<PAGE>

                               2001 ANNUAL REPORT

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                                 UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549

                                   FORM 10-K
                 ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001       COMMISSION FILE NUMBER 0-10697

               [DORCHESTER LOGO]  DORCHESTER HUGOTON, LTD.
             (Exact name of registrant as specified in its charter)

<Table>
<S>                                                    <C>
                        TEXAS
           (State or other jurisdiction of                                  75-1829064
           incorporation or organization)                      (I.R.S. Employer Identification No.)
</Table>

         1919 S. SHILOH ROAD, SUITE 600-LB48, GARLAND, TEXAS 75042-8234
          (Address of principal executive offices, including Zip Code)

       Registrant's telephone number, including area code: (972) 864-8610

       Securities registered pursuant to Section 12(b) of the Act:  NONE

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

  DEPOSITARY RECEIPTS FOR UNITS OF LIMITED PARTNERSHIP INTEREST IN DORCHESTER
                                 HUGOTON, LTD.

                                (Title of Class)

     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 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]

     The aggregate market value of the voting securities held by non-affiliates
of the registrant on JANUARY 1, 2002 was $127,888,000.

     As of FEBRUARY 1, 2002, there were outstanding Depositary Receipts for
10,744,380 Units of Limited Partnership Interest in Dorchester Hugoton, Ltd.

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<PAGE>

                             CROSS REFERENCE SHEET

<Table>
<Caption>
                         FORM 10-K ITEM
                       NUMBER AND CAPTION                             CAPTION IN FORM 10-K
                       ------------------                             --------------------
<C>  <S>                                                     <C>
PART I:

 1.  Business..............................................  Business and Properties of the
                                                               Partnership
 2.  Properties............................................  Business and Properties of the
                                                               Partnership
 3.  Legal Proceedings.....................................  Financial Information
 4.  Submission of Matters to a Vote of Security Holders...  None

PART II:
 5.  Market for Registrant's Common Equity and Related
     Stockholder Matters...................................  Depositary Receipts and the Depositary
                                                               Agreement
 6.  Selected Financial Data...............................  Selected Financial Data
 7.  Management's Discussion and Analysis of Financial
     Condition and Results of Operations...................  Management's Discussion and Analysis of
                                                               Financial Condition And Results of
                                                               Operations
 8.  Financial Statements and Supplementary Data...........  Financial Information
 9.  Changes in and Disagreements with Accountants on
     Accounting and Financial Disclosure...................  None

PART III:
10.  Directors and Executive Officers of the Registrant....  The Partnership
11.  Executive Compensation................................  The Partnership
12.  Security Ownership of Certain Beneficial Owners and
     Management............................................  Principal Holders
13.  Certain Relationships and Related Transactions........  The Partnership

PART IV:
14.  Exhibits and Reports on Form 8-K......................  Financial Information
</Table>
<PAGE>

                   BUSINESS AND PROPERTIES OF THE PARTNERSHIP

     Dorchester Hugoton, Ltd. (the "Partnership") has its principal place of
business at 1919 S. Shiloh Road, Suite 600-LB 48, Garland, Texas 75042-8234
(telephone (972) 864-8610) with field offices in Hooker, Oklahoma and Amarillo,
Texas and employed fourteen full time permanent employees (not including General
Partners) as of January 1, 2002. The Partnership was formed on June 16, 1982 as
a Texas limited partnership pursuant to a Certificate and Agreement of Limited
Partnership (as amended, the "Partnership Agreement"). Depositary receipts for
units of limited partnership interest were originally distributed on August 20,
1982 in the form of a taxable property dividend.

     The Partnership's principal operating assets consist of working interests
and support facilities for properties that produce natural gas from the Hugoton
gas field in Kansas and Oklahoma. The Hugoton field is considered one of the
most prolific gas fields in the United States. All of the Partnership's current
working interest wells (except for Kansas infill wells and Oklahoma replacement
and Fort Riley wells) were drilled and have been producing since prior to 1954.

OKLAHOMA PROPERTIES

     During 1998 the Partnership sold its working interest in one non-operated
Oklahoma well and, at the same time, acquired overriding royalty interests in
one Partnership owned and operated well. As a result, the Partnership's Oklahoma
working interests changed from 128 natural gas wells (115.7 net wells) to 127
natural gas wells (115.2 net wells) in the Guymon-Hugoton field. Additionally,
the Partnership's gross developed Oklahoma acreage changed from 80,501 acres
(74,621 net acres) to 79,861 acres (74,301 net acres). The Partnership continues
to operate and own interests in 117 wells in Oklahoma, of which the Partnership
has a 100% working interest in 109 wells, working interests ranging from 50% to
88% in 5 wells and liquefiable hydrocarbons interests only in the remaining 3
wells. The Partnership also has working interests ranging from 25% to 50% per
well in a 10 well group (previously 11) operated by an unaffiliated third party.
The Partnership also has minor royalty interests in various producing natural
gas wells. During December 1999 the Partnership acquired a 1.6% royalty interest
in one well operated by the Partnership and in one non-Hugoton well operated by
others. During December 2000, the Partnership acquired a 4.5% royalty interest
in another Oklahoma Partnership operated well. During 2001, the Partnership
acquired royalty interests ranging from .02% to 1.2% in 8 Oklahoma Partnership
operated wells.

     Of the Partnership's 127 gas wells, 124 deliver natural gas through a 132
mile Partnership owned and operated gas pipeline gathering system to the
Partnership's Oklahoma gas compressor station. Beginning November 1, 1994, the
Partnership began operation of a new 5400 horsepower gas compression and
dehydration facility and delivered gas to Panhandle Eastern Pipe Line Company
("PEPL"). Numerous other transmission pipelines are also nearby. The total cost
of these facilities was $6.0 million which included offices and warehouse
storage for both field and compressor operations. During 1999 the Partnership
installed two field rental gas compression units in Oklahoma. See "Regulation
and Prices" for more information.

     The Partnership began delivery of gas from its Oklahoma compression
facilities to Williams Gas Processing -- Mid Continent Region Co., a subsidiary
of the Williams Companies, Inc. during December 1996 following Federal Energy
Regulatory Commission approval. Williams Field Services Company subsequently
processes the gas at its plant near Baker, Oklahoma and returns the gas as
directed by the Partnership to the available transmission pipelines at the plant
outlet which include Williams Natural Gas Company, PEPL, and Natural Gas
Pipeline Company of America. The gas returned to the Partnership for subsequent
sale is of improved quality, including having the contaminant nitrogen removed.
Effective February 28, 2002 Williams Field Services will sell the processing
facility to Duke Energy Field Services, L.P., who intends to shift the
processing to its facility near Liberal, Kansas.

     Wells in the Guymon-Hugoton field are drilled into a 150 feet thick
geological formation commonly called the Chase Group. An average Partnership
well will encounter the top of the Chase Group approximately 2,700 feet below
the surface. This formation typically consists of non-productive
                                        1
<PAGE>

shale rock layers that separate the productive zones commonly called Herington,
Krider, Winfield and the deeper Fort Riley, which is sometimes referred to as
Towanda. At the time of drilling the Partnership's wells (primarily during the
late 1940's), the Fort Riley zone was considered to contain salt water rather
than natural gas and was not penetrated. Based on current information, the Fort
Riley zone for the most part appears to be full of water.

     The Partnership believes that it is possible that some of the Partnership
acreage contains gas productive Fort Riley zones without excessive water
saturation. The Partnership's existing wells are mechanically not capable of
being deepened. Consequently, to explore in the Fort Riley zone requires
drilling a well and isolating the zone for testing. Considering the numerous
unknown factors such as possible salt water and possible previous lateral gas
migration in the Fort Riley, the Partnership continues to urge caution in
predicting the outcome of such exploration.

     Thus far the Partnership has drilled and completed three wells to test the
Fort Riley zone. Each of the three wells replaced an existing gas well which was
plugged and abandoned as required by Oklahoma regulations. The first of the
three wells initially appeared to be favorable in both the Fort Riley zones and
Winfield/Krider zones; however, subsequent testing indicated that gas leaked
upward through the shale rock layer separating the zones, causing Fort Riley
evaluations to be inconclusive. The first of the three wells recently produced
377 MCF per day at 41 psig which is an improvement over the plugged well's
previous 105 MCF per day at 24 psig. The second of the three Fort Riley test
wells was not as successful, producing 78 MCF per day while pumping 30 bbls of
water per day. This second well replaced a Winfield/Krider well that produced
175 MCF per day with no water. In December 1998, this second Fort Riley well was
plugged and recompleted in the Winfield/ Krider zone, and in September 2001,
produced 142 MCF per day at 17 psig. During October 2001, the Partnership
reopened the previously plugged Fort Riley zone in this second well. At present,
this second well is producing 202 MCF per day at 16 psig and 38 bbls of water
per day from the commingled Winfield/Krider/Fort Riley zones. The third Fort
Riley test recently produced 46 MCF per day at 15 psig while pumping 25 bbls of
water per week. The third Fort Riley test replaced a Winfield/Krider well that
produced 85 MCF per day at 20 psig.

KANSAS PROPERTIES

     The Partnership currently operates and owns 100% of the working interest in
20 natural gas wells producing from the Kansas Hugoton field on 7,035 gross
developed acres. The natural gas from these operated wells is currently
delivered through a 26-mile gas gathering pipeline and compression facility
owned by the Partnership and is then sold at an index (average) of field market
prices. In November 1997 the Partnership began operation of additional gas
gathering pipelines and seven rental gas compressor units which are scattered
over a ten-mile area. Initial results showed a favorable increase in gas sales
which have since decreased similar to other producers' wells in the area. The
total capital cost was approximately $470,000. The Partnership's Kansas
operating costs for such field gas compression operations were approximately
$344,000 in 1998, $288,000 in 1999, $243,000 in 2000, and $249,000 in 2001.

     During 1986, the Kansas Corporation Commission ("KCC") issued an order
authorizing infill drilling on 320 acre spacing. Previously, each gas well
required 640 acres. The Partnership drilled and completed on its operated
properties eight producing wells through 1990 and one each in 1995, 1996 and
1997. One infill well was plugged in 1992 and another in 1993 for economic
reasons.

     During July 1998 the Partnership acquired in Kansas a royalty interest of
approximately 3% that included two wells operated by the Partnership and two
non-Hugoton wells operated by others. The Partnership also has minor overriding
royalty interests in producing natural gas wells in Kansas.

NATURAL GAS RESERVES AND OTHER FINANCIAL DATA

     Information with respect to the Partnership's natural gas reserves and
other financial data is presented in Note 5 to the Financial Statements included
elsewhere herein.
                                        2
<PAGE>

PARTNERSHIP OPERATIONS

     The Partnership has operated most of its properties since July 1, 1984.
Historically the cash necessary to pay the costs and expenses of operating the
Partnership and its properties, including debt service, has been provided by the
cash flow from the Partnership's producing properties. To the extent that
Partnership operations, including any future development of its properties,
require cash in excess of the Partnership's cash flow, the Partnership has
secured a financing commitment from a bank. See Note 2 to the Financial
Statements for a discussion regarding current bank borrowings.

REGULATION AND PRICES

     The transportation of natural gas after sale by the Partnership is
generally subject to regulation by federal authorities, specifically by the
Federal Energy Regulatory Commission (also referred to as the "FERC"), and
production of natural gas is regulated by various state agencies or authorities.
The Partnership's operations are also affected by various statutory controls or
obligations and, in varying degrees, by political developments and federal and
state laws and regulations. Natural gas production is affected by changing
federal and state tax and other laws which are specifically applicable to the
oil and gas industry, by constantly changing federal and state administrative
regulations as well as possible interruption or termination by government
authorities due to ecological and other considerations. Allowable gas production
rates have been, and are, to varying degrees, subject to conservation and
environmental laws and regulations.

     Both Kansas and Oklahoma regulate the amount of natural gas that can be
produced by assigning to each well or proration unit a monthly allowable rate of
production. Kansas and Oklahoma also specifically regulate the drilling of new
or replacement oil and gas wells, the spacing of wells, the prevention of waste
of natural gas resources, environmental protection and various other matters.

     During 2000, Kansas adopted new regulatory rules, agreed upon by most
producers, to enable the use of field compressors to operate Hugoton field wells
at a vacuum and provide that no well will be restricted to less than 100 mcf per
day. Possible effects of state allowed production in excess of 100 MCF per day
are not predictable. The Partnership has received approval to operate all its
wells at a vacuum; thus far, the Partnership has not experienced any significant
increase in current production. The existing Partnership rental compressors have
been adequate to create a vacuum.

     At present, the Oklahoma Guymon-Hugoton field is restricted by state
conservation regulations to a maximum of one well for each 640 acres (subject to
minor variances). Including the Partnership's 127 wells, there are about 1,350
currently producing gas wells in the Guymon-Hugoton field owned by both
independent producers and major oil and gas companies. Previously, a few
producers and numerous other interested parties in the area were actively
seeking either regulatory or legislative changes to enable "increased density
drilling" similar to Kansas infill drilling on 320 acre spacing. At present,
several producers in the field have actively opposed such infill drilling. The
difference in beliefs appears to rest in whether such infill drilling results in
increased reserves. In 1989 the Oklahoma Corporation Commission ("OCC")
concluded hearings on infill drilling and determined the present density of one
well per 640 acres was adequate to drain the 640 acres. Numerous studies of the
Kansas infill drilling results concluded that no new reserves were developed by
infill drilling. This conclusion is consistent with the Partnership's experience
in Kansas.

     A change in the Guymon-Hugoton field rules allowing infill drilling could
result in a large number of wells being drilled that are not needed to produce
the same gas that is being produced by the existing wells. The Partnership
believes it is not usually economically justifiable to drill a second well on
640 acres in Oklahoma just to produce the same gas as the original well, only
faster. THE OUTCOME AND COST OF INFILL DRILLING IS UNPREDICTABLE. In late
February 1997, Oklahoma did not pass legislation that would have allowed "infill
drilling." Similar proposed legislation may arise in the future. On June 21,
1999 Oklahoma enacted legislation that clarifies who must receive notices of any
application for Guymon-Hugoton infill drilling. Currently no such applications
have been filed and such filings are expected to be controversial and require
lengthy regulatory proceedings.
                                        3
<PAGE>

     On October 28, 1997 the OCC, which administers oil and gas conservation in
Oklahoma, conducted a hearing on a proposal to change the allowable amount of
production per well in the Guymon-Hugoton field. The hearing included
contradictory viewpoints that the proposal encouraged infill drilling vs. that
the proposal had no effect on the infill drilling issue. On February 4, 1998 the
OCC adopted rules that essentially removed production volume limits from nearly
all wells in the Guymon-Hugoton field effective July 1, 1998 and specifically
provided that the rule changes have no bearing on the question of infill
drilling which must be decided separately. Thus far only one company on
adjoining acreage has installed gas compression to try to benefit from
Oklahoma's removal of production limits. The Partnership elected to install
similar rental compression to stay competitive. Since 2000, seven of the
Partnership's wells have been assisted by such field compressors vs. five during
1999. Costs to operate the compressor units were approximately $79,000 in 2000
and $85,000 in 2001. The increase in production has more than offset costs of
compression. Further activities by others resulting from the field rule changes
and related costs and/or benefits to the Partnership are unpredictable.

     The pricing of all the Partnership's gas sales, both in Kansas and
Oklahoma, is primarily determined by supply and demand in the marketplace. This
price can fluctuate considerably. During 2001 the highest monthly average price
was $10.02/MMBTU in January and the lowest monthly average was $1.85/MMBTU in
October. The Partnership anticipates continued fluctuations in marketplace
pricing. See Note 1 to the Financial Statements for a discussion regarding
material customers and contracts.

     The FERC allows regulated transmission pipelines to transfer or sell
portions of their system classified or reclassified by the FERC as gas gathering
pipelines to non-regulated entities or affiliates. Most of the Partnership's
Oklahoma gas was not affected by any such sale or transfer and the effect on the
Partnership in Kansas has been minimal since only one of the two transmission
pipelines to which the Partnership delivered gas became a non-regulated
gathering pipeline in 1996. Since then the Partnership's gas from the 20 Kansas
wells was delivered directly to a transmission pipeline or sold to Duke Energy
Field Services, Inc. at the outlet of the Partnership's compressors. On May 1,
2000 the Partnership extended year to year a previously four-year gas sales
agreement with WFS Gas Resources Company (part of Williams Companies, Inc.)
providing for gathering, compression, and sale of gas at market prices. This
agreement covers only 3 wells (in which the Partnership has minimal interest)
that are not connected to the Partnership's Oklahoma gas gathering pipeline and
compression facilities. This sales agreement replaced the previously regulated
gathering and compression services provided by Williams Natural Gas Company.
Both Kansas and Oklahoma have adopted state regulation of gas gathering pipeline
systems available for hire which excludes the Partnership's facilities.
Additionally, current court decisions in both Kansas and Oklahoma sharply
restrict the practice of requiring royalty owners to bear their share of gas
gathering and compression costs. The Partnership has never charged royalty
owners for such costs.

COMPETITION

     The energy industry in which the Partnership competes is subject to intense
competition among a large number of companies, both larger and smaller than the
Partnership, many of which have financial and other resources greater than the
Partnership. See Note 1 to the Financial Statements for a discussion regarding
material customers.

ENVIRONMENTAL LAWS AND REGULATIONS

     The costs associated with the Partnership's compliance with environmental
laws and regulations has not had, and is not anticipated to have, a material
effect on its capital expenditures, earnings or competitive position. The
Partnership's gas production contains minimal contaminants other than nitrogen,
which is inert and non-toxic. The Partnership's quarterly air emission tests at
its Oklahoma compression facility continue to comply with the Oklahoma
Department of Environmental Quality's air quality regulations. The Kansas
Department of Health and Environment ("KDHE") on July 24,
                                        4
<PAGE>

1997 issued the Partnership an air emissions operating permit for its Kansas
compression facility. Previously such a permit was not required. At present, no
permits are necessary for the seven rental field compressors installed in Kansas
during 1997 or the two rental field compressors installed in Oklahoma during
1999.

                DEPOSITARY RECEIPTS AND THE DEPOSITARY AGREEMENT

     Immediately subsequent to its formation, all of the Partnership's units of
limited partnership interest ("Units") were deposited with an authorized
depositary ("Depositary"), to be held in accordance with the Depositary
Agreement. Effective September 8, 1998 the Depositary became BankBoston, N.A.,
which is now EquiServe Trust Company, N.A., P.O. Box 8040, Boston, MA 02266. The
Depositary maintains an account with respect to the Units deposited for which it
has issued Depositary Receipts. Holders of Depositary Receipts (also referred to
as "Unitholders") may transfer, combine or subdivide them at any office of the
Depositary designated for such purpose. Unitholders may also surrender them to
the Depositary and, upon submission of such documents as the General Partners
may require, reclaim deposited Units. However, the Units will not be readily
transferable and any redeposit of Units against newly issued Depositary Receipts
will require 60 days' advance written notice and is subject to certain other
conditions.

     The Depositary Receipts have been traded on the Nasdaq Stock Market under
the symbol "DHULZ" since August 26, 1982. The quoted market prices and reported
trading volumes for 2001 and 2000 were as follows:

<Table>
<Caption>
                                         2001                                         2000
                       -----------------------------------------    -----------------------------------------
                         LOW            HIGH            VOLUME        LOW            HIGH            VOLUME
                       -------         -------         ---------    -------         -------         ---------
<S>                    <C>             <C>             <C>          <C>             <C>             <C>
First Quarter........  12.2500         15.8750         1,005,000     8.8750         10.0625           687,000
Second Quarter.......  11.2500         14.5555         1,183,000     9.9375         14.1250         1,055,000
Third Quarter........  12.5000         14.8000           610,000    13.3750         15.6250           966,000
Fourth Quarter.......  10.2300         14.8571           409,000    13.0000         16.2500         1,251,000
</Table>

     As of January 1, 2002, there were approximately 4,900 Unitholders.

     The Units and the Depositary Receipts are fully paid and non-assessable.
Each record holder of a Depositary Receipt evidencing the ownership of one or
more Units will, for purposes of the Texas Revised Limited Partnership Act
("TRLPA"), be an assignee with respect to the interests in the Partnership
represented by such Units. Each such assignee may become a Substituted Limited
Partner upon (i) the execution and delivery of a request and agreement to become
a Substituted Limited Partner, which includes a power of attorney to the General
Partners, (ii) the approval of the General Partners to such admission as a
Substituted Limited Partner, and (iii) the filing of an amended Certificate of
Limited Partnership evidencing the admission of such person as a Substituted
Limited Partner. If such action is not taken, Unitholders will remain assignees
of the interests of the Partnership represented by the Units. Under certain
circumstances, a Unitholder may not become a Substituted Limited Partner if such
holder is not an Eligible Citizen. Each Unitholder (whether an assignee or
Limited Partner) as of the last day of each month is allocated a pro rata share
of the Partnership's profits and losses for the month then ended, regardless of
whether such holder receives any cash distributions from the Partnership. Each
Unitholder of record (whether an assignee or Limited Partner) as of the
applicable record date is entitled to receive an allocable share of any cash
distributions made by the Partnership. The timing and amount of such
distributions is determined by the General Partners. In addition, the
Partnership's Loan Agreement with Bank One, Texas, NA requires the Partnership
capital to remain above certain specified amounts. The Partnership Agreement
provides that prior to the dissolution of the Partnership, the General Partners
shall determine the amount of cash available for distribution, if any, at least
as of the end of each calendar quarter.

                                        5
<PAGE>

     Effective with the third quarter 1995 distribution, the Partnership's
transfer agents have paid all distributions as declared. Distributions per Unit,
including special distributions, have been as follows:
<Table>
<Caption>
                                                          CALENDAR YEAR
                       -----------------------------------------------------------------------------------
QUARTER                1982    1983   1984   1985/86   1987   1988   1989/90/91   1992   1993   1994/95/96
-------                -----   ----   ----   -------   ----   ----   ----------   ----   ----   ----------
<S>                    <C>     <C>    <C>    <C>       <C>    <C>    <C>          <C>    <C>    <C>
First................    N/A   $.02   $.01    $.01     $.02   $.03      $.05      $.05   $.12      $.17
Second...............    N/A    .01    .01     .01      .02    .04       .05       .05    .15       .17
Third................  $ .01    .01    .01     .01      .03    .04       .05       .05    .17       .17
Fourth...............    .02    .01    .01     .02      .03    .04       .05       .08    .17       .17
                       -----   ----   ----    ----     ----   ----      ----      ----   ----      ----
Total................  $ .03   $.05   $.04    $.05     $.10   $.15      $.20      $.23   $.61      $.68
                       =====   ====   ====    ====     ====   ====      ====      ====   ====      ====

<Caption>
                             CALENDAR YEAR
                       -------------------------
QUARTER                1997/98/99   2000   2001
-------                ----------   ----   -----
<S>                    <C>          <C>    <C>
First................     $.18      $.28   $ .27
Second...............      .18       .18     .42
Third................      .18       .22     .27
Fourth...............      .18       .22     .27
                          ----      ----   -----
Total................     $.72      $.90   $1.23
                          ====      ====   =====
</Table>

     After dissolution of the Partnership, distributions to each Unitholder of
record (whether an assignee or Limited Partner) will be made in accordance with
the Partnership Agreement.

     Hugoton Nominee, Inc., a Texas nominee corporation ("Nominee"), was formed
in August 1982 on behalf of the Partnership and has agreed to act as the Limited
Partner of record for those Unitholders of record who do not become Substituted
Limited Partners. If Nominee receives notice of any action requiring the vote of
Limited Partners, it will provide or cause to be provided such notice to the
Unitholders of record representing Units for which Nominee is acting as the
Limited Partner of record and inform those holders of their rights to become
Substituted Limited Partners. The Partnership is required to reimburse Nominee
for all expenses incurred in such capacity ($601 for 2001 and $507 for 2000) and
shall indemnify it against certain liabilities incurred by Nominee in such
capacity. Nominee may at any time resign or be removed by the Partnership, and a
successor appointed.

     The following summary is subject to the detailed provisions of the
Depositary Agreement and is qualified by reference to the Depositary Agreement,
copies of which are available at the Partnership's office and the Depositary.

     The Depositary may at any time resign or be removed by the Partnership, and
a qualified successor appointed. Any corporation into or with which the
Depositary may be merged or consolidated shall be the successor of the
Depositary without the execution or filing of any document or any further act.

     Any provision of the Depositary Agreement, including the form of Depositary
Receipt, may at any time and from time to time be amended by agreement between
the Partnership and the Depositary in any respect deemed necessary or desirable
by them that does not adversely affect any substantial right of the Unitholders
of record. The Unitholders of record representing twenty-five percent (25%) or
more of the deposited Units may at any time propose an amendment or amendments
to the Depositary Agreement. Any amendment of the Depositary Agreement that
imposes any fee, tax, or charge (other than fees and charges provided for in the
Depositary Agreement) upon, or otherwise adversely affects any substantial
rights of Unitholders of record shall not be effective until the expiration of
thirty (30) days after notice of the amendment has been given to the Unitholders
of record or, if the amendment is presented for a vote of the Unitholders of
record, until it has been approved by the affirmative vote of the Unitholders of
record representing fifty percent (50%) or more of the deposited Units. For the
purpose of considering any amendment of the Depositary Agreement that adversely
affects any substantial right of the Unitholders of record or any amendment
proposed by Unitholders of record but not adopted by the Depositary and the
Partnership, the Partnership shall call a meeting of Unitholders of record to be
held at a place in Dallas, Texas designated by the Partnership. The call shall
set forth the time, place, and purpose of the meeting, and notice thereof shall
be mailed at least twenty (20) days before the meeting to each record holder at
the close of business on the record date selected by the Partnership for the
purpose of the meeting. Any record holder may waive such notice. At the meeting
each record holder shall have one vote for each deposited Unit evidenced by each
Depositary Receipt registered in his name and may cast such vote in person or by
proxy. At the

                                        6
<PAGE>

meeting the presence in person or by proxy of Unitholders of record evidencing
at least fifty percent (50%) of the deposited Units shall be necessary to
constitute a quorum. If a proposed amendment is approved by the Unitholders of
record representing fifty percent (50%) or more of the deposited Units and if,
in the case of an amendment that alters the duties or liabilities of the
Depositary, the Partnership or any General Partner thereof, it is approved in
writing by whichever of them is or are affected, the amendment shall be declared
adopted, and upon filing with the Depositary of a certificate of the proceedings
of the meeting, verified by the chairman and the secretary thereof, together
with any such approval, the amendment shall thereupon become effective. In lieu
of adoption at a meeting, an amendment of the Depositary Agreement may be
approved if Unitholders of record as of a record date selected by the
Partnership representing fifty percent (50%) or more of the deposited Units
consent thereto in writing filed with the Depositary. No amendment shall impair
the right of the Unitholders of record to surrender the Depositary Receipt and
withdraw any or all of the deposited Units evidenced thereby. Unitholders of
record will not be entitled to notice as Limited Partners or the right to vote
as Limited Partners under the Depositary Agreement unless they are Substituted
Limited Partners (see notice requirements of Nominee above).

     The Depositary shall terminate the Depositary Agreement whenever directed
to do so by the Partnership by mailing notice of termination to the Unitholders
of record then outstanding at least thirty (30) days before the date fixed for
the termination in such notice.

     In addition to acting as depositary for the Units, the Depositary will act
as registrar and transfer agent for the Depositary Receipts. In addition to
receiving a monthly fee from the Partnership for serving in such capacities, the
Depositary will charge fees for Depositary Receipt transfers comparable to those
customary for stock transfer fees. All Depositary fees for transfer of
Depositary Receipts and withdrawal of Units will be borne by the Partnership and
not the Unitholders (except for fees customarily paid by stockholders for surety
bond premiums to replace lost or stolen certificates, special charges for
services requested by Unitholders and other similar fees or charges which will
be borne by the affected Unitholders). The Partnership will indemnify the
Depositary against certain liabilities incurred by the Depositary in connection
with its activities as depositary, transfer agent and registrar, including
liabilities arising under the Securities Act of 1933.

     The Depositary may terminate the Depositary Agreement if, after the
Depositary has delivered to the Partnership a written notice of its election to
resign, sixty (60) days have elapsed and a successor Depositary has not accepted
its appointment. The Depositary shall mail notice of termination to the
Unitholders of record. Termination shall be effective on the date fixed in the
notice, which shall be at least thirty (30) days after it is mailed.

                               PRINCIPAL HOLDERS

     The following table sets forth certain information regarding the beneficial
ownership of Units by the General Partners, their officers, and the
Partnership's officer effective as of January 1, 2002 and other persons,
excluding depositaries, of record on January 1, 2002 who held 5% or more of the
Units.

<Table>
<Caption>
                                                              NUMBER OF          PERCENT
                                                                UNITS              OF
                                                          BENEFICIALLY OWNED   CLASS(1)(3)
                                                          ------------------   -----------
<S>                                                       <C>                  <C>
P. A. Peak, Inc., General Partner.......................             --              --
Preston A. Peak, President of P.A. Peak, Inc............      1,577,412(2)        14.68%
James E. Raley, Inc., General Partner...................             --              --
James E. Raley, President of James E. Raley, Inc........         14,706             .14%
</Table>

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

(1) Based on 10,744,380 Units.

(2) Includes 1,576,412 Units owned by various entities for the benefit of Mr.
    Peak and his family, and 1,000 Units owned by Hugoton Nominee, Inc. of which
    he is the President and sole Director.

(3) The Units owned by the Advisory Committee members and the non-general
    partner officer of the Partnership is less than 1% of the total Units
    outstanding at December 31, 2001.

                                        7
<PAGE>

                                THE PARTNERSHIP

     The following summary contains certain provisions of the Partnership
Agreement. The Partnership was formed pursuant to the TRLPA to own, hold,
explore, develop and operate the properties contributed to it at its formation
and any other properties acquired pursuant to the Partnership Agreement.

     The statements herein relating to the Partnership Agreement are summaries
and do not purport to be complete. The summaries make use of terms defined in
the Partnership Agreement and are qualified in their entirety by reference to
the Partnership Agreement, a copy of which is available at the Partnership's
office.

MANAGEMENT OF THE PARTNERSHIP

     The General Partners, who have purchased an aggregate 1% net profits
interest in the Partnership, are P. A. Peak, Inc. whose sole shareholder is
Preston A. Peak, age 79, Investor, and James E. Raley, Inc., whose sole
shareholder is James E. Raley, age 62, Engineer. Kathleen A. Rawlings, age 44,
is the Partnership's Principal Accounting Officer and Administrative Services
Manager. She has been a full-time employee of the Partnership since 1983. Mr.
Peak is a former member of the Board of Directors of Kaneb Services, Inc. as
well as one of its subsidiaries. Mr. Raley is an independent consulting
engineer.

     The General Partners have complete and exclusive discretion in the
management and control of the business of the Partnership and all of its assets,
including authority to purchase or otherwise acquire any lease or other interest
in oil or gas property located within the geographical areas covered by the
properties conveyed to the Partnership and such other geographical areas within
the Hugoton Embayment as the General Partners may designate from time to time,
to borrow monies for the business of the Partnership, and to mortgage or pledge
all or any part of the Partnership's property as security, to surrender, release
or abandon any Partnership property, with or without consideration therefore,
and generally to execute and deliver such other documents and perform such other
acts as the General Partners in their sole discretion may determine to be
necessary or appropriate to carry out the business and affairs of the
Partnership.

     In accordance with governance rules for limited partnerships traded on the
Nasdaq Stock Market, the Partnership established in 1995 an Advisory Committee
consisting of two independent advisors to function as the Partnership's Audit
Committee and to review and approve any transactions between the Partnership and
its General Partners, including any compensation and benefits paid to the
General Partners by the Partnership. The Partnership Agreement was amended
accordingly.

     During 2000 the Partnership, with Advisory Committee approval, adopted an
Audit Committee charter which requires an annual review that complies with the
Nasdaq's Marketplace Rules. During April 2001 the Partnership Agreement was
amended to provide expansion of the Advisory Committee to three members with
staggered terms. The Advisors meet all current requirements to be independent
directors, including the requirement that at least one director have the
necessary financial experience and background. The Advisors, acting as the Audit
Committee, reviewed and discussed with the Partnership's independent outside
auditors (the "Auditors") and management the audited financial statements and
discussed with the Auditors the matters required to be discussed by the
Statement on Auditing Standards No. 61. The Audit Committee also had private
discussions with the Auditors and reviewed and discussed disclosures from the
Auditors concerning their independence. The Audit Committee recommended that the
audited statements appearing herewith be included in this Partnership Annual
Report on Form 10-K.

     Mr. Rawles Fulgham, age 74, of Dallas, Texas, Mr. Ronald P. Trout, age 62,
of Richardson, Texas, and Mr. W. Randall Blank, age 44, of Houston, Texas
presently serve on the Advisory Committee. Mr. Fulgham previously served as
Chairman and Chief Executive Officer of Global Industrial Technologies, Inc. and
is currently a director of NCH Corporation. Mr. Blank is currently a consultant
active in the natural gas industry. Previously, he was the Executive Vice
President of Rockland Pipeline Company in Houston, Texas. He also serves on the
Board of Directors of Panther Natural Gas

                                        8
<PAGE>

Company. Mr. Trout recently retired from Hourglass Capital Mgt. (a Texas money
management firm) where he was Co-Founder and Senior Vice President.

     Under the Partnership Agreement, each General Partner is entitled to
receive reasonable compensation for services rendered in operating and managing
the Partnership. The agreement, as amended effective January 1, 1998, provides
for a management fee to be divided among the General Partners in an annual
aggregate amount of $350,000 (previously $250,000) plus 1% of the annual gross
income of the Partnership from the Partnership properties. These amounts, on an
accrual basis, are included in the heading All Other Compensation within the
following table (no salaries, bonuses or other annual compensation was paid or
accrued):

<Table>
<Caption>
                                                           ALL OTHER COMPENSATION
                                         ----------------------------------------------------------
                                         PRESTON A. PEAK OR    JAMES E. RALEY OR
SUMMARY COMPENSATION TABLE                P.A. PEAK, INC.     JAMES E. RALEY, INC.
YEAR                                      GENERAL PARTNER       GENERAL PARTNER      TOTAL FOR YEAR
----                                     ------------------   --------------------   --------------
<S>                                      <C>                  <C>                    <C>
1999...................................       $ 88,509              $407,484(a)         $495,993
2000...................................       $137,905              $459,283(a)         $597,188
2001...................................       $145,896              $474,296(a)         $620,192
</Table>

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

(a) Includes the amount of taxable medical insurance premiums and payments of
    $5,975, $8,378 and $15,400 for James E. Raley in 1999, 2000 and 2001,
    respectively.

     Amounts expended by the Partnership for expenses (including certain private
club dues and office and other expenses) reimbursed or expended on behalf of
employees and the General Partners are believed to constitute ordinary and
incidental business expenses and are paid by the Partnership to facilitate the
conduct of Partnership business by such employees and General Partners. The
Partnership has concluded that the aggregate amount, if any, of personal benefit
is neither significant nor unusual nor does it result in any material additional
expense (less than $50,000) to the Partnership. During 2001, the General
Partners were reimbursed a total of $35,416 for all expenses incurred by them on
behalf of the Partnership, including their general and administrative expenses.
The General Partner(s) participate in a severance policy -- see Note 4 to the
Partnership's Financial Statements. No employees or officers of the corporate
General Partners participate in the Partnership's simplified employee pension
plan. Fees and expenses paid to members of the Advisory Committee amount to less
than $35,000 annually.

     Upon the resignation or other Withdrawal of a General Partner, the
remaining General Partners must select a Successor General Partner who is not an
affiliate of any General Partner and must notify the Unitholders and Limited
Partners (collectively referred to as the "Unitholders") of such selection. Such
Successor General Partner shall be accepted unless Unitholders holding more than
25% of the Units call a meeting and a majority in interest of the Unitholders
entitled to vote at such meeting disapprove the selection. So long as there is
more than one General Partner, the approval of a majority of the General
Partners is required to bind the Partnership, except as the General Partners may
from time to time delegate responsibility among themselves or to others.

     The General Partners shall not permit the Partnership to do business in any
jurisdiction or political subdivision in which the General Partners and the
Partnership have not previously taken such steps as may be necessary to assure
for the Limited Partners substantially the same limited liability as is provided
for limited partners in limited partnerships formed under the TRLPA.

TRANSACTIONS WITH AFFILIATES

     The Partnership Agreement specifically provides that an Affiliate of the
Partnership may enter into contracts with the Partnership as operator, seller or
purchaser of properties or services, or in other capacities, so long as the
transactions are fair and reasonable to the Partnership and the terms of any
contract or conveyance are no less favorable to the Partnership than those which
could be obtained from unrelated persons. However, the Partnership shall not
sell any part of an oil and gas mineral lease

                                        9
<PAGE>

to an Affiliate without the prior consent of a majority in interest of the
Unitholders. All transactions between the Partnership and its General Partners
and/or their Affiliates will be reviewed and approved by the Advisory Committee.

IMMUNITIES AND INDEMNITIES

     The Partnership Agreement also provides that no General Partner, nor any
shareholder, director, officer, employee or agent of a General Partner, shall be
liable to the Partnership or to the Partners for losses sustained or liabilities
incurred as a result of any act or omission which such General Partner in good
faith reasonably believed to be in, or not opposed to, the best interests of the
Partnership, unless such act or omission constituted gross negligence, willful
or wanton misconduct or breach of such General Partner's fiduciary obligations
to the Unitholders. A General Partner may rely upon, and shall have no liability
to the other Partners or to the Partnership if he relied upon, the opinion of
the Partnership's independent public accountants with respect to any matter
relating to computations and determinations which affect allocations or
distributions. Each General Partner is indemnified by the Partnership as
follows:

          (a) In any threatened, pending or completed action, suit or proceeding
     to which a General Partner was or is a party by reason of the fact that it
     is or was a General Partner of the Partnership (other than an action by or
     in the right of the Partnership), involving an alleged cause of action,
     arising out of the manner in which such General Partner conducted the
     Partnership's business if, in the transaction giving rise to such action,
     suit or proceeding, such General Partner acted in good faith and in a
     manner such General Partner reasonably believed to be in, or not opposed
     to, the best interests of the Partnership and such General Partner's
     conduct in such transaction did not constitute gross negligence, willful or
     wanton misconduct or willful breach of such General Partner's fiduciary
     obligations to the Unitholders.

          (b) In any threatened, pending or completed action, suit or proceeding
     by or in the right of the Partnership, to which a General Partner was or is
     a party, or is threatened to be made a party, by reason of the fact that it
     is or was a General Partner of the Partnership, involving an alleged cause
     of action arising out of the manner in which such General Partner managed
     the internal affairs of the Partnership as prescribed by the Agreement or
     by the TRLPA, or both (but excluding the activities covered in (a) above),
     if, in the transaction giving rise to such action, suit or proceeding, such
     General Partner acted in good faith and in a manner such General Partner
     reasonably believed to be in, or not opposed to, the best interests of the
     Partnership, except that no indemnification shall be made in respect of any
     claim, issue or matters as to which such General Partner shall have been
     adjudged to be liable for gross negligence, willful or wanton misconduct or
     breach of such General Partner's fiduciary obligations to the Unitholders,
     unless and only to the extent that the court in which such action, suit or
     proceeding was brought shall determine upon application that, despite the
     adjudication of liability but in view of all circumstances of the case,
     such General Partner is fairly and reasonably entitled to indemnity for
     such expenses which such court shall deem proper.

Insofar as indemnification for liabilities arising under the Securities Act of
1933 may be permitted to a General Partner pursuant to the foregoing provisions,
the Partnership has been informed that in the opinion of the United States
Securities and Exchange Commission such indemnification is against public policy
as expressed in the Act and is therefore unenforceable.

ACTIONS BY UNITHOLDERS

     A majority in interest of the Unitholders shall have the right to waive any
restriction on the General Partners contained in the Partnership Agreement. The
Applicable Percentage Interest of the Unitholders (since June 16, 1988, defined
as Unitholders who own 80% of all Units) shall have the right to dissolve the
Partnership, to amend the Partnership Agreement, to approve or reject the sale
of all or substantially all of the Partnership Property in the event that the
General Partners do not approve or

                                        10
<PAGE>

recommend such sale, or to remove one or all of the General Partners and elect a
successor General Partner to operate and carry on the business of the
Partnership, subject in each case to receipt of an opinion of counsel for the
Unitholders or a ruling from the Internal Revenue Service that the taking of
such action will not affect the federal income tax status of the Partnership,
and subject further in the case of the removal and replacement of a General
Partner, to the following:

          (a) The partnership interest of each removed General Partner must be
     terminated by agreement between such terminating Partner and the successor
     General Partner or, in the absence of an agreement, in accordance with the
     following: The assets of the Partnership shall be valued, and gain or loss
     allocated, as if all assets were sold for their fair market value as
     determined by independent consulting engineers. Then, within 30 days after
     such valuation is completed, the successor General Partner shall pay for
     the Partnership interest of each removed General Partner cash equal to the
     capital account balance of such Partner, after adjustment for the valuation
     and allocation provided above, plus interest at a rate equal to the lower
     of (i) the prime rate of Bank One, Texas, NA or (ii) the highest rate
     permitted by law, for a period from the valuation date until the payment
     date. The Partnership interest of each terminating Partner, including
     income and deductions attributable thereto realized after the valuation
     date, shall be owned by the successor General Partner.

          (b) The successor General Partner must make arrangements, satisfactory
     to the removed General Partner, to release the removed General Partner from
     personal liability with respect to all Partnership liabilities, if any, or
     to provide the removed General Partner with indemnity satisfactory to it
     against all liabilities of the Partnership with respect to which such
     release is not obtained.

     Meetings of the Unitholders may be called by any General Partner and shall
be called by the General Partners within 15 days following the written request
of Unitholders holding more than 50% of the Units on not less than 30 days nor
more than 60 days notice and at a reasonable time and place. There were no
meetings of the Unitholders held during 2001. Any action which may be taken at a
meeting of the Unitholders may be taken without a meeting if a consent in
writing, setting forth the action so taken, shall be signed by Unitholders
owning not less than the minimum percentage of Units that would be necessary to
authorize or take such action at a meeting at which all Unitholders were present
and voted. For purposes of obtaining a written consent, a General Partner may
require response by a specified date not later than 30 days after the date any
proposal is submitted to the Unitholders. Any Unitholder failing to notify the
Partnership of his support for or opposition to the proposal within the
specified time shall be conclusively deemed to have opposed the proposal.

     No Unitholder shall have any right, power or authority to take part in the
management or control of the business of, or to transact any business for, the
Partnership. All management responsibility is vested in the General Partners.
Each Unitholder irrevocably constitutes and appoints the General Partners, and
each of them, his true and lawful attorney-in-fact and agent, to execute,
acknowledge, verify, swear to, deliver, record and file, in the Unitholder's
place and stead, all instruments, documents, and certificates which may be
required, from time to time, by the laws of the United States of America, the
State of Texas, and any other state or country in which the Partnership conducts
business to effectuate, implement and continue the valid existence of the
Partnership. This power of attorney is coupled with an interest, and shall be
irrevocable, shall survive the death, dissolution, bankruptcy, incompetency or
legal disability, of a Unitholder and shall extend to each Unitholder's heirs,
successors and assigns and may be exercised for all Unitholders (or any of them)
by listing all (or any) of the Unitholders required to execute any instrument.

     No Limited Partner shall be required to make any additional contributions
to the Partnership. If additional funds are required, the General Partners will
attempt to obtain non-recourse loans but shall not be obligated to seek recourse
loans if non-recourse loans are not available. If any General Partner loans any
funds to the Partnership, the amount thereof shall be treated as a personal debt
of the Partnership, and shall bear interest at the prime rate set by Bank One,
Texas, NA.

                                        11
<PAGE>

ACCOUNTING AND ALLOCATIONS

     For federal income tax purposes, income, gain, loss, deductions and federal
tax credits shall be allocated on a monthly basis to the partners in accordance
with their profit sharing percentages. The General Partners have the right to
make or decline to make all elections required or permitted to be made for
federal income tax purposes, including the Section 754 election, and such
elections, other than the Section 754 election, shall also be controlling for
book purposes. The classification, realization and recognition of income,
deductions and other items shall be consistent with their treatment for federal
income tax purposes applicable to a partnership electing the method of
accounting which the General Partners elect and the elections provided for
above, other than the Section 754 election. The Partnership Agreement requires
that within two and one-half months after the end of each fiscal year, the
General Partners must furnish to each Unitholder a statement containing
necessary information concerning the Partnership's operations for the preceding
fiscal year.

TRANSFERS

     The Partnership interest of a General Partner may be transferred, in whole
or in part, only with the consent of the other General Partners, except where
such transfer is by reason of merger of a transferor corporate General Partner
into another corporation, or other transaction constituting a reorganization
under Section 368 of the Internal Revenue Code. As discussed above, the
Partnership Agreement contains provisions for valuing the Partnership interest
of a General Partner. A Unitholder may transfer all or part of his Units to any
person or persons; provided, however, that such transfer shall not confer upon
the transferee any right to become a Substituted Limited Partner. A transferee
of all or a part of such Units held prior thereto by a Unitholder may be
admitted to the Partnership as a Substituted Limited Partner only if the
transferee had requested and received the permission of the General Partners,
which permission may be withheld in the sole discretion of the General Partners.
Unless and until a transferee becomes a Substituted Limited Partner, the
transferee's status and rights shall be limited to the rights of a transferee of
limited partnership interests under the TRLPA. To the extent required by
applicable law, if a transferee is not an Eligible Citizen, a Depositary Receipt
evidencing the transferred Units will be issued and delivered to him, but he
shall not be entitled to admission as a Substituted Limited Partner and shall
remain a non-citizen assignee until he transfers the Units or he becomes an
Eligible Citizen and elects to become a Substituted Limited Partner. An Eligible
Citizen means a citizen or national of the United States; an alien lawfully
admitted for permanent residence in the United States; a private, public or
municipal corporation organized under the laws of the United States or of any
State or of the District of Columbia, or a territory thereof; or an association
of such citizens, nationals, resident aliens, or private, public or municipal
corporations, States or political subdivisions of States. If at any time the
Partnership or a General Partner is named a party in any judicial or
administrative proceeding that seeks the cancellation or forfeiture or any
property in which the Partnership has an interest because of the nationality (or
any other status that subjects the Partnership to the risk of losing its
eligibility to acquire or hold oil and gas leasehold interests in federal lands)
of any one or more Unitholders the General Partners may redeem the partnership
interest of such Unitholder.

DISSOLUTION AND LIQUIDATION

     The Partnership shall be dissolved upon the first to occur of the following
events:

          (a) The failure of the Partnership to own any oil and gas properties.

          (b) The Withdrawal of a General Partner, which is defined as the
     death, dissolution, resignation, insanity or other incapacity of a General
     Partner, termination of a marital relationship in which all or a part of
     the record or beneficial ownership of the General Partner is transferred,
     certain bankruptcy acts of a General Partner or a purported transfer by a
     General Partner of his management rights in the Partnership (subject to
     reconstitution as referred to below).

          (c) The agreement of the Applicable Percentage Interest of the
     Unitholders.

                                        12
<PAGE>

          (d) The agreement of all General Partners.

          (e) December 31, 2050.

     The dissolution shall be effective on the day the event occurs giving rise
to the dissolution, but the Partnership shall not terminate until all its
affairs have been wound up and its assets distributed. If the Partnership
dissolves because of the Withdrawal of a General Partner, the Partnership shall
not liquidate, but shall be reconstituted and shall continue as it was before.

     In liquidation, the assets of the Partnership shall be applied in the
following order or priority:

          (a) First, there shall be paid all liabilities of the Partnership to
     creditors other than Partners and Unitholders (collectively referred to as
     the "Partners"). If any liability is contingent, or uncertain in amount, a
     reserve equal to the maximum amount to which the Partnership could be
     reasonably held liable will be established. Upon the satisfaction or other
     discharge of such contingency, the amount of the reserve not required, if
     any, will be distributed in accordance with the balance of this provision.

          (b) Second, the debts, if any, of the Partnership to the Partners
     shall be paid.

          (c) Third, to the Partners in an amount equal to their then existing
     Capital Accounts. If any General Partner's Capital Account is less than
     zero, then each such Partner shall contribute cash to the Partnership equal
     to such deficit.

          (d) Fourth, to the Partners in accordance with their Profit Sharing
     Percentages.

     Each Partner agrees with every other Partner that (i) any Partner and any
person affiliated with a Partner may engage in or possess any interest in
another business venture or ventures; (ii) neither the Partnership nor the other
Partners shall have any right in said independent venture or to the income or
profits derived therefrom; and (iii) any General Partner may organize and be a
General Partner in other limited partnerships organized for the exploration for
oil, gas and other minerals or for any other purpose.

AMENDMENTS

     Amendments to the Partnership Agreement may be proposed by any General
Partner, or by Unitholders owning not less than 50% of the Units and must be
approved by the Applicable Percentage Interest of the Limited Partners. However,
no amendment shall be made which would cause the Partnership to be classified as
a corporation for purposes of the Internal Revenue Code. Without notice to the
Unitholders, the General Partners may make amendments to the Partnership
Agreement which do not adversely affect the rights of the Unitholders in any
material respect.

INHERITANCE TAXES

     Under certain circumstances, Texas inheritance tax and other laws regarding
devolution, probate and administration may be applicable to property in Texas,
including intangible personal property, of both resident and nonresident
decedents. Insofar as the Depositary Receipts may represent or constitute an
interest in property in Kansas and Oklahoma, they may be subject to devolution,
probate and administrative laws, and inheritance, gift and similar taxes, under
the laws of such states.

INCOME TAX TREATMENT

     Dorchester Gas Corporation received the opinion of counsel that the
Partnership would be classified as a partnership and that the Unitholders would
be treated as limited partners for federal income tax purposes. AS A NATURAL
RESOURCES PARTNERSHIP, THE PARTNERSHIP WAS NOT AFFECTED BY EXISTING TAX
PROVISIONS THAT CAUSED CERTAIN PUBLICLY TRADED PARTNERSHIPS TO BE TAXED AS
CORPORATIONS IN 1998. The Partnership itself, to the extent that it is treated
for federal income tax purposes as a partnership, is not

                                        13
<PAGE>

subject to any federal income taxation, but it is required to file annual
partnership returns of income. Each Unitholder will be required to take into
account in computing his federal income tax liability his distributive share
(determined in accordance with the allocation of profits and losses set forth in
the Partnership Agreement) of all items of Partnership income, gain, loss,
deduction or credit for any taxable year of the Partnership ending within or
with his taxable year without regard to whether such Unitholder has received or
will receive any cash distributions from the Partnership. The profits and losses
of the Partnership are allocated 1% to the General Partners and 99% to the
Limited Partners. The IRS may assess a deficiency attributable to Partnership
items within three years after the Partnership return is filed. The applicable
period of limitation with respect to Partnership items may be extended for all
Unitholders by the General Partners. No period of limitation extensions have
been granted at this time.

     A Unitholder's distributive share of the taxable income or loss of the
Partnership generally will be required to be included in determining his
reportable income for state or local tax purposes in the jurisdiction in which
he is a domicile or resident. In addition, the Partnership will conduct
operations in some states, including Kansas and Oklahoma, which impose a tax on
a Unitholder's share of the income derived from the activities or properties of
the Partnership in that state whether or not the Unitholder is a resident or
domicile of such state. Accordingly, a Unitholder may be subject to taxes in a
state in which the Partnership has operations or properties in addition to the
state in which the Unitholder has his residence or domicile. The Partnership
initiated an agreement with the Kansas Department of Revenue removing the
reporting burden for Unitholders who are nonresidents of Kansas and satisfying
any tax liability that might exist with respect to their allocable share of
Partnership income attributable to Kansas for 1982 through 2001.

     In view of the complexities of the tax considerations involved in the
ownership of Depositary Receipts, the holders of such are urged to consult tax
or legal advisors to determine how and to what extent such holders will be taxed
for federal and state income tax purposes and to determine all other legal
consequences to such holders of that status (See Note 1 to the Financial
Statements).

                            DORCHESTER HUGOTON, LTD.
                         (A TEXAS LIMITED PARTNERSHIP)

                            SELECTED FINANCIAL DATA
       FOR THE YEARS ENDED DECEMBER 31, 2001, 2000, 1999, 1998, AND 1997
                             (DOLLARS IN THOUSANDS)

<Table>
<Caption>
                                                2001      2000      1999      1998      1997
                                               -------   -------   -------   -------   -------
<S>                                            <C>       <C>       <C>       <C>       <C>
Net operating revenues.......................  $26,779   $25,182   $15,302   $15,366   $19,159
Net earnings.................................  $18,351   $17,962   $ 9,046   $ 9,010   $12,665
Net earnings per Unit........................  $  1.69   $  1.66   $  0.83   $  0.83   $  1.17
Cash distributions per Unit..................  $  1.23   $  0.90   $  0.72   $  0.72   $  0.72
Total assets at December 31..................  $41,454   $38,709   $28,165   $26,444   $25,215
Notes payable -- long term...................  $    --   $   100   $   100   $   100   $   122
Partnership capital at December 31...........  $37,336   $32,930   $24,338   $22,641   $20,841
</Table>

                                        14
<PAGE>

                    MANAGEMENT'S DISCUSSION AND ANALYSIS OF
                 FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     The Partnership's year-to-year changes in net earnings and cash flows from
operating activities are principally determined by changes in natural gas sales
volumes and gas prices. As shown in the following table, overall gas sales
volumes were down 3.5% from 1999 to 2000 and down 8.2% from 2000 to 2001.
Natural gas market prices were up 72% from 1999 to 2000 and up 12% from 2000 to
2001. Net earnings were $9,046,000 in 1999, $17,962,000 in 2000 and $18,351,000
in 2001. Operating cash flows were $11,045,000 in 1999, $18,526,000 in 2000 and
$21,029,000 in 2001. On April 13, 2001, the Partnership paid an increased
quarterly distribution of $0.27 per Unit for the first calendar quarter of 2001.
On June 15, 2001 the Partnership paid a special $0.15 per Unit distribution to
Unitholders of record on May 31, 2001. On July 13, 2001, October 12, 2001, and
January 11, 2002, the Partnership paid a distribution of $0.27 per Unit for each
of the remaining calendar quarters of 2001. The total of the five distributions
was approximately $13,349,000.

     In order to supplement its cash flows from operating activities and finance
significant capital projects, the Partnership entered into a $15 million
long-term unsecured revolving credit facility (the "Credit Agreement") with Bank
One, Texas, NA in 1994. See Note 2 to the Partnership's Financial Statements for
additional information on the Credit Agreement. The Partnership does not believe
that changes in interest rates will have a material effect on its financial
condition or operating results. Cash flows from operating activities remain
sufficient to meet the Partnership's anticipated costs and expenses and debt
service requirements. The Partnership has no current outstanding material
commitments for capital expenditures. Year-end cash and cash equivalents totaled
$15,767,000 for 2000 and $18,439,000 for 2001.

     As previously reported in the Partnership's Second Quarter Report on Form
10-Q, since its first annual payment in 1997, each May the Partnership paid an
Oklahoma ORRI production payment (calculated through the prior February) that is
based upon the difference between market gas prices compared to a table of
rising prices and based upon a table of declining volumes. On May 15, 2001 the
Partnership paid approximately $1,701,000 in ORRI production payments for the
year ended February 28, 2001. On August 9, 2001, the Partnership paid $5,270,000
to acquire, effective March 1, 2001, the Oklahoma ORRI production payment. The
effect of the transaction for the period March 1, 2001 through December 31, 2001
was an increase in the Partnership's revenue of approximately $860,000, due to
the reduction in ORRI production payments, and an increase in the Partnership's
depletion of approximately $530,000. The depletion increase was offset in part
by reduced depletion due to increases in reserves as reflected in Note 5 to the
Partnership's Financial Statements.

     During November 2001, the Partnership completed a settlement agreement
previously discussed in the Partnership Quarterly Reports on Form 10-Q that
resolved federally required refunds of Kansas tax reimbursements received in the
1980's. Consequently, the Partnership closed its 1998 escrow account with net
payments of approximately $320,000 to others and approximately $100,000 to the
Partnership. See Note 4 to the Partnership's Financial Statements for additional
information on the Settlement.

     The Partnership's 5,400 horsepower gas compression and dehydration facility
in Oklahoma has continued to operate satisfactorily since its start-up in
November 1994. Major maintenance was performed during 2001 at a cost of about
$300,000. The Partnership anticipates normal gradual increases in repairs. Field
consumption of natural gas at the compression and dehydration facilities is
estimated to be approximately 4.6% of the Oklahoma inlet gas volume and 9.6% in
Kansas as a result of field compression. The Partnership anticipates gradual
increases in Oklahoma field operating costs and expenses as repairs to its
50-plus-year-old pipelines and gas wells become more frequent and as pressures
decline. The Partnership does not anticipate significant replacement of these
items at this time, although additional rental field compression units may
become necessary during 2003. The cost of such additional compression could
require from $400,000 to $600,000 in capital and require $350,000 to $400,000
per year additional operating costs (primarily compressor rental). The purpose
of such

                                        15
<PAGE>

compressors is to get more gas production through the Partnership's pipelines at
lower pressures. While it is believed that the benefits of such compression will
more than exceed cost and recover capital, neither the timing of such a project
nor the increased gas production are currently predictable.

     The routine workover of wells in Oklahoma includes fracture treating (the
creation of cracks in the formation to assist gas flow toward the well bore from
the producing zones). Currently, the Partnership has fracture treated 37 wells
in Oklahoma which includes 7 wells during 2001. Such fracture treatments during
2001 have cost from $36,000 to $45,000 per well, excluding casing repairs on two
wells. Of the 7 wells, 5 increased in gas production volume and 7 increased in
gas pressure; the combination of an increase in pressure and volume resulted in
gas reserve increases ranging from 0% to 52%. THE RESULTS OF FRACTURE TREATING
CAN VARY WIDELY FROM WELL TO WELL AND MAY NOT BE SUCCESSFUL. Average Oklahoma
per well volume increases for the 7 wells were 31% (136 to 178 MCF per day). The
Partnership anticipates continuing additional fracture treating during 2002.

     The Partnership's portion of gas sales volumes (not reduced for Oklahoma
production payments where applicable), and weighted average sales prices were:

<Table>
<Caption>
                                                              YEAR ENDED DECEMBER 31
                                                             ------------------------
                                                              2001     2000     1999
                                                             ------   ------   ------
<S>                                                          <C>      <C>      <C>
Sales Volume -- MMCF:
  Oklahoma.................................................   5,141    5,576    5,580
  Kansas...................................................     974    1,082    1,320
                                                             ------   ------   ------
          Total............................................   6,115    6,658    6,900
                                                             ======   ======   ======
Weighted Average Sales Prices -- $/MCF:
  Oklahoma.................................................  $ 4.42   $ 3.95   $ 2.28
  Kansas...................................................    4.55     3.99     2.36
  Overall weighted average.................................    4.44     3.96     2.30
</Table>

     Oklahoma 2001 gas sales volumes were 7.8% lower than 2000 and 1999
primarily as a result of extensive scheduled maintenance during 2001 causing
downtime on the Partnership's central gas compression units that deliver the
Partnership gas into sales pipelines, combined with natural reservoir decline.
As discussed in Business and Properties of the Partnership -- Oklahoma
Properties section of this annual report, the Partnership will continue to
evaluate the Fort Riley zone including monitoring the activities of other
operators' Fort Riley completions. The Partnership, as non-operator, has agreed
to participate in the deepening of one Oklahoma well to include Upper Fort Riley
production. Such deepening has been rescheduled by the Operator from 2001 to
2002. As discussed in Business and Properties of the Partnership -- Regulations
and Prices, the Partnership is active in supporting its views regarding possible
Oklahoma regulatory/legislative action on infill drilling and monitoring
activities in the field resulting from removal of production quantity
restrictions in the Guymon-Hugoton field. In March 2002, gas delivered from the
Oklahoma central compression units is expected to be processed in facilities
owned by Duke Energy Field Services, LP under an existing processing agreement.
Minimal, if any, impact on the Partnership is expected. See Business and
Properties of the Partnership -- Oklahoma Properties for additional information.

     Kansas 2001 sales volumes were lower than 2000 and 1999 as a result of
declining well volumes and pressures typical of other producers in that area.
The use of field compression, which increased volume initially, helped lessen
the decline on an annual basis, particularly since Kansas allows those
compressors to create a vacuum at the well. See Business and Properties of the
Partnership -- Regulation and Prices section of this annual report. The
Partnership's Kansas gas is currently sold to Duke Energy Field Services, Inc.
("Duke") at an index (average) field market price plus a premium. See Note 1 to
the Financial Statements for a discussion regarding material customers and
contracts. Pursuant to notice given November 1, 2001, the current Duke gas sales
agreement will expire May 1, 2002. The Partnership is in negotiations with Duke
and other prospective purchasers for the period

                                        16
<PAGE>

following May 1, 2002; the outcome is not predictable, although it is believed
the impact of a price change will be immaterial to the Partnership's income and
cash flow.

     The Partnership is continuing to monitor the activity on nearby acreage in
the Council Grove formation. At present 15 wells have been drilled by others.
Two of the 15 wells were recompleted in the Guymon-Hugoton field which presently
improved production by 35 to 179 MCF per day over the two original
Guymon-Hugoton wells that were plugged and abandoned per state regulations. The
Partnership's ownership includes the Council Grove formation underlying most of
its Oklahoma acreage. IT IS NOT KNOWN IF SUCH MONITORING WILL RESULT IN ANY
PLANS BY THE PARTNERSHIP TO ATTEMPT A COUNCIL GROVE WELL; PREVIOUS PRELIMINARY
REVIEWS YIELDED UNFAVORABLE FORECASTS. Recent results by others in the 13
remaining wells have varied from 3 MCF per day to 354 MCF per day. Production
volumes in subsequent months have varied with most wells showing decreases.
Current total production from each of the three Council Grove wells owned by
others but located on the Partnership's acreage is approximately 6, 8 and 20 MCF
per day. The Partnership has a minor overriding royalty interest in the three
wells.

     As previously reported, the Partnership's expenditures for K-1 tax form
preparation and federal electronic filing for 4,000 to 5,000 Unitholders have
increased significantly as reflected in general and administrative costs
compared to years prior to 2000. The Partnership recently secured a two-year
agreement for such tax preparation and filing which will not apply in the event
the Partnership combines as described in Note 3 to the Partnership's Financial
Statements. Other general and administrative expenses increased in 2001 compared
to 2000 primarily due to increased insurance costs.

     On July 20, 2001 the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 141, Business
Combinations and SFAS No. 142, Goodwill and Intangible Assets. SFAS 141 is
effective for all business combinations completed after June 30, 2001. SFAS 142
is effective for fiscal years beginning after December 15, 2001; however,
certain provisions of this Statement apply to goodwill and other intangible
assets acquired between July 1, 2001 and the effective date of SFAS 142.

     Major provisions of these statements and their effective dates for the
Partnership are as follows:

     - All business combinations initiated after June 30, 2001 must use the
       purchase method of accounting;

     - Intangible assets acquired in a business combination must be recorded
       separately from goodwill if they arise from contractual or other legal
       rights or are separable from the acquired entity and can be sold,
       transferred, licensed, rented or exchanged, either individually or as a
       part of a related contract, asset or liability;

     - Goodwill, as well as intangible assets with indefinite lives, acquired
       after June 30, 2001, will not be amortized;

     - All acquired goodwill must be assigned to reporting units for purposes of
       impairment testing and segment reporting.

     The Partnership does not believe that the implementation of this standard
will have any material effect on its financial positions, results of operations,
or cash flows.

     As disclosed on a Form 8-K filed on December 14, 2001, the Partnership has
signed definitive agreements to combine the businesses and/or properties of the
Partnership, Republic Royalty Company, and Spinnaker Royalty Company, L.P., in a
non-taxable transaction, into a new publicly traded limited partnership. During
2001, approximately $785,000 was expensed related to the combination compared to
$339,000 in 2000. The combination is subject to a number of conditions including
(1) approval by a majority of Dorchester Hugoton Unitholders, (2) approvals by
the owners of Spinnaker Royalty and Republic Royalty and affiliated partnerships
and interest holders, and (3) filings with and/or clearances by various
securities and governmental authorities.

                                        17
<PAGE>

                             FINANCIAL INFORMATION

Financial Statements:

     Statements of Earnings for the Years Ended December 31, 2001, 2000 and
      1999.

     Statements of Comprehensive Income for the Years Ended December 31, 2001,
      2000 and 1999.

     Balance Sheets as of December 31, 2001 and 2000.

     Statements of Changes in Partnership Capital for the Years Ended December
      31, 1999, 2000 and 2001.

     Statements of Cash Flows for the Years Ended December 31, 2001, 2000, and
      1999.

     Notes to Financial Statements.

Exhibits:

<Table>
<Caption>
                                                                                 PREVIOUSLY FILED AND INCORPORATED WITH
     NUMBER                                DESCRIPTION                             (BEARING THE SAME EXHIBIT NUMBER)
     ------                                -----------                           --------------------------------------
<C>                <S>                                                           <C>
      2.1          -- Combination Agreement, plus exhibits, dated December 13,
                      2001                                                            Filed herewith
      2.2          -- Contribution Agreement, plus exhibits, dated December 13,
                      2001                                                            Filed herewith
      2.3          -- Business Opportunities Agreement, dated December 13, 2001       Filed herewith
      3.           -- Amended and Restated Certificate and Agreement of Limited
                      Partnership, as amended                                            June 30, 1995 Form 10-Q
      3.01         -- Certificates of Amendments to the Agreement of Limited
                      Partnership dated July 2, 1997 and December 15, 1997               December 31, 1997 Form 10-K
      3.02         -- Certificate of Amendment to the Agreement of Limited
                      Partnership dated April 3, 1998                                    March 31, 1998 Form 10-Q
      3.03         -- Certificate of Amendment to the Agreement of Limited
                      Partnership dated April 27, 2001                                   March 31, 2001 Form 10-Q
      4.1          -- Depositary Agreement, as amended                                June 30, 1995 Form 10-Q
      4.2          -- Specimen Depositary Receipt                                     December 31, 1995 Form 10-K
      4.3          -- Nominee Agreement among the Partnership, Dorchester and
                      Nominee                                                         December 31, 1995 Form 10-K
</Table>

     Reports on Form 8-K -- Reports on Form 8-K dated October 26, 2001, December
4, 2001, and December 14, 2001 were filed with events reported under Item 5 and
Item 7 thereof.

     All other schedules and exhibits have been omitted because they are either
not required, not applicable or the required information is disclosed in the
Financial Statements or related Notes.

                       REPORT OF INDEPENDENT ACCOUNTANTS

To the General Partners and Unitholders of Dorchester Hugoton, Ltd.:

We have audited the financial statements of Dorchester Hugoton, Ltd. listed
under Financial Information above. These financial statements are the
responsibility of the Partnership's management. Our responsibility is to express
an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. 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 financial statements referred to above present fairly, in
all material respects, the financial position of Dorchester Hugoton, Ltd. as of
December 31, 2001 and 2000, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 2001 in conformity
with accounting principles generally accepted in the United States of America.

                                            GRANT THORNTON LLP

Dallas, Texas
February 8, 2002

                                        18
<PAGE>

                            DORCHESTER HUGOTON, LTD.
                         (A TEXAS LIMITED PARTNERSHIP)

                             STATEMENTS OF EARNINGS
              FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
                             (DOLLARS IN THOUSANDS)

<Table>
<Caption>
                                                                YEAR ENDED DECEMBER 31
                                                              ---------------------------
                                                               2001      2000      1999
                                                              -------   -------   -------
<S>                                                           <C>       <C>       <C>
Net operating revenues:
  Natural gas sales.........................................  $27,153   $26,368   $15,849
  Other.....................................................      192       221       198
  Production payment (ORRI).................................     (566)   (1,407)     (745)
                                                              -------   -------   -------
          Total net operating revenues......................   26,779    25,182    15,302
                                                              -------   -------   -------
Costs and expenses:
  Operating.................................................    3,160     2,840     2,678
  Production taxes..........................................    1,721     1,529       910
  Depreciation, depletion and amortization..................    2,105     1,783     1,903
  General and administrative:
     Tax and regulatory reporting...........................      323       320       176
     Depositary and transfer agent fees.....................       22        22        24
     Other..................................................      634       448       363
  Management fees...........................................      605       589       490
  Merger costs..............................................      785       339        --
  Investment income.........................................     (897)     (664)     (318)
  Interest expense..........................................       36        39        37
  Other income, net.........................................      (66)      (25)       (7)
                                                              -------   -------   -------
          Total costs and expenses..........................    8,428     7,220     6,256
                                                              -------   -------   -------
Net earnings................................................  $18,351   $17,962   $ 9,046
                                                              =======   =======   =======
Net earnings per Unit.......................................  $  1.69   $  1.66   $  0.83
                                                              =======   =======   =======
</Table>

                       STATEMENTS OF COMPREHENSIVE INCOME
              FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
                             (DOLLARS IN THOUSANDS)

<Table>
<Caption>
                                                                YEAR ENDED DECEMBER 31
                                                              ---------------------------
                                                               2001      2000      1999
                                                              -------   -------   -------
<S>                                                           <C>       <C>       <C>
Net earnings................................................  $18,351   $17,962   $ 9,046
Unrealized holding gain (loss) on available for sale
  securities................................................     (534)      408       476
                                                              -------   -------   -------
Comprehensive income........................................  $17,817   $18,370   $ 9,522
                                                              =======   =======   =======
</Table>

                       See Notes to Financial Statements

                                        19
<PAGE>

                            DORCHESTER HUGOTON, LTD.
                         (A TEXAS LIMITED PARTNERSHIP)

                                 BALANCE SHEETS
                           DECEMBER 31, 2001 AND 2000
                             (DOLLARS IN THOUSANDS)

                                     ASSETS

<Table>
<Caption>
                                                               2001      2000
                                                              -------   -------
<S>                                                           <C>       <C>
Current assets:
  Cash and cash equivalents.................................  $18,439   $15,767
  Restricted cash (Note 4)..................................       --       409
  Investments -- available for sale.........................    5,030     5,564
  Accounts receivable.......................................    1,472     4,092
  Prepaid expenses and other current assets.................      453       284
                                                              -------   -------
          Total current assets..............................   25,394    26,116
                                                              -------   -------
Property and equipment -- at cost:
  Natural gas properties (full cost method).................   34,008    28,467
  Other.....................................................      988     1,122
                                                              -------   -------
          Total.............................................   34,996    29,589
Less accumulated depreciation, depletion and amortization:
  Full cost depletion.......................................   18,561    16,534
  Other.....................................................      375       462
                                                              -------   -------
          Total.............................................   18,936    16,996
                                                              -------   -------
  Net property and equipment................................   16,060    12,593
                                                              -------   -------
          Total assets......................................  $41,454   $38,709
                                                              =======   =======


                      LIABILITIES AND PARTNERSHIP CAPITAL

Current liabilities:
  Accounts payable..........................................  $   648   $   443
  Production and property taxes payable.....................      230       996
  Royalties payable.........................................      309     1,851
  Distributions payable to Unitholders......................    2,931     2,389
                                                              -------   -------
          Total current liabilities.........................    4,118     5,679
Notes payable -- long-term..................................       --       100
                                                              -------   -------
          Total liabilities.................................    4,118     5,779
                                                              -------   -------
Commitments and contingencies (Note 4)
  Partnership capital:
  General partners..........................................      271       222
  Unitholders...............................................   34,552    29,661
  Accumulated other comprehensive income....................    2,513     3,047
                                                              -------   -------
     Total partnership capital..............................   37,336    32,930
                                                              -------   -------
          Total liabilities and partnership capital.........  $41,454   $38,709
                                                              =======   =======
</Table>

                       See Notes to Financial Statements

                                        20
<PAGE>

                            DORCHESTER HUGOTON, LTD.
                         (A TEXAS LIMITED PARTNERSHIP)

                  STATEMENTS OF CHANGES IN PARTNERSHIP CAPITAL
              FOR THE YEARS ENDED DECEMBER 31, 1999, 2000 AND 2001
                             (DOLLARS IN THOUSANDS)

<Table>
<Caption>
                                                                            ACCUMULATED
                                                                               OTHER
                                                  GENERAL                  COMPREHENSIVE
YEAR                                              PARTNERS   UNITHOLDERS      INCOME        TOTAL
----                                              --------   -----------   -------------   -------
<S>                                               <C>        <C>           <C>             <C>
1999
  Balance at January 1, 1999....................    $128       $20,350        $2,163       $22,641
  Net earnings..................................      90         8,956            --         9,046
  Net unrealized holding gain on investments
     available for sale.........................      --            --           476           476
  Distributions ($0.72 per Unit)................     (78)       (7,736)           --        (7,814)
  Other.........................................      --           (11)           --           (11)
                                                    ----       -------        ------       -------
  Balance at December 31, 1999..................     140        21,559         2,639        24,338
                                                    ----       -------        ------       -------
2000
  Net earnings..................................     180        17,782            --        17,962
  Net unrealized holding gain on investments
     available for sale.........................      --            --           408           408
  Distributions ($0.90 per Unit)................     (98)       (9,670)           --        (9,768)
  Other.........................................      --           (10)           --           (10)
                                                    ----       -------        ------       -------
  Balance at December 31, 2000..................     222        29,661         3,047        32,930
                                                    ----       -------        ------       -------
2001
  Net earnings..................................     183        18,168            --        18,351
  Net unrealized holding loss on investments
     available for sale.........................      --            --          (534)         (534)
  Distributions ($1.23 per Unit)................    (133)      (13,216)           --       (13,349)
  Other.........................................      (1)          (61)           --           (62)
                                                    ----       -------        ------       -------
  Balance at December 31, 2001..................    $271       $34,552        $2,513       $37,336
                                                    ====       =======        ======       =======
</Table>

                       See Notes to Financial Statements

                                        21
<PAGE>

                            DORCHESTER HUGOTON, LTD.
                         (A TEXAS LIMITED PARTNERSHIP)

                            STATEMENTS OF CASH FLOWS
             FOR THE YEARS ENDED DECEMBER 31, 2001, 2000, AND 1999
                             (DOLLARS IN THOUSANDS)

<Table>
<Caption>
                                                               2001      2000      1999
                                                              -------   -------   -------
<S>                                                           <C>       <C>       <C>
Cash flows from operating activities:
  Net earnings..............................................  $18,351   $17,962   $ 9,046
  Adjustments to reconcile net earnings to net cash provided
     by operating activities:
     Depreciation, depletion and amortization...............    2,105     1,783     1,903
     Gain on sale of property and equipment.................      (22)      (29)       (8)
     Other..................................................      (62)      (10)      (11)
     Changes in operating assets and liabilities:
       Restricted cash......................................      409       (19)      (11)
       Accounts receivable..................................    2,620    (2,537)       90
       Prepaid expenses and other current assets............     (169)     (143)       11
       Accounts payable, taxes and royalties payable........   (2,203)    1,519        25
                                                              -------   -------   -------
Net cash provided by operating activities...................   21,029    18,526    11,045
                                                              -------   -------   -------
Cash flows from investing activities:
  Capital expenditures......................................   (5,587)     (496)     (391)
  Cash received on sale of property and equipment...........       37        54        12
                                                              -------   -------   -------
Net cash used by investing activities.......................   (5,550)     (442)     (379)
                                                              -------   -------   -------
Cash flows from financing activities:
  Distributions paid to Unitholders.........................  (12,807)   (9,334)   (7,816)
                                                              -------   -------   -------
Increase in cash and cash equivalents.......................    2,672     8,750     2,850
Cash and cash equivalents at beginning of year..............   15,767     7,017     4,167
                                                              -------   -------   -------
Cash and cash equivalents at end of year....................  $18,439   $15,767   $ 7,017
                                                              =======   =======   =======
Supplemental cash flow and other information:
  Interest paid (no interest was capitalized)...............  $    28   $    39   $    37
                                                              =======   =======   =======
  Distributions declared but not paid.......................  $ 2,931   $ 2,389   $ 1,956
                                                              =======   =======   =======
</Table>

                       See Notes to Financial Statements

                                        22
<PAGE>

                            DORCHESTER HUGOTON, LTD.
                         (A TEXAS LIMITED PARTNERSHIP)

                         NOTES TO FINANCIAL STATEMENTS
                        DECEMBER 31, 2001, 2000 AND 1999

1. GENERAL AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

     Nature of Operations -- The Partnership's operations consist principally of
the operation of natural gas properties located in Kansas and Oklahoma.

     Basis of Presentation -- Per-Unit information is calculated by dividing the
99% interest owned by Unitholders by the 10,744,380 Units outstanding.

     Reclassification -- Certain amounts in the 1999 and 2000 financial
statements have been reclassified to conform to the 2001 presentation.

     Estimates -- The preparation of financial statements in conformity with
accounting principles generally accepted in the United States of America
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results could differ
from those estimates.

     Cash and Cash Equivalents -- The Partnership's principal banking and
short-term investing activities are with major financial institutions.
Short-term investments with a maturity of three months or less are considered to
be cash equivalents and are carried at cost, which approximates fair value. Cash
balances in these accounts may, at times, exceed federally insured limits. The
Partnership has not experienced any losses in such cash accounts or investments
and does not believe it is exposed to any significant risk on cash and cash
equivalents.

     Concentration of Credit Risks -- The Partnership sells its natural gas to
major corporate gas purchasers in the United States and either requires major
corporate guarantees, good credit history with the Partnership, letters of
credit, or performs on-going credit evaluations or review of financial
statements on a regular basis. The Partnership has incurred minimal credit
losses.

     Investments -- The Partnership's investments consist of 128,000 shares of
Exxon Mobil Corporation (previously Exxon Corporation) common stock and are
classified as available for sale. At December 31, 2001 and 2000, the carrying
value of this stock, based on the quoted market price, was $5,030,400 and
$5,564,000, respectively, and the cost was $2,517,455 for both years.

     Property and Equipment -- The Partnership follows the full cost method of
accounting prescribed by the United States Securities and Exchange Commission
under which all costs relating to the acquisition, exploration and development
of natural gas properties (both productive and nonproductive) are capitalized
(not to exceed estimated discounted future net cash flows) by the country
(United States) in which the costs are incurred. Natural gas properties are
being depleted on the unit-of-production method using estimates of proved gas
reserves. Other assets are being depreciated or amortized using straight-line
methods for financial reporting purposes over estimated useful lives of 3 to 40
years.

     Gains or losses are recognized upon the disposition of natural gas
properties involving a significant portion of the Partnership's reserves.
Proceeds from other dispositions of natural gas properties are credited to the
full cost account.

     General Partners -- The Partnership's General Partners have the overall
responsibility for the management, operation and future development of the
properties. Each General Partner is entitled to receive reasonable compensation
in the form of a management fee, to be divided among the General Partners in an
annual aggregate amount of $350,000 plus 1% of the gross income from the
Partnership properties for services rendered in operating and managing the
Partnership. The General Partners are

                                        23
<PAGE>
                            DORCHESTER HUGOTON, LTD.
                         (A TEXAS LIMITED PARTNERSHIP)

                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

also reimbursed for all general and administrative expenses incurred by them on
behalf of the Partnership.

     Operating Agreement -- The Partnership operates substantially all of its
natural gas properties. Efforts are made to balance each working interest
owner's share of production to gas marketed by increasing or decreasing the
volumes of gas allocated to each working interest owner in subsequent months so
that each such working interest owner shall be able to share in the actual
cumulative production in proportion to its interest in the properties. The
Partnership receives in-kind the Partnership's share of gas produced from 11
wells in Oklahoma (10 operated by others and 1 operated by the Partnership). At
December 31, 2001, the net balance owed the Partnership is approximately 14,000
MCF compared to approximately 300 MCF at December 31, 2000.

     Other Agreements -- Effective May 1, 1997, the Partnership's Kansas gas was
committed for sale and processing to PanEnergy Field Services, Inc. (now Duke
Energy Field Services, Inc.) for a period of 3 years and year to year
thereafter. Duke Energy will pay based on an index of the market price in the
field plus a premium. Similarly, effective July 1, 2000 the Partnership's
Oklahoma gas was committed for sale to Williams Energy Marketing and Trading
Company ("WEM & TC") for a one-year period at a premium over the market price
index. Since July 1, 2001, such sales have been on a month-to-month basis at
varying market price indexes. During 1996, the Partnership's Oklahoma gas began
a five-year commitment to Williams Field Services Company for delivery through a
processing facility. During 2001, the commitment was extended another five
years. Effective February 28, 2002 Williams Field Services will sell the
processing facility to Duke Energy Field Services L.P. who intends to shift the
processing to its facility near Liberal, Kansas. The quantity sold to WEM & TC
is determined by nominations at the processing facility outlet. Imbalances with
actual deliveries to Williams Field Services Company are corrected in each
subsequent month. At December 31, 2001, the imbalance was approximately 3,000
MMBTU owed the Partnership compared to 7,000 MMBTU owed the Partnership at
December 31, 2000.

     Operating Revenue -- Natural gas revenues are recognized as production and
sales take place (the "sales method"). The Partnership's purchasers (including
their affiliates) who accounted for more than 10% of natural gas revenues for
each of the years ended December 31, 2001, 2000, and 1999 are as follows:

<Table>
<Caption>
                                                              PURCHASER   PURCHASER
YEAR                                                             "A"         "B"
----                                                          ---------   ---------
<S>                                                           <C>         <C>
2001........................................................     83%         16%
2000........................................................     83%         16%
1999........................................................     80%         19%
</Table>

     The Partnership believes that the loss of any single customer would not
have a material adverse effect on the results of its operations because the
transmission (and gathering) pipelines connected to the Partnership's facilities
are required by the Federal Energy Regulatory Commission or state regulations to
provide continued equal access for shipment of natural gas. Additionally, there
are numerous buyers available on each pipeline.

     Income Taxes -- The Partnership is treated as a partnership for income tax
purposes and, as a result, income or loss of the Partnership is includible in
the tax returns of the individual Unitholders. Accordingly, no recognition has
been given to income taxes in the financial statements.

     An investment in the Partnership by certain tax-exempt entities (such as
IRA's, pension plans, etc.) may produce Unrelated Business Taxable Income
("UBTI"). Many tax-exempt entities are

                                        24
<PAGE>
                            DORCHESTER HUGOTON, LTD.
                         (A TEXAS LIMITED PARTNERSHIP)

                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

subject to tax on UBTI. Tax-exempt entities subject to the tax on UBTI must file
with the IRS for each tax year that the entity has gross income of $1,000 or
more from an unrelated trade or business. Additionally, the Partnership reports
Unitholders' share of depreciation adjustments for alternative minimum tax
("AMT") purposes. The AMT adjustment must be taken into account when figuring
Unitholder passive activity gains and losses for AMT purposes. UBTI and AMT are
specialized areas of the tax law -- Unitholders should consult tax advisors
concerning their own tax situation. Finally, depletion of natural gas properties
is an expense allowable to each individual partner and the depletion expense as
reported on the financial statements will not be indicative of the depletion
expense an individual partner or Unitholder may be able to deduct for income tax
purposes.

     Simplified Employee Pension Plan -- Contributions aggregating $150,980,
$136,065, and $135,125 were made to eligible employees' accounts for 2001, 2000,
and 1999, respectively under the Partnership's simplified employee pension plan.
Employees become eligible in their third calendar year of employment. The
Partnership does not have any other post-retirement benefit plans.

     Operating Leases -- The Partnership rents administrative office space under
leases expiring at various dates through 2007. The Partnership also rents nine
skid-mounted field gas compressor units on a month-to-month basis. The
Partnership also has various prepaid site leases in Kansas and Oklahoma. Total
rental expense was $311,000, $337,000, and $333,000 for the years ended December
31, 2001, 2000, and 1999, respectively.

2. LOANS AND LONG-TERM DEBT

     On July 19, 1994, the Partnership entered into a $15,000,000 unsecured
revolving credit facility (the "Credit Agreement") with Bank One, Texas, NA (the
"Bank") which will expire July 31, 2002. The current borrowing base is
$6,000,000, which will be re-evaluated by the Bank at least annually. If, on any
such date, the aggregate amount of outstanding loans and letters of credit
exceed the current borrowing base, the Partnership is required to repay the
excess. This credit facility includes both cash advances and any letters of
credit that the Partnership may need, with interest being charged at the Bank's
base rate, which was 4.75% on December 31, 2001. All amounts borrowed under this
facility become due and payable on July 31, 2002. As of December 31, 2001, no
letters of credit were issued under the credit facility. The Partnership is
required to maintain certain minimum defined financial ratios with respect to
its current ratio and the ratio of net cash flow to debt service. In addition,
Partnership capital must be maintained above specified amounts. This note has
been guaranteed by the General Partners. Since July 1994 the maximum amount
borrowed under the Credit Agreement has been $5,800,000. During 2001 and 2000
the amount borrowed under the Credit Agreement was $100,000 (the minimum
borrowing necessary to maintain the credit facility).

3. AGREEMENT TO COMBINE BUSINESSES AND PROPERTIES.

     As disclosed on a Form 8-K filed on December 14, 2001, the Partnership has
signed definitive agreements to combine the businesses and/or properties of the
Partnership, Republic Royalty Company, and Spinnaker Royalty Company, L.P., in a
non-taxable transaction, into a new publicly traded limited partnership. During
2001, approximately $785,000 was expensed related to the combination compared to
$339,000 in 2000. The combination is subject to a number of conditions including
(1) approval by a majority of Dorchester Hugoton Unitholders, (2) approvals by
the owners of Spinnaker Royalty and Republic Royalty and affiliated partnerships
and interest holders, and (3) filings with and/or clearances by various
securities and governmental authorities.

                                        25
<PAGE>
                            DORCHESTER HUGOTON, LTD.
                         (A TEXAS LIMITED PARTNERSHIP)

                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

4. COMMITMENTS AND CONTINGENCIES

     Since its first annual payment in 1997, each May the Partnership paid an
Oklahoma production payment (calculated through the prior February) that is
based upon the difference between market gas prices compared to a table of
rising prices and based upon a table of declining volumes. On August 9, 2001,
the Partnership paid $5,270,000 to acquire, effective March 1, 2001, the
Oklahoma production payment.

     Through 1998 the Partnership recorded $450,000 (which included related
interest) towards a request from Panhandle Eastern Pipe Line Company ("PEPL")
for refund of Kansas tax reimbursements received by the Partnership during the
years 1983 to 1987. These charges resulted from a ruling by the United States
Court of Appeals for the District of Columbia, which overruled a previous order
by the Federal Energy Regulatory Commission ("FERC"). On March 9, 1998, $151,757
was paid to PEPL. An additional $366,633, which was still awaiting possible
settlement/regulatory/judicial/ legislative action, was placed into an escrow
account. On March 2, 1999, $2,840 was released from escrow to PEPL. On June 22,
2001, the Partnership, along with others, reached a Settlement Agreement with
PEPL which became final October 15, 2001 upon approval by the FERC. The
Partnership reduced its accrued liability from approximately $419,000 to
approximately $320,000 during the third quarter of 2001. Pursuant to that
Settlement, during October 2001, the Partnership returned all funds collected
from royalty owners (approximately $35,000) who had paid their refund obligation
to the Partnership. Also, in connection with the Settlement, on November 20,
2001 the Partnership paid from the escrow account approximately $285,000 to PEPL
and approximately $135,000 to the Partnership, subsequently closing the escrow
account.

     The Partnership is involved in a few other legal and/or administrative
proceedings arising in the ordinary course of its gas business, none of which
have predictable outcomes and none of which are believed to have any significant
effect on financial position or operating results.

     The Partnership adopted a severance policy during the first quarter of
1998. Benefits are generally payable to employees and General Partner(s) in the
event the Partnership incurs reduction in force or the elimination of a position
or group of positions. The policy provides for up to approximately $2.8 million
of severance payments if such obligations occur. Pursuant to the Combination
Agreement referred to in Note 3 such severance payments, estimated to be $2.7
million, will be paid by the Partnership prior to closing of the transaction.

5. UNAUDITED NATURAL GAS RESERVE INFORMATION

     Proved natural gas reserves are estimated quantities which geological and
engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions. Proved developed natural gas reserves are reserves that can be
expected to be recovered through existing wells with existing equipment and
operating methods. The Partnership retained Calhoun, Blair & Associates, Inc.,
an independent petroleum engineering consulting firm, to provide annual
estimates as of December 31 of each year of the Partnership's future net
recoverable natural gas reserves. The Partnership has no known reserves of crude
oil. There have been no events that have occurred since December 31, 2001 that
would have a material effect on the estimated proved developed natural gas
reserves.

     In accordance with SFAS No. 69 and Securities and Exchange Commission
("SEC") rules and regulations, the following information is presented with
regard to the Partnership's gas reserves, all of which are proved, developed and
located in the United States.

     The SEC has adopted SFAS No. 69 disclosure guidelines for oil and gas
producers. These rules require the Partnership to include as a supplement to the
basic financial statements a standardized measure of discounted future net cash
flows relating to proved oil and gas reserves.
                                        26
<PAGE>
                            DORCHESTER HUGOTON, LTD.
                         (A TEXAS LIMITED PARTNERSHIP)

                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

     The standardized measure, in management's opinion, should be examined with
caution. The basis for these disclosures is an independent petroleum engineer's
reserve study which contains imprecise estimates of quantities and rates of
production of reserves. Revision of prior year estimates can have a significant
impact on the results. Also, exploration and production improvement costs in one
year may significantly change previous estimates of proved reserves and their
valuation. Values of unproved properties and anticipated future price and cost
increases or decreases are not considered. Therefore, the standardized measure
is not necessarily a "best estimate" of the fair value of the Partnership's gas
properties or of future net cash flows.

     The following summaries of changes in reserves and standardized measure of
discounted future net cash flows were prepared from estimates of proved reserves
developed by independent petroleum engineers.
                SUMMARY OF CHANGES IN PROVED DEVELOPED RESERVES

<Table>
<Caption>
                                                                  NATURAL GAS (MMCF)
                                                              ---------------------------
                                                               2001      2000      1999
                                                              -------   -------   -------
<S>                                                           <C>       <C>       <C>
Estimated quantity, beginning of year.......................   54,127    58,209    64,147
Revisions in previous estimates.............................      743     3,012     1,478
Production..................................................   (6,568)   (7,094)   (7,416)
                                                              -------   -------   -------
Estimated quantity, end of year.............................   48,302    54,127    58,209
                                                              =======   =======   =======
Depletion of natural gas properties (per MCF)...............  $  0.31   $  0.24   $  0.24
                                                              =======   =======   =======
Development costs incurred (in thousands of dollars)........  $   240   $   301   $   332
                                                              =======   =======   =======
Leasehold acquisitions (in thousands of dollars)............  $ 5,297   $    23   $    16
                                                              =======   =======   =======
</Table>

            STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
                             (DOLLARS IN THOUSANDS)

<Table>
<Caption>
                                                                2001       2000       1999
                                                              --------   --------   --------
<S>                                                           <C>        <C>        <C>
Future estimated gross revenues.............................  $117,029   $313,890   $118,516
Future estimated gross production payment (ORRI)*...........        --    (18,613)    (5,353)
Future estimated production and development costs...........   (51,083)   (71,661)   (45,930)
                                                              --------   --------   --------
Future estimated net revenues...............................    65,946    223,616     67,233
10% annual discount for estimated timing of cash flows......   (21,220)   (83,613)   (22,851)
                                                              --------   --------   --------
Standardized measure of discounted future estimated net
  revenues..................................................  $ 44,726   $140,003   $ 44,382
                                                              ========   ========   ========
Sales of natural gas produced, net of production costs......  $(21,899)  $(20,812)  $(11,525)
Net changes in prices and production costs..................   (89,233)   108,425      8,717
Revisions of previous quantity estimates....................     3,488      3,964      2,509
Accretion of discount.......................................    12,471      3,932      3,627
Other.......................................................      (104)       112        445
                                                              --------   --------   --------
Net change in standardized measure of discounted future
  estimated net revenues....................................  $(95,277)  $ 95,621   $  3,773
                                                              ========   ========   ========
</Table>

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

* The ORRI was acquired during 2001 for $5,270,000. See Note 4 to the Financial
  Statements.

6. UNAUDITED QUARTERLY FINANCIAL DATA

     Quarterly financial data for the last two years (dollars in thousands
except per unit data) is summarized as follows:

<Table>
<Caption>
                                     2001 QUARTER ENDED                      2000 QUARTER ENDED
                            -------------------------------------   -------------------------------------
                                                 SEPTEM-   DECEM-                        SEPTEM-   DECEM-
                            MARCH 31   JUNE 30   BER 30    BER 31   MARCH 31   JUNE 30   BER 30    BER 31
                            --------   -------   -------   ------   --------   -------   -------   ------
<S>                         <C>        <C>       <C>       <C>      <C>        <C>       <C>       <C>
Net operating revenues....  $11,378    $7,014    $4,729    $3,658    $4,161    $5,572    $7,037    $8,412
Net earnings..............    9,224     4,830     3,045    1,252      2,638     3,403     5,239     6,682
Net earnings per Unit.....  $  0.85    $ 0.44    $ 0.28    $0.12     $ 0.24    $ 0.32    $ 0.48    $ 0.62
</Table>

                                        27
<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.

February 15, 2002                         DORCHESTER HUGOTON, LTD.

                                          P.A. PEAK, INC., GENERAL PARTNER

                                          By       /s/ PRESTON A. PEAK
                                            ------------------------------------
                                                 Preston A. Peak, President
                                             (Principal Executive and Financial
                                                          Officer)

                                          JAMES E. RALEY, INC., GENERAL PARTNER

                                          By       /s/ JAMES E. RALEY
                                            ------------------------------------
                                                 James E. Raley, President
                                             (Principal Executive and Financial
                                                          Officer)

                                          By    /s/ KATHLEEN A. RAWLINGS
                                            ------------------------------------
                                              Kathleen A. Rawlings, Controller
                                               (Principal Accounting 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 and on the dates indicated.

<Table>
<C>                                                      <S>                            <C>
P.A. PEAK, INC.

               By /s/ PRESTON A. PEAK                    General Partner                February 15, 2002
  -------------------------------------------------
                   Preston A. Peak
             President and Sole Director

JAMES E. RALEY, INC.

                By /s/ JAMES E. RALEY                    General Partner                February 15, 2002
  -------------------------------------------------
                   James E. Raley
             President and Sole Director
</Table>

                                        28
<PAGE>

                                 EXHIBIT INDEX

<Table>
<Caption>
                                                                                 PREVIOUSLY FILED AND INCORPORATED WITH
     NUMBER                                DESCRIPTION                             (BEARING THE SAME EXHIBIT NUMBER)
     ------                                -----------                           --------------------------------------
<C>                <S>                                                           <C>
      2.1          -- Combination Agreement, plus exhibits, dated December 13,
                      2001                                                            Filed herewith
      2.2          -- Contribution Agreement, plus exhibits, dated December 13,
                      2001                                                            Filed herewith
      2.3          -- Business Opportunities Agreement, dated December 13, 2001       Filed herewith
      3.           -- Amended and Restated Certificate and Agreement of Limited
                     Partnership, as amended                                          June 30, 1995 Form 10-Q
      3.01         -- Certificates of Amendments to the Agreement of Limited
                     Partnership dated July 2, 1997 and December 15, 1997             December 31, 1997 Form 10-K
      3.02         -- Certificate of Amendment to the Agreement of Limited
                     Partnership dated April 3, 1998                                  March 31, 1998 Form 10-Q
      3.03         -- Certificate of Amendment to the Agreement of Limited
                     Partnership dated April 27, 2001                                 March 31, 2001 Form 10-Q
      4.1          -- Depositary Agreement, as amended                                June 30, 1995 Form 10-Q
      4.2          -- Specimen Depositary Receipt                                     December 31, 1995 Form 10-K
      4.3          -- Nominee Agreement among the Partnership, Dorchester and
                      Nominee                                                         December 31, 1995 Form 10-K
</Table>

     Reports on Form 8-K -- Reports on Form 8-K dated October 26, 2001, December
4, 2001, and December 14, 2001 were filed with events reported under Item 5 and
Item 7 thereof.

     All other schedules and exhibits have been omitted because they are either
not required, not applicable or the required information is disclosed in the
Financial Statements or related Notes.