XTO ENERGY INC - 10-Q Quarterly Report

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2002

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 1-10662

XTO Energy Inc.

(Exact name of registrant as specified in its charter)

Delaware		75-2347769
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

810 Houston Street, Suite 2000, Fort Worth, Texas		76102
(Address of principal executive offices)		(Zip Code)

(817) 870-2800

(Registrant’s telephone number, including area code)

NONE

(Former name, former address and former fiscal year, if changed since last report)

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 ¨

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:

Class		Outstanding as of November 1, 2002
Common stock, $.01 par value		126,632,527

XTO ENERGY INC.

Form 10-Q for the Quarterly Period Ended September 30, 2002

INDEX

		Page

PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements

	Consolidated Balance Sheets at September 30, 2002 and December 31, 2001	3

	Consolidated Income Statementsfor the Three and Nine Months Ended September 30, 2002 and 2001	4

	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2002 and 2001	5

	Notes to Consolidated Financial Statements	6

	Independent Accountants’ Review Report	19

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	28

Item 4.	Controls and Procedures	29

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	30

Item 6.	Exhibits and Reports on Form 8-K	30

	Signatures	32

	Certifications	33

PART I. FINANCIAL INFORMATION

XTO ENERGY INC.

Consolidated Balance Sheets


(in thousands, except shares)	September 30, 2002			December 31, 2001
	(Unaudited)
ASSETS

Current Assets:
Cash and cash equivalents	$	5,588		$	6,810
Accounts receivable, net		128,143			111,101
Derivative fair value		18,466			107,526
Other current assets		12,133			13,930

Total Current Assets		164,330			239,367


Property and Equipment, at cost – successful efforts method:
Producing properties		2,841,282			2,359,534
Undeveloped properties		8,038			9,545
Other		49,627			43,584

Total Property and Equipment		2,898,947			2,412,663
Accumulated depreciation, depletion and amortization		(720,585	)		(571,276	)

Net Property and Equipment		2,178,362			1,841,387


Other Assets:
Derivative fair value		2,476			18,174
Other		34,487			33,399

Total Other Assets		36,963			51,573


TOTAL ASSETS	$	2,379,655		$	2,132,327


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities:
Accounts payable and accrued liabilities	$	134,749		$	125,486
Payable to royalty trusts		3,808			2,233
Derivative fair value		37,717			1,024
Enron Btu swap contract		43,272			43,272
Current income taxes payable		525			600
Deferred income taxes payable		6,496			27,330
Other current liabilities		2,712			1,898

Total Current Liabilities		229,279			201,843


Long-term Debt		975,000			856,000


Other Long-term Liabilities:
Derivative fair value		21,649			28,331
Deferred income taxes payable		242,915			199,091
Other long-term liabilities		24,999			26,012

Total Other Long-term Liabilities		289,563			253,434


Commitments and Contingencies (Note 4)

Stockholders’ Equity:
Common stock ($.01 par value, 250,000,000 shares authorized, 134,816,539 and 131,988,733 shares issued)		1,348			1,320
Additional paid-in capital		512,528			485,094
Treasury stock (8,367,267 and 8,215,998 shares)		(67,638	)		(64,714	)
Retained earnings		454,937			328,712
Accumulated other comprehensive income (loss)		(15,362	)		70,638

Total Stockholders’ Equity		885,813			821,050


TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	2,379,655		$	2,132,327

See Accompanying Notes to Consolidated Financial Statements.

XTO ENERGY INC.

Consolidated Income Statements (Unaudited)


(in thousands, except per share data)	Three Months Ended September 30						Nine Months Ended September 30
	2002			2001			2002			2001
REVENUES
Oil and condensate	$	31,988		$	29,594		$	84,366		$	94,193
Gas and natural gas liquids		167,860			165,453			479,495			552,607
Gas gathering, processing and marketing		1,798			2,615			7,811			9,806
Other		62			(355	)		(849	)		(1,126	)

Total Revenues		201,708			197,307			570,823			655,480


EXPENSES
Production		32,788			27,944			93,546			82,773
Taxes, transportation and other		14,275			12,556			38,917			52,786
Exploration		337			3,096			1,688			3,589
Depreciation, depletion and amortization		54,074			39,812			149,077			111,709
Gas gathering and processing		2,229			2,306			6,715			7,056
General and administrative		8,416			7,481			34,949			26,198
Derivative fair value (gain) loss		(2,807	)		(18,011	)		(1,676	)		(64,339	)

Total Expenses		109,312			75,184			323,216			219,772


OPERATING INCOME		92,396			122,123			247,607			435,708


OTHER INCOME (EXPENSE)
Loss on extinguishment of debt		—			—			(7,844	)		—
Interest expense, net		(14,962	)		(12,969	)		(39,368	)		(44,324	)

Total Other Income (Expense)		(14,962	)		(12,969	)		(47,212	)		(44,324	)

INCOME BEFORE INCOME TAX AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE		77,434			109,154			200,395			391,384


INCOME TAX
Current		35			62			278			19,374
Deferred		27,106			38,750			70,146			119,798

Total Income Tax Expense		27,141			38,812			70,424			139,172


NET INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE		50,293			70,342			129,971			252,212
Cumulative effect of accounting change, net of tax		—			—			—			(44,589	)

NET INCOME	$	50,293		$	70,342		$	129,971		$	207,623


EARNINGS PER COMMON SHARE
Basic:
Net income before cumulative effect of accounting change	$	0.40		$	0.57		$	1.04		$	2.07
Cumulative effect of accounting change, net of tax		—			—			—			(0.37	)

Net income	$	0.40		$	0.57		$	1.04		$	1.70

Diluted:
Net income before cumulative effect of accounting change	$	0.40		$	0.56		$	1.03		$	2.03
Cumulative effect of accounting change, net of tax		—			—			—			(0.36	)

Net income	$	0.40		$	0.56		$	1.03		$	1.67


DIVIDENDS DECLARED PER COMMON SHARE	$	0.0100		$	0.0100		$	0.0300		$	0.0267


WEIGHTED AVERAGE COMMON SHARES OUTSTANDING		125,426			123,596			124,455			122,112

See Accompanying Notes to Consolidated Financial Statements.

XTO ENERGY INC.

Consolidated Statements of Cash Flows (Unaudited)


(in thousands)	Nine Months Ended September 30
	2002			2001
OPERATING ACTIVITIES
Net income	$	129,971		$	207,623
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		149,077			111,709
Non-cash incentive compensation		10,216			3,491
Deferred income tax		70,146			119,798
(Gain) loss from sale of properties		(145	)		365
Non-cash derivative fair value (gain) loss		8,006			(71,737	)
Cumulative effect of accounting change, net of tax		—			44,589
Loss on extinguishment of debt		7,844			—
Other non-cash items		(407	)		(3,286	)
Changes in operating assets and liabilities (a)		6,329			34,737

Cash Provided by Operating Activities		381,037			447,289


INVESTING ACTIVITIES
Proceeds from sale of property and equipment		157			202
Property acquisitions		(198,578	)		(202,998	)
Development costs		(293,510	)		(269,950	)
Other property and asset additions		(5,987	)		(10,427	)
Officer loan repayments		—			6,496

Cash Used by Investing Activities		(497,918	)		(476,677	)


FINANCING ACTIVITIES
Proceeds from long-term debt		888,000			523,000
Payments on long-term debt		(769,000	)		(482,000	)
Dividends		(3,719	)		(3,177	)
Senior note offering costs		(8,381	)		—
Net proceeds from exercises of stock options and warrants		18,368			14,281
Subordinated note redemption costs		(4,714	)		—
Purchases of treasury stock and other		(4,895	)		(25,030	)

Cash Provided by Financing Activities		115,659			27,074


DECREASE IN CASH AND CASH EQUIVALENTS		(1,222	)		(2,314	)

Cash and Cash Equivalents, Beginning of Period		6,810			7,438


Cash and Cash Equivalents, End of Period	$	5,588		$	5,124


(a) Changes in Operating Assets and Liabilities
Accounts receivable	$	(17,789	)	$	47,031
Other current assets		1,797			(6,259	)
Other assets		949			336
Accounts payable, accrued liabilities and payable to royalty trusts		22,161			(25,633	)
Other current liabilities		(789	)		19,161
Other long-term liabilities		—			101

	$	6,329		$	34,737

See Accompanying Notes to Consolidated Financial Statements.

XTO ENERGY INC.

Notes to Consolidated Financial Statements

1. Interim Financial Statements

The accompanying consolidated financial statements of XTO Energy Inc. (formerly named Cross Timbers Oil Company), with the exception of the consolidated balance sheet at December 31, 2001, have not been audited by independent public accountants. In the opinion of the Company’s management, the accompanying financial statements reflect all adjustments necessary to present fairly the Company’s financial position at September 30, 2002, its income for the three and nine months ended September 30, 2002 and 2001, and its cash flows for the nine months ended September 30, 2002 and 2001. All such adjustments are of a normal recurring nature. Certain amounts presented in prior period financial statements have been reclassified for consistency with current period presentation. The results for interim periods are not necessarily indicative of annual results.

The financial data for the three- and nine-month periods ended September 30, 2002 included herein have been subjected to a limited review by KPMG LLP, the registrant’s independent accountants. The accompanying review report of independent accountants is not a report within the meaning of Sections 7 and 11 of the Securities Act of 1933 and the independent accountant’s liability under Section 11 does not extend to it. The Company’s consolidated financial statements for the year ended December 31, 2001 were audited by other independent accountants.

Certain disclosures have been condensed or omitted from these financial statements. Accordingly, these financial statements should be read with the consolidated financial statements included in the Company’s 2001 Annual Report on Form 10-K.

As of April 1, 2002, the Company early adopted the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections, related to rescission of SFAS No. 4, Reporting Gains and Losses from Extinguishment of Debt, by reporting such losses (Note 3) as non-extraordinary.

2. Related Party Transactions

A company, partially owned by a director of the Company, performed consulting services in connection with the Company’s acquisition of properties in East Texas, Louisiana and the San Juan Basin of New Mexico during 2002 (Note 13). The director-related company received a fee of $2.4 million for these services, which was 1% of the total of the property purchase price and the related exchange transaction value.

3. Long-term Debt

The Company’s outstanding debt consists of the following:

(in thousands)	September 30, 2002		December 31, 2001
Senior debt-
Bank debt under the revolving credit agreement due May 12, 2005	$	450,000	$	556,000
7½% senior notes due April 15, 2012		350,000		—

Subordinated debt-
9¼% senior subordinated notes due April 1, 2007		—		125,000
8¾% senior subordinated notes due November 1, 2009		175,000		175,000


Total long-term debt	$	975,000	$	856,000

On September 30, 2002, borrowings under the revolving credit agreement with commercial banks were $450 million with unused borrowing capacity of $350 million. The average interest rate of 3.24% at September 30, 2002 is based on the one-month London Interbank Offered Rate plus 1.375%.

Under the terms of an agreement with a bank counterparty, the Company purchased and canceled $9.7 million of its 9¼% senior subordinated notes on April 1, 2002. On June 3, 2002, the Company redeemed the remaining $115.3 million of its 9¼% notes at a redemption price of 104.625%, or $120.6 million, plus accrued interest of $1.8 million. As a result of these transactions, the Company recorded a pre-tax loss on extinguishment of debt of $7.8 million.

On April 23, 2002, the Company sold $350 million of 7½% senior notes due in 2012. The notes are general unsecured senior indebtedness ranking above the Company’s senior subordinated notes, but effectively subordinate to the Company’s secured bank borrowings. The senior notes require no sinking fund payments. Net proceeds of $341.6 million from the sale of notes have been used to finance property transactions (Note 13), to redeem the Company’s 9¼% senior subordinated notes and to reduce bank debt.

Under the terms of an agreement with a bank counterparty, the Company purchased and canceled $11.8 million of its 8¾% senior subordinated notes on November 1, 2002. Including the effects of this agreement and expensing of related deferred debt cost, the Company will record a pre-tax loss on extinguishment of debt of approximately $700,000 in fourth quarter 2002.

4. Commitments and Contingencies

Litigation

On April 3, 1998, a class action lawsuit, styled Booth, et al. v. Cross Timbers Oil Company, was filed against the Company in the District Court of Dewey County, Oklahoma. The action was filed on behalf of all persons who, at any time since June 1991, have been paid royalties on gas produced from any gas well within the State of Oklahoma under which the Company has assumed the obligation to pay royalties. The plaintiffs allege that the Company has reduced royalty payments by post-production deductions and has entered into contracts with subsidiaries that were not arm’s-length transactions. The plaintiffs further allege that these actions reduced the royalties paid to the plaintiffs and those similarly situated, and that such actions are a breach of the leases under which the royalties are paid. These deductions allegedly include production and post-production costs, marketing costs, administration costs and costs incurred by the Company in gathering, compressing, dehydrating, processing, treating, blending and/or transporting the gas produced. The Company contends that, to the extent any fees are proportionately borne by the plaintiffs, these fees are established by arm’s-length negotiations with third parties or, if charged by affiliates, are comparable to fees charged by third party gatherers or processors. The Company further contends that any such fees enhance the value of the gas or the products derived from the gas. The plaintiffs are seeking an accounting and payment of the monies allegedly owed to them. A hearing on the class certification issue has not been scheduled. The parties have entered into court-ordered mediation, and are continuing to discuss the terms of a possible settlement. Management’s estimate of the potential liability from this claim has been accrued in the Company’s financial statements.

On October 17, 1997, an action, styled United States of America ex rel. Grynberg v. Cross Timbers Oil Company, et al., was filed in the U. S. District Court for the Western District of Oklahoma against the Company and certain of its subsidiaries by Jack J. Grynberg on behalf of the United States under the qui tam provisions of the False Claims Act. The plaintiff alleges that the Company underpaid royalties on gas produced from federal leases and lands owned by Native Americans by at least 20% as a result of mismeasuring the volume of gas and incorrectly analyzing its heating content. According to the U.S. Department of Justice, the plaintiff has made similar allegations in over 70 actions filed against more than 300 other companies. The plaintiff seeks to recover the amount of royalties not paid, together with treble damages, a civil penalty of $5,000 to $10,000 for each violation and attorney fees and expenses. The plaintiff also seeks an order for the Company to cease the allegedly improper measuring practices. After its review, the Department of Justice decided in April 1999 not to intervene and asked the court to unseal the case. The court unsealed the case in May 1999. A multi-district litigation panel ordered that the lawsuits against the Company and other companies filed by Grynberg be transferred and consolidated to the federal district court in Wyoming. The Company

and other defendants filed a motion to dismiss the lawsuit, which was denied. The Company believes that the allegations of this lawsuit are without merit and intends to vigorously defend the action. Any potential liability from this claim cannot currently be reasonably estimated, and no provision has been accrued in the Company’s financial statements.

In February 2000, the Department of Interior notified the Company and several other producers that certain Native American leases located in the San Juan Basin had expired due to the failure of the leases to produce in paying quantities from February through August 1990. The Department of Interior has demanded abandonment of the property as well as payment of the gross proceeds from the wells minus royalties paid from the date of the alleged cessation of production to present. The Company has reached a tentative settlement with the Department of Interior to pay $288,000 in settlement of all claims. Management’s estimate of the potential liability from this claim has been accrued in the Company’s financial statements.

In June 2001, the Company was served with a lawsuit styled Price, et al. v. Gas Pipelines, et al. (formerly Quinque case). The action was filed in the District Court of Stevens County, Kansas, against the Company and one of its subsidiaries, along with over 200 natural gas transmission companies, producers, gatherers and processors of natural gas. Plaintiffs seek to represent a class of plaintiffs consisting of all similarly situated gas working interest owners, overriding royalty owners and royalty owners either from whom the defendants had purchased natural gas or who received economic benefit from the sale of such gas since January 1, 1974. No class has been certified. The allegations in the case are similar to those in the Grynberg case; however, the Price case broadens the claims to cover all oil and gas leases (other than the Federal and Native American leases that are the subject of the Grynberg case). The complaint alleges that the defendants have mismeasured both the volume and heating content of natural gas delivered into their pipelines resulting in underpayments to the plaintiffs. Plaintiffs assert a breach of contract claim, negligent or intentional misrepresentation, civil conspiracy, common carrier liability, conversion, violation of a variety of Kansas statutes and other common law causes of action. The amount of damages was not specified in the complaint. In September 2001, the Company filed a motion to dismiss the lawsuit, which is currently pending. In February 2002, the Company and one of its subsidiaries were dismissed from the suit and another subsidiary of the Company was added. The Company believes that the allegations of this lawsuit are without merit and intends to vigorously defend the action. Any potential liability from this claim cannot currently be reasonably estimated, and no provision has been accrued in the Company’s financial statements.

The Company is involved in various other lawsuits and certain governmental proceedings arising in the ordinary course of business. Company management and legal counsel do not believe that the ultimate resolution of these claims, including the lawsuits described above, will have a material effect on the Company’s financial position or liquidity, although an unfavorable outcome could have a material adverse effect on the operations of a given interim period or year.

See Note 6 regarding Enron Corporation bankruptcy and Note 7 regarding commodity sales commitments.

5. Financial Instruments

Derivatives

The Company uses financial and commodity-based derivative contracts to manage exposures to commodity price and interest rate fluctuations. The Company does not hold or issue derivative financial instruments for speculative or trading purposes. See Note 7.

In 1995, the Company entered a contract to sell gas based on crude oil pricing, referred to as the Enron Btu swap contract. This contract was terminated as a result of the bankruptcy filing of Enron Corporation (Note 6). Because the contract pricing was not clearly and closely associated with natural gas prices, it was considered a non-hedge derivative financial instrument, with changes in fair value recorded as a derivative (gain) loss in the income statement.

Prior to termination of the Enron Btu swap contract, the Company entered derivative contracts with another counterparty to effectively defer until 2005 and 2006 any cash flow impact related to 25,000 Mcf of daily gas deliveries

in 2002 that were to be made under the Enron Btu swap contract. Changes in fair value of these contracts are recorded as a derivative (gain) loss in the income statement. In March 2002, the Company terminated some of these contracts with maturities of May through December 2002 and received $6.6 million from the counterparty. Because these contracts are non-hedge derivatives, most of the $6.6 million gain related to their termination was recorded as derivative fair value gain in the fourth quarter 2001 income statement.

All derivative financial instruments are recorded on the balance sheet at fair value. Fair value is generally determined based on the difference between the fixed contract price and the underlying market price at the determination date, and/or the value confirmed by the counterparty. Changes in the fair value of effective cash flow hedges are recorded as a component of accumulated other comprehensive income, which is later transferred to earnings when the hedged transaction occurs. Changes in the fair value of derivatives that are not designated as hedges, as well as the ineffective portion of the hedge derivatives, are recorded in derivative fair value (gain) loss in the income statement. This ineffective portion is calculated as the estimated cumulative excess of the derivative (gain) loss over the associated cumulative (gain) loss in the expected cash flows from the item hedged.

The components of derivative fair value (gain) loss, as reflected in the consolidated income statements are:

(in thousands)	Three Months Ended September 30						Nine Months Ended September 30
	2002			2001			2002			2001
Change in fair value of the Enron Btu swap contract	$	—		$	(11,664	)	$	—		$	(32,418	)
Change in fair value of call options and other derivatives that do not qualify for hedge accounting		(5,929	)		(4,574	)		(4,229	)		(30,112	)
Ineffective portion of derivatives qualifying for hedge accounting		3,122			(1,773	)		2,553			(1,809	)

Derivative fair value (gain) loss	$	(2,807	)	$	(18,011	)	$	(1,676	)	$	(64,339	)

The estimated fair values of derivatives included in the consolidated balance sheets at September 30, 2002 and December 31, 2001 are summarized below. The decrease from a net derivative asset at December 31, 2001 to a net derivative liability at September 30, 2002 is primarily attributable to higher natural gas prices at September 30, 2002 and cash settlements during the period.

(in thousands)	September 30, 2002			December 31, 2001
Derivative Assets:
Fixed-price natural gas futures and swaps	$	19,805		$	116,829
Interest rate swap		1,137			2,791
Other (a) (b)		—			6,080
Derivative Liabilities:
Fixed-price natural gas futures and swaps		(43,180	)		(19,198	)
Collars		(4,119	)		—
Other (a)		(12,067	)		(10,157	)

Net derivative asset (liability)	$	(38,424	)	$	96,345

(a)

These contracts were entered prior to termination of the Enron Btu swap contract and effectively defer until 2005 and 2006 any cash flow impact related to 25,000 Mcf of daily gas deliveries in 2002 that were to be made under the Enron Btu swap contract.

(b)

In March 2002, the Company terminated contracts with maturities of May through December 2002 and received $6.6 million from the counterparty.

Concentration of Credit Risk

Most of the Company’s receivables are from a diverse group of energy companies, including major integrated companies, utilities, pipelines, wholesale gatherers, and marketing, oil refining and merchant power companies. In recent months, there has been an increased level of uncertainty regarding the credit quality of many companies in the energy industry. In response to this concern, the Company has tightened the standards under which it will sell to companies under an open line of credit, and management believes the Company has appropriate procedures to reduce the risk of noncollection of its receivables. As of September 30, 2002, the Company’s allowance for collectibility of all accounts receivable was $5.4 million.

Financial and commodity-based futures and swap contracts expose the Company to the credit risk of nonperformance by the counterparty to the contracts. This risk is lessened by the Company’s diversification of its exposure among primarily major financial institutions.

6. Enron Corporation Bankruptcy

As of December 2, 2001, the date of its bankruptcy filing, Enron Corporation was the counterparty to some of the Company’s hedge derivative contracts, as well as a purchaser of natural gas under certain physical delivery contracts. One of these contracts was the Enron Btu swap contract (Note 5).

The Company sent Enron notices of contract terminations in November and December 2001. Based on the fair value as of the contract termination dates, Enron owes the Company $7.8 million for physical gas deliveries in November and December 2001, and $13.5 million for net gains on hedge derivative contracts. These amounts are recorded in the balance sheet at September 30, 2002 and December 31, 2001. Enron also owes the Company $14.1 million in net unrealized gains related to undelivered gas under physical delivery contracts. This amount, however, will not be recorded in the financial statements until collectibility is assured.

Also recorded in the balance sheet at September 30, 2002 and December 31, 2001 is a current liability of $43.3 million related to the Enron Btu swap contract, based on fair values at the date of contract termination. As specified under the contract termination provisions, the Company, as the nondefaulting party, has notified Enron that its liability under this contract has been reduced to zero. Based upon discussions with outside legal counsel, the Company believes that these termination provisions are legally enforceable, and accordingly, it has no liability under this contract. However, under generally accepted accounting principles, this liability cannot be credited to income until legal extinguishment of the debt is finalized.

In the event the termination provisions of the Enron Btu swap contract are ultimately not enforced, the Company believes that, based on contract provisions and the opinion of outside legal counsel, it should have the right to offset any Enron Btu swap contract liability against all amounts due from Enron, including amounts related to undelivered gas under physical delivery contracts. Because the recorded Enron Btu swap contract liability exceeds total Enron receivables at September 30, 2002 and December 31, 2001, no reserve for asset collectibility has been recorded.

The Company and Enron have entered an agreement, which is subject to bankruptcy court approval, to settle all claims under the contracts between the parties. Enron filed a motion with the bankruptcy court on November 13, 2002, requesting that the court approve this agreement. The agreement generally meets Company management’s expectations and contemplates a payment to Enron in return for the termination of the contracts and the resolution of all issues related to the contracts. The terms of the agreement are subject to a confidentiality agreement, but the Company will disclose the relevant terms upon issuance by the bankruptcy court of an order approving the settlement. A hearing on the motion is scheduled for December 12, 2002.

The following is a summary of recorded, unrecorded and total amounts related to Enron, which do not reflect the terms of the proposed settlement agreement:

(in thousands)	Receivable (Payable) at September 30, 2002 and December 31, 2001
	Recorded			Unrecorded		Total
Accounts receivable:

Physical delivery contracts	$	7,817		$	14,069	$	21,886
Hedge derivative contract fair value		13,534			—		13,534


Total accounts receivable		21,351			14,069		35,420

Current liability – Enron Btu swap contract fair value		(43,272	)		—		(43,272	)


Net asset (liability)	$	(21,921	)	$	14,069	$	(7,852	)

7. Commodity Sales Commitments

Natural Gas

The Company has entered natural gas futures contracts and swap agreements that effectively fix prices for the production and periods shown below. Prices to be realized for hedged production are expected to be less than these fixed prices because of location, quality and other adjustments. See Note 5 regarding accounting for commodity hedges.

		Futures Contracts and Swap Agreements
Production Period		Mcf per Day	Average NYMEX Price per Mcf
2002	November to December	315,000	$3.74(a)
2003	January to March	510,000	4.05(b)
	April to June	400,000	3.87
	July to December	350,000	3.87
2004	January to December	75,000	3.88

(a)

Includes approximately $0.04 per Mcf gain that will be deferred and recognized in 2003 related to contract terminations and hedge redesignations.

(b)

Includes approximately $0.18 per Mcf gain that will be deferred and recognized in April through December 2003 related to contract terminations and hedge redesignations.

The Company has closed certain future contracts and swap agreements that were designated as cash flow hedges with deferred gains of $5.8 million recorded in accumulated other comprehensive income. These deferred gains, of which $1 million is related to terminated Enron futures contracts, will be recognized as revenue in the periods from November 2002 to December 2003.

In March 2002, the Company entered collar agreements which provide a floor (put) and ceiling (call) price for natural gas. If the market price of natural gas exceeds the ceiling price, the Company pays the counterparty the difference between these prices. If the market price of natural gas is between the floor and ceiling price, no payments are due from either the Company or the counterparty. If the floor price exceeds the market price, the Company receives from the counterparty the difference between these prices. Prices to be realized are expected to be less than these floor and ceiling prices because of location, quality and other adjustments. The Company has entered into collar agreements for the following production periods:

		Average NYMEX Price (a)
2002 Production Period	Mcf per Day	Floor	Ceiling
November to December	165,000	$3.27	$3.89

(a)

Includes reduction of $0.10 per Mcf for cost of collars.

The Company has entered basis swap agreements which effectively fix basis for the following production and periods:

	Location
Production Period	Arkoma			Houston Ship Channel			Mid-Continent			Rockies			San Juan Basin			Total
2002
November
Mcf per day		70,000			270,000			45,000			15,000			50,000		450,000
Basis per Mcf (a)	$	(0.11	)	$	(0.02	)	$	(0.14	)	$	(0.51	)	$	(0.36	)
December
Mcf per day		50,000			270,000			45,000			15,000			50,000		430,000
Basis per Mcf (a)	$	(0.10	)	$	(0.02	)	$	(0.14	)	$	(0.51	)	$	(0.36	)

2003
January to March
Mcf per day		50,000			280,000			45,000			15,000			50,000		440,000
Basis per Mcf (a)	$	(0.10	)	$	(0.02	)	$	(0.14	)	$	(0.51	)	$	(0.36	)

April to October
Mcf per day		70,000			130,000			30,000			15,000			40,000		285,000
Basis per Mcf (a)	$	(0.11	)	$	0.00		$	(0.14	)	$	(0.57	)	$	(0.38	)

November to December
Mcf per day		10,000			60,000			10,000			5,000			20,000		105,000
Basis per Mcf (a)	$	(0.07	)	$	0.00		$	(0.15	)	$	(0.65	)	$	(0.40	)

2004
January to March
Mcf per day		10,000			—			10,000			5,000			20,000		45,000
Basis per Mcf (a)	$	(0.07	)		—		$	(0.15	)	$	(0.65	)	$	(0.40	)

(a)

Additions (reductions) to NYMEX gas prices for location, quality and other adjustments.

In the first nine months of 2002, net gains on futures, collars and basis swap hedge contracts increased gas revenue by $62.3 million. Including the effect of fixed price physical delivery contracts, all hedging activities increased gas revenue by $88 million in the first nine months of 2002. During the first nine months of 2001, net losses on futures and basis swap hedge contracts reduced gas revenue by $33.5 million. Including the effect of fixed price physical delivery contracts, all hedging activities increased gas revenue by $35.2 million in the first nine months of 2001. As of September 30, 2002, an unrealized pre-tax derivative fair value loss of $20.2 million, related to cash flow hedges of gas price risk, was recorded in accumulated other comprehensive income. The ultimate settlement value of these hedges will be recognized in the income statement as gas revenue when the hedged gas sales occur over the next 27 months.

The Company’s settlement of futures, collars and basis swap contracts related to October 2002 gas production resulted in increased gas revenue of $2.3 million, or approximately $0.14 per Mcf.

The Company has entered gas physical delivery contracts that are considered to be normal sales, and therefore, are not recorded as derivatives in the financial statements, because they are not expected to be net cash settled. These contracts effectively fix prices for the following production and periods:

Location	2002 Production Period	Mcf per Day	Fixed Price per Mcf
Arkoma	October to December	20,000	$3.61
East Texas	October to December	10,000	3.63

Crude Oil

In July 2002, the Company entered oil futures contracts to sell 6,000 Bbls per day from August 2002 through March 2003 at the following NYMEX prices. Prices to be realized for hedged oil production are expected to be less than these NYMEX prices because of location, quality and other adjustments.

2002		2003
November	$26.31	January	$25.79
December	26.04	February	25.58
		March	25.36

Also in July 2002, the Company entered a sour oil basis swap on 5,000 Bbls of oil per day from August 2002 through June 2003 at the NYMEX West Texas Intermediate price less $1.25 per Bbl to effectively fix the location and quality price differential. Because this basis swap agreement includes an extendable option, it does not qualify for hedge accounting.

In the first nine months of 2002, net losses on futures and basis swap hedge contracts decreased oil revenue by $600,000. As of September 30, 2002, an unrealized pre-tax derivative fair value loss of $3.4 million, related to cash flow hedges of oil price risk, was recorded in accumulated other comprehensive income. The ultimate settlement value of these hedges will be recognized in the income statement as oil revenue over the next five months.

The Company’s settlement of futures and differential swap contracts related to October 2002 oil production resulted in decreased oil revenue of $400,000, or approximately $1.00 per Bbl.

8. Equity

In October 2001, the Company filed a shelf registration statement with the Securities and Exchange Commission to potentially offer securities which may include debt securities, preferred stock, common stock or warrants to purchase debt securities, preferred stock or common stock. The total price of securities that can be offered is $600 million, at prices and on terms to be determined at the time of sale. Net proceeds from the sale of such securities will be used for general corporate purposes, including reduction of bank debt. On April 23, 2002, the Company sold $350 million of 7½% senior notes under the shelf registration statement (Note 3).

As partial consideration for producing properties acquired in December 1997, the Company issued warrants to purchase 2,141,552 shares of common stock at a price of $6.70 per share for a period of five years. These warrants, valued at $5.7 million when issued and recorded as additional paid-in capital, were exercised on August 13, 2002, resulting in an increase to common stock and additional paid-in capital of $14.3 million.

See Note 12.

9. Common Shares Outstanding and Earnings per Common Share

The following reconciles earnings (numerator) and shares (denominator) used in the computation of basic and diluted earnings per share:

(in thousands, except per share data)	Three Months Ended September 30
	2002					2001
	Earnings		Shares	Earnings per Share		Earnings		Shares	Earnings per Share
Basic	$	50,293	125,426	$	0.40	$	70,342	123,596	$	0.57

Effect of dilutive securities:
Stock options		—	441				—	61
Warrants (a)		—	633				—	1,139

Diluted	$	50,293	126,500	$	0.40	$	70,342	124,796	$	0.56


	Nine Months Ended September 30
	2002					2001
	Earnings		Shares	Earnings per Share		Earnings		Shares	Earnings per Share
Basic	$	129,971	124,455	$	1.04	$	207,623	122,112	$	1.70

Effect of dilutive securities:
Stock options		—	448				—	585
Preferred stock		—	—				—	504
Warrants (a)		—	1,129				—	1,256

Diluted	$	129,971	126,032	$	1.03	$	207,623	124,457	$	1.67

(a)

All outstanding warrants were exercised on August 13, 2002. See Note 8. Dilutive effect is related to periods prior to exercise.

10. Comprehensive Income

In accordance with SFAS No. 130, Reporting Comprehensive Income, the following are components of comprehensive income:

(in thousands)	Three Months Ended September 30						Nine Months Ended September 30
	2002			2001			2002			2001
Net income	$	50,293		$	70,342		$	129,971		$	207,623


Other comprehensive income (loss):
Cumulative effect of accounting change		—			—			—			(103,574	)
Change in derivative fair value		(35,750	)		132,186			(70,643	)		187,525
Reclassification adjustments – contract (gain) loss settlements (a)		(19,805	)		(7,395	)		(61,665	)		34,940

		(55,555	)		124,791			(132,308	)		118,891
Income tax (expense) benefit		19,444			(43,677	)		46,308			(41,612	)


Total other comprehensive income (loss), net of tax		(36,111	)		81,114			(86,000	)		77,279


Total comprehensive income	$	14,182		$	151,456		$	43,971		$	284,902

(a)

For contract gain settlements, represents a reduction to other comprehensive income which is offset by contract proceeds included in oil and gas revenues. For contract loss settlements, represents an increase in other comprehensive income which is offset by contract payments that reduce oil and gas revenues.

11. Supplemental Cash Flow Information

The following are total interest and income tax payments (receipts) during each of the periods:

(in thousands)	Nine Months Ended September 30
	2002		2001
Interest	$	28,288	$	41,104
Income tax		353		(175	)

The accompanying consolidated statements of cash flows exclude the following non-cash equity transactions during the nine-month periods ended September 30, 2002 and 2001:

—

Grant of 462,000 performance shares and vesting of 516,000 performance shares in 2002 and grant of 448,000 performance shares and vesting of 249,000 performance shares in 2001

—

Conversion of 1.1 million shares of preferred stock into 5.3 million shares of common stock in 2001

12. Employee Benefit Plans

Stock Options

During the first nine months of 2002, a total of 365,000 stock options were exercised with a total exercise price of $4.9 million. As a result of these exercises, outstanding common stock increased by 291,000 shares and stockholders’ equity increased by a net $4.3 million. During the first nine months of 2002, 33,412 stock options were granted to nonemployee directors with an exercise price of $20.60 per share.

Performance Shares

During the first nine months of 2002, 454,000 performance shares were issued to key employees and 508,000 performance shares vested. As of September 30, 2002, there were 202,000 performance shares outstanding that vest when the common stock price reaches $21.67, 145,000 shares that vest when the common stock price reaches $22.00 and 13,500 shares that vest in increments of 6,750 in 2002 and 2003. The Company also issued to nonemployee directors a total of 8,250 performance shares in February 2002 which vested upon grant. Performance shares are expensed upon vesting at the common stock target, or current market, price. Non-cash compensation expense related to performance shares for the first nine months of 2002 was $10.2 million.

In October 2002, 202,000 performance shares vested when the common stock price reached $21.67, 145,000 performance shares vested when the stock price reached $22.00 and 150,000 performance shares issued in October vested when the stock price reached $23.34, resulting in non-cash compensation of $11.1 million. Treasury stock purchases related to these vested performance shares totaled $6.5 million. An additional 150,000 performance shares were issued in October that vest when the common stock price reaches $25.00.

13. Acquisitions

In March 2002, the Company acquired primarily gas-producing properties for $20 million in the East Texas Freestone Trend. This purchase was funded by bank borrowings. The Company also entered property transactions to increase its positions in East Texas, Louisiana and the San Juan Basin of New Mexico with a total purchase price of $144 million. The transactions, which were funded by proceeds from the Company’s sale of senior notes (Note 3) and were subject to typical post-closing adjustments, were as follows:

—

A purchase and sale agreement with CMS Oil and Gas Co. (CMS), a subsidiary of CMS Energy Corporation, to acquire properties in the Powder River Basin of Wyoming for $101 million. This acquisition was completed May 1, 2002.

—

An agreement to exchange the Powder River Basin properties acquired from CMS to Marathon Oil Company (Marathon), for primarily gas-producing properties in East Texas and Louisiana. The exchange was completed May 1, 2002.

—

An agreement to purchase primarily gas-producing properties in the San Juan Basin of New Mexico from Marathon for $43 million. This acquisition was completed on July 1, 2002.

Acquisitions were recorded using the purchase method of accounting. The following presents unaudited pro forma results of operations for the nine months ended September 30, 2002 and 2001 and the year ended December 31, 2001, as if these acquisitions had been consummated at the beginning of each period. These pro forma results are not necessarily indicative of future results.

	Pro Forma (Unaudited)
(in thousnds, except per share data)	Nine Months Ended September 30				Year Ended December 31
	2002		2001		2001
Revenues	$	584,883	$	707,615	$	899,495

Net income before cumulative effect of accounting change	$	131,631	$	268,973	$	310,877

Net income	$	131,631	$	224,384	$	266,288

Earnings per common share:

Basic	$	1.06	$	1.84	$	2.17

Diluted	$	1.04	$	1.80	$	2.14

Weighted average shares outstanding		124,455		122,112		122,505

In January 2001, the Company acquired gas properties in East Texas and Louisiana for $115 million from Herd Producing Company, Inc., and in February 2001, it acquired gas properties in East Texas for $45 million from Miller Energy, Inc. and other owners. In August 2001, the Company acquired primarily underdeveloped acreage in the Freestone area of East Texas for approximately $22 million. The purchases were funded through bank borrowings.

INDEPENDENT ACCOUNTANTS’ REVIEW REPORT

The Board of Directors and Shareholders of XTO Energy Inc.:

We have reviewed the accompanying consolidated balance sheet of XTO Energy Inc. (a Delaware corporation) and its subsidiaries as of September 30, 2002, the related consolidated income statements for the three- and nine-month periods ended September 30, 2002, and the consolidated cash flow statement for the nine-month period ended September 30, 2002. These financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the consolidated financial statements referred to above for them to be in conformity with accounting principles generally accepted in the United States of America.

The financial statements of XTO Energy Inc. as of and for the year ended December 31, 2001 were audited by other auditors who have ceased operations. Those auditors’ report, dated March 28, 2002, on those financial statements was unqualified. Such financial statements were not audited by us and, accordingly, we do not express an opinion or any form of assurance on the information set forth in the accompanying financial statements as of December 31, 2001. Additionally, the consolidated income statements for the three- and nine-month periods ended September 30, 2001, and the consolidated cash flow statement for the nine-month period ended September 30, 2001, were not reviewed by us and, accordingly, we do not express an opinion or any form of assurance on them.

As discussed in Note 1 to Consolidated Financial Statements, the Company changed its method of accounting for gains and losses on extinguishment of debt effective April 1, 2002, in connection with its adoption of provisions of Statement of Financial Accounting Standards (“SFAS”) No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections, related to rescission of SFAS No. 4.

KPMG LLP

Dallas, Texas

October 22, 2002

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read in conjunction with management’s discussion and analysis contained in the Company’s 2001 Annual Report on Form 10-K, as well as with the consolidated financial statements and notes thereto included in this quarterly report on Form 10-Q.

Oil and Gas Production and Prices

	Three Months Ended September 30						Nine Months Ended September 30
	2002		2001		Increase (Decrease)		2002		2001		Increase (Decrease)
Total production
Oil (Bbls)		1,195,592		1,224,472	(2	%)		3,558,761		3,711,632	(4	%)
Gas (Mcf)		49,354,740		39,191,076	26	%		136,857,900		110,311,913	24	%
Natural gas liquids (Bbls)		506,252		413,160	23	%		1,311,200		1,180,398	11	%
Mcfe		59,565,804		49,016,868	22	%		166,077,666		139,664,093	19	%

Average daily production
Oil (Bbls)		12,996		13,309	(2	%)		13,036		13,596	(4	%)
Gas (Mcf)		536,465		425,990	26	%		501,311		404,073	24	%
Natural gas liquids (Bbls)		5,503		4,491	23	%		4,803		4,324	11	%
Mcfe		647,454		532,792	22	%		608,343		511,590	19	%

Average sales price
Oil per Bbl	$	26.75	$	24.17	11	%	$	23.71	$	25.38	(7	%)
Gas per Mcf	$	3.26	$	4.08	(20	%)	$	3.38	$	4.82	(30	%)
Natural gas liquids per Bbl	$	14.00	$	13.43	4	%	$	12.91	$	17.39	(26	%)

Average NYMEX prices
Oil per Bbl	$	28.27	$	26.77	6	%	$	25.39	$	27.86	(9	%)
Gas per MMBtu	$	3.18	$	2.88	10	%	$	2.97	$	4.88	(39	%)


Bbl -		Barrel

Mcf -		Thousand cubic feet

Mcfe -		Thousand cubic feet of natural gas equivalent (computed on an energy equivalent basis of one Bbl equals six Mcf)

MMBtu -		One million British Thermal Units, a common energy measurement

Increased gas production is primarily attributable to development activity, partially offset by natural decline. Decreased oil production is primarily because of natural decline.

The average oil price for the first nine months of 2001 was higher as a result of global demand outpacing supply at the end of 2000 and early in 2001. Lagging demand in the remainder of 2001, attributable to a worldwide economic slowdown, caused oil prices to decline. OPEC members agreed to cut daily production by one million barrels in April 2001 and an additional one million barrels in September 2001 to adjust for weak demand and excess supply. The economic decline was accelerated by the terrorist attacks in the United States on September 11, 2001, placing further downward pressure on oil prices. OPEC cut an additional 1.5 million barrels per day for the first nine months of 2002, and in September 2002, announced it would maintain the production cut through December 2002. Oil prices have been higher in recent months because of lower inventories and rising tension in the Middle East. The average NYMEX price for October 2002 was $28.93 per Bbl. At November 1, 2002, the average NYMEX futures price for the following twelve months was $25.41 per Bbl.

Natural gas prices are dependent upon North American supply and demand, which is affected by weather conditions. Natural gas competes with alternative energy sources as a fuel for heating and the generation of electricity. Gas prices were unusually high at the beginning of 2001 as winter demand strained gas supplies. Gas prices declined during the remainder of 2001 because of fuel switching due to higher prices, milder weather and a weaker economy, which reduced the demand for gas to generate electricity and resulted in increased gas storage levels. As of December 31, 2001, the NYMEX gas price was $2.57 per MMBtu. Despite the winter of 2001-2002 being one of the warmest on record and resulting higher than average storage levels, gas prices have increased during 2002. The average NYMEX price for October 2002 was $4.07 per MMBtu. Gas prices increased recently because of the interruption of offshore gas supplies by hurricanes in the Gulf of Mexico and colder than normal weather early in the heating season. At November 1, 2002, the average NYMEX futures price for the following twelve months was $4.07 per MMBtu. Gas prices are expected to remain volatile.

The Company’s policy is to routinely hedge a portion of its production at commodity prices management deems attractive. The Company plans to continue this strategy. Such price hedging ultimately may or may not be beneficial. During third quarter 2002, the Company’s hedging activities increased gas revenue by $18.2 million, or $0.37 per Mcf and decreased oil revenue by $600,000, or $0.52 per Bbl. For the first nine months of 2002, the Company’s hedging activities increased gas revenue by $88 million, or $0.64 per Mcf and decreased oil revenue by $600,000, or $0.18 per Bbl. During third quarter 2001, hedging activities increased gas revenue by $54.6 million, or $1.39 per Mcf. During the first nine months of 2001, hedging activities increased gas revenue by $35.2 million, or $0.32 per Mcf.

The Company has hedged more than 90% of its remaining projected 2002 natural gas production at average NYMEX prices ranging between $3.64 and $3.84 per Mcf, and more than 70% of its expected 2003 gas production at an average price of $3.93. The Company has also hedged 75,000 Mcf per day of natural gas production from January to December 2004 at an average NYMEX price of $3.88 per Mcf. The Company has hedged 6,000 Bbls of oil production per day for October 2002 through March 2003, about 40% of expected oil production, at an average NYMEX price of $25.94 per Bbl. See Note 7 to Consolidated Financial Statements.

Results of Operations

Quarter Ended September 30, 2002 Compared with Quarter Ended September 30, 2001

Net income for third quarter 2002 was $50.3 million compared to $70.3 million for third quarter 2001. Third quarter 2002 earnings include a $1.8 million after-tax fair value gain related to derivatives that do not qualify for hedge accounting. Excluding this gain, earnings for the quarter were $48.5 million. Third quarter 2001 earnings include an $11.7 million after-tax fair value gain related to derivatives that do not qualify for hedge accounting. Excluding this gain, earnings for third quarter 2001 were $58.6 million.

Total revenues for third quarter 2002 were $201.7 million, a 2% increase from third quarter 2001 revenues of $197.3 million. Operating income for the quarter was $92.4 million, a 24% decrease from third quarter 2001 operating income of $122.1 million. Oil revenue increased $2.4 million (8%) primarily because of the 11% increase in oil prices, partially offset by the 2% decrease in production. Gas and natural gas liquids revenues increased $2.4 million (1%) primarily because of the 26% increase in gas volumes, the 23% increase in natural gas liquids volumes and the 4% increase in natural gas liquids prices. These increases were largely offset by the 20% decrease in gas prices. Third quarter gas gathering, processing and marketing revenues decreased $800,000 from third quarter 2001 primarily because of related derivative losses and lower gathering volumes and prices.

Excluding the derivative fair value (gain) loss, expenses for third quarter 2002 totaled $112.1 million, a 20% increase from third quarter 2001 expenses of $93.2 million. Production expense increased $4.8 million (17%) primarily because of higher production related to acquisitions and development. Taxes, transportation and other expense increased $1.7 million (14%) primarily because of higher production taxes and other deductions related to increased product revenues, and higher property taxes related to acquisitions. Depreciation, depletion and amortization increased $14.3 million (36%) because of higher drilling costs and increased production related to development. General and administrative expense increased $900,000 (12%) primarily because of Company growth.

The derivative fair value gain decreased from $18 million in third quarter 2001 to $2.8 million in third quarter 2002 primarily because of the change in fair value during third quarter 2001 of call options and the Enron Btu swap, which was terminated December 2001. See Note 5 to Consolidated Financial Statements.

Interest expense increased $2 million (15%) primarily because of a 22% increase in the weighted average principal related to property acquisitions and a decrease in capitalized interest from $1.5 million to $500,000, partially offset by a 14% decrease in the weighted average interest rate.

Nine Months Ended September 30, 2002 Compared with Nine Months Ended September 30, 2001

Net income for the nine months ended September 30, 2002 was $130 million, compared to $207.6 million for the same 2001 period. Earnings for the first nine months of 2002 include a $6.6 million after-tax charge for non-cash incentive compensation, a $5.1 million after-tax charge for extinguishment of debt and a $1.1 million after-tax fair value gain on derivatives that do not qualify for hedge accounting. Excluding these charges and gain, earnings were $140.6 million for the first nine months of 2002. Excluding a $44.6 million after-tax charge for adoption of the new derivative accounting principle, Statement of Financial Accounting Standards No. 133, an after-tax derivative fair value gain of $41.8 million, after-tax incentive compensation of $2.5 million and after-tax losses on property sales of $200,000, earnings for the first nine months of 2001 were $213.1 million.

Total revenues for the first nine months of 2002 were $570.8 million, or $84.7 million (13%) lower than revenues of $655.5 million for the first nine months of 2001. Operating income for the first nine months of 2002 was $247.6 million, a 43% decrease from operating income of $435.7 million for the comparable 2001 period. Oil revenue decreased $9.8 million (10%) because of the 7% decrease in prices and a 4% production decrease. Gas and natural gas liquids revenues decreased $73.1 million (13%) primarily because of the 30% decrease in gas prices and the 26% decrease in natural gas liquids prices. These price decreases were partially offset by the 24% increase in gas production and the 11% increase in natural gas liquids production. Gas gathering, processing and marketing revenues decreased $2 million (20%) primarily because of lower gathering prices, lower margins and related derivative losses.

Excluding derivative fair value (gain) loss, expenses for the first nine months of 2002 totaled $324.9 million, a 14% increase from total expenses for the first nine months of 2001 of $284.1 million. Production expense increased $10.8 million (13%) primarily because of higher production related to acquisitions and development, partially offset by lower fuel costs caused by decreased gas prices. Taxes, transportation and other expense decreased $13.9 million (26%) primarily because of lower product revenues, lower severance tax rates on new wells in East Texas and lower transportation fuel prices. Depreciation, depletion and amortization increased $37.4 million (33%) because of higher drilling costs and increased production related to development. General and administrative expense increased $8.8 million (33%) primarily because of a $6.3 million increase in non-cash incentive compensation and Company growth.

The decrease in derivative fair value gain, from $64.3 million in the first nine months of 2001 to $1.7 million in the first nine months of 2002, primarily reflects the change in fair value of call options and the Enron Btu swap in the first nine months of 2001. See Note 5 to Consolidated Financial Statements.

Interest expense decreased $5 million (11%) primarily because of a 23% decrease in the weighted average interest rate, partially offset by an 11% increase in the weighted average principal related to property acquisitions and a decrease in capitalized interest from $5 million to $3.8 million. During the first nine months of 2002, the Company recognized a $7.8 million loss on extinguishment of debt related to the redemption of its 9¼% senior subordinated notes.

Comparative Expenses per Mcf Equivalent Production

The following are expenses per Mcf equivalent (Mcfe) produced:

	Three Months Ended September 30						Nine Months Ended September 30
	2002		2001		Increase (Decrease)		2002		2001		Increase (Decrease)
Production	$	0.55	$	0.57	(4	%)	$	0.56	$	0.59	(5	%)
Taxes, transportation and other		0.24		0.26	(8	%)		0.23		0.38	(39	%)
Depreciation, depletion and amortization (DD&A)		0.91		0.81	12	%		0.90		0.80	13	%
General and administrative (G&A) (a)		0.14		0.15	(7	%)		0.15		0.16	(6	%)
Interest		0.25		0.26	(4	%)		0.24		0.32	(25	%)

(a)

Excludes non-cash incentive compensation.

The following are the primary reasons for variances of expenses on an Mcfe basis:

Production—Decreased production expense is primarily because of the increase in lower cost gas production through acquisitions and development.

Taxes, transportation and other—Most of these expenses vary with product prices. The significant decline in product prices is the primary reason for the lower nine-month expense per Mcfe. Decreased taxes, transportation and other expense is also because of lower severance tax rates on new wells in East Texas and lower transportation fuel prices.

DD&A—Increased DD&A is because of higher development costs per Mcfe.

G&A—Decreased G&A is primarily because of increased production, through acquisitions and development, outpacing increased personnel and other expenses related to Company growth.

Interest—Decreased interest expense is primarily because of lower interest rates and increased production, partially offset by increased weighted average principal and decreased capitalized interest.

Liquidity and Capital Resources

Cash Flow and Working Capital

Cash provided by operating activities was $381 million for the first nine months of 2002 compared with $447.3 million for the same 2001 period. Operating cash flow (defined as cash provided by operating activities before changes in operating assets and liabilities and exploration expense) decreased 10% from $416.1 million for the first nine months of 2001 to $376.4 million for the same 2002 period. Decreased cash flow is primarily because of decreased prices and increased operating expenses, partially offset by increased gas production from acquisitions and development activity.

During the nine months ended September 30, 2002, cash provided by operating activities of $381 million, borrowings of $888 million, proceeds from exercise of stock options and warrants of $18.4 million and from sale of property and equipment of $200,000 were used to fund net property acquisitions, development costs and other net capital additions of $498.1 million, debt payments of $769 million, senior note offering costs of $8.4 million, subordinated note redemption costs of $4.7 million, dividends of $3.7 million and treasury stock purchases and other financing activities of $4.9 million. The resulting decrease in cash and cash equivalents for the period was $1.2 million.

Total current assets decreased $75 million during the first nine months of 2002 primarily because of an $89.1 million decrease in derivative fair value related to cash settlements and increased natural gas prices, partially offset by a $17 million increase in accounts receivable due to increased product prices and timing of cash receipts. Total current liabilities increased $27.4 million during the first nine months of 2002, primarily because of a $36.7 million increase in derivative fair value liabilities, a $10.8 million increase in accounts payable and payable to royalty trusts, partially offset by a $20.8 million decrease in current deferred income taxes payable. Changes in current liabilities are generally related to increased natural gas prices and hedge derivative transactions.

Working capital decreased from $37.5 million at December 31, 2001 to negative working capital of $64.9 million at September 30, 2002 primarily because of the change in derivative fair value assets and liabilities, net of the related deferred tax effects. Any cash settlement of hedge derivatives should be offset by increased or decreased cash flows from the Company’s sale of related production. Therefore, the Company believes that most of its change in derivative fair value assets and liabilities are offset by changes in value of its oil and gas reserves. This offsetting change in value of oil and gas reserves, however, is not included in working capital.

Credit Risk Exposure

Financial and commodity-based swap contracts expose the Company to the credit risk of nonperformance by the counterparty to the contracts. This risk is lessened by the Company’s diversification of its exposure among primarily major financial institutions.

Enron Corporation Bankruptcy

The Company has recorded $21.4 million in accounts receivable and a $43.3 million Btu swap contract liability related to Enron Corporation. To the extent the Company ultimately realizes a cash settlement that differs from this net liability of $21.9 million, it will record a gain or loss on settlement and its working capital will change by the same amount. See Note 6 to Consolidated Financial Statements.

Acquisitions and Development

For the first nine months of 2002, the Company’s acquisition expenditures totaled $198.6 million, including property transactions completed in East Texas, Louisiana and the San Juan Basin of New Mexico with a total purchase price of $164 million. Of this amount, $20 million was funded by bank borrowings and the remaining $144 million was funded by proceeds from the Company’s sale of senior notes. See Note 13 to Consolidated Financial Statements.

Exploration and development expenditures for the first nine months of 2002 were $295.2 million, compared with $273.5 million for the first nine months of 2001. The Company has budgeted $350 to $375 million for 2002 exploration and development. Actual costs may vary significantly due to many factors, including development results and changes in drilling and service costs. Such expenditures are expected to be funded by cash flow from operations.

Through the first nine months of 2002, the Company participated in drilling 196 gas and nine oil wells, and in 347 workovers. In total, these projects have met or exceeded management expectations. Workovers have focused on recompletions, artificial lift and wellhead compression.

Drilling activity during the first nine months of 2002 was concentrated in East Texas and the Arkoma and San Juan basins. In East Texas, where 12 rigs are currently drilling, 70 wells were completed and an additional 35 wells are in

progress. The Company has 24 workovers completed or in progress in East Texas. The recent acquisitions in this area (see Note 13 to Consolidated Financial Statements) have added production and increased the Company’s inventory of drilling projects. The 27-mile gathering system, completed in January 2002 with a capacity of 400,000 Mcf per day, is now transporting 175,000 Mcf per day.

In the Arkoma Basin, 24 wells were completed in the first nine months of 2002 and an additional 22 wells are in progress. In this area, the Company has used a detailed development approach that examines each fault block in order to maximize hydrocarbon recovery. Many of the wells in this multi-pay basin were not initially stimulated or completed to more than two productive intervals. The Company has started a program to fracture-stimulate these wells along with a recompletion program to open additional intervals. The Company has 105 workovers completed or in progress in this area during the first nine months of 2002.

In the San Juan Basin, the Company completed 14 wells in the first nine months of 2002 and 14 wells are in progress. A total of 148 workovers have been completed or are in progress. The Company’s drilling program is focused on increased density drilling. A request to reduce current spacing of coalbed methane wells from 320 acres to 160 acres was approved by regulatory authorities in October 2002. This advancement will add 80 potential well locations. The Company also plans to implement a recently approved development program based on multi-zone completions that produce simultaneously.

The Company has also been active in the Mid-Continent area where, during the first nine months of 2002, 13 wells were completed, four wells are in progress and 65 workovers have been completed or are in progress.

The Company’s unused borrowing capacity of $350 million at September 30, 2002 under its revolving credit agreement is available for acquisitions and development.

Debt and Equity

As of September 30, 2002, long-term debt increased by $119 million from the balance at December 31, 2001. Net borrowings increased primarily to fund property acquisitions, less repayments from operating cash flow.

On April 23, 2002, the Company sold $350 million of 7½% senior notes due in 2012. The notes are general unsecured senior indebtedness ranking above the Company’s senior subordinated notes, but effectively subordinate to the Company’s secured bank borrowings. The senior notes require no sinking fund payments. Net proceeds of $341.6 million from the sale of notes have been used to finance property transactions (see Note 13 to Consolidated Financial Statements), to redeem the Company’s 9¼% senior subordinated notes and to reduce bank debt.

Under the terms of an agreement with a bank counterparty, the Company purchased and canceled $11.8 million of its 8¾% senior subordinated notes on November 1, 2002. Including the effects of the interest rate swap agreement and expensing of related deferred debt cost, the Company will record a pre-tax loss on extinguishment of debt of approximately $700,000 in fourth quarter 2002.

Stockholders’ equity at September 30, 2002 increased $64.8 million from year-end because of earnings of $130 million for the nine months ended September 30, 2002, and an increase in additional paid-in capital of $27.4 million related to exercise of stock options and warrants and issuance of performance shares, partially offset by a decrease in accumulated other comprehensive income of $86 million, treasury stock purchases of $2.9 million related to stock option exercises and performance share vesting and common stock dividends declared of $3.7 million. The decrease in accumulated other comprehensive income was attributable to the decline in fair value of cash flow hedge derivatives, which was related to the increase in natural gas prices and cash settlements during the quarter. The decline in accumulated other comprehensive income related to cash settlements is effectively offset by increased retained earnings

from receiving higher hedged gas prices. Any decline in accumulated other comprehensive income related to the fair value of derivatives that hedge future production is effectively offset by the increased value of proved reserves, which is not recorded in the financial statements.

Common Stock Dividends

In August 2002, the Board of Directors of the Company declared a third quarter common stock dividend of $0.01 per share that was paid in October.

Related Party Transactions

A company, partially owned by a director of the Company, performed consulting services in connection with the Company’s acquisition of properties in East Texas, Louisiana and the San Juan Basin of New Mexico during 2002. See Note 13 to Consolidated Financial Statements. The director-related company received a fee of $2.4 million for these services, which was 1% of the total of the property purchase price and the related exchange transaction value.

Accounting Pronouncements

In June 2001, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations, which amends SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, and addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. It requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the cost of the long-lived asset. The statement is required to be adopted for fiscal years beginning after June 15, 2002.

The Company currently accrues for any estimated asset retirement obligation, net of estimated salvage value, as part of its depletion and depreciation calculation. This method results in the recognition of the obligation over the life of the property on a unit-of-production basis. This estimated obligation is netted in property cost, as part of the accumulated depreciation, depletion and amortization balance. Under the method prescribed by SFAS No. 143, the retirement obligation is recorded as a liability at its estimated present value at the asset’s inception, with the offsetting charge to property cost. Periodic accretion of discount of the estimated liability is recorded in the income statement. The Company is in the process of evaluating the estimated impact of adoption of SFAS No. 143, including estimating the retirement obligation based on the nature, age and location of the property and recalculation of depreciation and depletion to date under the method prescribed. Because this evaluation must comprehend all the Company’s operated and nonoperated wells in various locations, this process is not expected to be complete until January 2003. Until then, the Company cannot reasonably estimate the impact of adoption of SFAS No. 143.

In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections. Effective April 1, 2002, the Company early adopted the provisions of SFAS No. 145 related to rescission of SFAS No. 4, Reporting Gains and Losses from Extinguishment of Debt, by reporting such losses as non-extraordinary. SFAS No. 145 also amends the accounting for certain sale-leaseback transactions entered after May 15, 2002, and rescinds SFAS Nos. 44 and 64, and amends other pronouncements for technical corrections for financial statements issued after May 15, 2002. The effects of these other rescissions and amendments do not have and are not expected to have a material effect on the Company’s financial statements.

In July 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. SFAS No. 146 requires that a liability for costs associated with exiting an activity (including restructurings) or disposal of long-lived assets be recognized when the liability is incurred and measured at the fair value of the liability. The provisions of SFAS No. 146 are required to be applied to exit or disposal activities initiated after December 31, 2002, and are not currently expected to have a material impact on the Company’s financial statements.

Forward-Looking Statements

Certain information included in this quarterly report and other materials filed or to be filed by the Company with the Securities and Exchange Commission, as well as information included in oral statements or other written statements made or to be made by the Company, contain projections and forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended, relating to the Company’s operations and the oil and gas industry. Such forward-looking statements may be or may concern, among other things, capital expenditures, cash flow, drilling activity, acquisition and development activities, pricing differentials, operating costs and expenses, production activities, oil, gas and natural gas liquids reserves and prices, hedging activities and the results thereof, liquidity, debt repayment, taxes, regulatory matters and competition. Such forward-looking statements are based on management’s current plans, expectations, assumptions, projections and estimates and are identified by words such as “expects,” “intends,” “plans,” “projects,” “predicts,” “anticipates,” “believes,” “estimates,” “goal,” “should,” “could,” “assume,” and similar words that convey the uncertainty of future events. These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that are difficult to predict. Therefore, actual results may differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or implied in such forward-looking statements.

Among the factors that could cause actual results to differ materially are:

—

crude oil and natural gas price fluctuations,

—

changes in interest rates,

—

the Company’s ability to acquire oil and gas properties that meet its objectives and to identify prospects for drilling,

—

higher than expected production costs and other expenses,

—

potential delays or failure to achieve expected production from existing and future exploration and development projects,

—

volatility of crude oil and natural gas prices and related financial derivatives,

—

basis risk and counterparty credit risk in executing commodity price risk management activities,

—

potential liability resulting from pending or future litigation, and

—

competition in the oil and gas industry as well as competition from other sources of energy.

In addition, these forward-looking statements may be affected by general domestic and international economic and political conditions.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in the Company’s 2001 Annual Report on Form 10-K, as well as with the consolidated financial statements and notes thereto included in this quarterly report on Form 10-Q.

Hypothetical changes in interest rates and prices chosen for the following estimated sensitivity effects are considered to be reasonably possible near-term changes generally based on consideration of past fluctuations for each risk category. It is not possible to accurately predict future changes in interest rates and commodity prices. Accordingly, these hypothetical changes may not necessarily be an indicator of probable future fluctuations.

Interest Rate Risk

The Company is exposed to interest rate risk on debt with variable interest rates. At September 30, 2002, the Company’s variable rate debt had a carrying value of $450 million, which approximated its fair value, and the Company’s fixed rate debt had a carrying value of $525 million and an approximate fair value of $554.2 million. Assuming a one percent, or 100-basis point, change in interest rates at September 30, 2002, the fair value of the Company’s fixed rate debt would change by approximately $34.6 million.

The Company entered an agreement with a bank to reduce the interest rate on $11.8 million face value of its 8¾% senior subordinated notes to a variable interest rate based on three-month LIBOR rates. This derivative financial instrument, which had a fair value gain of $1.1 million at September 30, 2002, was terminated on November 1, 2002 with an effective cash settlement of $1.4 million.

Commodity Price Risk

The Company hedges a portion of its price risks associated with its oil and natural gas sales. As of September 30, 2002, outstanding gas futures contracts and swap agreements had a net fair value loss of $19.7 million. The aggregate effect of a hypothetical 10% change in gas prices would result in a change of approximately $70.5 million in the fair value of these gas futures contracts and swap agreements at September 30, 2002. This sensitivity does not include physical product delivery contracts, which are not expected to be settled in cash or another financial instrument. These contracts had a fair value gain of $800,000 at September 30, 2002. As of September 30, 2002, outstanding oil futures contracts and differential swaps had a net fair value loss of $3.7 million. The aggregate effect of a hypothetical 10% change in oil prices would result in a change of approximately $2.5 million in the fair value of these oil futures contracts and differential swaps at September 30, 2002.

In conjunction with its hedging activities, the Company entered collar agreements in March 2002. As of September 30, 2002, outstanding gas collars had a fair value loss of $4.1 million. The aggregate effect of a hypothetical 10% change in gas prices would result in a change of approximately $2.7 million in the fair value of these collars at September 30, 2002.

Because these futures contracts, swap agreements and collars generally are designated hedge derivatives, and to the extent the hedges are effective, changes in their fair value are reported as a component of accumulated other comprehensive income until the related sale of production occurs. At that time, the realized hedge derivative gain or loss is transferred to product revenues in the consolidated income statement. In the event of a 10% increase in natural gas prices from their September 30, 2002 level, an additional estimated ineffective derivative loss of approximately $1 million would be recorded in the income statement.

The Company had a physical delivery contract to sell 35,500 Mcf per day from January 2002 through July 2005 at a price of approximately 10% of the average NYMEX futures price for intermediate crude oil. Because this gas sales contract was priced based on crude oil, which is not clearly and closely associated with natural gas prices, it was accounted for as a non-hedge derivative financial instrument. This contract (referred to as the Enron Btu swap contract) was terminated in December 2001 in conjunction with the bankruptcy filing of Enron Corporation. In November 2001, the Company entered derivative contracts to effectively defer until 2005 and 2006 any cash flow impact related to

25,000 Mcf of daily gas deliveries in 2002 that were to be made under the Enron Btu swap contract. The net fair value loss on these contracts at September 30, 2002 was $12.1 million. The effect of a hypothetical 10% change in gas prices would result in a change of approximately $3.1 million in the fair value of these contracts, while a 10% change in crude oil prices would result in a change of approximately $1.9 million.

Item 4. CONTROLS AND PROCEDURES

The Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Exchange Act Rule 13a-14 within the 90 days before the filing of this report. Based upon that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective in timely alerting them to material information relating to the Company required to be included in the Company’s periodic filings with the Securities and Exchange Commission.

There have been no significant changes in the Company’s internal controls or in other factors that could affect these controls subsequent to the date of their evaluation.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Items 2. through 5.

Not applicable.

Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits

Exhibit Number and Description			Page

10.1	*	Amendment to Amended and Restated Employment Agreement between the Company and Bob R. Simpson, dated August 20, 2002

10.2	*	Amendment to Amended and Restated Employment Agreement between the Company and Steffen E. Palko, dated August 20, 2002

10.3	*	1998 Stock Incentive Plan, as amended August 20, 2002

10.4	*	Amendment to Amended and Restated Management Group Employee Severance Protection Plan, dated August 20, 2002

Exhibit Number and Description				Page

10.5	*	Amendment to Amended Employee Severance Protection Plan, dated August 20, 2002

10.6	*	Outside Directors Severance Plan, dated August 20, 2002

11		Computation of per share earnings (included in Note 9 to Consolidated Financial Statements)

15		Letter re unaudited interim financial information

		15.1	Awareness letter of KPMG LLP

99		Additional Exhibits

		99.1	Chief Executive Officer Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

		99.2	Chief Financial Officer Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

* Management contract or compensatory plan

(b) Reports on Form 8-K

No reports on Form 8-K have been filed during the quarter for which this report is filed.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.

	XTO ENERGY INC.

Date: November 14, 2002	By	LOUIS G. BALDWIN
		Louis G. Baldwin
		Executive Vice President and Chief Financial Officer (Principal Financial Officer)

	By	BENNIE G. KNIFFEN
		Bennie G. Kniffen
		Senior Vice President and Controller (Principal Accounting Officer)

CERTIFICATIONS

I, Bob R. Simpson, Chief Executive Officer of XTO Energy Inc., certify that:

I have reviewed this quarterly report on Form 10-Q of XTO Energy Inc.;

Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

The registrant’s other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: November 14, 2002				BOB R. SIMPSON
				Bob R. Simpson Chief Executive Officer

CERTIFICATIONS

I, Louis G. Baldwin, Chief Financial Officer of XTO Energy Inc., certify that:

I have reviewed this quarterly report on Form 10-Q of XTO Energy Inc.;

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

Date: November 14, 2002				LOUIS G. BALDWIN
				Louis G. Baldwin Chief Financial Officer

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