash flow hedge, the effective portions of changes in the fair value of the derivative are recorded in other comprehensive income and are recognized in the statement of income when the associated production occurs and the resulting cash flows are reported as cash flows from operations. Ineffective portions of changes in the fair value of cash flow hedges are recognized as earnings. To qualify as a cash flow hedge, these swap contracts must be designated as cash flow hedges and changes in their fair value must correlate with changes in the price of anticipated future production such that our exposure to the effects of commodity price changes is reduced. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK Some of the information below contains forward-looking statements. The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term "market risk" refers to the risk of loss arising from adverse changes in oil and natural gas prices, and interest rates charged on borrowings and earned on cash equivalent investments. The disclosure is not meant to be a precise indicator of expected future losses, but rather an indicator of reasonably possible losses. This forward-looking information provides an indicator of how we view and manage our ongoing market risk exposures. Our market risk sensitive instruments were entered into for hedging purposes, not for trading purposes. COMMODITY PRICE RISK Our major market risk exposure is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices for natural gas. Pricing for oil and natural gas production is volatile. The following table sets forth our oil and natural gas hedging activities as of April 30, 2002. Our contracts are swap agreements for the sale of oil or natural gas based on NYMEX pricing. 27
OIL SWAPS NATURAL GAS SWAPS - ------------------------------------------------------- ------------------------------------------------------- 2002 CONTRACT VOLUMES WEIGHTED AVERAGE 2002 CONTRACT VOLUMES WEIGHTED AVERAGE PERIOD (BBLS) STRIKE PRICE PERIOD (MMBTUS) STRIKE PRICE - ------------------------------------------------------- ------------------------------------------------------- Second Quarter 224,000 $ 21.25 per Bbl Second Quarter 2,156,000 $ 2.87 per Mmbtu Third Quarter 228,000 $ 21.47 per Bbl Third Quarter 2,285,000 $ 2.89 per Mmbtu Fourth Quarter 222,000 $ 21.49 per Bbl Fourth Quarter 2,269,000 $ 2.89 per Mmbtu - ------------------------------------------------------- ------------------------------------------------------- 2003 CONTRACT VOLUMES WEIGHTED AVERAGE 2003 CONTRACT VOLUMES WEIGHTED AVERAGE PERIOD (BBLS) STRIKE PRICE PERIOD (MMBTUS) STRIKE PRICE - ------------------------------------------------------- ------------------------------------------------------- First Quarter 120,000 $ 22.94 per Bbl First Quarter 1,365,000 $ 3.50 per Mmbtu Second Quarter 120,000 $ 22.94 per Bbl Second Quarter 1,365,000 $ 3.50 per Mmbtu Third Quarter 120,000 $ 22.94 per Bbl Third Quarter 1,365,000 $ 3.50 per Mmbtu Fourth Quarter 120,000 $ 22.94 per Bbl Fourth Quarter 1,365,000 $ 3.50 per Mmbtu
Realized gains or losses from the settlement of the swaps are recorded in our financial statements as increases or decreases in oil and natural gas revenues. For example, using the oil swaps in place during the quarter ended March 31, 2002, if the settlement price exceeded the actual weighted average strike price of $20.77, then a reduction in oil revenues would have been recorded for the difference between the settlement price and $20.77 multiplied by the hedged volume of 199,000 Bbls. Conversely, if the settlement price was less than $20.77, then an increase in oil revenues would have been recorded for the difference between the settlement price and $20.77 multiplied by the hedged volume of 199,000 Bbls. For example, for a hedged volume of 199,000 Bbls, if the settlement price was $21.77, then oil revenues would have decreased by $199,000. Conversely, if the settlement price was $19.77, oil revenues would have increased by $199,000. We report average oil, natural gas and NGLs prices including the effects of quality, gathering and transportation costs as well as the net effect of monthly oil and natural gas hedge settlements. The following table sets forth our oil, natural gas and NGL prices, both realized before monthly hedge settlements and realized including monthly hedge settlements and the net effects of the monthly settlements of our oil and natural gas price hedges on revenue.
THREE MONTHS ENDED MARCH 31, ------------------------------------ 2001 2002 ----------------- ----------------- (IN THOUSANDS, EXCEPT PER UNIT DATA) Average price per Bbl of oil - realized before monthly hedge settlements............$ 26.95 $ 19.22 Average price per Bbl of oil - realized including monthly hedge settlements......... 27.81 18.63 Average price per Bbl of NGLs - realized before monthly hedge settlements........... 25.98 12.47 Average price per Bbl of NGLs - realized including monthly hedge settlements........ 25.98 12.47 Average price per Mcf of natural gas - realized before monthly hedge settlements.... 6.60 2.11 Average price per Mcf of natural gas - realized including monthly hedge settlements. 5.98 2.42 Increase (reduction) in revenue from monthly hedge settlements......................$ (1,402) $ 645
INTEREST RATE RISK At March 31, 2002, our exposure to interest rates related primarily to borrowings under our credit agreements and interest earned on short-term investments. As of March 31, 2002, we were not using any derivatives to manage interest rate risk. Interest is payable on borrowings under the credit agreements based on a floating rate as more fully described in "Item 2. 28 Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources." If short-term interest rates would have averaged 1% higher during the three months ended March 31, 2002, our interest expense would have increased by approximately $121,000. This amount was determined by applying the hypothetical interest rate change of 1% to our outstanding borrowings under the credit agreements during the three months ended March 31, 2002. FOREIGN CURRENCY EXCHANGE RATE RISK We account for a significant portion of our business in Canadian dollars. We are therefore subject to foreign currency exchange rate risk on cash flows of our Canadian operations that are not denominated in Canadian dollars. Presently, a significant portion of the sales of our Canadian oil and natural gas is denominated in U.S. dollars. Foreign currency exchange gains and/or losses related to these transactions have not been significant. The borrowings under our Canadian credit facility are denominated in Canadian dollars. The asset and liability balances of our Canadian business are translated monthly using current exchange rates, with any resulting unrealized translation gains or losses included in other comprehensive income. 29 PART II - OTHER INFORMATION ITEM 5. OTHER INFORMATION SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS We held our Annual Meeting of Shareholders on April 25, 2002, at which meeting the shareholders of our common stock and our convertible preferred stock considered the following: (1) the election of eight directors to hold office until the next Annual Meeting of Shareholders or until their successors have been duly qualified and elected, (2) an amendment to the EXCO Resources, Inc. 1998 Stock Option Plan to increase the number of shares of common stock authorized for option grants from 2,200,000 to 3,500,000 and to ratify and confirm options previously granted by the Board of Directors and not yet approved by the shareholders, and (3) the ratification of the appointment of Ernst & Young LLP as our independent auditors. Douglas H. Miller was elected as a director and received 8,187,889 votes for his election, with 25,353 votes withheld. T. W. Eubank was elected as a director and received 8,187,889 votes for his election, with 25,353 votes withheld. J. Douglas Ramsey was elected as a director and received 8,187,889 votes for his election, with 25,353 votes withheld. Jeffrey D. Benjamin was elected as a director and received 8,203,549 votes for his election, with 9,693 votes withheld. Earl E. Ellis was elected as a director and received 8,203,549 votes for his election, with 9,693 votes withheld. J. Michael Muckleroy was elected as a director and received 8,187,989 votes for his election, with 25,253 votes withheld. Boone Pickens was elected as a director and received 8,203,549 votes for his election, with 9,693 votes withheld. Stephen F. Smith was elected as a director and received 8,203,749 votes for his election, with 9,493 votes withheld. The proposal to amend the EXCO Resources, Inc. 1998 Stock Option Plan to increase the number of shares of common stock authorized for option grants from 2,200,000 to 3,500,000 shares and to ratify and confirm all of the options heretofore granted by the Board of Directors was approved with 5,356,723 votes in favor of approval, 763,015 votes against and 2,281 votes abstained. The proposal to ratify the appointment of Ernst & Young LLP as our independent auditors was approved with 8,159,183 votes in favor of approval, 52,228 votes against and 1,831 votes abstained. 30 ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) THE FOLLOWING EXHIBITS ARE INCLUDED HEREIN: NO. DESCRIPTION OF EXHIBIT 2.1 Pre-Acquisition Agreement between EXCO Resources, Inc., and EXCO Resources Canada Inc., and Addison Energy, Inc., dated March 22, 2001, filed as an Exhibit to EXCO's Form 10-Q filed May 8, 2001 and incorporated by reference herein. 3.1 Restated Articles of Incorporation of EXCO filed as an Exhibit to EXCO's Form S-3/A filed June 2, 1998 and incorporated by reference herein. 3.2 Restated Bylaws of EXCO, as amended, filed as an Exhibit to EXCO's Form S-3/A filed June 2, 1998 and incorporated by reference herein. 4.1 Restated Articles of Incorporation of EXCO filed as an Exhibit to EXCO's Form S-3/A filed June 2, 1998 and incorporated by reference herein. 4.2 Restated Bylaws of EXCO, as amended, filed as an Exhibit to EXCO's Form S-3/A filed June 2, 1998 and incorporated by reference herein. 4.3 Specimen Stock Certificate for the Common Stock of EXCO filed as an Exhibit to EXCO's Pre-Effective Amendment No. 1 to Form S-2 filed on June 2, 1998 and incorporated by reference herein. 4.4 Credit Agreement among EXCO Resources, Inc. as borrower, and Bank One, NA and the institutions named herein as lenders, Bank One, NA, as administrative agent and Fleet National Bank, as syndication agent and BNP Paribas, as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated April 26, 2001, filed as an Exhibit to EXCO's Form 10-Q filed May 8, 2001 and incorporated by reference herein. 4.5 Credit Agreement among EXCO Resources Canada Inc. as borrower, and Bank One Canada and the institutions named herein as lenders, Bank One Canada, as administrative agent and BNP Paribas (Canada) as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated April 26, 2001, filed as an Exhibit to EXCO's Form 10-Q filed May 8, 2001 and incorporated by reference herein. 4.6 Statement of Designation for 5% Convertible Preferred Stock, dated June 21, 2001, filed as an Exhibit to EXCO's Form 8-K/A filed June 29, 2001 and incorporated by reference herein. 31 4.7 First Amendment to Credit Agreement among EXCO Resources Canada Inc. as borrower, and Bank One Canada and the institutions named herein as lenders, Bank One Canada, as administrative agent and BNP Paribas (Canada) as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated April 26, 2001, filed as an Exhibit to EXCO's Form 10-Q filed May 8, 2001 and incorporated by reference herein. 4.8 First Amendment to Credit Agreement among EXCO Resources, Inc. as borrower, and Bank One, NA and the institutions named herein as lenders, Bank One, NA, as administrative agent and Fleet National Bank, as syndication agent and BNP Paribas, as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated November 14, 2001, filed as an Exhibit to EXCO's Form 10-Q, dated November 14, 2001 and incorporated by reference herein. 4.9 Second Amendment to Credit Agreement among EXCO Resources Canada Inc. as borrower, and Bank One Canada and the institutions named herein as lenders, Bank One Canada, as administrative agent and BNP Paribas (Canada) as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated November 14, 2001, filed as an Exhibit to EXCO's Form 10-Q, dated November 14, 2001 and incorporated by reference herein. 4.10 Restated Credit Agreement among EXCO Resources, Inc. and EXCO Operating, LP, as borrowers, Bank One, NA, as administrative agent, BNP Paribas, as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated December 18, 2001, filed as an Exhibit to EXCO's Form 8-K filed January 2, 2002 and incorporated by reference herein. 4.11 Restated Credit Agreement among Addison Energy, Inc., as borrower, Bank One, NA, Canada Branch, as administrative agent, BNP Paribas (Canada), as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated December 18, 2001, filed as an Exhibit to EXCO's Form 8-K filed January 2, 2002 and incorporated by reference herein. 4.12 Amendment to Restated Credit Agreement among EXCO Resources, Inc. and EXCO Operating, LP, as borrowers, Bank One, NA, as administrative agent, BNP Paribas, as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated April 26, 2002 (filed herewith). 32 4.13 Amendment to Restated Credit Agreement among Addison Energy Inc., as borrower, Bank One, NA, Canada Branch, as administrative agent, BNP Paribas (Canada), as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated April 26, 2002 (filed herewith). 10.1* EXCO Resources, Inc. 1998 Stock Option Plan, filed as Appendix A to EXCO's Proxy Statement dated March 17, 1998 and incorporated by reference herein. 10.2* Amendment No. 1 to the EXCO Resources, Inc. 1998 Stock Option Plan, filed as Exhibit 10.10 to EXCO's Form 10-Q dated May 17, 1999 and incorporated by reference herein. 10.3* Amendment No. 2 to EXCO Resources, Inc. 1998 Stock Option Plan filed as Exhibit 4.6 to Form S-8 filed April 26, 2001 and incorporated by reference herein. 10.4* Amendment No. 3 to the EXCO Resources, Inc. 1998 Stock Option Plan filed as Exhibit 4.8 to Form S-8 filed May 10, 2002 and incorporated by reference herein. 10.5* EXCO Resources, Inc. 1998 Director Compensation Plan filed as Appendix D to EXCO's Proxy Statement dated March 16, 1999 and incorporated by reference herein. 10.6 Purchase and Sale Agreement between Central Resources, Inc., as seller, and EXCO Resources, Inc., as buyer, dated August 31, 2000, filed as an Exhibit to EXCO's Form 8-K filed October 2, 2000 and incorporated by reference herein. 10.7 Amended and Restated Credit Agreement among EXCO Resources, Inc., as borrower, Bank of America, N.A., as administrative agent, Bank One, Texas, N.A., as syndication agent and the financial institutions listed on Schedule I, dated September 22, 2000, filed as an Exhibit to EXCO's Form 8-K filed October 2, 2000 and incorporated by reference herein. 10.8 Warrant Agreement including Exhibit 3, the Form of Registration Rights Agreement among EXCO Resources, Inc., as issuer , and Central Resources, Inc., as registered holder, dated September 22, 2000, as Exhibit E to the Purchase and Sale Agreement between Central Resources, Inc., as seller, and EXCO Resources, Inc., as buyer, dated August 31, 2000, filed as an Exhibit to EXCO's Form 8-K filed October 2, 2000 and incorporated by reference herein. 33 10.9 Credit Agreement among EXCO Resources, Inc. as borrower, and Bank One, NA and the institutions named herein as lenders, Bank One, NA, as administrative agent and Fleet National Bank, as syndication agent and BNP Paribas, as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated April 26, 2001, filed as an Exhibit to EXCO's Form 10-Q filed May 8, 2001 and incorporated by reference herein. 10.10 Credit Agreement among EXCO Resources Canada Inc. as borrower, and Bank One Canada and the institutions named herein as lenders, Bank One Canada, as administrative agent and BNP Paribas (Canada) as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated April 26, 2001, filed as an Exhibit to EXCO's Form 10-Q filed May 8, 2001 and incorporated by reference herein. 10.11 First Amendment to Credit Agreement among EXCO Resources Canada Inc. as borrower, and Bank One Canada and the institutions named herein as lenders, Bank One Canada, as administrative agent and BNP Paribas (Canada) as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, filed as an Exhibit to EXCO's Form 10-Q filed May 8, 2001 and incorporated by reference herein. 10.12 First Amendment to Credit Agreement among EXCO Resources, Inc. as borrower, and Bank One, NA and the institutions named herein as lenders, Bank One, NA, as administrative agent and Fleet National Bank, as syndication agent and BNP Paribas, as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated November 14, 2001, filed as an Exhibit to EXCO's Form 10-Q filed November 14, 2001 and incorporated by reference herein. 10.13 Second Amendment to Credit Agreement among EXCO Resources Canada Inc. as borrower, and Bank One Canada and the institutions named herein as lenders, Bank One Canada, as administrative agent and BNP Paribas (Canada) as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated November 14, 2001, filed as an Exhibit to EXCO's Form 10-Q filed November 14, 2001 and incorporated by reference herein. 10.14 Agreement of Purchase and Sale among PrimeWest Energy Inc. and PrimeWest Oil and Gas Corp., as sellers, and Addison Energy Inc., as buyer, dated November 22, 2001, filed as an Exhibit to EXCO's Form 8-K filed January 2, 2002 and incorporated by reference herein. 10.15 Restated Credit Agreement among EXCO Resources, Inc. and EXCO Operating, LP, as borrowers, Bank One, NA, as administrative agent, BNP Paribas, as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated December 34 18, 2001, filed as an Exhibit to EXCO's Form 8-K filed January 2, 2002 and incorporated by reference herein. 10.16 Restated Credit Agreement among Addison Energy Inc., as borrower, Bank One, NA, Canada Branch, as administrative agent, BNP Paribas (Canada), as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated December 18, 2001, filed as an Exhibit to EXCO's Form 8-K filed January 2, 2002 and incorporated by reference herein. 10.17* Promissory Note dated September 15, 1998 by and between Douglas H. Miller, as maker, and EXCO Resources, Inc., as payee, filed as an Exhibit to Mr. Miller's Schedule 13 D/A filed September 23, 1998 and incorporated by reference herein. 10.18* Pledge Agreement dated September 15, 1998 by and between Douglas H. Miller, as pledgor, and EXCO Resources, Inc., as the secured party, filed as an Exhibit to Mr. Miller's Schedule 13 D/A filed September 23, 1998 and incorporated by reference herein. 10.19* Promissory Note dated November 29, 1999 by and between Douglas H. Miller, as maker, and EXCO Resources, Inc., as payee, filed as an Exhibit to Mr. Miller's Schedule 13 D/A filed February 11, 2002 and incorporated by reference herein. 10.20* Pledge Agreement dated November 29, 1999 by and between Douglas H. Miller, as pledgor, and EXCO Resources, Inc., as the secured party, filed as an Exhibit to Miller's Schedule 13 D/A filed February 11, 2002 and incorporated by reference herein. 10.21 Amendment to Restated Credit Agreement among EXCO Resources, Inc. and EXCO Operating, LP, as borrowers, Bank One, NA, as administrative agent, BNP Paribas, as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated April 26, 2002 (filed herewith). 10.22 Amendment to Restated Credit Agreement among Addison Energy Inc., as borrower, Bank One, NA, Canada Branch, as administrative agent, BNP Paribas (Canada), as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated April 26, 2002 (filed herewith). - ---------- *These exhibits are management contracts. 35 (b) REPORTS ON FORM 8-K Current report on Form 8-K dated December 18, 2001 filed January 2, 2002 pursuant to Item 2 and Item 7 reporting the acquisition of properties by Addison Energy Inc., a wholly owned subsidiary of EXCO Resources, Inc., from PrimeWest Energy Inc. and PrimeWest Oil and Gas Corp. and containing the PrimeWest Properties Purchase and Sale Agreement and Financial Statements. Current report on Form 8-K/A dated December 18, 2001 filed February 14, 2002 pursuant to Item 7 containing the PrimeWest Properties Financial Statements. SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed in its behalf by the undersigned thereunto duly authorized. EXCO RESOURCES, INC. (Registrant) Date: May 14, 2002 By: /s/ J. DOUGLAS RAMSEY ----------------------------------- J. Douglas Ramsey Vice President and Chief Financial Officer By: /s/ J. DAVID CHOISSER ----------------------------------- J. David Choisser Vice President and Chief Accounting Officer 36 INDEX TO EXHIBITS NO. DESCRIPTION OF EXHIBIT 2.1 Pre-Acquisition Agreement between EXCO Resources, Inc., and EXCO Resources Canada Inc., and Addison Energy, Inc., dated March 22, 2001, filed as an Exhibit to EXCO's Form 10-Q filed May 8, 2001 and incorporated by reference herein. 3.1 Restated Articles of Incorporation of EXCO filed as an Exhibit to EXCO's Form S-3/A filed June 2, 1998 and incorporated by reference herein. 3.2 Restated Bylaws of EXCO, as amended, filed as an Exhibit to EXCO's Form S-3/A filed June 2, 1998 and incorporated by reference herein. 4.1 Restated Articles of Incorporation of EXCO filed as an Exhibit to EXCO's Form S-3/A filed June 2, 1998 and incorporated by reference herein. 4.2 Restated Bylaws of EXCO, as amended, filed as an Exhibit to EXCO's Form S-3/A filed June 2, 1998 and incorporated by reference herein. 4.3 Specimen Stock Certificate for the Common Stock of EXCO filed as an Exhibit to EXCO's Pre-Effective Amendment No. 1 to Form S-2 filed on June 2, 1998 and incorporated by reference herein. 4.4 Credit Agreement among EXCO Resources, Inc. as borrower, and Bank One, NA and the institutions named herein as lenders, Bank One, NA, as administrative agent and Fleet National Bank, as syndication agent and BNP Paribas, as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated April 26, 2001, filed as an Exhibit to EXCO's Form 10-Q filed May 8, 2001 and incorporated by reference herein. 4.5 Credit Agreement among EXCO Resources Canada Inc. as borrower, and Bank One Canada and the institutions named herein as lenders, Bank One Canada, as administrative agent and BNP Paribas (Canada) as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated April 26, 2001, filed as an Exhibit to EXCO's Form 10-Q filed May 8, 2001 and incorporated by reference herein. 4.6 Statement of Designation for 5% Convertible Preferred Stock, dated June 21, 2001, filed as an Exhibit to EXCO's Form 8-K/A filed June 29, 2001 and incorporated by reference herein. 4.7 First Amendment to Credit Agreement among EXCO Resources Canada Inc. as borrower, and Bank One Canada and the institutions named herein as lenders, Bank One Canada, as administrative agent and BNP Paribas (Canada) 37 as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated April 26, 2001, filed as an Exhibit to EXCO's Form 10-Q filed May 8, 2001 and incorporated by reference herein. 4.8 First Amendment to Credit Agreement among EXCO Resources, Inc. as borrower, and Bank One, NA and the institutions named herein as lenders, Bank One, NA, as administrative agent and Fleet National Bank, as syndication agent and BNP Paribas, as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated November 14, 2001, filed as an Exhibit to EXCO's Form 10-Q, dated November 14, 2001 and incorporated by reference herein. 4.9 Second Amendment to Credit Agreement among EXCO Resources Canada Inc. as borrower, and Bank One Canada and the institutions named herein as lenders, Bank One Canada, as administrative agent and BNP Paribas (Canada) as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated November 14, 2001, filed as an Exhibit to EXCO's Form 10-Q, dated November 14, 2001 and incorporated by reference herein. 4.10 Restated Credit Agreement among EXCO Resources, Inc. and EXCO Operating, LP, as borrowers, Bank One, NA, as administrative agent, BNP Paribas, as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated December 18, 2001, filed as an Exhibit to EXCO's Form 8-K filed January 2, 2002 and incorporated by reference herein. 4.11 Restated Credit Agreement among Addison Energy, Inc., as borrower, Bank One, NA, Canada Branch, as administrative agent, BNP Paribas (Canada), as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated December 18, 2001, filed as an Exhibit to EXCO's Form 8-K filed January 2, 2002 and incorporated by reference herein. 4.12 Amendment to Restated Credit Agreement among EXCO Resources, Inc. and EXCO Operating, LP, as borrowers, Bank One, NA, as administrative agent, BNP Paribas, as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated April 26, 2002 (filed herewith). 4.13 Amendment to Restated Credit Agreement among Addison Energy Inc., as borrower, Bank One, NA, Canada Branch, as administrative agent, BNP Paribas (Canada), as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and 38 bookrunner, and the financial institutions which are or may become Lenders, dated April 26, 2002 (filed herewith). 10.1* EXCO Resources, Inc. 1998 Stock Option Plan, filed as Appendix A to EXCO's Proxy Statement dated March 17, 1998 and incorporated by reference herein. 10.2* Amendment No. 1 to the EXCO Resources, Inc. 1998 Stock Option Plan, filed as Exhibit 10.10 to EXCO's Form 10-Q dated May 17, 1999 and incorporated by reference herein. 10.3* Amendment No. 2 to EXCO Resources, Inc. 1998 Stock Option Plan filed as Exhibit 4.6 to Form S-8 filed April 26, 2001 and incorporated by reference herein. 10.4* Amendment No. 3 to the EXCO Resources, Inc. 1998 Stock Option Plan filed as exhibit 4.8 to Form S-8 filed May 10, 2002 and incorporated by reference herein. 10.5* EXCO Resources, Inc. 1998 Director Compensation Plan filed as Appendix D to EXCO's Proxy Statement dated March 16, 1999 and incorporated by reference herein. 10.6 Purchase and Sale Agreement between Central Resources, Inc., as seller, and EXCO Resources, Inc., as buyer, dated August 31, 2000, filed as an Exhibit to EXCO's Form 8-K filed October 2, 2000 and incorporated by reference herein. 10.7 Amended and Restated Credit Agreement among EXCO Resources, Inc., as borrower, Bank of America, N.A., as administrative agent, Bank One, Texas, N.A., as syndication agent and the financial institutions listed on Schedule I, dated September 22, 2000, filed as an Exhibit to EXCO's Form 8-K filed October 2, 2000 and incorporated by reference herein. 10.8 Warrant Agreement including Exhibit 3, the Form of Registration Rights Agreement among EXCO Resources, Inc., as issuer , and Central Resources, Inc., as registered holder, dated September 22, 2000, as Exhibit E to the Purchase and Sale Agreement between Central Resources, Inc., as seller, and EXCO Resources, Inc., as buyer, dated August 31, 2000, filed as an Exhibit to EXCO's Form 8-K filed October 2, 2000 and incorporated by reference herein. 10.9 Credit Agreement among EXCO Resources, Inc. as borrower, and Bank One, NA and the institutions named herein as lenders, Bank One, NA, as administrative agent and Fleet National Bank, as syndication agent and BNP Paribas, as documentation agent and Banc One Capital Markets, Inc. as lead 39 arranger and bookrunner, dated April 26, 2001, filed as an Exhibit to EXCO's Form 10-Q filed May 8, 2001 and incorporated by reference herein. 10.10 Credit Agreement among EXCO Resources Canada Inc. as borrower, and Bank One Canada and the institutions named herein as lenders, Bank One Canada, as administrative agent and BNP Paribas (Canada) as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated April 26, 2001, filed as an Exhibit to EXCO's Form 10-Q filed May 8, 2001 and incorporated by reference herein. 10.11 First Amendment to Credit Agreement among EXCO Resources Canada Inc. as borrower, and Bank One Canada and the institutions named herein as lenders, Bank One Canada, as administrative agent and BNP Paribas (Canada) as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, filed as an Exhibit to EXCO's Form 10-Q filed May 8, 2001 and incorporated by reference herein. 10.12 First Amendment to Credit Agreement among EXCO Resources, Inc. as borrower, and Bank One, NA and the institutions named herein as lenders, Bank One, NA, as administrative agent and Fleet National Bank, as syndication agent and BNP Paribas, as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated November 14, 2001, filed as an Exhibit to EXCO's Form 10-Q filed November 14, 2001 and incorporated by reference herein. 10.13 Second Amendment to Credit Agreement among EXCO Resources Canada Inc. as borrower, and Bank One Canada and the institutions named herein as lenders, Bank One Canada, as administrative agent and BNP Paribas (Canada) as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated November 14, 2001, filed as an Exhibit to EXCO's Form 10-Q filed November 14, 2001 and incorporated by reference herein. 10.14 Agreement of Purchase and Sale among PrimeWest Energy Inc. and PrimeWest Oil and Gas Corp., as sellers, and Addison Energy Inc., as buyer, dated November 22, 2001, filed as an Exhibit to EXCO's Form 8-K filed January 2, 2002 and incorporated by reference herein. 10.15 Restated Credit Agreement among EXCO Resources, Inc. and EXCO Operating, LP, as borrowers, Bank One, NA, as administrative agent, BNP Paribas, as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated December 18, 2001, filed as an Exhibit to EXCO's Form 8-K filed January 2, 2002 and incorporated by reference herein. 40 10.16 Restated Credit Agreement among Addison Energy Inc., as borrower, Bank One, NA, Canada Branch, as administrative agent, BNP Paribas (Canada), as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated December 18, 2001, filed as an Exhibit to EXCO's Form 8-K filed January 2, 2002 and incorporated by reference herein. 10.17* Promissory Note dated September 15, 1998 by and between Douglas H. Miller, as maker, and EXCO Resources, Inc., as payee, filed as an Exhibit to Mr. Miller's Schedule 13 D/A filed September 23, 1998 and incorporated by reference herein. 10.18* Pledge Agreement dated September 15, 1998 by and between Douglas H. Miller, as pledgor, and EXCO Resources, Inc., as the secured party, filed as an Exhibit to Mr. Miller's Schedule 13 D/A filed September 23, 1998 and incorporated by reference herein. 10.19* Promissory Note dated November 29, 1999 by and between Douglas H. Miller, as maker, and EXCO Resources, Inc., as payee, filed as an Exhibit to Mr. Miller's Schedule 13 D/A filed February 11, 2002 and incorporated by reference herein. 10.20* Pledge Agreement dated November 29, 1999 by and between Douglas H. Miller, as pledgor, and EXCO Resources, Inc., as the secured party, filed as an Exhibit to Miller's Schedule 13 D/A filed February 11, 2002 and incorporated by reference herein. 10.21 Amendment to Restated Credit Agreement among EXCO Resources, Inc. and EXCO Operating, LP, as borrowers, Bank One, NA, as administrative agent, BNP Paribas, as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated April 26, 2002 (filed herewith). 10.22 Amendment to Restated Credit Agreement among Addison Energy Inc., as borrower, Bank One, NA, Canada Branch, as administrative agent, BNP Paribas (Canada), as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated April 26, 2002 (filed herewith). - ---------- *These exhibits are management contracts. 41 EX-4.12 3 a2079796zex-4_12.txt EXHIBIT 4.12 Exhibits 4.12 And 10.21 AMENDMENT TO RESTATED CREDIT AGREEMENT THIS AMENDMENT TO RESTATED CREDIT AGREEMENT (hereinafter referred to as the "Amendment") executed as of the 26th day of April, 2002, by and between EXCO RESOURCES, INC., a Texas corporation ("EXCO") and EXCO OPERATING, LP, a Delaware limited partnership ("Operating") (EXCO and Operating are hereinafter collectively referred to as "Borrowers" and individually as a "Borrower") and BANK ONE, NA, a national banking association ("Bank One"), and each of the financial institutions which is a party thereto (as evidenced by the signature pages to the Agreement) or which may from time to time become a party hereto pursuant to the provisions of Section 28 thereof or any successor or assignee thereof (hereinafter collectively referred to as "Lenders", and individually, "Lender") and Bank One, as Administrative Agent (the "Agent") and BNP Paribas, as Syndication Agent, and The Bank of Nova Scotia, as Documentation Agent and Banc One Capital Markets, Inc., as Lead Arranger and Bookrunner ("Arranger"). WITNESSETH: WHEREAS, as of April 26, 2001, EXCO, as Borrower, the Lenders and the Agent entered into a Credit Agreement pursuant to which the Lenders made available to the Borrowers certain credit facilities in the form therein described; and WHEREAS, as of December 18, 2001, Borrowers, Lenders and Agent entered into a Restated Credit Agreement (the "Credit Agreement"); and WHEREAS, the Borrowers have requested that the Lenders agree to make certain additional amendments to the Credit Agreement and the Lenders, together with certain additional financial institutions who shall become a party to the Credit Agreement at the Amendment Effective Date (as hereinafter defined), have agreed to do so on the terms and conditions hereinafter set forth. NOW, THEREFORE, the parties agree to amend the Credit Agreement as follows: 1. Unless otherwise defined herein all defined terms used herein shall have the same meaning as ascribed to such terms in the Credit Agreement. 2. The Lenders have agreed among themselves to reallocate their respective Commitments and to allow Fleet National Bank and Toronto Dominion (Texas), Inc. to acquire an interest in the Commitments and the Loans. After such reallocation of the Commitments, the Lenders shall own the Revolving Commitment Percentages set forth on the signature pages hereto at the Amendment Effective Date. Each Lender shall surrender its existing Note and be issued a new Note in a face amount equal to each Lender's Revolving Commitment Percentage times $124,000,000. Each said Note to be in the form of Exhibit "B" to the Credit Agreement with appropriate insertions. 3. As of the Amendment Effective Date, the Borrowing Base shall be $65,000,000 until redetermined pursuant to the provisions of Section 7(b) of the Credit Agreement. 4. Except to the extent its provisions are specifically amended, modified or superseded by this Amendment, the representations, warranties and affirmative and negative covenants of the Borrowers contained in the Credit Agreement are incorporated herein by reference for all purposes as if copied herein in full. The Borrowers hereby restate and reaffirm each and every term and provision of the Credit Agreement, as amended, including, without limitation, all representations, warranties and affirmative and negative covenants. Except to the extent its provisions are specifically amended, modified or superseded by this Amendment, the Credit Agreement, as amended, and all terms and provisions thereof shall remain in full force and effect, and the same in all respects are confirmed and approved by the Borrowers and the Lenders. 5. This Amendment shall be effective as of the date first above written, but only upon the satisfaction of the conditions precedent set forth in Paragraph 6 hereof. 6. The obligations of Lenders under this Amendment shall be subject to the following conditions precedent: (a) EXECUTION AND DELIVERY. The Borrowers shall have executed and delivered this Amendment, and other required documents, all in form and substance satisfactory to the Agent; (b) REPRESENTATIONS AND WARRANTIES. The representations and warranties of the Borrowers under this Amendment are true and correct in all material respects as of such date, as if then made (except to the extent that such representations and warranties related solely to an earlier date); (c) NO EVENT OF DEFAULT. No Event of Default shall have occurred and be continuing nor shall any event have occurred or failed to occur which, with the passage of time or service of notice, or both, would constitute an Event of Default; (d) OTHER DOCUMENTS. The Agent shall have received such other instruments and documents incidental and appropriate to the transaction provided for herein as the Agent or its counsel may reasonably request, and all such documents shall be in form and substance satisfactory to the Agent; (e) LEGAL MATTERS SATISFACTORY. All legal matters incident to the consummation of the transactions contemplated hereby shall be reasonably satisfactory to special counsel for the Agent retained at the expense of Borrowers. 7. Borrowers hereby represent and warrant that all factual information heretofore and contemporaneously furnished by or on behalf of Borrowers to Agent for purposes of or in connection with this Amendment does not contain any untrue statement of a material fact or omit -2- to state any material fact necessary to keep the statements contained herein or therein from being misleading. Each of the foregoing representations and warranties shall constitute a representation and warranty of Borrowers made under the Credit Agreement, and it shall be an Event of Default if any such representation and warranty shall prove to have been incorrect or false in any material respect at the time given. Each of the representations and warranties made under the Credit Agreement (including those made herein) shall survive and not be waived by the execution and delivery of this Amendment or any investigation by Lenders. 8. The Borrowers agree to indemnify and hold harmless the Lenders and their respective officers, employees, agents, attorneys and representatives (singularly, an "Indemnified Party", and collectively, the "Indemnified Parties") from and against any loss, cost, liability, damage or expense (including the reasonable fees and out-of-pocket expenses of counsel to the Lender, including all local counsel hired by such counsel) ("Claim") incurred by the Lenders in investigating or preparing for, defending against, or providing evidence, producing documents or taking any other action in respect of any commenced or threatened litigation, administrative proceeding or investigation under any federal securities law, federal or state environmental law, or any other statute of any jurisdiction, or any regulation, or at common law or otherwise, which is alleged to arise out of or is based upon any acts, practices or omissions or alleged acts, practices or omissions of the Borrowers or their agents or arises in connection with the duties, obligations or performance of the Indemnified Parties in negotiating, preparing, executing, accepting, keeping, completing, countersigning, issuing, selling, delivering, releasing, assigning, handling, certifying, processing or receiving or taking any other action with respect to the Loan Documents and all documents, items and materials contemplated thereby even if any of the foregoing arises out of an Indemnified Party's ordinary negligence. The indemnity set forth herein shall be in addition to any other obligations or liabilities of the Borrowers to the Lenders hereunder or at common law or otherwise, and shall survive any termination of this Amendment, the expiration of the Loan and the payment of all indebtedness of the Borrowers to the Lenders hereunder and under the Notes, provided that the Borrowers shall have no obligation under this section to the Lenders with respect to any of the foregoing arising out of the gross negligence or willful misconduct of the Lenders. If any Claim is asserted against any Indemnified Party, the Indemnified Party shall endeavor to notify the Borrowers of such Claim (but failure to do so shall not affect the indemnification herein made except to the extent of the actual harm caused by such failure). The Indemnified Party shall have the right to employ, at the Borrowers' expense, counsel of the Indemnified Parties' choosing and to control the defense of the Claim. The Borrowers may at their own expense also participate in the defense of any Claim. Each Indemnified Party may employ separate counsel in connection with any Claim to the extent such Indemnified Party believes it reasonably prudent to protect such Indemnified Party. THE PARTIES INTEND FOR THE PROVISIONS OF THIS SECTION TO APPLY TO AND PROTECT EACH INDEMNIFIED PARTY FROM THE CONSEQUENCES OF STRICT LIABILITY IMPOSED OR THREATENED TO BE IMPOSED ON ANY INDEMNIFIED PARTY AS WELL AS FROM THE CONSEQUENCES OF ITS OWN NEGLIGENCE, WHETHER OR NOT THAT NEGLIGENCE IS THE SOLE, CONTRIBUTING, OR CONCURRING CAUSE OF ANY CLAIM. 9. This Amendment may be executed in any number of counterparts and all of such counterparts taken together shall be deemed to constitute one and the same instrument. -3- 10. WRITTEN CREDIT AGREEMENT. THE CREDIT AGREEMENT, AS AMENDED BY THIS AMENDMENT REPRESENTS THE FINAL AGREEMENT BETWEEN AND AMONG THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN AND AMONG THE PARTIES. 11. NEW LENDERS. Each of Fleet National Bank and Toronto Dominion (Texas), Inc. hereby agree to become a Lender under the Credit Agreement, to acquire the Commitment Percentage in the Commitments and the Loans as set forth on the signature page hereto and to be bound as a Lender by all of the provisions of the Credit Agreement. The Borrowers and the Agent hereby consent to an assignment of a portion of the Commitment to Fleet National Bank and Toronto Dominion (Texas), Inc. IN WITNESS WHEREOF, the parties have caused this Amendment to Restated Credit Agreement to be duly executed as of the date first above written. BORROWERS: EXCO RESOURCES, INC. By: /s/ J. DOUGLAS RAMSEY --------------------- J. Douglas Ramsey, Vice President and Chief Financial Officer EXCO OPERATING, LP a Delaware limited partnership By: EXCO Investment II, LLC, its General Partner By: /s/ T. W. EUBANK ---------------- T.W. Eubank, President -4- LENDERS: REVOLVING COMMITMENT BANK ONE, NA PERCENTAGE: a national banking association 25.0% (Main Office Chicago) as a Lender and as Administrative Agent By: /s/ THOMAS K. MARTIN -------------------- Thomas K. Martin, Associate Director -5- REVOLVING COMMITMENT BNP PARIBAS PERCENTAGE: as a Lender and as Syndication Agent 21.4285714% By: /s/ BETSY JOCHER ---------------- Name: Betsy Jocher Title: Vice President By: /s/ POLLY SCHOTT ---------------- Name: Polly Schott Title: Vice President -6- REVOLVING COMMITMENT THE BANK OF NOVA SCOTIA PERCENTAGE: as a Lender and as Documentation Agent 21.4285714% By: /s/ N. BELL ----------- Name: N. Bell Title: Assistant Agent -7- REVOLVING COMMITMENT COMERICA BANK-TEXAS PERCENTAGE: 14.2857143% By: /s/ PETER L. SEFZIK ------------------- Name: Peter L. Sefzik Title: Assistant Vice President -8- REVOLVING COMMITMENT FLEET NATIONAL BANK PERCENTAGE: 10.7142857% By: /s/ JEFFREY RATHKAMP -------------------- Name: Jeffrey Rathkamp Title: Vice President -9- REVOLVING COMMITMENT TORONTO DOMINION (TEXAS), INC. PERCENTAGE: 7.1428571% By: /s/ ANN S. SLANIS ----------------- Name: Ann S. Slanis Title: Vice President -10- SCHEDULE 1 Bank One, NA 25.000000000% The Bank of Nova Scotia 21.428571429% BNP Paribas 21.428571429% Comerica Bank-Texas 14.285714286% Fleet National Bank 10.714285714% Toronto Dominion (Texas), Inc. 7.142857143%
-11- EX-4.13 4 a2079796zex-4_13.txt EXHIBIT 4.13 Exhibits 4.13 And 10.22 AMENDMENT TO RESTATED CREDIT AGREEMENT THIS AMENDMENT TO RESTATED CREDIT AGREEMENT (hereinafter referred to as the "Amendment") executed as of the 26th day of April, 2002, by and between ADDISON ENERGY INC., an Alberta, Canada corporation ("Borrower") and BANK ONE, NA, CANADA BRANCH ("Bank One"), and each of the financial institutions which is a party thereto (as evidenced by the signature pages to the Agreement) or which may from time to time become a party thereto pursuant to the provisions of Section 28 thereof or any successor or assignee thereof (hereinafter collectively referred to as "Lenders", and individually, "Lender") and Bank One, as Administrative Agent (the "Agent"), BNP Paribas (Canada), as Syndication Agent, The Bank of Nova Scotia, as Documentation Agent and Banc One Capital Markets, Inc., as Lead Arranger and Bookrunner ("Arranger"). WITNESSETH: WHEREAS, as of April 26, 2001, Borrower, the Lenders and the Agent entered into a Credit Agreement pursuant to which the Lenders made available to the Borrowers certain credit facilities in the form therein described; and WHEREAS, as of December 18, 2001, Borrower, Lenders and Agent entered into a Restated Credit Agreement (the "Credit Agreement"); and WHEREAS, the Borrower has requested that the Lenders agree to make certain additional amendments to the Credit Agreement and the Lenders, together with certain additional financial institutions who shall become a party to the Credit Agreement at the Amendment Effective Date (as hereinafter defined), have agreed to do so on the terms and conditions hereinafter set forth. NOW, THEREFORE, the parties agree to amend the Credit Agreement as follows: 1. Unless otherwise defined herein all defined terms used herein shall have the same meaning as ascribed to such terms in the Credit Agreement. 2. The Lenders have agreed to increase their Commitments to Borrower and in connection therewith reallocate their respective Commitments and allow Fleet National Bank and The Toronto-Dominion Bank to acquire an interest in the Commitments and the Loans. After such increase and reallocation of the Commitments, the Lenders shall own the Revolving Commitment Percentages set forth on the signature pages hereto at the Amendment Effective Date. Each Lender shall surrender its existing Note and be issued a new Note in a face amount equal to each Lender's Revolving Commitment Percentage times $250,000,000 Canadian. Each said Note to be in the form of Exhibit "B" to the Credit Agreement with appropriate insertions. 3. As of the Amendment Effective Date, the Borrowing Base shall be U.S. $75,000,000 or the Canadian dollar equivalent until redetermined pursuant to the provisions of Section 7(b) of the Credit Agreement. 4. Except to the extent its provisions are specifically amended, modified or superseded by this Amendment, the representations, warranties and affirmative and negative covenants of the Borrower contained in the Credit Agreement are incorporated herein by reference for all purposes as if copied herein in full. The Borrower hereby restates and reaffirms each and every term and provision of the Credit Agreement, as amended, including, without limitation, all representations, warranties and affirmative and negative covenants. Except to the extent its provisions are specifically amended, modified or superseded by this Amendment, the Credit Agreement, as amended, and all terms and provisions thereof shall remain in full force and effect, and the same in all respects are confirmed and approved by the Borrower and the Lenders. 5. This Amendment shall be effective as of the date first above written, but only upon the satisfaction of the conditions precedent set forth in Paragraph 6 hereof. 6. The obligations of Lenders under this Amendment shall be subject to the following conditions precedent: (a) EXECUTION AND DELIVERY. The Borrower shall have executed and delivered this Amendment, and other required documents, all in form and substance satisfactory to the Agent; (b) REPRESENTATIONS AND WARRANTIES. The representations and warranties of the Borrower under this Amendment are true and correct in all material respects as of such date, as if then made (except to the extent that such representations and warranties related solely to an earlier date); (c) NO EVENT OF DEFAULT. No Event of Default shall have occurred and be continuing nor shall any event have occurred or failed to occur which, with the passage of time or service of notice, or both, would constitute an Event of Default; (d) OTHER DOCUMENTS. The Agent shall have received such other instruments and documents incidental and appropriate to the transaction provided for herein as the Agent or its counsel may reasonably request, and all such documents shall be in form and substance satisfactory to the Agent; (e) LEGAL MATTERS SATISFACTORY. All legal matters incident to the consummation of the transactions contemplated hereby shall be reasonably satisfactory to special counsel for the Agent retained at the expense of Borrower. 7. Borrower hereby represents and warrants that all factual information heretofore and contemporaneously furnished by or on behalf of Borrower to Agent for purposes of or in connection with this Amendment does not contain any untrue statement of a material fact or omit -2- to state any material fact necessary to keep the statements contained herein or therein from being misleading. Each of the foregoing representations and warranties shall constitute a representation and warranty of Borrower made under the Credit Agreement, and it shall be an Event of Default if any such representation and warranty shall prove to have been incorrect or false in any material respect at the time given. Each of the representations and warranties made under the Credit Agreement (including those made herein) shall survive and not be waived by the execution and delivery of this Amendment or any investigation by Lenders. 8. The Borrower agrees to indemnify and hold harmless the Lenders and their respective officers, employees, agents, attorneys and representatives (singularly, an "Indemnified Party", and collectively, the "Indemnified Parties") from and against any loss, cost, liability, damage or expense (including the reasonable fees and out-of-pocket expenses of counsel to the Lender, including all local counsel hired by such counsel) ("Claim") incurred by the Lenders in investigating or preparing for, defending against, or providing evidence, producing documents or taking any other action in respect of any commenced or threatened litigation, administrative proceeding or investigation under any federal securities law, federal or state environmental law, or any other statute of any jurisdiction, or any regulation, or at common law or otherwise, which is alleged to arise out of or is based upon any acts, practices or omissions or alleged acts, practices or omissions of the Borrower or its agents or arises in connection with the duties, obligations or performance of the Indemnified Parties in negotiating, preparing, executing, accepting, keeping, completing, countersigning, issuing, selling, delivering, releasing, assigning, handling, certifying, processing or receiving or taking any other action with respect to the Loan Documents and all documents, items and materials contemplated thereby even if any of the foregoing arises out of an Indemnified Party's ordinary negligence. The indemnity set forth herein shall be in addition to any other obligations or liabilities of the Borrower to the Lenders hereunder or at common law or otherwise, and shall survive any termination of this Amendment, the expiration of the Loan and the payment of all indebtedness of the Borrower to the Lenders hereunder and under the Notes, provided that the Borrower shall have no obligation under this section to the Lenders with respect to any of the foregoing arising out of the gross negligence or willful misconduct of the Lenders. If any Claim is asserted against any Indemnified Party, the Indemnified Party shall endeavor to notify the Borrower of such Claim (but failure to do so shall not affect the indemnification herein made except to the extent of the actual harm caused by such failure). The Indemnified Party shall have the right to employ, at the Borrower's expense, counsel of the Indemnified Parties' choosing and to control the defense of the Claim. The Borrowers may at their own expense also participate in the defense of any Claim. Each Indemnified Party may employ separate counsel in connection with any Claim to the extent such Indemnified Party believes it reasonably prudent to protect such Indemnified Party. THE PARTIES INTEND FOR THE PROVISIONS OF THIS SECTION TO APPLY TO AND PROTECT EACH INDEMNIFIED PARTY FROM THE CONSEQUENCES OF STRICT LIABILITY IMPOSED OR THREATENED TO BE IMPOSED ON ANY INDEMNIFIED PARTY AS WELL AS FROM THE CONSEQUENCES OF ITS OWN NEGLIGENCE, WHETHER OR NOT THAT NEGLIGENCE IS THE SOLE, CONTRIBUTING, OR CONCURRING CAUSE OF ANY CLAIM. 9. This Amendment may be executed in any number of counterparts and all of such counterparts taken together shall be deemed to constitute one and the same instrument. -3- 10. WRITTEN CREDIT AGREEMENT. THE CREDIT AGREEMENT, AS AMENDED BY THIS AMENDMENT REPRESENTS THE FINAL AGREEMENT BETWEEN AND AMONG THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN AND AMONG THE PARTIES. 11. NEW LENDERS. Each of Fleet National Bank and The Toronto-Dominion Bank hereby agree to become a Lender under the Credit Agreement, to acquire the Commitment Percentage in the Commitments and the Loans as set forth on the signature page hereto and to be bound as a Lender by all of the provisions of the Credit Agreement. The Borrower and the Agent hereby consent to an assignment of a portion of the Commitment to Fleet National Bank and The Toronto-Dominion Bank. IN WITNESS WHEREOF, the parties have caused this Amendment to Restated Credit Agreement to be duly executed as of the date first above written. BORROWER: ADDISON ENERGY INC. By: /s/ J. DOUGLAS RAMSEY --------------------- J. Douglas Ramsey, Vice President and Chief Financial Officer -4- LENDERS: REVOLVING COMMITMENT BANK ONE, NA CANADA BRANCH PERCENTAGE: as a Lender and as Administrative Agent 25.0% By: /s/ MICHAEL TAM --------------- Name: Michael Tam Title: Director -5- REVOLVING COMMITMENT BNP PARIBAS (CANADA) PERCENTAGE: as a Lender and as Syndication Agent 21.4285714% By: /s/ MICHAEL GOSSELLN -------------------- Name: Michael Gosselln Title: Director, Energy & Project Finance By: /s/ JEAN-PHILIPPE CADOT ----------------------- Name: Jean-Philippe Cadot Title: Vice President, Corporate Banking -6- REVOLVING COMMITMENT THE BANK OF NOVA SCOTIA PERCENTAGE: as a Lender and as Documentation Agent 21.4285714% By: /s/ BRIAN WILLIAMSON -------------------- Name: Brian Williamson Title: Director -7- REVOLVING COMMITMENT COMERICA BANK, CANADA BRANCH PERCENTAGE: 14.2857143% By: /s/ ROBERT ROSEN ---------------- Name: Robert Rosen Title: Vice-President -8- REVOLVING COMMITMENT FLEET NATIONAL BANK PERCENTAGE: 10.7142857% By: /s/ JEFFREY RATHKAMP -------------------- Name: Jeffrey Rathkamp Title: Vice President -9- REVOLVING COMMITMENT THE TORONTO-DOMINION BANK PERCENTAGE: 7.1428571% By: /s/ DEBBI L. BRITO ------------------ Name: Debbi L. Brito Title: Asst. Mngr. Credit Compliance & Administration -10- SCHEDULE 1 Bank One, NA, Canada Branch 25.000000000% The Bank of Nova Scotia 21.428571429% BNP Paribas (Canada) 21.428571429% Comerica Bank, Canada Branch 14.285714286% Fleet National Bank 10.714285714% The Toronto-Dominion Bank 7.142857143%
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