UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

 

Commission File Number 0-9204

 

EXCO RESOURCES, INC.

(Exact name of registrant as specified in its charter)

 

 

(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 o           NO ý

 

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

 

YES o           NO ý

 

The number of shares of common stock, par value $0.01 per share, outstanding at April 30, 2004 was 1,000.

 

 

EXCO RESOURCES, INC.

 

INDEX

 

PART I.	FINANCIAL INFORMATION (1)	3
Item 1.	Financial Statements (Unaudited)	3
	Condensed Consolidated Balance Sheets at December 31, 2003 and March 31, 2004	3
	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2003 and 2004	5
	Condensed Consolidated Statements of Cash Flow for the Three Months Ended March 31, 2003 and 2004	6
	Condensed Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2003 and 2004	7
	Notes to Condensed Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 3.	Quantitative and Qualitative Disclosure About Market Risk	43
Item 4.	Controls and Procedures	45
PART II.	OTHER INFORMATION	45
Item 6.	Exhibits and Reports on Form 8-K	45
Signatures		49
Index to Exhibits		50

 

(1)   Financial information for the periods prior to July 29, 2003, the date of the going private transaction, represents predecessor basis financial statements.  See Note 1 to the condensed consolidated financial statements.

 

2

 

PART I—FINANCIAL INFORMATION

 

Item 1. Financial Statements (Unaudited)

 

EXCO RESOURCES, INC.

 

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

 

		December 31, 2003			March 31, 2004
					(Unaudited)
Assets
Current assets:
Cash and cash equivalents		$	7,333		$	28,647
Accounts receivable:
Oil and natural gas sales		13,514			21,296
Joint interest		3,857			2,587
Interest and other		1,895			2,026
Oil and natural gas derivatives		705			122
Marketable securities		818			54
Other		3,447			3,077
Total current assets		31,569			57,809
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties		9,195			15,057
Proved developed and undeveloped oil and natural gas properties		416,679			629,919
Accumulated depreciation, depletion and amortization		(11,931		)	(22,239		)
Oil and natural gas properties, net		413,943			622,737
Gas gathering assets, net		—			17,891
Office and field equipment, net		1,101			5,142
Deferred financing costs, net		1,565			10,671
Oil and natural gas derivatives		204			59
Advances to affiliates		46			59
Goodwill		53,346			52,685
Other assets		3,256			3,215
Total assets		$	505,030		$	770,268

 

See accompanying notes

 

3

 

		December 31, 2003			March 31, 2004
					(Unaudited)
Liabilities and Stockholder's Equity
Current liabilities:
Accounts payable and accrued liabilities		$	25,308		$	33,870
Revenues and royalties payable		3,350			6,801
Income taxes payable		3,726			5,228
Current portion of asset retirement obligations		—			1,325
Oil, natural gas and interest rate derivatives		12,804			27,711
Total current liabilities		45,188			74,935
Long-term debt		207,951			445,472
Asset retirement obligations and other long-term liabilities		18,343			25,089
Deferred income taxes		45,899			37,375
Oil and natural gas derivatives		3,780			13,589
Commitments and contingencies		—			—
Stockholder’s equity:
Common stock, $.01 par value:
Authorized shares—100,000
Issued and outstanding shares—1,000 at December 31, 2003 and March 31, 2004		1			1
Capital contributed by EXCO Holdings Inc.		172,045			172,045
Retained earnings (deficit)		4,177			(4,889		)
Accumulated other comprehensive income (loss):
Foreign currency translation adjustments		7,680			6,657
Unrealized gain (loss) on equity investments		(34		)	(6		)
Total stockholder’s equity		183,869			173,808
Total liabilities and stockholder’s equity		$	505,030		$	770,268

 

See accompanying notes.

 

4

 

EXCO RESOURCES, INC.

 

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited, in thousands, except per share amounts)

 

		Three Months Ended March 31,
		2003			2004
		(Predecessor)			(Successor)
Revenues:
Oil and natural gas		$	27,010		$	47,734
Commodity price risk management activities		—			(26,878		)
Other income (loss)		(1,697		)	645
Total revenues		25,313			21,501
Costs and expenses:
Oil and natural gas production		8,520			10,791
Depreciation, depletion and amortization		5,079			10,756
Accretion of discount on asset retirement obligations		295			416
General and administrative		3,548			4,765
Interest		1,108			8,792
Total costs and expenses		18,550			35,520
Income (loss) before income taxes		6,763			(14,019		)
Income tax expense (benefit)		2,669			(4,953		)
Income (loss) before cumulative effect of change in accounting principle		4,094			(9,066		)
Cumulative effect of change in accounting principle, net of income taxes		255			—
Net income (loss)		4,349			$	(9,066	)
Dividends on preferred stock		1,311
Earnings on common stock		$	3,038
Basic earnings per share:
Income before cumulative effect of change in accounting principle		$	.39
Cumulative effect of change in accounting principle, net of income taxes		.04
Earnings on common stock		$	.43
Diluted earnings per share:
Income before cumulative effect of change in accounting principle		$	.33
Cumulative effect of change in accounting principle, net of income taxes		.02
Earnings on common stock		$	.35
Weighted average number of common and common equivalent shares outstanding:
Basic		7,022
Diluted		12,544

 

See accompanying notes.

 

5

 

EXCO RESOURCES, INC.

 

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOW

(Unaudited, in thousands)

 

		Three Months Ended March 31,
		2003			2004
		(Predecessor)			(Successor)
Operating Activities:
Net income (loss)		$	4,349		$	(9,066	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		5,079			10,756
Accretion of discount on asset retirement obligations		295			416
Non-cash changes in fair value of derivatives		—			22,863
Cumulative effect of change in accounting principle, net of income taxes		(255		)	—
Deferred income taxes		379			(7,254		)
Amortization of deferred financing costs		—			2,139
Expense from derivative ineffectiveness and terminated hedges, net		1,396			—
Other operating activities		150			1
Effect of changes in:
Accounts receivable		(5,059		)	4,043
Other current assets		(152		)	1,068
Accounts payable and other current liabilities		2,383			4,100
Net cash provided by operating activities		8,565			29,066
Investing Activities:
Acquisition of North Coast Energy, Inc., less cash acquired		—			(215,055		)
Additions to oil and natural gas properties, gathering systems and equipment		(14,374		)	(27,548		)
Proceeds from dispositions of property and equipment		3,050			6,846
Other investing activities		(32		)	766
Net cash used in investing activities		(11,356		)	(234,991		)
Financing Activities:
Proceeds from long-term debt		16,077			357,101
Payments on long-term debt		(10,711		)	(118,469		)
Preferred stock dividends		(1,311		)	—
Deferred financing costs		(972		)	(11,219		)
Other financing activities		(2		)	(13		)
Net cash provided by financing activities		3,081			227,400
Net increase in cash		290			21,475
Effect of exchange rates on cash and cash equivalents		6			(161		)
Cash at beginning of period		1,942			7,333
Cash at end of period		$	2,238		$	28,647
Supplemental Cash Flow Information:
Interest paid		$	914		$	1,859
Income taxes paid		$	—		$	786

 

See accompanying notes.

 

6

 

EXCO RESOURCES, INC.

 

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited, in thousands)

 

		Three Months Ended March 31,
		2003			2004
		(Predecessor)			(Successor)
Net income (loss)		$	4,349		$	(9,066	)
Other comprehensive income:
Hedging activities:
Effective changes in fair value		123			—
Reclassification adjustments for settled contracts		(2,533		)	—
Amortization of terminated contracts		(975		)	—
Total hedging activities		(3,385		)	—
Foreign currency translation adjustment		1,919			(1,023		)
Unrealized gain on equity investments		48			28
Total comprehensive income (loss)		$	2,931		$	(10,061	)

 

See accompanying notes.

 

7

 

EXCO RESOURCES, INC.

 

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2004

(Unaudited)

 

1.              The Merger

 

On July 29, 2003, pursuant to an Agreement and Plan of Merger, ER Acquisition, Inc., a Texas corporation, and a wholly-owned subsidiary of EXCO Holdings Inc., a Delaware corporation, was merged into EXCO Resources, Inc. (EXCO, the Company, or Resources).  EXCO Holdings Inc. (Holdings or our parent) was formed by our chairman and chief executive officer, Douglas H. Miller, and his buying group for the purpose of entering into the merger agreement. The holders of EXCO’s common stock, other than Holdings and its subsidiaries, received cash of $18.00 per share. The buyout was funded with borrowings from EXCO’s existing credit facilities of approximately $53.6 million and approximately $172.0 million of equity. The equity capital for Holdings was provided by:

 

• Cerberus Capital Management, L.P., or Cerberus, an investment management firm— $106.5 million in cash;

 

• Other institutional investors—$34.3 million in cash;

 

• Certain members of EXCO’s management—$10.5 million in cash and the contribution of EXCO shares; and

 

• Other institutional and other investors—$20.7 million in cash and the contribution of EXCO shares.

 

Upon completion of the merger transaction, EXCO’s common stock was delisted from trading on the NASDAQ National Market or any other exchange and EXCO’s common stock registration pursuant to Section 12(g)(4) of the Securities Exchange Act of 1934 was terminated. Accordingly, earnings per share data is not shown for any of the periods subsequent to July 28, 2003.

 

The total purchase price for EXCO was $353.5 million representing the purchase of all outstanding common stock and stock options including the amounts contributed to Holdings by management and key employees and other investors, and liabilities assumed as detailed below and has been allocated as follows (dollars in thousands):

 

 

(1) Represents deferred income taxes recorded at the date of the merger due to differences between the book basis and the tax basis of assets. For book purposes, we had a step-up in basis related to purchase accounting while our existing tax basis carried over.

 

8

 

As a result of the change in control, generally accepted accounting principles (GAAP) requires the acquisition by Holdings to be accounted for as a purchase transaction in accordance with Statement of Financial Accounting Standards No. 141, “Business Combinations”.  GAAP requires the application of “push down accounting” in situations where the ownership of an entity has changed, meaning that the post-transaction financial statements of the acquired entity (i.e. EXCO) reflect the new basis of accounting in accordance with Staff Accounting Bulletin No. 54 (“SAB 54”). Accordingly, the financial statements as of December 31, 2003 and for the 156 day period then ended reflect Holdings’ stepped up basis resulting from the acquisition that has been pushed down to us. The aggregate purchase price has been allocated to the underlying assets and liabilities based upon the respective estimated fair values at July 29, 2003 (date of acquisition). Carryover basis accounting applies for tax purposes. All financial information presented prior to July 29, 2003 represents predecessor basis of accounting.

 

The purchase price allocation resulted in $51.1 million of goodwill, $24.2 million in the United States geographic operating segment and $26.9 million in the Canadian geographic operating segment. None of the goodwill is deductible for income tax purposes. Furthermore, in accordance with SFAS No. 142, “Goodwill and Intangible Assets”, goodwill is not amortized, but is tested for impairment on an annual basis, or more frequently as impairment indicators arise. Impairment tests, which involve the use of estimates related to the fair market value of the business operations with which goodwill is associated, are performed annually at the end of our fourth quarter. Losses, if any, resulting from impairment tests will be reflected in operating income in the statement of operations. Changes in the balance of goodwill from the date of acquisition to December 31, 2003 are the result of foreign currency translation adjustments for associated Canadian goodwill.

 

See “Note 9. Issuance of Senior Unsecured Notes and the Acquisition of North Coast Energy, Inc.” for pro forma condensed consolidated statements of operations.

 

2.  Basis of Presentation

 

EXCO Resources, Inc., a Texas corporation, was formed in 1957. Our operations consist primarily of acquiring interests in producing oil and natural gas properties located in the continental United States and Canada. We also act as the operator of some of these properties and receive overhead reimbursement fees as a result.

 

The accompanying consolidated balance sheets as of December 31, 2003 and March 31, 2004 and the results of operations, cash flows and comprehensive income for the three months ended March 31, 2004 are for EXCO and its subsidiaries and represent the stepped up successor basis of accounting (New EXCO).

 

The accompanying condensed consolidated results of operations, cash flow and comprehensive income for the three months ended March 31, 2003 are for EXCO and its subsidiaries and represent the predecessor basis of accounting (Old EXCO).  All inter-company transactions have been eliminated.

 

In management’s opinion, the accompanying unaudited 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, 2003 and March 31, 2004, and the results of operations, cash flow and other comprehensive income for the three month periods ended March 31, 2003 and 2004.

 

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

 

9

 

that the disclosures we have made are adequate to make the information presented not misleading. You should read these unaudited interim financial statements in conjunction with our audited financial statements and notes included in the Prospectus for our senior notes exchange offer dated April 22, 2004.

 

The results of operations for the interim periods are not necessarily indicative of the results we expect for the full year.

 

Certain prior year amounts have been reclassified to conform to the current year presentation.

 

Stock Options

 

Statement of Financial Accounting Standards (SFAS) No. 123, “Accounting for Stock-Based Compensation” defines a fair value based method of accounting for employee stock compensation plans, but allows for the continuation of the intrinsic value based method of accounting to measure compensation cost prescribed by Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (APB 25). For companies electing not to change their accounting, SFAS 123 requires pro forma disclosures of earnings and earnings per share as if the change in accounting provision of SFAS 123 has been adopted.

 

Old EXCO elected to continue to utilize the accounting method prescribed by APB 25, under which no compensation cost was recognized, and adopt the disclosure requirements of SFAS 123. As a result, SFAS 123 had no effect on our results of operations at March 31, 2003. Stock based compensation expense reflected in the table below for the three months ended March 31, 2003, was a result of options issued under Old EXCO’s 1998 Stock Option Plan that were issued subject to our shareholders’ approval and options that were issued to the management and key employees of Addison.

 

Had compensation costs for these plans been determined consistent with SFAS 123, Old EXCO’s net income and earnings per share (EPS) would have been adjusted to the following pro forma amounts (New EXCO has not issued any stock options):

 

				March 31, 2003
				(In thousands, except per share amounts)
Stock based compensation expense (net of taxes)		As Reported		$	264
		Pro Forma		$	666
Net income		As Reported		$	4,349
		Pro Forma		$	3,947
Basic EPS		As Reported		$	.43
		Pro Forma		$	.38
Diluted EPS		As Reported		$	.35
		Pro Forma		$	.31

 

3. Asset Retirement Obligations

 

Prior to 2003, Old EXCO provided for future site restoration costs on its Canadian oil and natural gas properties based upon management’s estimates. The costs were being recognized over the remaining life of proved reserves by a charge to depreciation, depletion and amortization in the statement of operations with a related increase in the non-current deferred abandonment liability. Actual expenditures for site restoration were charged to the deferred abandonment liability when incurred.  Old EXCO did not provide for site restoration on its U.S. properties as it estimated that salvage values would exceed the asset retirement costs.

 

In June 2001, the Financial Accounting Standards Board issued SFAS No. 143, “Accounting for Asset Retirement Obligations”. The statement requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. Old EXCO adopted the new rules on asset retirement obligations on January 1, 2003, for its U.S. and Canadian operations. Application of the new rules resulted in an increase in net proved developed and undeveloped oil and natural gas properties of approximately $11.4 million, recognition of an asset retirement obligation liability of approximately $10.4 million, an increase in deferred income tax liability of approximately $690,000, and a cumulative effect of adoption that increased net income and stockholder’s equity by approximately $255,000.  The increase in net income resulting from the cumulative effect of the change in accounting increased basic earnings per share by $.04 and diluted earnings per share by $.02 for the three month period ended March 31, 2003.

 

10

 

The following pro forma data summarizes Old EXCO’s net income and earnings per share as if it had adopted the provisions of SFAS 143 on January 1, 2003, including an associated pro forma asset retirement obligation on that date of $7.1 million:

 

		Three Months Ended March 31, 2003
		(In thousands, expect per share amounts)
Net income, as reported		$		4,349
Pro forma adjustments to reflect retroactive adoption of SFAS 143		(255			)
Pro forma net income		$	4,094
Earnings on common stock per share:
Basic-as reported		$		.43
Basic-pro forma		$		.39
Diluted-as reported		$		.35
Diluted-pro forma		$		.33

 

The following is a reconciliation of our asset retirement obligations as of March 31, 2003 and 2004 (in thousands of dollars):

 

		March 31
		2003			2004
Deferred abandonment costs at beginning of period		$	2,176		$	17,742
Cumulative effect of change in accounting principle		10,433			—
Liabilities incurred or assumed during period		120			7,883
Liabilities settled during period		(339		)	(128		)
Accretion of discount		295			416
Effect of foreign currency conversions		466			(101		)
Asset retirement obligation at end of period		13,151			25,812
Less current portion		—			1,325
Long-term obligation		$	13,151		$	24,488

 

We have no assets that are legally restricted for purposes of settling asset retirement obligations.

 

4. Earnings Per Share

 

SFAS No. 128, “Earnings per Share”, required Old EXCO to present two calculations of earnings per common share for the three month period ended March 31, 2003.  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) the outstanding 5% convertible preferred stock was converted to common stock.

 

11

 

Earnings per share subsequent to July 28, 2003 (after the going private transaction) are not presented since New EXCO is wholly-owned by Holdings, our parent.

 

		Three Months Ended March 31, 2003
		(In thousands)
Weighted average number of basic shares outstanding		7,022
Effects of:
Employee and director stock options		525
Convertible preferred stock		4,997
Weighted average number of diluted shares outstanding		12,544

 

5. 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, 2003 and March 31, 2004, we had $9.2 million and $15.1 million, respectively, in unproved oil and natural gas properties.  We assess our unproved oil and natural gas properties on a quarterly basis. During the three months ended March 31, 2004, we reclassified $1.7 million from unproved oil and natural gas properties to proved 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. This ceiling test 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.

 

12

 

6. Geographic Operating Segment Information

 

The only industry segment in which we operate is 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. Geographic operating segment income tax expenses have been determined based on expected effective tax rates for the various tax jurisdictions where we have oil and natural gas producing activities.

 

		United States			Canada			Corporate and Other			Total
		(In thousands)
Three months ended March 31, 2003:
Oil and natural gas sales		$	9,073		$	17,937		$	—		$	27,010
Other income (loss)		(1,569		)	—			(128		)	(1,697		)
		7,504			17,937			(128		)	25,313
Production costs		4,908			3,612			—			8,520
Depreciation, depletion and amortization		2,375			2,704			—			5,079
Accretion expense		138			157			—			295
General and administrative		—			—			3,548			3,548
Interest		—			—			1,108			1,108
		7,421			6,473			4,656			18,550
Income (loss) before income taxes		83			11,464			(4,784		)	6,763
Income tax expense (benefit)		28			4,730			(2,089		)	2,669
Net income (loss)		$	55		$	6,734		$	(2,695	)	$	4,094
Total assets		$	130,946		$	142,893		$	—		$	273,839
Three months ended March 31, 2004:
Oil and natural gas sales		$	28,667		$	19,067		$	—		$	47,734
Commodity price risk management activities		(23,562		)	(3,316		)	—			(26,878		)
Other income		—			—			645			645
		5,105			15,751			645			21,501
Production costs		6,403			4,388			—			10,791
Depreciation, depletion and amortization		6,053			4,703			—			10,756
Accretion expense		198			218			—			416
General and administrative		—			—			4,765			4,765
Interest		—			—			8,792			8,792
		12,654			9,309			13,557			35,520
Income (loss) before income taxes		(7,549		)	6,442			(12,912		)	(14,019		)
Income tax expense (benefit)		(2,552		)	2,552			(4,953		)	(4,953		)
Net income (loss)		$	(4,997	)	$	3,890		$	(7,959	)	$	(9,066	)
Total assets		$	483,644		$	286,624		$	—		$	770,268
Goodwill		$	23,831		$	28,854		$	—		$	52,685

 

7. Derivative Financial Instruments

 

In connection with the incurrence of debt related to our acquisition activities, our management has adopted a policy of entering into oil and natural gas derivative financial instruments to protect against commodity price fluctuations and to achieve a more predictable cash flow.  SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activity,” requires 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 was immediately recognized in earnings in our predecessor basis financial statements.  Prior to July 29, 2003, all of Old EXCO’s derivative financial instruments were designated as cash flow hedges.  Beginning July 29, 2003, the date of the merger, we have not designated our derivative financial instruments as hedging instruments and, as a result, we recognize the change in the derivative’s fair value currently in earnings.

 

Old EXCO entered into several swap transactions during 2000 and 2001 with Enron North America Corp., an affiliate of Enron Corp. (the Enron Hedges).  On December 2, 2001, Enron Corp. and other Enron related entities, including Enron North America, filed for bankruptcy under Chapter 11 of the United States Code in the United States Bankruptcy Court in the Southern Division of New York.  We terminated all of our hedging contracts with Enron North America, effective as of December 5, 2001.  We believe that we are owed approximately $15.3 million, including settlements already due but not paid, but the exact amount of the claim will be determined pursuant to the terms of the ISDA Master Agreement.  We have valued the Enron derivative asset at $2.8 million, which represented our estimate of the fair market value of our bankruptcy claim against Enron North America, which is shown in the accompanying consolidated balance sheet in other assets.  Our estimate of the value of our bankruptcy claim was based upon informal offers that we received from third parties attempting to purchase those claims as well as management’s best estimate of the financial condition of Enron’s bankruptcy estate as determined from published reports and court filings related to the bankruptcy.  Our claim was sold to a third party in April 2004 for approximately $4.7 million.

 

 

13

 

The following table sets forth our oil and natural gas derivatives as of March 31, 2004.  The fair values at March 31, 2004 are estimated from quotes from the counterparties and represent the amount that we would expect to receive or pay to terminate the contracts at March 31, 2004.  We have the right to offset amounts we expect to receive or pay among our individual counterparties.  As a result, we have offset amounts for financial statement presentation purposes.

 

		Volume mmbtu/ bbls		Weighted Average Strike Price			Weighted Average Differential to NYMEX			Fair Value at March 31, 2004
		(In thousands, except prices and differentials)
Natural Gas:
Swaps:
2004		9,730		$	4.62					$	(13,521	)
2005		15,622		4.91						(10,379		)
2006		10,403		4.82						(3,574		)
2007		6,387		4.60						(2,066		)
2008		2,745		4.55						(505		)
2009		1,825		4.51						(215		)
2010		1,825		4.51						(85		)
2011		1,825		4.51						(19		)
2012		1,830		4.51						20
2013		1,825		4.51						44
		54,017
Floor Prices:
2004		7,920		4.04						189
2005		1,058		4.25						144
		8,978
Ceiling Prices:
2004		5,500		6.01						(3,651		)
		5,500
Basis Protection Swaps:
2004		364					$	(0.82	)	27
		364
Total Natural Gas										(33,591		)
Oil:
Swaps:
2004		561		24.25						(5,289		)
2005		329		25.65						(1,668		)
		890
Total Oil										(6,957		)
Total Oil and Natural Gas										$	(40,548	)

 

At March 31, 2004, the average forward NYMEX oil prices per Bbl for the remainder of calendar 2004 and 2005 were $33.68 and $30.83, respectively and the average forward NYMEX natural gas price per Mmbtu for the remainder of calendar 2004 and 2005 were $5.98 and $5.61, respectively.

 

14

 

8.  Credit Agreements

 

U.S. Credit Agreement.  On January 27, 2004, our U.S. credit agreement was amended and restated to provide for borrowings up to $250.0 million with a borrowing base of $120.0 million. The amendment also provided for an extension of the U.S. credit agreement maturity date to January 27, 2007.  Upon the issuance of the $100.0 million in additional 7¼% senior notes on April 13, 2004, the U.S. credit agreement borrowing base was reduced to $95.0 million. (See “Note 12. Subsequent Event - Additional Debt Offering”).The borrowing base is currently being redetermined for the May 1, 2004 effective date, and will be redetermined each November 1 and May 1 thereafter. Our borrowing base is determined based on a number of factors including commodity prices. We use derivative financial instruments to lessen the impact of volatility in commodity prices. At March 31, 2004, we had $1,000 of outstanding indebtedness and letter of credit commitments of $275,000 and approximately $94.7 million available for borrowing. Borrowings under our amended and restated credit agreement are secured by a first lien mortgage providing a security interest in 90% of our U.S. oil and natural gas properties including North Coast. 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 .50% plus an applicable margin or (ii) LIBOR (London InterBank Offered Rate) plus an applicable margin. At March 31, 2004, the six month LIBOR rate was 1.16%, which would result in an interest rate of approximately 2.41% on any new indebtedness we may incur under the U.S. credit agreement.

 

Canadian Credit Agreement.  On January 27, 2004, our Canadian credit agreement was amended and restated to provide for borrowings up to $189.4 million with a borrowing base of approximately $105.0 million (CDN $138.6 million using the exchange rate on January 26, 2004). The amendment also provided for an extension of the Canadian credit agreement maturity date to January 27, 2007.  The issuance of the $100.0 million in additional 7¼% senior notes on April 13, 2004 did not impact the borrowing base under the Canadian credit agreement. (See “Note 12. Subsequent Event - Additional Debt Offering”). The borrowing base is currently being redetermined for the May 1, 2004 effective date, and will be redetermined each November 1 and May 1 thereafter. Our borrowing base is determined based on a number of factors including commodity prices. We use derivative financial instruments to lessen the impact of volatility in commodity prices. At March 31, 2003, we had approximately $95.5 million of outstanding indebtedness and approximately $9.5 million available for borrowing. On April 8, 2004, we borrowed approximately $5.3 million under the Canadian credit agreement to partially fund an acquisition of oil and natural gas properties. We repaid substantially all of our borrowings under the Canadian credit agreement, approximately $98.8 million, from the net proceeds of the $100.0 million in additional 7¼% senior notes on April 13, 2004.  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, 2004, the six month Banker’s Acceptance rate was 2.07%, which would result in an interest rate of approximately 4.07% on any new indebtedness we incur under the Canadian credit agreement.

 

Financial Covenants and Ratios.  Our amended and restated U. S. and 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 (as defined under our credit agreements) of at least 1.0 to 1.0 at the end of any fiscal quarter;

 

•                  not permit our ratio of consolidated funded debt to consolidated EBITDA (as defined under our credit agreements) to be greater than (i) 4.35 to 1.00 at the end of each fiscal quarter ending prior to June 30, 2004 and (ii) 4.00 to 1.00 on June 30, 2004 and at the end of each fiscal quarter thereafter;

 

•                  not permit our ratio of consolidated funded debt (other than the senior notes) to consolidated EBITDA (as defined under our credit agreements) to be greater than (i) 3.25 to 1.0 at the end of each fiscal quarter ending prior to June 30, 2004 and (ii) 3.00 to 1.00 on June 30, 2004 and at the end of each fiscal quarter thereafter; and

 

•                  not permit our ratio of consolidated EBITDA (as defined under our credit agreements) to consolidated interest expense to be less 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.

 

As of March 31, 2004, we were in compliance with the covenants contained in our former U.S. and Canadian credit agreements.

 

Our current assets to current liabilities ratio as defined under our former credit agreements was 4.07 to 1.00 at March 31, 2004.

 

Our consolidated funded debt to consolidated EBITDA (as defined under our credit agreements) at March 31, 2004 as defined under our credit agreements was 3.22 to 1.00.

 

15

 

Our consolidated funded debt (other than the senior notes) to consolidated EBITDA (as defined under our credit agreements) at March 31, 2004 as defined under our credit agreements was 0.69 to 1.00.

 

At March 31, 2004, our consolidated EBITDA (as defined under our former credit agreements) to consolidated interest expense was 4.33 to 1.00.

 

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.  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.

 

9.  Issuance of Senior Unsecured Notes and the Acquisition of North Coast Energy, Inc.

 

On November 26, 2003, we entered into the North Coast Acquisition Agreement, as amended and restated on December 4, 2003 to acquire all of the issued and outstanding stock of North Coast pursuant to a tender offer and merger.  We acquired all of the outstanding common stock, options and warrants of North Coast on January 27, 2004 for a purchase price of $167.8 million and we assumed $57.0 million of North Coast’s outstanding indebtedness.  As a result, on January 27, 2004, North Coast became a wholly-owned subsidiary and established a new core operating area for us in the Appalachian Basin.  We have accounted for the North Coast acquisition using the purchase method of accounting and have consolidated its operations effective January 27, 2004.

 

On January 20, 2004, we completed the private placement of $350.0 million aggregate principal amount of 7 ¼% Senior Notes due 2011 pursuant to Rule 144A and Regulation S under the Securities Act at a price of 100% of the principal amount.  The net proceeds of the offering were used to acquire North Coast, pay down debt under our credit facilities and North Coast’s credit facility, repay our senior term loan in full and pay fees and expenses associated with those transactions.

 

Interest is payable on the senior notes semi-annually in arrears on January 15 and July 15 of each year, commencing July 15, 2004. The senior notes mature on January 15, 2011. Prior to January 15, 2007, we may redeem all, but not less than all, of the senior notes in cash at a redemption price equal to 100% of the principal amount of the notes plus a premium. We may redeem some or all of the senior notes beginning on January 15, 2007 for the redemption price set forth in the notes. If a change of control occurs, subject to certain conditions, we must offer holders of the notes an opportunity to sell us their notes at a purchase price of 101% of the principal amount of the notes, plus accrued and unpaid interest to the date of the purchase.

 

The indenture governing the senior notes contains covenants which limit our ability and the ability of certain of our subsidiaries to:

 

•                  Incur or guarantee additional debt and issue certain types of preferred stock;

 

•                  Pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated debt;

 

•                  Make investments;

 

•                  Create liens on our assets;

 

•                  Enter into sale/leaseback transactions;

 

•                  Create restrictions on the ability of our restricted subsidiaries to pay dividends or make other payments to us;

 

•                  Engage in transactions with our affiliates;

 

•                  Transfer or issue shares of stock of subsidiaries;

 

•                  Transfer or sell assets; and

 

•                  Consolidate, merge or transfer all or substantially all of our assets and the assets of our subsidiaries.

 

16

 

As required by the registration rights agreements we entered into in conjunction with the sale of the senior notes, we are offering to exchange the senior notes for a new issue of substantially identical notes registered under the Securities Act.  The exchange offer expires on May 28, 2004.  We have also agreed to file a shelf registration statement to cover resales of the notes under certain circumstances.

 

Concurrent with the issuance of the senior notes, we wrote-off $938,000 of costs incurred in January 2004 to secure bridge loan financing which was not utilized upon issuance of the senior notes and deferred financing costs of approximately $726,000 related to the senior term loan, which was retired with the proceeds of the senior notes.

 

The total purchase price for North Coast was $225.5 million representing the purchase of all outstanding common stock and liabilities assumed as detailed below and has been allocated as follows (dollars in thousands):

 

Purchase Price Calculations:
Payments for tendered shares including options and warrants		$	167,781
Assumption of debt including interest		57,149
Merger related costs		554
Total North Coast acquisition costs (before cash acquired)		$	225,484
Allocation of purchase price:
Oil and natural gas properties – proved		$	192,946
Oil and natural gas properties – unproved		7,258
Gas gathering assets and other equipment		21,454
Cash		10,429
Other assets		22
Deferred income tax asset		942
Other current assets		11,080
Accounts payable and accrued expenses		(10,462		)
Asset retirement obligations		(5,639		)
Liabilities from commodity price risk management activities		(2,546		)
Total Allocation		$	225,484

 

The following unaudited pro forma condensed consolidated statements of operations for the three months ended March 31, 2003 and 2004 have been derived from our unaudited consolidated statement of operations for the three months ended March 31, 2003 and 2004 and North Coast’s unaudited consolidated financial statements for the quarter ended March 31, 2003 and the 27 day period from January 1 to January 27, 2004.  The pro forma statements of operations give effect to the following events as if each occurred on January 1 of each respective year.

 

•                  Our going private transaction, which occurred on July 29, 2003.  See ”Note 1. The Merger”.

 

•                  Our acquisition of North Coast for a purchase price of approximately $225.5 million. The North Coast acquisition was accounted for using the purchase method of accounting in accordance with Statement of Financial Accounting Standards No. 141, “Business Combinations.” Accordingly, EXCO’s historical financial statements reflect the allocation of the purchase price to the underlying assets and liabilities based upon their estimated fair values. For tax purposes we also received a step up in tax basis equal to the purchase price.

 

•                  Adjustments to conform North Coast’s historical accounting policies related to oil and natural gas properties from successful efforts to full cost accounting.

 

•                  The issuance of $350.0 million in senior notes.

 

•                  The assumption of North Coast’s debt and repayment of our and North Coast’s credit facilities.

 

•                  The payment of our related fees and expenses.

 

17

 

The pro forma information presented herein does not purport to be indicative of the financial position or results of operations that would have actually occurred had the events discussed above occurred on the dates indicated or which may occur in the future.

 

		EXCO Historical			North Coast Historical						Pro Forma
		Three Months Ended March 31, 2003			Three Months Ended March 31, 2003			Adjustments for the Transactions			Three Months Ended March 31, 2003
		(Dollars in thousands)
Revenues and other income:
Oil and natural gas		$	27,010		$	13,048		$	—		$	40,058
Commodity price risk management activities		—			—			—			—
Well operating, gathering and other		—			1,334			(1,334		)(b)	—
Other income (expense)		(1,697		)	111			11		(b)	(1,575		)
Total revenues and other income		25,313			14,493			(1,323		)	38,483
Costs and expenses:
Oil and natural gas production		8,520			2,580			(317		)(b)	10,783
Well operating, gathering and other		—			1,006			(1,006		)(b)	—
Exploration expense		—			522			(522		)(c)	—
Depreciation, depletion and amortization		5,079			2,210			3,929		(d)	11,218
Accretion of asset retirement obligations		295			—			85		(e)	380
General and administrative		3,548			1,289			1,249		(f)	6,086
Interest		1,108			713			5,832		(h)	7,653
Total costs and expenses		18,550			8,320			9,250			36,120
Income (loss) before income taxes		6,763			6,173			(10,573		)	2,363
Income tax expense (benefit)		2,669			2,168			(3,771		)(i)	1,066
Net income (loss)		$	4,094		$	4,005		$	(6,802	)	$	1,297
		EXCO Historical			North Coast Historical						Pro Forma
		Three Months Ended March 31, 2004			27 Day Period from January 1 to January 27, 2004 (a)			Adjustments for the Transaction			Three Months Ended March 31, 2004
		(Dollars in thousands)
Revenues and other income:
Oil and natural gas		$	47,734		$	6,540		$	—		$	54,274
Commodity price risk management activities		(26,878		)	—			—			(26,878		)
Well operating, gathering and other		—			490			(490		)(b)	—
Other income (expense)		645			150			20		(b)	815
Total revenues and other income		21,501			7,180			(470		)	28,211
Costs and expenses:
Oil and natural gas production		10,791			878			(108		)(b)	11,561
Well operating, gathering and other		—			362			(362		)(b)	—
Exploration expense		—			200			(200		)(c)	—
Depreciation, depletion and amortization		10,756			851			473		(d)	12,080
Accretion of asset retirement obligations		416			—			30		(e)	446
General and administrative		4,765			11,535			(11,021		)(g)	5,279
Interest		8,792			186			934		(h)	9,912
Total costs and expenses		35,520			14,012			(10,254		)	39,278
Income (loss) before income taxes		(14,019		)	(6,832		)	9,784			(11,067		)
Income tax expense (benefit)		(4,953		)	(2,448		)	3,664		(i)	(3,737		)
Net income (loss)		$	(9,066	)	$	(4,384	)	$	6,120		$	(7,330	)

 

 

18

 

(a)	Represents historical information for North Coast for the 27 day period from January 1 to January 27, 2004.
(b)	Represents reclassifications to conform to EXCO’s presentation.
(c)	Represents the adjustment to capitalize exploration expense as required under the full-cost method of accounting employed by EXCO.
(d)	Represents increased depreciation, depletion and amortization primarily relating to the step up in basis of oil and natural gas properties associated with the purchase price allocation for the North Coast transaction as if it occurred on January 1, 2003.
(e)	Represents additional accretion charges resulting from the revaluation of fair value based upon EXCO management’s assessment of certain factors as they relate to North Coast’s asset retirement obligation.
(f)	Represents third party costs incurred by EXCO directly related to the going private transaction and additional contractual management compensation resulting from the going private transaction.
(g)	Represents transaction costs incurred by North Coast and expensed during the 27 day period from January 1 to January 27, 2004 primarily related to investment banking fees, employee bonus and severance payments and other costs incurred in connection with the acquisition of North Coast by EXCO.
(h)	Represents the additional interest expense that would have resulted had the $350.0 million of 7 ¼% senior notes due 2011 been issued on January 1, 2004 net of the reduction in interest expense relating to the repayment of outstanding debt under the bank credit agreements and the senior term loan occurred on January 1, 2004.
(i)	Represents the income tax effect of the pro forma adjustments and adjustment of North Coast’s historical rate to approximate EXCO’s U.S. tax rate.

 

10.   Acquisitions and Dispositions

 

Transactions, other than North Coast, that occurred during the three months ended March 31, 2004

 

During the three months ended March 31, 2004, we completed five oil and natural gas property acquisitions in Canada and one in the United States.  Estimated total proved reserves net to our interest from these acquisitions included approximately 530.3 Mbbls of oil and NGLs and 7,233.0 Mmcf of natural gas.  The total purchase price for the acquisitions was approximately $11.0 million funded with borrowings under our Canadian credit agreement and from surplus cash.

 

During the three months ended March 31, 2004, we completed three sales of oil and natural gas properties in the United States.  As of January 1, 2004, estimated total proved reserves net to our interest from these properties included approximately 92.6 Mbbls of oil and NGLs and 4,928.3 Mmcf of natural gas.  The total sales proceeds we received were approximately $6.6 million.  During the first quarter of 2003, we recorded revenue of approximately $731,000, oil and natural gas production costs of $134,000 and depletion expense of $98,000 on these properties.  During the first quarter of 2004, we recorded revenue of approximately $297,000, oil and natural gas production costs of $92,000 and depletion expense of $65,000 on these properties.

 

Transactions that occurred during the three months ended March 31, 2003

 

During the three months ended March 31, 2003, we completed two oil and natural gas property acquisitions, one in Canada and one in the United States. Estimated total proved reserves net to our interest from these acquisitions included approximately 196.0 Mbbls of oil and NGLs and 3,700 Mmcf of natural gas.  The total purchase price for the acquisitions was approximately $5.5 million funded with borrowings under our Canadian credit agreement and from surplus cash. In addition, we have also completed ten smaller acquisitions during this period for consideration that totaled approximately $600,000.

 

During the first three months of 2003, we sold six oil and natural gas properties in the United States. As of January 1, 2003, estimated total proved reserves net to our interest from these properties included approximately 565.0 Mbbls of oil and NGLs and 192.0 Mmcf of natural gas. The total sales proceeds we received were approximately $3.1 million.  During the first quarter of 2003, we recorded revenues of approximately $130,000, oil and natural gas production costs of $40,000 and depletion expense of $20,000.

 

19

 

11.   Consolidating Financial Statements

 

Set forth below are condensed consolidating financial statements of EXCO, the guarantor subsidiaries and the non-guarantor subsidiary.  The senior unsecured notes are jointly and severally guaranteed by our current and some of our future subsidiaries in the United States (referred to as Guarantor Subsidiaries).  Addison is not a guarantor of the senior unsecured notes.  Instead, the notes are secured, subject to specified permitted liens and except as described below, by a second-priority security interest in 65% of the capital stock of Addison.  This share pledge is limited such that, at any time, the aggregate par value, book value as carried by us or market value (whichever is greatest) of such pledged capital stock is not equal to or greater than 20% of then outstanding aggregate principal amount of the notes.  The notes are also secured by a second-priority security interest in 100% of the capital stock of Taurus Acquisition, Inc.

 

The following financial information presents consolidating financial statements, which include:

 

•                  Resources;

•                  the guarantor subsidiaries on a combined basis;

•                  the non-guarantor subsidiary;

•                  elimination entries necessary to consolidate Resources, the guarantor subsidiaries and the non-guarantor subsidiary; and

•                  the Company on a consolidated basis.

 

Taurus Acquisition, Inc., EXCO Investment I, LLC and EXCO Investment II, LLC are guarantors of the senior unsecured notes.  These companies have no material operations and, accordingly, these companies have been omitted from the guarantor financial information.  Investments in subsidiaries are accounted for using the equity method of accounting.  The financial information for the guarantor and non-guarantor subsidiaries is presented on a combined basis.  The elimination entries primarily eliminate investment in subsidiaries and intercompany balances and transactions.  As of January 27, 2004, North Coast Energy, Inc. and North Coast Energy Eastern, Inc. became guarantors of the senior unsecured notes.

 

20

 

EXCO RESOURCES, INC.

 

CONSOLIDATING BALANCE SHEET (Unaudited)

 

December 31, 2003

 

		Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
		(In thousands)
Assets
Current assets:
Cash and cash equivalents		$	3,372		$	—		$	3,961		$	—		$	7,333
Other current assets		10,262			—			13,974			—			24,236
Total current assets		13,634			—			17,935			—			31,569
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties		2,598			—			6,597			—			9,195
Proved developed and undeveloped oil and natural gas properties		102,955			84,416			229,308			—			416,679
Allowance for depreciation, depletion and amortization		(3,091		)	(2,162		)	(6,678		)	—			(11,931		)
Oil and natural gas properties, net		102,462			82,254			229,227			—			413,943
Office and field equipment, net		811			—			290			—			1,101
Goodwill		24,218			—			29,128			—			53,346
Investments in and advances to affiliates		184,520			12,895			—			(197,369		)	46
Other assets, net		4,498			—			527			—			5,025
Total assets		$	330,143		$	95,149		$	277,107		$	(197,369	)	$	505,030
Liabilities and Stockholder’s Equity
Current liabilities		$	25,644		$	—		$	19,544		$	—		$	45,188
Long-term debt		99,470			—			108,481			—			207,951
Deferred income taxes		12,139			—			33,760			—			45,899
Other liabilities		9,021			1,527			11,575			—			22,123
Payable to parent		—			—			48,927			(48,927		)	—
Commitments and contingencies		—			—			—			—			—
Stockholder's equity		183,869			93,622			54,820			(148,442		)	183,869
Total liabilities and stockholder’s equity		$	330,143		$	95,149		$	277,107		$	(197,369	)	$	505,030

 

21

 

EXCO RESOURCES, INC.

 

CONSOLIDATING BALANCE SHEET (Unaudited)

 

March 31, 2004

 

		Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
		(In thousands)
Assets
Current assets:
Cash and cash equivalents		$	14,445		$	9,565		$	4,637		$	—		$	28,647
Other current assets		9,238			7,589			12,335			—			29,162
Total current assets		23,683			17,154			16,972			—			57,809
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties		2,598			7,258			5,201			—			15,057
Proved developed and undeveloped oil and natural gas properties		100,337			283,304			246,278			—			629,919
Allowance for depreciation, depletion and amortization		(4,821		)	(6,091		)	(11,327		)	—			(22,239		)
Oil and natural gas properties, net		98,114			284,471			240,152			—			622,737
Gas gathering, office and field equipment, net		1,140			21,589			304			—			23,033
Goodwill		23,831			—			28,854			—			52,685
Investments in and advances to affiliates		424,434			16,739			—			(441,114		)	59
Other assets, net		13,581			22			342			—			13,945
Total assets		$	584,783		$	339,975		$	286,624		$	(441,114	)	$	770,268
Liabilities and Stockholder’s Equity
Current liabilities		$	39,437		$	11,564		$	23,934		$	—		$	74,935
Long-term debt		350,001			—			95,471			—			445,472
Deferred income taxes		3,624			867			32,884			—			37,375
Other liabilities		17,913			7,333			13,432			—			38,678
Payable to parent		—			52,133			64,367			(116,500		)	—
Commitments and contingencies		—			—			—			—			—
Stockholder's equity		173,808			268,078			56,536			(324,614		)	173,808
Total liabilities and stockholder’s equity		$	584,783		$	339,975		$	286,624		$	(441,114	)	$	770,268

 

22

 

EXCO RESOURCES, INC.

 

CONSOLIDATING STATEMENTS OF OPERATIONS (Unaudited)

 

For the Three Months Ended March 31, 2003

 

		Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
		(In thousands)
Revenues:
Oil and natural gas sales		$	3,067		$	6,006		$	17,937		$	—		$	27,010
Other income (loss)		(1,729		)	—			32			—			(1,697		)
Equity in earnings of subsidiaries		11,104			—			—			(11,104		)	—
Total revenues and other income		12,442			6,006			17,969			(11,104		)	25,313
Costs and expenses:
Oil and natural gas production		3,382			1,526			3,612			—			8,520
Depreciation, depletion and amortization		1,495			880			2,704			—			5,079
Accretion of discount on asset retirement obligations		81			57			157			—			295
General and administrative		2,274			—			1,274			—			3,548
Interest		300			—			808			—			1,108
Total costs and expenses		7,532			2,463			8,555			—			18,550
Income before income taxes		4,910			3,543			9,414			(11,104		)	6,763
Income tax expense		—			—			2,669			—			2,669
Income before cumulative effect of change in accounting principle		4,910			3,543			6,745			(11,104		)	4,094
Cumulative effect of change in accounting principle, net of income taxes		(561		)	—			816			—			255
Net income		$	4,349		$	3,543		$	7,561		$	(11,104	)	$	4,349

 

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