The following discussion and analysis should be read in conjunction with Item 6, Selected Financial Data, and the Consolidated Financial Statements at Item 15(a). Unless otherwise indicated, throughout this discussion the term "Mcfe" refers to thousands of cubic feet of gas equivalent quantities produced for the indicated period, with oil and natural gas liquid quantities converted to Mcf on an energy equivalent ratio of one barrel to six Mcf.

Overview

Our business is to produce and sell natural gas, natural gas liquids and crude oil from our predominantly southwestern and central U.S. properties, most of which we operate. Because our gathering, processing and marketing functions are ancillary to and dependent upon our production of natural gas, natural gas liquids and crude oil, we have determined that our business comprises only one industry segment.

In 2008, we achieved the following record financial and operating results:

- Average daily gas production was 1.91 Bcf, a 31% increase from 2007, average daily oil production was 56.0 MBbls, a 19% increase from 2007, and average daily natural gas liquids production was 15.6 MBbls, a 15% increase from 2007.

- Year-end proved reserves were 13.86 Tcfe, a 23% increase from year-end 2007.

- Cash flow from operating activities was $5.2 billion, a 44% increase from 2007.

- Year-end stockholders' equity was $17.3 billion, a 118% increase from year-end 2007.

We achieve production and proved reserve growth primarily through acquisitions of both producing and unproved properties, followed by low-risk development generally funded by cash flow from operating activities. Funding sources for our acquisitions include proceeds from sales of public and private equity and debt, bank or commercial paper borrowings and cash flow from operating activities. During 2008, we acquired $7.9 billion of proved properties with proved reserves of 1.5 Tcf of natural gas, 19.9 million Bbls of natural gas liquids and 57.6 million Bbls of oil, as well as $3.1 billion of unproved properties.

In a trend that began in 2004 and continued until mid-2008, commodity prices for natural gas, natural gas liquids and crude oil increased significantly. However, due to oversupply concerns, tightened credit markets and lower demand in slowing U.S and global economies, commodity prices declined sharply in the second half of 2008 (see "Significant Events, Transactions and Conditions-Product Prices").

The higher prices in prior years and into 2008 led to increased activity in the industry, including the highest drilling rig levels in 25 years and increased demand for oil and gas properties. All of these factors led to significant cost inflation throughout the industry - such as labor, production expenses, drilling costs and acquisition prices. With the deepening of the U.S. and global recession and tightened credit markets, which has led to sharp declines in commodity prices in the latter half of 2008, recent drilling rig counts have decreased more than 30% from peak levels reached in September 2008, acquisition activity has slowed, and all industry costs have begun to decline. This has led many oil and gas exploration and production companies to reevaluate their development plans for the coming year including cuts to their development budgets. Our 2009 development budget is $2.75 billion. Additionally, $450 million has been budgeted for the construction of pipeline infrastructure and compression and processing facilities.

Like all oil and gas exploration and production companies, we face the challenge of natural production decline. An oil and gas exploration and production company depletes part of its asset base with each unit of production. Despite this natural decline, we have been able to grow our production through acquisitions and drilling, adding more reserves than we produce. We also attempt to manage our natural decline by combining the acquisition of mature properties with shallower decline rates with the drilling of new wells that have higher decline rates. This has allowed us to keep our natural decline rate lower than the industry average. Future growth will depend on our ability to continue to add reserves in excess of production.

Our goal for 2009 is to increase production by 14%. To achieve future production and reserve growth, we will continue to evaluate acquisitions that meet our criteria and to complete development projects included in our inventory of between 11,100 and 12,220 identified potential drilling locations. We cannot ensure that we will be able to find properties that meet our acquisition criteria and that we can purchase such properties on acceptable terms (see "Liquidity and Capital Resources-Capital Expenditures").

Increased activity in the oil and gas producing industry has also had an effect on our ability to hire qualified people including not only operational employees, but also all classifications of industry-specific professionals. We continue to hire the employees we need to adequately staff

our operations; but, the cost of hiring and the time to fill positions has increased. However, with the slowing economy and decreased industry activity, we expect it will be easier to find qualified employees. Our employee turnover continues to remain low with total turnover of 7.2% in 2008 and 9.6% in 2007.

Sales prices for our natural gas, oil and natural gas liquids production are influenced by supply and demand conditions over which we have little or no control, including weather and regional and global economic conditions. To provide predictable production growth, we may hedge a portion of our production at commodity prices management deems attractive to ensure stable cash flow margins to fund our operating commitments and development program. As of February 2009, we have hedged approximately 80% of our 2009 projected gas production at an average NYMEX price of $8.79 per Mcf and about 95% of our 2009 crude oil production at an average NYMEX price of $117.11 per Bbl. Our average realized price on hedged production will be lower than these average NYMEX prices because of location, quality and other adjustments.

In 2009, given our hedge position and current commodity strip pricing, we expect to generate enough cash flow from operations to fund our capital expenditures and reduce our debt to between $10.0 billion and $10.5 billion. In December 2008 and January 2009, we entered into early settlement and reset arrangements with eight financial counterparties covering a portion of our 2009 natural gas and crude oil hedge volumes. As a result of these early settlements, we received approximately $2.7 billion ($1.7 billion after-tax) which was used to reduce outstanding debt.

The combined effect of higher product prices, a 31% increase in gas production, a 19% increase in oil production and a 16% increase in natural gas liquids production resulted in a 40% increase in total revenues to $7.7 billion in 2008 from $5.5 billion in 2007. On an Mcfe produced basis, total revenues were $9.00 in 2008, a 9% increase from $8.29 in 2007.

We analyze on an Mcfe produced basis, the following expenses, most of which trend with changes in production:

                                                                                 INCREASE
                                                     2008          2007         (DECREASE)
Production                                         $   1.10      $   0.93              18%
Taxes, transportation and other                        0.82          0.67              22%
Depreciation, depletion and amortization               2.37          1.78              33%
Accretion of discount in asset retirement
obligation                                             0.04          0.03              33%
General and administrative, excluding stock
compensation                                           0.25          0.25              -
Interest                                               0.56          0.38              47%
                                                   $   5.14      $   4.04              27%

Production expense per Mcfe rose 18% primarily because of increased water disposal, power and fuel costs as well as certain one-time and discretionary items related to recent property acquisitions including increased compression, maintenance and workover costs. Taxes, transportation and other expense generally is based on product revenues. The 22% increase in transportation and other expense is a result of higher product prices and higher transportation costs related to increased third-party transportation partially offset by lower property taxes. The 33% increase in depreciation, depletion and amortization per Mcfe resulted from higher acquisition, development and facility costs as well as an impairment of proved properties of approximately $128 million, or $0.15 per Mcfe, and a $107 million, or $0.13 per Mcfe, increase in the impairment of unproved properties. The impairment of unproved properties is expected to increase approximately $70 million to approximately $225 million in 2009. General and administrative expense per Mcfe remained flat because increased personnel and other costs related to Company growth was offset by increased production. The 47% increase in interest expense is primarily because of an increase in weighted average borrowings to fund recent acquisitions.

Significant expenses that generally do not trend with production include:

Non-cash stock incentive compensation. Stock incentive compensation expense was $170 million in 2008 compared to $65 million in 2007. The increase is primarily related to additional grants made in 2007 and 2008.

Derivative fair value (gain) loss. This is the net realized and unrealized gain or loss on derivative financial instruments that does not qualify for hedge accounting treatment and fluctuates based on changes in the fair value of underlying commodities. The net derivative fair value gain was $85 million in 2008 compared to $11 million in 2007.

Our primary sources of liquidity are cash flow from operating activities, borrowings under either our revolving credit agreement, our commercial paper program, or our other unsecured and uncommitted lines of credit and public and private offerings of equity and debt. We attempt to balance variable rate debt, fixed rate debt and debt maturities to manage interest cost, interest rate volatility and financing risk (See "Liquidity and Capital Resources - Financing").

27 XTO ENERGY | 2008 form 10-K

Significant Events, Transactions and Conditions

The following events, transactions and conditions affect the comparability of results of operations and financial condition for each of the years ended December 31, 2008, 2007 and 2006 and may impact future operations and financial condition.

Acquisitions. We acquired proved and unproved properties at a total cost of $11.0 billion in 2008, $4.0 billion in 2007 and $786 million in 2006, which were funded by a combination of proceeds from sales of common stock and senior notes, borrowings under either our bank credit facilities or commercial paper program and cash flow from operating activities. The following are significant acquisitions in each of these years:

                                                   AMOUNT
CLOSING DATE                 SELLER             (in millions)                ACQUISITION AREA
2008   January to June   Various               $         2,253       Eastern and San Juan Regions,
                                                                     Barnett, Fayetteville, Woodford
                                                                     and Marcellus Shales
       May               Southwestern Energy               520       Fayetteville Shale
                         Company
       July              Linn Energy, LLC                  600       Marcellus Shale
                         Headington Oil                  1,804       Bakken Shale
                         Company
       September         Hunt Petroleum                  4,315 (a)   Eastern Region, South Texas and
                         Corporation                                 Gulf Coast Region and North Sea
       October           Hollis R. Sullivan,               800       Barnett Shale
                         Inc.
2007   July              Dominion Resources,             2,576       Rocky Mountain Region, San Juan
                         Inc.                                        Basin and South Texas
       October           Various                           550       Barnett Shale
2006   February          Total E&P USA, Inc.               300       East Texas and Mississippi
       June              Peak Energy                       150 (b)   Barnett Shale
                         Resources Inc.

(a) Represents a portion of the allocated purchase price of Hunt Petroleum Corporation and includes an allocation of $4.2 billion to proved properties and $160 million to unproved properties. See Note 14 to the Consolidated Financial Statements.

(b) Represents a portion of the allocated purchase price of Peak Energy Resources, Inc. and includes an allocation of $97 million to proved properties and $53 million to unproved properties. See Note 14 to the Consolidated Financial Statements.

2008, 2007 and 2006 Development and Exploration Programs. Gas development focused on the Eastern and North Texas Regions during 2008, 2007 and 2006. Oil development was concentrated primarily in the Permian Region during all three years. Development costs totaled $3.4 billion in 2008, $2.5 billion in 2007 and $2.0 billion in 2006. Exploration activity in 2008 and 2007 was primarily drilling and geological and geophysical analysis, including seismic studies in the South Texas and Gulf Coast Region and the Woodford and Fayetteville Shales. Exploratory costs were $517 million in 2008, $257 million in 2007 and $123 million in 2006. Our development and exploration activities are generally funded by cash flow from operations.

2009 Acquisition, Development and Exploration Program. We have budgeted $2.75 billion for our 2009 development and exploration program, which we expect to fund using cash flow from operations. While we expect to focus primarily on development activities in 2009, we expect to actively review acquisition opportunities. If acquisition, development and exploration expenditures exceed cash flow from operations, we expect to obtain additional funding through our bank credit facilities, our commercial paper program, public or private issuance of debt or equity, or asset sales. Our total budget for acquisitions, development and exploration will be adjusted to focus on opportunities offering the highest rates of return. Additionally, $450 million has been budgeted for the construction of pipeline infrastructure and compression and processing facilities.

As of December 31, 2008, we have an inventory of between 11,100 and 12,220 identified potential drilling locations. We plan to drill about 1,000 (800 net) development wells and perform approximately 800 (700 net) workovers and recompletions in 2009. Drilling plans are dependent upon product prices.

Product Prices. In addition to supply and demand, oil and gas prices are affected by seasonal, political and other conditions we generally cannot control or predict.

Gas. Natural gas prices are affected by weather, the U.S. economy, the level of North American production, storage levels, crude oil prices and import levels of liquefied natural gas. Natural gas competes with alternative energy sources as fuel for heating and the generation of electricity. In a trend that began in 2004 and continued until mid-2008, prices for natural gas increased significantly reaching as high as $13.00 per MMBtu in July 2008. Due to concerns of oversupply from shale gas development, declining demand due to the deepening U.S. recession, falling oil prices and increased gas in storage, recent gas prices have dropped sharply. We expect prices to remain volatile. As described under "Hedging Activities" below, we use commodity price hedging instruments to reduce our exposure to gas price fluctuations. The following are comparative average gas prices for the last three years:

                                                         YEAR ENDED DECEMBER 31
     (per Mcf)                                          2008       2007      2006
     Average NYMEX price                              $    9.03   $  6.86   $  7.23
     Average realized sales price                     $    7.81   $  7.50   $  7.69
     Average realized sales price excluding hedging   $    8.04   $  6.26   $  6.26

At February 20, 2009, the average NYMEX gas price for the following 12 months was $4.75 per MMBtu. As computed on an energy equivalent basis, our proved reserves were 85% natural gas at December 31, 2008. After considering hedges in place as of February 20, 2009, we estimate that a $0.10 per Mcf change in the average gas sales price would result in approximately a $14 million change in 2009 annual operating cash flow before income taxes.

Oil. Crude oil prices are generally determined by global supply and demand. In a trend that began in 2004 and continued until mid-2008, prices for oil increased significantly reaching a record high above $147 per Bbl in July 2008. However, lower demand as a result of the deepening U.S. recession and slowing global economy, the tightened credit markets and rising crude oil supplies have caused oil prices to decline sharply in the second half of 2008. We expect oil prices to remain volatile. As described under "Hedging Activities" below, we use commodity price hedging instruments to reduce our exposure to oil price fluctuations. The following are comparative average oil prices for the last three years:

                                                          YEAR ENDED DECEMBER 31
    (per Bbl)                                           2008       2007       2006
    Average NYMEX price                               $  99.75   $  72.39   $  66.22
    Average realized sales price                      $  87.59   $  70.08   $  60.96
    Average realized sales price excluding hedging    $  93.17   $  68.68   $  60.79

At February 20, 2009, the average NYMEX oil price for the following 12 months was $44.87 per Bbl. After considering hedges in place as of February 20, 2009, we estimate that a $1.00 per barrel change in the average oil sales price would result in a minimal change in 2009 annual operating cash flow before income taxes.

Hedging Activities. We may enter futures contracts, collars and basis swap agreements, as well as fixed-price physical delivery contracts, to hedge our exposure to product price volatility. Our policy is to consider hedging a portion of our production at commodity prices management deems attractive. While there is a risk we may not be able to realize the full benefit of rising prices, management plans to continue its hedging strategy because of the benefits of predictable, stable cash flows.

In 2008, all hedging activities decreased gas revenue by $159 million, natural gas liquids revenue by $19 million and oil revenue by $114 million. In 2007, all hedging activities increased gas revenue by $658 million and oil revenue by $24 million. In 2006, all hedging activities increased gas revenue by $618 million and oil revenue by $3 million.

The following summarizes our NYMEX hedging positions under futures contracts and swap agreements as of February 2009, excluding basis adjustments.

Our average daily production was 2.17 Bcf of gas, 63.5 MBbls of oil and 15.4 MBbls of natural gas liquids in fourth quarter 2008. Prices to be realized for hedged production will be less than these NYMEX prices because of location, quality and other adjustments. See Note 8 to the Consolidated Financial Statements.

                                                       WEIGHTED AVERAGE
                                                         NYMEX PRICE
             PRODUCTION PERIOD           MCF PER DAY       PER MCF
             2009 January to December      1,745,000        $ 8.79(a)
             2010 January to December        730,000        $ 8.67

(a) Includes swap agreements for 1,173,000 Mcf per day which were early settled and reset at current market prices. The price shown is the price that will be used for cash flow hedge accounting purposes and has been reduced for transaction costs related to the early settlements. The weighted average cash settlement contract price for all contracts is $6.56 per Mcf. See "Early Settlement of Hedges" below.

                                                       WEIGHTED AVERAGE
                                                       NYMEX PRICE PER
            PRODUCTION PERIOD           BBLS PER DAY         BBL
            2009 January to December          62,500        $ 117.11(a)
            2010 January to December          27,500        $ 126.65

(a) Includes swap agreements for 53,000 Bbls per day which were early settled and reset at current market prices. The price shown is the price that will be used for cash flow hedge accounting purposes and has been reduced for transaction costs related to the early settlements. The weighted average cash settlement contract price for all contracts is $62.86 per Bbl. See "Early Settlement of Hedges" below.

Early Settlement of Hedges. In December 2008 and January 2009, we entered into early settlement and reset arrangements with eight financial counterparties covering a portion of our 2009 natural gas and crude oil hedge volumes. As a result of these early settlements, we received approximately $2.7 billion ($1.7 billion after-tax) which was used to reduce outstanding debt. Of this amount, $453 million ($287 million after-tax) was received in 2008 and the remainder was received in 2009. Under cash flow hedge accounting, the $453 million received in 2008 is included in accumulated other comprehensive income (loss) at December 31, 2008, and will be recognized in earnings during 2009 as the hedged production occurs.

29 XTO ENERGY | 2008 form 10-K

Derivative Fair Value (Gain) Loss. We record in our income statements realized and unrealized derivative fair value gains and losses related to derivatives that do not qualify for hedge accounting, as well as the ineffective portion of hedge derivatives. We recorded net derivative fair value gains of $85 million in 2008, $11 million in 2007 and $102 million in 2006. Of these amounts, a $1 million gain in 2008, an $11 million gain in 2007 and a $67 million gain in 2006 was due to the ineffective portion of hedge derivatives. These ineffective hedge derivative gains and losses are primarily because of fluctuating oil and gas prices and their effect on hedges of production in areas without corresponding basis or location differential swap contracts.

Derivative fair value (gain) loss in 2008 includes a $38 million loss ($24 million after-tax) on certain natural gas futures that no longer qualify for hedge accounting due to the September 2008 bankruptcy filing of Lehman Brothers Holding Inc., the parent company of one of our counterparties. The 2008 derivative fair value (gain) loss also includes a $78 million gain ($50 million after-tax) on certain crude oil swap agreements that did not qualify for hedge accounting. The derivative fair value (gain) loss in 2006 includes a net gain related to our Btu swap contracts of $16 million.

Unrealized derivative gains and losses associated with effective cash flow hedges are recorded in stockholders' equity as accumulated other comprehensive income (loss). At December 31, 2008, we have an unrealized pre-tax gain of $4.1 billion in accumulated other comprehensive income (loss) related to the fair value of derivatives designated as cash flow hedges of natural gas and crude oil price risk. Based on December 31 mark-to-market prices, $3.1 billion of this fair value gain is expected to be reclassified into earnings in 2009. The actual reclassification to earnings will be based on mark-to-market prices at contract settlement date.

Stock-Based Compensation. Stock compensation totaled $170 million in 2008, $65 million in 2007 and $63 million in 2006. Included in stock option expense in 2006 is $36 million related to options granted which were subject to accelerated vesting provisions upon retirement under employment agreements for certain employees. As required under SFAS No. 123R, stock option awards subject to such vesting provisions granted to retirement-eligible employees are expensed upon grant, rather than over the expected vesting period. As of December 31, 2008, stock compensation expense is expected to total $94 million in 2009, $55 million in 2010, and $26 million in 2011 related to all outstanding stock awards. These expected costs are subject to change for stock incentive awards granted after December 31, 2008.

Hugoton Royalty Trust Distribution. In January 2006, the Board of Directors declared a dividend to common stockholders, consisting of all 21.7 million Hugoton Royalty Trust units owned by us. The dividend ratio of 0.047688 trust units for each common share outstanding was set on the record date of April 26, 2006. The units were distributed on May 12, 2006, when this dividend was recorded. We recorded this dividend at $614 million, or approximately $1.35 per common share, the fair market value of the units based on the May 12, 2006 average high and low New York Stock Exchange trade price of $28.31. After considering the cost of the trust units, we recorded a gain on distribution of $469 million before income tax.

Senior Note Offerings. In March 2006, we sold $400 million of 5.65% senior notes due April 2016 and $600 million of 6.1% senior notes due April 2036.

In July 2007, we sold $300 million of 5.9% senior notes due August 1, 2012, $450 million of 6.25% senior notes due August 1, 2017 and $500 million of 6.75% senior notes due August 1, 2037. In August 2007, we sold an additional $250 million of the 5.9% senior notes, $300 million of the 6.25% senior notes and $450 million of the 6.75% senior notes that constituted a further issuance of the senior notes issued in July 2007.

In April 2008, we sold $400 million of 4.625% senior notes due June 15, 2013, $800 million of 5.50% senior notes due June 15, 2018 and $800 million of 6.375% senior notes due June 15, 2038. In August 2008, we sold $250 million of 5.00% senior notes due August 1, 2010, $500 million of 5.75% senior notes due December 15, 2013, $1.0 billion of 6.50% senior notes due December 15, 2018 and $500 million of 6.75% senior notes due August 1, 2037. The notes due 2037 constitute a further issuance of the 6.75% senior notes issued in July 2007. Proceeds from the senior notes were used to fund property acquisitions and reduce bank debt.

Common Stock Transactions. In June 2007, we completed a public offering of 21.6 million common shares at $48.40 per share. After underwriting discount and other offering costs of $35 million, net proceeds of $1.0 billion were used to fund a portion of the acquisition of natural gas and oil properties from Dominion Resources, Inc.

In February 2008, we completed a public offering of 23 million common shares at $55.00 per share. After underwriting discount and other offering costs of $42 . . .