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, 1997          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 25, 1998, 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>
                                     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 Kelley Oil & Gas Corporation
("KOGC" and collectively with its subsidiaries, "Kelley").

         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.

         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, 1998, the Partnership had
participated in drilling 91 gross (29.0 net) wells, of which 87 gross (26.33
net) wells have been found to be productive and 4 gross (2.67 net) wells were
dry. During 1997, recompletion and work-over operations were conducted on
several wells. From its inception through December 31, 1997, the Partnership
produced 18.9 Bcf of natural gas and 143,813 barrels of oil and natural gas
liquids, generating total oil and gas revenues of $43.4 million, of which $36.3
million or $1.67 per Unit has been distributed to the partners.

         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

                                        1
<PAGE>
the necessary partnership capital and distributed additional uncommitted funds
of $1.1 million or $0.05 per Unit to the partners as a return of capital.

MANAGEMENT, OPERATIONS AND PROPERTIES

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

         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. Reserve estimates contained herein were prepared by H. J. Gruy
& Associates, Inc. ("Gruy") independent petroleum engineers, as of January 1,
1996, 1997 and 1998.

         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, 1996, 1997
and 1998. 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

                                                        AS OF JANUARY 1,
                                                --------------------------------
                                                 1996         1997         1998
                                                ------       ------       ------
Crude oil and liquids (Mbbl):
   Proved developed .....................          107          118           81
   Proved undeveloped ...................           60            5            2
                                                ------       ------       ------
     Total proved .......................          167          123           83
                                                ======       ======       ======
Natural gas (Mmcf):
   Proved developed .....................       16,988       31,296       24,175
   Proved undeveloped ...................       41,652        4,051        1,467
                                                ------       ------       ------
     Total proved .......................       58,640       35,347       25,642
                                                ======       ======       ======

         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 5 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
expenditures,

                                        2
<PAGE>
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, 1998 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, 1998                       1997 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 ...............           9       8,082       8,136        31.1           3       2,138       2,156        31.2
   Sailes field ...............          24       8,002       8,146        31.2          11       2,159       2,225        32.2
   West Bryceland field .......          23       5,514       5,652        21.6           3       1,376       1,394        20.2
   Ada field ..................           7       3,414       3,456        13.2        --           531         531         7.7
SOUTH LOUISIANA:
   Fire Island field ..........          11         556         622         2.4           6         309         345         5.0
   Orange Grove/Humphreys field           9          59         113         0.4           6          52          88         1.3
OTHER:
   As a group .................        --            15          15         0.1           1         162         168         2.4
                                  ---------   ---------   ---------   ---------   ---------   ---------   ---------   ---------
     Total ....................          83      25,642      26,140       100.0          30       6,727       6,907       100.0
                                  =========   =========   =========   =========   =========   =========   =========   =========
</TABLE>
         ADDITIONAL INFORMATION REGARDING THESE FIELDS IS SET FORTH BELOW.
UNLESS OTHERWISE NOTED, WELL INFORMATION IS PROVIDED AS OF DECEMBER 31, 1997,
AND RESERVE INFORMATION IS PROVIDED AS OF JANUARY 1, 1998:

                                 NORTH LOUISIANA

                                        3
<PAGE>
         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.

         SAILES FIELD. The Sailes field is located in Bienville Parish,
Louisiana. The Partnership has interests in 29 gross (10.2 net) wells producing
from the Glen Rose, Hosston A, B and C formations at depths ranging from 7,200
to 9,900 feet. Kelley Oil operates 27 of the wells. The Sailes field reserves
are 96.4% proved developed.

         WEST BRYCELAND FIELD. The West Bryceland field is located in Bienville
Parish, Louisiana. The Partnership has interests in 21 gross (5.1 net) wells
producing from the Hosston A, B and C formations at depths ranging from 7,100 to
10,000 feet. Kelley Oil operates 18 of the wells. The West Bryceland field
reserves are 85% proved developed.

         ADA FIELD. The Ada field is located in Bienville and Webster Parishes,
Louisiana. The Partnership has an interest in 4 gross (1.0 net) wells producing
from the Hosston A and B formations at depths ranging from 7,500 to 8,600 feet.
Kelley operates 1 of the wells. The Ada field reserves are 89.5% proved
developed.

                                 SOUTH LOUISIANA

         FIRE ISLAND FIELD. The Fire Island field is located in Vermillion
Parish, Louisiana. The Partnership has an interest in 1 gross (0.7 net) well
producing from the MA-36 formation at a depth of 14,167 feet. Kelley Oil
operates the well. The Fire Island field reserves are 100% proved developed.

         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, 1995, 1996 and 1997.
Detailed additional information concerning the Partnership's oil and gas
producing activities is contained in the Supplementary Information.

                             OIL AND GAS PRODUCTION
                                                        YEAR ENDED DECEMBER 31,
                                                       ------------------------
                                                        1995     1996     1997
                                                       ------   ------   ------

Crude oil, condensate and natural gas liquids (Bbls)   49,816   49,168   30,025
Natural gas (Mmcf) .................................    4,000    7,872    6,727

                    AVERAGE SALES PRICES AND PRODUCTION COSTS
<TABLE>
<CAPTION>
                                                                 YEAR ENDED DECEMBER 31,
                                                           ------------------------------------
                                                              1995         1996         1997
                                                           ----------   ----------   ----------
<S>                                                        <C>          <C>          <C>
Average sales price:
   Crude oil, condensate and natural gas liquids per Bbl   $    16.58   $    21.59   $    19.64
   Natural gas per Mcf .................................         1.71         2.27         2.27
Oil and gas revenues per Mcfe ..........................         1.80         2.32         2.29
Average production costs per Mcfe ......................          .26          .29          .29
</TABLE>
                                        4
<PAGE>
OIL AND GAS WELLS

         As of December 31, 1997, the Partnership owned interests in productive
oil and gas wells (including producing wells and wells capable of production) as
follows:

                                                        GROSS(1)          NET
                                                       ----------     ----------
Oil wells ........................................              2            .38
Gas wells ........................................             82          22.45
                                                       ----------     ----------
   Total .........................................             84          22.83
                                                       ==========     ==========

(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 from inception through December 31, 1997, based on a narrower
definition for development wells under guidelines established by the Securities
and Exchange Commission.
<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>
1995...          27       1           --         1           8.89     .67           --       .67
1996...          38    --             --      --            10.11    --             --      --
1997...           5    --             --      --             1.07    --             --      --
</TABLE>
         Initial test results for wells completed during the fourth quarter of
1997 are summarized below.

                             INITIAL TEST RESULTS(1)
                                      FROM
                         FOURTH QUARTER 1997 COMPLETIONS
<TABLE>
<CAPTION>
                                                                                           THOUSAND
WELL NAME                                                           /64"     FLOWING        CUBIC      BARRELS
   FIELD NAME          COMPLETION    RESERVOIR                     CHOKE      TUBING         FEET        OIL     WORKING
     PARISH, STATE         DATE      COMPLETED     PERFORATIONS     SIZE    PRESSURE       PER DAY     PER DAY   INTEREST
--------------------   -----------   ----------   --------------   -------   ----------   ----------   -------   --------
<S>                      <C>                        <C>                 <C>       <C>          <C>          <C>  <C>
Oxy 2 ..............     11/8/97      Hosston       8257-9351'          16        2,020        3,184        20   .2117032
   West Bryceland
     Bienville, LA
</TABLE>
     (1)Reflects initial test results reported under state reporting
requirements and may not be indicative of actual producing rates to sales.


         WELLS IN PROGRESS. At December 31, 1997, one gross (0.31 net) well was
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

                                        5
<PAGE>
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.

HEDGING OF NATURAL GAS

         KOGC 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. KOGC does
not engage in speculative transactions. KOGC'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 1997,
the Company used price and basis swap agreements. Additional information
concerning Partnership hedging activities during 1997 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, 1997, Kelley Oil had 57 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
relationships 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

                                        6
<PAGE>
complex federal and state statutes and regulations that may affect the
Partnership, directly or indirectly, the following discussion of certain
statutes and regulations should not be relied upon as an exhaustive review of
all matters affecting the Partnership's operations.

TRANSPORTATION AND PRODUCTION

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

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

ENVIRONMENTAL REGULATIONS

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

                                        7
<PAGE>
coverage of such insurance and the amount of protection afforded thereby cannot
be predicted with respect to any particular possible environmental liability and
may not be adequate to protect the Partnership from substantial expense.

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

         The CAA requires or will require most industrial operations in the
United States to incur capital expenditures in order to meet air emission
control standards developed by the EPA and state environmental agencies.
Although no assurances can be given, the Company believes implementation of such
amendments will not have a material adverse effect on its financial condition or
results of operations. RCRA is the principal federal statute governing the
treatment, storage and disposal of hazardous wastes. RCRA imposes stringent
operating requirements (and liability for failure to meet such requirements) on
a person who is either a "generator" or "transporter" of hazardous waste or an
"owner" or "operator" of a hazardous waste treatment, storage or disposal
facility. At present, RCRA includes a statutory exemption that allows oil and
natural gas exploration and production wastes to be classified as non-hazardous
waste. As a result, the Partnership is not required to comply with a substantial
portion of RCRA's requirements because the 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 COMPANY OR ITS REPRESENTATIVES) THAT ARE FORWARD-LOOKING IN NATURE ARE
INTENDED TO BE "FORWARD-LOOKING STATEMENTS" WITHIN THE MEANING OF SECTION 27A OF
THE SECURITIES ACT OF 1933, AS AMENDED, AND SECTION 21E OF THE SECURITIES
EXCHANGE ACT OF 1934, AS AMENDED, RELATING TO MATTERS SUCH AS ANTICIPATED
OPERATING AND FINANCIAL PERFORMANCE, BUSINESS PROSPECTS, DEVELOPMENTS AND
RESULTS OF THE PARTNERSHIP. ACTUAL PERFORMANCE, PROSPECTS, DEVELOPMENTS AND
RESULTS MAY DIFFER MATERIALLY FROM ANY OR ALL ANTICIPATED RESULTS DUE TO
ECONOMIC CONDITIONS AND OTHER RISKS, UNCERTAINTIES AND CIRCUMSTANCES

                                        8
<PAGE>
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" discussed elsewhere in this Report.

         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. At present, the level of drilling activity in the
United States has resulted in increased demand for, and therefore increased
costs associated with, drilling equipment and the services and products of other
vendors to the industry. In particular, in connection with drilling activities
in the marshy regions of south Louisiana, there has been an increased cost of
drilling operations due to increased costs for barge rigs necessary to conduct
activity in such region. Moreover, the number of drilling contractors offering
barge drilling and workover services is limited.

         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

                                        9
<PAGE>
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.

                                     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, 1998, 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.

                                                                   DISTRIBUTIONS
                  1995                                             -------------
                  First quarter..................................... $   .04
                  Second quarter....................................     .09
                  Third quarter.....................................     .10
                  Fourth quarter....................................     .10

                  1996
                  First quarter.....................................     .12
                  Second quarter....................................     .18
                  Third quarter.....................................     .18
                  Fourth quarter....................................     .21

                  1997
                  First quarter.....................................     .22
                  Second quarter....................................     .20
                  Third quarter.....................................     .13
                  Fourth quarter....................................     .10

                  1998
                  First quarter.....................................     .11

         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.

                                       10
<PAGE>
         In addition to its regular distributions of net available cash from
quarterly operations, the Partnership distributed $4.3 million and $1.1 million
of uncommitted capital (or a total of $0.25 per Unit) during 1996 and 1997,
respectively. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations."


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>
                                               FEBRUARY
                                               28, 1994
                                               (DATE OF
                                              INCEPTION)
                                                THROUGH          YEAR ENDED DECEMBER 31,
                                              DECEMBER 31,    -----------------------------
                                                  1994          1995       1996      1997
                                              ------------    --------    -------   -------
<S>                                           <C>             <C>         <C>       <C>
SUMMARY OF OPERATIONS:
   Total revenues .........................   $      1,140    $ 10,647    $20,240   $15,970
   Production expenses ....................            126       1,123      2,348     2,036
   Exploration expenses ...................          3,389       6,767        606       369
   General and administrative expenses ....             89         620        854       934
   Interest expense .......................             17        --         --        --
   Depreciation, depletion and amortization          1,618       6,617      5,536     4,631
   Impairment of oil and gas properties ...           --        10,914       --        --
   Net income (loss) ......................         (4,099)    (15,394)    10,896     8,000
   Net income (loss) per Unit(1) ..........           (.19)       (.71)       .50       .37
   Units outstanding ......................         20,864      20,864     20,864    20,864
<CAPTION>
                                               FEBRUARY
                                               28, 1994
                                               (DATE OF
                                              INCEPTION)
                                                THROUGH          YEAR ENDED DECEMBER 31,
                                              DECEMBER 31,    -----------------------------
                                                  1994          1995       1996      1997
                                              ------------    --------    -------   -------
SUMMARY BALANCE SHEET DATA:
   Working capital (deficit) ..............   $        780    $ (4,515)   $ 3,647   $ 5,551
   Oil and gas properties, net ............         14,122      12,715     19,035    15,743
   Total partners' equity .................         14,902       8,200     22,682    21,294
   Total assets ...........................         17,917      15,733     25,479    21,781
</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, 1997. 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 Kelley Oil & Gas Corporation ("KOGC"), owns 91.9%
of the Units, together with its 3.94% managing general partnership interest.

                                       11
<PAGE>
         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.

         PROPERTY IMPAIRMENT UNDER SFAS 121. In the fourth quarter of 1995, the
Partnership implemented the 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"). Under 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. The Partnership performed an assessment of the carrying value of
its oil and gas properties indicating an impairment should be recognized at year
end. Under this analysis, the fair value of the Partnership's oil and gas
properties was estimated on a depletable unit basis using escalated pricing and
present value discount factors reflecting risk assessments. Based on this
analysis, the Partnership recognized a noncash impairment charge of $10.9
million against the carrying value of its oil and gas properties under SFAS 121
at December 31, 1995.

         HEDGING ACTIVITIES. KOGC 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.
KOGC does not engage in speculative transactions. KOGC'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
1997, KOGC 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. 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, approximately 65% of the
Partnership's natural gas production for 1997 was affected by hedging
transactions at an average NYMEX quoted price of $2.35 per Mmbtu before
transaction and transportation costs. As of December 31, 1997, approximately 29%
of the Partnership's anticipated natural gas production for 1998 has been hedged
by natural gas price swap agreements at an average NYMEX quoted price of $2.30
per Mmbtu before transaction and transportation costs. Certain natural gas price
swap agreements outstanding at December 31, 1997 permit the counterparty to
double the contract volume at a specified price. If this feature is exercised on
all contracts outstanding at December 31, 1997, approximately 40% of the
Partnership's anticipated natural gas production for 1998 has been hedged by
natural gas price swap agreements at an average NYMEX quoted price of $2.31 per
Mmbtu before transaction and transportation costs. In addition, as of December
31, 1997, the Partnership had outstanding natural gas basis swap agreements
covering approximately 34% of its anticipated natural gas production for January
1998 through September 1998. Hedging activities decreased Partnership revenues
by approximately $1.2 million in 1997 as compared to estimated revenues had no
hedging activities been conducted.

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

         DRILLING OPERATIONS. Since inception, the Partnership participated in
drilling 91 gross (29.0 net) wells, of which 87 gross (26.33 net) wells were
found productive and 4 gross (2.67 net) wells were dry. During 1997,
recompletion and workover operations were conducted on several of the wells. See
"Liquidity and Capital Resources" below.

                                       12
<PAGE>
RESULTS OF OPERATIONS

         YEARS ENDED DECEMBER 31, 1997 AND 1996. Oil and gas revenues of
$15,835,000 for 1997 decreased 17% compared to $18,986,000 in 1996 as a result
of lower production volumes. Production of natural gas decreased 15% from
7,872,000 Mcf in 1996 to 6,727,000 Mcf in 1997. Production of crude oil
decreased 39% from 49,168 barrels in 1996 to 30,025 barrels in 1997. 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 89% from $1,254,000 in 1996 to $135,000 in
1997, 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 $2,036,000 in 1997
versus $2,348,000 in 1996. This decrease was primarily due to lower production
levels. On a unit of production basis, these expenses remained constant from
1996 to 1997 at $0.29 per Mcfe.

         The Partnership expensed exploration costs in 1997 of $369,000, a 39%
decrease from the 1996 level of $606,000, primarily reflecting the decrease in
exploratory activities during the current period.

         General and administrative expenses of $934,000 in 1997 increased 9%
from $854,000 in 1996, reflecting the Partnership's share of administration
costs associated with development operations of KOGC. On a unit of production
basis, these expenses increased from $0.10 per Mcfe in 1996 to $0.14 per Mcfe in
1997.

         Depreciation, depletion and amortization ("DD&A") expense decreased 16%
from $5,536,000 in 1996 to $4,631,000 in 1997, primarily as a result of lower
current period production. On a unit-of--production basis, DD&A decreased from
$0.68 per Mcfe in 1996 to $0.67 per Mcfe in 1997.

         The Partnership recognized net income in 1997 of $8,000,000 or $0.37
per Unit compared to net income of $10,896,000 or $0.50 per Unit in 1996,
reflecting the foregoing developments.

         YEAR ENDED DECEMBER 31, 1996 COMPARED TO YEAR ENDED DECEMBER 31, 1995.
Oil and gas revenues of $18,986,000 in 1996 increased 146% compared to
$7,723,000 in 1995. Production of natural gas increased 97% to 7,872,000 Mcf in
1996 from 4,000,000 Mcf in 1995, while the average price of natural gas
increased 33% to $2.27 per Mcf in 1996 from $1.71 per Mcf in 1995. Production of
crude oil in 1996 totaled 49,168 barrels, with an average sales price of $21.59
per barrel, compared to 49,816 barrels at $16.58 per barrel in the prior year,
representing a volume decrease of 1% and a price increase of 30%. The increase
in revenues and production from 1995 levels reflects the Partnership's
completion of 38 wells during 1996.

         Lease operating expenses and severance taxes were $2,348,000 in 1996
and $1,123,000 in 1995, an increase of 109%, reflecting higher production
levels. On a unit of production basis, these expenses increased to $0.29 per
Mcfe in 1996 from $0.26 per Mcfe in 1995.

         The Partnership expensed exploration and dry hole costs of $606,000 in
1996 and $6,767,000 in 1995, a decrease of 91%, primarily reflecting a larger
allocation of resources to exploratory prospects in south Louisiana during 1995.

         General and administrative expenses of $854,000 in 1996 increased 38%
from $620,000 in 1995, reflecting an increase in the Partnership's share of
administration costs associated with development operations of Kelley. On a unit
of production basis, these expenses decreased to $0.10 per Mcfe 1996 from $0.14
per Mcfe in 1995.

         Depreciation, depletion and amortization ("DD&A") decreased to
$5,536,000 in 1996 compared to $6,617,000 in 1995 due to lower depletion rates
following noncash impairment charges aggregating $10,914,000 recognized in the
fourth quarter of 1995 against the carrying value of the Partnership's oil and
gas properties under FAS 121. On a unit of production basis, DD&A decreased to
$0.68 per Mcfe in 1996 from $1.54 per Mcfe in 1995. See "General-Property
Impairment under SFAS 121" above.

                                       13
<PAGE>
         The Partnership realized net income in 1996 of $10,896,000 or $0.50 per
Unit compared to a net loss of $15,394,000 or $0.71 per Unit in 1995, reflecting
the foregoing developments.

LIQUIDITY AND CAPITAL RESOURCES

         LIQUIDITY. Net cash provided by the Partnership's operating activities
during 1997, as reflected on its statements of cash flows, totaled $11,071,000.
The Partnership's cash position was increased during 1997 by payments of
subscriptions for Units and General Partner contributions aggregating
$5,819,000. During the year, funds were used in investing and financing
activities comprised primarily of property and equipment expenditures of
$1,708,000 for exploration and development of the Partnership's oil and gas
properties and distributions to partners aggregating $15,207,000 (including a
return of uncommitted capital - see "Capital Resources"). As a result of these
activities, the Partnership's cash and cash equivalents decreased from $25,000
at December 31, 1996 to zero at December 31, 1997.

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

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

         On February 29, 1996, the Contemplated Capital exceeded the Committed
Expenditures. Accordingly, the excess Contemplated Capital aggregating
$4,345,000 or $0.20 per Unit was distributed as a return of capital during 1996.
In 1996, Kelley 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 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.

         In December 1996, KOGC entered into a new revolving credit facility
with a group of banks, as amended December 1, 1997 (the "Credit Facility"). The
agreement for the Credit Facility provides for a maximum $140 million ($125
million prior to amendment) revolving credit loan, which requires the payment of
interest only until December 2000, when all borrowings will be repayable. The
Partnership and Joint Venture are guarantors under the Credit Facility. The
Credit Facility is secured by all the oil and gas properties and other assets of
KOGC and its subsidiaries, including the Partnership and the Joint Venture. The
agreement covering the Credit Facility provides various financial covenants as
well as restrictions on additional debt, mergers and asset sales, but limits the
lenders' recourse upon any default to Partnership and Joint Venture assets
attributable to Kelley Oil's interests in the Partnership. At December 31, 1997
the borrowing base was $138 million.

                                       14
<PAGE>
         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 1997 aggregating
$0.65 per Unit or a total of $13,562,000, along with $559,000 to the Managing
and Special General Partners for their interests. In March 1998, the Partnership
made a quarterly distribution of $0.11 per Unit or a total of $2,295,000, along
with $95,000 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.

         The Partnership does not anticipate that it will incur any significant
expenditures to address Year 2000 issues, nor do Year 2000 issues represent a
known material event or uncertainty to the Partnership. To the extent that the
Partnership may be adversely affected by the Year 2000 issues of its suppliers,
customers and other entities generally, it does not believe that it will be more
adversely affected than other companies in its industry with similar operations.

         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 gas
prices received by the Partnership during the periods indicated.

                                                        AVERAGE         AVERAGE
                                                       OIL PRICE       GAS PRICE
                                                        ($/BBL)         ($/MCF)
YEAR ENDED:                                           ----------       ---------
   December 31, 1995...............................   $   16.58        $  1.71
   December 31, 1996...............................       21.59           2.27
   December 31, 1997...............................       19.64           2.27

                                       15
<PAGE>
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................................................................................  17
Balance Sheets - December 31, 1996 and 1997.................................................................  18
Statements of Operations - For the years ended December 31, 1995, 1996 and 1997.............................  19
Statements of Cash Flows - For the years ended December 31, 1995, 1996 and 1997.............................  20
Statements of Changes in Partners' Equity - For the years ended December 31, 1995, 1996 and 1997............  21
Notes to Financial Statements...............................................................................  22
</TABLE>
                                       16
<PAGE>
                          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,
1996 and 1997 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,
1997. 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, 1996 and 1997, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1997, in conformity with generally accepted accounting principles.

         As discussed in Note 1 to the financial statements, in 1995 the
Partnership changed its method of accounting for the impairment of long-lived
assets to conform with Statement of Financial Accounting Standards No. 121.

DELOITTE & TOUCHE LLP

Houston, Texas
March 6, 1998

                                       17
<PAGE>
                KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM
                                 BALANCE SHEETS

                                 (IN THOUSANDS)
<TABLE>
<CAPTION>
                                                                      DECEMBER 31,
                                                                 --------------------
                                                                   1996        1997
                                                                 --------    --------
ASSETS:
<S>                                                              <C>         <C>
   Cash ......................................................   $     25    $   --
   Accounts receivable - trade ...............................        217          59
   Accounts receivable - affiliates ..........................      6,202       5,979
                                                                 --------    --------
     Total current assets ....................................      6,444       6,038
                                                                 --------    --------
   Oil and gas properties, successful efforts method:
     Properties subject to amortization ......................     43,870      45,209
     Less:  Accumulated depreciation, depletion & amortization    (24,835)    (29,466)
                                                                 --------    --------
     Total oil and gas properties ............................     19,035      15,743
                                                                 --------    --------
   Total assets ..............................................   $ 25,479    $ 21,781
                                                                 ========    ========
LIABILITIES:
   Accounts payable and accrued expenses .....................   $  2,797    $    487
                                                                 --------    --------
     Total current liabilities ...............................      2,797         487
                                                                 --------    --------
   Total liabilities .........................................      2,797         487
                                                                 --------    --------
PARTNERS' EQUITY:
   LP Unitholders' equity ....................................      1,527       1,172
   GP Unitholders' equity ....................................     20,025      19,280
   Managing and Special General Partners' equity .............      1,130         842
                                                                 --------    --------
     Total partners' equity ..................................     22,682      21,294
                                                                 --------    --------
   Total liabilities and partners' equity ....................   $ 25,479    $ 21,781
                                                                 ========    ========
</TABLE>
See Notes to Financial Statements.

                                       18
<PAGE>
                KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM
                            STATEMENTS OF OPERATIONS

                      (IN THOUSANDS, EXCEPT PER UNIT DATA)
<TABLE>
<CAPTION>
                                                                          YEAR ENDED DECEMBER 31,
                                                                       -----------------------------
                                                                         1995       1996      1997
                                                                       --------    -------   -------
<S>                                                                    <C>         <C>       <C>
REVENUES:
   Oil and gas sales ...............................................   $  7,723    $18,986   $15,835
   Interest income .................................................      2,924      1,254       135
                                                                       --------    -------   -------
     Total revenues ................................................     10,647     20,240    15,970
                                                                       --------    -------   -------
COSTS AND EXPENSES:
   Lease operating expenses ........................................        699      1,636     1,402
   Severance taxes .................................................        424        712       634
   Exploration expenses ............................................      6,767        606       369
   General and administrative expenses .............................        620        854       934
   Depreciation, depletion and amortization ........................      6,617      5,536     4,631
   Impairment of oil and gas properties ............................     10,914       --        --
                                                                       --------    -------   -------
     Total expenses ................................................     26,041      9,344     7,970
                                                                       --------    -------   -------
Net income (loss) ..................................................   $(15,394)   $10,896   $ 8,000
                                                                       ========    =======   =======
Net income (loss) allocable to LP and GP unitholders ...............   $(14,785)   $10,465   $ 7,684
                                                                       ========    =======   =======
Net income (loss) allocable to managing and special general partners   $   (609)   $   431   $   316
                                                                       ========    =======   =======
Net income (loss) per unit .........................................   $   (.71)   $   .50   $   .37
                                                                       ========    =======   =======
Average LP and GP Units outstanding ................................     20,864     20,864    20,864
                                                                       ========    =======   =======
</TABLE>
See Notes to Financial Statements.

                                       19
<PAGE>
                KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM
                            STATEMENTS OF CASH FLOWS

                                 (IN THOUSANDS)
<TABLE>
<CAPTION>
                                                                            YEAR ENDED DECEMBER 31,
                                                                      --------------------------------
                                                                         1995        1996        1997
                                                                      --------    --------    --------
<S>                                                                   <C>         <C>         <C>
OPERATING ACTIVITIES:
   Net income (loss) ..............................................   $(15,394)   $ 10,896    $  8,000
   Adjustments to reconcile net loss to net cash provided by
     operating activities:
     Depreciation, depletion and amortization .....................      6,617       5,536       4,631
     Impairment of oil and gas properties .........................     10,914        --          --
     Exploration expenses .........................................      6,767         606         369
     Gain on sale of oil and gas properties .......................       --           (89)       --
     Changes in operating assets and liabilities:
       Decrease (increase) in accounts receivable .................        132      (4,396)        381
       Increase (decrease) in other assets ........................        (16)         21        --
       Increase (decrease) in accounts payable and accrued expenses      4,474      (3,819)     (2,310)
                                                                      --------    --------    --------
   Net cash provided by operating activities ......................     13,494       8,755      11,071
                                                                      --------    --------    --------
INVESTING ACTIVITIES:
   Capital expenditures ...........................................    (22,959)    (13,235)     (1,708)
   Sale of other non-current assets ...............................         68          82        --
   Sale of oil and gas properties .................................       --           780        --
                                                                      --------    --------    --------
   Net cash used in investing activities ..........................    (22,891)    (12,373)     (1,708)
                                                                      --------    --------    --------
FINANCING ACTIVITIES:
   Capital contributed by partners ................................     15,870      22,920       5,819
   Syndication costs charged to equity ............................         (9)       --          --
   Distributions ..................................................     (7,169)    (14,989)    (14,121)
   Distributions of uncommitted capital ...........................       --        (4,345)     (1,086)
                                                                      --------    --------    --------
   Net cash provided by (used in) financing activities ............      8,692       3,586      (9,388)
                                                                      --------    --------    --------
   Increase (decrease) in cash and cash equivalents ...............       (705)        (32)        (25)

Cash and cash equivalents, beginning of period ....................        762          57          25
                                                                      --------    --------    --------
Cash and cash equivalents, end of period ..........................   $     57    $     25    $   --
                                                                      ========    ========    ========
</TABLE>
See Notes to Financial Statements.

                                       20
<PAGE>
                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, 1995 .   $       3,121    $      11,150    $      631    $ 14,902
                                        -------------    -------------    ----------    --------

Capital contributed .................              84           14,061         1,725      15,870
Syndication costs ...................              (1)              (8)         --            (9)
Distributions .......................            (387)          (6,499)         (283)     (7,169)
Net loss ............................            (832)         (13,953)         (609)    (15,394)
                                        -------------    -------------    ----------    --------
Partners' equity at December 31, 1995           1,985            4,751         1,464       8,200
                                        -------------    -------------    ----------    --------

Capital contributed .................            --             22,920          --        22,920
Return of capital contributed .......            (236)          (3,937)         (172)     (4,345)
Distributions .......................            (813)         (13,583)         (593)    (14,989)
Net income ..........................             591            9,874           431      10,896
                                        -------------    -------------    ----------    --------
Partners' equity at December 31, 1996           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
                                        =============    =============    ==========    ========
</TABLE>
See Notes to Financial Statements.

                                       21
<PAGE>
                KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM
                          NOTES TO FINANCIAL STATEMENTS


NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

         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, 1997, all Unit
subscriptions were paid. In addition to the Units, Kelley Oil Corporation, the
managing general partner of the Partnership ("Kelley Oil") 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, 1997, 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.

         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. In the fourth quarter of 1995, the
Partnership implemented the 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"). Under 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. The Partnership performed an assessment of the carrying value of
its oil and gas properties indicating an impairment should be recognized at year
end. Under this analysis, the fair value of the Partnership's oil and gas
properties was estimated on a depletable unit basis using escalated pricing and
present value discount factors reflecting risk assessments. Based on this
analysis, the Partnership recognized a noncash impairment charge of $10.9
million against the carrying value of its oil and gas properties under SFAS 121
at December 31, 1996.

                                       22
<PAGE>
         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.

         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, and payables.

         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 4 - "Hedging Activities" for a discussion of the
Partnership's accounting policies related to hedging activities.

         CONCENTRATION OF CREDIT RISK AND SIGNIFICANT CUSTOMERS. Substantially
all of the Partnership's receivables are due from the marketing subsidiary of
Kelley Oil, 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. Based upon the provisions of SFAS
130, it is anticipated that the Partnership will not have a significant change
in its reporting requirements.

         RISKS AND UNCERTAINTIES. 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 1995 and
1996 have been reclassified to conform to the 1997 presentation.

NOTE 2 - CASH DISTRIBUTIONS

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

                 1995
                First quarter............................   $  .04
                Second quarter...........................      .09
                Third quarter............................      .10
                Fourth quarter...........................      .10
                                                            ------
                   Total.................................   $  .33
                                                            ======

                                       23
<PAGE>
                1996
                First quarter............................   $  .12
                Second quarter...........................      .18
                Third quarter............................      .18
                Fourth quarter...........................      .21
                                                            ------
                   Total.................................   $  .69
                                                            ======

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

         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 3 - RELATED PARTY TRANSACTIONS

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

         For the years ended December 31, 1995, 1996 and 1997, Kelley Oil was
reimbursed by the Partnership for costs directly associated with acquisition,
exploration and development activities aggregating $2,649,000, $1,245,000 and
$369,000, respectively, and for its allocable portion of general and
administrative expenses aggregating $542,000, $753,000 and $934,000,
respectively. For the years ended December 31, 1995 and 1996, the Partnership
capitalized $1,963,000, $611,000, respectively, of allocated direct costs to oil
and gas properties.

         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.

         In December 1996, KOGC entered into a new revolving credit facility
with a group of banks, as amended December 1, 1997 (the "Credit Facility"). The
agreement for the Credit Facility provides for a maximum $140 million ($125
million prior to amendment) revolving credit loan, which requires the payment of
interest only until December 2000, when all borrowings will be repayable. The
Partnership and Joint Venture are guarantors under the Credit Facility. The
Credit Facility is secured by all the oil and gas properties and other assets of
KOGC and its subsidiaries, including the Partnership and the Joint Venture. The
agreement covering the Credit Facility provides various financial covenants as
well as restrictions on additional debt, mergers and asset sales, but limits the
lenders' recourse upon any default to Partnership and Joint Venture assets
attributable to Kelley Oil's interests in the Partnership. At December 31, 1997
the borrowing base was $138 million.

         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
1995, 1996 and 1997, the fee was 2% of the resale price for marketed natural
gas.

                                       24
<PAGE>
NOTE 4 - HEDGING ACTIVITIES

           KOGC 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. KOGC does
not engage in speculative transactions. KOGC'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 1997,
the KOGC 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. 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, approximately 65% of the
Partnership's natural gas production for 1997 was affected by its hedging
transactions at an average NYMEX quoted price of $2.35 per Mmbtu before
transaction and transportation costs. As of December 31, 1997, approximately 29%
of the Partnership's anticipated natural gas production for 1998 has been hedged
by natural gas price swap agreements at an average NYMEX quoted price of $2.30
per Mmbtu before transaction and transportation costs. Certain natural gas price
swap agreements outstanding at December 31, 1997 permit the counterparty to
double the contract volume at a specified price. If this feature is exercised on
all contracts outstanding at December 31, 1997, approximately 40% of the
Partnership's anticipated natural gas production for 1998 has been hedged by
natural gas price swap agreements at an average NYMEX quoted price of $2.31 per
Mmbtu before transaction and transportation costs. In addition, as of December
31, 1997, the Partnership had outstanding natural gas basis swap agreements
covering approximately 34% of its anticipated natural gas production for January
1998 through September 1998. Hedging activities decreased Partnership revenues
by approximately $1.2 million in 1997 as compared to estimated revenues had no
hedging activities been conducted.

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

NOTE 5 -   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,
                                                       --------------------------------
                                                         1995        1996        1997
                                                       --------    --------    --------
<S>                                                    <C>         <C>         <C>
Evaluated properties subject to amortization .......   $ 31,932    $ 43,870    $ 45,209
Accumulated depreciation, depletion and amortization    (19,217)    (24,835)    (29,466)
                                                       --------    --------    --------
   Net capitalized costs ...........................   $ 12,715    $ 19,035    $ 15,743
                                                       ========    ========    ========
</TABLE>
                                       25
<PAGE>
         COSTS INCURRED. All costs were incurred in oil and gas property
development activities (as defined in the Partnership Agreement) and aggregated
$22,959,000, $13,235,000 and $1,708,000 for the years ended December 31, 1995,
1996 and 1997, respectively.

         RESERVES. The following table summarizes the Partnership's net
ownership interests in estimated quantities of proved oil and gas reserves and
changes in net proved reserves, all of which are located in the continental
United States, for the years ended December 31, 1995, 1996 and 1997.
<TABLE>
<CAPTION>
                                                       CRUDE OIL, CONDENSATE
                                                       AND NATURAL GAS LIQUIDS                     NATURAL GAS
                                                                 (MBBLS)                              (MMCF)
                                                     --------------------------------    --------------------------------
                                                       1995        1996        1997        1995        1996        1997
                                                     --------    --------    --------    --------    --------    --------
<S>                                                    <C>         <C>         <C>      <C>         <C>         <C>
Proved developed and undeveloped reserves:
   Beginning of year .............................        583         167         123      49,146      58,640      35,347
   Revisions of previous estimates ...............       (472)          7         (10)    (32,447)    (15,438)     (2,978)
   Extensions and discoveries ....................        106        --          --        45,941         439        --
   Sales of reserves in place ....................       --            (2)       --          --          (422)       --
   Production ....................................        (50)        (49)        (30)     (4,000)     (7,872)     (6,727)
                                                     --------    --------    --------    --------    --------    --------
     End of year .................................        167         123          83      58,640      35,347      25,642
                                                     ========    ========    ========    ========    ========    ========

Proved developed reserves at end of year .........        107         118          81      16,988      31,296      24,175
                                                     ========    ========    ========    ========    ========    ========
</TABLE>
         The reported revisions of previous reserve estimates during 1995
reflect downward year-end revisions primarily on undeveloped locations in south
Louisiana based on reprocessed 3-D seismic data and a change in the
Partnership's drilling strategy to focus exclusively on lower risk north
Louisiana locations for the balance of its drilling program. As a result of
these factors, the Partnership performed an assessment of the carrying value of
its oil and gas properties under SFAS 121 indicating an impairment should be
recognized as of year end. See Note 1 - "Summary of Significant Accounting
Policies". Based on this analysis, the Partnership recognized a noncash
impairment charge of $10.9 million against the carrying values of its oil and
gas properties under SFAS 121 at December 31, 1995.

         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, 1995, 1996 and 1997
is shown below.

                                 (IN THOUSANDS)
<TABLE>
<CAPTION>
                                                                         DECEMBER 31,
                                                              ----------------------------------
                                                                 1995         1996        1997
                                                              ---------    ---------    --------
<S>                                                           <C>          <C>          <C>
Future cash inflows .......................................   $ 122,415    $ 129,261    $ 64,664
Future production costs ...................................     (16,301)     (11,520)    (13,817)
Future development costs ..................................     (14,955)      (3,063)     (1,759)
                                                              ---------    ---------    --------
   Future net cash flows ..................................      91,159      114,678      49,088
10% annual discount for estimating timing of cash flows ...     (35,047)     (39,540)    (17,764)
                                                              ---------    ---------    --------
   Standardized measure of discounted future net cash flows   $  56,112    $  75,138    $ 31,324
                                                              =========    =========    ========
</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.

                                       26
<PAGE>
         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, 1995, 1996 and 1997 was calculated using prices in effect as of
those dates, which had a weighted average of $19.73, $24.93 and $17.18,
respectively, per barrel of oil and $2.03, $3.66 and $2.47, respectively, per
Mcf of natural gas.

         CHANGES IN STANDARDIZED MEASURE. Changes in standardized measure of
future net cash flows relating to proved oil and gas reserves are summarized
below.

                                 (IN THOUSANDS)
<TABLE>
<CAPTION>
                                                           YEAR ENDED DECEMBER 31,
                                                      --------------------------------
                                                         1995        1996        1997
                                                      --------    --------    --------
<S>                                                   <C>         <C>         <C>
Changes due to current year operations:
   Sales of oil and gas, net of production costs ..   $ (6,600)   $(16,638)   $(13,799)
   Sales of oil and gas properties ................       --          (780)       --
   Extensions and discoveries .....................     43,902         264        --
   Development costs incurred during the year .....      4,181      12,395       2,189
Changes due to revisions in standardized variables:
   Prices and production costs ....................        (70)     48,749     (30,889)
   Revisions of previous quantity estimates .......    (25,442)    (36,503)     (3,872)
   Estimated future development costs .............      8,121         178        (587)
   Accretion of discount ..........................      3,556       5,611       7,514
   Production rates (timing) and other ............     (7,092)      5,750      (4,370)
                                                      --------    --------    --------
     Net increase .................................     20,556      19,026     (43,814)

   Beginning of period ............................     35,556      56,112      75,138
                                                      --------    --------    --------
     End of year ..................................   $ 56,112    $ 75,138    $ 31,324
                                                      ========    ========    ========
</TABLE>
                                    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 57 employees as of December 31, 1997, 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 Kelley Oil & Gas Corporation.

                                       27
<PAGE>
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>
John F. Bookout................. 75     President, Chief Executive Officer and a director                  1996
David C. Baggett................ 36     Senior Vice President and Chief Financial Officer and a director   1997
Dallas D. Laumbach.............. 61     Senior Vice President-Exploration and Production and a director    1996
Thomas E. Baker................. 67     General Counsel and Corporate Secretary                            1996
</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.
From 1988 through 1993, he served as a member of the Supervisory Board of Royal
Dutch Petroleum. He currently serves on the board of directors of McDermott
International Inc., J. Ray McDermott, S.A. and The Investment Company of America
as well as the board of trustees of the United States Counsel for International
Business and various civic and educational bodies.

         DAVID C. BAGGETT was elected Senior Vice President and Chief Financial
Officer and a director of Kelley Oil in March 1997. Previously, he was a partner
with Deloitte & Touche LLP for more than five years.

         DALLAS D. LAUMBACH has served as Senior Vice President-Exploration and
Production and a director of Kelley Oil since February 1996 and has served
concurrently as President of Concorde Gas, Inc. since August 1996. He previously
served as Senior Vice President of Contour commencing in December 1993. Before
joining Contour, Mr. Laumbach served in positions of increasing responsibility
for 24 years at Shell Oil Company, concluding as Manager-Business Development in
Shell's Head Office.

         THOMAS E. BAKER is an attorney and joined Kelley Oil in July 1996 as
General Counsel and Corporate Secretary. From August 1991 through June 1996, Mr.
Baker was engaged in a private consulting practice.

BENEFICIAL OWNERSHIP REPORTING

         Not applicable.

ITEM 11.  EXECUTIVE COMPENSATION

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


ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

BENEFICIAL OWNERS

         The following table sets forth information as of December 31, 1997 with
respect to the only person known by the Partnership to own beneficially more
than five percent of the Partnership's Units.

                                       28
<PAGE>
                                 AMOUNT & NATURE
NAME AND ADDRESS OF               OF BENEFICIAL         PERCENT
BENEFICIAL OWNER                    OWNERSHIP          OF CLASS
------------------------         ---------------       --------
Kelley Oil Corporation             19,163,889             91.85%
601 Jefferson, Suite 1100            Direct
Houston, Texas  77002


MANAGEMENT

         The following table sets forth information as of December 31, 1997 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.

                                   AMOUNT & NATURE
NAME AND ADDRESS OF                 OF BENEFICIAL                   PERCENT
BENEFICIAL OWNER                    OWNERSHIP(1)                   OF CLASS
-------------------                ----------------                --------
John F. Bookout                              --                         --
Dallas D. Laumbach                           --                         --
David C. Baggett                             --                         --
All directors and officers
   as a group (9 persons)                 None                      None


         (1)      Represents direct beneficial ownership.

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

         The Unitholders have a 96.04% share and the General Partners a 3.96%
share in the costs and revenues of the Partnership. Allocations of costs and
revenues to Unitholders are made in accordance with the number of Units owned.
The General Partners contributed $2,580,897 to the Partnership for their 3.96%
interest. Costs and expenses incurred by Kelley Oil in connection with the
syndication and organization of the Partnership aggregating approximately
$750,000 were reimbursed by the Partnership in 1994 and charged to partners'
equity. For further discussion on Related Transactions see Note 3 to Notes to
Financial Statements.


                                     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.

                                       29
<PAGE>
         (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 1997.

                                       30
<PAGE>
                                   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 30th day of
March, 1998.
<TABLE>
<CAPTION>
<S>                                         <C>
                                            KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM

                                            By: KELLEY OIL CORPORATION, Managing General Partner


By:      /S/ JOHN F. BOOKOUT            By:     /S/ DAVID C. BAGGETT            By:   /S/ KENNETH R. BICKETT
           John F. Bookout                        David C. Baggett                      Kenneth R. Bickett
       Chief Executive Officer                  Senior Vice President                       Controller
                                             and Chief Financial Officer            (Chief Accounting Officer)
</TABLE>
         Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed as of the 30th day of March, 1998 by the following
persons in their capacity as directors of the Registrant's managing general
partner.



             /S/ JOHN F. BOOKOUT                         /S/ DALLAS D. LAUMBACH
               John F. Bookout                             Dallas D. Laumbach



            /S/ DAVID C. BAGGETT
              David C. Baggett

                                       31