<PAGE>   1
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                       SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D. C. 20549

                                    FORM 10-K

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

                  FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000

                           COMMISSION FILE NO. 0-20998

                              KELLEY PARTNERS 1992
                          DEVELOPMENT DRILLING PROGRAM
             (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)

                  TEXAS                                  76-0373428
    (STATE OR OTHER JURISDICTION OF         (I.R.S. EMPLOYER IDENTIFICATION NO.)
     INCORPORATION OR ORGANIZATION)

           601 JEFFERSON ST.
              SUITE 1100
             HOUSTON, TEXAS                                 77002
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)                  (ZIP CODE)

       REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (713) 652-5200

           SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

                                      None
                                (TITLE OF CLASS)

           SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:

                 Units of Limited and General Partner Interests
                                (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 under the Securities Exchange Act of 1934 is not contained
herein, and will not be contained, to the best of the Registrant's knowledge, in
definitive proxy or information statements incorporated in Part III of this Form
10-K or any amendments to this Form 10-K. [ ]

As of March 23, 2001, Kelley Partners 1992 Development Drilling Program had
16,033,009 units of limited and general partner interests (the "Units")
outstanding. The Units are not publicly traded.

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<PAGE>   2

                                     PART I

ITEMS 1 AND 2.  BUSINESS AND PROPERTIES

INTRODUCTION

         General. Kelley Partners 1992 Development Drilling Program, a Texas
limited partnership (the "Partnership"), was formed in 1992 to develop oil and
gas properties located onshore in Louisiana. The Partnership issued a total of
16,033,009 units of limited and general partner interests ("Units"),
representing 96.04% of the total interests in the Partnership, for $48,099,027.
The Units consist of 1,647,500 Units of limited partner interests ("LP Units")
and 14,385,509 Units of general partner interests ("GP Units"). In addition, the
Partnership issued managing and special general partner ("General Partner")
interests, representing the other 3.96% of the total interests in the
Partnership, for $1,983,258. In the aggregate, Kelley Oil Corporation, a
Delaware corporation, the managing general partner of the Partnership (the
"Managing General Partner" or "Kelley Oil"), owns 92.12% of the total interests
of the Partnership. Kelley Oil is a subsidiary of Contour Energy Co.,
collectively with its subsidiaries ("Contour").

         In December 2000, Kelley Oil invited the unit holders for the
Partnership to tender their units for cash. The cash offer was $0.123 per unit
for all of the Partnership units not held by Kelley Oil. A total of 1,298,724
Partnership units (50% of units eligible for tender) were tendered. The total
cost was approximately $200,000, including transaction costs. After the tender,
Kelley Oil owns 91.82% of the Units and a 3.94% General Partner interest.

As used in this Annual Report on Form 10-K (the "Report"), "Mcf" means thousand
cubic feet, "Mmcf" means million cubic feet, "Bcf" means billion cubic feet,
"Bbl" means barrel or 42 U.S. gallons liquid volume, "Mbbl" means thousand
barrels, "Mcfe" means thousand cubic feet of natural gas equivalent using the
ratio of six Mcf of natural gas to one Bbl of crude oil, condensate and natural
gas liquids, "Mmcfe" means million cubic feet of natural gas equivalent, "Bcfe"
means billion cubic feet of natural gas equivalent, and "Mmbtu" means million
British thermal units. This Report includes various other capitalized terms that
are defined when first used.

         The Partnership has received the benefits of a dramatic increase in the
level of commodity prices (mainly natural gas) during 2000. However, the
commodity markets are volatile and there is no certainty that current oil and
natural gas prices can be sustained at these levels. Historically, Contour on
behalf of the Partnership periodically enters into hedge contracts to protect
against commodity price declines. However, effective 2001 the Partnership no
longer plans to enter into hedging transactions because small production volumes
makes doing so no longer feasible.

         Operations. Development activities of the Partnership are conducted
through a joint venture (the "Joint Venture") between the Partnership and Kelley
Operating Company, Ltd. ("Kelley Operating"), a subsidiary partnership of Kelley
Oil. The Partnership contributed to the Joint Venture substantially all of the
partners' contributed capital to finance the costs of drilling, completing,
equipping and, when necessary, abandoning the wells drilled by the Joint
Venture, proportionate with the Joint Venture's working interest in each well.
Kelley Operating contributed to the Joint Venture specific drilling rights for
development wells on its properties selected by the Managing General Partner. In
return for the contributed drilling rights, Kelley Operating has reserved a 20%
reversionary interest after Payout (as defined in the Joint Venture Agreement)
in the costs and revenues of the Joint Venture.

         In addition to its reversionary interest, Kelley Operating retained one
third of its working interest associated with the drilling rights contributed to
the Joint Venture. Accordingly, Kelley Operating has contributed proportionately
to the development and operating costs of all Partnership wells and receives a
proportionate share of the revenues attributable to the sale of production from
those wells.

         Development and Production. From inception through the completion of
drilling activities in 1994, the Partnership participated in drilling 39 gross
wells, of which 30 gross (11.07 net) wells were productive and 9 gross (4.16
net) wells were dry. Subsequently, two producing Partnership wells were plugged
when production declined to


                                       1

<PAGE>   3

noncommercial levels. From its inception through 2000, the Partnership produced
10.7 Bcf of natural gas and 212,513 barrels of oil and natural gas liquids,
generating total oil and gas revenues of $25,635,000, as restated, of which
$4,823,000 or $0.29 per Unit has been distributed to the partners. To enable the
Partnership to fund part of its drilling and recompletion expenses in excess of
contributed capital, quarterly distributions were suspended in October 1994,
reinstated for only one quarter in 1995, and suspended again thereafter. In
February 2001, the fourth quarter 2000 earnings distribution was paid to the
managing and special general partners and the unitholders in the amounts of
$13,000 and $304,000, or $0.02 per Unit, respectively. However, future
distributions to the unitholders are dependent on the future operating results
of the Partnership. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations."

MANAGEMENT, OPERATIONS AND PROPERTIES

         Kelley Oil's principal executive offices are located at 601 Jefferson
Street, Suite 1100, Houston, Texas 77002, and its main telephone number is (713)
652-5200. As Managing General Partner, Kelley Oil makes all decisions regarding
the business and operations of the Partnership. The Partnership has no employees
and utilizes the officers and staff of Kelley Oil to perform all management and
administrative functions. Kelley Oil's staff includes employees experienced in
geology, geophysics, petroleum engineering, land acquisition and management,
finance and accounting. Kelley Oil is also the managing general partner of
Kelley Operating. See "Employees" below and "Directors and Executive Officers of
Kelley Oil Corporation."

         On March 8, 2001, Contour announced that John F. Bookout, Contour's
President and Chief Executive Officer had informed the Board of Directors of his
intention to retire effective April 30, 2001, and to step down as Chairman and a
member of the Board of Directors effective May 30, 2001. Kenneth R. Sanders will
assume the position of President and Chief Executive Officer effective April 30,
2001. Additionally, Rick G. Lester, Contour's Chief Financial Officer, was
appointed Executive Vice President. Both Messrs. Sanders and Lester were elected
directors of Contour.

         The General Partners receive no management or other fees or promoted
interests from the Partnership or the Joint Venture. The Partnership reimburses
Kelley Oil for all direct costs incurred in managing the Partnership and all
indirect costs allocable to the Partnership, principally comprised of general
and administrative expenses. These arrangements are the same for all development
drilling programs ("DDPs") sponsored by Kelley Oil.

ESTIMATED PROVED RESERVES

         General. The estimated gross quantities of proved and proved developed
reserves for properties in which the Partnership owns interests were prepared as
of January 1, 1999, 2000 and 2001, by an independent petroleum engineering firm.
For the reserves at January 1, 2000 and 2001, Contour applied appropriate
Partnership revenue interests to determine the Partnership's net proved reserves
shown below.

         Quantities. The following table sets forth the Partnership's estimated
quantities of proved and proved developed reserves of crude oil (including
condensate and natural gas liquids) and natural gas as of January 1, 1999, 2000
and 2001. Proved developed reserves are reserves that can be expected to be
recovered from existing wells with existing equipment and operating methods.
Proved undeveloped reserves are proved reserves that are expected to be
recovered from new wells drilled to known reservoirs on undrilled acreage for
which the existence and recoverability of reserves can be estimated with
reasonable certainty, or from existing wells where a relatively major
expenditure is required for recompletion.



                                       2
<PAGE>   4

                            ESTIMATED PROVED RESERVES

<TABLE>
<CAPTION>
                                                            AS OF JANUARY 1,
                                                     ---------------------------
                                                     1999       2000       2001
                                                     -----      -----      -----
<S>                                                  <C>        <C>        <C>
Crude oil and liquids (Mbbl):
   Proved developed ...........................         88         64         70
   Proved undeveloped .........................         --         --         --
                                                     -----      -----      -----
     Total proved .............................         88         64         70
                                                     =====      =====      =====
Natural gas (Mmcf):
   Proved developed ...........................      3,759      1,196      1,247
   Proved undeveloped .........................         --         --         --
                                                     -----      -----      -----
     Total proved .............................      3,759      1,196      1,247
                                                     =====      =====      =====
</TABLE>


         Detailed information concerning the Partnership's estimated proved
reserves and discounted net future cash flows is contained in the Supplementary
Financial Information included in Note 7 in Notes to the Financial Statements.
The Partnership has not filed any estimates of reserves with any federal
authority or agency during the past year other than estimates contained in its
last annual report filed with the Securities and Exchange Commission ("SEC").

         Uncertainties in Estimating Reserves. Oil and gas proved reserves
cannot be measured exactly. Reserve estimates are inherently imprecise and may
be expected to change as additional information becomes available. Estimates of
oil and gas reserves, of necessity, are projections based on engineering data,
and there are uncertainties inherent in the interpretation of such data as well
as the projection of future rates of production and the timing of development
expenditures. Reserve estimates are based on many factors related to reservoir
performance which require evaluation by the engineers interpreting the available
data, as well as price and other economic factors. The reliability of these
estimates at any point in time depends on the quality and quantity of the
technical and economic data, the production performance of the reservoirs as
well as extensive engineering judgment. Further, estimates of the economically
recoverable quantities of oil and natural gas attributable to any particular
group of properties, classifications of such reserves based on risk of recovery
and estimates of the future net revenues expected therefrom prepared by
different engineers or by the same engineers at different times may vary
substantially. Consequently, reserve estimates are subject to revision as
additional data becomes available during the producing life of a reservoir.
There also can be no assurance that the reserves set forth herein will
ultimately be produced. In addition, the estimates of future net revenues from
proved reserves of the Partnership and the present value thereof are based upon
certain assumptions about future production levels, prices and costs that may
not be correct when judged against actual subsequent experience.

DESCRIPTION OF SIGNIFICANT PROPERTIES

         General. The properties of the Partnership consist primarily of
interests in producing wells located in the Hosston, Smackover, Miocene and
Oligocene trends in Louisiana. All of the Partnership's oil and gas reserves are
located within the continental United States.


                                       3
<PAGE>   5

         Significant Fields. The following table sets forth certain information
as of January 1, 2001 with respect to the Partnership's interests in its most
significant fields, together with information for all other fields combined.

                          SIGNIFICANT PROVED PROPERTIES
                                 (IN THOUSANDS)

<TABLE>
<CAPTION>
                                                 PROVED RESERVES AT JANUARY 1, 2001               2000 PRODUCTION
                                             -----------------------------------------   -------------------------------------------
                                                                     GAS                                         GAS
                                               OIL        GAS     EQUIVALENT               OIL        GAS    EQUIVALENT
PROPERTY                                     (Mbbls)     (Mmcf)    (Mmcfe)         %     (Mbbls)     (Mmcf)    (Mmcfe)         %
--------                                     -------     ------   ----------     -----   -------     ------  -----------    -----
<S>                                           <C>        <C>       <C>           <C>      <C>        <C>      <C>           <C>
RTH LOUISIANA:
Ada field ..............................         --        183        183         11.0      --         21         21         10.3
Sibley field ...........................         10        345        405         24.3      --         29         29         14.3
SOUTH LOUISIANA:
   Orange Grove/Humphreys field ........          7        121        163          9.8       2         21         33         16.3
   Ouiski Bayou field ..................         53        546        864         51.8       7         72        114         56.2
OTHER:
   As a group ..........................         --         52         52          3.1      --          6          6          2.9
                                                 --      -----      -----        -----       -        ---        ---        -----
     Total .............................         70      1,247      1,667        100.0       9        149        203        100.0
                                                 ==      =====      =====        =====       =        ===        ===        =====
</TABLE>


         Additional information regarding these fields is set forth below.
Unless otherwise noted, acreage and well information is provided as of December
31, 2000, and reserve information is provided as of January 1, 2001.

                                 NORTH LOUISIANA

         Ada Field. The Ada field is located in Bienville and Webster Parishes,
Louisiana. The Partnership has an interest in 1 gross (.14 net) well producing
from the Sligo and Hosston formations at a depth of 8,600 feet. The well is
operated by a third party. The Ada field reserves are 100% proved developed.

Sibley Field. The Sibley field is located in Webster Parish, Louisiana. The
Partnership has interests in 5 gross (.34 net) wells producing from the Hosston
formation at depths ranging from 7,300 to 10,000 feet. Kelley Oil operates one
of the wells. The Sibley field reserves are 100% proved developed.

                                 SOUTH LOUISIANA

         Orange Grove/Humphreys Field. The Orange Grove/Humphreys field is
located in Terrebonne Parish, Louisiana. The Partnership has an interest in 1
gross (.33 net) well producing from the 1st Hollywood formation at a depth of
approximately 11,600 feet that Kelley Oil operates. The Orange Grove/Humphreys
field reserves are 100% proved developed.

         Ouiski Bayou Field. The Ouiski Bayou field is located in Terrebonne
Parish, Louisiana. The Partnership has an interest in 1 gross (.33 net) well
producing from the Cib op formation at a depth of 17,000 feet that Kelley Oil
operates. The Ouiski Bayou field reserves are 100% proved developed.


                                       4
<PAGE>   6


PRODUCTION, PRICE AND COST DATA

         The following tables set forth the oil and gas production, average
sales price and average production costs per equivalent unit of oil and gas
produced by the Partnership for the years ended December 31, 1998, 1999 and
2000. Detailed additional information concerning the Partnership's oil and gas
producing activities is contained in the Supplementary Financial Information
included in Note 7 in Notes to the Financial Statements.

                             OIL AND GAS PRODUCTION

<TABLE>
<CAPTION>
                                                                                     YEAR ENDED DECEMBER 31,
                                                                                -----------------------------
                                                                                  1998       1999       2000
                                                                                -------    -------    -------
<S>                                                                             <C>        <C>        <C>
Crude oil, condensate and natural gas liquids (Bbls)............................ 10,172      9,398      9,031
Natural gas (Mmcf)..............................................................    601        314        149
</TABLE>


                                      AVERAGE SALES PRICES AND PRODUCTION COSTS

<TABLE>
<CAPTION>
                                                                                     YEAR ENDED DECEMBER 31,
                                                                                -----------------------------
                                                                                  1998       1999       2000
                                                                                -------    -------    -------
<S>                                                                             <C>        <C>        <C>
Average sales price:
   Crude oil, condensate and natural gas liquids per Bbl........................$ 13.56    $ 15.78    $ 29.70
   Natural gas per Mcf, including the effects of hedging (1)....................   2.30       2.26       3.59
Oil and gas revenues per Mcfe (1)...............................................   2.30       2.32       3.95
Average production costs per Mcfe (1)...........................................    .90       1.02       1.26
</TABLE>


(1)  Includes effect of new accounting pronouncement requiring shipping and
     handling expenses (i.e. compression and transportation expenses) to be
     included in production costs rather than netted in revenues. The impact on
     production costs are increases of $.15/Mcfe, $.13/Mcfe and $.03/Mcfe for
     the years 1998, 1999 and 2000, respectively. Realized prices for natural
     gas per Mcf and oil and gas revenues per Mcfe have been restated
     accordingly. See Note 6 in Notes to the Financial Statements.

OIL AND GAS WELLS

         As of December 31, 2000, the Partnership owned interests in productive
oil and gas wells (including producing wells and wells capable of production) as
follows:

<TABLE>
<CAPTION>
                                                                                         GROSS(1)            NET
                                                                                        ---------         --------
<S>                                                                                     <C>               <C>
Oil wells...............................................................................       --               --
Gas wells...............................................................................        9             1.35
                                                                                        ---------         --------
 Total..................................................................................        9             1.35
                                                                                        =========         ========
</TABLE>
(1)  One or more completions in the same hole are counted as one well; none
     of the wells have multiple completions.

         Wells Drilled. All of the wells drilled by the Partnership are
development wells based on definitions in the Partnership Agreement of the
Partnership. The following table sets forth the number of gross and net
productive and dry development wells and exploratory wells drilled by the
Partnership during the periods indicated, based on a narrower definition for
development wells under SEC guidelines.

                                       5
<PAGE>   7

<TABLE>
<CAPTION>

                                 GROSS                  GROSS                  NET                     NET
                          DEVELOPMENT WELLS      EXPLORATORY WELLS     DEVELOPMENT WELLS      EXPLORATORY WELLS
                          -----------------      -----------------     -----------------      -----------------
                          PRODUCTIVE    DRY      PRODUCTIVE    DRY     PRODUCTIVE    DRY      PRODUCTIVE    DRY
                          ----------    ---      ----------    ---     ----------    ---      ----------    ---
<S>                       <C>           <C>      <C>           <C>     <C>           <C>      <C>           <C>

1998.......................  --          --          --         --          --        --          --         --
1999.......................  --          --          --         --          --        --          --         --
2000.......................  --          --          --         --          --        --          --         --
</TABLE>


MARKETING OF NATURAL GAS AND CRUDE OIL

         The Partnership does not refine or process any of the oil and natural
gas it produces. The natural gas production of the Partnership is sold to
various purchasers typically in the areas where the natural gas is produced. The
Partnership currently is able to sell all of its natural gas at current market
prices. Its revenue streams are therefore sensitive to changes in current market
prices. The Partnership's sales of crude oil, condensate and natural gas liquids
generally are related to posted field prices.

         In addition to marketing natural gas and crude oil produced on
Partnership properties, a subsidiary of Kelley Oil aggregates volumes to
increase market power, provides gas transportation arrangements, provides
nomination and gas control services, supervises gas gathering operations and
performs revenue receipt and disbursement services as well as regulatory filing,
recordkeeping, inspection, testing, monitoring functions, coordinating the
connection of wells to various pipeline systems, performing gas market surveys
and overseeing gas balancing with its various gas gatherers and transporters.

         The Partnership believes that its activities are not currently
constrained by a lack of adequate transportation systems or system capacity and
does not foresee any material disruption in available transportation for its
production. However, there can be no assurance that the Partnership will not
encounter constraints in the future. In that event, the Partnership would be
forced to seek alternate sources of transportation and may face increased costs.

COMPETITION

         The oil and gas industry is highly competitive. Major oil and gas
companies, independent concerns, drilling and production purchase programs and
individual producers and operators are active bidders for desirable oil and gas
properties, as well as the equipment and labor required to operate those
properties. Many competitors have financial resources substantially greater than
those of the Partnership and staffs and facilities substantially larger than
those of Kelley Oil. The availability of a ready market for the oil and gas
production of the Partnership depends in part on the cost and availability of
alternative fuels, the level of consumer demand, the extent of other domestic
production of oil and gas, the extent of importation of foreign oil and gas, the
cost of and proximity to pipelines and other transportation facilities,
regulations by state and federal authorities and the cost of complying with
applicable environmental regulations.

EMPLOYEES

         The Partnership has no employees and utilizes the management and staff
of Kelley Oil. As of December 31, 2000, Kelley Oil had 45 employees. Kelley
Oil's staff includes employees experienced in geology, geophysics, petroleum
engineering, land acquisition and management, finance and accounting. See
"Directors and Executive Officers of Kelley Oil Corporation." None of Kelley
Oil's employees are represented by a union. Kelley Oil has never experienced an
interruption in its operations from any kind of labor dispute, and its working
relationship with its employees is satisfactory.


                                       6
<PAGE>   8


REGULATION

         The Partnership's operations are subject to extensive and continually
changing regulation, as legislation affecting the oil and natural gas industry
is under constant review for amendment and expansion. Many departments and
agencies, both federal and state, are authorized by statute to issue and have
issued rules and regulations binding on the oil and natural gas industry and its
individual participants. The failure to comply with such rules and regulations
can result in substantial penalties. The regulatory burden on the oil and
natural gas industry increases the Partnership's cost of doing business and,
consequently, affects its profitability. However, the Partnership does not
believe that it is affected in a significantly different manner by these
regulations than are its competitors in the oil and natural gas industry.
Because of the numerous and complex federal and state statutes and regulations
that may affect the Partnership, directly or indirectly, the following
discussion of certain statutes and regulations should not be relied upon as an
exhaustive review of all matters affecting the Partnership's operations.

Transportation and Production

         Transportation and Sale of Natural Gas and Crude Oil. Sales of natural
gas, crude oil and condensate ("Products") can be made by the Partnership at
market prices not subject at this time to price controls. The price that the
Partnership receives from the sale of these Products is affected by the ability
to transport and cost of transporting the Products to market. Under applicable
laws, the Federal Energy Regulation Commission ("FERC") regulates both the
construction of pipeline facilities and the transportation of Products in
interstate commerce.

         Regulation of Drilling and Production. Drilling and production
operations of the Partnership are subject to regulation under a wide range of
state and federal statutes, rules, orders and regulations. State and federal
statutes and regulations govern, among other matters, the amounts and types of
substances and materials that may be released into the environment, the
discharge and disposition of waste materials, the reclamation and abandonment of
wells and facility sites and remediation of contaminated sites, and require
permits for drilling operations, drilling bonds and reports concerning
operations. Most states in which the Partnership owns and operates properties
have regulations governing conservation matters, including provisions for the
unitization or pooling of oil and natural gas properties, the establishment of
maximum rates of production from oil and natural gas wells and the regulation of
the spacing, plugging and abandonment of wells. Many states also restrict
production to the market demand for oil and natural gas and several states have
indicated interest in revising applicable regulations. The effect of these
regulations is to limit the amount of oil and natural gas the Partnership can
produce from its wells and to limit the number of wells or the locations at
which it can drill. Moreover, each state generally imposes an ad valorem,
production or severance tax with respect to the production and sale of crude
oil, natural gas and gas liquids within its jurisdiction.

Environmental Regulations

         General. The various federal environmental laws, including the National
Environmental Policy Act; the Clean Air Act of 1990, as amended ("CAA"); Oil
Pollution Act of 1990, as amended ("OPA"); Water Pollution Control Act, as
amended ("FWPCA"); the Resource Conservation and Recovery Act as amended
("RCRA"); the Toxic Substances Control Act; and the Comprehensive Environmental
Response, Compensation and Liability Act, as amended ("CERCLA"), and the various
state and local environmental laws, and the regulations adopted pursuant to such
law, governing the discharge of materials into the environment, or otherwise
relating to the protection of the environment, continue to be taken seriously by
the Partnership. In particular, the Partnership's drilling, development and
production operations, its activities in connection with storage and
transportation of crude oil and other liquid hydrocarbons and its use of
facilities for treating, processing or otherwise handling hydrocarbons and
wastes therefrom are subject to stringent environmental regulation, and
violations are subject to reporting requirements, civil penalties and criminal
sanctions. As with the industry generally, compliance with existing regulations
increases the Company's overall cost of business. The increased costs are not
reasonably ascertainable. Such areas affected include unit production expenses
primarily related to the control and limitation of air emissions and the
disposal of produced water, capital costs to drill exploration and development
wells resulting from expenses primarily related to the management and disposal
of drilling


                                       7
<PAGE>   9

fluids and other oil and natural gas exploration wastes and capital costs to
construct, maintain and upgrade equipment and facilities and plug and abandon
inactive well sites and pits.

         Environmental regulations historically have been subject to frequent
change by regulatory authorities, and the Partnership is unable to predict the
ongoing cost of compliance with these laws and regulations or the future impact
of such regulations on its operations. However, the Partnership does not believe
that changes to these regulations will materially adversely affect its
competitive position because the Partnership's competitors are similarly
affected. A discharge of hydrocarbons or hazardous substances into the
environment could subject the Partnership to substantial expense, including both
the cost to comply with applicable regulations pertaining to the remediation of
releases of hazardous substances into the environment and claims by neighboring
landowners and other third parties for personal injury and property damage. The
Partnership maintains insurance, which may provide protection to some extent
against environmental liabilities, but the coverage of such insurance and the
amount of protection afforded thereby cannot be predicted with respect to any
particular possible environmental liability and may not be adequate to protect
the Partnership from substantial expense.

         The OPA and regulations thereunder impose a variety of regulations on
"responsible parties" related to the prevention of oil spills and liability for
damages resulting from such spills in United States waters. A "responsible
party" includes the owner or operator of an onshore facility, vessel, or
pipeline, or the lessee or permittee of the area in which an offshore facility
is located. The OPA assigns liability to each responsible party for oil removal
costs and a variety of public and private damages. The FWPCA imposes
restrictions and strict controls regarding the discharge of produced waters and
other oil and natural gas wastes into navigable waters. State laws for the
control of water pollution also provide varying civil, criminal and
administrative penalties and impose liabilities in the case of a discharge of
petroleum or its derivatives, or other hazardous substances, into state waters.
In addition, the Environmental Protection Agency ("EPA") has promulgated
regulations that require many oil and natural gas production operations to
obtain permits to discharge storm water runoff.

         The CAA requires or will require most industrial operations in the
United States to incur capital expenditures in order to meet air emission
control standards developed by the EPA and state environmental agencies.
Although no assurances can be given, the Company believes implementation of such
amendments will not have a material adverse effect on its financial condition or
results of operations. RCRA is the principal federal statute governing the
treatment, storage and disposal of hazardous wastes. RCRA imposes stringent
operating requirements (and liability for failure to meet such requirements) on
a person who is either a "generator" or "transporter" of hazardous waste or an
"owner" or "operator" of a hazardous waste treatment, storage or disposal
facility. At present, RCRA includes a statutory exemption that allows oil and
natural gas exploration and production wastes to be classified as non-hazardous
waste. As a result, the Partnership is not required to comply with a substantial
portion of RCRA's requirements because its operations generate minimal
quantities of hazardous wastes.

         CERCLA, also known as "Superfund", imposes liability, without regard to
fault or the legality of the original act, on certain classes of persons that
contributed to the release of a "hazardous substance" into the environment.
These persons include the "owner" or "operator" of the site and companies that
disposed or arranged for the disposal of the hazardous substances found at the
site. CERCLA also authorizes the EPA and, in some instances, third parties to
act in response to threats to the public health or the environment and to seek
to recover from the responsible classes of persons the costs they incur. In the
course of its ordinary operations, the Partnership may generate waste that may
fall within CERCLA's definition of a "hazardous substance". As a result, the
Partnership may be jointly and severally liable under CERCLA or under analogous
state laws for all or part of the costs required to clean up sites at which such
wastes have been disposed. The Partnership currently owns or leases, and has in
the past owned or leased, numerous properties that for many years have been used
for the exploration and production of oil and natural gas. Although the
Partnership has utilized operating and disposal practices that were standard in
the industry at the time, hydrocarbons or other wastes may have been disposed of
or released on or under the properties owned or leased by the Partnership on or
under other locations where such wastes have been taken for disposal. In
addition, many of these properties have been operated by third parties whose
actions with respect to the treatment and disposal or release of hydrocarbons or
other wastes were


                                       8
<PAGE>   10

not under the Partnership's control. These properties and wastes disposed
thereon may be subject to CERCLA, RCRA and analogous state laws. Under such
laws, the Partnership could be required to remove or remediate previously
disposed wastes (including wastes disposed of or released by prior owners or
operators), to clean up contaminated property (including contaminated
groundwater) or to perform remedial plugging operations to prevent future
contamination.

CAUTION AS TO FORWARD-LOOKING STATEMENTS

         Statements contained in this Report and other materials filed or to be
filed by the Partnership with the Securities and Exchange Commission (as well as
information included in oral or other written statements made or to be made by
the Company or its representatives) that are forward-looking in nature are
intended to be "forward-looking statements" within the meaning of Section 27A of
the Securities Act of 1933, as amended, and Section 21E of the Securities
Exchange Act of 1934, as amended, relating to matters such as anticipated
operating and financial performance, business prospects, developments and
results of the Partnership. Actual performance, prospects, developments and
results may differ materially from any or all anticipated results due to
economic conditions and other risks, uncertainties and circumstances partly or
totally outside the control of the Partnership, including rates of inflation,
natural gas prices, uncertainty of reserve estimates, rates and timing of future
production of oil and gas, exploratory and development activities, acquisition
risks and activities, changes in the level and timing of future costs and
expenses related to drilling and operating activities and those risks described
under "Risk Factors" below.

         Words such as "anticipated," "expect," "estimate," "project" and
similar expressions are intended to identify forward-looking statements.
Forward-looking statements include the risks described in "Risk Factors".

RISK FACTORS

         The Partnership cautions that the following risk factors could affect
its actual results in the future, in addition to "Uncertainties in Estimating
Reserves" and "Liquidity and Capital Resources" discussed elsewhere in this
Report.

         Depletion of Reserves. Producing oil and natural gas reservoirs
generally are characterized by declining production rates that vary depending
upon reservoir characteristics and other factors. The Partnership's future oil
and natural gas reserves and production, and, therefore, cash flow and income,
are highly dependent upon its success in efficiently producing its reserves.

         Volatility of Oil, Natural Gas and Natural Gas Liquids Prices. The
Partnership's financial results are affected significantly by the prices
received for its oil, natural gas and natural gas liquids production.
Historically, the markets for oil, natural gas and natural gas liquids have been
volatile and are expected to continue to be volatile in the future. The
Partnership's future financial condition and results of operations will depend,
in part, upon the prices received for its oil and natural gas production, as
well as the costs of developing and producing reserves. Because the Partnership
will no longer plans to hedge its production, prices realized by the Partnership
may be more volatile than historically.

         Operating Hazards and Uninsured Risks. Oil and gas drilling activities
are subject to numerous risks, many of which are uninsurable, including the risk
that no commercially viable oil or natural gas production will be obtained; many
of such risks are beyond the Partnership's control. The decision to develop a
prospect or property will depend in part on the evaluation of data obtained
through geophysical and geological analyses, production data and engineering
studies, the results of which are often inconclusive or subject to varying
interpretations. The cost of drilling, completing and operating wells is often
uncertain, and overruns in budgeted expenditures are common risks that can make
a particular project uneconomical. Technical problems encountered in actual
drilling, completion and workover activities can delay such activity and add
substantial costs to a project. Further, drilling may be curtailed, delayed or
canceled as a result of many factors, including title problems, weather
conditions, compliance with government permitting requirements, shortages of or
delays in obtaining equipment, reductions in product prices and limitations in
the market for products.


                                       9
<PAGE>   11


         The availability of a ready market for the Partnership's oil and
natural gas production also depends on a number of factors, including the demand
for and supply of oil and natural gas and the proximity of reserves to pipelines
or trucking and terminal facilities. Natural gas wells may be partially or
totally shut in for lack of a market or because of inadequacy or unavailability
of natural gas pipeline or gathering system capacity.

         The Partnership's oil and natural gas business also is subject to all
of the operating risks associated with the drilling for and production of oil
and natural gas, including, but not limited to, uncontrollable flows of oil,
natural gas, brine or well fluids into the environment (including groundwater
and shoreline contamination), blowouts, cratering, mechanical difficulties,
fires, explosions, pollution and other risks, any of which could result in
substantial losses to the Partnership. Although the Partnership maintains
insurance at levels that it believes are consistent with industry practices, it
is not fully insured against all risks. Losses and liabilities arising from
uninsured and underinsured events could have a material adverse effect on the
financial condition and operations of the Partnership.

ITEM 3.  LEGAL PROCEEDINGS

         Contour, through its subsidiaries, is involved in various claims and
lawsuits incidental to its business. In the opinion of management, the ultimate
liability thereunder, if any, will not have a material effect on the financial
condition of Kelley Oil or the Partnership.

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

         Not applicable.



                                       10
<PAGE>   12

                                     PART II

ITEM 5.  MARKET FOR UNITS AND RELATED UNITHOLDER MATTERS

         There is no market for the Units of the Partnership. Transfer of the
Units was substantially restricted by the provisions of the Partnership
Agreement until the Partnership Agreement was amended in December 2000 to allow
unitholders to buy or sell units from existing unitholders. As of March 23,
2001, there were 477 holders of record of the Partnership's Units.

         The following table sets forth the cash distributions per Unit paid by
the Partnership during the periods indicated.

<TABLE>
<CAPTION>

                                                                                      DISTRIBUTIONS
                                                                                      -------------
<S>                                                                                   <C>

                  1998:
                  First quarter......................................................   $    --
                  Second quarter.....................................................        --
                  Third quarter......................................................        --
                  Fourth quarter.....................................................        --

                  1999:
                  First quarter......................................................        --
                  Second quarter.....................................................        --
                  Third quarter......................................................        --
                  Fourth quarter.....................................................        --

                  2000:
                  First quarter......................................................        --
                  Second quarter.....................................................        --
                  Third quarter......................................................        --
                  Fourth quarter.....................................................       .02
</TABLE>


         Distribution levels are affected by numerous factors, including oil and
gas prices, production levels and operating costs, together with any working
capital or debt service requirements. To enable the Partnership to fund part of
its drilling and recompletion expenses in excess of contributed capital,
distributions were suspended in the fourth quarter of 1994 and reinstated only
for the third quarter of 1995. In the third quarter 2000, the final payment on
the $6,000,000 Initial Loan from Kelley Oil was paid. In February 2001, the
fourth quarter 2000 earnings distribution was paid to the managing and special
general partners and the unitholders in the amounts of $13,000 and $304,000, or
$0.02 per Unit, respectively. Future distributions to the unitholders and the
managing and special general partners are contingent on future operating
results. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations."



                                       11
<PAGE>   13


ITEM 6.  SELECTED FINANCIAL DATA

         The following table presents selected financial data for the
Partnership. The financial information presented below is derived from the
Partnership's audited Financial Statements presented elsewhere in this Report
and in previously filed Form 10Ks, and should be read in conjunction with those
Financial Statements and the related Notes thereto.

                KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
                     (IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)

<TABLE>
<CAPTION>
                                                                       YEAR ENDED DECEMBER 31,
                                                   -------------------------------------------------------------
                                                     1996          1997         1998         1999         2000
                                                   ---------    ---------    ---------    ---------     --------
<S>                                                <C>          <C>          <C>          <C>           <C>
SUMMARY OF OPERATIONS:
  Total revenues (1) (3)...........................$   4,991    $   2,391    $   1,495    $   1,693     $  800
  Production expenses (1)..........................      816          645          594          378        256
  Exploration expenses.............................       (3)         --            --           --         --
  General and administrative expenses..............      325          476          134           92         62
  Interest expense.................................      810          376          287          174          6
  Depreciation, depletion and amortization.........    1,280          587          427          225        120
  Impairment of oil and gas properties.............       --           --          466           --         --
  Net income (loss)................................    1,763          307         (413)         824        356
  Net income (loss) per Unit (2)...................      .11          .02         (.02)         .05        .02
  Distributions paid per Unit (2)..................       --           --           --           --        .02
  Units outstanding................................   16,033       16,033       16,033       16,033     16,033
</TABLE>

<TABLE>
<CAPTION>
                                                                         AS OF DECEMBER 31,
                                                   -------------------------------------------------------------
                                                     1996          1997         1998         1999         2000
                                                   ---------    ---------    ---------    ---------     --------
<S>                                                <C>          <C>          <C>          <C>           <C>
SUMMARY BALANCE SHEET DATA:
   Working capital (deficit).......................$   1,582    $     288    $      23    $     (17)    $     (1)
   Oil and gas properties, net.....................    3,987        3,369        2,528        1,070          927
   Long-term debt..................................    5,400        3,181        2,488          166           --
   Total partners' equity..........................      169          476           63          887          926
   Total assets....................................    5,712        3,741        2,649        1,115        1,011
</TABLE>

(1)      Total Revenues and Production expenses have been restated for the years
         1997, 1998 and 2000 in accordance with a new accounting pronouncement.
         See Note 6 in Notes to the Financial Statements and "Management's
         Discussion and Analysis of Financial Condition and Results of
         Operations".
(2)      Per Unit amounts are based on the Unitholders' 96.04% share of net
         income and loss.
(3)      1999 revenues include gain on sale of properties of $850.


                                       12
<PAGE>   14


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

GENERAL

         In 1992, the Partnership issued a total of 16,033,009 units of limited
and general partner interests ("Units") at $3.00 per Unit for a total of
$48,099,027. The Units represent 96.04% of the total interests in the
Partnership and consist of 1,647,500 Units of limited partner interests ("LP
Units") and 14,385,509 Units of general partner interests ("GP Units") at
December 31, 2000. In addition, the Partnership issued managing and special
general partner interests on a pro rata basis for $1,983,258, representing 3.96%
of the total interests in the Partnership. In the aggregate, Kelley Oil
Corporation, a Delaware corporation, the managing general partner of the
Partnership (the "Managing General Partner" or "Kelley Oil"), owns 92.12% of the
total interests of the Partnership. Kelley Oil is a subsidiary of Contour Energy
Co., collectively with its subsidiaries ("Contour").

         In December 2000, Kelley Oil invited the unit holders for the
Partnership to tender their units for cash. The cash offer was $0.123 per unit
for the Partnership units not held by Kelley Oil. A total of 1,298,724
Partnership units (50% of units eligible for tender) were tendered. The total
cost was approximately $200,000, including transaction costs. After the tender,
Kelley Oil owns 91.82% of the Units and a 3.94% General Partner interest.

         Drilling Operations. Since inception, the Partnership participated in
drilling 39 gross (15.23 net) wells, of which 30 gross (11.07 net) wells were
found productive and 9 gross (4.16 net) wells were dry.

         Hedging Activities. Historically, Contour on behalf of the Partnership
periodically enters into hedge contracts to protect against commodity price
declines. Contour normally employs the average NYMEX price for the last three
days of the contract for natural gas and the monthly average of the closing
NYMEX price for crude oil as the underlying index ("Index Price"). See Note 5
in the Notes to the Financial Statements. However, effective 2001 the
Partnership no longer plans to enter into hedging transactions because small
production volumes makes doing so no longer feasible.

         Through natural gas price swap agreements, the Partnership hedged
approximately 49% and 50%, respectively, of its natural gas production for 1998
and 1999, respectively, at average NYMEX quoted prices of $2.31 and $2.17 per
Mmbtu, respectively, before transaction and transportation costs. For 2000, the
Partnership hedged approximately 72% of its natural gas production using price
swap agreements (48%) and a costless collar (24%). The average price received
under the swap agreements was $2.59/Mmbtu. The costless collar included a
ceiling of $4.98/Mmbtu and a floor of $4.00/mmbtu at the closing Index Price. As
of December 31, 2000, none of the Partnership's anticipated natural gas
production for 2001 has been hedged

         Through crude oil price swap agreements, the Partnership hedged
approximately 29% of its crude oil production for 1999 at an average NYMEX
quoted price of $20.00 per bbl, before transaction and transportation costs. No
crude oil was hedged in 1998. For 2000, the Company hedged approximately 66% of
its crude oil production using price swap agreements (41%) and costless collars
(25%). The average price received under the swap agreements was $26.21/Bbl. The
costless collars included an average ceiling of $32.21/Bbl and an average floor
of $26.11/Bbl at the closing Index Price. As of December 31, 2000, none of the
Partnership's crude oil production for 2001 had been hedged.

          Hedging activities decreased Partnership oil and natural gas revenues
by approximately $17,000 and $109,000 in 1999 and 2000, respectively, and
increased such revenues by approximately $50,000 in 1998 as compared to
estimated revenues had no hedging activities been conducted.

         The credit risk exposure from counterparty nonperformance on natural
gas forward sales contracts and derivative financial instruments is generally
the amount of unrealized gains under the contracts. The Partnership has not
experienced counterparty nonperformance on these agreements.


                                       13
<PAGE>   15


RESULTS OF OPERATIONS

         Years Ended December 31, 2000 and 1999. Oil and gas revenues were
$800,000 for 2000 as compared to $843,000 in the corresponding period of 1999,
primarily as a result of lower oil and gas production offset by higher oil and
natural gas prices. Production of natural gas decreased 53% from 314,000 Mcf in
1999 to 149,000 Mcf in 2000. Production of crude oil in the current year totaled
9,031 barrels compared to 9,398 barrels last year, representing a decrease of
4%. Oil and gas production decreased due to the sale of properties to Phillips
Petroleum Company ("Phillips") in the second quarter of 1999 and natural
depletion.

         Lease operating expenses and severance taxes were $256,000 in 2000
versus $378,000 in 1999, a decrease of 32%, primarily related to the sale of
properties to Phillips. On a unit of production basis, these expenses increased
to $1.26 per Mcfe in 2000 from $1.02 per Mcfe in 1999. Transportation and
compression expenses of $48,000 ($0.13 per Mcfe) and $7,000 ($0.03 per Mcfe)
were included in lease operating expense for 1999 and 2000, respectively, as a
result of a new accounting pronouncement. See Note 6 in Notes to Financial
Statements.

         General and administrative expenses of $62,000 in 2000 decreased 33%
from $92,000 in 1999. On a unit of production basis, these expenses increased
from $0.25 per Mcfe in 1999 to $0.31 per Mcfe in 2000.

         In 2000 and 1999, the Partnership incurred interest expense of $6,000
and $174,000, respectively, on a loan advanced to it by Kelley Oil in August
1994 to fund part of its drilling expenses in excess of contributed capital. The
reduction reflects the lower average note payable balance outstanding in 2000 as
compared to 1999. In 2000, the final payment of $166,000 was made on the
$6,000,000 Initial Loan. See "Liquidity and Capital Resources".

         Depreciation, depletion and amortization ("DD&A") expense decreased 47%
from $225,000 in 1999 to $120,000 in 2000 due to lower production levels related
to the sale of properties to Phillips and lower depletion rates. On a unit of
production basis, DD&A expense decreased from $0.61 per Mcfe in 1999 to $0.59
per Mcfe in 2000.

         The Partnership recognized net income in 2000 of $356,000 or $0.02 per
Unit compared to net income in 1999 of $824,000, including a $850,000 gain on
sale of properties, or $0.05 per Unit. The reasons for the variance between 2000
and 1999 are described in the foregoing discussion.

         Years Ended December 31, 1999 and 1998. Oil and gas revenues of
$843,000 for 1999 decreased 43% compared to $1,495,000 in the corresponding
period of 1998 primarily as a result of lower oil and gas production. Production
of natural gas decreased 48% from 601,000 Mcf in 1998 to 314,000 Mcf in 1999.
Production of crude oil in the current year totaled 9,398 barrels compared to
10,172 barrels last year, representing a decrease of 8%. Oil and gas production
decreased due to the sale of properties to Phillips and natural depletion.

         In 1999, the Partnership recognized a $850,000 gain on the sale of the
north Louisiana fields to Phillips.

         Lease operating expenses and severance taxes were $378,000 in 1999
versus $594,000 in 1998, a decrease of 36%, primarily related to the sale of
properties to Phillips. On a unit of production basis, these expenses increased
to $1.02 per Mcfe in 1999 from $0.90 per Mcfe in 1998. Transportation and
compression expenses of $97,000 ($0.15 per Mcfe) and $48,000 ($0.13 per Mcfe)
were included in lease operating expense for 1998 and 1999, respectively, as a
result of a new accounting pronouncement.

         General and administrative expenses of $92,000 in 1999 decreased 31%
from $134,000 in 1998. On a unit of production basis, these expenses increased
from $0.20 per Mcfe in 1998 to $0.25 per Mcfe in 1999.

         In 1999 and 1998, the Partnership incurred interest expense of $174,000
and $287,000, respectively, on a loan advanced to it by Kelley Oil in August
1994 to fund part of its drilling expenses in excess of contributed capital. The


                                       14
<PAGE>   16

reduction reflects the lower average note payable balance outstanding in 1999 as
compared to 1998. See "Liquidity and Capital Resources" below.

         DD&A expense decreased 47% from $427,000 in 1998 to $225,000 in 1999
due to lower production levels related to the sale of properties to Phillips and
lower depletion rates. On a unit of production basis, DD&A expense decreased
from $0.64 per Mcfe in 1998 to $0.61 per Mcfe in 1999.

         In 1998, the Partnership recognized a non-cash impairment charge of
$466,000 against the carrying values of its proved oil and gas properties, for
the year ended December 31, 1998 (see "Oil and Gas Properties" in Note 1 to the
Financial Statements).

         The Partnership recognized net income in 1999 of $824,000 or $0.05 per
Unit compared to a net loss in 1998 of $413,000 or $(0.02) per Unit. The reasons
for the variance between 1999 and 1998 are described in the foregoing
discussion.

LIQUIDITY AND CAPITAL RESOURCES

         Liquidity. Net cash provided by the Partnership's operating activities
during 2000, as reflected on its statement of cash flows, totaled $460,000.
During the period, funds used in financing activities included a reduction in
the Initial Loan principal of $166,000 and partnership distributions of
$317,000. As a result of these activities, the Partnership's cash and cash
equivalents remained at zero at December 31, 2000.

         The Partnership has received the benefits of a dramatic increase in the
level of commodity prices (mainly natural gas) during 2000. However, the
commodity markets are volatile and there is no certainty that current oil and
natural gas prices can be sustained at these levels. Historically, Contour on
behalf of the Partnership periodically enters into hedge contracts to protect
against commodity price declines. However, effective 2001 the Partnership no
longer plans to enter into hedging transactions because small production volumes
makes doing so no longer feasible.

         Capital Resources. The partners' equity at December 31, 2000 increased
to $926,000 as compared to $887,000 at December 31, 1999. The Partnership has
completed its development stage. Accordingly, cash flow from operations should
be adequate to meet its expected capital and general working capital needs. As
of December 31, 2000, the Partnership was fully capitalized with contributions
aggregating $50,082,285.

         Distribution Policy. The Partnership maintains a policy of distributing
cash which is not required for the conduct of Partnership business to
Unitholders on a quarterly basis. To meet its financial obligations for drilling
overexpenditures, the Partnership suspended distributions commencing in October
1994 and reinstated a quarterly distribution for only one quarter in 1995. In
2000, the final payment of $166,000 was made on the $6,000,000 Initial Loan. In
February 2001, the fourth quarter 2000 earnings distribution was paid to the
managing and special general partners and the unitholders in the amounts of
$13,000 and $304,000, or $0.02 per Unit, respectively. However, future
distributions to the unitholders and the managing and special general partners
are contingent on future operating results.


                                       15
<PAGE>   17


         Inflation and Changing Prices. Oil and natural gas prices, as with most
commodities, are highly volatile, have fluctuated during recent years and
generally have not followed the same pattern as inflation. The following table
shows the changes in the average oil and natural gas prices (including the
effects of hedging) received by Partnership during the periods indicated.

<TABLE>
<CAPTION>
                                                                                            Average        Average
                                                                                           Oil Price      Gas Price
                                                                                            ($/Bbl)        ($/Mcf)
                                                                                           ---------      ---------
<S>                                                                                          <C>             <C>
  YEAR ENDED:
    December 31, 1998...................................................................     13.56           2.30
    December 31, 1999...................................................................     15.78           2.26
    December 31, 2000...................................................................     29.70           3.59
</TABLE>

         Accounting Pronouncements. The Partnership adopted Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities" ("SFAS 133") effective January 1, 2001. The statement,
as amended, requires that all derivatives be recognized as either assets or
liabilities and measured at fair value, and changes in the fair value of
derivatives be reported in current earnings, unless the derivative is designated
and effective as a hedge. If the intended use of the derivative is to hedge the
exposure to changes in the fair value of an asset, a liability or firm
commitment, then the changes in the fair value of the derivative instrument will
generally be offset in the income statement by the change in the item's fair
value. However, if the intended use of the derivative is to hedge the exposure
to variability in expected future cash flows then the changes in fair value of
the derivative instrument will generally be reported in Other Comprehensive
Income (OCI). The gains and losses on the derivative instrument that are
reported in OCI will be reclassified to earnings in the period in which earnings
are impacted by the hedged item.

         As of January 1, 2001, the Partnership is not party to any derivative
instruments and as such there is no impact on its financial statements as a
result of the adoption of SFAS 133.

         In the fourth quarter of 2000, the Partnership adopted Emerging Issues
Task Force Issue No. 00-10 ("EITF No. 00-10") accounting for Shipping and
Handling Fees and Costs. EITF No. 00-10 addresses how shipping and handling fees
should be classified in the income statement. As a result of EITF No. 00-10, the
Partnership has reclassified its transportation and compression expenses from
oil and gas revenues to production expenses.


                                       16
<PAGE>   18

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

         See discussion in Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations-Hedging


                                       17

<PAGE>   19

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA



                                              INDEX TO FINANCIAL STATEMENTS

KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM:

<TABLE>
<CAPTION>

                                                                                                             PAGE
                                                                                                             ----
<S>                                                                                                          <C>
Independent Auditors' Report...............................................................................   19
Balance Sheets - December 31, 1999 and 2000................................................................   20
Statements of Operations - For the years ended December 31, 1998, 1999 and 2000............................   21
Statements of Cash Flows - For the years ended December 31, 1998, 1999 and 2000............................   22
Statements of Changes in Partners' Equity (Deficit) - For the years ended
    December 31, 1998, 1999 and 2000.......................................................................   23
Notes to Financial Statements..............................................................................   24
</TABLE>


                                       18
<PAGE>   20




                          INDEPENDENT AUDITORS' REPORT


To the Partners of Kelley Partners 1992 Development Drilling Program:


We have audited the accompanying balance sheets of Kelley Partners 1992
Development Drilling Program (a Texas limited partnership) as of December 31,
1999 and 2000, and the related statements of operations, cash flows, and changes
in partners' equity (deficit) for each of the three years in the period ended
December 31, 2000. These financial statements are the responsibility of the
Partnership's management. Our responsibility is to express an opinion on these
financial statements based on our audits.

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

In our opinion, such financial statements present fairly, in all material
respects, the financial position of Kelley Partners 1992 Development Drilling
Program as of December 31, 1999 and 2000, and the results of its operations and
its cash flows for each of the three years in the period ended December 31,
2000, in conformity with accounting principles generally accepted in the United
States of America.




DELOITTE & TOUCHE LLP

Houston, Texas
March 22, 2001



                                       19
<PAGE>   21


                KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
                                 BALANCE SHEETS

                                 (IN THOUSANDS)

<TABLE>
<CAPTION>
                                                                                                DECEMBER 31,
                                                                                         ---------------------------
                                                                                           1999              2000
                                                                                         ---------         ---------
<S>                                                                                      <C>               <C>
ASSETS:
   Cash and cash equivalents............................................................ $      --         $      --
   Accounts receivable - trade..........................................................        28                37
   Accounts receivable - affiliates.....................................................        17                47
                                                                                         ---------         ---------
     Total current assets...............................................................        45                84
                                                                                         ---------         ---------

   Oil and gas properties, successful efforts method:
     Properties subject to amortization.................................................    41,466            41,443
     Less:  Accumulated depreciation, depletion & amortization..........................   (40,396)          (40,516)
                                                                                         ---------         ---------
     Total oil and gas properties.......................................................     1,070               927
                                                                                         ---------         ---------
   Total assets......................................................................... $   1,115         $   1,011
                                                                                         =========         =========

LIABILITIES:
   Accounts payable and accrued expenses................................................ $      62         $      85
                                                                                         ---------         ---------
     Total current liabilities..........................................................        62                85
                                                                                         ---------         ---------
   Long-term note payable - affiliate...................................................       166                --
                                                                                         ---------         ---------
     Total liabilities..................................................................       228                85
                                                                                         ---------         ---------

PARTNERS' EQUITY:
   LP Unitholders' equity...............................................................        62                67
   GP Unitholders' equity...............................................................       789               822
   Managing and Special General Partners' equity........................................        36                37
                                                                                         ---------         ---------
     Total partners' equity.............................................................       887               926
                                                                                         ---------         ---------
   Total liabilities and partners' equity .............................................. $   1,115         $   1,011
                                                                                         =========         =========
</TABLE>


                       See Notes to Financial Statements.



                                       20
<PAGE>   22



                KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
                            STATEMENTS OF OPERATIONS

                      (IN THOUSANDS, EXCEPT PER UNIT DATA)


<TABLE>
<CAPTION>
                                                                                    YEAR ENDED DECEMBER 31,
                                                                       --------------------------------------------
                                                                         1998              1999              2000
                                                                       ---------        ---------         ---------
<S>                                                                    <C>              <C>               <C>
REVENUES:
   Oil and gas sales...................................................$   1,495        $     843         $     800
   Gain on sale of properties..........................................       --              850                --
                                                                       ---------        ---------         ---------
   Total revenues......................................................    1,495            1,693               800
                                                                       ---------        ---------         ---------
COSTS AND EXPENSES:
   Lease operating expenses............................................      517              333               224
   Severance taxes.....................................................       77               45                32
   General and administrative expenses.................................      134               92                62
   Interest expense....................................................      287              174                 6
   Depreciation, depletion and amortization............................      427              225               120
   Impairment of oil and gas properties................................      466               --                --
                                                                       ---------        ---------         ---------
     Total expenses....................................................    1,908              869               444
                                                                       ---------        ---------         ---------
Net (loss) income......................................................$    (413)       $     824          $    356
                                                                       =========        =========         =========
Net (loss) income allocable to LP and GP unitholders...................$    (397)       $     791         $     342
                                                                       =========        =========         =========
Net (loss) income allocable to managing and
   special general partners............................................$     (16)       $      33         $      14
                                                                       =========        =========         =========
Net (loss) income per LP and GP Unit...................................$   (.02)        $     .05         $    .02
                                                                       =========        =========         =========
Average LP and GP Units outstanding....................................   16,033           16,033            16,033
                                                                       =========        =========         =========
</TABLE>


                       See Notes to Financial Statements.



                                       21
<PAGE>   23

                KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
                            STATEMENTS OF CASH FLOWS

                                 (IN THOUSANDS)

<TABLE>
<CAPTION>
                                                                                   YEAR ENDED DECEMBER 31,
                                                                       ---------------------------------------------
                                                                          1998             1999              2000
                                                                       ---------        ----------        ----------
<S>                                                                     <C>              <C>               <C>
OPERATING ACTIVITIES:
   Net (loss) income................................................... $    (413)       $     824         $     356
   Adjustments to reconcile net (loss) income to net cash
     provided by operating activities:
     Gain on sale of properties........................................        --             (850)               --
     Depreciation, depletion and amortization..........................       427              225               120
     Impairment of oil and gas properties..............................       466               --                --
     Changes in operating assets and liabilities:
       Decrease (increase) in accounts receivable......................       251               75               (39)
       Increase (decrease) in accounts payable and accrued expenses....        14              (36)               23
                                                                        ---------       ----------        ----------
   Net cash provided by operating activities...........................       745              238               460
                                                                        ---------       ----------        ----------
INVESTING ACTIVITIES:
   Capital expenditures................................................       (52)             (14)               23
   Proceeds from sale of assets........................................        --            2,098                --
                                                                        ---------       ----------        ----------
   Net cash (used in) provided by investing activities.................       (52)           2,084                23
                                                                        ---------       ----------        ----------
FINANCING ACTIVITIES:
   Distributions.......................................................        --               --              (317)
   Payments on long-term borrowings....................................      (693)          (2,322)             (166)
                                                                        ---------       ----------        ----------
   Net cash used in financing activities...............................      (693)          (2,322)             (483)
                                                                        ---------       ----------        ----------

Increase (decrease) in cash and cash equivalents.......................        --               --                --

Cash and cash equivalents, beginning of period.........................        --               --                --
                                                                        ---------       ----------        ----------
Cash and cash equivalents, end of period............................... $      --        $      --         $      --
                                                                        =========       ==========        ==========
</TABLE>

                       See Notes to Financial Statements.




                                       22
<PAGE>   24



                KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
               STATEMENTS OF CHANGES IN PARTNERS' EQUITY (DEFICIT)

                                 (IN THOUSANDS)

<TABLE>
<CAPTION>
                                                                                         MANAGING
                                                                                            AND
                                                                                          SPECIAL
                                                              LP              GP          GENERAL
                                                         UNITHOLDERS     UNITHOLDERS      PARTNERS          TOTAL
                                                         -----------     -----------      --------          -----
<S>                                                      <C>             <C>              <C>               <C>
Partners' equity at January 1, 1998..................       $  21           $ 436           $  19           $ 476
                                                            -----           -----           -----           -----
Net loss.............................................         (41)           (356)            (16)           (413)
                                                            -----           -----           -----           -----
  Partners' (deficit) equity at December 31, 1998....         (20)             80               3              63
                                                            -----           -----           -----           -----
Net income...........................................          82             709              33             824
                                                            -----           -----           -----           -----
  Partners' equity at December 31, 1999..............          62             789              36             887
                                                            -----           -----           -----           -----
Distributions........................................         (31)           (273)            (13)           (317)
Net income...........................................          36             306              14             356
                                                            -----           -----           -----           -----
  Partners' equity at December 31, 2000..............       $  67           $ 822           $  37           $ 926
                                                            =====           =====           =====           =====
</TABLE>


                       See Notes to Financial Statements.



                                       23
<PAGE>   25

                KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
                          NOTES TO FINANCIAL STATEMENTS


NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

         Cash and Cash Equivalents. The Partnership considers all highly liquid
investments with an original maturity of three months or less when purchased to
be cash equivalents.

         Income Taxes. The income or loss of the Partnership for federal income
tax purposes is includable in the tax returns of the individual partners of the
Partnership. Accordingly, no recognition has been given to income taxes in the
accompanying financial statements.

         Oil and Gas Properties. Oil and gas properties are located in the
United States, and are held of record by Kelley Operating Company, Ltd. The
Partnership utilizes the successful efforts method of accounting for its oil and
gas operations. Under the successful efforts method, the costs of successful
wells and development dry holes are capitalized and amortized on a
unit-of-production basis over the life of the related reserves. Exploratory
drilling costs are initially capitalized pending determination of proved
reserves but are charged to expense if no proved reserves are found. Estimated
future abandonment and site restoration costs, net of anticipated salvage
values, are taken into account in depreciation, depletion and amortization.

         The Partnership's proved oil and gas properties are reviewed for
indications of impairment whenever events or circumstances indicate that the
carrying value of its oil and gas properties may not be recoverable. As a result
of a decline in its proved reserves at January 1, 1999 from year-earlier levels,
the Partnership performed an assessment of the fair value of its oil and gas
properties which indicated an impairment should be recognized. Under this
analysis, the fair value for the Partnership's proved oil and gas properties was
estimated using escalated pricing and present value discount factors reflecting
risk assessments. Based on this analysis, the Partnership recognized a non-cash
impairment charge of $466,000 against the carrying value of its proved oil and
gas properties at December 31, 1998.

         Oil and Gas Revenues. The Partnership recognizes oil and gas revenue
from its interests in producing wells as oil and gas is produced and sold from
those wells. Oil and gas sold is not significantly different from the
Partnership's production entitlement.

          Net Income or Loss Per Unit. Net income or loss per Unit is computed
based on the weighted average number of Units outstanding during the period
divided into the net income or loss allocable to the Unitholders.

         Financial Instruments. The Partnership's financial instruments consist
of cash and cash equivalents, receivables, payables, debt and commodity
derivatives. See Note 5 - "Hedging Activities". Management believes the carrying
amounts of the financial instruments classified in current assets or liabilities
approximate fair value due to their short-term nature.

         Derivative Financial Instruments. From time to time, the Partnership
has entered into transactions in derivative financial instruments covering
future oil and natural gas production principally as a hedge against natural gas
price declines. See Note 5 - "Hedging Activities" for a discussion of the
Partnership's accounting policies related to hedging activities.

          Concentration of Credit Risk and Significant Customers. Substantially
all of the Partnership's receivables are due from the marketing subsidiary of
Kelley Oil Corporation ("Kelley Oil"), which purchases approximately 80% of the
Partnership's natural gas for resale to a limited number of natural gas
transmission companies and other gas purchasers. To date, this concentration has
not had a material adverse effect on the financial condition of the Partnership.


                                       24
<PAGE>   26

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

         Reclassifications. Certain financial statement items in 1998 and 1999
have been reclassified to conform to the 2000 presentation. See Note 6.

NOTE 2 - LONG-TERM DEBT

         In August 1994, one of the credit facilities maintained by Kelley Oil
was modified to add the Partnership as a borrower, and $6 million was advanced
to the Partnership to fund part of its drilling overexpenditures. The
Partnership's bank debt was subsequently replaced by a $6 million loan from
Kelley Oil (the "Initial Loan") funded with borrowings by Kelley Oil under a
credit facility. Interest has been paid by the Partnership based on Contour's
borrowing cost resulting in an effective rate of 10 3/8% for 1998, 1999 and
2000. In 2000, the final payment of $166,000 was made on the $6,000,000 Initial
Loan.

NOTE 3 - CASH DISTRIBUTIONS

         The Partnership maintains a policy of distributing cash that is not
required for the conduct of Partnership business to Unitholders on a quarterly
basis. To meet its financial obligations for drilling overexpenditures, the
Partnership suspended distributions commencing in October 1994 and reinstated a
quarterly distribution for only one quarter in 1995. Operating cash flows since
1995 through the third quarter 2000 have been used to service the Partnership's
debt. See Note 3 - Long Term Debt. In February 2001, the fourth quarter 2000
earnings distribution was paid to the managing and special general partners and
the unitholders in the amounts of $13,000 and $304,000, or $0.02 per Unit,
respectively. However, future distributions to the unitholders and the managing
and special general partners are contingent on future operating results.

NOTE 4 - RELATED PARTY TRANSACTIONS

         The Unitholders have a 96.04% share and the general partners a 3.96%
share in the costs and revenues of the Partnership. The Partnership reimburses
Kelley Oil for all direct costs incurred in managing the Partnership and all
indirect costs (principally general and administrative expenses) allocable to
the Partnership.

         Overhead allocated to the Partnership by Kelley Oil for the years ended
December 31, 1998, 1999 and 2000 related to general and administrative expenses
aggregated $134,000, $92,000 and $62,000, respectively.

         Substantially all of the Partnership's gas sales are made to an
affiliated company, Concorde Gas Marketing, Inc., an indirect wholly-owned
subsidiary of Kelley Oil ("CGM"), which remarkets gas to third parties. For
1998, 1999 and 2000, a fee of 2% of the resale price was charged to the
Partnership by CGM for its marketing services.

         In December 2000, Kelley Oil invited the unit holders for the
Partnership to tender their units for cash. The cash offer was $0.123 per unit
for all of the Partnership units not held by Kelley Oil. A total of 1,298,724
Partnership units (50% of units eligible for tender) were tendered. The total
cost was approximately $200,000, including transaction costs. After the tender,
Kelley Oil owns 91.82% of the Units and a 3.94% General Partner interest.


                                       25
<PAGE>   27

NOTE 5 - HEDGING ACTIVITIES

         Historically, Contour has entered into hedge agreements on behalf of
the Partnership to protect against commodity price declines. Because of small
production volumes, beginning 2001, the Partnership production will no longer be
hedged.

         Contour periodically uses forward sales contracts, natural gas and
crude oil price swap agreements, collars and options to reduce exposure to
downward price fluctuations on its natural gas and crude oil production. Contour
does not engage in speculative transactions. During 2000, Contour used price
swap agreements and collars. Price swap agreements generally provide for Contour
to receive or make counterparty payments on the differential between a fixed
price and a variable indexed price for natural gas and crude oil. Collars
combine put and call options to establish a ceiling and a floor. Contour
normally employs the average NYMEX price for the last three days of the contract
for natural gas and the monthly average of closing NYMEX prices for crude oil as
the underlying index ("Index Price"). To the extent the Index Price closes above
the established ceiling Contour must make payments to the counterparty on the
differential between the Index Price and the ceiling. Conversely, if the Index
Price closes below the established floor, the counterparty must make payments to
Contour on the differential between the Index Price and the floor. If the Index
Price closes between the ceiling and the floor, no settlement is due. Gains and
losses realized by the Partnership from hedging activities are included in oil
and gas revenues and average sales prices in the period that the related
production is sold. Contour's hedging activities also cover the oil and gas
production attributable to the interest in such production of the public
unitholders in its subsidiary partnerships, including the production of the
Partnership, for 1998, 1999 and 2000.

         Through natural gas price swap agreements, the Partnership hedged
approximately 49% and 50%, respectively, of its natural gas production for 1998
and 1999, respectively, at average NYMEX quoted prices of $2.31 and $2.17 per
Mmbtu, respectively, before transaction and transportation costs. For 2000, the
Partnership hedged approximately 72% of its natural gas production using price
swap agreements (48%) and a costless collar (24%). The average price received
under the swap agreements was $2.59/Mmbtu. The costless collar included a
ceiling of $4.98/Mmbtu and a floor of $4.00/mmbtu at the closing Index Price. As
of December 31, 2000, none of the Partnership's anticipated natural gas
production for 2001 has been hedged

         Through crude oil price swap agreements, the Partnership hedged
approximately 29% of its crude oil production for 1999 at an average NYMEX
quoted price of $20.00 per bbl, before transaction and transportation costs. No
crude oil was hedged in 1998. For 2000, the Company hedged approximately 66% of
its crude oil production using price swap agreements (41%) and costless collars
(25%). The average price received under the swap agreements was $26.21/Bbl. The
costless collars included an average ceiling of $32.21/Bbl and an average floor
of $26.11/Bbl at the closing Index Price. As of December 31, 2000, none of the
Partnership's crude oil production for 2001 had been hedged.

         Hedging activities decreased Partnership oil and natural gas revenues
by approximately $17,000 and $109,000 in 1999 and 2000, respectively, and
increased such revenues by approximately $50,000 in 1998 as compared to
estimated revenues had no hedging activities been conducted.

         The credit risk exposure from counterparty nonperformance on natural
gas forward sales contracts and derivative financial instruments is generally
the amount of unrealized gains under the contracts. The Partnership has not
experienced counterparty nonperformance on these agreements.

NOTE 6 - NEW ACCOUNTING PRONOUNCEMENTS

         The Partnership adopted Statement of Financial Accounting Standards No.
133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133")
effective January 1, 2001. The statement, as amended, requires that all
derivatives be recognized as either assets or liabilities and measured at fair
value, and changes in the fair value of derivatives be reported in current
earnings, unless the derivative is designated and effective as a hedge. If the
intended



                                       26
<PAGE>   28



use of the derivative is to hedge the exposure to changes in the fair value of
an asset, a liability or firm commitment, then the changes in the fair value of
the derivative instrument will generally be offset in the income statement by
the change in the item's fair value. However, if the intended use of the
derivative is to hedge the exposure to variability in expected future cash flows
then the changes in fair value of the derivative instrument will generally be
reported in Other Comprehensive Income (OCI). The gains and losses on the
derivative instrument that are reported in OCI will be reclassified to earnings
in the period in which earnings are impacted by the hedged item.

         As of January 1, 2001, the Partnership is not party to any derivative
instruments and as such there is no impact on its financial statements as a
result of the adoption of SFAS 133.

         In the fourth quarter of 2000, the Partnership adopted Emerging Issues
Task Force Issue No. 00-10 ("EITF No. 00-10") accounting for Shipping and
Handling Fees and Costs. EITF No. 00-10 addresses how shipping and handling fees
should be classified in the income statement. As a result of EITF No. 00-10, the
Partnership has reclassified its transportation and compression expenses from
oil and gas revenues to production expenses. As a result, $97,000, $48,000 and
$7,000 of expenses were reclassified from oil and gas revenues to production
expenses for the years ended December 31, 1998, 1999 and 2000, respectively.

NOTE 7 - SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND GAS EXPLORATION,
         DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)

         This section provides information required by Statement of Financial
Accounting Standards No. 69, "Disclosures about Oil and Gas Producing
Activities."

         Capitalized costs. Capitalized costs and accumulated depreciation,
depletion and amortization relating to oil and gas producing activities, all of
which are conducted within the continental United States, are summarized below.

                                                   (IN THOUSANDS)

<TABLE>
<CAPTION>
                                                                                  YEAR ENDED DECEMBER 31,
                                                                      ---------------------------------------------
                                                                         1998              1999             2000
                                                                      ----------       ----------         ---------
<S>                                                                   <C>              <C>                <C>
Properties subject to amortization................................... $   44,354       $   41,466         $  41,443
Accumulated depreciation, depletion and amortization.................    (41,826)         (40,396)          (40,516)
                                                                      ----------       ----------         ---------
   Net capitalized costs............................................. $    2,528       $    1,070         $     927
                                                                      ==========       ==========         =========
</TABLE>

         Costs Incurred. All costs were incurred in oil and gas property
development activities (as defined in the Partnership Agreement) and aggregated
$52,000, $14,000 and $(23,000) in 1998, 1999 and 2000, respectively.

         Reserves. The following table summarizes the Partnership's net
ownership interests in estimated quantities of proved oil and gas reserves and
changes in net proved reserves, all of which are located in the continental
United States, for the years ended December 31, 1998, 1999 and 2000.

         Oil and gas proved reserves cannot be measured exactly. Reserve
estimates are inherently imprecise and may be expected to change as additional
information becomes available. Estimates of oil and gas reserves, of necessity,
are projections based on engineering data, and there are uncertainties inherent
in the interpretation of such data as well as the projection of future rates of
production and the timing of development expenditures. Reserve estimates are
based on many factors related to reservoir performance which require evaluation
by the engineers interpreting the available data, as well as price and other
economic factors. The reliability of these estimates at any point in time
depends on the quality and quantity of the technical and economic data, the
production performance of the reservoirs as well as extensive engineering
judgment. Further, estimates of the economically recoverable quantities of oil
and natural gas attributable to any particular group of properties,
classifications of such reserves based on risk of recovery and estimates of the
future net revenues expected therefrom prepared by different engineers or by the
same engineers at different times


                                       27
<PAGE>   29

may vary substantially. Consequently, reserve estimates are subject to revision
as additional data becomes available during the producing life of a reservoir.
There also can be no assurance that the reserves set forth herein will
ultimately be produced. In addition, the estimates of future net revenues from
proved reserves of the Partnership and the present value thereof are based upon
certain assumptions about future production levels, prices and costs that may
not be correct when judged against actual subsequent experience.
<TABLE>
<CAPTION>
                                                       CRUDE OIL, CONDENSATE
                                                      AND NATURAL GAS LIQUIDS                    NATURAL GAS
                                                              (Mbbls)                               (Mmcf)
                                                  ------------------------------      ------------------------------
                                                   1998        1999        2000        1998        1999        2000
                                                  ------      ------      ------      ------      ------      ------
<S>                                               <C>         <C>         <C>         <C>         <C>         <C>
Proved developed and undeveloped reserves:
   Beginning of year ........................         78          88          64       5,521       3,759       1,196
   Revisions of previous estimates ..........         20          (9)         15      (1,161)       (187)        200
   Extensions and discoveries ...............         --          --          --          --          --          --
   Sale of oil and gas properties ...........         --          (6)         --          --      (2,062)         --
   Production ...............................        (10)         (9)         (9)       (601)       (314)       (149)
                                                  ------      ------      ------      ------      ------      ------
     End of year ............................         88          64          70       3,759       1,196       1,247
                                                  ======      ======      ======      ======      ======      ======
Proved developed reserves
   at end of year ...........................         88          64          70       3,759       1,196       1,247
                                                  ======      ======      ======      ======      ======      ======
</TABLE>


         Standardized Measure. The following table of the Standardized Measure
of Discounted Future Net Cash Flows concerning the standardized measure of
future cash flows from proved oil and gas reserves are presented in accordance
with Statement of Financial Accounting Standards No. 69. As prescribed by this
statement, the amounts shown are based on prices and costs at the end of each
period, and with a 10% annual discount factor. Extensive judgments are involved
in estimating the timing of production and the costs that will be incurred
throughout the remaining lives of the fields. Accordingly, the estimates of
future net revenues from proved reserves and the present value thereof may not
be materially correct when judged against actual subsequent results. Further,
since prices and costs do not remain static, and no price or cost changes have
been considered, and future production and development costs are estimates to be
incurred in developing and producing the estimated proved oil and gas reserves,
the results are not necessarily indicative of the fair market value of estimated
proved reserves, and the results may not be comparable to estimates disclosed by
other oil and gas producers.

                                                   (IN THOUSANDS)


<TABLE>
<CAPTION>
                                                                           AS OF DECEMBER 31,
                                                                 ------------------------------------
                                                                   1998          1999          2000
                                                                 --------      --------      --------
<S>                                                              <C>           <C>           <C>
Future cash inflows ........................................     $  8,617      $  4,269      $ 14,394
Future production costs ....................................       (3,295)       (1,581)       (3,179)
Future development costs ...................................         (186)          (55)          (52)
                                                                 --------      --------      --------
  Future net cash flows ....................................        5,136         2,633        11,163
10% annual discount for estimating timing of cash flows ....       (1,964)         (933)       (4,883)
                                                                 --------      --------      --------
  Standardized measure of discounted future net cash flows .     $  3,172      $  1,700      $  6,280
                                                                 ========      ========      ========
</TABLE>

         Future cash inflows are computed by applying year-end prices of oil and
gas to year-end quantities of proved oil and gas reserves. Future production and
development costs are computed by Kelley Oil's petroleum engineers by estimating
the expenditures to be incurred in developing and producing the Partnership's
proved oil and gas reserves at the end of the year, based on year-end costs and
assuming continuation of existing economic conditions.


                                       28
<PAGE>   30

         A discount factor of 10% was used to reflect the timing of future net
cash flows. The standardized measure of discounted future net cash flows is not
intended to represent the replacement cost or fair market value of the
Partnership's oil and gas properties.

         The standardized measure of discounted future net cash flows as of
December 31, 1998, 1999 and 2000 was calculated using prices in effect as of
those dates, which averaged $9.88, $25.46 and $26.45, respectively, per barrel
of oil and $2.06, $2.15 and $10.05, respectively, per Mcf of natural gas.

         Changes in Standardized Measure. Changes in standardized measure of
future net cash flows relating to proved oil and gas reserves are summarized
below.

                                                   (IN THOUSANDS)
<TABLE>
<CAPTION>

                                                                           YEAR ENDED DECEMBER 31,
                                                                      ---------------------------------
                                                                        1998         1999         2000
                                                                      -------      -------      -------
<S>                                                                   <C>          <C>          <C>
Changes due to current year operations:
   Sales of oil and gas, net of production costs ................     $  (901)     $  (465)     $  (544)
   Sales of reserves in place ...................................          --       (1,668)          --
   Extensions and discoveries, net of future production costs ...          --           --           --
   Development costs incurred during the year ...................          --           --           --
Changes due to revisions in standardized variables:
   Prices and production costs ..................................      (2,304)         557        4,003
   Revisions of previous quantity estimates .....................        (766)         152        1,096
   Estimated future development costs ...........................         (53)         (97)          20
   Accretion of discount ........................................         662          317          170
   Production rates (timing) and other ..........................         (84)        (268)        (165)
                                                                      -------      -------      -------
     Net increase (decrease) ....................................      (3,446)      (1,472)       4,580
Beginning of year ...............................................       6,618        3,172        1,700
                                                                      -------      -------      -------
End of year .....................................................     $ 3,172      $ 1,700      $ 6,280
                                                                      =======      =======      =======
</TABLE>


ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
         FINANCIAL DISCLOSURES

         None.


                                       29
<PAGE>   31



                                    PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF KELLEY OIL CORPORATION


GENERAL

         The Partnership has no directors, officers or employees. Directors and
officers of Kelley Oil perform all management functions for the Partnership.
Kelley Oil had 45 employees as of December 31, 2000, and its staff includes
employees experienced in geology, geophysics, petroleum engineering, land
acquisition and management, finance, accounting, and administration.

BACKGROUND OF KELLEY OIL

         Kelley Oil is an oil and gas operating company formed in April 1983.
Since January 1986, Kelley Oil has been engaged in the management of the DDPs.
Since the Consolidation in February 1995, Kelley Oil has been a wholly-owned
subsidiary of Contour Energy Co. (formerly Kelley Oil & Gas Corporation).

EXECUTIVE OFFICERS OF KELLEY OIL

         Set forth below are the names, ages and positions of the current
executive officers and directors of Kelley Oil. All directors are elected for a
term of one year and serve until their successors are duly elected and
qualified. All executive officers hold office until their successors are duly
appointed and qualified.

<TABLE>
<CAPTION>
                                                                                                             OFFICER
                                                                                                               OR
                                                                                                           DIRECTOR OF
                                                                                                           THE COMPANY
NAME                              AGE    POSITION                                                             SINCE
----                              ---    --------                                                          -----------
<S>                               <C>    <C>                                                               <C>
John F. Bookout.................  78     President, Chief Executive Officer and  a director                   1996
Rick G. Lester..................  49     Senior Vice President and Chief Financial Officer and a director     1998
Kenneth R. Sanders..............  51     Senior Vice President - Exploration and Production and a director    1999
</TABLE>


         John F. Bookout joined Kelley Oil as Chairman of the Board, President
and Chief Executive Officer in February 1996. He served as Chairman of the Board
of Contour Production Company L.L.C. ("Contour") since its inception in 1993.

         Rick G. Lester was elected Senior Vice President and Chief Financial
Officer and a director of Kelley Oil in October 1998. Previously, he was Vice
President and Chief Financial Officer of Domain Energy Corporation.

         Kenneth R. Sanders has served as Senior Vice President - Exploration
and Production and a director of Kelley Oil since August 1999. Previously, he
was Vice-President - Exploitation, Acquisitions & Engineering of Seagull Energy
E&P, Inc.


BENEFICIAL OWNERSHIP REPORTING

         Not applicable.


                                       30
<PAGE>   32

ITEM 11.  EXECUTIVE COMPENSATION

         Not applicable.  See "Certain Relationships and Related Transactions."

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

BENEFICIAL OWNERS

         The following table sets forth information as of December 31, 2000 with
respect to the only Unitholder known by the Partnership to own beneficially more
than five percent of the Partnership's Units.

<TABLE>
<CAPTION>
                                                       AMOUNT & NATURE
NAME AND ADDRESS OF                                     OF BENEFICIAL                                     PERCENT
BENEFICIAL OWNER                                          OWNERSHIP                                       OF CLASS
-------------------                                    ---------------                                    --------
<S>                                                    <C>                                                <C>
Kelley Oil Corporation                                   14,721,034                                        91.82%
601 Jefferson, Suite 1100                                  Direct
Houston, Texas  77002
</TABLE>


MANAGEMENT

         The following table sets forth information as of December 31, 2000 with
respect to Units beneficially owned, directly or indirectly, by each of the
directors of Kelley Oil and by all officers and directors of Kelley Oil as a
group.

<TABLE>
<CAPTION>
                                                       AMOUNT & NATURE
NAME AND ADDRESS OF                                     OF BENEFICIAL                                     PERCENT
BENEFICIAL OWNER                                         OWNERSHIP(1)                                     OF CLASS
-------------------                                    ---------------                                    --------
<S>                                                    <C>                                                <C>
John F. Bookout                                                --                                             --
Kenneth R. Sanders                                             --                                             --
Rick G. Lester                                                 --                                             --
All directors and officers
   as a group (8 persons)                                    None                                           None
</TABLE>

(1)   Represents direct beneficial ownership.

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

         The Unitholders have a 96.04% share and the General Partners a 3.96%
share in the costs and revenues of the Partnership. Allocations of costs and
revenues to Unitholders are made in accordance with the number of Units owned.
The General Partners contributed $1,983,258 to the Partnership for their 3.96%
interest in the same proportion as the deferred subscriptions for Units were
payable.

         Kelley Oil is reimbursed for its direct costs and an allocable portion
of its general and administrative expenses incurred as Managing General Partner.
See Note 4 in the Notes to Financial Statements.

         It is the policy of the Partnership to engage in transactions with
related parties only on terms that are no less favorable to the Partnership than
could be obtained on an arm's-length basis from unrelated parties. The
Partnership believes that all payments to related parties are reasonable and in
amounts not greater than fees that would be charged on an arm's-length basis by
unrelated parties.


                                       31
<PAGE>   33

                                     PART IV

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

     (a) FINANCIAL STATEMENTS AND SCHEDULES:

         (1)  Financial Statements: The financial statements required to be
              filed are included under Item 8 of this Report.

         (2)  Schedules: Schedules for which provision is made in applicable
              accounting regulations of the SEC are not required under the
              related instructions or are inapplicable, and therefore have been
              omitted.

         (3)  Exhibits:

         EXHIBIT
         NUMBER:      EXHIBIT

              4.1     Amended and Restated Agreement of Limited Partnership of
                      the Registrant (included as Exhibit A to the Prospectus
                      forming part of the Registrant's Registration Statement on
                      Form S-1 (File No. 33-51250) filed on August 26, 1992, as
                      amended (the "Registration Statement") and incorporated
                      herein by reference).

              4.2     Joint Venture Agreement of Kelley Partners 1992
                      Development Drilling Joint Venture (incorporated by
                      reference to Exhibit B to the Prospectus forming part of
                      the Registration Statement).

              4.3     Amendment to Amended and Restated Agreement of Limited
                      Partnership of the Registrant.

     (b) REPORTS ON FORM 8-K:

         No reports on Form 8-K were filed by the Registrant during the fourth
quarter of 2000.


                                       32
<PAGE>   34

                                   SIGNATURES


         Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized, this 28 day of March
2001.


                KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM


              By: KELLEY OIL CORPORATION, Managing General Partner




By:      /s/ John F. Bookout                By:     /s/ Rick G. Lester
   ---------------------------------           --------------------------------
           John F. Bookout                            Rick G. Lester
       Chief Executive Officer                     Senior Vice President
                                                and Chief Financial Officer



         Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed as of the 28 day of March 2001 by the following
persons in their capacity as directors of the Registrant's managing general
partner.


         /s/ John F. Bookout                       /s/ Kenneth R. Sanders
   ---------------------------------           --------------------------------
           John F. Bookout                            Kenneth R. Sanders


         /s/ Rick G. Lester
   ---------------------------------
           Rick G. Lester


                                       33


<PAGE>   35

                               INDEX TO EXHIBITS


<TABLE>
<CAPTION>

EXHIBIT
 NUMBER:     EXHIBIT
-------      -------
<S>          <C>

  4.1        Amended and Restated Agreement of Limited Partnership of the
             Registrant (included as Exhibit A to the Prospectus forming part of
             the Registrant's Registration Statement on Form S-1 (File No.
             33-51250) filed on August 26, 1992, as amended (the "Registration
             Statement") and incorporated herein by reference).

  4.2        Joint Venture Agreement of Kelley Partners 1992 Development
             Drilling Joint Venture (incorporated by reference to Exhibit B to
             the Prospectus forming part of the Registration Statement).

  4.3        Amendment to Amended and Restated Agreement of Limited Partnership
             of the Registrant.
</TABLE>