<PAGE>

                                     1997
================================================================================
               UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                            Washington, D.C. 20549

                                   FORM 10-K

           [X]  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                        SECURITIES EXCHANGE ACT OF 1934

                 For the fiscal year ended  DECEMBER 31, 1997
                                            -----------------

                                      OR

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

           For the transition period from ___________ to ___________

                        Commission File Number:  1-10662
                                                 -------


                           CROSS TIMBERS OIL COMPANY
             (Exact name of registrant as specified in its charter)


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


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


       Registrant's telephone number, including area code (817) 870-2800
                                                          --------------

          Securities registered pursuant to Section 12(b) of the Act:


    Title of Each Class           Name of Each Exchange on Which Registered
----------------------------    ---------------------------------------------
Common stock, $.01 par value                New York Stock Exchange
Series A convertible preferred              New York Stock Exchange
  stock, $.01 par value


          Securities registered pursuant to Section 12(g) of the Act:
                                     None

Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes  X   No
   -----   -----

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to be the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.   X
           -----

    Aggregate market value of the voting stock held by nonaffiliates of the
         Registrant as of March 2, 1998 was approximately $593 million

 Number of Shares of Common Stock outstanding as of March 2, 1998 - 38,972,860
                                                                    ----------

                      DOCUMENTS INCORPORATED BY REFERENCE
                        (To The Extent Indicated Herein)

Part III of this Report is incorporated by reference from the Registrant's
definitive Proxy Statement for its Annual Meeting of Stockholders, which will be
filed with the Commission no later than April 30, 1998.

================================================================================
<PAGE>

                           CROSS TIMBERS OIL COMPANY
                        1997 ANNUAL REPORT ON FORM 10-K
                               TABLE OF CONTENTS


   ITEM                                                                   PAGE
   ----                                                                   ----

                                     PART I

1. and 2.    Business and Properties.........................................  1
   3.        Legal Proceedings............................................... 14
   4.        Submission of Matters to a Vote of Security Holders............. 14

                                    PART II

   5.        Market for Registrant's Common Equity and
             Related Stockholder Matters..................................... 15
   6.        Selected Financial Data......................................... 16
   7.        Management's Discussion and Analysis of Financial Condition
             and Results of Operations....................................... 18
   8.        Financial Statements and Supplementary Data..................... 26
   9.        Changes in and Disagreements with Accountants on Accounting
             and Financial Disclosure........................................ 26

                                    PART III

   10.       Directors and Executive Officers of the Registrant.............. 26
   11.       Executive Compensation.......................................... 26
   12.       Security Ownership of Certain Beneficial Owners and Management.. 26
   13.       Certain Relationships and Related Transactions.................. 26

                                    PART IV

   14.       Exhibits, Financial Statement Schedules and Reports on Form 8-K. 27
<PAGE>

                                     PART I

ITEMS 1. AND 2.  BUSINESS AND PROPERTIES

General

     Cross Timbers Oil Company and its wholly owned subsidiaries ("the Company")
are engaged in the acquisition, development, exploitation and exploration of
producing oil and gas properties, and in the production, processing, marketing
and transportation of oil and natural gas.  The Company has grown primarily
through acquisitions of proved oil and gas reserves, followed by development and
exploitation activities and strategic acquisitions of additional interests in or
near such acquired properties.  The Company's proved reserves are principally
located in relatively long-lived fields with well-established production
histories concentrated in western Oklahoma, the Permian Basin of West Texas and
New Mexico, the Hugoton Field of Oklahoma and Kansas, the San Juan Basin of
northwestern New Mexico and the Green River Basin of Wyoming.

     The Company's estimated proved reserves at December 31, 1997 were 47.9
million barrels ("Bbls") of oil and 815.8 billion cubic feet ("Bcf") of natural
gas and 13.8 million Bbls of natural gas liquids, as compared to December 31,
1996 proved reserves of 42.4 million Bbls of oil and 540.5 Bcf of natural gas.
Increased proved reserves during 1997 are primarily the result of predominantly
gas-producing property acquisitions and development and exploitation activities,
partially offset by production.  During 1997, the Company's daily oil and gas
production averaged 10,905 Bbls and 135,855 Mcf.  Fourth quarter 1997 daily oil
and gas production averaged 11,378 Bbls and 150,907 Mcf. Following its December
1997 acquisition of gas-producing properties in the San Juan Basin, the Company
began separate reporting of natural gas liquids production related to this
acquisition.  Natural gas liquids production for the month of December 1997 was
80,500 Bbls or 2,596 Bbls per day.

     The Company's properties are characterized by relatively long reserve life
and highly predictable well production profiles.  Based on December 31, 1997
proved reserves and projected 1998 production, the average reserve-to-production
index of the Company's proved reserves is 13.3 years.  In general, the Company's
properties have extensive production histories and production enhancement
opportunities.  While the Company's properties are geographically diversified,
the producing fields are concentrated within core areas, allowing for
substantial economies of scale in production and cost-effective application of
reservoir management techniques gained from prior operations. By operating the
majority of its properties, the Company can control expenses, capital allocation
and the timing of development and exploitation activities in its fields, thus
allowing the Company to reduce production costs of acquired properties.

     The Company has generated a substantial inventory of approximately 950
potential development drilling locations within its existing properties (of
which 486 have been attributed proved undeveloped reserves), to support future
net reserve additions.  Approximately 200 of these locations will require
certain regulatory approvals and legislation in Oklahoma prior to drilling.

     The Company has recently begun to emphasize exploration of unproved
reserves as part of its business strategy.  During 1997, the Company expensed
$2.1 million in connection with its exploration program, primarily including
seismic and other geological and geophysical analysis costs.  The Company has
allocated 10% to 15% of its 1998 budget, or up to $13.5 million for exploration
activities.

     The Company employs a disciplined acquisition program refined by senior
management to augment its core properties and expand its reserve base.  The
Company's engineers and geologists use their expertise and experience gained
through the management of existing core properties to target properties to be
acquired with similar geological and reservoir characteristics.

     A subsidiary of the Company operates a gas gathering system in Major
County, Oklahoma, where a significant portion of the Company's gas is produced.
Since August 1, 1995, another subsidiary of the Company has operated a gas
gathering system and a gas processing plant in the Hugoton Field of Kansas and
Oklahoma.

                                       1
<PAGE>

     Most of the Company's production is sold at market-responsive prices.  The
Company also markets its oil and gas, including sales of gas under forward sales
contracts.  The Company occasionally uses futures contracts and other price risk
management instruments to hedge pricing risks.

History of the Company

     Cross Timbers Oil Company was incorporated in Delaware in 1990 to act as
the managing general partner of Cross Timbers Oil Company, L.P. ("Partnership"),
and ultimately to acquire the business and properties of the Partnership.  The
Partnership was formed to combine in February 1991 the business and operations
of six limited partnerships and two corporations that were founded between 1986
and 1989.  On May 18, 1993, the Partnership exchanged its common units of
ownership for an equal number of shares of common stock in Cross Timbers Oil
Company and the Company sold 8.3 million shares of common stock (adjusted for
subsequent stock splits) in its initial public offering.

     During 1991, the predecessors of the Company formed Cross Timbers Royalty
Trust ("Royalty Trust") by carving net profits interests out of substantially
all the royalty and overriding royalty interests that the Company's predecessors
then owned in Texas, New Mexico and Oklahoma, and certain nonoperated working
interest properties in Texas and Oklahoma.  The Company makes monthly net
profits payments to the Royalty Trust based on revenues received and costs
disbursed for the properties from which the net profits interests were carved.
Royalty Trust units of beneficial interest ("Units") are listed on the New York
Stock Exchange under the symbol "CRT."  During 1996 and 1997, the Company
purchased 1,326,300, or 22%, of the outstanding Units.  The Board of Directors
has authorized the purchase of up to two million, or 33%, of the outstanding
Units.

Current Operating Environment

     The oil and gas industry is affected by many factors that the Company
generally cannot control.  Crude oil prices are generally determined by global
supply and demand.  After hitting a five-year low at the end of 1993, oil prices
reached their highest levels since the Persian Gulf War in 1990 during fourth
quarter 1996 and January 1997. Crude oil prices ranged from $17 to $20 during
most of 1997, then declined to a $16 average in December and to the $14 to $15
level in first quarter 1998.  The recent weakening in oil prices has generally
been attributed to increased OPEC production following its November 1997
decision to increase quotas,  increased non-OPEC production from the North Sea
and Latin America, and the recent United Nations decision to allow increased
Iraqi crude oil sales for humanitarian reasons.  Also contributing to decline
have been a mild 1997/1998 winter in the U.S. and Europe and the sudden drop in
demand from depressed economies in the Far East. After hitting a decade low of
$11.00, prices in late March 1998 began to increase upon news that some of the
major oil exporting countries planned to meet regarding curtailment of
production.

     Natural gas prices are influenced by national and regional supply and
demand, which is often dependent upon weather conditions.  Natural gas competes
with alternative energy sources as a fuel for heating and the generation of
electricity.  Gas prices were adversely impacted in 1995 as a result of the
winter of 1994/1995 being one of the warmest of the century.  Prices increased
in fourth quarter 1995 and continued their upward spiral through February 1996
because of low storage levels and colder than expected weather.  Generally
because of colder weather, storage concerns and U.S. economic growth, prices
remained relatively high during most of 1996 and 1997, reaching their highest
levels since 1985.  Gas prices declined, however, in December 1997 and have
remained lower in first quarter 1998, primarily because of an abnormally mild
winter in the central and eastern U.S. and elevated storage levels.

Business Strategy

     The primary components of the Company's business strategy are (i) acquiring
long-lived, operated oil and gas properties, (ii) increasing production and
reserves through aggressive management of operations and through development,
exploitation and exploration activities, and (iii) retaining management and
technical staff that have substantial experience in the Company's core areas.

     Acquiring Long-Lived, Operated Properties.  The Company seeks to acquire
long-lived, onshore operated producing properties that (i) contain complex
multiple-producing horizons with the potential for increases in reserves and
production, (ii) are in the Company's core operating areas or in areas with
similar geologic and reservoir characteristics and (iii) present opportunities
to reduce expenses through more efficient operations.  The Company

                                       2
<PAGE>

believes that the properties it acquires provide opportunities to increase
production and reserves through the implementation of mechanical and operational
improvements, workovers, behind-pipe completions, secondary recovery operations,
new development wells and other exploitation activities. The Company also seeks
to acquire facilities related to gathering, processing, marketing and
transporting oil and gas in areas where it owns reserves. Such facilities can
enhance profitability, reduce gathering, processing, marketing and
transportation costs, provide marketing flexibility and give the Company access
to additional markets. The Company's ability to successfully purchase properties
is dependent upon, among other things, competition for such purchases and the
availability of cash resources.

     Increasing Production and Reserves.  A principal component of the Company's
strategy is to increase production and reserves through aggressive management of
operations and through development, exploitation and exploration.  The Company
believes that its principal properties possess geologic and reservoir
characteristics that make them well suited for production increases through low-
risk exploitation and drilling programs.  The Company has generated an inventory
of approximately 950 potential drilling locations for this program.
Additionally, the Company reviews operations and mechanical data on operated
properties to determine if actions can be taken to reduce operating costs or
increase production.  Such actions include installing, repairing and upgrading
lifting equipment, redesigning downhole equipment to improve production from
different zones, modifying surface facilities and conducting restimulations and
recompletions.  The Company may also initiate, upgrade or revise existing
secondary recovery operations and drill development wells.

     The Company attempts to select projects that it believes will have the
potential to add substantially to proved reserves and cash flow.  Although it
has not historically engaged in significant exploratory activities, the Company
believes that it can prudently and successfully add growth potential through
exploratory activities given improved technology, its experienced technical
staff and its expanded base of operations.

     Experienced Management and Technical Staff.  Most of the Company's senior
management and technical staff have worked together for over 20 years and have
substantial experience in the Company's core operating areas. Bob R. Simpson and
Steffen E. Palko, who were co-founders of the Company and its predecessors, were
previously executive officers of Southland Royalty Company, one of the largest
U.S. independent oil and gas producers prior to its acquisition by Burlington
Northern, Inc. in 1985.

     Other Strategies.  The Company may also acquire working interests in
producing properties that do not include the right to operate such properties
("nonoperated interests") if such interests otherwise meet its acquisition
criteria.  The Company attempts to acquire nonoperated interests in fields that
are operated by major or established independent oil companies, where such
fields represent a significant investment to the operator and are therefore more
likely to be carefully managed by it.  The Company may also acquire nonoperated
interests with the intent of ultimately aggregating, through future
acquisitions, sufficient interests to obtain the right to operate the
properties.  The Company attempts to acquire nonoperated interests where
geologic conditions indicate the potential for undeveloped reserves that the
operator will exploit.

     The Company also attempts to acquire a portion of its oil and gas reserves
in the form of royalty interests. Royalty interests offer less exposure to
operational liabilities because they do not participate in operating activities
and do not bear production or development costs.  However, royalty interests
typically allow only limited influence on the operation or development of
properties.

     Business Goals.  In May 1997, the Company announced strategic goals for
1998 and 1999, including 50% increases in cash flow per share and proved
reserves per share.  Specifically, the Company's goal is to increase cash flow
per share to $2.97 in 1998 and to $3.67 in 1999, an aggregate increase of 50%
from 1997's goal of $2.45 (all adjusted for the February 25, 1998 three-for-two
stock split).  Proved reserves at year-end 1999 are targeted at 5.4 barrels of
oil equivalent ("BOE") per share, or 50% above the Company's year-end 1997 goal
of 3.6 BOE per share. Debt per BOE in 1998 and 1999 is expected to be $2.40.
These goals were based on May 1997 commodity prices which, net to the Company,
were approximately $20 per Bbl of oil and $2.00 per Mcf of gas.

     The Company also announced its plans to make strategic acquisitions
totaling $260 to $280 million from May 1997 through the end of 1999.  After
closing the Amoco Acquisition in December 1997 and the expected closing of the
EEX Acquisition in April 1998, the Company has significantly exceeded this goal.


                                       3
<PAGE>

     The Company has budgeted $70 to $90 million for its 1998 exploration and
development program which is expected to be funded primarily by cash flow from
operations. Exploration expenditures are expected to be 10% to 15% of the 1998
budget. The total capital budget, including acquisitions, will be adjusted
throughout 1998 to capitalize on opportunities offering the highest rates of
return after considering oil and gas price volatility.

ACQUISITIONS

     During 1995, the Company acquired predominantly gas-producing properties
for a total cost of $131 million, and a gas processing plant and gathering
facility for $29 million.  The Santa Fe Acquisition, the largest of these
acquisitions, closed on August 1, 1995 and consisted of mostly operated
properties, a gas processing plant and gathering system in the Hugoton Field of
Kansas and Oklahoma.  The 1995 acquisitions increased proved reserves by
approximately 3 million Bbls and 171 Bcf.

     During 1996, the Company acquired predominantly gas-producing properties
for a total cost of $106 million. The Enserch Acquisition, the largest of these
acquisitions, closed in July 1996 at a cost of $39.4 million and primarily
consisted of operated interests in the Green River Basin of southwestern
Wyoming.  In November 1996, the Company acquired additional interests in the
Fontenelle Unit, the most significant property included in the Enserch
Acquisition, at a cost of $12.5 million.  In December 1996, the Company acquired
primarily operated interests in gas-producing properties in the Ozona area of
the Permian Basin of West Texas for $28.1 million.  From July through December
1996, the Company acquired 16% of the publicly traded outstanding units of
beneficial interest in Cross Timbers Royalty Trust ("Units"), at a total cost of
$12.8 million.  The 1996 acquisitions increased proved reserves by approximately
1.6 million Bbls and 153.4 Bcf.

     During 1997, the Company acquired predominantly gas-producing properties
for a total cost of $256 million. The Amoco Acquisition, the largest of these
acquisitions, closed December 1, 1997 at an estimated adjusted purchase price of
$195 million, including five-year warrants to purchase 937,500 shares of the
Company's common stock at a price of $15.31 per share.  This acquisition
consists primarily of operated properties in the San Juan Basin of New Mexico.
In May 1997, the Company acquired primarily gas-producing properties in
Oklahoma, Kansas and Texas for an estimated adjusted purchase price of $39
million.  The Company also acquired an additional 6% of the Royalty Trust Units
at a cost of $5.4 million.  The 1997 acquisitions increased proved reserves by
approximately 3.2 million Bbls of oil, 248 Bcf of natural gas and 13.9 million
Bbls of natural gas liquids.

     On February 25, 1998, the Company announced it had entered into a
definitive agreement with EEX Corporation to acquire producing properties and
undeveloped acreage in East Texas.  The transaction is expected to close in late
April 1998 with an effective date of January 1, 1998.  After purchase price
adjustments, the preliminary purchase price of $265 million is expected to be
reduced to $245 million.  The Company's internal engineers estimate proved
reserves attributable to the acquisition to be 250 Bcf and 1.6 million Bbls as
of April 1998.


                                       4
<PAGE>

SIGNIFICANT PROPERTIES

     The following table summarizes proved reserves and discounted present
value, before income tax, of proved reserves by the Company's major operating
areas at December 31, 1997 (in thousands):
<TABLE>
<CAPTION>

                                      Proved Reserves
                       --------------------------------------------         Discounted
                                                       Natural Gas         Present Value
                                                        Liquids         before Income Tax of
                         Oil (Bbls)      Gas (Mcf)       (Bbls)           Proved Reserves
                       -------------   ------------   -------------   -----------------------
<S>                    <C>            <C>             <C>            <C>           <C>
     Permian Basin...        38,960          99,687           -        $233,739          29.9%
     Mid-Continent...         5,721         167,563           -         175,605          22.4%
     San Juan Basin..         1,228         221,986        13,810       168,787          21.6%
     Hugoton.........           260         161,299           -         111,468          14.3%
     Rocky Mountain..         1,279         154,846           -          80,791          10.3%
     Other (a).......           406          10,394           -          11,932           1.5%
                          ---------       ---------   ------------    ---------      --------
     Total...........        47,854         815,775        13,810      $782,322         100.0%
                          =========       =========   ============    =========      ========
</TABLE>
     (a) Includes 375,000 Bbls and 8,790,000 Mcf and discounted present value
         before income tax of $9,922,000 related to the Company's 22% ownership
         of Royalty Trust Units at December 31, 1997.

PERMIAN BASIN AREA

     Prentice Field.  The Prentice Field is located in Terry and Yoakum
Counties, Texas.  In 1993, the Company acquired its initial interest in the
Prentice Northeast Unit in three separate transactions, accumulating a 62.1%
interest. In January 1994, the Company purchased an additional 29.4% interest in
the Prentice Northeast Unit, increasing the Company's total ownership to 91.5%.
The Company assumed operations of the Unit effective March 1, 1994.  Current net
production from the 186-well Unit is approximately 3,350 Bbls of oil and 500 Mcf
of gas per day.  The Company also owns an interest in 80 gross (1.7 net)
nonoperated wells.

     Discovered in 1950, the Prentice Field produces from carbonate reservoirs
in the Clear Fork and Glorieta formations at depths ranging from 6,000 to 7,000
feet.  The Prentice Field has been separated into several waterflood units for
secondary recovery operations.  The Prentice Northeast Unit was formed in 1964
with waterflood operations commencing a year later.  Development potential
exists through infill drilling and improvement of waterflood efficiency.
Tertiary recovery potential also exists through carbon dioxide flooding.

     During 1997, the Company drilled 31 gross (28.4 net) development wells in
the Prentice Northeast Unit. Twenty-four of these wells were 10-acre infill
wells and the remaining seven wells were strategically located to extend the
prospective area for infill development in the central and northern portion of
the Unit.  The Company plans to drill a total of up to 25 wells during 1998
depending upon oil prices.

     Russell Field.  The Russell Field is located in Gaines County, Texas.  The
Company owns an interest in 25 gross (23.4 net) wells that it operates and 137
gross (42.6 net) wells operated by others.  Current net daily oil and gas
production is approximately 900 Bbls and 470 Mcf.

     The Russell Field, discovered in 1943, produces from the San Andres,
Glorieta, Middle Clear Fork and Devonian formations at depths ranging from 4,800
to 10,800 feet.  Exploitation potential exists through restimulations,
recompletions, infill drilling, and the implementation of secondary recovery
operations in the Middle Clear Fork and San Andres formations.

     Ozona Area.  The Company acquired interests in 1996 in the Henderson,
Ozona, and Davidson Ranch fields located in Crockett County, Texas.  The Company
has interests in 111 gross (64.9 net) wells that it operates and 133 gross (27.5
net) wells operated by others.  Current net daily production is approximately
11.3 MMcf and 58 Bbls.

     Oil and gas were first discovered in the Ozona area in 1962.  Production is
from the Pennsylvanian Canyon sandstones and Strawn carbonates at depths ranging
from 6,500 to 9,000 feet.  Development potential for this area

                                       5
<PAGE>

includes infill drilling, field extension and delineation drilling, and the
possibility of horizontal drilling in the Strawn Formation.

     During 1997, the Company drilled a total of 23 gross (15.4 net) operated
wells and participated in 14 gross (2.3 net) wells operated by others, making it
one of the Company's most active gas development areas.  The Company plans to
drill or participate in drilling a total of 34 wells during 1998.

     University Block 9.  The University Block 9 Field is located in Andrews
County, Texas.  The Company owns a 100% working  interest in 55 wells that it
operates.  Current net daily production is approximately 2,570 Bbls of oil and
2,160 Mcf of gas.

     The University Block 9 Field was discovered in 1953. Productive zones are
of Wolfcamp, Pennsylvanian, and Devonian age at 8,400, 8,700 and 10,400 feet,
respectively.  The Company operates the Wolfcamp Unit, Penn Unit, and 23 of the
24 active Devonian wells.  Development potential includes proper wellbore
utilization, recompletions, infill drilling and improvement of waterflood
efficiency.

     This field was one of the Company's most active oil development areas
during 1997, where the Company drilled 16 wells, 6 of which were in the process
of drilling at year-end.  During 1998, the Company plans to drill up to 20 wells
depending upon oil prices.

MID-CONTINENT AREA

     Major County Area.  The Company is one of the largest producers in the
Ringwood, Northwest Okeene and Cheyenne Valley fields in Major County, Oklahoma.
The Company operates 451 gross (389.4 net) wells and has an interest in 202
gross (45.8 net) wells operated by others.  Current net daily oil and gas
production is approximately 1,050 Bbls and 33,300 Mcf.

     Oil and gas were first discovered in the Major County area in 1945. The
fields in the Major County area are located in the Anadarko Basin and are
characterized by oil and gas production from a variety of structural and
stratigraphic traps.  Productive zones range from 6,500 to 9,400 feet and
include the Oswego, Red Fork, Chester, Manning, Mississippian, Hunton and
Arbuckle formations.

     The Company develops the Major County area primarily through mechanical
improvements, restimulations, recompletions to shallower zones and development
drilling.  During 1997, the Company participated in the drilling of 32 gross
(24.8 net) wells in the western portion of the County, targeted at the
Mississippian and Chester formations. The Company has budgeted 24 wells in Major
County for 1998.

     A subsidiary of the Company operates a gathering system and pipeline in the
Major County area.  The gathering system collects gas from 425 wells through 300
miles of pipeline in the Major County area.  The gathering system has current
throughput of approximately 28,500 Mcf per day, 70% of which is produced from
Company-operated wells.  Estimated capacity of the gathering system is 40,000
Mcf per day.  Gas is delivered to a processing plant owned and operated by a
third party, and then transmitted by a 26-mile Company-operated pipeline to
connections with other pipelines.

     Since 1994, the Company has operated its Major County gathering system.
Through its direct maintenance and management, the Company has achieved
operating cost reductions and improved reliability.  During 1994 and 1995, the
gathering system was converted from centralized to field compression through the
installation of four field compression stations.  Field compression has allowed
the system to operate more efficiently and to expand into previously
inaccessible areas.

     Elk City Field.  The Elk City Field is located in Beckham and Washita
Counties of western Oklahoma.  The Company operates the Elk City Unit with 35
gross (31.6 net) wells and owns an interest in 9 gross (1.5 net) wells operated
by others.  Current net production of the Elk City Field is approximately 160
Bbls of oil and 4,500 Mcf of gas per day.


                                       6
<PAGE>

     The Elk City Field was discovered in 1947 and has been extensively
developed.  Production is from the Hoxbar (9,500 feet), Atoka (13,100 feet) and
Morrow (15,500 feet) zones.  The Company's primary development activities in
this field have been to initiate mechanical efficiencies and to recomplete
additional productive intervals. Recompletions and zone isolations have been
successful and additional opportunities for these types of workovers remain in
the field.  Recent recompletions to the Atoka Formation have resulted in
significant reserve additions.  There are several other deep wellbores with
similar recompletion potential.

HUGOTON AREA

     The Hugoton Field, discovered in 1922, covers parts of Texas, Oklahoma and
Kansas and is the largest gas field in the United States.  It is estimated that
5 million productive acres exist in the entire field.  The Company owns an
interest in 390 gross (365.9 net) wells that it operates and 84 gross (18.8 net)
wells operated by others.  Current net production averages approximately 35,900
Mcf of gas per day and 125 Bbls of oil per day.

     Approximately 70% of the Company's Hugoton gas production is delivered to
the Tyrone Plant, a gas processing plant operated by the Company.  In May 1996,
the Company completed the installation of a field compressor on the southern end
of the Tyrone gathering system.  This unit compresses gas from 45 wells, 39 of
which are owned by the Company, and has resulted in a significant production
increase.  The Company also completed the installation and start-up of a residue
compressor and 11.5 miles of high pressure residue pipeline during August 1996.
The installation of these facilities allows the Company to operate the Tyrone
Plant more efficiently and allows access to three additional interstate
pipelines.

     While much of the Kansas portion of the Hugoton Field has been infill
drilled on 320-acre spacing, the Company believes that there are up to 40
additional potential infill drilling locations.  The Oklahoma portion is drilled
on 640-acre spacing.  The Company believes that there are approximately 200
potential infill drilling locations, subject to regulatory approval and possibly
new legislation being enacted in Oklahoma.

     During 1997, the Company drilled 18 gross (12.1 net) wells to the Chester,
Council Grove and Chase formations.  The Company plans to drill 12 wells during
1998.

ROCKY MOUNTAIN AREA

     San Juan Basin.  The San Juan Basin of northwestern New Mexico and
southwestern Colorado contains the largest reserves of natural gas in the Rocky
Mountains and, within the United States, is second in size only to the Hugoton
Field.  The Company acquired most of its interests in the San Juan Basin in
December 1997 from Amoco Corporation.  The Company owns an interest in 616 gross
(498 net) wells that it operates and 974 gross (177.2 net) wells operated by
others.  Of these wells, 60 gross (49.8 net) operated wells and 20 gross (3.6
net) non-operated wells are dual completions.  Current net daily production
averages approximately 39,000 Mcf of gas, 230 Bbls of oil and 2,500 Bbls of
natural gas liquids.

     The Company has identified 139 infill wellsites, primarily in the Dakota
and Fruitland Coal formations, relating to 8.6 million BOE of proved undeveloped
reserves that the Company expects will require approximately $17.3 million to
drill and complete.  In addition, the Company plans to evaluate more than 150
potential infill wellsites over the next year.  The Company plans to drill 20
operated wells during 1998.

     Green River Basin.  The Green River Basin is located in southwestern
Wyoming.  The Company has interests in 147 gross (137.3 net) wells that it
operates and 48 gross (8.2 net) wells operated by others in the Fontenelle,
Nitchie Gulch and Pine Canyon fields.  Current net daily production is
approximately 28,100 Mcf of gas and 60 Bbls of oil.

     Gas production was discovered in the Fontenelle area in the early 1970's.
The producing reservoirs are the Cretaceous Frontier and Dakota sandstones at
depths ranging from 7,500 to 10,000 feet.  Exploitation potential for the fields
in this area include restimulations, recompletions and development drilling.

     During 1997, the Company drilled 32 gross (29 net) wells in the Fontenelle
Unit.  The Company plans to drill approximately 15 wells during 1998.


                                       7
<PAGE>

     During 1997, the Company also installed additional field compression to
lower overall field operating pressures and to improve overall field
performance.  The Company also completed an interconnect to another pipeline in
the southeastern part of the Fontenelle field that added an additional market
for the gas.

RESERVES

     The following are estimated quantities of proved reserves and cash flows
therefrom as of December 31, 1997, 1996 and 1995:
<TABLE>
<CAPTION>
                                                         December 31
                                                --------------------------------
                                                   1997        1996      1995
                                                ----------  ---------  ---------
                                                         (in thousands)
<S>                                             <C>        <C>        <C>
        Proved developed:
          Oil (Bbls)..........................      33,835      31,883    28,946
          Gas (Mcf)...........................     677,710     466,412   320,230
          Natural gas liquids (Bbls)..........      11,494           -         -
        Proved undeveloped:
          Oil (Bbls)..........................      14,019      10,557    11,042
          Gas (Mcf)...........................     138,065      74,126    37,840
          Natural gas liquids (Bbls)..........       2,316           -         -
        Total proved:
          Oil (Bbls)..........................      47,854      42,440    39,988
          Gas (Mcf)...........................     815,775     540,538   358,070
          Natural gas liquids (Bbls)..........      13,810           -         -
        Estimated future net cash flows:
             Before income tax................  $1,484,542  $1,737,024  $712,907
             After income tax.................  $1,193,167  $1,286,037  $581,888
        Present value of estimated future
          net cash flows, discounted at 10%:
             Before income tax................  $  782,322  $  946,150  $405,706
             After income tax.................  $  642,109  $  706,481  $335,156
</TABLE>

     Miller and Lents, Ltd. ("Miller and Lents"), an independent petroleum
engineering firm, prepared the estimates of the Company's proved reserves and
the future net cash flow (and present value thereof) attributable to proved
reserves at December 31, 1997, 1996 and 1995.  As prescribed by the Securities
and Exchange Commission, such proved reserves were estimated using oil and gas
prices and production and development costs as of December 31 of each such year,
without escalation.  See Note 12 to Consolidated Financial Statements for
additional information regarding estimated proved reserves.

     There are numerous uncertainties inherent in estimating quantities of
proved reserves, including many factors beyond the control of the Company.
Reserve engineering is a subjective process of estimating subsurface
accumulations of oil and gas that cannot be measured in an exact manner, and the
accuracy of any reserve estimate is a function of the quality of available data
and the interpretation thereof.  As a result, estimates by different engineers
often vary, sometimes significantly.  In addition, physical factors such as the
results of drilling, testing and production subsequent to the date of an
estimate, as well as economic factors such as change in product prices, may
justify revision of such estimates.  Accordingly, oil and gas quantities
ultimately recovered will vary from reserve estimates.

     During 1997, the Company filed estimates of oil and gas reserves as of
December 31, 1996 with the U.S. Department of Energy on Form EIA-23.  These
estimates are consistent with the reserve data reported in Note 12 to
Consolidated Financial Statements for the year ended December 31, 1996, with the
exception that Form EIA-23 includes only reserves from properties operated by
the Company.

                                       8
<PAGE>

EXPLORATION AND PRODUCTION DATA

     For the following data, "gross" refers to the total wells or acres in which
the Company owns a working interest and "net" refers to gross wells or acres
multiplied by the percentage working interest owned by the Company. Although
many of the Company's wells produce both oil and gas, a well is categorized as
an oil well or a gas well based upon the ratio of oil to gas production.

Producing Wells

     The following table summarizes the Company's producing wells as of December
31, 1997, all of which are located in the United States:
<TABLE>
<CAPTION>

                           Operated Wells       Non-Operated Wells        Total (a)
                        --------------------  ---------------------  --------------------
                           Gross      Net       Gross        Net       Gross       Net
                        ---------- ---------  ---------- ----------  ---------  ---------
<S>                    <C>         <C>         <C>       <C>         <C>        <C>
  Oil................        608      552.3       3,139       186.9      3,747      739.2
  Gas................      1,705    1,447.5       1,566       296.3      3,271    1,743.8
                           -----    -------       -----       -----      -----    -------
  Total..............      2,313    1,999.8       4,705       483.2      7,018    2,483.0
                           =====    =======       =====       =====      =====    =======
</TABLE>
  (a) One gross (1 net) oil well and 79 gross (52.4 net) gas wells are dual
      completions.


Drilling Activity

     The following table summarizes the number of development wells drilled by
the Company during the years indicated.  As of December 31, 1997, the Company
was in the process of drilling 29 gross (19.7 net) wells.
<TABLE>
<CAPTION>

                                         Year Ended December 31
                        ----------------------------------------------------------
                               1997               1996                1995
                        -----------------  -------------------  ------------------
                         Gross      Net      Gross      Net       Gross      Net
                        -------- --------  ---------  --------  --------  --------
<S>                     <C>      <C>      <C>        <C>        <C>      <C>
  Development wells:
   Completed as-
     Oil wells........     82         53.4     92        45.5        71      17.3
     Gas wells........    119         85.9     70        38.1        24      16.8
   Non-productive.....      5          3.2      4         2.7         2       1.1
                          ---        -----   ----        ----        --      ----
   Total..............    206        142.5    166        86.3        97      35.2
                          ---        -----   ----        ----        --      ----

  Exploratory wells:
   Completed as-
     Gas wells........      2          0.6      -           -         -         -
   Non-productive.....      1          0.1      -           -         -         -
                          ---        -----   ----        ----        --      ----
   Total..............      3          0.7      -           -         -         -
                          ---        -----   ----        ----        --      ----
  Total (a)...........    209        143.2    166        86.3        97      35.2
                          ===        =====   ====        ====        ==      ====

</TABLE>
  (a) Included in totals are 57 gross (6.9 net), 85 gross (10.4 net) and 61
      gross (3.2 net) wells drilled on nonoperated interests in 1997, 1996 and
      1995, respectively. Excluded from above totals are 21 gross (0.4 net) and
      31 gross (0.6 net) carbon dioxide wells drilled on non-operated interests
      in 1996 and 1995, respectively.

                                       9
<PAGE>

Acreage

     The following table summarizes developed and undeveloped leasehold acreage
in which the Company owns a working interest as of December 31, 1997.  Excluded
from this summary is acreage in which the Company's interest is limited to
royalty, overriding royalty and other similar interests.
<TABLE>
<CAPTION>

                       Developed (a)(b)             Undeveloped
                  ------------------------    -----------------------
                     Gross       Net             Gross      Net
                  -----------  -----------    ----------  -----------
<S>               <C>         <C>             <C>         <C>
    Oklahoma....     334,973      278,713            934          753
    Texas.......      98,143       60,997         23,834       12,917
    Kansas......      80,500       67,821              -            -
    New Mexico..     221,539       95,536          5,534        3,458
    Wyoming.....      43,811       31,144          1,360          990
    Other.......       8,929        6,493          7,072        4,644
                     -------      -------         ------       ------
    Total.......     787,895      540,704         38,734       22,762
                     =======      =======         ======       ======

</TABLE>
    (a) "Developed acres" are acres spaced or assignable to productive wells.
    (b) Certain leasehold acreage in Oklahoma and Texas is subject to a 75% net
        profits interest conveyed to the Royalty Trust.

Oil and Gas Sales Prices and Production Costs

     The following table shows the average sales prices per Bbl of oil
(including condensate), Mcf of gas and per Bbl of natural gas liquids produced
and the production costs and production and property taxes per barrel of oil
equivalent ("BOE," computed on an energy equivalent basis of 6 Mcf to 1 Bbl):
<TABLE>
<CAPTION>

                                             Year Ended December 31
                                             ----------------------
                                              1997    1996    1995
                                             ------  ------  ------
<S>                                          <C>     <C>     <C>
    Sales prices:..........................
      Oil (per Bbl)........................  $18.90  $21.38  $17.09
      Gas (per Mcf)........................  $ 2.20  $ 1.97  $ 1.42
      Natural gas liquids (per Bbl)........  $ 9.66       -       -

    Production costs per BOE...............  $ 3.54  $ 4.05  $ 4.26
    Production and property taxes per BOE..  $ 1.33  $ 1.23  $ 1.04

</TABLE>

DELIVERY COMMITMENTS

     The Company sells to a single purchaser approximately 10,000 Mcf of gas per
day through July 1998 and 11,650 Mcf of gas per day from August 1998 through
July 2005.  The Company has also entered contracts with two purchasers to sell a
total of 30,000 Mcf per day in March 1998 and 10,000 Mcf per day in April, May
and June 1998. Deliveries under these contracts are generally in Oklahoma, where
the Company's production and reserves are adequate to meet these sales
commitments.

     The Company has committed to sell up to 4,500 Mcf of gas per day to a
cogeneration facility under a take-or-pay contract that expires in September
2004. The Company generally purchases gas at market prices to fill this
commitment.


COMPETITION AND MARKETS

     The Company faces competition from other oil and gas companies in all
aspects of its business, including acquisition of producing properties and oil
and gas leases, marketing of oil and gas, and obtaining goods, services and
labor.  Many of its competitors have substantially larger financial and other
resources.  Factors that affect the

                                       10
<PAGE>

Company's ability to acquire producing properties include available funds,
available information about the property and the Company's standards established
for minimum projected return on investment. Because gathering systems are the
only practical method for the intermediate transportation of natural gas,
competition for natural gas delivery is presented by other pipelines and gas
gathering systems. Competition is also presented by alternative fuel sources,
including heating oil and other fossil fuels. Because of the long-lived nature
of the Company's oil and gas reserves and management's expertise in exploiting
these reserves, management believes that it is effective in competing in the
market.

     The Company's ability to market oil and gas depends on many factors beyond
its control, including the extent of domestic production and imports of oil and
gas, the proximity of the Company's gas production to pipelines, the available
capacity in such pipelines, the demand for oil and gas, the effects of weather,
and the effects of state and federal regulation.  The Company cannot assure that
it will always be able to market all of its production or obtain favorable
prices.  The Company, however, does not currently believe that the loss of any
of its oil or gas purchasers would have a material adverse effect on its
operations.

     Decreases in oil and gas prices have had, and could have in the future, an
adverse effect on the Company's acquisition and development programs, proved
reserves, revenues, profitability, cash flow and dividends.  See Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operations, "General - Product Prices."


FEDERAL AND STATE REGULATIONS

     There have been, and continue to be, numerous federal and state laws and
regulations governing the oil and gas industry that are often changed in
response to the current political or economic environment.  Compliance with this
regulatory burden is often difficult and costly and may carry substantial
penalties for noncompliance.  The following are some specific regulations that
may affect the Company.  The Company cannot predict the impact of these or
future legislative or regulatory initiatives.

Federal Regulation of Natural Gas

     The interstate transportation and sale for resale of natural gas is subject
to federal regulation, including transportation rates charged and various other
matters, by the Federal Energy Regulatory Commission ("FERC").  The Company's
gathering system and 26-mile pipeline have been declared exempt from FERC
jurisdiction, and therefore, the Company's gathering service is not regulated by
FERC.  Federal wellhead price controls on all domestic gas were terminated on
January 1, 1993.  The Company cannot predict the impact of government regulation
on any natural gas facilities.

     In 1992, FERC issued Orders Nos. 636 and 636-A, requiring operators of
pipelines to unbundle transportation services from sales services and allow
customers to pay for only the services they require, regardless of whether the
customer purchases gas from such pipelines or from other suppliers.  The United
States Court of Appeals upheld the unbundling provisions and other components of
FERC's orders but remanded several issues to FERC for further explanation.  On
February 27, 1997, FERC issued Order No. 636-C, addressing the Court's concern.
Petitions for rehearing on Order No. 636-C are pending.  FERC's order remains
subject to judicial review and may be changed as a result of that review.
Although FERC's regulations should generally facilitate the transportation of
gas produced from the Company's properties and the direct access to end-user
markets, the impact of these regulations on marketing the Company's production
or on its gas transportation business cannot be predicted.  The Company,
however, does not believe that it will be affected any differently than other
natural gas producers and marketers with which it competes.

Federal Regulation of Oil

     Sales of crude oil, condensate and natural gas liquids are not currently
regulated and are made at market prices.  The net price received from the sale
of these products is affected by market transportation costs.  A significant
part of the Company's oil production is transported by pipeline.  The Energy
Policy Act of 1992 required the FERC to adopt a simplified ratemaking
methodology for interstate oil pipelines.  In 1993 and 1994, the FERC issued
Order Nos. 561 and 561-A, adopting rules that establish new rate methods for
such pipelines.  Under the new rules, effective January 1, 1995, interstate oil
pipelines can change rates based on an inflation index, though other rate
mechanisms may be used

                                       11
<PAGE>

in specific circumstances. The United States Court of Appeals upheld FERC's
orders in 1996. The Company cannot predict the effect these rules may have on
the cost of moving oil to market.

State Regulation

     The oil and gas operations of the Company are subject to various types of
regulation at the state and local levels.  Such regulation includes requirements
for drilling permits, the method of developing new fields, the spacing and
operations of wells and waste prevention.  The production rate may be regulated
and the maximum daily production allowable from oil and gas wells may be
established on a market demand or conservation basis.  These regulations may
limit the Company's production from its wells and the number of wells or
locations the Company can drill.

     The Company may become party to agreements relating to the construction or
operations of pipeline systems for the transportation of natural gas.  To the
extent that such gas is produced, transported and consumed wholly within one
state, such operations may, in certain instances, be subject to the state's
administrative authority charged with regulating pipelines.  The rates the
Company could charge for gas, the transportation of gas, and the construction
and operation of such pipelines would be subject to the regulations governing
such matters.  Certain states have recently adopted regulations with respect to
gathering systems, and other states are considering regulations with respect to
gathering systems. New regulations passed have not had a material effect on the
operations of the Company's gathering systems, but the Company cannot predict
whether any further rules will be adopted or, if adopted, the effect these rules
may have on the Company's gathering systems.

Federal, State or Indian Leases

     The Company's operations on federal, state or Indian oil and gas leases are
subject to numerous restrictions, including nondiscrimination statutes.  Such
operations must be conducted pursuant to certain on-site security regulations
and other permits and authorizations issued by the Bureau of Land Management,
Minerals Management Service and other agencies.


ENVIRONMENTAL REGULATIONS

     Various federal, state and local laws regulating the discharge of materials
into the environment, or otherwise relating to the protection of the
environment, directly impact oil and gas exploration, development and production
operations, and consequently may impact the Company's operations and costs.
Management believes that the Company is in substantial compliance with
applicable environmental laws and regulations.  To date, the Company has not
expended any material amounts to comply with such regulations, and management
does not currently anticipate that future compliance will have a materially
adverse effect on the consolidated financial position or results of operations
of the Company.


EMPLOYEES

     The Company had 349 and 306 employees as of December 31, 1997 and 1996,
respectively.  None of the Company's employees are represented by a union.  The
Company considers its relations with its employees to be good.

                                       12
<PAGE>

EXECUTIVE OFFICERS OF THE COMPANY

     The officers of the Company are elected by and serve until their successors
are elected by the Board of Directors.

     BOB R. SIMPSON, 49, was a co-founder of the Company with Mr. Palko and has
been Chairman and Chief Executive Officer of the Company since July 1, 1996.
Prior thereto, Mr. Simpson served as Vice Chairman and Chief Executive Officer
or held similar positions with the Company since 1986.  Mr. Simpson was Vice
President of Finance and Corporate Development (1979-1986) and Tax Manager
(1976-1979) of Southland Royalty Company.

     STEFFEN E. PALKO, 47, was a co-founder of the Company with Mr. Simpson and
has been Vice Chairman and President or held similar positions with the Company
since 1986.  Mr. Palko was Vice President - Reservoir Engineering (1984-1986)
and Manager of Reservoir Engineering (1982-1984) of Southland Royalty Company.

     J. RICHARD SEEDS, 52, has been a director of the Company since July 1996
and has served as Executive Vice President since May 1997.  Mr. Seeds previously
was Career Guidance Counselor with the Springtown Independent School District
(1993-1997) and an independent personal investment manager (1986-1993).  Mr.
Seeds was Vice President of Finance and Controller (1979-1986) and Controller
(1977-1979) of Southland Royalty Company.

     LOUIS G. BALDWIN, 48, has been Senior Vice President and Chief Financial
Officer or held similar positions with the Company since 1986.  Mr. Baldwin was
Assistant Treasurer (1979-1986) and Financial Analyst (1976-1979) at Southland
Royalty Company.

     KEITH A. HUTTON, 39, has been Senior Vice President - Asset Development or
held similar positions with the Company since 1987.  From 1982 to 1987, Mr.
Hutton was a Reservoir Engineer with Sun Exploration & Production Company.

     BENNIE G. KNIFFEN, 47, has been Senior Vice President and Controller or
held similar positions with the Company since 1986.  From 1976 to 1986, Mr.
Kniffen held the position of Director of Auditing or similar positions with
Southland Royalty Company.

     LARRY B. MCDONALD, 51, has been Senior Vice President - Operations or held
similar positions with the Company since 1990.  Prior to that time, Mr. McDonald
owned and operated McDonald Energy, Inc. (1986-1990).

     TIMOTHY L. PETRUS, 43, has been Senior Vice President - Acquisitions or
held similar positions with the Company since 1988.  Prior to that time, Mr.
Petrus was a Vice President with Texas American Bank (1980-1988) and was a
Senior Project Engineer with Exxon (1976-1980).

     KENNETH F. STAAB, 41, has been Senior Vice President of Engineering or held
similar positions with the Company since 1986.  Prior to that time, Mr. Staab
was a Reservoir Engineer with Southland Royalty Company (1982-1986).

     THOMAS L. VAUGHN, 51, has been Senior Vice President - Operations or held
similar positions with the Company since 1988.  From 1986 to 1988, Mr. Vaughn
owned and operated Vista Operating Company.

     VAUGHN O. VENNERBERG II, 43, has been Senior Vice President - Land or held
similar positions with the Company since 1987.  Prior to that time, Mr.
Vennerberg was Land Manager with Hutton Gas Operating Company (1986-1987).

                                       13
<PAGE>

ITEM 3.  LEGAL PROCEEDINGS

     In June 1996, Holshouser v. Cross Timbers Oil Company, a class action
lawsuit, was filed in the District Court of Major County, Oklahoma.  The action
was filed on behalf of all parties who, at any time since June 1991, have
allegedly had production or other costs deducted by the Company from royalties
paid on gas produced in Oklahoma when the royalty is based upon a specified
percentage of the proceeds received from the gas sold.  The plaintiff alleges
that such deductions are a breach of the Company's contractual obligations to
the class and is seeking to recover an unspecified amount of damages as a result
of the alleged breach.  The plaintiff is also seeking a determination of the
Company's obligations to the plaintiff and the class regarding production or
other costs.  The Company has responded that it has complied with all of its
contractual obligations and denied that the matter is appropriate for
determination as a class action.  The parties have conducted discovery on the
class certification issues, but no further action has been taken in the case.
Management believes it has strong defenses against this claim and intends to
vigorously defend the action.  Management's estimate of the potential liability
from this claim has been accrued in the Company's financial statements.

     The Company and certain of its subsidiaries are involved in various other
lawsuits and certain governmental proceedings arising in the ordinary course of
business.  Company management and legal counsel do not believe that the ultimate
resolution of these claims, including the class action lawsuit described above,
will have a material effect on the Company's financial position, liquidity or
operations.


ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     No matters were submitted for a vote of security holders during the fourth
quarter of 1997.

                                       14
<PAGE>

                                    PART II
                                    -------

ITEM 5.  MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

     The Company's common stock is listed on the New York Stock Exchange and
trades under the symbol "XTO."  The following table sets forth quarterly high
and low sales prices and cash dividends declared for each quarter of 1997 and
1996 (as adjusted for the three-for-two stock splits effected on March 19, 1997
and February 25, 1998):
<TABLE>
<CAPTION>

                       High      Low    Dividends
                      -------  -------  ---------
<S>                   <C>      <C>      <C>
    1997
    First Quarter...  $13.719  $10.422      $.037
    Second Quarter..   13.750    9.828       .037
    Third Quarter...   16.375   12.328       .037
    Fourth Quarter..   19.125   13.297       .037

    1996
    First Quarter...  $ 8.328  $ 6.938      $.033
    Second Quarter..   11.438    7.563       .033
    Third Quarter...   12.781    8.500       .033
    Fourth Quarter..   11.891   10.000       .033
</TABLE>

     The determination of the amount of future dividends, if any, to be declared
and paid is in the sole discretion of the Company's Board of Directors and will
depend on the Company's financial condition, earnings and funds from operations,
the level of its capital expenditures, dividend restrictions in its financing
agreements, its future business prospects and other matters as the Board of
Directors deems relevant.  Furthermore, the Company's Revolving Credit Agreement
with banks restricts the amount of dividends to 25% of cash flow from operations
for the latest four consecutive quarterly periods.  The Company's 9 1/4% and 8
3/4% senior subordinated notes also place certain restrictions on distributions
to common shareholders, including dividend payments.

     On February 17, 1998, the Board of Directors declared a dividend of $.04
per share payable on April 15, 1998 to shareholders of record on March 31, 1998.
On March 2, 1998, the Company had 320 shareholders of record.

                                       15
<PAGE>

ITEM 6.  SELECTED FINANCIAL DATA

     The following table presents selected financial information for each of the
years, and as of year-end, in the five-year period ended December 31, 1997.
This information should be read in conjunction with Item 7, Management's
Discussion and Analysis, and the Consolidated Financial Statements at Item
14(a).
<TABLE>
<CAPTION>

                                                      1997         1996          1995          1994         1993
                                                  ------------  -----------  -------------  ----------  ------------
                                                    (in thousands except production, per share and per unit data)
<S>                                               <C>           <C>          <C>            <C>         <C>
CONSOLIDATED STATEMENT OF OPERATIONS DATA (a)
Revenues:.......................................
 Oil and condensate.............................    $  75,223    $  75,013      $  60,349    $ 53,324     $  39,747
 Gas and natural gas liquids....................      110,104       73,402         40,543      38,389        34,649
 Gas gathering, processing and marketing........        9,851       12,032          7,091       4,274         3,717
 Other..........................................        5,494          944          4,922         288            69
                                                    ---------    ---------      ---------    --------     ---------
 Total Revenues.................................    $ 200,672    $ 161,391      $ 112,905    $ 96,275     $  78,182
                                                    =========    =========      =========    ========     =========
Earnings (loss) available to common stock.......    $  23,905    $  19,790    $(10,538)(b)   $  3,048    $(4,012)(c)
                                                    =========    =========    ===========    ========    ==========
Per common share (d)
 Basic..........................................    $    0.60    $    0.50      $(0.28)(b)   $   0.09     $(0.12)(c)
                                                    =========    =========      =========    ========     =========
 Diluted........................................    $    0.59    $    0.48       (0.28)(b)   $   0.08     $(0.12)(c)
                                                    =========    =========      =========    ========     =========
Pro forma earnings (loss) (e)...................            -            -              -           -     $    (251)
                                                    =========    =========      =========    ========     =========
Per common share/unit-basic and diluted (d)(e)..            -            -              -           -     $   (0.01)
                                                    =========    =========      =========    ========     =========
Weighted average common shares/
 units outstanding..............................       39,773       39,913         38,072      35,829        32,682
                                                    =========    =========      =========    ========     =========
Dividends/distributions declared
  per common share/unit (f).....................    $    0.15    $    0.13      $    0.13    $   0.13     $    0.13
                                                    =========    =========      =========    ========     =========

CONSOLIDATED STATEMENT OF CASH FLOWS DATA (a)
Operating cash flow (g).........................    $  89,979    $  68,263      $  40,439    $ 37,816     $  27,925
Cash provided (used) by:
 Operating activities...........................    $  98,006    $  59,694      $  32,938    $ 42,293     $  32,209
 Investing activities...........................    $(311,322)   $(124,871)     $(160,416)   $(62,745)    $(104,789)
 Financing activities...........................    $ 213,195    $  66,902      $ 121,852    $ 26,232     $  70,332

CONSOLIDATED BALANCE SHEET DATA (a)
 Property and equipment, net....................    $ 723,836    $ 450,561      $ 364,474    $244,555     $ 228,551
 Total assets...................................    $ 788,455    $ 523,070      $ 402,675    $292,451     $ 258,019
 Long-term debt.................................    $ 539,000    $ 314,757      $ 238,475    $142,750     $ 111,750
 Owners' equity.................................    $ 170,243    $ 142,668      $ 130,700    $113,333     $ 115,168

OPERATING DATA (a)
Average daily production:.......................
 Oil (Bbls).....................................       10,905        9,584          9,677       9,497         6,968
 Gas (Mcf)......................................      135,855      101,845         78,408      58,182        51,260
 Natural gas liquids (Bbls).....................          220            -              -           -             -
 Barrels of oil equivalent (BOE)................       33,768       26,558         22,745      19,194        15,511

Average sales price:
 Oil (per Bbl)..................................    $   18.90    $   21.38      $   17.09    $  15.38     $   15.63
 Gas (per Mcf)..................................    $    2.20    $    1.97      $    1.42    $   1.81     $    1.85
 Natural gas liquids (per Bbl)..................    $    9.66            -              -           -             -

Production costs (per BOE)......................    $    3.54    $    4.05      $    4.26    $   4.62     $    5.16
Production and property taxes (per BOE).........    $    1.33    $    1.23      $    1.04    $   1.23     $    1.19

Proved reserves:
 Oil (Bbls).....................................       47,854       42,440         39,988      33,581        21,082
 Gas (Mcf)......................................      815,775      540,538        358,070     177,061       169,119
 Natural gas liquids............................       13,810            -              -           -             -
 Barrels of oil equivalent (BOE)................      197,627      132,530         99,666      63,091        49,269

OTHER DATA
Ratio of earnings to fixed charges (h)..........          2.2          2.6       (0.2) (i)        1.5           0.9

</TABLE>

                                       16
<PAGE>

(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 $20.3 million pre-tax, non-cash impairment charge
    recorded upon adoption of Statement of Financial Accounting Standards No.
    121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived
    Assets to Be Disposed Of.
(c) Includes effect of a one-time, non-cash accounting charge of $4 million for
    net deferred income tax liabilities recorded upon the merger of the Company
    with the former Partnership.
(d) Adjusted for the three-for-two stock splits effected on March 19, 1997 and
    February 25, 1998.
(e) As if all former Partnership income was subject to corporate income tax,
    exclusive of the charge in (c) above.
(f) Excludes non-recurring distributions of the former Partnership.
(g) Defined as cash provided by operating activities before changes in working
    capital.
(h) For purposes of calculating this ratio, earnings include income (loss) from
    continuing operations before income tax and fixed charges.  Fixed charges
    include interest expense, the portion of rentals (calculated as one-third)
    considered to be representative of the interest factor and preferred stock
    dividends.
(i) Includes effect of the charge in (b) above.  Excluding the effect of this
    charge, the ratio of earnings to fixed charges is 1.3.

                                       17
<PAGE>

ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
         OF OPERATIONS

GENERAL

     Cross Timbers Oil Company ("the Company") was organized in October 1990
to ultimately acquire the business and properties of predecessor entities that
were created from 1986 through 1989.  The Company completed its initial public
offering of common stock in May 1993.

     The Company follows the successful efforts method of accounting (see Note 1
to Consolidated Financial Statements).  As of October 1, 1995, the Company
adopted SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of, recording a pre-tax, non-cash impairment
charge of $20.3 million.  The Company has implemented the disclosure provisions
of SFAS No. 123, Accounting for Stock-Based Compensation, but continues to
record compensation of stock-based awards using Accounting Principles Board
Opinion No. 25, Accounting for Stock Issued to Employees.  As of December 31,
1997, the Company adopted SFAS No. 128, Earnings Per Share, which requires that
basic and diluted earnings per share be reported for all periods.  In June 1997,
the Financial Accounting Standards Board issued SFAS No. 130, Reporting of
Comprehensive Income, and SFAS No. 131, Disclosures About Segments of an
Enterprise and Related Information.  The Company will be required to comply with
the provisions of these statements in its 1998 financial statements.  The
Company has not assessed the effect that these new standards will have on its
consolidated financial statements and/or disclosures.

     In addition to the adoption of accounting principles described above, the
following events affect the comparative results of operations and/or financial
condition for the years ended December 31, 1997, 1996 and 1995, and/or may
impact future operations and financial condition.  Throughout Management's
Discussion and Analysis of Financial Condition and Results of Operations,
references to barrels of oil equivalent ("BOE") refer to quantities of
production for the indicated period (with gas quantities converted to barrels on
an energy equivalent ratio of six Mcf to one barrel).

Three-for-Two Stock Splits.  The Company effected a three-for-two stock split on
March 19, 1997, and on February 25, 1998.  All common stock shares, treasury
stock shares and per share amounts have been retroactively restated to reflect
both stock splits.

1998 Acquisition.  On February 25, 1998, the Company announced it had entered
into a definitive agreement with EEX Corporation to acquire producing properties
and undeveloped acreage in East Texas.  The transaction is expected to close in
late April 1998 with an effective date of January 1, 1998 and to be financed
through bank lines of credit.  After purchase price adjustments, the preliminary
purchase price of $265 million is expected to be reduced to $245 million.

1997 Acquisitions.  During 1997, the Company acquired predominantly gas-
producing properties for a total cost of $256 million.  The Amoco Acquisition,
the largest of these acquisitions, closed December 1, 1997 for an estimated
adjusted purchase price of $195 million, including $5.7 million for five-year
warrants to purchase 937,500 shares of the Company's common stock at $15.31 per
share, and consisted of producing oil and gas properties in the San Juan Basin
of New Mexico.  On May 14, 1997, the Company acquired primarily gas-producing
properties in Oklahoma, Kansas and Texas for an estimated adjusted purchase
price of $39 million from a subsidiary of Burlington Resources, Inc.  During
1997, the Company acquired an additional 6% of the publicly traded outstanding
units of beneficial interest in Cross Timbers Royalty Trust, at a cost of $5.4
million.  These 1997 acquisitions were primarily funded by bank borrowings and
cash flow from operations (see "Liquidity and Capital Resources-Financing"
below).  See Note 10 to Consolidated Financial Statements.

1996 Acquisitions.  In 1996, the Company acquired primarily gas-producing
properties for a total cost of $106 million. The Enserch Acquisition, the
largest of these acquisitions, closed in July 1996 at a cost of $39.4 million
and primarily consisted of operated interests in the Green River Basin of
southwestern Wyoming.  In November 1996, the Company acquired additional
interests in the Fontenelle Unit, the most significant property included in the
Enserch Acquisition, at a cost of $12.5 million.  In December 1996, the Company
acquired primarily operated interests in gas-producing properties in the Ozona
area of the Permian Basin of West Texas for $28.1 million.  From July through
December 1996, the Company acquired 16% of the publicly traded outstanding units
of beneficial interest in Cross Timbers Royalty Trust at a total cost of $12.8
million.  These 1996 acquisitions were primarily funded by bank borrowings. See
Note 10 to Consolidated Financial Statements.

                                       18
<PAGE>

1995 Acquisitions.  During 1995, the Company acquired predominantly gas-
producing properties for a total cost of $131 million, and a gas processing
plant and gathering facility for $29 million.  The Santa Fe Acquisition, the
largest of these acquisitions, closed on August 1, 1995 and consisted of mostly
operated properties and related facilities in the Hugoton Field of Kansas and
Oklahoma.  The 1995 acquisitions were primarily funded by bank borrowings and
proceeds from the 1995 common stock offering and asset sales.  See Note 10 to
Consolidated Financial Statements.

1997, 1996 and 1995 Development and Exploration Programs.  During 1997, the
Company drilled 60 oil and 109 gas wells and completed 100 recompletions and
workovers.  During 1996, the Company drilled 48 oil wells and 52 gas wells and
completed 125 recompletions and workovers.  In 1995, the Company drilled 40
wells and performed 61 recompletions and workovers.  Oil development was
concentrated in the Prentice Northeast Unit of West Texas during these three
years, as well as the University Block 9 Field during 1997.  Gas development
focused on the Ozona Field of West Texas in the last half of 1997, the
Fontenelle Unit of southwestern Wyoming during 1997 and 1996 and Major County,
Oklahoma during 1996 and 1995.  Exploration activity during 1997 was primarily
geological and geophysical analysis, including seismic, of undeveloped
properties at total cost of $2.1 million. Exploration activity was concentrated
in Cleveland and Texas counties of Oklahoma, Henderson County, Texas, Lea
County, New Mexico and the Illinois Basin.  Exploratory expenditures were
insignificant in 1996 and 1995.

1998 Development and Exploration Program.  The Company has budgeted $70 to $90
million for its 1998 development and exploration program which is expected to be
funded primarily by cash flow from operations.  Exploration expenditures are
expected to be 10% to 15% of the 1998 budget.  The total capital budget,
including acquisitions, will be adjusted throughout 1998 to capitalize on
opportunities offering the highest rates of return.

1997 Senior Subordinated Notes.  The Company sold $125 million of 9 1/4% senior
subordinated notes on April 2, 1997 and $175 million of 8 3/4% senior
subordinated notes on October 28, 1997.  Net proceeds of $121.1 million and
$169.9 million from the 9 1/4% Notes and 8 3/4% Notes, respectively, were used
to reduce bank borrowings under the loan agreement.  See Note 2 to Consolidated
Financial Statements.

1997 and 1996 Conversion of Subordinated Notes.  During November and December
1996, $27.7 million principal of the Company's 5 1/4% convertible subordinated
notes was converted by noteholders into 2,696,521 shares of common stock.  In
January 1997, the remaining principal of $29.7 million was converted by
noteholders into 2,892,363 shares of common stock and $29,000 was redeemed.

1996 Preferred Stock Exchange.  In September 1996, pursuant to the Company's
exchange offer, a total of 2,979,249 shares of common stock were exchanged for
1,138,729 shares of Series A convertible preferred stock.  See Note 5 to
Consolidated Financial Statements.

1995 Common Stock Offering.  In August 1995, the Company sold 5,062,500 shares
of common stock.  The net proceeds of $29.5 million from this offering were used
to partially fund the Santa Fe Acquisition.

1997 and 1996 Treasury Stock Purchases.  As part of its 1997 and 1996 strategic
acquisition plans, the Board of Directors has authorized the purchase of a total
of 7.5 million shares of the Company's common stock.  During 1997 and 1996, the
Company purchased 2.4 million and 2.9 million shares of common stock on the open
market at a total cost of $28 million and $30.7 million, respectively.  An
additional 484,000 shares have been purchased through March 20, 1998 at a cost
of $7.5 million.  These purchases were primarily funded by bank borrowings.  As
of March 20, 1998, 1.7 million treasury shares remain available to purchase.

Investment in Equity Securities.  During 1997 and 1996, the Company acquired
less than 5% of two publicly traded independent oil and gas producers at a total
cost of $6.5 million and $16.1 million, respectively.  During 1997, the Company
sold its investment in equity securities at a gain of $2.4 million.  The Company
realized a gain of $1.6 million upon the sale of an investment in equity
securities during 1995.

Property Sales.  In 1997, 1996 and 1995, sales of producing properties resulted
in net gains of $1.8 million, $500,000 and $3 million, respectively.

                                       19
<PAGE>

Stock Incentive Compensation.  Stock incentive compensation includes stock
appreciation right ("SAR") compensation and performance share compensation, and
is the result of these stock awards and subsequent increases in the Company's
stock price.  See Note 9 to Consolidated Financial Statements.  During 1997,
stock incentive compensation totaled $3.7 million, which included SAR
compensation of $400,000 (cash payments of $300,000) and non-cash performance
share compensation of $3.3 million.  In 1996, stock incentive compensation
totaled $6.2 million, which included SAR compensation of $3.7 million (cash
payments of $7.1 million, partially offset by prior accruals) and non-cash
performance share compensation of $2.5 million.  During 1995, stock incentive
compensation totaled $5.1 million, which included SAR compensation of $2.3
million (cash payments of $800,000) and non-cash performance share compensation
of $2.8 million.  Exercises and forfeitures under the 1991 Stock Incentive Plan
have reduced outstanding stock incentive units (including SARs) from 836,000 at
year-end 1995 to 51,000 at year-end 1996, and 25,000 at year-end 1997.

Extraordinary Item.  During 1995, the Company recognized an extraordinary gain
of $700,000 (net of income tax of $300,000) as a result of the purchase and
early retirement of $8.3 million principal amount of the Company's 5 1/4%
convertible subordinated notes.  In 1996, the Company redeemed, purchased and
retired a total of $9 million principal amount of the notes at a loss before
income tax of $400,000.  This loss was not presented as an extraordinary item
because it was not material to 1996 earnings.

Product Prices.  Oil and gas prices are affected not only by supply and demand
factors, but are also subject to substantial seasonal, political and other
fluctuations that are generally beyond the ability of the Company to control or
predict.

     Crude oil prices are generally affected by global politics and supply,
particularly among OPEC members.  The average posted per barrel price of West
Texas Intermediate ("WTI") oil, a benchmark crude, was $18.63, $20.45 and $16.77
in 1997, 1996 and 1995, respectively.  Despite the anticipation of and eventual
resumption of Iraqi exports, oil prices reached their highest levels since the
1990 Persian Gulf War during fourth quarter 1996 and January 1997. After demand
slightly outpaced supply in January 1997, the crude oil market remained in
balance during most of the year, supporting prices in the range of $17 to $20
per barrel, before sliding to an average posted WTI price of $16.18 in December.
Further declines in 1998 have resulted in an average posted WTI price of $14.22
for January and February. The recent weakening in oil prices is due to increased
OPEC production following its November 1997 decision to increase quotas, as well
as increased non-OPEC production from the North Sea and Latin America. The price
decline has also been attributed to mild winters in the U.S. and Europe and the
sudden drop in demand from depressed economies in the Far East. After hitting a
decade low of $11.00, prices in late March 1998 began to increase upon news that
some of the major oil exporting countries planned to meet regarding curtailment
of production. Based on 1997 production, the Company estimates that a $1.00 per
barrel increase or decrease in the average oil sales price would result in
approximately a $3.8 million change in 1998 annual income before income tax.

     Natural gas prices are generally influenced by national and regional supply
and demand, which is often dependent upon the weather.  Specific gas prices are
also based on the location of production, pipeline capacity, gathering charges
and the energy content of the gas.  Throughout most of 1995, gas prices were
relatively weak, primarily because of unseasonably warm weather.  Gas prices
increased in fourth quarter 1995 and continued their upward spiral through
February 1996 because of low storage levels and colder than expected weather.
Generally because of colder weather, storage concerns and U.S. economic growth,
prices remained relatively high during most of 1996 and 1997, reaching their
highest levels since 1985.  Gas prices declined, however, in December 1997 and
have remained lower in first quarter 1998, primarily because of an abnormally
mild winter in the central and eastern U.S. and elevated storage levels.
Despite continued growth in domestic demand, 1998 gas prices will largely depend
on the weather, gas storage levels, increased supplies resulting from domestic
exploration and Canadian imports, and price competition from other energy
sources.  Based on 1997 production, the Company estimates that a $0.10 per Mcf
increase or decrease in the average gas sales price would result in
approximately a $4.5 million change in 1998 annual income before income tax.
See Note 6 to Consolidated Financial Statements regarding commodity price
hedging instruments the Company has entered to reduce its exposure to gas price
fluctuations.

                                       20
<PAGE>

RESULTS OF OPERATIONS

1997 COMPARED TO 1996

     Earnings available to common stock for 1997 were $23.9 million as compared
with $19.8 million for 1996. This significant improvement in earnings was the
result of higher gas prices and increased gas production from the 1996 and 1997
acquisitions and development programs.  Results for 1997 and 1996 included the
effects of stock incentive compensation of $3.7 million and $6.2 million,
respectively.  Also included in 1997 results were net gains on sale of
properties and equity securities of $1.8 million and $2.4 million, respectively,
and lawsuit settlement proceeds of $1.3 million.  A $500,000 gain on sale of
properties was included in 1996 results.  Earnings for 1997 and 1996 were
reduced by dividends of $1.8 million and $500,000, respectively, on preferred
stock issued in September 1996.

     Revenues for 1997 were $200.7 million, or 24% above 1996 revenues of $161.4
million.  Oil revenue remained constant as a 13% increase in oil production was
offset by a 12% decrease in oil prices from an average of $21.38 in 1996 to
$18.90 in 1997 (see "General-Product Prices" above).  Increased production was
primarily because of the 1997 acquisitions and development programs.

     Gas revenue increased $36.7 million or 50% because of a 33%  increase in
production combined with a 12% price increase (see "General-Product Prices"
above).  Increased gas production was attributable to the 1996 and 1997
acquisitions and development programs.  Gas revenues for 1997 also included
$800,000 from San Juan Basin natural gas liquids production attributable to the
December 1997 Amoco Acquisition.

     Gas gathering, processing and marketing revenues decreased $2.2 million
primarily because of a decrease in margin and gas volumes.  Other revenues
increased $4.6 million primarily because of increased net gains on sale of
properties and equity securities and lawsuit settlement proceeds received in
1997.

     Expenses for 1997 totaled $161.5 million as compared with total 1996
expenses of $130.4 million.  All expenses other than general and administrative
expense increased in 1997 primarily because of the 1996 and 1997 acquisitions
and exploration and development programs.

     Production expense increased $4.2 million or 11%.  Per BOE, production
expense decreased from $4.05 to $3.54.  This decrease is primarily because of
the lower operating costs of gas-producing properties acquired in 1996 and 1997,
the timing of workovers, increasing production without comparable increases in
lifting costs and other operating efficiencies initiated after acquiring
operated properties.  Exploration expense for 1997 totaled $2.1 million, and
were predominantly geological and geophysical costs related to the 1997
exploration program.  Exploration costs in 1996 and prior were included in
production expense since not significant.

     Taxes on production and property increased 37% or $4.5 million because of
increased oil and gas revenues, as well as increased property taxes related to
the 1996 and 1997 acquisitions.  Taxes on production and property per BOE
increased 8% from $1.23 to $1.33 because of increased gas prices and higher
property tax rates.

     Depreciation, depletion and amortization ("DD&A") increased $9.9 million,
or 26%, primarily because of the 1996 and 1997 acquisitions and development
programs.  On a BOE basis, DD&A decreased slightly from $3.89 in 1996 to $3.87
in 1997.

     General and administrative expense decreased $602,000, or 4%, because of a
$2.5 million decrease in stock incentive compensation, partially offset by
increased expenses from Company growth.  Excluding stock incentive compensation,
general and administrative expense per BOE was $0.99 in 1997 as compared to
$1.04 in 1996.

     Gas gathering and processing expense increased $1.6 million or 23%.  This
increase was primarily because of rental expense related to the Tyrone plant and
gathering system lease that began in March 1996 and the Major County, Oklahoma
gathering system lease that began in November 1996.  This increase offsets
related decreases in DD&A and interest.

     Interest expense increased $9.6 million or 56% because of a 36% increase in
weighted average borrowings to partially fund the 1996 and 1997 acquisitions and
purchases of treasury stock, combined with a 20% increase in the

                                       21
<PAGE>

weighted average interest rate. Weighted average principal outstanding during
1997 was $351 million at an average interest rate of 7.6% compared with weighted
average principal of $259 million at 6.4% for 1996. Interest expense per BOE
increased from $1.76 in 1996 to $2.16 in 1997 primarily as the result of an
increase in the weighted average interest rate (primarily attributable to the
senior subordinated notes sold in April and October 1997), as well as the result
of financing expenditures for other than oil and gas producing properties
(investment in equity securities and treasury stock purchases) with bank and
other short-term borrowings.

1996 COMPARED TO 1995

     Earnings available to common stock for 1996 were $19.8 million as compared
to a net loss of $10.5 million for 1995.  Significantly improved results were
because of higher oil and gas prices and increased gas production from the 1995
and 1996 acquisitions and development programs.  Additionally, 1995 results
included a $20.3 million, pre-tax, non-cash impairment charge recorded upon
adoption of SFAS 121.  Results for 1996 and 1995 included the effects of stock
incentive compensation of $6.2 million and $5.1 million, respectively.  Also
included in 1995 results were net gains on sale of properties and equity
securities of $3 million and $1.6 million, respectively, and a $700,000
extraordinary gain on the Company's purchase and retirement of a portion of its
convertible subordinated notes. Earnings for 1996 have been reduced by dividends
of $500,000 on preferred stock that was issued in September 1996.

     Revenues for 1996 were $161.4 million, or 43% above 1995 revenues of $112.9
million.  Oil revenue increased $14.7 million or 24% primarily because of a 25%
increase in oil prices from an average of $17.09 in 1995 to $21.38 in 1996 (see
"General- Product Prices" above).  The Company's 1996 average oil price was
above the average WTI price of $20.45 because of improved oil marketing margins.
Oil production declined 1% from 1995 to 1996 primarily because of property sales
and natural decline, largely offset by the effects of the 1995 and 1996
acquisitions and development programs.

     Gas revenue increased $32.9 million or 81% because of a 39% price increase
(see "General- Product Prices" above) combined with a 30% increase in
production.  Increased gas production was attributable to the 1995 and 1996
acquisitions and development programs.

     Gas gathering, processing and marketing revenues increased $4.9 million
primarily because of revenues from the gas processing plant and gathering
facility acquired as part of the Santa Fe Acquisition on August 1, 1995.  Other
revenues decreased $4 million primarily because of net gains on sale of
properties and equity securities in 1995.

     Expenses for 1996 totaled $130.4 million as compared with total 1995
expenses of $129.9 million.  Expenses for 1995 included the $20.3 million
impairment charge recorded upon adoption of SFAS No. 121 in October 1995. All
expenses other than impairment increased in 1996 primarily because of the 1995
and 1996 acquisitions.

     Production expense increased $4 million or 11%.  Per BOE, production
expense decreased from $4.26 to $4.05.  This decrease is primarily because the
1995 and 1996 acquisitions were predominantly gas-producing properties that
generally have lower production costs per BOE.

     Taxes on production and property increased 38% or $3.3 million because of
increased oil and gas revenues. Taxes on production and property per BOE
increased 18% from $1.04 to $1.23 primarily because of higher oil and gas
prices.

     Depreciation, depletion and amortization ("DD&A") increased $1 million, or
3%, primarily because of the 1995 and 1996 acquisitions and development
programs.  On a BOE basis, DD&A decreased from $4.44 in 1995 to $3.89 in 1996.
Decreased DD&A per BOE is the result of increased proved reserve estimates at
January 1, 1996, reduced depletable costs resulting from the SFAS 121 provision
recorded in fourth quarter 1995, and the sale and operating leaseback of the
Tyrone gas processing plant and related gathering system.

     General and administrative expense increased $3.3 million, or 25%, because
of Company growth and increased stock incentive compensation.  Excluding stock
incentive compensation, general and administrative expense per BOE was $1.04 in
1996 as compared to $0.97 in 1995.

                                       22
<PAGE>

     Gas gathering and processing expense increased from $2.5 million in 1995 to
$6.9 million in 1996.  This increase was primarily because of rental expense
related to the Tyrone plant and gathering system lease that began in March 1996.
This increase offsets related decreases in DD&A and interest.

     Interest expense increased $4.5 million or 36% primarily because of
increased debt to partially fund the 1995 and 1996 acquisitions and purchases of
treasury stock and equity securities.  Weighted average principal outstanding
during 1996 was $259 million at an average interest rate of 6.4% compared with
weighted average principal of $195.1 million at 6.2% for 1995.  Interest expense
per BOE increased from $1.51 in 1995 to $1.76 in 1996 primarily because of
financing expenditures for other than oil and gas producing properties with bank
and other short-term borrowings.


LIQUIDITY AND CAPITAL RESOURCES

     The Company's primary sources of liquidity are cash flow from operating
activities, public offerings of equity and debt, and bank debt.  The Company's
cash requirements, other than for operations, are generally for the acquisition,
exploration and development of oil and gas properties, and debt and dividend
payments.  The Company believes that its sources of liquidity are adequate to
fund its cash requirements during 1998.

     Cash provided by operating activities was $98 million in 1997, compared
with $59.7 million in 1996 and $32.9 million in 1995.  The fluctuation from 1996
to 1997 was primarily because of increased gas prices and production, combined
with the timing of cash receipts.  Before changes in working capital, cash flow
from operations was $90 million, $68.3 million and $40.4 million in 1997, 1996
and 1995, respectively.

     The 1997, 1996 and 1995 acquisitions were primarily financed by proceeds
from long-term debt borrowings. The 1995 acquisitions were also partially funded
by proceeds from a public offering of common stock.  Exploration and development
expenditures and dividend payments have generally been funded by cash flow from
operations.

Financial Condition

     Total assets increased from $523 million at December 31, 1996 to $788
million at December 31, 1997, primarily because of the 1997 acquisitions.  As of
December 31, 1997, total capitalization of the Company was $709 million, of
which 76% was long-term debt.  This compares with capitalization of $457 million
at December 31, 1996, of which 69% was long-term debt.  The increase in the
debt-to-capitalization ratio from year-end 1996 to 1997 is because of increased
borrowings under the Company's loan agreement to fund the 1997 acquisitions and
other capital expenditures (see "Financing" below).

Working Capital

     The Company generally uses available cash to reduce bank debt and,
therefore, does not maintain large cash and cash equivalent balances.  Short-
term liquidity needs are satisfied by bank commitments under the loan agreement
(see "Financing" below).  Because of this, and since the Company's principal
source of operating cash flows (i.e., proved reserves to be produced in the
following year) cannot be reported as working capital, the Company often has low
or negative working capital.

Financing

     On November 21, 1997, the Company entered into a new Revolving Credit
Agreement with commercial banks ("loan agreement").  As of December 31, 1997,
the loan agreement had a borrowing base and commitment of $365 million with
resulting unused borrowing capacity of $136 million.  The interest rate on
borrowings at December 31, 1997 was 7.1%.  The Company periodically renegotiates
the loan agreement to increase the borrowing commitment and extend the revolving
facility; however, there is no assurance that the Company will continue to do so
in the future. After the anticipated closing of the EEX Acquisition in April
1998, the Company expects the borrowing base and commitment to be at least $560
million.

     The borrowing base is redetermined annually based on the value and expected
cash flow of the Company's proved oil and gas reserves.  If outstanding
borrowings are greater than the redetermined borrowing base, outstanding
borrowings must be reduced to the level of the redetermined borrowing base
within a specified period.  Otherwise,

                                       23
<PAGE>

borrowings under the loan agreement do not mature until December 31,
2002, but may be prepaid at any time without penalty.

     During 1995, the Company purchased and retired $8.3 million principal
amount of its 5 1/4% convertible subordinated notes ("5 1/4% Notes"), resulting
in an extraordinary gain of $700,000.  During 1996, the Company redeemed,
purchased and retired a total of $9 million principal amount of the notes at a
loss of $400,000, and holders of the 5 1/4% Notes converted principal of $27.7
million into 2,696,521 shares of common stock.  In January 1997, the remaining
$29.7 million of the 5 1/4% Notes was converted by noteholders into 2,892,363
shares of common stock and $29,000 was redeemed.

     In August 1995, the Company sold 5.1 million shares of common stock for net
proceeds of $29.5 million that were used to partially fund the Santa Fe
Acquisition.  In September 1996, pursuant to the Company's exchange offer, a
total of 2,979,249 shares of common stock were exchanged for 1,138,729 shares of
Series A convertible preferred stock.

     In April 1997, the Company sold $125 million of 9 1/4% senior subordinated
notes ("9 1/4% Notes") and in October 1997, the Company sold $175 million of 8
3/4% senior subordinated notes ("8 3/4% Notes").  Net proceeds of $121.1 million
and $169.9 million from the sale of 9 1/4% Notes and the 8 3/4% Notes,
respectively, were used to reduce bank borrowings under the loan agreement. See
Note 2 Consolidated Financial Statements.

     On February 25, 1998, the Company filed a shelf registration statement with
the Securities and Exchange Commission to potentially offer securities which may
include debt securities, preferred stock, common stock or warrants to purchase
debt securities, preferred stock or common stock.  The securities will be
offered at an aggregate offering price not to exceed $200 million, at prices and
on terms to be determined at the time of the sale.  Net proceeds from the sale
will be used for general corporate purposes, including reduction of bank
borrowings under the loan agreement.

Capital Expenditures

     In May 1997, the Company announced its plan to make strategic acquisitions
totaling $260 to $280 million from that date through the end of 1999.  As a
result of closing the Amoco Acquisition in December 1997 at an estimated cost of
$195 million and the expected closing of the EEX Acquisition in April 1998 at an
estimated cost of $245 million, the Company has significantly exceeded this
goal.  Acquisition costs totaled $255.6 million, $105.8 million and $131.3
million during 1997, 1996 and 1995, respectively.  Producing property
acquisitions include purchases of outstanding beneficial units ("Units") of
Cross Timbers Royalty Trust at a cost of $5.4 million for 6% of the Units in
1997 and $12.8 million for 16% of the Units in 1996. As of December 31, 1997,
the Company owned 1,326,300 Units; the Board of Directors has authorized a total
purchase of up to two million Units.  Acquisitions were primarily funded by bank
debt.  See Note 10 to Consolidated Financial Statements.

      The Company continues to pursue acquisitions that meet its criteria,
although there are no assurances that such properties will be available.  The
Company plans to fund future acquisitions through a combination of cash flow
from operations and bank borrowings; proceeds from public equity and debt
transactions may also be utilized.

     In 1997, exploration and development cash expenditures totaled $90.5
million compared with the budget of $70 million.  On an incurred basis,
exploration and development costs for 1997 totaled $88.6 million. In 1996,
exploration and development cash expenditures totaled $32.3 million, compared
with the budget of $40 million.  The Company has budgeted $70 to $90 million for
the 1998 development program.  As it has done historically, the Company expects
to fund the 1998 development program from cash flow from operations.  Since
there are no material long-term commitments associated with this budget, the
Company has the flexibility to adjust its actual development 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 are operated by third
parties which control the timing and amount of expenditures required to exploit
the Company's interests in such properties.  Therefore, the Company can give no
assurances regarding the timing or amount of such expenditures.

                                       24
<PAGE>

     To date, the Company's expenditures to comply with environmental or safety
regulations have not been significant, and the Company currently does not expect
such expenditures to be significant during 1998.  However, developments such as
new regulations, enforcement policies or claims for damages could result in
significant future costs.

Dividends

     The Board of Directors has declared quarterly dividends of $0.033 per
common share since the Company's inception through 1996 and $0.037 per common
share in 1997.  In January 1998, the Board of Directors increased the quarterly
dividend to $0.04 per share, or $6.2 million annually.  Continued dividend
payments are dependent upon available cash flow, as well as other factors.  In
addition, the Company's loan agreement restricts the amount of common stock
dividends to 25% of operating cash flow for the last four quarters.

     Cumulative dividends on Series A convertible preferred stock are paid
quarterly, when declared by the Board of Directors, based on an annual rate of
$1.5625 per share, or $1.8 million annually.

Year 2000

     The Company is in the process of reviewing and making necessary
modifications to its computer systems for year 2000 compliance.  Costs incurred
to date to modify the Company's computer systems have not been material, and
future costs are not expected to be material.  Timely completion of such
modifications is not considered to be a material risk to the Company.  The
Company currently does not have information regarding the year 2000 compliance
status of its major suppliers and customers.  In the event that any of the
Company's significant suppliers or customers does not timely achieve year 2000
compliance, the Company's operations could be adversely affected.

PRODUCTION IMBALANCES

     The Company has gas production imbalance positions that are the result of
partial interest owners selling more or less than their proportionate share of
gas on jointly owned wells.  Imbalances are generally settled by
disproportionate gas sales over the remaining life of the well or by cash
payment by the overproduced party to the underproduced party.  The Company uses
the entitlement method of accounting for natural gas sales.  At December 31,
1997, the Company's consolidated balance sheet includes a net receivable of $5.1
million for a net underproduced balancing position of 1,114,000 Mcf of natural
gas and 8,049,000 Mcf of carbon dioxide.  Production imbalances do not have, and
are not expected to have, a significant impact on the Company's liquidity or
operations.

DERIVATIVES

     The Company uses derivatives on a limited basis to hedge interest rate and
product price risks, as opposed to their use for trading purposes.  To reduce
variable interest rate exposure on debt, the Company had entered into a series
of interest rate swap agreements, the last of which expired September 1996.  The
Company had no other significant derivative transactions or balances from 1994
to 1997.  During the first quarter of 1998, the Company entered into several
derivative transactions to hedge its exposure to price fluctuations for gas
production from January 1998 through December 2000.  See Note 6 to Consolidated
Financial Statements.

FORWARD-LOOKING STATEMENTS

     Certain statements included in this Item 7, as well as statements included
in Items 1 and 2 of this report, relating to future development expenditures,
strategic acquisitions, proved reserves and other matters of anticipated
financial and operating performance constitute forward-looking statements.
These statements are based on assumptions concerning oil and gas prices,
drilling results and production, and administrative and other costs that
management believes are reasonable based on currently available information.
However, management's assumptions and the Company's future performance are both
subject to a wide range of risks, uncertainties and other factors that could
cause the Company's actual results and experience to differ materially from the
anticipated results or other expectations expressed in the Company's forward-
looking statements.  Risks and uncertainties that may affect the operations and
results of the Company's performance include, but are not limited to, commodity
price fluctuations, competitive energy supplies, market demand, drilling risks,
governmental regulations and uncertainties of proved reserve estimates.  In

                                       25
<PAGE>

addition, potential producing property acquisitions that meet the Company's
profitability, size, and geographic and other criteria may not be available on
acceptable economic terms.


ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     The following financial statements and supplementary information are
included under Item 14(a):
<TABLE>
<CAPTION>

                                                          Page
                                                          ----
<S>                                                       <C>

    Consolidated Balance Sheets.........................    28
    Consolidated Statements of Operations...............    29
    Consolidated Statements of Cash Flows...............    30
    Consolidated Statements of Stockholders' Equity.....    31
    Notes to Consolidated Financial Statements..........    32
    Report of Independent Public Accountants............    49
    Selected Quarterly Financial Data
     (Note 11 to Consolidated Financial Statements).....    45
    Information about Oil and Gas Producing Activities
     (Note 12 to Consolidated Financial Statements).....    46

</TABLE>
ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
         FINANCIAL DISCLOSURE

     None.



                                    PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

ITEM 11.  EXECUTIVE COMPENSATION

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     Except for the portion of Item 10 relating to Executive Officers of the
Registrant which is included in Part I of this Report, the information called
for by Items 10 through 13 is incorporated by reference from the Company's
Notice of Annual Meeting and Proxy Statement to be filed with the Securities and
Exchange Commission no later than April 30, 1998.

                                       26
<PAGE>

                                    PART IV

ITEM 14.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

    (a) The following documents are filed as a part of this report:

                                                                            Page
                                                                            ----

        1. Financial Statements:

           Consolidated Balance Sheets at December 31, 1997 and 1996..........28
           Consolidated Statements of Operations for the years ended
             December 31, 1997, 1996 and 1995.................................29
           Consolidated Statements of Cash Flows for the years ended
             December 31, 1997, 1996 and 1995.................................30
           Consolidated Statements of Stockholders' Equity for the years ended
             December 31, 1997, 1996 and 1995.................................31
           Report of Independent Public Accountants...........................49

        2. Financial Statement Schedules:

           All financial schedules have been omitted because they are not
           applicable or the required information is presented in the financial
           statements or the notes to financial statements.

        3. Exhibits:

           See Index to Exhibits at page 51 for a description of the exhibits
           filed as a part of this report.

    (b) Reports on Form 8-K

           The Company filed the following reports on Form 8-K during the
           quarter ended December 31, 1997 and through March 27, 1998:

           On December 16, 1997, the Company filed a report on Form 8-K dated
           December 1, 1997 regarding its acquisition of certain producing oil
           and gas properties in the San Juan Basin of New Mexico from a
           subsidiary of Amoco Corporation.

           On February 17, 1998, the Company filed a report on Form 8-K/A
           (Amendment No. 1 to Form 8-K dated December 1, 1997) to file
           financial statements for the acquisition of certain producing oil and
           gas properties in the San Juan Basin of New Mexico from a subsidiary
           of Amoco Corporation.

           On February 23, 1998, the Company filed a report on Form 8-K dated
           February 18, 1998 regarding the issuance of news release number 98-04
           announcing earnings for the quarter and year ended December 31, 1997.

           On February 25, 1998, the Company filed a report on Form 8-K dated
           February 25, 1998 regarding its intent to acquire producing
           properties and undeveloped acreage in the East Texas Basin from EEX
           Corporation.

                                       27
<PAGE>

CROSS TIMBERS OIL COMPANY
CONSOLIDATED BALANCE SHEETS
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>


(in thousands)                                                                   DECEMBER 31
                                                                          ------------------------
                                                                              1997         1996
                                                                          ------------  ----------
<S>                                                                       <C>           <C>
ASSETS

Current Assets:
  Cash and cash equivalents.............................................    $   3,816   $   3,937
  Accounts receivable, net (Note 6).....................................       43,996      44,320
  Deferred income tax benefit (Note 3)..................................          445         558
  Other current assets..................................................        3,905       2,965
                                                                            ---------   ---------
    Total Current Assets................................................       52,162      51,780
                                                                            ---------   ---------

Property and Equipment, at cost --
    successful efforts method (Notes 1 and 2):
  Producing properties..................................................      931,259     639,990
  Undeveloped properties................................................        6,406       2,493
  Other property and equipment..........................................       23,703      16,470
                                                                            ---------   ---------
  Total Property and Equipment..........................................      961,368     658,953
  Accumulated depreciation, depletion and amortization..................     (237,532)   (208,392)
                                                                            ---------   ---------
    Net Property and Equipment..........................................      723,836     450,561
                                                                            ---------   ---------

Investment in Equity Securities, at market value........................            -      16,714
                                                                            ---------   ---------

Other Assets............................................................       12,457       4,015
                                                                            ---------   ---------

TOTAL ASSETS............................................................    $ 788,455   $ 523,070
                                                                            =========   =========

LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities:
  Accounts payable and accrued liabilities..............................    $  52,266   $  45,729
  Payable to Royalty Trust..............................................        2,073       2,770
  Accrued stock incentive compensation (Note 9).........................          554         483
  Short-term debt (Note 2)..............................................            -       3,000
                                                                            ---------   ---------
    Total Current Liabilities...........................................       54,893      51,982
                                                                            ---------   ---------

Long-term Debt (Note 2).................................................      539,000     314,757
                                                                            ---------   ---------

Deferred Income Taxes Payable (Note 3)..................................       21,320      10,323
                                                                            ---------   ---------

Other Long-term Liabilities (Note 4)....................................        2,999       3,340
                                                                            ---------   ---------
Commitments and Contingencies (Note 4)

Stockholders' Equity (Note 5):
  Series A convertible preferred stock ($.01 par value, 25,000,000
     shares authorized, 1,138,729 issued, at liquidation value of $25)..       28,468      28,468
  Common stock ($.01 par value, 100,000,000 shares authorized,
     46,310,710 and 42,314,965 shares issued)...........................          463         423
  Additional paid-in capital............................................      210,954     164,436
  Treasury stock (6,860,779 and 3,868,171 shares).......................      (76,656)    (40,219)
  Unrealized gain on investment in equity securities....................            -         638
  Retained earnings (deficit)...........................................        7,014     (11,078)
                                                                            ---------   ---------
    Total Stockholders' Equity..........................................      170,243     142,668
                                                                            ---------   ---------

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY..............................    $ 788,455   $ 523,070
                                                                            =========   =========

</TABLE>
          See accompanying notes to consolidated financial statements.

                                       28
<PAGE>

CROSS TIMBERS OIL COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>


(in thousands, except per share data)
                                                                 YEAR ENDED DECEMBER 31
                                                               ----------------------------
                                                                 1997      1996      1995
                                                               --------  --------  --------
<S>                                                         <C>          <C>       <C>
REVENUES

Oil and condensate...................................          $ 75,223  $ 75,013  $ 60,349
Gas and natural gas liquids..........................           110,104    73,402    40,543
Gas gathering, processing and marketing..............             9,851    12,032     7,091
Other................................................             5,494       944     4,922
                                                               --------  --------  --------

Total Revenues.......................................           200,672   161,391   112,905
                                                               --------  --------  --------

EXPENSES

Production...........................................            43,580    39,365    35,338
Exploration..........................................             2,088         -         -
Taxes on production and property.....................            16,405    11,944     8,646
Depreciation, depletion and amortization.............            47,721    37,858    36,892
Impairment (Note 1)..................................                 -         -    20,280
General and administrative (Note 9)..................            15,818    16,420    13,156
Gas gathering and processing.........................             8,517     6,905     2,528
Interest, net........................................            26,677    17,072    12,523
Trust development costs..............................               665       854       561
                                                               --------  --------  --------

Total Expenses.......................................           161,471   130,418   129,924
                                                               --------  --------  --------

INCOME (LOSS) BEFORE INCOME TAX
 AND EXTRAORDINARY ITEM..............................            39,201    30,973   (17,019)

Income Tax Expense (Benefit) (Note 3)................            13,517    10,669    (5,825)
                                                               --------  --------  --------

NET INCOME (LOSS) BEFORE EXTRAORDINARY ITEM..........            25,684    20,304   (11,194)

EXTRAORDINARY ITEM (Note 1)..........................                 -         -       656
                                                               --------  --------  --------

NET INCOME (LOSS)....................................            25,684    20,304   (10,538)

Preferred stock dividends............................             1,779       514         -
                                                               --------  --------  --------

EARNINGS (LOSS) AVAILABLE TO COMMON STOCK............          $ 23,905  $ 19,790  $(10,538)
                                                               ========  ========  ========

EARNINGS (LOSS) PER COMMON SHARE (Notes 1 and 7)

 Basic...............................................             $0.60     $0.50    $(0.28)
                                                               ========  ========  ========
 Diluted.............................................             $0.59     $0.48    $(0.28)
                                                               ========  ========  ========

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (Note 5)..            39,773    39,913    38,072
                                                               ========  ========  ========

</TABLE>

          See accompanying notes to consolidated financial statements.

                                       29
<PAGE>

CROSS TIMBERS OIL COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>


(in thousands)
(Note 8)
                                                                              YEAR ENDED DECEMBER 31
                                                                         ---------------------------------
                                                                            1997       1996        1995
                                                                         ---------   ---------   ---------
 <S>                                                                      <C>         <C>         <C>
OPERATING ACTIVITIES

Net income (loss)......................................................  $  25,684   $  20,304   $ (10,538)
Adjustments to reconcile net income (loss) to net cash
 provided by operating activities:
  Depreciation, depletion and amortization.............................     47,721      37,858      36,892
  Impairment...........................................................          -           -      20,280
  Exploration..........................................................      2,088           -           -
  Performance share compensation.......................................      3,315       2,545       2,945
  Accrued stock appreciation right compensation........................         71      (3,398)      1,447
  Deferred income tax..................................................     13,393      10,213      (6,023)
  Gain from sale of properties and equity securities...................     (4,157)       (576)     (4,520)
  Extraordinary item...................................................          -           -        (656)
  Other non-cash items.................................................      1,864       1,317         612
  Changes in working capital (a).......................................      8,027      (8,569)     (7,501)
                                                                         ---------   ---------   ---------

CASH PROVIDED BY OPERATING ACTIVITIES..................................     98,006      59,694      32,938
                                                                         ---------   ---------   ---------

INVESTING ACTIVITIES

Sale of equity securities..............................................     24,626         402      16,923
Investment in equity securities........................................     (6,479)    (16,093)       (123)
Sale of property and equipment.........................................     17,972      37,388      13,095
Property acquisitions..................................................   (238,294)   (109,535)   (131,342)
Exploration and development costs......................................    (90,470)    (32,291)    (19,296)
Gas plant, gathering and other additions...............................    (18,677)     (4,742)    (39,673)
                                                                         ---------   ---------   ---------

CASH USED BY INVESTING ACTIVITIES......................................   (311,322)   (124,871)   (160,416)
                                                                         ---------   ---------   ---------

FINANCING ACTIVITIES

Proceeds from long-term debt...........................................    688,400     188,000     193,000
Payments on long-term debt.............................................   (437,430)    (81,200)    (96,040)
Proceeds from sale of common stock, net................................          -           -      29,450
Dividends..............................................................     (7,571)     (5,339)     (4,951)
Proceeds on exercise of stock options..................................        750         904         744
Preferred stock exchange offer costs...................................          -        (540)          -
Purchase of treasury stock.............................................    (30,954)    (34,923)       (351)
                                                                         ---------   ---------   ---------

CASH PROVIDED BY FINANCING ACTIVITIES..................................    213,195      66,902     121,852
                                                                         ---------   ---------   ---------

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS.......................       (121)      1,725      (5,626)

CASH AND CASH EQUIVALENTS, JANUARY 1...................................      3,937       2,212       7,838
                                                                         ---------   ---------   ---------

CASH AND CASH EQUIVALENTS, DECEMBER 31.................................  $   3,816   $   3,937   $   2,212
                                                                         =========   =========   =========

(a) CHANGES IN WORKING CAPITAL
    Accounts receivable................................................  $     246   $ (16,999)  $  (9,365)
    Other current assets...............................................       (970)     (1,683)        963
    Accounts payable, accrued liabilities and payable to Royalty Trust.      8,751      10,113         901
                                                                         ---------   ---------   ---------

  DECREASE (INCREASE) IN WORKING CAPITAL...............................  $   8,027   $  (8,569)  $  (7,501)
                                                                         =========   =========   =========
</TABLE>
          See accompanying notes to consolidated financial statements.

                                       30
<PAGE>

CROSS TIMBERS OIL COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>


(in thousands)
(Note 5)
                                             SHARES                                       STOCKHOLDERS' EQUITY
                                ----------------------------------     -----------------------------------------------------------
                                                   COMMON STOCK
                                               -------------------                              ADDITIONAL               RETAINED
                                 PREFERRED                  IN           PREFERRED    COMMON      PAID-IN    TREASURY    EARNINGS
                                  STOCK         ISSUED    TREASURY         STOCK       STOCK      CAPITAL      STOCK     (DEFICIT)
                                ----------     --------  ---------     ------------  ---------  ----------   --------   ----------
<S>                            <C>          <C>         <C>           <C>           <C>         <C>        <C>        <C>
BALANCES, DECEMBER 31, 1994...       -          35,833        2         $     -      $   358      $123,054   $    (11)  $   (9,953)

Sale of common stock..........       -           5,062        -               -           50        29,400          -            -
Issuance of performance
 shares.......................       -             369        -               -            4         2,943          -            -
Stock option exercises........       -             170       67               -            2         1,043       (517)           -
Common stock dividends
 ($0.13 per share)............       -               -        -               -            -             -          -       (5,135)
Net loss......................       -               -        -               -            -             -          -      (10,538)
                                ----------     --------  ---------     ------------  ---------  ----------   --------   ----------

BALANCES, DECEMBER 31, 1995...       -          41,434       69               -          414       156,440       (528)     (25,626)

Issuance/vesting of
 performance shares...........       -             168      106               -            2         2,673     (1,038)           -
Stock option exercises........       -             996      768               -           10         7,189     (7,931)           -
Treasury stock purchases......       -               -    2,925               -            -             -    (30,722)           -
Exchange of Series A
 convertible preferred stock
  for common stock............   1,139          (2,979)       -          28,468          (30)      (28,978)         -            -
Conversion of subordinated
 convertible notes to
  common stock................       -           2,696        -               -           27        27,112          -            -
Common stock dividends
 ($0.13 per share)............       -               -        -               -            -             -          -       (5,242)
Preferred stock dividends
 ($0.45 per share)............       -               -        -               -            -             -          -         (514)
Net income....................       -               -        -               -            -             -          -       20,304
                                ----------     --------  ---------     ------------  ---------  ----------   --------   ----------

BALANCES, DECEMBER 31, 1996...   1,139          42,315    3,868          28,468          423       164,436    (40,219)     (11,078)

Issuance/vesting of
 performance shares...........       -             180       76               -            2         3,431     (1,098)           -
Stock option exercises........       -             924      566               -            9         8,183     (7,326)           -
Treasury stock purchases......       -               -    2,351               -            -             -    (28,013)           -
Conversion of subordinated
 convertible notes to
  common stock................       -           2,892        -               -          29         29,179          -            -
Issuance of warrants..........       -               -        -               -           -          5,725          -            -
Common stock dividends
 ($0.15 per share)............       -               -        -               -           -              -          -       (5,813)
Preferred stock dividends
 ($1.56 per share)............       -               -        -               -           -              -          -       (1,779)
Net income....................       -               -        -               -           -              -          -       25,684
                                ----------     --------  ---------     ------------  ---------  ----------   --------   ----------

BALANCES, DECEMBER 31, 1997...   1,139          46,311    6,861         $28,468      $  463     $  210,954   $(76,656)  $    7,014
                                ==========     ========  =========     ============  =========  ==========   ========   ==========

</TABLE>
          See accompanying notes to consolidated financial statements.

                                       31
<PAGE>

CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
--------------------------------------------------------------------------------


1.  ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

     Cross Timbers Oil Company, a Delaware corporation, was organized in October
1990 to ultimately acquire the business and properties of predecessor entities
that were created from 1986 through 1989.  Cross Timbers Oil Company completed
its initial public offering of common stock in May 1993.

     The accompanying consolidated financial statements include the financial
statements of Cross Timbers Oil Company and its wholly owned subsidiaries ("the
Company").  All significant intercompany balances and transactions have been
eliminated in the consolidation.  In preparing the accompanying financial
statements, management has made certain estimates and assumptions that affect
reported amounts in the financial statements and disclosures of contingencies.
Actual results may differ from those estimates.

     All common stock shares and per share amounts in the accompanying financial
statements have been adjusted for the three-for-two stock splits effected on
March 19, 1997 and February 25, 1998 (Note 5).

     The Company is an independent oil and gas company with production and
exploration concentrated in Texas, Oklahoma, Kansas, New Mexico and Wyoming.
The Company also gathers, processes and markets gas, transports and markets oil
and conducts other activities directly related to the oil and gas producing
industry.

     Property and Equipment

     The Company follows the successful efforts method of accounting,
capitalizing costs of successful exploratory wells and expensing costs of
unsuccessful exploratory wells.  Exploratory geological and geophysical costs
are expensed as incurred. All developmental costs are capitalized.  The Company
generally pursues acquisition and development of proved reserves, although the
Company increased its exploration activities in 1997.  Most of the property
costs reflected on the accompanying consolidated balance sheets are from
acquisitions of producing properties from other oil and gas companies.  As of
December 31, 1997 and 1996, producing properties balances include costs of
$26,570,000 and $6,115,000, respectively, related to wells in progress of
drilling.

     Depreciation, depletion and amortization of producing properties is
computed on the unit-of-production method based on estimated proved oil and gas
reserves.  Other property and equipment is generally depreciated using the
straight-line method over estimated useful lives which range from 3 to 40 years.
Repairs and maintenance are expensed, while renewals and betterments are
generally capitalized.

     Effective October 1, 1995, the Company adopted Statement of Financial
Accounting Standards ("SFAS") No. 121, Accounting for the Impairment of Long-
Lived Assets and for Long-Lived Assets to be Disposed Of.  Based generally on a
field-level assessment, producing properties were written down to estimated fair
value when their net basis exceeded estimated direct future net cash flows from
such properties.  The Company's resulting impairment provision was $20,280,000
before income tax.  After initial adoption of SFAS No. 121, the Company assesses
impairment of long-lived assets whenever events or changes in circumstances
indicate that the net basis of the asset may not be recoverable.  No impairment
was recorded in 1997 or 1996 and, prior to adoption of SFAS No. 121 in 1995, no
impairment of producing properties was required, based on a total Company
assessment using undiscounted estimated future net cash flows.  Impairment of
individually significant undeveloped properties is assessed on a property-by-
property basis and impairment of other undeveloped properties is assessed and
amortized on an aggregate basis.

     Cross Timbers Royalty Trust

     The Company makes monthly net profits payments to Cross Timbers Royalty
Trust ("Royalty Trust") based on revenues and costs related to properties from
which net profits interests were carved.  Net profits payments to the Royalty
Trust are generally based on revenues received and costs disbursed by the
Company in the prior month.  For financial reporting purposes, the Company
reduces oil and gas revenues and taxes on production for amounts allocated to
the Royalty Trust.  The Royalty Trust's portion of development costs are
expensed as trust development costs in the accompanying consolidated statements
of operations.  As of December 31, 1997 and 1996, the Company owned 22% and 16%,
respectively,

                                       32
<PAGE>

of the Royalty Trust's publicly traded units of beneficial interest ("Units")
(Note 10). Royalty Trust Units are traded on the New York Stock Exchange under
the symbol "CRT".

     Cash and Cash Equivalents

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

     Investment in Equity Securities

     Investment in equity securities at December 31, 1996 is reported at market
value and classified as available-for-sale securities, rather than trading
securities, in accordance with SFAS No. 115, Accounting for Certain Investments
in Debt and Equity Securities.  Accordingly, the related unrealized gain on
investment at December 31, 1996, net of deferred income taxes, is excluded from
earnings and is reported as a separate component of stockholders' equity.  There
was no investment in equity securities at December 31, 1997.

     Other Assets

     Other assets primarily include deferred debt costs that are amortized over
the term of the related debt (Note 2).  Other assets are presented net of
accumulated amortization of $2,860,000 and $2,628,000 at December 31, 1997 and
1996, respectively.

     Derivatives

     The Company uses derivatives on a limited basis to hedge interest rate and
product price risks, as opposed to their use for trading purposes.  Amounts
receivable or payable under interest swap agreements are recorded as adjustments
to interest expense.  Gains and losses on commodity futures contracts and other
price risk management instruments are recognized in oil and gas revenues when
the hedged transaction occurs.  Cash flows related to derivative transactions
are included in operating activities.

     Production Imbalances

     The Company uses the entitlement method of accounting for gas sales, based
on the Company's net revenue interest in production.  Accordingly, revenue is
deferred when gas deliveries exceed the Company's net revenue interest, while
revenue is accrued for under-deliveries.  Production imbalances are generally
recorded at the estimated sales price in effect at the time of production.  At
December 31, 1997, the Company recorded a net receivable of $5,054,000 for a net
underproduced balancing position of 1,114,000 Mcf of natural gas and 8,049,000
Mcf of carbon dioxide.  At December 31, 1996, the Company recorded a net
receivable of $3,964,000 for a net underproduced balancing position of 821,000
Mcf of natural gas and 6,824,000 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 the month of delivery based on customer
nominations. Gas processing and marketing revenues are recorded net of cost of
gas sold of $57.1 million, $56.4 million and $30 million for 1997, 1996 and
1995, respectively.  These amounts are net of intercompany eliminations.

     Other Revenues

     Other revenues include gain/loss from sale of equity securities and from
sale of property and equipment.  During 1997 and 1996, the Company realized
gains on sale of property and equipment of $1,757,000 and $520,000,
respectively, and on sale of equity securities of $2,400,000 and $56,000,
respectively.  During 1995, the Company realized a gain on sales of properties
of $2,960,000.

     Exploration Expense

     During 1997, the Company incurred $2.1 million of exploration costs,
primarily composed of geological and geophysical costs related to the 1997
exploration program.  Exploration costs were not significant prior to 1997.

                                       33
<PAGE>

     Interest Expense

     Interest expense includes amortization of deferred debt costs and is
presented net of interest income of $71,000, and capitalized interest of
$1,185,000 for the year ended December 31, 1997 and net of interest income of
$152,000 and $399,000 for the years ended December 31, 1996 and 1995,
respectively.

     Stock-Based Compensation

     In accordance with Accounting Principles Board Opinion No. 25, Accounting
for Stock Issued to Employees, no compensation is recorded for stock options or
other stock-based awards that are granted to employees with an exercise price
equal to or above the common stock price on the grant date.  Compensation
related to performance share grants is recognized from the grant date until the
performance conditions are satisfied, based on the market price of the Company's
common stock. The pro forma effect of recording stock-based compensation at the
estimated fair value of awards on the grant date, as prescribed by SFAS No. 123,
Accounting for Stock-Based Compensation, is disclosed in Note 9.

     Extraordinary Item

     During 1995, the Company recognized an extraordinary gain of $656,000 (net
of income tax of $338,000), or $0.01 per common share, upon the purchase and
early retirement of a portion of the Company's 5 1/4% convertible subordinated
notes. A loss of $430,000, before income tax, on purchases and redemption of the
notes in 1996 was not presented as an extraordinary item because it was not
material to 1996 earnings.

     Earnings per Common Share

     Effective December 31, 1997, the Company adopted SFAS No. 128, Earnings Per
Share, which changed the method of computing and disclosing earnings per share
for all periods.  Under SFAS No. 128, the Company must report basic earnings per
share, which excludes the effect of potentially dilutive securities, and diluted
earnings per share, which includes the effect of all potentially dilutive
securities unless their impact is antidilutive.  The Company previously only
reported earnings per share excluding potentially dilutive securities because
their effect was antidilutive or less than 3% dilutive, as prescribed by the
accounting pronouncement superseded by SFAS No. 128.  See Note 7.

     Earnings (loss) per common share for all periods presented is based on
weighted average common shares outstanding as adjusted for the three-for-two
stock splits on March 19, 1997 and February 25, 1998 (Note 5).

     Sales to Major Customers

     In 1997, gas sales to one purchaser were approximately 14% of total
revenues.  In 1996, gas sales to two purchasers were approximately 15% and 14%
of total revenues.  There were no sales to a single purchaser that exceeded 10%
of total revenues in 1995.

     Recent Accounting Pronouncements

     In June 1997, the Financial Accounting Standards Board issued SFAS No. 130,
Reporting of Comprehensive Income, and SFAS No. 131, Disclosures About Segments
of an Enterprise and Related Information.  The Company will be required to
comply with the provisions of these statements in its 1998 financial statements.
The Company has not assessed the effect that these new standards will have on
its consolidated financial statements and/or disclosures.

                                       34
<PAGE>

2.  DEBT

     The Company's outstanding debt consists of the following (in thousands):
<TABLE>
<CAPTION>
                                                                      December 31
                                                                  --------------------
                                                                    1997       1996
                                                                  ---------  ---------
<S>                                                               <C>        <C>
  SHORT-TERM DEBT:

  Short-term borrowings, 7.9% at December 31, 1997..............  $ 10,000   $ 13,000
  Reclassified to long-term debt................................   (10,000)   (10,000)
                                                                  --------   --------

  Total short-term debt.........................................  $      -   $  3,000
                                                                  ========   ========

  LONG-TERM DEBT:

  Senior debt-
     Bank debt under revolving credit agreements,
     7.1% at December 31, 1997..................................  $229,000   $275,000

  Subordinated debt-
    5 1/4% convertible subordinated notes due November 1, 2003..         -     29,757
    9 1/4% senior subordinated notes due April 1, 2007..........   125,000          -
    8 3/4% senior subordinated notes due November 1, 2009.......   175,000          -
                                                                  --------   --------

  Sub-total long-term debt......................................   529,000    304,757
  Reclassified from short-term debt.............................    10,000     10,000
                                                                  --------   --------

  Total long-term debt..........................................  $539,000   $314,757
                                                                  ========   ========

</TABLE>
     Senior Debt

     On November 21, 1997, the Company entered into a new Revolving Credit
Agreement with commercial banks ("loan agreement").  As of December 31, 1997,
the loan agreement had a borrowing base and commitment of $365 million with
resulting unused borrowing capacity of $136 million.  The borrowing base is
redetermined annually based on the value and expected cash flow of the Company's
proved oil and gas  reserves.  If outstanding borrowings are greater than the
redetermined borrowing base, outstanding borrowings must be reduced to the level
of the redetermined borrowing base within a specified period.  Otherwise,
borrowings under the loan agreement do not mature until December 31, 2002, but
may be prepaid at any time without penalty. The Company periodically
renegotiates the loan agreement to increase the borrowing commitment and extend
the revolving facility. After the closing of the EEX Acquisition in April 1998
(Note 10), the Company expects the borrowing base and commitment to be at least
$560 million.

     Reclassification of short-term to long-term debt represents unused capacity
under the loan agreement based on outstanding debt balances at December 31, 1997
and expected borrowing commitments through December 31, 1998. The Company has
both the intent and ability to refinance this debt on a long-term basis.

     Restrictions set forth in the loan agreement include limitations on the
incurrence of additional indebtedness, the creation of certain liens, and the
redemption or prepayment of subordinated indebtedness. The loan agreement also
limits dividends to 25% of cash flow from operations for the latest four
consecutive quarterly periods. The Company is also required to maintain a
current ratio of not less than one (where unused borrowing commitments are
included as a current asset).

     The loan agreement provides the option of borrowing at floating interest
rates based on the prime rate or at fixed rates for periods of up to six months
based on certificate of deposit rates or London Interbank Offered Rates
("LIBOR"). Borrowings under the loan agreement at December 31, 1997 were based
on LIBOR rates with a maturity of 30 days and accrued at the applicable LIBOR
rate plus 1%. Interest is paid at maturity, or quarterly if the term is for a
period of 90 days or more. The Company also incurs a commitment fee of 3/8% on
unused borrowing commitments. The weighted average interest rate on senior debt
was 6.9%, 6.7% and 7.1% during 1997, 1996 and 1995, respectively.

                                       35
<PAGE>

     Subordinated Debt

     During 1995, the Company purchased and retired $8.3 million principal
amount of its 5 1/4% convertible subordinated notes ("5 1/4% Notes"), resulting
in an extraordinary gain of $656,000 (Note 1).  During 1996, the Company
redeemed, purchased and retired a total of $9 million principal amount of the 5
1/4% Notes at a loss before income tax of $430,000, and holders of the 5 1/4%
Notes converted principal of $27.7 million into common stock at a conversion
price of $10.28 per share (Note 5).  In January 1997, the remaining $29.7
million principal amount of the 5 1/4% Notes was converted by noteholders into
common stock and $29,000 principal was redeemed.

     The Company sold $125 million of 9 1/4% senior subordinated notes ("9 1/4%
Notes") on April 2, 1997, and $175 million of 8 3/4% senior subordinated notes
("8 3/4% Notes") on October 28, 1997 (the  9 1/4% Notes and the 8 3/4% Notes
collectively referred to as  "the Notes").  The Notes are general unsecured
indebtedness that is subordinate to bank borrowings under the loan agreement.
Net proceeds of $121.1 million and $169.9 million from the 9 1/4% Notes and 8
3/4% Notes, respectively, were used to reduce bank borrowings under the loan
agreement.  The 9 1/4% Notes mature on April 1, 2007 and interest is payable
each April 1 and October 1, while the 8 3/4% Notes mature on November 1, 2009
with interest payable each May 1 and November 1.

     The Company has the option to redeem the 9 1/4% Notes on April 1, 2002 and
the 8 3/4% Notes on November 1, 2002 at a price of approximately 105%, and
thereafter at prices declining ratably at each anniversary to 100% in 2005.  In
addition, on or prior to April 1, 2000 and November 1, 2000 for the 9 1/4% Notes
and 8 3/4% Notes, respectively, the Company may redeem up to one-third of the
Notes with the net proceeds from one or more public equity offerings at a price
of approximately 109% plus accrued interest, subject to certain requirements.
Upon a change in control (as defined) of the Company, the holders of the Notes
have the right to require the Company to purchase all or a portion of their
Notes at 101% plus accrued interest.

     The Notes were issued under indentures that place certain restrictions on
the Company, including limitations on additional indebtedness, liens, dividend
payments, treasury stock purchases, disposition of proceeds from asset sales,
transfers of assets and transactions with subsidiaries and affiliates.

     See also Note 5 "- Registration Statement."


3.  INCOME TAX

     The effective income tax rate for the Company (before extraordinary item)
was different than the statutory federal income tax rate for the following
reasons (in thousands):
<TABLE>
<CAPTION>
                                                                 1997     1996      1995
                                                               -------  --------   -------
<S>                                                           <C>      <C>        <C>
   Income tax expense (benefit) at the
      federal statutory rate of 34%.........................   $13,329   $10,531   $(5,786)
    State and local taxes and other.........................       188       138       (39)
                                                               -------   -------   -------
    Income tax expense (benefit)............................   $13,517   $10,669   $(5,825)
                                                               =======   =======   =======

</TABLE>
     Components of income tax expense (benefit) before extraordinary item are as
follows (in thousands):
<TABLE>
<CAPTION>

                                                                 1997      1996      1995
                                                               --------  --------  --------
<S>                                                           <C>       <C>       <C>

    Current income tax......................................   $   124   $   456   $   198
    Deferred income tax expense (benefit)...................    22,509    13,152    (3,221)
    Net operating loss carryforward.........................    (9,116)   (2,939)   (2,802)
                                                               -------   -------   -------
    Income tax expense (benefit)............................   $13,517   $10,669   $(5,825)
                                                               =======   =======   =======
</TABLE>

                                       36
<PAGE>

     Deferred tax assets and liabilities are the result of temporary
differences between the financial statement carrying values and tax bases of
assets and liabilities.  The Company's net deferred tax liabilities are recorded
as a current asset of $445,000 and a long-term liability of $21,320,000 at
December 31, 1997, and a current asset of $558,000 and a long-term liability of
$10,323,000 at December 31, 1996.  Significant components of net deferred tax
liabilities are (in thousands):
<TABLE>
<CAPTION>

                                                                                December 31
                                                                              ----------------
                                                                               1997     1996
                                                                              -------  -------
<S>                                                                           <C>      <C>
 Deferred tax liabilities:
   Intangible development costs.............................................  $37,856  $21,764
   Tax depletion and depreciation in excess of financial statement amounts..    8,008    3,298
   Other....................................................................    2,228    1,905
                                                                              -------  -------
          Total deferred tax liabilities....................................   48,092   26,967
                                                                              -------  -------

 Deferred tax assets:
   Net operating loss carryforwards.........................................   20,926   11,810
   Trust development expenses...............................................    3,959    3,733
   Accrued stock appreciation right and performance share compensation......      739      787
   Other....................................................................    1,593      872
                                                                              -------  -------
          Total deferred tax assets.........................................   27,217   17,202
                                                                              -------  -------

 Net deferred tax liabilities...............................................  $20,875  $ 9,765
                                                                              =======  =======
</TABLE>

     As of December 31, 1997, the Company has estimated tax loss carryforwards
of approximately $62 million that are scheduled to expire in 2008 through 2012.


4.  COMMITMENTS AND CONTINGENCIES

     Leases

     The Company leases offices, vehicles and certain other equipment in its
primary locations under non-cancelable operating leases.  As of December 31,
1997, minimum future lease payments for all non-cancelable lease agreements
(including the sale and operating leaseback agreements described below) were as
follows (in thousands):
<TABLE>
<CAPTION>

<S>                                 <C>
               1998................  $ 6,645
               1999................    6,445
               2000................    6,188
               2001................    6,102
               2002................    6,086
               Remaining...........    8,707
                                     -------
                                     $40,173
                                     =======
</TABLE>

     Amounts incurred by the Company under operating leases (including renewable
monthly leases) were $9,132,000, $5,489,000,  and $1,912,000 in 1997, 1996 and
1995, respectively.

     In March 1996, the Company sold its Tyrone gas processing plant and related
gathering system for $28 million and entered an agreement to lease the facility
from the buyers for an initial term of eight years at annual rentals of $4
million, and with fixed renewal options for an additional 13 years.  The Company
does not have the right or option to purchase, nor does the lessor 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 term or any renewal period, the
lessor must first offer to sell it to the Company at its fair market value.
Additionally, the Company has a right of first refusal of any third party offers
to buy the facility after the initial term.  This transaction has been recorded
as a sale and operating leaseback, with no gain or loss on the sale.  Proceeds
of the sale were used to reduce borrowings under the loan agreement (Note 2).

     In November 1996, the Company sold its gathering system in Major County,
Oklahoma for $8 million and entered an agreement to 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 (Note 2) and may be irrevocably fixed by the Company with 20 days advance
notice.  As of December 31, 1997, annual rentals were $1.7 million.  The Company
does not have the right or option to purchase, nor does the lessor have the
obligation to sell the facility at any time.  However,

                                       37
<PAGE>

if the lessor decides to sell the facility at the end of the initial term or any
renewal period, the lessor must first offer to sell it to the Company at its
fair market value. Additionally, the Company has a right of first refusal of any
third party offers to buy the facility after the initial term. This transaction
has been recorded as a sale and operating leaseback, with a deferred gain of
$3.4 million on the sale. The deferred gain is amortized over the lease term
based on pro rata rentals and is recorded in other long-term liabilities in the
accompanying balance sheet. Proceeds of the sale were used to reduce borrowings
under the loan agreement.

     Employment Agreements

     Two executive officers have entered into year-to-year employment agreements
with the Company.  The agreements are automatically renewed each year-end unless
terminated by either party upon thirty days notice prior to each December 31.
Under these agreements, each of the officers receives a minimum annual salary of
$300,000 and is entitled to participate in any incentive compensation programs
administered by the Board of Directors.  The agreements also provide that, in
the event the officer terminates his employment for good reason, as defined in
the agreement, the officer will receive severance pay equal to the amount that
would have been paid under the agreement had it not been terminated.  If such
termination follows a change in control of the Company, the officer is entitled
to a lump-sum payment of three times his most recent annual compensation.

     Sales Contracts

     The Company sells gas to a single purchaser under a ten-year contract that
began August 1, 1995.  From August 1995 through July 1998 ("initial period"),
10,000 Mcf of gas per day is sold at a contract price equal to a monthly natural
gas index for deliveries in Oklahoma plus $.35 per Mcf through December 1996,
and plus $.30 per Mcf from January 1997 through July 1998.  For December 1997,
the initial period contract price was $2.65 per Mcf.  From August 1998 through
July 2005 ("final period"), 11,650 Mcf of gas per day will be sold at a contract
price of approximately 10% of the month's average NYMEX futures contract for
West Texas Intermediate crude oil, adjusted for the point of physical delivery.
For December 1997, the final period contract price would have been $1.63 per
Mcf, assuming delivery in Oklahoma.  The Company's spot price for December 1997
deliveries in Oklahoma was $2.32 per Mcf.

     The Company has entered contracts with two purchasers to sell a total of
30,000 Mcf per day in March 1998 and 10,000 Mcf per day in April, May and June
1998.  The production is to be delivered in Oklahoma at the NYMEX index price,
as adjusted for Btu content and gathering charges, less a weighted average
delivery point differential ("basis") of $.18 per Mcf.  See Note 6.

     Since August 1991, the Company has sold gas to a cogeneration facility
under a take-or-pay contract that expires in September 2004. The Company has
committed to sell up to 4,500 Mcf of gas per day under this contract, subject to
certain modifications, at a price based on a composite energy cost index. Since
the Company generally purchases such gas at spot prices, there is exposure to
loss during months of rapidly increasing gas prices. The Company recognized a
net loss on this contract of $551,000 and $206,000 during 1997 and 1996,
respectively, and a net profit of $453,000 during 1995.

     Section 29 Tax Credits

     In January 1998, the Company entered a contract to monetize Section 29 tax
credits generated by production from qualified properties, most of which were
acquired in December 1997. As a result, the Company anticipates receiving
approximately $1.8 million annually from 1998 through 2002 which will be
recorded as gas revenue.

     Litigation

     In June 1996, Holshouser v. Cross Timbers Oil Company, a class action
lawsuit, was filed in the District Court of Major County, Oklahoma.  The action
was filed on behalf of all parties who, at any time since June 1991, have
allegedly had production or other costs deducted by the Company from royalties
paid on gas produced in Oklahoma when the royalty is based upon a specified
percentage of the proceeds received from the gas sold.  The plaintiff alleges
that such deductions are a breach of the Company's contractual obligations to
the class and is seeking to recover an unspecified amount of damages as a result
of the alleged breach.  The plaintiff is also seeking a determination of the
Company's obligations to the plaintiff and the class regarding production or
other costs.  The Company has responded that it has complied with all of its
contractual obligations and denied that the matter is appropriate for
determination as a class action.  The parties have conducted discovery on the
class certification issues, but no further action has been taken in the case.
Management believes it has strong defenses against this claim and intends to
vigorously defend the action.  Management's estimate of the potential liability
from this claim has been accrued in the accompanying financial statements.

                                       38
<PAGE>

     The Company and certain of its subsidiaries are involved in various other
lawsuits and certain governmental proceedings arising in the ordinary course of
business.  Company management and legal counsel do not believe that the ultimate
resolution of these claims, including the class action lawsuit described above,
will have a material effect on the Company's financial position, liquidity or
operations.

     Other

     To date, the Company's expenditures to comply with environmental or safety
regulations have not been significant and are not expected to be significant in
the future.  However, developments such as new regulations, enforcement policies
or claims for damages could result in significant future costs.


5.  EQUITY

     Three-for-Two Stock Splits

     The Company effected a three-for-two common stock split on March 19, 1997
and on February 25, 1998.  All common stock shares, treasury stock shares and
per share amounts have been retroactively restated to reflect both stock splits.

     Public Offering of Common Stock

     In August 1995, the Company completed a public offering of 9,816,243 shares
of common stock, of which 5,062,500 shares were sold by the Company and
4,753,743 shares were sold by stockholders. The Company's net proceeds from the
offering of $29.5 million were used to partially fund a significant producing
property acquisition.

     Performance Shares

     During 1997, 1996 and 1995, the Company issued 180,000, 167,625 and 369,562
performance shares (Note 8).

     Series A Convertible Preferred Stock

     In September 1996, pursuant to the Company's exchange offer, a total of
2,979,249 shares of common stock  were exchanged for 1,138,729 shares of Series
A convertible preferred stock ("Preferred Stock").  The Company incurred costs
of $540,000 related to this exchange offer.  All exchanged shares of common
stock have been canceled and are authorized but unissued.  Preferred Stock is
recorded in the accompanying consolidated balance sheet at its liquidation
preference of $25 per share.

     Cumulative dividends on Preferred Stock 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, and is
redeemable, in whole or in part, by the Company after October 15, 1999.
Redemption is allowed only under certain circumstances on or before October 15,
2000 at $26.09 per share, and thereafter unconditionally at prices declining
ratably annually to $25.00 per share after October 15, 2006, plus dividends
accrued and unpaid to the redemption date.

     The Preferred Stock is convertible at the option of the holder at any time,
unless previously redeemed, into shares of common stock at a rate of 2.16 shares
of common stock for each share of Preferred Stock, subject to adjustment in
certain events.  Preferred Stock holders are allowed one vote for each common
share into which their Preferred Stock may be converted.

     Treasury Stock

     During 1997, 1996 and 1995, the Company acquired 2,571,396, 3,341,515 and
45,490 shares of its common stock at an average cost per share of $12.06, $10.45
and $7.72, respectively.  Additionally, the Company received 421,212, 457,994
and 21,465 shares in 1997, 1996  and 1995 that are held in treasury, as payment
for the option price upon exercise of stock options.

     Convertible Debt

     During November and December 1996, $27.7 million principal of the Company's
5 1/4% convertible subordinated notes (Note 2) was converted by noteholders into
2,696,521 shares of common stock.  In January 1997, principal of $29.7 million
of the notes was converted by noteholders into 2,892,363 shares of common stock.

                                       39
<PAGE>

     Common Stock Warrants

     As partial consideration for producing properties acquired in December 1997
(Note 10), the Company issued warrants to purchase 937,500 shares of common
stock at a price of $15.31 per share for a period of five years.  These warrants
were valued at $5,725,000 and were recorded as additional paid-in capital.

     Common Stock Dividends

     Since the Company's inception, the Board of Directors has declared
quarterly dividends of $0.033 per common share through 1996 and $0.037 per
common shares in 1997.  In January 1998, the Board of Directors increased its
regular quarterly cash dividend to $0.04 per share payable April 15, 1998 to
shareholders of record on March 31, 1998.  See Note 2 regarding restrictions on
dividends.

     Registration Statement

     On February 25, 1998, the Company filed a shelf registration statement with
the Commission to potentially offer securities which may include debt
securities, preferred stock, common stock or warrants to purchase debt
securities, preferred stock or common stock.  The securities will be offered at
an aggregate offering price not to exceed $200 million, at prices and on terms
to be determined at the time of sale.  Net proceeds from the sale of such
securities will be used for general corporate purposes, including reduction of
bank borrowings under the loan agreement (Note 2).


6.  FINANCIAL INSTRUMENTS

     Commodity Price Hedging Instruments

     The Company periodically enters into futures contracts, energy swaps,
collars, basis swaps and option agreements to hedge its exposure to price
fluctuations on crude oil and natural gas sales.  The Company did not have any
significant hedging activity from 1994 through 1997.  See Note 4.

     In January 1998, the Company entered into gas price collars with floor and
ceiling prices of $2.01 and $2.46 per Mcf for 30,000 Mcf per day from March
through September 1998.  In February and March 1998, the Company entered into
futures contracts to sell 10,000 Mcf per day from May through August 1998 at a
price of $2.35 per Mcf.  Prices to be realized by the Company for hedged
production will be less than these hedged prices because of location, quality
and other adjustments.

     In January 1998, the Company entered into basis swap agreements with three
financial institutions that effectively fix the delivery point differential
("basis") at $0.27 per Mcf on San Juan Basin gas production of 10,000 Mcf per
day in January 1998, 20,000 Mcf per day from February 1998 through March 1999,
and 10,000 Mcf per day from April 1999 through December 2000.

     Fair Value

     Because of their short-term maturity, the fair value of cash and cash
equivalents, accounts receivable and accounts payable approximates their
carrying values at December 31, 1997 and 1996.  The following are estimated fair
values and carrying values of the Company's other financial instruments (none of
which are held or issued for trading purposes) at these dates (in thousands):
<TABLE>
<CAPTION>
                                                       Asset (Liability)
                                        ---------------------------------------------
                                         December 31, 1997       December 31, 1996
                                        ----------------------  ---------------------
                                         Carrying      Fair      Carrying     Fair
                                          Amount      Value       Amount     Value
                                        ----------  ----------  ----------  ---------
<S>                                     <C>         <C>         <C>         <C>

     Investment in equity securities..  $       -   $       -   $  16,714   $  16,714
     Short-term debt..................  $       -   $       -   $  (3,000)  $  (3,000)
     Long-term debt...................  $(539,000)  $(538,288)  $(314,757)  $(317,331)
</TABLE>

     The above fair values were estimated based on:  investment in equity
securities- quoted market price; short and long-term debt- short-term borrowings
and bank borrowings approximate the carrying value because of short-term
interest rate maturities, while the fair value of subordinated notes is
estimated to be $299.3 million and $32.2 million at December 31, 1997 and 1996
based on a current market quote.


                                       40
<PAGE>
     Concentrations of Credit Risk

     Although the Company's cash equivalents and derivative financial
instruments are exposed to the risk of credit loss, the Company does not believe
such risk to be significant. Cash equivalents are high-grade, short-term
securities, placed with highly rated financial institutions. Most of the
Company's receivables are from a broad and diverse group of energy companies
and, accordingly, do not represent a significant credit risk. The Company's gas
marketing activities generate receivables from customers including pipeline
companies, local distribution companies 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 for
collectibility of all accounts receivable of $911,000 at December 31, 1997 and
1996.


7.  EARNINGS PER SHARE

     The following reconciles earnings (numerator) and shares (denominator) used
in the computation of basic and diluted earnings per share (in thousands,except
per share data):
<TABLE>
<CAPTION>
                                                                                    Earnings
                                                        Earnings       Shares       per Share
                                                        ---------     -------      ------------
<S>                                                     <C>           <C>          <C>
1997
------------------------------------------------------
     Basic
       Net income.....................................  $ 25,684
       Preferred stock dividends......................    (1,779)
                                                        --------
       Earnings available to common stock - basic.....    23,905      39,773 (a)   $    0.60
                                                                                   =========
     Diluted
       Effect of dilutive securities (b):
               Stock options..........................         -         451
         Warrants.....................................         -           3
               5 1/4% convertible subordinated notes..        46         115
                                                        --------      ------
       Earnings available to common stock - diluted...  $ 23,951      40,342 (a)   $    0.59
                                                        ========      ======       =========
1996
------------------------------------------------------
     Basic
       Net income.....................................  $ 20,304
       Preferred stock dividends......................      (514)
                                                        --------
       Earnings available to common stock - basic.....    19,790      39,913       $    0.50
     Diluted                                                                       =========
       Effect of dilutive securities:
               Stock options..........................         -         361
         5 1/4% convertible subordinated notes........     2,570       6,039
                                                        --------      ------
       Earnings available to common stock - diluted...  $ 22,360      46,313       $    0.48
                                                        ========      ======       =========
1995
------------------------------------------------------
     Basic
       Net loss before extraordinary item - basic.....  $(11,194)     38,072       $   (0.29)
                                                                      ======       =========
       Extraordinary item.............................       656
                                                        --------
       Net loss after extraordinary item - basic......  $(10,538)     38,072       $   (0.28)
                                                        ========      ======       =========
     Diluted
       Effect of dilutive securities..................         - (c)       - (c)

       Net loss before extraordinary item - diluted...  $(11,194)     38,072       $   (0.29)
                                                        ========      ======       =========
       Net loss after extraordinary item - diluted....  $(10,538)     38,072       $   (0.28)
                                                        ========      ======       =========
</TABLE>
       (a) The Company acquired 484,000 treasury shares from January through
           March 1998.
       (b) Based on common shares outstanding at December 31, 1997, potential
          conversion of Series A convertible preferred stock becomes dilutive to
          earnings per share at annual and quarterly net income levels exceeding
          approximately $28.5 million and $7.1 million, respectively.
       (c) Because of the loss, convertible securities have an antidilutive
          effect on loss per share.

                                       41
<PAGE>

8.  SUPPLEMENTAL CASH FLOW INFORMATION

     The consolidated statements of cash flows exclude the following non-cash
transactions (Notes 5, 9 and 10):

     -  Conversion of $29.7 million and $27.7 million principal amount of 5 1/4%
        Convertible subordinated notes into 2,892,363 and 2,696,521 shares of
        common stock in 1997 and 1996, respectively

     -  Issuance of warrants in 1997 to purchase 937,500 shares of common stock
        and exchange of properties valued at $15.7 million, as partial
        consideration for producing properties acquired

     -  Grants of 180,000, 167,625 and 369,562 performance shares to key
        employees and nonemployee directors in 1997, 1996 and 1995,
        respectively.

     -  Receipt of 421,212, 457,994, and 21,465 shares of common stock for the
        option price of exercised stock options in 1997, 1996 and 1995

     -  Exchange of 2,979,249 shares of common stock for 1,138,729 shares of
        Series A convertible preferred stock in 1996

     Interest payments during 1997 totaled $21,276,000, including $1,185,000 of
capitalized interest.  Interest payments during 1996 and 1995 totaled
$16,369,000 and $12,202,000 respectively.  Income tax payments during 1997, 1996
and 1995 totaled $941,000, $6,000 and $541,000, respectively.


9.  EMPLOYEE BENEFIT PLANS

     401(k) Plan

     The Company sponsors a 401(k) benefit plan that allows employees to
contribute and defer a portion of their wages. The Company matches employee
contributions of up to 8% of wages (10% of wages as of January 1, 1998).
Employee contributions vest immediately while the Company's matching
contributions vest 100% after three years of service.  All employees over 21
years of age and with at least three months service with the Company may
participate.  Company contributions under the plan were $1,180,000, $979,000 and
$814,000 in 1997, 1996 and 1995, respectively.

     1991 Stock Incentive Plan

     A total of 1,012,500 incentive units ("Units"), have been granted to
directors, officers and other key employees under the 1991 Stock Incentive Plan
("1991 Plan").  Units consist of a stock option ("Option") and a stock
appreciation right ("SAR"). An Option provides the right to purchase one share
of common stock at the exercise price, which generally is the market price at
the date the Unit is granted. A SAR entitles the recipient to a payment equal to
twice the excess of the market price of one share of common stock on the date
the Option is exercised over the exercise price. As of December 31, 1997, 3,341
Units remain available for grant under the 1991 Plan. General and administrative
expense includes stock incentive compensation related to SARs of $359,000, $3.7
million and $2.3 million for 1997, 1996 and 1995, respectively. SAR cash
payments were $288,000, $7.1 million and $800,000 in 1997, 1996 and 1995,
respectively.

     1994 and 1997 Stock Incentive Plans

     Under the 1994 Stock Incentive Plan ("1994 Plan")  and the 1997 Stock
Incentive Plan ("1997 Plan"), a total of 2,250,000 shares of common stock may be
issued under each plan to directors, officers and other key employees pursuant
to grants of Options or performance shares of common stock ("performance
shares").  At December 31, 1997, 25,177 and 320,625 shares remained available
for grant under the 1994 Plan and the 1997 Plan, respectively.  Options vest and
become exercisable on terms specified when granted by the compensation committee
("the Committee") of the Board of Directors.  Options granted under the 1994
Plan are not exercisable prior to six months and no Option is exercisable after
ten years from its grant date. Options granted under the 1994 Plan and the 1997
Plan generally vest in equal amounts over five years, with provisions for
earlier vesting if specified performance requirements are met. As of December
31, 1997, there are 878,625 outstanding stock options that vest when the common
stock price reaches $20.

     Performance shares are subject to restrictions determined by the Committee
and are subject to forfeiture if performance targets established by the
Committee are not met.  Otherwise, holders of performance shares generally have
all the voting, dividend and other rights of other stockholders.  The Company
issued to key employees 169,875, 154,125 and


                                       42
<PAGE>
356,062 performance shares during 1997, 1996 and 1995, respectively, of which
243,000 and 356,062 vested in 1997 and 1996, respectively, when the common stock
price reached specified levels. General and administrative expense includes
compensation related to these performance share grants of $3.3 million, $2.5
million and $2.8 million in 1997, 1996 and 1995, respectively. As of December
31, 1997, there are 81,000 performance shares that vest when the common stock
price reaches $20. The Company also issued to nonemployee directors a total of
10,125 performance shares in 1997 and 13,500 in each of 1996 and 1995.

     Unit/ Option Activity and Balances

     The following summarizes Unit and Option activity and balances from 1995
through 1997:
<TABLE>
<CAPTION>

                                         Weighted              1994 and
                                         Average   1991 Plan   1997 Plan
                                         Exercise  Incentive     Stock
                                          Price      Units      Options
                                         --------  ----------  ----------
<S>                                      <C>       <C>         <C>
     1995
     ----------------------------------
           Beginning of year...........    $ 6.12  1,006,502   1,229,659
              Grants...................      7.37          -     177,187
              Exercises................      5.36   (169,790)          -
              Forfeitures..............      6.55       (902)     (7,596)
                                                   ---------   ---------
           End of year.................      6.27    835,810   1,399,250
                                                   =========   =========
           Exercisable at end of year..      5.70    783,689     212,256
                                                   =========   =========

     1996
     ----------------------------------
           Beginning of year...........    $ 6.27    835,810   1,399,250
              Grants...................      9.64          -     303,750
              Exercises................      5.70   (784,658)   (211,079)
              Forfeitures..............      6.61       (189)     (4,925)
                                                   ---------   ---------
           End of year.................      7.32     50,963   1,486,996
                                                   =========   =========
           Exercisable at end of year..      6.66     50,963   1,006,146
                                                   =========   =========

     1997
     ----------------------------------
           Beginning of year...........    $ 7.32     50,963   1,486,996
              Grants...................     12.11          -   1,757,250
              Exercises................      6.75    (26,213)   (897,229)
              Forfeitures..............      8.79          -     (18,315)
                                                   ---------   ---------
           End of year.................     11.11     24,750   2,328,702
                                                   =========   =========
           Exercisable at end of year..     10.96     24,750   1,119,044
                                                   =========   =========

</TABLE>
    The following summarizes information about Units/ Options at December 31,
1997:
<TABLE>
<CAPTION>

                            Units/ Options Outstanding  Units/ Options Exercisable
                         ------------------------------ --------------------------
                                    Weighted   Weighted               Weighted
Average                              Average    Average               Average
Range of                            Remaining   Exercise              Exercise
Exercise Prices            Number     Term       Price       Number     Price
---------------          ---------  --------  -----------  --------- ----------
<S>                      <C>        <C>        <C>           <C>     <C>

1991 Plan
  $5.32 - $7.56....      24,750     4.1 years  $   5.44      24,750    $ 5.44

1994 and 1997 Plans
  $6.61 - $7.89....     305,580     7.3 years      7.11      198,467      6.90
  $9.67 - $10.92...     272,622     8.4 years      9.68       48,702      9.68
  $12.04 - $13.40..   1,750,500     9.4 years     12.12      871,875     12.12
                      ---------                            ---------
                      2,353,452     9.0 years     11.11    1,143,794     10.96
                      ==========                           =========

</TABLE>

                                       43
<PAGE>

     Estimated Fair Value of Grants

     Using the Black-Scholes option-pricing model and the following assumptions,
the weighted average fair value of option grants was estimated to be $5.05,
$3.82 and $2.58 for options granted in 1997, 1996 and 1995, respectively.
<TABLE>
<CAPTION>

                                            1997      1996      1995
                                          --------  --------  --------
<S>                                       <C>       <C>       <C>

       Risk-free interest rates.........      6.4%      6.4%      5.8%
       Dividend yield...................      1.6%      1.4%      1.4%
       Weighted average expected lives..  5 years   6 years   6 years
       Volatility.......................       47%       35%       31%
</TABLE>

     Pro Forma Effect of Recording Stock-Based Compensation at Estimated Fair
Value

     The following are pro forma earnings (loss) available to common stock and
earnings (loss) per common share for 1997 and 1996, as if stock-based
compensation had been recorded at the estimated fair value of stock awards at
the grant date, as prescribed by SFAS 123, Accounting for Stock-Based
Compensation (Note 1):
<TABLE>
<CAPTION>

(in thousands, except per share data)
                                                                1997      1996       1995
                                                               -------  ---------  ---------
<S>                                                            <C>      <C>        <C>
     Earnings (loss) available to common stock
       As reported......................................       $23,905  $ 19,790   $(10,538)
       Pro forma........................................       $21,646  $ 19,767   $(11,200)

     Earnings (loss) per common share:
       Basic     As reported.............................      $  0.60  $   0.50   $  (0.28)
                 Pro forma...............................      $  0.54  $   0.50   $  (0.29)

       Diluted   As reported.............................      $  0.59  $   0.48   $  (0.28)
                 Pro forma...............................      $  0.54  $   0.48   $  (0.29)

</TABLE>

10.  ACQUISITIONS

     From July 1996 through May 1997, the Company purchased 1,326,300, or 22%,
of the outstanding Units in the Royalty Trust at a cost of $18.2 million, funded
primarily with bank debt.  The Company purchased an additional 33,700 Units in
January 1998 at a cost of $500,000.  The Board of Directors has authorized the
purchase of up to two million, or 33%, of the outstanding  Units.  The Company
considers its investment in Units as an acquisition of oil and gas properties;
accordingly, the cost of these Units has been included in producing properties
in the accompanying consolidated balance sheets.

     On July 19, 1996, the Company acquired primarily gas-producing properties
in the Green River Basin of southwestern Wyoming from Enserch Exploration
("Enserch Acquisition") for an adjusted purchase price of $39.4 million.  The
properties primarily consist of operated interests in the Fontenelle, Nitchie
Gulch and Pine Canyon fields.  On November 21, 1996, the Company acquired
additional interests in the Fontenelle Unit, the most significant property
included in the Enserch Acquisition, for an adjusted purchase price of $12.5
million.  These acquisitions were funded by bank debt and cash flow from
operations.

     On December 2, 1996, the Company acquired primarily gas-producing
properties in the Northern Val Verde area of the Permian Basin of West Texas.
The properties are primarily operated interests in the Henderson, Ozona and
Davidson Ranch fields.  The adjusted purchase price of $28.1 million was funded
by bank debt and cash flow from operations.

     On May 14, 1997, the Company acquired primarily gas-producing properties in
Oklahoma, Kansas and Texas for an estimated adjusted purchase price of $39
million from a subsidiary of Burlington Resources Inc.  The properties are
primarily operated interests.  The Company funded the acquisition with bank debt
and cash flow from operations.

     On December 1, 1997, the Company acquired interests in certain producing
oil and gas properties in the San Juan Basin of New Mexico from a subsidiary of
Amoco Corporation ("Amoco Acquisition") for $252 million, including warrants to
purchase 937,500 shares of the Company's common stock at a price of $15.31 per
share for a period of five years.  After

                                       44
<PAGE>

adjustments for other acquisition costs, estimated cash flows through date of
closing and preferential purchase rights exercised by third parties, the
properties were purchased for approximately $195 million, including
approximately $5.7 million value for the warrants. Amoco elected to accept
certain producing properties owned by the Company valued at $15.7 million in
lieu of cash, reducing cash consideration to $173.6 million, which was funded
through bank lines of credit. Additional purchase price revisions may result
from customary post-closing adjustments.

     These acquisitions have been recorded using the purchase method of
accounting.  The following presents unaudited pro forma results of operations
for the years ended December 31, 1997 and 1996 as if these acquisitions had been
consummated as of January 1, 1996.  These pro forma results are not necessarily
indicative of future results.
<TABLE>
<CAPTION>

        (in thousands, except per share data)                Pro Forma (Unaudited)
                                                         -------------------------------
                                                           1997                   1996
                                                         --------               --------
<S>                                                     <C>                    <C>
       Revenues....................................      $237,515               $216,915
                                                         ========               ========

       Net income..................................      $ 26,469               $ 19,507
                                                         ========               ========

       Earnings available to common stock..........      $ 24,690               $ 18,993
                                                         ========               ========

       Earnings per common share:
            Basic..................................      $   0.62               $   0.48
                                                         ========               ========
            Diluted................................      $   0.61               $   0.47
                                                         ========               ========

</TABLE>

     On February 25, 1998, the Company entered into an agreement with EEX
Corporation to acquire producing properties and undeveloped acreage in the East
Texas Basin for $265 million ("EEX Acquisition").  The transaction is
anticipated to close in late April 1998 with an effective date of January 1,
1998.  The preliminary purchase price of $265 million is expected to be reduced
to $245 million by purchase price adjustments.  The acquisition is also subject
to third party consents and other typical purchase price adjustments.  The
Company plans to finance the acquisition through bank lines of credit.


11.  QUARTERLY FINANCIAL DATA (Unaudited)

     The following are summarized quarterly financial data for the years ended
December 31, 1997 and 1996 (in thousands, except per share data):
<TABLE>
<CAPTION>
                                                Quarter
                                   ---------------------------------
                                     1st      2nd      3rd      4th
                                   -------  -------  -------  -------
<S>                                <C>      <C>      <C>      <C>
1997
---------------------------------
     Revenues....................  $53,494  $45,969  $44,086  $57,123
     Gross profit (a)............  $25,833  $17,044  $14,594  $24,225
     Earnings available to
       common stock..............  $10,650  $ 3,735  $ 2,779  $ 6,741
     Earnings per common share
       Basic.....................  $  0.26  $  0.09  $  0.07  $  0.17
       Diluted...................  $  0.25  $  0.09  $  0.07  $  0.17
     Average shares outstanding..   40,395   39,498   39,581   39,629
1996
---------------------------------
     Revenues....................  $36,081  $36,735  $39,201  $49,374
     Gross profit (a)............  $13,482  $13,606  $14,240  $23,137
     Earnings available to
       common stock..............  $ 4,671  $ 1,807  $ 4,647  $ 8,665
     Earnings per common share
       Basic.....................  $  0.11  $  0.04  $  0.12  $  0.23
       Diluted...................  $  0.11  $  0.04  $  0.11  $  0.22
     Average shares outstanding..   41,402   41,171   39,644   37,465
</TABLE>
     (a) Revenues less expenses, other than general and administrative, net
         interest expense and income tax.

                                       45
<PAGE>

12.  SUPPLEMENTARY FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES
(Unaudited)

     All of the Company's operations are directly related to oil and gas
producing activities located in the United States.

     Costs Incurred Related to Oil and Gas Producing Activities

     The following table summarizes costs incurred whether such costs are
capitalized or expensed for financial reporting purposes (in thousands):
<TABLE>
<CAPTION>

                                   1997      1996      1995
                                 --------  --------  --------
<S>                              <C>       <C>       <C>
    Acquisitions:
       Producing properties....  $251,663  $105,252  $130,929
       Undeveloped properties..     3,964       563       413
    Development (a)............    86,555    44,758    20,797
    Exploration (b)............     2,088       280       264
                                 --------  --------  --------
    Total......................  $344,270  $150,853  $152,403
                                 ========  ========  ========
</TABLE>
    (a) Includes $800,000 of capitalized interest in 1997.  No interest was
        capitalized in prior years.
    (b) Includes geological and geophysical costs of $1,672,000, $103,000 and
        $169,000 in 1997, 1996 and 1995, respectively.


     Proved Reserves

     Independent petroleum engineers have estimated the Company's proved oil and
gas reserves, all of which are located in the United States.  Proved reserves
are the estimated quantities that geologic and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.  Proved developed reserves are
the quantities expected to be recovered through existing wells with existing
equipment and operating methods.  Due to the inherent uncertainties and the
limited nature of reservoir data, such estimates are subject to change as
additional information becomes available.  The reserves actually recovered and
the timing of production of these reserves may be substantially different from
the original estimate.  Revisions result primarily from new information obtained
from development drilling and production history and from changes in economic
factors.

     Standardized Measure

     The standardized measure of discounted future net cash flows ("standardized
measure") and changes in such cash flows are prepared using assumptions required
by the Financial Accounting Standards Board.  Such assumptions include the use
of year-end prices for oil and gas and year-end costs for estimated future
development and production expenditures to produce year-end estimated proved
reserves.  Discounted future net cash flows are calculated using a 10% rate.
Estimated future income taxes are calculated by applying year-end statutory
rates to future pre-tax net cash flows, less the tax basis of related assets and
applicable tax credits.

     The standardized measure does not represent management's estimate of the
Company's future cash flows or the value of proved oil and gas reserves.
Probable and possible reserves, which may become proved in the future, are
excluded from the calculations.  Furthermore, year-end prices used to determine
the standardized measure of discounted cash flows, are influenced by seasonal
demand and other factors and may not be the most representative in estimating
future revenues or reserve data.

                                       46
<PAGE>

<TABLE>
<CAPTION>


                                                        Oil             Gas         Natural Gas
                                                       (Bbls)          (Mcf)     Liquids (Bbls) (a)
                                                  ----------------  -----------  ------------------
PROVED RESERVES                                                    (in thousands)
<S>                                               <C>               <C>          <C>

  December 31, 1994.............................           33,581      177,061
    Revisions...................................            1,314        4,507
    Extensions, additions and discoveries.......            6,378       41,899
    Production..................................           (3,532)     (28,619)
    Purchases in place..........................            3,056      170,711
    Sales in place..............................             (809)      (7,489)
                                                       ----------   ----------

  December 31, 1995.............................           39,988      358,070
    Revisions...................................            2,361       29,379
    Extensions, additions and discoveries.......            2,220       37,480
    Production..................................           (3,508)     (37,275)
    Purchases in place..........................            1,552      153,400
    Sales in place..............................             (173)        (516)
                                                       ----------   ----------

  December 31, 1996.............................           42,440      540,538                   -
    Revisions...................................             (989)     (14,182)                  -
    Extensions, additions and discoveries.......            9,263      112,906                   -
    Production..................................           (3,980)     (49,587)                (80)
    Purchases in place..........................            3,195      248,040              13,890
    Sales in place..............................           (2,075)     (21,940)                  -
                                                       ----------   ----------          ----------

  December 31, 1997.............................           47,854      815,775              13,810
                                                       ==========   ==========          ==========

  PROVED DEVELOPED RESERVES

  December 31, 1994.............................           26,948      164,169
                                                       ==========   ==========

  December 31, 1995.............................           28,946      320,230
                                                       ==========   ==========

  December 31, 1996.............................           31,883      466,412
                                                       ==========   ==========

  December 31, 1997.............................           33,835      677,710              11,494
                                                       ==========   ==========          ==========

  STANDARDIZED MEASURE OF DISCOUNTED FUTURE                         December 31
                                                       -------------------------------------
    NET CASH FLOWS RELATING TO PROVED RESERVES            1997         1996          1995
                                                       ----------   ----------    ----------
                                                                    (in thousands)
  Future cash inflows...........................       $2,604,453   $2,634,641    $1,322,345
  Future costs:.................................
    Production..................................         (979,317)    (819,780)     (536,831)
    Development.................................         (140,594)     (77,837)      (72,607)
                                                       ----------   ----------    ----------
  Future net cash flows before income tax.......        1,484,542    1,737,024       712,907
  Future income tax.............................         (291,375)    (450,987)     (131,019)
                                                       ----------   ----------    ----------
  Future net cash flows.........................        1,193,167    1,286,037       581,888
  10% annual discount...........................         (551,058)    (579,556)     (246,732)
                                                       ----------   ----------    ----------

  Standardized measure (b)......................       $  642,109   $  706,481    $  335,156
                                                       ==========   ==========    ==========
</TABLE>
  (a) Proved reserves attributable to natural gas liquids were not considered
      significant prior to the Amoco Acquisition in December 1997 (Note 10).
      Natural gas liquids proved reserves as disclosed include only San Juan
      Basin properties purchased in this acquisition.
  (b) Before income tax, the standardized measure (or discounted present value
      of future net cash flows) was $782,322,000 $946,150,000 and $405,706,000
      at December 31, 1997, 1996 and 1995, respectively.

                                       47
<PAGE>

<TABLE>
<CAPTION>

CHANGES IN STANDARDIZED MEASURE OF
DISCOUNTED FUTURE NET CASH FLOWS              1997        1996       1995
                                           ----------  ----------  ---------
                                                     (in thousands)
<S>                                        <C>         <C>        <C>

  Standardized measure, January 1........  $ 706,481   $ 335,156   $213,146
                                           ---------   ---------   --------
  Revisions:
    Prices and costs.....................   (388,559)    360,053     67,528
    Quantity estimates...................     55,497      34,099      8,709
    Accretion of discount................     86,845      37,291     22,242
    Future development costs.............   (120,073)    (36,267)   (41,416)
    Income tax...........................     99,455    (169,118)   (36,109)
    Production rates and other...........     (1,614)       (155)    (2,682)
                                           ---------   ---------   --------
      Net revisions......................   (268,449)    225,903     18,272
  Extensions, additions and discoveries..     92,582      49,802     44,135
  Production.............................   (125,343)    (97,106)   (56,909)
  Development costs......................     73,062      33,484     16,616
  Purchases in place (a).................    207,387     160,670    106,137
  Sales in place.........................    (43,611)     (1,428)    (6,241)
                                           ---------   ---------   --------
      Net change.........................    (64,372)    371,325    122,010
                                           ---------   ---------   --------

  Standardized measure, December 31......  $ 642,109   $ 706,481   $335,156
                                           =========   =========   ========
</TABLE>
  (a) Based on the year-end present value (at year-end prices and costs) plus
      the cash flow received from such properties during the year, rather than
      the estimated present value at the date of acquisition.

     Year-end oil prices used in the estimation of proved reserves and
calculation of the standardized measure were $15.50, $24.25, $18.00,  and $16.00
per Bbl at December 31, 1997, 1996, 1995 and 1994, respectively.  Year-end
average gas prices were $2.20, $3.02, $1.68, and $1.66 per Mcf at December 31,
1997, 1996, 1995 and 1994.  Year-end average natural gas liquids prices were
$11.07 at December 31, 1997.  Proved oil and gas reserves and the standardized
measure at December 31, 1997 include 375,000 Bbls and 8,790,000 Mcf, and
$9,286,000, respectively, attributable to the Company's 22% ownership of the
Royalty Trust (Note 10).

     Price and cost revisions are primarily the net result of changes in year-
end prices, based on beginning of year reserve estimates.  Quantity estimate
revisions during 1997 are primarily the result of proved undeveloped reserve
additions attributable to increased development costs. Quantity estimate
revisions during 1996 are primarily the effect of the extended economic life of
proved reserves that resulted from development workovers and higher year-end oil
and gas prices.

                                       48
<PAGE>

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS



To the Board of Directors and Stockholders of
Cross Timbers Oil Company

We have audited the accompanying consolidated balance sheets of Cross Timbers
Oil Company and its subsidiaries as of December 31, 1997 and 1996, and the
related consolidated statements of operations, cash flows and stockholders'
equity for each of the three years in the period ended December 31, 1997.  These
financial statements are the responsibility of the Company's management.  Our
responsibility is to express an opinion on these financial statements based on
our audits.

We conducted our audits in accordance with generally accepted auditing
standards.  Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement.  An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements.  An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement 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 of the Company as of
December 31, 1997 and 1996, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 1997, in conformity
with generally accepted accounting principles.

As described in Note 1, effective October 1, 1995, the Company adopted Statement
of Financial Accounting Standards No. 121, Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of.



ARTHUR ANDERSEN LLP

Fort Worth, Texas
March 18, 1998

                                       49
<PAGE>

                                   SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized, on the 30th day of March
1998.

                                   CROSS TIMBERS OIL COMPANY



                                   By           Bob R. Simpson
                                      --------------------------------------
                                       Bob R. Simpson, Chairman of the Board
                                            and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities indicated on the 30th day of March 1998.



PRINCIPAL EXECUTIVE OFFICERS (AND DIRECTORS)            DIRECTORS



              Bob R. Simpson                         J. Luther King, Jr.
---------------------------------------      -----------------------------------
 Bob R. Simpson, Chairman of the Board              J. Luther King, Jr.
     and Chief Executive Officer



          Steffen E. Palko                               Jack P. Randall
---------------------------------------      -----------------------------------
    Steffen E. Palko, Vice Chairman                      Jack P. Randall
      of the Board and President



           J. Richard Seeds                             Scott G. Sherman
---------------------------------------      -----------------------------------
           J. Richard Seeds,                            Scott G. Sherman
       Executive Vice President





          PRINCIPAL FINANCIAL OFFICER        PRINCIPAL ACCOUNTING OFFICER




           Louis G. Baldwin                           Bennie G. Kniffen
---------------------------------------      -----------------------------------
Louis G. Baldwin, Senior Vice President               Bennie G. Kniffen,
     and Chief Financial Officer                    Senior Vice President
                                                        and Controller

                                       50
<PAGE>

                                 INDEX TO EXHIBITS

Exhibit
  No.                              Description                             Page
--------   -----------------------------------------------------------    ------

  3.1      Certificate of Incorporation of Cross Timbers Oil Company,
           as amended through and restated on May 18, 1994 (incorporated
           by reference to Exhibit 4.1 to Registration Statement on
           Form S-8, File No. 33-81766)

  3.2      Bylaws of Cross Timbers Oil Company (incorporated by
           reference to Exhibit 3.4 to Registration Statement on
           Form S-1, File No. 33-59820)

  4.1      Form of Certificate of Designations of Series A Convertible
           Preferred Stock, par value $.01 per share (incorporated by
           reference to Exhibit 4 to Form 8-A/A, Amendment No. 1, dated
           September 3, 1996)

  4.2      Indenture dated as of April 1, 1997, between Cross Timbers
           Oil Company and The Bank of New York, as Trustee for the
           9 1/4% Senior Subordinated Notes due 2007 (incorporated
           by reference to Exhibit 4.1 to Registration Statement of
           Form S-4, File No. 333-26603).

  4.3      Indenture, dated as of October 28, 1997, between Cross Timbers
           Oil Company and the Bank of New York, as Trustee for the
           8 3/4% Senior Subordinated Notes due 2009 (incorporated by
           reference to Exhibit 4.1 to Registration Statement on
           Form S-4, File No. 333-39097).

 10.1      Revolving Credit Agreement dated November 21, 1997, between
           Cross Timbers Oil Company and certain commercial banks
           named therein (incorporated by reference to Exhibit 99.1
           to Form 8-K dated December 1, 1997)

 10.2      Employment Agreement between the Company and Bob R. Simpson,
           dated February 21, 1995 (incorporated by reference to
           Exhibit 10.6 to Form 10-K for the year ended
           December 31, 1994)

 10.3      Employment Agreement between the Company and Steffen E. Palko,
           dated February 21, 1995 (incorporated by reference to Exhibit
           10.7 to Form 10-K for the year ended December 31, 1994)

 10.4      1991 Stock Incentive Plan (incorporated by reference to
           Exhibit 10.7 to Registration Statement on Form S-1,
           File No. 33-59820)

 10.5      Form of grant under 1991 Stock Incentive Plan (incorporated by
           reference to Exhibit 10.8 to Registration Statement on Form S-1,
           File No. 33-59820)

 10.6      1994 Stock Incentive Plan (incorporated by reference to
           Exhibit 4.4 to Registration Statement on Form S-8, File
           No. 33-81766)

 10.7      Form of grant under 1994 Stock Incentive Plan (incorporated by
           reference to Exhibit 4.5 to Registration Statement on Form S-8,
           File No. 33-81766)

 10.8      1997 Stock Incentive Plan, as amended February 25, 1998

                                       51
<PAGE>

Exhibit
  No.                              Description                             Page
--------   -----------------------------------------------------------    ------

 10.9      Form of grant under 1997 Stock Incentive Plan, as amended
           February 25, 1998

           a. Employee option grant
           b. Employee performance share grant
           c. Non-employee director option grant
           d. Non-employee director performance share grant
           e. Amendment to award agreements under the 1997 Stock
              Incentive Plan

 10.10     Registration Rights Agreement among Cross Timbers Oil Company
           and partners of Cross Timbers Oil Company, L.P. (incorporated
           by reference to Exhibit 10.9 to Registration Statement on
           Form S-1, File No. 33-59820)

 10.11     Warrant Agreement dated December 1, 1997 by and between
           Cross Timbers Oil Company and Amoco Corporation

 12.1      Computation of Ratio of Earnings to Fixed Charges

 21.1      Subsidiaries of Cross Timbers Oil Company

 23.1      Consent of Arthur Andersen LLP

 23.2      Consent of Miller and Lents, Ltd.



--------------------------------

     Copies of the above exhibits not contained herein are available, at the
     cost of reproduction, to any security holder upon written request to the
     Secretary, Cross Timbers Oil Company, 810 Houston St., Suite 2000, Fort
     Worth, Texas 76102.

                                       52