SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1997 COMMISSION FILE NO. 0-20998
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)
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 15, 1997, 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>
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 Kelley Oil & Gas Corporation ("KOGC" and, collectively with its
subsidiaries, "Kelley").
As used in this Report, "Mcf" means thousand cubic feet, "Mmcf" means
million cubic feet, "Bcf" means billion cubic feet, "Bbl" means barrel or 42
U.S. gallons liquid volume, "Mbbl" means thousand barrels, "Mcfe" means thousand
cubic feet of natural gas equivalent using the ratio of six Mcf of natural gas
to one Bbl of crude oil, condensate and natural gas liquids, "Mmcfe" means
million cubic feet of natural gas equivalent, "Bcfe" means billion cubic feet of
natural gas equivalent, and "Mmbtu" means million British thermal units. This
Report includes various other capitalized terms that are defined when first
used.
OPERATIONS. Development activities of the Partnership are conducted
through a joint venture (the "Joint Venture") between the Partnership and Kelley
Operating Company, Ltd. ("Kelley Operating"), a subsidiary partnership of Kelley
Oil. The Partnership 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. During 1997, recompletion and
work-over operations were conducted on one well. From its inception through
1997, the Partnership produced 9.6 Bcf of natural gas and 183,912 barrels of oil
and natural gas liquids, generating total oil and gas revenues of $22,428,000,
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
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Oil to perform all management and administrative functions. Kelley Oil's staff
includes employees experienced in geology, geophysics, petroleum engineering,
land acquisition and management, finance and accounting. Kelley Oil is also the
managing general partner of Kelley Operating. See "Employees" below and
"Directors and Executive Officers of Kelley Oil Corporation."
The General Partners receive no management or other fees or promoted
interests from the Partnership or the Joint Venture. The Partnership reimburses
Kelley Oil for all direct costs incurred in managing the Partnership and all
indirect costs allocable to the Partnership, principally comprised of general
and administrative expenses. These arrangements are the same for all development
drilling programs ("DDPs") sponsored by Kelley Oil.
ESTIMATED PROVED RESERVES
GENERAL. Reserve estimates contained herein were prepared by H. J. Gruy
& Associates, Inc. ("Gruy") independent petroleum engineers, as of January 1,
1996, 1997 and 1998.
QUANTITIES. The following table sets forth the Partnership's estimated
quantities of proved and proved developed reserves of crude oil (including
condensate and natural gas liquids) and natural gas as of January 1, 1996, 1997
and 1998. Proved developed reserves are reserves that can be expected to be
recovered from existing wells with existing equipment and operating methods.
Proved undeveloped reserves are proved reserves that are expected to be
recovered from new wells drilled to known reservoirs on undrilled acreage for
which the existence and recoverability of reserves can be estimated with
reasonable certainty, or from existing wells where a relatively major
expenditure is required for recompletion.
ESTIMATED PROVED RESERVES
AS OF JANUARY 1,
--------------------------------
1996 1997 1998
------ ------ ------
Crude oil and liquids (Mbbl):
Proved developed ..................... 201 102 78
Proved undeveloped ................... -- -- --
------ ------ ------
Total proved ....................... 201 102 78
====== ====== ======
Natural gas (Mmcf):
Proved developed ..................... 10,220 7,537 5,521
Proved undeveloped ................... -- -- --
------ ------ ------
Total proved ....................... 10,220 7,537 5,521
====== ====== ======
Detailed information concerning the Partnership's estimated proved
reserves and discounted net future cash flows is contained in the Supplementary
Financial Information included in Note 6 to the Partnership's Financial
Statements. The Partnership has not filed any estimates of reserves with any
federal authority or agency during the past year other than estimates contained
in its last annual report filed with the Securities and Exchange Commission
("SEC").
UNCERTAINTIES IN ESTIMATING RESERVES. 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
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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.
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, 1998 with respect to the Partnership's interests in its most
significant fields, together with information for all other fields combined.
SIGNIFICANT PROVED PROPERTIES
(IN THOUSANDS)
<TABLE>
<CAPTION>
PROVED RESERVES AT JANUARY 1, 1998 1997 PRODUCTION
----------------------------------------- -----------------------------------------
GAS GAS
OIL GAS EQUIVALENT OIL GAS EQUIVALENT
PROPERTY (MBBLS) (MMCF) (MMCFE) % (MBBLS) (MMCF) (MMCFE) %
-------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
NORTH LOUISIANA:
Ada field .................. 1 468 474 7.9 -- 23 23 2.2
Sailes field ............... 4 3,399 3,423 57.2 1 592 598 58.1
Sibley field ............... 11 839 905 15.1 -- 81 81 7.9
West Bryceland field ....... -- 46 46 0.8 -- 10 10 1.0
SOUTH LOUISIANA:
Orange Grove/Humphreys field 2 140 152 2.5 1 68 74 7.2
Ouiski Bayou field ......... 60 559 919 15.3 7 74 116 11.3
OTHER:
As a group ................. -- 70 70 1.2 2 115 127 12.3
-------- -------- -------- -------- -------- -------- -------- --------
Total .................... 78 5,521 5,989 100.0 11 963 1,029 100.0
======== ======== ======== ======== ======== ======== ======== ========
</TABLE>
ADDITIONAL INFORMATION REGARDING THESE FIELDS IS SET FORTH BELOW.
UNLESS OTHERWISE NOTED, ACREAGE AND WELL INFORMATION IS PROVIDED AS OF DECEMBER
31, 1997, AND RESERVE INFORMATION IS PROVIDED AS OF JANUARY 1, 1998:
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. The Sailes field is located in Bienville Parish,
Louisiana. The Partnership has interests in 6 gross (2.16 net) wells producing
from the Hosston formation at depths ranging from 7,240 to 9,900 feet. Kelley
Oil operates five of the wells. The Sailes field reserves are 100% proved
developed.
SIBLEY FIELD. The Sibley field is located in Webster Parish, Louisiana.
The Partnership has interests in 5 gross (.36 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.
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WEST BRYCELAND FIELD. The West Bryceland field is located in Bienville
Parish, Louisiana. The Partnership has an interest in 1 gross (0.24 net) well
producing from the Hosston formation at depths ranging from 6,500 to 10,500
feet. The West Bryceland field reserves are 100% proved developed.
SOUTH LOUISIANA
ORANGE GROVE/HUMPHREYS FIELD. The Orange Grove/Humphreys field is
located in Terrebonne Parish, Louisiana. The Partnership has interests in 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, 1995, 1996 and 1997.
Detailed additional information concerning the Partnership's oil and gas
producing activities is contained in the Supplementary Financial Information
included in Note 6 to the Partnership's Financial Statements.
OIL AND GAS PRODUCTION
YEAR ENDED DECEMBER 31,
------------------------
1995 1996 1997
------ ------ ------
Crude oil, condensate and natural gas liquids (Bbls) 40,936 27,133 11,395
Natural gas (Mmcf) ................................. 2,741 1,838 963
AVERAGE SALES PRICES AND PRODUCTION COSTS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------
1995 1996 1997
------ ------ ------
Average sales price:
<S> <C> <C> <C>
Crude oil, condensate and natural gas liquids per Bbl $18.66 $21.74 $19.92
Natural gas per Mcf ................................. 1.77 2.27 2.18
Oil and gas revenues per Mcfe .......................... 1.91 2.40 2.25
Average production costs per Mcfe ...................... .41 .41 .56
</TABLE>
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OIL AND GAS WELLS
As of December 31, 1997, the Partnership owned interests in productive
oil and gas wells (including producing wells and wells capable of production) as
follows:
GROSS(1) NET
-------- --------
Oil wells .................................. -- --
Gas wells .................................. 20 4.88
-------- --------
Total ..................................... 20 4.88
======== ========
(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>
1995 ........... -- -- -- -- -- -- -- --
1996 ........... -- -- -- -- -- -- -- --
1997 ........... -- -- -- -- -- -- -- --
</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
KOGC has periodically used forward sales contracts, natural gas price
swap agreements, natural gas basis swap agreements and options to reduce
exposure to downward price fluctuations on its natural gas production. KOGC does
not engage in speculative transactions. KOGC's hedging activities also cover the
oil and gas production attributable to the
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Partnership, including the interest in such production of the public unitholders
of the Partnership. During 1997, the Company used price and basis swap
agreements. Additional information concerning Partnership hedging activities
during 1997 is set forth in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" contained elsewhere in this Report.
COMPETITION
The oil and gas industry is highly competitive. Major oil and gas
companies, independent concerns, drilling and production purchase programs and
individual producers and operators are active bidders for desirable oil and gas
properties, as well as the equipment and labor required to operate those
properties. Many competitors have financial resources substantially greater than
those of the Partnership and staffs and facilities substantially larger than
those of Kelley Oil. The availability of a ready market for the oil and gas
production of the Partnership depends in part on the cost and availability of
alternative fuels, the level of consumer demand, the extent of other domestic
production of oil and gas, the extent of importation of foreign oil and gas, the
cost of and proximity to pipelines and other transportation facilities,
regulations by state and federal authorities and the cost of complying with
applicable environmental regulations.
EMPLOYEES
The Partnership has no employees and utilizes the management and staff
of Kelley Oil. As of December 31, 1997, Kelley Oil had 57 employees. Kelley
Oil's staff includes employees experienced in geology, geophysics, petroleum
engineering, land acquisition and management, finance and accounting. See
"Directors and Executive Officers of Kelley Oil Corporation." None of Kelley
Oil's employees are represented by a union. Kelley Oil has never experienced an
interruption in its operations from any kind of labor dispute, and its working
relationships with its employees is satisfactory.
REGULATION
The Partnership's operations are subject to extensive and continually
changing regulation, as legislation affecting the oil and natural gas industry
is under constant review for amendment and expansion. Many departments and
agencies, both federal and state, are authorized by statute to issue and have
issued rules and regulations binding on the oil and natural gas industry and its
individual participants. The failure to comply with such rules and regulations
can result in substantial penalties. The regulatory burden on the oil and
natural gas industry increases the Partnership's cost of doing business and,
consequently, affects its profitability. However, the Partnership does not
believe that it is affected in a significantly different manner by these
regulations than are its competitors in the oil and natural gas industry.
Because of the numerous and complex federal and state statutes and regulations
that may affect the Partnership, directly or indirectly, the following
discussion of certain statutes and regulations should not be relied upon as an
exhaustive review of all matters affecting the Partnership's operations.
TRANSPORTATION AND PRODUCTION
TRANSPORTATION AND SALE OF NATURAL GAS AND CRUDE OIL. Sales of natural
gas, crude oil and condensate ("Products") can be made by the Partnership at
market prices not subject at this time to price controls. The price that the
Partnership receives from the sale of these Products is affected by the ability
to transport and cost of transporting the Products to market. Under applicable
laws, the Federal Energy Regulation Commission ("FERC") regulates both the
construction of pipeline facilities and the transportation of Products in
interstate commerce.
REGULATION OF DRILLING AND PRODUCTION. Drilling and production
operations of the Partnership are subject to regulation under a wide range of
state and federal statutes, rules, orders and regulations. State and federal
statutes and regulations govern, among other matters, the amounts and types of
substances and materials that may be released into the environment, the
discharge and disposition of waste materials, the reclamation and abandonment of
wells and facility sites and remediation of contaminated sites, and require
permits for drilling operations, drilling bonds and reports concerning
operations. Most states in which the Partnership owns and operates properties
have regulations governing conservation matters, including provisions for the
unitization or pooling of oil and natural gas properties, the establishment of
maximum rates of production from oil and natural gas wells and the regulation of
the spacing, plugging and abandonment of wells.
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Many states also restrict production to the market demand for oil and natural
gas and several states have indicated interest in revising applicable
regulations. The effect of these regulations is to limit the amount of oil and
natural gas the Partnership can produce from its wells and to limit the number
of wells or the locations at which the it can drill. Moreover, each state
generally imposes an ad valorem, production or severance tax with respect to the
production and sale of crude oil, natural gas and gas liquids within its
jurisdiction.
ENVIRONMENTAL REGULATIONS
GENERAL. The various federal environmental laws, including the National
Environmental Policy Act; the Clean Air Act of 1990, as amended ("CAA"); Oil
Pollution Act of 1990, as amended ("OPA"); Water Pollution Control Act, as
amended ("FWPCA"); the Resource Conservation and Recovery Act as amended
("RCRA"); the Toxic Substances Control Act; and the Comprehensive Environmental
Response, Compensation and Liability Act, as amended ("CERCLA"), and the various
state and local environmental laws, and the regulations adopted pursuant to such
law, governing the discharge of materials into the environment, or otherwise
relating to the protection of the environment, continue to be taken seriously by
the Partnership. In particular, the Partnership's drilling, development and
production operations, its activities in connection with storage and
transportation of crude oil and other liquid hydrocarbons and its use of
facilities for treating, processing or otherwise handling hydrocarbons and
wastes therefrom are subject to stringent environmental regulation, and
violations are subject to reporting requirements, civil penalties and criminal
sanctions. As with the industry generally, compliance with existing regulations
increases the Company's overall cost of business. The increased costs are not
reasonably ascertainable. Such areas affected include unit production expenses
primarily related to the control and limitation of air emissions and the
disposal of produced water, capital costs to drill exploration and development
wells resulting from expenses primarily related to the management and disposal
of drilling fluids and other oil and natural gas exploration wastes and capital
costs to construct, maintain and upgrade equipment and facilities and plug and
abandon inactive well sites and pits.
Environmental regulations historically have been subject to frequent
change by regulatory authorities, and the Partnership is unable to predict the
ongoing cost of compliance with these laws and regulations or the future impact
of such regulations on its operations. However, the Partnership does not believe
that changes to these regulations will materially adversely affect the its
competitive position because the Partnership's competitors are similarly
affected. A discharge of hydrocarbons or hazardous substances into the
environment could subject the Partnership to substantial expense, including both
the cost to comply with applicable regulations pertaining to the remediation of
releases of hazardous substances into the environment and claims by neighboring
landowners and other third parties for personal injury and property damage. The
Partnership maintains insurance, which may provide protection to some extent
against environmental liabilities, but the coverage of such insurance and the
amount of protection afforded thereby cannot be predicted with respect to any
particular possible environmental liability and may not be adequate to protect
the Partnership from substantial expense.
The OPA and regulations thereunder impose a variety of regulations on
"responsible parties" related to the prevention of oil spills and liability for
damages resulting from such spills in United States waters. A "responsible
party" includes the owner or operator of an onshore facility, vessel, or
pipeline, or the lessee or permittee of the area in which an offshore facility
is located. The OPA assigns liability to each responsible party for oil removal
costs and a variety of public and private damages. The FWPCA imposes
restrictions and strict controls regarding the discharge of produced waters and
other oil and natural gas wastes into navigable waters. State laws for the
control of water pollution also provide varying civil, criminal and
administrative penalties and impose liabilities in the case of a discharge of
petroleum or its derivatives, or other hazardous substances, into state waters.
In addition, the Environmental Protection Agency ("EPA") has promulgated
regulations that require many oil and natural gas production operations to
obtain permits to discharge storm water runoff.
The CAA requires or will require most industrial operations in the
United States to incur capital expenditures in order to meet air emission
control standards developed by the EPA and state environmental agencies.
Although no assurances can be given, the Company believes implementation of such
amendments will not have a material adverse effect on its financial condition or
results of operations. RCRA is the principal federal statute governing the
treatment, storage and disposal of hazardous wastes. RCRA imposes stringent
operating requirements (and liability for failure to meet such requirements) on
a person who is either a "generator" or "transporter" of hazardous waste or an
"owner" or "operator" of a hazardous waste treatment, storage or disposal
facility. At present, RCRA includes a statutory exemption that allows oil and
natural gas exploration and production wastes to be classified as non-hazardous
waste. As a result, the Partnership is
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not required to comply with a substantial portion of RCRA's requirements because
the its operations generate minimal quantities of hazardous wastes.
CERCLA, also known as "Superfund", imposes liability, without regard to
fault or the legality of the original act, on certain classes of persons that
contributed to the release of a "hazardous substance" into the environment.
These persons include the "owner" or "operator" of the site and companies that
disposed or arranged for the disposal of the hazardous substances found at the
site. CERCLA also authorizes the EPA and, in some instances, third parties to
act in response to threats to the public health or the environment and to seek
to recover from the responsible classes of persons the costs they incur. In the
course of its ordinary operations, the Partnership may generate waste that may
fall within CERCLA's definition of a "hazardous substance". As a result, the
Partnership may be jointly and severally liable under CERCLA or under analogous
state laws for all or part of the costs required to clean up sites at which such
wastes have been disposed. The Partnership currently owns or leases, and has in
the past owned or leased, numerous properties that for many years have been used
for the exploration and production of oil and natural gas. Although the
Partnership has utilized operating and disposal practices that were standard in
the industry at the time, hydrocarbons or other wastes may have been disposed of
or released on or under the properties owned or leased by the Partnership on or
under other locations where such wastes have been taken for disposal. In
addition, many of these properties have been operated by third parties whose
actions with respect to the treatment and disposal or release of hydrocarbons or
other wastes were not under the Partnership's control. These properties and
wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws.
Under such laws, the Partnership could be required to remove or remediate
previously disposed wastes (including wastes disposed of or released by prior
owners or operators), to clean up contaminated property (including contaminated
groundwater) or to perform remedial plugging operations to prevent future
contamination.
CAUTION AS TO FORWARD-LOOKING STATEMENTS
STATEMENTS CONTAINED IN THIS REPORT AND OTHER MATERIALS FILED OR TO BE
FILED BY THE PARTNERSHIP WITH THE SECURITIES AND EXCHANGE COMMISSION (AS WELL AS
INFORMATION INCLUDED IN ORAL OR OTHER WRITTEN STATEMENTS MADE OR TO BE MADE BY
THE COMPANY OR ITS REPRESENTATIVES) THAT ARE FORWARD-LOOKING IN NATURE ARE
INTENDED TO BE "FORWARD-LOOKING STATEMENTS" WITHIN THE MEANING OF SECTION 27A OF
THE SECURITIES ACT OF 1933, AS AMENDED, AND SECTION 21E OF THE SECURITIES
EXCHANGE ACT OF 1934, AS AMENDED, RELATING TO MATTERS SUCH AS ANTICIPATED
OPERATING AND FINANCIAL PERFORMANCE, BUSINESS PROSPECTS, DEVELOPMENTS AND
RESULTS OF THE PARTNERSHIP. ACTUAL PERFORMANCE, PROSPECTS, DEVELOPMENTS AND
RESULTS MAY DIFFER MATERIALLY FROM ANY OR ALL ANTICIPATED RESULTS DUE TO
ECONOMIC CONDITIONS AND OTHER RISKS, UNCERTAINTIES AND CIRCUMSTANCES PARTLY OR
TOTALLY OUTSIDE THE CONTROL OF THE PARTNERSHIP, INCLUDING RATES OF INFLATION,
NATURAL GAS PRICES, UNCERTAINTY OF RESERVE ESTIMATES, RATES AND TIMING OF FUTURE
PRODUCTION OF OIL AND GAS, EXPLORATORY AND DEVELOPMENT ACTIVITIES, ACQUISITION
RISKS AND ACTIVITIES, CHANGES IN THE LEVEL AND TIMING OF FUTURE COSTS AND
EXPENSES RELATED TO DRILLING AND OPERATING ACTIVITIES AND THOSE RISKS DESCRIBED
UNDER "RISK FACTORS" BELOW.
WORDS SUCH AS "ANTICIPATED," "EXPECT," "ESTIMATE," "PROJECT" AND
SIMILAR EXPRESSIONS ARE INTENDED TO IDENTIFY FORWARD-LOOKING STATEMENTS.
FORWARD-LOOKING STATEMENTS INCLUDE THE RISKS DESCRIBED IN "RISK FACTORS".
RISK FACTORS
The Partnership cautions that the following risk factors could affect
its actual results in the future, in addition to "Uncertainties in Estimating
Reserves" discussed elsewhere in this Report.
DEPLETION OF RESERVES. 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.
SUBSTANTIAL LEVERAGE. As of December 31, 1997, the Partnership has
total indebtedness for money borrowed of approximately $3,181,000 and partners'
equity of approximately $476,000. 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
8
<PAGE>
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. At present, the level of drilling activity in the
United States has resulted in increased demand for, and therefore increased
costs associated with, drilling equipment and the services and products of other
vendors to the industry. In particular, in connection with drilling activities
in the marshy regions of south Louisiana, there has been an increased cost of
drilling operations due to increased costs for barge rigs necessary to conduct
activity in such region. Moreover, the number of drilling contractors offering
barge drilling and workover services is limited.
The availability of a ready market for the Partnership's oil and
natural gas production also depends on a number of factors, including the demand
for and supply of oil and natural gas and the proximity of reserves to pipelines
or trucking and terminal facilities. Natural gas wells may be partially or
totally shut in for lack of a market or because of inadequacy or unavailability
of natural gas pipeline or gathering system capacity.
The Partnership's oil and natural gas business also is subject to all
of the operating risks associated with the drilling for and production of oil
and natural gas, including, but not limited to, uncontrollable flows of oil,
natural gas, brine or well fluids into the environment (including groundwater
and shoreline contamination), blowouts, cratering, mechanical difficulties,
fires, explosions, pollution and other risks, any of which could result in
substantial losses to the Partnership. Although the Partnership maintains
insurance at levels that it believes are consistent with industry practices, it
is not fully 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
KOGC, 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.
9
<PAGE>
PART II
ITEM 5. MARKET FOR UNITS AND RELATED UNITHOLDER MATTERS
There is no market for the Units of the Partnership, and transfer of
the Units is substantially restricted by the provisions of the Partnership
Agreement. As of February 28, 1998, there were 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.
DISTRIBUTIONS
---------------
1995:
First quarter .............................. --
Second quarter ............................. --
Third quarter .............................. $ .02
Fourth quarter ............................. --
1996:
First quarter .............................. --
Second quarter ............................. --
Third quarter .............................. --
Fourth quarter ............................. --
1997:
First quarter .............................. --
Second quarter ............................. --
Third quarter .............................. --
Fourth quarter ............................. --
1998:
First quarter .............................. --
The distribution for each quarter in which payments were made
represents substantially all of the Partnership's net available cash from the
preceding quarter's operations. Distribution levels are affected by numerous
factors, including oil and gas prices, production levels and operating costs,
together with any working capital or debt service requirements. 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."
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.
10
<PAGE>
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------------
1993 1994 1995 1996 1997
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
SUMMARY OF OPERATIONS:
Total revenues ......................... $ 2,925 $ 7,171 $ 5,713 $ 4,991 $ 2,322
Production expenses .................... 359 1,261 1,223 816 576
Exploration expenses ................... 14,278 2,706 148 (3) --
General and administrative expenses .... 146 599 474 325 476
Interest expense ....................... -- 157 672 810 376
Depreciation, depletion and amortization 4,416 8,497 4,945 1,280 587
Impairment of oil and gas properties ... -- 9,638 11,082 -- --
Net income (loss) ...................... (16,274) (15,687) (12,831) 1,763 307
Net income (loss) per Unit(1) .......... (.97) (.94) (.77) .11 .02
Distributions paid per Unit(1) ......... .06 .19 .02 -- --
Units outstanding ...................... 16,033 16,033 16,033 16,033 16,033
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------------
1993 1994 1995 1996 1997
-------- -------- -------- -------- --------
SUMMARY BALANCE SHEET DATA:
Working capital (deficit) ............. $ (2,260) $ (3,962) $ (1,857) $ 1,582 $ 288
Oil and gas properties, net ........... 25,550 21,417 6,263 3,987 3,369
Long term debt ........................ -- 6,000 6,000 5,400 3,181
Total partners' equity (deficit) ...... 23,290 11,455 (1,594) 169 476
Total assets .......................... 28,039 21,700 6,469 5,712 3,741
</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, 1997. 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 Kelly Oil & Gas Corporation ("KOGC"), 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.
PROPERTY IMPAIRMENT UNDER SFAS 121. In the fourth quarter of 1995, the
Partnership implemented the Financial Accounting Standards Board's Statement No.
121, "Accounting for the Impairment of Long-Lived Assets and for LongLived
Assets to be Disposed Of" ("SFAS 121"). Under SFAS 121, certain assets are
required to be reviewed periodically for impairment whenever circumstances
indicate their carrying amount exceeds their fair value and may not be
recoverable. As a result of a decline in its proved reserves at January 1, 1996
from year-earlier levels, the Partnership performed an assessment of the
carrying value of its oil and gas properties indicating an impairment should be
recognized at year end. Under this analysis, the fair value of the Partnership's
oil and gas properties was estimated on a depletable unit basis using
11
<PAGE>
escalated pricing and present value discount factors reflecting risk
assessments. Based on this analysis, the Partnership recognized a noncash
impairment charge of $8.7 million against the carrying value of its oil and gas
properties under SFAS 121 at December 31, 1995.
HEDGING ACTIVITIES. KOGC has periodically used forward sales contracts,
natural gas price swap agreements, natural gas basis swap agreements and options
to reduce exposure to downward price fluctuations on its natural gas production.
KOGC does not engage in speculative transactions. KOGC's hedging activities also
cover the oil and gas production attributable to the Partnership, including the
interest in such production of the public unitholders of the Partnership. During
1997, KOGC used price and basis swap agreements. Price swap agreements generally
provide for the Partnership to receive or make counterparty payments on the
differential between a fixed price and a variable indexed price for natural gas.
Basis swap agreements generally provide for the Partnership to receive or make
counterparty payments on the differential between a variable indexed price and
the price it receives from the sale of natural gas production, and are used to
hedge against unfavorable price movements in the relationship between such
variable indexed price and the price received for such production. Gains and
losses realized by the Partnership from hedging activities are included in oil
and gas revenues and average sales prices in the period that the related
production is sold.
Through natural gas price swap agreements, approximately 65% of the
Partnership's natural gas production for 1997 was affected by hedging
transactions at an average NYMEX quoted price of $2.35 per Mmbtu before
transaction and transportation costs. As of December 31, 1997, approximately 29%
of the Partnership's anticipated natural gas production for 1998 has been hedged
by natural gas price swap agreements at an average NYMEX quoted price of $2.30
per Mmbtu before transaction and transportation costs. Certain natural gas price
swap agreements outstanding at December 31, 1997 permit the counterparty to
double the contract volume at a specified price. If this feature is exercised on
all contracts outstanding at December 31, 1997, approximately 40% of the
Partnership's anticipated natural gas production for 1998 has been hedged by
natural gas price swap agreements at an average NYMEX quoted price of $2.31 per
Mmbtu before transaction and transportation costs. In addition, as of December
31, 1997, the Partnership had outstanding natural gas basis swap agreements
covering approximately 34% of its anticipated natural gas production for January
1998 through September 1998. Hedging activities decreased Partnership revenues
by approximately $156,000 in 1997 as compared to estimated revenues had no
hedging activities been conducted.
The credit risk exposure from counterparty nonperformance on natural
gas forward sales contracts and derivative financial instruments is generally
the amount of unrealized gains under the contracts. The Partnership has not
experienced counterparty nonperformance on these agreements and does not
anticipate any in future periods.
RESULTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 1997 AND 1996. Oil and gas revenues of
$2,322,000 for 1997 decreased 52% compared to $4,807,000 in the corresponding
period of 1996 primarily as a result of lower oil and gas production. Production
of natural gas decreased 48% from 1,838,000 Mcf in 1996 to 963,000 Mcf in 1997.
Production of crude oil in the current year totaled 11,395 barrels compared to
27,133 barrels last year, representing a decrease of 58%. Oil and gas production
decreased due to natural depletion and a reduction in the drilling of new wells
to offset that decline.
Lease operating expenses and severance taxes were $576,000 in 1997
versus $816,000 in 1996, a decrease of 29%, reflecting lower production levels.
On a unit of production basis, these expenses increased to $0.56 per Mcfe in
1997 from $0.41 per Mcfe in 1996.
General and administrative expenses of $476,000 in 1997 increased 46%
from $325,000 in 1996. On a unit of production basis, these expenses increased
from $0.16 per Mcfe in 1996 to $0.46 per Mcfe in 1997.
In 1997 and 1996, the Partnership incurred interest expense of $376,000
and $810,000, 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 1997 as
compared to 1996. See "Liquidity and Capital Resources" below.
12
<PAGE>
DD&A expense decreased 54% from $1,280,000 in 1996 to $587,000 in 1997
due to lower production levels and lower depletion rates. On a unit of
production basis, DD&A expense decreased to $0.57 per Mcfe in 1997 from $0.64
per Mcfe in 1996.
The Partnership recognized net income in 1997 of $307,000 or $0.02 per
Unit compared to net income in 1996 of $1,763,000 or $0.11 per Unit. The reasons
for the variance between 1997 and 1996 are described in the foregoing
discussion.
YEARS ENDED DECEMBER 31, 1996 AND 1995. Oil and gas revenues of
$4,807,000 in 1996 decreased 16% compared to $5,708,000 in 1995. Production of
natural gas decreased 33% to 1,838,000 Mcf in 1996 from 2,741,000 Mcf in 1995,
while the average price of natural gas increased 28% to $2.27 per Mcf in 1996
from $1.77 per Mcf in 1995. Production of crude oil in 1996 totaled 27,133
barrels, with an average sales price of $21.74 per barrel, compared to 40,936
barrels at $18.66 per barrel in 1995 the prior year, representing a volume
decrease of 34% and a price increase of 17%. The decrease in oil and gas
production and revenues in 1996 reflects remedial requirements for several
wells, normal depletion of other wells and the sale of 50% of the Partnership's
interest in four wells, effective December 1, 1996.
Lease operating expenses and severance taxes were $816,000 in 1996 and
$1,223,000 in 1995, a decrease of 33%, reflecting lower production levels and
reduced workover costs. On a unit of production basis, these expenses remained
constant at $0.41 per Mcfe in 1996 and 1995.
General and administrative expenses of $325,000 in 1996 decreased 31%
from $474,000 in 1995, reflecting a reduction in the Partnership's share of
administration costs associated with development operations of Kelley. On a unit
of production basis, these expenses remained constant at $0.16 per Mcfe in 1996
and 1995.
In 1995 and 1996, the Partnership incurred interest expenses of
$672,000 and $810,000, respectively, on a loan advanced in August 1994 to fund
part of its drilling expenses in excess of contributed capital. See "Liquidity
and Capital Resources" below.
Depreciation, depletion and amortization ("DD&A") decreased 74% from
$4,945,000 in 1995 to $1,280,000 in 1996 due to lower production levels and
lower depletion rates following noncash impairment charges aggregating
$8,747,000 recognized in the fourth quarter of 1995 against the carrying value
of the Partnership's oil and gas properties under SFAS 121. See
"General-Property Impairment under SFAS 121" above. On a unit of production
basis, DD&A decreased to $0.64 per Mcfe in 1996 from $1.66 per Mcfe in 1995.
The Partnership realized net income in 1996 of $1,763,000 or $0.11 per
Unit compared to a net loss of $12,831,000 or $0.77 per Unit in 1995, reflecting
the foregoing developments.
LIQUIDITY AND CAPITAL RESOURCES
LIQUIDITY. Net cash provided by the Partnership's operating activities
during 1997, as reflected on its statement of cash flows, totaled $2,166,000.
During the period, funds used in financing activities included a reduction in
the loan principal of $2,219,000. As a result of these activities, the
Partnership's cash and cash equivalents were reduced to zero at December 31,
1997 from $22,000 at December 31, 1996.
CAPITAL RESOURCES. The partners' equity at December 31, 1997 increased
to $476,000 as compared to $169,000 at December 31, 1996. 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, 1997, the Partnership was fully capitalized with contributions
aggregating $50,082,285.
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 KOGC's
borrowing cost resulting in
13
<PAGE>
an effective rate of 11.2%, 13.5% and 103/8% for 1995, 1996 and 1997,
respectively. On December 31, 1996 the interest rate for the Initial Loan was
reduced to 103/8% following the repayment of KOGC's 13 1/2% Senior Notes, which
were replaced by 103/8% Senior Subordinated Notes during the fourth quarter.
In December 1996, KOGC entered into a new revolving credit facility
with a group of banks, as amended December 1, 1997 (the "Credit Facility"). The
agreement for the Credit Facility provides for a maximum $140 million ($125
million prior to amendment) revolving credit loan, which requires the payment of
interest only until December 2000, when all borrowings will be repayable. The
Partnership and Joint Venture are guarantors under the Credit Facility. The
Credit Facility is secured by all the oil and gas properties and other assets of
KOGC and its subsidiaries, including the Partnership and the Joint Venture. The
agreement covering the Credit Facility provides various financial covenants as
well as restrictions on additional debt, mergers and asset sales, but limits the
lenders' recourse upon any default to Partnership and Joint Venture assets
attributable to Kelley Oil's interests in the Partnership. At December 31, 1997
the borrowing base was $138 million.
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. 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, 1997, $3,181,000 of the $6,000,000 Initial
Loan remained outstanding. By continuing to service its debt from operating cash
flow, the Partnership expects to further reduce the outstanding balance of the
Initial Loan in 1998.
The Partnership does not anticipate that it will incur any significant
expenditures to address Year 2000 issues, nor do Year 2000 issues represent a
known material event or uncertainty to it. To the extent that the Partnership
may be adversely affected by the Year 2000 issues of its suppliers, customers
and other entities generally, it does not believe that it will be more adversely
affected than other companies in its industry with similar operations.
INFLATION AND CHANGING PRICES. Oil and natural gas prices, as with most
commodities, are highly volatile, have fluctuated during recent years and
generally have not followed the same pattern as inflation. The following table
shows the changes in the average oil and gas prices received by Partnership
during the periods indicated.
AVERAGE AVERAGE
OIL PRICE GAS PRICE
($/BBL) ($/MCF)
--------- ---------
YEAR ENDED:
December 31, 1995 ................. $ 18.66 $ 1.77
December 31, 1996 ................. 21.74 2.27
December 31, 1997 ................. 19.92 2.18
14
<PAGE>
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............................................................................... 16
Balance Sheets - December 31, 1996 and 1997................................................................ 17
Statements of Operations - For the years ended December 31, 1995, 1996 and 1997............................ 18
Statements of Cash Flows - For the years ended December 31, 1995, 1996 and 1997............................ 19
Statements of Changes in Partners' Equity (Deficit) - For the years ended
December 31, 1995, 1996 and 1997....................................................................... 20
Notes to Financial Statements.............................................................................. 21
</TABLE>
15
<PAGE>
INDEPENDENT AUDITORS' REPORT
To the Partners of Kelley Partners 1992 Development Drilling Program
We have audited the accompanying balance sheets of Kelley Partners 1992
Development Drilling Program (a Texas limited partnership) as of December 31,
1996 and 1997, 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, 1997. These financial statements are the responsibility of the
Partnership's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all
material respects, the financial position of Kelley Partners 1992 Development
Drilling Program as of December 31, 1996 and 1997, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1997, in conformity with generally accepted accounting principles.
As discussed in Note 1 to the financial statements, in 1995 the
Partnership changed its method of accounting for the impairment of long-lived
assets to conform with Statement of Financial Accounting Standards No. 121.
DELOITTE & TOUCHE LLP
Houston, Texas
March 6, 1998
16
<PAGE>
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
BALANCE SHEETS
(IN THOUSANDS)
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------
1996 1997
-------- --------
<S> <C> <C>
ASSETS:
Cash and cash equivalents ................................. $ 22 $ --
Accounts receivable - trade ............................... 126 30
Accounts receivable - affiliates .......................... 1,577 342
-------- --------
Total current assets .................................... 1,725 372
-------- --------
Oil and gas properties, successful efforts method:
Properties subject to amortization ...................... 44,333 44,302
Less: Accumulated depreciation, depletion & amortization (40,346) (40,933)
-------- --------
Total oil and gas properties ............................ 3,987 3,369
-------- --------
Total assets .............................................. $ 5,712 $ 3,741
======== ========
LIABILITIES:
Accounts payable and accrued expenses ..................... $ 143 $ 84
-------- --------
Total current liabilities ............................... 143 84
-------- --------
Long term note payable - affiliate ........................ 5,400 3,181
-------- --------
Total liabilities ....................................... 5,543 3,265
-------- --------
PARTNERS' EQUITY:
LP Unitholders' equity (deficit) .......................... (9) 21
GP Unitholders' equity .................................... 171 436
Managing and Special General Partners' equity ............. 7 19
-------- --------
Total partners' equity .................................. 169 476
-------- --------
Total liabilities and partners' equity .................... $ 5,712 $ 3,741
======== ========
</TABLE>
See Notes to Financial Statements.
17
<PAGE>
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER UNIT DATA)
YEAR ENDED DECEMBER 31,
--------------------------------
1995 1996 1997
-------- -------- --------
REVENUES:
Oil and gas sales ...................... $ 5,708 $ 4,807 $ 2,322
Interest and other income .............. 5 184 --
-------- -------- --------
Total revenues ....................... 5,713 4,991 2,322
-------- -------- --------
COSTS AND EXPENSES:
Lease operating expenses ............... 889 624 474
Severance taxes ........................ 334 192 102
Exploration expenses ................... 148 (3) --
General and administrative expenses .... 474 325 476
Interest expense ....................... 672 810 376
Depreciation, depletion and amortization 4,945 1,280 587
Impairment of oil and gas properties ... 11,082 -- --
-------- -------- --------
Total expenses ....................... 18,544 3,228 2,015
-------- -------- --------
NET INCOME (LOSS) ......................... $(12,831) $ 1,763 $ 307
======== ======== ========
NET INCOME (LOSS) ALLOCABLE TO LP
AND GP UNITHOLDERS ..................... $(12,323) $ 1,694 $ 295
======== ======== ========
NET INCOME (LOSS) ALLOCABLE TO MANAGING AND
SPECIAL GENERAL PARTNERS ............... $ (508) $ 69 $ 12
======== ======== ========
NET INCOME (LOSS) PER LP AND GP UNIT ...... $ (.77) $ .11 $ .02
======== ======== ========
Average LP and GP Units outstanding ....... 16,033 16,033 16,033
======== ======== ========
See Notes to Financial Statements.
18
<PAGE>
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------
1995 1996 1997
-------- -------- --------
<S> <C> <C> <C>
OPERATING ACTIVITIES:
Net income (loss) .................................... $(12,831) $ 1,763 $ 307
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation, depletion and amortization .......... 4,945 1,280 587
Impairment of oil and gas properties .............. 11,082 -- --
Exploration expenses .............................. 148 (3) --
Gain on sale of oil and gas properties ............ -- (182) --
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable ...... 261 (734) 1,331
Decrease (increase) in other assets ............. (8) 21 --
Decrease in accounts payable and accrued expenses (2,376) (2,718) (59)
-------- -------- --------
Net cash provided by (used in) operating activities .. 1,221 (573) 2,166
-------- -------- --------
INVESTING ACTIVITIES:
Capital expenditures ................................. (1,544) (239) (41)
Proceeds from sale of assets ......................... 523 1,420 72
-------- -------- --------
Net cash provided by (used in) investing activities .. (1,021) 1,181 31
-------- -------- --------
FINANCING ACTIVITIES:
Capital contributed by partners ...................... 115 -- --
Payments on long-term borrowings ..................... -- (600) (2,219)
Distributions to partners ............................ (333) -- --
-------- -------- --------
Net cash used in financing activities ................ (218) (600) (2,219)
-------- -------- --------
Increase (decrease) in cash and cash equivalents ..... (18) 8 (22)
Cash and cash equivalents, beginning of period ....... 32 14 22
-------- -------- --------
Cash and cash equivalents, end of period ............. $ 14 $ 22 $ --
======== ======== ========
</TABLE>
See Notes to Financial Statements.
19
<PAGE>
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
STATEMENTS OF CHANGES IN PARTNERS' EQUITY (DEFICIT)
(IN THOUSANDS)
<TABLE>
<CAPTION>
MANAGING
AND
SPECIAL
LP GP GENERAL
UNITHOLDERS UNITHOLDERS PARTNERS TOTAL
------------ ------------ ------------ ------------
<S> <C> <C> <C> <C>
Partners' equity at January 1, 1995 ............... $ 1,112 $ 9,884 $ 459 $ 11,455
------------ ------------ ------------ ------------
Capital contributed ............................... -- 115 -- 115
Distributions ..................................... (33) (287) (13) (333)
Net loss .......................................... (1,262) (11,061) (508) (12,831)
------------ ------------ ------------ ------------
Partners' deficit at December 31, 1995 .......... (183) (1,349) (62) (1,594)
------------ ------------ ------------ ------------
Net income ........................................ 174 1,520 69 1,763
------------ ------------ ------------ ------------
Partners' equity (deficit) at December 31, 1996 . (9) 171 7 169
------------ ------------ ------------ ------------
Net income ........................................ 30 265 12 307
------------ ------------ ------------ ------------
Partners' equity at December 31, 1997 ........... $ 21 $ 436 $ 19 $ 476
============ ============ ============ ============
</TABLE>
See Notes to Financial Statements.
20
<PAGE>
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
NOTES TO FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
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.
The general partners own in the aggregate a 3.96% general partner
interest in the Partnership. In addition, as of December 31, 1997, 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.
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. In the fourth quarter of 1995, the
Partnership implemented the Financial Accounting Standards Board's Statement No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of" ("FAS 121"). Under FAS 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 a decline in its proved reserves at January 1, 1996
from year-earlier levels, the Partnership performed an assessment of the
carrying value of its oil and gas properties indicating an impairment should be
recognized at year end. Under this analysis, the fair value of the Partnership's
oil and gas properties was estimated on a depletable unit basis using escalated
pricing and present value discount factors reflecting risk assessments. Based on
this analysis, the Partnership recognized a noncash impairment charge of
$8,747,000 against the carrying value of its oil and gas properties under FAS
121 at December 31, 1995.
21
<PAGE>
OIL AND GAS REVENUES. The Partnership recognizes oil and gas revenue
from its interests in producing wells as oil and gas is produced and sold from
those wells. Oil and gas sold is not significantly different from the
Partnership's production entitlement.
NET INCOME OR LOSS PER UNIT. Net income or loss per Unit is computed
based on the weighted average number of Units outstanding during the period
divided into the net income or loss allocable to the Unitholders.
FINANCIAL INSTRUMENTS. The Partnership's financial instruments consist
of cash and cash equivalents, receivables, payables and debt. As of December 31,
1997, the estimated fair value of the Partnership's debt approximated its
carrying value. The estimated fair values at December 31, 1997 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 5 - "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. Based upon the provisions of SFAS
130, it is anticipated that the Partnership will not have a significant change
in its reporting requirements.
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.
RISKS AND UNCERTAINTIES. The preparation of financial statements in
conformity with generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts of assets and
liabilities 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 1995 and
1996 have been reclassified to conform to the 1997 presentation.
NOTE 2 - 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 Kelley's
borrowing cost resulting in an effective rate of 11.2%, 13.5% and 103/8 % for
1995, 1996 and 1997, respectively. On December 31, 1996, the interest rate for
the Initial Loan was reduced to 103/8% following the repayment of KOGC's 13 1/2%
Senior Notes, which were replaced by 103/8% 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, 1997, $3,181,000 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 1998.
22
<PAGE>
In December 1996, KOGC entered into a new revolving credit facility
with a group of banks, as amended December 1, 1997 (the "Credit Facility"). The
agreement for the Credit Facility provides for a maximum $140 million ($125
million prior to amendment) revolving credit loan, which requires the payment of
interest only until December 2000, when all borrowings will be repayable. The
Partnership and Joint Venture are guarantors under the Credit Facility. The
Credit Facility is secured by all the oil and gas properties and other assets of
KOGC and its subsidiaries, including the Partnership and the Joint Venture. The
agreement covering the Credit Facility provides various financial covenants as
well as restrictions on additional debt, mergers and asset sales, but limits the
lenders' recourse upon any default to Partnership and Joint Venture assets
attributable to Kelley Oil's interests in the Partnership. At December 31, 1997
the borrowing base was $138 million.
NOTE 3 - CASH DISTRIBUTIONS
The following table sets forth, for the periods indicated, the
distributions per Unit. Cash distributions were paid in the quarter indicated
and were based upon net available cash generated from operations in the
preceding quarter.
1995 1996 1997
-------- -------- ---------
First quarter ....................... $ -- $ -- $ --
Second quarter ...................... -- -- --
Third quarter ....................... .02 -- --
Fourth quarter ...................... -- -- --
-------- -------- ---------
Totals ........................... $ .02 $ -- $ --
======== ======== =========
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 2 - Long-Term
Debt.
NOTE 4 - 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, 1995, 1996 and 1997, these costs aggregated $220,000,
$1,000, and zero, respectively. The Partnership capitalized $77,000, $1,000 and
zero of allocated direct costs to oil and gas properties for the years ended
December 31, 1995, 1996 and 1997, respectively.
Overhead allocated to the Partnership by Kelley Oil for the years ended
December 31, 1995, 1996 and 1997 related to general and administrative expenses
aggregated $391,000, $227,000 and $476,000, respectively.
Substantially all gas sales of KOGC 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 1995, 1996 and 1997, the fee was 2% of
the resale price for marketed natural gas.
NOTE 5 - HEDGING ACTIVITIES
KOGC has periodically used forward sales contracts, natural gas price
swap agreements, natural gas basis swap agreements and options to reduce
exposure to downward price fluctuations on its natural gas production. KOGC does
not engage in speculative transactions. KOGC's hedging activities also cover the
oil and gas production attributable to the Partnership, including the interest
in such production of the public unitholders of the Partnership. During 1997,
the KOGC used price and basis swap agreements. Price swap agreements generally
provide for the Partnership to receive or make
23
<PAGE>
counterparty payments on the differential between a fixed price and a variable
indexed price for natural gas. Basis swap agreements generally provide for the
Partnership to receive or make counterparty payments on the differential between
a variable indexed price and the price it receives from the sale of natural gas
production, and are used to hedge against unfavorable price movements in the
relationship between such variable indexed price and the price received for such
production. Gains and losses realized by the Partnership from hedging activities
are included in oil and gas revenues and average sales prices in the period that
the related production is sold.
Through natural gas price swap agreements, approximately 65% of the
Partnership's natural gas production for 1997 was affected by its hedging
transactions at an average NYMEX quoted price of $2.35 per Mmbtu before
transaction and transportation costs. As of December 31, 1997, approximately 29%
of the Partnership's anticipated natural gas production for 1998 has been hedged
by natural gas price swap agreements at an average NYMEX quoted price of $2.30
per Mmbtu before transaction and transportation costs. Certain natural gas price
swap agreements outstanding at December 31, 1997 permit the counterparty to
double the contract volume at a specified price. If this feature is exercised on
all contracts outstanding at December 31, 1997, approximately 40% of the
Partnership's anticipated natural gas production for 1998 has been hedged by
natural gas price swap agreements at an average NYMEX quoted price of $2.31 per
Mmbtu before transaction and transportation costs. In addition, as of December
31, 1997, the Partnership had outstanding natural gas basis swap agreements
covering approximately 34% of its anticipated natural gas production for January
1998 through September 1998. Hedging activities decreased Partnership revenues
by approximately $156,000 in 1997 as compared to estimated revenues had no
hedging activities been conducted.
The credit risk exposure from counterparty nonperformance on natural
gas forward sales contracts and derivative financial instruments is generally
the amount of unrealized gains under the contracts. The Partnership has not
experienced counterparty nonperformance on these agreements and does not
anticipate any in future periods.
NOTE 6 - SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND GAS EXPLORATION,
DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)
This section provides information required by Statement of Financial
Accounting Standards No. 69, "Disclosures about Oil and Gas Producing
Activities."
CAPITALIZED COSTS. Capitalized costs and accumulated depreciation,
depletion and amortization relating to oil and gas producing activities, all of
which are conducted within the continental United States, are summarized below.
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------
1995 1996 1997
-------- -------- --------
<S> <C> <C> <C>
Unevaluated properties ............................. $ -- $ -- $ --
Evaluated properties subject to amortization ....... 45,230 44,333 44,302
-------- -------- --------
Total properties subject to amortization ........ 45,230 44,333 44,302
Accumulated depreciation, depletion and amortization (38,967) (40,346) (40,933)
-------- -------- --------
Net capitalized costs ........................... $ 6,263 $ 3,987 $ 3,369
======== ======== ========
</TABLE>
COSTS INCURRED. All costs were incurred in oil and gas property
development activities (as defined in the Partnership Agreement) and aggregated
$1,544,000, $239,000 and $41,000 in 1995, 1996 and 1997, respectively.
RESERVES. The following table summarizes the Partnership's net
ownership interests in estimated quantities of proved oil and gas reserves and
changes in net proved reserves, all of which are located in the continental
United States, for the years ended December 31, 1995, 1996 and 1997 are
summarized below. Reserves estimates contained below were
24
<PAGE>
prepared by H.J. Gruy & Associates, Inc. ("Gruy"), independent petroleum
engineers. See "Estimated Proved Reserves-Uncertainties in Estimating Reserves"
under Items 1 and 2 of this Form 10-K.
<TABLE>
<CAPTION>
CRUDE OIL, CONDENSATE
AND NATURAL GAS LIQUIDS NATURAL GAS
(MBBLS) (MMCF)
----------------------------------- -----------------------------------
1995 1996 1997 1995 1996 1997
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Proved developed and undeveloped reserves:
Beginning of year ..................... 290 201 102 14,827 10,220 7,537
Revisions of previous estimates ....... (48) (4) (13) (1,317) (289) (1,053)
Extensions and discoveries ............ -- -- -- -- 251 --
Sale of oil and gas properties ........ -- (68) -- (549) (807) --
Production ............................ (41) (27) (11) (2,741) (1,838) (963)
--------- --------- --------- --------- --------- ---------
End of year ......................... 201 102 78 10,220 7,537 5,521
========= ========= ========= ========= ========= =========
Proved developed reserves
at end of year ........................ 201 102 78 10,220 7,537 5,521
========= ========= ========= ========= ========= =========
</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,
--------------------------------
1995 1996 1997
-------- -------- --------
<S> <C> <C> <C>
Future cash inflows ...................................... $ 25,546 $ 29,709 $ 15,157
Future production costs .................................. (5,502) (3,141) (3,750)
Future development costs ................................. (60) (77) (254)
-------- -------- --------
Future net cash flows .................................. 19,984 26,491 11,153
10% annual discount for estimating timing of cash flows .. (7,090) (10,771) (4,535)
-------- -------- --------
Standardized measure of discounted future net cash flows $ 12,894 $ 15,720 $ 6,618
======== ======== ========
</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.
25
<PAGE>
The standardized measure of discounted future net cash flows as of
December 31, 1995, 1996 and 1997 was calculated using prices in effect as of
those dates, which averaged $19.73, $25.36 and $17.01, respectively, per barrel
of oil and $2.11, $3.72 and $2.49, respectively, per Mcf of natural gas.
CHANGES IN STANDARDIZED MEASURE. Changes in standardized measure of
future net cash flows relating to proved oil and gas reserves are summarized
below.
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------
1995 1996 1997
-------- -------- --------
<S> <C> <C> <C>
Changes due to current year operations:
Sales of oil and gas, net of production costs ............ $ (4,485) $ (3,991) $ (1,746)
Sales of reserves in place ............................... (339) (1,321) --
Extensions and discoveries, net of future production costs -- 310 --
Development costs incurred during the year ............... 493 242 24
Changes due to revisions in standardized variables:
Prices and production costs .............................. 2,703 7,765 (6,699)
Revisions of previous quantity estimates ................. 31 (739) (1,279)
Estimated future development costs ....................... (1,202) (230) (133)
Accretion of discount .................................... 1,544 1,289 1,572
Production rates (timing) and other ...................... (1,288) (499) (841)
-------- -------- --------
Net increase (decrease) ................................ (2,543) 2,826 (9,102)
Beginning of year ........................................... 15,437 12,894 15,720
-------- -------- --------
End of year ................................................. $ 12,894 $ 15,720 $ 6,618
======== ======== ========
</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 57 employees as of December 31, 1997, and its staff includes
employees experienced in geology, geophysics, petroleum engineering, land
acquisition and management, finance, accounting, and administration.
BACKGROUND OF KELLEY OIL
Kelley Oil is 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 KOGC.
26
<PAGE>
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>
John F. Bookout................. 75 President, Chief Executive Officer and a director 1996
David C. Baggett................ 36 Senior Vice President and Chief Financial Officer and a director 1997
Dallas D. Laumbach.............. 61 Senior Vice President-Exploration and Production and a director 1996
Thomas E. Baker................. 67 General Counsel and Corporate Secretary 1996
</TABLE>
JOHN F. BOOKOUT joined Kelley Oil as Chairman of the Board, President
and Chief Executive Officer in February 1996. He served as Chairman of the Board
of Contour Production Company L.L.C. ("Contour") since its inception in 1993.
From 1988 through 1993, he served as a member of the Supervisory Board of Royal
Dutch Petroleum. He currently serves on the board of directors of McDermott
International Inc., J. Ray McDermott, S.A. and The Investment Company of America
as well as the board of trustees of the United States Counsel for International
Business and various civic and educational bodies.
DAVID C. BAGGETT was elected Senior Vice President and Chief Financial
Officer and a director of Kelley Oil in March 1997. Previously, he was a partner
with Deloitte & Touche LLP for more than five years.
DALLAS D. LAUMBACH has served as Senior Vice President-Exploration and
Production and a director of Kelley Oil since February 1996 and has served
concurrently as President of Concorde Gas, Inc. since August 1996. He previously
served as Senior Vice President of Contour commencing in December 1993. Before
joining Contour, Mr. Laumbach served in positions of increasing responsibility
for 24 years at Shell Oil Company, concluding as Manager-Business Development in
Shell's Head Office.
THOMAS E. BAKER is an attorney and joined Kelley Oil in July 1996 as
General Counsel and Corporate Secretary. From August 1991 through June 1996, Mr.
Baker was engaged in a private consulting practice.
BENEFICIAL OWNERSHIP REPORTING
Not applicable.
ITEM 11. EXECUTIVE COMPENSATION
Not applicable. See "Certain Relationships and Related Transactions."
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
BENEFICIAL OWNERS
The following table sets forth information as of December 31, 1997 with
respect to the only Unitholder known by the Partnership to own beneficially more
than five percent of the Partnership's Units.
27
<PAGE>
AMOUNT & NATURE
NAME AND ADDRESS OF OF BENEFICIAL PERCENT
BENEFICIAL OWNER OWNERSHIP OF CLASS
Kelley Oil Corporation 13,422,310 83.72%
601 Jefferson, Suite 1100 Direct
Houston, Texas 77002
MANAGEMENT
The following table sets forth information as of December 31, 1997 with
respect to Units beneficially owned, directly or indirectly, by each of the
directors of Kelley Oil and by all officers and directors of Kelley Oil as a
group.
AMOUNT & NATURE
NAME AND ADDRESS OF OF BENEFICIAL PERCENT
BENEFICIAL OWNER OWNERSHIP(1) OF CLASS
John F. Bookout -- --
Dallas D. Laumbach -- --
David C. Baggett -- --
All directors and officers
as a group (8 persons) None None
(1) Represents direct beneficial ownership.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The Unitholders have a 96.04% share and the General Partners a 3.96%
share in the costs and revenues of the Partnership. Allocations of costs and
revenues to Unitholders are made in accordance with the number of Units owned.
The General Partners contributed $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 4 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.
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.
28
<PAGE>
(3) EXHIBITS:
EXHIBIT
NUMBER: EXHIBIT
4.1 Amended and Restated Agreement of Limited Partnership of
the Registrant (included as Exhibit A to the Prospectus
forming part of the Registrant's Registration Statement on
Form S-1 (File No. 33-51250) 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).
(b) REPORTS ON FORM 8-K:
No reports on Form 8-K were filed by the Registrant during the fourth
quarter of 1997.
29
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized, this 30th day of
March, 1998.
<TABLE>
<CAPTION>
<S> <C>
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
By: KELLEY OIL CORPORATION, Managing General Partner
By: /S/ JOHN F. BOOKOUT By: /S/ DAVID C. BAGGETT By: /S/ KENNETH R. BICKETT
John F. Bookout David C. Baggett Kenneth R. Bickett
Chief Executive Officer Senior Vice President Controller
and Chief Financial Officer (Chief Accounting Officer)
</TABLE>
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed as of the 30th day of March, 1998 by the following
persons in their capacity as directors of the Registrant's managing general
partner.
/S/ JOHN F. BOOKOUT /S/ DALLAS D. LAUMBACH
John F. Bookout Dallas D. Laumbach
/S/ DAVID C. BAGGETT
David C. Baggett
30
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> DEC-31-1997
<CASH> 0
<SECURITIES> 0
<RECEIVABLES> 372
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 372
<PP&E> 44,302
<DEPRECIATION> 40,933
<TOTAL-ASSETS> 3,741
<CURRENT-LIABILITIES> 84
<BONDS> 3,181
0
0
<COMMON> 0
<OTHER-SE> 476
<TOTAL-LIABILITY-AND-EQUITY> 3,741
<SALES> 2,322
<TOTAL-REVENUES> 2,322
<CGS> 0
<TOTAL-COSTS> 576
<OTHER-EXPENSES> 1,063
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 376
<INCOME-PRETAX> 307
<INCOME-TAX> 0
<INCOME-CONTINUING> 307
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 307
<EPS-PRIMARY> .02
<EPS-DILUTED> .02
</TABLE>
