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, 1996 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. [X]
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 1996, recompletion and
work-over operations were conducted on three wells, and one-half of the
Partnership's interests in four wells were sold. From its inception through
1996, the Partnership produced 8.6 Bcf of natural gas and 172,517 barrels of oil
and natural gas liquids, generating total oil and gas revenues of $20,106,000,
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 is an independent oil and gas company with principal executive
offices in Houston, Texas. As Managing General Partner, Kelley Oil makes all
decisions regarding the business and operations of the Partnership. The
Partnership
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has no employees and utilizes the officers and staff of Kelley Oil to perform
all management and administrative functions. Kelley Oil's staff includes
employees experienced in geology, geophysics, petroleum engineering, land
acquisition and management, finance and accounting. Kelley Oil is also the
managing general partner of Kelley Operating. See "Employees" below and
"Directors and Executive Officers of Kelley Oil Corporation."
The General Partners receive no management or other fees or promoted
interests from the Partnership or the Joint Venture. The Partnership reimburses
Kelley Oil for all direct costs incurred in managing the Partnership and all
indirect costs allocable to the Partnership, principally comprised of general
and administrative expenses. These arrangements are the same for all development
drilling programs ("DDPs") sponsored by Kelley Oil.
ESTIMATED PROVED RESERVES
GENERAL. Reserve estimates contained herein were prepared by H. J. Gruy &
Associates, Inc. ("Gruy") independent petroleum engineers, as of January 1, 1997
and 1996, and were prepared by Kelley Oil and reviewed by Gruy at January 1,
1995.
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 for the years ended December
31, 1994, 1995 and 1996 and principal components of the changes in the
quantities of reserves for each of the periods then ended. 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,
-------------------------------
1995 1996 1997
------ ------ -----
Crude oil and liquids (Mbbl):
Proved developed ....................... 290 201 102
Proved undeveloped ..................... -- -- --
------ ------ -----
Total proved .......................... 290 201 102
====== ====== =====
Natural gas (Mmcf):
Proved developed ....................... 14,827 10,220 7,537
Proved undeveloped ..................... -- -- --
------ ------ -----
Total proved .......................... 14,827 10,220 7,537
====== ====== =====
Detailed information concerning the Partnership's estimated proved
reserves and discounted net future cash flows is contained in the Supplementary
Financial Information included in Note 7 to the Partnership's Financial
Statements. The Partnership has not filed any estimates of reserves with any
federal authority or agency during the past year other than estimates contained
in its last annual report filed with the 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
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attributable to any particular group of properties, classifications of such
reserves based on risk of recovery and estimates of the future net revenues
expected therefrom prepared by different engineers or by the same engineers at
different times may vary substantially. Consequently, reserve estimates are
subject to revision as additional data becomes available during the producing
life of a reservoir. There also can be no assurance that the reserves set forth
herein will ultimately be produced or that the proved undeveloped reserves set
forth herein will be developed within the periods anticipated. In addition, the
estimates of future net revenues from proved reserves of Kelley and the present
value thereof are based upon certain assumptions about future production levels,
prices and costs that may not be correct when judged against actual subsequent
experience.
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, 1997 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, 1997 1996 PRODUCTION
------------------------------------ ---------------------------------------
GAS GAS
OIL GAS EQUIVALENT OIL GAS EQUIVALENT
PROPERTY (MBBLS) (MMCF) (MMCFE) % (MBBLS) (MMCF) (MMCFE) %
--- ----- ----- ----- -- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C>
NORTH LOUISIANA:
Ada field .................................... 1 634 640 7.9 -- 135 135 6.7
Sailes field ................................. 7 4,310 4,352 53.4 2 807 819 40.9
Sibley field ................................. 12 1,244 1,316 16.1 -- 126 126 6.3
West Bryceland field ......................... -- 47 47 .6 -- 10 10 .5
SOUTH LOUISIANA(1):
Orange Grove/Humphreys field ................. 4 328 352 4.3 4 289 313 15.7
Ouiski Bayou field ........................... 76 701 1,157 14.2 15 164 254 12.7
OTHER:
As a group ................................... 2 273 285 3.5 6 307 343 17.2
--- ----- ----- ----- -- ----- ----- -----
Total ..................................... 102 7,537 8,149 100.0 27 1,838 2,000 100.0
=== ===== ===== ===== == ===== ===== =====
</TABLE>
- ---------------
(1) Effective December 1, 1996, Kelley entered into a joint venture
whereby it sold 50% of its net acreage position as well as 50% of its interest
in 23 wells and related facilities in the Houma Embayment, including in the
Orange Grove/Humphreys and Ouiski Bayou fields. The sale included interest in
four Partnership wells. See "Management's Discussion and Analysis of Financial
Position and Results of Operations."
ADDITIONAL INFORMATION REGARDING THESE FIELDS IS SET FORTH BELOW.
UNLESS OTHERWISE NOTED, ACREAGE AND WELL INFORMATION IS PROVIDED AS OF DECEMBER
31, 1996, AND RESERVE INFORMATION IS PROVIDED AS OF JANUARY 1, 1997:
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.
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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.
WEST BRYCELAND FIELD. The West Bryceland field is located in Bienville
Parish, Louisiana. The Partnership has interests 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
severance taxes) per equivalent unit of oil and gas produced by the Partnership
for the years ended December 31, 1994, 1995 and 1996. Detailed additional
information concerning the Partnership's oil and gas producing activities is
contained in the Supplementary Financial Information included in Note 7 to the
Partnership's Financial Statements.
OIL AND GAS PRODUCTION
YEAR ENDED DECEMBER 31,
------------------------
1994 1995 1996
------ ------ ------
Crude oil, condensate and natural gas liquids (Bbls) 73,706 40,936 27,133
Natural gas (Mmcf) .................................. 3,198 2,741 1,838
AVERAGE SALES PRICES AND PRODUCTION COSTS
YEAR ENDED DECEMBER 31,
-------------------------------
1994 1995 1996
-------- -------- -------
Average sales price:
Crude oil, condensate and natural
gas liquids (Bbl) .................... $ 16.59 18.66 21.74
Natural gas (Mcf) ...................... 1.83 1.77 2.27
Oil and gas revenues per Mcfe .......... 1.95 1.91 2.40
Average production costs per Mcfe ...... .35 .41 .41
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OIL AND GAS WELLS
As of December 31, 1996, 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
-------- ---- ---------- ---- ---------- ---- ---------- ----
<C> <C> <C> <C> <C> <C> <C> <C> <C>
1994.... 10 1 2 1 3.29 .66 .86 .67
1995.... -- -- -- -- -- -- -- --
1996.... -- -- -- -- -- -- -- --
</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 KOGC and its subsidiaries is sold to
various purchasers typically in the areas where the natural gas is produced. the
Partnership currently is able to sell, under contract or in the spot market, all
of its natural gas at current market prices. Substantially all of the
Partnership's natural gas is sold under short-term contracts or contracts
providing for periodic adjustments or in the spot market. 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 KOGC 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 and monitoring functions. In addition, a subsidiary of the Company
coordinates the connection of newly drilled wells to various pipeline systems,
performs gas market surveys and oversees gas balancing with its various gas
gatherers and transporters. During 1995 and 1996, a subsidiary of the Company
received from certain of its subsidiaries and from unrelated customers a
marketing fee of 2% of the resale price for marketed natural gas. The Company
consideres these arrangements customary among natural gas producers and their
marketing affiliates.
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 these
constraints in the future. In that event, the Partnership would be forced to
seek alternate sources of transportation and may face increased costs.
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HEDGING OF NATURAL GAS
Kelley periodically has used forward sales contracts, natural gas swap
agreements and options to reduce exposure to downward price fluctuations on its
natural gas production. The swap agreements generally provide for Kelley to
receive or make counterparty payments on the differential between a fixed price
and a variable indexed price for natural gas. Gains and losses realized by
Kelley from hedging activities are included in oil and gas revenues and average
sales prices. Kelley's hedging activities also cover the oil and gas production
attributable to the interest in such production of the public unitholders in
Kelley's subsidiary partnerships. Through a combination of natural gas swap
agreements, forward sales contracts and options, approximately 55% of Kelley's
natural gas production for 1996 was affected by Kelley's hedging transactions at
an average NYMEX quoted price of $2.25 per MMBtu before transaction and
transportation costs. Approximately 44% of Kelley's anticipated natural gas
production for the first eight months of 1997 has been hedged by natural gas
swap agreements at an average NYMEX quoted price of $2.42 per MMBtu before
transaction and transportation costs. Hedging activities related to swaps and
options reduced revenues by approximately $3.1 million in 1996 and increased
revenues by approximately $1.8 million in 1995 as compared to estimated revenues
had no hedging activities been conducted. Hedging activities were not material
in 1994. At December 31, 1996, the Company had an unrealized loss of $2.6
million.
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.
REGULATION OF OIL AND GAS MARKETS
GENERAL. 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 those 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, Kelley 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 SALE OF NATURAL GAS. The FERC regulates interstate
natural gas pipeline transportation rates and service conditions. This affects
the marketing of gas produced by the Partnership and the revenues it receives
for sales of natural gas. Since 1985, the FERC has adopted policies intended to
make natural gas transportation more accessible to gas buyers and sellers on an
open and nondiscriminatory basis. The FERC's most recent action in this area,
Order No. 636, reflected its finding that, under the then-existing regulatory
structure, interstate pipelines and other gas merchants, including producers,
did not compete on a "level playing field" in selling gas. Order No. 636
instituted individual pipeline services restructuring proceedings, designed
specifically to "unbundle" the services provided by many interstate pipelines
(for example, transportation, sales and storage) so that buyers of natural gas
may secure supplies and delivery services from the most economical source,
whether interstate pipelines or other parties. The FERC has issued final orders
in the restructuring proceedings, and a number of pipelines have filed tariff
sheets reflecting refinements in the implementation of Order No. 636 following
three years of operation under the program. In addition, the FERC has announced
its intention to reexamine certain of its transportation related policies,
including the appropriate manner in which interstate pipelines release
transportation capacity under Order No. 636 and, more recently, the price that
shippers can charge for released capacity.
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The FERC also has issued a new policy regarding the use of nontraditional
methods of setting rates for interstate gas pipelines in certain circumstances
as alternatives to cost-of-service based rates. A number of pipelines have
obtained FERC authorization to charge negotiated rates as one alternative.
Although the FERC's actions, such as Order No. 636, do not regulate gas
producers such as the Partnership, these actions are intended to foster
increased competition within all phases of the natural gas industry. To date,
the FERC's pro-competition policies have not materially affected the
Partnership's business or operations. On a prospective basis, however, these
orders may substantially increase the burden on the producers and transporters
to nominate and deliver on a daily basis a specified volume of natural gas.
Producers and transporters that deliver deficient volume or volumes in excess of
their daily nominations could be subject to additional charges by the pipeline
carriers.
The U.S. Court of Appeals for the District of Columbia Circuit has
affirmed the FERC's Order No. 636 restructuring rule and remanded certain issues
for further explanation or clarification. Numerous petitions seeking judicial
review of the individual pipeline restructuring orders are currently pending in
that court. It is not possible to predict what, if any, effect the order on
remand or the court's decision in the individual pipeline cases will have on the
Partnership. Kelley does not believe, however, that it will be affected any
differently than other gas producers or marketers with which it competes.
Additional proposals and proceedings that might affect the natural gas
industry are considered from time to time by Congress, the FERC, state
regulatory bodies and the courts. Kelley cannot predict when or if any such
proposals might become effective or their effect, if any, on the Partnership's
operations. The natural gas industry historically has been very heavily
regulated, and there is no assurance that the less stringent regulatory approach
recently pursued by the FERC and Congress will continue indefinitely.
TRANSPORTATION AND SALE OF CRUDE OIL. Sales of crude oil and condensate
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 cost of transporting the products to market.
Commencing in October 1993, the FERC issued a series of orders (Order Nos. 561
and 561-A) in which it revised its regulations governing the rates that may be
charged by oil pipelines. The new rules, which became effective January 1, 1995,
provide a simplified, generally applicable method for regulating rates by use of
an index for setting rate ceilings. In certain circumstances, the new rules
permit oil pipelines to establish rates using traditional costs of service and
other methods of ratemaking. On October 28, 1994, the FERC issued two separate
orders (Nos. 571 and 572), adopting additional regulations governing rates that
an oil pipeline may be authorized to charge. Order No. 571 authorizes a pipeline
to implement cost-of-service based rates, provided it can demonstrate that there
is a substantial divergence between the actual costs experienced by the carrier
and the indexed rate that the pipeline is directed to charge under Order No.
561. In Order No. 572, the FERC adopted regulations that authorize a pipeline to
charge market-based rates, provided it can demonstrate that it lacks significant
market power in the market(s) in which it proposes to charge those rates. These
rules have been affirmed by the U.S. Court of Appeals for the District of
Columbia Circuit. The effect that these new rules may have on moving The
Partnership's liquid products to market cannot yet be determined.
REGULATION OF PRODUCTION. The production of oil and natural gas is subject
to regulation under a wide range of state and federal statutes, rules, orders
and regulations. State and federal statutes and regulations require permits for
drilling operations, drilling bonds and reports concerning operations. Most
states in which The Partnership owns and operates properties have regulations
governing conservation matters, including provisions for the unitization or
pooling of oil and natural gas properties, the establishment of maximum rates of
production from oil and natural gas wells and the regulation of the spacing,
plugging and abandonment of wells. Many states also restrict production to the
market demand for oil and natural gas, and several states have indicated
interest in revising applicable regulations. The effect of these regulations is
to limit the amount of oil and natural gas the Partnership can produce from its
wells and to limit the number of wells or the locations at which the Partnership
can drill. Moreover, each state generally imposes an ad valorem, production or
severance tax with respect to production and sale of crude oil, natural gas and
gas liquids within its jurisdiction.
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ENVIRONMENTAL REGULATIONS
GENERAL. Various federal, state and local laws and regulations governing
the discharge of materials into the environment, or otherwise relating to the
protection of the environment, affect the Partnership's operations and costs. In
particular, the Partnership's 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. As with the industry generally, compliance with
existing regulations increases the Partnership's overall cost of business.
Affected areas 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 gas exploration wastes and capital costs to construct, maintain and
upgrade equipment and facilities.
The Partnership incurs some expenses related to the disposition of
drilling fluids and produced waters, but these costs do not constitute a
material expense. The Partnership anticipates that it will incur additional
expenses related to compliance with environmental regulations at the time it
abandons a producing property or lease. The amount of these costs will vary, but
based on the Partnership's experience, the amount and timing of these costs
should not materially increase its overall cost of business. In addition, the
Partnership does not anticipate that it will be required to make any significant
capital expenditures to comply with current environmental requirements.
Environmental regulations historically have been subject to frequent
change by regulatory authorities, and the Partnership is unable to predict the
ongoing cost to comply with these laws and regulations or their future impact on
its operations. However, the Partnership does not believe that changes to these
regulations will materially adversely affect its competitive position because
its 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 some protection against environmental liabilities, but the coverage
of the insurance and the amount of protection afforded for any particular
possible environmental liability may not be adequate to protect the Partnership
from substantial expense.
WATER. The Oil Pollution Act (the "OPA") was enacted in 1990 and amends
provisions of the Federal Water Pollution Control Act of 1972 (the "FWPCA") and
other statutes as they pertain to prevention and response to oil spills. The OPA
subjects owners of facilities to strict, joint and potentially unlimited
liability for removal costs and certain other consequences of an oil spill into
navigable waters, along shorelines or in an exclusive economic zone. In the
event of an oil spill into such waters, substantial liabilities could be imposed
upon the Partnership. States in which the Partnership operates also have enacted
similar laws. Regulations are being developed under both the OPA and state laws
that may impose additional regulatory burdens on the Partnership.
The FWPCA imposes restrictions and strict controls regarding the discharge
of produced waters and other oil and gas wastes into navigable waters. These
controls have become more stringent over the years, and it is probable that
additional restrictions will be imposed in the future. Permits must be obtained
to discharge pollutants into state and federal waters. The FWPCA provides for
civil, criminal and administrative penalties for any unauthorized discharges of
oil and other hazardous substances in reportable quantities and, along with the
OPA, imposes substantial potential liability for the costs of removal,
remediation and damages. 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
gas production operations to obtain permits to discharge storm water runoff. The
Partnership believes that compliance with existing permits and with foreseeable
new permit requirements will not have a material adverse effect on its financial
condition or results of operations.
AIR EMISSIONS. The operations of the Partnership are subject to the
Federal Clean Air Act and comparable state and local statutes. The Partnership
believes that its operations are in substantial compliance with these statutes.
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Amendments to the Federal Clean Air Act enacted in 1990 require or will
require most industrial operations in the United States to incur capital
expenditures in order to meet air emission control standards developed by the
EPA and state environmental agencies. Although no assurances can be given, the
Partnership believes implementation of the amendments will not have a material
adverse effect on its financial condition or results of operations.
SOLID WASTE. The Federal Resource Conservation and Recovery Act ("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 gas exploration and
production wastes to be classified as non-hazardous waste. A similar exemption
is contained in many of the state counterparts to RCRA. As a result, the
Partnership is not required to comply with a substantial portion of RCRA's
requirements because its operations generate minimal quantities of hazardous
wastes. However, at various times in the past, proposals have been made to
rescind the exemption that excludes oil and gas exploration and production
wastes from regulation as hazardous waste under RCRA. Repeal or modification of
this exemption by administrative, legislative or judicial process, or through
changes in applicable state statutes, would increase the volume of hazardous
waste to be managed and disposed of by the Partnership. Hazardous wastes are
subject to more rigorous and costly disposal requirements than are non-hazardous
wastes. These changes in the regulations may result in additional capital
expenditures or operating expenses by the Partnership.
SUPERFUND. The Comprehensive Environmental Response, Compensation and
Liability Act ("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." 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
covered wastes have been disposed.
The Partnership has interests in numerous properties that for many years
have been used for the exploration and production of oil and 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 these properties or on or under other locations where
the wastes have been taken for disposal. In addition, many of these properties
have been operated by third parties whose 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 those 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.
ENVIRONMENTAL. Operations on the Partnership's properties may generally be
liable for clean-up costs to the federal government for up to $50 million for
each discharge of oil or hazardous substances under the Federal Clean Water Act,
up to $350 million for each oil discharge under the Oil Pollution Act of 1990
and for up to $50 million plus response costs for hazardous substance
contamination under CERCLA. The Partnership may also be subject to liability for
any violation of the RCRA. Liability is unlimited in cases of willful negligence
or misconduct, and there is no limit on liability for environmental clean-up
costs or damages on claims by the state or private parties. In addition, the EPA
requires producers such as the Partnership to prepare and implement spill
prevention control and countermeasure plans relating to the possible discharge
of oil into navigable waters and requires permits to authorize the discharge of
pollutants into those waters. State and local permits or approvals may also be
needed for waste-water discharges and air pollutant emissions. Violations of
environment related lease conditions or environmental permits can result in
substantial civil and criminal penalties as well as potential court injunctions
curtailing operations. The Partnership believes its operations comply with
environmental regulations, permits and lease conditions.
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ENERGY POLICY ACT. The Energy Policy Act of 1992 (the "Energy Act") was
enacted to promote vehicle fuel efficiency and the development of renewable
energy sources such as hydroelectric, solar, wind and geothermal energy. Other
provisions of the Energy Act include initiatives for reducing restrictions on
certain natural gas imports and exports and for expanding and deregulating
natural gas markets. While these provisions could have a positive impact on the
Partnership's natural gas sales on a long term basis, any positive impact could
be offset by measures promoting the use of alternative energy sources other than
natural gas. The impact of the Energy Act on the Partnership has not been
material.
EMPLOYEES
The Partnership has no employees and utilizes the management and staff of
Kelley Oil. As of January 1, 1997, Kelley Oil had 70 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.
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.
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, 1997, there were 798 holders of record of the
Partnership's Units.
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The following table sets forth the cash distributions per Unit paid by the
Partnership during the periods indicated.
DISTRIBUTIONS
1994:
First quarter.................................$ .08
Second quarter................................ .07
Third quarter................................. .04
Fourth quarter................................ --
1995:
First quarter................................. --
Second quarter................................ --
Third quarter................................. .02
Fourth quarter................................ --
1996:
First quarter................................. --
Second quarter................................ --
Third quarter................................. --
Fourth quarter................................ --
1997:
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.
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KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
YEAR ENDED DECEMBER 31,
1994 1995 1996
-------- ------- -------
SUMMARY OF OPERATIONS:
Total revenues ............................. $ 7,171 5,713 4,991
Production expenses ........................ 1,261 1,223 816
Exploration and dry hole costs ............. 2,706 148 (3)
General and administrative expenses ........ 599 474 325
Interest expense ........................... 157 672 810
Depreciation, depletion and amortization ... 8,497 4,945 1,280
Impairment of oil and gas properties ....... 9,638 11,082 --
Net income (loss) .......................... (15,687) (12,831) 1,763
Net income (loss) per Unit(1) .............. (.94) (.77) .11
Net available cash from operations(2) ...... 5,154 3,344 3,040
Net available cash per Unit(1)(2) .......... .31 .20 .18
Distributions paid per Unit(1) ............. .19 .02 --
Units outstanding .......................... 16,033 16,033 16,033
AS OF DECEMBER 31,
1994 1995 1996
-------- ------ -----
SUMMARY BALANCE SHEET DATA:
Working capital (deficit) ............. $ (3,962) (1,857) 1,582
Oil and gas properties, net ........... 21,417 6,263 3,987
Long term debt ........................ 6,000 6,000 5,400
Total partners' equity (deficit) ...... 11,455 (1,594) 169
Total assets .......................... 23,149 7,724 6,169
(1) Per Unit amounts are based on the Unitholders' 96.04% share of net income
and loss.
(2) The Partnership's net available cash generally corresponds to the sum of
its net income or loss plus exploration and dry hole costs and noncash charges
for impairment of oil and gas properties and depreciation, depletion and
amortization.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL
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
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 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 FAS 121 at December 31, 1995.
HEDGING ACTIVITIES. Kelley periodically has used forward sales contracts,
natural gas swap agreements and options to reduce exposure to downward price
fluctuations on its natural gas production. The swap agreements generally
provide for Kelley to receive or make counterparty payments on the differential
between a fixed price and a variable indexed price for natural gas. Gains and
losses realized by Kelley from hedging activities are included in oil and gas
revenues and average sales prices. Kelley's hedging activities also cover the
oil and gas production attributable to the interest in such production
12
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of the public unitholders in Kelley's subsidiary partnerships. Through a
combination of natural gas swap agreements, forward sales contracts and options,
approximately 55% of Kelley's natural gas production for 1996 was affected by
Kelley's hedging transactions at an average NYMEX quoted price of $2.25 per
MMBtu before transaction and transportation costs. Approximately 44% of Kelley's
anticipated natural gas production for the first eight months of 1997 has been
hedged by natural gas swap agreements at an average NYMEX quoted price of $2.42
per MMBtu before transaction and transportation costs. Hedging activities
related to swaps and options reduced revenues by approximately $3.1 million in
1996 and increased revenues by approximately $1.8 million in 1995 as compared to
estimated revenues had no hedging activities been conducted. Hedging activities
were not material in 1994. At December 31, 1996, the Company had an unrealized
loss of $2.6 million.
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 1996 COMPARED TO YEAR ENDED DECEMBER 31, 1995. Oil
and gas revenues of $4,807,000 in 1996 decreased 15.8% compared to $5,708,000 in
1995. Production of natural gas decreased 32.9% to 1,838,000 Mcf in 1996 from
2,741,000 Mcf in 1995, while the average price of natural gas increased 28.2% 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 33.7% and a price increase of 16.5%. The
decrease in oil and gas production and revenues iin 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 33.3%, 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 31.4%
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 74.1% 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 FAS 121. See "General-Property
Impairment under FAS 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. Net available cash from Partnership operations
(representing its net income or loss plus exploration and dry hole costs and
noncash charges for DD&A and impairment of oil and gas properties) aggregated
$3,040,000 or $0.18 per Unit in 1996 compared to $3,344,000 or $0.20 per Unit in
1995. In 1996, available cash was used to pay down loan costs.
YEAR ENDED DECEMBER 31, 1995 COMPARED TO YEAR ENDED DECEMBER 31, 1994. Oil
and gas revenues of $5,708,000 in 1995 decreased 19.8% compared to $7,115,000 in
1994. During 1995, production of natural gas decreased 14.3% from 3,198,000 Mcf
in 1994 to 2,741,000 Mcf, while the average price of natural gas decreased 3.3%
from $1.83 per Mcf in 1994 to $1.77 per Mcf in 1995. Production of crude oil in
1995 totaled 40,936 barrels, with an average sales price of $18.66 per barrel
compared to 73,706 barrels at $16.59 per barrel in the prior year, representing
a volume decrease of 44.5% and a price increase of 12.5%.
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The decrease in oil and gas production and revenues in 1995 reflected
remedial requirements for several significant wells, normal depletion of other
wells and the sale of one well. In addition, while natural gas prices remained
depressed, hedging activities contributed $367,000 to oil and gas revenues in
1995.
Lease operating expenses and severance taxes were $1,223,000 in 1995
versus $1,261,000 in 1994, a decrease of 3.0%, reflecting lower production
offset by higher workover costs in 1995. On a unit of production basis, these
expenses increased to $0.41 per Mcfe in 1995 from $0.35 per Mcfe in the prior
year.
In 1995 and 1994, the Partnership expensed exploration and dry hole costs
of $148,000 and $2,706,000, respectively. The Partnership's exploration and dry
hole costs for both years were incurred primarily for geological and geophysical
expenses.
General and administrative expenses of $474,000 in 1995 decreased 20.9%
from $599,000 in 1994, reflecting 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 1995 and the prior
year.
In 1995 and 1994, the Partnership incurred interest expenses of $672,000
and $157,000, 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.
DD&A decreased 41.8% from $8,497,000 in 1994 to $4,945,000 in 1995 as a
result of lower net capitalized costs to amortize. On a unit of production
basis, these noncash charges decreased to $1.66 per Mcfe in 1995 from $2.33 per
Mcfe in the prior year. The Partnership also recognized noncash charges of
$11,082,000 in 1995 and $9,638,000 in 1994 for impairment of its oil and gas
properties. See "General-Property Impairment under FAS 121" above.
The Partnership recognized a net loss of $12,831,000 or $0.77 per Unit for
1995 compared to a net loss of $15,687,000 or $0.94 per Unit in the prior year,
reflecting the foregoing developments. Net available cash from Partnership
operations (representing its net loss plus exploration and dry hole costs and
noncash charges for DD&A and impairment of oil and gas properties) aggregated
$3,344,000 or $0.20 per Unit in 1995 compared to $5,154,000 or $0.31 per Unit in
1994.
LIQUIDITY AND CAPITAL RESOURCES
LIQUIDITY. Net cash used in the Partnership's operating activities during
1996, as reflected on its statement of cash flows, totaled $573,000. During the
period, funds were provided by investing activities comprised of the sale of oil
and gas properties and other non-current assets aggregating $1,321,000 and
$99,000, respectively, partially offset by property and equipment expenditures
of $239,000. In addition, cash was used in financing activities for the
repayment of long-term borrowings. As a result of these activities, the
Partnership's cash and cash equivalents increased to $22,000 at December 31,
1996 from $14,000 at December 31, 1995.
CAPITAL RESOURCES. The partners' equity at December 31, 1996 increased to
$169,000. 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.
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% and 13.5% for 1995 and 1996,
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.
14
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In December 1996, KOGC entered into a $125 million revolving credit
facility with a group of banks (the "Credit Facility"). The agreement for the
Credit Facility 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. Although the Credit Facility is secured by
all the oil and gas assets of Kelley Oil, Kelley Operating and the various
guarantors, the lenders' recourse to Partnership and Joint Venture assets upon
any default is limited after Partnership debt repayment to Kelley Oil's interest
in the remaining assets.
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. During 1996, the
Partnership's operating cash flow in excess of distributions was applied to pay
interest on the Initial Loan and to reduce unfunded payables for third party
drilling overexpenditures.
DISTRIBUTION POLICY. The Partnership maintains a policy of distributing
the maximum amount of its net available cash to Unitholders on a quarterly
basis. For these purposes, net available cash generally represents the net
operating cash flow of the Partnership after deducting working capital
requirements. To meet its financial obligations for the 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 flow in excess of distributions in 1995 and all of
its operating cash flow in 1996 were applied to pay interest on the Initial Loan
and to reduce unfunded payables for third party Drilling Overexpenditures. While
$5,400,000 of the $6,000,000 Initial Loan remained outstanding at December 31,
1996, the balance of the outstanding Drilling Overexpenditures was repaid in
1996. By continuing to service its debt from operating cash flow, the
Partnership expects to further reduce the outstanding balance of the Initial
Loan in 1997.
Net available cash per Unit from operations in the quarter and year ended
December 31, 1996 was determined as follows:
QUARTER YEAR
ENDED ENDED
DECEMBER 31, DECEMBER 31,
1996 1996
-------- ------
Net income (loss) per Unit ..................... $ .04 .11
Depreciation, depletion and amortization
charges per Unit.............................. .01 .07
-------- ------
Net available cash per Unit .................. $ .05 .18
======== ======
INFLATION AND CHANGING PRICES. Oil and natural gas prices have fluctuated
during recent years and generally have not followed the same pattern as
inflation. The following table shows the changes in the average oil and gas
prices received by Kelley Partners during the periods indicated.
AVERAGE AVERAGE
OIL PRICE GAS PRICE
($/BBL) ($/MCF)
YEAR ENDED: -------- ---------
December 31, 1994..................................... $16.59 1.83
December 31, 1995..................................... 18.66 1.77
December 31, 1996..................................... 21.74 2.27
FORWARD-LOOKING STATEMENTS
FROM TIME TO TIME, THE PARTNERSHIP MAY PUBLISH 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
15
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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, RESERVE ESTIMATES, RATES AND
TIMING OF FUTURE PRODUCTION OF OIL AND GAS, AND CHANGES IN THE LEVEL AND TIMING
OF FUTURE COSTS AND EXPENSES RELATED TO DRILLING AND OPERATING ACTIVITIES.
WORDS SUCH AS "ANTICIPATED," "EXPERT," "ESTIMATE," "PROJECT" AND SIMILAR
EXPRESSIONS ARE INTENDED TO IDENTIFY FORWARD-LOOKING STATEMENTS. FORWARD-LOOKING
STATEMENTS MAY BE MADE IN MANAGEMENT'S STATEMENTS (ORALLY OR IN WRITING)
INCLUDING PRESS RELEASES, AND IN FILINGS OF THE SEC, INCLUDING THIS REPORT.
In addition to "Uncertainties in Estimating Reserves" and other such
factors mentioned in this Report, the following additional risk factors should
be considered:
SUBSTANTIAL LEVERAGE. As of December 31, 1996, the Partnership has total
indebtedness for money borrowed of approximately $5.4 million and partners'
equity of approximately $0.2 million. The Partnership's ability to make
scheduled payments of principal, to pay interest on or to refinance its
indebtedness for money borrowed depends on its future performance, which is
subject not only to its own actions but also to general economic, financial,
competitive, legislative, regulatory and other factors beyond its control, as
well as to the prevailing market prices for oil, natural gas and natural gas
liquids.
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 business plan
does not contemplate developing or acquiring additional reserves.
VOLATILITY OF OIL, NATURAL GAS AND NATURAL GAS LIQUIDS PRICES. The
Partnership's financial results are affected significantly by the prices
received for its oil, natural gas and natural gas liquids production.
Historically, the markets for oil, natural gas and natural gas liquids have been
volatile and are expected to continue to be volatile in the future. The prices
received by the Partnership for its oil, natural gas and natural gas liquids
production and the levels of 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 producing its reserves.
OPERATING HAZARDS AND UNINSURED RISKS. The Partnership's oil and natural
gas business also is subject to all of the operating risks associated with the
production of oil and natural gas, including uncontrollable flows of oil,
natural gas, brine or well fluids into the environment (including groundwater
and shoreline contamination), cratering, mechanical difficulties, fires,
explosions, pollution and other risks, any of which could result in substantial
losses. 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.
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 shut in for lack of a
market or because of inadequacy or unavailability of natural gas pipeline or
gathering system capacity.
16
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM: PAGE
----
Independent Auditors' Reports............................................ 19
Balance Sheets - December 31, 1996 and 1995.............................. 21
Statements of Operations - For the years ended
December 31, 1996, 1995 and 1994...................................... 22
Statements of Cash Flows - For the years ended
December 31, 1996, 1995 and 1994...................................... 23
Statements of Changes in Partners' Equity (Deficit) -
For the years ended December 31, 1996, 1995 and 1994.................. 24
Notes to Financial Statements............................................ 25
18
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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 1995, and the related statements of operations, cash flows, and changes
in partners' equity (deficit) for each of the two years in the period ended
December 31, 1996. These financial statements are the responsibility of
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 audits 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 at December 31, 1996 and 1995, and the results of its operations and its
cash flows for each of the two years in the period ended December 31, 1996, in
conformity with generally accepted accounting principles.
As discussed in Note 1, 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 3, 1997
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REPORT OF INDEPENDENT AUDITORS
To the Partners of Kelley Partners 1992 Development Drilling Program
We have audited the balance sheet of Kelley Partners 1992 Development
Drilling Program (a Texas limited partnership) as of December 31, 1994, and the
related statements of operations, partners' equity, and cash flows for the year
then ended. The balance sheet as of December 31, 1994 is not presented
separately herein. These financial statements are the responsibility of
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audit 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 audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Kelley Partners 1992
Development Drilling Program at December 31, 1994 and results of its operations
and its cash flows for the year then ended, in conformity with generally
accepted accounting principles.
Ernst & Young LLP
Houston, Texas
March 6, 1995
20
<PAGE>
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
BALANCE SHEETS
($ IN THOUSANDS)
DECEMBER 31,
1995 1996
-------- -------
ASSETS:
Cash and cash equivalents ............................. $ 14 22
Accounts receivable - trade ........................... 171 126
Accounts receivable - affiliates ...................... 1,255 2,034
Other assets .......................................... 21 --
-------- -------
Total current assets ................................. 1,461 2,182
-------- -------
Oil and gas properties, successful efforts method:
Properties subject to amortization ................... 45,230 44,333
Less: Accumulated depreciation, depletion &
amortization ..................................... (38,967) (40,346)
-------- -------
Total oil and gas properties ......................... 6,263 3,987
-------- -------
TOTAL ASSETS .......................................... $ 7,724 6,169
======== =======
LIABILITIES:
Accounts payable and accrued expenses ................. $ 375 143
Accounts payable - affiliates ......................... 2,943 457
-------- -------
Total current liabilities ............................ 3,318 600
-------- -------
Notes payable - long term ............................. 6,000 5,400
-------- -------
TOTAL LIABILITIES .................................... 9,318 6,000
-------- -------
PARTNERS' EQUITY (DEFICIT):
LP Unitholders' equity (deficit) ...................... (183) (9)
GP Unitholders' equity (deficit) ...................... (1,349) 171
Managing and Special General Partners' equity (deficit) (62) 7
-------- -------
TOTAL PARTNERS' EQUITY (DEFICIT) ..................... (1,594) 169
-------- -------
TOTAL LIABILITIES AND PARTNERS' EQUITY ................ $ 7,724 6,169
======== =======
See Notes to Financial Statements.
20
<PAGE>
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER UNIT DATA)
YEAR ENDED DECEMBER 31,
------------------------------
1994 1995 1996
-------- ------- -------
REVENUES:
Oil and gas sales .......................... $ 7,115 5,708 4,807
Interest and other income .................. 56 5 184
-------- ------- -------
Total revenues ............................ 7,171 5,713 4,991
-------- ------- -------
COSTS AND EXPENSES:
Lease operating expenses ................... 856 889 624
Severance taxes ............................ 405 334 192
Exploration and dry hole costs ............. 2,706 148 (3)
General and administrative expenses ........ 599 474 325
Interest expense ........................... 157 672 810
Depreciation, depletion and amortization ... 8,497 4,945 1,280
Impairment of oil and gas properties ....... 9,638 11,082 --
-------- ------- -------
Total costs and expenses .................. 22,858 18,544 3,228
-------- ------- -------
NET INCOME (LOSS) ............................ $(15,687) (12,831) 1,763
======== ======= =======
NET INCOME (LOSS) ALLOCABLE TO LP UNITHOLDERS $ (1,460) (1,262) 174
======== ======= =======
NET INCOME (LOSS) ALLOCABLE TO GP UNITHOLDERS $(13,606) (11,061) 1,520
======== ======= =======
NET INCOME (LOSS) ALLOCABLE TO MANAGING AND
SPECIAL GENERAL PARTNERS ................... $ (621) (508) 69
======== ======= =======
NET INCOME (LOSS) PER UNIT ................... $ (.94) (.77) .11
======== ======= =======
Average Units outstanding .................... 16,033 16,033 16,033
======== ======= =======
See Notes to Financial Statements.
21
<PAGE>
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------
1994 1995 1996
-------- ------- ------
<S> <C> <C> <C>
OPERATING ACTIVITIES:
Net income (loss) ................................. $(15,687) (12,831) 1,763
Adjustments to reconcile net loss to net cash
provided by operating activities:
Depreciation, depletion and amortization ........ 8,497 4,945 1,280
Impairment of oil and gas properties ............ 9,638 11,082 --
Dry hole costs .................................. 1,973 5 (3)
Gain on sale of oil and gas properties .......... -- -- (182)
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable ..... 36 261 (734)
Decrease (increase) in other assets ............ 516 (8) 21
Increase (decrease) in accounts payable and
accrued expenses .............................. 938 (2,376) (2,718)
-------- ------- ------
Net cash provided by (used in) operating activities 5,911 1,078 (573)
-------- ------- ------
INVESTING ACTIVITIES:
Purchases of property and equipment ............... (16,170) (1,401) (239)
Sale of oil and gas properties .................... -- 380 1,321
Sale of non-current assets ........................ 195 143 99
-------- ------- ------
Net cash provided by (used in) investing
activities ...................................... (15,975) (878) 1,181
-------- ------- ------
FINANCING ACTIVITIES:
Capital contributed by partners ................... 7,023 115 --
Payments on long-term borrowings .................. -- -- (600)
Proceeds from long-term borrowings ................ 6,000 -- --
Distributions to partners ......................... (3,171) (333) --
-------- ------- ------
Net cash provided by (used in) financing
activities ...................................... 9,852 (218) (600)
-------- ------- ------
Increase (decrease) in cash and cash equivalents .. (212) (18) 8
Cash and cash equivalents, beginning of period .... 244 32 14
-------- ------- ------
Cash and cash equivalents, end of period .......... $ 32 14 22
======== ======= ======
</TABLE>
See Notes to Financial Statements.
22
<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> <C>
Partners' equity at January 1, 1994 ............. $ 2,867 19,218 1,205 23,290
-------- ------- ------- -------
Capital contributed ............................. -- 7,023 -- 7,023
Distributions ................................... (295) (2,751) (125) (3,171)
Net loss........................... (1,460) (13,606) (621) (15,687)
-------- ------- ------- -------
Partners' equity at December 31, 1994 ......... 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
======== ======= ======= =======
</TABLE>
See Notes to Financial Statements.
23
<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, 1996, Kelley Oil and its
officers and directors owned 13,422,310 (83.72%) Units and 2,000 (.01%) Units,
respectively. 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. Cost centers for amortization purposes are determined on a
field-by-field basis. Estimated future abandonment and site restoration costs,
net of anticipated salvage values, are taken into account in depreciation,
depletion and amortization.
The successful efforts method imposes limitations on the carrying or book
value of oil and gas properties and requires an impairment provision or noncash
charge against earnings for any quarter in which the carrying value of oil and
gas properties exceeds the standardized measure of undiscounted future net cash
flows from its proved oil and gas reserves based on prices received for its oil
and gas production as of the end of that quarter or a subsequent date prior to
publication of financial results for the quarter. As a result of declines in
natural gas prices, the Partnership recognized noncash charges for impairment of
oil and gas properties aggregating $9,638,000 during 1994.
24
<PAGE>
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.
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,
1996, the estimated fair value of the Partnership's debt approximated its
carrying value. The estimated fair values at December 31, 1996 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. Realized and unrealized gains and losses are recorded in other assets
or liabilities until the underlying natural gas is produced and sold, at which
time those gains and losses are included in oil and gas revenues. See Note 6 -
Hedging Activities.
CONCENTRATION OF CREDIT RISK. Substantially all of the Partnership's
receivables are due from the marketing subsidiary of Kelley Oil, which purchases
natural gas for resale to a limited number of natural gas transmission companies
and other gas purchasers. See Note 4 - Related Party Transactions.
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.
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% and 13.5% for 1995 and 1996,
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.
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. During 1995 and 1996, the
Partnership's operating cash flow in excess of distributions was applied to pay
interest on the Initial Loan and to reduce unfunded payables for third party
drilling overexpenditures. While $5,400,000 of the $6,000,000 Initial Loan
remained outstanding at December 31, 1996, the balance of the outstanding
Drilling Overexpenditures was repaid in 1996. By continuing to service its debt
from operating cash flow, the Partnership expects to further reduce the
outstanding balance of the Initial Loan in 1997.
25
<PAGE>
In December 1996, KOGC entered into a $125 million revolving credit
facility with a group of banks (the "Credit Facility"). The agreement for the
Credit Facility requires the payment of interest only until December 2000, when
all borrowings will be repayable. The Partnership and Joint Venture are
guarantors under the Credit Facility. Although the Credit Facility is secured by
all the oil and gas assets of Kelley Oil, Kelley Operating and the various
guarantors, the lenders' recourse to Partnership and Joint Venture assets upon
any default is limited after Partnership debt repayment to Kelley Oil's interest
in the remaining assets.
NOTE 3 - CASH DISTRIBUTIONS
The following table sets forth, for the periods indicated, the
distributions per Unit. Cash distributions were paid in the quarter indicated
and were based upon net available cash generated from operations in the
preceding quarter.
1994 1995 1996
------ ------ -----
First quarter.........................................$ .08 -- --
Second quarter........................................ .07 -- --
Third quarter......................................... .04 .02 --
Fourth quarter........................................ -- -- --
------ ------ ------
Totals..............................................$ .19 .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, 1994, 1995 and 1996, these costs aggregated $2,080,000, $220,000,
and $1,000, respectively. The Partnership capitalized $1,347,000, $77,000, and
$1,000 of allocated direct costs to oil and gas properties for the years ended
December 31, 1994, 1995 and 1996, respectively.
Overhead allocated to the Partnership by Kelley Oil for the years ended
December 31, 1994, 1995 and 1996 related to general and administrative expenses
aggregated $538,000, $391,000 and $227,000, 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. During 1994, CGM received for its services
either fees or a marketing differential equal to $0.05 per MMBtu of gas sold and
delivered. For 1995 and 1996, the fee was modified to 2% of the resale price for
marketed natural gas.
26
<PAGE>
NOTE 5 - SALES TO MAJOR CUSTOMERS
Sales to customers in excess of 10% of total oil and gas sales for the
years ended December 31, 1994, 1995 and 1996 were as follows:
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
-----------------------------
1994 1995 1996
------ ------ -----
Concorde Gas Marketing(1).......................5,769 4,749 3,585
Falco S & D Inc................................. 864 583 176
(1) During 1996, approximately 52% of CGM's gas purchases were made for
resale to Sonat Marketing Company (28%), Coral Energy Resources (20%) and LIG
Chemical Company (10%). During 1995, approximately 82% of CGM's resales were
made to Sonat Marketing Company (22%), Associataed Natural Gas, Inc. (21%),
Pontchartrain Natural Gas System (17%), Transok Gas Company (12%) and LIG
Chemical Company (10%). During 1994, approximately 73% of GCM's resales were
made to Pontchartrain Natural Gas System (23%), LIG Chemical Company (22%),
Associated Natural Gas, Inc. (18%) and Fina Natural Gas Company (10%).
NOTE 6 - HEDGING ACTIVITIES
Kelley periodically has used forward sales contracts, natural gas swap
agreements and options to reduce exposure to downward price fluctuations on its
natural gas production. The swap agreements generally provide for Kelley to
receive or make counterparty payments on the differential between a fixed price
and a variable indexed price for natural gas. Gains and losses realized by
Kelley from hedging activities are included in oil and gas revenues and average
sales prices. Kelley's hedging activities also cover the oil and gas production
attributable to the interest in such production of the public unitholders in
Kelley's subsidiary partnerships. Through a combination of natural gas swap
agreements, forward sales contracts and options, approximately 55% of Kelley's
natural gas production for 1996 was affected by Kelley's hedging transactions at
an average NYMEX quoted price of $2.25 per MMBtu before transaction and
transportation costs. Approximately 44% of Kelley's anticipated natural gas
production for the first eight months of 1997 has been hedged by natural gas
swap agreements at an average NYMEX quoted price of $2.42 per MMBtu before
transaction and transportation costs. Hedging activities related to swaps and
options reduced revenues by approximately $3.1 million in 1996 and increased
revenues by approximately $1.8 million in 1995 as compared to estimated revenues
had no hedging activities been conducted. Hedging activities were not material
in 1994. At December 31, 1996, the Company had an unrealized loss of $2.6
million.
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 7 - SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND GAS EXPLORATION,
DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)
This section provides information required by Statement of Financial
Accounting Standards No. 69, "Disclosures about Oil and Gas Producing
Activities."
27
<PAGE>
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)
YEAR ENDED DECEMBER 31,
-----------------------------
1994 1995 1996
------ ------ -----
Unevaluated properties ..................... $ -- -- --
Evaluated properties subject to amortization 44,214 45,230 44,333
------- ------ ------
Total properties subject to amortization . 44,214 45,230 44,333
Accumulated depreciation, depletion and
amortization ............................. (22,797) (38,967) (40,346)
-------- ------- -------
Net capitalized costs .................... $ 21,417 6,263 3,987
======== ======= =======
COSTS INCURRED. All costs were incurred in oil and gas property
development activities (as defined in the Partnership Agreement) and aggregated
$16,903,000, $1,545,000 and $238,593 in 1994, 1995 and 1996, 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, 1994, 1995 and 1996 are summarized below.
Reserves estimates contained below were prepared by H.J. Gruy & Associates, Inc.
("Gruy"), independent petroleum engineers, for 1995 and 1996, and were prepared
by the Company and reviewed by Gruy for 1994. 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)
-------------------- -----------------------------
1994 1995 1996 1994 1995 1996
---- ---- ---- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C>
Proved developed and
undeveloped reserves:
Beginning of year ........ 374 290 201 15,888 14,827 10,220
Revisions of previous
estimates ............... (80) (48) (4) (2,172) (1,317) (289)
Extensions and discoveries 70 -- -- 4,309 -- 251
Sale of oil and gas
properties .............. -- -- (68) -- (549) (807)
Production ............... (74) (41) (27) (3,198) (2,741) (1,838)
---- ---- ---- ------- ------- -------
End of year ............. 290 201 102 14,827 10,220 7,537
==== ==== ==== ======= ======= =======
Proved developed reserves
at end of year ........... 290 201 102 14,827 10,220 7,537
==== ==== ==== ======= ======= =======
</TABLE>
28
<PAGE>
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)
AS OF DECEMBER 31,
-------------------------------------
1994 1995 1996
-------- ------- -------
Future cash inflows ................. $ 28,819 25,546 29,709
Future production costs ............. (6,937) (5,502) (3,141)
Future development costs ............ (465) (60) (77)
-------- ------- -------
Future net cash flows .............. 21,417 19,984 26,491
10% annual discount for
estimating timing of cash flows.... (5,980) (7,090) (10,771)
-------- ------- -------
Standardized measure of
discounted future net cash
flows............................ 15,437 12,894 15,720
Future cash inflows are computed by applying year-end prices of oil and
gas to year-end quantities of proved oil and gas reserves. Future production and
development costs are computed by Kelley Oil's petroleum engineers by estimating
the expenditures to be incurred in developing and producing the Partnership's
proved oil and gas reserves at the end of the year, based on year-end costs and
assuming continuation of existing economic conditions.
A discount factor of 10% was used to reflect the timing of future net cash
flows. The standardized measure of discounted future net cash flows is not
intended to represent the replacement cost or fair market value of the
Partnership's oil and gas properties.
The standardized measure of discounted future net cash flows as of
December 31, 1994, 1995 and 1996 was calculated using prices in effect as of
those dates, which averaged $15.65, $19.73 and $25.36, respectively, per barrel
of oil and $1.64, $2.11 and $3.72, respectively, per Mcf of natural gas.
29
<PAGE>
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,
------------------------------
1994 1995 1996
-------- ------- -------
<S> <C> <C> <C>
Changes due to current year operations:
Sales of oil and gas, net of production costs ............ $ (5,854) (4,485) (3,991)
Sales of reserves in place ............................... -- (339) (1,321)
Extensions and discoveries, net of future production costs 4,883 -- 310
Development costs incurred during the year ............... 6,534 493 242
Changes due to revisions in standardized variables:
Prices and production costs .............................. (6,419) 2,703 7,765
Revisions of previous quantity estimates ................. (2,530) 31 (739)
Estimated future development costs ....................... (1,452) (1,202) (230)
Accretion of discount .................................... 1,902 1,544 1,289
Production rates (timing) and other ...................... (648) (1,288) (500)
-------- ------- -------
Net increase (decrease) ................................ (3,584) (2,543) 2,826
Beginning of year .......................................... 19,021 15,437 12,894
-------- ------- -------
End of year ................................................ $ 15,437 12,894 15,720
======== ======= =======
</TABLE>
Sales of oil and gas, net of production costs, are based on historical
results. Extensions and discoveries, the changes due to revisions in
standardized variables and the accretion of discount are reported on a
discounted basis.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURES
In connection with the Contour Transaction, the Partnership dismissed
Ernst & Young LLP ("E&Y") as its principal accountants, effective February 15,
1996. On the same date, the Partnership engaged Deloitte & Touche LLP ("D&T") as
its principal accountants to audit its financial statements. The change in
accountants was approved by the audit committee of the board of directors of
Kelley Oil, contingent upon the closing under the Purchase Agreement. Neither of
E&Y's reports on the Partnership's financial statements for the years ended
December 31, 1993 and 1994 contained an adverse opinion or disclaimer of
opinion, or was qualified or modified as to uncertainty, audit scope or
accounting principles. During the last two years and the interim period prior to
the date of the change in accountants, (i) the Partnership had no disagreements
with E&Y on any matter of accounting principles or practices, financial
statement disclosure or auditing scope or procedure, (ii) E&Y did not advise the
Partnership of any "reportable event" as defined in Regulation S-K under the
Securities Exchange Act of 1934 and (iii) the Partnership did not consult with
D&T on any accounting, auditing, financial reporting or any other matters.
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 70 employees as of December 31, 1996, and its staff includes
30
<PAGE>
employees experienced in geology, geophysics, petroleum engineering, land
acquisition and management, finance, accounting, and administration.
BACKGROUND OF KELLEY OIL
Kelley Oil is a publicly held independent oil and gas 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.
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.
OFFICER
OR
DIRECTOR OF
THE COMPANY
NAME AGE POSITION SINCE
- ---- --- -------- -----------
John F. Bookout.......74 President, Chief Executive Officer 1996
and a director
David C. Baggett......35 Senior Vice President and Chief 1997
Financial Officer and a director
Dallas D. Laumbach....60 Senior Vice President-Exploration 1996
and Production and a director
Thomas E. Baker.......66 General Counsel and Corporate Secretary 1996
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."
31
<PAGE>
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
BENEFICIAL OWNERS
The following table sets forth information as of December 31, 1996 with
respect to the only Unitholder known by the Partnership to own beneficially more
than five percent of the Partnership's Units.
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, 1996 with
respect to Units beneficially owned, directly or indirectly, by each of the
directors of Kelley Oil and by all officers and directors of Kelley Oil as a
group.
AMOUNT & NATURE
NAME AND ADDRESS OF OF BENEFICIAL PERCENT
BENEFICIAL OWNER OWNERSHIP(1) OF CLASS
- ------------------- --------------- --------
John F. Bookout -- --
Dallas D. Laumbach -- --
David C. Baggett -- --
All directors and officers
as a group (9 persons) 2,000 .01%
(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.
During 1994, 1995 and 1996, Kelley Oil was reimbursed by the Partnership for
costs directly associated with the Partnership's development drilling activities
in the amounts of $2,080,000, $220,000 and $1,000, respectively. Kelley Oil was
reimbursed for its general and administrative expenses allocable to Partnership
operations in the amount of $538,000, $391,000 and $227,000 in 1994, 1995 and
1996, respectively.
It is the policy of the Partnership to engage in transactions with related
parties only on terms that are no less favorable to the Partnership than could
be obtained on an arm's-length basis from unrelated parties. The Partnership
believes that all payments to related parties are reasonable and in amounts not
greater than fees that would be charged on an arm's-length basis by unrelated
parties.
32
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a)FINANCIAL STATEMENTS AND SCHEDULES:
(1) FINANCIAL STATEMENTS: The financial statements required to be filed
are included under Item 8 of this Report.
(2) SCHEDULES: Schedules for which provision is made in applicable
accounting regulations of the SEC are not required under the related
instructions or are inapplicable, and therefore have been omitted.
(3)EXHIBITS:
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 1996.
33
<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 27th day of
March, 1997.
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/ LAWRENCE G. MARBLE
John F. Bookout David C. Baggett Lawrence G. Marble
Chief Executive Officer Senior Vice President Controller
and Chief Financial Officer (Chief Accounting Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed as of the 27th day of March, 1996 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
Davd C. Baggett
34
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<PERIOD-TYPE> Year
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> DEC-31-1996
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<RECEIVABLES> 2,160
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<PP&E> 44,333
<DEPRECIATION> 40,346
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0
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