<PAGE>   1
 
                               1995 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, 1995       COMMISSION FILE NUMBER 0-10697
 
                     (LOGO)  DORCHESTER HUGOTON, LTD.
             (Exact name of registrant as specified in its charter)
 
<TABLE>
<S>                                            <C>
                     TEXAS                               75-1829064
        (State or other jurisdiction of              (I.R.S. Employer 
        incorporation or organization)               Identification No.)
</TABLE>
 
         9696 SKILLMAN STREET, SUITE 320-LB42, DALLAS, TEXAS 75243-8200
          (Address of principal executive offices, including Zip Code)
 
       Registrant's telephone number, including area code: (214) 340-3443
 
       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, 1996 WAS $105,234,000.
 
     AS OF FEBRUARY 1, 1996, THERE WERE OUTSTANDING DEPOSITARY RECEIPTS FOR
10,744,380 UNITS OF LIMITED PARTNERSHIP INTEREST IN DORCHESTER HUGOTON, LTD.
 
     Documents Incorporated by Reference:  None
 
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<PAGE>   2
 
                             CROSS REFERENCE SHEET
 
<TABLE>
<CAPTION>
                      FORM 10-K ITEM
                    NUMBER AND CAPTION                              CAPTION IN FORM 10-K
                    ------------------                              --------------------
<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>   3
 
                   BUSINESS AND PROPERTIES OF THE PARTNERSHIP
 
     Dorchester Hugoton, Ltd. (the "Partnership") was formed on June 16, 1982 as
a limited partnership under the laws of the State of Texas, pursuant to a
Certificate and Agreement of Limited Partnership (as amended, the "Partnership
Agreement"), by Dorchester Gas Corporation ("Dorchester") which contributed
working interests in certain natural gas properties in Kansas and Oklahoma to
the Partnership. Depositary receipts ("Depositary Receipts") for units of
limited partnership interest ("Units") were distributed on August 20, 1982 to
Dorchester stockholders of record as of July 2, 1982 in the form of a taxable
dividend on the basis of one Unit for each ten shares of Dorchester common stock
held. Cash payments were made in lieu of distributing fractional Units.
 
     Neither Dorchester nor the Partnership received any proceeds from the
distribution of the Units. The Partnership has its principal place of business
at 9696 Skillman Street, Suite 320-LB42, Dallas, Texas 75243-8200 (telephone
(214) 340-3443) and field offices in Hooker, Oklahoma and Amarillo, Texas. The
Partnership has working interests in certain properties producing natural gas
from the Hugoton gas fields of Kansas and Oklahoma. The Hugoton field is
considered one of the most prolific gas fields in the United States. All of the
wells (except for infill wells in Kansas and two replacement wells in Oklahoma)
in which the Partnership currently has an interest were drilled and have been
producing since prior to 1954. At January 1, 1996, the Partnership employed
fifteen full time permanent employees (not including General Partners).
 
KANSAS PROPERTIES
 
     The Partnership's working interests currently include 32 natural gas wells
(18.88 net wells) producing from the Kansas Hugoton field on 11,515 gross
developed acres (7,062 net acres). Eighteen of the wells (in each of which the
Partnership has an 80% working interest) are operated by the Partnership. The
Partnership's portion of natural gas from these operated wells is currently sold
under monthly nominations in the spot market at field prices of $1.815 per MMBTU
at February 1, 1996. The Partnership's portion of gas sales was approximately
5.9 million cubic feet per day ("MMCFD") during January 1996. Most of the gas is
delivered through an 11 mile gas gathering pipeline and compression facility
that the Partnership initially completed in 1988. During 1995 the compression
facility was modified to handle greater volumes of gas at lower pressures. Also,
the gas gathering pipeline was extended 4 1/2 miles during 1995 to enable all 18
wells to flow through the Kansas compression facility. Previously gas from two
of the wells was delivered through pipelines of others. The remaining 14 wells
(in each of which the Partnership has a 32% working interest) are operated by an
unaffiliated third party who is also receiving market-responsive prices for
natural gas production including the Partnership's portion.
 
     The Partnership's allowable quantity of natural gas which may be produced
from its Kansas properties is regulated by the Kansas Corporation Commission
("KCC"). Such allowables increased October 1, 1993 and April 1, 1994. The
increase effective April 1, 1994 was primarily a result of basic rule changes by
the KCC. Recent field wide state tests show a higher than normal decrease in the
gas reservoir pressure of nearly all producers in the Kansas Hugoton field. The
Partnership's October 1995 allowable (effective until October 1996) declined
slightly compared to October 1994 primarily as a result of lower test pressures.
 
     In April, 1986, the KCC issued an order authorizing phased-in infill
drilling on 320 acre spacing. The Partnership drilled and completed (including
acquired and completed wellbores of others) nine producers as follows: one in
1987; two in 1988; three in 1989; two in 1990; and one in 1995. The Partnership
has also participated in the drilling and completion of seven producers on its
non-operated properties as follows: one in 1987; one in 1988; and five in 1989.
One infill well was plugged in 1992 and another in 1993 for economic reasons.
The Partnership currently has available two previously undrilled units for
additional infill wells.
 
     The Partnership also has minor overriding royalty interests in producing
natural gas wells in Kansas.
 
                                        1
<PAGE>   4
 
OKLAHOMA PROPERTIES
 
     The Partnership owns working interests in 128 natural gas wells (115.7 net
wells) producing from the Guymon-Hugoton field on 80,501 gross developed acres
(74,501 net acres). It currently operates and owns 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 an 11 well group operated
by unaffiliated third parties.
 
     THE PARTNERSHIP'S ACTIVITIES IN THE GUYMON-HUGOTON FIELD HAVE BEEN
INFLUENCED BY NUMEROUS LAWSUITS WHICH ARE DESCRIBED IN CONSIDERABLE DETAIL IN
NOTE 3 TO THE FINANCIAL STATEMENTS.
 
     Until May 1, 1994, natural gas from the existing Guymon-Hugoton field was
sold under a 1946 Gas Purchase Contract (the "Contract"), as amended. In a
December, 1992 settlement of litigation, the Partnership amended the Contract,
effective January 1, 1993, with Natural Gas Pipeline Company of America
("Natural") providing for the Partnership to receive prices equivalent to an
index of market responsive pricing. Natural subsequently assigned this contract
to MidCon Gas Services Corp. ("MidCon"), an affiliate of Natural (collectively
"NGPL"). Following NGPL's notice to the Partnership in January, 1994 the
Contract terminated on May 1, 1994. On May 1, 1994, the Partnership began
operation of its low pressure gas pipeline gathering facilities and began sales
at low pressure direct (without processing or compressing) to Williams Gas
Marketing Company. Such sales continued until November 1, 1994 at generally 95%
of an index price reflective of the spot market price in the area. Because of
capacity, Williams limited purchases of the Partnership's gas during this period
to about one-half of the quantity available for sale.
 
     Beginning November 1, 1994, the Partnership's new 5400 horsepower gas
compression and dehydration facility became operational and gas began being
delivered direct (without processing) to Panhandle Eastern Pipe Line Company
("Panhandle Eastern"). Numerous other transmission pipelines are also nearby.
Such new facilities have, among other things, replaced the compression
previously provided under the Contract by NGPL. Installed cost of the facilities
totaled $6.0 million which include offices and warehouse storage for both field
and compressor operations. The Partnership's portion of gas sales delivered to
Panhandle Eastern averaged 17.7 MMCFD during 1995. Centana Energy or Williams
Energy Services Company (formerly Williams Gas Marketing Company) have purchased
the gas since November 1, 1994 at prices slightly greater than an index price
reflective of the spot market price in the area.
 
     Pending Federal Energy Regulatory Commission approval, the Partnership
anticipates delivery of gas from its Oklahoma compression facilities to Williams
Gas Processing -- Mid Continent Region Co., a subsidiary of the Williams
Companies, Inc. in the first half of 1996. Williams Field Services Company will
subsequently process the gas at its newly constructed plant near Baker, Oklahoma
and return the gas as directed by the Partnership to the available transmission
pipelines at the plant outlet which include Williams Natural Gas Company,
Panhandle Eastern Pipe Line Company, and Natural Gas Pipeline Company of
America. The gas returned to the Partnership for subsequent sale will be of
improved quality, including having the contaminant nitrogen removed.
 
     Prior to May 1, 1994, the Partnership's Oklahoma production was subject to
a June 16, 1982 Gas Processing Agreement (the "Agreement") with a Parker &
Parsley Petroleum Company subsidiary or affiliate (the successor to Damson Oil
Corporation & affiliates -- collectively referred to as "P&P"). Generally, the
Oklahoma gas production was processed in P&P's Hooker, Oklahoma gas processing
plant ("the Hooker Plant") where natural gas liquids such as ethane, propane,
and butanes were extracted and the remaining gas ("residue gas") was delivered
and sold to NGPL at the plant outlet. The extraction of natural gas liquids
requires the consumption of some gas as fuel and the extraction itself shrinks
the gas production in both volume and heating value (referred to as "fuel and
shrinkage"). The Agreement provided, among other things, that P&P operate the
Partnership's gas gathering pipelines, that P&P retain the natural gas liquids
extracted and that the Partnership receive, for fuel and shrinkage incurred, the
value (in MMBTU) of the gas produced at the wellhead (including severance taxes)
less amounts received for residue gas sales under the Contract. The Agreement
 
                                        2
<PAGE>   5
 
terminated upon termination of the Contract on May 1, 1994 (Parker & Parsley
contends termination on January 1, 1993). Since January 1, 1993 P&P has paid for
this fuel and shrinkage at an assumed value for the gas produced at the wellhead
of under $.20/MCF, which the Partnership strongly disputes. Approximately 25%
(contractual limitation) of the wellhead volume (adjusted for heating value)
became fuel and shrinkage. Since May 1, 1994, the Partnership's gas has been
delivered and sold without processing.
 
     Subject to pending litigation, the increase in price effective January 1,
1993 for Oklahoma's natural gas production may generate a production payment due
to P&P. The production payment, as well as certain future rights of limited
participation in additional wells that might be drilled if well spacing is
changed, relates to the Partnership's purchase of the 20% working interest from
P&P in 1986.
 
     In 1989 the Oklahoma Corporation Commission concluded its inquiry
proceedings into the need for increased density drilling on a field-wide basis
in the Guymon-Hugoton field and determined that the presently permitted well
density is adequate. However, the Partnership may perform exploratory drilling
at a later date to test for additional zones that may underlie portions of the
properties or attempt to fracture treat some existing wells (see Management's
Discussion and Analysis of Financial Condition and Results of Operations).
 
     The Partnership also has minor royalty interests in producing natural gas
wells in Oklahoma.
 
NATURAL GAS RESERVES AND OTHER FINANCIAL DATA
 
     As a result of publicity by others regarding acquisitions and proposed
sales of Kansas and Oklahoma Hugoton gas reserves, during July, 1995 the
Partnership requested Calhoun Engineering, Inc., its independent petroleum
engineering consulting firm, to study the proved natural gas reserves in order
to determine if the Partnership's reserves were being stated on a basis
comparable to other producers in the Kansas/Oklahoma Hugoton fields. The study
yielded a January 1, 1995 increase from 83,989 MMCF (millions of cubic feet) to
102,525 MMCF in the Partnership's proved developed natural gas reserves. The
increase is primarily the result of the use of a lower abandonment pressure.
 
     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. In a gas reservoir, the pressure at each well declines as the
well produces gas. A lower abandonment pressure means the well is projected to
produce gas over a longer period of time and thus not be abandoned until the
lower pressure occurs. As a result of this study, the Partnership's abandonment
pressures are now believed to be similar to pressures used by other producers in
the Kansas/Oklahoma Hugoton fields, and the revised reserves are therefore
comparable to reserve statements of others in the same fields. As of January 1,
1996, the Partnership's reserves are 90,925 MMCF after considering 1995
production and revisions.
 
     Information with respect to the Partnership's natural gas reserves and
other financial data is presented in Note 4 to the Financial Statements included
elsewhere herein.
 
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 the properties,
require cash in excess of the Partnership's cash flow, the Partnership would
need to secure (and has secured) outside sources of financing from banks or
other financial institutions. See Note 2 to the Financial Statements for a
discussion regarding current bank borrowings.
 
                                        3
<PAGE>   6
 
REGULATION AND PRICES
 
     The sale of natural gas has been subject to regulation by federal
authorities and production of natural gas is regulated by various state agencies
or authorities. The Federal Energy Regulatory Commission (the "FERC") previously
had authority over administering price regulations for certain natural gas,
which included the Natural Gas Policy Act of 1978 (the "NGPA"). See the
discussion of the Natural Gas Wellhead Decontrol Act of 1989 below regarding
price regulations. In addition, various aspects of the Partnership's operations
are affected by various statutory controls or obligations and, in varying
degrees, by political developments and federal and state laws and regulations.
In particular, natural gas production operations are affected by changing tax
and other laws relating to the petroleum industry, by constantly changing
administrative regulations and possible interruption or termination by
government authorities on account of ecological and other considerations.
Production rates have for many years been subject to conservation and
environmental laws and regulations. In addition, the petroleum industry is
subject to specific federal and state tax laws.
 
     Both states in the areas in which the Partnership has producing natural gas
properties have regulatory provisions regulating the amount of natural gas that
can be produced by annually assigning to each well or proration unit an
allowable rate of production. In 1995 Oklahoma reduced its statewide gas
proration regulation, but retained such regulation in the Guymon-Hugoton field.
Both states have regulations not only controlling the rates of production, but
also requiring permits for the drilling of wells, controlling the spacing of
wells, preventing the waste of natural gas resources, environmental protection
and various other matters.
 
     With the enactment of the Natural Gas Wellhead Decontrol Act of 1989,
natural gas price controls were eliminated at the earlier of expiration of
current contracts, upon mutual renegotiation of current contracts or January 1,
1993. Consequently, on January 1, 1993 the sale of Oklahoma gas became solely
dependent upon the contractual arrangements with the purchaser rather than the
FERC "minimum rate" price ($.402/MCF in December, 1992 before tax adjustments)
established by the NGPA. As described in Note 3 to the Financial Statements
herein, the Contract was amended effective January 1, 1993 to enable sale of the
Partnership's Oklahoma gas at prices equivalent to an index of market responsive
pricing. Subsequently, the Contract terminated and gas has been sold under
short-term arrangements.
 
     Since January 1, 1993, 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. Since January 1995, the
lowest price was $1.235/MMBtu in August 1995 and the highest was $2.005/MMBtu in
January 1996. The Partnership anticipates continued fluctuations in marketplace
pricing.
 
     Currently, the FERC is allowing regulated transmission pipelines to
transfer or sell portions of their system classified or re-classified by the
FERC as gas gathering pipelines to non-regulated entities or affiliates. The
Partnership's gas currently delivered from its new facility in Oklahoma will not
be affected by any such sale or transfer and the Partnership believes the effect
in Kansas to be minimal since only one of the two transmission pipelines to
which the Partnership delivers gas is scheduled to become a non-regulated
gathering pipeline. Effective March 1, 1996, as a result of FERC approval, the
Partnership's Kansas gas, if delivered to one specific transmission pipeline,
will be subject to a previously negotiated agreement with Anadarko Gathering
Company providing for a portion of the gas transportation and mainline
compression previously provided by one of the regulated transmission pipelines.
Such agreement also includes gas gathering and compression for the Partnership's
interest in the 14 wells operated by others which have been gathered and
compressed by a transmission pipeline company. Additionally, the Partnership is
negotiating a gathering and compression agreement with Williams Field
Services -- Mid-Continent Region Company as Agent for Williams Gas Processing --
Mid-Continent Region Company to provide for gas gathering and compression
previously provided by Williams Natural Gas Company for four wells (three of
which the Partnership has minimal interest) that are not connected to the
Partnership's Oklahoma Compression facility. Such agreement will not be
effective until the FERC approves a pending proposed transfer of pipeline
transmission facilities.
 
                                        4
<PAGE>   7
 
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. All present natural gas production in Oklahoma and Kansas is sold
under month to month contracts based upon a price slightly higher than an index
price reflective of the spot market price in the area. 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 quarterly air emission tests at its Oklahoma compression facility
continue to comply with Oklahoma Department of Environmental Quality, Air
Quality Division regulations. The Partnership was advised by the Kansas
Department of Health and Environment (K.D.H.E.) that a permit was not required
for the 1995 modifications to the Kansas compression facility. One Kansas well
will undergo K.D.H.E. regulated non-hazardous soil removal and disposal to
remedy minor mercury contamination.
 
                DEPOSITARY RECEIPTS AND THE DEPOSITARY AGREEMENT
 
     Upon formation of the Partnership, Dorchester deposited all Units with a
predecessor of Society National Bank (the "Depositary"), to be held in
accordance with the Depositary Agreement. The Depositary maintains an account
with respect to the Units deposited for which it has issued Depositary Receipts.
Holders of Depositary Receipts ("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.
 
     Effective August 21, 1995 the transfer agent for the Partnership's
depositary units changed from Society Bank to American Stock Transfer & Trust
Company, 40 Wall Street, New York, New York 10005. The Partnership amended the
Depositary Agreement to conform to such change.
 
     On July 25, 1989, the Partnership announced a two-for-one (2-for-1) split
of its Units effective July 26, 1989. Depositary Receipts for the additional
Units were distributed on August 5, 1989 to Unitholders of record as of July 26,
1989. On October 1, 1987, the Partnership announced a three-for-one (3-for-1)
split of its Units effective October 15, 1987. Depositary Receipts for the
additional Units were distributed on October 30, 1987, to Unitholders of record
as of October 15, 1987. These non-taxable splits were made to enhance the
tradability of the Depositary Receipts evidencing the Units and increased to
5,372,190 at October 30, 1987 and 10,744,380 at August 5, 1989, the number of
Units presently outstanding. All per-Unit information has been retroactively
adjusted to give effect to these non-taxable splits.
 
     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 1995 and 1994 were as follows:
 
<TABLE>
<CAPTION>
                                                       1995                       1994
                                              -----------------------    ----------------------
                                              LOW    HIGH     VOLUME     LOW    HIGH     VOLUME
                                              ---    ----    --------    ---    ----    --------
    <S>                                       <C>     <C>     <C>        <C>    <C>      <C>
    First Quarter...........................  11 1/2  12 1/4  224,000    15      17      517,000
    Second Quarter..........................  10 7/8  12 1/4  522,000    12 3/4  15 1/2  302,000
    Third Quarter...........................  10      12 1/2  447,000    12 1/4  13 3/4  369,000
    Fourth Quarter..........................  10 3/4  13      352,000    11 1/2  14 1/4  375,000
</TABLE>
 
     As of January 1, 1996, there were approximately 4,100 Unitholders.
 
                                        5
<PAGE>   8
 
     During 1993 the National Association of Securities Dealers, Inc. (the
"NASD") adopted new governance rules for limited partnerships traded on the
Nasdaq Stock Market. The Partnership sought a waiver or exemption from certain
of these rules which became effective on October 31, 1993. Effective August
1995, the Partnership established a new Advisory Committee consisting of two
independent advisors to function as the audit committee for the Partnership and
to review and approve any transactions between the Partnership and the General
Partners, including any compensation and benefits paid to the General Partners
by the Partnership. The formation of the Advisory Committee has been approved by
the Nasdaq Listing Qualifications Committee and resolves the previous pending
request by the Partnership for an exemption from the NASD limited partnership
governance rules. The Partnership Agreement was amended accordingly.
 
     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. See Management's Discussion
and Analysis of Financial Condition and Results of Operations for information
regarding future cash distributions. 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.
 
     Distributions per Unit covering quarterly cash receipts for natural gas
production have been as follows:
 
<TABLE>
<CAPTION>
                                                    YEAR ENDED DECEMBER 31,
      QUARTER         1982   1983   1984   1985/86   1987   1988   1989/90/91   1992   1993   1994   1995
--------------------  ----   ----   ----   -------   ----   ----   ----------   ----   ----   ----   ----
<S>                   <C>    <C>    <C>    <C>       <C>    <C>    <C>          <C>    <C>    <C>    <C>
First...............   N/A   $.02   $.01    $ .01    $.02   $.03      $.05      $.05   $.12   $.17   $.17
Second..............   N/A    .01    .01      .01     .02    .04       .05       .05    .15    .17    .17
Third...............  $.01    .01    .01      .01     .03    .04       .05       .05    .17    .17    .17
Fourth..............   .02    .01    .01      .02     .03    .04       .05       .08    .17    .17    .17
                      ----   ----   ----    -----    ----   ----      ----      ----   ----   ----   ----
Total...............  $.03   $.05   $.04    $ .05    $.10   $.15      $.20      $.23   $.61   $.68   $.68
                      ====   ====   ====    =====    ====   ====      ====      ====   ====   ====   ====
</TABLE>
 
     Effective with the third quarter 1995 distribution, the Partnership's new
transfer agent, American Stock Transfer & Trust, paid all distributions as
declared. Continue to contact the Partnership for questions on distributions for
previous periods.
 
     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
 
                                        6
<PAGE>   9
 
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 ($408 for 1995 and $427 for 1994) 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 offices of the Partnership 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 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.
 
                                        7
<PAGE>   10
 
     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, 1996 and other persons,
excluding depositaries, of record on January 1, 1996 who held 5% or more of the
Units.
 
<TABLE>
<CAPTION>
                                                             NUMBER OF
                                                               UNITS            PERCENT OF
                                                         BENEFICIALLY OWNED     CLASS(1)(3)
                                                         ------------------     -----------
    <S>                                                  <C>                    <C>
    Dana Corporation Employee
      Benefit Trust Plan.................................        580,000            5.4%
    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.....         14,434            .13%
</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, 1995.
 
                                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 by Dorchester and
any other properties acquired pursuant to the Partnership Agreement.
 
     The Partnership Agreement was amended August 9, 1995 to provide for an
Advisory Committee and to make certain other amendments which were necessary to
conform to, or to provide desired flexibility permitted by, changes in Texas
Partnership law and federal tax law. The amendments were filed with the June 30,
1995 United States Securities and Exchange Commission Form 10-Q.
 
     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.
 
                                        8
<PAGE>   11
 
MANAGEMENT OF THE PARTNERSHIP
 
     The General Partners, who have purchased an aggregate 1% net profits
interest in the Partnership, are P. A. Peak, Inc. which is owned by Preston A.
Peak, age 73, Investor, and James E. Raley, Inc., which is owned by James E.
Raley, age 56, Engineer. Kathleen A. Rawlings, age 38, 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 member of the
Board of Directors of Kaneb Services, Inc. as well as one of its subsidiaries.
Mr. Raley is an independent consulting engineer.
 
     Effective August 1995, the Partnership established a new Advisory Committee
consisting of two independent advisors to function as the audit committee for
the Partnership and to review and approve any transactions between the
Partnership and the General Partners, including any compensation and benefits
paid to the General Partners by the Partnership. Mr. Rawles Fulgham of Dallas,
Texas and Mr. W. Randall Blank of Houston, Texas have agreed to serve on the
Advisory Committee. Until his recent retirement, Mr. Fulgham served as Executive
Director of Merrill Lynch Private Capital, Inc. He currently serves as senior
advisor of Merrill Lynch & Co. Inc. and a director of Dresser Industries, Inc.,
NCH Corporation, Global Industrial Technologies, Inc., Banctec, Inc. and
Republic Financial Services, Inc. Mr. Blank is currently Executive Vice
President of Rockland Pipeline Company in Houston, Texas and on the Board of
Directors of the Gas Processors' Association.
 
     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 therefor, 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.
 
     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, 1995 and August
9, 1995 provides for a management fee to be divided among the General Partners
in an annual aggregate amount of $250,000 (previously $150,000 effective January
1, 1991) 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
                                             ----------------------------------------------------------
    SUMMARY COMPENSATION TABLE               PRESTON A. PEAK OR    JAMES E. RALEY OR
                                              P.A. PEAK, INC.     JAMES E. RALEY, INC.
    Year                                      GENERAL PARTNER       GENERAL PARTNER      TOTAL FOR YEAR
    ----                                     ------------------   --------------------   --------------
    <S>                                      <C>                  <C>                    <C>
    1993...................................       $147,269              $154,225(a)         $301,494
    1994...................................        133,120               139,425(a)         $272,545
    1995...................................        178,468               202,278(a)         $380,746
</TABLE>
 
---------------
(a) Includes the amount of taxable medical insurance premiums and payments of
    $6,956, $6,305, and $5,894 for James E. Raley in 1993, 1994, and 1995,
    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. No employees or officers of the
corporate General Partners participate in the Partnership's simplified
 
                                        9
<PAGE>   12
 
employee pension plan. Fees and expenses paid to members of the Advisory
Committee amount to less than $30,000 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 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
 
                                       10
<PAGE>   13
 
     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.
 
     The General Partners are reimbursed for all expenses incurred by them on
behalf of the Partnership, including their general and administrative expenses
(a total of $22,784 for 1995).
 
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 (the Applicable Percentage of Unitholders means
Unitholders who own from June 16, 1982 to June 16, 1984 100% of the Units owned
by all Unitholders, for the next three succeeding years more than 95%, 90% and
85% of such Units, respectively, and thereafter 80% of such Units) of the
Unitholders 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 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. Any action which
may be taken at a meeting of the Unitholders may be taken without a meeting if a
 
                                       11
<PAGE>   14
 
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.
 
     There were no meetings of the Unitholders held during 1995.
 
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
 
                                       12
<PAGE>   15
 
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.
 
          (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
 
                                       13
<PAGE>   16
 
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.
 
INCOME TAX TREATMENT
 
     Dorchester 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. The Partnership itself, to the extent
that it is treated for federal income tax purposes as a partnership, is not
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. Therefore, the items of income, gain, loss, deduction or
credit will be allocated 1% to the General Partners and 99% to the Unitholders.
The Partnership is a "federally registered partnership" pursuant to the
provisions of the Internal Revenue Code. As such the IRS may assess a deficiency
attributable to Partnership items within four years (instead of the normal
three-year period) 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.
 
     Under certain circumstances, Texas inheritance tax and other laws
respecting 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. 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 partners 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
1995. The assets owned by the Partnership may be subject to ad valorem taxes
assessed by local political jurisdictions within which the assets are situated.
Production from the Partnership's oil or gas properties may also be subject to
state taxes on gross production in certain jurisdictions.
 
                                       14
<PAGE>   17
 
     As a natural resources partnership, Dorchester will not be affected by
existing tax provisions that will cause certain publicly traded partnerships to
be taxed as corporations in 1998.
 
     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, 1995, 1994, 1993, 1992, AND 1991
 
                             (DOLLARS IN THOUSANDS)
 
<TABLE>
<CAPTION>
                                                 1995       1994       1993       1992       1991
                                               --------   --------   --------   --------   --------
<S>                                            <C>        <C>        <C>        <C>        <C>
Operating revenues..........................   $ 13,027   $ 11,624   $ 14,454   $  5,038   $  5,095
Net earnings................................   $  7,592   $  7,599   $  9,687   $  1,997   $  2,157
Net earnings per Unit.......................        70c        70c        89c        18c        20c
Cash distributions per Unit.................        68c        68c        61c        23c        20c
Total assets at December 31.................   $ 19,601   $ 18,861   $ 16,716   $ 12,013   $ 12,541
Notes payable -- long term..................   $  1,725   $  1,850         --         --         --
Partnership capital at December 31..........   $ 14,499   $ 13,769   $ 13,643   $ 10,653   $ 11,163
</TABLE>
 
                                       15
<PAGE>   18
 
                    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 either natural gas
sales volumes or unit prices. The dramatic increase in net earnings and cash
flows from operating activities in 1993 was the result of the contract
litigation settlement and the related contractual amendment to the Partnership's
prior gas purchase contract. This amendment increased pricing of the
Partnership's Oklahoma gas from low regulated prices to higher market prices.
The decrease in net earnings and cash flows from operating activities in 1994
was primarily due to reduced sales of Oklahoma gas during the period which the
Partnership constructed its new Oklahoma compression facilities. The changes in
operating costs and expenses from 1993 to 1994 (a decrease of 20%) and 1994 to
1995 (an increase of 27%) reflect the start-up in operations of the
Partnership's Oklahoma gas gathering pipeline and compression facility.
Previously, a subsidiary of Parker & Parsley Petroleum Company performed the gas
gathering operations pipelining gas to its Hooker, Oklahoma gas processing plant
(referred to as the "Hooker Plant") and the gas purchaser provided gas
compression services. Future increases in operating costs and expenses are not
expected to be as significant since the personnel and equipment needed to
operate its Oklahoma facilities are now in place. The increase in operating
costs and expenses during 1995 was more than offset by the revenue increase
which resulted from not delivering the Partnership's Oklahoma gas to the Hooker
Plant. Deliveries to the Hooker Plant resulted in gas shrinkage of approximately
25% for which the Partnership received minimal pricing as fuel and shrinkage
payments. The Partnership's 1993 revenues and weighted average gas prices would
have been approximately 18% higher had gas not been processed through the Hooker
Plant. Net earnings and cash flows from operating activities were also
negatively impacted in 1994 due to sharply lower natural gas market prices. The
1995 increase in revenues is primarily the result of not having the six month
period in 1994 during the construction of the Partnership's Oklahoma facilities
which reduced sales of Oklahoma gas. Weighted average gas prices during 1995
were down 8% compared to 1994. Accounts receivable turnover improved marginally
during 1995.
 
     The Partnership's litigation costs and expenses vary significantly from
year to year and are dependent upon whether litigation activity is at the trial
or appellate courts and were $1,288,000 in 1993, $448,000 in 1994, and $366,000
in 1995. While the Partnership believes its legal costs and expenses will
increase in 1996, the costs and expenses associated with its litigation
activities are not subject to prediction and can vary significantly depending
upon the type of legal activities being pursued.
 
     The Partnership's new 5,400 horsepower gas compression and dehydration
facility, which was constructed at a cost of approximately $6 million, has
continued to operate essentially trouble free since its start-up in November,
1994. Total field operation employees increased from four to eight during 1994
and have remained at eight during 1995. This increase in personnel is reflective
of the Partnership's greater operational responsibility in both compression and
gas gathering pipeline operations. Field usage consumption of natural gas at the
compression and dehydration facilities is estimated to be approximately 4% of
the inlet gas volume. The Partnership anticipates gradual increases in field
operating costs and expenses as repairs to its 45+ year-old pipelines and gas
wells become more frequent. The Partnership does not anticipate significant
replacement of these items at this time.
 
     The Partnership's net change in cash and temporary investments is also
influenced by distributions paid to its Unitholders. Distributions paid
increased 31% and 240% in 1994 and 1993, respectively.
 
     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.
 
                                       16
<PAGE>   19
 
     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.
 
     The Partnership's portion of gas sales volumes (in MMCF) and weighted
average BTU adjusted sales prices per MCF were as follows:
 
<TABLE>
<CAPTION>
                                                                   YEAR ENDED DECEMBER 31
                                                                  -------------------------
                                                                  1995      1994      1993
                                                                  -----     -----     -----
    <S>                                                           <C>       <C>       <C>
    Sales Volumes:
      Oklahoma..................................................  6,464     4,898     7,020
      Kansas....................................................  2,014     2,132     1,479
                                                                  -----     -----     -----
              Total.............................................  8,478     7,030     8,499
                                                                  =====     =====     =====
    Weighted Average Sales Prices:
      Oklahoma..................................................  $1.54     $1.60     $1.63
      Kansas....................................................   1.46      1.76      2.01
      Overall weighted average..................................   1.52      1.65      1.70
</TABLE>
 
     Natural gas production volumes in Kansas increased in 1994 compared to 1993
and 1992 due to increased allowables which were effective April 1, 1994 and
October 1, 1993. The increases in gas production allowables which were effective
April 1, 1994 were primarily the result of changes in the basic proration order
for the Kansas Hugoton field. However, recent field wide state tests show a
decrease in nearly all producers' (including the Partnership's) gas reservoir
pressures. Consequently, the Partnership's October 1995 production allowables
(which are effective until October 1996) declined slightly as compared to
October 1994. In late 1995 the Partnership began installing the necessary
equipment which will enable its existing Kansas compression facility to handle
greater gas volumes at lower pressures. The Partnership also installed
approximately 4 1/2 miles of pipeline in late 1995 which will enable it to
receive natural gas from two wells which previously delivered gas through other
pipelines. The Partnership's total cost through December, 1995 associated with
these projects was approximately $800,000. The projects were operational in
December, 1995 and completed in January, 1996. Since project construction was
done in stages, compression facility downtime was minimized. In June, 1995 the
Partnership drilled and completed one additional infill well in Kansas. It has
no current plans to drill any additional infill wells.
 
     Following a slight decrease in 1993, Oklahoma gas sales volumes dipped
significantly in 1994 and then rebounded in 1995. Sales volumes in 1994 were
significantly reduced beginning in May, 1994 and continuing through October,
1994 during which time the Partnership was limited to delivering its gas to low
pressure pipelines while the Oklahoma compression facility was under
construction. The Partnership's 1995 natural gas sales volumes in Oklahoma were
down only 8% from 1993 volumes. The compression facility has operated with
minimal downtime primarily due to routine preventive maintenance. Natural gas
deliveries continue to be made through a nearby transmission line owned by
Panhandle Eastern Pipe Line Company under month to month sales agreements.
During January 1996, the Partnership drilled and completed one replacement well
in Oklahoma.
 
     Depreciation, depletion and amortization costs (collectively, "DD&A") in
1995 have increased significantly compared to 1994 primarily as a result of the
addition of the $6 million Oklahoma compression facility. As discussed in the
"Business and Properties of the Partnership" portion of this report, the
Partnership's natural gas reserves have been revised in order to be on a basis
comparable with other producers in the Oklahoma/Kansas Hugoton fields. The
resulting January 1, 1995 increase in recoverable reserves, from 84 BCF (billion
cubic feet) to 103 BCF, is the first such revision of this type recorded by the
Partnership since 1982. The Partnership does not anticipate any further material
revisions in the foreseeable future. As a result of increasing reserves and
dependent upon a holder's unit acquisition date, the Partnership expects that
generally Unitholder's DD&A may decrease from 1994, which might increase taxable
income in 1995.
 
                                       17
<PAGE>   20
 
     The Partnership anticipates beginning delivery of natural gas from its
Oklahoma compression facilities to Williams Gas Processing -- Mid Continent
Region Co., a subsidiary of the Williams Companies, Inc., sometime during the
first half of 1996. Williams Field Services Company will subsequently process
the gas at its newly constructed plant near Baker, Oklahoma and return the gas
as directed by the Partnership to the available transmission pipelines at their
plant outlet which include Williams Natural Gas Company, Panhandle Eastern Pipe
Line Company, and Natural Gas Pipeline Company of America. The gas returned to
the Partnership for sale will be of improved quality, including having the
contaminant nitrogen removed.
 
     As discussed in Note 3 to the Financial Statement, litigation between the
Partnership and various entities of Parker & Parsley Petroleum Company (referred
to as "P&P") is continuing. Presently, the Partnership has $242,000 in bonds
posted and has not recorded the amount of any prior favorable judgments. P&P
continues to assert that the Partnership owes it approximately $1.4 million
through March 1, 1994 for an alleged unpaid production payment. The Partnership
has not recognized any amount as being owed for such production payment and all
such issues are still pending in a trial court. From January 1, 1993 through
April 30, 1994, the Partnership's Oklahoma gas was processed by P&P in their
Hooker Plant. A final decision was rendered by an Oklahoma District Court in
September, 1995 which ruled that the 1982 Gas Processing Agreement with P&P was
in effect through April 30, 1994 and covered such processing. The Partnership
was favorably awarded $6,558,036 plus interest for underpayments during the
period by P&P. In October, 1995 and again in early 1996 the Corpus Christi,
Texas Court of Appeals decided that the same 1982 Processing Agreement
terminated on January 1, 1993. Should the Texas decision be valid, there remains
unresolved the amounts due the Partnership for the period January 1, 1993
through April 30, 1994. Further appellate proceedings are underway in both
states. While the Partnership has been generally successful in litigation, the
potential consequences of any unfavorable decision on future operation is
significant in two respects. Should P&P be successful in overturning decisions
regarding ownership of gas gathering pipelines, the Partnership would likely
begin construction of a new gas gathering pipeline system to replace the
existing 45-year old system. The cost of such a new system is estimated to be $7
to $10 million. The Partnership has no estimate of the cost if P&P successfully
overturns decisions and obtains a grant of processing rights (other than an
expired 1982 agreement) as such rights are undefined. Historically, processing
the Partnership's gas reduced the quantity for sale by approximately 25% and P&P
paid only minimal amounts for such reductions. Consequently, the Partnership
must await resolution of these litigation matters prior to making any
significant decisions regarding capital expenditures for production enhancement
or material changes in its current distribution policy.
 
     Inflation has had a minimal effect on the Partnership's operating results.
The overall environmental risks associated with the Partnership's properties
(which include a small number of gas wells with open top tanks having protective
netting) and operations, as well as any related costs associated with its
compliance with environmental laws and regulations, are considered to be
minimal.
 
                                       18
<PAGE>   21
 
                             FINANCIAL INFORMATION
Financial Statements:
 
     Statements of Earnings for the Years Ended December 31, 1995, 1994, 1993.
     Balance Sheets as of December 31, 1995 and 1994.
     Statements of Changes in Partnership Capital for the Years Ended
      December 31, 1993, 1994 and 1995.
     Statements of Cash Flows for the Years Ended December 31, 1995, 1994, 1993.
     Notes to Financial Statements.
 
Exhibits:
 
<TABLE>
<S>                 <C>
           3.       -- Amended and Restated Certificate and Agreement of Limited Partnership,
                       as amended*
           4.1      -- Depositary Agreement, as amended*
           4.2      -- Specimen Depositary Receipt
           4.3      -- Nominee Agreement among the Partnership, Dorchester and Nominee
          27.       -- Financial Data Schedule
</TABLE>
 
     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. No reports on Form 8-K were filed during
the last quarter of the year covered by this report.
---------------
 
* Previously filed and incorporated by reference to the respective Exhibits
  (bearing the same exhibit numbers) to the Partnership's Form 10-Q for the
  quarter ended June 30, 1995.
 
                       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 of this Form 10-K. 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 generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Dorchester Hugoton, Ltd. as of
December 31, 1995 and 1994, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 1995 in conformity
with generally accepted accounting principles.
 
                                            COOPERS & LYBRAND L.L.P.
Dallas, Texas
February 12, 1996
 
                                       19
<PAGE>   22
 
                            DORCHESTER HUGOTON, LTD.
                         (A TEXAS LIMITED PARTNERSHIP)
 
                             STATEMENTS OF EARNINGS
              FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
                             (DOLLARS IN THOUSANDS)
 
<TABLE>
<CAPTION>
                                                                    YEAR ENDED DECEMBER 31
                                                                -------------------------------
                                                                 1995        1994        1993
                                                                -------     -------     -------
<S>                                                             <C>         <C>         <C>
Operating revenues............................................  $13,027     $11,624     $14,454
                                                                -------     -------     -------
Costs and expenses:
  Operating...................................................    2,218       1,747       2,194
  Production and property taxes...............................      831         814       1,027
  Depreciation, depletion and amortization....................    1,362         810         764
  General and administrative:
     Tax and regulatory reporting.............................      166         137         218
     Depositary and transfer agent fees.......................       14          17          16
     Other....................................................      405         321         304
  Management fees.............................................      375         266         295
  Interest expense............................................      144          41          --
  Other expense (income)......................................      (80)       (128)        (51)
                                                                -------     -------     -------
          Total costs and expenses............................    5,435       4,025       4,767
                                                                -------     -------     -------
Net earnings..................................................  $ 7,592     $ 7,599     $ 9,687
                                                                =======     =======     =======
Net earnings per Unit.........................................      70c         70c         89c
                                                                =======     =======     =======
</TABLE>
 
                       See Notes to Financial Statements
 
                                       20
<PAGE>   23
 
                            DORCHESTER HUGOTON, LTD.
                         (A TEXAS LIMITED PARTNERSHIP)
 
                                 BALANCE SHEETS
                           DECEMBER 31, 1995 AND 1994
                             (DOLLARS IN THOUSANDS)
 
                                     ASSETS
 
<TABLE>
<CAPTION>
                                                                            1995        1994
                                                                           -------     -------
<S>                                                                        <C>         <C>
Current assets:
  Cash and temporary cash investments....................................  $   183     $    --
  Investments -- available for sale......................................    2,190       1,640
  Accounts receivable....................................................    3,197       3,141
  Prepaid expenses and other current assets..............................      136          88
                                                                           -------     -------
     Total current assets................................................    5,706       4,869
                                                                           -------     -------
Property and equipment -- at cost:
  Natural gas properties (full cost method)..............................   21,168      20,018
  Other..................................................................    1,072         978
                                                                           -------     -------
       Total.............................................................   22,240      20,996
Less accumulated depreciation, depletion and amortization:
  Full cost depletion....................................................    7,916       6,638
  Other..................................................................      429         366
                                                                           -------     -------
       Total.............................................................    8,345       7,004
                                                                           -------     -------
  Net property and equipment.............................................   13,895      13,992
                                                                           -------     -------
       Total assets......................................................  $19,601     $18,861
                                                                           =======     =======
                             LIABILITIES AND PARTNERSHIP CAPITAL
Current liabilities:
  Accounts payable.......................................................  $   776     $   626
  Current portion of long-term debt......................................       25          25
  Production and property taxes payable..................................      231         254
  Royalties payable......................................................      297         272
  Accrued liabilities -- other...........................................      200         200
  Distributions payable to unitholders...................................    1,848       1,865
                                                                           -------     -------
     Total current liabilities...........................................    3,377       3,242
Notes payable -- long-term...............................................    1,725       1,850
                                                                           -------     -------
     Total liabilities...................................................    5,102       5,092
                                                                           -------     -------
Commitments and contingencies (Note 3)...................................       --          --
Partnership capital:
  General partners.......................................................       68          61
  Unitholders............................................................   14,431      13,708
                                                                           -------     -------
     Total partnership capital...........................................   14,499      13,769
                                                                           -------     -------
       Total liabilities and partnership capital.........................  $19,601     $18,861
                                                                           =======     =======
</TABLE>
 
                       See Notes to Financial Statements
 
                                       21
<PAGE>   24
 
                            DORCHESTER HUGOTON, LTD.
                         (A TEXAS LIMITED PARTNERSHIP)
 
                  STATEMENTS OF CHANGES IN PARTNERSHIP CAPITAL
              FOR THE YEARS ENDED DECEMBER 31, 1993, 1994 AND 1995
                             (DOLLARS IN THOUSANDS)
 
<TABLE>
<CAPTION>
                                                               GENERAL
                                                               PARTNERS   UNITHOLDERS    TOTAL
                                                               --------   -----------   -------
<S>                                                            <C>        <C>           <C>
Year Ended December 31, 1993:
     Balance at December 31, 1992.............................   $ 29       $10,624     $10,653
  Net earnings................................................     97         9,590       9,687
                                                                 ----       -------     -------
  Distributions:
     Cash paid on April 16, July 16 and October 15, 1993
       (12c, 15c and 17c per Unit, respectively)..............    (48)       (4,727)     (4,775)
     Payable on January 15, 1994 to holders of record on
       December 31, 1993 (17c per Unit).......................    (18)       (1,827)     (1,845)
                                                                 ----       -------     -------
            Total distributions...............................    (66)       (6,554)     (6,620)
                                                                 ----       -------     -------
  Net unrealized holding loss on investments available for
     sale.....................................................     (1)          (69)        (70)
  Other.......................................................     --            (7)         (7)
                                                                 ----       -------     -------
     Balance at December 31, 1993.............................     59        13,584      13,643
                                                                 ----       -------     -------
Year Ended December 31, 1994:
  Net earnings................................................     76         7,523       7,599
                                                                 ----       -------     -------
  Distributions:
     Cash paid on April 15, July 15 and October 14, 1994
       (17c per Unit).........................................    (55)       (5,480)     (5,535)
     Payable on January 20, 1995 to holders of record on
       December 31, 1994 (17c per Unit).......................    (19)       (1,826)     (1,845)
                                                                 ----       -------     -------
            Total distributions...............................    (74)       (7,306)     (7,380)
                                                                 ----       -------     -------
  Net unrealized holding loss on investments available for
     sale.....................................................     (0)          (66)        (66)
  Other.......................................................     --           (27)        (27)
                                                                 ----       -------     -------
     Balance at December 31, 1994.............................     61        13,708      13,769
                                                                 ----       -------     -------
Year Ended December 31, 1995:
  Net earnings................................................     76         7,516       7,592
                                                                 ----       -------     -------
  Distributions:
     Cash paid on April 21, July 21 and October 20, 1995
       (17c per Unit).........................................    (55)       (5,480)     (5,535)
     Payable on January 19, 1996 to holders of record on
       December 31, 1995 (17c per Unit).......................    (19)       (1,826)     (1,845)
                                                                 ----       -------     -------
            Total distributions...............................    (74)       (7,306)     (7,380)
                                                                 ----       -------     -------
  Net unrealized holding gain on investments available for
     sale.....................................................      5           545         550
  Other.......................................................     --           (32)        (32)
                                                                 ----       -------     -------
     Balance at December 31, 1995.............................   $ 68       $14,431     $14,499
                                                                 ====       =======     =======
</TABLE>
 
                       See Notes to Financial Statements
 
                                       22
<PAGE>   25
 
                            DORCHESTER HUGOTON, LTD.
                         (A TEXAS LIMITED PARTNERSHIP)
 
                            STATEMENTS OF CASH FLOWS
               FOR THE YEARS ENDED DECEMBER 31, 1995, 1994, 1993
                             (DOLLARS IN THOUSANDS)
 
<TABLE>
<CAPTION>
                                                                 1995        1994        1993
                                                               --------     -------     -------
<S>                                                            <C>          <C>         <C>
Cash flows from operating activities:
  Net earnings...............................................  $  7,592     $ 7,599     $ 9,687
  Adjustments to reconcile net earnings to net cash provided
     by operating activities:
     Depreciation, depletion and amortization................     1,362         810         764
     Loss on sale of property and equipment..................        12          26          --
     Other...................................................       (32)        (27)         (8)
     Changes in current assets and liabilities:
       Accounts receivable...................................       (56)        271      (2,047)
       Prepaid expenses and other current assets.............       (49)         44          23
       Accounts payable, taxes and royalties payable.........       275         127         440
       Other accrued liabilities.............................        --        (100)        300
                                                               --------     -------     -------
Net cash provided by operating activities....................     9,104       8,750       9,159
                                                               --------     -------     -------
Cash flows from investing activities:
  Capital expenditures.......................................    (1,305)     (6,335)       (264)
  Purchase of available-for-sale securities..................        --          (3)     (1,774)
  Cash received on sale of property and equipment............        29          10          --
  Sale of other property.....................................        --          --          26
                                                               --------     -------     -------
Net cash used by investing activities........................    (1,276)     (6,328)     (2,012)
                                                               --------     -------     -------
Cash flows from financing activities:
  Proceeds from long-term borrowing..........................     9,200       1,875          --
  Loan payments..............................................    (9,325)         --          --
  Other......................................................      (123)        123          --
  Distributions paid to Unitholders..........................    (7,397)     (7,386)     (5,647)
                                                               --------     -------     -------
Net cash used by financing activities........................    (7,645)     (5,388)     (5,647)
                                                               --------     -------     -------
Increase (decrease) in cash and temporary cash investments...       183      (2,966)      1,500
Cash and temporary cash investments at beginning of year.....        --       2,966       1,466
                                                               --------     -------     -------
Cash and temporary cash investments at end of year...........  $    183     $    --     $ 2,966
                                                               ========     =======     =======
Supplemental cash flow and other information:
  Interest paid (no interest was capitalized)................  $    142     $    41     $    --
                                                               ========     =======     =======
  Distributions declared but not paid........................  $  1,848     $ 1,865     $ 1,871
                                                               ========     =======     =======
</TABLE>
 
                       See Notes to Financial Statements
 
                                       23
<PAGE>   26
 
                            DORCHESTER HUGOTON, LTD.
                         (A TEXAS LIMITED PARTNERSHIP)
 
                         NOTES TO FINANCIAL STATEMENTS
                        DECEMBER 31, 1995, 1994 AND 1993
 
1. GENERAL AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
     Formation of Partnership -- Dorchester Hugoton, Ltd. (the "Partnership")
was formed June 16, 1982, by Dorchester Gas Corporation ("Dorchester") which
conveyed to the Partnership 80 percent of its working interest in certain
natural gas properties effective June 1, 1982. The properties contributed by
Dorchester have been recorded by the Partnership at the allocated historical net
cost of the properties to Dorchester based on the estimated relative fair value
of the contributed properties to Dorchester's total oil and gas properties
located in the United States. Depositary receipts ("Depositary Receipts") for
units of limited partnership interest ("Units") in the Partnership were
distributed on August 20, 1982, to Dorchester stockholders of record as of July
2, 1982, in the form of a taxable dividend on the basis of one Unit for each 10
shares of Dorchester common stock held and to certain key employees (a total of
1,790,730 Units were distributed). In 1984, Dorchester, through a series of
transactions, became Dorchester Master Limited Partnership ("DMLP"), of which
Damson Oil Corporation ("Damson") was General Partner. In 1990-1992, Parker &
Parsley Petroleum Company or one of its subsidiaries purchased substantially all
of the assets of DMLP and Damson.
 
     Unit Splits -- Effective October 15, 1987, the Partnership made a
three-for-one (3-for-1) split of its Units. Depositary Receipts for the
additional Units were distributed on October 30, 1987, to record holders of
Depositary Receipts ("Unitholders") as of October 15, 1987, and increased to
5,372,190 the number of Units outstanding. Effective July 26, 1989, the
Partnership made a two-for-one (2-for-1) split of its Units. Depositary receipts
for the additional Units were distributed on August 5, 1989, and increased to
10,744,380 the number of Units outstanding. All per-Unit information has been
retroactively adjusted to give effect to the non-taxable splits.
 
     Basis of Presentation -- Per-Unit information is calculated by dividing the
Unitholders' 99% interest in the Partnership by the 10,744,380 Units
outstanding.
 
     Reclassification -- Certain amounts in the 1993 and 1994 financial
statements have been reclassified to conform with the 1995 presentation.
 
     Estimates -- The preparation of financial statements in conformity with
generally accepted accounting principles 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 Temporary Cash Investments -- Temporary cash investments, which
are primarily invested in short-term certificates of deposit, are carried at
cost, which approximates market. Investments with an original maturity of three
months or less are considered to be cash equivalents.
 
     Investments -- The Partnership's investments consist of 27,000 shares of
Exxon Corporation common stock purchased for $1,776,450 in 1993 and are
classified as available for sale. The Partnership has recognized an unrealized
holding gain on the increase in value of $550,125 in 1995 and an unrealized
holding loss on the temporary decline in value of $66,825 and $69,375 in 1994
and 1993, respectively. These declines have been treated as a separate component
of the Partnership's capital. At December 31, 1995 and 1994, the carrying value
of this stock, based on the quoted market price, was $2,190,375 and $1,640,250,
respectively.
 
     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 nonproduc-
 
                                       24
<PAGE>   27
 
                            DORCHESTER HUGOTON, LTD.
                         (A TEXAS LIMITED PARTNERSHIP)
 
                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
 
tive) are capitalized (not to exceed 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 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 $250,000 effective January 1, 1995 (previously
$150,000 effective January 1, 1991) plus 1% of the gross income from the
Partnership properties for services rendered in operating and managing the
Partnership. The General Partners are 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
present, the net balance owed the Partnership is approximately 62,000 MCF, down
from 110,000 MCF at December 31, 1994.
 
     Other Agreements -- Until May 1, 1994 the Partnership's Oklahoma natural
gas was sold under a 1946 Gas Purchase Contract with Natural Gas Pipeline
Company of America and assigns after processing pursuant to a June 16, 1982 Gas
Processing Agreement with a Parker & Parsley Petroleum Company entity (See Note
3).
 
     Operating Revenue -- Natural gas revenues are recognized as production and
sales take place (the "sales method"). The Partnership's purchasers who
individually accounted for more than 10% of natural gas revenues for each of the
years ended December 31, 1995, 1994 and 1993 are as follows:
 
<TABLE>
<CAPTION>
                                        PURCHASER    PURCHASER    PURCHASER    PURCHASER    PURCHASER
                                           "A"          "B"          "C"          "D"          "E"
                                        ---------    ---------    ---------    ---------    ---------
    <S>                                 <C>          <C>          <C>          <C>          <C>
    1995..............................                                             55%          36%
    1994..............................                   18%          28%          17%          20%
    1993..............................      74%          10%
</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 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. The tax basis of the
Partnership's assets and liabilities is greater than the amounts reported in the
financial statements by $1,059,814 and $2,353,026 as of December 31, 1995 and
1994, respectively.
 
                                       25
<PAGE>   28
 
                            DORCHESTER HUGOTON, LTD.
                         (A TEXAS LIMITED PARTNERSHIP)
 
                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
 
     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 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 -- The Partnership adopted a simplified
employee pension plan in 1983 (revised in 1985 and 1989) under which uniform
contributions aggregating $57,274, $44,257, and $38,402 were made to eligible
employees' accounts for 1995, 1994 and 1993, respectively. 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 1999.
 
     Concentration of Credit Risks -- The Partnership sells its natural gas to
gas purchasers in the United States and performs on-going credit evaluations of
its customers, requiring major corporate guarantees or letters of credit on a
regular basis. The Partnership has incurred minimal credit losses.
 
     The Partnership invests its excess cash in deposits with major financial
institutions with a typical maturity of less than one week and, therefore, bears
minimal risk of loss. The Partnership has not experienced any losses on its
money market investments.
 
     Environmental Costs -- Expenditures for environmental related activities
are expensed or capitalized in accordance with generally accepted accounting
principles. Liabilities for these expenditures are recorded when it is probable
that obligations have been incurred and the amounts can be reasonably estimated.
 
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"). The Credit Agreement currently has a borrowing base of $4,250,000,
which will be re-evaluated by the Bank at least semi-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 8.5% on December 31, 1995. All amounts borrowed under this facility become
due and payable on July 31, 1997. As of December 31, 1995, a letter of credit
totaling $242,000 was issued under the credit facility and the amount borrowed
was $1,700,000. 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
$2,800,000. The 1995 weighted average amount borrowed under the Credit Agreement
was $1,400,000.
 
     The Partnership purchased land in 1994 for its compression and dehydration
facility for $100,000, of which $75,000 is payable by contract at $25,000 per
year plus interest at 6% and is collateralized by
 
                                       26
<PAGE>   29
 
                            DORCHESTER HUGOTON, LTD.
                         (A TEXAS LIMITED PARTNERSHIP)
 
                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
 
the land. The Partnership also purchased land in January, 1996 adjacent to its
Kansas compressor facility for $93,600, of which $88,600 is payable by contract
at $22,150 per year plus interest at 8 1/2% and is collateralized by the land.
Both notes approximate market value.
 
3. LITIGATION AND OTHER
 
     Prior to May 1, 1994, the Partnership's Oklahoma natural gas production was
sold under the 1946 Gas Purchase Contract, as amended, (the "Contract") to
Natural Gas Pipeline Company of America or its assigns (collectively referred to
as "NGPL"). Such gas was also subject to a June 16, 1982 Gas Processing
Agreement (the "Agreement") between the Partnership and Parker & Parsley
Petroleum Company entities (successor to Damson Oil Corporation and Dorchester
Master Limited Partnership) (collectively referred to as "P&P" or as "Parker &
Parsley"). As a result, the Partnership's Oklahoma gas production was processed
in P&P's Hooker, Oklahoma gas processing plant where natural gas liquids were
extracted and the remaining gas ("residue gas") was delivered and sold to NGPL
at the plant outlet. The extraction of natural gas liquids requires the
consumption of some gas as fuel and the extraction itself shrinks the gas
production in both volume and heating value (referred to as "fuel and
shrinkage"). The Agreement provided, among other things, that P&P operate the
Partnership's gas gathering pipelines, that P&P retain the natural gas liquids
extracted, and that the Partnership would receive for fuel and shrinkage
incurred the value of the gas produced at the wellhead (including severance
taxes) less amounts received for residue gas sales to NGPL. The Agreement
terminated upon termination of the Partnership's Contract with NGPL on May 1,
1994.
 
     On May 1, 1990, the Partnership instituted legal action in Wharton County,
Texas District Court against NGPL seeking cancellation of the Contract and
damages. In early December, 1992, the Partnership settled its litigation against
NGPL and amended the Contract. The amended Contract provided that NGPL would pay
for the residue gas from the Partnership's Oklahoma properties at an indexed
market price. The Contract was subsequently terminated by NGPL effective May 1,
1994. The processor of the Partnership's Oklahoma gas, P&P, previously
intervened in the litigation in Wharton County, Texas claiming certain rights
under the Contract, the Agreement and to the Partnership's gas gathering
pipeline system in Oklahoma.
 
     In 1986, pursuant to a preferential right to purchase in an August 23, 1982
Operating Agreement between the Partnership and a predecessor to P&P, the
Partnership acquired additional interests in Texas County, Oklahoma (the "1986
Transaction"). On November 2, 1993, the Oklahoma Court of Appeals affirmed the
decision of the Texas County, Oklahoma District Court granting the Partnership
quiet title to all personal and real property interests acquired by the
Partnership in the 1986 Transaction, including a 20% interest in the Texas
County, Oklahoma leases and all of the gas pipeline gathering system. P&P
continues to attempt to dispute the impact of that decision. Additionally, on
April 20, 1994 the Partnership was granted an injunction by the Texas County,
Oklahoma District Court to enjoin P&P from interfering with the Partnership's
May 1, 1994 operation of low pressure gas pipeline gathering facilities. At
present, P&P has filed an appeal seeking reversal of the District Court's
injunction rulings. Also on November 2, 1993, the Court of Appeals remanded, for
a new trial, a 1990 jury finding of fraud which had awarded the Partnership
$4,715,326 related to the 1986 Transaction. The Oklahoma Supreme Court granted
certiorari on March 21, 1994. On June 19, 1995, the Oklahoma Supreme Court
withdrew and denied certiorari. Consequently, the sole issue of fraud by P&P
will be retried in Texas County, Oklahoma. No retrial date has been set.
Additionally, on January 10, 1994 the Oklahoma Court of Appeals decision became
final which had reversed a judgment awarding the Partnership $724,082 based on
P&P's underpayment for fuel and shrinkage at the Hooker gas processing plant
during the period of November 1988 through March 1991. Subsequently, P&P was
awarded and received $91,402 in attorney's fees from the Partnership. None of
the Court of Appeals'
 
                                       27
<PAGE>   30
 
                            DORCHESTER HUGOTON, LTD.
                         (A TEXAS LIMITED PARTNERSHIP)
 
                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
 
decisions are expected to have any material adverse affect on the Partnership's
financial position or operating results. The Partnership has not recognized any
of the prior judgment amounts in its favor in its financial statements.
 
     On December 22, 1993 the Texas County, Oklahoma District Court issued a
partial summary judgment with respect to disputed matters between the
Partnership and P&P regarding gathering and processing the Partnership's
Oklahoma gas and the Agreement. The partial summary judgment ruled that (1) the
Partnership owns the Oklahoma gas pipeline gathering system, (2) there are no
processing rights other than the Agreement, whereby P&P gathers and processes
the Partnership's Oklahoma gas, (3) the Agreement was still in effect, and (4)
payments for fuel and shrinkage under the Agreement are to be based upon the
same price per MMBTU as paid the Partnership for its Oklahoma gas sales plus
applicable taxes. On May 1, 1994 the Agreement terminated concurrently with the
termination of the Partnership's 1946 Gas Purchase Contract with NGPL. On August
26, 1994, P&P and the Partnership stipulated by agreement that (among other
issues) the amount of underpayment due the Partnership for fuel and shrinkage
during the period January 1993 through April 1994 to be either $4,837,046 or
$6,558,036 depending upon the Court's determination of proper severance tax
applicability. A hearing including these issues was conducted October 18, 1994.
On September 21, 1995 the Texas County, Oklahoma District Court issued its Final
Judgment and Order favorably awarding the Partnership $6,588,036 plus interest
for underpayment by P&P for fuel and shrinkage. The Court's ruling also made
final the previous decisions that the Partnership owns the Oklahoma gas pipeline
gathering system and P&P had no rights to process the gas after the May 1, 1994
expiration of the Agreement. On October 6, 1995 P&P filed a supersedeas bond. On
October 13, 1995 P&P filed an appeal contesting all of the District Court's
findings and P&P seeks to reduce or eliminate the supersedeas bond. On December
13, 1995 the Texas County, Oklahoma District Court denied Parker & Parsley's
motion to reduce or eliminate the supersedeas bond and awarded the Partnership
$110,446 in attorneys' fees and expenses. The Partnership anticipates that
Parker & Parsley will appeal all December 13, 1995 decisions. The Partnership
has not recognized any of the prior judgment amounts in its favor in its
financial statements.
 
     Through January 25, 1994, the Wharton County, Texas District Court ruled
that (1) P&P is not liable to the Partnership for excess extraction of natural
gas liquids prior to January 1, 1993 (2) the 1982 Gas Processing Agreement
expired on January 1, 1993, and (3) P&P is not a party to the Partnership's
contract covering Oklahoma gas sales. Issues of ownership of the gas pipeline
gathering system and any gas processing rights (other than the Agreement) in
Oklahoma were dismissed for various reasons including lack of subject matter
jurisdiction. All other remaining issues were dismissed and attorney's fees in
the amount of $208,000 were awarded to P&P. Both the Partnership and P&P
appealed portions of the Court's decisions and the Partnership has provided a
supersedeas bond in the amount of $242,000 related to attorneys fees with
prospective interest. On October 5, 1995 and again in early 1996 the Thirteenth
Court of Appeals in Corpus Christi, Texas issued an opinion which remanded to
the Wharton County District Court for further proceedings the issues of (1)
ownership of the gas pipeline gathering system and (2) ownership of rights to
process the gas produced by the Partnership's Oklahoma gas wells. Additionally,
the Appellate Court affirmed the Wharton District Court's decision terminating
on January 1, 1993, the 1982 Gas Processing Agreement whereby the Partnership's
Oklahoma gas was processed in the P&P Hooker Oklahoma Plant until May 1, 1994.
Also, the Court affirmed the Wharton County District Court's decision that
Parker & Parsley was not liable to the Partnership for previous overextraction
at the Hooker Oklahoma Plant. The Court also affirmed, but slightly reduced, the
trial court's award of attorney's fees of $200,000 to P&P. The Partnership has
begun seeking further appellate court review.
 
                                       28
<PAGE>   31
 
                            DORCHESTER HUGOTON, LTD.
                         (A TEXAS LIMITED PARTNERSHIP)
 
                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
 
     On May 11, 1994 the Partnership instituted legal action in Texas County,
Oklahoma District Court against P&P for breach of the preferential right to
purchase clause in an August 23, 1982 Operating Agreement between the
Partnership and a predecessor to P&P. A production payment and a right to
participate in new wells were reserved by P&P predecessors in their June, 1986
sale of interests in Texas County, Oklahoma properties to the Partnership. The
Partnership is contesting conveyances made between P&P's predecessors (Damson
and Dorchester Master Limited Partnership) and P&P with respect to the
production payment and participation right. The Partnership is requesting such
production payment and participation right be subject to specific performance
enabling exercise of the Partnership's rights under the preferential right to
purchase. Generally the right to participate in new wells is limited to a
maximum working interest of 5%. At present, the Partnership believes no wells
have been drilled which would be subject to such participation. The Partnership
believes it is reasonably possible that the partnership will prevail. A
production payment may be owed to P&P if the Partnership is unsuccessful.
However, the exact amount of any such payment that might be due is not currently
known. As of March 1, 1994, the amount that could be owed might range between
$600,000 to $1,000,000. Although not calculable, an estimated additional range
of $900,000 to $1,300,000 could be owed for the period from March 1, 1994
through February 29, 1996. Future projections of any production payment amount
utilize annual calculations through February based on a table of declining
volumes and the amount that unknown future gas prices exceed a table of rising
prices. P&P has asserted the production payment amount owed to be $1,394,505
through February 28, 1994. Should the Partnership successfully maintain the
right to purchase, the determination of whether to purchase would depend upon
the purchase price, which is unknown.
 
     On May 19, 1994 P&P instituted legal action in the 116th Judicial District
of Dallas County, Texas asserting that Dorchester Hugoton owed and had not paid
a production payment, had improperly failed to allow P&P to participate in the
1993 drilling of a replacement well in Texas County, Oklahoma and asserting
other claims of tortious interference and unfair competition, apparently by
virtue of the Partnership's operation of its low pressure gas pipeline. On July
11, 1994 the Dallas County District Court denied the Partnership's motion to
stay or abate due to identical claims in Oklahoma. On March 28, 1995, a motion
by P&P for partial summary judgment was denied by the Dallas court. By agreement
with P&P all litigation in the Dallas County, Texas suit has been deferred until
completion of all identical litigation in Texas County, Oklahoma. In Oklahoma,
the trial regarding the Partnership's right to exercise the preferential right
to purchase both the production payment and right to participate in new wells
awaits rescheduling by the Court. All other matters, such as the amount to be
paid in exercising the preferential right or the amount of a production payment,
if any, are delayed until issuance of a ruling following the pending Oklahoma
trial.
 
     Pursuant to requirements of the Dallas, Texas District Court, the
Partnership and P&P attempted settlement by mediation during August, 1995. On
August 21, 1995 the independent mediator declared an impasse.
 
     On December 20, 1995 the Partnership began legal action in the Texas
County, Oklahoma District Court seeking to quiet the Partnership's title and
seeking a declaratory order that Parker & Parsley has no participation rights
regarding an Oklahoma replacement well completed by the Partnership in January,
1996. Such action was necessary as P&P has continued to assert that it had the
right to participate to the extent of 5% in a similar Oklahoma replacement well
completed by the Partnership in 1993. The parties have agreed to abate this
proceeding pending resolution of the same issues regarding the 1993 replacement
well.
 
                                       29
<PAGE>   32
 
                            DORCHESTER HUGOTON, LTD.
                         (A TEXAS LIMITED PARTNERSHIP)
 
                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
 
4. 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 Engineering, 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. As discussed previously in this Annual Report under
Business and Properties of the Partnership, proved developed natural gas
reserves for the year beginning January 1, 1995 were revised to be more
comparable to reserves of others in the same field. This effect is shown in the
tabulation below as 1995 revisions. The Partnership has no known reserves of
crude oil. There have been no events that have occurred since December 31, 1995
that would have a material effect on the proved developed natural gas reserves.
The estimated net quantities of proved natural gas reserves (all of which were
from developed properties located within the United States) at December 31,
1995, 1994 and 1993 and the changes for the years then ended were as follows:
 
<TABLE>
<CAPTION>
                                                                   NATURAL GAS (MMCF)
                                                              -----------------------------
                                                               1995       1994       1993
                                                              ------     ------     -------
    <S>                                                       <C>        <C>        <C>
    Estimated quantity, beginning of year...................  83,989     96,246     108,125
    Revisions in previous estimates.........................  15,701     (5,226)     (3,378)
    Production..............................................  (8,765)    (7,031)     (8,501)
                                                              ------     ------     -------
    Estimated quantity, end of year.........................  90,925     83,989      96,246
                                                              ======     ======     =======
    Development costs incurred (in thousands of dollars)....  $1,149     $5,857     $   167
                                                              ======     ======     =======
</TABLE>
 
     The standardized measure of discounted future net cash flows related to
proved natural gas reserves at December 31, 1995, 1994 and 1993 (in thousands of
dollars) follows:
 
<TABLE>
<CAPTION>
                                                             1995        1994        1993
                                                           --------    --------    --------
    <S>                                                    <C>         <C>         <C>
    Future estimated gross revenues....................... $173,699    $127,658    $162,931
    Future estimated production and development costs.....   57,064      40,972      36,647
                                                           --------    --------    --------
    Future estimated net revenues.........................  116,635      86,686     126,284
    Future estimated net revenues 10% annual discount for
      estimated timing of cash flows......................  (47,051)    (33,565)    (55,269)
                                                           --------    --------    --------
    Standardized measure of discounted future estimated
      net revenues........................................ $ 69,584    $ 53,121    $ 71,015
                                                           ========    ========    ========
    Sales of natural gas produced, net of production
      costs............................................... $ (9,851)   $ (9,057)   $(11,233)
    Net changes in prices and production costs............   12,914     (11,516)      7,026
    Revisions of previous quantity estimates..............    8,367      (3,349)      1,306
    Accretion of discount.................................    4,881       6,551       6,226
    Other.................................................      152        (523)        241
                                                           --------    --------    --------
    Net change in standardized measure of discounted
      future estimated net revenues....................... $ 16,463    $(17,894)   $  3,566
                                                           ========    ========    ========
</TABLE>
 
     Future estimated gross revenues are based on existing year-end contractual
prices. Price increases, including those based upon inflation, have not been
considered. Operating costs, production taxes and future development costs are
based on current costs with no escalation. Care should be exercised in
 
                                       30
<PAGE>   33
 
                            DORCHESTER HUGOTON, LTD.
                         (A TEXAS LIMITED PARTNERSHIP)
 
                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
 
using the above information as a forecast of future economic conditions or
revenues. Reserve estimates and projections of future revenues and expenses are
inherently imprecise and the use of prices and costs in effect at year-end and
of a ten percent discount rate are necessarily arbitrary bases.
 
5. UNAUDITED QUARTERLY FINANCIAL DATA
 
     Quarterly financial data for the last two years (dollars in thousands) is
summarized as follows:
 
<TABLE>
<CAPTION>
                                             1995 QUARTER ENDED                  1994 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>
Revenues.............................  $3,311  $ 2,974  $2,909  $3,833    $3,665   $ 2,601  $2,168  $3,190
Net earnings.........................   1,890    1,613   1,608   2,481     2,627     1,746   1,337   1,889
Net earnings per Unit................     17c      15c     15c     23c       24c       16c     12c     18c
</TABLE>
 
                                       31
<PAGE>   34
 
                                   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 19, 1996                         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 19, 1996
  ---------------------------------
          Preston A. Peak
    President and Sole Director

JAMES E. RALEY, INC.

By    /s/  JAMES E. RALEY               General Partner                February 19, 1996
  ---------------------------------
           James E. Raley
    President and Sole Director
</TABLE>
 
                                       32
<PAGE>   35
 
                               INDEX TO EXHIBITS
 
<TABLE>
<CAPTION>
                                                                                    SEQUENTIALLY
  EXHIBIT                                                                            NUMBERED
  NUMBER                                  DESCRIPTION                                  PAGES
-----------------------------------------------------------------------------------------------
<S>        <C>                                                                      <C>
      3.   -- Amended and Restated Certificate and Agreement of Limited Partnership,
              as amended*
      4.1  -- Depositary Agreement, as amended*
      4.2  -- Specimen Depositary Receipt
      4.3  -- Nominee Agreement among the Partnership, Dorchester and Nominee
     27.   -- Financial Data Schedule
</TABLE>
 
---------------
 
* Previously filed and incorporated by reference to the respective Exhibits
  (bearing the same exhibit numbers) to the Partnership's Form 10-Q for the
  quarter ended June 30, 1995.
 
                                       33