C R O S S T I M B E R S O I L C O M P A N Y 2000 Annual Report

ABOUT THE REPORT

From Alaska to Arkoma, our work takes us to diverse regions of the

country – each area abundant with natural and man-made beauty.

As you turn the pages of this report, we hope to convey the essence

of these treasures through our collection of photographs.

ON THE COVER

A lone East Texas explorer navigates Caddo Lake’s bayous and

cypress swamps.

The eastern part of Texas is blessed with richly textured landscapes.

Beneath this visual bounty, mother nature has hidden deposits of oil

and gas deep within the rocks. In 2000, our team of scientific

explorers completed a journey of discovery in this basin. Their

“find” – a trillion cubic feet of natural gas resources – will fuel our

growth as a leading natural gas producer for years to come.

COMPANY PROFILE

Cross Timbers Oil Company, established in 1986, is a premier

domestic natural gas producer engaged in the acquisition,

exploitation and development of high-quality, long-lived oil and gas

properties. Since going public in 1993, proved oil and gas reserves

have grown at a compound annual rate of 34% to 2.252 trillion

cubic feet of gas equivalent. Cross Timbers operates 92% of its

properties, which are concentrated in Texas, Arkansas, Oklahoma,

Kansas, New Mexico, Wyoming, Louisiana and Alaska. The

Company is listed on the New York Stock Exchange under the

symbol “XTO.” It also created the Cross Timbers Royalty Trust

(“CRT” traded on the NYSE) and the Hugoton Royalty Trust

(“HGT” traded on the NYSE) which went public in 1992 and

1999, respectively.

Total Revenues(in millions)

0

500

1,000

2,500

1,500

2,000

Proved Reserves(in Bcfe)

Operating Cash Flow(in millions)

0

100

300

200

500

400

Daily Production(in MMcfe)

$700

$600

$500

$400

$300

$200

$100

0

$400

$300

$200

$100

096 97 98 99 0096 97 98 99 0096 97 98 99 00 96 97 98 99 00

GlossaryBbls Barrels (of oil or NGLs)Bcf Billion cubic feet (of gas)Bcfe Billion cubic feet equivalentBOE Barrels of oil equivalentBOPD Barrels of oil per dayE&P Exploration & productionMBO Thousand barrels of oilMcf Thousand cubic feet (of gas)Mcfe Thousand cubic feet equivalentMMcf Million cubic feet (of gas)MMcfe Million cubic feet equivalentNGLs Natural gas liquidsTcf Trillion cubic feet (of gas)Tcfe Trillion cubic feet equivalent

One barrel of oil is the energy equivalent of six Mcf of natural gas.

F I N A N C I A L H I G H L I G H T S

1

In thousands except production, per share and per unit data 2000 1999 1998

FinancialTotal revenues $ 600,851 $ 341,295 $ 249,486Income (loss) before income tax and minority interest $ 176,432(a) $ 70,605(b) $ (105,570)(c)Earnings (loss) available to common stock $ 115,235(a) $ 44,964(b) $ (71,498)(c)Per common share (d)

Basic $ 1.62 $ 0.64 $ (1.10)Diluted $ 1.55 $ 0.63 $ (1.10)

Operating cash flow (e) $ 344,638 $ 132,683 $ 78,480Operating cash flow per share (d) $ 4.84 $ 1.89 $ 1.21Total assets $ 1,591,904 $ 1,477,081 $ 1,207,005Long-term debt

Senior $ 469,000 $ 684,100 $ 615,000Subordinated notes and other $ 300,000 $ 307,000 $ 305,411

Total stockholders’ equity $ 497,367 $ 277,817 $ 201,474Common shares outstanding at year-end (d) 77,556 73,334 67,091

ProductionDaily production

Oil (Bbls) 12,941 14,006 12,598Gas (Mcf) 343,871 288,000 229,717Natural gas liquids (Bbls) 4,430 3,631 3,347Mcfe 448,098 393,826 325,390

Average priceOil (per Bbl) $ 27.07 $ 16.94 $ 12.21Gas (per Mcf) $ 3.38 $ 2.13 $ 2.07Natural gas liquids (per Bbl) $ 19.61 $ 11.80 $ 7.62

Proved ReservesOil (Bbls) 58,445 61,603 54,510Gas (Mcf) 1,769,683 1,545,623 1,209,224Natural gas liquids (Bbls) 22,012 17,902 17,174Mcfe 2,252,425 2,022,653 1,639,328

(a) Includes effect of a $43.2 million pre-tax gain on significant asset sales, a $55.8 million pre-tax derivative fair-value loss and $26.1 million in non-cash incentive compensation expense.

(b) Includes effect of a $40.6 million pre-tax gain on sale of Hugoton Royalty Trust units.

(c) Includes effect of a $93.7 million pre-tax net loss on investment in equity securities and a $2 million pre-tax, non-cash impairment charge.

(d) Adjusted for the three-for-two stock splits effected on February 25, 1998 and September 18, 2000.

(e) Cash provided by operating activities before changes in operating assets and liabilities and exploration expense.

Simply stated . . . Cross Timbers had its best year ever in2000. The ongoing success of our exceptional development pro-gram coupled with higher commodity prices resulted in a land-slide of record-setting achievements:

Operations yielded cash flow in excess of $344 million or $4.84 per share, with earnings reaching $1.62 per share.

Gas production averaged 344 MMcf per day, almost 20% higher than 1999. Including liquids, the daily production rate improved to over 448 MMcfe.

Proved reserves grew by 11% to 2.25 Tcfe at year-end 2000, with 79% natural gas.

Cash margins doubled to $2.10 per Mcfe, up from $.92 per Mcfe in 1999.

Debt slid to a historic low level of $.34 per Mcfe.

The stock price hit an all-time high of $29 in December, reflecting appreciation of more than 350% for the year.

These accomplishments have elevated the Company to “topof class” status among the independents. Even more impressive,we believe the best is yet to come. Production is slated for dramatic growth and 2001 financial performance is on pace to setnew records. Just as importantly, the underlying value of ourreserves, our “gold in the vault,” is increasing with the strongercommodity price environment.

Accelerating internal growth. Our extensive operated positions in the San Juan Basin, Arkoma Basin and East Texasprovide an unparalleled inventory of low-risk drill bit opportuni-ties. These high-impact projects provide a new facet to theproven Cross Timbers’ strategy – double-digit, internally generated growth.

For both 2001 and 2002, natural gas production is targetedto increase 20% per year. By comparison, the entire energy sectorlooks to grow gas volumes only 2% to 3% annually. We alsoexpect our Company’s reserve base to steadily build to 3 Tcfewithin the same period, a 50% increase from the year-end 1999level of 2 Tcfe. Notably, this substantial increase in both reservesand production can be achieved through our existing property base.

Making a discovery. We take pride in our proven process –buying quality reserves and working hard to make them better.Our exploitation model is low-risk, consistent and lucrative. Still,the overwhelming success in our East Texas Freestone Trend is farsurpassing our expectations. Trend production is slated toincrease from 50 MMcf per day to more than 200 MMcf per dayduring the next two years. Our development program, which hasidentified more than 500 well locations with average reserve tar-gets of 3.5 Bcfe (2.4 Bcfe net), is striving to bring over 1.2 Tcfe ofresource potential to fruition. In essence, the Company will delivera “discovery” from the heart of a long-established, premier gasbasin, thus achieving successful exploration-type results withoutexploration-type risks. When combined with the upsides from

our other core areas, the potential reserve additions the Companynow owns grow to more than 1.5 Tcfe.

Building strong financials. With operations in high gear,we are determined to achieve solid fiscal performance in 2001.By locking-in a NYMEX gas price above $5.50 per Mcf for themajority of our production, we should realize cash flow in excessof $500 million for the year, an amount greater than the cumula-tive cash flow of the Company from 1993 through 1999. Mostimportantly, this sizeable profit provides us the flexibility to fullyfund our capital objectives. Fifty percent will be dedicated to thedevelopment program and the balance will be devoted to enhancing shareholder value through high-return acquisitions and prudent balance sheet improvements.

Company valuation is on the rise. The emerging CrossTimbers’ profile – a top natural gas producer with internally gen-erated production and reserve growth and a solid capital structure– has led to an upward trend in our market valuation. We havesteadily created value on a per share basis since going public in1993. Ownership of gas reserves has grown sequentially whiledebt is pegged at a historically low level per Mcfe and is stillheading lower. So the investment community is now payingmore attention. Our stock price has risen impressively. But thegood news is that there’s plenty more room to grow.

Historically, reserves such as ours have been valued at about$1.00 per Mcf in the ground. We believe the market today is$1.50 or better and if this commodity price environment persists,reserve values should move towards $2.00 per Mcf. Our “MoneyGrows in Texas” graph on page 3 depicts our reserve value sensi-tivity per share through next year. As you can see, $1.50 perMcfe next year is a $48 share price, while $2.00 per Mcfe is a $67share price. These estimates also assume we achieve our 3 Tcfereserve goal next year.

THE GOALSA banner year in 2000 allowed us to exceed all the targets we

articulated at its onset – $4.00 per share in cash flow ($4.84 actu-al), a debt level of $0.40 to $0.45 per Mcfe ($0.34 actual) andreserves of 40 Mcfe (44 actual) per share prior to the three-for-twostock split completed in September 2000.

For 2001, we have established new goals to further enhancevalue and make Cross Timbers a market standout. These targets include:

Generating $6.00 in cash flow and $3.00 in earnings on aper share basis.

Increasing our natural gas production by 20% and total production by 15% to 18%.

Growing our proved reserve base to 2.6 Tcfe by year end.

Improving our equity level to a position of 50% of total book capitalization.

Cash flow and debt. Our cash flow goal will allow theCompany to fund its development program of $250 million and

2

T O O U R S H A R E H O L D E R S

OUTLOOK

Since 1996, Cross Timbers has been growing at a dizzyingpace. Our purchase of more than $1 billion of premier, long-lived, gas-producing properties, coupled with aggressive exploita-tion, has tripled the Company’s production and reserves. At thesame time, our exploitation performance has produced stellarresults – leading the industry in drill bit finding costs and culmi-nating with a trillion cubic foot “discovery” of natural gas in theEast Texas Basin. All in all, Cross Timbers has built itself into apremier owner and exploiter of domestic natural gas reserves and

production.Prices have doubled. From our perspec-

tive, we are in a new era for natural gas. Thereason – scarcity. Over the past ten years,domestic production remained relatively flat.All incremental gas demand, the result ofeconomic growth and environmental concern,was satisfied by imports. At this juncture,three key factors have created a fundamentalchange in the supply/demand market: 1) thenatural decline of U.S. production isapproaching 20% per year; 2) supply-sideprospects continue to deteriorate along withthe nation’s exploration infrastructure; and 3)more than 90% of increased demand for

electricity is slated to be fueled by natural gas – up from just15% currently. The result is tight supply in the face of burgeoning demand.

For gas producers, this should result in prices that, while stillvolatile, will remain at a higher level for the next several years.We predict a range between $4.00 and $6.00 per Mcf. As themarketplace adapts to this new paradigm, we expect to reap therewards through stronger valuations driven by increased reserves,earnings and cash flow. Our dedicated team of more than 600strong will be here working to make it happen.

Simply stated . . . the future has never been brighter for Cross Timbers.

We appreciate your continued support.

Bob R. SimpsonChairman and Chief Executive Officer

Steffen E. PalkoVice Chairman and President

March 30, 20013

have $250 million remaining for other purposes. To date, wehave utilized $167 million of this excess to purchase an additional240 Bcfe of reserves in our high-impact East Texas FreestoneTrend. Meanwhile, by achieving the earnings target, shareholders’equity should grow to about $750 million by year-end 2001 from$497 million at year-end 2000. This alone takes our equity tobook capitalization ratio to a comfortable 50% level. All remain-ing cash flow, $80 million plus, can then be used to enhance busi-ness performance – whether expanding our existing reserve base,increasing the drilling budget, repurchasing Company stock orfurther reducing debt.

Production and reserves. Gas produc-tion volumes for 2001 should averagebetween 405 and 410 MMcf per day, with anexit rate approaching 450 MMcf. In our EastTexas Freestone Trend alone, we plan to drill80 development wells, each contributing netreserves of 2.4 Bcfe. Combined with the 240 Bcfe of natural gas reserves already purchased in 2001, we anticipate achievingour 2001 reserve goal in short order.

FINANCIAL RESULTSIn 2000, cash flow from operations hit a

record $344.6 million or $4.84 per share, a160% increase from $132.7 million or $1.89per share in 1999. The Company reported earnings available tocommon stock of $115.2 million, or $1.62 per share, comparedwith earnings of $45 million or $0.64 per share for 1999.Excluding after-tax, non-cash incentive compensation, gains onasset sales and losses in the fair value of certain derivatives relatedto the Company’s hedging activities, our earnings were $140.1 million or $1.97 per share for the year 2000, comparedwith $14.8 million or $0.21 per share for 1999.

Higher production and stronger commodity prices alsoresulted in record revenues. In 2000, revenues totaled $600.9 million, a 76% increase from $341.3 million in 1999.Operating income for the year increased to $212.1 million, a122% gain from $95.4 million for 1999.

COMMON STOCK OFFERINGEarly in 2000, the Board of Directors, in recognition of the

significant value of our common stock, authorized the repurchaseof up to 8.25 million shares, or 11% of the 73.4 million sharesoutstanding at year-end 1999. During the first half of the year, werepurchased 5.3 million shares for $41.4 million, or $7.88 per share.

In November 2000, we recycled these shares by selling 6.6million shares of common stock from treasury in a public offering.Proceeds of $126.1 million, or $19.11 per share, were used fordebt reduction, sharply improving our balance sheet. Wedecreased the debt level and increased shareholders’ equity simul-taneously – clearing the way for our stock to trade at higher multiples of cash flow and earnings.

0

$15

$30

$75

$29

$37

$44

$52

$31

$40

$47

$55

$39

$48

$57

$67

$45

$60

$1.25 per Mcfe $1.50 per Mcfe

$1.75 per Mcfe $2.00 per Mcfe

Money Grows in TexasXTO Reserve Valuation (per share)

TODAY 2001e 2002e

substantial reserve additions for the Company. Our well-

proven strategy of acquiring and improving premier prop-

erties will generate tremendous results from this trend.

The upsides already identified – 1.2 Tcf of natural gas –

ensure continued natural gas growth in 2001 and beyond.

In 2000, our natural gas drilling pro-

gram targeted all of the core gas areas – the

Arkoma Basin (40 wells), East Texas (43

wells), the San Juan Basin (34 wells), Major

and Woodward counties of northwestern

Oklahoma (32 wells) and the Fontenelle

Unit of southwestern Wyoming (five wells).

Development of oil reserves focused on

our Permian Basin properties in Texas and

the Middle Ground Shoal Field in Alaska.

In West Texas, we drilled 34 wells. Our

University Block 9 drilling program again

highlighted the Devonian Formation with

16 vertical wells and seven horizontal side-

tracks being completed. In the Prentice Northeast Unit,

we drilled 11 development wells. In the Cook Inlet, we

initiated our development plan for the waterflood exten-

sion in the Middle Ground Shoal Field.

Moving into 2001, we established a $250 million

budget for our development and exploration program with

a majority (66%) allocated to East Texas. More than 85%

will be deployed to increase our natural gas production by

20%. In total, we plan to drill about 285 wells and imple-

ment more than 400 workover and recompletion activities

during the year compared to 208 wells

and 400 workovers in 2000.

At Cross Timbers, we identify and acquire high-

quality, long-lived oil and gas producing properties. We

then strive to increase their value by deploying talented

professionals to optimize efficiencies, reduce costs and

apply technical innovation to find, develop and produce

still more reserves. Consistent application

of this “acquire and exploit” strategy has

created a focused, opportunity-driven

growth machine with a rich property base of

legacy assets and an unprecedented portfolio

of development prospects. With strong

commodity prices, we are now shifting our

development efforts into overdrive. The

Company is primed to achieve record-set-

ting internal production growth of 15% to

18% for the next two years in a highly prof-

itable manner: generating a rate of return of

30% at a gas price of $2.50 per Mcf and

100% at $5.00 per Mcf. For an industry

struggling with steep production declines, the surprise

answer is that . . .

“Cross Timbers’ disciplined, proven strategy has

built a growth vehicle that emulates exploration success

— without the high risk.”

DEVELOPMENT

Cross Timbers implemented its most ambitious capital

program to date during 2000, spending $168 million on

development and exploration activities. This program

developed 459 Bcfe of reserves, replacing 280% of produc-

tion at an industry-leading finding cost of just $0.37 per

Mcfe. Over the past three years,

the Company significantly stepped-

up capital expenditures from $78

million to $168 million while finding costs remained

consistently low. Impressively, during this time, drill bit

production replacement increased from 137% to 280% per

year (see Operational Performance exhibit). This remark-

able achievement speaks volumes about the quality of the

Company’s reserve base and the talent of its technical and

operations staff.

The year’s major achievement was the “discovery” of

our expansive, multi-pay East Texas Freestone Trend where

our rich property base yielded record production rates and

O P E R A T I O N S O V E R V I E W

163

341

459500

400

300

200

100

0

$2.00

$1.50

$1.00

$0.50

0

Development cost ($MM)

Drill bit reserves added (Bcfe)

Finding cost ($ per Mcfe)

Operational PerformanceGetting Bigger and Getting Better

1998 1999 2000

$0.48

$0.28$0.37

Green River Valley, WyomingThe meandering Green River cuts a swath through the high plains.

5

Lower 48Producing Areas

Fontenelle Area

San Juan BasinHugoton Area

Arkoma Basin

Permian Basin East Texas Basin

KEY AREAS

East Texas

This producing region is well known as one of our

nation’s premier gas basins. It has a well-established history

of producing oil and gas from a range of pay intervals,

running from 7,000 feet to 13,000 feet. Due to their

expansive areal extent and

multi-pay nature, major

gas basins such as the East

Texas Basin seem to be

continuously reinvigorated

with new plays overlooked

in previous development

cycles. Today, the most

exciting onshore natural

gas play in the nation is

occurring in East Texas.

Key players have rushed

into the area to drill for

the high-rate gas produc-

tion of the over-pressured Bossier sandstones. Fortunately,

Cross Timbers staked its claim to this “boom” early.

In 1998, our Company established its initial position

with the acquisition of 251 Bcfe focused in eight produc-

ing fields. These fields were among the most prolific in

the basin, having already produced almost 2 Tcfe, primarily

from the Travis Peak Formation. While our initial work

focused on expanding Travis Peak development, we also

began testing deeper productive horizons – Cotton Valley

sandstones, Bossier sandstones and Cotton Valley lime-

stone. Our success with this “pilot program” during 1999

exposed tremendous potential in these deeper horizons.

We mapped the deeper intervals, identified development

areas and expanded the productive limits of our existing

property base. The results of our

development program and the associat-

ed studies pointed to the western shelf

of the basin as the most prospective area – mainly

Freestone, Robertson, Limestone and Leon counties.

During 2000, the Company drilled 43 wells in these

areas, 19 of which targeted multi-pay completions in

Freestone County’s Freestone Field. We also completed 72

workovers and recompletions. Fifteen recompletions tar-

geted the Bossier and Cotton Valley sandstones located in

the Bald Prairie Field. Our work exceeded all expectations.

Production from our East Texas properties increased to a

record daily production rate of 144 MMcf, up more than

35% year over year. We also increased reserves to 639

Bcfe, more than doubling the size of our initial acquisition.

Cross Timbers has a unique approach to developing

this new Bossier sand-

stone play. While other

operators focus primarily

on the Bossier sandstones,

our program centers on

multi-pay development

of the deeper horizons,

including the Cotton

Valley sandstones,

Bossier sandstones and

Cotton Valley limestone.

As a result, our economics

per well are not depend-

ent upon the success of

any single zone. We refer to this area of multiple

productive horizons, based on geologic structures, as our

East Texas Freestone Trend.

A key component to our success involves applying

technical innovation. We evolved our completion tech-

niques to best suit the tight-sand characteristics of the

reservoirs. Conventional gelled-sand fracturing has been

replaced by high-rate water fracturing. The results have

yielded higher initial production rates at only 30% to

40% of the cost.

Summary of Proved Reserves by AreaSEC Assumptions – December 31, 2000

(in thousands)Proved Reserves Discounted

Natural Gas Natural Gas Present Value beforeLiquids Equivalents Income Tax of

Area Oil (Bbls) Gas (Mcf) (Bbls) (Mcfe) Proved ReservesEast Texas 2,870 621,645 – 638,865 $ 2,575,779 33.2%Arkoma Basin 38 478,776 – 479,004 2,028,993 26.2%San Juan Basin 1,447 291,829 22,012 432,583 1,249,886 16.1%Hugoton

Royalty Trust (a) 2,877 326,582 – 343,844 1,230.419 15.9%Permian Basin 35,285 34,909 – 246,619 451,071 5.8%Alaska Cook Inlet 13,873 – – 83,238 128,412 1.7%Cross Timbers

Royalty Trust (b) 1,710 12,410 – 22,670 63,185 0.8%Other 345 3,532 – 5,602 20,887 0.3%Total 58,445 1,769,683 22,012 2,252,425 $7,748,632 100.0%(a) Includes Cross Timbers’ ownership in the Hugoton Royalty Trust and the

related underlying properties.(b) Includes Cross Timbers’ ownership in the Cross Timbers Royalty Trust and the

related underlying properties.

7

Fort Stockton, TexasThe world’s largest roadrunner, PaisanoPete, is alive and well at the corner ofMain Street and Highway 290.

Fort Davis, TexasSunrise casts long shadows from the remains of this age-old army outpost.

9

Each new well targets the Cotton Valley sandstones,

Bossier sandstones and Cotton Valley limestone intervals

while leaving shallower Travis Peak potential behind-pipe

for future development. These deeper pay intervals can

produce 1 Bcf to 3 Bcf of gas reserves each. Thus, an indi-

vidual wellbore could contribute from 2 Bcf to as much as

9 Bcf of reserves. Our engineers have conservatively

assigned an average risk-adjusted reserve target of

3.5 Bcfe (2.4 Bcfe net) in total for each well. With

more than 49,000 net acres and over 500 identified

well locations, Cross Timbers has proved-up the

equivalent of an exploration-type “discovery.” This

resource potential of more

than 1.2 Tcf of natural gas

will fuel internally generated

growth in both reserves and production for many

years to come.

Freestone Field. Freestone Field is defined by

a deeper Cotton Valley limestone structure that is

reflected up into the shallower horizons. The field

was originally developed for the Travis Peak

interval, with only a few wells producing from the

deeper horizons. With a hydrocarbon column of

over 200 feet, the Cotton Valley limestone structure

in this field has been highly productive where

completed. Older wells completed in this zone have

produced more than 3 Bcf each.

Up the wellbore, two additional zones have

proven highly productive. The Bossier sandstones

are deposited and draped over the limestone in three

separate productive reservoirs. These horizons vary

in thickness from 20 feet to 150 feet per sand. The

original wells with production from the Bossier

sandstones have yielded reserves ranging from 1 Bcf

to 2.5 Bcf each. The third zone, the Cotton Valley sand-

stones, is deposited above the Bossier sandstones and covers

a 700-foot section. These heterogeneous sandstones

contain numerous productive “pays” ranging from 20 feet

to 100 feet in thickness.

These limited tests of the deeper horizons gave us a

tantalizing look at this trend’s tremendous development

potential. Again, the secret to achieving commercial pro-

duction in any of these tight zones is the correct fracturing

technique. Past development efforts typically failed due to

reservoir damage caused by poor completion methods.

Shiprock, New MexicoThis volcanic plume, named the “rockwith wings” by the Navajo, rises fromthe southwestern desert.

Thus, our procedure of simultaneously completing and

commingling the intervals will actualize this relatively

untapped, rich reserve base.

In 1999, the Company drilled four wells to test the

Cotton Valley limestone, Cotton Valley sandstones and

Bossier sandstones. The combined rate exceeded 4 MMcf

per day per well and reserves topped 4 Bcf per well. Based

on these stellar results, the Company drilled 19

additional wells targeting deeper intervals during

2000. The first month’s

daily production aver-

aged 3.8 MMcf per

well, with reserve projections of 4 Bcf per well. We

focused on testing the productivity of new infill

development wells, along with drilling six delin-

eation wells strategically located at the outer edge

of the field. These “step-out” wells proved just as

successful as their infill counterparts, producing at

comparable rates.

Thus, the entire

acreage position was

defined as prospective

for field development.

In fact, one of the

best wells drilled, the

Eppes No. 6, was a

western step-out well that aver-

aged over 5.5 MMcf per day in the

first month of production.

During the 14 months that elapsed while testing

these wells, Freestone Field production increased

five-fold to 42 MMcf per day from 8 MMcf per day.

The Company expects to drill 36 wells in

Freestone Field during 2001 with another 50 to 60

potential locations beyond that for future development.

We believe, with our plan fully implemented, the field

will yield more than 120 MMcf per day by the end of

2002. Our future development targets 300 Bcfe of

gas reserves.

Bald Prairie Field. Like Freestone Field, the produc-

tive limits of this Robertson County field are defined by

the presence of a Cotton Valley limestone structure, from

which the majority of existing wells produce gas. Several

scattered completions in the Bossier sandstones have

proven productive, delineating upside opportunity.

Gamma ray curve from theNewsome #10 identifying theextensive pay zones in the typicalFreestone Field wellbore.

Bossier ‘D’ sandstone – photomicrograph depicting the poresystem surrounding the quartz grains.

11

In 2000, Cross Timbers focused on recompleting produc-

ing wells into two behind-pipe pay zones, the Bossier and

Cotton Valley sandstones. The 15 workovers proved

successful. Daily production rates averaged 1.5 MMcf and

additional reserves were estimated at 2 Bcf per well.

Due to this program, field production increased rapidly to

22 MMcf from 6 MMcf per day during the fourth quarter

of 2000.

Recent acquisitions have increased Cross Timbers’

position from 3,500 acres to 10,000 acres in this prolific

field. Each producing Cotton Valley limestone well is

expected to recover more than

2 Bcf. The reserve potential for

each well completed and commin-

gled in multiple zones is about

4 Bcf. Development plans for 2001

include 24 additional recomple-

tions and 24 new wells. We have

also identified 150 potential well

locations for development with total

impact projected at 380 Bcf of gas

reserves. As a result, Bald Prairie

will be one of our most active development

areas in 2001.

Willow Springs Field. This Gregg County field,

although not located in the Freestone Trend, has been a

focus area for Cross Timbers. Willow Springs produces

from both the Travis Peak and Cotton Valley sandstones at

depths ranging from 8,500 feet to 10,500 feet. The

Company’s development plan has entailed drilling deeper

to the less exploited Cotton Valley sandstones and then

commingling with the shallower

Travis Peak zone. The same high-

rate water fracturing technique

innovated for our East Texas Freestone Trend fields is

utilized in Willow Springs.

A total of 24 wells have been drilled since our acquisi-

tion, with 12 occurring last year. Our 2000 development

drilling program included several step-out wells that

extended the productive limits of the field to both the

northeast and southwest. The 15 wells planned for 2001

will test field limits and continue our successful infill pro-

gram. Daily production has increased to 38 MMcf from

8 MMcf in just two years.

Other Fields. Cross Timbers has additional upsides

in all of its East Texas fields. In Opelika and Tri-Cities,

previous operators bypassed reserves in the Cotton Valley

sandstones. Further, the Travis Peak and Rodessa forma-

tions provide numerous opportunities for recompletion and

multi-zone development. The Whelan, North Lansing

and Logansport fields also provide opportunities for field

extensions and infill drilling. In total, the Company plans

to drill two wells and perform 12 workovers in these fields

during 2001.

Arkoma Basin

The Arkoma Basin stretches

over 200 miles from central

Arkansas into southeastern

Oklahoma. This expansive

basin was first developed in the

1920s to supply gas to Little

Rock, Fort Smith and other

smaller surrounding towns.

Over the years it has gained a reputation

as a long-lived, high-quality natural gas

resource. Characterized as geologically

complex and multi-pay, the basin has very shallow decline

rates. Much like the East Texas Basin, the Arkoma Basin

has generated renewed interest and Cross Timbers entered

in grand style.

In 1999, the Company acquired 480 Bcfe for $468

million to become the largest natural gas producer in

Arkansas with an acreage position of more than 340,000

net acres. The Company embarked on a massive undertak-

ing – a geologic mapping of the region’s more than 20

producing intervals. To aid in this enormous task, we

acquired more than 2,000 miles of 2-D seismic lines to

reprocess and reinterpret with the newest technology avail-

able. Combined with subsurface mapping, this seismic

data will provide a better understanding of the basin’s

complex faulting and depositional patterns. This equates

to finding more hydrocarbon “traps.” The Company has

also initiated the use of electric imaging logs on new wells

to better define reservoir traps and limits. This technical

approach will lead to more drilling locations and, in fact, a

competitive advantage for Cross Timbers. The Company is

also designing a 3-D seismic program in Oklahoma where

data acquisition should begin in the next several months.

Four Corners Area, New MexicoLook out for falling rocks and big arrows.

Glass Mountains, OklahomaSediments speckled with “glassy” gypsum cascade from the mesas and buttes into the muddy wash.

13

The Company’s net production from 1,100 wells totals

more than 100 MMcf per day, with 85% from operated

leases. During 2000, the first full year of our operations on

the properties, the Company drilled 40 wells and completed

more than 120 workovers. Our initial work focused on the

installation of 74 wellhead compressors that reduced

producing pressures and increased daily production by an

average of 100 Mcf per well. Due to the multi-pay nature

of the basin, the Company has identified substantial upside

in the existing wellbores. We successfully recompleted

numerous wells to unopened pay zones

in 2000.

In 2001, the Company plans to

accelerate both development drilling

and workovers across its acreage posi-

tion. The Arkoma property base is

divided into three distinct areas with

unique geologic and producing charac-

teristics – the Arkansas Fairway Trend,

the Arkansas Overthrust Trend and the

Oklahoma Cromwell/Atoka Trend.

Arkansas Fairway Trend. The

majority of the Company’s production

flows from this extensive area of the

basin, which produces from multiple reservoirs at depths

ranging from 2,500 feet to 7,500 feet. The structural

setting of the area is dominated by east-west faults forming

isolated traps in the Atokan-aged and Morrowan-aged

sandstones. New wells will target these traps.

During 2000, the Company drilled 25 Fairway wells

with a success rate of 95%. The average daily flow rate

was 1 MMcf, with reserves of

1 Bcfe per well. Our process has

already defined numerous additional

drilling locations based on both structural and stratigraphic

separation. The Orr and Hale sandstones were the focus pay

intervals for our new wells in the Aetna and Cecil fields.

The Silex Field, also in the Fairway Trend, was one of

the first fields discovered in the Arkoma Basin and is still

providing new opportunities. In 2000, we drilled the Silex

8-22 to test the deeper horizons of this mature structure.

This well encountered productive carbonate intervals in the

Boone and Penters formations at a depth of only 4,500

feet. As this Mississippian-aged interval is comparable to

intervals that the Company has successfully developed in

the Anadarko Basin, we used a similar high-rate water

fracturing technique which resulted in an initial daily rate

of 1.3 MMcf. The Company has identified eleven potential

locations for the Boone and Penters intervals on this struc-

ture. We plan to drill three of those wells in 2001.

In total, the Company plans to drill 42 wells in the

Fairway Trend during 2001. The majority of which will

be located in the Aetna, Cecil and Peter Pender fields

where we expect to gain substantial

production rate and reserves.

Arkansas Overthrust Trend.

This area, located just south of the

Fairway Trend, typically has multiple

thrust faults that created isolated reser-

voirs. Production is found at varying

depths, ranging from 3,500 feet to

7,500 feet. In this area, the key to

drilling successful new wells is pene-

tration of the pay zone near the crest

of the imbricate fold where greater

fracturing occurs, thus enhancing the

flow characteristics in the rock.

The use of electric imaging logs has greatly assisted in

identifying optimal well locations in this highly

faulted area.

During 2000, we drilled nine wells in the Overthrust

Trend with average initial daily rates of 1.5 MMcf and

reserves of 1.4 Bcfe per well. One of our best wells, the

Glen Jones 4-20, initially produced at 4 MMcf per day.

Surprisingly, the productive zone in this well is not present

in an offset well only 400 feet away due to the complex

faulting. With the electrical imaging tool, we were able to

pinpoint the crest of the imbricate fold and successfully

find a new reservoir. The Company plans to drill 18 new

wells during 2001 in this highly prospective area.

Oklahoma Cromwell/Atoka Trend. In this area of

southeastern Oklahoma, the Cromwell sandstones are our

primary target with the Atoka sandstones and Wapanuka

limestones as secondary objectives. Our development

activities are focused in the Ashland and South Pine

Hollow fields.

Kenai River, AlaskaBraving the frigid waters, a lone angler casts for another king salmon.

NICHOLS

TURNER

TURNER

TURNER

Arkoma Overthrust Area – Electrical imaging logsidentify faults and structural dip in the Glen Jones#3 which defines the imbricate fault trap in the Glen Jones #4.

15

The Ashland Field has produced over 70 Bcf to date.

Our efforts have concentrated on 80-acre infill wells to better

capture the substantial gas in place. Using 2-D seismic to

identify the Atoka anomalies, we strategically drill our

wells to encounter not only the Cromwell sandstones but

also shallower secondary targets. Completion techniques

utilize the same successful water fracturing and commin-

gling practices employed in the Anadarko and East Texas

basins. Five wells were drilled in Ashland Field during

2000 with average initial daily production rates of

1.7 MMcf and reserves totaling 1.3 Bcf per well. The

Company plans to drill 12 wells in 2001.

San Juan Basin

Cross Timbers entered the San Juan Basin in

December of 1997 with the purchase of 290 Bcfe for

$195 million. Since then, gross operated production has

increased by 56% to 75 MMcf per day and reserves,

including sales and production, have grown to 647 Bcfe.

A large portion of this increase can be attributed to opera-

tional improvements, primarily compression. During

2000, the Company installed 75 wellhead compressors,

bringing total installations to 230 since we assumed

operations. These projects increased daily production rates

by 100 Mcf per well and reserves by 300 MMcf per well.

During 2000, we drilled 36 wells and performed 170

workovers. Drilling focused on the Fruitland Coal (ten

wells), Pictured Cliffs (14 wells), Mesaverde (six wells) and

Dakota (six wells). The Company plans to drill 43 wells

and complete more than 100 workovers and recompletions

during 2001.

Fruitland Coal. To date, the Company has focused

the majority of its Fruitland Coal development efforts on

trend extensions. This coalbed methane play, first pursued

in the basin in the 1980s, has fueled a substantial increase

in basin-wide production into the

1990s. For Cross Timbers, our

coalbed methane development is

focused on the northwestern portion of the basin surround-

ing the city of Farmington. The Company drilled ten

wells during 2000, several of which were successful step-

out wells. Daily production from this unconventional

formation has risen to 12 MMcf from 2 MMcf since

Cross Timbers assumed operations.

Discussions are underway to reduce spacing require-

ments to 160 acres from 320 acres, with approval expected

within the next several years. This will give the Company

30 additional locations with aggregate net reserve potential

of 20 Bcf. During 2001, the Company plans to drill ten

Fruitland Coal wells.

Mesaverde Formation. This prolific formation pro-

duces from three main sandstone intervals: the Cliffhouse,

Menefee and Point Lookout. The Company drilled six new

wells and recompleted three wells to the Mesaverde during

2000 with excellent results. These activities yielded aver-

age initial rates of 900 Mcf

per day per well and added

reserves of 1 Bcf per well.

With development costs of

about $0.50 per Mcfe, the

wells are highly economic.

A recent regulatory ruling

allowing 80-acre spacing

has given us an abundance

of new opportunities.

Eighty new locations

containing about 80 Bcf

of reserve potential are

available for develop-

ment, along with numerous

recompletions. Cross Timbers

plans to drill and complete 13

wells to the Mesaverde during 2001.

Dakota Formation. The Dakota horizon produces

from a total of six separate sandstone reservoirs at depths

ranging from 6,500 feet to 7,500 feet. The Company has

focused its drilling efforts in areas where the bottom three

sandstones were generally not penetrated by older wells.

Therefore, these sandstones were undrained, resulting in

more prolific production. These new wells were also

drilled deeper, through the Dakota, to test the previously

untapped Burro Canyon and Morrison sandstones. During

2000, the Company drilled six successful wells to the

Dakota and deeper horizons. These wells had initial rates of

600 Mcf per day and reserves of 1 Bcf per well.

Cross Timbers operates more than 400 Dakota produc-

ers drilled on 160-acre spacing and discussions are under-

way to reduce the spacing to 80 acres. If approved, the

Company sees another 200 potential Dakota well locations,

with an aggregate target of about 60 Bcf. Reduced spac-

ing in the Mesaverde and Dakota will generate tremendous

development opportunities for the future.

Windmill, KansasOn the Great Plains, these isolated steel towers spin wind power into running water.

Alma, ArkansasPopeye longs for another can of spinach to bust out of the clink.

17

new wells completed during the past year. Once again,

trend extension was the key to success. For example, the

Hughes 2-6, a northern step-out well, was completed at a

daily rate of 1.5 MMcf. During 2001, the Company plans

to continue the successful development program begun in

the Chester in 1999 with 15 additional wells.

Development in the Fontenelle Unit included five suc-

cessful wells and five re-stimulations. Drilling focused on

continued 80-acre development of the Frontier sandstones

with a successful step-out well that extended the eastern

boundary. Plans for 2001 call for increased activity levels

that include drilling ten wells and continuing the successful

re-stimulation program with seven workovers.

The Hugoton Field of Oklahoma has seen a develop-

ment resurgence with successful recompletions to the

Towanda Formation and a new re-stimulation technique

for the older Chase Group producers. During 2000, the

Company’s Towanda development consisted of eight

successful workovers, divided between recompletions and

deepenings of older wells. These activities yielded average

daily rates of 190 Mcf per well and reserves of 400 MMcf

per well. Economics were exceptional due to the low

development costs of just $0.15 per Mcfe. The Company

also embarked

on a pilot proj-

ect to test new

re-stimulation

techniques in

the Hugoton

Chase inter-

vals. Fifteen

of these re-

stimulations

were completed

during 2000 with daily rate

increases averaging 75 Mcf per

well, doubling the prior rate. The

Company produces approximately 29 MMcf per day from

400 operated wells in the Hugoton Chase Formation.

Plans for 2001 include ten Towanda completions and 35

Hugoton Chase re-stimulations.

We plan to spend $15 million to drill 37 wells and

perform 61 workovers and recompletions during 2001 in

the Hugoton Royalty Trust properties.

Burro Canyon and Morrison Formations.

Cross Timbers is spearheading a new play for production

from sandstones located just below the Dakota. We have

encountered productive Burro Canyon and Morrison

intervals in about a third of our Dakota development wells.

These wells produce at high sustained rates. One example,

the Kutz Federal 12E, was completed in the Burro Canyon

sandstones during 1999 produc-

ing at a daily rate of 1.4 MMcf.

This well has produced 550 MMcf

and is still holding its initial rate of 1.4 MMcf per day

after 18 months. Also, Cross Timbers owns an interest in

the Davis A Federal 1M that started production at 6 MMcf

per day from the Burro Canyon and Morrison sandstones.

After producing more than 1 Bcf in nine months, the well

still has a daily rate above 2.5 MMcf. Another well, the

Aztec Gas Com 4E, a recent Morrison sandstone comple-

tion, is also producing at daily rates exceeding 2.5 MMcf.

These are exceptional completion rates for the mature San

Juan Basin and bode well for a new cycle of development.

Hugoton Royalty Trust Area

During 2000, the Company drilled 39 wells and com-

pleted 90 workovers. Development drilling in Oklahoma

was focused in Major and Woodward counties (32 wells),

the Hugoton Field (one well) and the Elk City Unit (one

well). Also, five wells were drilled in the Fontenelle Unit

of Wyoming.

In Major and Woodward counties, the Chester and

Mississippian formations were the primary targets. In

Major County, 18 successful wells were drilled with aver-

age initial rates of 700 Mcf per day and reserves of 1 Bcf

per well. The Mississippian (Osage) trend development

was successfully extended to the south and east. The

Stanford 5-2, a southern step-out well, was completed at

a rate of 30 BOPD and 1.3 MMcf per day. Based on the

economic success of this well, three additional offset wells

will be drilled during 2001 with a total of ten wells drilled

in the Mississippian (Osage) trend during the next year.

The Chester Formation, with its four separate produc-

ing intervals, was the primary target for 14 wells drilled in

Woodward County during 2000. Daily operated produc-

tion in this area has increased to 14 MMcf from 8 MMcf.

The Quinlan area has received the most attention with ten

Rusk, TexasThe Texas State Railroad is over a hundred years old and still keeping it on the tracks.

Ozark Mountains, ArkansasBorn of a source deep in the mountains,the Mulberry River winds through therolling terrain.

We plan to drill ten infill wells in 2001 and see an

additional 30 to 40 well locations for future development.

Alaska

Middle Ground Shoal Field. The Middle Ground

Shoal Field in Alaska’s Cook Inlet has been producing oil

since the late 1960s. To date, more than 120 million Bbls

have been recovered and our engineers estimate over 30 mil-

lion Bbls of remaining potential. After a comprehensive

engineering and geologic study, we began our development

plan to accelerate extraction and maximize reserve recovery

from this complex, multi-pay structure.

Prior to our acquisition in 1998, a

total of 28 producing wells and 11 injec-

tors had been utilized to produce 3,950

BOPD through a full-scale waterflood

operation. This complex structure is

separated by a crestal fault that creates

East and West flanks. Numerous oil-

bearing zones within the Tyonek

Formation, ranging from 7,000 feet to

10,000 feet, remained virtually unswept.

Thus, our team created a

development plan to increase daily pro-

duction to more than 5,000 BOPD.

In 2000, we initiated our opera-

tional plan by expanding the development program on the

West Flank. First, two producing wells were converted to

injectors. The volume of injected water was increased and

oil volumes quickly responded in offset producers. Next,

two successful sidetrack wells were drilled to tap previously

untouched pockets of oil. As a result, production has risen

to about 4,400 BOPD, substantially ahead of our original

projections.

Development plans for 2001 include completing three

new producing wells along with optimizing the pressure

and volume performance of our waterflood expansion.

Development costs should be about $12 million.

EXPLORATION

Using our 3-D seismic model, we drilled and completed

three wells offsetting our successful 1999 Cowboy prospect

wildcat in the Nemaha Ridge area of central Oklahoma.

The Cowboy prospect was completed at an initial rate

of 230 BOPD while our new wildcat wells averaged

155 BOPD each.

18

Permian Basin

University Block 9. This West Texas field produces

from the Wolfcamp, Pennsylvanian and Devonian formations

which range in depth from 8,400 feet to 10,000 feet.

Development primarily focused on the deeper Devonian

Formation leaving the shallower zones for future develop-

ment. Sixteen vertical and seven horizontal sidetracks were

completed during 2000. As a result, field production

surged to 3,900 BOPD, a rate not seen since 1975.

The vertical Devonian wells had average initial rates of

175 BOPD and reserves of 180 MBO per well. Two southern

extension wells, the University 9D-6 and BA-5, tested at

160 BOPD and 300 BOPD, respectively.

The success of these wells instilled new life

into an area of the field where development

was once considered uncertain. The

University H-3 well, an eastern step-out

well, produced at 200 BOPD, proving up

additional locations in the eastern portion of

the field.

The seven horizontal sidetrack wells in

the Devonian interval were completed at

producing rates averaging 150 BOPD each.

Several of these were successful multi-lateral

horizontals. These innovative sidetracks use

an existing wellbore to develop reserves that

would have historically required two new vertical wells to

adequately drain. By using the multi-laterals, we can drill

and complete for just 25% of the cost of two vertical wells.

During 2001, the Company will focus on further devel-

opment of the Devonian Formation with six vertical wells

and 12 horizontal sidetracks.

Prentice Northeast Unit. This West Texas waterflood

unit is located in Terry and Yoakum counties and produces

from the Glorieta and Clear Fork formations at depths from

6,800 feet to 7,700 feet.

In 1995, Cross Timbers initiated a 10-acre development

drilling program. A total of 92 wells have been drilled to

date with 11 wells completed during 2000. Production has

averaged about 3,400 BOPD for the past several years due to

our continuing program of drilling ten wells per year.

Individual wells produce at initial rates of about 100 BOPD

and recover reserves averaging 70 MBO. During 2000,

drilling activities proved-up areas in the northern and east-

ern portions of the unit, where delineation wells encountered

high oil cuts, indicating pockets of unswept reserves.

A crestal fault separates the field into Eastand West flanks, trapping the hydrocarbons ofthe Tyonek reservoirs.

19

Proved Oil & Gas ReservesDecember 31, 2000(in thousands)

Oil Gas NGLs(Bbls) (Mcf) (Bbls) Mcfe

Proved developed 46,334 1,328,953 16,448 1,705,645 Proved undeveloped 12,111 440,730 5,564 546,780 Total proved 58,445 1,769,683 22,012 2,252,425 Estimated future net cash flows,

before income tax $ 15,239,560Present value before income tax $ 7,748,632

Changes in Proved Reserves(in thousands)

Oil Gas NGLs(Bbls) (Mcf) (Bbls) Mcfe

December 31, 1999 61,603 1,545,623 17,902 2,022,653 Revisions 2,709 142,974 3,709 181,482 Extensions and discoveries 1,145 258,843 1,951 277,419 Production (4,736) (125,857) (1,622) (164,005)Purchases in place 833 26,557 72 31,987 Sales in place (3,109) (78,457) – (97,111)December 31, 2000 58,445 1,769,683 22,012 2,252,425

Based on SEC assumptions

Also during 2000, we drilled a successful test well,

the Vernon Black 2-28, in the South Pine Hollow Field of

southeastern Oklahoma. Initial gas production averaged

more than 3 MMcf per day from the Cromwell

sandstones. We anticipate more locations in this

area based on a new seismic evaluation.

In 2001, we will continue to pursue these

exploration successes and other high-impact

projects. Plans call for exploration tests in the

high-potential region of the southern overthrust

trend of the Arkoma Basin of Arkansas where we

hold 80,000 acres. This prospect area is 20

miles south of our Washburn Anticline Trend

where fields have produced more than 50 Bcfe.

We expect to drill the first exploration well here

during the first half of 2001.

Finally, the Company will initiate several

wells to test the outer limits of our East Texas

Freestone Trend. In total, the exploration

budget is $10 million for the year.

RESERVES AND PRODUCTION

After several consecutive years of aggressive acquisi-

tions, Cross Timbers shifted its focus in 2000 to the huge

inventory of exploitation opportunities created by the

execution of its “acquire and exploit” strategy.

Estimated proved oil and gas reserves at year-end 2000

totaled 2.252 Tcfe, up 11% from 2.022 Tcfe at year-end

1999. This translates to 29 Mcfe for each share of the

Company’s common stock.

The Company replaced 491 Bcfe or 300% of 2000

production at a cost of $0.41 per Mcfe. Through the drill

bit, we replaced 280% of production at a cost of $0.37 per

Mcfe. For the past five years Cross Timbers has replaced

478% of its production at a finding cost of just $0.64 per

Mcfe. This remarkable performance places Cross Timbers

among the best in the industry for finding cost and produc-

tion replacement statistics and is a direct result of the

strength of our strategy, technical team and legacy asset base.

During 2000, the Company produced 4.7 million Bbls

of oil, 1.6 million Bbls of NGLs and 125.9 Bcf of natural

gas. Oil and NGLs production averaged 17,371 BOPD,

down 2% from 1999 due primarily to property sales. Daily

gas production averaged 343.9 MMcf, up 19% from 288.0

MMcf in 1999.

As of December 31, 2000, estimated future net cash

flows before income tax totaled $15.2 billion based on

realized prices of $25.49 per Bbl of oil, $9.55 per Mcf of

gas and $26.33 per Bbl of NGLs. The present

value before income tax, discounted at 10%, was

$7.7 billion, compared to the year-end 1999 level

of $1.8 billion. The realized prices at year-end

1999 were $24.17 per Bbl of oil, $2.20 per Mcf

of gas and $13.83 per Bbl of NGLs.

Assuming NYMEX prices of $25.00 per Bbl

of oil and $5.00 per Mcf of gas, estimated future

net cash flows before income tax would total

$7.4 billion while present value before income

tax, discounted at 10%, would be $3.8 billion.

Importantly, total proved reserves would decrease

by only 1% to 2.224 Tcfe.

Oil prices increased 60% in 2000 to an

average of $27.07 per Bbl, up from $16.94 per

Bbl in 1999. This increase reflects OPEC’s continuing

resolve to maintain higher oil prices through production

cuts when necessary. On the natural gas front, increased

demand driven by more seasonal weather and rising elec-

tricity generation needs clashed with declining domestic

productive capacity to result in reduced gas in storage,

higher prices and increased volatility. As such, our average

gas price for 2000 rose 59% to $3.38 per Mcf from an

average of $2.13 per Mcf in 1999. The NGLs price per Bbl

averaged $19.61, up 66% from the 1999 average sales price

of $11.80 per Bbl.

96 97 98 99 000

500

1000

2500

1500

2000

Proved Reservesby Category

(in Bcfe)

Oil NGLs Gas

20

In thousands except production, per share and per unit data 2000 1999 1998 1997 1996

Consolidated Income Statement and Cash Flows Data (a)

Revenues:Oil and condensate $ 128,194 $ 86,604 $ 56,164 $ 75,223 $ 75,013Gas and natural gas liquids 456,814 239,056 182,587 110,104 73,402Gas gathering, processing and marketing 16,123 10,644 9,438 9,851 12,032Other (280) 4,991 1,297 3,094 888

Total revenues $ 600,851 $ 341,295 $ 249,486 $198,272 $161,335

Earnings (loss) available to common stock $ 115,235(b) $ 44,964(c) $ (71,498)(d) $ 23,905 $ 19,790

Per common share (e)Basic $ 1.62 $ 0.64 $ (1.10) $ 0.40 $ 0.33Diluted $ 1.55 $ 0.63 $ (1.10) $ 0.39 $ 0.32

Weighted average common shares outstanding (e) 71,154 70,228 65,094 59,660 59,870

Dividends declared per common share (e) $ 0.0333 $ 0.0267 $ 0.1067 $ 0.1000 $ 0.0867

Operating cash flow (f) $ 344,638 $ 132,683 $ 78,480 $ 89,979 $ 68,263

Consolidated Balance Sheet Data (a)

Property and equipment, net $ 1,357,374 $1,339,080 $1,050,422 $723,836 $450,561Total assets $ 1,591,904 $1,477,081 $1,207,005 $788,455 $523,070Long-term debt $ 769,000 $ 991,100 $ 920,411 $539,000 $314,757Stockholders’ equity $ 497,367 $ 277,817 $ 201,474 $170,243 $142,668

Operating Data (a)

Average daily production:Oil (Bbls) 12,941 14,006 12,598 10,905 9,584Gas (Mcf) 343,871 288,000 229,717 135,855 101,845Natural gas liquids (Bbls) 4,430 3,631 3,347 220 —Mcfe 448,098 393,826 325,390 202,609 159,349

Average sales price:Oil (per Bbl) $27.07 $16.94 $12.21 $18.90 $21.38Gas (per Mcf) $ 3.38 $ 2.13 $ 2.07 $ 2.20 $ 1.97Natural gas liquids (per Bbl) $19.61 $11.80 $ 7.62 $ 9.66 —

Production expense (per Mcfe) $ 0.53 $ 0.53 $ 0.53 $ 0.59 $ 0.67Taxes, transportation and other (per Mcfe) $ 0.35 $ 0.23 $ 0.25 $ 0.22 $ 0.20

Proved reserves:Oil (Bbls) 58,445 61,603 54,510 47,854 42,440Gas (Mcf) 1,769,683 1,545,623 1,209,224 815,775 540,538Natural gas liquids (Bbls) 22,012 17,902 17,174 13,810 —Mcfe 2,252,425 2,022,653 1,639,328 1,185,759 795,178

(a) Significant producing property acquisitions in each of the years presented affect the comparability of year-to-year financial and operating data.

(b) Includes effect of a $43.2 million pre-tax gain on significant asset sales, a $55.8 million pre-tax derivative fair-value loss and $26.1 million in non-cash incentive compensation expense.

(c) Includes effect of a $40.6 million pre-tax gain on sale of Hugoton Royalty Trust units.

(d) Includes effect of a $93.7 million pre-tax net loss on investment in equity securities and a $2 million pre-tax, non-cash impairment charge.

(e) Adjusted for the three-for-two stock splits effected on March 19, 1997, February 25, 1998 and September 18, 2000.

(f) Defined as cash provided by operating activities before changes in operating assets and liabilities and exploration expense.

S E L E C T E D F I N A N C I A L D A T A

21

M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S

G e n e r a lThe following events affect the comparability of results of

operations and financial condition for the years ended December 31,2000, 1999 and 1998, and may impact future operations andfinancial condition. Throughout this discussion, the term “Mcfe”refers to thousands of cubic feet of gas equivalent quantitiesproduced for the indicated period, with oil and natural gas liquidquantities converted to Mcf on an energy equivalent ratio of onebarrel to six Mcf.

Three-for-Two Stock Splits. The Company effected three-for-two stock splits on February 25, 1998 and September 18, 2000. All common stock shares, treasury stock shares and per shareamounts have been retroactively restated to reflect all stock splits.

1999 Acquisitions. During 1999, the Company acquiredpredominantly gas-producing properties at a total cost of $510million primarily funded by a combination of bank borrowings,proceeds from a public offering of common stock and the issuanceof common stock. The acquisitions include:

• Spring Holding Company Acquisition. In July 1999, theCompany and Lehman Brothers Holdings, Inc. each acquired50% of the common stock of Spring Holding Company for a combination of cash and the Company’s common stocktotaling $85 million. In September 1999, the Companyexercised its option to acquire Lehman’s 50% interest in Spring for $44.3 million. The acquisition includes gasproperties located in the Arkoma Basin of Arkansas andOklahoma with a purchase price of $235 million. Afterpurchase accounting adjustments and other costs, the cost ofthe properties was $257 million.

• Ocean Energy Acquisition. In September 1999, theCompany and Lehman acquired Arkoma Basin gas propertiesfor $231 million. Lehman contributed $100 million in cashand the Company contributed $100 million in securities,including its common stock, to a jointly owned company.The acquisition was funded with cash of $100 million andbank borrowings of $131 million. The Company acquiredLehman’s interest in this acquisition on March 31, 2000 for$111 million, which was funded by proceeds from the salesof producing properties and equity securities, as well as bankdebt. The $11 million in excess of Lehman’s investment wasrecorded as additional property cost in 2000.

1998 Acquisitions. During 1998, the Company acquired oil-and gas-producing properties at a total cost of $340 million,i n c l u d i n g :

• East Texas Basin Acquisition. The Company acquiredthese primarily gas-producing properties at a purchase priceof $245 million, later reduced to $215 million by a $30 million production payment sold to EEX Corporation.This acquisition closed in April 1998 and was funded bybank debt, partially repaid from proceeds of the 1998Common Stock Offering.

• Cook Inlet Acquisition. In September 1998, the Companyacquired these oil-producing properties in Alaska from

affiliates of Shell Oil Company in exchange for 2.9 millionshares of the Company’s common stock along with certainprice guarantees and a non-interest bearing note payable of$6 million, resulting in a purchase price of $45 million.

• Seagull Acquisition. This acquisition included primarilygas-producing properties in northwest Oklahoma and the SanJuan Basin of New Mexico. The Company acquired theseproperties in November 1998 for an estimated purchase priceof $31 million, funded by bank borrowings.

Hugoton Royalty Trust Sales. The Company createdHugoton Royalty Trust in December 1998 by conveying 80% netprofits interests in producing properties in Kansas, Oklahoma andWyoming. In April and May 1999, the Company sold 17 millionunits, or 42.5%, of Hugoton Royalty Trust in its initial publicoffering. Total proceeds from this sale were $148.6 million, which were used to reduce bank debt. Total gain on sale, includingthe sale of units pursuant to an employee incentive plan, was $40.6 million before income tax. In October and November 2000,the Company sold 1.2 million units, or approximately 3%, ofHugoton Royalty Trust pursuant to the employee incentive plan.Total gain on these sales during 2000 was $11 million beforeincome tax.

2000 Property Sales. In March 2000, the Company sold oil- and gas-producing properties in Crockett County, Texas and Lea County, New Mexico for total gross proceeds of $68.3 million.

1999 Property Sales. In May and June 1999, the Companysold primarily nonoperated gas-producing properties in New Mexicofor $44.9 million. In September 1999, the Company sold primarilynonoperated oil- and gas-producing properties in Oklahoma, Texas,New Mexico and Wyoming for $63.5 million, including sales of$22.5 million of properties acquired in the Spring HoldingCompany Acquisition.

2000, 1999 and 1998 Development and ExplorationP r o g r a m s . Oil development was concentrated in the UniversityBlock 9 Field during all three years. Gas development focused onthe East Texas area in 2000 and 1999, the Hugoton Area during1998, and the Fontenelle Unit during all three years. Explorationactivity has been primarily geological and geophysical analysis,including seismic studies, of undeveloped properties. Exploratoryexpenditures were $1 million in 2000, $900,000 in 1999 and $8 million in 1998.

2001 Development and Exploration Program. The Companyhas budgeted $250 million for its 2001 development andexploration program, which is expected to be funded primarily bycash flow from operations. The Company anticipates explorationexpenditures will be approximately 4% of the 2001 budget. The total capital budget, including acquisitions, will be adjustedthroughout 2001 to focus on opportunities offering the highest ratesof return.

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Common Stock Transactions. The following significant salesand issuances of common stock occurred during the three-yearperiod ended December 31, 2000:

• In November 2000, the Company sold 6.6 million shares ofcommon stock from treasury with net proceeds ofapproximately $126.1 million. The proceeds were used toreduce outstanding indebtedness.

• In July 1999, the Company sold 3 million shares of commonstock from treasury with net proceeds of approximately $26.5 million. The proceeds were used to repurchase 2.9 million shares of common stock issued to affiliates ofShell for the Cook Inlet Acquisition.

• In July 1999, the Company issued 6 million shares ofcommon stock for its 50% interest in Spring HoldingCompany and for cash proceeds of $3.2 million which wasused to reduce bank debt.

• In September 1998, the Company issued 2.9 millioncommon shares from treasury to affiliates of Shell for theCook Inlet Acquisition. In July 1999, the Companyrepurchased these shares from Shell.

• In April 1998, the Company sold 10.8 million shares ofcommon stock. Net proceeds of $133.1 million were used topartially repay bank debt used to fund the East Texas BasinA c q u i s i t i o n .

Treasury Stock Purchases. The Company often repurchasesshares of its common stock as part of its strategic acquisition plans.The Company purchased on the open market 5.3 million shares at acost of $41.4 million in 2000, 7,500 shares at a cost of $53,000 in1999 and 6.5 million shares at a cost of $65.6 million in 1998.Through March 26, 2001, 4.3 million shares remain under the May2000 Board of Directors’ authorization to purchase an additional 4.5 million shares.

Conversion of Preferred Stock. In January 2001, theCompany sent notice to preferred stockholders that it would redeemall outstanding shares on February 16, 2001 at a price of $25.94 pershare plus accrued and unpaid dividends. Prior to the redemptiondate, 1.1 million outstanding shares of preferred stock wereconverted into 3.5 million common shares.

Investment in Equity Securities. In 1998, the Companypurchased what it believed to be undervalued oil and gas reserves byacquiring common stock of publicly traded independent oil and gasproducers at a total cost of $167.7 million. For accounting purposes,the Company considered equity securities purchased in 1998 to betrading securities since they were purchased with the intent to resellin the near future, and therefore recognized unrealized investmentgains and losses in the income statements. After selling a portion ofthese securities in 1998 and 1999, the Company sold its remaininginvestment in equity securities in 2000 for $43.7 million. TheCompany recognized a $13.3 million gain in 2000, and losses of$1.1 million in 1999 and $93.7 million in 1998 related to thisi n v e s t m e n t .

Derivative Fair Value Loss. During 2000, the Companyrecorded a $55.8 million loss on call options which the Companysold in 1999 related to its hedging activities. Because written calloptions do not provide protection against declining prices, they do not qualify for hedge or loss deferral accounting. A currentliability of $53.8 million related to this loss is recorded in theconsolidated balance sheet at December 31, 2000. See “AccountingChanges” below.

Incentive Compensation. Incentive compensation results fromstock appreciation right, performance share and royalty trust optionawards, and subsequent changes in the Company’s stock price. In 2000, incentive compensation totaled $26.1 million, which wasprimarily related to performance share grants and royalty trustoption exercises. Incentive compensation was not significant in1999. In 1998, incentive compensation totaled $1.3 million, whichincluded non-cash performance share compensation of $1.6 million,partially offset by a reduction in stock appreciation rightcompensation of $300,000. As of December 31, 2000, there were85,000 performance shares outstanding that vested when thecommon stock price closed above $30.00 on March 9, 2001, and13,500 performance shares that vest in increments of 4,500 in eachof 2001, 2002 and 2003. On March 9, 2001, an additional 77,000 performance shares were issued that vest when the stockprice closes above $32.50.

Product Prices. In addition to supply and demand, oil and gasprices are affected by seasonal, political and other fluctuations theCompany generally cannot control or predict.

Crude oil prices are generally determined by global supply anddemand. Starting at about $15 per barrel, crude oil prices declinedthroughout 1998, dropping to a posted West Texas Intermediate(“WTI”) price of $8.00 per barrel in December 1998, the lowestlevel since 1978. Oil prices increased in 1999 because of productioncuts by OPEC and other leading oil exporters, reduced inventoriesand anticipated increased demand. Despite OPEC productionincreases in 2000, increased demand has sustained higher prices. In September 2000, posted WTI prices reached $34.25, theirhighest levels since the 1990 Persian Gulf War. In response tolower prices in 2001 caused by lagging demand, OPEC membersannounced their resolve to maintain higher oil prices throughproduction cuts when needed. The Company uses commodity pricehedging instruments to reduce its exposure to oil price fluctuations.Including the effect of these hedging instruments, the Company’saverage oil price decreased from $28.72 to $27.07 in 2000 and from $17.37 to $16.94 in 1999. Based on 2000 production, the Company estimates that a $1.00 per barrel increase or decreasein the average oil sales price would result in approximately a $4.5 million change in 2001 annual operating cash flow.

Natural gas prices are influenced by North American supplyand demand, which is often dependent upon weather conditions.Natural gas competes with alternative energy sources as a fuel forheating and the generation of electricity. Gas prices wereapproximately $2.00 per MMBtu in January 1998 and remainedlower throughout the year because of mild winters in the central andeastern U.S. Cooler spring weather and lower industry productionlevels strengthened gas prices in 1999 and, after declining briefly atthe end of 1999, continued to strengthen in 2000. The combination

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of lower domestic productive capacity, reduced storage and increasedsummer and winter demand have resulted in higher natural gasprices with increased volatility. NYMEX gas prices reached a recordhigh of $10.10 in December 2000. At March 15, 2001, the averageNYMEX price for the following 12 months was $5.08 per MMBtu.The Company uses commodity price hedging instruments to reduceits exposure to gas price fluctuations. Including the effect of thesehedging instruments, the Company’s average gas price decreasedfrom $3.70 to $3.38 in 2000 and from $2.18 to $2.13 in 1999.Based on 2000 production, the Company estimates that a $0.10 perMcf increase or decrease in the average gas sales price would result inapproximately an $11 million change in 2001 annual operating cashflow. However, a significant portion of the Company’s gas productionthrough March 2002 is hedged by contracts that effectively fix prices.See Note 8 to Consolidated Financial Statements.

Impairment Provision. During 1998, the Company recordedan impairment provision on producing properties of $2 millionbefore income tax. This impairment provision was determinedbased on an assessment of recoverability of net property costs fromestimated future net cash flows from those properties. Estimatedfuture net cash flows are based on management’s best estimate ofprojected oil and gas reserves and prices. If oil and gas pricessignificantly decline, the Company may be required to recordimpairment provisions in the future, which could be material.

Results of Operations2000 Compared to 1999

For the year 2000, earnings available to common stock were$115.2 million compared with earnings available to common stockof $45 million for 1999. The 2000 earnings include a $7.3 millionafter-tax gain from the sale of Hugoton Royalty Trust units, a $13.1 million after-tax gain on sale of properties, an $8.8 millionafter-tax gain on investment in equity securities, a $17.3 millionafter-tax charge for incentive compensation and a $36.8 after-tax losson the change in derivative fair value. The 1999 earnings include a $26.8 million after-tax gain from the sale of Hugoton RoyaltyTrust units, a $4.2 million after-tax gain on sale of properties, and an $800,000 after-tax loss on investment in equity securities.Excluding these gains and losses from asset sales and incentivecompensation, earnings for 2000 were $140.1 million, comparedwith $14.8 million for 1999.

Revenues for 2000 were $600.9 million, or 76% above 1999revenues of $341.3 million. Oil revenue increased $41.6 million, or 48%, because of a 60% increase in oil prices from an average of$16.94 per Bbl in 1999 to $27.07 in 2000 (see “General – Product Prices” above), partially offset by a 7% decrease in oilproduction. Decreased production was primarily because of the2000 property sales.

Gas and natural gas liquids revenue increased $217.8 million,or 91%, because of a 20% increase in gas production, a 22% increasein natural gas liquids production, a 59% increase in gas prices from an average of $2.13 per Mcf in 1999 to $3.38 in 2000 and a 66% increase in natural gas liquids prices from an average price of $11.80 per Bbl in 1999 to $19.61 in 2000 (see “General – ProductPrices” above). Increased gas and natural gas liquids production was attributable to the 1999 acquisitions and the 1999 and 2000development programs.

Gas gathering, processing and marketing revenues increased$5.5 million primarily because of higher gas and natural gas liquidsprices, increased margin and increased volumes from the 1999acquisitions. Other revenues were $5.3 million lower primarilybecause of decreased net gains on sale of properties.

Expenses for 2000 totaled $388.7 million as compared withtotal 1999 expenses of $245.9 million. Most expenses increased in2000 primarily because of the 1999 acquisitions and the 1999 and2000 development programs.

Production expense increased $10.9 million, or 14%, becauseof increased production related to the 1999 acquisitions and 1999and 2000 development programs. Production expense per Mcferemained flat at $0.53. The Company’s 2000 exploration expense of $1 million, which was predominantly geological and geophysicalcosts, remained about the same as 1999.

Taxes, transportation and other deductions increased 68% or$23 million because of increased oil and gas revenues, as well asincreased transportation, compression and other charges related tothe 1999 acquisitions and the 1999 and 2000 developmentprograms. Taxes, transportation and other per Mcfe increased 52%from $0.23 to $0.35 because of increased prices and otherd e d u c t i o n s .

Depreciation, depletion and amortization (“DD&A”) increased$17.4 million, or 16%, primarily because of the 1999 acquisitionsand the 1999 and 2000 development programs. On an Mcfe basis,DD&A increased slightly from $0.78 in 1999 to $0.79.

General and administrative expense increased $35.4 million, or 251% because of incentive compensation of $26.1 million andincreased expenses from Company growth related to the 1999acquisitions. Excluding incentive compensation, general andadministrative expense per Mcfe increased from $0.10 in 1999 to$0.14 in 2000.

Interest expense increased $14.7 million, or 23%, primarilybecause of a 7% increase in weighted average borrowings and an 8% increase in the weighted average interest rate. Interest classifiedas part of the gain (loss) on investment in equity securities decreased$4.6 million from 1999. Interest expense per Mcfe increased from$0.45 in 1999 to $0.48 in 2000.

1999 Compared to 1998

For the year 1999, earnings available to common stock were$45 million compared with a loss available to common stock of$71.5 million for 1998. The 1999 earnings include a $26.8 millionafter-tax gain from the sale of Hugoton Royalty Trust units, a $4.2million after-tax gain on sale of properties and an $800,000 after-taxloss on investment in equity securities. The 1998 loss includes a$61.8 million after-tax loss related to the Company’s investment inequity securities, a $500,000 after-tax gain on sale of properties, a$1.3 million after-tax impairment write-off of producing propertiesand a $900,000 after-tax charge for incentive compensation.Excluding these gains and losses from investments and asset salesand charges for impairment and incentive compensation, earningsfor 1999 were $14.8 million, compared with an $8 million loss for 1998.

Revenues for 1999 were $341.3 million, or 37% above 1998revenues of $249.5 million. Oil revenue increased $30.4 million,

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or 54%, because of an 11% increase in oil production and a 39%increase in oil prices from an average of $12.21 per Bbl in 1998 to$16.94 in 1999 (see “General – Product Prices” above). Increasedproduction was primarily because of the 1998 acquisitions.

Gas and natural gas liquids revenue increased $56.5 million, or 31%, because of a 25% increase in gas production, a 3% increasein gas prices and a 55% increase in natural gas liquids prices from an average price of $7.62 per Bbl in 1998 to $11.80 in 1999 (see “General – Product Prices” above). Increased gas productionwas attributable to the 1998 and 1999 acquisitions anddevelopment programs.

Gas gathering, processing and marketing revenues increased$1.2 million primarily because of higher gas and natural gas liquidsprices, increased margin and increased volumes from the 1999acquisitions. Other revenues were $3.7 million higher primarilybecause of increased net gains on sale of properties, partially offset by decreased lawsuit settlement receipts.

Expenses for 1999 totaled $245.9 million as compared withtotal 1998 expenses of $209.2 million. Most expenses increased in1999 primarily because of the 1998 and 1999 acquisitions anddevelopment programs.

Production expense increased $13 million, or 21%, because ofincreased production. Production expense per Mcfe remained flat at$0.53. The Company lowered its exploration budget for 1999,resulting in a $7.1 million reduction in exploration expense, whichis predominantly geological and geophysical costs.

Taxes, transportation and other deductions increased 16% or$4.6 million because of increased oil and gas revenues, as well asincreased transportation, compression and other charges related tothe 1998 and 1999 acquisitions. Taxes, transportation and other per Mcfe decreased 8% from $0.25 to $0.23 because of decreasedproperty taxes and a lower production tax rate associated withproduction from the 1999 acquisitions.

Depreciation, depletion and amortization increased $28.8 million, or 34%, primarily because of the 1998 and 1999acquisitions and development programs. On an Mcfe basis, DD&Aincreased from $0.70 in 1998 to $0.78 in 1999 primarily because ofthe higher cost per Mcfe of the 1998 and 1999 acquisitions.

General and administrative expense increased $600,000, or5%, because of increased expenses from Company growth related tothe 1998 and 1999 acquisitions. Excluding incentive compensation,general and administrative expense per Mcfe remained at $0.10 in 1999.

Interest expense increased $12.1 million, or 23%, primarilybecause of a comparable increase in weighted average borrowings topartially fund the 1998 and 1999 acquisitions. Interest related toinvestment in equity securities has been classified as part of the losson investment in equity securities. Interest expense per Mcfeincreased slightly from $0.44 in 1998 to $0.45 in 1999.

Liquidity and Capital Resourc e sThe Company’s primary sources of liquidity are cash flow from

operating activities, producing property sales, including sales ofroyalty trust units, public offerings of equity and debt, and bankdebt. Other than for operations, the Company’s cash requirementsare generally for the acquisition, exploration and development of oiland gas properties, and debt and dividend payments. Exploration

and development expenditures and dividend payments havegenerally been funded by cash flow from operations. The Companybelieves that its sources of liquidity are adequate to fund its cashrequirements in 2001.

Cash provided by operating activities was $377.4 million in2000, compared with cash provided by operating activities of$133.3 million in 1999 and $53.9 million cash used by operationsin 1998. Fluctuations during this three-year period were primarilybecause of purchases of equity securities and lower product prices in1998 and increased prices and production from acquisitions anddevelopment activity in 1999 and 2000. Before changes inoperating assets and liabilities and exploration expense, cash flowfrom operations was $344.6 million in 2000, $132.7 million in1999 and $78.5 million in 1998.

Financial Condition

Total assets increased 8% from $1.5 billion at December 31,1999 to $1.6 billion at December 31, 2000, primarily because ofhigher product prices and Company growth related to the 1999acquisitions. As of December 31, 2000, total capitalization of theCompany was $1.3 billion, of which 61% was long-term debt.Capitalization at December 31, 1999 was also $1.3 billion, but78% was long-term debt. The decrease in the debt-to-capitalizationratio from year-end 1999 to 2000 is because of repayment of debtfrom cash flow and the sale of common stock.

Working Capital

The Company generally uses available cash to reduce bank debt and, therefore, does not maintain large cash and cash equivalentbalances. Short-term liquidity needs are satisfied by bankcommitments under the loan agreement (see “Financing” below).Because of this, and since the Company’s principal source ofoperating cash flows (i.e., proved reserves to be produced in thefollowing year) cannot be reported as working capital, the Companyoften has low or negative working capital. The decrease in workingcapital from $39.3 million at December 31, 1999 to negativeworking capital of $25.3 million at December 31, 2000 wasprimarily attributable to the sale of equity security investments andincreased current liabilities, net of the increase in current deferredincome tax benefit, related to the derivative fair value loss.

Included in other current liabilities at December 31, 2000 is a$53.8 million derivative loss accrual for the fair value of call optionssold in 1999 related to the Company’s hedging activities.Beginning January 1, 2001, the Company will also accrue fair valuelosses related to unrealized hedge derivative losses and a gas deliverycontract. See “Accounting Changes” below. The Company expectsthat any cash settlement of these derivative losses should be offset byincreased cash flows from the Company’s sale of related production.Therefore, the Company believes that substantially all derivative fair value gains and losses are offset by changes in value of its naturalgas reserves. This offsetting change in gas reserve value, however, isnot reflected in working capital.

Prior to their sale, equity securities owned by the Company hadbeen held in a PaineWebber broker account and provided supportfor officer margin debt. As of March 2001, officer margin debtbalances related to Company common stock were fully repaid, andthe margin support agreements were terminated because they wereno longer needed. See Note 3 to Consolidated Financial Statements.

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F i n a n c i n g

In May 2000, the Company entered a new revolving creditagreement with commercial banks with a commitment of $800 million. Proceeds of this loan agreement were used torefinance the Company’s previous senior credit facility and to fullyrepay a $25 million term loan and the separate bank debt of theCompany’s subsidiaries, Spring Holding Company and SummerAcquisition Company. In June 2000, the loan agreement wasamended to allow the Company to issue letters of credit. Any lettersof credit outstanding reduce the borrowing capacity under therevolving credit facility. As of December 31, 2000, letters of creditoutstanding totaled $33 million. Borrowings at December 31, 2000under the loan agreement were $469 million with unused borrowingcapacity of $298 million. The borrowing base is redeterminedannually based on the value and expected cash flow of theCompany’s proved oil and gas reserves. If borrowings exceed theredetermined borrowing base, the banks may require that the excessbe repaid within a year. Based on reserve values at December 31,2000 and parameters specified by the banks, the borrowing basesupports borrowings in excess of the $800 million commitment.Borrowings under the loan agreement are due May 12, 2005, but may be prepaid at any time without penalty. The Companyperiodically renegotiates the loan agreement to increase theborrowing commitment and extend the revolving facility. In February 2001, the loan agreement was amended to allow therepurchase of the Company’s subordinated debt and to increasecommodity hedging limits.

On January 3, 2001, the Company purchased primarily gas-producing properties in East Texas and Louisiana for $115 million,of which $11.6 million had been paid in 2000. This acquisition was funded through borrowings under the loan agreement which are expected to be repaid from cash flow during the first six monthsof 2001.

The 1999 and 1998 acquisitions were partially funded by thesale and issuance of common stock and cash flow from operations.The 1999 acquisitions were also partially funded by contributionsfrom Lehman, the Company’s equity partner until the Companylater purchased Lehman’s interest in these acquisitions. Thesetransactions are described under “General” above. See also “CapitalExpenditures” below.

Capital Expenditures

Because of their size, the 1999 acquisitions were made jointlywith Lehman as a 50% equity partner. Pursuant to its call option,the Company acquired Lehman’s interest in the Spring HoldingAcquisition in September 1999. The Company exercised its optionto purchase Lehman’s interest in the Ocean Energy Acquisition onMarch 31, 2000 for $111 million, funded primarily by the proceedsfrom sales of property and equity security investments. TheCompany plans to fund any future property acquisitions through acombination of cash flow from operations and proceeds from assetsales, bank debt, public equity or debt transactions. There are norestrictions under the Company’s revolving credit agreement thatwould affect the Company’s ability to use its remaining borrowingcapacity for acquisitions of producing properties.

In February 2000, the Board of Directors authorized therepurchase of 3.8 million shares of the Company’s common stock.

Upon completion of repurchases under this authorization, the Boardof Directors authorized the repurchase of an additional 4.5 millionshares in May. During 2000, the Company repurchased 5.3 millionshares of its common stock at a cost of $41.4 million, including 1.3 million shares repurchased under a prior Board authorization.As of March 26, 2001, 4.3 million shares are available for repurchaseunder the May 2000 Board authorization.

In 2000, exploration and development cash expenditurestotaled $155.4 million compared with $91.6 million in 1999. The Company has budgeted $250 million for the 2001 developmentprogram. As it has done historically, the Company expects to fundthe 2001 development program with cash flow from operations.Since there are no material long-term commitments associated withthis budget, the Company has the flexibility to adjust its actualdevelopment expenditures in response to changes in product prices,industry conditions and the effects of the Company’s acquisition and development programs.

A minor portion of the Company’s existing properties areoperated by third parties which control the timing and amount of expenditures required to exploit the Company’s interests in suchproperties. Therefore, the Company cannot assure the timing oramount of these expenditures.

To date, the Company has not spent significant amounts tocomply with environmental or safety regulations, and it does notexpect to do so during 2001. However, developments such as newregulations, enforcement policies or claims for damages could resultin significant future costs.

D i v i d e n d s

The Board of Directors declared quarterly dividends of $0.0267per common share in 1998, $0.0067 per common share from 1999through second quarter 2000 and $0.01 per common share for thethird and fourth quarters of 2000. The Company’s ability to paydividends is dependent upon available cash flow, as well as otherfactors. In addition, the Company’s bank loan agreement restrictsthe amount of common stock dividends to 25% of cash flow fromoperations, as defined, for the last four quarters.

Cumulative dividends on Series A convertible preferred stockare paid quarterly, when declared by the Board of Directors, basedon an annual rate of $1.5625 per share. Pursuant to the Company’snotice of preferred stock redemption, all preferred stock wasconverted into common shares prior to March 2001.

Accounting ChangesEffective January 1, 2001, the Company has adopted Statement

of Financial Accounting Standards (“SFAS”) No. 133, Accounting forDerivative Instruments and Hedging Activities, as amended by SFASNos. 137 and 138. SFAS No. 133 requires the Company to recordall derivatives on the balance sheet at fair value. Change in the fairvalue of derivatives that are not designated as hedges, as well as theineffective portion of hedge derivatives, must be recognized as aderivative fair value gain or loss in the income statement. Change infair value of effective cash flow hedges are recorded as a componentof other comprehensive income, which is later transferred to earningswhen the hedged transaction occurs. Physical delivery contractswhich cannot be net cash settled are deemed to be normal sales andtherefore are not accounted for as derivatives. However, physical

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delivery contracts that have a price not clearly and closely associatedwith the asset sold are not a normal sale and must be accounted foras a non-hedge derivative.

The Company accounted for adoption of SFAS No. 133 onJanuary 1, 2001 by recording a one-time after-tax charge of $44.6 million in the income statement for the cumulative effect of a change in accounting principle, and an unrealized after-tax loss of $67.3 million in other comprehensive income. The charge to theincome statement is primarily related to the Company’s physicaldelivery contract to sell 35,500 Mcf of natural gas per day from2002 through July 2005 at crude oil-based prices. The unrealizedloss is related to the derivative fair value of cash flow hedges. SeeNote 8 to Consolidated Financial Statements. Amounts recorded onthe balance sheet at January 1, 2001 were a $103.6 million currentliability, a $2.2 million long-term asset and a $70.8 million long-term liability related to the fair value of derivatives, and a currentdeferred tax asset of $36.3 million and a reduction to the long-termtax liability of $24 million for the related tax benefits.

As oil and gas prices fluctuate, the Company will recognize aderivative fair value gain or loss in its consolidated income statementrelated to the gas physical delivery contract with crude oil-basedpricing, as well as written call options. The opportunity loss, relatedto market gas prices exceeding the prices provided by thesecontracts, is immediately recognized as a loss in derivative fair valuein the income statement. This contrasts with opportunity losses on hedge derivative contracts which are recorded as an unrealizedloss in other comprehensive income and later recognized in theincome statement when the related sale occurs. Since there is no netcash settlement expected under the gas physical delivery contract,any losses recognized under this contract will be reversed intoincome when gas is delivered. In all other cases, derivative lossesshould be offset by increased cash flows from the Company’s latersale of related production. Accordingly, the Company believes thatsubstantially all derivative fair value gains and losses will be offset by changes in the value of its natural gas reserves. This offsettingchange in gas reserve value, however, is not reflected in theCompany’s financial statements.

See “Qualitative and Quantitative Disclosures about MarketRisk – Commodity Price Risk” for the effect of price changes onderivative fair value gains and losses.

P roduction ImbalancesThe Company has gas production imbalance positions that are

the result of partial interest owners selling more or less than theirproportionate share of gas on jointly owned wells. Imbalances aregenerally settled by disproportionate gas sales over the remaininglife of the well, or by cash payment by the overproduced party to theunderproduced party. The Company uses the entitlement method of accounting for natural gas sales. At December 31, 2000, theCompany’s consolidated balance sheet includes a net current asset of$2.5 million for a net underproduced balancing position of 911,000Mcf of natural gas, and a net long-term liability of $3.7 million foran overproduced balancing position of 3,581,000 Mcf of natural gas,net of an underproduced balancing position of 10,062,000 Mcf ofcarbon dioxide. Production imbalances do not have, and are notexpected to have, a significant impact on the Company’s liquidity or operations.

F o rw a rd-Looking StatementsCertain information included in this annual report and other

materials filed or to be filed by the Company with the Securities andExchange Commission, as well as information included in oralstatements or other written statements made or to be made by theCompany, contain projections and forward-looking statementswithin the meaning of Section 21E of the Securities Exchange Act of1934, as amended, and Section 27A of the Securities Act of 1933, as amended, relating to the Company’s operations and the oil andgas industry. Such forward-looking statements may be or mayconcern, among other things, capital expenditures, cash flow,drilling activity, acquisition and development activities, pricingdifferentials, operating costs, production activities, oil, gas andnatural gas liquids reserves and prices, hedging activities and theresults thereof, liquidity, debt repayment, regulatory matters andcompetition. Such forward-looking statements are based onmanagement’s current plans, expectations, assumptions, projectionsand estimates and are identified by words such as “expects,”“intends,” “plans,” “projects,” “predicts,” “anticipates,” “believes,”“estimates,” “goal,” “should,” “could,” “assume,” and similar wordsthat convey the uncertainty of future events. These statements arenot 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 insuch forward-looking statements.

Among the factors that could cause actual results to differmaterially are:

• crude oil and natural gas price fluctuations,

• changes in interest rates,

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

• higher than expected production costs and other expenses,

• potential delays or failure to achieve expected productionfrom existing and future exploration and developmentp r o j e c t s ,

• volatility of crude oil, natural gas and hydrocarbon-basedfinancial derivative prices,

• basis risk and counterparty credit risk in executingcommodity price risk management activities,

• potential liability resulting from pending or future litigation, and

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

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

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Q U A N T I TATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company only enters derivative financial instruments inconjunction with its hedging activities. These instrumentsprincipally include interest rate swap agreements and commodityfutures, swaps and option agreements. These financial andcommodity-based derivative contracts are used to limit the risks ofinterest rate fluctuations and natural gas and crude oil price changes.Gains and losses on these derivatives are generally offset by lossesand gains on the respective hedged exposures.

The Board of Directors has adopted a policy governing the useof derivative instruments, which requires that all derivatives used bythe Company relate to an underlying, offsetting position, anticipatedtransaction or firm commitment, and prohibits the use ofspeculative, highly complex or leveraged derivatives. The policy alsorequires review and approval by the Chairman or the Executive VicePresident - Administration of all risk management programs usingderivatives and all derivative transactions. These programs are alsoreviewed at least annually by the Board of Directors.

Hypothetical changes in interest rates and prices chosen for the following estimated sensitivity effects are considered to bereasonably possible near-term changes generally based onconsideration of past fluctuations for each risk category. It is notpossible to accurately predict future changes in interest rates andproduct prices. Accordingly, these hypothetical changes may notnecessarily be an indicator of probable future fluctuations.

I n t e rest Rate RiskThe Company is exposed to interest rate risk on short-term and

long-term debt carrying variable interest rates. At December 31,2000, the Company’s variable rate debt had a carrying value of $469 million, which approximated its fair value, and the Company’sfixed rate debt had a carrying value of $300 million and anapproximate fair value of $305 million. Assuming a one percent, or 100-basis point, change in interest rates at December 31, 2000,the fair value of the Company’s fixed rate debt would change byapproximately $16.4 million. The Company attempts to balancethe benefit of lower cost variable rate debt that has inherentincreased risk with more expensive fixed rate debt that has lessmarket risk. This is accomplished through a mix of bank debt withshort-term variable rates and fixed rate subordinated debt, as well as the use of interest rate swaps.

The following table shows the carrying amount and fair valueof long-term debt and interest rate swaps, and the hypotheticalchange in fair value that would result from a 100-basis point changein interest rates. The hypothetical change in fair value could resultin a gain or a loss depending on an increase or decrease in theinterest rate.

H y p o t h e t i c a lC a r r y i n g F a i r Change in

(in thousands) A m o u n t V a l u e Fair Value

December 31, 2000Long-term debt $ ( 7 6 9 , 0 0 0 ) $ ( 7 7 4 , 0 0 0 ) $ 1 6 , 3 8 9Interest rate swaps 4 7 3 2 , 6 5 1 1 , 4 8 4

December 31, 1999Long-term debt $ ( 9 9 1 , 1 0 0 ) $ ( 9 8 1 , 5 4 0 ) $ 1 6 , 7 7 1Interest rate swaps 2 1 8 2 , 5 0 3 2 , 2 3 7

Commodity Price RiskThe Company hedges a portion of its price risks associated

with its crude oil and natural gas sales. As of December 31, 2000,the Company had outstanding gas futures contracts, swapagreements and gas basis swap agreements. Gas futures contractsand swap agreements would have had a total fair value loss ofapproximately $112.8 million at December 31, 2000 and $2.7 million at December 31, 1999. Basis swap agreements had afair value gain of $3.9 million at December 31, 2000 and a fair valueloss of $1.1 million at December 31, 1999. The aggregate effect of a hypothetical 10% change in gas prices and basis would result in a change of approximately $19.9 million in the fair value of gas futures contracts and swap agreements and approximately$483,000 in the fair value of basis swap agreements at December 31,2000. This sensitivity does not include the effects of commoditycontracts, such as physical product delivery contracts, that cannot be settled in cash or another financial instrument. See Note 8 toConsolidated Financial Statements.

In conjunction with its hedging activities, the Company soldcall options to sell future gas production at certain ceiling prices.Call options outstanding had a fair value loss of $44.5 million atDecember 31, 2000 and $300,000 at December 31, 1999. Theaggregate effect of a hypothetical 10% change in gas prices and basiswould result in a change of approximately $8.1 million in the fairvalue of these options at December 31, 2000. Changes in the fairvalue of these options are recognized in the consolidated incomestatements since they do not qualify for hedge accounting. See Note 7 to Consolidated Financial Statements.

The Company has entered a physical delivery contract to sell35,500 Mcf per day from 2002 through July 2005 at a price ofapproximately 10% of the average NYMEX futures price forintermediate crude oil. Because this gas sales contract is pricedbased on crude oil, which is not clearly and closely associated withnatural gas prices, it must be accounted for as a non-hedge derivativefinancial instrument under SFAS No. 133 beginning January 1,2001. See Note 8 to Consolidated Financial Statements and“Accounting Changes” above. The pre-tax fair value loss of thiscontract at January 1, 2001 is $70.8 million. The effect of ahypothetical 10% change in gas prices would result in a change ofapproximately $15.8 million in the fair value of this contract, whilea 10% change in crude oil prices would result in a change ofapproximately $8.7 million.

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Cr o s s T i m b e r s O i l C om pa n y

December 31

(in thousands, except shares) 2000 1999

ASSETS

Current Assets:Cash and cash equivalents $ 7,438 $ 5,734Accounts receivable, net 158,826 68,998Investment in equity securities — 29,052Deferred income tax benefit 17,098 4,168Other current assets 10,075 5,540

Total Current Assets 193,437 113,492

Property and Equipment, at cost — successful efforts method:Producing properties 1,732,017 1,635,883Undeveloped properties 6,460 10,358Gas gathering and other 38,340 32,902

Total Property and Equipment 1,776,817 1,679,143Accumulated depreciation, depletion and amortization (419,443) (340,063)

Net Property and Equipment 1,357,374 1,339,080

Other Assets 32,879 16,817

Loans to Officers 8,214 7,692

TOTAL ASSETS $1,591,904 $1,477,081

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities:Accounts payable and accrued liabilities $ 153,581 $ 68,937Payable to royalty trusts 8,577 2,739Other current liabilities 56,593 2,542

Total Current Liabilities 218,751 74,218

Long-term Debt 769,000 991,100

Deferred Income Taxes Payable 82,476 25,975

Other Long-term Liabilities 24,310 7,959

Commitments and Contingencies (Note 6)

Minority Interest in Consolidated Subsidiary — 100,012

Stockholders’ Equity:Series A convertible preferred stock ($.01 par value, 25,000,000 shares authorized,

1,088,663 and 1,138,729 shares issued, at liquidation value of $25) 27,217 28,468Common stock ($.01 par value, 100,000,000 shares authorized,

82,586,830 and 87,282,751 shares issued) 826 873Additional paid-in capital 435,735 396,277Treasury stock (5,031,040 and 13,949,073 shares) (50,829) (119,387)Retained earnings (deficit) 84,418 (28,414)

Total Stockholders’ Equity 497,367 277,817

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY $1,591,904 $1,477,081

See accompanying notes to consolidated financial statements.

C O N S O L I D A T E D B A L A N C E S H E E T S

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C O N S O L I D A T E D I N C O M E S T A T E M E N T S

Year Ended December 31

(in thousands, except per share data) 2000 1999 1998

REVENUES

Oil and condensate $128,194 $ 86,604 $ 56,164Gas and natural gas liquids 456,814 239,056 182,587Gas gathering, processing and marketing 16,123 10,644 9,438Other (280) 4,991 1,297

Total Revenues 600,851 341,295 249,486

EXPENSES

Production 86,988 76,110 63,148Taxes, transportation and other 56,696 33,681 29,105Exploration 1,047 904 8,034Depreciation, depletion and amortization 129,807 112,364 83,560Impairment — — 2,040Gas gathering and processing 8,930 8,743 8,360General and administrative 49,460 14,091 13,479Derivative fair value loss 55,821 — — Trust development costs — — 1,498

Total Expenses 388,749 245,893 209,224

OPERATING INCOME 212,102 95,402 40,262

OTHER INCOME (EXPENSE)Gain on significant property divestitures 29,965 40,566 — Gain (loss) on investment in equity securities 13,279 (1,149) (93,719)Interest expense, net (78,914) (64,214) (52,113)

Total Other Income (Expense) (35,670) (24,797) (145,832)

INCOME (LOSS) BEFORE INCOME TAXAND MINORITY INTEREST 176,432 70,605 (105,570)

Income Tax Expense (Benefit) 59,380 23,965 (35,851)Minority Interest in Net (Income) Loss of Consolidated Subsidiaries (59) 103 —

NET INCOME (LOSS) 116,993 46,743 (69,719)Preferred stock dividends 1,758 1,779 1,779

EARNINGS (LOSS) AVAILABLE TO COMMON STOCK $115,235 $ 44,964 $ (71,498)

EARNINGS (LOSS) PER COMMON SHAREBasic $ 1.62 $ 0.64 $ (1.10)

Diluted $ 1.55 $ 0.63 $ (1.10)

Weighted Average Common Shares Outstanding 71,154 70,228 65,094

See accompanying notes to consolidated financial statements.

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C O N S O L I D A T E D S T A T E M E N T S O F C A S H F L O W S

Year Ended December 31

(in thousands) 2000 1999 1998

OPERATING ACTIVITIES

Net income (loss) $ 116,993 $ 46,743 $ (69,719)Adjustments to reconcile net income (loss) to net cash

provided (used) by operating activities:Depreciation, depletion and amortization 129,807 112,364 83,560Impairment — — 2,040Non-cash incentive compensation 25,790 93 1,141Deferred income tax 58,993 23,657 (35,744)(Gain) loss on investment in equity securities and from sale of properties (45,578) (51,802) 86,628Non-cash loss in derivative fair value 54,512 — — Minority interest in net income (loss) of consolidated subsidiaries 59 (103) — Other non-cash items 3,015 827 2,540Changes in operating assets and liabilities (a) 33,830 1,522 (124,322)

Cash Provided (Used) by Operating Activities 377,421 133,301 (53,876)

INVESTING ACTIVITIES

Proceeds from sale of Hugoton Royalty Trust units — 148,570 —Proceeds from sale of other property and equipment 77,119 110,500 2,494Property acquisitions (45,648) (270,226) (296,390)Purchase of Spring Holding Company — (42,540) —Development costs (154,382) (90,725) (69,356)Gas gathering and other additions (11,033) (10,479) (7,517)(Loans to) repayments from officers 60 (1,470) (5,795)

Cash Used by Investing Activities (133,884) (156,370) (376,564)

FINANCING ACTIVITIES

Proceeds from short- and long-term debt 523,400 256,400 877,900Payments on short- and long-term debt (745,500) (339,262) (496,938)Purchase of minority interest (100,071) (42,385) — Contributions from minority interests — 142,500 — Common stock offering 126,125 29,668 133,113Dividends (3,891) (4,950) (8,460)Purchases of treasury stock and other (41,896) (25,501) (66,658)

Cash Provided (Used) by Financing Activities (241,833) 16,470 438,957

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 1,704 (6,599) 8,517Cash and Cash Equivalents, January 1 5,734 12,333 3,816

Cash and Cash Equivalents, December 31 $ 7,438 $ 5,734 $ 12,333

(a) Changes in Operating Assets and LiabilitiesAccounts receivable $ (90,921) $ (8,227) $ (7,022)Investment in equity securities 43,746 20,180 (131,809)Other current assets (4,535) (32) (1,513)Other assets (15,535) — —Current liabilities 82,392 (11,628) 16,022Other long-term liabilities 18,683 1,229 —

Decrease (Increase) in Operating Assets and Liabilities $ 33,830 $ 1,522 $(124,322)

See accompanying notes to consolidated financial statements.

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C O N S O L I D A T E D S T A T E M E N T S O F S T O C K H O L D E R S ’ E Q U I T Y

Additional RetainedPreferred Common Paid-in Treasury Earnings

(in thousands, except per share amounts) Stock Stock Capital Stock (Deficit) Total

Balances, December 31, 1997 $28,468 $695 $210,722 $ (76,656) $ 7,014 $170,243Sale of common stock — 108 133,005 — — 133,113Issuance/vesting of performance shares — 1 1,804 (536) — 1,269Stock option exercises — 7 2,984 (483) — 2,508Treasury stock purchases — — — (65,575) — (65,575)Treasury stock issued — — 13,741 24,695 — 38,436Common stock dividends ($0.11 per share) — — — — (7,022) (7,022)Preferred stock dividends ($1.56 per share) — — — — (1,779) (1,779)Net loss — — — — (69,719) (69,719)

Balances, December 31, 1998 28,468 811 362,256 (118,555) (71,506) 201,474Issuance/sale of common stock — 60 45,640 — — 45,700Issuance/vesting of performance shares — 2 231 — — 233Stock option exercises — — 95 (755) — (660)Treasury stock purchases — — — (25,517) — (25,517)Treasury stock issued — — (11,945) 25,440 — 13,495Common stock dividends ($0.03 per share) — — — — (1,872) (1,872)Preferred stock dividends ($1.56 per share) — — — — (1,779) (1,779)Net income — — — — 46,743 46,743

Balances, December 31, 1999 28,468 873 396,277 (119,387) (28,414) 277,817Sale of common stock from treasury — — 61,427 64,698 — 126,125Issuance/vesting of performance shares — 8 18,244 (6,976) — 11,276Stock option exercises — 32 29,976 (4,933) — 25,075Treasury stock purchases — — — (55,758) — (55,758)Cancellation of shares — (89) (71,438) 71,527 — —Common stock dividends ($0.03 per share) — — — — (2,403) (2,403)Preferred stock converted to common (1,251) 2 1,249 — — —Preferred stock dividends ($1.56 per share) — — — — (1,758) (1,758)Net income — — — — 116,993 116,993

Balances, December 31, 2000 $27,217 $826 $435,735 $ (50,829) $ 84,418 $497,367

See accompanying notes to consolidated financial statements.

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1. Organization and Summary of Significant Accounting Policies

Cross Timbers Oil Company, a Delaware corporation, wasorganized in October 1990 to ultimately acquire the business andproperties of predecessor entities that were created from 1986through 1989. Cross Timbers Oil Company completed its initialpublic offering of common stock in May 1993.

The accompanying consolidated financial statements includethe financial statements of Cross Timbers Oil Company and itswholly owned subsidiaries (“the Company”). All significantintercompany balances and transactions have been eliminated in theconsolidation. In preparing the accompanying financial statements,management has made certain estimates and assumptions that affectreported amounts in the financial statements and disclosures ofcontingencies. Actual results may differ from those estimates.Certain amounts presented in prior period financial statements havebeen reclassified for consistency with current period presentation.

All common stock shares and per share amounts in theaccompanying financial statements have been adjusted for the three-for-two stock splits effected on February 25, 1998 andSeptember 18, 2000.

The Company is an independent oil and gas company withproduction and exploration concentrated in Texas, Oklahoma,Arkansas, Kansas, New Mexico, Wyoming, Alaska and Louisiana.The Company also gathers, processes and markets gas, transportsand markets oil and conducts other activities directly related to itsoil and gas producing activities.

Comprehensive Income

During the years ended December 31, 2000, 1999 and 1998,there were no reportable elements of comprehensive income otherthan net income.

Property and Equipment

The Company follows the successful efforts method ofaccounting, capitalizing costs of successful exploratory wells andexpensing costs of unsuccessful exploratory wells. Exploratorygeological and geophysical costs are expensed as incurred. All developmental costs are capitalized. The Company generallypursues acquisition and development of proved reserves as opposedto exploration activities. Most of the property costs reflected in theaccompanying consolidated balance sheets are from acquisitions ofproducing properties from other oil and gas companies. Producingproperties balances include costs of $66,823,000 at December 31,2000 and $27,937,000 at December 31, 1999, related to wells inprocess of drilling.

Depreciation, depletion and amortization of producingproperties is computed on the unit-of-production method based onestimated proved oil and gas reserves. Other property andequipment is generally depreciated using the straight-line methodover estimated useful lives which range from 3 to 40 years. Repairsand maintenance are expensed, while renewals and betterments aregenerally capitalized. The estimated undiscounted cost, net ofsalvage value, of dismantling and removing major oil and gasproduction facilities, including necessary site restoration, are accruedusing the unit-of-production method.

If conditions indicate that long-term assets may be impaired,the carrying value of property and equipment is compared to

management’s future estimated pretax cash flow. If impairment isnecessary, the asset carrying value is adjusted to fair value. Cashflow pricing estimates are based on existing proved reserve andproduction information and pricing assumptions that managementbelieves are reasonable. Impairment of individually significantundeveloped properties is assessed on a property-by-property basis,and impairment of other undeveloped properties is assessed andamortized on an aggregate basis. The Company recorded animpairment provision on producing properties of $2,040,000 beforeincome tax in 1998.

Royalty Trusts

The Company created Cross Timbers Royalty Trust inFebruary 1991 and Hugoton Royalty Trust in December 1998 byconveying defined net profits interests in certain of the Company’sproperties. Units of both trusts are traded on the New York StockExchange. The Company makes monthly net profits payments toeach trust based on revenues and costs from the related underlyingproperties. The Company owns 22.7% of Cross Timbers RoyaltyTrust units that it purchased on the open market in 1996 and 1997,and owns 54.3% of the Hugoton Royalty Trust following the sale ofunits in 1999 and 2000. The cost of the Company’s interest in thetrusts is included in producing properties. Amounts due the trusts,net of amounts retained by the Company’s ownership of trust units,are deducted from the Company’s revenues, taxes, productionexpenses and development costs. As of January 1, 1999, theCompany no longer records the trusts’ portion of development costsas an expense in the consolidated income statement.

Cash and Cash Equivalents

Cash equivalents are considered to be all highly liquidinvestments having an original maturity of three months or less.

Investment in Equity Securities

In accordance with Statement of Financial AccountingStandards (“SFAS”) No. 115, Accounting for Certain Investments in Debtand Equity Securities, equity securities were recorded as tradingsecurities since they were acquired principally for resale in the nearfuture. Accordingly, this investment at December 31, 1999 isrecorded as a current asset at market value, unrealized holding gainsand losses are recognized in the consolidated income statements, andcash flows from purchases and sales of equity securities are includedin cash provided (used) by operating activities in the consolidatedstatements of cash flows. Gains (losses) on trading securities andinterest expense related to the cost of these investments are classifiedas other income (expense) in the consolidated income statements.See Note 2.

Other Assets

Other assets primarily include deferred debt costs that areamortized over the term of the related debt (Note 4) and the long-term portion of gas balancing receivable (see “Revenue Recognition”below). Other assets are presented net of accumulated amortizationof $11,574,000 at December 31, 2000 and $7,252,000 at December 31, 1999.

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N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S (continued)

D e r i v a t i v e s

The Company uses derivatives to hedge product price andinterest rate risks, as opposed to their use for trading purposes.Gains and losses on commodity futures contracts are recognized inoil and gas revenues when the hedged transaction occurs. Amountsreceivable or payable under interest swap agreements are recorded as adjustments to interest expense. Cash flows related to derivativetransactions are included in operating activities. See Note 7.

In conjunction with its hedging activities, the Companyoccasionally enters natural gas call options. Because options do not provide protection against declining prices, they do not qualifyfor hedge or loss deferral accounting. The opportunity loss, related to gas prices exceeding the fixed gas prices effectivelyprovided by the call options, is recognized as a derivative fair valueloss, rather than deferring the loss and recognizing it as reduced gas revenue when the hedged production occurs, as prescribed byhedge accounting.

Effective January 1, 2001, the Company adopted SFAS No.133, Accounting for Derivative Instruments and Hedging Activities, asamended by SFAS Nos. 137 and 138 (Note 7). SFAS No. 133requires the Company to record all derivatives on the balance sheetat fair value. Change in the fair value of derivatives that are notdesignated as hedges, as well as the ineffective portion of hedgederivatives, must be recognized as a derivative fair value gain or lossin the income statement. Changes in the fair value of effective cashflow hedges are recorded as a component of other comprehensiveincome, which is later transferred to earnings when the hedgedtransaction occurs. Physical delivery contracts which cannot be netcash settled are deemed to be normal sales and therefore are notaccounted for as derivatives. However, physical delivery contractsthat have a price not clearly and closely associated with the asset soldare not a normal sale and must be accounted for as a non-hedgederivative (Note 8).

Revenue Recognition

The Company uses the entitlement method of accounting forgas sales, based on the Company’s net revenue interest inproduction. Accordingly, revenue is deferred when gas deliveriesexceed the Company’s net revenue interest, while revenue is accruedfor under-deliveries. Production imbalances are generally recordedat the estimated sales price in effect at the time of production. At December 31, 2000, the Company’s consolidated balance sheetincludes a net current asset of $2.5 million for a net underproducedbalancing position of 911,000 Mcf of natural gas, and a net long-term liability of $3.7 million for an overproduced balancing positionof 3,581,000 Mcf of natural gas, net of an underproduced balancingposition of 10,062,000 Mcf of carbon dioxide.

Gas Gathering, Processing and Marketing Revenues

Gas produced by the Company and third parties is marketed by the Company to brokers, local distribution companies and end-users. Gas gathering and marketing revenues are recognized in themonth of delivery based on customer nominations. Gas processingand marketing revenues are recorded net of cost of gas sold of $144.3 million for 2000, $66.2 million for 1999 and $56.3 millionfor 1998. These amounts are net of intercompany eliminations.

Other Revenues

Other revenues include gains and losses from sale of propertyand equipment. Excluding the gain on sale of significant propertydivestitures, including the sale of Hugoton Royalty Trust units(Note 13), the Company realized gains on sale of property andequipment of $920,000 in 2000, $6,390,000 in 1999 and $795,000in 1998.

Interest Expense

Interest expense includes amortization of deferred debt costsand is presented net of interest income of $1,430,000 in 2000,$619,000 in 1999 and $91,000 in 1998, and net of capitalizedinterest of $3,488,000 in 2000, $1,353,000 in 1999 and$1,070,000 in 1998. Interest expense related to investment inequity securities has been classified as a component of gain (loss) on investment in equity securities (Note 2).

Stock-Based Compensation

In accordance with Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, no compensation isrecorded for stock options or other stock-based awards that aregranted to employees or non-employee directors with an exerciseprice equal to or above the common stock price on the grant date.Compensation related to performance share grants is recognizedfrom the grant date until the performance conditions are satisfied.The pro forma effect of recording stock-based compensation at theestimated fair value of awards on the grant date, as prescribed bySFAS No. 123, Accounting for Stock-Based Compensation, is disclosed inNote 12.

Earnings per Common Share

In accordance with SFAS No. 128, Earnings Per Share, theCompany reports basic earnings per share, which excludes the effectof potentially dilutive securities, and diluted earnings per share,which includes the effect of all potentially dilutive securities unlesstheir impact is antidilutive. See Note 10.

Segment Reporting

In accordance with SFAS No. 131, Disclosures about Segments ofan Enterprise and Related Information, the Company has identified only one operating segment, which is the exploration andproduction of oil and gas. All the Company’s assets are located inthe United States and all its revenues are attributable to UnitedStates customers.

There were no sales to a single purchaser that exceeded 10% oftotal revenues in 2000, 1999 or 1998.

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Cr o s s T im b e r s O i l C o m p an y

34

(continued)

2. Investment in Equity Securities

In 1998, the Company purchased what it believed to beundervalued oil and gas reserves through investments in publiclytraded equity securities of select energy companies. After selling aportion of these securities in 1998 and 1999, the Company sold itsremaining investment in equity securities in 2000 for $43.7 million,resulting in a gain of $13.3 million.

The following are components of gain (loss) on investment inequity securities:

(in thousands) 2 0 0 0 1 9 9 9 1 9 9 8

Realized gains (losses) on sale of securities:G a i n s $ 4,683 $ 823 $ 8 8 7L o s s e s ( 3 5 , 5 2 3 ) ( 2 3 , 0 4 7 ) (15,706)

Net gains (losses) ( 3 0 , 8 4 0 ) ( 2 2 , 2 2 4 ) ( 1 4 , 8 1 9 )

Changes in unrealized gains (losses) 4 5 , 5 3 5 2 7 , 0 7 0 (72,605)

Interest expense related to investment inequity securities ( 1 , 4 1 6 ) ( 5 , 9 9 5 ) ( 6 , 2 9 5 )

Gains (losses) on investment in equity securities $ 13,279 $ (1,149) $ ( 9 3 , 7 1 9 )

3. Related Party Transactions

Loans to Officers

Pursuant to margin support agreements with each of sixofficers, the Company, with Board of Director authorization, agreedto use up to $15 million of the value of Cross Timbers Royalty Trustunits owned by the Company and investment in equity securities, to provide margin support for the officers’ broker accounts in whichthey held Company common stock. The Company also agreed topay each officer’s margin debt to the extent unpaid by the officer. In connection with these agreements, in December 1998 theCompany loaned four officers a total of $5,795,000 to reduce theirmargin debt. An additional $1,530,000 was loaned during 1999,including a new loan to a fifth officer. The loans are full recourseand due in December 2003, with an interest rate equal to theCompany’s bank debt rate. At each balance sheet date, the loansare reviewed to determine whether a reserve for collectibility shouldbe booked as compensation expense. To date, no reserve forcollectibility has been recorded. As of March 2001, officer margindebt balances related to Company common stock were fully repaid,and the margin support agreements were terminated because theywere no longer needed.

Other Transactions

A company, partially owned by a director of the Company,performs consulting services in connection with the Company’sacquisition and divestiture programs, for which it received feestotaling $994,000 in 2000. The director-related company alsorepresented the purchaser of properties sold by the Company during1999 and invested in the purchase.

The same director-related company performed consultingservices in 1998 in connection with the Cook Inlet Acquisition.After the Company recovers its acquisition costs, including interestand subsequent property development and operating costs, thedirector-related company will receive, at its election, either a 20%working interest or a 1% overriding royalty interest conveyed fromthe Company’s 100% working interest in these properties.

4. Debt

The Company’s outstanding debt consists of the following:

December 31

(in thousands) 2000 1 9 9 9

Long-term Debt:

Senior debt –Bank debt under revolving credit agreements

due May 12, 2005, 8.3% at December 31, 2000 $ 4 6 9 , 0 0 0 $ 4 3 9 , 0 0 0

Subordinated debt –91⁄4% senior subordinated notes due April 1, 2007 1 2 5 , 0 0 0 1 2 5 , 0 0 083⁄4% senior subordinated notes due November 1, 2009 1 7 5 , 0 0 0 1 7 5 , 0 0 0

Spring Holding Company –Senior bank debt, 8.5% — 1 1 6 , 1 0 0Senior subordinated debt, 12.9% — 7 , 0 0 0

Summer Acquisition Company –Senior bank debt, 8.5% — 1 2 9 , 0 0 0

Total long-term debt $ 7 6 9 , 0 0 0 $ 9 9 1 , 1 0 0

Senior Debt

In May 2000, the Company entered a new revolving creditagreement with commercial banks with a commitment of $800million. Proceeds of this loan agreement were used to refinance theCompany’s previous senior credit facility and to fully repay a $25million term loan and the separate bank debt of the Company’ssubsidiaries, Spring Holding Company and Summer AcquisitionCompany. In June 2000, the loan agreement was amended to allowthe Company to issue letters of credit. Any letters of creditoutstanding reduce the borrowing capacity under the revolvingcredit facility. As of December 31, 2000, letters of creditoutstanding totaled $33 million. Borrowings at December 31, 2000under the loan agreement were $469 million with unused borrowingcapacity of $298 million. The borrowing base is redeterminedannually based on the value and expected cash flow of theCompany’s proved oil and gas reserves. If borrowings exceed theredetermined borrowing base, the banks may require that the excessbe repaid within a year. Based on reserve values at December 31,2000 and parameters specified by the banks, the borrowing basesupports borrowings in excess of the $800 million commitment.Borrowings under the loan agreement are due May 12, 2005, but may be prepaid at any time without penalty. The Companyperiodically renegotiates the loan agreement to increase theborrowing commitment and extend the revolving facility. In February 2001, the loan agreement was amended to allow therepurchase of the Company’s subordinated debt and to increasecommodity hedging limits.

On January 3, 2001, the Company purchased primarily gas-producing properties in East Texas and Louisiana for $115 million,of which $11.6 million had been paid in 2000. This acquisition was funded through borrowings under the loan agreement.

The credit facility is secured by the Company’s producingproperties. Restrictions set forth in the loan agreement includelimitations on the incurrence of additional indebtedness, the creationof certain liens, and the redemption or prepayment of subordinatedindebtedness. The loan agreement also limits dividends to 25% ofcash flow from operations, as defined, for the latest four consecutivequarterly periods. The Company is also required to maintain a

N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S

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N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S (continued)

current ratio of not less than one (where unused borrowingcommitments are included as a current asset).

The loan agreement provides the option of borrowing atfloating interest rates based on the prime rate or at fixed rates forperiods of up to six months based on certificate of deposit rates orLondon Interbank Offered Rates (“LIBOR”). Borrowings under theloan agreement at December 31, 2000 were based on LIBOR rateswith maturity of one to six months and accrued at the applicableLIBOR rate plus 11⁄2%. Interest is paid at maturity, or quarterly ifthe term is for a period of 90 days or more. The Company alsoincurs a commitment fee on unused borrowing commitments whichwas 0.35% at December 31, 2000. The weighted average interestrate on senior debt was 8.2% during 2000, 6.7% during 1999 and6.9% during 1998.

Subordinated Debt

The Company sold $125 million of 91⁄4% senior subordinatednotes on April 2, 1997, and $175 million of 83⁄4% seniorsubordinated notes on October 28, 1997. The notes are generalunsecured indebtedness that is subordinate to bank borrowingsunder the loan agreement. Net proceeds of $121.1 million from the91⁄4% notes and $169.9 million from the 83⁄4% notes were used to reduce bank borrowings under the loan agreement. The 91⁄4%notes mature on April 1, 2007 and interest is payable each April 1and October 1, while the 83⁄4% notes mature on November 1, 2009with interest payable each May 1 and November 1.

The Company has the option to redeem the 91⁄4% notes onApril 1, 2002 and the 83⁄4% notes on November 1, 2002 at a price of approximately 105%, and thereafter at prices declining ratably at each anniversary to 100% in 2005. Upon a change in control of the Company, the noteholders have the right to require theCompany to purchase all or a portion of their notes at 101% plusaccrued interest.

The notes were issued under indentures that place certainrestrictions on the Company, including limitations on additionalindebtedness, liens, dividend payments, treasury stock purchases,disposition of proceeds from asset sales, transfers of assets andtransactions with subsidiaries and affiliates.

See Note 7 regarding interest rate swap agreements.

5. Income Tax

The effective income tax rate for the Company was differentthan the statutory federal income tax rate for the following reasons:

(in thousands) 2 0 0 0 1 9 9 9 1 9 9 8

Income tax expense (benefit) at thefederal statutory rate of 34% $ 5 9 , 9 8 7 $ 2 4 , 0 0 6 $ ( 3 5 , 8 9 3 )

State and local taxes and other ( 6 0 7 ) ( 4 1 ) 4 2

Income tax expense (benefit) $ 5 9 , 3 8 0 $ 2 3 , 9 6 5 $ ( 3 5 , 8 5 1 )

Components of income tax expense (benefit) are as follows:

(in thousands) 2 0 0 0 1 9 9 9 1 9 9 8

Current income tax $ 3 8 7 $ 3 0 8 $ ( 1 0 7 )Deferred income tax expense (benefit) 6 3 , 7 9 2 2 8 , 6 9 7 ( 2 , 6 2 6 )Net operating loss carryforward ( 4 , 7 9 9) ( 5 , 0 4 0 ) ( 3 3 , 1 1 8 )

Income tax expense (benefit) $ 5 9 , 3 8 0 $ 2 3 , 9 6 5 $ ( 3 5 , 8 5 1 )

Deferred tax assets and liabilities are the result of temporarydifferences between the financial statement carrying values and taxbases of assets and liabilities. The Company’s net deferred taxliabilities are recorded as a current asset of $17,098,000 and a long-term liability of $82,476,000 at December 31, 2000, and a currentasset of $4,168,000 and a long-term liability of $25,975,000 atDecember 31, 1999. Significant components of net deferred taxassets and liabilities are:

December 31

(in thousands) 2 0 0 0 1 9 9 9

Deferred tax assets:Net operating loss carryforwards $ 6 9 , 3 7 0 $ 6 4 , 1 1 8Accrued stock appreciation right and

performance share compensation 9 1 6 9 8 5Unrealized loss on trading securities — 6 , 1 0 3Derivative fair value loss 1 5 , 0 2 4 —O t h e r 5 , 0 3 8 2 , 8 9 1

Total deferred tax assets 9 0 , 3 4 8 7 4 , 0 9 7

Deferred tax liabilities:Property and equipment 1 4 8 , 3 6 3 9 2 , 1 1 5O t h e r 7 , 3 6 3 3 , 7 8 9

Total deferred tax liabilities 1 5 5 , 7 2 6 9 5 , 9 0 4

Net deferred tax assets (liabilities) $ ( 6 5 , 3 7 8 ) $ ( 2 1 , 8 0 7 )

As of December 31, 2000, the Company has estimated tax losscarryforwards of approximately $210 million, of which $11 millionare related to capital losses. The capital loss tax carryforwards expirein 2005 while the remaining $199 million are scheduled to expire in2008 through 2020. Approximately $21.7 million of the tax losscarryforwards are the result of the Spring Acquisition. TheCompany has not booked any valuation allowance because it believesit has tax planning strategies available to realize its tax lossc a r r y f o r w a r d s .

6. Commitments and Contingencies

L e a s e s

The Company leases offices, vehicles and certain otherequipment in its primary locations under noncancelable operatingleases. As of December 31, 2000, minimum future lease paymentsfor all noncancelable lease agreements (including the sale andoperating leaseback agreements described below) were as follows:

(in thousands)

2 0 0 1 $ 1 2 , 1 4 72 0 0 2 1 1 , 9 3 72 0 0 3 1 1 , 6 0 42 0 0 4 7 , 0 0 52 0 0 5 5 , 0 5 1R e m a i n i n g 2 1 , 3 5 7

T o t a l $ 6 9 , 1 0 1

Amounts incurred by the Company under operating leases(including renewable monthly leases) were $17,329,000 in 2000,$14,093,000 in 1999 and $11,180,000 in 1998.

In March 1996, the Company sold its Tyrone gas processingplant and related gathering system for $28 million and entered anagreement to lease the facility from the buyers for an initial term ofeight years at annual rentals of $4 million, and with fixed renewaloptions for an additional 13 years. This transaction was recorded asa sale and operating leaseback, with no gain or loss on the sale.

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(continued)

In November 1996, the Company sold its gathering system inMajor County, Oklahoma for $8 million and entered an agreementto lease the facility from the buyers for an initial term of eight years,with fixed renewal options for an additional 10 years. Rentals are adjusted monthly based on the 30-day LIBOR rate and may beirrevocably fixed by the Company with 20 days advance notice. As of December 31, 2000, annual rentals were $1.7 million. This transaction was recorded as a sale and operating leaseback, witha deferred gain of $3.4 million on the sale. The deferred gain isamortized over the lease term based on pro rata rentals and isrecorded in other long-term liabilities in the accompanying con-solidated balance sheets. The deferred gain balance at December 31,2000 was $2 million.

Under each of the above sale and leaseback transactions, theCompany does not have the right or option to purchase, nor does thelessor have the obligation to sell the facility at any time. However, if the lessor decides to sell the facility at the end of the initial termor any renewal period, the lessor must first offer to sell it to theCompany at its fair market value. Additionally, the Company has aright of first refusal of any third party offers to buy the facility afterthe initial term.

Letters of Credit

The Company issued letters of credit totaling $33 million tocounterparties and purchasers under certain hedge derivatives andphysical delivery contracts (Note 8).

Employment Agreements

Two executive officers have year-to-year employmentagreements with the Company. The agreements are automaticallyrenewed each year-end unless terminated by either party upon thirtydays notice prior to each December 31. Under these agreements, theofficers receive a minimum annual salary of $625,000 and $450,000,respectively, and are entitled to participate in any incentivecompensation programs administered by the Board of Directors.The agreements also provide that, in the event the officer terminateshis employment for good reason, as defined in the agreement, theCompany terminates the employee without cause or a change incontrol of the Company occurs, the officer is entitled to a lump-sumpayment of three times the officer’s most recent annualc o m p e n s a t i o n .

Commodity Commitments

The Company has entered into natural gas physical deliverycontracts, futures contracts and swap agreements that effectively fixprices, and natural gas call options that provide ceiling prices. See Note 8.

L i t i g a t i o n

On April 3, 1998, a class action lawsuit, styled Booth, et al. v.Cross Timbers Oil Company, was filed against the Company in theDistrict Court of Dewey County, Oklahoma. The action was filedon behalf of all persons who, at any time since June 1991, have beenpaid royalties on gas produced from any gas well within the State ofOklahoma under which the Company has assumed the obligation topay royalties. The plaintiffs allege that the Company has reducedroyalty payments by post-production deductions and has enteredinto contracts with subsidiaries that were not arm’s-length

transactions. The plaintiffs further allege that these actions reducedthe royalties paid to the plaintiffs and those similarly situated, andthat such actions are a breach of the leases under which the royaltiesare paid. These deductions allegedly include production and post-production costs, marketing costs, administration costs and costsincurred 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 propor-tionately borne by the plaintiffs, these fees are established by arm’s-length negotiations with third parties or, if charged by affiliates, arecomparable to fees charged by third party gatherers or processors.The Company further contends that any such fees enhance the valueof the gas or the products derived from the gas. The plaintiffs areseeking an accounting and payment of the monies allegedly owed tothem. A hearing on the class certification issue has not beenscheduled. Management believes it has strong defenses against thisclaim and intends to vigorously defend the action. Management’sestimate 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 Americaex rel. Grynberg v. Cross Timbers Oil Company, et al., was filed in the U. S. District Court for the Western District of Oklahoma againstthe Company and certain of its subsidiaries by Jack J. Grynberg onbehalf of the United States under the qui tam provisions of the FalseClaims Act. The plaintiff alleges that the Company underpaidroyalties on gas produced from federal leases and lands owned byNative Americans by at least 20% during the past 10 years as aresult of mismeasuring the volume of gas and incorrectly analyzingits heating content. The plaintiff has made similar allegations inover 70 actions filed against more than 300 other companies. Theplaintiff seeks to recover the amount of royalties not paid, togetherwith treble damages, a civil penalty of $5,000 to $10,000 for eachviolation and attorney fees and expenses. The plaintiff also seeks anorder for the Company to cease the allegedly improper measuringpractices. After its review, the Department of Justice decided inApril 1999 not to intervene and asked the court to unseal the case.The court unsealed the case in May 1999. A multi-districtlitigation panel ordered that the lawsuits against the Company andother companies filed by Grynberg be transferred and consolidatedto the federal district court in Wyoming. The Company and otherdefendants filed a motion to dismiss which has been heard by theCourt and a decision is pending. The Company believes that theallegations of this lawsuit are without merit and intends tovigorously defend the action. Any potential liability from this claimis not currently determinable and no provision has been accrued inthe Company’s financial statements.

A third lawsuit, Bishop, et al. v. Amoco Production Co., et al., wasfiled in May 2000 in the Third Judicial District Court in LincolnCounty, Wyoming by owners of royalty and overriding royaltyinterests in wells located in Wyoming. The plaintiffs alleged thatthe Company and the other producer defendants deductedimpermissible costs of production from royalty payments that weremade to the plaintiffs and other similarly situated persons and failedto properly inform the plaintiffs and others of the deductions takenas allegedly required by Wyoming statutes. The action was broughtas a class action on behalf of all persons who own an interest in wellslocated in Wyoming as to which the defendants pay royalties andoverriding royalties. The plaintiffs sought a declaratory judgment

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that the deductions made were impermissible and sought damagesin the amount of the deductions made, together with interest andattorneys’ fees. The Company has reached a settlement of thisaction, which is subject to court approval. The Company has agreedto pay a total settlement amount of $572,000 for a release of claimsrelating to deductions taken by the Company, the statutoryreporting of claims, and other miscellaneous matters. The Companyfurther agreed that it would not take similar deductions from royaltyowners in the future and to itemize other deductions from futureroyalty disbursements. The Company expects that the court willapprove the settlement in April 2001. This settlement was accruedin the Company’s financial statements.

In February 2000, the Department of Interior notified theCompany and several other producers that certain Native Americanleases located in the San Juan Basin have expired due to the failure of the leases to produce in paying quantities. The Department ofInterior has demanded abandonment of the property as well aspayment of the gross proceeds from the wells minus royalties paidfrom the date of the alleged cessation of production to present. The Company has filed a Notice of Appeal with the Interior Boardof Indian Appeals. The potential loss from these claims is currentlynot determinable, but could be material to the Company’s annualearnings. The Company believes that the claim is without merit andthat there is currently not a probable loss. No related provision isaccrued in the Company’s financial statements.

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

O t h e r

To date, the Company’s expenditures to comply withenvironmental or safety regulations have not been significant and arenot expected to be significant in the future. However, developmentssuch as new regulations, enforcement policies or claims for damagescould result in significant future costs.

See also Note 3.

7. Financial Instruments

The Company uses financial and commodity-based derivativecontracts to manage exposures to commodity price and interest ratefluctuations. The Company does not hold or issue derivativefinancial instruments for speculative or trading purposes.

Commodity Price Hedging Instruments

The Company periodically enters into futures contracts, energyswaps, collars and basis swaps to hedge its exposure to pricefluctuations on crude oil and natural gas sales. When actualcommodity prices exceed the fixed price provided by these contracts,the Company pays this excess to the counterparty and records anopportunity loss in the period related production occurs. Whenactual commodity prices are below the contractually provided fixedprice, the Company receives this difference and records a gain in the

production period. These gains and losses are recorded as acomponent of oil and gas revenues. See Note 8.

In 2000, the Company recognized net losses on futurescontracts and basis swap transactions of $40.5 million related to gashedging and $7.8 million related to oil hedging. During 1999, theCompany recognized net losses on futures contracts and basis swaptransactions of $5.7 million related to gas hedging and $2.2 millionrelated to oil hedging. During 1998, the Company recognized netgains of $7.7 million related to gas hedging.

The Company occasionally sells gas call options. Because theseoptions are covered by Company production and the strike prices arebelow current market gas prices, they have the same effect on theCompany as product hedges. However, because written options donot provide protection against declining prices, they do not qualifyfor hedge or loss deferral accounting. The opportunity loss, relatedto gas prices exceeding the fixed gas prices effectively provided bythe call options, has been recognized as a loss in derivative fair value,rather than deferring the loss and recognizing it as reduced gasrevenue when the hedged production occurs. For the year endedDecember 31, 2000, a derivative fair value loss of $55.8 million was recorded in the consolidated income statements, of which $1.3 million was cash settled.

Interest Rate Swap Agreements

In September 1998, to reduce variable interest rate exposure ondebt, the Company entered into a series of interest rate swapagreements, effectively fixing its interest rate at an average of 6.9%on a total notional balance of $150 million until September 2005.In 1999 and 2000, the Company terminated these interest rateswaps, resulting in total proceeds received and a gain of $2 million.This gain has been deferred and is being amortized against interestexpense through September 2005.

To reduce the interest rate on a portion of its subordinateddebt, the Company entered an agreement with a bank that haspurchased on the market the Company’s subordinated notes with aface value of $21.6 million. The Company pays the bank a variableinterest rate based on three-month LIBOR rates, and receivessemiannually from the bank the fixed interest rate on the notes. The term of the agreement for approximately half the notes isthrough April 2002, and for the remaining half is throughNovember 2002. Any depreciation in market value of the notesfrom the date purchased by the bank is immediately payable to thebank. Any appreciation in the market value, including anydepreciation payments, is receivable from the bank to the extent ofthe market value of the notes at the end of the agreement. The Company has the option of terminating this agreement andrepurchasing the notes from the bank at any time at market value.

Cr o s s T i m b e r s O i l C om pa n y

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(continued)N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S

deemed to be normal sales and therefore are not accounted for asderivatives. However, physical delivery contracts that have a pricenot clearly and closely associated with the asset sold are not a normalsale and must be accounted for as a non-hedge derivative (Note 8).

The Company accounted for adoption of SFAS No. 133 onJanuary 1, 2001 by recording a one-time after-tax charge of $44.6 million in the income statement for the cumulative effect of a change in accounting principle and an unrealized loss of $67.3 million in other comprehensive income. The charge to theincome statement is primarily related to the Company’s physicaldelivery contract to sell 35,500 Mcf of natural gas per day from2002 through July 2005 at crude oil-based prices. The unrealizedloss is related to the derivative fair value of cash flow hedges.Amounts recorded on the balance sheet at January 1, 2001 were a $103.6 million current liability, a $2.2 million long-termasset and a $70.8 million long-term liability related to the fair valueof derivatives and a current deferred tax asset of $36.3 million and areduction to the long-term tax liability of $24 million for the relatedtax benefits.

8. Natural Gas Sales Commitments

The Company has entered into natural gas futures contractsand swap agreements that effectively fix prices, and natural gas calloptions that provide ceiling prices, for the production and periodsshown below. The Company does not have any outstanding basisswap agreements as of March 2001. Prices to be realized for hedgedproduction may be less than these fixed prices because of location,quality and other adjustments.

Futures Contractsand Swap Agreements Call Options ( a )

Production Period Mcf per Day per Mcf Mcf per Day per Mcf

2 0 0 1 April to September 8 0 , 0 0 0 $2 . 7 9 5 3 , 3 3 3 $2.60 - 3.05

O c t o b e r 8 0 , 0 0 0 2 . 7 9 5 3 , 3 3 3 2.60 - 3.05

N o v e m b e r 8 0 , 0 0 0 2 . 8 6 2 0 , 0 0 0 2 . 9 5

D e c e m b e r 8 0 , 0 0 0 2 . 9 3 2 0 , 0 0 0 2 . 9 5

2 0 0 2 January to March 1 0 , 0 0 0 5 . 4 7 — —

( a ) Includes a natural gas call option to sell 20,000 Mcf per day in the San Juan Basinat an average ceiling index price of $2.70 per Mcf for the year 2001 which isexercisable in December 2001. Based on current San Juan Basin basis ofapproximately $0.30 per Mcf for April through October and $0.20 for Novemberand December, and including premium received of $0.05 per Mcf, this calloption is reflected above at a NYMEX prices of $3.05 and $2.95 per Mcf.

The Company’s settlement of futures contracts and swapagreements related to first quarter 2001 gas production resulted in anet loss of approximately $26 million. This loss will be recognizedas a decrease in gas revenue of approximately $0.78 per Mcf in thefirst quarter of 2001.

The Company has entered into physical delivery contractswhich cannot be net cash settled and are therefore considered to benormal sales. These contracts effectively fix prices for the followingproduction and periods:

Fixed PriceL o c a t i o n Production Period Mcf per Day per Mcf

East Texas April 2001 to March 2002 4 0 , 0 0 0 $5 . 4 2A r k o m a April to September 2001 9 0 , 0 0 0 5 . 5 5

October 2001 to March 2002 5 0 , 0 0 0 5 . 3 6San Juan Basin April to September 2001 2 5 , 0 0 0 5 . 1 4

October 2001 to March 2002 1 0 , 0 0 0 5 . 0 5Rocky Mountains April 2001 to March 2002 1 0 , 0 0 0 4 . 9 7M i d - C o n t i n e n t April to September 2001 4 5 , 0 0 0 5 . 4 5

October 2001 to March 2002 3 0 , 0 0 0 5 . 5 5

Fair Value

Because of their short-term maturity, the fair value of cash andcash equivalents, accounts receivable and accounts payableapproximates their carrying values at December 31, 2000 and 1999.The following are estimated fair values and carrying values of theCompany’s other financial instruments at each of these dates:

Asset (Liability)

December 31, 2000 December 31, 1999C a r r y i n g F a i r C a r r y i n g F a i r

(in thousands) A m o u n t V a l u e A m o u n t V a l u e

Investment in equity securities $ — $ — $ 2 9 , 0 5 2 $ 2 9 , 0 5 2Long-term debt ( 7 6 9 , 0 0 0 ) ( 7 7 4 , 0 0 0 ) ( 9 9 1 , 1 0 0 ) ( 9 8 1 , 5 4 0 )Futures contracts — ( 1 1 2 , 8 0 7 ) — ( 2 , 6 7 6 )Basis swap agreements — 3 , 8 6 8 — ( 1 , 1 1 3 )Call options ( 5 3 , 7 6 9 ) ( 5 3 , 7 6 9 ) ( 3 4 7 ) ( 3 4 7 )Interest rate swap agreements 4 7 3 2 , 6 5 1 2 1 8 2 , 5 0 3

The fair value of short-term borrowings and bank borrowingsapproximates the carrying value because of short-term interest ratematurities. The fair value of subordinated long-term debt is based on current market quotes. The fair value of futures contracts,swap agreements and call options is estimated based on currentcommodity prices and interest rates.

Concentrations of Credit Risk

Although the Company’s cash equivalents and derivativefinancial instruments are exposed to the risk of credit loss, theCompany does not believe such risk to be significant. Cashequivalents are high-grade, short-term securities, placed with highly rated financial institutions. Most of the Company’sreceivables are from a broad and diverse group of energy companiesand, accordingly, do not represent a significant credit risk. The Company’s gas marketing activities generate receivables fromcustomers including pipeline companies, local distributioncompanies and end-users in various industries. Letters of credit or other appropriate security are obtained as considered necessary to limit risk of loss. The Company recorded an allowance forcollectibility of all accounts receivable of $3,121,000 at December 31, 2000 and $2,150,000 at December 31, 1999. The Company’s bad debt provision was $1,093,000 in 2000,$1,347,000 in 1999 and $411,000 in 1998. Financial andcommodity-based swap contracts expose the Company to the creditrisk of non-performance by the counterparty to the contracts. The Company does not believe this risk is significant since theexposure is diversified among major banks and financial institutionswith high credit ratings.

New Derivative Accounting Principle

Effective January 1, 2001, the Company has adopted SFAS No.133, Accounting for Derivative Instruments and Hedging Activities, asamended by SFAS Nos. 137 and 138. SFAS No. 133 requires theCompany to record all derivatives on the balance sheet at fair value.Change in the fair value of derivatives that are not designated as hedges, as well as the ineffective portion of hedge derivatives,must be recognized as a derivative fair value gain or loss in theincome statement. Change in fair value of effective cash flow hedgesare recorded as a component of other comprehensive income, whichis later transferred to earnings when the hedged transaction occurs.Physical delivery contracts which cannot be net cash settled are

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C r o s s T im b e r s O i l C o m p an y

Other Physical Delivery Contracts

From August 1995 through July 1998 the Company receivedan additional $0.30 to $0.35 per Mcf on 10,000 Mcf of gas per day.In exchange therefor, the Company agreed to sell 11,650 Mcf perday from August 1998 through May 2000 at the index price and21,650 Mcf per day from June 2000 through July 2005 at a price of approximately 10% of the average NYMEX futures price forintermediate crude oil. After contract amendments in May andOctober 2000, the Company has agreed to sell 21,650 Mcf per dayat the index price through December 2000, 34,344 Mcf per day atthe index price in 2001 and 35,500 Mcf per day from 2002 throughJuly 2005 at a price of approximately 10% of the average NYMEXfutures price for intermediate crude oil. Because this gas salescontract is priced based on crude oil, which is not clearly and closelyassociated with natural gas prices, it must be accounted for as aderivative financial instrument under SFAS No. 133 beginningJanuary 1, 2001 (Note 7).

As partial consideration for an acquisition, the Company agreedto sell gas volumes ranging from 40,000 Mcf in 2000 to 35,000 Mcfin 2003 at specified discounts from index prices. This commitmentwas recorded at its total value of $7.5 million in March 1999 inother current and long-term liabilities. The discounts are charged tothe liability as taken. As of December 31, 2000, $1.6 million isrecorded in other current liabilities and $2.4 million is recorded inother long-term liabilities related to this commitment.

The Company has committed to sell all gas production fromcertain East Texas properties to EEX Corporation at market pricesthrough the earlier of December 31, 2001, or until a total ofapproximately 34.3 billion cubic feet (27.8 billion cubic feet net tothe Company’s interest) of gas has been delivered. Based on currentproduction, this sales commitment is approximately 24,700 Mcf(20,000 Mcf net to the Company’s interest) per day.

As a part of the Ocean Energy Acquisition, the Companyassumed a commitment to sell 6,800 Mcf of gas per day throughApril 2003 at prices which are adjusted by the monthly index price.In 2000, the prices ranged from $0.50 to $0.95 per Mcf. Delivery of the committed sales volumes is in Arkansas.

9. Equity

Three-for-Two Stock Splits

The Company effected three-for-two common stock splits on February 25, 1998 and September 18, 2000. All common stockshares, treasury stock shares and per share amounts have beenretroactively restated to reflect these stock splits.

Common Stock

The following reflects the Company’s common stock activity:

Shares Issued Year Ended December 31,

(in thousands) 2 0 0 0 1 9 9 9 1 9 9 8

Balance, beginning of year 8 7 , 2 8 3 8 1 , 0 7 2 6 9 , 4 6 6Issuance/sale of common stock — 6 , 0 0 0 1 0 , 8 0 5Issuance/vesting of performance shares 8 1 3 1 9 5 1 2 3Stock option exercises 3 , 1 9 5 1 6 6 7 8Cancellation of shares ( 8 , 8 6 6 ) — —Preferred stock converted to common 1 6 2 — —

Balance, end of year 8 2 , 5 8 7 8 7 , 2 8 3 8 1 , 0 7 2

Shares in Treasury Year Ended December 31,

(in thousands) 2 0 0 0 1 9 9 9 1 9 9 8

Balance, beginning of year 1 3 , 9 4 9 1 3 , 9 8 1 1 0 , 2 9 1Issuance/sale of common stock ( 6 , 6 0 0 ) ( 3 , 0 0 0 ) ( 2 , 8 8 3 )Issuance/vesting of performance shares 3 8 1 — 4 1Stock option exercises 2 7 6 7 7 3 7Treasury stock purchases 5 , 8 9 1 2 , 8 9 1 6 , 4 9 5Cancellation of shares ( 8 , 8 6 6 ) — —

Balance, end of year 5 , 0 3 1 1 3 , 9 4 9 1 3 , 9 8 1

In April 1998, the Company completed a public offering of11.3 million shares of common stock, of which 10.8 million shareswere sold by the Company and the remaining shares were sold by astockholder. The Company’s net proceeds from the offering of$133.1 million were used to partially repay bank debt used to fundthe East Texas Basin Acquisition. The offering was made pursuantto the shelf registration statement filed with the Securities andExchange Commission in February 1998. See “Shelf RegistrationStatement” below.

In September 1998, the Company issued from treasury 2.9 million shares to affiliates of Shell Oil Company for the CookInlet Acquisition. The Company effectively guaranteed Shell a$13.33 per share value. As of December 31, 1998, these shares were valued at $13.33 per share, or a total of $38.4 million. The $13.33 guarantee was effectively settled in July 1999 upon theCompany’s repurchase of these shares from Shell at $8.83 per share,or $25.5 million, and net additional payments to Shell of $13million which was charged to equity at that date.

In July 1999, the Company issued 6 million shares of commonstock at its fair value of $7.617 per share in exchange for its 50% interest in Spring Holding Company and for cash proceeds of $3.2 million which were used to reduce bank debt (Note 14).

Also in July 1999, the Company sold from treasury 3 millionshares of common stock in an underwritten public offering for netproceeds of approximately $26.5 million. The proceeds were used to repurchase the 2.9 million shares of common stock issued to Shell for the Cook Inlet Acquisition. The offering was madepursuant to the shelf registration statement.

In May 2000, in conjunction with the dissolution ofWhitewine Holding Company, the Company’s wholly ownedsubsidiary, 8.9 million shares were canceled from treasury stock.This transaction caused a $71.5 million reduction in treasury stock with an offsetting reduction in additional paid-in capital,resulting in no change to total stockholders’ equity.

In November 2000, the Company sold from treasury 6.6 million shares of common stock in an underwritten publicoffering for net proceeds of approximately $126.1 million. The proceeds were used to reduce outstanding indebtedness. The offering was made pursuant to the shelf registration statement.

Performance Shares

The Company issued performance shares totaling 820,000 in2000, 213,000 in 1999 and 123,000 in 1998 (Note 12). In October1999, 18,000 performance shares were forfeited from the sharesissued in 1998.

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Treasury Stock

The Company’s open market treasury share acquisitions totaled5.3 million shares in 2000 at an average price of $7.88, 7,500 sharesin 1999 at an average price of $7.04 and 6.5 million shares in 1998at an average price of $10.10 per share. Through March 26, 2001,4.3 million shares remain under the May 2000 Board of Directors’authorization to repurchase 4.5 million shares of the Company’scommon stock.

Stockholder Rights Plan

In August 1998, the Board of Directors adopted a stockholderrights plan that is designed to assure that all stockholders receive fair and equal treatment in the event of any proposed takeover of theCompany. Under this plan, a dividend of one preferred sharepurchase right was declared for each outstanding share of commonstock, par value $.01 per share, payable on September 15, 1998 tostockholders of record on that date. Each right entitles stockholdersto buy one one-thousandth of a share of newly created Series AJunior Participating Preferred Stock at an exercise price of $80,subject to adjustment in the event a person acquires or makes atender or exchange offer for 15% or more of the outstandingcommon stock. In such event, each right entitles the holder (otherthan the person acquiring 15% or more of the outstanding commonstock) to purchase shares of common stock with a market value oftwice the right’s exercise price. At any time prior to such event, the Board of Directors may redeem the rights at one cent per right.The rights can be transferred only with common stock and expire in ten years.

Shelf Registration Statement

In February 1998, the Company filed a shelf registrationstatement with the Commission to potentially offer securities whichcould include debt securities, preferred stock, common stock orwarrants to purchase debt securities, preferred stock or commonstock. The shelf registration statement was amended in April 1998to increase the maximum total price of securities to be offered to$400 million, at prices and on terms to be determined at the time ofsale. Net proceeds from the sale of such securities are to be used forgeneral corporate purposes, including reduction of bank debt. After the April 1998, July 1999 and November 2000 commonstock offerings, $99.4 million remains available under the shelfregistration statement for future sales of securities.

Common Stock Warrants

As partial consideration for producing properties acquired inDecember 1997, the Company issued warrants to purchase1,427,701 shares of common stock at a price of $10.05 per share fora period of five years. These warrants were valued at $5.7 millionand recorded as additional paid-in capital.

Common Stock Dividends

The Board of Directors declared quarterly dividends of $0.0267per common share in 1998, $0.0067 per common share from 1999through second quarter 2000 and $0.01 per common share for thethird and fourth quarters of 2000. See Note 4 regarding restrictionson dividends.

Series A Convertible Preferred Stock

Series A convertible preferred stock is recorded in theaccompanying consolidated balance sheets at its liquidationpreference of $25 per share. Cumulative dividends on preferredstock are payable quarterly in arrears, when declared by the Board of Directors, based on an annual rate of $1.5625 per share. The preferred stock has no stated maturity and no sinking fund, andis redeemable, in whole or in part, by the Company. The preferredstock is convertible at the option of the holder at any time, unlesspreviously redeemed, into shares of common stock at a rate of 3.24 shares of common stock for each share of preferred stock,subject to adjustment in certain events. During 2000, 50,000 sharesof convertible preferred stock were converted into 162,000 shares ofcommon stock. In January 2001, the Company sent notice topreferred stockholders that it would redeem all outstanding shareson February 16, 2001 at a price of $25.94 per share plus accrued andunpaid dividends. Prior to the redemption date, 1.1 millionoutstanding shares of preferred stock were converted into 3.5 millioncommon shares in 2001.

10. Earnings Per Share

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

E a r n i n g s(in thousands, except per share data) E a r n i n g s S h a r e s per Share

2 0 0 0B a s i c

Net income $ 1 1 6 , 9 9 3Preferred stock dividends ( 1 , 7 5 8 )

Earnings available to common stock – basic 1 1 5 , 2 3 5 7 1 , 1 5 4 $ 1.62

D i l u t e dEffect of dilutive securities

Stock options — 5 1 8Preferred stock 1 , 7 5 8 3 , 6 4 7W a r r a n t s — 3 8 7

Earnings available to common stock – diluted $ 1 1 6 , 9 9 3 7 5 , 7 0 6 $ 1 . 5 5

1 9 9 9B a s i c

Net income $ 4 6 , 7 4 3Preferred stock dividends ( 1 , 7 7 9 )

Earnings available to common stock – basic 4 4 , 9 6 4 7 0 , 2 2 8 $ 0 . 6 4

D i l u t e dEffect of dilutive securities

Stock options — 1 6 1Preferred stock 1 , 7 7 9 3 , 6 9 0W a r r a n t s — —

Earnings available to common stock – diluted $ 4 6 , 7 4 3 7 4 , 0 7 9 $ 0 . 6 3

1 9 9 8B a s i c

Net loss $ ( 6 9 , 7 1 9 )Preferred stock dividends ( 1 , 7 7 9 )

Loss available to common stock – basic ( 7 1 , 4 9 8 ) 6 5 , 0 9 4 $( 1 . 1 0 )

D i l u t e dEffect of dilutive securities:

Stock options — 5 0 7W a r r a n t s — 3 5

Loss available to common stock – diluted $ ( 7 1 , 4 9 8 ) 6 5 , 6 3 6 $( 1 . 1 0 ) ( a )

( a ) Because of the antidilutive effect of dilutive securities on loss per common share,diluted loss available to common stock is the same as basic.

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N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S (continued)

11. Supplemental Cash Flow Information

The consolidated statements of cash flows exclude thefollowing non-cash transactions (Notes 9, 12 and 13):

• Cancellation of 8.9 million shares of treasury stock in 2000 • Conversion of 50,000 shares of preferred stock to common stock

in 2000• Sale of Hugoton Royalty Trust units in 2000 in exchange for

495,000 shares of common stock valued at $11.3 million, andin 1999 in exchange for 74,000 shares of common stock valuedat $700,000

• Purchase of a 50% interest in Spring Holding Company in1999 in exchange for 5.6 million shares of common stock,valued at $42.5 million

• The Cook Inlet Acquisition in 1998, a purchase of oil-producing properties for 2.9 million shares of common stock, a related effective guarantee of $13.33 per share value and a $6 million note payable

• Performance shares activity, including:– Grants of 820,000 shares in 2000, 213,000 shares in 1999

and 123,000 shares in 1998 to key employees andnonemployee directors

– Vesting of 1,007,000 shares in 2000, 18,000 shares in1999 and 137,000 shares in 1998

– Forfeiture of 18,000 shares in 1999• Receipt of common stock of 44,000 shares (valued at $967,000)

in 2000 and 13,000 shares (valued at $181,000) in 1998 for theoption price of exercised stock options

Interest payments in 2000 totaled $80,067,000 (including$3,488,000 of capitalized interest), $70,500,000 in 1999 (including$1,353,000 of capitalized interest) and $57,200,000 in 1998(including $1,070,000 of capitalized interest). Income tax paymentswere $1,085,000 in 2000; net income tax refunds were $322,000during 1999 and $454,000 during 1998.

12. Employee Benefit Plans

401(k) Plan

The Company sponsors a 401(k) benefit plan that allowsemployees to contribute and defer a portion of their wages. The Company matches employee contributions of up to 10% ofwages (8% of wages prior to January 1, 1998). Employeecontributions vest immediately while the Company’s matchingcontributions vest 100% upon the earlier of three consecutive yearsof participation in the plan or five years of service. All employeesover 21 years of age may participate. Company contributions underthe plan were $3,226,000 in 2000, $2,514,000 in 1999 and$1,766,000 in 1998.

Post-Retirement Health Plan

Effective January 1, 2001, the Company adopted a retireemedical plan for employees who retire at age 55 or over with aminimum of five years full-time service. Benefits under the plan arethe same as for active employees, and continue until the retiredemployee or the employee’s dependents are eligible for Medicare oranother similar federal health insurance program. After Medicareeligibility, only prescription coverage is provided. Premiums areonly charged to dependents. Post-retirement medical benefits are

not pre-funded by the Company, but are paid when incurred. As of the plan’s inception, total prior service cost is estimated to be $804,000. For the year 2001, total expense is estimated to be $1.1 million which includes the total prior service cost, current yearservice cost and interest. The annual rate of increase in health carecosts were assumed to range from 9% in 2000 to 6% in 2006 andbeyond. An increase of 1% in the assumed health care cost trendrate would result in an increase in the total estimated service andinterest cost of $158,000 for 2001, and would increase the estimatedprior service cost at January 1, 2001 by $417,000. The weightedaverage discount rate used to determine the prior service cost andinterest was 7.75% at January 1, 2001.

1994 and 1997 Stock Incentive Plans

Under the 1994 Stock Incentive Plan and the 1997 StockIncentive Plan, a total of 3,375,000 shares of common stock may beissued under each plan to directors, officers and other key employeespursuant to grants of stock options or performance shares of commonstock. At December 31, 2000, there are 49,000 shares available forgrant under the 1994 Plan and 649,000 shares available for grantunder the 1997 Plan. Options vest and become exercisable on termsspecified when granted by the compensation committee (“theCommittee”) of the Board of Directors. Options granted under the1994 Plan have a term of ten years and are not exercisable until sixmonths after their grant date. Options granted under the 1994 Planand the 1997 Plan generally vest in equal amounts over five years,with provisions for earlier vesting if specified performancerequirements are met. In May 1998, all options under the 1994Plan vested by resolution of the Board of Directors.

1998 Stock Incentive Plan

In May 1998, the stockholders approved the 1998 StockIncentive Plan under which 9,000,000 shares of common stock areavailable for grant. Grants under the 1998 Plan are subject to theprovision that outstanding stock options and performance sharesunder all the Company’s stock incentive plans cannot exceed 6% ofthe Company’s outstanding common stock at the time such grantsare made. At December 31, 2000, there were 1,759,000 sharesavailable for grant under the 1998 Plan. Stock options generallyvest and become exercisable annually in equal amounts over a five-year period, with provision for accelerated vesting when the commonstock price reaches specified levels. There were 1,135,000 optionsoutstanding at December 31, 2000 that vested when the commonstock price closed above $30.00 on March 9, 2001 and 104,000options that vest when the common stock price closes above $32.50.In 2001, an additional 927,000 options were granted, of which647,000 have vested and 280,000 vest when the stock price closesabove $32.50.

Performance Shares

Performance shares granted under the 1994, 1997 and 1998Plans are subject to restrictions determined by the Committee andare subject to forfeiture if performance targets are not met.Otherwise, holders of performance shares generally have all thevoting, dividend and other rights of other stockholders. TheCompany issued performance shares to key employees totaling820,000 in 2000, 195,000 in 1999 and 108,000 in 1998.

Cr o s s T im b e r s O i l C om pa n y

Cr o s s T im b e r s O i l C om pa n y

42

(continued)

Performance shares vested, totaling 1,007,000 in 2000 and 122,000in 1998, when the common stock price reached specified levels. In 1999, 18,000 performance shares issued in 1998 were forfeited.General and administrative expense includes compensation relatedto these performance share grants of $18.4 million in 2000,$102,000 in 1999 and $1.6 million in 1998. As of December 31,2000, there were 85,000 performance shares that vested when thecommon stock price closed above $30.00 on March 9, 2001 and13,500 performance shares that vest in increments of 4,500 in eachof 2001, 2002 and 2003. In March 2001, an additional 77,000performance shares were issued that vest when the stock price closesabove $32.50. The Company also issued to nonemployee directors atotal of 18,000 performance shares in 1999 and 15,000 performanceshares in 1998, which vested upon grant.

In February 2001, the Board approved an agreement withcertain executive officers under which the officers, immediately priorto a change in control of the Company, will receive a total grant of77,000 performance shares for every $2.50 increment in the closingprice of the Company’s common stock above $30.00. The numberof performance shares granted under the agreement will be reducedby the number of performance shares awarded to the officers betweenthe date of the agreement and the date of the change in control.Certain officers will also receive a total grant of 155,000 perfor-mance shares immediately prior to a change in control without regardto the price of the Company’s common stock.

Royalty Trust Option Plans

Under the 1998 Royalty Trust Option Plan, the Companygranted certain officers options to purchase 1,290,000 HugotonRoyalty Trust units at prices of $8.03 and $9.50 per unit, or a totalof $12 million. These units were exercised in 1999 and 2000,resulting in non-cash compensation expense of $7.1 million in 2000and $60,000 in 1999 (Note 13).

Option Activity and Balances

The following summarizes option activity and balances from1998 through 2000:

Weighted AverageExercise Price Stock Options

1 9 9 8

Beginning of year $ 7.41 3 , 5 3 0 , 1 7 0G r a n t s 1 1 . 6 8 2 , 0 9 3 , 6 2 5E x e r c i s e s 7 . 7 6 ( 1 , 6 3 2 , 6 9 1 )F o r f e i t u r e s 1 1 . 4 6 ( 3 2 , 6 2 5 )

End of year 9 . 4 9 3 , 9 5 8 , 4 7 9

Exercisable at end of year 7 . 3 5 2 , 0 5 3 , 8 5 4

1 9 9 9

Beginning of year $ 9.49 3 , 9 5 8 , 4 7 9G r a n t s 7 . 1 1 6 1 4 , 8 1 2E x e r c i s e s 4 . 5 7 ( 1 5 , 6 9 3 )F o r f e i t u r e s 7 . 7 5 ( 4 2 , 8 6 2 )

End of year 9 . 2 0 4 , 5 1 4 , 7 3 6

Exercisable at end of year 7 . 3 9 2 , 0 0 9 , 3 6 1

2 0 0 0

Beginning of year $ 9.20 4 , 5 1 4 , 7 3 6G r a n t s 1 9 . 9 9 4 , 7 6 2 , 5 0 3E x e r c i s e s 9 . 8 1 ( 4 , 6 4 3 , 4 1 4 )F o r f e i t u r e s 8 . 9 1 ( 2 4 6 , 3 3 6 )

End of year 2 0 . 1 4 4 , 3 8 7 , 4 8 9

Exercisable at end of year 1 9 . 2 4 3 , 1 4 8 , 5 0 9

The following summarizes information about outstandingoptions at December 31, 2000:

Options Outstanding Options Exercisable

W e i g h t e d W e i g h t e d W e i g h t e dA v e r a g e A v e r a g e A v e r a g e

Range of R e m a i n i n g E x e r c i s e E x e r c i s eExercise Prices N u m b e r T e r m P r i c e N u m b e r P r i c e

$ 2.76 - $ 8 . 2 8 1 6 3 , 8 7 2 6.2 years $ 6 . 4 2 1 6 3 , 8 7 2 $ 6 . 4 2$ 8.29 - $13.80 3 7 0 , 9 1 2 7.5 years 1 2 . 3 1 3 7 0 , 9 1 2 1 2 . 3 1$13.81 - $19.32 3 3 2 , 4 2 5 7.6 years 1 4 . 2 9 3 3 2 , 4 2 5 1 4 . 2 9$19.33 - $27.59 3 , 5 2 0 , 2 8 0 9.8 years 2 2 . 1 6 2 , 2 8 1 , 3 0 0 2 2 . 0 0

4 , 3 8 7 , 4 8 9 3 , 1 4 8 , 5 0 9

Estimated Fair Value of Grants

Using the Black-Scholes option-pricing model and thefollowing assumptions, the weighted average fair value of optiongrants was estimated to be $10.27 in 2000, $4.27 in 1999 and$4.55 in 1998.

2 0 0 0 1 9 9 9 1 9 9 8

Risk-free interest rates 5 . 8 % 5 . 8 % 5 . 6 %Dividend yield 0 . 2 % 3 . 0 % 3 . 2 %Weighted average expected lives 5 years 5 years 5 yearsV o l a t i l i t y 5 3 % 9 1 % 5 2 %

Pro Forma Effect of Recording Stock-Based

Compensation at Estimated Fair Value

The following are pro forma earnings (loss) available tocommon stock and earnings (loss) per common share for 2000, 1999and 1998, as if stock-based compensation had been recorded at theestimated fair value of stock awards at the grant date, as prescribedby SFAS 123, Accounting for Stock-Based Compensation:

(in thousands, except per share data) 2 0 0 0 1 9 9 9 1 9 9 8

Earnings (loss) available to common stock:As reported $ 1 1 5 , 2 3 5 $ 44,964 $ ( 7 1 , 4 9 8 )Pro forma $ 91,194 $ 4 0 , 3 7 3 $( 7 5 , 7 8 5 )

Earnings (loss) per common share:B a s i c As reported $ 1 . 6 2 $ 0 . 6 4 $ ( 1 . 1 0 )

Pro forma $ 1 . 2 8 $ 0 . 5 7 $ ( 1 . 1 6 )D i l u t e d As reported $ 1 . 5 5 $ 0 . 6 3 $ ( 1 . 1 0 )

Pro forma $ 1 . 2 3 $ 0 . 5 7 $ ( 1 . 1 6 )

13. Sale of Hugoton Royalty Trust Units

In December 1998, the Company formed the Hugoton RoyaltyTrust by conveying 80% net profits interests in properties located in the Hugoton area of Kansas and Oklahoma, the Anadarko Basinof Oklahoma and the Green River Basin of Wyoming. These netprofits interests were conveyed to the trust in exchange for 40 million units of beneficial interest. In April and May 1999, theCompany sold 17 million, or 42.5%, of the trust units in an initialpublic offering at a price of $9.50 per unit, less underwriters’discount and expenses. Total net proceeds from the sale were $148.6 million, resulting in a gain of $40.3 million before incometax. Proceeds from the sale were used to reduce bank debt.

In 1999 and 2000, officers exercised options to purchase a total of 1.3 million Hugoton Royalty Trust units from the Companypursuant to the 1998 Royalty Trust Option Plan in exchange for shares of Company common stock. The Company recognizedgains of $11 million in 2000 and $235,000 in 1999 on these sales of trust units.

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N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S (continued)

the Panhandle area of Texas and the Green River Basin of Wyoming,including sales of $22.5 million of properties acquired in the Spring acquisition.

In March 2000, the Company sold primarily gas-producingproperties in Crockett County, Texas for gross proceeds of $43 million and sold oil- and gas-producing properties in LeaCounty, New Mexico for gross proceeds of $25.3 million.

Acquisitions have been recorded using the purchase method ofaccounting. The following presents unaudited pro forma results ofoperations for the year ended December 31, 1999 as if theseacquisitions and the sale of Hugoton Royalty Trust units and otherproperties had been consummated immediately prior to January 1,1999. Pro forma results are not presented for the year endedDecember 31, 2000 because the effects of these transactionsexcluded from 2000 results are not significant. These pro formaresults are not necessarily indicative of future results.

Pro Forma1 9 9 9

(in thousands, except per share data) ( U n a u d i t e d )

R e v e n u e s $ 3 5 3 , 1 8 6

Net income $ 4 5 , 5 5 2

Earnings available to common stock $ 4 3 , 9 2 4

Earnings per common share:B a s i c $ 0 . 6 0

D i l u t e d $ 0 . 5 9

On December 5, 2000, the Company entered into a definitiveagreement to acquire primarily gas-producing properties in EastTexas and Louisiana for $115 million from Herd ProducingCompany, Inc. The purchase was completed on January 3, 2001,and was funded through borrowings under existing bank lines. The purchase is subject to typical post-closing adjustments.

On January 2, 2001, the Company repurchased 9,598,000MMBtu of natural gas for $9.9 million from a production paymentsold to EEX Corporation in a 1998 acquisition. In December 2001,the Company can repurchase an additional 9,598,000 MMBtu of gasfrom the production payment for approximately $11 million.

14. Acquisitions and Dispositions

A c q u i s i t i o n s

On July 1, 1999, the Company and Lehman BrothersHoldings, Inc. acquired predominantly gas-producing properties inthe Arkoma Basin through the purchase of the common stock ofSpring Holding Company, a private oil and gas company located inTulsa, Oklahoma for $85 million. The Company issued 5.6 millionshares of common stock for its ownership interest in Spring andLehman contributed $42.5 million in cash. The Company andLehman each owned 50% of a limited liability company thatacquired the common stock of Spring. Pursuant to a put and callagreement, the Company purchased Lehman’s interest in September1999 for $44.3 million, or $1.8 million in excess of the recordedminority interest, which excess was recorded as producing propertycost. Property cost associated with the Spring acquisition totaledapproximately $235 million, a portion of which was attributed toother than producing properties, including a gas gathering system,compressors, undeveloped leasehold cost and other tangibleproperty. After purchase accounting adjustments, including a $14.1 million step-up adjustment for deferred income taxes, the costof the properties was $257 million. Although the Company andLehman had equal board representation and control of Spring, theCompany’s management controlled operations of the properties fromJuly 1, 1999 and had the right to purchase Lehman’s interestpursuant to the call agreement. The Company accordinglyconsolidated its investment in Spring from July 1, 1999, withrecognition of Lehman’s investment as a minority interest throughSeptember 1999.

On September 15, 1999, the Company and Lehman acquiredArkoma Basin oil and gas properties from Ocean Energy, Inc. for$231 million. The original purchase price of $235.3 million wasreduced by estimated net revenue received between the July 1, 1999effective date and the closing date. The Company and Lehman eachowned 50% of Whitewine Holding Company, which was formed toacquire the Arkoma Basin properties. Pursuant to a put and callagreement, the Company purchased Lehman’s 50% interest in theOcean Energy Acquisition on March 31, 2000 for $111 million, or$11 million in excess of the recorded minority interest, which excesswas recorded as producing property cost. Although the Companyand Lehman had equal board representation and control ofWhitewine, the Company’s management controlled operations ofthe properties from September 15, 1999 and had the right topurchase Lehman’s interest pursuant to the call agreement.Whitewine’s financial results are consolidated in the Company’sfinancial statements, with recognition of Lehman’s 50% interest as a minority interest through March 31, 2000.

D i s p o s i t i o n s

On May 4, 1999, the Company sold nonoperated producingproperties in the San Juan Basin of New Mexico to Vastar Resources,Inc. for $29.9 million. The Company sold other nonoperatedproducing properties in June 1999 for approximately $15 million.Proceeds from the sales were used to reduce bank debt.

On September 14, 1999, producing properties were sold forapproximately $63.5 million before closing costs in twotransactions. The Company sold primarily nonoperated propertiesin Oklahoma, the Permian Basin of West Texas and New Mexico,

C r o s s T im b e r s O i l C o m p an y

Cr o s s T im b e r s O i l C om pa n y

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original estimate. Revisions result primarily from new informationobtained from development drilling and production history andfrom changes in economic factors.

Standardized Measure

The standardized measure of discounted future net cash flows(“standardized measure”) and changes in such cash flows are preparedusing assumptions required by the Financial Accounting StandardsBoard. Such assumptions include the use of year-end prices for oiland gas and year-end costs for estimated future development andproduction expenditures to produce year-end estimated provedreserves. Discounted future net cash flows are calculated using a10% rate. Estimated future income taxes are calculated by applyingyear-end statutory rates to future pre-tax net cash flows, less the taxbasis of related assets and applicable tax credits.

The standardized measure does not represent management’sestimate of the Company’s future cash flows or the value of provedoil and gas reserves. Probable and possible reserves, which maybecome proved in the future, are excluded from the calculations.Furthermore, year-end prices used to determine the standardizedmeasure of discounted cash flows, are influenced by seasonal demandand other factors and may not be the most representative inestimating future revenues or reserve data.

Proved Reserves Natural GasOil G a s L i q u i d s

(in thousands) (Bbls) ( M c f ) ( B b l s )

December 31, 1997 4 7 , 8 5 4 8 1 5 , 7 7 5 1 3 , 8 1 0R e v i s i o n s ( 5 , 8 9 3 ) ( 5 , 4 2 9 ) 2 , 6 3 1Extensions, additions and discoveries 8 2 1 1 7 2 , 0 5 9 1 , 8 7 5P r o d u c t i o n ( 4 , 5 9 8 ) ( 8 3 , 8 4 7 ) ( 1 , 2 2 2 )Purchases in place 1 6 , 3 3 1 3 1 1 , 2 6 0 8 0Sales in place ( 5 ) ( 5 9 4 ) —

December 31, 1998 54,510 1,209,224 1 7 , 1 7 4R e v i s i o n s 1 0 , 7 9 2 6 0 , 0 1 1 1 , 8 3 8Extensions, additions and discoveries 3 , 0 0 3 1 6 6 , 6 6 9 3 , 3 5 7P r o d u c t i o n ( 5 , 1 1 2 ) ( 1 0 5 , 1 2 0 ) ( 1 , 3 2 5 )Purchases in place 2 , 7 9 0 4 9 4 , 6 6 6 2 0Sales in place ( 4 , 3 8 0 ) ( 2 7 9 , 8 2 7 ) ( 3 , 1 6 2 )

December 31, 1999 61,603 1,545,623 1 7 , 9 0 2R e v i s i o n s 2 , 7 0 9 1 4 2 , 9 7 4 3 , 7 0 9Extensions, additions and discoveries 1 , 1 4 5 2 5 8 , 8 4 3 1 , 9 5 1P r o d u c t i o n ( 4 , 7 3 6 ) ( 1 2 5 , 8 5 7 ) ( 1 , 6 2 2 )Purchases in place 8 3 3 2 6 , 5 5 7 7 2Sales in place ( 3 , 1 0 9 ) ( 7 8 , 4 5 7 ) —

December 31, 2000 58,445 1,769,683 2 2 , 0 1 2

Proved Developed Reserves Natural GasOil G a s Liquids

(in thousands) ( B b l s ) ( M c f ) (Bbls)

December 31, 1997 3 3 , 8 3 5 6 7 7 , 7 1 0 1 1 , 4 9 4

December 31, 1998 4 2 , 8 7 6 9 6 8 , 4 9 5 1 4 , 0 0 0

December 31, 1999 48,010 1,225,014 1 3 , 7 8 1

December 31, 2000 46,334 1,328,953 1 6 , 4 4 8

(continued)

15. Quarterly Financial Data ( U n a u d i t e d )

The following are summarized quarterly financial data for theyears ended December 31, 2000 and 1999:

(in thousands, except per share data) Q u a r t e r

1 s t 2 n d 3 r d 4 t h2 0 0 0

R e v e n u e s $1 1 3 , 3 2 6 $1 2 1 , 6 5 0 $1 6 0 , 5 1 9 $2 0 5 , 3 5 6Gross profit ( a ) $ 4 4 , 9 9 7 $ 3 0 , 0 9 4 $ 8 0 , 9 8 1 $1 0 5 , 4 9 0Earnings available to

common stock $ 3 3 , 2 6 7 $ 7 9 8 $ 3 1 , 3 6 6 $ 4 9 , 8 0 4Earnings per common share

B a s i c $ 0 . 4 6 $ 0 . 0 1 $ 0 . 4 5 $ 0 . 6 8D i l u t e d $ 0 . 4 4 $ 0 . 0 1 $ 0 . 4 3 $ 0 . 6 4

Average shares outstanding 7 2 , 4 4 1 6 8 , 9 1 8 6 9 , 5 1 8 7 3 , 7 2 8

1 9 9 9

R e v e n u e s $ 6 9 , 4 1 5 $ 6 5 , 5 5 0 $ 9 5 , 3 2 6 $1 1 1 , 0 0 4Gross profit ( a ) $ 1 5 , 1 5 4 $ 1 3 , 6 0 1 $ 3 6 , 4 2 0 $ 4 4 , 3 1 8Earnings (loss) available to

common stock $ ( 2 , 0 9 1 ) $ 2 8 , 3 4 1 $ 1 3 , 0 7 1 $ 5 , 6 4 3Earnings (loss) per common share

B a s i c $ ( 0 . 0 3 ) $ 0 . 4 2 $ 0 . 1 8 $ 0 . 0 8D i l u t e d $ ( 0 . 0 3 ) $ 0 . 4 1 $ 0 . 1 7 $ 0 . 0 8

Average shares outstanding 6 7 , 0 9 1 6 7 , 1 0 0 7 3 , 3 7 1 7 3 , 2 4 7

(a) Operating income before general and administrative expense.

16. Supplementary Financial Information for Oil and GasProducing Activities ( U n a u d i t e d )

All of the Company’s operations are directly related to oil andgas producing activities located in the United States.

Costs Incurred Related to Oil and Gas Producing Activities

The following table summarizes costs incurred whether suchcosts are capitalized or expensed for financial reporting purposes:

(in thousands) 2 0 0 0 1 9 9 9 1 9 9 8

A c q u i s i t i o n s :Producing properties $ 31,983 $ 5 0 5 , 9 1 2 $ 3 3 9 , 8 8 9Undeveloped properties 3 , 4 9 0 4 , 1 8 2 5 1 4

D e v e l o p m e n t ( a ) 1 6 3 , 2 2 4 8 9 , 3 0 6 6 9 , 3 6 7E x p l o r a t i o n :

Geological and geophysical studies 8 2 9 8 7 2 7 , 9 4 3Dry hole expense — — —Rental expense and other 2 1 8 3 2 9 1

T o t a l $ 1 9 9 , 7 4 4 $ 6 0 0 , 3 0 4 $ 4 1 7 , 8 0 4

(a) Includes capitalized interest of $3,488,000 in 2000, $1,353,000 in 1999 and$1,070,000 in 1998.

Proved Reserves

Independent petroleum engineers have estimated theCompany’s proved oil and gas reserves, all of which are located in theUnited States. Proved reserves are the estimated quantities thatgeologic and engineering data demonstrate with reasonable certaintyto be recoverable in future years from known reservoirs underexisting economic and operating conditions. Proved developedreserves are the quantities expected to be recovered through existingwells with existing equipment and operating methods. Due to theinherent uncertainties and the limited nature of reservoir data, suchestimates are subject to change as additional information becomesavailable. The reserves actually recovered and the timing ofproduction of these reserves may be substantially different from the

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Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves December 31

(in thousands) 2 0 0 0 1999 1998

Future cash inflows $ 1 8 , 8 6 6 , 8 3 2 $ 5,113,094 $ 3,041,776Future costs:

P r o d u c t i o n ( 3 , 2 3 7 , 5 7 4 ) ( 1 , 5 4 9 , 4 0 1 ) ( 1 , 1 3 5 , 7 8 9 )D e v e l o p m e n t ( 3 8 9 , 6 9 8 ) ( 2 9 4 , 2 5 0 ) ( 2 2 8 , 5 6 1 )

Future net cash flows before income tax 1 5 , 2 3 9 , 5 6 0 3 , 2 6 9 , 4 4 3 1 , 6 7 7 , 4 2 6

Future income tax ( 4 , 9 4 7 , 6 1 4 ) ( 7 1 8 , 8 9 2 ) ( 2 3 1 , 2 4 9 )

Future net cash flows 1 0 , 2 9 1 , 9 4 6 2 , 5 5 0 , 5 5 1 1 , 4 4 6 , 1 7 710% annual discount ( 5 , 0 2 9 , 9 1 6 ) ( 1 , 1 5 3 , 6 1 1 ) ( 6 3 7 , 7 7 4 )

Standardized measure ( a ) $ 5,262,030 $ 1,396,940 $ 8 0 8 , 4 0 3

(a) Before income tax, the year-end standardized measure (or discounted present valueof future net cash flows) was $7,748,632,000 in 2000, $1,765,936,000 in 1999and $908,606,000 in 1998.

Changes in Standardized Measure ofDiscounted Future Net Cash Flows

(in thousands) 2 0 0 0 1999 1 9 9 8

Standardized measure, January 1 $ 1 , 3 9 6 , 9 4 0 $ 808,403 $ 6 4 2 , 1 0 9

R e v i s i o n s :Prices and costs 5 , 0 9 6 , 9 7 3 6 0 8 , 1 2 3 ( 1 8 4 , 5 6 8 )Quantity estimates 1 9 0 , 4 5 7 6 2 , 0 3 3 6 5 , 6 0 0Accretion of discount 1 2 3 , 2 2 5 7 0 , 2 5 6 5 8 , 1 9 5Future development costs ( 1 9 6 , 0 4 8 ) ( 1 1 3 , 1 1 0 ) ( 1 0 4 , 6 3 6 )Income tax ( 2 , 0 8 2 , 7 4 5 ) ( 2 5 9 , 4 0 3 ) 5 3 , 7 5 8Production rates and other 1 , 3 7 8 ( 1 3 7 ) ( 2 9 6 )

Net revisions 3 , 1 3 3 , 2 4 0 3 6 7 , 7 6 2 ( 1 1 1 , 9 4 7 )Extensions, additions and discoveries 1 , 0 1 8 , 3 4 9 1 2 5 , 2 0 9 9 6 , 8 2 9P r o d u c t i o n ( 4 4 1 , 3 2 3 ) ( 2 1 5 , 8 6 9 ) ( 1 4 6 , 4 9 8 )Development costs 1 2 8 , 7 5 7 7 0 , 2 7 5 5 6 , 9 0 4Purchases in place ( a ) 1 1 5 , 8 6 6 4 1 4 , 7 5 9 2 7 1 , 8 0 6Sales in place ( b ) ( 8 9 , 7 9 9 ) ( 1 7 3 , 5 9 9 ) ( 8 0 0 )

Net change 3 , 8 6 5 , 0 9 0 5 8 8 , 5 3 7 1 6 6 , 2 9 4

Standardized measure, December 31 $ 5 , 2 6 2 , 0 3 0 $ 1,396,940 $ 8 0 8 , 4 0 3

(a) Generally based on the year-end present value (at year-end prices and costs) plusthe cash flow received from such properties during the year, rather than theestimated present value at the date of acquisition.

( b ) Generally based on beginning of the year present value (at beginning of year pricesand costs) less the cash flow received from such properties during the year, ratherthan the estimated present value at the date of sale.

Price and cost revisions are primarily the net result of changesin year-end prices, based on beginning of year reserve estimates.Quantity estimate revisions are primarily the result of the extendedeconomic life of proved reserves and proved undeveloped reserveadditions attributable to increased development activity.

Year-end realized oil prices used in the estimation of provedreserves and calculation of the standardized measure were $25.49 for2000, $24.17 for 1999 and $9.50 for 1998. Year-end averagerealized gas prices were $9.55 for 2000, $2.20 for 1999 and $2.01for 1998. Year-end average realized natural gas liquids prices were$26.33 for 2000, $13.83 for 1999 and $3.99 for 1998. Proved oiland gas reserves at December 31, 2000 include:

• 1,970,000 Bbls of oil and 223,578,000 Mcf of gas anddiscounted present value before income tax of $842,346,000related to the Company’s ownership of approximately 54% ofHugoton Royalty Trust units at December 31, 2000.

• 747,000 Bbls of oil and 7,986,000 Mcf of gas and discountedpresent value before income tax of $38,403,000 related to theCompany’s ownership of approximately 23% of CrossTimbers Royalty Trust units at December 31, 2000.

Based on NYMEX prices of $25.00 per Bbl for oil and $5.00per Mcf for gas (which are comparable to realized prices of $23.69per Bbl for oil and $4.79 per Mcf for gas), and an $18.86 per Bblrealized price for natural gas liquids, estimated proved reserves atDecember 31, 2000 would be 57.7 million Bbls of oil, 1.75 Tcf ofnatural gas and 21.6 million Bbls of natural gas liquids. Usingthese prices, the present value of estimated future cash flows,discounted at 10% and before income tax, would be$ 3 , 8 3 4 , 0 2 4 , 0 0 0 .

(continued)

C r o s s T im b e r s O i l C o m p a n y

46

R E P O R T O F I N D E P E N D E N T P U B L I C A C C O U N T A N T S

To the Board of Directors and Stockholders ofC ross Timbers Oil Company

We have audited the accompanying consolidated balance sheets of Cross Timbers Oil Company and its subsidiaries as of December 31,2000 and 1999, and the related consolidated income statements, statements of cash flows and stockholders’ equity for each of the three yearsin the period ended December 31, 2000. These financial statements are the responsibility of the Company’s management. Ourresponsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require thatwe plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. Anaudit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit alsoincludes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financialstatement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position ofthe Company as of December 31, 2000 and 1999, and the results of its operations and its cash flows for each of the three years in the periodended December 31, 2000, in conformity with accounting principles generally accepted in the United States.

ARTHUR ANDERSEN LLP

Fort Worth, TexasMarch 22, 2001

M A R K E T P R I C E O F C O M M O N S T O C K A N D D I V I D E N D S D E C L A R E D P E R S H A R E

C ross Timbers common stock began trading on the New York Stock Exchange on May 11, 1993 under the symbol “XTO.” The following table shows the high and low prices of Cross Timbers common stock and the dividends declared for each quarter of 1999and 2000. These values have been adjusted for the thre e - f o r-two split that occurred in September 2000. As of March 1, 2001, therew e re 593 holders of re c o rd of Cross Timbers common stock.

Quarter End H i g h L o w D i v i d e n d

2 0 0 0

M a rch 31 $ 8.917 $ 5.042 $ 0.0067

June 30 1 4 . 8 3 3 8 . 1 6 7 0 . 0 0 6 7

September 30 2 1 . 6 2 5 1 0 . 6 6 7 0 . 0 1 0 0

December 31 2 9 . 0 0 0 1 6 . 7 5 0 0 . 0 1 0 0

1 9 9 9

M a rch 31 $ 6.042 $ 3.042 $ 0.0067

June 30 9 . 9 1 7 4 . 5 0 0 0 . 0 0 6 7

September 30 1 0 . 0 8 3 7 . 3 3 3 0 . 0 0 6 7

December 31 8 . 8 7 5 5 . 4 5 8 0 . 0 0 6 7

47

Senior Officers

Bob R. Simpson Chairman and Chief Executive Officer

Steffen E. Palko Vice Chairman and President

Louis G. Baldwin Executive Vice President and Chief Financial Officer

Keith A. HuttonExecutive Vice President, O p e r a t i o n s

Vaughn O. Vennerberg IIExecutive Vice President,A d m i n i s t r a t i o n

Bennie G. Kniffen Senior Vice President and C o n t r o l l e r

Timothy L. Petrus Senior Vice President, Acquisitions

Kenneth F. Staab Senior Vice President, Engineering

Thomas L.V a u g h nSenior Vice President, Operations

Other Officers

Virginia N. Anderson Corporate Secretary

Adam E. Auten Assistant Treasurer

Nick J. Dungey Vice President, Natural GasO p e r a t i o n s

Robert B. Gathright Assistant Controller andDirector of Budget and Planning

Jeffrey F. Heyer Vice President, Geology

Ken K. KirbyVice President, OperationsEast Texas

Gary L. MarkestadVice President, OperationsSan Juan Basin

Frank G. McDonald Vice President and General Counsel and AssistantS e c r e t a r y

Robert C. Myers Vice President, Human Resources

D i r e c t o r s

Bob R. Simpson Chairman and Chief Executive Officer Cross Timbers Oil Company

Steffen E. Palko Vice Chairman and President Cross Timbers Oil Company

J. Luther King, Jr. President Luther King Capital Management Corporation

Jack P. RandallP r e s i d e n tRandall & Dewey

Scott G. Sherman Owner Sherman Enterprises

Herbert D. SimonsCounsel Winstead Sechrest, & Minick P.C.

Advisory Directors

Louis G. Baldwin Executive Vice President and Chief Financial Officer

Dr. Lane G. Collins Professor of Accounting/Business LawBaylor University

Keith A. HuttonExecutive Vice President, O p e r a t i o n s

Vaughn O. Vennerberg IIExecutive Vice President,A d m i n i s t r a t i o n

John M. O’Rear Vice President and Treasurer

Edwin S. Ryan, Jr. Vice President, Land

Terry L. Schultz Vice President, Gas Marketing

Doug C. Schultze Vice President, OperationsPermian Basin

Gary D. Simpson Vice President, Investor Relations

Mark A. StevensVice President, Taxation

E. E. Storm IIIVice President and General Counsel, Land and Acquisitions

L. Frank Thomas IIIVice President,Information Technology

Michael R. Tyson Assistant Controller and Director of Financial Reporting

D I R E C T O R S A N D O F F I C E R S

48

Corporate Headquarters810 Houston Street, Suite 2000Fort Worth, Texas 76102(817) 870-2800

Oklahoma City Office210 West Park Avenue, Suite 2350Oklahoma City, Oklahoma 73102(405) 232-4011

Midland Office3000 N. Garfield, Suite 175Midland, Texas 79705 (915) 682-8873

Tyler OfficeWoodgate Center1001 ESE Loop 323, Suite 410Tyler, Texas 75701 (903) 939-1200

Farmington Office2700 Farmington Avenue Bldg. K, Suite 1 Farmington, New Mexico 87401 (505) 324-1090

Ozark OfficeP. O. Box 213Highway 23 and Airport RoadOzark, Arkansas 72949(501) 667-4819

Alaska Office52260 Shell RoadKenai, Alaska 99611(907) 776-2506

Annual Meeting Tuesday, May 15, 2001 at 10 a.m. Fort Worth Club Tower777 Taylor Street12th Floor, Horizon RoomFort Worth, Texas

Independent AuditorsArthur Andersen LLP Fort Worth, Texas

Senior Subordinated Notes91⁄4% Notes due 200783⁄4% Notes due 2009

Transfer Agents and Registrars Common Stock: Mellon Investor Services LLC Dallas, Texasw w w . m e l l o n - i n v e s t o r . c o mSenior Subordinated Notes: Bank of New York Corporate Trust DivisionNew York, New York

Form 10-KCopies of the Company’s Annual Reporton Form 10-K filed with the Securitiesand Exchange Commission may beobtained, without charge, upon request toInvestor Relations at our corporateaddress. Copies of any exhibits to theCompany’s Annual Report on Form 10-Kmay also be obtained, without charge,upon specific request.

Direct Stock Purchase/Dividend Reinvestment PlanA Direct Stock Purchase and DividendReinvestment Plan allows new investorsto buy Cross Timbers common stock foras little as $500 and existing shareholdersto automatically reinvest dividends. Formore information, request a prospectusfrom: Mellon Investor Services LLC at(800) 938-6387.

Shareholder ServicesFor questions about dividend checks,electronic payment of dividends, stockcertificates, address changes, accountbalance, transfer procedures and year-end tax information call (888) 877-2892.

Web Sitew w w . c r o s s t i m b e r s . c o m

C O R P O R A T E I N F O R M A T I O N

ON THE BACK COVER

As the stars come out, the star gazing begins.

The West Texas sun drifts down and the twilight hours

awaken. On the faint horizon, the McDonald Observatory

is silhouetted against the dusk. Keeping a constant watch

deep in the Davis Mountains, the lab’s giant telescopes pan

the sky searching for another “discovery.”

ABOUT THE PHOTOGRAPHER

Gary McCoy is passionate about the land and deeply

respectful of its inhabitants. For this annual report, he set

out to capture the shapes and shades of our operating areas.

Although Gary’s photographic skills were challenged by

sub-zero temperatures, rain, snow and blowing sand, he

came away with a richly textured tapestry of the field.

For the past 25 years, he has traveled extensively for

corporate and editorial clients. His photographs have been

selected for recognition by Communication Arts, The New

York Art Directors’ Club, Graphis and The American

Institute of Graphic Arts. A native of Wichita Falls, Texas,

Gary now lives in Dallas.

This Annual Report, other than historical financial information, containsforward-looking statements regarding results of future developmentexpenditures, growth in production, cash flow per share, proved reserves,debt levels, strategic acquisitions and other matters subject to a numberof risks and uncertainties which are detailed in the Company’s AnnualReport on Form 10-K for the year ended December 31, 2000, which isincorporated by this reference as though fully set forth herein. Although the Company believes that the expectations reflected in suchforward-looking statements are reasonable based on currently availableinformation, there is no assurance that these goals and projections can or will be met.

Cross Timbers Oil Company

8 1 0 H o u s t o n S t r e e t , S u i t e 2 0 0 0F o r t Wo r t h , Te x a s 7 6 1 0 2

( 8 1 7 ) 8 7 0 - 2 8 0 0w w w. c r o s s t i m b e r s . c o m