<PAGE>

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                      SECURITIES AND EXCHANGE COMMISSION
                            Washington, D. C. 20549

                                   FORM 10-K

                 Annual Report Pursuant to Section 13 or 15(d)
                    of the Securities Exchange Act of 1934

For the Fiscal Year Ended December 31, 2001         Commission File No. 0-20998

                             KELLEY PARTNERS 1992
                         DEVELOPMENT DRILLING PROGRAM
            (Exact name of Registrant as specified in its charter)

                 Texas                               76-0373428
    (State or other jurisdiction of     (I.R.S. Employer Identification No.)
    incorporation or organization)

           1001 McKinney St.
               Suite 900
            Houston, Texas                              77002
    (Address of principal executive                  (Zip Code)
               offices)

      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 22, 2002, Kelley Partners 1992 Development Drilling Program had
16,033,009 units of limited and general partner interests (the "Units")
outstanding. The Units are not publicly traded.

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                                    PART I

Items 1 and 2. Business and Properties

 Introduction

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

   In December 2000, Contour E&P invited the unit holders for the Partnership
to tender their units for cash. The cash offer was $0.123 per unit for all of
the Partnership units not held by Contour E&P. A total of 1,298,724
Partnership units (50% of units eligible for tender) were tendered. The total
cost was approximately $200,000, including transaction costs.

   In 2001, Kelley Oil Corporation, the Managing General Partner of the
Partnership converted to a Delaware limited liability company and changed its
name to Contour Energy E&P, LLC. As of December 31, 2001, Contour E&P owns
91.86% of the Units and a 3.94% General Partner interest.

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

   During the first half of 2001, the partnership benefited from an increase
in the level of commodity prices compared to historic levels. However, cash
prices and NYMEX based prices for both oil and natural gas have declined
significantly during the second half of 2001 and early 2002, reflecting the
volatility of commodity prices. Natural gas prices over the past six months
have averaged below $2.50/Mcf and crude prices have averaged below $20.00/bbl.
Sustained prices at these levels or lower could have a materially adverse
impact on the Partnership's results of operations and its ability to make
future distributions. Historically, Contour periodically entered into hedge
contracts to protect against commodity price declines on behalf of the
Partnership. However, effective 2001 the Partnership no longer participated in
hedging transactions due to its relatively small production volumes.

   General Partner. Contour's 14% senior secured notes totaling $105 million
becomes due by April 15, 2003. Redemption of these notes begins in 2002 with
$2.1 million principal payments due in July and October. An additional
redemption payment of $2.1 million is due in January 2003 with a final payment
of $98.7 million due on April 15, 2003. It is not anticipated that Contour
will generate sufficient cash flows from operations to repay this debt.
Neither can it assume that future borrowings will be available in an amount
sufficient to pay or refinance this obligation on commercially reasonable
terms or at all. Failure to repay or refinance the debt as it matures would
result in a default under the indenture.

   Contour has entered into discussions with certain of its debt holders that
may lead to a restructuring transaction. The outcome of the negotiations and
the possible impact on the Partnership are uncertain. However,

                                       1
<PAGE>

if negotiations are not successful, Contour may be forced to seek protection
under federal bankruptcy regulations. Contour E&P is a guarantor under the 14%
senior secured notes. A potential default under these notes or a bankruptcy
filing by Contour could have a material adverse impact on the Partnership.

   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
Contour E&P. The Partnership contributed to the Joint Venture substantially
all of the partners' contributed capital to finance the costs of drilling,
completing, equipping and, when necessary, abandoning the wells drilled by the
Joint Venture, proportionate with the Joint Venture's working interest in each
well. Kelley Operating contributed to the Joint Venture specific drilling
rights for development wells on its properties selected by the Managing
General Partner. In return for the contributed drilling rights, Kelley
Operating has reserved a 20% reversionary interest after Payout (as defined in
the Joint Venture Agreement) in the costs and revenues of the Joint Venture.

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

   Development. From inception through the completion of drilling activities
in 1994, the Partnership participated in drilling 39 gross wells, of which 30
gross (11.07 net) wells were productive and 9 gross (4.16 net) wells were dry.
The Partnership currently produces from 10 active wells mostly located in the
Ada and Sibley fields of north Louisiana and the Orange Grove, Humphreys, and
Ouiski Bayou fields of South Louisiana. No wells were drilled in 2001 and
there are no drilling plans for 2002.

   Distributions. The Partnership maintains a policy of distributing cash that
is not required for the conduct of Partnership business to unitholders on a
quarterly basis. During 2001, current year earnings distributions were paid to
the managing and special general partners and the unitholders in the amounts
of $17,000 and $436,000, or $0.03 per Unit, respectively. However, future
distributions to the unitholders are dependent on the future operating results
of the Partnership. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations."

 Management, Operations and Properties

   Contour E&P's principal executive offices are located at 1001 McKinney
Street, Suite 900, Houston, Texas 77002, and its main telephone number is
(713) 652-5200. As Managing General Partner, Contour E&P makes all decisions
regarding the business and operations of the Partnership. The Partnership has
no employees and utilizes the officers and staff of Contour E&P to perform all
management and administrative functions. Contour E&P's staff includes
employees experienced in geology, geophysics, petroleum engineering, land
acquisition and management, finance and accounting. Contour E&P is also the
managing general partner of Kelley Operating. See "Employees" below and
"Managers of Contour Energy E&P, LLC".

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

   The General Partners receive no management or other fees or promoted
interests from the Partnership or the Joint Venture. The Partnership
reimburses Contour E&P 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 Contour E&P.

                                       2
<PAGE>

 Estimated Proved Reserves

   General. The estimated gross quantities of proved and proved developed
reserves for properties in which the Partnership owns interests were prepared
as of January 1, 2000, 2001 and 2002, by an independent petroleum engineering
firm. For the reserves at January 1, 2000, 2001 and 2002, Contour applied
appropriate Partnership revenue interests to determine the Partnership's net
proved reserves shown below.

   Quantities. The following table sets forth the Partnership's estimated
quantities of proved and proved developed reserves of crude oil (including
condensate and natural gas liquids) and natural gas as of January 1, 2000,
2001 and 2002. Proved developed reserves are reserves that can be expected to
be recovered from existing wells with existing equipment and operating
methods. Proved undeveloped reserves are proved reserves that are expected to
be recovered from new wells drilled to known reservoirs on undrilled acreage
for which the existence and recoverability of reserves can be estimated with
reasonable certainty, or from existing wells where a relatively major
expenditure is required for recompletion.

Estimated Proved Reserves

<TABLE>
<CAPTION>
                                                                As of January 1,
                                                                ----------------
                                                                2000  2001  2002
                                                                ----- ----- ----
<S>                                                             <C>   <C>   <C>
Crude oil and liquids (Mbbl):
  Proved developed.............................................    64    70  57
  Proved undeveloped...........................................    --    --  --
                                                                ----- ----- ---
    Total proved...............................................    64    70  57
                                                                ===== ===== ===

Natural gas (Mmcf):
  Proved developed............................................. 1,196 1,247 798
  Proved undeveloped...........................................    --    --  --
                                                                ----- ----- ---
    Total proved............................................... 1,196 1,247 798
                                                                ===== ===== ===
</TABLE>

   Detailed information concerning the Partnership's estimated proved reserves
and discounted net future cash flows is contained in the Supplementary
Financial Information included in Note 8 in Notes to the Financial Statements.
The Partnership has not filed any estimates of reserves with any federal
authority or agency during the past year other than estimates contained in its
last annual report filed with the Securities and Exchange Commission ("SEC").

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

                                       3
<PAGE>

 Description of Significant Properties

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

   Significant Fields. The following table sets forth certain information as
of January 1, 2002 with respect to the Partnership's interests in its most
significant fields, together with information for all other fields combined.

Significant Proved Properties

<TABLE>
<CAPTION>
                           Proved Reserves at January 1,
                                       2002                       2001 Production
                          ------------------------------- -------------------------------
                                            Gas                             Gas
                            Oil    Gas   Equivalent         Oil    Gas   Equivalent
Property                  (Mbbls) (Mmcf)  (Mmcfe)     %   (Mbbls) (Mmcf)  (Mmcfe)     %
--------                  ------- ------ ---------- ----- ------- ------ ---------- -----
                                                  (in thousands)
<S>                       <C>     <C>    <C>        <C>   <C>     <C>    <C>        <C>
North Louisiana:
  Ada field.............     --     25        25      2.2    --      8        8       4.4
  Sibley field..........     10    266       326     28.6    --     20       20      11.0
South Louisiana:
  Orange Grove/Humphreys
   field................      2     31        43      3.8     2     29       41      22.5
  Ouiski Bayou field....     43    448       706     61.9     7     66      108      59.3
Other:
  As a group............      2     28        40      3.5    --      5        5       2.8
                            ---    ---     -----    -----   ---    ---      ---     -----
   Total................     57    798     1,140    100.0     9    128      182     100.0
                            ===    ===     =====    =====   ===    ===      ===     =====
</TABLE>

   Additional information regarding these fields is set forth below. Unless
otherwise noted, acreage and well information is provided as of December 31,
2001, and reserve information is provided as of January 1, 2002.

North Louisiana

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

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

South Louisiana

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

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

 Production, Price and Cost Data

   The following tables set forth the oil and gas production, average sales
price and average production costs per equivalent unit of oil and gas produced
by the Partnership for the years ended December 31, 1999, 2000 and

                                       4
<PAGE>

2001. Detailed additional information concerning the Partnership's oil and gas
producing activities is contained in the Supplementary Financial Information
included in Note 8 in Notes to the Financial Statements.

Oil and Gas Production

<TABLE>
<CAPTION>
                                                                  Year Ended
                                                                 December 31,
                                                               -----------------
                                                               1999  2000  2001
                                                               ----- ----- -----
<S>                                                            <C>   <C>   <C>
Crude oil, condensate and natural gas liquids (Bbls).......... 9,398 9,031 8,598
Natural gas (Mmcf)............................................   314   149   128
</TABLE>

Average Sales Prices and Production Costs

<TABLE>
<CAPTION>
                                                           Year Ended December
                                                                   31,
                                                           --------------------
                                                            1999   2000   2001
                                                           ------ ------ ------
<S>                                                        <C>    <C>    <C>
Average sales price:
  Crude oil, condensate and natural gas liquids per Bbl... $15.78 $29.70 $25.25
  Natural gas per Mcf, including the effects of hedging
   (1)....................................................   2.26   3.59   4.70
Oil and gas revenues per Mcfe (1).........................   2.32   3.95   4.56
Average production costs per Mcfe (1).....................   1.02   1.26   1.16
</TABLE>
--------
(1) Includes effect of accounting pronouncement EITF 00-10 issued in 2000
    requiring shipping and handling expenses (i.e. compression and
    transportation expenses) to be included in production costs rather than
    netted in revenues. Realized prices for natural gas per Mcf and oil and
    gas revenues per Mcfe have been restated accordingly.

 Oil and Gas Wells

   As of December 31, 2001, the Partnership owned interests in productive oil
and gas wells (including producing wells and wells capable of production) as
follows:

<TABLE>
<CAPTION>
                                                                Gross(/10/  Net
                                                                ---------- -----
<S>                                                             <C>        <C>
Oil wells......................................................      1       .02
Gas wells......................................................      9      1.35
                                                                   ---     -----
Total..........................................................     10      1.37
                                                                   ===     =====
</TABLE>
--------
(1) One or more completions in the same hole are counted as one well; none of
    the wells have multiple completions.

   Wells Drilled. All of the wells drilled by the Partnership are development
wells based on definitions in the Partnership Agreement of the Partnership.
The following table sets forth the number of gross and net productive and dry
development wells and exploratory wells drilled by the Partnership during the
periods indicated, based on a narrower definition for development wells under
SEC guidelines. The Partnership did not drill or participate in any wells
during 1999, 2000 and 2001.

 Marketing of Natural Gas and Crude Oil

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

   In addition to marketing natural gas and crude oil produced on Partnership
properties, a subsidiary of Contour E&P 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

                                       5
<PAGE>

disbursement services as well as regulatory filing, recordkeeping, inspection,
testing, monitoring functions, coordinating the connection of wells to various
pipeline systems, performing gas market surveys and overseeing gas balancing
with its various gas gatherers and transporters.

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

 Competition

   The oil and gas industry is highly competitive. Major oil and gas
companies, independent concerns, drilling and production purchase programs and
individual producers and operators are active bidders for desirable oil and
gas properties, as well as the equipment and labor required to operate those
properties. Many competitors have financial resources substantially greater
than those of the Partnership and staffs and facilities substantially larger
than those of Contour E&P. 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.

 Title to Properties

   The Partnership properties are subject to royalty interests, liens incident
to operating agreements, liens for current taxes and other customary burdens,
including other mineral encumbrances and restrictions. The Partnership does
not believe that any mortgage, lien or other burden materially interferes with
the use of such properties in the operation of its business.

   The Partnership believes that it have satisfactory title to or rights in
all of its producing properties. As is customary in the oil and natural gas
industry, minimal investigation of title is made at the time of acquisition of
undeveloped properties. Title investigation is made, and title opinions of
local counsel are generally obtained before commencement of drilling
operations or at least in connection with the preparation of division orders
when production is obtained and the revenues therefrom are allocated.

 Employees

   The Partnership has no employees and utilizes the management and staff of
Contour E&P. As of December 31, 2001, Contour E&P had 47 employees. Contour
E&P's staff includes employees experienced in geology, geophysics, petroleum
engineering, land acquisition and management, finance and accounting. See
"Managers of Contour Energy E&P, LLC". None of Contour E&P's employees are
represented by a union. Contour E&P has never experienced an interruption in
its operations from any kind of labor dispute, and its working relationship
with its employees is satisfactory.

Regulation

   General. The production, processing, marketing, and transportation of oil
and gas, and planned terminaling and storage of oil and gas storage by the
Partnership are subject to federal, state and local regulations which can have
a significant impact upon our overall operations.

   Exploration and Production. The availability of a ready market for oil and
natural gas production depends on numerous regulatory factors beyond our
control. The Partnership's operations are subject to various regulations at
the federal, state and local levels. These regulations include:

  . requiring permits for the drilling of wells;

  . maintaining bonding requirements to drill or operate wells; and

                                       6
<PAGE>

  . regulating the location of wells, the method of drilling and casing
    wells, the surface use and restoration of properties upon which wells are
    drilled, the plugging and abandoning of wells and the disposal of fluids
    used in connection with well operations.

   Our operations also are subject to various conservation regulations. These
include:

  . the regulation of the size of drilling and spacing units;

  . the density of wells that may be drilled; and

  . the unitization or pooling of gas and oil properties.

   In addition, state conservation laws establish maximum rates of production
from gas and oil wells, generally prohibiting the venting or flaring of gas,
and impose certain requirements regarding the ratability of production. The
effect of these regulations is to limit the amount of oil and gas the
Partnership can produce from its wells and to limit the number of wells or the
locations at which it can drill.

   Federal Regulation. Historically, the transportation and sales for resale
of gas in interstate commerce have been regulated pursuant to the Natural Gas
Act of 1938 ("NGA"), the Natural Gas Policy Act of 1978 ("NGPA") and Federal
Energy Regulatory Commission ("FERC") regulations. Effective January 1, 1993,
the Natural Gas Wellhead Decontrol Act deregulated price for all "first sales"
of natural gas. Thus, all sales of gas by the Partnership may be made at
market prices, subject to applicable contract provisions. Sales of gas are
affected by the availability, terms and cost of pipeline transportation. Since
1985, the FERC has implemented regulations intended to make natural gas
transportation more accessible to gas buyers and sellers on an open-access,
non-discriminatory basis.

   Beginning in April 1992, the FERC issued Order Nos. 636, 636-A, 636-B, 636-
C and 636-D ("Order No. 636") which required interstate pipelines to provide
open-access transportation on a not unduly discriminatory basis for all gas
shippers. The FERC has stated that it intends for Order No. 636 and its future
restructuring activities to foster increased competition within all phases of
the gas industry. Although Order No. 636 does not directly regulate the
Partnership's production and marketing activities, it does affect how buyers
and sellers gain access to the necessary transportation facilities and how the
Partnership and its competitors sell gas in the marketplace.

   The courts have largely affirmed the significant features of Order No. 636
and the numerous related orders pertaining to individual pipelines. However,
some appeals remain pending and the FERC continues to review and modify its
regulations regarding the transportation of gas. For example, in February
2000, the FERC issued Order No. 637, which;


  . lifts the cost-based cap on pipeline transportation rates in the capacity
    release market until September 30, 2002, for short-term releases of
    pipeline capacity of less than one year;


  . permits pipelines to file for authority to charge different maximum cost-
    based rates for peak and off-peak periods;

  . encourages, but does not mandate, auctions for pipeline capacity;

  . requires pipelines to implement imbalance management services;

  . restricts the ability of pipelines to impose penalties for imbalances,
    overruns and non-compliance with operational flow orders; and

  . implements a number of new pipeline reporting requirements.

                                       7
<PAGE>

   Order No. 637 also requires the FERC staff to analyze whether the FERC
should implement additional fundamental policy changes. These include whether
to pursue performance-based or other non-cost based ratemaking techniques and
whether the FERC should mandate greater standardization in terms and
conditions of service across the interstate pipeline grid.

   The Partnership cannot predict what further action the FERC will take on
these matters, nor can it accurately predict whether the FERC's actions will
achieve the goal of increasing competition in markets in which its gas is
sold. However, the Partnership does not believe that any action taken will
affect it in a way that materially differs from the way it affects its
competitors.

   The Outer Continental Shelf Lands Act ("OCSLA"), which the FERC implements
as to transportation and pipeline issues, requires that all pipelines
operating on or across the Outer Continental Shelf provide open-access, non-
discriminatory service. Historically, the FERC has opted not to impose
regulatory requirements under its OCSLA authority on gatherers and other
entities outside the reach of its NGA jurisdiction. However, on April 13,
2000, the FERC issued Order No. 639 as a vehicle to assure shippers using OCS
facilities of open access and nondiscriminatory conditions of service,
including nondiscriminatory rates. To achieve such assurances, the FERC
required that virtually all non-proprietary pipeline transporters of gas on
the Outer Continental Shelf report information on their affiliations, rates
and conditions of service. The reporting requirements established by the FERC
in Order No. 639 may apply, in certain circumstances, to operators of
production platforms and other facilities on the Outer Continental Shelf, with
respect to gas movements across such facilities. The rehearing order (Order
639-A) issued August 2, 2000, slightly modified the original order, but
maintained its material provisions.

   The FERC retains authority under the OCSLA to exercise jurisdiction over
gatherers and other entities outside the reach of its NGA jurisdiction if
necessary to ensure non-discriminatory access to service on the Outer
Continental Shelf. The Partnership does not believe that any FERC action taken
under its OCSLA jurisdiction will affect it in a way that materially differs
from the way it affects other gas producers, gatherers and marketers.

   Additional proposals and proceedings that might affect the gas industry are
pending before Congress, the FERC and the courts. The gas industry
historically has been very heavily regulated; therefore, there is no assurance
that the less stringent regulatory approach recently pursued by the FERC and
Congress will continue.

   Sales and Transportation of Oil. Our sales of crude oil, condensate and gas
liquids are not currently regulated, and are subject to applicable contract
provisions made at market prices. In a number of instances, however, the
ability to transport and sell our products is dependent on pipelines whose
rates, terms and conditions of service are subject to the FERC's jurisdiction
under the Interstate Commerce Act. In other instances, the Partnership's
ability to transport and sell its products is dependent on pipelines whose
rates, terms and conditions of service are subject to regulation by state
regulatory bodies under state statutes.

   The regulation of pipelines that transport oil, condensate and natural gas
liquids generally is more light-handed than the FERC's regulation of gas
pipelines under the NGA. Regulated pipelines that transport crude oil,
condensate, and natural gas liquids are subject to common carrier obligations
that generally ensure non-discriminatory access. With respect to interstate
pipeline transportation subject to regulation of the FERC under the Interstate
Commerce Act, rates generally must be cost-based, although market-based rates
or negotiated settlement rates are permitted in certain circumstances.

   State Regulation. Most states regulate the production and sale of oil and
gas, including requirements for obtaining drilling permits, the method of
developing new fields, the spacing and operation of wells and the prevention
of waste of oil and gas resources. The rate of production may be regulated and
the maximum daily production allowable from both oil and gas wells may be
established on a market demand or conservation basis or both.

                                       8
<PAGE>

   Environmental Regulations. The Partnership takes seriously 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. In particular, its drilling,
development and production operations, its activities in connection with
storage and transportation of crude oil and other liquid hydrocarbons and its
use of facilities for treating, processing or otherwise handling hydrocarbons
and wastes therefrom are subject to stringent environmental regulation, and
violations are subject to reporting requirements, civil penalties and criminal
sanctions. As with the industry generally, compliance with existing
regulations increases the Partnership's overall cost of business. The
increased costs are not reasonably ascertainable. Such areas affected include
unit production expenses primarily related to the control and limitation of
air emissions and the disposal of produced water, capital costs to drill
exploration and development wells resulting from expenses primarily related to
the management and disposal of drilling fluids and other oil and natural gas
exploration wastes and capital costs to construct, maintain and upgrade
equipment and facilities and plug and abandon inactive well sites and pits.

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

   The CAA requires or will require most industrial operations in the United
States to incur capital expenditures in order to meet air emission control
standards developed by the EPA and state environmental agencies. Although no
assurances can be given, the Partnership believes implementation of such
amendments will not have a material adverse effect on its financial condition
or results of operations. RCRA is the principal federal statute governing the
treatment, storage and disposal of hazardous wastes. RCRA imposes stringent
operating requirements (and liability for failure to meet such requirements)
on a person who is either a "generator" or "transporter" of hazardous waste or
an "owner" or "operator" of a hazardous waste treatment,

                                       9
<PAGE>

storage or disposal facility. At present, RCRA includes a statutory exemption
that allows oil and natural gas exploration and production wastes to be
classified as non-hazardous waste. As a result, the Partnership is not
required to comply with a substantial portion of RCRA's requirements because
its operations generate minimal quantities of hazardous wastes.

   CERCLA, also known as "Superfund", imposes liability, without regard to
fault or the legality of the original act, on certain classes of persons that
contributed to the release of a "hazardous substance" into the environment.
These persons include the "owner" or "operator" of the site and companies that
disposed or arranged for the disposal of the hazardous substances found at the
site. CERCLA also authorizes the EPA and, in some instances, third parties to
act in response to threats to the public health or the environment and to seek
to recover from the responsible classes of persons the costs they incur. In
the course of its ordinary operations, the Partnership may generate waste that
may fall within CERCLA's definition of a "hazardous substance". As a result,
it 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 have
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 it
has used 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 it or 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 our control. These properties and wastes disposed
thereon may be subject to CERCLA, RCRA and analogous state laws. Under such
laws, the Partnership could be required to remove or remediate previously
disposed wastes (including wastes disposed of or released by prior owners or
operators), to clean up contaminated property (including contaminated
groundwater) or to perform remedial plugging operations to prevent future
contamination.

Caution as to Forward-Looking Statements

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

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

Risk Factors

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

   Management. Contour E&P, a wholly owned subsidiary of Contour, is the
Managing General Partner of the Partnership. As Managing General Partner,
Contour E&P makes decisions affecting the assets of the Partnership. Contour
E&P also owns a substantial majority of the Partnership units. As owner of
units and manager of the Partnership assets, an adverse financial event to
Contour could also adversely affect the business of the

                                      10
<PAGE>

Partnership. Contour has $105 million of debt becoming due by April 15, 2003.
Failure to repay or refinance the debt as it matures would result in a default
under the indenture. That could have a material adverse impact on the
Partnership.

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

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

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

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

   The Partnership's oil and natural gas business also is subject to all of
the operating risks associated with the drilling for and production of oil and
natural gas, including, but not limited to, uncontrollable flows of oil,
natural gas, brine or well fluids into the environment (including groundwater
and shoreline contamination), blowouts, cratering, mechanical difficulties,
fires, explosions, pollution and other risks, any of which could result in
substantial losses to the Partnership. Although the Partnership maintains
insurance at levels that it believes are consistent with industry practices,
it is not fully insured against all risks. Losses and liabilities arising from
uninsured and underinsured events could have a material adverse effect on the
financial condition and operations of the Partnership. Moreover, the cost of
obtaining insurance increased dramatically in 2001 for the industry as a
whole. The Partnership's cost more than doubled in 2001 from the prior year.
Recent catastrophic events may cause the insurance market to continue to
tighten. As a result, the Partnership may not be able to maintain insurance at
adequate levels or at reasonable rates and particular types of coverage may
not be available in the future.

Item 3. Legal Proceedings

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

Item 4. Submission of Matters to a Vote of Security Holders

   Not applicable.

                                      11
<PAGE>

                                    PART II

Item 5. Market for Units and Related Unitholder Matters

   There is no market for the Units of the Partnership. Transfer of the Units
was substantially restricted by the provisions of the Partnership Agreement
until the Partnership Agreement was amended in December 2000 to allow
unitholders to buy or sell units from existing unitholders. As of March 22,
2002, there were 471 holders of record of the Partnership's Units.

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

<TABLE>
<CAPTION>
                                                                   Distributions
                                                                   -------------
1999:
-----
<S>                                                                <C>
First quarter.....................................................    $  --
Second quarter....................................................       --
Third quarter.....................................................       --
Fourth quarter....................................................       --
                                                                      ------
  Total...........................................................    $  --
                                                                      ======

<CAPTION>
2000:
-----
<S>                                                                <C>
First quarter.....................................................    $  --
Second quarter....................................................       --
Third quarter.....................................................       --
Fourth quarter....................................................       .02
                                                                      ------
  Total...........................................................    $  .02
                                                                      ======

<CAPTION>
2001:
-----
<S>                                                                <C>
First quarter                                                         $  --
Second quarter....................................................       .01
Third quarter.....................................................       .01
Fourth quarter....................................................       .01
                                                                      ------
  Total...........................................................    $  .03
                                                                      ======
</TABLE>

   Distribution levels are affected by numerous factors, including oil and gas
prices, production levels and operating costs, together with any working
capital or debt service requirements. To enable the Partnership to fund part
of its drilling and recompletion expenses in excess of contributed capital,
distributions were suspended in the fourth quarter of 1994 and reinstated only
for the third quarter of 1995. In the third quarter 2000, the final payment on
the $6,000,000 Initial Loan from Contour E&P was paid. The Partnership made
distributions for the year 2001 aggregating $435,000 to the unitholders, or
$0.03 per Unit, and $18,000 to the Managing and Special General Partners for
their interest. Future distributions to the unitholders and the managing and
special general partners are contingent on future operating results. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."

                                      12
<PAGE>

Item 6. Selected Financial Data

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

               KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
                    (In thousands, except per unit amounts)

<TABLE>
<CAPTION>
                                             Year Ended December 31,
                                     ------------------------------------------
                                      1997    1998     1999     2000     2001
                                     ------- -------  -------  -------  -------
<S>                                  <C>     <C>      <C>      <C>      <C>
Summary of Operations:
 Total revenues (1) (3)............. $ 2,391 $ 1,495  $ 1,693  $   800  $   817
 Production expenses (1)............     645     594      378      256      209
 Exploration expenses                    --      --       --       --       --
 General and administrative
  expenses..........................     476     134       92       62       44
 Interest expense...................     376     287      174        6      --
 Depreciation, depletion and
  amortization......................     587     427      225      120       77
 Impairment of oil and gas
  properties........................     --      466      --       --       --
 Net income (loss)..................     307    (413)     824      356      487
 Net income (loss) applicable to
  Unitholders (2)...................     295    (397)     791      342      468
 Net income (loss) per Unit (2).....     .02    (.02)     .05      .02      .03
 Distributions paid per Unit (2)....     --      --       --       .02      .03
 Units outstanding..................  16,033  16,033   16,033   16,033   16,033

<CAPTION>
                                             Year Ended December 31,
                                     ------------------------------------------
                                      1997    1998     1999     2000     2001
                                     ------- -------  -------  -------  -------
<S>                                  <C>     <C>      <C>      <C>      <C>
Summary Balance Sheet Data:
 Working capital (deficit).......... $   288 $    23  $   (17) $    (1) $    92
 Oil and gas properties, net........   3,369   2,528    1,070      927      868
 Long-term debt.....................   3,181   2,488      166      --       --
 Total partners' equity.............     476      63      887      926      960
 Total assets.......................   3,741   2,649    1,115    1,011    1,007
</TABLE>
--------
(1) Total Revenues and Production expenses have been restated for the years
    1997, 1998 and 2000 in accordance with accounting pronouncement EITF 00-10
    issued in 2000.
(2) Per Unit amounts are based on the Unitholders' 96.04% share of net income
    and loss.
(3) 1999 revenues include gain on sale of properties of $850.

                                      13
<PAGE>

Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations

 General

   In 1992, the Partnership issued a total of 16,033,009 units of limited and
general partner interests ("Units") at $3.00 per Unit for a total of
$48,099,027. The Units represent 96.04% of the total interests in the
Partnership and consist of 1,647,500 Units of limited partner interests ("LP
Units") and 14,385,509 Units of general partner interests ("GP Units") at
December 31, 2001. In addition, the Partnership issued managing and special
general partner interests on a pro rata basis for $1,983,258, representing
3.96% of the total interests in the Partnership. In the aggregate, Contour
Energy E&P, LLC (formerly Kelley Oil Corporation), a Delaware corporation, the
Managing General Partner of the Partnership ("Contour E&P"), owns 91.86% of
the Units and a 3.94% general partner interest at December 31, 2001. Contour
E&P is a subsidiary of Contour Energy Co., collectively with its subsidiaries
("Contour").

   In December 2000, Contour E&P invited the unit holders for the Partnership
to tender their units for cash. The cash offer was $0.123 per unit for all of
the Partnership units not held by Contour E&P. A total of 1,298,724
Partnership units (50% of units eligible for tender) were tendered. The total
cost was approximately $200,000, including transaction costs.

   In 2001, Kelley Oil Corporation, the Managing General Partner of the
Partnership converted to a Delaware limited liability company and changed its
name to Contour Energy E&P, LLC.

   General Partner. Contour's 14% senior secured notes totaling $105 million
becomes due by April 15, 2003. Contour E&P is a guarantor under these notes.
Redemption of these notes begins in 2002 with $2.1 million principal payments
due in July and October. An additional redemption payment of $2.1 million is
due in January 2003 with a final payment of $98.7 million due on April 15,
2003. It is not anticipated that Contour will generate sufficient cash flows
from operations to repay this debt. Neither can it assume that future
borrowings will be available in an amount sufficient to pay or refinance this
obligation on commercially reasonable terms or at all. Failure to repay or
refinance the debt as it matures would result in a default under the
indenture.

   Contour has entered into discussions with certain of its debt holders that
may lead to a restructuring transaction. The outcome of the negotiations and
the possible impact on the Partnership are uncertain. However, if negotiations
are not successful. Contour may be forced to seek protection under federal
bankruptcy regulations. Contour E&P is a guarantor under the 14% senior
secured notes. A potential default under these notes or a bankruptcy filing by
Contour could have a material adverse impact on the Partnership.

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

   Hedging Activities. Historically, Contour periodically entered into hedge
contracts to protect against commodity price declines on behalf of the
Partnership. Contour normally employs the average NYMEX price for the last
three days of the contract for natural gas and the monthly average of closing
NYMEX prices for crude oil as the underlying index ("Index Price") See Note 6
in the Notes to the Financial Statements. However, effective 2001 the
Partnership no longer plans to enter into hedging transactions because small
production volumes makes doing so no longer feasible.

   Through natural gas price swap agreements, the Partnership hedged
approximately 50% of its natural gas production for 1999 at average NYMEX
quoted price of $2.17/Mmbtu, before transaction and transportation costs. For
2000, the Partnership hedged approximately 72% of its natural gas production
using price swap agreements (48%) and a costless collar (24%). The average
price received under the swap agreements was $2.59/Mmbtu. The costless collar
included a ceiling of $4.98/Mmbtu and a floor of $4.00/Mmbtu at the closing
Index Price.

   Through crude oil price swap agreements, the Partnership hedged
approximately 29% of its crude oil production for 1999 at an average NYMEX
quoted price of $20.00 /Bbl, before transaction and transportation costs. For
2000, the Company hedged approximately 66% of its crude oil production using
price swap

                                      14
<PAGE>

agreements (41%) and costless collars (25%). The average price received under
the swap agreements was $26.21/Bbl. The costless collars included an average
ceiling of $32.21/Bbl and an average floor of $26.11/Bbl at the closing Index
Price.

   Hedging activities decreased Partnership oil and natural gas revenues by
approximately $17,000 and $109,000 in 1999 and 2000, respectively 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.

 Critical Accounting Policies

   Introduction. The forgoing describes the critical accounting policies used
by the Partnership in reporting its financial condition and results of
operations. In some cases, accounting standards allow more than one
alternative accounting method for reporting, such is the case with accounting
for oil and gas activities described below. In those cases, the Partnership's
reported results of operations would be different should it employ an
alternative accounting method.

   Successful Efforts Method of Accounting for Oil and Gas Activities. The
Securities and Exchange Commission ("SEC") prescribes in Regulation SX the
financial accounting and reporting standards for companies engaged in oil and
gas producing activities. Two methods are prescribed: the successful efforts
method and the full cost method. Like many other oil and gas companies, the
Partnership has chosen to follow the successful efforts method.

   Costs of successful wells, development dry holes and leases containing
productive reserves are capitalized and amortized on a unit of production
basis over the life of the related reserves. Estimated future abandonment and
site restoration costs, net of anticipated salvage values, are amortized on a
unit of production basis over the life of the related reserves. Other
exploration costs, including geological and geophysical expenses applicable to
undeveloped leasehold, leasehold expiration costs and delay rentals are
expensed as incurred.

   In accordance with accounting under successful efforts, the Partnership
reviews proved oil and gas properties for indications of impairment whenever
events or circumstances indicate that the carrying value of its oil and gas
properties may not be recoverable. The Partnership's oil and gas reserves are
mature, but still have a relatively long life. However, even a temporary drop
in prices can have a material impact on its business.

   Estimated Abandonment or Site Restoration. The estimated costs of future
abandonment and site restoration, net of anticipated salvage values, are
amortized on a unit-of-production basis over the life of the related reserves.
The amortization of these costs is included on the Partnership's Statements of
Income under depreciation, depletion and amortization expense.

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

   At of January 1, 2001, the Partnership was not party to any derivative
instruments and as such there was no impact on its financial statements as a
result of the adoption of SFAS 133. During and at year-end 2001, the
Partnership did not and was not participating in any derivative instruments.

                                      15
<PAGE>

 Results of Operations

   Years Ended December 31, 2001 and 2000. Oil and gas revenues were $817,000
for 2001 as compared to $800,000 in the corresponding period of 2000,
primarily as a result of higher natural gas prices partially offset by lower
oil and gas production. Production of natural gas decreased 14% from 149,000
Mcf in 2000 to 128,000 Mcf in 2001. Production of crude oil in the current
year totaled 8,598 barrels compared to 9,031 barrels last year, representing a
decrease of 5%. Oil and gas production decreased due normal declines in the
Partnership's producing areas.

   Lease operating expenses and severance taxes were $209,000 in 2001 versus
$256,000 in 2000, a decrease of 18%, primarily related lower production and
lower lifting costs per equivalent production unit. Lower lifting costs were
partially offset by an increase in severance tax expense on a per unit basis
resulting from a rate increase in Louisiana. On a unit of production basis,
these expenses decreased to $1.16 per Mcfe in 2001 from $1.26 per Mcfe in
2000.

   General and administrative ("G&A") expenses of $44,000 in 2001 decreased
29% from $62,000 in 2000. On a unit of production basis, these expenses
decreased from $0.31 per Mcfe in 2000 to $0.24 per Mcfe in 2001. As the
Partnership's production declines it receives a smaller allocation of G&A
costs from Contour Energy E&P.

   In 2000, the Partnership incurred interest expense of $6,000 on a loan
advanced to it by Contour E&P in August 1994 to fund part of its drilling
expenses in excess of contributed capital. In 2000, the final payment of
$166,000 was made on the $6,000,000 Initial Loan.

   Depreciation, depletion and amortization ("DD&A") expense decreased 36%
from $120,000 in 2000 to $77,000 in 2001 due to lower production levels and
lower composite depletion rates. On a unit of production basis, DD&A expense
decreased 27% from $0.59 per Mcfe in 2000 to $0.43 per Mcfe in 2001.

   The Partnership recognized net income in 2001 of $487,000 or $0.03 per Unit
compared to net income in 2000 of $356,000, or $0.02 per Unit. The reasons for
the variance between 2001 and 2000 are described in the foregoing discussion.

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

   Lease operating expenses and severance taxes were $256,000 in 2000 versus
$378,000 in 1999, a decrease of 32%, primarily related to the sale of
properties to Phillips. On a unit of production basis, these expenses
increased to $1.26 per Mcfe in 2000 from $1.02 per Mcfe in 1999.
Transportation and compression expenses of $48,000 ($0.13 per Mcfe) and $7,000
($0.03 per Mcfe) were included in lease operating expense for 1999 and 2000,
respectively, as a result of accounting pronouncement EITF 00-10 issued in
2000.

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

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

                                      16
<PAGE>

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

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

 Liquidity and Capital Resources

   Liquidity. Net cash provided by the Partnership's operating activities
during 2001, as reflected on its statement of cash flows, totaled $471,000.
During the period, funds used in investing activities totaled $18,000 in
capital expenditures and funds used in financing activities were for
partnership distributions of $453,000. As a result of these activities, the
Partnership's cash and cash equivalents remained at zero at December 31, 2001.

   During the first half of 2001, the Partnership benefited from an increase
in the level of commodity prices compared to historic levels. However, cash
prices and NYMEX based prices for both oil and natural gas have declined
significantly during the second half of 2001 and early 2002, reflecting the
volatility of commodity prices. Natural gas prices over the past six months
have averaged below $2.50/Mcf and crude prices have averaged below $20.00/bbl.
Sustained prices at these levels or lower could have a materially adverse
impact on the Partnership's results of operations and its ability to make
future distributions. Historically, Contour on behalf of the Partnership
periodically enters into hedge contracts to protect against commodity price
declines. However, effective 2001 the Partnership no longer participated in
hedging transactions due to its relatively small production volumes.

   Capital Resources. The partners' equity at December 31, 2001 increased to
$960,000 as compared to $926,000 at December 31, 2000. The Partnership has
completed its development stage. Accordingly, cash flow from operations should
be adequate to meet its expected capital and general working capital needs. As
of December 31, 2001, the Partnership was fully capitalized with contributions
aggregating $50,082,285.

   Although the capital needs of the Partnership are minimal and are funded by
cash flows from operations, the administration of the Partnership and its
assets are dependent on Contour E&P as Managing General Partner. The financial
difficulties of Contour could have a detrimental effect on its abilities to
administer the Partnership.

   Distribution Policy. The Partnership maintains a policy of distributing
cash, which is not required for the conduct of Partnership business to
Unitholders on a quarterly basis. During 2001, current year earnings
distributions were paid to the managing and special general partners and the
unitholders in the amounts of $18,000 and $435,000, or $0.03 per Unit,
respectively. However, future distributions to the unitholders and the
managing and special general partners are contingent on future operating
results.

   Related Party Transactions. The Unitholders have a 96.04% share and the
general partners a 3.96% share in the costs and revenues of the Partnership.
The Partnership reimburses Contour E&P for all direct costs incurred in
managing the Partnership and all indirect costs (principally general and
administrative expenses) allocable to the Partnership.

   Overhead allocated to the Partnership by Contour E&P for the years ended
December 31, 1999, 2000 and 2001 related to general and administrative
expenses aggregated $92,000, $62,000 and $44,000, respectively.

   Substantially all of the Partnership's gas sales are made to an affiliated
company, Concorde Gas Marketing, Inc.("CGM"), an indirect wholly-owned
subsidiary of Contour E&P, which remarkets gas to third parties. For 1999,
2000 and 2001, a fee of 2% of the resale price was charged to the Partnership
by CGM for its marketing services.

   In December 2000, Contour E&P invited the unit holders for the Partnership
to tender their units for cash. The cash offer was $0.123 per unit for all of
the Partnership units not held by Contour E&P. A total of 1,298,724

                                      17
<PAGE>

Partnership units (50% of units eligible for tender) were tendered. The total
cost was approximately $200,000, including transaction costs. After the
tender, Contour E&P owned 91.82% of the Units and a 3.94% General Partner
interest.

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

<TABLE>
<CAPTION>
                                                                 Average Average
                                                                   Oil     Gas
                                                                  Price   Price
                                                                 ($/Bbl) ($/Mcf)
                                                                 ------- -------
<S>                                                              <C>     <C>
Year Ended:
  December 31, 1999.............................................  15.78   2.26
  December 31, 2000.............................................  29.70   3.59
  December 31, 2001.............................................  25.25   4.70
</TABLE>

   Accounting Pronouncements. The Partnership adopted Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and
Hedging Activities" ("SFAS 133") effective January 1, 2001. The Partnership
was not party to any derivative instruments during 2001 and as such there was
not impact from the adoption of SFAS 133.

   In July 2001, the Financial Accounting Standards Board ("FASB") issued two
new pronouncements: Statement of Financial Accounting Standards ("SFAS") No.
141, "Business Combinations", and SFAS No. 142, "Goodwill and Other Intangible
Assets". SFAS 141 prohibits the use of the pooling-of-interest method for
business combinations initiated after June 30, 2001 and also applies to all
business combinations accounted for by the purchase method that are completed
after June 30, 2001. SFAS 142, effective for fiscal years beginning after
December 15, 2001, addresses financial accounting and reporting for acquired
goodwill and other intangible assets and supersedes APB Opinion No. 17,
Intangible Assets. It addresses how intangible assets that are acquired
individually or with a group of other assets (but not those acquired in a
business combination) should be accounted for in financial statements upon
their acquisition. This Statement also addresses how goodwill and other
intangible assets should be accounted for after they have been initially
recognized in the financial statements. The Partnership expects no impact on
its financial statements from the adoption of these standards.

   In August and October 2001, the FASB issued SFAS No. 143, "Accounting for
Asset Retirement Obligations" and SFAS No. 144, "Accounting for Impairment or
Disposal of Long-Lived Assets". SFAS 143 requires entities to record the fair
value of a liability for an asset retirement obligation in the period in which
it is incurred and a corresponding increase in the carrying amount of the
related long-lived asset. Subsequently, the asset retirement costs should be
allocated to expense using a systematic and rational method. SFAS 143 is
effective for fiscal years beginning after June 15, 2002. SFAS 144 addresses
financial accounting and reporting for the impairment of long-lived assets and
for long-lived assets to be disposed of. It supersedes, with exceptions, SFAS
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed of", and is effective for fiscal years beginning after
December 15, 2001. The Partnership is currently assessing the impact of SFAS
No. 143 and cannot yet reasonably estimate the impact, if any, this statements
will have on its financial statements upon adoption. The Partnership expects
no impact on its financial statements from the adoption of SFAS 144.

Item 7A. Quantitative and Qualitative Disclosure About Market Risk

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

                                      18
<PAGE>

Item 8. Financial Statements and Supplementary Data

                         Index to Financial Statements

<TABLE>
<CAPTION>
                                                                           Page
Kelley Partners 1992 Development Drilling Program:                         ----

<S>                                                                        <C>
Independent Auditors' Report..............................................  20
Balance Sheets--December 31, 2000 and 2001................................  21
Statements of Income--For the years ended December 31, 1999, 2000 and
 2001.....................................................................  22
Statements of Cash Flows--For the years ended December 31, 1999, 2000 and
 2001.....................................................................  23
Statements of Changes in Partners' Equity (Deficit)--For the years ended
 December 31, 1999,
 2000 and 2001............................................................  24
Notes to Financial Statements.............................................  25
</TABLE>

                                       19
<PAGE>

                         INDEPENDENT AUDITORS' REPORT

To the Partners of Kelley Partners 1992 Development Drilling Program:

We have audited the accompanying balance sheets of Kelley Partners 1992
Development Drilling Program (a Texas limited partnership) as of December 31,
2000 and 2001, and the related statements of income, cash flows, and changes
in partners' equity (deficit) for each of the three years in the period ended
December 31, 2001. These financial statements are the responsibility of the
Partnership's management. Our responsibility is to express an opinion on these
financial statements based on our audits.

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

In our opinion, such financial statements present fairly, in all material
respects, the financial position of Kelley Partners 1992 Development Drilling
Program as of December 31, 2000 and 2001, and the results of its operations
and its cash flows for each of the three years in the period ended December
31, 2001, in conformity with accounting principles generally accepted in the
United States of America.

   The accompanying financial statements for the year ended December 31, 2001
have been prepared assuming that the Partnership will continue as a going
concern. As discussed in Note 2 to the financial statements, the parent of the
Managing General Partner is attempting to negotiate a restructuring of its
long-term debt which could lead to a filing for bankruptcy protection under
federal bankruptcy regulations. This raises substantial doubt about the
Partnership's ability to continue as a going concern. The financial statements
do not include any adjustments that might result from the outcome of this
uncertainty.

DELOITTE & TOUCHE LLP

Houston, Texas
March 7, 2002
(April 15, 2002 as to Note 2)

                                      20
<PAGE>

               KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM

                                 BALANCE SHEETS
                                 (In thousands)

<TABLE>
<CAPTION>
                               December 31,
                             ------------------
                               2000      2001
                             --------  --------
<S>                          <C>       <C>
Assets:
  Cash and cash
   equivalents.............. $     --    $   --
  Accounts receivable--
   trade....................       37        12
  Accounts receivable--
   affiliates...............       47       127
                             --------  --------
    Total current assets....       84       139
                             --------  --------
Oil and gas properties,
 successful efforts method:
  Properties subject to
   amortization.............   41,443    41,461
  Less: Accumulated
   depreciation, depletion &
   amortization.............  (40,516)  (40,593)
                             --------  --------
  Total oil and gas
   properties...............      927       868
                             --------  --------
    Total assets............ $  1,011  $  1,007
                             ========  ========
Liabilities:
  Accounts payable and
   accrued expenses......... $     85  $     47
                             --------  --------
    Total current
     liabilities............       85        47
                             --------  --------
    Total liabilities.......       85        47
                             --------  --------
Partners' Equity:
  LP Unitholders' equity....       67        70
  GP Unitholders' equity....      822       851
  Managing and Special
   General Partners'
   equity...................       37        39
                             --------  --------
    Total partners' equity..      926       960
                             --------  --------
  Total liabilities and
   partners' equity......... $  1,011  $  1,007
                             ========  ========
</TABLE>


                       See Notes to Financial Statements.

                                       21
<PAGE>

               KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM

                              STATEMENTS OF INCOME
                      (In thousands, except per unit data)

<TABLE>
<CAPTION>
                                                       Year Ended December 31,
                                                       -----------------------
                                                        1999    2000    2001
                                                       ------- ------- -------
<S>                                                    <C>     <C>     <C>
Revenues:
  Oil and gas sales................................... $   843 $   800 $   817
  Gain on sale of properties..........................     850      --      --
                                                       ------- ------- -------
  Total revenues......................................   1,693     800     817
                                                       ------- ------- -------
Costs And Expenses:
  Lease operating expenses............................     333     224     178
  Severance taxes.....................................      45      32      31
  General and administrative expenses.................      92      62      44
  Interest expense....................................     174       6      --
  Depreciation, depletion and amortization............     225     120      77
                                                       ------- ------- -------
    Total expenses....................................     869     444     330
                                                       ------- ------- -------
Net income............................................ $   824 $   356 $   487
                                                       ======= ======= =======
Net income allocable to LP and GP unitholders......... $   791 $   342 $   468
                                                       ======= ======= =======
Net income allocable to managing and special general
 partners............................................. $    33 $    14 $    19
                                                       ======= ======= =======
Net income per LP and GP Unit......................... $   .05 $   .02 $   .03
                                                       ======= ======= =======
Average LP and GP Units outstanding...................  16,033  16,033  16,033
                                                       ======= ======= =======
</TABLE>


                       See Notes to Financial Statements.

                                       22
<PAGE>

               KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM

                            STATEMENTS OF CASH FLOWS
                                 (In thousands)

<TABLE>
<CAPTION>
                                                             Year Ended
                                                            December 31,
                                                         ---------------------
                                                          1999    2000   2001
                                                         -------  -----  -----
<S>                                                      <C>      <C>    <C>
Operating Activities:
 Net income............................................. $   824  $ 356  $ 487
 Adjustments to reconcile net income to net cash
  provided by operating activities:
  Gain on sale of properties............................    (850)    --     --
  Depreciation, depletion and amortization..............     225    120     77
  Changes in operating assets and liabilities:
   Decrease (increase) in accounts receivable...........      75    (39)   (55)
   (Decrease) increase in accounts payable and accrued
    expenses............................................     (36)    23    (38)
                                                         -------  -----  -----
 Net cash provided by operating activities..............     238    460    471
                                                         -------  -----  -----
Investing Activities:
 Capital expenditures...................................     (14)    23    (18)
 Proceeds from sale of assets...........................   2,098     --     --
                                                         -------  -----  -----
 Net cash provided by (used in) investing activities....   2,084     23    (18)
                                                         -------  -----  -----
Financing Activities:
 Distributions..........................................      --   (317)  (453)
 Payments on long-term borrowings.......................  (2,322)  (166)    --
                                                         -------  -----  -----
 Net cash used in financing activities..................  (2,322)  (483)  (453)
                                                         -------  -----  -----
Increase (decrease) in cash and cash equivalents........      --     --     --
Cash and cash equivalents, beginning of period..........      --     --     --
                                                         -------  -----  -----
Cash and cash equivalents, end of period................ $    --  $  --  $  --
                                                         =======  =====  =====
</TABLE>


                       See Notes to Financial Statements.

                                       23
<PAGE>

               KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM

              STATEMENTS OF CHANGES IN PARTNERS' EQUITY (DEFICIT)
                                 (In thousands)

<TABLE>
<CAPTION>
                                                                 Managing
                                                                   and
                                                                 Special
                                             LP          GP      General
                                         Unitholders Unitholders Partners Total
                                         ----------- ----------- -------- -----
<S>                                      <C>         <C>         <C>      <C>
Partners'equity at January 1, 1999......    $(20)       $ 80       $ 3    $ 63
                                            ----        ----       ---    ----
Net income..............................      82         709        33     824
                                            ----        ----       ---    ----
 Partners' equity at December 31, 1999..      62         789        36     887
                                            ----        ----       ---    ----
Distributions...........................     (31)       (273)      (13)   (317)
Net income..............................      36         306        14     356
                                            ----        ----       ---    ----
 Partners' equity at December 31, 2000..      67         822        37     926
                                            ----        ----       ---    ----
Distributions...........................     (45)       (391)      (17)   (453)
Net income..............................      48         420        19     487
                                            ----        ----       ---    ----
 Partners' equity at December 31, 2001..    $ 70        $851       $39    $960
                                            ====        ====       ===    ====
</TABLE>




                       See Notes to Financial Statements.

                                       24
<PAGE>

               KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM

                         NOTES TO FINANCIAL STATEMENTS

NOTE 1--ORGANIZATION AND MANAGEMENT

   In 1992, the Partnership issued a total of 16,033,009 units of limited and
general partner interests ("Units"). The Units represent 96.04% of the total
interests in the Partnership and consist of 1,647,500 Units of limited partner
interests ("LP Units") and 14,385,509 Units of general partner interests ("GP
Units") at December 31, 2001. In addition, the Partnership issued managing and
special general partner interests on a pro rata basis representing 3.96% of
the total interests in the Partnership. In the aggregate, Contour Energy E&P,
LLC (formerly Kelley Oil Corporation), a Delaware corporation, the Managing
General Partner of the Partnership ("Contour E&P"), owns 91.86% of the Units
and a 3.94% general partner interest at December 31, 2001. Contour E&P is a
subsidiary of Contour Energy Co., collectively with its subsidiaries
("Contour").

   In December 2000, Contour E&P invited the unit holders for the Partnership
to tender their units for cash. The cash offer was $0.123 per unit for all of
the Partnership units not held by Contour E&P. A total of 1,298,724
Partnership units (50% of units eligible for tender) were tendered. The total
cost was approximately $200,000, including transaction costs.

   In 2001, Kelley Oil Corporation, the Managing General Partner of the
Partnership converted to a Delaware limited liability company and changed its
name to Contour Energy E&P, LLC.

NOTE 2--GENERAL PARTNER

   Contour's 14% senior secured notes totaling $105 million becomes due by
April 15, 2003. Contour E&P is a guarantor under these notes. Redemption of
these notes begins in 2002 with $2.1 million principal payments due in July
and October. An additional redemption payment of $2.1 million is due in
January 2003 with a final payment of $98.7 million due on April 15, 2003. It
is not anticipated that Contour will generate sufficient cash flows from
operations to repay this debt. Neither can it assume that future borrowings
will be available in an amount sufficient to pay or refinance this obligation
on commercially reasonable terms or at all. Failure to repay or refinance the
debt as it matures would result in a default under the indenture.

   Contour has entered into discussions with certain of its debt holders that
may lead to a restructuring transaction. The outcome of the negotiations and
the possible impact on the Partnership are uncertain. However, if negotiations
are not successful, Contour may be forced to seek protection under federal
bankruptcy regulations. Contour E&P is a guarantor under the 14% senior
secured notes. A potential default under these notes or a bankruptcy filing by
Contour could have a material adverse impact on the Partnership.

NOTE 3--SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

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


                                      25
<PAGE>

               KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM

                  NOTES TO FINANCIAL STATEMENTS--(Continued)


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

   The Partnership's proved oil and gas properties are reviewed for
indications of impairment whenever events or circumstances indicate that the
carrying value of its oil and gas properties may not be recoverable. Under
this analysis, the fair value for the Partnership's proved oil and gas
properties was estimated using escalated pricing and present value discount
factors reflecting risk assessments. Based on this analysis, the Partnership
recognized no charges to impairment during 1999, 2000, and 2001.

   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 Per Unit. Net income per Unit is computed based on the weighted
average number of Units outstanding during the period divided into the net
income allocable to the Unitholders. Net income allocable to the Unitholders
represents 96.04% of the Partnership's net income.

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

   Derivative Financial Instruments. From time to time, the Partnership has
entered into transactions in derivative financial instruments covering future
oil and natural gas production principally as a hedge against natural gas
price declines. See Note 6--"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 Concorde Gas Marketing, Inc.,
the marketing subsidiary of Contour Energy E&P, LLC, which purchases
approximately 80% of the Partnership's natural gas for resale to a limited
number of natural gas transmission companies and other gas purchasers. To
date, this concentration has not had a material adverse effect on the
financial condition of the Partnership.

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

   Reclassifications. Certain financial statement items in 1999 and 2000 have
been reclassified to conform to the 2001 presentation.

                                      26
<PAGE>

               KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM

                  NOTES TO FINANCIAL STATEMENTS--(Continued)


NOTE 4--CASH DISTRIBUTIONS

   The Partnership maintains a policy of distributing cash that is not
required for the conduct of Partnership business to Unitholders on a quarterly
basis. During 2001, current year earnings distributions were paid to the
managing and special general partners and the unitholders in the amounts of
$18,000 and $435,000, or $0.03 per Unit, respectively. However, future
distributions to the unitholders and the managing and special general partners
are contingent on future operating results.

NOTE 5--RELATED PARTY TRANSACTIONS

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

   Overhead allocated to the Partnership by Contour E&P for the years ended
December 31, 1999, 2000 and 2001 related to general and administrative
expenses aggregated $92,000, $62,000 and $44,000, respectively.

   Substantially all of the Partnership's gas sales are made to an affiliated
company, Concorde Gas Marketing, Inc.("CGM"), an indirect wholly-owned
subsidiary of Contour E&P, which remarkets gas to third parties. For 1999,
2000 and 2001, a fee of 2% of the resale price was charged to the Partnership
by CGM for its marketing services.

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

NOTE 6--HEDGING ACTIVITIES

   Historically, Contour periodically entered into hedge contracts to protect
against commodity price declines on behalf of the Partnership. Because of
small production volumes, beginning 2001, the Partnership production no longer
was hedged.

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

   Through natural gas price swap agreements, the Partnership hedged
approximately 50% of its natural gas production for 1999 at average NYMEX
quoted prices of $2.17/Mmbtu, before transaction and transportation costs. For
2000, the Partnership hedged approximately 72% of its natural gas production
using price swap

                                      27
<PAGE>

               KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM

                  NOTES TO FINANCIAL STATEMENTS--(Continued)

agreements (48%) and a costless collar (24%). The average price received under
the swap agreements was $2.59/Mmbtu. The costless collar included a ceiling of
$4.98/Mmbtu and a floor of $4.00/mmbtu at the closing Index Price. As of
December 31, 2001, none of the Partnership's anticipated natural gas
production for 2002 has been hedged.

   Through crude oil price swap agreements, the Partnership hedged
approximately 29% of its crude oil production for 1999 at an average NYMEX
quoted price of $20.00/Bbl, before transaction and transportation costs. For
2000, the Company hedged approximately 66% of its crude oil production using
price swap agreements (41%) and costless collars (25%). The average price
received under the swap agreements was $26.21/Bbl. The costless collars
included an average ceiling of $32.21/Bbl and an average floor of $26.11/Bbl
at the closing Index Price. As of December 31, 2001, none of the Partnership's
crude oil production for 2002 had been hedged.

   Hedging activities decreased Partnership oil and natural gas revenues by
approximately $17,000 and $109,000 in 1999 and 2000, respectively, 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.

   The Partnership adopted Statement of Financial Accounting Standards No.
133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS
133") effective January 1, 2001. The Partnership was not party to any
derivative instruments during 2001 and as such there was no impact from the
adoption of SFAS 133.

NOTE 7--NEW ACCOUNTING PRONOUNCEMENTS

   In July 2001, the Financial Accounting Standards Board ("FASB") issued two
new pronouncements: Statement of Financial Accounting Standards ("SFAS") No.
141, "Business Combinations", and SFAS No. 142, "Goodwill and Other Intangible
Assets". SFAS 141 prohibits the use of the pooling-of-interest method for
business combinations initiated after June 30, 2001 and also applies to all
business combinations accounted for by the purchase method that are completed
after June 30, 2001. SFAS 142, effective for fiscal years beginning after
December 15, 2001, addresses financial accounting and reporting for acquired
goodwill and other intangible assets and supersedes APB Opinion No. 17,
Intangible Assets. It addresses how intangible assets that are acquired
individually or with a group of other assets (but not those acquired in a
business combination) should be accounted for in financial statements upon
their acquisition. This Statement also addresses how goodwill and other
intangible assets should be accounted for after they have been initially
recognized in the financial statements. The Partnership expects no impact on
its financial statements from the adoption of these standards.

   In August and October 2001, the FASB issued SFAS No. 143, "Accounting for
Asset Retirement Obligations" and SFAS No. 144, "Accounting for Impairment or
Disposal of Long-Lived Assets". SFAS 143 requires entities to record the fair
value of a liability for an asset retirement obligation in the period in which
it is incurred and a corresponding increase in the carrying amount of the
related long-lived asset. Subsequently, the asset retirement costs should be
allocated to expense using a systematic and rational method. SFAS 143 is
effective for fiscal years beginning after June 15, 2002. SFAS 144 addresses
financial accounting and reporting for the impairment of long-lived assets and
for long-lived assets to be disposed of. It supersedes, with exceptions, SFAS
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed of", and is effective for fiscal years beginning after
December 15, 2001. The Partnership is currently assessing the impact of SFAS
No. 143 and cannot yet reasonably estimate the impact, if any, this statement
will have on its financial statements upon adoption. The Partnership expects
no impact to its financial statements upon the adoption of SFAS 144.

                                      28
<PAGE>

               KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM

                  NOTES TO FINANCIAL STATEMENTS--(Continued)


NOTE 8--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.

<TABLE>
<CAPTION>
                                                  Year Ended December 31,
                                                 ----------------------------
                                                   1999      2000      2001
                                                 --------  --------  --------
                                                       (in thousands)
<S>                                              <C>       <C>       <C>
Properties subject to amortization.............. $ 41,466  $ 41,443  $ 41,461
Accumulated depreciation, depletion and
 amortization...................................  (40,396)  (40,516)  (40,593)
                                                 --------  --------  --------
Net capitalized costs........................... $  1,070  $    927  $    868
                                                 ========  ========  ========
</TABLE>

   Costs Incurred. All costs were incurred in oil and gas property development
activities (as defined in the Partnership Agreement) and aggregated $14,000,
$(23,000) and $18,000 in 1999, 2000 and 2001, 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, 1999, 2000 and 2001.

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

<TABLE>
<CAPTION>
                            Crude Oil, Condensate
                           and Natural Gas Liquids
                                   (Mbbls)                Natural Gas (Mmcf)
                           ---------------------------   ---------------------
                            1999      2000      2001      1999    2000   2001
                           -------   -------   -------   -------  -----  -----
<S>                        <C>       <C>       <C>       <C>      <C>    <C>
Proved developed and
 undeveloped reserves:
 Beginning of year.......       88        64        70     3,759  1,196  1,247
 Revisions of previous
  estimates..............       (9)       15        (4)     (187)   200   (321)
Extensions and
 discoveries                    --        --        --        --     --     --
 Sale of oil and gas
  properties.............       (6)       --        --    (2,062)    --     --
 Production..............       (9)       (9)       (9)     (314)  (149)  (128)
                           -------   -------   -------   -------  -----  -----
  End of year............       64        70        57     1,196  1,247    798
                           =======   =======   =======   =======  =====  =====
Proved developed reserves
 at end of year..........       64        70        57     1,196  1,247    798
                           =======   =======   =======   =======  =====  =====
</TABLE>

                                      29
<PAGE>

               KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM

                  NOTES TO FINANCIAL STATEMENTS--(Continued)


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

<TABLE>
<CAPTION>
                                                      As of December 31,
                                                    -------------------------
                                                     1999     2000     2001
                                                    -------  -------  -------
                                                        (In thousands)
<S>                                                 <C>      <C>      <C>
Future cash inflows................................ $ 4,269  $14,394  $ 3,232
Future production costs............................  (1,581)  (3,179)  (1,257)
Future development costs...........................     (55)     (52)     (52)
                                                    -------  -------  -------
Future net cash flows..............................   2,633   11,163    1,923
10% annual discount for estimating timing of cash
 flows.............................................    (933)  (4,883)    (731)
                                                    -------  -------  -------
Standardized measure of discounted future net cash
 flows............................................. $ 1,700  $ 6,280  $ 1,192
                                                    =======  =======  =======
</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 Contour E&P's petroleum engineers by
estimating the expenditures to be incurred in developing and producing the
Partnership's proved oil and gas reserves at the end of the year, based on
year-end costs and assuming continuation of existing economic conditions.

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

   The standardized measure of discounted future net cash flows as of December
31, 1999, 2000 and 2001 was calculated using prices in effect as of those
dates, which averaged $25.46, $26.45 and $20.79, respectively, per barrel of
oil and $2.15, $10.05 and $2.57, respectively, per Mcf of natural gas.

                                      30
<PAGE>

               KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM

                   NOTES TO FINANCIAL STATEMENTS--(Continued)


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


<TABLE>
<CAPTION>
                                                       Year Ended December
                                                               31,
                                                      ------------------------
                                                       1999     2000    2001
                                                      -------  ------  -------
                                                          (In thousands)
<S>                                                   <C>      <C>     <C>
Changes due to current year operations:
 Sales of oil and gas, net of production costs....... $  (465) $ (544) $  (608)
 Sales of reserves in place..........................  (1,668)     --       --
 Extensions and discoveries, net of future production
  costs..............................................      --      --       --
 Development costs incurred during the year..........      --      --       --
Changes due to revisions in standardized variables:
 Prices and production costs.........................     557   4,003   (5,039)
 Revisions of previous quantity estimates............     152   1,096     (377)
 Estimated future development costs..................     (97)     20       (6)
 Accretion of discount...............................     317     170      628
 Production rates (timing) and other.................    (268)   (165)     314
                                                      -------  ------  -------
  Net (decrease) increase............................  (1,472)  4,580   (5,088)
Beginning of year....................................   3,172   1,700    6,280
                                                      -------  ------  -------
End of year.......................................... $ 1,700  $6,280  $ 1,192
                                                      =======  ======  =======
</TABLE>

Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosures

   None.


                                       31
<PAGE>

                                   PART III

Item 10. Managers of Contour Energy E&P, LLC

 General

   The Partnership has no directors, officers or employees. Managers of
Contour E&P perform all management functions for the Partnership. Contour E&P
had 47 employees as of December 31, 2001, and its staff includes employees
experienced in geology, geophysics, petroleum engineering, land acquisition
and management, finance, accounting, and administration.

 Background of Contour Energy E&P, LLC

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

 Managers of Contour Energy E&P, LLC.

   Set forth below are the names, ages and positions of the managers of
Contour E&P. [All managers hold office until their successors are duly
appointed and qualified.]

<TABLE>
<CAPTION>
                                                                      Officer,
                                                                     Director or
                                                                     Manager of
                                                                     the Company
      Name                                              Age Position    Since
      ----                                              --- -------- -----------
      <S>                                               <C> <C>      <C>
      Rick G. Lester...................................  50 Manager     1998
      Kenneth R. Sanders...............................  52 Manager     1999
</TABLE>

   Rick G. Lester was appointed a manager of Contour Energy E&P, LLC upon it
formation in 2001. Prior to that he served Executive Vice President and Chief
Financial Officer and a director of Kelley Oil Corporation, the predecessor
Company to Contour Energy E&P, LLC. Previously, he was Vice President and
Chief Financial Officer of Domain Energy Corporation.

   Kenneth R. Sanders was appointed a manager of Contour Energy E&P, LLC upon
it formation in 2001. Prior to that he served as President, CEO and director
of Kelley Oil Corporation, the predecessor Company to Contour Energy E&P, LLC.
Previously, he was Vice-President--Exploitation, Acquisitions & Engineering of
Seagull Energy E&P, Inc.

 Beneficial Ownership Reporting

   Not applicable.

Item 11. Executive Compensation

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

                                      32
<PAGE>

Item 12. Security Ownership of Certain Beneficial Owners and Management

 Beneficial Owners

   The following table sets forth information as of December 31, 2001 with
respect to the only Unitholder known by the Partnership to own beneficially
more than five percent of the Partnership's Units.

<TABLE>
<CAPTION>
                                                        Amount & Nature
                                                         of Beneficial  Percent
      Name and Address of Beneficial Owner                 Ownership    of Class
      ------------------------------------              --------------- --------
      <S>                                               <C>             <C>
      Contour Energy E&P, LLC..........................   14,727,337     91.86%
      1001 McKinney, Suite 900                                Direct
      Houston, Texas 77002
</TABLE>

 Management

   The following table sets forth information as of December 31, 2001 with
respect to Units beneficially owned, directly or indirectly, by each of the
managers of Contour E&P and by all managers of Contour E&P as a group.

<TABLE>
<CAPTION>
                                                        Amount & Nature
                                                         of Beneficial  Percent
      Name and Address of Beneficial Owner               Ownership(1)   of Class
      ------------------------------------              --------------- --------
      <S>                                               <C>             <C>
      Kenneth R. Sanders...............................        --           --
      Rick G. Lester...................................        --           --
      All mangers as a group (2 persons)...............      None         None
</TABLE>
--------
(1)Represents direct beneficial ownership.

Item 13. Certain Relationships and Related Transactions

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

   Contour E&P is reimbursed for its direct costs and an allocable portion of
its general and administrative expenses incurred as Managing General Partner.
See Note 5 in the Notes to Financial Statements.

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

                                      33
<PAGE>

                                    PART IV

Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K

 (a)Financial Statements and Schedules:

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

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

   (3) Exhibits:

<TABLE>
<CAPTION>
 Exhibit
 Number  Exhibit
 ------- -------
 <C>     <S>
 4.1     Amended and Restated Agreement of Limited Partnership of the
         Registrant (included as Exhibit A to the Prospectus forming part of
         the Registrant's Registration Statement on Form S-1 (File No. 33-
         51250) filed on August 26, 1992, as amended (the "Registration
         Statement") and incorporated herein by reference).
 4.2     Joint Venture Agreement of Kelley Partners 1992 Development Drilling
         Joint Venture (incorporated by reference to Exhibit B to the
         Prospectus forming part of the Registration Statement).
 4.3     Amendment to Amended and Restated Agreement of Limited Partnership of
         the Registrant (incorporated by reference to Exhibit 4.3 to the
         Registrant's Annual Report on Form 10-K (File
         No. 0-20998) for the year ended December 31, 2000).
</TABLE>

 (b)Reports on Form 8-K:

   No reports on Form 8-K were filed by the Registrant during the fourth
quarter of 2001.

                                      34
<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 16th day of
April 2002.

               KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM

             By: CONTOUR ENERGY E&P, LLC, Managing General Partner

       /s/ Kenneth R. Sanders                      /s/ Rick G. Lester
   By:_________________________           By: _________________________________
         Kenneth R. Sanders                            Rick G. Lester
                                                          Manager

                Manager
   Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed as of the 16th day of April 2002 by the following
persons in their capacity as managers of the Registrant's managing general
partner.

    /s/ Kenneth R. Sanders                        /s/ Rick G. Lester
  __________________________                   ________________________
       Kenneth R. Sanders                            Rick G. Lester

                                      35