<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, 1999          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 24, 2000, 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") 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 92.2% of the total interests
of the Partnership. Kelley Oil is a subsidiary of Contour Energy Co. (formerly
Kelley Oil & Gas Corporation) collectively with its subsidiaries, "Contour".

         As used in this 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.

         In 1999, Contour undertook several strategic actions in response to the
severe downturn in the industry in 1998 caused by low commodity prices and the
closing of the capital markets to smaller oil and gas companies. These actions,
described below, were designed to increase the near-term liquidity of Contour,
Kelley Oil and the Partnership, provide capital for ongoing capital expenditure
programs and establish a stronger base for future growth.

         In April 1999, Contour entered into an Exploration and Development
Agreement with Phillips Petroleum Company ("Phillips") relating to certain of
its interests in the Bryceland, West Bryceland and Sailes fields in north
Louisiana ("Phillips Transaction"). Pursuant to the agreement, Contour: (1)
received an $83 million cash payment, (2) retained a 42 Bcf, 8-year volumetric
overriding royalty interest and a 1% override on the excess production above
such royalty interest and (3) retained 25% of its working interest in the Cotton
Valley formation. In addition, Phillips, will at its risk and expense, operate,
develop, exploit and explore the properties thereby relieving Contour of
significant operating, exploration and development costs in the future. The
transaction closed on May 17, 1999.

         As part of the Phillips Transaction described above, the Partnership
conveyed its interest in the West Bryceland and Sailes fields to Phillips for
$8.3 million. The Partnership's reserve quantities attributable to such fields
represented approximately one-half of the Partnership's total reserve quantities
at January 1, 1999 and one-half of its total 1998 production. The sales proceeds
were distributed to the Partnership in the third quarter of 1999.

         In April 1999, Contour negotiated a private offering of $135 million
principal amount, 14% Senior Secured Notes (the "Notes"). The Notes are secured
by a first lien on substantially all of Contour's proved oil and natural gas
properties remaining after the sale to Phillips and guaranteed by three entities
wholly-owned by Contour. In accordance with the Notes indenture, on June 30,
1999, Contour funded $37.5 million to repurchase $35 million principal amount of
the Notes at a repurchase price equal to 104% of the principal amount, plus
accrued and unpaid interest and commitment fees to the date of the repurchase.

         On May 17, 1999, Contour funded $28.5 million to repurchase $46.1
million of the outstanding principal amounts of its 77/8% Convertible
Subordinated Notes due December 15, 1999 and its 8 1/2% Convertible Subordinated
Debentures



                                       1
<PAGE>   3

due April 1, 2000 (collectively, the "Securities") at a price equal to $590 per
$1,000 principal amount (not including accrued interest paid of $1.2 million).

          In addition, on May 17, 1999, Contour repaid all borrowings
outstanding under its credit facility of $115.5 million plus accrued interest
and terminated the revolving credit facility and funded cash collateral for a
$1.5 million letter of credit which was subsequently increased to $7.5 million.
Contour used net proceeds remaining from the transactions for general corporate
purposes.

         Contour has received the benefits of a general increase in the level of
commodity prices over the past several months. This increase, combined with the
actions described above, have provided Contour with near-term liquidity and
capital for its ongoing operations. However, the commodity markets are volatile
and there is no certainty that current oil and natural gas prices can be
sustained at these levels. In addition, Contour continues to have significant
debt outstanding relative to its asset base and pays a high portion of its cash
flow to service such debt. Furthermore, as Contour does not have a revolving
credit facility, it also does not have ready access to incremental sources of
capital to supplement its operational requirements. Contour believes that it has
the ability for the foreseeable future based on its current condition, including
economic conditions, to meet all obligations as they come due and fund its
current capital expenditure program from cash on hand and operational cash
flows. However, because of the combination of the factors described herein and
the uncertainty of drilling successes required to sustain or increase
operational cash flows, there can be no assurance that Contour will be able to
fund future obligations.

         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.

         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.

         Development and Production. As of January 1, 2000, 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, 1999, the Partnership produced 24.5
Bcf of natural gas and 174,092 barrels of oil and natural gas liquids,
generating total oil and gas revenues of $54.8 million, $57.0 million or $2.62
per Unit has been distributed to the partners (includes $8.3 million or $0.38
per unit related to the 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.




                                       2
<PAGE>   4

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."

         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, 1998, 1999 and 2000, by an independent petroleum engineering firm.
For the reserves at January 1, 2000, 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, 1998, 1999
and 2000. 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.

                            ESTIMATED PROVED RESERVES

<TABLE>
<CAPTION>
                                                      AS OF JANUARY 1,
                                             -----------------------------------
                                               1998         1999         2000
                                             --------     --------     ---------
<S>                                          <C>          <C>          <C>
Crude oil and liquids (Mbbl):
   Proved developed.......................         81           57            16
   Proved undeveloped.....................          2            2             1
                                             --------     --------     ---------
     Total proved.........................         83           59            17
                                             ========     ========     =========

Natural gas (Mmcf):
   Proved developed                            24,175       22,730         9,312
   Proved undeveloped.....................      1,467        1,633           754
                                             --------     --------     ---------
     Total proved.........................     25,642       24,363        10,066
                                             ========     ========     =========
</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 to the Partnership's 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




                                       3
<PAGE>   5

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 or that
the proved undeveloped reserves set forth herein will be developed within the
periods anticipated. 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, 1999 with respect to the Partnership's interests in its most
significant fields, together with information for all other fields combined.

                          SIGNIFICANT PROVED PROPERTIES
                                 (IN THOUSANDS)

<TABLE>
<CAPTION>
                                PROVED RESERVES AT JANUARY 1, 2000         1999 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 ...............        6    6,919    6,955    68.4        1      909      915    50.8
   Sailes field ...............       --       --       --      --        2      542      554    30.8
   West Bryceland field .......       --       --       --      --       --      216      216    12.0
   Ada field ..................        5    3,126    3,156    31.0       --       50       50     2.8
SOUTH LOUISIANA:
   Orange Grove/Humphreys field        6       21       57      .6        5       31       61     3.4
OTHER:
   As a group .................       --       --       --      --       .8       --        5      .2
                                  ------   ------   ------   -----   ------   ------   ------   -----
     Total ....................       17   10,066   10,168   100.0      8.8    1,748    1,801   100.0
                                  ======   ======   ======   =====   ======   ======   ======   =====
</TABLE>


         As part of the Phillips Transaction described above, the Partnership
conveyed its interests in the West Bryceland and Sailes fields to Phillips.

         Additional information regarding these fields is set forth below.
Unless otherwise noted, well information is provided as of December 31, 1999,
and reserve information is provided as of January 1, 2000:

                                 NORTH LOUISIANA

         Sibley Field. The Sibley field is located in Webster Parish, Louisiana.
The Partnership has interests in 24 gross (4.5 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.




                                       4
<PAGE>   6

         Sailes Field and West Bryceland fields. The Partnership sold its
interest in these two fields to Phillips in the transaction described above.

         Ada Field. The Ada field is located in Bienville and Webster Parishes,
Louisiana. The Partnership has an interest in 5 gross (1.3 net) wells producing
from the Hosston A and B formations at depths ranging from 7,500 to 8,600 feet.
Kelley operates one of the wells. The Ada field reserves are 88.3% proved
developed.

                                 SOUTH LOUISIANA

         Orange Grove/Humphreys Field. The Orange Grove/Humphreys field is
located in Terrebonne Parish, Louisiana. The Partnership has interests in 3
gross (1.0 net) wells producing from the Big Hum, Realty, Bourg and KK
formations at depths ranging from 10,700 to 12,800 feet. Kelley Oil operates all
of the wells. 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 (including transfers) and average production costs (lifting cost
plus ad valorem and severance taxes) per equivalent unit of oil and gas produced
by the Partnership for the years ended December 31, 1997, 1998 and 1999.
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,
                                                               ------------------------
                                                                1997    1998      1999
                                                               ------  ------     -----
<S>                                                            <C>     <C>        <C>

Crude oil, condensate and natural gas liquids (Bbls)........   30,025  21,487     8,792
Natural gas (Mmcf)..........................................    6,727   3,914     1,748
</TABLE>


                    AVERAGE SALES PRICES AND PRODUCTION COSTS

<TABLE>
<CAPTION>
                                                                             YEAR ENDED DECEMBER 31,
                                                                             -----------------------
                                                                              1997    1998    1999
                                                                             ------  ------  -------
<S>                                                                          <C>     <C>     <C>
Average sales price:
   Crude oil, condensate and natural gas liquids per Bbl...................  $19.64  $13.48  $15.26
   Natural gas per Mcf, including the effects of hedging...................    2.27    1.99    1.94

Oil and gas revenues per Mcfe..............................................    2.29    2.00    1.89
Average production costs per Mcfe..........................................     .29     .37     .38
</TABLE>




                                       5
<PAGE>   7

OIL AND GAS WELLS

         As of December 31, 1999, 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    .38
Gas wells........................................          32   7.12
                                                      -------   ----
   Total.........................................          34   7.50
                                                      =======   ====
</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, 1997, 1998 and 1999, 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>

1997............      5          --      --         --       1.07       --      --         --
1998............      1          --      --         --        .31       --      --         --
1999............     --          --      --         --        --        --      --         --
</TABLE>


         Wells in Progress. At December 31, 1999, 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, under contracts providing for periodic
price adjustments or in the spot market, all of its natural gas at current
market prices. Its revenue streams are therefore sensitive to changes in current
market prices. The Partnership's sales of crude oil, condensate and natural gas
liquids generally are related to posted field prices.

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

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




                                       6
<PAGE>   8

HEDGING OF NATURAL GAS

         Contour has periodically used forward sales contracts, natural gas
price swap agreements, natural gas basis swap agreements and options to reduce
exposure to downward price fluctuations on its natural gas production. Contour
does not engage in speculative transactions. Contour's hedging activities also
cover the oil and gas production attributable to the Partnership, including the
interest in such production of the public unitholders of the Partnership. During
1999, Contour used price and basis swap agreements to hedge its exposure to
possible declines in natural gas prices. Additional information concerning
Partnership hedging activities during 1999 is set forth in "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
contained elsewhere in this Report.

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, 1999, Kelley Oil had 47 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.

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




                                       7
<PAGE>   9

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.

         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.



                                       8
<PAGE>   10

         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 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.



                                       9
<PAGE>   11

         Depletion of Reserves; Necessity of Successful Development. 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 developing and its current 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 prices
received by the Partnership for its oil, natural gas and natural gas liquids
production and the levels of such production are subject to government
regulation, legislation and policies. 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.

         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. Although domestic drilling activity is currently at a
relatively low level, resulting in less demand for such services and a general
decrease in service costs, there can be no assurance that such market conditions
will continue.

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

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


ITEM 3.  LEGAL PROCEEDINGS

         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, and transfer of
the Units is substantially restricted by the provisions of the Partnership
Agreement. As of February 28, 2000, there were 658 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>
                  1997
                  First quarter..................................       .22
                  Second quarter.................................       .20
                  Third quarter..................................       .13
                  Fourth quarter.................................       .10

                  1998
                  First quarter..................................       .11
                  Second quarter.................................       .12
                  Third quarter..................................       .08
                  Fourth quarter.................................       .07

                  1999
                  First quarter..................................       .05
                  Second quarter.................................       .09
                  Third quarter..................................       .42
                  Fourth quarter.................................       .01

                  2000
                  First quarter..................................       .02
</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. Distribution levels are affected by numerous
factors, including oil and gas prices, production levels and operating costs,
together with any working capital or debt service requirements.

         In addition to its regular distributions of net available cash from
quarterly operations, the Partnership distributed $1.1 million of uncommitted
capital (or a total of $0.25 per Unit) during 1997. 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 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,
                                                ----------------------------------------------------
                                                  1995        1996      1997       1998        1999
                                                --------    -------   -------     ------     -------
<S>                                             <C>        <C>        <C>        <C>         <C>
SUMMARY OF OPERATIONS:
   Total revenues...........................    $ 10,647   $ 20,240   $15,970    $ 8,081     $ 5,399
   Production expenses......................       1,123      2,348     2,036      1,515         687
   Exploration expenses.....................       6,767        606       369         --          --
   General and administrative expenses......         620        854       934        854         454
   Depreciation, depletion and amortization.       6,617      5,536     4,631      3,080       1,124
   Impairment of oil and gas properties.....      10,914         --        --         81          --
   Net income (loss)........................     (15,394)    10,896     8,000      2,551       3,134
   Net income (loss) per Unit(1)............        (.71)      .50       .37         .12         .14
   Units outstanding........................      20,864     20,864    20,864     20,864      20,864
</TABLE>


<TABLE>
<CAPTION>
                                                                   AS OF DECEMBER 31,
                                               --------------------------------------------------------
                                                 1995       1996          1997         1998       1999
                                               --------   --------     ---------     -------     ------
<S>                                            <C>        <C>          <C>           <C>         <C>
SUMMARY BALANCE SHEET DATA:
   Working capital (deficit)................   $(4,515)   $  3,647     $   5,551     $ 2,923     $  800
   Oil and gas properties, net..............    12,715      19,035        15,743      12,667      5,487
   Total partners' equity...................     8,200      22,682        21,294      15,590      6,287
   Total assets.............................    15,733      25,479        21,781      15,763      6,408
</TABLE>



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


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, 1999. 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. Kelley
Oil Corporation, managing general partner of the Partnership ("Kelley Oil") and
a wholly-owned subsidiary of Contour Energy Co. (formerly Kelley Oil & Gas
Corporation ("Contour"), owns 91.9% of the Units, together with its 3.94%
managing general partnership interest.

         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" below.




                                       12
<PAGE>   14

         Hedging Activities. Contour has periodically used forward sales
contracts, natural gas and crude oil price swap agreements, natural gas basis
swap agreements and options to reduce exposure to downward price fluctuations on
its natural gas and crude oil production. Contour does not engage in speculative
transactions. Contour's hedging activities also cover the oil and gas production
attributable to the Partnership, including the interest in such production of
the public unitholders of the Partnership. During 1999, Contour used price and
basis swap agreements. Price swap agreements generally provide for the
Partnership to receive or make counterparty payments on the differential between
a fixed price and a variable indexed price for natural gas. Basis swap
agreements generally provide for the Partnership to receive or make counterparty
payments on the differential between a variable indexed price and the price it
receives from the sale of natural gas production, and are used to hedge against
unfavorable price movements in the relationship between such variable indexed
price and the price received for such production. Additionally, Contour must
provide cash collateral for any hedges (through swap or other agreements) to
cover counter-party risk to the hedging party. Gains and losses realized by the
Partnership from hedging activities are included in oil and gas revenues and
average sales prices in the period that the related production is sold.

         Through natural gas price swap agreements, the Partnership hedged
approximately 65%, 49% and 50%, respectively, of its natural gas production for
1997, 1998 and 1999, respectively, at average NYMEX quoted prices of $2.35,
$2.31 and $2.17 per Mmbtu, respectively, before transaction and transportation
costs. As of December 31, 1999, approximately 8% of the Partnership's
anticipated natural gas production for 2000 has been hedged by natural gas price
swap agreements at an average NYMEX quoted price of $2.41 per Mmbtu before
transaction and transportation costs. Per additional hedging activities since
December 31, 1999, approximately 47% of the Partnership's anticipated natural
gas production for 2000 has been hedged at an average NYMEX quoted price of
$2.56 per Mmbtu before transaction and transportation. 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 either 1997 or
1998. As of December 31, 1999, approximately 7% of the Partnership's crude oil
production for 2000 had been hedged by crude oil price swap agreements at an
average NYMEX quoted price of $25.05 per bbl before transaction and
transportation costs. Per additional hedging activities since December 31, 1999,
approximately 43% of the Partnership's anticipated crude oil production for 2000
has been hedged at an average NYMEX quoted price of $26.21 per bbl before
transaction and transportation costs. Hedging activities decreased Partnership
revenues by approximately $1.2 million in 1997 and $31,000 in 1999,
respectively, and increased such revenues by approximately $370,000 in 1998 as
compared to estimated revenues had no hedging activities been conducted. At
December 31, 1999, the unrealized gain on the Partnership's existing hedging
instruments for future production months in 2000 approximated $2,000.

         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 and does not
anticipate any in future periods.

         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, 1999 and 1998. Oil and gas revenues of
$3,406,000 for 1999 decreased 58% compared to $8,081,000 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.

         Lease operating expenses and severance taxes were $687,000 in 1999
versus $1,515,000 in 1998. This decrease was primarily related to the sale of
properties to Phillips. On a unit of production basis, these expenses increased
3% from 1998 at $0.37 per Mcfe to $0.38 per Mcfe in 1999.




                                       13
<PAGE>   15

         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.

         Depreciation, depletion and amortization ("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, under Statement of Financial Accounting Standards No. 121
("SFAS 121"), "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of," the Partnership recognized a non-cash
impairment charge of $81 thousand against the carrying values of its proved oil
and gas properties, for the year ended December 31, 1998 (see "Property
Impairment under SFAS 121" in Note 2 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.

         Years Ended December 31, 1998 and 1997. Oil and gas revenues of
$8,081,000 for 1998 decreased 49% compared to $15,835,000 in 1997 as a result of
lower production volumes and lower prices received for its oil and gas sold.
Production of natural gas decreased 42% from 6,727,000 Mcf in 1997 to 3,914,000
Mcf in 1998. Production of crude oil decreased 28% from 30,025 barrels in 1997
to 21,487 barrels in 1998. Oil and gas production decreased due to natural
depletion and a reduction in the drilling of new wells to offset that decline.

         Interest income decreased from $135,000 in 1997 to zero in 1998, due to
Kelley Oil having funded its subscription commitment in its entirety during the
second quarter of 1997.

         Lease operating expenses and severance taxes were $1,515,000 in 1998
versus $2,036,000 in 1997. This decrease was primarily due to lower production
levels. On a unit of production basis, these expenses increased 27% from 1997 at
$0.29 per Mcfe to $0.37 per Mcfe in 1998.

         The Partnership expensed no exploration costs in 1998 a decrease from
the 1997 level of $369,000.

         General and administrative expenses of $854,000 in 1998 decreased 9%
from $934,000 in 1997, reflecting the Partnership's share of administration
costs associated with development operations of Contour. On a unit of production
basis, these expenses increased from $0.14 per Mcfe in 1997 to $0.21 per Mcfe in
1998.

         Depreciation, depletion and amortization ("DD&A") expense decreased 33%
from $4,631,000 in 1997 to $3,080,000 in 1998, primarily as a result of lower
current period production. On a unit-of-production basis, DD&A increased from
$0.67 per Mcfe in 1997 to $0.76 per Mcfe in 1998.

         In 1998, under Statement of Financial Accounting Standards No. 121
("SFAS 121"), "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of," the Partnership recognized a non-cash
impairment charge of $81 thousand against the carrying values of its proved oil
and gas properties, for the year ended December 31, 1998 (see "Property
Impairment under SFAS 121" in Note 2 to the Financial Statements).

         The Partnership recognized net income in 1998 of $2,551,000 or $0.12
per Unit compared to net income of $8,000,000 or $0.37 per Unit in 1997,
reflecting the foregoing developments.

LIQUIDITY AND CAPITAL RESOURCES

         Liquidity. Net cash provided by the Partnership's operating activities
during 1999, as reflected on its statements of cash flows, totaled $4,389,000.
During the year, funds provided by investing activities included proceeds from
the sale of properties to Phillips of $8,308,000, partially offset by capital
expenditures of $260,000. Funds used in financing




                                       14
<PAGE>   16

activities consisted of cash distributions to partners of $12,437,000. As a
result of these activities, the Partnership's cash and cash equivalents was zero
at December 31, 1998 and December 31, 1999.

         In 1999, Contour undertook several strategic actions in response to the
severe downturn in the industry in 1998 caused by low commodity prices and the
closing of the capital markets to smaller oil and gas companies. These actions,
described below, were designed to increase the near-term liquidity of Contour,
Kelley Oil and the Partnership, provide capital for ongoing capital expenditure
programs and establish a stronger base for future growth.

         In April 1999, Contour entered into an Exploration and Development
Agreement with Phillips Petroleum Company ("Phillips") relating to certain of
its interests in the Bryceland, West Bryceland and Sailes fields in north
Louisiana ("Phillips Transaction"). Pursuant to the agreement, Contour: (1)
received an $83 million cash payment, (2) retained a 42 Bcf, 8-year volumetric
overriding royalty interest and a 1% override on the excess production above
such royalty interest and (3) retained 25% of its working interest in the Cotton
Valley formation. In addition, Phillips, will at its risk and expense, operate,
develop, exploit and explore the properties thereby relieving Contour of
significant operating, exploration and development costs in the future. The
transaction closed on May 17, 1999.

         As part of the Phillips transaction described above, the Partnership
conveyed its interest in the West Bryceland and Sailes fields to Phillips for
$8.3 million. The Partnership's reserve quantities attributable to such fields
represented approximately one-half of the Partnership's total reserve quantities
at January 1, 1999 and one-half of its total 1998 production. The sales proceeds
were distributed to the Partnership in the third quarter of 1999.

         In April 1999, Contour negotiated a private offering of $135 million
principal amount, 14% Senior Secured Notes (the "Notes"). The Notes are secured
by a first lien on substantially all of Contour's proved oil and natural gas
properties remaining after the sale to Phillips and guaranteed by three entities
wholly-owned by Contour. In accordance with the Notes indenture, on June 30,
1999, Contour funded $37.5 million to repurchase $35 million principal amount of
the Notes at a repurchase price equal to 104% of the principal amount, plus
accrued and unpaid interest and commitment fees to the date of the repurchase.

         On May 17, 1999, Contour funded $28.5 million to repurchase $46.1
million of the outstanding principal amounts of its 77/8% Convertible
Subordinated Notes due December 15, 1999 and its 8 1/2% Convertible Subordinated
Debentures due April 1, 2000 (collectively, the "Securities") at a price equal
to $590 per $1,000 principal amount (not including accrued interest paid of $1.2
million).

          In addition, on May 17, 1999, Contour repaid all borrowings
outstanding under its credit facility of $115.5 million plus accrued interest
and terminated the revolving credit facility and funded cash collateral for a
$1.5 million letter of credit which was subsequently increased to $7.5 million.
Contour used net proceeds remaining from the transactions for general corporate
purposes.

         Contour has received the benefits of a general increase in the level of
commodity prices over the past several months. This increase, combined with the
actions described above, have provided Contour with near-term liquidity and
capital for its ongoing operations. However, the commodity markets are volatile
and there is no certainty that current oil and natural gas prices can be
sustained at these levels. In addition, Contour continues to have significant
debt outstanding relative to its asset base and pays a high portion of its cash
flow to service such debt. Furthermore, as Contour does not have a revolving
credit facility, it also does not have ready access to incremental sources of
capital to supplement its operational requirements. Contour believes that it has
the ability for the foreseeable future based on its current condition, including
economic conditions, to meet all obligations as they come due and fund its
current capital expenditure program from cash on hand and operational cash
flows. However, because of the combination of the factors described herein and
the uncertainty of drilling successes required to sustain or increase
operational cash flows, there can be no assurance that Contour will be able to
fund future obligations.

         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




                                       15
<PAGE>   17

$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 have 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 four quarterly distributions in 1999 aggregating
$.57 per Unit or a total of $11,944,000, along with $493,000 to the Managing and
Special General Partners for their interests. In March 2000, the Partnership
made a quarterly distribution of $0.02 per Unit or a total of $417,000, along
with $17,000 to the Managing and Special General Partners for their interests.
The distributions in each quarter generally represented substantially all of the
Partnership's net available cash from prior quarter operations. The Partnership
intends to continue making quarterly distributions consistent with its cash
distribution policy.

         Year 2000. Contour, on behalf of the Partnership, conducted reviews and
evaluations in response to Year 2000 issues. These issues involved the potential
disruption to systems, processes, and business practices that may have occurred
if system hardware and software utilized by Contour, its vendors, and customers
had been unable to process year 2000 data. Neither Contour nor the Partnership
incurred any disruptions due to year 2000 issues.

         The foregoing statements are intended to be and are hereby designated
"Year 2000 Readiness Disclosures" within the meaning of the Year 2000
Information and Readiness Act.

         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, 1997....................     19.64           2.27
   December 31, 1998....................     13.48           1.99
   December 31, 1999....................     15.26           1.94
</TABLE>




                                       16
<PAGE>   18

         Accounting Pronouncements. In June 1998, the Financial Accounting
Standards Board issued Statement of Financial Accounting Standards No. 133,
"Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133")
which was amended in June 1999 by SFAS No. 137, "Accounting for Derivative
Instruments and Hedging Activities - Deferral of the Effective Date of FASB
Statement No. 133 - an amendment of FASB Statement No. 133." SFAS No. 133, as
amended, is effective for fiscal years beginning after June 15, 2000, and
establishes accounting and reporting standards for derivative instruments and
hedging activities that require an entity to recognize all derivatives as an
asset or liability measured at its fair value. Depending on the intended use of
the derivative, changes in its fair value will be reported in the period of
change as either a component of earnings or a component of other comprehensive
income. Retroactive application to periods prior to adoption is not allowed. The
Partnership has not quantified the impact of adoption on its financial
statements.

         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

<TABLE>
<CAPTION>
KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM:                                                           PAGE
                                                                                                             ----
<S>                                                                                                          <C>

Independent Auditors' Report................................................................................  19
Balance Sheets - December 31, 1998 and 1999.................................................................  20
Statements of Operations - For the years ended December 31, 1997, 1998 and 1999.............................  21
Statements of Cash Flows - For the years ended December 31, 1997, 1998 and 1999.............................  22
Statements of Changes in Partners' Equity - For the years ended December 31, 1997, 1998 and 1999............  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,
1998 and 1999 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,
1999. These financial statements are the responsibility of the Partnership's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.

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

         In our opinion, such financial statements present fairly, in all
material respects, the financial position of Kelley Partners 1994 Development
Drilling Program as of December 31, 1998 and 1999, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1999, in conformity with generally accepted accounting principles.






DELOITTE & TOUCHE LLP

Houston, Texas
March 23, 2000




                                       19
<PAGE>   21

                KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM
                                 BALANCE SHEETS

                                 (IN THOUSANDS)

<TABLE>
<CAPTION>
                                                                        DECEMBER 31,
                                                                    --------------------
                                                                      1998        1999
                                                                    --------    --------
<S>                                                                 <C>         <C>
ASSETS:
   Cash .........................................................   $     --    $     --
   Accounts receivable - trade ..................................         20          16
   Accounts receivable - affiliates .............................      3,076         905
                                                                    --------    --------
     Total current assets .......................................      3,096         921
                                                                    --------    --------

   Oil and gas properties, successful efforts method:
     Properties subject to amortization .........................     45,294      32,619
     Less: Accumulated depreciation, depletion & amortization ...    (32,627)    (27,132)
                                                                    --------    --------
     Total oil and gas properties ...............................     12,667       5,487
                                                                    --------    --------
   Total assets .................................................   $ 15,763    $  6,408
                                                                    ========    ========

LIABILITIES:
   Accounts payable and accrued expenses ........................   $    173    $    121
                                                                    --------    --------
     Total current liabilities ..................................        173         121
                                                                    --------    --------
   Total liabilities ............................................        173         121
                                                                    --------    --------

PARTNERS' EQUITY:
   LP Unitholders' equity .......................................        857         346
   GP Unitholders' equity .......................................     14,116       5,693
   Managing and Special General Partners' equity ................        617         248
                                                                    --------    --------
     Total partners' equity .....................................     15,590       6,287
                                                                    --------    --------
   Total liabilities and partners' equity .......................   $ 15,763    $  6,408
                                                                    ========    ========
</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,
                                                                     ---------------------------
                                                                       1997      1998      1999
                                                                     -------   -------   -------
<S>                                                                  <C>       <C>       <C>
REVENUES:
   Oil and gas sales .............................................   $15,835   $ 8,081   $ 3,406
   Gain on sale of properties ....................................        --        --     1,993
   Interest income ...............................................       135        --        --
                                                                     -------   -------   -------
     Total revenues ..............................................    15,970     8,081     5,399
                                                                     -------   -------   -------

COSTS AND EXPENSES:
   Lease operating expenses ......................................     1,402     1,102       519
   Severance taxes ...............................................       634       413       168
   Exploration expenses ..........................................       369        --        --
   General and administrative expenses ...........................       934       854       454
   Depreciation, depletion and amortization ......................     4,631     3,080     1,124
   Impairment of oil and gas properties ..........................        --        81        --
                                                                     -------   -------   -------
     Total expenses ..............................................     7,970     5,530     2,265
                                                                     -------   -------   -------
Net income .......................................................   $ 8,000   $ 2,551   $ 3,134
                                                                     =======   =======   =======

Net income  allocable to LP and GP unitholders ...................   $ 7,684   $ 2,449   $ 3,010
                                                                     =======   =======   =======

Net income  allocable to managing and special general partners ...   $   316   $   102   $   124
                                                                     =======   =======   =======

Net income per LP and GP unit ....................................   $   .37   $   .12   $   .14
                                                                     =======   =======   =======

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,
                                                                   --------------------------------
                                                                     1997        1998        1999
                                                                   --------    --------    --------
<S>                                                                <C>         <C>         <C>
OPERATING ACTIVITIES:
   Net income (loss) ...........................................   $  8,000    $  2,551    $  3,134
   Adjustments to reconcile net loss to net cash provided by
     operating activities:
     Gain on sale of properties ................................         --          --      (1,993)
     Depreciation, depletion and amortization ..................      4,631       3,080       1,124
     Impairment of oil and gas properties ......................         --          81          --
     Exploration expenses ......................................        369          --          --
     Changes in operating assets and liabilities:
       Decrease in accounts receivable .........................        381       2,942       2,176
       Decrease in accounts payable and accrued expenses .......     (2,310)       (313)        (52)
                                                                   --------    --------    --------
   Net cash provided by operating activities ...................     11,071       8,341       4,389
                                                                   --------    --------    --------

INVESTING ACTIVITIES:
   Capital expenditures ........................................     (1,708)        (86)       (260)
   Sale of oil and gas properties ..............................         --          --       8,308
                                                                   --------    --------    --------
   Net cash (used in) provided by investing activities .........     (1,708)        (86)      8,048
                                                                   --------    --------    --------

FINANCING ACTIVITIES:
   Capital contributed by partners .............................      5,819          --          --
   Distributions ...............................................    (14,121)     (8,255)    (12,437)
   Distributions of uncommitted capital ........................     (1,086)         --          --
                                                                   --------    --------    --------
   Net cash used in financing activities .......................     (9,388)     (8,255)    (12,437)
                                                                   --------    --------    --------

   Increase (decrease) in cash and cash equivalents ............        (25)         --          --

Cash and cash equivalents, beginning of period .................         25          --          --
                                                                   --------    --------    --------
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, 1997 .....      1,527      20,025       1,130      22,682
                                            --------    --------    --------    --------

Capital contributed .....................         --       5,571         248       5,819
Return of capital contributed ...........        (60)       (983)        (43)     (1,086)
Distributions ...........................       (772)    (12,790)       (559)    (14,121)
Transfers ...............................         39         211        (250)         --
Net income ..............................        438       7,246         316       8,000
                                            --------    --------    --------    --------
Partners' equity at December 31, 1997 ...      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
                                            ========    ========    ========    ========
</TABLE>



See Notes to Financial Statements.




                                       23
<PAGE>   25

                KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM
                          NOTES TO FINANCIAL STATEMENTS

NOTE 1 - ORGANIZATION, INDUSTRY CONDITIONS AND LIQUIDITY

         Organization. Kelley Partners 1994 Development Drilling Program, a
Texas limited partnership (the "Partnership"), commenced operations on February
28, 1994 upon completion of a public offering of 20,864,414 units of limited
partner interests and general partner interests (the "Units") in the Partnership
at $3.00 per Unit. Subscribers for more than 3,333 Units were entitled to defer
up to 90% of their subscriptions, with deferred subscriptions payable when
called through November 30, 1994. As of December 31, 1999, all Unit
subscriptions were paid. In addition to the Units, Kelley Oil Corporation, the
managing general partner of the Partnership ("Kelley Oil") and a wholly-owned
subsidiary of Contour Energy Co. (formerly Kelley Oil & Gas Corporation)
("Contour") contributed $2,568,000 to the Partnership for its 3.94% general
partner interest, and David L. Kelley, special general partner of the
Partnership, had contributed $13,000 for his .02% general partner interest.

         The Partnership was formed for the sole purpose of financing the
drilling of development wells, as defined in its partnership agreement (the
"Partnership Agreement"), on selected properties owned by Kelley Operating
Company, Ltd. ("Kelley Operating"), a Texas limited partnership of which Kelley
Oil owns, both directly and indirectly, 100% of the partnership interests. The
Partnership's development activities have been conducted through a joint venture
(the "Joint Venture") between the Partnership and Kelley Operating, which has
retained a 20% interest in the Joint Venture after Payout (as defined in the
Joint Venture Agreement) in consideration of its contribution of drilling
rights.

         As of December 31, 1999, Kelley Oil owned 19,163,889 (91.9%) Units. The
Partnership has no officers, directors or employees. The officers and employees
of Kelley Oil perform the management and administrative functions of the
Partnership. 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.

         In 1999, Contour undertook several strategic actions in response to the
severe downturn in the industry in 1998 caused by low commodity prices and the
closing of the capital markets to smaller oil and gas companies. These actions,
described below, were designed to increase the near-term liquidity of Contour,
Kelley Oil and the Partnership, provide capital for ongoing capital expenditure
programs and establish a stronger base for future growth.

         In April 1999, Contour entered into an Exploration and Development
Agreement with Phillips Petroleum Company ("Phillips") relating to certain of
its interests in the Bryceland, West Bryceland and Sailes fields in north
Louisiana ("Phillips Transaction"). Pursuant to the agreement, Contour: (1)
received an $83 million cash payment, (2) retained a 42 Bcf, 8-year volumetric
overriding royalty interest and a 1% override on the excess production above
such royalty interest and (3) retained 25% of its working interest in the Cotton
Valley formation. In addition, Phillips, will at its risk and expense, operate,
develop, exploit and explore the properties thereby relieving Contour of
significant operating, exploration and development costs in the future. The
transaction closed on May 17, 1999.

         As part of the Phillips transaction described above, the Partnership
conveyed its interest in the West Bryceland and Sailes fields to Phillips for
$8.3 million. The Partnership's reserve quantities attributable to such fields
represented approximately one-half of the Partnership's total reserve quantities
at January 1, 1999 and one-half of its total 1998 production. The sales proceeds
were distributed to the Partnership in the third quarter of 1999.

         In April 1999, Contour negotiated a private offering of $135 million
principal amount, 14% Senior Secured Notes (the "Notes"). The Notes are secured
by a first lien on substantially all of Contour's proved oil and natural gas
properties remaining after the sale to Phillips and guaranteed by three entities
wholly-owned by Contour. In accordance with the Notes indenture, on June 30,
1999, Contour funded $37.5 million to repurchase $35 million principal amount of
the Notes at a repurchase price equal to 104% of the principal amount, plus
accrued and unpaid interest and commitment fees to the date of the repurchase.



                                       24
<PAGE>   26

         On May 17, 1999, Contour funded $28.5 million to repurchase $46.1
million of the outstanding principal amounts of its 77/8% Convertible
Subordinated Notes due December 15, 1999 and its 8 1/2% Convertible SubordinateD
Debentures due April 1, 2000 (collectively, the "Securities") at a price equal
to $590 per $1,000 principal amount (not including accrued interest paid of $1.2
million).

         In addition, on May 17, 1999, Contour repaid all borrowings outstanding
under its credit facility of $115.5 million plus accrued interest and terminated
the revolving credit facility and funded cash collateral for a $1.5 million
letter of credit which was subsequently increased to $7.5 million. Contour used
net proceeds remaining from the transactions for general corporate purposes.

         Contour has received the benefits of a general increase in the level of
commodity prices over the past several months. This increase, combined with the
actions described above, have provided Contour with near-term liquidity and
capital for its ongoing operations. However, the commodity markets are volatile
and there is no certainty that current oil and natural gas prices can be
sustained at these levels. In addition, Contour continues to have significant
debt outstanding relative to its asset base and pays a high portion of its cash
flow to service such debt. Furthermore, as Contour does not have a revolving
credit facility, it also does not have ready access to incremental sources of
capital to supplement its operational requirements. Contour believes that it has
the ability to meet all near-term obligations and fund its current capital
expenditure program from cash on hand and operational cash flows. However,
because of the combination of the factors described herein and the uncertainty
of drilling successes required to sustain or increase operational cash flows,
there can be no assurance that Contour will be able to fund future obligations.

NOTE 2 - 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. 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.

         Property Impairment under SFAS 121. Under Financial Accounting
Standards Board's Statement No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of" (SFAS 121"),
certain assets are required to be reviewed periodically for impairment whenever
circumstances indicate their carrying amount exceeds their fair value and 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 as of year end. 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 thousand
against the carrying value of its proved oil and gas properties under SFAS 121,
at December 31, 1998.

         Syndication and Organization Costs. Costs and expenses incurred in
connection with the syndication and organization of the Partnership aggregating
approximately $1,571,000 have been charged to partners' equity. These
syndication costs include approximately $750,000 of general and administrative
expenses allocated by Kelley Oil for expenses directly identified with
syndication and organization activities.




                                       25
<PAGE>   27

         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 (Loss) Per Unit. Net income (loss) per Unit is computed
based on the weighted average number of Units outstanding during the period
divided into the net income (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 5).

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

         Concentration of Credit Risk and Significant Customers. Substantially
all of the Partnership's receivables are due from the marketing subsidiary of
Kelley Oil, 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.

         Comprehensive Income. In June 1997, the Financial Accounting Standards
Board issued Statement of Financial Accounting Standards No. 130, "Reporting
Comprehensive Income" ("SFAS 130"). SFAS 130 establishes standards for reporting
and displaying comprehensive income and its components. SFAS 130 is effective
for periods beginning after December 15, 1997. The purpose of reporting
comprehensive income is to report a measure of all changes in equity of an
enterprise that results from recognized transactions and other economic events
of the period other than transactions with owners in their capacity as owners.
As of December 31, 1999, there are no adjustments ("Other Comprehensive Income")
to net income in deriving comprehensive income.

         Use of estimates. The preparation of financial statements in conformity
with generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities, 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.

         Changes in Presentation. Certain financial statement items in 1997 and
1998 have been reclassified to conform to the 1999 presentation.




                                       26
<PAGE>   28

NOTE 3 - 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>
          1997
          First quarter............................    $ .22
          Second quarter...........................      .20
          Third quarter............................      .13
          Fourth quarter...........................      .10
                                                       -----
             Total.................................    $ .65
                                                       =====

           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
                                                       =====
</TABLE>


         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 $4,345,000 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 $1,086,000 or $0.05 per
Unit to the partners as a return of capital.

NOTE 4 - 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.

         For the years ended December 31, 1997, 1998 and 1999, Kelley Oil was
reimbursed by the Partnership for costs directly associated with acquisition,
exploration and development activities aggregating $369,000, zero and zero,
respectively, and for its allocable portion of general and administrative
expenses aggregating $934,000, $854,000 and $454,000, respectively.

         Kelley Partners advanced approximately $1,879,000 on behalf of the
Partnership prior to the closing of the Partnership's offering of Units for the
purpose of funding drilling activities. The entire amount of these advances,
together with interest at a market rate, was repaid following the closing of the
Partnership's offering.

         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
1997, 1998 and 1999, the fee was 2% of the resale price for marketed natural
gas.

NOTE 5 - HEDGING ACTIVITIES

           Contour has periodically used forward sales contracts, natural gas
price swap agreements, natural gas basis swap agreements and options to reduce
exposure to downward price fluctuations on its natural gas production. Contour
does not engage in speculative transactions. Contour's hedging activities also
cover the oil and gas production attributable to the Partnership, including the
interest in such production of the public unitholders of the Partnership. During
1999, Contour used price and basis swap agreements. Price swap agreements
generally provide for the Partnership to receive or make counterparty payments
on the differential between a fixed price and a variable indexed price for
natural gas. Basis swap




                                       27
<PAGE>   29

agreements generally provide for the Partnership to receive or make counterparty
payments on the differential between a variable indexed price and the price it
receives from the sale of natural gas production, and are used to hedge against
unfavorable price movements in the relationship between such variable indexed
price and the price received for such production. Additionally, Contour must
provide cash collateral for any hedges (through swap or other agreements) to
cover counter-party risk to the hedging party. Gains and losses realized by the
Partnership from hedging activities are included in oil and gas revenues and
average sales prices in the period that the related production is sold.

         Through natural gas price swap agreements, the Partnership hedged
approximately 65%, 49% and 50%, respectively, of its natural gas production for
1997, 1998 and 1999, respectively, at average NYMEX quoted prices of $2.35,
$2.31 and $2.17 per Mmbtu, respectively, before transaction and transportation
costs. As of December 31, 1999, approximately 8% of the Partnership's
anticipated natural gas production for 2000 has been hedged by natural gas price
swap agreements at an average NYMEX quoted price of $2.41 per Mmbtu before
transaction and transportation costs. Per additional hedging activities since
December 31, 1999, approximately 47% of the Partnership's anticipated natural
gas production for 2000 has been hedged at an average NYMEX quoted price of
$2.56 per Mmbtu before transaction and transportation. 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 either 1997 or
1998. As of December 31, 1999, approximately 7% of the Partnership's crude oil
production for 2000 had been hedged by crude oil price swap agreements at an
average NYMEX quoted price of $25.05 per bbl before transaction and
transportation costs. Per additional hedging activities since December 31, 1999,
approximately 43% of the Partnership's anticipated crude oil production for 2000
has been hedged at an average NYMEX quoted price of $26.21 per bbl before
transaction and transportation costs. Hedging activities decreased Partnership
revenues by approximately $1.2 million in 1997 and $31,000 in 1999,
respectively, and increased such revenues by approximately $370,000 in 1998 as
compared to estimated revenues had no hedging activities been conducted. At
December 31, 1999, the unrealized gain on the Partnership's existing hedging
instruments for future production months in 2000 approximated $2,000.

         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 and does not
anticipate any in future periods.

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,
                                                           --------------------------------
                                                             1997        1998        1999
                                                           --------    --------    --------
<S>                                                        <C>         <C>         <C>

Evaluated properties subject to amortization ...........   $ 45,209    $ 45,294    $ 32,619
Accumulated depreciation, depletion and amortization ...    (29,466)    (32,626)    (27,132)
                                                           --------    --------    --------
   Net capitalized costs ...............................   $ 15,743    $ 12,668    $  5,487
                                                           ========    ========    ========
</TABLE>


         Costs Incurred. All costs were incurred in oil and gas property
development activities (as defined in the Partnership Agreement) and aggregated
$1,708,000, $85,000 and $260,000 for the years ended December 31, 1997, 1998 and
1999, respectively.




                                       28
<PAGE>   30

         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, 1997, 1998 and 1999. See
"Estimated Proved Reserves - Uncertainties in Estimating Reserves under
Items 1 and 2 of this Form 10K."

<TABLE>
<CAPTION>
                                                     CRUDE OIL, CONDENSATE
                                                    AND NATURAL GAS LIQUIDS               NATURAL GAS
                                                            (MBBLS)                         (MMCF)
                                                 -----------------------------    -----------------------------
                                                  1997       1998       1999       1997       1998       1999
                                                 -------    -------    -------    -------    -------    -------
<S>                                              <C>        <C>        <C>        <C>        <C>        <C>
Proved developed and undeveloped reserves:
   Beginning of year .........................       123         83         59     35,347     25,642     24,363
   Revisions of previous estimates ...........       (10)        (3)         6     (2,978)     2,635       (359)
   Extensions and discoveries ................        --         --         --         --         --         --
    Sales of reserves in place ...............        --         --        (39)        --         --    (12,190)
   Production ................................       (30)       (21)        (9)    (6,727)    (3,914)    (1,748)
                                                 -------    -------    -------    -------    -------    -------
     End of year .............................        83         59         17     25,642     24,363     10,066
                                                 =======    =======    =======    =======    =======    =======

Proved developed reserves at end of year .....        81         57         16     24,175     22,730      9,312
                                                 =======    =======    =======    =======    =======    =======
</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, 1997, 1998 and 1999
is shown below.

                                 (IN THOUSANDS)

<TABLE>
<CAPTION>
                                                                            DECEMBER 31,
                                                                  --------------------------------
                                                                    1997        1998        1999
                                                                  --------    --------    --------
<S>                                                               <C>         <C>         <C>

Future cash inflows ...........................................   $ 64,664    $ 49,978    $ 21,212
Future production costs .......................................    (13,817)    (15,017)     (6,718)
Future development costs ......................................     (1,759)     (1,327)     (1,012)
                                                                  --------    --------    --------
   Future net cash flows ......................................     49,088      33,634      13,482
10% annual discount for estimating timing of cash flows .......    (17,764)    (14,031)     (6,180)
                                                                  --------    --------    --------
   Standardized measure of discounted future net cash flows ...   $ 31,324    $ 19,603    $  7,302
                                                                  ========    ========    ========
</TABLE>


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

         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, 1997, 1998 and 1999 was calculated using prices in effect as of
those dates, which had a weighted average of $17.18, $9.88 and $25.53,
respectively, per barrel of oil and $2.47, $2.03 and $2.07, respectively, per
Mcf of natural gas.




                                       29
<PAGE>   31

         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,
                                                          --------------------------------
                                                            1997        1998        1999
                                                          --------    --------    --------
<S>                                                       <C>         <C>         <C>
Changes due to current year operations:
   Sales of oil and gas, net of production costs ......   $(13,799)   $ (6,566)   $ (2,719)
   Sales of oil and gas properties ....................         --          --     (10,358)
   Extensions and discoveries .........................         --          --          --
   Development costs incurred during the year .........      2,189         233          --
Changes due to revisions in standardized variables:
   Prices and production costs ........................    (30,889)     (8,506)       (410)
   Revisions of previous quantity estimates ...........     (3,872)      2,151        (269)
   Estimated future development costs .................       (587)       (252)       (221)
   Accretion of discount ..............................      7,514       3,132       1,960
   Production rates (timing) and other ................     (4,370)     (1,913)       (284)
                                                          --------    --------    --------
     Net increase (decrease) ..........................    (43,814)    (11,721)    (12,301)
   Beginning of year ..................................     75,138      31,324      19,603
                                                          --------    --------    --------
     End of year ......................................   $ 31,324    $ 19,603    $  7,302
                                                          ========    ========    ========
</TABLE>


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

         None




                                       30
<PAGE>   32

                                    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 47 employees as of December 31, 1999, and its staff includes
employees experienced in geology, geophysics, petroleum engineering, land
acquisition and management, finance, accounting and administration.

BACKGROUND OF KELLEY OIL

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

EXECUTIVE OFFICERS OF KELLEY OIL

         Set forth below are the names, ages and positions of the current
executive officers and directors of 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............ 77     President, Chief Executive Officer and a director        1996
Rick G. Lester............. 48     Senior Vice President and Chief Financial Officer        1998
Kenneth R. Sanders......... 50     Senior Vice President-Exploration and Production         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.


ITEM 11.  EXECUTIVE COMPENSATION

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




                                       31
<PAGE>   33

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

BENEFICIAL OWNERS

         The following table sets forth information as of December 31, 1999 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                19,163,889              91.85%
601 Jefferson, Suite 1100               Direct
Houston, Texas  77002
</TABLE>


MANAGEMENT

         The following table sets forth information as of December 31, 1999 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 4 to Notes to
Financial Statements.




                                       32
<PAGE>   34

                                     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).

     (b) REPORTS ON FORM 8-K:

         No reports on Form 8-K were filed by the Registrant during the fourth
quarter of 1999.




                                       33
<PAGE>   35

                                   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 3rd day of April
2000.


                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 3rd day of April 2000 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




                                       34
<PAGE>   36

                                 EXHIBIT INDEX

<TABLE>
<CAPTION>
         EXHIBIT
         NUMBER:      EXHIBIT
         -------      -------

<S>                   <C>
              4.1     Amended and Restated Agreement of Limited Partnership of
                      the Registrant (included as Exhibit A to the Prospectus
                      forming part of the Registrant's Registration Statement on
                      Form S-1 (File No. 33-72528) 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).

              27      Financial Data Schedule
</TABLE>