<PAGE>   1
 
================================================================================
 
                UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549
 
                                   FORM 10-K
 
     [X]         ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934
 
                  FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996
 
                                       OR
 
     [ ]       TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
                    OF THE SECURITIES EXCHANGE ACT OF 1934.
 
                         FOR THE TRANSITION PERIOD FROM
                                ------------ TO
                                  ------------
 
                         COMMISSION FILE NUMBER 0-23166
 
            [ LOGO]       HUGOTON ENERGY CORPORATION
             (Exact name of registrant as specified in its charter)
 
<TABLE>
<S>                                            <C>
                    KANSAS                                       48-1036256
         (State or other jurisdiction                         (I.R.S. Employer
      of incorporation or organization)                     Identification No.)
 
           301 N. MAIN, SUITE 1900,
               WICHITA, KANSAS                                     67202
   (Address of principal executive offices)                      (Zip Code)
</TABLE>
 
       Registrant's telephone number, including area code (316) 262-1522
 
          SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
 
<TABLE>
<CAPTION>
                                                           NAME OF EACH EXCHANGE
             TITLE OF EACH CLASS                            ON WHICH REGISTERED
             -------------------                           ---------------------
<C>                                            <C>
                     None                                           None
</TABLE>
 
          SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
 
                           COMMON STOCK, NO PAR VALUE
                                (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     [ ]
 
     As of February 1, 1997, Registrant had outstanding 19,753,911 shares of
Common Stock. The aggregate market value of the voting stock held by
non-affiliates of the Registrant, based upon the closing sale price of the
Common Stock on February 1, 1997 as reported on the NASDAQ National Market, was
approximately $49,925,000.
 
                      DOCUMENTS INCORPORATED BY REFERENCE
 
  Notice of Annual Meeting of Shareholders and Proxy Statement Dated April 10,
1997 (in Part III)
 
================================================================================
<PAGE>   2
 
                               TABLE OF CONTENTS
 
<TABLE>
<CAPTION>
                                                                           PAGE
                                                                           ----
<S>       <C>                                                           <C>
                                      PART I
Item 1.   Business....................................................           3
Item 2.   Properties..................................................          13
Item 3.   Legal Proceedings...........................................          14
Item 4.   Submission of Matters to a Vote of Security Holders.........          14
                                     PART II
Item 5.   Market for Registrant's Common Stock and Related Shareholder
          Matters.....................................................          14
Item 6.   Selected Financial Data.....................................          15
Item 7.   Management's Discussion and Analysis of Financial Condition
          and Results of Operations...................................          16
Item 8.   Consolidated Financial Statements and Supplementary Data....          20
Item 9.   Changes in and Disagreements with Accountants on Accounting
          and Financial Disclosure....................................          21
                                     PART III
Item 10.  Directors and Executive Officers of the Company.............          21
Item 11.  Executive Compensation......................................          21
Item 12.  Security Ownership of Certain Beneficial Owners and
          Management..................................................          21
Item 13.  Certain Relationships and Related Transactions..............          21
                                     PART IV
Item 14.  Exhibits, Financial Statement Schedules, and Reports on Form
          8-K.........................................................          21
Signatures............................................................          24
Financial Information.................................................  Appendix A
</TABLE>
 
                                        2
<PAGE>   3
 
                                     PART I
ITEM 1. BUSINESS
 
OVERVIEW
 
     Hugoton Energy Corporation (the "Company") is a rapidly growing independent
oil and natural gas company engaged in the exploration for and the development,
exploitation, production and acquisition of oil and natural gas reserves and
properties. The Company has historically been one of the most active independent
operators in the Hugoton Field and has expanded its operations throughout the
Mid-Continent area in Kansas, Oklahoma and Texas, and into the Permian Basin in
West Texas and New Mexico, the Austin Chalk Trend of Texas and Louisiana and the
Williston Basin in Montana and North Dakota. The Company intends to expand its
reserve base by continuing its drilling and acquisition activities primarily in
its four core areas. The Company focuses on exploring and developing properties
that it believes possess significant upside potential, which can be realized
through the application of 3-D seismic technology and traditional geologic
studies, as well as advanced drilling and completion techniques.
 
     The Company has increased its proved reserves from 22 Bcfe at December 31,
1991 to 322 Bcfe at December 31, 1996. The proved reserves are 70% natural gas
and are 77% proved developed producing, with a reserve-to-production ratio of 11
years, based on 1996 production. The Company operates 1,625 wells, representing
87% of its reserves. During the five years ended December 31, 1996, the Company
added proved reserves equal to 500% of production at an average cost of $.66 per
Mcfe. The Company's average net daily production has increased from 2.6 MMcfe
during 1991 to 79.8 MMcfe during 1996.
 
     The Company's rapid growth is a result of its aggressive drilling and
acquisition programs. During the last five years, the Company has drilled a
total of 242 wells and completed 176 of them for a success ratio of 73%. This
drilling program has added approximately 106 Bcfe of proved reserves, or 141% of
production, at an average cost of $.37 per Mcfe.
 
     During the five year period ended December 31, 1996, the Company's
acquisitions added over 270 Bcfe to proved reserves, or 359% of production, at
an average cost of $.78 per Mcfe. The Company focuses on potential acquisitions
within its core areas, but also considers selected opportunities in new areas.
The Company's strategy is to acquire producing properties with operational
control in oil and natural gas basins that offer significant exploitation,
development and exploratory prospects. The Company's most significant
acquisitions have been the purchase of the limited partnership interests in two
oil and natural gas partnerships owned by The Prudential Insurance Company of
America ("Prudential") in 1993 and the purchase of Consolidated Oil & Gas, Inc.
("COG") in 1995.
 
     The Company has accumulated an acreage position of approximately 567,000
net acres, including 165,000 net acres that were added during 1996. These
acreage holdings are located in the Company's four core areas and have
exploration and development opportunities with multiple pay horizons. The
Company believes that it has sufficient drilling prospects in its acreage
inventory to allow it to continue its drilling program through 1999, and it
intends to continue to add acreage to its holdings. The Company's 1997 capital
budget is $75 million, an increase of 63% over 1996 capital expenditures, and
includes $50 million for the drilling of approximately 200 wells, $10 million
for 3-D seismic and land costs and $15 million for small strategic acquisitions.
In its 1997 drilling budget, the Company has assembled prospects with a wide
range of risk profiles, with approximately 60% of the budget to be spent for
relatively lower risk development drilling, and approximately 40% for
exploratory drilling. The drilling budget will be expended 30% in the Hugoton
Producing Area and other fields in the Mid-Continent areas, 30% in the Permian
Basin, 20% in the Austin Chalk Trend, and 20% in the Williston Basin.
 
     The Company is incorporated in the State of Kansas, its principal executive
offices are located at 301 North Main, Suite 1900, Wichita, Kansas 67202 and its
telephone number is (316) 262-1522.
 
DRILLING
 
     The Company continues to aggressively develop and explore its extensive
leasehold position and plans to drill approximately 200 wells during 1997.
 
                                        3
<PAGE>   4
 
     Infill and Development Drilling. The Company has drilled 93 infill and
development wells during the last five years and achieved a success rate of 88%.
The Company seeks to acquire properties that contain additional infill and
development potential. These properties generally contain producing wells with
multiple pay horizons that have not been fully developed.
 
     Field Extension and Exploratory Drilling. The Company has drilled 149 field
extension and exploratory wells during the last five years and achieved a
success rate of 63%. The Company continues to extend the limits of its producing
fields as well as those owned by or acquired from others. In addition, the
Company is involved in numerous exploration projects, including various 3-D
seismic and horizontal drilling projects.
 
     The following table sets forth the wells drilled by the Company during the
periods indicated:
 
<TABLE>
<CAPTION>
                                                     YEARS ENDED DECEMBER 31,
                                          -----------------------------------------------
                                              1996             1995             1994
                                          -------------    -------------    -------------
                                          GROSS    NET     GROSS    NET     GROSS    NET
                                          -----    ----    -----    ----    -----    ----
<S>                                       <C>      <C>     <C>      <C>     <C>      <C>
Infill and Development:
  Productive............................  30.0     23.9     5.0      2.3    22.0     21.0
  Non-Productive........................   1.0      0.1     4.0      3.0     2.0      1.3
                                          ----     ----    ----     ----    ----     ----
          Total.........................  31.0     24.0     9.0      5.3    24.0     22.3
                                          ====     ====    ====     ====    ====     ====
Field Extension and Exploratory:
  Productive............................  28.0     12.2    23.0     14.4    26.0     20.0
  Non-Productive........................   8.0      5.8     7.0      5.8    28.0     21.0
                                          ----     ----    ----     ----    ----     ----
          Total.........................  36.0     18.0    30.0     20.2    54.0     41.0
                                          ====     ====    ====     ====    ====     ====
Total:
  Productive............................  58.0     36.1    28.0     16.7    48.0     41.0
  Non-Productive........................   9.0      5.9    11.0      8.8    30.0     22.3
                                          ----     ----    ----     ----    ----     ----
          Total.........................  67.0     42.0    39.0     25.5    78.0     63.3
                                          ====     ====    ====     ====    ====     ====
</TABLE>
 
     As of December 31, 1996, the Company had a working interest in 939 gross
(446 net) natural gas wells and 1,320 gross (1,064 net) oil wells. At February
15, 1997, the Company was participating in the drilling of 5 wells.
 
GAS GATHERING AND PROCESSING
 
     The Company owns and operates the Kinsler gas gathering system and
processing plant in Morton County, Kansas. The gathering system consists of more
than 30 miles of pipelines and currently serves 28 wells, of which 24 are
operated by the Company. The gathering system has a throughput capacity of
approximately 10 MMcf per day. During the year ended December 31, 1996, the
system gathered an average of 4.1 MMcf per day of natural gas.
 
     The processing plant is currently processing 2.3 MMcf per day and during
the year ended December 31, 1996, the plant recovered an average of 9,000
gallons of NGLs per day. All gas delivered to the system is purchased by the
Company at the wellhead at prices related to the Panhandle Eastern Pipe Line
monthly index. All NGLs are trucked to the Jayhawk NGL pipeline and delivered to
a Warren NGL, Inc. fractionation plant where they are sold at monthly average
spot market prices. In August of 1996, the Company modified its downstream
transportation arrangements and now all residue gas available after processing
is delivered to PanEnergy Field Services and is marketed on the Panhandle
Eastern Pipe Line system at spot market prices.
 
                                        4
<PAGE>   5
 
ACREAGE
 
     The table below describes the Company's developed and undeveloped leasehold
acreage as of December 31, 1996. A substantial portion of the developed
leasehold acreage is developed above 3,500 feet, but is undeveloped below 3,500
feet.
 
<TABLE>
<CAPTION>
                            UNDEVELOPED ACREAGE   DEVELOPED ACREAGE      TOTAL ACREAGE
                            -------------------   -----------------   -------------------
                             GROSS       NET       GROSS      NET       GROSS       NET
                            --------   --------   -------   -------   ---------   -------
<S>                         <C>        <C>        <C>       <C>       <C>         <C>
Hugoton/Mid-Continent.....   221,754    112,984   311,070   219,792     532,824   332,776
Permian Basin.............    19,616      4,208    44,074    34,712      63,690    38,920
Austin Chalk..............   149,583     68,136    12,147     3,339     161,730    71,475
Williston Basin...........   265,810    111,240    49,778    13,009     315,588   124,249
                             -------    -------   -------   -------   ---------   -------
          Total...........   656,763    296,568   417,069   270,852   1,073,832   567,420
                             =======    =======   =======   =======   =========   =======
</TABLE>
 
     No possible or probable reserves have been assigned to the Company's
undeveloped acreage. As is customary in the oil and gas industry, the Company
can retain its interests in undeveloped acreage by drilling activity which
establishes commercial production sufficient to maintain the leases, or by
payment of delay rentals during the remaining primary term of such a lease. The
Company paid $0.2 million in delay rentals for 1996 and projects an expense of
approximately $1.7 million for 1997. The oil and natural gas leases in which the
Company has an interest are for varying primary terms.
 
     In addition to the developed and undeveloped acreage indicated, the Company
is engaged in numerous farmout agreements with other owners of oil and natural
gas leases and is actively leasing additional acreage. A farmout agreement is a
customary industry agreement which provides that the assignee drill an
exploratory well or wells on the farmout properties, and if the well is
completed as a commercial producer of oil and/or natural gas, the assignee earns
an assignment of some or all of the assignor's natural gas and oil lease
interests.
 
     As of December 31, 1996, the Company is an assignee in various farmout
agreements. Rights to earn the interest in the farmout acreage can be
surrendered by the Company at any time by giving notice to an assignor, or they
can be lost through nonperformance by the Company.
 
OIL AND NATURAL GAS RESERVES
 
     The following table summarizes the estimates of the Company's proved
producing, proved non-producing and proved undeveloped reserves as of December
31, 1996, and the discounted present value attributable to the Company's
estimated proved reserves at such date, as estimated by independent petroleum
engineers, Ryder Scott Company.
 
<TABLE>
<CAPTION>
                                                          PROVED RESERVES
                                         --------------------------------------------------
                                         PRODUCING   NON-PRODUCING   UNDEVELOPED    TOTAL
                                         ---------   -------------   -----------   --------
<S>                                      <C>         <C>             <C>           <C>
Natural gas (MMcf).....................   180,610         9,217         35,354      225,181
Oil and NGLs (MBbls)...................    11,200           868          4,110       16,178
Natural gas equivalents (MMcfe)........   247,810        14,425         60,014      322,249
Present value of estimated future net
  revenues before income taxes
  (discounted at 10%) (in
  thousands)(1)........................  $345,544       $25,124        $93,772     $464,440
</TABLE>
 
---------------
 
(1) The present value of estimated future net revenues before income taxes
    determined in accordance with Commission regulations (discounted at 10%) as
    of December 31, 1996 was determined using the weighted average sales prices
    of $3.79 per Mcf of natural gas and $24.53 per Bbl of oil.
 
     These estimates of the Company's proved reserves have not been filed with
or included in reports to any federal agency.
 
                                        5
<PAGE>   6
 
     In accordance with applicable requirements of the Securities and Exchange
Commission (the "Commission"), estimates of the Company's proved reserves and
future net revenues are made using oil and natural gas sales prices estimated to
be in effect as of the date of such reserve estimates and are held constant
throughout the life of the properties (except to the extent a contract
specifically provides for escalation). Estimated quantities of proved reserves
and future net revenues therefrom are affected by oil and natural gas prices,
which have fluctuated widely in recent years. There are numerous uncertainties
inherent in estimating oil and natural gas reserves and their estimated values,
including many factors beyond the control of the producer. The reserve data set
forth in this document represents only estimates. Reserve engineering is a
subjective process of estimating underground accumulations of oil and natural
gas that cannot be measured in an exact manner. The accuracy of any reserve
estimate is a function of the quality of available data and engineering and
geological interpretation and judgment. As a result, estimates of different
engineers may vary. In addition, estimates of reserves are subject to revision
based upon actual production, results of future development and exploration
activities, prevailing oil and natural gas prices, operating costs and other
factors, of which revisions may be material. Accordingly, reserve estimates are
often different from the quantities of oil and natural gas that are ultimately
recovered. The meaningfulness of such estimates is highly dependent upon the
accuracy of the assumptions upon which they are based.
 
     The volume of production from oil and natural gas properties declines as
reserves are depleted. Except to the extent the Company acquires properties
containing proved reserves or conducts successful exploration and development
activities, or both the proved reserves of the Company will decline as reserves
are produced. The Company's future oil and natural gas production is therefore
highly dependent upon its level of success in finding or acquiring additional
reserves.
 
PRODUCTION
 
     The following table sets forth the Company's oil and natural gas production
data during the periods indicated:
 
<TABLE>
<CAPTION>
                                                             YEARS ENDED DECEMBER 31,
                                                             ------------------------
                                                              1996     1995     1994
                                                             ------   ------   ------
<S>                                                          <C>      <C>      <C>
Net Production(1):
  Natural gas (MMcf).......................................  19,026   14,651   12,491
  Oil (MBbls)..............................................   1,700    1,018      369
  Natural gas equivalents (MMcfe)..........................  29,226   20,759   14,705
Average Net Daily Production(1):
  Natural gas (Mcf)........................................  51,983   40,139   34,223
  Oil (Bbls)...............................................   4,644    2,789    1,012
  Natural gas equivalents (Mcfe)...........................  79,847   56,873   40,295
Average Sales Price(2):
  Natural Gas ($/Mcf)......................................  $ 1.87   $ 1.30   $ 1.44
  Oil ($/Bbl)..............................................   18.03    16.37    15.31
  Natural gas equivalents ($/Mcfe).........................    2.27     1.72     1.61
Other Data:
  Production costs ($/Mcfe)(3).............................  $ 0.74   $ 0.56   $ 0.51
  Depreciation, depletion and amortization ($/Mcfe)(4).....    0.76     0.68     0.54
</TABLE>
 
---------------
 
(1) Net production and average net daily production excludes NGLs and natural
    gas purchased by AmGas Corporation and resold to third parties.
 
(2) Includes the effect of hedging transactions. Average prices received from
    sales of natural gas include revenues attributable to NGLs as the Company
    has not historically accounted separately for production or revenues
    attributable to NGLs.
 
(3) Consists of lease operating expenses, production and severance taxes and
    gathering, transportation and other production expenses.
 
(4) Excludes depreciation, depletion and amortization not related to oil and gas
    properties.
 
                                        6
<PAGE>   7
 
MARKETING
 
     Approximately 90% of the Company's natural gas production is sold at index
related, spot-market prices. The balance of the Company's gas is sold under
longer term contracts at percentage-of-proceeds or fixed prices.
 
     Most of the Company's spot market gas is sold to Cibola Energy Services
Corporation ("Cibola"), a wholly-owned subsidiary of TransCanada Pipelines, Ltd.
Under a marketing agreement, Cibola has marketing rights to all of the Company's
undedicated gas production. The agreement mitigates the Company's exposure to
pipeline imbalance penalties and enables the Company to take advantage of the
size, diverse markets and trading expertise of Cibola, while still maintaining
market control. This arrangement increases the Company's access to premium gas
markets and enhances its pricing options. In addition, Cibola assists the
Company in such areas as nominations, scheduling and solicitation of gathering
and transportation discounts. This symbiotic relationship provides the benefits
of an in-house marketing company, without the overhead expense. The agreement
may be canceled by either party upon sixty (60) days notice.
 
     Natural Gas Liquids. The Company's natural gas liquids produced from its
processing plant are sold at market prices (see "Gas Gathering and Processing").
The Company's natural gas liquids extracted by third party processors are
generally sold under percentage of proceeds contracts.
 
     Hedging Activities. The Company utilizes commodity swap agreements in an
attempt to reduce its exposure to commodity price movements. At December 31,
1996, the Company had entered into swap agreements fixing the price of 70,000
Bbls per month, for the first three months of its oil production for 1997 at a
weighted average price of $24.25 per Bbl. In addition, the Company had entered
into forward sales contracts for 20 MMcf per day of natural gas for the first
three months of 1997 at a net price of $3.68 per Mcf.
 
     Customers. During 1996, Cibola and GPM Gas Corporation each purchased in
excess of 10% of the oil and natural gas sold by the Company (29% in the
aggregate). The Company entered into an exclusive marketing agreement with
Cibola during 1995. The agreement allows either party to terminate the agreement
upon 60 days notice if they are dissatisfied with the results. The Company
benefits from a long-standing business relationship with the above purchasers;
however, based on the current demand for oil and natural gas, the Company does
not believe the loss of any of these purchasers would have a material adverse
effect on the Company (see Note 10 of the Company's Notes to the Consolidated
Financial Statements).
 
     Oil and Natural Gas Condensate. All of the Company's crude oil and
condensate is sold at current market prices, under various short and
intermediate term contracts. The Company aggregates the majority of its
production into regional packages and periodically solicits offers from
qualified buyers.
 
     Trading. In December 1995, the Company formed HEC Trading Company ("HTC"),
a wholly-owned subsidiary, to buy, sell and trade various oil and natural gas
products, including financial instruments, in order to add value to the
Company's production.
 
TITLE TO PROPERTIES
 
     As is customary in the oil and natural gas industry, the Company makes only
a cursory review of title to farmout acreage and to undeveloped oil and natural
gas leases upon execution of any contracts. Prior to the commencement of
drilling operations, a thorough title examination is conducted and curative work
is performed with respect to significant defects. To the extent title opinions
or other investigations reflect title defects, the Company, rather than the
seller of the undeveloped property, is typically responsible to cure any such
title defects at its expense. If the Company were unable to remedy or cure any
title defect of a nature such that it would not be prudent to commence drilling
operations on the property, the Company could suffer a loss of its entire
investment in the property. The Company has obtained title opinions on
substantially all of its producing properties and believes that it has
satisfactory title to such properties in accordance with standards generally
accepted in the oil and gas industry. Prior to completing an acquisition of
producing oil and natural gas leases, the Company obtains title opinions on all
leases valued at $25,000 or greater. The Company's oil and natural gas
properties are subject to customary royalty interests, liens for current taxes
and
 
                                        7
<PAGE>   8
 
other burdens which the Company believes do not materially interfere with the
use of or affect the value of such properties.
 
COMPETITION
 
     The oil and gas industry is highly competitive. The Company competes for
the acquisition of oil and natural gas properties, primarily on the basis of the
price to be paid for such properties, with numerous entities, including major
oil companies, other independent oil and gas concerns and individual producers
and operators. Many competitors have financial and other resources substantially
greater than those of the Company. The Company believes that it enjoys a
competitive advantage over most other companies active in the Hugoton Producing
Area because of its extensive database of information and its technical and
geological experience in the area.
 
REGULATION
 
  General
 
     Various aspects of the Company's oil and natural gas operations are
regulated by administrative agencies under statutory provisions of the states
where such operations are subject to various types of regulation, including
regulation by state and federal agencies. Legislation affecting the oil and gas
industry is under constant review for amendment or expansion. Numerous
departments and agencies, both federal and state, are authorized by statute to
issue, and have issued, rules and regulations binding upon the oil and gas
industry and its individual members. The Federal Energy Regulatory Commission
("FERC") regulates the transportation and sale for resale of natural gas in
interstate commerce pursuant to the Natural Gas Act of 1938 ("NGA") and the
Natural Gas Policy Act of 1978 ("NGPA"). In the past, the Federal government has
regulated the prices at which oil and gas could be sold. While sales by
producers of natural gas, and all sales of crude oil, condensate and natural gas
liquids can currently be made at uncontrolled market prices, Congress could
reenact price controls in the future. Deregulation of wellhead sales in the
natural gas industry began with the enactment of the NGPA in 1978. In 1989,
Congress enacted the Natural Gas Wellhead Decontrol Act ("the Decontrol Act").
The Decontrol Act removed all NGA and NGPA price and nonprice controls affecting
wellhead sales of natural gas effective January 1, 1993.
 
  Regulation of Oil and Natural Gas Exploration and Production
 
     Exploration and production operations of the Company are subject to various
types of regulation at the federal, state and local levels. Such regulations
include requiring permits and drilling bonds for the drilling of wells,
regulating the location of wells, the method of drilling and casing wells, and
the surface use and restoration of properties upon which wells are drilled. Many
states also have statutes or regulations addressing conservation matters,
including provisions for the utilization or pooling of oil and gas properties,
the establishment of maximum rates of production from oil and gas wells and the
regulation of spacing, plugging and abandonment of such wells. Some state
statutes limit the rate at which oil and gas can be produced from the Company's
properties. See "Risk Factors -- Compliance with Governmental Regulations."
 
  Natural Gas Marketing, Gathering, Processing and Transportation
 
     Federal legislation and regulatory controls in the United States have
historically affected the price of natural gas and the manner in which such
production is marketed.
 
     Commencing in April 1992, the FERC issued Order Nos. 636,636-A, and 636-B
("Order No. 636"), which require interstate pipelines to provide transportation
separate, or "unbundled," from the pipelines' sales of gas. Also, Order No. 636
requires pipelines to provide open-access transportation on a basis that is
equal for all gas supplies. Although Order No. 636 does not directly regulate
the Company's activities, the FERC has stated that it intends for Order No. 636
to foster increased competition within all phases of the natural gas industry.
It is unclear what impact, if any, increased competition within the natural gas
industry under Order No. 636 will have on the Company's activities. Although
Order No. 636 could provide the Company with additional market access and more
fairly applied transportation service rates, Order No. 636 could also subject
 
                                        8
<PAGE>   9
 
the Company to more restrictive pipeline imbalance tolerances and greater
penalties for violation of those tolerances.
 
     In many instances, the result of Order No. 636 and related initiatives have
been to substantially reduce or eliminate the interstate pipelines' traditional
role as wholesalers of natural gas in favor of providing only storage and
transportation services.
 
     Order No. 636 has been implemented on all interstate pipelines. In July
1996, the United States Court of Appeals for the District of Columbia Circuit
largely upheld Order No. 636. A number of parties have appealed this ruling to
the Supreme Court and proceedings on remanded issues are currently ongoing at
FERC. In addition, numerous parties have filed petitions for review of Order No.
636, as well as orders in individual pipeline restructuring proceedings. Upon
such judicial review, these orders may be remanded or reversed in whole or in
part. With Order No. 636 subject to court review, and pending ongoing court
reviews of individual pipeline restructurings, it is difficult to predict with
precision its ultimate effects.
 
     In December 1992, the FERC issued Order No. 547, governing the issuance of
blanket marketer sales certificates to all natural gas sellers other than
interstate pipelines. The order eliminates the need for natural gas producers
and marketers to seek specific authorization under Section 7 of the NGA from the
FERC to make sales of natural gas for resale. The FERC intends Order No. 547, in
tandem with Order No. 636, to foster a competitive market for natural gas by
giving natural gas purchasers access to multiple supply sources at market-driven
prices. Order No. 547 may increase competition in markets in which the Company's
natural gas is sold.
 
     The FERC has recently announced its intention to re-examine certain of its
transportation-related policies, including the appropriate manner in which
interstate pipelines release transportation capacity under Order No. 636, and
the use of market-based rates for interstate gas transmission. While any
resulting FERC action would affect the Company only indirectly, these inquires
are intended to further enhance competition in natural gas markets.
 
     Regulation of onshore natural gas gathering activities is primarily a
matter of state oversight. Regulation of gas gathering and transportation
activities, depending upon the state involved, may include various
transportation, safety, rate, environmental and non-discriminatory purchase and
transport requirements.
 
  Oil Sales and Transportation Rates
 
     Sales prices of crude oil and gas liquids by the Company are not regulated.
The price the Company receives from the sale of these products may be affected
by the cost of transporting the products to market. Effective January 1995, the
FERC implemented regulations establishing an indexing system under which oil
pipelines will be able to change their transportation rates, subject to
prescribed ceiling levels. The indexing system would generally index such rates
to inflation, subject to certain conditions and limitations. The Company is not
able at this time to predict the effects of these regulations if any, on the
transportation costs associated with oil production from the Company's oil
producing operations.
 
     Additional proposals and proceedings that might affect the oil and gas
industry are pending before the FERC and the courts. The Company cannot predict
when or whether any such proposals may become effective. In the past, the
natural gas industry has been heavily regulated. There is no assurance that the
regulatory approach currently pursued by the FERC will continue indefinitely.
 
  Pipeline Safety Regulation
 
     The Company's gathering operations are subject to safety and operational
regulations relating to the design, installation, testing, construction,
operation, replacement and management of facilities. Pipeline safety issues have
recently been the subject of increasing focus in various political and
administrative arenas at both the state and federal levels. Additional pending
legislation would, among other things, increase the frequency with which certain
pipelines must be inspected, as well as increase potential civil and criminal
penalties for violations of pipeline safety.
 
                                        9
<PAGE>   10
 
  Operating Hazards and Environmental Matters
 
     The oil and gas business involves a variety of operating risks, including
the risk of fire, explosions, blow-outs, pipe failure, casing collapse,
abnormally pressured formations and environmental hazards such as oil spills,
gas leaks, ruptures and discharges of toxic gases, the occurrence of any of
which could result in substantial losses to the Company due to injury or loss of
life, severe damage to or destruction of property, natural resources and
equipment, pollution or other environmental damage, clean-up responsibilities,
regulatory investigation and penalties and suspension of operations. Such
hazards may hinder or delay drilling, development and on-line operations.
 
     Extensive federal, state and local laws govern oil and natural gas
operations regulating the discharge of materials into the environment or
otherwise relating to the protection of the environment. Numerous governmental
departments issue rules and regulations to implement and enforce such laws which
are often difficult and costly to comply with and which carry substantial
penalties for failure to comply. Some laws, rules and regulations relating to
protection of the environment may, in certain circumstances, impose "strict
liability" for environmental contamination, rendering a person liable for
environmental damages and cleanup costs without regard to negligence of fault on
the part of such person. Other laws, rules and regulations may restrict the rate
of oil and natural gas production below the rate that would otherwise exist. The
regulatory burden on the oil and natural gas industry increases its cost of
doing business and consequently affects its profitability. These laws, rules and
regulations affect the operations of the Company. Compliance with environmental
requirements generally could have a material adverse effect upon the capital
expenditures, earnings or competitive position of Hugoton and its subsidiaries.
The Company believes that it is in substantial compliance with current
applicable environmental laws and regulations and that continued compliance with
existing requirements will not have a material adverse impact on the Company.
Nevertheless, changes in environmental law have the potential to adversely
affect the Company's operations. For instance, at least two separate courts have
recently ruled that certain wastes associated with the production of crude oil
may be classified as hazardous substances under the Comprehensive Environmental
Response, Compensation, and Liability Act (commonly called "Superfund") and thus
the Company could become subject to the burdensome cleanup and liability
standards established under the federal Superfund program if significant
concentrations of such wastes were determined to be present at the Company's
properties or to have been produced as a result of the Company's operations.
Alternately, pending amendments to Superfund presently under consideration by
the U.S. Congress could relax many of the burdensome cleanup and liability
standards established under the statute.
 
     The Company has established guidelines to be followed to comply with
environmental laws, rules and regulations. The Company has designated a
compliance officer whose responsibility is to monitor regulatory requirements
and their impacts on the Company and to implement appropriate compliance
procedures. The Company also employs an environmental manager whose
responsibilities include causing the Company's operations to be carried out in
accordance with applicable environmental guidelines and implementing adequate
safety precautions.
 
     Although the Company maintains insurance against some, but not all, of the
risks described above, including insuring the cost of clean-up operations,
public liability and physical damage, there is no assurance that such insurance
will be adequate to cover all such costs or that such insurance will continue to
be available in the future or that such insurance will be available at premium
levels that justify its purchase. The occurrence of a significant event not
fully insured or indemnified against could have a material adverse effect on the
Company's financial condition and operations.
 
     The Company has established guidelines to be followed to comply with
environmental laws, rules and regulations. The Company has designated a
compliance officer whose responsibility is to monitor regulatory requirements
and their impacts on the Company and to implement appropriate compliance
procedures. Although the Company maintains pollution insurance against the costs
of clean-up operations, public liability and physical damage, there is no
assurance that such insurance will be adequate to cover all such costs or that
such insurance will continue to be available in the future.
 
                                       10
<PAGE>   11
 
EMPLOYEES
 
     On February 7, 1997, the Company employed 113 people, including 53 that
work in the Company's various field offices. The Company believes its
relationship with its employees is satisfactory.
 
OFFICES AND EQUIPMENT
 
     The Company leases its Wichita, Kansas headquarters under a lease covering
approximately 40,000 square feet, expiring in 2006. The monthly rent is
approximately $30,000. The Company also leases office space in Denver, Colorado
and owns six field operating offices in Kansas, Oklahoma, Texas, and North
Dakota. The Company also maintains an inventory of field equipment and materials
including tubular goods, compressors, pumping units and field vehicles.
 
FORWARD-LOOKING INFORMATION AND RISK FACTORS
 
     Certain of the statements set forth under "Item 1. -- Business" and "Item
7 -- Management's Discussion and Analysis of Financial Condition and Results of
Operations" and elsewhere in this Form 10-K, such as the statements regarding
planned capital expenditures, the availability of capital resources to fund
capital expenditures and the number of anticipated wells to be drilled in 1997
and thereafter, are forward-looking and are based upon the Company's current
belief as to the outcome and timing of such future events. There are numerous
risks and uncertainties that can affect the outcome and timing of such events,
including many factors beyond the control of the Company. These factors include,
but are not limited to, the matters described below. Should one or more of these
risks or uncertainties occur, or should underlying assumptions prove incorrect,
the Company's actual results and plans for 1997 and beyond could differ
materially from those expressed in the forward-looking statements.
 
     Volatility of Oil and Gas Prices. The Company's future revenue,
profitability and rate of growth are substantially dependent upon the prevailing
prices of, and the demand for, oil and natural gas. Prices for oil and natural
gas are subject to wide fluctuation due to changes in the supply of and demand
for oil and natural gas, market uncertainty, and a variety of additional factors
that are beyond the control of the Company, such as various economic, political
and regulatory developments, and competition from other sources of energy.
 
     Uncertainty of Estimates of Oil and Gas Reserves. Estimating quantities of
reserves and future net cash flows is not an exact science. There are numerous
uncertainties inherent in estimating quantities of proved oil and gas reserves,
including many factors beyond the control of the Company. This Form 10-K
contains estimates of the proved oil and gas reserves of the Company and the
estimated future net cash flows therefrom. Such estimates rely upon various
assumptions, including those prescribed by the Commission, such as future oil
and gas prices, drilling and operating expenses, capital expenditures, taxes,
and availability of funds. The present value of future net cash flows referred
to in this Form 10-K should not be construed as the current market value of the
estimated oil and gas reserves attributable to the Company's properties. The
process of estimating oil and gas reserves is complex, requiring significant
decisions and assumptions in the evaluation of available geological, engineering
and economic data for each reservoir. As a result, any such estimate is
inherently an imprecise estimation of reserve quantities and estimated future
net revenue therefrom. Actual future production, revenue, taxes, development
expenditures, operating expenses and quantities of recoverable oil and gas
reserves will vary from those assumed in the estimate.
 
     Any significant variance from the assumptions could materially affect the
quantity and value of the Company's reserves as compared to the estimates set
forth in this Form 10-K. The Company's production operations may be curtailed or
suspended as a result of governmental requirements or price controls, mechanical
difficulties or other circumstances beyond the control of the Company. The
Company's properties may also be susceptible to hydrocarbon drainage from
production by other operators on adjacent properties. In addition, these
reserves may be subject to downward or upward revision based upon production
history, results of future exploration and development, prevailing oil and gas
prices and other factors.
 
                                       11
<PAGE>   12
 
     Need for Development and Acquisition of Additional Reserves. The Company's
future success, as is generally the case in the industry, depends upon its
ability to find, develop or acquire additional oil and gas reserves that are
economically recoverable. Unless the Company conducts successful exploration,
development and exploitation activities on properties it currently owns or
acquires additional properties containing proved reserves, the Company's proved
reserves will decline. The successful acquisition of producing properties
requires an assessment of recoverable reserves, future oil and gas prices and
operating costs, potential environmental and other liabilities, title issues and
other factors. Such assessments are necessarily inexact and their accuracy is
inherently uncertain.
 
     There can be no assurance that the Company's exploration and development
projects will result in significant additional reserves or that the Company will
have success drilling productive wells at economically viable costs.
Furthermore, while the Company's revenues may increase if prevailing oil and gas
prices increase, the Company's finding costs for additional reserves could also
increase.
 
     The Company intends to make substantial capital expenditures for the
acquisition, exploration, development and production of its oil and natural gas
reserves. While the Company believes that cash flow from operations and
borrowings under the Company's existing bank credit facility should provide the
Company sufficient funds for its planned activities through the end of 1997,
additional debt or equity financing may be required prior to such time or
thereafter to fund further exploration, exploitation and development activities
or future property acquisitions. No assurances can be given as to the
availability or terms of any such additional financing that may be required or
that financing will continue to be available to the Company. If such financing
is not available, the Company's exploration, exploitation and development
activities and future property acquisitions may be curtailed.
 
     Risks of Hedging Transactions. In order to manage its exposure to price
risks in the marketing of its oil and natural gas, the Company has in the past
and expects to continue to enter into oil and natural gas price hedging
arrangements with respect to a portion of its expected production. These
arrangements may include futures contracts on the New York Mercantile Exchange
("NYMEX"), fixed price delivery contracts and financial swaps. While intended to
reduce the effects of volatility of the price of oil and natural gas, such
transactions may limit potential gains by the Company if oil and natural gas
prices were to rise substantially over the price established by the hedge. In
addition, such transactions may expose the Company to the risk of financial loss
in certain circumstances, including instances in which (i) production is less
than expected, (ii) if there is a widening of price differentials between
delivery points for the Company's production and the delivery point assumed in
the hedging arrangement, (iii) the counterparties to the Company's future
contracts fail to perform the contract, or (iv) a sudden, unexpected event
materially impacts oil or natural gas prices.
 
     Concentration of Ownership. The Company, Odyssey Partners, L.P., Cramer,
Rosenthal, McGlynn, Inc., American Gas & Oil Investors, Limited Partnership, Am
GO II, Limited Partnership, Am GO III, Limited Partnership, First Reserve
Secured Energy Assets Fund, Limited Partnership, First Reserve Fund V, Limited
Partnership, COMDISCO, Inc. and Floyd C. Wilson entered into a certain Agreement
of Shareholders (the "Shareholders Agreement"). The Shareholders Agreement
provides that the parties agree, so long as they own certain percentages of
common stock of the Company, to vote their shares of Company Common Stock to
elect the members of the Board of Directors. The parties to the Shareholders
Agreement beneficially own approximately 83% of the outstanding shares of Common
Stock. Accordingly, these shareholders, if they voted together, would have the
ability to elect all of the Company's directors and to approve all other
stockholder actions.
 
     Dependence on Key Personnel. The Company depends to a large extent on the
services of Floyd C. Wilson and W. Mark Womble. Mr. Wilson and Mr. Womble devote
their full time to the Company. The Company currently has an employment contract
with Mr. Wilson that expires in August 2000 and with Mr. Womble that expires in
September 1999. The unavailability of Mr. Wilson or Mr. Womble could have a
material adverse effect on the Company. The Company believes that its success is
also dependent upon its ability to continue to employ and retain skilled
technical personnel.
 
     Marketability of Production. The marketability of the Company's production
depends upon the availability and capacity of gas gathering systems, pipelines
and processing facilities, and the unavailability or
 
                                       12
<PAGE>   13
 
lack of capacity thereof could result in the shut-in of producing wells or the
delay or discontinuance of development plans for properties. In addition,
Federal and state regulation of oil and gas production and transportation,
general economic conditions and changes in supply and demand could adversely
affect the Company's ability to produce and market its oil and natural gas on a
profitable basis.
 
     Competition. The Company operates in a highly competitive environment. The
Company competes with major and independent oil and gas companies for the
acquisition of desirable oil and gas properties, as well as the equipment and
labor required to develop and operate such properties. The Company also competes
with major and independent oil and gas companies in the marketing and sale of
oil and natural gas to marketers and end-users. Many of these competitors have
financial and other resources substantially greater than those of the Company.
 
     Drilling Risks. Drilling involves numerous risks, including the risk that
no commercially productive oil or gas reservoirs will be encountered. The cost
of drilling and completing wells is often uncertain, and drilling operations may
be curtailed, delayed or canceled as a result of a variety of factors, including
unexpected drilling conditions, pressure or irregularities in formations,
equipment failures or accidents, weather conditions, and shortages or delays in
the delivery of equipment. There can be no assurance as to the success of the
Company's future drilling activities.
 
     Operating Hazards. The oil and gas business involves a variety of operating
risks, including the risk of fire, explosions, blow-outs, pipe failure,
abnormally pressured formations and environmental hazards such as oil spills,
gas leaks, ruptures or discharges of toxic gases, the occurrence of any of which
could result in substantial losses to the Company due to injury or loss of life,
severe damage to or destruction of property, natural resources and equipment,
pollution or other environmental damage, clean-up responsibilities, regulatory
investigation and penalties, and suspension of operations. In accordance with
customary industry practice, the Company maintains insurance against some, but
not all, of the risks described above. There can be no assurance that any
insurance obtained by the Company will be adequate to cover any losses or
liabilities. The Company cannot predict the continued availability of insurance
or the availability of insurance at premium levels that justify its purchase.
 
     Compliance with Governmental Regulations. Oil and gas operations are
subject to various federal, state and local governmental regulations which may
be changed from time to time in response to economic or political conditions.
Matters subject to regulation include discharge permits for drilling operations,
drilling and abandonment bonds or other financial responsibility requirements,
reports concerning operations, the spacing of wells, unitization and pooling of
properties and taxation. From time to time, regulatory agencies have imposed
price controls and limitations on production by restricting the rate of flow of
oil and gas wells below actual production capacity in order to conserve supplies
of oil and gas. In addition, the production, handling, storage, transportation
and disposal of oil and gas, by-products thereof and other substances and
materials produced or used in connection with oil and gas operations are subject
to regulation under federal, state and local laws and regulations primarily
relating to protection of human health and the environment. These laws and
regulations have continually imposed increasingly strict requirements for water
and air pollution control and solid waste management.
 
     No Dividends. The Company has never paid cash dividends on its Common Stock
and does not intend to pay cash dividends on its Common Stock in the foreseeable
future. The Company currently intends to retain its cash for the continued
development of its business, including development, exploration and acquisition
activities. In addition, the Company's bank credit facility currently restricts
the ability of the Company to pay dividends.
 
ITEM 2. PROPERTIES
 
     The location and character of the Company's oil and gas properties and its
gathering facilities are described above under Item 1. Business.
 
                                       13
<PAGE>   14
 
ITEM 3. LEGAL PROCEEDINGS
 
     The Company is a named defendant in lawsuits and is a party in governmental
proceedings from time to time arising in the ordinary course of business. While
the outcome of such lawsuits and other proceedings against the Company cannot be
predicted with certainty, management does not believe that these matters will
have a material adverse effect on the financial condition or results of
operations of the Company.
 
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
 
     No matters were submitted to a vote of the Company's shareholders during
the fourth quarter of 1996.
 
                                    PART II
 
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER MATTERS
 
     The Company's common stock trades on the NASDAQ National Market under the
symbol "HUGO." The following table sets forth the high and low sales price per
share for the Company's common stock for the period January 1, 1996 through
December 31, 1996:
 
<TABLE>
<CAPTION>
                                                              HIGH     LOW
                                                              ----     ---
<S>                                                           <C>      <C>
First Quarter...............................................  $ 9 1/4  $7 1/4
Second Quarter..............................................    8 3/4   7
Third Quarter...............................................    9 3/8   7 3/8
Fourth Quarter..............................................   11 5/8   8 1/4
</TABLE>
 
     On February 19, 1997, the closing price for the Company's common stock was
$11.125.
 
     The Company has approximately 1,100 shareholders, including 1,000
beneficial owners and 100 holders of record as of February 15, 1997.
 
     No dividends have been paid on the Company's common stock to date. The
Company intends to maintain a policy of retaining cash for the continued
expansion of its business.
 
                                       14
<PAGE>   15
 
ITEM 6. SELECTED FINANCIAL DATA
 
<TABLE>
<CAPTION>
                                                              YEARS ENDED DECEMBER 31,
                                                 --------------------------------------------------
                                                   1996       1995       1994      1993      1992
                                                 --------   --------   --------   -------   -------
                                                       (IN THOUSANDS, EXCEPT PER SHARE DATA)
<S>                                              <C>        <C>        <C>        <C>       <C>
INCOME STATEMENT DATA:
Revenues:
  Oil and gas..................................  $ 66,292   $ 35,906   $ 23,696   $17,349   $ 6,731
  Gas plant....................................     1,914      1,638      1,945     1,172     2,177
  Other(1).....................................        10     (3,315)       (11)       16       547
                                                 --------   --------   --------   -------   -------
          Total revenues.......................    68,216     34,229     25,630    18,537     9,455
                                                 --------   --------   --------   -------   -------
Expenses:
  Production...................................    21,667     11,570      7,528     7,178     4,671
  Gas plant....................................     1,420        978      1,189       934     1,320
  Exploration..................................     1,711      2,239      3,036       587       137
  General and administrative...................     6,872      4,346      3,117     1,883     1,761
  Compensatory stock option expense(2).........        --         --         --     3,289        --
  Depreciation, depletion and amortization.....    23,423     15,234      8,677     5,582     1,452
                                                 --------   --------   --------   -------   -------
          Total expenses.......................    55,093     34,367     23,547    19,453     9,341
                                                 --------   --------   --------   -------   -------
Operating income (loss)........................    13,123       (138)     2,083      (916)      114
Other income (expenses):
  Interest.....................................    (6,070)    (5,108)    (3,077)   (2,371)     (502)
  Other........................................       466        319        252       199        44
                                                 --------   --------   --------   -------   -------
          Total other income (expense).........    (5,604)    (4,789)    (2,825)   (2,172)     (458)
                                                 --------   --------   --------   -------   -------
Income (loss) before income taxes and
  extraordinary item...........................     7,519     (4,927)      (742)   (3,088)     (344)
(Provision) benefit for income taxes...........    (3,316)     1,394         66       582       (86)
                                                 --------   --------   --------   -------   -------
Income (loss) before extraordinary item........     4,203     (3,533)      (676)   (2,506)     (430)
Extraordinary item-loss from early
  extinguishment of debt, net of tax...........        --       (136)        --        --        --
                                                 --------   --------   --------   -------   -------
          Net income (loss)....................  $  4,203   $ (3,669)  $   (676)  $(2,506)  $  (430)
                                                 ========   ========   ========   =======   =======
          Net income (loss) per common share...  $   0.21   $  (0.27)  $  (0.07)  $ (0.41)  $ (0.09)
                                                 ========   ========   ========   =======   =======
Weighted average number of common shares
  outstanding..................................    19,698     13,460     10,310     6,071     5,000
OTHER DATA:
Net cash provided by operating activities......  $ 29,484   $ 11,367   $ 10,431   $ 5,931   $ 1,928
Net cash (used) in investing activities........   (36,706)   (36,869)   (39,116)  (78,765)   (3,685)
Net cash provided by financing activities......     7,040     27,750     28,683    73,755     1,865
BALANCE SHEET DATA (AT END OF PERIOD):
Working capital (deficit)......................  $  8,545   $  6,083   $ 11,551   $ 1,732   $(2,234)
Property and equipment, net....................   232,778    217,635     96,436    78,842    12,342
Total assets...................................   251,929    234,655    116,634    88,329    16,309
Long-term debt.................................    95,000     88,000     60,000    62,500     9,062
Shareholders' equity...........................   131,527    127,324     50,225    19,995     1,184
</TABLE>
 
---------------
 
(1) The year ended December 31, 1995 includes a charge of $2.7 million relating
    to the Company's natural gas hedging activities resulting from a loss of
    basis correlation for certain contracts (see Note 11 of Company's Notes to
    the Consolidated Financial Statements).
 
(2) Reflects a non-cash charge for compensatory stock options granted to certain
    employees that have been or will be satisfied by the Company's Chairman of
    the Board, President and Chief Executive Officer.
 
                                       15
<PAGE>   16
 
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS OVERVIEW
 
GENERAL
 
     Hugoton Energy Corporation was formed in 1987 through the acquisition of
several limited partnership interests in the Hugoton Producing Area, and until
1993 grew primarily through acquisitions in that core area. Since 1993, the
Company has grown through producing property and leasehold acquisitions and
development and exploratory drilling, primarily in three additional core areas:
the Williston Basin, the Permian Basin and, most recently, the Austin Chalk
Trend. Expansion into these areas marked a shift in the Company's asset base
from the lower risk, limited upside of the Hugoton Producing Area to areas with
much greater exploration and development potential. On February 1, 1994, the
Company completed its initial public offering of 3.45 million shares of Common
Stock.
 
     The Company's 1997 capital budget is $75 million, an increase of 63% over
1996 capital expenditures, and 70% of the drilling budget is planned for
expenditures outside of the Hugoton Producing Area. The Company continues to
aggressively pursue acquisitions, but the timing and impact of such acquisitions
cannot be predicted.
 
     1996 Acquisitions and Property Sales.  During 1996, the Company spent $17.4
million to acquire 165,000 additional net undeveloped acres, including 95,000
net acres in the Williston Basin. These acreage additions were equal to 70% of
the Company's net undeveloped acres at December 31, 1995.
 
     On June 20, 1996, the Company purchased a 50% working interest for $12.9
million in approximately 95,000 gross acres in the Austin Chalk Trend in
Louisiana. This acreage acquisition, coupled with the January 1, 1996 acreage
acquisition mentioned below and several smaller acreage acquisitions in the
third quarter, presents the Company with a total of 148,000 gross acres in the
Austin Chalk Trend to explore.
 
     During 1996, the Company sold its interest in a group of non-strategic
producing gas properties and a gas gathering and salt water disposal system
located in Southern Colorado and Northern New Mexico to a major oil company for
$4.5 million. The Company also sold its interest in approximately 450
non-strategic producing oil properties located in Northeast Oklahoma for $1.5
million.
 
     On January 1, 1996, the Company purchased an undivided interest in a group
of producing oil and gas properties and undeveloped acreage for $9.7 million
from a privately-held company that owns an undivided interest in and operates
the properties. The producing properties and acreage are located in Southeast
Texas and established a presence for the Company in the Austin Chalk Trend. The
acquisition included eight producing wells and 35,000 gross acres, in which the
Company's working interests are 25% and 50%, respectively.
 
     Prior Major Property Acquisitions.  The Company's current property position
has been shaped by two large acquisitions consummated in 1995 and 1993 and
several smaller acquisitions.
 
     In September 1995, the Company acquired COG, a privately owned oil and gas
company for $35 million in cash and 9.1 million shares of Common Stock. The
acquisition extended the Company's operations into several basins outside the
Hugoton Producing Area, primarily into the Williston Basin and Permian Basin.
 
     In July 1993, the Company significantly strengthened its position as a
major operator in the Hugoton Field with the $73.5 million purchase from
Prudential of interests in two limited partnerships formed to acquire and
develop properties in the Hugoton Producing Area for which the Company had acted
as general partner.
 
     These two acquisitions were supplemented by a $13.6 million acquisition of
56 producing wells in the Hugoton Producing Area from Mobil Corporation in 1995,
as well as the purchase in 1994 of a 50% interest in 186,000 mineral acres
covering deep rights underlying shallow production located in the Hugoton Field
which is being developed jointly with Oxy U.S.A.
 
     The future results of the Company may depend on its ability to locate and
develop additional oil and natural gas properties, to attract and employ new
sources of capital, to develop these properties and to successfully market the
resulting production of crude oil and natural gas products. Historically, the
markets for
 
                                       16
<PAGE>   17
 
oil and natural gas have been volatile and are likely to continue to be volatile
in the future but it is impossible to predict these future price movements.
Declines in oil and natural gas prices may adversely affect the Company's cash
flow, liquidity and profitability. Due to the nature of the oil and natural gas
industry and the general risks relating to the exploration for and production of
oil and natural gas, including the volatility of prices for crude oil and
natural gas products, there can be no assurance that these efforts will be
successful.
 
RESULTS OF OPERATIONS
 
     The following table sets forth the Company's oil and natural gas production
during the periods indicated:
 
<TABLE>
<CAPTION>
                                                            YEARS ENDED DECEMBER 31,
                                                           ---------------------------
                                                            1996      1995      1994
                                                           -------   -------   -------
<S>                                                        <C>       <C>       <C>
Net Production:
  Natural gas (MMcf).....................................   19,026    14,651    12,491
  Oil (MBbls)............................................    1,700     1,018       369
  Natural gas equivalents (MMcfe)........................   29,226    20,759    14,705
Average Sales Price(1):
  Natural gas ($/Mcf)(2).................................  $  1.87   $  1.30   $  1.44
  Oil ($/Bbl)............................................    18.03     16.37     15.31
  Natural gas equivalents ($/Mcfe).......................     2.27      1.72      1.61
Other Data:
  Production costs ($/Mcfe)(3)...........................  $  0.74   $  0.56   $  0.51
  Depreciation, depletion and amortization($/Mcfe)(4)....     0.76      0.68      0.54
</TABLE>
 
---------------
 
(1) Includes the effect of hedging transactions. See Note 11 of the Company's
    Notes to the Consolidated Financial Statements.
 
(2) Average prices received from sales of natural gas include revenues
    attributable to NGLs as the Company has not historically accounted
    separately for production or revenues attributable to NGLs.
 
(3) Consists of lease operating expenses, production and severance taxes and
    gathering, transportation and other production expense.
 
(4) Excludes depreciation, depletion and amortization not related to oil and gas
    properties.
 
  YEAR ENDED DECEMBER 31, 1996 COMPARED TO YEAR ENDED DECEMBER 31, 1995
 
     Net Income or Loss and Cash Flow from Operating Activities. For the year
ended December 31, 1996, the Company reported net income of $4.2 million, or
$.21 per share, on total revenue of $68.2 million. This compares to a net loss
of $3.7 million, or $.27 per share, on total revenue of $34.2 million for the
year ended December 31, 1995. Cash flows from operating activities for 1996
increased by 159% to $29.4 million from $11.4 million in 1995. The increase in
net income for 1996 is largely attributable to a full year impact of the
addition of the properties acquired in the COG acquisition completed in
September of 1995, higher average sales prices per Mcfe ($2.27 in 1996 versus
$1.72 in 1995) and the continued success of the Company's drilling program. The
Company's net income, cash flows and average sales prices for 1996 were all
significantly impacted by the Company's oil and natural gas swap contracts,
resulting in pre-tax income and the average sales price per Mcfe being reduced
by $8.7 million and $.30, respectively, for the year ended December 31, 1996.
 
     Oil and Gas Revenues. Revenues from oil and gas operations increased by 85%
to $66.3 million in 1996, compared to $35.9 million during 1995. The increase
from 1995 to 1996 is largely attributed to the inclusion of the COG and other
acquisition properties for the full year in 1996, higher average sales prices
and the continued success of the Company's drilling activities. The Company's
1996 gas production increased by 30% and oil production increased by 67% over
1995 production.
 
     Production Expense. Production expense for 1996 increased to $21.7 million
compared to $11.6 million in 1995. The overall increase reflects the addition of
a substantial number of wells (through the COG and other
 
                                       17
<PAGE>   18
 
acquisitions and the Company's drilling program), and the per unit increase in
production expenses reflects an increase in the oil component of the Company's
production, which is relatively higher cost than gas production.
 
     Exploration Expense. Exploration expense decreased by $.5 million from $2.2
million in 1995 to $1.7 million in 1996. The decrease was due largely to the
higher success rate achieved by the Company from its drilling program (87% in
1996 versus 72% in 1995).
 
     General and Administrative Expense. General and administrative expense
increased to $6.9 million in 1996 compared to $4.3 million in 1995. This
increase reflected the impact of a full year of expenses subsequent to the
acquisition of COG and the continued expansion of the Company's operations.
 
     Depreciation, Depletion and Amortization Expense. Depreciation, depletion
and amortization ("DD&A") for 1996 was $23.4 million compared to $15.2 million
for 1995. The Company's DD&A expense per Mcfe increased from $.68 in 1995 to
$.76 in 1996. These increases are mainly due to higher production levels in 1996
compared to 1995 and the result of increased DD&A rates resulting from the
adjustment of such rates to incorporate the book allocated basis to proved oil
and gas properties acquired from COG, which bear a higher unit of production
DD&A rate than the Company's other producing properties.
 
     Interest Expense. Interest expense was $6.1 million for 1996 compared to
$5.1 million for 1995. This increase is attributable to a higher average
long-term debt balance outstanding during 1996, principally as a result of
funding the COG and other acquisitions.
 
     Income Taxes. For 1996, the Company recorded a tax provision of $3.3
million compared to a $1.4 million benefit recorded in 1995. The effective tax
rate for 1996 was 44.1% as compared to 28.3% in 1995. The provision recorded in
1996 exceeds a normal tax rate primarily as a result of the amortization of
certain non-deductible property costs arising from the purchase allocation
related to the COG acquisition.
 
  YEAR ENDED DECEMBER 31, 1995 COMPARED TO YEAR ENDED DECEMBER 31, 1994
 
     Net Loss and Cash Flow from Operating Activities. For the year ended
December 31, 1995, the Company reported a net loss of $3.7 million, or $.27 per
share, on total revenue of $34.2 million. This compares to a net loss of $0.7
million, or $.07 per share, on total revenue of $25.6 million for the year ended
December 31, 1994. Cash flows from operating activities for 1995 increased by 9%
to $11.4 million from $10.4 million in 1994. The increase in the net loss for
1995 was largely due to the charge to earnings of $2.7 million related to the
decoupling of the Company's natural gas swap contracts during the fourth quarter
of 1995 (see Note 11 of the Company's Notes to the Consolidated Financial
Statements), losses incurred on the sale of oil and gas properties of $0.6
million during 1995 and an increase in the charge for expired leases of $0.9
million. The increase in revenues for 1995 is attributable to an increase in the
price per Mcfe received by the Company ($1.72 in 1995 versus $1.61 in 1994) and
the impact of the addition of the properties acquired in the COG acquisition
completed in September 1995.
 
     Oil and Gas Revenues. Revenues from oil and gas operations increased by 52%
to $35.9 million in 1995, compared to $23.7 million during 1994. The increase
from 1994 to 1995 was largely attributable to the inclusion of the COG and other
acquisition properties for four and six months, respectively, and the continued
success of the Company's drilling activities. The Company's 1995 gas production
increased by 17% and oil production increased by 176% over 1994 production.
 
     Production Expense. Production expense for 1995 increased by 54% to $11.6
million compared to $7.5 million in 1994. The increase reflects the addition of
a substantial number of wells (through the COG and Mobil acquisitions and the
Company's drilling program), and the increase in the oil component of the
Company's production.
 
     Exploration Expense. Exploration expense decreased from $3.0 million in
1994 to $2.2 million in 1995. The decrease was due largely to the higher success
rate achieved by the Company from its drilling program (72% in 1995 versus 62%
in 1994) and a fewer number of wells drilled by the Company (39 gross wells in
1995 compared to 78 gross wells in 1994).
 
                                       18
<PAGE>   19
 
     General and Administrative Expense. General and administrative expense
increased to $4.3 million in 1995 compared to $3.1 million in 1994. This
increase reflected the continued expansion of the Company's operation and the
associated costs of additional personnel; however; these expenses declined when
expressed as a percentage of revenues reflecting the Company's efforts to
acquire properties that can be incorporated into its existing property base with
minimal incremental general and administrative expense.
 
     Depreciation, Depletion and Amortization Expense. DD&A for 1995 was $15.2
million compared to $8.7 million for 1994. The Company's DD&A expense per Mcfe
increased from $.54 in 1994 to $.68 in 1995. These increases were mainly due to
higher production levels in 1995 compared to 1994 and the result of increased
DD&A rates resulting from the application of such rates to the book allocated
basis to proved oil and gas properties acquired from COG in September 1995,
which bear a higher unit of production DD&A rate than the Company's other
producing properties.
 
     Interest Expense. Interest expense was $5.1 million for 1995 compared to
$3.1 million for 1994. This increase was attributable to a higher average
long-term debt balance outstanding during 1995, principally as a result of
funding the COG and other acquisitions.
 
     Income Taxes. For 1995, the Company recorded a tax benefit of $1.4 million
compared to a $.07 million benefit recorded in 1994. The benefit recorded in
1995 recognized the effect of the COG acquisition, whereby the Company accounted
for the acquisition under the purchase method of accounting, and as required by
FAS 109, the basis differences between the allocated fair value for book
purposes and the assumed historical tax bases required the Company to establish
the necessary deferred tax liabilities for these temporary differences. As such,
the Company's deferred net tax liability position allowed the Company to
recognize a tax benefit for the pre-tax operating losses generated in the period
subsequent to the acquisition date of COG. During 1995, the pre-tax losses
incurred by the Company prior to the acquisition of COG were not tax benefited
because the Company was in a net deferred tax asset position which required such
benefits to be reduced by valuation allowances.
 
LIQUIDITY AND CAPITAL RESOURCES
 
     The Company's working capital position increased by $2.5 million from
year-end 1995 to $8.5 million at December 31, 1996. Cash decreased by $0.2
million and accounts receivable increased by $4.1 million. The Company's ratio
of current assets to current liabilities was 2.0 to 1.0 at December 31, 1996 and
1.8 to 1.0 at December 31, 1995.
 
     Capital Expenditures. The Company's primary needs for cash are for
exploration, development and acquisitions of oil and gas properties, payment of
interest on outstanding indebtedness and working capital obligations. The
Company's 1997 capital expenditure budget has been set at $75 million of which
approximately $50 million is committed to drilling, $10 million for 3-D seismic
and land costs and $15 million for small strategic acquisitions. Funding for the
Company's exploration and development activities and its working capital
obligations is provided primarily by internally-generated cash flow. The Company
budgets its capital expenditures based on projected cash flows and routinely
adjusts the level of its capital expenditures in response to anticipated changes
in cash flows.
 
     Capital Resources. The Company's capital resources consist of cash flow
from operating activities and funds available under the credit facility. On
September 7, 1995, the Company arranged a new bank credit facility,
simultaneously with the closing of the COG acquisition. The new facility is an
unsecured $250 million revolving credit agreement that is due September 7, 1999.
The facility is provided by seven banks, led by Bank One, Texas as agent and
Texas Commerce Bank National Association as co-agent. The Borrowing Base, as
defined in the loan agreement, is currently set at $135 million, and is subject
to semi-annual redetermination based upon an evaluation of the Company's oil and
gas reserves. Outstanding borrowings were $95 million at December 31, 1996.
 
     The credit facility provides the option of borrowing at floating interest
rates based on Bank One's base rate or at a Eurodollar option based on the
London Interbank Offered Rate ("LIBOR") plus 3/4 of 1% to 1.25% per annum,
depending on the outstanding loan balance. Interest is paid quarterly or at the
end of each
 
                                       19
<PAGE>   20
 
interest period. The Company also incurs a commitment fee of 1/4 of 1% on the
unused portion of the Borrowing Base. In addition, the credit facility also
contains customary restrictive covenants, including restrictions on the payment
of dividends in excess of 50% of the Company's annual net income, and requires
the Company to maintain certain financial ratios.
 
     At December 31, 1996, the Company was a party to one interest rate swap
agreement that was entered into on December 11, 1995 for $25 million in notional
principal amount. The effect of this agreement is to provide the Company with an
interest rate on $25 million in notional principal amount for the three-year
term of the agreement of 5.445% plus a margin of 3/4 of 1% to 1.25%. Under
market conditions at December 31, 1996, the aggregate effective annual interest
rate after giving effect to the swap agreement was 6.542%.
 
     The Company has historically funded its operations and capital spending
programs with cash flow from operations and borrowings under bank credit
facilities. The Company believes that cash flow from operations and the
borrowing availability under the credit facility will be sufficient to meet its
anticipated capital requirements for 1997. However, because future cash flows
and the availability of financing are subject to a number of variables, such as
the level of production and the prices received for oil and natural gas, there
can be no assurance that the Company's capital resources will be sufficient to
maintain currently planned levels of capital expenditures.
 
     Hedging Transactions. With the objective of achieving more predictable
revenues and cash flows and reducing the exposure to fluctuations in oil and
natural gas prices, the Company has entered into hedging transactions of various
kinds with respect to both oil and natural gas. While the use of these hedging
arrangements limits the downside risk of adverse price movements, it may also
limit future revenues from favorable price movements.
 
     At December 31, 1996, the Company had entered into swap agreements fixing
the price of 70,000 barrels per month, for the first three months of its oil
production for 1997 at a weighted average price of $24.25 per Bbl. In addition,
the Company has entered into a forward sale of 20 MMcf of natural gas per day
for the first three months of 1997 at a net price to the Company of $3.68 per
Mcf. The Company continues to evaluate whether to enter into additional hedging
transactions for 1997 and future years. In addition, the Company may determine
from time to time to terminate its then existing hedging positions. (See Note 11
of the Company's Notes to the Consolidated Financial Statements).
 
     The Company's net income, cash flows and average sales prices for 1996 were
all significantly impacted by the Company's oil and natural gas swap contracts,
resulting in pre-tax income and the average sales price per Mcfe being reduced
by $8.7 million and $.30, respectively, for the year ended December 31, 1996.
The reduction was caused in part by an unusually high volatility of natural gas
prices and the widening of the differential or correlation between the cash
prices for the Company's production and the NYMEX contract settlement prices.
 
INFLATION AND CHANGES IN PRICES
 
     The Company's revenues and the value of its oil and natural gas properties
have and will continue to be affected by changes in oil and natural gas prices.
The Company's ability to maintain current borrowing capacity and to obtain
additional capital on attractive terms is also substantially dependent on oil
and natural gas prices. Oil and natural gas prices are subject to significant
seasonal and other fluctuations that are beyond the Company's ability to control
or predict. Although certain of the Company's costs and expenses are affected by
the level of inflation, inflation did not have a significant effect on the
Company's operations during 1996 or 1995.
 
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
     See the Consolidated Financial Statements and supplementary data listed in
the accompanying Index to Financial Statements and Supplemental Data and
Financial Statement Schedules on page A-1 herein. Information required by other
schedules required under Regulation S-X is either not applicable or is included
in the financial statements or notes thereto.
 
                                       20
<PAGE>   21
 
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
 
     None.
 
                                    PART III
 
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY
 
     Reference is made to the disclosure under the captions, "Board of
Directors," "Proposal I -- Election of Directors," "Executive Officers" and
"Section 16 Reporting," in the Company's definitive Proxy Statement to be filed
on or about April 10, 1997, pursuant to Regulation 14A in connection with its
Annual Meeting of Shareholders to be held May 16, 1997, which is incorporated
herein by reference.
 
ITEM 11. EXECUTIVE COMPENSATION
 
     Reference is made to the disclosure under the captions, "Executive
Compensation and Other Matters," "Option Grants Table," and "Option Exercise
Table" in the Company's definitive Proxy Statement to be filed on or about April
10, 1997, pursuant to Regulation 14A in connection with its Annual Meeting of
Shareholders to be held May 16, 1997, which is incorporated herein by reference.
 
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
 
     Reference is made to the disclosure under the captions, "Security Ownership
of Certain Beneficial Owners and Management" in the Company's definitive Proxy
Statement to be filed on or about April 10, 1997, pursuant to Regulation 14A in
connection with its Annual Meeting of Shareholders to be held May 16, 1997,
which is incorporated herein by reference.
 
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
 
     Reference is made to the disclosure under the captions, "Certain
Relationships and Related Transactions" in the Company's definitive Proxy
Statement to be filed on or about April 10, 1997, pursuant to Regulation 14A in
connection with its Annual Meeting of Shareholders to be held May 16, 1997,
which is incorporated herein by reference.
 
                                    PART IV
 
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULE, AND REPORTS ON FORM 8-K
 
     (a) The following documents are filed as part of this report:
 
          (1) and (2) Financial Statements and Schedule:
 
          See Index to Financial Statements, Supplemental Data, and Financial
     Statement Schedule which appears on page A-1 herein.
 
          (3) Exhibits: The following documents are filed as exhibits to this
     report.
 
<TABLE>
<C>                      <S>
           2.1           -- Agreement and Plan of Merger, dated May 26, 1995, by and
                            among Hugoton Energy Corporation, Oil & Gas, Inc. and
                            Hugoton Exploration Corporation (Incorporated by
                            reference to Exhibit 4.4 of the Registration Statement on
                            Form S-3, Registration No. 33-97366)
           2.2           -- Amendment to Agreement and Plan of Merger, dated August
                            3, 1995 by and among Hugoton Energy Corporation,
                            Consolidated Oil & Gas, Inc. and Hugoton Exploration
                            Corporation (Incorporated by reference to Exhibit 4.4 of
                            the Registration Statement on Form S-3, Registration No.
                            33-97366)
</TABLE>
 
                                       21
<PAGE>   22
<TABLE>
<S>                      <C>
           3.1           -- Restated Articles of Incorporation of the Company, as
                            amended (Incorporated by reference to Exhibit 3.1 of the
                            Registration Statement on Form S-1, Registration No.
                            33-70924)
           3.2           -- Bylaws of the Company, as amended (Incorporated by
                            reference to Exhibit 3.2 of the Registration Statement on
                            Form S-1, Registration No. 33-70924)
           4.1           -- Specimen Common Stock certificate (Incorporated by
                            reference to Exhibit 4.1 of the Registration Statement on
                            Form S-1, Registration No. 33-70924)
          10.1           -- Employment Agreement, dated September 1, 1995 between the
                            Company and Floyd C. Wilson (Incorporated by reference to
                            Exhibit 10.1 of the Company's 1995 Annual Report on Form
                            10-K)
          10.2*          -- Employment Agreement, dated September 7, 1995 between the
                            Company and Jay W. Decker
          10.3*          -- Employment Agreement, dated December 16, 1996 between the
                            Company and W. Mark Womble
          10.4           -- 1993 Stock Option Plan (Incorporated by reference to
                            Exhibit 10.12 of the Registration Statement on Form S-1,
                            Registration No. 33-70924)
          10.5           -- 401(k) Employee Benefit Plan (Incorporated by reference
                            to Exhibit 10.13 of the Registration Statement on Form
                            S-1, Registration No. 33-70924)
          10.6           -- Nonemployee Directors' Stock Option Plan (Incorporated by
                            reference to Exhibit 10.14 of the Registration Statement
                            on Form S-1, Registration No. 33-70924)
          10.7           -- 1995 Stock Option Plan (Incorporated by reference to
                            Exhibit 4.1 of the Registration Statement on Form S-8,
                            Registration No. 33-97092)
          10.8           -- Loan Agreement, dated September 7, 1995, by and among the
                            Company, Amgas Corporation, Hugoton Exploration
                            Corporation, Tiffany Gathering Inc., Bank One, Texas
                            N.A., Texas Commerce Bank National Association, Bank of
                            Montreal, Wells Fargo Bank, National Association,
                            Meespierson N.V., Credit Lyonnais Cayman Island Branch
                            and Bank of Scotland, and Bank One, Texas N.A. as Agent,
                            and Texas Commerce Bank National Association as Co-agent
                            (Incorporated by reference to Exhibit 10.8 of the
                            Company's 1995 Annual Report on Form 10-K)
          10.9           -- First Amendment to Loan Agreement dated January 22, 1996,
                            by and among the Company, Amgas Corporation, Hugoton
                            Exploration Corporation, HEC Trading Company, Tiffany
                            Gathering, Inc., Bank One, Texas N.A., Texas Commerce
                            Bank National Association, Bank of Montreal, Wells Fargo
                            Bank, National Association, Meespierson N.V., Credit
                            Lyonnais Cayman Island Branch and Bank of Scotland, and
                            Bank One, Texas N.A. as Agent, and Texas Commerce Bank
                            National Association as Co-agent (Incorporated by
                            reference to Exhibit 10.9 of the Company's 1995 Annual
                            Report on Form 10-K)
          10.10*         -- Second Amendment to Loan Agreement dated June 11, 1996,
                            by and among the Company, Amgas Corporation, Hugoton
                            Exploration Corporation, HEC Trading Company, Tiffany
                            Gathering, Inc., Bank One, Texas N.A., Texas Commerce
                            Bank National Association, Bank of Montreal, Wells Fargo
                            Bank, National Association, Meespierson N.V., Credit
                            Lyonnais Cayman Island Branch and Bank of Scotland, and
                            Bank One, Texas N.A. as Agent, and Texas Commerce Bank
                            National Association as Co-Agent
          10.11          -- Purchase and sale agreement dated June 1, 1995 by and
                            between Mobil Oil Corporation and the Company
                            (Incorporated by reference to Exhibit 10.10 of the
                            Company's 1995 Annual Report on Form 10-K)
</TABLE>
 
                                       22
<PAGE>   23
<TABLE>
<S>                      <C>
          10.12          -- Shareholder Agreement dated May 26, 1995, by and among
                            the Company, Consolidated Oil & Gas, Inc. and Odyssey
                            Partners, L.P. (Incorporated by reference to Exhibit
                            10.11 of the Company's 1995 Annual Report on Form 10-K)
          10.13          -- Agreement of Shareholders dated September 7, 1995, by and
                            among the Company, First Reserve Fund V, Limited
                            Partnership, First Reserve Secured Energy Assets Fund,
                            Limited Partnership, American Gas & Oil Investors,
                            Limited Partnerships, AmGO II, Limited Partnership, AmGO
                            III, Limited Partnership, J. W. Decker, COMDISCO, Inc.,
                            Odyssey Partners, L. P. and Floyd C. Wilson (Incorporated
                            by reference to Exhibit 10.12 of the Company's 1995
                            Annual Report on Form 10-K)
          10.14          -- Registration Rights Agreement dated September 7, 1995, by
                            and among the Company Hugoton Energy Corporation, Odyssey
                            Partners, L.P., Cramer, Rosenthal, McGlynn, Inc.,
                            American Gas & Oil Investors, AmGO II, AmGO III, First
                            Reserve Secured Energy Assets Fund, First Reserve Fund V,
                            COMDISCO, Inc. and Floyd C. Wilson (Incorporated by
                            reference to Exhibit 10.13 of the Company's 1995 Annual
                            Report on Form 10-K)
          10.15*         -- Purchase and Sale Agreement dated December 28, 1995 by
                            and between Shield Petroleum Incorporated, P&M Properties
                            and the Company
          10.16*         -- Purchase and Sale Agreement dated June 18, 1996 by and
                            between Shield Petroleum Incorporated and the Company
          21.1           -- List of subsidiaries of the Company (Incorporated by
                            reference to Exhibit 21.1 of the Company's 1995 Annual
                            Report on Form 10-K)
          23.1*          -- Consent of Ernst & Young LLP
          23.2*          -- Consent of Ryder Scott Company
 
---------------
 
* Filed herewith
</TABLE>
 
                                       23
<PAGE>   24
 
                                   SIGNATURES
 
     Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized, on the 21st day of
February, 1997.
 
                                            HUGOTON ENERGY CORPORATION
                                            (Registrant)
 
                                            By      /s/ FLOYD C. WILSON
                                             -----------------------------------
                                                       Floyd C. Wilson
                                              Chairman of the Board, President
                                                             and
                                                   Chief Executive Officer
 
     Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities indicated on the 21st day of February 1997.
 
<TABLE>
<CAPTION>
                      SIGNATURE                                      TITLE                        DATE
                      ---------                                      -----                        ----
<C>                                                    <S>                                 <C>
 
                 /s/ FLOYD C. WILSON                   Chairman of the Board, President    February 21, 1997
-----------------------------------------------------    and Chief Executive Officer
                   Floyd C. Wilson
 
                 /s/ W. MARK WOMBLE                    Executive Vice President, Chief     February 21, 1997
-----------------------------------------------------    Financial Officer (Principal
                   W. Mark Womble                        Financial Officer) and Director
 
                   /s/ J.W. DECKER                     Executive Vice President and        February 21, 1997
-----------------------------------------------------    Director
                     J.W. Decker
 
                /s/ SHANE M. BAYLESS                   Controller (Principal Accounting    February 21, 1997
-----------------------------------------------------    Officer)
                  Shane M. Bayless
 
                 /s/ STEPHEN BERGER                    Director                            February 21, 1997
-----------------------------------------------------
                   Stephen Berger
 
                /s/ DAVID S. ELKOURI                   Director                            February 21, 1997
-----------------------------------------------------
                  David S. Elkouri
 
                /s/ JOHN T. MCNABB II                  Director                            February 21, 1997
-----------------------------------------------------
                  John T. McNabb II
 
                /s/ ALAN J. ANDREINI                   Director                            February 21, 1997
-----------------------------------------------------
                  Alan J. Andreini
 
                                                       Director
-----------------------------------------------------
                 William E. Macaulay
 
                 /s/ JONATHAN LINKER                   Director                            February 21, 1997
-----------------------------------------------------
                   Jonathan Linker
</TABLE>
 
                                       24
<PAGE>   25
 
                           HUGOTON ENERGY CORPORATION
 
                  INDEX TO FINANCIAL STATEMENTS, SUPPLEMENTAL
                     DATA AND FINANCIAL STATEMENT SCHEDULE
 
<TABLE>
<CAPTION>
                                                              PAGE
                                                              ----
<S>                                                           <C>
Consolidated Financial Statements:
Report of Independent Auditors..............................   A-2
Consolidated Balance Sheets as of December 31, 1996 and
  1995......................................................   A-3
Consolidated Statements of Operations for the years ended
  December 31, 1996, 1995, and 1994.........................   A-4
Consolidated Statements of Shareholders' Equity for the
  years ended December 31, 1996, 1995 and 1994..............   A-5
Consolidated Statements of Cash Flows for the years ended
  December 31, 1996, 1995 and 1994..........................   A-6
Notes to Consolidated Financial Statements..................   A-7
Unaudited Supplemental Oil and Gas Information..............  A-21
Consolidated Financial Statement Schedule for the years
  ended December 31, 1996, 1995 and 1994:
     II - Valuation and Qualifying Accounts.................  A-24
</TABLE>
 
                                       A-1
<PAGE>   26
 
                         REPORT OF INDEPENDENT AUDITORS
 
The Board of Directors and Shareholders
Hugoton Energy Corporation
 
     We have audited the accompanying consolidated balance sheets of Hugoton
Energy Corporation as of December 31, 1996 and 1995, and the related
consolidated statements of operations, shareholders' equity and cash flows for
each of the three years in the period ended December 31, 1996. Our audits also
included the financial statement schedule listed in the Index at Item 14(a).
These financial statements and the schedule are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements and the schedule based on our audits.
 
     We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
 
     In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the consolidated financial position of
Hugoton Energy Corporation at December 31, 1996 and 1995, and the consolidated
results of its operations and its cash flows for each of the three years in the
period ended December 31, 1996 in conformity with generally accepted accounting
principles. Also, in our opinion, the related financial statement schedule, when
considered in relation to the basic financial statements taken as a whole,
presents fairly in all material respects the information set forth therein.
 
Wichita, Kansas
February 7, 1997
 
                                       A-2
<PAGE>   27
 
                           HUGOTON ENERGY CORPORATION
 
                          CONSOLIDATED BALANCE SHEETS
 
<TABLE>
<CAPTION>
                                                                  DECEMBER 31,
                                                              --------------------
                                                                1996        1995
                                                              --------    --------
                                                                 (IN THOUSANDS)
<S>                                                           <C>         <C>
                           ASSETS
Current assets:
  Cash......................................................  $  3,732    $  3,914
  Accounts receivable, less allowance for doubtful accounts
     of $146 ($155 in 1995).................................    12,985       8,859
  Other.....................................................       568       1,096
                                                              --------    --------
          Total current assets..............................    17,285      13,869
                                                              --------    --------
Properties and equipment, at cost (successful efforts
  method)
  Proved properties.........................................   253,419     232,173
  Unproved properties.......................................    24,696       7,314
  Gas plant and gathering system............................     1,478       2,976
  Other.....................................................     6,303       5,612
                                                              --------    --------
                                                               285,896     248,075
          Less accumulated depreciation, depletion and
            amortization....................................   (53,118)    (30,440)
                                                              --------    --------
                                                               232,778     217,635
                                                              --------    --------
Other assets, net...........................................     1,866       3,151
                                                              --------    --------
          Total Assets......................................  $251,929    $234,655
                                                              ========    ========
                       LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
  Accounts payable..........................................  $  6,534    $  4,439
  Other accrued liabilities.................................     1,104         831
  Accrued swap contract liability...........................        --       1,646
  Accrued property taxes payable............................       505         529
  Accrued interest payable..................................       597         341
                                                              --------    --------
          Total current liabilities.........................     8,740       7,786
                                                              --------    --------
Long-term debt..............................................    95,000      88,000
Deferred income taxes.......................................    16,142      10,795
Other deferred liabilities..................................       520         750
Commitments and contingencies
Shareholders' equity:
  Preferred stock, no par value, 10,000 shares authorized,
     none issued and outstanding............................        --          --
  Common Stock, no par value, 100,000 shares authorized,
     19,702 shares issued and outstanding (19,697 in
     1995)..................................................       197         197
  Paid-in capital...........................................   134,541     134,541
  Retained deficit..........................................    (3,211)     (7,414)
                                                              --------    --------
          Total shareholders' equity........................   131,527     127,324
                                                              --------    --------
          Total Liabilities and Shareholders' Equity........  $251,929    $234,655
                                                              ========    ========
</TABLE>
 
                            See accompanying notes.
 
                                       A-3
<PAGE>   28
 
                           HUGOTON ENERGY CORPORATION
 
                     CONSOLIDATED STATEMENTS OF OPERATIONS
 
<TABLE>
<CAPTION>
                                                                 YEAR ENDED DECEMBER 31,
                                                              -----------------------------
                                                               1996       1995       1994
                                                              -------    -------    -------
                                                                     (IN THOUSANDS,
                                                                 EXCEPT PER SHARE DATA)
<S>                                                           <C>        <C>        <C>
Revenues:
  Oil and gas...............................................  $66,292    $35,906    $23,696
  Gas plant.................................................    1,914      1,638      1,945
  Loss on certain gas swap contracts........................       10     (2,712)        --
  Gain (loss) on sale of properties.........................       --       (603)       (11)
                                                              -------    -------    -------
          Total revenues....................................   68,216     34,229     25,630
                                                              -------    -------    -------
Expenses:
  Production
     Lease operations.......................................   16,460      9,214      5,664
     Production and severance tax...........................    3,639      1,974      1,367
     Gathering, transportation and other....................    1,568        382        497
  Gas plant.................................................    1,420        978      1,189
  Exploration...............................................    1,711      2,239      3,036
  General and administrative................................    6,872      4,346      3,117
  Depreciation, depletion and amortization..................   23,423     15,234      8,677
                                                              -------    -------    -------
          Total expenses....................................   55,093     34,367     23,547
                                                              -------    -------    -------
Operating income (loss).....................................   13,123       (138)     2,083
                                                              -------    -------    -------
Other income (expenses):
  Interest..................................................   (6,070)    (5,108)    (3,077)
  Other.....................................................      466        319        252
                                                              -------    -------    -------
          Total other income (expenses).....................   (5,604)    (4,789)    (2,825)
                                                              -------    -------    -------
Income (loss) before income taxes and extraordinary item....    7,519     (4,927)      (742)
(Provision) benefit for income taxes........................   (3,316)     1,394         66
                                                              -------    -------    -------
Income (loss) before extraordinary item.....................    4,203     (3,533)      (676)
Extraordinary item -- loss from early extinguishment of
  debt, net of income tax...................................       --       (136)        --
                                                              -------    -------    -------
Net income (loss)...........................................  $ 4,203    $(3,669)   $  (676)
                                                              =======    =======    =======
Income (loss) per common share:
Income (loss) before extraordinary item.....................  $  0.21    $ (0.26)   $ (0.07)
                                                              =======    =======    =======
Extraordinary item..........................................  $    --    $ (0.01)   $    --
                                                              =======    =======    =======
Net income (loss) per common share..........................  $  0.21    $ (0.27)   $ (0.07)
                                                              =======    =======    =======
Weighted average number of common shares outstanding........   19,698     13,460     10,310
                                                              =======    =======    =======
</TABLE>
 
                            See accompanying notes.
 
                                       A-4
<PAGE>   29
 
                           HUGOTON ENERGY CORPORATION
 
                CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
 
<TABLE>
<CAPTION>
                                                 COMMON STOCK
                                   PREFERRED   ----------------    PAID-IN     RETAINED
                                     STOCK     NUMBER    AMOUNT    CAPITAL     DEFICIT      TOTAL
                                   ---------   ------    ------    -------     --------     -----
                                                            (IN THOUSANDS)
<S>                                <C>         <C>       <C>       <C>         <C>         <C>
YEARS ENDED DECEMBER 31, 1996,
  1995 AND 1994:
BALANCE, DECEMBER 31, 1993.......     --        7,143      $ 71    $ 22,994     $(3,070)   $ 19,995
Proceeds from issuance of common
  stock..........................     --        3,450        35      30,736          --      30,771
Stock options exercised..........     --           13        --         135          --         135
Net loss.........................     --           --        --          --        (675)       (675)
                                     ---       ------      ----    --------     -------    --------
BALANCE, DECEMBER 31, 1994.......     --       10,606       106      53,865      (3,745)     50,226
Issuance of common stock in
  connection with the acquisition
  of Consolidated Oil & Gas,
  Inc............................     --        9,091        91      80,695          --      80,786
Tax effect of stock options
  exercised......................     --           --        --         (19)         --         (19)
Net loss.........................     --           --        --          --      (3,669)     (3,669)
                                     ---       ------      ----    --------     -------    --------
BALANCE, DECEMBER 31, 1995.......     --       19,697       197     134,541      (7,414)    127,324
Stock options exercised..........     --            5        --          40          --          40
Tax effect of stock options
  exercised......................     --           --        --         (40)         --         (40)
Net income.......................     --           --        --          --       4,203       4,203
                                     ---       ------      ----    --------     -------    --------
BALANCE, DECEMBER 31, 1996.......     --       19,702      $197    $134,541     $(3,211)   $131,527
                                     ===       ======      ====    ========     =======    ========
</TABLE>
 
                            See accompanying notes.
 
                                       A-5
<PAGE>   30
 
                           HUGOTON ENERGY CORPORATION
 
                     CONSOLIDATED STATEMENTS OF CASH FLOWS
 
<TABLE>
<CAPTION>
                                                                 YEAR ENDED DECEMBER 31,
                                                              ------------------------------
                                                                1996       1995       1994
                                                              --------   --------   --------
                                                                      (IN THOUSANDS)
<S>                                                           <C>        <C>        <C>
Cash flows from operating activities:
  Net income (loss).........................................  $  4,203   $ (3,669)  $   (676)
Adjustments to reconcile net income (loss) to net cash
  provided by operating activities:
  Extraordinary loss........................................        --        136         --
  Depreciation, depletion, and amortization.................    23,423     15,234      8,677
  Leasehold abandonments....................................       225        886         --
  Deferred income taxes.....................................     3,316     (1,504)        --
  (Gain) loss on sale of proved properties and other
     assets.................................................       (85)       582        (80)
  Gain on sale of marketable securities.....................        --        (73)        --
  Other non-cash charges....................................       230        462         --
Changes in operating assets and liabilities net of effects
  from acquisitions:
  Accounts receivable.......................................    (4,126)    (1,577)     1,138
  Other current assets......................................       528        530       (114)
  Other.....................................................     1,046         99        (15)
  Accounts payable..........................................     2,095        567        967
  Accrued liabilities.......................................       505     (2,452)       284
  Accrued swap contract liability...........................    (1,646)      1646         --
  Deferred liabilities......................................      (230)       500        250
                                                              --------   --------   --------
  Net cash provided by operating activities.................    29,484     11,367     10,431
Cash flows from investing activities:
  Payment for business acquisition, net of cash acquired....        --    (28,799)        --
  Proceeds from sale of proved properties and other
     assets.................................................  7,407...      3,357         --
  Additions to properties and equipment.....................   (44,091)   (22,578)   (25,964)
  Purchase of marketable securities available for sale......        --         --    (11,085)
  Proceeds from sale of marketable securities...............        --     11,158         --
  Purchase of rights relating to operating agreements.......        --         --     (2,000)
  Net change in note receivable.............................       (22)        (7)       (67)
                                                              --------   --------   --------
  Net cash used in investing activities.....................   (36,706)   (36,869)   (39,116)
Cash flows from financing activities:
  Increase in debt issue costs..............................        --       (250)        --
  Proceeds from long-term debt..............................    25,000    113,000     29,500
  Repayment of long-term debt...............................   (18,000)   (85,000)   (32,000)
  Net proceeds from issuance of common stock................        --         --     32,085
  Initial public offering costs paid........................        --         --     (1,037)
  Proceeds from exercised stock options.....................        40         --        135
                                                              --------   --------   --------
  Net cash provided by financing activities.................     7,040     27,750     28,683
                                                              --------   --------   --------
Net increase (decrease) in cash.............................      (182)     2,248         (2)
Cash at beginning of year...................................     3,914      1,666      1,668
                                                              --------   --------   --------
Cash at end of year.........................................  $  3,732   $  3,914   $  1,666
                                                              ========   ========   ========
Supplemental disclosure of cash flow information:
  Interest paid.............................................  $  6,140   $  5,714   $  2,860
  Income taxes paid.........................................        --         38         15
  Common stock issued in connection with the acquisition of
     COG....................................................        --     80,786         --
</TABLE>
 
     During 1996 the Company determined that it was necessary to adjust the
deferred tax liability related oil and gas properties acquired in connection
with the acquisition of COG. The effect of the adjustment was to increase
deferred income tax liability and properties and equipment by $1,991.
 
                            See accompanying notes.
 
                                       A-6
<PAGE>   31
 
                           HUGOTON ENERGY CORPORATION
 
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                       (IN THOUSANDS FOR DOLLAR AMOUNTS)
 
1. ORGANIZATION AND ACCOUNTING POLICIES
 
BASIS OF PRESENTATION
 
     The accompanying statements include the accounts of Hugoton Energy
Corporation and its wholly owned subsidiaries, AmGas, Corporation. (AmGas),
which was formed on December 19, 1991, Hugoton Exploration Corporation (HEX),
which was formed on November 9, 1993, Tiffany Gathering, Inc. (TGI), which was
acquired as a result of the acquisition of Consolidated Oil & Gas, Inc. on
September 7, 1995 and HEC Trading Company (HTC), which was formed December 14,
1995. All significant intercompany accounts and transactions have been
eliminated in consolidation.
 
ORGANIZATION, LINE OF BUSINESS, AND CREDIT CONCENTRATION
 
     Hugoton Energy Corporation (HEC), incorporated April 23, 1987, and its
wholly owned subsidiaries, Amgas, HEX, TGI and HTC, (hereinafter referred to as
the "Company") are engaged in the acquisition of, exploration for and the
development and production of, natural gas and oil. In addition, the Company
owns and operates a gas gathering system and a gas processing plant. The
principal markets for the Company's natural gas and oil production are
Mid-Continent-based oil and gas marketing and crude oil refining companies. The
Company grants credit to certain first purchasers of oil and gas. The Company
also grants credit to certain oil and gas property owners related to lease
operating expenses paid on their behalf by the Company. Such first purchasers
and property owners are principally located in the United States.
 
USE OF ESTIMATES
 
     The preparation of financial statements in conformity with generally
accepted accounting principles, requires management to make certain estimates
and assumptions that affect the amounts reported in the financial statements and
accompanying notes. Actual results could differ from those estimates.
 
HEDGING ACTIVITIES
 
     Commodity Hedges. The Company manages the risk associated with the
fluctuations in the prices of oil and natural gas primarily through short-term
fixed-priced energy swap contracts. Each energy swap contract is designated to
existing natural gas or oil production of the Company and involves the exchange
of amounts based on a fixed commodity price for amounts based on an average of
quoted index prices of the commodity.
 
     Gains and losses from hedging transactions are recognized in income and
reflected in the accompanying statements of cash flows as operating activities
in the periods for which the underlying commodity was hedged (the accrual
accounting method). The fair value of the swap agreements are not recognized in
the financial statements. Gains and losses on terminations of energy swap
contracts are deferred and amortized as an adjustment to income over the
remaining term of the original contract life of the terminated swap agreement.
If the necessary correlation to the commodity being hedged ceases during the
contract period, the basis differential attributable to such contracts is
recognized as a gain or loss and is no longer deferred, but recognized in
current operating results in the period the loss of correlation was identified
(see Note 11).
 
     Interest-Rate Swap Agreement. The Company has also entered into an interest
rate swap agreement to effectively convert a portion of its floating-rate
borrowings into fixed-rate obligations and manage its exposure to interest rate
fluctuations. The accrual accounting method is used and the interest rate
differential to be received or paid is being accrued and recognized as an
adjustment to interest expense related to the debt.
 
                                       A-7
<PAGE>   32
 
                           HUGOTON ENERGY CORPORATION
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
                       (IN THOUSANDS FOR DOLLAR AMOUNTS)
 
OIL AND GAS PROPERTIES
 
     The Company accounts for its oil and gas activities using the successful
efforts method. Under the successful efforts method, all costs incurred to
purchase, lease, or otherwise acquire a property are capitalized when incurred.
Costs to drill and equip all development wells and successful exploratory wells
are capitalized. All other exploration costs including geological and
geophysical costs, lease rentals, impaired acreage costs and the cost of
unsuccessful exploratory wells are charged to expense.
 
     In March 1995, the FASB issued Statement No. 121, Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of,
which requires impairment losses to be recognized for long-lived assets used in
operations when indicators of impairment are present and the undiscounted cash
flows are not sufficient to recover the assets' carrying amount. The impairment
loss is measured by comparing the fair value of the asset to its carrying
amount. The Company elected early adoption of Statement No. 121 in 1995 and,
based on available estimates and current circumstances, has determined that no
impairment loss has occurred during the years ended December 31, 1996 and 1995.
 
     Impairment is recognized for undeveloped properties by providing a
valuation allowance based on such factors as lease term, prior experience and
anticipated plans of the Company to develop the properties.
 
     Depreciation, depletion and amortization of proved properties, wells, and
related equipment is provided on a unit-of-production method based upon
estimated recoverable proved oil and gas reserves.
 
     With respect to normal dispositions, the cost of properties retired or
otherwise disposed of, and the applicable accumulated depreciation, depletion
and amortization are removed from the accounts, and the resulting profit or
loss, if any, is reflected in current operations.
 
OTHER PROPERTY AND EQUIPMENT
 
     Other property and equipment are depreciated by the straight-line method
over the following estimated useful lives:
 
<TABLE>
<S>                                                           <C>
                                                                  31 1/2
Building....................................................       years
Gas plant...................................................    10 years
Vehicles....................................................     3 years
Office furniture and equipment..............................     3 years
</TABLE>
 
DEBT ISSUE COSTS
 
     The debt issue costs which are included in other assets are being amortized
by the straight-line method over the four-year term of the bank revolving note
agreement.
 
RIGHTS RELATED TO OPERATING AGREEMENT
 
     Costs to acquire rights related to operating agreements for which the
Company is the operator of producing properties for unrelated third parties are
included in other assets and are being amortized on a straight-line basis over
the estimated life of the managed properties, which approximates 10 years.
 
OIL AND GAS SALES AND GAS IMBALANCES
 
     Oil and gas revenues are recognized as production and sales take place. The
Company uses the sales method of accounting for gas imbalances in those
circumstances where the Company has underproduced or overproduced its ownership
percentage in a property. Under this method, a liability is recorded to the
extent that the Company's overproduced position in a reservoir cannot be
recouped through the production of
 
                                       A-8
<PAGE>   33
 
                           HUGOTON ENERGY CORPORATION
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
                       (IN THOUSANDS FOR DOLLAR AMOUNTS)
 
remaining reserves. The Company's net overproduced position at December 31, 1996
and 1995 was not significant.
 
EARNINGS PER COMMON SHARE
 
     Earnings per common share are based upon the weighted average number of
common shares outstanding during each period. The weighted average number of
common shares does not include any common stock equivalents because (1) shares
issuable pursuant to options that will be satisfied with shares held by the
principal shareholder are already included in shares outstanding and (2) the
remaining stock options outstanding are not materially dilutive.
 
INCOME TAXES
 
     Deferred tax assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their respective tax
bases. Valuation allowances are established when necessary to reduce deferred
tax assets to the amounts expected to be realized. Deferred tax assets and
liabilities are measured using enacted tax rates expected to apply to taxable
income in the years in which those temporary differences are expected to be
recovered or settled.
 
STOCK BASED COMPENSATION
 
     In October 1995, the FASB issued Statement No. 123, Accounting for
Stock-Based Compensation, which prescribed accounting and reporting standards
for all stock-based compensation plans, including employee stock options,
restricted stock, and stock appreciation rights. Statement No. 123 did not
require companies to change their existing accounting for employee stock options
under APB Opinion No. 25, Accounting for Stock Issued to Employees, but instead
encouraged companies to recognize expense for stock-based awards on their
estimated fair value on the date of grant. Companies electing to continue to
follow present account rules under APB 25 are required to provide pro forma
disclosures of what net income and earnings per share would have been had the
new fair value method been used. The Company has elected to continue to apply
the existing accounting rules contained in APB 25 and the required pro forma
disclosures under the new method have been presented (see Note 7).
 
RECLASSIFICATION
 
     Certain prior year amounts have been classified to conform with the 1996
presentation.
 
2. ACQUISITIONS
 
1996 ACQUISITIONS
 
     On June 20, 1996, the Company purchased a 50% working interest for $12.9
million in approximately 95,000 gross acres in the Austin Chalk Trend in
Louisiana. This acreage acquisition, coupled with the January 1, 1996 acreage
acquisition mentioned below and various acreage acquired in the third quarter,
presents the Company with a total of 148,000 gross acres in the Austin Chalk
Trend to explore.
 
     On January 1, 1996, the Company purchased an undivided interest in a group
of producing oil and gas properties and undeveloped acreage for $9.7 million
from a privately-held company that owns an undivided interest in and operates
the properties. The producing properties and acreage are located in Southeast
Texas and established a presence for the Company in the Austin Chalk trend. The
acquisition included eight producing wells and 35,000 gross acres, of which the
Company's working interest is 25% and 50% respectively.
 
                                       A-9
<PAGE>   34
 
                           HUGOTON ENERGY CORPORATION
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
                       (IN THOUSANDS FOR DOLLAR AMOUNTS)
 
ACQUISITION OF CONSOLIDATED OIL & GAS, INC.
 
     On September 7, 1995, the Company closed its acquisition (effective
September 1, 1995) of Consolidated Oil & Gas, Inc. ("COG"). The acquisition was
financed by cash on hand, bank borrowings under the Company's credit facility
(see Note 4) and by the issuance of 9,090,736 shares of the Company's common
stock.
 
     The acquisition has been accounted for as a purchase and, accordingly, the
acquired underlying assets and liabilities have been recorded at their estimated
fair values at the date of acquisition. The purchase price was allocated to the
assets and liabilities acquired as follows:
 
<TABLE>
<CAPTION>
                                                               (IN THOUSANDS)
<S>                                                            <C>
Cash........................................................         $  9,062
Accounts receivable.........................................            3,595
Other current assets........................................              353
Properties and equipment....................................          118,419
Other assets................................................            1,383
Deferred income tax liabilities.............................          (12,299)
Accrued liabilities.........................................           (1,866)
                                                                     --------
Net allocated fair value of assets..........................         $118,647
Less:
  Value of common stock issued net of offering costs
     incurred of $2,167.....................................          (80,786)
Cash acquired...............................................           (9,062)
                                                                     --------
Cash paid...................................................         $ 28,799
                                                                     ========
</TABLE>
 
     The operations of COG are included in the Company's consolidated financial
statements from the effective date of the acquisition.
 
OTHER 1995 ACQUISITIONS
 
     On June 30, 1995, the Company purchased a group of producing oil and
natural gas properties from Mobil Corporation for $13.6 million of cash. These
properties, which produce predominately natural gas, are located in southwestern
Kansas and the Oklahoma panhandle. The effective date of the acquisition was
July 1, 1995.
 
     The operations of the Mobil acquisition is included in the Company's
consolidated financial statements from the effective date of the acquisition.
 
1994 ACQUISITIONS
 
     During 1994, the Company acquired producing properties, undeveloped acreage
and the rights to operate a group of properties for a total purchase price of
approximately $14 million in three separate acquisitions. The undeveloped
acreage acquired gives the Company a 50% interest in approximately 186,000
undeveloped mineral acres (below the depth of 3,500 feet) in the Kansas Hugoton
Producing Area. One of the acquisitions was a stock purchase with underlying
assets consisting of producing properties and undeveloped acreage. In connection
with a portion of the interests acquired in undeveloped acreage, the Company
entered into a joint exploration agreement for the exploration of this acreage
block with Oxy USA, whereby Oxy was granted a carried interest in certain costs
in the drilling of an agreed upon number of wells (see Note 11). The operations
of the acquisitions are included in the Company's consolidated financial
statements from the effective date of the acquisitions.
 
                                      A-10
<PAGE>   35
 
                           HUGOTON ENERGY CORPORATION
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
                       (IN THOUSANDS FOR DOLLAR AMOUNTS)
 
PRO FORMA RESULTS OF OPERATIONS
 
     The accompanying unaudited pro forma results of operations gives effect to
the COG and Mobil Acquisitions as if the transactions had occurred on January 1,
1994 under the purchase method of accounting. The unaudited pro forma results of
operations data is presented for illustrative purposes and is not necessarily
indicative of the actual results that would have occurred had the acquisitions
been consummated as of January 1, 1994 or of future results of operations. The
data reflects adjustments for (a) the mark to market of open hedging contracts
held by COG at the time of acquisition, (b) the estimated change in general and
administrative expenses giving effect to integration of the administrative
functions of the combined companies, (c) the estimated increase in depreciation,
depletion and amortization relating to the acquisitions, (d) the estimated
increase in interest expense resulting from the increased borrowings relating to
the acquisitions and (e) the estimated provision for income taxes for the change
in income taxes resulting from the inclusion of the historical results of
operations of the acquisitions and the adjustments in (a) through (d) above. The
pro forma effects of the property acquisitions for 1996 are not presented as
such amounts are not significant.
 
<TABLE>
<CAPTION>
                                                                   YEARS ENDED
                                                                   DECEMBER 31,
                                                              ----------------------
                                                                1995         1994
                                                              ---------    ---------
                                                              (IN THOUSANDS, EXCEPT
                                                                 PER SHARE DATA)
<S>                                                           <C>          <C>
Unaudited pro forma information:
  Revenues..................................................    $58,307      $73,002
  Net income (loss) before extraordinary item...............    $(4,239)     $ 4,899
  Net income (loss).........................................    $(4,375)     $ 3,426
  Net income (loss) per share...............................    $  (.22)     $   .17
</TABLE>
 
3. TRANSACTIONS WITH AFFILIATES
 
     The Company accounts for transactions with the Company's Chairman and CEO
for his pro rata share of revenues and expenses in association with his
interests in certain oil and gas prospects he personally has participated in,
since the formation of the Company. The Company believes that the terms of the
principal shareholder's participation are comparable to those by other
non-affiliated working interest owners.
 
4. LONG-TERM DEBT
 
     Long-term debt at December 31, 1996 and 1995, consists of the following:
 
<TABLE>
<CAPTION>
                                                               1996       1995
                                                              -------    -------
                                                                (IN THOUSANDS)
<S>                                                           <C>        <C>
Bank credit facility with a group of seven banks, principal
  payable at September 7, 1999, interest payable at Bank
  One's base rate and LIBOR rates at various Eurodollar
  maturity dates (6.45% to 8.25% at December 31, 1996)......  $95,000    $88,000
                                                              -------    -------
Less current maturities.....................................       --         --
                                                              -------    -------
                                                              $95,000    $88,000
                                                              =======    =======
</TABLE>
 
     On September 7, 1995, the Company arranged a new bank credit facility,
simultaneously with the closing of the COG acquisition. The new facility is an
unsecured $250 million revolving credit agreement that is due September 7, 1999.
The facility is provided by seven banks, led by Bank One, Texas, N.A. ("Bank
One") as agent and Texas Commerce Bank National Association as Co-agent. The
Borrowing Base, as defined in the loan agreement, is currently set at $135
million, and is subject to semi-annual redetermination. In connection
 
                                      A-11
<PAGE>   36
 
                           HUGOTON ENERGY CORPORATION
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
                       (IN THOUSANDS FOR DOLLAR AMOUNTS)
 
with the arrangement of the new bank credit facility, during 1995 the Company
recorded an extraordinary loss of $220 ($136 after income taxes) which
represented the write-off of the related unamortized loan costs.
 
     At December 31, 1996, the Company was a party to one interest rate swap
agreement that was entered into on December 11, 1995 for $25 million in notional
principal amount. The effect of this agreement is to provide the Company with an
interest rate on $25 million in notional principal amount for the three-year
term of the agreement of 5.445% plus a margin of 3/4 of 1 % to 1.25%. Under
market conditions at December 31, 1996, the aggregate effective annual interest
rate after giving effect to the swap agreement was 6.542%.
 
     The credit facility provides the option of borrowing at floating interest
rates based on Bank One's base rate or at a Eurodollar option based on the
London Interbank Offered Rate ("LIBOR") plus 3/4 of 1% to 1.25% per annum,
depending on the outstanding loan balance. Interest is payable quarterly or at
the end of each interest period. The Company also incurs a commitment fee of
 1/4 of 1% on the unused portion of the Borrowing Base.
 
     In addition, the bank credit facility contains restrictive covenants
requiring, among other things, the maintenance of a specified current ratio,
tangible net worth and a limitation of the declaration or payment of dividends
on the Company's stock to 50% of net income for any fiscal year. The Company is
in compliance with these covenants at December 31, 1996.
 
     Principal maturities of long-term debt over the next five years are as
follows (in thousands):
 
<TABLE>
<S>                                                        <C>
1997.....................................................  $    --
1998.....................................................       --
1999.....................................................   95,000
2000.....................................................       --
2001.....................................................       --
                                                           -------
                                                           $95,000
                                                           =======
</TABLE>
 
5. INCOME TAXES
 
     Significant components of the provision (benefit) for income taxes are as
follows:
 
<TABLE>
<CAPTION>
                                                                  DECEMBER 31,
                                                            -------------------------
                                                             1996      1995      1994
                                                            ------    -------    ----
                                                                 (IN THOUSANDS)
<S>                                                         <C>       <C>        <C>
Current:
  Federal.................................................  $   --    $    --    $(66)
  State...................................................      --         --      --
                                                            ------    -------    ----
          Total...........................................      --         --     (66)
Deferred:
  Federal.................................................   2,967     (1,247)     --
  State...................................................     349       (147)     --
                                                            ------    -------    ----
          Total...........................................   3,316     (1,394)     --
                                                            ------    -------    ----
          Total income tax expense (benefit)..............  $3,316    $(1,394)   $(66)
                                                            ======    =======    ====
</TABLE>
 
     Deferred income taxes reflect the net tax effects of temporary differences
between the carrying amounts of assets and liabilities for financial reporting
purposes and the amounts used for income tax purposes. During 1995 and 1994, in
connection with transactions involving the purchase price allocations relating
to acquisitions of businesses, the Company recorded deferred tax liabilities net
of valuation allowance of approximately
 
                                      A-12
<PAGE>   37
 
                           HUGOTON ENERGY CORPORATION
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
                       (IN THOUSANDS FOR DOLLAR AMOUNTS)
 
$12,300 and $650, respectively for the financial statement/tax bases difference
in the underlying assets. Such taxable differences enabled the Company to reduce
its valuation allowance by approximately $999 and $650 in 1995 and 1994,
respectively. The benefit of reducing the valuation allowance was recorded as a
reduction to the property and equipment or intangibles recorded in the
acquisitions in accordance with SFAS No. 109.
 
     Significant components of the Company's deferred tax assets and liabilities
as of December 31, 1996 and 1995 are as follows:
 
<TABLE>
<CAPTION>
                                                               1996       1995
                                                              -------    -------
                                                                (IN THOUSANDS)
<S>                                                           <C>        <C>
Deferred tax assets:
  Compensatory stock option expense.........................  $   309    $   698
  Allowance for doubtful accounts...........................       56         59
  Accrued liabilities.......................................    --            23
  Net operating loss carryforward...........................    7,091      6,002
  Swap contract loss........................................    --           626
  AMT credit carryforward...................................      550        550
                                                              -------    -------
          Net deferred tax assets...........................    8,006      7,958
                                                              -------    -------
Deferred tax liabilities:
  Book basis of oil and gas properties in excess of tax
     basis..................................................   24,148     18,400
  Other.....................................................    --           353
                                                              -------    -------
          Total deferred tax liabilities....................   24,148     18,753
                                                              -------    -------
          Net deferred tax liabilities......................  $16,142    $10,795
                                                              =======    =======
</TABLE>
 
     The reconciliation of income tax expense (benefit) computed at the U.S.
federal statutory tax rates to the actual income tax expense (benefit) is:
 
<TABLE>
<CAPTION>
                                                                 DECEMBER 31,
                                                         ----------------------------
                                                           1996       1995      1994
                                                         --------    -------    -----
                                                                (IN THOUSANDS)
<S>                                                      <C>         <C>        <C>
Income tax expense (benefit) at federal statutory
  rate.................................................  $  2,557    $(1,675)   $(252)
State income taxes, net of federal benefit.............       301       (197)     (45)
Utilization of loss carryback..........................     --            --      (66)
Nondeductible amortization.............................       443         --       --
Various accruals and expenses not deductible for tax...        14        102       --
Valuation allowance....................................     --           376      310
Other..................................................         1         --      (13)
                                                         --------    -------    -----
Actual income tax expense (benefit)....................  $  3,316    $(1,394)   $ (66)
                                                         ========    =======    =====
</TABLE>
 
     At December 31, 1996, the Company had net operating loss carryforwards of
approximately $18,600, which can be carried forward to reduce future federal
income taxes payable. Net operating loss carryforwards expire beginning in 2009
if not utilized.
 
                                      A-13
<PAGE>   38
 
                           HUGOTON ENERGY CORPORATION
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
                       (IN THOUSANDS FOR DOLLAR AMOUNTS)
 
6. PREFERRED STOCK
 
     The Company has authorized a class of undesignated preferred stock
consisting of 10,000,000 shares, none of which are issued and outstanding. The
Board of Directors has not determined the rights and privileges of holders of
such preferred stock and the Company has no present plans to issue any shares of
preferred stock.
 
7. STOCK OPTIONS
 
     The Company has various stock plans (the "Plans") whereby options to
purchase shares of common stock have been or may be granted to officers,
employees, and non-employee directors. The vesting periods and expiration of
options are determined on a plan by plan, or grant by grant basis. Expiration
dates of the options outstanding at December 31, 1996, range from July 25, 1997
to October 24, 2002.
 
     In 1993 the Company adopted an employee stock option plan and a Nonemployee
Directors stock option plan which was amended during 1996 that provide for the
issuance of incentive and non-qualified options to purchase common stock. The
employee stock option plan provides for the issuance of up to 600,000 shares and
the Nonemployee Director plan provides for the issuance of up to 150,000 shares.
 
     In 1995 the Company and its shareholders approved the 1995 Stock Option
Plan for employees whereby 500,000 shares were reserved for issuance.
 
     The Company has elected to follow Accounting Principles Board Opinion No.
25, "Accounting for Stock Issued to Employees" (APB 25) and related
Interpretations in accounting for its employee stock options because, as
discussed below, the alternative fair value accounting provided for under FASB
Statement No. 123, "Accounting For Stock-Based Compensation," requires use of
option valuation models that were not developed for use in valuing employee
stock options. Under APB 25, because the exercise price of the Company's
employee stock options equals the market price of the underlying stock on the
date of grant, no compensation expense is recognized.
 
     The following is a summary of stock option activity, and related
information for the years ended December 31, 1996, 1995, and 1994:
 
<TABLE>
<CAPTION>
                                              EMPLOYEE                  NON-EMPLOYEE
                                      -------------------------   ------------------------
                                      NUMBER OF    PRICE RANGE    NUMBER OF   PRICE RANGE
                                       SHARES       PER SHARE      SHARES      PER SHARE
                                      ---------   -------------   ---------   ------------
<S>                                   <C>         <C>             <C>         <C>
Outstanding, December 31, 1993......    579,852     $.10- 10.00     75,000          $10.00
  Stock options granted.............     10,000           11.50     20,000           12.25
  Stock options exercised...........    (39,085)     .10- 10.00         --
  Stock options expired or
     canceled.......................         --                         --
                                      ---------                    -------
Outstanding, December 31, 1994......    550,767      .10- 11.50     95,000     10.00-12.25
  Stock options granted.............    582,500     8.00-9.0938      4,000            8.41
  Stock options exercised...........   (101,190)            .10         --              --
  Stock options expired or
     canceled.......................    (53,000)    8.00- 10.00     (6,000)     8.41-12.25
                                      ---------                    -------
Outstanding, December 31, 1995......    979,077      .10- 11.50     93,000      8.41-12.25
  Stock options granted.............    339,000    7.125-  8.50     40,000            8.75
  Stock options exercised...........   (115,890)     .10-  8.00         --              --
  Stock options expired or
     canceled.......................   (112,500)   7.125- 11.50         --              --
                                      ---------                    -------
Outstanding, December 31, 1996......  1,089,687     $.10- 11.50    133,000     $8.41-12.25
                                      =========                    =======
</TABLE>
 
                                      A-14
<PAGE>   39
 
                           HUGOTON ENERGY CORPORATION
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
                       (IN THOUSANDS FOR DOLLAR AMOUNTS)
 
<TABLE>
<S>                                    <C>        <C>           <C>        <C>
Exercisable at December 31,
  1994...............................   59,500    $.10-11.50     27,500    $10.00-12.25
  1995...............................  316,900    $.10-11.50     55,500      8.41-12.25
  1996...............................  470,350     .10-11.50    125,500      8.41-12.25
</TABLE>
 
     Stock options granted during 1996 include 125,000 shares at a price of
$8.34 to an officer which have been approved by the Board of Directors, but are
subject to approval by the Company's shareholders.
 
     At December 31, 1996, 1995 and 1994, there were 96,148, 162,648, and 65,148
shares, respectively, reserved for future grants under existing plans.
 
     Pursuant to the 1993 Stock Option Plan, a principal shareholder entered
into an agreement with the Company whereby, upon any exercise of an outstanding
option with a $.10 exercise price, he will deliver to the Company the number of
shares to which the optionee is entitled to such exercise and the Company will
pay to the principal shareholder the exercise price paid for such shares by the
optionee. This agreement does not pertain to any future options granted under
the Plan.
 
     Additionally, the principal shareholder entered into an agreement with the
Company, whereby, upon the exercise of certain of the non-employee stock options
at $10 per share (which were not granted under the 1993 Stock Option Plan), he
will deliver to the Company the number of shares to which the optionee is
entitled pursuant to such exercise and the Company will pay to the principal
shareholder the exercise price paid for such shares by the optionee.
 
     At December 31, 1996 the number of shares subject to options which will be
delivered to the Company by the Company's Chairman and CEO are as follows:
 
<TABLE>
<CAPTION>
OPTION              NUMBER OF
PRICE                SHARES
------              ---------
<C>                 <C>
 $ .10                 88,185
 10.00                 75,000
</TABLE>
 
FAS 123 PRO FORMA INFORMATION
 
     Pro forma information regarding net income and earnings per share is
required by Statement 123 which also requires that the information be
determined, as if the Company had accounted for its employee stock option
granted subsequent to December 31, 1994 under the fair value method of that
Statement. The fair value for these options was estimated at the date of grant
using a Black-Scholes option pricing model with the following range of
assumptions for 1996 and 1995:
 
<TABLE>
<CAPTION>
                                                                1996          1995
                                                             ----------    ----------
<S>                                                          <C>           <C>
Expected life of options (years)...........................         2-4           2-4
Expected stock price volatility............................       .316%         .316%
Risk-free interest rate....................................  5.13-5.30%    5.68-6.11%
</TABLE>
 
     The range of assumptions for the expected life and the interest rate is
caused by the separation of the grants into portions based on their vesting
terms.
 
     The Black-Scholes option valuation model was developed for use in
estimating the fair value of traded options which have no vesting restrictions
and are fully transferable. In addition, option valuation models require the
input of highly subjective assumptions including the expected stock price
volatility. Because the Company's employee stock options have characteristics
significantly different from those of traded options, and because changes in the
subjective input assumptions can materially affect the fair value estimated, in
 
                                      A-15
<PAGE>   40
 
                           HUGOTON ENERGY CORPORATION
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
                       (IN THOUSANDS FOR DOLLAR AMOUNTS)
 
management's opinion, the existing models do not necessarily provide a reliable
single measure of the fair value of its employee stock options.
 
     For purposes of pro forma disclosures, the estimated fair value of the
options is amortized to expense over the options' vesting period. The Company's
pro forma information follows:
 
<TABLE>
<CAPTION>
                                                                1996          1995
                                                              ---------    ----------
                                                                  (IN THOUSANDS,
                                                              EXCEPT PER SHARE DATA)
<S>                                                           <C>          <C>
Net income (loss) -- as reported............................     $4,203       $(3,669)
Net income (loss) -- pro forma..............................     $3,505       $(4,195)
Earnings (loss) per share -- as reported....................     $  .21       $  (.27)
Earnings (loss) per share -- pro forma......................     $  .18       $  (.31)
</TABLE>
 
     Because Statement 123 is applicable only to options granted subsequent to
December 31, 1994, its pro forma effect will not be fully reflected until 1997.
 
     The weighted-average remaining contractual life of options outstanding as
of December 31, 1996, 1995, and 1994 were 3.0 years, 3.3 years, and 3.3 years
respectively. The weighted-average option exercise price information for the
years 1996, 1995, and 1994 follows:
 
<TABLE>
<CAPTION>
                                                               1996        1995        1994
                                                               ----        ----        ----
<S>                                                          <C>         <C>         <C>
Outstanding January 1......................................    $7.35       $5.49      $5.07
Stock options granted......................................    $8.15       $8.39      $12.00
Stock options exercised....................................    $.44        $.10       $3.52
Stock options expired or canceled..........................    $9.94       $9.74      $  --
Outstanding, December 31...................................    $8.00       $7.35      $5.49
Exercisable at December 31.................................    $8.03       $8.38      $9.76
Weighted-average fair value of options granted during the
  year.....................................................    $2.23       $2.20
</TABLE>
 
8. EMPLOYEE BENEFIT PLANS
 
     During 1994, the Company adopted a qualified 401(k) Profit Sharing Plan
which permits eligible employees to defer up to 10% of their compensation. The
Company may make matching contributions related to an employee's deferral on a
discretionary basis.
 
     Prior to the adoption of the qualified 401(k) Profit Sharing Plan, the
Company had a discretionary profit sharing plan. During the years ended December
31, 1996, 1995 and 1994, the Company incurred expenses of $215,786, $138,277 and
$25,345, respectively, related to these plans.
 
                                      A-16
<PAGE>   41
 
                           HUGOTON ENERGY CORPORATION
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
                       (IN THOUSANDS FOR DOLLAR AMOUNTS)
 
9. OIL AND GAS PROPERTY COSTS
 
     Capitalized costs relating to the Company's oil and gas producing
activities and the related amounts of accumulated depreciation, depletion and
amortization are shown below (in thousands):
 
<TABLE>
<CAPTION>
                                                               DECEMBER 31,
                                                     --------------------------------
                                                       1996        1995        1994
                                                     --------    --------    --------
<S>                                                  <C>         <C>         <C>
Proved properties..................................  $253,419    $232,173    $ 97,382
Unproved properties................................    24,696       7,314       9,104
                                                     --------    --------    --------
          Total property costs.....................   278,115     239,487     106,486
Accumulated depreciation, depletion and
  amortization.....................................   (49,921)    (28,377)    (15,038)
                                                     --------    --------    --------
          Net property costs.......................  $228,194    $211,110    $ 91,448
                                                     ========    ========    ========
</TABLE>
 
     Costs incurred (all of which were incurred in the United States) in the
Company's oil and gas activities were as follows (in thousands):
 
<TABLE>
<CAPTION>
                                                                DECEMBER 31,
                                                       ------------------------------
                                                        1996        1995       1994
                                                       -------    --------    -------
<S>                                                    <C>        <C>         <C>
Acquisition of Properties:
  Proved.............................................  $ 5,355    $129,962    $ 5,092
  Unproved...........................................   17,382       1,526      8,795
Exploration..........................................    9,168       5,530      7,644
Development..........................................    7,756       2,313      3,589
                                                       -------    --------    -------
                                                       $39,661    $139,331    $25,120
                                                       =======    ========    =======
</TABLE>
 
10. MAJOR CUSTOMERS
 
     The Company markets its oil and gas production to numerous purchasers under
a combination of short-and long-term contracts. During 1996, 1995 and 1994, the
Company's largest three purchasers accounted for 38%, 55% and 60%, respectively,
of oil and gas revenues of the Company. The Company had no other purchasers that
accounted for greater than 10% of its oil and gas revenues. The Company believes
that the loss of any single customer would not have a material adverse effect on
the results of operations of the Company.
 
11. COMMITMENTS AND CONTINGENCIES
 
LEGAL CONTINGENCIES
 
     The Company is not a defendant in any significant pending legal proceedings
other than routine litigation incidental to its business. While the ultimate
results of these proceedings cannot be predicted with certainty, the Company
does not believe that the outcome of these matters will have a material adverse
effect on the Company.
 
                                      A-17
<PAGE>   42
 
                           HUGOTON ENERGY CORPORATION
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
                       (IN THOUSANDS FOR DOLLAR AMOUNTS)
 
LEASE AGREEMENTS
 
     The Company leases office facilities under noncancellable operating leases.
Future minimum rental commitments as of December 31, 1996 are as follows:
 
<TABLE>
<CAPTION>
                            YEAR                                AMOUNT
                            ----                                ------
                                                                 (IN
                                                                THOUSANDS)
<S>                                                             <C>
1997........................................................    $  459
1998........................................................       459
1999........................................................       459
2000........................................................       459
2001........................................................       459
Thereafter..................................................     1,864
                                                                ------
          Total.............................................    $4,159
                                                                ======
</TABLE>
 
     Approximately $520 of such rental commitments is included in Other Deferred
Liabilities as of December 31, 1996.
 
DRILLING OBLIGATION
 
     During 1994, the Company entered into an agreement with Oxy USA whereby a
carried interest for certain costs of drilling a specified number of wells would
be borne by the Company. The carried interest arose in connection with the
acquisition of rights to certain undeveloped acreage acquired from OXY USA (see
Note 2). In order to maintain its acquired rights in the undeveloped acreage,
the Company was obligated to drill 20 wells by September 1, 1995 and 20
additional wells by January 1, 1997. The Company satisfactorily complied with
both the September 1, 1995 and January 1, 1997 drilling obligation.
 
HEDGING TRANSACTIONS
 
     With the objective of achieving more predictable revenues and cash flows
and reducing the exposure to fluctuation in gas and oil prices, the Company has
entered into hedging transactions of various kinds with respect to both gas and
oil. While the use of these hedging arrangements limits the downside risk of
adverse price movements, it may also limit future revenues from favorable price
movements. As of December 31, 1996, the Company had entered into hedging
transactions with respect to a portion of its estimated production for 1997. The
Company continues to evaluate whether to enter into additional hedging
transactions for future years. In addition, the Company may determine from time
to time to terminate its then existing hedging positions. Generally, either the
Company or the counter party to the agreements is required to make a settlement
payment to the other equal to the difference between the specified contract
amount and the settlement amount. The following is a summary of the Company's
hedging transactions in effect as of December 31, 1996 and 1995:
 
          Natural Gas -- at December 31, 1996, the Company had entered into a
     formal sale contract for 20 MMcf of natural gas per day for the first three
     months of 1997 at a net price of $3.68 per Mcf.
 
          At December 31, 1995, the Company was a party to natural gas swap
     agreements which ran from November 1995 through October 1996 NYMEX natural
     gas futures contract month for a quantity of 39,000 MMBTU per day at an
     average price of $1.80 per MMBTU.
 
          Oil -- at December 31, 1996, the Company was a party to swap
     agreements fixing the price of 70,000 barrels per month, for the first
     three months of its oil production for 1997 at a weighted average price of
     $24.25/barrel.
 
                                      A-18
<PAGE>   43
 
                           HUGOTON ENERGY CORPORATION
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
                       (IN THOUSANDS FOR DOLLAR AMOUNTS)
 
          At December 31, 1995, the Company was a party to oil swap agreements
     which ran from the January 1996 through December 1996 NYMEX WTI crude oil
     futures contract month for a quantity of 40,000 barrels per month at an
     average price of $17.28 per BBL.
 
     During 1995, though its acquisition of COG, the Company assumed certain
hedge contract obligations for crude oil futures. The crude oil futures
obligation was comprised of several swap agreements with fixed prices ranging
from $18.00 to $20.80 per BBL on an aggregate volume of 40,000 to 100,000 BBLS
per month. Of the assumed contracts, only two remained in effect at December 31,
1995, representing a total of 40,000 BBLS at a price range of $18.00 to $20.80
per BBL. Differences between the monthly amortization and the contract
settlement amount was reflected in the Company's oil and gas revenues.
 
     The Company is required to post margin in the form of cash when projected
commodity prices exceed the scheduled fixed prices in the contract less any
amount of agreed upon open credit. The amount of margin cash posted at December
31, 1996 and 1995 was $-0- and $325 respectively.
 
     In 1995, a realized hedging loss of $250 was included in oil and gas sales.
The Company had net deferred losses of $1,283 for settled derivative contracts
at December 31, 1995, relative to future production periods. During 1995, the
Company recorded a charge to earnings of $2.7 million related to the
"decoupling" of the basis correlation between the Company's cash price and NYMEX
contract settlement price.
 
     In 1996, a realized hedging loss of $8,698 was included in oil and gas
sales. The Company had no deferred gain or losses at December 31, 1996.
 
12. FINANCIAL INSTRUMENTS
 
     The following information is provided regarding the estimated fair value of
certain on and off-balance sheet financial instruments employed by the Company
as of December 31, 1996 and the methods and assumptions used to estimate the
fair value of such financial instruments:
 
<TABLE>
<CAPTION>
                                               DECEMBER 31, 1996      DECEMBER 31, 1995
                                              -------------------    -------------------
                                              CARRYING     FAIR      CARRYING     FAIR
                                               AMOUNT      VALUE      AMOUNT      VALUE
                                              --------    -------    --------    -------
                                                            (IN THOUSANDS)
<S>                                           <C>         <C>        <C>         <C>
Fixed-price natural gas energy swaps........  $    --     $    --    $ (1,646)   $(1,349)
Fixed-price crude oil swaps.................       --        (251)         --        301
Long-term debt (1)..........................   95,000      95,000      88,000     88,000
Interest rate swaps.........................       --          59          --        158
</TABLE>
 
---------------
 
(1) Carrying amount does not include capitalized debt issue costs (see Note 1).
 
     Cash, accounts receivable, other current assets, accounts payable and
accrued liabilities are each estimated to have a fair value approximating
carrying amount due to the short maturity of those instruments, or to the
criteria used to determine carrying value in the financial instruments.
 
     The "fair value" of the Company's fixed-price natural gas and crude oil
swaps as of December 31, 1995 were estimated based on quoted market prices of
natural gas and crude oil for the periods covered by the contracts. The net
differential between the fixed prices in each contract and the quoted market
prices for future periods, as adjusted for estimated basis, has been applied to
the volumes covered by each contract to arrive at an estimated future value.
 
     The fair value of the Company's long-term debt is estimated to approximate
the carrying amount at December 31, 1996.
 
                                      A-19
<PAGE>   44
 
                           HUGOTON ENERGY CORPORATION
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
                       (IN THOUSANDS FOR DOLLAR AMOUNTS)
 
     The fair value of the Company's interest rate swap at December 31, 1996 is
based on quoted market prices as of such dates.
 
13. ADDITIONAL CASH FLOW INFORMATION
 
     For purposes of cash flows, the Company considers cash to include currency
on hand and demand deposits with banks or other financial institutions.
 
14. INITIAL PUBLIC OFFERING
 
     On January 25, 1994, the Company sold 3,450,000 shares of common stock in
an initial public offering for proceeds of approximately $32 million, exclusive
of offering costs. The Company used the proceeds to pay down borrowings on its
bank credit facility. Supplemental loss per share would be $0.05 giving affect
to the public offering as if it had occurred January 1, 1994 with the proceeds
of the offering used to retire debt. For the computation, shares issued in the
public offering were included in the weighted average shares outstanding from
the beginning of the year end and, accordingly, the net loss was reduced by the
interest expense on the debt retired.
 
15. YEAR-END ADJUSTMENTS
 
     The aggregate effect of adjustments recorded in the fourth quarter of 1995
and 1994, had the effect of increasing the net loss and decreasing the net loss
by approximately $783 and $534, respectively. The principal adjustment was
related to revisions of previous estimates of depreciation, depletion and
amortization of proved properties as a result of revisions to the underlying oil
and gas reserves.
 
                                      A-20
<PAGE>   45
 
                           HUGOTON ENERGY CORPORATION
 
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                      SUPPLEMENTAL OIL AND GAS INFORMATION
                                  (UNAUDITED)
 
OIL AND GAS RESERVES
 
     The following information summarizes the Company's net proved reserves of
oil and natural gas and the present values thereof for each of the three years
ended December 31, 1996. The December 31, 1994, 1995 and 1996 reserve estimates
were based on the reports by the independent engineering firm of Ryder Scott
Company. All studies have been prepared in accordance with regulations
prescribed by the Securities and Exchange Commission. Future net revenue is
estimated by such engineers using oil and gas prices in effect as the end of
each respective year with price escalations permitted only for those properties
which have contracts allowing specific increases. Future operating costs are
based on the level of operating expenses incurred during each such year. The
reliability of any reserve estimate is a function of the quality of available
information and of engineering interpretation and judgment. Such estimates are
susceptible to revision in light of subsequent drilling and production history
or as a result of economic conditions.
 
     Estimated Quantities of Oil and Gas Reserves (unaudited). The following
table sets forth the Company's estimated proved reserves for each of the three
years ended December 31, 1995. All of the Company's reserves are located within
the United States:
 
<TABLE>
<CAPTION>
                                            1996                1995                1994
                                      -----------------   -----------------   -----------------
                                        OIL       GAS       OIL       GAS       OIL       GAS
                                      (MBBLS)   (MMCF)    (MBBLS)   (MMCF)    (MBBLS)   (MMCF)
                                      -------   -------   -------   -------   -------   -------
<S>                                   <C>       <C>       <C>       <C>       <C>       <C>
PROVED RESERVES
Beginning of year...................  13,884    192,962    4,982    139,694     3,035   138,512
Acquisition of proved reserves......      49      4,829    9,923     60,564       222     8,669
Extensions and discoveries..........   4,489     45,199      401      3,093       803     5,278
Revisions of previous estimates.....    (106)     4,293     (391)     8,733     1,291      (274)
Sales of reserves in place..........    (438)    (3,076)     (13)    (4,471)       --        --
Production..........................  (1,700)   (19,026)  (1,018)   (14,651)     (369)  (12,491)
                                      ------    -------   ------    -------   -------   -------
End of year.........................  16,178    225,181   13,884    192,962     4,982   139,694
                                      ======    =======   ======    =======   =======   =======
PROVED DEVELOPED PRODUCING RESERVES
Beginning of year...................  12,746    189,434    4,745    132,230     2,844   117,064
                                      ======    =======   ======    =======   =======   =======
End of year.........................  11,200    180,610   12,746    189,434     4,745   132,230
                                      ======    =======   ======    =======   =======   =======
</TABLE>
 
                                      A-21
<PAGE>   46
 
                           HUGOTON ENERGY CORPORATION
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
                      SUPPLEMENTAL OIL AND GAS INFORMATION
                                  (UNAUDITED)
 
     Standardized Measure of Discounted Future Net Cash Flows (unaudited). The
following table reflects the standardized measure of discounted future net cash
flows relating to the Company's interests in proved oil and gas reserves. The
future net cash inflows were developed as follows:
 
     (1) Estimates were made of quantities of proved reserves and the future
         period during which they are expected to be produced based on year-end
         economic conditions.
 
     (2) The estimated cash flows from future production of proved reserves were
         prepared on the basis of prices received at December 31, 1996, 1995,
         1994, as follows: 1996-$24.53 per BBL, $3.79 per MCF; 1995-$18.01 per
         BBL, $1.76 per MCF; and 1994-$15.56 per BBL, $1.25 per MCF.
 
     (3) The resulting future gross revenue streams were reduced by estimated
         future costs to develop and to produce the proved reserves, based on
         year-end cost estimates.
 
     (4) Future income taxes were computed by applying the appropriate statutory
         tax rates to the future pre-tax net cash flows less the current tax
         basis of the properties involved and related carryforwards, giving
         effect to permanent differences and tax credits.
 
     (5) The resulting future net revenue streams were reduced to present value
         amounts by applying a 10% discount factor.
 
<TABLE>
<CAPTION>
                                                         YEAR ENDED DECEMBER 31,
                                                    ---------------------------------
                                                       1996        1995        1994
                                                    ----------   ---------   --------
                                                             (IN THOUSANDS)
<S>                                                 <C>          <C>         <C>
Future cash inflows...............................  $1,267,988   $ 583,236   $250,584
Future costs:
  Production......................................     354,996     233,098    103,471
  Development.....................................      44,120       3,779      2,015
                                                    ----------   ---------   --------
Future net cash flows before income taxes.........     868,872     346,359    145,098
Discount at 10% per annum.........................    (404,432)   (154,853)   (64,169)
Discounted future income taxes....................    (129,004)    (18,256)      (847)
                                                    ----------   ---------   --------
Standardized measure of discounted future net cash
  flows...........................................  $  335,436   $ 173,250   $ 80,082
                                                    ==========   =========   ========
</TABLE>
 
                                      A-22
<PAGE>   47
 
                           HUGOTON ENERGY CORPORATION
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
                      SUPPLEMENTAL OIL AND GAS INFORMATION
                                  (UNAUDITED)
 
     The following are the principal sources of change in the standardized
measure of discounted future net cash flows:
 
<TABLE>
<CAPTION>
                                                          YEAR ENDED DECEMBER 31,
                                                      -------------------------------
                                                        1996        1995       1994
                                                      ---------   --------   --------
                                                              (IN THOUSANDS)
<S>                                                   <C>         <C>        <C>
Standardized measure of discounted future net cash
  flows, beginning of period........................  $ 173,250   $ 80,082   $ 84,116
Net changes in prices and production costs..........    169,025     27,837    (18,820)
Revisions in quantity estimates.....................     10,507     (6,057)     2,905
Accretion in discount...............................     19,151      8,093      8,860
New field discoveries and extensions, net of future
  production and development costs..................    120,561      7,173     11,105
Purchases of reserves in-place......................      9,648    101,430      5,199
Sales of reserves in-place..........................     (2,634)    (2,904)        --
Sales of oil and gas produced, net of production
  costs.............................................    (53,323)   (24,995)   (16,924)
Net change in income taxes..........................   (110,749)   (17,409)     3,641
                                                      ---------   --------   --------
Standardized measure of discounted future net cash
  flows, end of period..............................  $ 335,436   $173,250   $ 80,082
                                                      =========   ========   ========
</TABLE>
 
                                      A-23
<PAGE>   48
 
                                                                     SCHEDULE II
 
                           HUGOTON ENERGY CORPORATION
 
                       VALUATION AND QUALIFYING ACCOUNTS
                                 (IN THOUSANDS)
 
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------
                                                   BALANCE AT                               BALANCE AT
                                                   BEGINNING                                  END OF
                   DESCRIPTION                     OF PERIOD     ADDITIONS    DEDUCTIONS      PERIOD
------------------------------------------------------------------------------------------------------
<S>                                                <C>           <C>          <C>           <C>
Year ended December 31, 1996:
  Allowance for doubtful accounts................     $155         $ --         $  (9)         $146
Year ended December 31, 1995:
  Allowance for doubtful accounts................      159           --(B)         (4)          155
  Valuation allowance for deferred tax assets....      623          376          (999)           --
Year ended December 31, 1994:
  Allowance for doubtful accounts................      326           --          (167)          159
  Valuation allowance for deferred tax assets....      963          310(A)       (650)          623
</TABLE>
 
---------------
 
(A) During 1994, in connection with a stock acquisition, the Company recorded a
    deferred tax liability of $650,000 for the financial statement/tax bases
    difference in the underlying assets. Such taxable differences enabled the
    Company to reduce its valuation allowance by the same amount. The benefit of
    reducing the valuation allowance was recorded as a reduction to the
    intangibles recorded in the acquisition in accordance with SFAS 109.
 
(B) At December 31, 1995, the Company decreased its valuation allowance to zero
    as a result of the Company's acquisition of COG, whereby the allocated value
    of the acquired assets exceeded the historical tax basis by an amount which
    will enable the Company to realize the deferred assets recorded.
 
                                      A-24
<PAGE>   49
 
                               INDEX TO EXHIBITS
 
<TABLE>
<C>                      <S>
           2.1           -- Agreement and Plan of Merger, dated May 26, 1995, by and
                            among Hugoton Energy Corporation, Oil & Gas, Inc. and
                            Hugoton Exploration Corporation (Incorporated by
                            reference to Exhibit 4.4 of the Registration Statement on
                            Form S-3, Registration No. 33-97366)
           2.2           -- Amendment to Agreement and Plan of Merger, dated August
                            3, 1995 by and among Hugoton Energy Corporation,
                            Consolidated Oil & Gas, Inc. and Hugoton Exploration
                            Corporation (Incorporated by reference to Exhibit 4.4 of
                            the Registration Statement on Form S-3, Registration No.
                            33-97366)
           3.1           -- Restated Articles of Incorporation of the Company, as
                            amended (Incorporated by reference to Exhibit 3.1 of the
                            Registration Statement on Form S-1, Registration No.
                            33-70924)
           3.2           -- Bylaws of the Company, as amended (Incorporated by
                            reference to Exhibit 3.2 of the Registration Statement on
                            Form S-1, Registration No. 33-70924)
           4.1           -- Specimen Common Stock certificate (Incorporated by
                            reference to Exhibit 4.1 of the Registration Statement on
                            Form S-1, Registration No. 33-70924)
          10.1           -- Employment Agreement, dated September 1, 1995 between the
                            Company and Floyd C. Wilson (Incorporated by reference to
                            Exhibit 10.1 of the Company's 1995 Annual Report on Form
                            10-K)
          10.2*          -- Employment Agreement, dated September 7, 1995 between the
                            Company and Jay W. Decker
          10.3*          -- Employment Agreement, dated December 16, 1996 between the
                            Company and W. Mark Womble
          10.4           -- 1993 Stock Option Plan (Incorporated by reference to
                            Exhibit 10.12 of the Registration Statement on Form S-1,
                            Registration No. 33-70924)
          10.5           -- 401(k) Employee Benefit Plan (Incorporated by reference
                            to Exhibit 10.13 of the Registration Statement on Form
                            S-1, Registration No. 33-70924)
          10.6           -- Nonemployee Directors' Stock Option Plan (Incorporated by
                            reference to Exhibit 10.14 of the Registration Statement
                            on Form S-1, Registration No. 33-70924)
          10.7           -- 1995 Stock Option Plan (Incorporated by reference to
                            Exhibit 4.1 of the Registration Statement on Form S-8,
                            Registration No. 33-97092)
          10.8           -- Loan Agreement, dated September 7, 1995, by and among the
                            Company, Amgas Corporation, Hugoton Exploration
                            Corporation, Tiffany Gathering Inc., Bank One, Texas
                            N.A., Texas Commerce Bank National Association, Bank of
                            Montreal, Wells Fargo Bank, National Association,
                            Meespierson N.V., Credit Lyonnais Cayman Island Branch
                            and Bank of Scotland, and Bank One, Texas N.A. as Agent,
                            and Texas Commerce Bank National Association as Co-agent
                            (Incorporated by reference to Exhibit 10.8 of the
                            Company's 1995 Annual Report on Form 10-K)
          10.9           -- First Amendment to Loan Agreement dated January 22, 1996,
                            by and among the Company, Amgas Corporation, Hugoton
                            Exploration Corporation, HEC Trading Company, Tiffany
                            Gathering, Inc., Bank One, Texas N.A., Texas Commerce
                            Bank National Association, Bank of Montreal, Wells Fargo
                            Bank, National Association, Meespierson N.V., Credit
                            Lyonnais Cayman Island Branch and Bank of Scotland, and
                            Bank One, Texas N.A. as Agent, and Texas Commerce Bank
                            National Association as Co-agent (Incorporated by
                            reference to Exhibit 10.9 of the Company's 1995 Annual
                            Report on Form 10-K)
</TABLE>
<PAGE>   50
<TABLE>
<S>                      <C>
          10.10*         -- Second Amendment to Loan Agreement dated June 11, 1996,
                            by and among the Company, Amgas Corporation, Hugoton
                            Exploration Corporation, HEC Trading Company, Tiffany
                            Gathering, Inc., Bank One, Texas N.A., Texas Commerce
                            Bank National Association, Bank of Montreal, Wells Fargo
                            Bank, National Association, Meespierson N.V., Credit
                            Lyonnais Cayman Island Branch and Bank of Scotland, and
                            Bank One, Texas N.A. as Agent, and Texas Commerce Bank
                            National Association as Co-Agent
          10.11          -- Purchase and sale agreement dated June 1, 1995 by and
                            between Mobil Oil Corporation and the Company
                            (Incorporated by reference to Exhibit 10.10 of the
                            Company's 1995 Annual Report on Form 10-K)
          10.12          -- Shareholder Agreement dated May 26, 1995, by and among
                            the Company, Consolidated Oil & Gas, Inc. and Odyssey
                            Partners, L.P. (Incorporated by reference to Exhibit
                            10.11 of the Company's 1995 Annual Report on Form 10-K)
          10.13          -- Agreement of Shareholders dated September 7, 1995, by and
                            among the Company, First Reserve Fund V, Limited
                            Partnership, First Reserve Secured Energy Assets Fund,
                            Limited Partnership, American Gas & Oil Investors,
                            Limited Partnerships, AmGO II, Limited Partnership, AmGO
                            III, Limited Partnership, J. W. Decker, COMDISCO, Inc.,
                            Odyssey Partners, L. P. and Floyd C. Wilson (Incorporated
                            by reference to Exhibit 10.12 of the Company's 1995
                            Annual Report on Form 10-K)
          10.14          -- Registration Rights Agreement dated September 7, 1995, by
                            and among the Company Hugoton Energy Corporation, Odyssey
                            Partners, L.P., Cramer, Rosenthal, McGlynn, Inc.,
                            American Gas & Oil Investors, AmGO II, AmGO III, First
                            Reserve Secured Energy Assets Fund, First Reserve Fund V,
                            COMDISCO, Inc. and Floyd C. Wilson (Incorporated by
                            reference to Exhibit 10.13 of the Company's 1995 Annual
                            Report on Form 10-K)
          10.15*         -- Purchase and Sale Agreement dated December 28, 1995 by
                            and between Shield Petroleum Incorporated, P&M Properties
                            and the Company
          10.16*         -- Purchase and Sale Agreement dated June 18, 1996 by and
                            between Shield Petroleum Incorporated and the Company
          21.1           -- List of subsidiaries of the Company (Incorporated by
                            reference to Exhibit 21.1 of the Company's 1995 Annual
                            Report on Form 10-K)
          23.1*          -- Consent of Ernst & Young LLP
          23.2*          -- Consent of Ryder Scott Company

---------------
</TABLE>
 
* Filed herewith