<PAGE>   1
================================================================================

                       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. 0-23784


                              KELLEY PARTNERS 1994
                          DEVELOPMENT DRILLING PROGRAM
             (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)


                 TEXAS                                   76-0419001
    (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 1994 Development Drilling Program had
20,864,414 units of limited and general partner interests (the "Units")
outstanding. The Units are not publicly traded.



================================================================================


<PAGE>   2



                                     PART I

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

INTRODUCTION

         General. Kelley Partners 1994 Development Drilling Program, a Texas
limited partnership (the "Partnership") was formed in 1994 to develop oil and
gas properties located onshore in Louisiana. The Partnership issued a total of
20,864,414 units of limited and general partner interests ("Units"),
representing 96.04% of the total interests in the Partnership, for $62,593,242.
Of this amount, the Partnership distributed $4.3 million and $1.1 million of
uncommitted capital during 1996 and 1997, respectively. See "Development and
Production" below. The Units consist of 1,194,782 Units of limited partner
interests ("LP Units") and 19,669,632 Units of general partner interests ("GP
Units"). In addition, the Partnership issued managing and special general
partner interests, representing the remaining 3.96% of the total interests in
the Partnership, for $2,580,897. In the aggregate, Kelley Oil Corporation, a
Delaware corporation, the managing general partner of the Partnership (the
"Managing General Partner" or "Kelley Oil"), owns 95.76% 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 $0.28 per unit
for all of the Partnership units not held by Kelley Oil. A total of 783,621
Partnership units (46% of units eligible for tender) were tendered. The total
cost was approximately $265,000, including transaction costs. After the tender,
Kelley Oil owns 95.61% 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 has contributed to the Joint Venture substantially all of
the partners' contributed capital in order 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 has contributed to the Joint Venture specific drilling
rights for wells on its properties selected by the Managing General Partner. In
return for the contributed drilling rights, Kelley Operating has a 20%
reversionary interest after Payout (as defined in the Joint Venture Agreement)
in the costs and revenues of the Joint Venture. Payout occurred in the third
quarter of 2000.

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



                                       1
<PAGE>   3



         Development and Production. As of January 1, 2001, the Partnership had
participated in drilling 92 gross (29.31 net) wells, of which 88 gross (26.64
net) wells have been found to be productive and 4 gross (2.67 net) wells were
dry. From its inception through December 31, 2000, the Partnership produced 25.3
Bcf of natural gas and 177,123 barrels of oil and natural gas liquids,
generating total oil and gas revenues of $59.1 million. Of this amount, $58.1
million or $2.67 per Unit has been distributed to the partners (includes $8.3
million or $0.38 per unit related to the sale of properties in 1999 to Phillip
Petroleum Company ("Phillips Transaction").

         The Partnership Agreement restricts activities of the Partnership to
the financing of development wells drilled by the Joint Venture and requires any
contributions of the partners not used or committed to be used for drilling
activities within two years after the commencement of operations (the
"Commitment Period"), except for necessary operating capital, to be distributed
to the partners on a pro rata basis as a return of capital. Accordingly, the
Partnership distributed $4.3 million of uncommitted capital or $0.20 per Unit
during 1996. In 1996, Kelley initiated a program for streamlining operations,
improving drilling efficiency and reducing lease operating expenses. As a
result, during 1997 Kelley revised its estimate of the necessary partnership
capital and distributed additional uncommitted funds of $1.1 million or $0.05
per Unit to the partners as a return of capital.

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 ...............         57         16          9
   Proved undeveloped .............          2          1         --
                                        ------     ------     ------
     Total proved .................         59         17          9
                                        ======     ======     ======

Natural gas (Mmcf):
   Proved developed ...............     22,730      9,312      6,295
   Proved undeveloped .............      1,633        754         --
                                        ------     ------     ------
     Total proved .................     24,363     10,066      6,295
                                        ======     ======     ======
</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 6 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. There are numerous uncertainties
in estimating quantities of proved reserves believed to have been discovered and
in projecting future rates of production and the timing of development
expenditures, including many factors beyond the control of the Partnership. The
reserve data set forth in this document are only estimates. Reserve estimates
are inherently imprecise and may be expected to change as additional information
becomes available. Furthermore, estimates of oil and natural 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. Reservoir engineering is a subjective process of estimating
underground accumulations of oil and natural gas that cannot be measured
exactly, and the accuracy of any reserve estimate is a function of the quality
of available data and of engineering and geological interpretation and judgment.
Accordingly, 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 cash
flows expected therefrom prepared by different engineers or by the same
engineers at different times may vary substantially. There also can be no
assurance that the reserves set forth herein will ultimately be produced. It is
possible that variances from the estimates will be material.

DESCRIPTION OF SIGNIFICANT PROPERTIES

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

         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.



                                       3
<PAGE>   5


                          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>
NORTH LOUISIANA:
   Sibley field .....................      3     4,200     4,218      66.4       1.0       641       647      76.3
   Ada field ........................      4     2,088     2,112      33.3        .4       180       182      21.5
SOUTH LOUISIANA:
   Orange Grove/Humphreys field .....      2         7        19        .3       1.6         9        19       2.2
                                       -----     -----     -----     -----     -----     -----     -----     -----
     Total ..........................      9     6,295     6,349     100.0       3.0       830       848     100.0
                                       =====     =====     =====     =====     =====     =====     =====     =====
</TABLE>


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

                                 NORTH LOUISIANA

         Sibley Field. The Sibley field is located in Webster Parish, Louisiana.
The Partnership has interests in 24 gross (3.6 net) wells producing from the
Hosston A, B and C formations at depths ranging from 4,600 to 8,900 feet. Kelley
Oil operates 16 of the wells. The Sibley field reserves are 100% proved
developed.

         Ada Field. The Ada field is located in Bienville and Webster Parishes,
Louisiana. The Partnership has an interest in 5 gross (1.0 net) wells producing
from the Hosston A and B formations at depths ranging from 7,500 to 8,600 feet.
Kelley Oil operates one of the wells. The Ada 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 interests in 1
gross (.28 net) well producing from the Realty formation at a depth of 11,200
feet that Kelley Oil operates. The Orange Grove/Humphreys field reserves are
100% proved developed.


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 Information.


                             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) .....     21,487      8,792      3,031
Natural gas (Mmcf) .......................................      3,914      1,748        830
</TABLE>




                                       4
<PAGE>   6
                    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 ........     $13.48     $15.26     $28.80
   Natural gas per Mcf, including the effects of hedging(1) .....       2.24       2.13       3.24

Oil and gas revenues per Mcf(1) .................................       2.24       2.14       3.27
Average production costs per Mcfe(1) ............................        .56        .56        .68
</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 $.19/Mcfe, $.18/Mcfe and $.14/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 5 in Notes to 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 ......................................................................        2      .31
Gas wells ......................................................................       28     4.57
                                                                                     ----     ----
   Total .......................................................................       30     4.88
                                                                                     ====     ====
</TABLE>


     (1) One or more completions in the same hole are counted as one well; one
         of the wells has 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 years ended December 31, 1998, 1999 and 2000, based on a
narrower definition for development wells under guidelines established by the
SEC.


<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 ...................      1           --          --         --        .31           --         --          --
1999 ...................     --           --          --         --         --           --         --          --
2000 ...................     --           --          --         --         --           --         --          --
</TABLE>


         Wells in Progress. At December 31, 2000, no wells were in progress of
drilling.

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 of its natural gas at current market
prices. Its revenue streams are therefore sensitive to changes



                                       5
<PAGE>   7



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.

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.




                                       6
<PAGE>   8


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 Partnership'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 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.



                                       7
<PAGE>   9



         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 Partnership 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 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 Partnership 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



                                       8
<PAGE>   10



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
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

         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.



                                       9
<PAGE>   11



ITEM 3. LEGAL PROCEEDINGS

         The Partnership 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 380 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 ..............................................................     $    .11
Second quarter .............................................................          .12
Third quarter ..............................................................          .08
Fourth quarter .............................................................          .07
                                                                                 --------
  Total ....................................................................     $    .38
                                                                                 ========

1999
First quarter ..............................................................     $    .05
Second quarter .............................................................          .09
Third quarter ..............................................................          .42
Fourth quarter .............................................................          .01
                                                                                 --------
  Total ....................................................................     $    .57
                                                                                 ========

2000
First quarter ..............................................................     $    .02
Second quarter .............................................................          .02
Third quarter ..............................................................          .02
Fourth quarter .............................................................          .05
                                                                                 --------
  Total ....................................................................     $    .11
                                                                                 ========
</TABLE>


         The distribution for each quarter in which payments were made
represents substantially all of the Partnership's net available cash from the
preceding quarter's operations. The Partnership made distributions for the year
2000 aggregating $2,336,000 to the unitholders, or $0.11 per Unit, and $96,000
to the Managing and Special General Partners for their interest. In February
2001, the fourth quarter 2000 distribution was paid to the managing and special
general partners and the unitholders in the amounts of $45,000 and $1,085,000,
or $0.05 per Unit, respectively. Distribution levels are affected by numerous
factors, including oil and gas prices, production levels and operating costs,
together with any working capital requirements. Future distributions to the
unitholders and 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 1994 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) .........................     $20,240     $16,556     $ 8,822     $ 5,724     $ 2,700
   Production expenses(1) .......................       2,348       2,622       2,256       1,012         577
   Exploration expenses .........................         606         369          --          --          --
   General and administrative expenses ..........         854         934         854         454         259
   Depreciation, depletion and amortization .....       5,536       4,631       3,080       1,124         693
   Impairment of oil and gas properties .........          --          --          81          --          --
   Net income ...................................      10,896       8,000       2,551       3,134       1,171
   Net income per Unit(2) .......................         .50         .37         .12         .14         .05
   Units outstanding ............................      20,864      20,864      20,864      20,864      20,864
</TABLE>


<TABLE>
<CAPTION>
                                                                         AS OF  DECEMBER 31,
                                                      -------------------------------------------------------
                                                         1996        1997        1998        1999        2000
                                                      -------     -------     -------     -------     -------
<S>                                                   <C>         <C>         <C>         <C>         <C>
SUMMARY BALANCE SHEET DATA:
   Working capital ..............................     $ 3,647     $ 5,551     $ 2,923     $   800     $     2
   Oil and gas properties, net ..................      19,035      15,743      12,667       5,487       5,024
   Total partners' equity .......................      22,682      21,294      15,590       6,287       5,026
   Total assets .................................      25,479      21,781      15,763       6,408       5,396
</TABLE>



(1)      Total Revenues and Production expenses have been restated for the years
         1997, 1998, 1999 and 2000 in accordance with a new accounting
         pronouncement. See Note 5 in the Notes to Financial Statements and
         "Management's Discussion and Analysis of Financial Conditions and
         Results of Operations".

(2)      Per Unit amounts are based on the Unitholders' 96.04% share of net
         income.

(3)      1999 includes gain on the sale of properties of $1,993.


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

GENERAL

         In 1994, Kelley Partners 1994 Development Drilling Program (the
"Partnership") issued a total of 20,864,414 units of limited and general partner
interests ("Units") at $3.00 per Unit for total subscription commitments of
$62,593,242. The Units represent 96.04% of the total interests in the
Partnership and consist of 1,194,782 Units of limited partner interests ("LP
Units") and 19,669,632 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 subscription commitments of
$2,580,897, representing 3.96% of the total interests in the Partnership. As of
December 31, 2000, Kelley Oil Corporation, managing general partner of the
Partnership ("Kelley Oil") and a wholly-owned subsidiary of Contour Energy Co.
("Contour"), owns 95.61% of the Units, together with its 3.94% managing general
partnership interest.



                                       12
<PAGE>   14


         Kelley Oil did not have adequate current liquidity or capital resources
to fund its entire subscription commitment by the end of the deferred payment
period in November 1994. Kelley Oil has made subsequent contributions, together
with interest at a market rate, as funds were needed for the Partnership's
drilling activities. As of December 31, 1997, Kelley Oil had fully funded its
subscription commitment. See "Liquidity and Capital Resources".

         In December 2000, Kelley Oil invited the unit holders for the
Partnership to tender their units for cash. The cash offer was $0.28 per unit
for all of the Partnership units not held by Kelley Oil. A total of 783,621
Partnership units (46% of units eligible for tender) were tendered. The total
cost was approximately $265,000, including transaction costs. After the tender,
Kelley Oil owns 95.61% of the Units and a 3.94% General Partner interest.

         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 4
in 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 $31,000 and $498,000 in 1999 and 2000, respectively, and
increased such revenues by approximately $370,000 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.

         Drilling Operations. Since inception, the Partnership participated in
drilling 92 gross (29.31 net) wells, of which 88 gross (26.64 net) wells were
found productive and 4 gross (2.67 net) wells were dry.

RESULTS OF OPERATIONS

         Years Ended December 31, 2000 and 1999. Oil and gas revenues of
$2,700,000 for 2000 decreased 28% compared to $3,731,000 in 1999 as a result of
lower natural gas and crude oil production volumes, partially offset by higher
natural gas and crude oil prices. Production of natural gas decreased 53% from
1,748,000 Mcf in 1999 to 830,000 Mcf in 2000. Production of crude oil decreased
66% from 8,792 barrels in 1999 to 3,031 barrels in 2000. 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.



                                       13
<PAGE>   15



         Lease operating expenses and severance taxes were $577,000 in 2000
versus $1,012,000 in 1999, a decrease of 43%, primarily related to the sale of
properties to Phillips. On a unit of production basis, these expenses increased
to $0.68 per Mcfe in 2000 from $0.56 per Mcfe in 1999. Transportation and
compression expenses of $325,000 ($0.18 per Mcfe) and $122,000 ($0.14 per Mcfe)
were included in lease operating expense for 1999 and 2000, respectively, as a
result of a new accounting pronouncement. See Note 5 in Notes to Financial
Statements.

         General and administrative expenses of $259,000 in 2000 decreased 43%
from $454,000 in 1999, reflecting the Partnership's share of administration
costs associated with development operations of Contour. On a unit of production
basis, these expenses increased to $0.31 per Mcfe in 2000 from $0.25 per Mcfe in
1999.

         Depreciation, depletion and amortization ("DD&A") expense decreased 38%
from $1,124,000 in 1999 to $693,000 in 2000, primarily as a result of lower
current period production related to the sale of properties to Phillips. On a
unit-of-production basis, DD&A increased to $0.82 per Mcfe in 2000 from $0.62
per Mcfe in 1999.

         The Partnership recognized net income in 2000 of $1,171,000 or $0.05
per Unit compared to net income of $3,134,000, including a $1,993,000 gain on
sale of properties, or $0.14 per Unit in 1999, reflecting the foregoing
developments.

         Years Ended December 31, 1999 and 1998. Oil and gas revenues of
$3,731,000 for 1999 decreased 58% compared to $8,822,000 in 1998 as a result of
lower natural gas and crude oil production volumes. Production of natural gas
decreased 55% from 3,914,000 Mcf in 1998 to 1,748,000 Mcf in 1999. Production of
crude oil decreased 59% from 21,487 barrels in 1998 to 8,792 barrels in 1999.
Oil and gas production decreased due to the sale of properties to Phillips and
natural depletion.

         In 1999, the Partnership recognized a $1,993,000 gain on the sale of
the north Louisiana fields to Phillips.

         Lease operating expenses and severance taxes were $1,012,000 in 1999
versus $2,256,000 in 1998, a decrease of 55%, primarily related to the sale of
properties to Phillips. On a unit of production basis, these expenses for both
2000 and 1999 was $0.56 per Mcfe. Transportation and compression expenses of
$741,000 ($0.19 per Mcfe) and $325,000 ($0.18 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 $454,000 in 1999 decreased 47%
from $854,000 in 1998, reflecting the Partnership's share of administration
costs associated with development operations of Contour. On a unit of production
basis, these expenses increased from $0.21 per Mcfe in 1998 to $0.25 per Mcfe in
1999.

         DD&A expense decreased 64% from $3,080,000 in 1998 to $1,124,000 in
1999, primarily as a result of lower current period production related to the
sale of properties to Phillips. On a unit-of-production basis, DD&A decreased
from $0.76 per Mcfe in 1998 to $0.62 per Mcfe in 1999.

         In 1998, the Partnership recognized a non-cash impairment charge of
$81,000 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 $3,134,000 or $0.14
per Unit compared to net income of $2,551,000 or $0.12 per Unit in 1998,
reflecting the foregoing developments.

LIQUIDITY AND CAPITAL RESOURCES

         Liquidity. Net cash provided by the Partnership's operating activities
during 2000, as reflected on its statements of cash flows, totaled $2,662,000.
During the year, funds used by investing activities consisted of capital



                                       14
<PAGE>   16



expenditures of $230,000. Funds used in financing activities consisted of cash
distributions to partners of $2,432,000. As a result of these activities, the
Partnership's cash and cash equivalents was 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 Partnership Agreement contemplates pro rata
contributions from the Unitholders and the General Partners of $62,593,242
(96.04%) and $2,580,897 (3.96%), respectively, or an aggregate of $65,174,139
("Contemplated Capital"). Under the deferred payment option applicable to
investments in the Partnership exceeding $10,000, deferred subscriptions for
Units and the General Partners' deferred contributions were payable when called
by Kelley Oil during the period ended November 30, 1994. Kelley Oil initially
subscribed for 18,821,655 Units in addition to its 3.94% General Partner
interest in the Partnership. Following defaults by Public Unitholders on a total
of 342,234 Units, the defaulted Units were subscribed by Kelley Oil in
accordance with its undertaking in the Partnership Agreement. This increased
Kelley Oil's total subscription commitment to $60,059,529 or 92.2% of the
Partnership's total Contemplated Capital (the "KOIL Share"), with the Public
Unitholders committing for the balance or 7.85% of the total Contemplated
Capital (the "Public Share").

         The Partnership Agreement requires any contributions of the partners
not used or committed to be used for drilling activities during the two-year
Commitment Period ended February 29, 1996, except for necessary operating
capital, to be distributed to the partners on a pro rata basis as a return of
capital. For this purpose, "committed for use" means funds that have been
contracted or allocated by Kelley Oil for drilling, completion or other
Partnership activities, and "necessary operating capital" means funds that, in
the opinion of Kelley Oil, should remain in reserve to assure the continued
operation of the Partnership.

         On February 29, 1996, the Contemplated Capital exceeded the Committed
Expenditures. Accordingly, the excess Contemplated Capital aggregating
$4,345,000 or $0.20 per Unit was distributed as a return of capital during 1996.
In 1996, Kelley Oil initiated a program for streamlining operations, improving
drilling efficiency and reducing lease operating costs. These efforts generated
cost savings that effectively reduced the February 1996 estimate for Committed
Expenditures. As a result, during 1997 Kelley Oil revised its estimate of the
necessary partnership capital and distributed additional uncommitted funds of
$1,086,000 or $0.05 per Unit to the partners as a return of capital.

         During the first six months of 1997, Kelley Oil contributed the final
portion of its commitment to the Partnership with capital contributions of
$5,819,000. Cash flows from operations are expected to be adequate to meet the
Partnership's capital expenditure and working capital needs.

         Distribution Policy. The Partnership maintains a policy of distributing
the maximum amount of its net available cash to Unitholders on a quarterly
basis. The Partnership made distributions for the year 2000 aggregating
$2,336,000 to the unitholders, or $0.11 per Unit, and $96,000 to the Managing
and Special General Partners for their interest. However, future distributions
to the unitholders and managing and special general partners are contingent on
future operating results.



                                       15
<PAGE>   17



         Inflation and Changing Prices. Oil and natural gas prices 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 the
Partnership during the periods indicated.

<TABLE>
<CAPTION>
                                                      AVERAGE    AVERAGE
                                                     OIL PRICE  GAS PRICE
                                                      ($/Bbl)    ($/Mcf)
                                                     ---------  ---------
<S>                                                  <C>        <C>
YEAR ENDED:
   December 31, 1998 .............................     13.48      2.24
   December 31, 1999 .............................     15.26      2.13
   December 31, 2000 .............................     28.80      3.24
</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 Activities.



                                       17
<PAGE>   19



ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


         INDEX TO FINANCIAL STATEMENTS

KELLEY PARTNERS 1994 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 - 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 1994 Development Drilling Program:


We have audited the accompanying balance sheets of Kelley Partners 1994
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 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 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 1994 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 1994 DEVELOPMENT DRILLING PROGRAM
                                 BALANCE SHEETS

                                 (IN THOUSANDS)


<TABLE>
<CAPTION>
                                                                              DECEMBER 31,
                                                                        ----------------------
                                                                          1999          2000
                                                                        --------      --------
<S>                                                                     <C>           <C>
ASSETS:
   Cash ...........................................................     $     --     $      --
   Accounts receivable - trade ....................................           16             9
   Accounts receivable - affiliates ...............................          905           363
                                                                        --------      --------
     Total current assets .........................................          921           372
                                                                        --------      --------

   Oil and gas properties, successful efforts method:
     Properties subject to amortization ...........................       32,619        32,849
     Less:  Accumulated depreciation, depletion & amortization ....      (27,132)      (27,825)
                                                                        --------      --------
     Total oil and gas properties .................................        5,487         5,024
                                                                        --------      --------
   Total assets ...................................................     $  6,408      $  5,396
                                                                        ========      ========

LIABILITIES:
   Accounts payable and accrued expenses ..........................     $    121      $    370
                                                                        --------      --------
     Total current liabilities ....................................          121           370
                                                                        --------      --------
   Total liabilities ..............................................          121           370
                                                                        --------      --------

PARTNERS' EQUITY:
   LP Unitholders' equity .........................................          346           284
   GP Unitholders' equity .........................................        5,693         4,544
   Managing and Special General Partners' equity ..................          248           198
                                                                        --------      --------
     Total partners' equity .......................................        6,287         5,026
                                                                        --------      --------
   Total liabilities and partners' equity .........................     $  6,408      $  5,396
                                                                        ========      ========
</TABLE>


                       See Notes to Financial Statements.



                                       20
<PAGE>   22



                KELLEY PARTNERS 1994 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 ..............................................     $ 8,822     $ 3,731     $ 2,700
   Gain on sale of properties .....................................          --       1,993          --
                                                                        -------     -------     -------
     Total revenues ...............................................       8,822       5,724       2,700
                                                                        -------     -------     -------

COSTS AND EXPENSES:
   Lease operating expenses .......................................       1,843         844         502
   Severance taxes ................................................         413         168          75
   General and administrative expenses ............................         854         454         259
   Depreciation, depletion and amortization .......................       3,080       1,124         693
   Impairment of oil and gas properties ...........................          81          --          --
                                                                        -------     -------     -------
     Total expenses ...............................................       6,271       2,590       1,529
                                                                        -------     -------     -------
Net income ........................................................     $ 2,551     $ 3,134     $ 1,171
                                                                        =======     =======     =======

Net income allocable to LP and GP unitholders .....................     $ 2,449     $ 3,010     $ 1,125
                                                                        =======     =======     =======

Net income allocable to managing and special general partners .....     $   102     $   124     $    46
                                                                        =======     =======     =======

Net income per LP and GP unit .....................................     $   .12     $   .14     $   .05
                                                                        =======     =======     =======

Average LP and GP Units outstanding ...............................      20,864      20,864      20,864
                                                                        =======     =======     =======
</TABLE>


                       See Notes to Financial Statements.



                                       21
<PAGE>   23



                KELLEY PARTNERS 1994 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 income ...........................................................     $  2,551      $  3,134      $  1,171
   Adjustments to reconcile net income to net cash provided by
     operating activities:
     Gain on sale of properties .........................................           --        (1,993)           --
     Depreciation, depletion and amortization ...........................        3,080         1,124           693
     Impairment of oil and gas properties ...............................           81            --            --
     Changes in operating assets and liabilities:
       Decrease in accounts receivable ..................................        2,942         2,176           549
       (Decrease) increase in accounts payable and accrued expenses .....         (313)          (52)          249
                                                                              --------      --------      --------
   Net cash provided by operating activities ............................        8,341         4,389         2,662
                                                                              --------      --------      --------

INVESTING ACTIVITIES:
   Capital expenditures .................................................          (86)         (260)         (230)
   Sale of oil and gas properties .......................................           --         8,308            --
                                                                              --------      --------      --------
   Net cash (used in) provided by investing activities ..................          (86)        8,048          (230)
                                                                              --------      --------      --------

FINANCING ACTIVITIES
   Distributions ........................................................       (8,255)      (12,437)       (2,432)
                                                                              --------      --------      --------
   Net cash used in financing activities ................................       (8,255)      (12,437)       (2,432)
                                                                              --------      --------      --------

   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 1994 DEVELOPMENT DRILLING PROGRAM
                    STATEMENTS OF CHANGES IN PARTNERS' EQUITY

                                 (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 ......     $  1,172      $ 19,280      $    842      $ 21,294
                                               --------      --------      --------      --------

Distributions ............................         (454)       (7,474)         (327)       (8,255)
Net income ...............................          139         2,310           102         2,551
                                               --------      --------      --------      --------
Partners' equity at December 31, 1998 ....          857        14,116           617        15,590
                                               --------      --------      --------      --------

Distributions ............................         (683)      (11,261)         (493)      (12,437)
Net income ...............................          172         2,838           124         3,134
                                               --------      --------      --------      --------
Partners' equity at December 31, 1999 ....          346         5,693           248         6,287
                                               --------      --------      --------      --------

Distributions ............................         (137)       (2,199)          (96)       (2,432)
Transfer .................................            9            (9)           --            --
Net income ...............................           66         1,059            46         1,171
                                               --------      --------      --------      --------
Partners' equity at December 31, 2000 ....     $    284      $  4,544      $    198      $  5,026
                                               ========      ========      ========      ========
</TABLE>



                       See Notes to Financial Statements.



                                       23
<PAGE>   25



                KELLEY PARTNERS 1994 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 Company's proved oil and gas properties was
estimated using escalated pricing and present value discount factors reflecting
risk assessments. Based on this analysis, the Company recognized a non-cash
impairment charge of $81,000 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 and commodity derivatives
(see Note 4). Management believes the carrying amounts of the financial
instruments classified as 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 4 - "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 90% 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, the 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 5.

NOTE 2 - CASH DISTRIBUTIONS

         The table below details cash distributions per LP and GP Unit, other
than the return of uncommitted capital, by quarter paid.


<TABLE>
<S>                                                              <C>
1998
First quarter ..............................................     $    .11
Second quarter .............................................          .12
Third quarter ..............................................          .08
Fourth quarter .............................................          .07
                                                                 --------
   Total ...................................................     $    .38
                                                                 ========

1999
First quarter ..............................................     $    .05
Second quarter .............................................          .09
Third quarter ..............................................          .42
Fourth quarter .............................................          .01
                                                                 --------
   Total ...................................................     $    .57
                                                                 ========

2000
First quarter ..............................................     $    .02
Second quarter .............................................          .02
Third quarter ..............................................          .02
Fourth quarter .............................................          .05
                                                                 --------
   Total ...................................................     $    .11
                                                                 ========
</TABLE>


         The Partnership maintains a policy of distributing cash that is not
required for the conduct of Partnership business to Unitholders on a quarterly
basis. The Partnership made distributions for the year 2000 aggregating
$2,336,000 to the unitholders, or $0.11 per Unit, and $96,000 to the Managing
and Special General Partners for their interest. In February 2001, the fourth
quarter 2000 distribution was paid to the managing and special general partners
and the unitholders in the amounts of $45,000 and $1,085,000, or $0.05 per Unit,
respectively. Distribution levels are affected by numerous factors, including
oil and gas prices, production levels and operating costs, together with any
working capital requirements. Future distributions to the unitholders and
managing and special general partners are contingent on future operating
results.

NOTE 3 - RELATED PARTY TRANSACTIONS

         The Unitholders have a 96.04% share and the general partners have 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.


                                       25
<PAGE>   27
         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 $854,000, $454,000 and $259,000, 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 $0.28 per unit
for all of the Partnership units not held by Kelley Oil. A total of 783,621
Partnership units (46% of units eligible for tender) were tendered. The total
cost was approximately $265,000, including transaction costs. After the tender,
Kelley Oil owns 95.61% of the Units and a 3.94% General Partner interest.

NOTE 4 - 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 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 $31,000 and $498,000 in 1999 and 2000, respectively, and
increased such revenues by approximately $370,000 in 1998 as compared to
estimated revenues had no hedging activities been conducted.



                                       26
<PAGE>   28



         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 5 - 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 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,
$741,000, $325,000 and $122,000 of expenses were reclassified from oil and gas
revenues to production expenses for the years ended December 31, 1998, 1999 and
2000, respectively.

NOTE 6 - 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 ......................     $ 45,294      $ 32,619      $ 32,849
Accumulated depreciation, depletion and amortization ....      (32,626)      (27,132)      (27,825)
                                                              --------      --------      --------
   Net capitalized costs ................................     $ 12,668      $  5,487      $  5,024
                                                              ========      ========      ========
</TABLE>


         Costs Incurred. All costs were incurred in oil and gas property
development activities (as defined in the Partnership Agreement) and aggregated
$86,000, $260,000 and $230,000 for the years ended December 31, 1998, 1999 and
2000, respectively.



                                       27
<PAGE>   29



         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

         There are numerous uncertainties in estimating quantities of proved
reserves believed to have been discovered and in projecting future rates of
production and the timing of development expenditures, including many factors
beyond the control of the Partnership. The reserve data set forth in this
document are only estimates. Reserve estimates are inherently imprecise and may
be expected to change as additional information becomes available. Furthermore,
estimates of oil and natural 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. Reservoir engineering is a subjective
process of estimating underground accumulations of oil and natural gas that
cannot be measured exactly, and the accuracy of any reserve estimate is a
function of the quality of available data and of engineering and geological
interpretation and judgment. Accordingly, 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 cash flows expected therefrom prepared by
different engineers or by the same engineers at different times may vary
substantially. There also can be no assurance that the reserves set forth herein
will ultimately be produced. It is possible that variances from the estimates
will be material.


<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 ............................          83           59           17       25,642       24,363       10,066
   Revisions of previous estimates ..............          (3)           6           (5)       2,635         (359)      (2,941)
   Extensions and discoveries ...................          --           --           --           --           --           --
   Sales of reserves in place ...................          --          (39)          --           --      (12,190)          --
   Production ...................................         (21)          (9)          (3)      (3,914)      (1,748)        (830)
                                                      -------      -------      -------      -------      -------      -------
     End of year ................................          59           17            9       24,363       10,066        6,295
                                                      =======      =======      =======      =======      =======      =======

Proved developed reserves at end of year ........          57           16            9       22,730        9,312        6,295
                                                      =======      =======      =======      =======      =======      =======
</TABLE>


         Standardized Measure. The table of the Standardized Measure of
Discounted Future Net Cash Flows relating to the Partnership's ownership
interests in proved oil and gas reserves as of December 31, 1998, 1999 and 2000
is shown below.


                                 (IN THOUSANDS)

<TABLE>
<CAPTION>
                                                                                 DECEMBER 31,
                                                                     ------------------------------------
                                                                       1998          1999          2000
                                                                     --------      --------      --------
<S>                                                                  <C>           <C>           <C>
Future cash inflows ............................................     $ 49,978      $ 21,212      $ 61,862
Future production costs ........................................      (15,017)       (6,718)       (8,311)
Future development costs .......................................       (1,327)       (1,012)         (272)
                                                                     --------      --------      --------
   Future net cash flows .......................................       33,634        13,482        53,279
10% annual discount for estimating timing of cash flows ........      (14,031)       (6,180)      (29,156)
                                                                     --------      --------      --------
   Standardized measure of discounted future net cash flows ....     $ 19,603      $  7,302      $ 24,123
                                                                     ========      ========      ========
</TABLE>



                                       28
<PAGE>   30



         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.

         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 had a weighted average of $9.88, $25.53 and $26.03,
respectively, per barrel of oil and $2.03, $2.07 and $9.79, 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 .......     $ (6,566)     $ (2,719)     $ (2,123)
   Sales of oil and gas properties .....................           --       (10,358)           --
   Extensions and discoveries ..........................           --            --            --
   Development costs incurred during the year ..........          233            --            --
Changes due to revisions in standardized variables:
   Prices and production costs .........................       (8,506)         (410)       29,993
   Revisions of previous quantity estimates ............        2,151          (269)      (11,351)
   Estimated future development costs ..................         (252)         (221)          736
   Accretion of discount ...............................        3,132         1,960           730
   Production rates (timing) and other .................       (1,913)         (284)       (1,164)
                                                             --------      --------      --------
     Net (decrease) increase ...........................      (11,721)      (12,301)       16,821
   Beginning of year ...................................       31,324        19,603         7,302
                                                             --------      --------      --------
     End of year .......................................     $ 19,603      $  7,302      $ 24,123
                                                             ========      ========      ========
</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.

EXECUTIVE OFFICERS OF KELLEY OIL

         Set forth below are the names, ages and positions of the current
executive officers and directors of the Company. 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 person 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                                   19,947,520                                          95.61%
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 (9 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 $2,580,897 to the Partnership for their 3.96%
interest. Costs and expenses incurred by Kelley Oil in connection with the
syndication and organization of the Partnership aggregating approximately
$750,000 were reimbursed by the Partnership in 1994 and charged to partners'
equity. For further discussion on Related Transactions see Note 3 in the Notes
to Financial Statements



                                       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: All 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. 33-72528) filed on December 7, 1993,
                    as amended (the "Registration Statement") and incorporated
                    herein by reference).

           4.2      Joint Venture Agreement of Kelley Partners 1994
                    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 1994 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       DESCRIPTION
         -------      -----------
<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. 33-72528) filed on December 7, 1993,
                      as amended (the "Registration Statement") and incorporated
                      herein by reference).

           4.2        Joint Venture Agreement of Kelley Partners 1994
                      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>