KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM, 10-K, 2000-04-03

KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
10-K, 2000-04-03
DRILLING OIL & GAS WELLS

Previous: LASER TECHNOLOGY INC, DEF 14A, 2000-04-03

Next: CONCEPTS DIRECT INC, DEF 14A, 2000-04-03

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

<TABLE>
<S> <C>
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549

FORM 10-K

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

FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999 COMMISSION FILE NO. 0-20998

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

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

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

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

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

None
(TITLE OF CLASS)

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

Units of Limited and General Partner Interests
(TITLE OF CLASS)
</TABLE>

Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
--- ---

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K under the Securities Exchange Act of 1934 is not contained
herein, and will not be contained, to the best of the Registrant's knowledge, in
definitive proxy or information statements incorporated in Part III of this Form
10-K or any amendments to this Form 10-K. [ ]

As of March 24, 2000, Kelley Partners 1992 Development Drilling Program had
16,033,009 units of limited and general partner interests (the "Units")
outstanding. The Units are not publicly traded.

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

<PAGE> 2

PART I

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

INTRODUCTION

General. Kelley Partners 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. Kelley Oil Corporation, the managing general
partner of the Partnership (the "Managing General Partner" or "Kelley Oil"),
owns 83.72% of the Units and a 3.94% General Partner interest. Kelley Oil is a
subsidiary of Contour Energy Co. (formerly Kelley Oil & Gas Corporation),
collectively with its subsidiaries ("Contour").

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

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

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

As part of the Phillips Transaction described above, the Partnership
conveyed its interest in the West Bryceland and Sailes fields to Phillips for
$2.1 million. The Partnership's reserve quantities attributable to such fields
represented approximately one-half of the Partnership's total reserve quantities
at January 1, 1999 and one-half of its total 1998 production. In the third
quarter of 1999, the sales proceeds were applied to reduce the Partnership's
loan to Kelley Oil.

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

On May 17, 1999, Contour funded $28.5 million to repurchase $46.1
million of the outstanding principal amounts of its 7 7/8% Convertible
Subordinated Notes due December 15, 1999 and its 8 1/2% Convertible Subordinated
Debentures due April 1, 2000 (collectively, the "Securities") at a price equal
to $590 per $1,000 principal amount (not including accrued interest paid of $1.2
million).

<PAGE> 3

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

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

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

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

Development and Production. From inception through the completion of
drilling activities in 1994, the Partnership participated in drilling 39 gross
wells, of which 30 gross (11.07 net) wells were productive and 9 gross (4.16
net) wells were dry. Subsequently, two producing Partnership wells were plugged
when production declined to noncommercial levels. From its inception through
1999, the Partnership produced 10.5 Bcf of natural gas and 203,482 barrels of
oil and natural gas liquids, generating total oil and gas revenues of
$24,621,000, of which $4,506,000 or $0.27 per Unit has been distributed to the
partners. To enable the Partnership to fund part of its drilling and
recompletion expenses in excess of contributed capital, quarterly distributions
were suspended in October 1994, reinstated for only one quarter in 1995, and
suspended again thereafter. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations."

MANAGEMENT, OPERATIONS AND PROPERTIES

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

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

<PAGE> 4

ESTIMATED PROVED RESERVES

General. The estimated gross quantities of proved and proved developed
reserves for properties in which the Partnership owns interests were prepared as
of January 1, 1998, 1999 and 2000, by an independent petroleum engineering firm.
For the reserves at January 1, 2000, Contour applied appropriate Partnership
revenue interests to determine the Partnership's net proved reserves shown
below.

Quantities. The following table sets forth the Partnership's estimated
quantities of proved and proved developed reserves of crude oil (including
condensate and natural gas liquids) and natural gas as of January 1, 1998, 1999
and 2000. Proved developed reserves are reserves that can be expected to be
recovered from existing wells with existing equipment and operating methods.
Proved undeveloped reserves are proved reserves that are expected to be
recovered from new wells drilled to known reservoirs on undrilled acreage for
which the existence and recoverability of reserves can be estimated with
reasonable certainty, or from existing wells where a relatively major
expenditure is required for recompletion.

ESTIMATED PROVED RESERVES

<TABLE>
<CAPTION>
AS OF JANUARY 1,
-----------------------------------
1998 1999 2000
-------- -------- ---------
<S> <C> <C> <C>
Crude oil and liquids (Mbbl):
Proved developed............................................................. 78 88 64
Proved undeveloped........................................................... - - -
-------- -------- ---------
Total proved............................................................... 78 88 64
======== ======== =========

Natural gas (Mmcf):
Proved developed............................................................. 5,521 3,759 1,196
Proved undeveloped........................................................... - - -
-------- -------- ---------
Total proved............................................................... 5,521 3,759 1,196
======== ======== =========
</TABLE>

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

Uncertainties in Estimating Reserves. 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 or that the proved undeveloped reserves set forth herein
will be developed within the periods anticipated. In addition, the estimates of
future net revenues from proved reserves of Kelley 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> 5

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, 2000 with respect to the Partnership's interests in its most
significant fields, together with information for all other fields combined.

SIGNIFICANT PROVED PROPERTIES
(IN THOUSANDS)

<TABLE>
<CAPTION>
PROVED RESERVES AT JANUARY 1, 2000 1999 PRODUCTION
------------------------------------- -------------------------------------
GAS GAS
OIL GAS EQUIVALENT OIL GAS EQUIVALENT
PROPERTY (MBBLS) (MMCF) (MMCFE) % (MBBLS) (MMCF) (MMCFE) %
- -------- ------- ------- ------- ------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
NORTH LOUISIANA:
Ada field ........................ -- 186 186 11.8 -- 34 34 9.2
Sailes field ..................... -- -- -- -- -- 133 133 36.0
Sibley field ..................... 10 439 499 31.6 -- 38 38 10.4
West Bryceland field ............. -- -- -- -- -- -- -- --
SOUTH LOUISIANA:
Orange Grove/Humphreys field ..... -- -- -- -- 2 21 33 9.0
Ouiski Bayou field ............... 54 553 877 55.5 6 71 107 29.2
OTHER:
As a group ....................... -- 18 18 1.1 1 17 23 6.2
------- ------- ------- ------- ------- ------- ------- -------
Total .......................... 64 1,196 1,580 100.0 9 314 368 100.0
======= ======= ======= ======= ======= ======= ======= =======
</TABLE>

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

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

NORTH LOUISIANA

Ada Field. The Ada field is located in Bienville and Webster Parishes,
Louisiana. The Partnership has an interest in 1 gross (.16 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.

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

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

4
<PAGE> 6

SOUTH LOUISIANA

Orange Grove/Humphreys Field. The Orange Grove/Humphreys field is
located in Terrebonne Parish, Louisiana. The Partnership has interests in 2
gross (0.66 net) wells producing from the 1st Hollywood, Tex W, Upper Krumbhaar
and Bourg formations at depths ranging from 10,300 to 12,500 feet. Kelley Oil
operates all of the wells. 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. Kelley Oil
operates the well. 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 (including transfers) and average production costs (lifting cost
plus ad valorem and severance taxes) per equivalent unit of oil and gas produced
by the Partnership for the years ended December 31, 1997, 1998 and 1999.
Detailed additional information concerning the Partnership's oil and gas
producing activities is contained in the Supplementary Financial Information
included in Note 7 to the Partnership's Financial Statements.

OIL AND GAS PRODUCTION

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------
1997 1998 1999
--------- --------- --------
<S> <C> <C> <C>
Crude oil, condensate and natural gas liquids (Bbls)............................ 11,395 10,172 9,398
Natural gas (Mmcf).............................................................. 963 601 314
</TABLE>

AVERAGE SALES PRICES AND PRODUCTION COSTS

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------
1997 1998 1999
--------- --------- --------
<S> <C> <C> <C>
Average sales price:
Crude oil, condensate and natural gas liquids per Bbl........................$ 19.92 $ 13.56 $ 15.78
Natural gas per Mcf, including the effects of hedging........................ 2.18 2.10 2.11
Oil and gas revenues per Mcfe................................................... 2.25 2.11 2.15
Average production costs per Mcfe............................................... .56 .75 .89
</TABLE>

5
<PAGE> 7

OIL AND GAS WELLS

As of December 31, 1999, the Partnership owned interests in productive
oil and gas wells (including producing wells and wells capable of production) as
follows:

<TABLE>
<CAPTION>
GROSS(1) NET
--------- ---------
<S> <C> <C>
Oil wells............................................................................... - -
Gas wells............................................................................... 20 4.88
--------- ---------
Total.................................................................................. 20 4.88
========= =========
</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.

<TABLE>
<CAPTION>
GROSS GROSS NET NET
DEVELOPMENT WELLS EXPLORATORY WELLS DEVELOPMENT WELLS EXPLORATORY WELLS
------------------ ----------------- ------------------- ------------------
PRODUCTIVE DRY PRODUCTIVE DRY PRODUCTIVE DRY PRODUCTIVE DRY
---------- --- ---------- --- ---------- --- ---------- ---
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1997....................... - - - - - - - -
1998....................... - - - - - - - -
1999....................... - - - - - - - -
</TABLE>

MARKETING OF NATURAL GAS AND CRUDE OIL

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

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

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

HEDGING OF NATURAL GAS

6
<PAGE> 8

Partnership, including the interest in such production of the public unitholders
of the Partnership. During 1999, the Company used price and basis swap
agreements to hedge its exposure to possible declines in natural gas prices.
Additional information concerning Partnership hedging activities during 1999 is
set forth in "Management's Discussion and Analysis of Financial Condition and
Results of Operations" contained elsewhere in this Report.

COMPETITION

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

EMPLOYEES

The Partnership has no employees and utilizes the management and staff
of Kelley Oil. As of December 31, 1999, Kelley Oil had 47 employees. Kelley
Oil's staff includes employees experienced in geology, geophysics, petroleum
engineering, land acquisition and management, finance and accounting. See
"Directors and Executive Officers of Kelley Oil Corporation." None of Kelley
Oil's employees are represented by a union. Kelley Oil has never experienced an
interruption in its operations from any kind of labor dispute, and its working
relationship with its employees is satisfactory.

REGULATION

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

Transportation and Production

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

Regulation of Drilling and Production. Drilling and production
operations of the Partnership are subject to regulation under a wide range of
state and federal statutes, rules, orders and regulations. State and federal
statutes and regulations govern, among other matters, the amounts and types of
substances and materials that may be released into the environment, the
discharge and disposition of waste materials, the reclamation and abandonment of
wells and facility sites and remediation of contaminated sites, and require
permits for drilling operations, drilling bonds and reports concerning
operations. Most states in which the Partnership owns and operates properties
have regulations governing conservation matters, including provisions for the
unitization or pooling of oil and natural gas properties, the establishment of
maximum

7
<PAGE> 9

rates of production from oil and natural gas wells and the regulation of the
spacing, plugging and abandonment of wells. Many states also restrict production
to the market demand for oil and natural gas and several states have indicated
interest in revising applicable regulations. The effect of these regulations is
to limit the amount of oil and natural gas the Partnership can produce from its
wells and to limit the number of wells or the locations at which it can drill.
Moreover, each state generally imposes an ad valorem, production or severance
tax with respect to the production and sale of crude oil, natural gas and gas
liquids within its jurisdiction.

Environmental Regulations

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

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

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

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

8
<PAGE> 10

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

CERCLA, also known as "Superfund", imposes liability, without regard to
fault or the legality of the original act, on certain classes of persons that
contributed to the release of a "hazardous substance" into the environment.
These persons include the "owner" or "operator" of the site and companies that
disposed or arranged for the disposal of the hazardous substances found at the
site. CERCLA also authorizes the EPA and, in some instances, third parties to
act in response to threats to the public health or the environment and to seek
to recover from the responsible classes of persons the costs they incur. In the
course of its ordinary operations, the Partnership may generate waste that may
fall within CERCLA's definition of a "hazardous substance". As a result, the
Partnership may be jointly and severally liable under CERCLA or under analogous
state laws for all or part of the costs required to clean up sites at which such
wastes have been disposed. The Partnership currently owns or leases, and has in
the past owned or leased, numerous properties that for many years have been used
for the exploration and production of oil and natural gas. Although the
Partnership has utilized operating and disposal practices that were standard in
the industry at the time, hydrocarbons or other wastes may have been disposed of
or released on or under the properties owned or leased by the Partnership on or
under other locations where such wastes have been taken for disposal. In
addition, many of these properties have been operated by third parties whose
actions with respect to the treatment and disposal or release of hydrocarbons or
other wastes were not under the Partnership's control. These properties and
wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws.
Under such laws, the Partnership could be required to remove or remediate
previously disposed wastes (including wastes disposed of or released by prior
owners or operators), to clean up contaminated property (including contaminated
groundwater) or to perform remedial plugging operations to prevent future
contamination.

CAUTION AS TO FORWARD-LOOKING STATEMENTS

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

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

RISK FACTORS

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

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

9
<PAGE> 11

Substantial Leverage. As of December 31, 1999, the Partnership has
total indebtedness for money borrowed of approximately $166,000 and partners'
equity of approximately $887,000. The Partnership's ability to make payments of
principal, to pay interest on or to refinance its indebtedness for money
borrowed depends on its future performance, which is subject not only to its own
actions but also to general economic, financial, competitive, legislative,
regulatory and other factors beyond its control, as well as to the prevailing
market prices for oil, natural gas and natural gas liquids.

Volatility of Oil, Natural Gas and Natural Gas Liquids Prices. The
Partnership's financial results are affected significantly by the prices
received for its oil, natural gas and natural gas liquids production.
Historically, the markets for oil, natural gas and natural gas liquids have been
volatile and are expected to continue to be volatile in the future. The prices
received by the Partnership for its oil, natural gas and natural gas liquids
production and the levels of such production are subject to government
regulation, legislation and policies. The Partnership's future financial
condition and results of operations will depend, in part, upon the prices
received for its oil and natural gas production, as well as the costs of
developing and producing reserves.

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

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

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

ITEM 3. LEGAL PROCEEDINGS

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

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

Not applicable.

10
<PAGE> 12

PART II

ITEM 5. MARKET FOR UNITS AND RELATED UNITHOLDER MATTERS

There is no market for the Units of the Partnership, and transfer of
the Units is substantially restricted by the provisions of the Partnership
Agreement. As of February 28, 2000, there were 803 holders of record of the
Partnership's Units.

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

<TABLE>
<CAPTION>
DISTRIBUTIONS
-------------
<S> <C>
1997:
First quarter................................................ --
Second quarter............................................... --
Third quarter................................................ --
Fourth quarter............................................... --

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

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

2000:
First quarter................................................ --
</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. Quarterly distributions are not expected to be
reinstated until all Partnership indebtedness has been repaid. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations."

11
<PAGE> 13

ITEM 6. SELECTED FINANCIAL DATA

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

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

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------------------------
1995 1996 1997 1998 1999
--------- --------- --------- --------- ------
<S> <C> <C> <C> <C> <C>
SUMMARY OF OPERATIONS:
Total revenues...................................$ 5,713 $ 4,991 $ 2,322 $ 1,398 $1,645
Production expenses.............................. 1,223 816 576 497 330
Exploration expenses............................. 148 (3) - - -
General and administrative expenses.............. 474 325 476 134 92
Interest expense................................. 672 810 376 287 174
Depreciation, depletion and amortization......... 4,945 1,280 587 427 225
Impairment of oil and gas properties............. 11,082 - - 466 -
Net income (loss)................................ (12,831) 1,763 307 (413) 824
Net income (loss) per Unit(1).................... (.77) .11 .02 (.02) .05
Distributions paid per Unit(1)................... .02 - - - -
Units outstanding................................ 16,033 16,033 16,033 16,033 16,033

<CAPTION>
AS OF DECEMBER 31,
-----------------------------------------------------------
1995 1996 1997 1998 1999
--------- --------- --------- --------- ------
<S> <C> <C> <C> <C> <C>
SUMMARY BALANCE SHEET DATA:
Working capital (deficit).......................$ (1,857) $ 1,582 $ 288 $ 23 $ (17)
Oil and gas properties, net..................... 6,263 3,987 3,369 2,528 1,070
Long term debt.................................. 6,000 5,400 3,181 2,488 166
Total partners' equity (deficit)................ (1,594) 169 476 63 887
Total assets.................................... 6,469 5,712 3,741 2,649 1,115
</TABLE>

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

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, 1999. 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. Kelley Oil Corporation, managing
general partner of the Partnership ("Kelley Oil") and a wholly-owned subsidiary
of Contour Energy Co. (formerly Kelly Oil & Gas Corporation ) (Contour), owns
83.72% of the Units, together with its 3.94% managing general partnership
interest.

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

Hedging Activities. Contour has periodically used forward sales
contracts, natural gas and crude oil price swap agreements, natural gas basis
swap agreements and options to reduce exposure to downward price fluctuations on
its natural

12
<PAGE> 14

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

Through natural gas price swap agreements, the Partnership hedged
approximately 65%, 49% and 50%, respectively, of its natural gas production for
1997, 1998 and 1999, respectively, at average NYMEX quoted prices of $2.35,
$2.31 and $2.17 per Mmbtu, respectively, before transaction and transportation
costs. As of December 31, 1999, approximately 8% of the Partnership's
anticipated natural gas production for 2000 has been hedged by natural gas price
swap agreements at an average NYMEX quoted price of $2.41 per Mmbtu before
transaction and transportation costs. Per additional hedging activities since
December 31, 1999, approximately 47% of the Partnership's anticipated natural
gas production for 2000 has been hedged at an average NYMEX quoted price of
$2.56 per Mmbtu before transaction and transportation. Through crude oil price
swap agreements, the Partnership hedged approximately 29% of its crude oil
production for 1999 at an average NYMEX quoted price of $20.00 per bbl, before
transaction and transportation costs. No crude oil was hedged in either 1997 or
1998. As of December 31, 1999, approximately 7% of the Partnership's crude oil
production for 2000 had been hedged by crude oil price swap agreements at an
average NYMEX quoted price of $25.05 per bbl before transaction and
transportation costs. Per additional hedging activities since December 31, 1999,
approximately 43% of the Partnership's anticipated crude oil production for 2000
has been hedged at an average NYMEX quoted price of $26.21 per bbl before
transaction and transportation costs. Hedging activities decreased Partnership
revenues by approximately $156,000 and $17,000 in 1997 and 1999, respectively,
and increased such revenues by approximately $50,000 in 1998 as compared to
estimated revenues had no hedging activities been conducted. At December 31,
1999, the unrealized gain/loss on the Partnership's existing hedging instruments
for future production months in 2000 was not material.

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

RESULTS OF OPERATIONS

Years Ended December 31, 1999 and 1998. Oil and gas revenues of
$795,000 for 1999 decreased 43% compared to $1,398,000 in the corresponding
period of 1998 primarily as a result of lower oil and gas production. Production
of natural gas decreased 48% from 601,000 Mcf in 1998 to 314,000 Mcf in 1999.
Production of crude oil in the current year totaled 9,398 barrels compared to
10,172 barrels last year, representing a decrease of 8%. Oil and gas production
decreased due to the sale of properties to Phillips and natural depletion.

Lease operating expenses and severance taxes were $330,000 in 1999
versus $497,000 in 1998, a decrease of 37%, primarily related to the sale of
properties to Phillips. On a unit of production basis, these expenses increased
to $0.89 per Mcfe in 1999 from $0.75 per Mcfe in 1998.

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

In 1999 and 1998, the Partnership incurred interest expense of $174,000
and $287,000, respectively, on a loan advanced to it by Kelley Oil in August
1994 to fund part of its drilling expenses in excess of contributed capital. The
reduction reflects the lower average note payable balance outstanding in 1999 as
compared to 1998. See "Liquidity and Capital Resources" below.

13
<PAGE> 15

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

In 1998, under Statement of Financial Accounting Standards No. 121
("SFAS 121"), "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of," the Partnership recognized a non-cash
impairment charge of $466 thousand against the carrying values of its proved oil
and gas properties, for the year ended December 31, 1998 (see "Property
Impairment under SFAS 121" in Note 2 to the Financial Statements).

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

Years Ended December 31, 1998 and 1997. Oil and gas revenues of
$1,398,000 for 1998 decreased 40% compared to $2,322,000 in the corresponding
period of 1997 primarily as a result of lower oil and gas production. Production
of natural gas decreased 38% from 963,000 Mcf in 1997 to 601,000 Mcf in 1998.
Production of crude oil in the current year totaled 10,172 barrels compared to
11,395 barrels last year, representing a decrease of 11%. Oil and gas production
decreased due to natural depletion.

Lease operating expenses and severance taxes were $497,000 in 1998
versus $576,000 in 1997, a decrease of 14%, reflecting lower production levels.
On a unit of production basis, these expenses increased to $0.75 per Mcfe in
1998 from $0.56 per Mcfe in 1997.

General and administrative expenses of $134,000 in 1998 decreased 72%
from $476,000 in 1997. On a unit of production basis, these expenses decreased
from $0.46 per Mcfe in 1997 to $0.20 per Mcfe in 1998.

In 1998 and 1997, the Partnership incurred interest expense of $287,000
and $376,000, respectively, on a loan advanced to it by Kelley Oil in August
1994 to fund part of its drilling expenses in excess of contributed capital. The
reduction reflects the lower average note payable balance outstanding in 1998 as
compared to 1997. See "Liquidity and Capital Resources" below.

Depreciation, depletion and amortization ("DD&A") expense decreased 27%
from $587,000 in 1997 to $427,000 in 1998 due to lower production levels and
lower depletion rates. On a unit of production basis, DD&A expense increased
from $0.57 per Mcfe in 1997 to $0.64 per Mcfe in 1998.

The Partnership recognized a net loss in 1998 of $413,000 or $(0.02)
per Unit compared to net income in 1997 of $307,000 or $0.02 per Unit. The
reasons for the variance between 1998 and 1997 are described in the foregoing
discussion.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity. Net cash provided by the Partnership's operating activities
during 1999, as reflected on its statement of cash flows, totaled $238,000.
During the period, funds provided by investing activities included proceeds from
the sale of properties to Phillips of $2,098,000, partially offset by capital
expenditures of $14,000, and funds used in financing activities included a
reduction in the Initial Loan principal of $2,322,000. As a result of these
activities, the Partnership's cash and cash equivalents remained at zero at
December 31, 1999 and December 31, 1998.

14
<PAGE> 16

Capital Resources. The partners' equity at December 31, 1999 increased
to $887,000 as compared to $63,000 at December 31, 1998. 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, 1999, the Partnership was fully capitalized with contributions
aggregating $50,082,285.

15
<PAGE> 17

In August 1994, one of the credit facilities maintained by Kelley Oil
was modified to add the Partnership as a borrower, and $6 million was advanced
to the Partnership to fund part of its drilling overexpenditures. The
Partnership's bank debt was subsequently replaced by a $6 million loan from
Kelley Oil (the "Initial Loan") funded with borrowings by Kelley Oil under a
credit facility. Interest has been paid by the Partnership based on Contour's
borrowing cost resulting in an effective rate of 10 3/8% for 1997, 1998 and
1999. On December 31, 1996 the interest rate for the Initial Loan was reduced to
10 3/8% following the repayment of Contour's 13 1/2% Senior Notes, which were
replaced by 10 3/8% Senior Subordinated Notes during the fourth quarter.

Distribution Policy. The Partnership maintains a policy of distributing
cash which is not required for the conduct of Partnership business to
Unitholders on a quarterly basis. To meet its financial obligations for drilling
overexpenditures, the Partnership suspended distributions commencing in October
1994 and reinstated a quarterly distribution for only one quarter in 1995. At
December 31, 1999, $166,000 of the $6,000,000 Initial Loan remained outstanding.
By continuing to service its debt from operating cash flow, the Partnership
expects to further reduce the outstanding balance of the Initial Loan in 1999.

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

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

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

<TABLE>
<CAPTION>
Average Average
Oil Price Gas Price
($/Bbl) ($/Mcf)
--------- ---------
<S> <C> <C>
YEAR ENDED:
December 31, 1997............................... 19.92 2.18
December 31, 1998............................... 13.56 2.10
December 31, 1999............................... 15.78 2.11
</TABLE>

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

16
<PAGE> 18

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

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

17
<PAGE> 19

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM: PAGE
----
<S> <C>
Independent Auditors' Report............................................................................... 19
Balance Sheets - December 31, 1998 and 1999................................................................ 20
Statements of Operations - For the years ended December 31, 1997, 1998 and 1999............................ 21
Statements of Cash Flows - For the years ended December 31, 1997, 1998 and 1999............................ 22
Statements of Changes in Partners' Equity (Deficit) - For the years ended
December 31, 1997, 1998 and 1999....................................................................... 23
Notes to Financial Statements.............................................................................. 24
</TABLE>

18
<PAGE> 20

INDEPENDENT AUDITORS' REPORT

To the Partners of Kelley Partners 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,
1998 and 1999, and the related statements of operations, cash flows, and changes
in partners' equity (deficit) for each of the three years in the period ended
December 31, 1999. These financial statements are the responsibility of the
Partnership's management. Our responsibility is to express an opinion on these
financial statements based on our audits.

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

In our opinion, such financial statements present fairly, in all
material respects, the financial position of Kelley Partners 1992 Development
Drilling Program as of December 31, 1998 and 1999, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1999, in conformity with generally accepted accounting principles.

DELOITTE & TOUCHE LLP

Houston, Texas
March 23, 2000

19
<PAGE> 21

KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
BALANCE SHEETS

(IN THOUSANDS)

<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------
1998 1999
------------ ------------
<S> <C> <C>
ASSETS:
Cash and cash equivalents ......................................... $ -- $ --
Accounts receivable - trade ....................................... 12 28
Accounts receivable - affiliates .................................. 109 17
------------ ------------
Total current assets ............................................ 121 45
------------ ------------

Oil and gas properties, successful efforts method:
Properties subject to amortization .............................. 44,354 41,466
Less: Accumulated depreciation, depletion & amortization ....... (41,826) (40,396)
------------ ------------
Total oil and gas properties .................................... 2,528 1,070
------------ ------------
Total assets ...................................................... $ 2,649 $ 1,115
============ ============

LIABILITIES:
Accounts payable and accrued expenses ............................. $ 98 $ 62
------------ ------------
Total current liabilities ....................................... 98 62
------------ ------------
Long term note payable - affiliate ................................ 2,488 166
------------ ------------
Total liabilities ............................................... 2,586 228
------------ ------------

PARTNERS' EQUITY:
LP Unitholders' equity ............................................ (20) 62
GP Unitholders' equity ............................................ 80 789
Managing and Special General Partners' equity ..................... 3 36
------------ ------------
Total partners' equity .......................................... 63 887
------------ ------------
Total liabilities and partners' equity ............................ $ 2,649 $ 1,115
============ ============
</TABLE>

See Notes to Financial Statements.

20
<PAGE> 22

KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
STATEMENTS OF OPERATIONS

(IN THOUSANDS, EXCEPT PER UNIT DATA)

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------
1997 1998 1999
------------ ------------ ------------
<S> <C> <C> <C>
REVENUES:
Oil and gas sales ............................................ $ 2,322 $ 1,398 $ 795
Gain on sale of properties ................................... -- -- 850
------------ ------------ ------------
Total revenues ............................................... 2,322 1,398 1,645
------------ ------------ ------------

COSTS AND EXPENSES:
Lease operating expenses ..................................... 474 420 285
Severance taxes .............................................. 102 77 45
Exploration expenses ......................................... -- -- --
General and administrative expenses .......................... 476 134 92
Interest expense ............................................. 376 287 174
Depreciation, depletion and amortization ..................... 587 427 225
Impairment of oil and gas properties ......................... -- 466 --
------------ ------------ ------------
Total expenses ............................................. 2,015 1,811 821
------------ ------------ ------------
Net income (loss) ............................................... $ 307 $ (413) $ 824
============ ============ ============

Net income (loss) allocable to LP and GP unitholders ............ $ 295 $ (397) $ 791
============ ============ ============

Net income (loss) allocable to managing and
special general partners ..................................... $ 12 $ (16) $ 33
============ ============ ============

Net income (loss) per LP and GP Unit ............................ $ .02 $ (.02) $ .05
============ ============ ============

Average LP and GP Units outstanding ............................. 16,033 16,033 16,033
============ ============ ============
</TABLE>

See Notes to Financial Statements.

21
<PAGE> 23

KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
STATEMENTS OF CASH FLOWS

(IN THOUSANDS)

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------
1997 1998 1999
------------ ------------ ------------
<S> <C> <C> <C>
OPERATING ACTIVITIES:
Net income (loss) ...................................................... $ 307 $ (413) $ 824
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Gain on sale of properties ........................................... -- -- (850)
Depreciation, depletion and amortization ............................. 587 427 225
Impairment of oil and gas properties ................................. -- 466 --
Changes in operating assets and liabilities:
Decrease in accounts receivable .................................... 1,331 251 75
Increase (decrease) in accounts payable and accrued expenses ....... (59) 14 (36)
------------ ------------ ------------
Net cash provided by operating activities .............................. 2,166 745 238
------------ ------------ ------------

INVESTING ACTIVITIES:
Capital expenditures ................................................... (41) (52) (14)
Proceeds from sale of assets ........................................... 72 -- 2,098
------------ ------------ ------------
Net cash provided by (used in) investing activities .................... 31 (52) 2,084
------------ ------------ ------------

FINANCING ACTIVITIES:
Payments on long-term borrowings ....................................... (2,219) (693) (2,322)
------------ ------------ ------------
Net cash used in financing activities .................................. (2,219) (693) (2,322)
------------ ------------ ------------

Increase (decrease) in cash and cash equivalents .......................... (22) -- --

Cash and cash equivalents, beginning of period ............................ 22 -- --
------------ ------------ ------------
Cash and cash equivalents, end of period .................................. $ -- $ -- $ --
============ ============ ============
</TABLE>

See Notes to Financial Statements.

22
<PAGE> 24

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

(IN THOUSANDS)

<TABLE>
<CAPTION>
MANAGING
AND
SPECIAL
LP GP GENERAL
UNITHOLDERS UNITHOLDERS PARTNERS TOTAL
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Partners' equity (deficit) at January 1, 1997 ......... $ (9) $ 171 $ 7 $ 169
----------- ----------- ----------- -----------
Net income ............................................ 30 265 12 307
----------- ----------- ----------- -----------
Partners' equity (deficit) at December 31, 1997 ..... 21 436 19 476
----------- ----------- ----------- -----------
Net loss .............................................. (41) (356) (16) (413)
----------- ----------- ----------- -----------
Partners' equity (deficit) at December 31, 1998 ..... (20) 80 3 63
----------- ----------- ----------- -----------
Net income ............................................ 82 709 33 824
----------- ----------- ----------- -----------
Partners' equity at December 31, 1999 ............... $ 62 $ 789 $ 36 $ 887
=========== =========== =========== ===========
</TABLE>

See Notes to Financial Statements.

23
<PAGE> 25

KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
NOTES TO FINANCIAL STATEMENTS

NOTE 1 - INDUSTRY CONDITIONS AND LIQUIDITY

Organization. Kelley Partners 1992 Development Drilling Program, a
Texas limited partnership (the "Partnership"), was formed in June 1992 and
commenced operations on November 27, 1992 upon completion of a public offering
of 16,033,009 units of limited partner interests and general partner interests
(the "Units") in the Partnership at $3.00 per Unit. Kelley Oil Corporation
("Kelley Oil") serves as the managing general partner of the Partnership, and
David L. Kelley serves as the special general partner of the Partnership.

The sole purpose of the Partnership is to finance the drilling of
development wells, as defined in its partnership agreement (the "Partnership
Agreement"), on selected properties owned by Kelley Operating Company, Ltd.
("Kelley Operating"), a Texas limited partnership of which Kelley Oil & Gas
Partners, Ltd. ("Kelley Partners") was the sole limited partner. The
Partnership's development activities have been conducted through a joint venture
(the "Joint Venture") between the Partnership and Kelley Operating, which has
retained a 20% interest in the Joint Venture after Payout (as defined in the
Joint Venture Agreement) in consideration of its contribution of drilling
rights. In February 1995, the equity interests in Kelley Partners and Kelley Oil
were consolidated (the "Consolidation") in Kelley Oil & Gas Corporation
(collectively with its predecessors, "KOGC"). In March 1996, Kelley Partners was
merged into KOGC, and Kelley Partners' 98% limited partner interest in Kelley
Operating was transferred to Kelley Oil. In 1999, KOGC's name was changed to
Contour Energy Co. ("Contour")

The general partners own in the aggregate a 3.96% general partner
interest in the Partnership. In addition, as of December 31, 1999, Kelley Oil
owned 13,422,310 (83.72%) Units. The Partnership has no officers, directors or
employees. The officers and employees of Kelley Oil perform the management and
administrative functions of the Partnership. The Partnership reimburses Kelley
Oil for all direct costs incurred in managing the Partnership and all indirect
costs allocable to the Partnership, principally comprised of general and
administrative expenses.

24
<PAGE> 26

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

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

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

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

Property Impairment under FAS 121. Under Financial Accounting Standards
Board's Statement No. 121, "Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to be Disposed Of" (SFAS 121"), certain assets are
required to be reviewed periodically for impairment whenever circumstances
indicate their carrying amount exceeds their fair value and may not be
recoverable. As a result of a decline in its proved reserves at January 1, 1999
from year-earlier levels, the Partnership performed an assessment of the fair
value of its oil and gas properties which indicated an impairment should be
recognized as of year end. Under this analysis, the fair value for the
Partnership's proved oil and gas properties was estimated using escalated
pricing and present value discount factors reflecting risk assessments. Based on
this analysis, the Partnership recognized a non-cash impairment charge of $466
thousand against the carrying value of its proved oil and gas properties under
SFAS 121, at December 31, 1998.

25
<PAGE> 27

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

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

Financial Instruments. The Partnership's financial instruments consist
of cash and cash equivalents, receivables, payables, debt and commodity
derivatives (see Note 6). As of December 31, 1999, the estimated fair value of
the Partnership's debt approximated its carrying value. The estimated fair
values at December 31, 1999 were determined using the borrowing rates available
for debt with similar terms and maturities.

Derivative Financial Instruments. From time to time, the Partnership
has entered into transactions in derivative financial instruments covering
future natural gas production principally as a hedge against natural gas price
declines. See Note 6 - "Hedging Activities" for a discussion of the
Partnership's accounting policies related to hedging activities.

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

Concentration of Credit Risk and Significant Customers. Substantially
all of the Partnership's receivables are due from the marketing subsidiary of
Kelley Oil, which purchases approximately 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 generally accepted accounting principles 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.

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

NOTE 3 - LONG-TERM DEBT

In August 1994, one of the credit facilities maintained by Kelley Oil
was modified to add the Partnership as a borrower, and $6 million was advanced
to the Partnership to fund part of its drilling overexpenditures. The
Partnership's bank debt was subsequently replaced by a $6 million loan from
Kelley Oil (the "Initial Loan") funded with borrowings by Kelley Oil under a
credit facility. Interest has been paid by the Partnership based on Contour's
borrowing cost resulting in an effective rate of 10 3/8% for 1997, 1998 and
1999. On December 31, 1996, the interest rate for the Initial Loan was reduced
to 10 3/8% following the repayment of Contour's 13 1/2% Senior Notes, which were
replaced by 10 3/8% Senior Subordinated Notes during the fourth quarter.

The Partnership maintains a policy of distributing cash which is not
required for the conduct of Partnership business to Unitholders on a quarterly
basis. To meet its financial obligations for drilling overexpenditures, the
Partnership suspended distributions commencing in October 1994 and reinstated a
quarterly distribution for only one quarter in 1995. The Partnership's operating
cash flows in 1996 were applied to pay interest on the Initial Loan and to
reduce unfunded payables for third party drilling overexpenditures. At December
31, 1999, $166,000 of the $6,000,000 Initial Loan remained

26
<PAGE> 28

outstanding. By continuing to service its debt from operating cash flow, the
Partnership expects to further reduce the outstanding balance of the Initial
Loan in 2000.

NOTE 4 - CASH DISTRIBUTIONS

To enable to Partnership to fund part of its drilling and recompletion
expenditures in excess of contributed capital, distributions were suspended in
October 1994 and reinstated for only one quarter in 1995. See Note 3 - Long-Term
Debt.

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
Kelley Oil for all direct costs incurred in managing the Partnership and all
indirect costs (principally general and administrative expenses) allocable to
the Partnership.

Kelley Oil is reimbursed by the Partnership for costs directly
associated with acquisition, exploration and development activities. For the
years ended December 31, 1997, 1998 and 1999, these costs aggregated zero, zero
and zero, respectively. The Partnership capitalized zero in 1997, 1998 and 1999,
respectively, of allocated direct costs to oil and gas properties.

Overhead allocated to the Partnership by Kelley Oil for the years ended
December 31, 1997, 1998 and 1999 related to general and administrative expenses
aggregated $476,000, $134,000 and $92,000, respectively.

Substantially all gas sales of Contour and its subsidiaries, including
the Partnership (collectively, "Kelley"), are made to an affiliated company,
Concorde Gas Marketing, Inc., a wholly owned subsidiary of Kelley Oil ("CGM"),
which remarkets gas to third parties. For 1997, 1998 and 1999, the fee was 2% of
the resale price for marketed natural gas.

NOTE 6 - HEDGING ACTIVITIES

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

27
<PAGE> 29

bbl before transaction and transportation costs. Per additional hedging
activities since December 31, 1999, approximately 43% of the Partnership's
anticipated crude oil production for 2000 has been hedged at an average NYMEX
quoted price of $26.21 per bbl before transaction and transportation costs.
Hedging activities decreased Partnership revenues by approximately $156,000 and
$17,000 in 1997 and 1999, respectively, and increased such revenues by
approximately $50,000 in 1998 as compared to estimated revenues had no hedging
activities been conducted. At December 31, 1999, the unrealized gain/loss on the
Partnership's existing hedging instruments for future production months in 2000
was not material.

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

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

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

(IN THOUSANDS)

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------
1997 1998 1999
------------ ------------ ------------
<S> <C> <C> <C>
Unevaluated properties ..................................... $ -- $ -- $ --
Evaluated properties subject to amortization ............... 44,302 44,354 41,466
------------ ------------ ------------
Total properties subject to amortization ................ 44,302 44,354 41,466
Accumulated depreciation, depletion and amortization ....... (40,933) (41,826) (40,396)
------------ ------------ ------------
Net capitalized costs ................................... $ 3,369 $ 2,528 $ 1,070
============ ============ ============
</TABLE>

Costs Incurred. All costs were incurred in oil and gas property
development activities (as defined in the Partnership Agreement) and aggregated
$41,000, $52,000 and $14,000 in 1997, 1998 and 1999, 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, 1997, 1998 and 1999. See
"Estimated Proved Reserves-Uncertainties in Estimated Reserves" under Items 1
and 2 of this Form 10K.

28
<PAGE> 30

<TABLE>
<CAPTION>
CRUDE OIL, CONDENSATE
AND NATURAL GAS LIQUIDS NATURAL GAS
(MBBLS) (MMCF)
-------------------------- --------------------------
1997 1998 1999 1997 1998 1999
------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
Proved developed and undeveloped reserves:
Beginning of year ......................... 102 78 88 7,537 5,521 3,759
Revisions of previous estimates ........... (13) 20 (9) (1,053) (1,161) (187)
Extensions and discoveries ................ -- -- -- -- -- --
Sale of oil and gas properties ............ -- -- (6) -- -- (2,062)
Production ................................ (11) (10) (9) (963) (601) (314)
------ ------ ------ ------ ------ ------
End of year ............................. 78 88 64 5,521 3,759 1,196
====== ====== ====== ====== ====== ======
Proved developed reserves
at end of year ............................ 78 88 64 5,521 3,759 1,196
====== ====== ====== ====== ====== ======
</TABLE>

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

(IN THOUSANDS)

<TABLE>
<CAPTION>
AS OF DECEMBER 31,
--------------------------------------
1997 1998 1999
---------- ---------- ----------
<S> <C> <C> <C>
Future cash inflows ........................................... $ 15,157 $ 8,617 $ 4,269
Future production costs ....................................... (3,750) (3,295) (1,581)
Future development costs ...................................... (254) (186) (55)
---------- ---------- ----------
Future net cash flows ....................................... 11,153 5,136 2,633
10% annual discount for estimating timing of cash flows ....... (4,535) (1,964) (933)
---------- ---------- ----------
Standardized measure of discounted future net cash flows .... $ 6,618 $ 3,172 $ 1,700
========== ========== ==========
</TABLE>

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

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

The standardized measure of discounted future net cash flows as of
December 31, 1997, 1998 and 1999 was calculated using prices in effect as of
those dates, which averaged $17.01, $9.88 and $25.46, respectively, per barrel
of oil and $2.49, $2.06 and $2.15, respectively, per Mcf of natural gas.

29
<PAGE> 31

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

(IN THOUSANDS)

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------
1997 1998 1999
---------- ---------- ----------
<S> <C> <C> <C>
Changes due to current year operations:
Sales of oil and gas, net of production costs ................. $ (1,746) $ (901) $ (465)
Sales of reserves in place .................................... -- -- (1,668)
Extensions and discoveries, net of future production costs .... -- -- --
Development costs incurred during the year .................... 24 -- --
Changes due to revisions in standardized variables:
Prices and production costs ................................... (6,699) (2,304) 557
Revisions of previous quantity estimates ...................... (1,279) (766) 152
Estimated future development costs ............................ (133) (53) (97)
Accretion of discount ......................................... 1,572 662 317
Production rates (timing) and other ........................... (841) (84) (268)
---------- ---------- ----------
Net increase (decrease) ..................................... (9,102) (3,446) (1,472)
Beginning of year ................................................ 15,720 6,618 3,172
---------- ---------- ----------
End of year ...................................................... $ 6,618 $ 3,172 $ 1,700
========== ========== ==========
</TABLE>

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

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF KELLEY OIL CORPORATION

GENERAL

The Partnership has no directors, officers or employees. Directors and
officers of Kelley Oil perform all management functions for the Partnership.
Kelley Oil had 47 employees as of December 31, 1999, and its staff includes
employees experienced in geology, geophysics, petroleum engineering, land
acquisition and management, finance, accounting, and administration.

BACKGROUND OF KELLEY OIL

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

30
<PAGE> 32

EXECUTIVE OFFICERS OF KELLEY OIL

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

<TABLE>
<CAPTION>
OFFICER
OR
DIRECTOR OF
THE COMPANY
NAME AGE POSITION SINCE
- ---- --- -------- -----------
<S> <C> <C> <C>
John F. Bookout................. 77 President, Chief Executive Officer and a director 1996
Rick G. Lester.................. 48 Senior Vice President and Chief Financial Officer 1998
Kenneth R. Sanders.............. 50 Senior Vice President-Exploration and Production 1999
</TABLE>

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

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

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

BENEFICIAL OWNERSHIP REPORTING

Not applicable.

ITEM 11. EXECUTIVE COMPENSATION

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

31
<PAGE> 33

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

BENEFICIAL OWNERS

The following table sets forth information as of December 31, 1999 with
respect to the only Unitholder known by the Partnership to own beneficially more
than five percent of the Partnership's Units.

<TABLE>
<CAPTION>
AMOUNT & NATURE
NAME AND ADDRESS OF OF BENEFICIAL PERCENT
BENEFICIAL OWNER OWNERSHIP OF CLASS
- ---------------- --------- --------
<S> <C> <C>
Kelley Oil Corporation 13,422,310 83.72%
601 Jefferson, Suite 1100 Direct
Houston, Texas 77002
</TABLE>

MANAGEMENT

The following table sets forth information as of December 31, 1999 with
respect to Units beneficially owned, directly or indirectly, by each of the
directors of Kelley Oil and by all officers and directors of Kelley Oil as a
group.

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

(1)Represents direct beneficial ownership.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

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

Kelley Oil is reimbursed for its direct costs and an allocable portion
of its general and administrative expenses incurred as Managing General Partner.
See Note 5 of 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.

32
<PAGE> 34

PART IV

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

(a) FINANCIAL STATEMENTS AND SCHEDULES:

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

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

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

(b) REPORTS ON FORM 8-K:

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

33
<PAGE> 35

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized, this 3rd day of April
2000.

KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM

By: KELLEY OIL CORPORATION, Managing General Partner

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

Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed as of the 3rd day of April 2000 by the following
persons in their capacity as directors of the Registrant's managing general
partner.

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

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

<PAGE> 36

INDEX TO EXHIBITS

<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------ -----------
<S> <C>
4.1 Amended and Restated Agreement of Limited Partnership of
the Registrant (included as Exhibit A to the Prospectus
forming part of the Registrant's Registration Statement on
Form S-1 (File No. 33-51250) 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).

27 Financial Data Schedule
</TABLE>

<ARTICLE> 5
<MULTIPLIER> 1,000

<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
<CASH> 0
<SECURITIES> 0
<RECEIVABLES> 45
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 45
<PP&E> 41,466
<DEPRECIATION> 40,396
<TOTAL-ASSETS> 1,115
<CURRENT-LIABILITIES> 62
<BONDS> 166
0
0
<COMMON> 0
<OTHER-SE> 887
<TOTAL-LIABILITY-AND-EQUITY> 1,115
<SALES> 795
<TOTAL-REVENUES> 1,645
<CGS> 0
<TOTAL-COSTS> 330
<OTHER-EXPENSES> 317
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 174
<INCOME-PRETAX> 824
<INCOME-TAX> 0
<INCOME-CONTINUING> 824
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 824
<EPS-BASIC> .05
<EPS-DILUTED> .05

</TABLE>