Back to GetFilings.com

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

For the quarterly period ended March 31, 2005

OR

Commission File Number: 1-10662

XTO Energy Inc.

(Exact name of registrant as specified in its charter)

(817) 870-2800

(Registrant’s telephone number, including area code)

NONE

(Former name, former address and former fiscal year, if change 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 by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). 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:

Table of Contents

XTO ENERGY INC.

Form 10-Q for the Quarterly Period Ended March 31, 2005

TABLE OF CONTENTS

2

Table of Contents

PART I. FINANCIAL INFORMATION

XTO ENERGY INC.

Consolidated Balance Sheets

See Accompanying Notes to Consolidated Financial Statements.

3

Table of Contents

XTO ENERGY INC.

Consolidated Income Statements (Unaudited)

See Accompanying Notes to Consolidated Financial Statements.

4

Table of Contents

XTO ENERGY INC.

Consolidated Statements of Cash Flows (Unaudited)

See Accompanying Notes to Consolidated Financial Statements.

5

Table of Contents

XTO ENERGY INC.

Notes to Consolidated 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, 2004, have not been audited by independent public accountants. In the opinion of management, the accompanying financial statements reflect all adjustments necessary to present fairly our financial position at March 31, 2005 and our income and cash flows for the three months ended March 31, 2005 and 2004. 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-month periods ended March 31, 2005 and 2004 included herein have been subjected to a limited review by KPMG LLP, our independent registered public accountants. The accompanying review report of independent registered public accountants is not a report within the meaning of Sections 7 and 11 of the Securities Act of 1933 and the independent registered public accountant’s liability under Section 11 does not extend to it.

All common shares and per share amounts in the accompanying financial statements have been adjusted for the four-for-three stock split effected on March 15, 2005.

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 our 2004 Annual Report on Form 10-K.

See “Accounting Pronouncements” under Item 2 of this quarterly report on Form 10-Q.

Other

Inventory of tubular goods and equipment for future use on our producing properties is included in other current assets in the consolidated balance sheets, with balances of $61.3 million at March 31, 2005 and $34.7 million at December 31, 2004.

Accrued interest payable is included in accounts payable and accrued liabilities in the consolidated balance sheets, with balances of $32.1 million at March 31, 2005 and $26.6 million at December 31, 2004.

Our effective income tax rates for the three-month 2005 and 2004 periods are higher than the maximum federal statutory rate of 35% primarily because of state and local taxes.

A portion of the producing properties obtained in the August 2004 ChevronTexaco acquisition were considered nonstrategic and marked for disposition at the time of purchase. In August 2004, we exchanged $37.8 million of these properties for 19,000 net contiguous acres in our new core operating area, the Barnett Shale of North Texas, and $25.4 million in other consideration. This exchange was with companies either wholly or majority owned by the adult children and a brother of Bob R. Simpson, Chairman and Chief Executive Officer of the Company. In connection with this exchange, we granted these companies an option to purchase other properties included in the ChevronTexaco acquisition. On March 1, 2005, these companies purchased the option properties for an adjusted purchase price of $11.5 million. Lehman Brothers Inc. provided a fairness opinion to the Board of Directors on the value of properties exchanged and sold.

6

Table of Contents

Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties (including removal of our offshore platforms in Alaska) at the end of their productive lives, in accordance with applicable state laws. We determine our asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The following is a summary of the asset retirement obligation activity:

Our long-term debt consists of the following:

On March 31, 2005, borrowings under the revolving credit agreement with commercial banks were $266 million, with unused borrowing capacity of $734 million. The weighted average interest rate of 3.84% at March 31, 2005 is based on the one-month London Interbank Offered Rate plus 1%. On April 1, 2005, we entered into an amended and restated five-year senior revolving credit agreement with commercial banks that provides for an initial commitment amount of $1.5 billion, which may be increased by us, subject to certain approvals, to a maximum of $2 billion. The new agreement amends and restates our five-year revolving credit agreement dated February 17, 2004. The new agreement also increased permitted encumbrances and investments. We will use the facility for general corporate purposes and as a backup facility for possible future issuance of commercial paper. The maturity date on the facility is April 1, 2010, with annual options to request successive one-year extensions. After closing acquisitions in April (Note 13), our bank borrowings were $480 million at April 29, 2005 with a weighted average interest rate of 3.68%.

Also on April 1, 2005, we entered into an amendment to our $300 million term loan credit agreement. The amendment conforms the covenants contained in the term loan to the covenants contained in our revolving credit agreement, which was amended and restated as of the same date.

7

Table of Contents

In April 2005, we sold $400 million of 5.3% senior notes that were issued at 99.683% of par to yield 5.338% to maturity. Net proceeds of approximately $395.5 million were used to reduce borrowings outstanding under our bank revolving credit facility. The notes mature in June 2015 and interest is payable each June 30 and December 30, beginning December 30, 2005.

Litigation

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 by Jack J. Grynberg on behalf of the United States under the qui tam provisions of the U.S. False Claims Act against the Company and certain of our subsidiaries. The plaintiff alleges that we underpaid royalties on natural gas produced from federal leases and lands owned by Native Americans in amounts in excess of 20% as a result of mismeasuring the volume of natural gas, incorrectly analyzing its heating content and improperly valuing the natural gas during at least the past ten years. The plaintiff seeks treble damages for the unpaid royalties (with interest, attorney fees and expenses), civil penalties between $5,000 and $10,000 for each violation of the U.S. False Claims Act, and an order for us to cease the allegedly improper measuring practices. This lawsuit against us and similar lawsuits filed by Grynberg against more than 300 other companies have been consolidated in the United States District Court for Wyoming. In October 2002, the court granted a motion to dismiss Grynberg’s royalty valuation claims, and Grynberg’s appeal of this decision was dismissed for lack of appellate jurisdiction in May 2003. The parties have completed discovery regarding whether the plaintiff has met the jurisdictional prerequisites for maintaining an action under the U.S. False Claims Act. In June 2004, we joined with other defendants in filing a motion to dismiss, contending that the plaintiff has not satisfied the jurisdictional requirements to maintain this action. A hearing on this motion was held in March 2005, and we are awaiting the decision of the court. While we are unable to predict the outcome of this case, we believe that the allegations of this lawsuit are without merit and intend to vigorously defend the action. Any potential liability from this claim cannot currently be reasonably estimated, and no provision has been accrued in our financial statements.

In June 2001, we were 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 us and one of our subsidiaries, along with over 200 natural gas transmission companies, producers, gatherers and processors of natural gas. The 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. 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. The 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 February 2002, we, along with one of our subsidiaries, were dismissed from the suit and another subsidiary of the Company was added. A hearing was held in January 2003, and the court held that a class should not be certified. The plaintiffs’ counsel has filed an amended class action petition, which reduces the proposed class to only royalty owners, reduces the claims to mismeasurement of volume only, conspiracy, unjust enrichment and accounting, and only applies to gas measured in Kansas, Colorado and Wyoming. The court held an evidentiary hearing in April 2005 to determine whether the amended class should be certified, and we are awaiting the decision of the court. While we are unable to predict the outcome of this case, we believe that the allegations of this lawsuit are without merit and intend to vigorously defend the action. Any potential liability from this claim cannot currently be reasonably estimated, and no provision has been accrued in our financial statements.

On August 5, 2003, the Price plaintiffs served one of our subsidiaries with a new original class action petition styled Price, et al. v. Gas Pipelines, et al. The action was filed in the District Court of Stevens County, Kansas, against natural gas pipeline owners and operators. The plaintiffs seek to represent a class of plaintiffs consisting of all similarly situated gas royalty owners either from whom the defendants had purchased natural gas or measured natural gas since

8

Table of Contents

January 1, 1974 to the present. The new petition alleges the same improper analysis of gas heating content that had previously been alleged in the Price case discussed above until it was removed from the case by the filing of the amended class action petition. In all other respects, the new petition appears to be identical to the amended class action petition in that it has a proposed class of only royalty owners, alleges conspiracy, unjust enrichment and accounting, and only applies to gas measured in Kansas, Colorado and Wyoming. The court held an evidentiary hearing in April 2005 to determine whether the amended class should be certified, and we are awaiting the decision of the court. The amount of damages was not specified in the complaint. While we are unable to predict the outcome of this case, we believe that the allegations of this lawsuit are without merit and intend to vigorously defend the action. Any potential liability from this claim cannot currently be reasonably estimated, and no provision has been accrued in our financial statements.

In September 2004, we were served with a lawsuit styled Burkett, et al. v. J.M. Huber Corp. and XTO Energy Inc. The action was filed in the District Court of La Plata County, Colorado against us and J.M. Huber Corporation. The plaintiffs allege that the defendants have deducted in their calculation of royalty payments expenses of compression, gathering, treatment, dehydration, or other costs to place the natural gas produced in a marketable condition at a marketable location. The plaintiffs seek to represent a class consisting of all lessors and their successors in interest who own or have owned mineral interests located in La Plata County, Colorado and that are leased to or operated by Huber or us, except to the extent that the lessors or their successors have expressly authorized deduction of post-production expenses from royalties. We acquired the interests of Huber in producing properties in La Plata County effective October 1, 2002, and have assumed the responsibility for certain liabilities of Huber prior to the effective date, which may include liability for post-production deductions made by Huber. As of December 31, 2004, based on an evaluation of available information, we accrued a $3.1 million estimated liability for this claim in our consolidated financial statements. On February 17, 2005, we agreed to a tentative settlement of approximately $5.1 million, resulting in an additional loss of approximately $2 million that has been recorded in our consolidated income statement for the three months ended March 31, 2005.

On March 31, 2005, the Division of Air Quality of the Department of Environmental Conservation of the State of Alaska issued us a Notice of Violation regarding nitrogen oxide emissions from one of our cranes that exceed the limitations of our operational permit for one of our platforms in the Cook Inlet of Alaska. We are currently in the initial investigatory phase of this matter and, although liability could potentially exceed $100,000, we do not anticipate a material penalty.

We are involved in various other lawsuits and certain governmental proceedings arising in the ordinary course of business. Our 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 our financial position or liquidity, although an unfavorable outcome could have a material adverse effect on the operations of a given interim period or year.

Transportation Contracts

We have entered firm transportation contracts with various pipelines. Under these contracts we are obligated to transport minimum daily gas volumes or pay for any deficiencies at a specified reservation fee rate. As calculated on a monthly basis, our failure to deliver these minimum volumes to the pipeline requires us to pay the pipeline for any deficiency. Our production committed to these pipelines is expected to exceed the minimum daily volumes provided in the contracts. We have generally delivered at least minimum volumes under our firm transportation contracts, therefore avoiding payment for deficiencies. As of March 31, 2005, maximum commitments under our transportation contracts were as follows:

9

Table of Contents

As a result of our April 1, 2005 Antero Resources acquisition (Note 13), we acquired additional firm transportation contracts with various pipelines. Maximum commitments under these contracts total approximately $47 million, including approximately $7 million for the remainder of 2005. We do not currently expect to make any deficiency payments related to these contracts.

Drilling Contracts

As of March 31, 2005, we have contracts to use 42 drilling rigs in 2005 with total commitments of $80.3 million. Early termination of these contracts at March 31, 2005 would have required us to pay maximum penalties of $21.7 million. As a result of our April 1, 2005 Antero Resources acquisition, we added contracts to use 9 rigs with total commitments of $40.2 million through April 2006. Early termination of these contracts at April 1, 2005 would have required us to pay maximum penalties of $36.9 million. We do not currently expect to pay any early termination penalties related to these contracts.

Other

On April 3, 2005, the Board of Directors accepted the retirement of Steffen E. Palko from the Board effective April 1, 2005, and as President effective May 1, 2005, and we entered a consulting and non-competition agreement with him. Under the terms of this agreement, Mr. Palko is to receive a $4 million bonus related to his performance as an employee and $2 million related to a noncompetition period of 18 months. Mr. Palko was paid $3 million on May 1 and the remaining $3 million is payable on November 1, 2006. We accrued $3 million of the bonus in the March 31, 2005 consolidated financial statements, and the remaining $1 million will be expensed in April 2005. Prior to the announcement of his retirement, an estimated bonus of $700,000 had been accrued related to his services for first quarter 2005. The $2 million related to the noncompetition period will be expensed ratably from May 2005 through October 2006. We also will pay Mr. Palko $65,000 per month for his consulting services and for office space and other expenses for a period of 18 months, subject to termination by either party upon thirty days’ notice. The consulting payments are guaranteed for nine months unless the contract is earlier terminated or breached by Mr. Palko.

In October 2004, we agreed to acquire an aircraft for $17.1 million, either through purchase or lease, and made an initial payment of $6.8 million. An additional payment of $9.3 million was made in April 2005. We expect to take delivery of the aircraft in July 2005.

Through April 2005, including the effects of the Antero Resources acquisition, we have acquired more than 150,000 net acres in the Barnett Shale of North Texas. Most of these net acres are generally subject to lease expiration if initial wells are not drilled within a specified period, generally not exceeding one year. Because we have ample resources to meet the drilling requirements, we currently do not anticipate significant impairment of these leases.

We acquired compressor leases as a result of our April 1, 2005 Antero Resources acquisition. We expect to make payments totaling $5.7 million over the remaining terms of the leases through 2011, including $700,000 for the remainder of 2005.

See Note 7 regarding commodity sales commitments.

10

Table of Contents

Derivatives

We use financial and commodity-based derivative contracts to manage exposures to commodity price and interest rate fluctuations. We do not hold or issue derivative financial instruments for speculative or trading purposes. See Note 7.

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 loss, which is later transferred to earnings when the hedged transaction occurs (Note 10). 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 loss in the income statement. This ineffective portion is calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged. Btu swap contracts do not qualify for hedge accounting.

The components of derivative fair value loss in the consolidated income statements are:

The estimated fair values of derivatives included in the consolidated balance sheets at March 31, 2005 and December 31, 2004 are summarized below. The increase in the net derivative liability from December 31, 2004 to March 31, 2005 is primarily attributable to the effect of rising oil and natural gas prices, partially offset by cash settlements of derivatives during the period.

Concentrations of Credit Risk

Most of our receivables are from a diverse group of companies including major energy companies, pipeline companies, local distribution companies and end-users in various industries. We currently have greater concentrations of credit with several A- or better rated integrated energy companies. Financial and commodity-based swap contracts

11

Table of Contents

expose us to the credit risk of nonperformance by the counterparty to the contracts. This exposure is diversified among major investment grade financial institutions, and we have master netting agreements with most counterparties that provide for offsetting payables against receivables from separate derivative contracts. Letters of credit or other appropriate security are obtained as considered necessary to limit risk of loss. As of March 31, 2005, our allowance for uncollectible receivables was $3.9 million.

Our policy is to routinely hedge a portion of our production at commodity prices management deems attractive. While there is a risk we may not be able to realize the benefit of rising prices, management plans to continue this strategy because of the benefits of more predictable production growth and cash flows. See Note 6 regarding accounting for cash flow hedge derivatives.

In addition to selling gas under fixed price physical delivery contracts, we enter futures contracts, energy swaps, collars and basis swaps to hedge our exposure to price fluctuations on natural gas and crude oil sales. When actual commodity prices exceed the fixed price provided by these contracts, we pay this excess to the counterparty, and when the commodity prices are below the contractually provided fixed price, we receive this difference from the counterparty. We have hedged a portion of our exposure to variability in future cash flows from crude oil and natural gas sales through December 2005.

Natural Gas

We have entered into 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 may be less than these fixed prices because of location, quality and other adjustments.

As a result of our April 1, 2005 purchase of Antero Resources Corporation (Note 13), we acquired the following derivative contracts with an estimated unrealized fair value loss at that date of $18.3 million. The liability related to this unrealized loss has been included as part of the Antero Resources acquisition cost. These derivatives have been designated as cash flow hedges of Antero Resources production. Subsequent changes in the fair market value of these hedge contracts will be recorded in accumulated other comprehensive loss and reclassified to earnings at the contract settlement date to the extent the contracts are determined to provide effective cash flow hedges.

12

Table of Contents

We also acquired the following put and call options in the Antero Resources acquisition. These contracts had an estimated unrealized fair value loss of approximately $2.7 million at the April 1, 2005 acquisition date, and have been included as part of the Antero Resources acquisition cost. These contracts will not be designated as cash flow hedges. Subsequent changes in the fair market value of these options will be recorded as a derivative fair value gain or loss in our consolidated income statement.

The price we receive for our gas production is generally less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors. We have entered basis swap agreements that effectively fix the basis adjustment for the following delivery locations and periods:

13

Table of Contents

In the Antero Resources acquisition, we acquired basis swap agreements for West Texas delivery of 5,000 Mcf of daily gas production from April 2005 through December 2006 at the NYMEX price less $0.27 per Mcf. These contracts had an unrealized fair value gain of $800,000 at April 1, 2005.

In first quarter 2005, net losses on futures and basis swap hedge contracts decreased gas revenue by $4.1 million. In first quarter 2004, net losses on futures and basis swap hedge contracts decreased gas revenue by $23.2 million. As of March 31, 2005, an unrealized pre-tax derivative fair value loss of $106.7 million, related to cash flow hedges of gas price risk, was recorded in accumulated other comprehensive loss. This fair value loss is expected to be reclassified into earnings in 2005. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date.

The settlement of futures contracts and basis swap agreements related to April 2005 gas production reduced gas revenue by approximately $8.6 million, or $0.31 per Mcf.

Crude Oil

In connection with our 2004 acquisitions from ExxonMobil Corporation and ChevronTexaco Corporation, we entered oil futures contracts to sell, through December 2005, 10,000 Bbls per day at an average West Texas Intermediate NYMEX price of $35.91 per Bbl and 5,000 Bbls per day at an average West Texas Intermediate NYMEX price of $43.28 per Bbl. For 5,000 Bbls per day of production hedged at $35.91 per Bbl, we entered a crude sweet and sour differential swap of $3.05 per Bbl, to effectively fix the price for crude sour production at $32.86 per Bbl. Prices to be realized for hedged oil production are expected to be less than the NYMEX price because of location, quality and other adjustments.

In first quarter 2005, net losses on futures and differential swap hedge contracts decreased oil revenue by $11.5 million. There were no outstanding crude oil futures or differential swap hedge contracts during first quarter 2004. As of March 31, 2005, an unrealized pre-tax derivative fair value loss of $49.7 million related to cash flow hedges of oil price risk was recorded in accumulated other comprehensive loss. This entire fair value loss is expected to be reclassified into earnings in 2005. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date.

We effected a four-for-three stock split on March 15, 2005 and a five-for-four stock split on March 17, 2004. All common stock shares, treasury stock shares and per share amounts have been retroactively restated to reflect these stock splits.

Our acquisition of Antero Resources Corporation in April 2005 (Note 13) was partially funded through issuance to the seller of 13.3 million shares of common stock and five-year warrants to purchase an additional 2 million shares of common stock at $27.00 per share. We filed a registration statement with the Securities and Exchange Commission for the resale of the common stock.

In February 2005, we filed a shelf registration statement with the Securities and Exchange Commission to potentially offer securities which could include debt securities, preferred stock, common stock, or warrants to purchase debt or stock. The total face amount of securities that can be offered is $2.5 billion, 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 the reduction of bank debt. In April 2005, we sold $400 million of 5.3% senior notes under this registration statement (Note 4).

See Note 12.

14

Table of Contents

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

The following are components of comprehensive income:

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

15

Table of Contents

The accompanying consolidated statements of cash flows exclude the following non-cash transactions during the three-month periods ended March 31, 2005 and 2004:

During the first three months of 2005, a total of 832,000 stock options were exercised at a weighted average exercise price of $14.81 per share. As a result of these exercises, outstanding common stock increased by 662,000 shares and stockholders’ equity increased by a net $11.9 million.

During the first three months of 2005, 62,000 performance shares were issued to key employees and 860,000 performance shares vested. As of March 31, 2005, there were no performance shares outstanding. In February 2005, nonemployee directors received a grant of 18,000 unrestricted common shares. Non-cash compensation expense related to performance shares and nonemployee director unrestricted common shares was $23.6 million for the first three months of 2005 and $33.2 million for the first three months of 2004.

The following are pro forma net income and earnings per share for the three months ended March 31, 2005 and 2004, as if stock-based compensation had been recorded at the estimated fair value of stock awards at the grant date, as prescribed by SFAS No. 123, Accounting for Stock-Based Compensation:

At the end of March 2005, we traded nonoperated producing properties owned by us in the San Juan and Permian basins and in Alaska for producing properties owned by ConocoPhillips in the East Texas Freestone Trend, the San Juan Basin and the Permian Basin Goldsmith Field. The properties exchanged by each party had an approximate value of $74 million. We accounted for this transaction as an exchange of similar productive assets used in oil and gas producing

16

Table of Contents

activities, under APB Opinion No. 29 and SFAS No. 19, resulting in no gain or loss recognized on the exchange. We operate the properties that we received in this exchange.

On April 1, 2005, we acquired Antero Resources Corporation, which operates in the Barnett Shale in the Fort Worth Basin. The purchase price was approximately $685 million, consisting of $337.5 million cash, 13.3 million shares of our common stock and warrants to purchase an additional 2 million shares at $27.00 per share. The cash portion of the acquisition was funded with borrowings under our revolving credit facility. We also purchased related midstream assets encompassing 80 miles of pipeline and associated compression and processing facilities through the assumption of related bank debt of $175 million. Including additional assumed debt of $43 million for ongoing development, leasing and infrastructure, the adjusted purchase price totaled $903 million. Further purchase price adjustments will be made for net assets and liabilities acquired and a step-up for deferred income taxes. At closing, total Antero Resources assumed bank debt was repaid with borrowings under our revolving credit facility.

We have entered an agreement to purchase producing properties from Plains Exploration & Production Company for $350 million. The properties are located in our core Eastern Region of East Texas and northwestern Louisiana, and we will operate approximately 60% of the value of the acquired properties. The purchase will have an effective date of January 1, 2005, and is expected to close by May 31, 2005, subject to customary closing conditions and adjustments. The final closing price will be reduced by net revenues after the effective date, estimated at $20 to $25 million.

17

Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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 March 31, 2005, the related consolidated income statements for the three-month periods ended March 31, 2005 and 2004, and the consolidated cash flow statements for the three-month periods ended March 31, 2005 and 2004. These financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with standards established by the Public Company Accounting Oversight Board (United States). 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 the standards of the Public Company Accounting Oversight Board (United States), 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 U.S. generally accepted accounting principles.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of XTO Energy Inc. as of December 31, 2004, and the related consolidated statements of income, stockholders’ equity, and cash flows for the year then ended (not presented herein), included in the Company’s 2004 Annual Report on Form 10-K, and in our report dated March 7, 2005, we expressed an unqualified opinion on those statements. Our report on those statements referred to a change in accounting for asset retirement obligations in 2003. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2004 is fairly stated, in all material respects, in relation to the consolidated balance sheet included in the Company’s 2004 Annual Report on Form 10-K from which it has been derived.

KPMG LLP

Dallas, Texas

May 5, 2005

18

Table of Contents

The following discussion should be read in conjunction with management’s discussion and analysis contained in our 2004 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