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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
Amendment No. 1
to
FORM 10-K
on
Form 10-K/A
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999 COMMISSION FILE NO. 0-20998
KELLEY PARTNERS 1992
DEVELOPMENT DRILLING PROGRAM
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
TEXAS 76-0373428
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER IDENTIFICATION NO.)
INCORPORATION OR ORGANIZATION)
601 JEFFERSON ST.
SUITE 1100
HOUSTON, TEXAS 77002
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (713) 652-5200
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
None
(TITLE OF CLASS)
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Units of Limited and General Partner Interests
(TITLE OF CLASS)
</TABLE>
Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
--- ---
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K under the Securities Exchange Act of 1934 is not contained
herein, and will not be contained, to the best of the Registrant's knowledge, in
definitive proxy or information statements incorporated in Part III of this Form
10-K or any amendments to this Form 10-K. [ ]
As of March 24, 2000, Kelley Partners 1992 Development Drilling Program had
16,033,009 units of limited and general partner interests (the "Units")
outstanding. The Units are not publicly traded.
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EXPLANATORY NOTE
This Amendment No. 1 to Form 10-K on Form 10-K/A amends Items 1 and 2 to the
Registrant's Annual Report on Form 10-K for the year ended December 31, 1999 to
correctly reflect the Registrant's ownership of certain oil and gas wells as
reflected on pages 4 to 6.
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PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
INTRODUCTION
General. Kelley Partners 1992 Development Drilling Program, a Texas
limited partnership (the "Partnership"), was formed in 1992 to develop oil and
gas properties located onshore in Louisiana. The Partnership issued a total of
16,033,009 units of limited and general partner interests ("Units"),
representing 96.04% of the total interests in the Partnership, for $48,099,027.
The Units consist of 1,647,500 Units of limited partner interests ("LP Units")
and 14,385,509 Units of general partner interests ("GP Units"). In addition, the
Partnership issued managing and special general partner ("General Partner")
interests, representing the other 3.96% of the total interests in the
Partnership, for $1,983,258. Kelley Oil Corporation, the managing general
partner of the Partnership (the "Managing General Partner" or "Kelley Oil"),
owns 83.72% of the Units and a 3.94% General Partner interest. Kelley Oil is a
subsidiary of Contour Energy Co. (formerly Kelley Oil & Gas Corporation),
collectively with its subsidiaries ("Contour").
As used in this Report, "Mcf" means thousand cubic feet, "Mmcf" means
million cubic feet, "Bcf" means billion cubic feet, "Bbl" means barrel or 42
U.S. gallons liquid volume, "Mbbl" means thousand barrels, "Mcfe" means thousand
cubic feet of natural gas equivalent using the ratio of six Mcf of natural gas
to one Bbl of crude oil, condensate and natural gas liquids, "Mmcfe" means
million cubic feet of natural gas equivalent, "Bcfe" means billion cubic feet of
natural gas equivalent, and "Mmbtu" means million British thermal units. This
Report includes various other capitalized terms that are defined when first
used.
In 1999, Contour undertook several strategic actions in response to the
severe downturn in the industry in 1998 caused by low commodity prices and the
closing of the capital markets to smaller oil and gas companies. These actions,
described below, were designed to increase the near-term liquidity of Contour,
Kelley Oil and the Partnership, provide capital for ongoing capital expenditure
programs and establish a stronger base for future growth.
In April 1999, Contour entered into an Exploration and Development
Agreement with Phillips Petroleum Company ("Phillips") relating to certain of
its interests in the Bryceland, West Bryceland and Sailes fields in north
Louisiana ("Phillips Transaction"). Pursuant to the agreement, Contour: (1)
received an $83 million cash payment, (2) retained a 42 Bcf, 8-year volumetric
overriding royalty interest and a 1% override on the excess production above
such royalty interest and (3) retained 25% of its working interest in the Cotton
Valley formation. In addition, Phillips, will at its risk and expense, operate,
develop, exploit and explore the properties thereby relieving Contour of
significant operating, exploration and development costs in the future. The
transaction closed on May 17, 1999.
As part of the Phillips Transaction described above, the Partnership
conveyed its interest in the West Bryceland and Sailes fields to Phillips for
$2.1 million. The Partnership's reserve quantities attributable to such fields
represented approximately one-half of the Partnership's total reserve quantities
at January 1, 1999 and one-half of its total 1998 production. In the third
quarter of 1999, the sales proceeds were applied to reduce the Partnership's
loan to Kelley Oil.
In April 1999, Contour negotiated a private offering of $135 million
principal amount, 14% Senior Secured Notes (the "Notes"). The Notes are secured
by a first lien on substantially all of Contour's proved oil and natural gas
properties remaining after the sale to Phillips and guaranteed by three entities
wholly-owned by Contour. In accordance with the Notes indenture, on June 30,
1999, Contour funded $37.5 million to repurchase $35 million principal amount of
the Notes at a repurchase price equal to 104% of the principal amount, plus
accrued and unpaid interest and commitment fees to the date of the repurchase.
On May 17, 1999, Contour funded $28.5 million to repurchase $46.1
million of the outstanding principal amounts of its 7 7/8% Convertible
Subordinated Notes due December 15, 1999 and its 8 1/2% Convertible Subordinated
Debentures due April 1, 2000 (collectively, the "Securities") at a price equal
to $590 per $1,000 principal amount (not including accrued interest paid of $1.2
million).
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In addition, on May 17, 1999, Contour repaid all borrowings outstanding
under its credit facility of $115.5 million plus accrued interest and terminated
the revolving credit facility and funded cash collateral for a $1.5 million
letter of credit which was subsequently increased to $7.5 million. Contour used
net proceeds remaining from the transactions for general corporate purposes.
Contour has received the benefits of a general increase in the level of
commodity prices over the past several months. This increase, combined with the
actions described above, have provided Contour with near-term liquidity and
capital for its ongoing operations. However, the commodity markets are volatile
and there is no certainty that current oil and natural gas prices can be
sustained at these levels. In addition, Contour continues to have significant
debt outstanding relative to its asset base and pays a high portion of its cash
flow to service such debt. Furthermore, as Contour does not have a revolving
credit facility, it also does not have ready access to incremental sources of
capital to supplement its operational requirements. Contour believes that it has
the ability for the foreseeable future based on its current condition, including
economic conditions, to meet all obligations as they come due and fund its
current capital expenditure program from cash on hand and operational cash
flows. However, because of the combination of the factors described herein and
the uncertainty of drilling successes required to sustain or increase
operational cash flows, there can be no assurance that Contour will be able to
fund future obligations.
Operations. Development activities of the Partnership are conducted
through a joint venture (the "Joint Venture") between the Partnership and Kelley
Operating Company, Ltd. ("Kelley Operating"), a subsidiary partnership of Kelley
Oil. The Partnership contributed to the Joint Venture substantially all of the
partners' contributed capital to finance the costs of drilling, completing,
equipping and, when necessary, abandoning the wells drilled by the Joint
Venture, proportionate with the Joint Venture's working interest in each well.
Kelley Operating contributed to the Joint Venture specific drilling rights for
development wells on its properties selected by the Managing General Partner. In
return for the contributed drilling rights, Kelley Operating has reserved a 20%
reversionary interest after Payout (as defined in the Joint Venture Agreement)
in the costs and revenues of the Joint Venture.
In addition to its reversionary interest, Kelley Operating retained one
third of its working interest associated with the drilling rights contributed to
the Joint Venture. Accordingly, Kelley Operating has contributed proportionately
to the development and operating costs of all Partnership wells and receives a
proportionate share of the revenues attributable to the sale of production from
those wells.
Development and Production. From inception through the completion of
drilling activities in 1994, the Partnership participated in drilling 39 gross
wells, of which 30 gross (11.07 net) wells were productive and 9 gross (4.16
net) wells were dry. Subsequently, two producing Partnership wells were plugged
when production declined to noncommercial levels. From its inception through
1999, the Partnership produced 10.5 Bcf of natural gas and 203,482 barrels of
oil and natural gas liquids, generating total oil and gas revenues of
$24,621,000, of which $4,506,000 or $0.27 per Unit has been distributed to the
partners. To enable the Partnership to fund part of its drilling and
recompletion expenses in excess of contributed capital, quarterly distributions
were suspended in October 1994, reinstated for only one quarter in 1995, and
suspended again thereafter. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations."
MANAGEMENT, OPERATIONS AND PROPERTIES
Kelley Oil's principal executive offices are located at 601 Jefferson
Street, Suite 1100, Houston, Texas 77002, and its main telephone number is (713)
652-5200. As Managing General Partner, Kelley Oil makes all decisions regarding
the business and operations of the Partnership. The Partnership has no employees
and utilizes the officers and staff of Kelley Oil to perform all management and
administrative functions. Kelley Oil's staff includes employees experienced in
geology, geophysics, petroleum engineering, land acquisition and management,
finance and accounting. Kelley Oil is also the managing general partner of
Kelley Operating. See "Employees" below and "Directors and Executive Officers of
Kelley Oil Corporation."
The General Partners receive no management or other fees or promoted
interests from the Partnership or the Joint Venture. The Partnership reimburses
Kelley Oil for all direct costs incurred in managing the Partnership and all
indirect costs allocable to the Partnership, principally comprised of general
and administrative expenses. These arrangements are the same for all development
drilling programs ("DDPs") sponsored by Kelley Oil.
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ESTIMATED PROVED RESERVES
General. The estimated gross quantities of proved and proved developed
reserves for properties in which the Partnership owns interests were prepared as
of January 1, 1998, 1999 and 2000, by an independent petroleum engineering firm.
For the reserves at January 1, 2000, Contour applied appropriate Partnership
revenue interests to determine the Partnership's net proved reserves shown
below.
Quantities. The following table sets forth the Partnership's estimated
quantities of proved and proved developed reserves of crude oil (including
condensate and natural gas liquids) and natural gas as of January 1, 1998, 1999
and 2000. Proved developed reserves are reserves that can be expected to be
recovered from existing wells with existing equipment and operating methods.
Proved undeveloped reserves are proved reserves that are expected to be
recovered from new wells drilled to known reservoirs on undrilled acreage for
which the existence and recoverability of reserves can be estimated with
reasonable certainty, or from existing wells where a relatively major
expenditure is required for recompletion.
ESTIMATED PROVED RESERVES
<TABLE>
<CAPTION>
AS OF JANUARY 1,
-----------------------------------
1998 1999 2000
-------- -------- ---------
<S> <C> <C> <C>
Crude oil and liquids (Mbbl):
Proved developed............................................................. 78 88 64
Proved undeveloped........................................................... - - -
-------- -------- ---------
Total proved............................................................... 78 88 64
======== ======== =========
Natural gas (Mmcf):
Proved developed............................................................. 5,521 3,759 1,196
Proved undeveloped........................................................... - - -
-------- -------- ---------
Total proved............................................................... 5,521 3,759 1,196
======== ======== =========
</TABLE>
Detailed information concerning the Partnership's estimated proved
reserves and discounted net future cash flows is contained in the Supplementary
Financial Information included in Note 7 to the Partnership's Financial
Statements. The Partnership has not filed any estimates of reserves with any
federal authority or agency during the past year other than estimates contained
in its last annual report filed with the Securities and Exchange Commission
("SEC").
Uncertainties in Estimating Reserves. Oil and gas proved reserves
cannot be measured exactly. Reserve estimates are inherently imprecise and may
be expected to change as additional information becomes available. Estimates of
oil and gas reserves, of necessity, are projections based on engineering data,
and there are uncertainties inherent in the interpretation of such data as well
as the projection of future rates of production and the timing of development
expenditures. Reserve estimates are based on many factors related to reservoir
performance which require evaluation by the engineers interpreting the available
data, as well as price and other economic factors. The reliability of these
estimates at any point in time depends on the quality and quantity of the
technical and economic data, the production performance of the reservoirs as
well as extensive engineering judgment. Further, estimates of the economically
recoverable quantities of oil and natural gas attributable to any particular
group of properties, classifications of such reserves based on risk of recovery
and estimates of the future net revenues expected therefrom prepared by
different engineers or by the same engineers at different times may vary
substantially. Consequently, reserve estimates are subject to revision as
additional data becomes available during the producing life of a reservoir.
There also can be no assurance that the reserves set forth herein will
ultimately be produced or that the proved undeveloped reserves set forth herein
will be developed within the periods anticipated. In addition, the estimates of
future net revenues from proved reserves of Kelley and the present value thereof
are based upon certain assumptions about future production levels, prices and
costs that may not be correct when judged against actual subsequent experience.
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DESCRIPTION OF SIGNIFICANT PROPERTIES
General. The properties of the Partnership consist primarily of
interests in producing wells located in the Hosston, Smackover, Miocene and
Oligocene trends in Louisiana. All of the Partnership's oil and gas reserves are
located within the continental United States.
Significant Fields. The following table sets forth certain information
as of January 1, 2000 with respect to the Partnership's interests in its most
significant fields, together with information for all other fields combined.
SIGNIFICANT PROVED PROPERTIES
(IN THOUSANDS)
<TABLE>
<CAPTION>
PROVED RESERVES AT JANUARY 1, 2000 1999 PRODUCTION
------------------------------------- -------------------------------------
GAS GAS
OIL GAS EQUIVALENT OIL GAS EQUIVALENT
PROPERTY (MBBLS) (MMCF) (MMCFE) % (MBBLS) (MMCF) (MMCFE) %
- -------- ------- ------- ------- ------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
NORTH LOUISIANA:
Ada field ........................ -- 186 186 11.8 -- 34 34 9.2
Sailes field ..................... -- -- -- -- -- 133 133 36.0
Sibley field ..................... 10 439 499 31.6 -- 38 38 10.4
West Bryceland field ............. -- -- -- -- -- -- -- --
SOUTH LOUISIANA:
Orange Grove/Humphreys field ..... -- -- -- -- 2 21 33 9.0
Ouiski Bayou field ............... 54 553 877 55.5 6 71 107 29.2
OTHER:
As a group ....................... -- 18 18 1.1 1 17 23 6.2
------- ------- ------- ------- ------- ------- ------- -------
Total .......................... 64 1,196 1,580 100.0 9 314 368 100.0
======= ======= ======= ======= ======= ======= ======= =======
</TABLE>
As part of the Phillips Transaction described above, the Partnership
conveyed its interests in the West Bryceland and Sailes fields to Phillips.
Additional information regarding these fields is set forth below.
Unless otherwise noted, acreage and well information is provided as of December
31, 1999, and reserve information is provided as of January 1, 2000:
NORTH LOUISIANA
Ada Field. The Ada field is located in Bienville and Webster Parishes,
Louisiana. The Partnership has an interest in 1 gross (.14 net) well producing
from the Sligo and Hosston formations at a depth of 8,600 feet. The well is
operated by a third party. The Ada field reserves are 100% proved developed.
Sailes Field and West Bryceland fields. The Partnership sold its
interest in these two fields to Phillips in the transaction described above.
Sibley Field. The Sibley field is located in Webster Parish, Louisiana.
The Partnership has interests in 5 gross (.34 net) wells producing from the
Hosston formation at depths ranging from 7,300 to 10,000 feet. Kelley Oil
operates one of the wells. The Sibley field reserves are 100% proved developed.
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SOUTH LOUISIANA
Orange Grove/Humphreys Field. The Orange Grove/Humphreys field is
located in Terrebonne Parish, Louisiana. The Partnership has an interest in 1
gross (0.33 net) well producing from the 1st Hollywood formation at a depth
of approximately 11,600 feet. Kelley Oil operates the well. The Orange
Grove/Humphreys field reserves are 100% proved developed.
Ouiski Bayou Field. The Ouiski Bayou field is located in Terrebonne
Parish, Louisiana. The Partnership has an interest in 1 gross (.33 net) well
producing from the Cib op formation at a depth of 17,000 feet. Kelley Oil
operates the well. The Ouiski Bayou field reserves are 100% proved developed.
PRODUCTION, PRICE AND COST DATA
The following tables set forth the oil and gas production, average
sales price (including transfers) and average production costs (lifting cost
plus ad valorem and severance taxes) per equivalent unit of oil and gas produced
by the Partnership for the years ended December 31, 1997, 1998 and 1999.
Detailed additional information concerning the Partnership's oil and gas
producing activities is contained in the Supplementary Financial Information
included in Note 7 to the Partnership's Financial Statements.
OIL AND GAS PRODUCTION
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------
1997 1998 1999
--------- --------- --------
<S> <C> <C> <C>
Crude oil, condensate and natural gas liquids (Bbls)............................ 11,395 10,172 9,398
Natural gas (Mmcf).............................................................. 963 601 314
</TABLE>
AVERAGE SALES PRICES AND PRODUCTION COSTS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------
1997 1998 1999
--------- --------- --------
<S> <C> <C> <C>
Average sales price:
Crude oil, condensate and natural gas liquids per Bbl........................$ 19.92 $ 13.56 $ 15.78
Natural gas per Mcf, including the effects of hedging........................ 2.18 2.10 2.11
Oil and gas revenues per Mcfe................................................... 2.25 2.11 2.15
Average production costs per Mcfe............................................... .56 .75 .89
</TABLE>
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OIL AND GAS WELLS
As of December 31, 1999, the Partnership owned interests in productive
oil and gas wells (including producing wells and wells capable of production) as
follows:
<TABLE>
<CAPTION>
GROSS(1) NET
--------- ---------
<S> <C> <C>
Oil wells............................................................................... - -
Gas wells............................................................................... 10 1.37
--------- ---------
Total.................................................................................. 10 1.37
========= =========
</TABLE>
(1) One or more completions in the same hole are counted as one well; none
of the wells have multiple completions.
Wells Drilled. All of the wells drilled by the Partnership are
development wells based on definitions in the Partnership Agreement of the
Partnership. The following table sets forth the number of gross and net
productive and dry development wells and exploratory wells drilled by the
Partnership during the periods indicated, based on a narrower definition for
development wells under SEC guidelines.
<TABLE>
<CAPTION>
GROSS GROSS NET NET
DEVELOPMENT WELLS EXPLORATORY WELLS DEVELOPMENT WELLS EXPLORATORY WELLS
------------------ ----------------- ------------------- ------------------
PRODUCTIVE DRY PRODUCTIVE DRY PRODUCTIVE DRY PRODUCTIVE DRY
---------- --- ---------- --- ---------- --- ---------- ---
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1997....................... - - - - - - - -
1998....................... - - - - - - - -
1999....................... - - - - - - - -
</TABLE>
MARKETING OF NATURAL GAS AND CRUDE OIL
The Partnership does not refine or process any of the oil and natural
gas it produces. The natural gas production of the Partnership is sold to
various purchasers typically in the areas where the natural gas is produced. The
Partnership currently is able to sell, under contracts providing for periodic
price adjustments or in the spot market, all of its natural gas at current
market prices. Its revenue streams are therefore sensitive to changes in current
market prices. The Partnership's sales of crude oil, condensate and natural gas
liquids generally are related to posted field prices.
In addition to marketing natural gas and crude oil produced on
Partnership properties, a subsidiary of Kelley Oil aggregates volumes to
increase market power, provides gas transportation arrangements, provides
nomination and gas control services, supervises gas gathering operations and
performs revenue receipt and disbursement services as well as regulatory filing,
recordkeeping, inspection, testing, monitoring functions, coordinating the
connection of wells to various pipeline systems, performing gas market surveys
and overseeing gas balancing with its various gas gatherers and transporters.
The Partnership believes that its activities are not currently
constrained by a lack of adequate transportation systems or system capacity and
does not foresee any material disruption in available transportation for its
production. However, there can be no assurance that the Partnership will not
encounter constraints in the future. In that event, the Partnership would be
forced to seek alternate sources of transportation and may face increased costs.
HEDGING OF NATURAL GAS
Contour has periodically used forward sales contracts, natural gas
price swap agreements, natural gas basis swap agreements and options to reduce
exposure to downward price fluctuations on its natural gas production. Contour
does not engage in speculative transactions. Contour's hedging activities also
cover the oil and gas production attributable to the
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Partnership, including the interest in such production of the public unitholders
of the Partnership. During 1999, the Company used price and basis swap
agreements to hedge its exposure to possible declines in natural gas prices.
Additional information concerning Partnership hedging activities during 1999 is
set forth in "Management's Discussion and Analysis of Financial Condition and
Results of Operations" contained elsewhere in this Report.
COMPETITION
The oil and gas industry is highly competitive. Major oil and gas
companies, independent concerns, drilling and production purchase programs and
individual producers and operators are active bidders for desirable oil and gas
properties, as well as the equipment and labor required to operate those
properties. Many competitors have financial resources substantially greater than
those of the Partnership and staffs and facilities substantially larger than
those of Kelley Oil. The availability of a ready market for the oil and gas
production of the Partnership depends in part on the cost and availability of
alternative fuels, the level of consumer demand, the extent of other domestic
production of oil and gas, the extent of importation of foreign oil and gas, the
cost of and proximity to pipelines and other transportation facilities,
regulations by state and federal authorities and the cost of complying with
applicable environmental regulations.
EMPLOYEES
The Partnership has no employees and utilizes the management and staff
of Kelley Oil. As of December 31, 1999, Kelley Oil had 47 employees. Kelley
Oil's staff includes employees experienced in geology, geophysics, petroleum
engineering, land acquisition and management, finance and accounting. See
"Directors and Executive Officers of Kelley Oil Corporation." None of Kelley
Oil's employees are represented by a union. Kelley Oil has never experienced an
interruption in its operations from any kind of labor dispute, and its working
relationship with its employees is satisfactory.
REGULATION
The Partnership's operations are subject to extensive and continually
changing regulation, as legislation affecting the oil and natural gas industry
is under constant review for amendment and expansion. Many departments and
agencies, both federal and state, are authorized by statute to issue and have
issued rules and regulations binding on the oil and natural gas industry and its
individual participants. The failure to comply with such rules and regulations
can result in substantial penalties. The regulatory burden on the oil and
natural gas industry increases the Partnership's cost of doing business and,
consequently, affects its profitability. However, the Partnership does not
believe that it is affected in a significantly different manner by these
regulations than are its competitors in the oil and natural gas industry.
Because of the numerous and complex federal and state statutes and regulations
that may affect the Partnership, directly or indirectly, the following
discussion of certain statutes and regulations should not be relied upon as an
exhaustive review of all matters affecting the Partnership's operations.
Transportation and Production
Transportation and Sale of Natural Gas and Crude Oil. Sales of natural
gas, crude oil and condensate ("Products") can be made by the Partnership at
market prices not subject at this time to price controls. The price that the
Partnership receives from the sale of these Products is affected by the ability
to transport and cost of transporting the Products to market. Under applicable
laws, the Federal Energy Regulation Commission ("FERC") regulates both the
construction of pipeline facilities and the transportation of Products in
interstate commerce.
Regulation of Drilling and Production. Drilling and production
operations of the Partnership are subject to regulation under a wide range of
state and federal statutes, rules, orders and regulations. State and federal
statutes and regulations govern, among other matters, the amounts and types of
substances and materials that may be released into the environment, the
discharge and disposition of waste materials, the reclamation and abandonment of
wells and facility sites and remediation of contaminated sites, and require
permits for drilling operations, drilling bonds and reports concerning
operations. Most states in which the Partnership owns and operates properties
have regulations governing conservation matters, including provisions for the
unitization or pooling of oil and natural gas properties, the establishment of
maximum
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rates of production from oil and natural gas wells and the regulation of the
spacing, plugging and abandonment of wells. Many states also restrict production
to the market demand for oil and natural gas and several states have indicated
interest in revising applicable regulations. The effect of these regulations is
to limit the amount of oil and natural gas the Partnership can produce from its
wells and to limit the number of wells or the locations at which it can drill.
Moreover, each state generally imposes an ad valorem, production or severance
tax with respect to the production and sale of crude oil, natural gas and gas
liquids within its jurisdiction.
Environmental Regulations
General. The various federal environmental laws, including the National
Environmental Policy Act; the Clean Air Act of 1990, as amended ("CAA"); Oil
Pollution Act of 1990, as amended ("OPA"); Water Pollution Control Act, as
amended ("FWPCA"); the Resource Conservation and Recovery Act as amended
("RCRA"); the Toxic Substances Control Act; and the Comprehensive Environmental
Response, Compensation and Liability Act, as amended ("CERCLA"), and the various
state and local environmental laws, and the regulations adopted pursuant to such
law, governing the discharge of materials into the environment, or otherwise
relating to the protection of the environment, continue to be taken seriously by
the Partnership. In particular, the Partnership's drilling, development and
production operations, its activities in connection with storage and
transportation of crude oil and other liquid hydrocarbons and its use of
facilities for treating, processing or otherwise handling hydrocarbons and
wastes therefrom are subject to stringent environmental regulation, and
violations are subject to reporting requirements, civil penalties and criminal
sanctions. As with the industry generally, compliance with existing regulations
increases the Company's overall cost of business. The increased costs are not
reasonably ascertainable. Such areas affected include unit production expenses
primarily related to the control and limitation of air emissions and the
disposal of produced water, capital costs to drill exploration and development
wells resulting from expenses primarily related to the management and disposal
of drilling fluids and other oil and natural gas exploration wastes and capital
costs to construct, maintain and upgrade equipment and facilities and plug and
abandon inactive well sites and pits.
Environmental regulations historically have been subject to frequent
change by regulatory authorities, and the Partnership is unable to predict the
ongoing cost of compliance with these laws and regulations or the future impact
of such regulations on its operations. However, the Partnership does not believe
that changes to these regulations will materially adversely affect its
competitive position because the Partnership's competitors are similarly
affected. A discharge of hydrocarbons or hazardous substances into the
environment could subject the Partnership to substantial expense, including both
the cost to comply with applicable regulations pertaining to the remediation of
releases of hazardous substances into the environment and claims by neighboring
landowners and other third parties for personal injury and property damage. The
Partnership maintains insurance, which may provide protection to some extent
against environmental liabilities, but the coverage of such insurance and the
amount of protection afforded thereby cannot be predicted with respect to any
particular possible environmental liability and may not be adequate to protect
the Partnership from substantial expense.
The OPA and regulations thereunder impose a variety of regulations on
"responsible parties" related to the prevention of oil spills and liability for
damages resulting from such spills in United States waters. A "responsible
party" includes the owner or operator of an onshore facility, vessel, or
pipeline, or the lessee or permittee of the area in which an offshore facility
is located. The OPA assigns liability to each responsible party for oil removal
costs and a variety of public and private damages. The FWPCA imposes
restrictions and strict controls regarding the discharge of produced waters and
other oil and natural gas wastes into navigable waters. State laws for the
control of water pollution also provide varying civil, criminal and
administrative penalties and impose liabilities in the case of a discharge of
petroleum or its derivatives, or other hazardous substances, into state waters.
In addition, the Environmental Protection Agency ("EPA") has promulgated
regulations that require many oil and natural gas production operations to
obtain permits to discharge storm water runoff.
The CAA requires or will require most industrial operations in the
United States to incur capital expenditures in order to meet air emission
control standards developed by the EPA and state environmental agencies.
Although no assurances can be given, the Company believes implementation of such
amendments will not have a material adverse effect on its financial condition or
results of operations. RCRA is the principal federal statute governing the
treatment, storage and disposal of hazardous wastes. RCRA imposes stringent
operating requirements (and liability for failure to meet such requirements) on
a person who is either a "generator" or "transporter" of hazardous waste or an
"owner" or "operator" of a
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hazardous waste treatment, storage or disposal facility. At present, RCRA
includes a statutory exemption that allows oil and natural gas exploration and
production wastes to be classified as non-hazardous waste. As a result, the
Partnership is not required to comply with a substantial portion of RCRA's
requirements because its operations generate minimal quantities of hazardous
wastes.
CERCLA, also known as "Superfund", imposes liability, without regard to
fault or the legality of the original act, on certain classes of persons that
contributed to the release of a "hazardous substance" into the environment.
These persons include the "owner" or "operator" of the site and companies that
disposed or arranged for the disposal of the hazardous substances found at the
site. CERCLA also authorizes the EPA and, in some instances, third parties to
act in response to threats to the public health or the environment and to seek
to recover from the responsible classes of persons the costs they incur. In the
course of its ordinary operations, the Partnership may generate waste that may
fall within CERCLA's definition of a "hazardous substance". As a result, the
Partnership may be jointly and severally liable under CERCLA or under analogous
state laws for all or part of the costs required to clean up sites at which such
wastes have been disposed. The Partnership currently owns or leases, and has in
the past owned or leased, numerous properties that for many years have been used
for the exploration and production of oil and natural gas. Although the
Partnership has utilized operating and disposal practices that were standard in
the industry at the time, hydrocarbons or other wastes may have been disposed of
or released on or under the properties owned or leased by the Partnership on or
under other locations where such wastes have been taken for disposal. In
addition, many of these properties have been operated by third parties whose
actions with respect to the treatment and disposal or release of hydrocarbons or
other wastes were not under the Partnership's control. These properties and
wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws.
Under such laws, the Partnership could be required to remove or remediate
previously disposed wastes (including wastes disposed of or released by prior
owners or operators), to clean up contaminated property (including contaminated
groundwater) or to perform remedial plugging operations to prevent future
contamination.
CAUTION AS TO FORWARD-LOOKING STATEMENTS
Statements contained in this Report and other materials filed or to be
filed by the Partnership with the Securities and Exchange Commission (as well as
information included in oral or other written statements made or to be made by
the Company or its representatives) that are forward-looking in nature are
intended to be "forward-looking statements" within the meaning of Section 27A of
the Securities Act of 1933, as amended, and Section 21E of the Securities
Exchange Act of 1934, as amended, relating to matters such as anticipated
operating and financial performance, business prospects, developments and
results of the Partnership. Actual performance, prospects, developments and
results may differ materially from any or all anticipated results due to
economic conditions and other risks, uncertainties and circumstances partly or
totally outside the control of the Partnership, including rates of inflation,
natural gas prices, uncertainty of reserve estimates, rates and timing of future
production of oil and gas, exploratory and development activities, acquisition
risks and activities, changes in the level and timing of future costs and
expenses related to drilling and operating activities and those risks described
under "Risk Factors" below.
Words such as "anticipated," "expect," "estimate," "project" and
similar expressions are intended to identify forward-looking statements.
Forward-looking statements include the risks described in "Risk Factors".
RISK FACTORS
The Partnership cautions that the following risk factors could affect
its actual results in the future, in addition to "Uncertainties in Estimating
Reserves" and "liquidity and Capital Resources" discussed elsewhere in this
Report.
Depletion of Reserves. Producing oil and natural gas reservoirs
generally are characterized by declining production rates that vary depending
upon reservoir characteristics and other factors. The Partnership's future oil
and natural gas reserves and production, and, therefore, cash flow and income,
are highly dependent upon its success in efficiently producing its reserves.
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Substantial Leverage. As of December 31, 1999, the Partnership has
total indebtedness for money borrowed of approximately $166,000 and partners'
equity of approximately $887,000. The Partnership's ability to make payments of
principal, to pay interest on or to refinance its indebtedness for money
borrowed depends on its future performance, which is subject not only to its own
actions but also to general economic, financial, competitive, legislative,
regulatory and other factors beyond its control, as well as to the prevailing
market prices for oil, natural gas and natural gas liquids.
Volatility of Oil, Natural Gas and Natural Gas Liquids Prices. The
Partnership's financial results are affected significantly by the prices
received for its oil, natural gas and natural gas liquids production.
Historically, the markets for oil, natural gas and natural gas liquids have been
volatile and are expected to continue to be volatile in the future. The prices
received by the Partnership for its oil, natural gas and natural gas liquids
production and the levels of such production are subject to government
regulation, legislation and policies. The Partnership's future financial
condition and results of operations will depend, in part, upon the prices
received for its oil and natural gas production, as well as the costs of
developing and producing reserves.
Operating Hazards and Uninsured Risks. Oil and gas drilling activities
are subject to numerous risks, many of which are uninsurable, including the risk
that no commercially viable oil or natural gas production will be obtained; many
of such risks are beyond the Partnership's control. The decision to develop a
prospect or property will depend in part on the evaluation of data obtained
through geophysical and geological analyses, production data and engineering
studies, the results of which are often inconclusive or subject to varying
interpretations. The cost of drilling, completing and operating wells is often
uncertain, and overruns in budgeted expenditures are common risks that can make
a particular project uneconomical. Technical problems encountered in actual
drilling, completion and workover activities can delay such activity and add
substantial costs to a project. Further, drilling may be curtailed, delayed or
canceled as a result of many factors, including title problems, weather
conditions, compliance with government permitting requirements, shortages of or
delays in obtaining equipment, reductions in product prices and limitations in
the market for products. Although domestic drilling activity is currently at a
relatively low level, resulting in less demand for such services and a general
decrease in service costs, there can be no assurance that such market conditions
will continue.
The availability of a ready market for the Partnership's oil and
natural gas production also depends on a number of factors, including the demand
for and supply of oil and natural gas and the proximity of reserves to pipelines
or trucking and terminal facilities. Natural gas wells may be partially or
totally shut in for lack of a market or because of inadequacy or unavailability
of natural gas pipeline or gathering system capacity.
The Partnership's oil and natural gas business also is subject to all
of the operating risks associated with the drilling for and production of oil
and natural gas, including, but not limited to, uncontrollable flows of oil,
natural gas, brine or well fluids into the environment (including groundwater
and shoreline contamination), blowouts, cratering, mechanical difficulties,
fires, explosions, pollution and other risks, any of which could result in
substantial losses to the Partnership. Although the Partnership maintains
insurance at levels that it believes are consistent with industry practices, it
is not fully insured against all risks. Losses and liabilities arising from
uninsured and underinsured events could have a material adverse effect on the
financial condition and operations of the Partnership.
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SIGNATURES
Pursuant to the requirements of Rule 12b-15 under 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 4th day of May
2000.
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
By: KELLEY OIL CORPORATION, Managing General Partner
By: /s/ Rick G. Lester
-----------------------
Rick G. Lester
Senior Vice President
and Chief Financial Officer
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