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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996 COMMISSION FILE NO. 0-23784
KELLEY PARTNERS 1994
DEVELOPMENT DRILLING PROGRAM
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
TEXAS 76-0419001
(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 1994 Development Drilling Program had
20,864,414 units of limited and general partner interests (the "Units")
outstanding. The Units are not publicly traded.
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<PAGE>
PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
INTRODUCTION
GENERAL. Kelley Partners 1994 Development Drilling Program, a Texas
limited partnership (the "Partnership") formed in 1994 to develop oil and gas
properties located onshore in Louisiana. The Partnership issued a total of
20,864,414 units of limited and general partner interests ("Units"),
representing 96.04% of the total interests in the Partnership, for $62,593,242.
Of this amount, the Partnership distributed $340,105 of uncommitted capital at
the end of March 1996. See "Development and Production" below. The Units consist
of 1,188,796 Units of limited partner interests ("LP Units") and 19,675,618
Units of general partner interests ("GP Units"). In addition, the Partnership
issued managing and special general partner interests, representing the
remaining 3.96% of the total interests in the Partnership, for $2,580,897. In
the aggregate, Kelley Oil Corporation, the managing general partner of the
Partnership (the "Managing General Partner" or "Kelley Oil"), owns 92.2% of the
total interests of the Partnership. 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 joing venture (the "Joint Venture") between the Partnership and Kelley
Operating Company, Ltd. ("Kelley Operating"), a subsidiary partnership of Kelley
Oil. The Partnership has contributed to the Joint Venture substantially all of
the partners' contributed capital in order 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 has contributed to the Joint Venture specific drilling
rights for wells on its properties selected by the Managing General Partner. In
return for the contributed drilling rights, Kelley Operating has 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 has retained
one third of its working interest associated with the drilling rights
contributed to the Joint Venture. Accordingly, Kelley Operating contributed
proportionately to the development and operating costs of all of the
Partnership's wells and receives a proportionate share of the revenues
attributable to the sale of production from those wells.
DEVELOPMENT AND PRODUCTION. As of January 1, 1997, the Partnership had
participated in drilling 86 gross wells, of which 82 gross (23.73 net) wells
have been found to be productive and 4 gross (2.67 net) wells were dry. During
1996, recompletion and work-over operations were conducted on several wells, and
one-half of the Partnership's interests in four wells were sold. From its
inception through December 31, 1996, the Partnership produced 12.2 Bcf of
natural gas and 113,788 barrels of oil and natural gas liquids, generating total
oil and gas revenues of $27,524,000, of which $22,159,207 or $1.02 per Unit has
been distributed to the partners.
The Partnership Agreement restricts activities of the Partnership to the
financing of development wells drilled by the Joint Venture and requires any
contributions of the partners not used or committed to be used for drilling
activities within two years after the commencement of operations (the
"Commitment Period"), except for necessary operating capital, to be distributed
to the partners on a pro rata basis as a return of capital. In accordance with
this requirement, Kelley Oil determined the adjusted level of total partnership
capital at $60.7 million as of the end of the Commitment Period based on an
additional 34 wells committed for drilling in 1996 plus 14 proved undeveloped
locations expected to be drilled thereafter. Accordingly, the Partnership
distributed $340,105 of uncommitted capital or $0.20 per Unit to Unitholders
other than Kelley
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Oil ("Public Unitholders") at the end of March 1996. As of March 15, 1997, the
Contemplated Capital for the remainder of the drilling activities projected for
the Partnership will exceed the Committed Expenditures by approximately $2.7
million, or $0.12 per Unit. Accordingly, a distribution of the excess
Contemplated Capital is expected to be made in 1997. 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 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......................... 121 107 118
Proved undeveloped....................... 462 60 5
------- ------- -------
Total proved........................... 583 167 123
======= ======= =======
Natural gas (Mmcf):
Proved developed......................... 13,557 16,988 31,296
Proved undeveloped....................... 35,589 41,652 4,051
------- ------- -------
Total proved........................... 49,146 58,640 35,347
======= ======= =======
Detailed information concerning the Partnership's estimated proved
reserves and discounted net future cash flows is contained in the Supplementary
Financial Information included in Note 6 to the Partnership's Financial
Statements. The Partnership has not filed any estimates of reserves with any
federal authority or agency during the past year other than estimates contained
in its last annual report filed with the SEC.
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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.
DESCRIPTION OF SIGNIFICANT PROPERTIES
GENERAL. The properties of the Partnership consist primarily of
interests in producing wells located in the Hosston, Smackover and Miocene
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:
Sibley field.................. 18 11,587 11,695 32.4 4 2,621 2,645 32.4
Sailes field.................. 55 10,004 10,334 28.6 18 2,732 2,840 34.8
West Bryceland field.......... 16 8,581 8,677 24.1 2 862 874 10.7
Ada field..................... 8 4,102 4,150 11.5 2 625 637 7.8
SOUTH LOUISIANA(1):
Fire Island field............. 13 669 747 2.1 10 469 529 6.5
Orange Grove/Humphreys field.. 11 56 122 .3 13 558 636 7.8
OTHER:
As a group.................... 2 348 360 1.0 -- 5 5 --
--------- ------------ ------------ ------- ------ ------- ------ -------
Total...................... 123 35,347 36,085 100.0 49 7,872 8,166 100.0
========= ============ ============ ======= ====== ======= ====== =======
</TABLE>
- ------------
(1) Effective December 1, 1996, Kelley entered into a joint venture whereby
it sold in the Houma Embayment, including in the Orange Grove/Humphreys and
Ouiski Bayou fields, 50% of its net acreage position as well as 50% of its
interest in 23 wells and related facilities in such area. The sale included
interest in four Partnership wells.
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:
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NORTH LOUISIANA
SIBLEY FIELD. The Sibley field is located in Webster Parish, Louisiana.
The Partnership has interests in 21 gross (3.89 net) wells producing from the
Hosston A, B and C formations at depths ranging from 4,600 to 8,900 feet. Kelley
Oil operates 14 of the wells. The Sibley field reserves are 96% proved
developed.
SAILES FIELD. The Sailes field is located in Bienville Parish,
Louisiana. The Partnership has interests in 28 gross (9.94 net) wells producing
from the Glen Rose, Hosston A, B and C formations at depths ranging from 7,200
to 9,900 feet. Kelley Oil operates 26 of the wells. The Sailes field reserves
are 97% proved developed.
WEST BRYCELAND FIELD. The West Bryceland field is located in Bienville
Parish, Louisiana. The Partnership has interests in 18 gross (4.40 net) wells
producing from the Hosston A, B and C formations at depths ranging from 7,100 to
10,000 feet. Kelley Oil operates 16 of the wells. The West Bryceland field
reserves are 85% proved developed.
ADA FIELD. The Ada field is located in Bienville and Webster Parishes,
Louisiana. The Partnership has an interest in 3 gross (.76 net) wells producing
from the Hosston A and B formations at depths ranging from 7,500 to 8,600 feet.
Kelley operates one of the wells. The Ada field reserves are 50% proved
developed.
SOUTH LOUISIANA
FIRE ISLAND FIELD. The Fire Island field is located in Vermillion
Parish, Louisiana. The Partnership has an interest in 1 gross (.67 net) well
producing from the MA-36 formation at a depth of 14,167 feet. Kelley Oil
operates the well. The Fire Island field reserves are 100% proved developed.
ORANGE GROVE/HUMPHREYS FIELD. The Orange Grove/Humphreys field is
located in Terrebonne Parish, Louisiana. The Partnership has interests in 3
gross (1.01 net) wells producing from the Big Hum, Realty, Bourg and KK
formations at depths ranging from 10,700 to 12,800 feet. Kelley Oil operates all
of the wells. The Orange Grove/Humphreys 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 period from inception through December 31, 1994 and for the years ended
December 31, 1995 and 1996. Detailed additional information concerning the
Partnership's oil and gas producing activities is contained in the Supplementary
Information.
OIL AND GAS PRODUCTION
FEBRUARY 28,
1994 (DATE
OF INCEPTION)
THROUGH YEAR ENDED DECEMBER 31,
DECEMBER 31, -----------------------
1994 1995 1996
------- ------- -----
Crude oil, condensate and
natural gas liquids (Bbls).......... 14,804 49,816 49,168
Natural gas (Mmcf).................... 339 4,000 7,872
4
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AVERAGE SALES PRICES AND PRODUCTION COSTS
FEBRUARY 28,
1994 (DATE
OF INCEPTION)
THROUGH YEAR ENDED DECEMBER 31,
DECEMBER 31, -----------------------
1994 1995 1996
------- ------- -----
Average sales price:
Crude oil, condensate and natural
gas liquids (Bbl)................. $ 16.17 16.58 21.59
Natural gas (Mcf)................... 1.70 1.71 2.27
Oil and gas revenues per Mcfe......... 1.90 1.80 2.32
Average production costs per Mcfe..... .29 .26 .29
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............................. 2 .38
Gas wells............................. 75 21.64
------ -----
Total............................... 77 22.02
====== =====
- ------------
(1) One or more completions in the same hole are counted as one well; one of the
wells has 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 from inception through December 31, 1996, 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.......... 16 -- 1 2 5.59 -- .67 1.33
1995.......... 27 1 -- 1 8.89 .67 -- .67
1996.......... 38 -- -- -- 10.11 -- -- --
</TABLE>
5
<PAGE>
Initial test results for wells completed during the fourth quarter of
1996 are summarized below.
<TABLE>
<CAPTION>
INITIAL TEST RESULTS(1)
FROM
FOURTH QUARTER 1996 COMPLETIONS
THOUSAND
WELL NAME FLOWING CUBIC BARRELS
FIELD NAME COMPLETION RESERVOIR CHOKE TUBING FEET OIL WORKING
PARISH, STATE DATE COMPLETED PERFORATIONS SIZE PRESSURE PER DAY PER DAY INTEREST
- ----------------------------- --------- --------- ------------- ----- -------- ------- ------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Stewart #1-Alt. 10/24/96 Hosston 7520 - 9503' 17 1,225 4,962 48 .219876
Sailes A & B
Bienville, LA
Smith Heirs 27 #1-Alt. 10/29/96 Hosston 7350 - 10103' 20 1,000 678 25 .600734
Sailes A & B
Bienville, LA
O.L. McConathy #3-Alt. 10/11/96 Hosston 7389 - 9620' 17 2,640 5,009 10 .135077
West Bryceland A & B
Bienville, LA
Sutton A #3-Alt. 11/22/96 Hosston 7762 - 10131' 16 2,800 5,067 23 .223416
West Bryceland A & B
Bienville, LA
Smith #2-Alt. 11/26/96 Hosston 7374 - 9860' 19 1,440 2,520 7 .135077
West Bryceland A & B
Bienville, LA
LA Minerals, Ltd. 23 #2-Alt. 11/20/96 Hosston 7090 - 9446' 12 3,475 1,652 3 .128695
West Bryceland A & B
Bienville, LA
Fizer et. al. #1-Alt. 11/27/96 Hosston 6835 - 8806' 18 1,275 1,208 2 .172986
Sibley A & B
Webster, LA
Hamner et. al. 30 #1-Alt. 12/20/96 Hosston 6860 - 8813' 15 2,350 3,184 30 .136965
West Bryceland A & B
Bienville, LA
Yates #1-Alt. 12/10/96 Hosston 7228 - 8894' 12 1,860 1,877 5 .295261
Sibley A & B
Webster, LA
</TABLE>
- ------------
(1)Reflects initial test results reported under state reporting requirements
and may not be indicative of actual producing rates to sales.
WELLS IN PROGRESS. At December 31, 1996, 3 gross (1.50 net) wells were
in progress of drilling.
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
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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. Kelley considers 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 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
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
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 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
7
<PAGE>
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. 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-ofservice 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
8
<PAGE>
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.
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
9
<PAGE>
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.
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 nonhazardous 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
10
<PAGE>
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.
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 is involved from time to time 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 658 holders of record of the
Partnership's Units.
11
<PAGE>
The following table sets forth the cash distributions per Unit paid by
the Partnership during the periods indicated.
DISTRIBUTIONS
-------------
1995
----
First quarter................................. $ .04
Second quarter................................ .09
Third quarter................................. .10
Fourth quarter................................ .10
1996
----
First quarter................................. .12
Second quarter................................ .18
Third quarter................................. .18
Fourth quarter................................ .21
1997
----
First quarter................................. .22
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.
In addition to its regular distributions of net available cash from
quarterly operations, the Partnership distributed $340,105 of uncommitted
capital or $0.20 per Unit to the Public Unitholders in March 1996. As of March
15, 1997, the Contemplated Capital for the remainder of the drilling activities
projected for the Partnership will exceed the Committed Expenditures by
approximately $2.7 million, or $0.12 per Unit. Accordingly, a distribution of
the excess Contemplated Capital is expected to be made in 1997. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."
12
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
The following table presents selected financial data for the
Partnership. The financial information presented below is derived from the
Partnership's audited Financial Statements presented elsewhere in this Report
and should be read in conjunction with those Financial Statements and the
related Notes thereto.
KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
<TABLE>
<CAPTION>
FEBRUARY 28,
1994 (DATE
OF INCEPTION)
THROUGH YEAR ENDED DECEMBER 31,
DECEMBER 31, -----------------------------
1994 1995 1996
------------ ------------ --------
<S> <C> <C> <C>
SUMMARY OF OPERATIONS:
Total revenues................................ $ 1,140 10,647 20,240
Production expenses........................... 126 1,123 2,348
Exploration and dry hole costs................ 3,389 6,767 606
General and administrative expenses........... 89 620 855
Interest expense.............................. 17 -- --
Depreciation, depletion and amortization...... 1,618 6,617 5,536
Impairment of oil and gas properties.......... -- 10,914 --
Net income (loss)............................. (4,099) (15,394) 10,896
Net income (loss) per Unit(1)................. (.19) (.71) .50
Net available cash from operations(2)......... 908 8,904 17,038
Net available cash per Unit(1)(2)............. .04 .41 .78
Units outstanding............................. 20,864 20,864 20,864
AS OF DECEMBER 31,
--------------------------------------------------
1994 1995 1996
------------ ------------ --------
SUMMARY BALANCE SHEET DATA:
Working capital (deficit)...................... $ 780 (4,515) 3,647
Oil and gas properties, net.................... 14,122 12,715 19,035
Total partners' equity......................... 14,902 8,200 22,682
Total assets................................... 18,017 15,789 26,452
</TABLE>
- ------------
(1) Per Unit amounts are based on the Unitholders' 96.04% share of net
income (loss).
(2) The Partnership's net available cash generally corresponds to the
sum of its net income (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 LongLived 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. 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
13
<PAGE>
analysis, the Partnership recognized a noncash impairment charge of $10.9
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
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
GENERAL. The Partnership commenced operations in the first quarter of
1994. Accordingly, the Partnership's operating results for 1994 do not reflect a
full year of production, and comparisons with 1995 and 1996 operating data may
not be meaningful.
YEAR ENDED DECEMBER 31, 1996 COMPARED TO YEAR ENDED DECEMBER 31, 1995.
Oil and gas revenues of $18,986,000 in 1996 increased 145.8% compared to
$7,723,000 in 1995. Production of natural gas increased 96.8% to 7,872,000 Mcf
in 1996 from 4,000,000 Mcf in 1995, while the average price of natural gas
increased 32.2% to $2.27 per Mcf in 1996 from $1.71 per Mcf in 1995. Production
of crude oil in 1996 totaled 49,168 barrels, with an average sales price of
$21.59 per barrel, compared to 49,816 barrels at $16.58 per barrel in the prior
year, representing a volume decrease of 1.3% and a price increase of 30.2%. The
increase in revenues and production from 1995 levels reflects the Partnership's
completion of 38 wells during 1996.
Lease operating expenses and severance taxes were $2,348,000 in 1996 and
$1,123,000 in 1995, an increase of 109.1%, reflecting higher production levels.
On a unit of production basis, these expenses increased to $0.29 per Mcfe in
1996 from $0.26 per Mcfe in 1995.
The Partnership expensed exploration and dry hole costs of $606,000 in
1996 and $6,767,000 in 1995, a decrease of 91.0%, primarily reflecting a larger
allocation of resources to exploratory prospects in south Louisiana during 1995.
General and administrative expenses of $854,000 in 1996 increased 37.9%
from $620,000 in 1995, reflecting an increase in the Partnership's share of
administration costs associated with development operations of Kelley. On a unit
of production basis, these expenses decreased to $0.10 per Mcfe 1996 from $0.14
per Mcfe in 1995.
Depreciation, depletion and amortization ("DD&A") decreased to
$5,536,000 in 1996 compared to $6,617,000 in 1995 due to lower depletion rates
following noncash impairment charges aggregating $10,914,000 recognized in the
fourth quarter of 1995 against the carrying value of the Partnership's oil and
gas properties under FAS 121. On a unit of production basis, DD&A decreased to
$0.68 per Mcfe in 1996 from $1.54 per Mcfe in 1995. See "General-Property
Impairment under FAS 121" above.
The Partnership realized net income in 1996 of $10,896,000 or $0.50 per
Unit compared to a net loss of $15,394,000 or $0.71 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 the
14
<PAGE>
1995 property impariment, increased 91.4% in 1996 to $17,038,000 or $0.78 per
Unit compared to $8,904,000 or $0.41 per Unit in 1995.
YEAR ENDED DECEMBER 31, 1995 COMPARED TO YEAR ENDED DECEMBER 31, 1994.
Oil and gas revenues of $7,723,000 in 1995 increased 847.6% compared to $815,000
in 1994. During 1995, production of natural gas increased 1,079.9% from 339,000
Mcf in 1994 to 4,000,000 Mcf, while the average price of natural gas increased
less than 1% from $1.70 per Mcf in 1994 to $1.71 per Mcf in 1995. Production of
crude oil in 1995 totaled 49,816 barrels, with an average sales price of $16.58
per barrel compared to 14,804 barrels at $16.17 per barrel in 1994, representing
production and price increases of 236.5% and 2.5%, respectively. The increase in
revenues and production from 1994 levels reflects the Partnership's completion
of 27 wells brought on line during 1995. In addition, while natural gas prices
have remained depressed, hedging activities contributed $429,000 to oil and gas
revenues in 1995.
Lease operating expenses and severance taxes were $1,123,000 in 1995
versus $126,000 in 1994, an increase of 791.3%, reflecting the increased level
of production. On a unit of production basis, these expenses decreased to $0.26
per Mcfe in 1995 from $0.29 per Mcfe in 1994, due primarily to a decrease in the
severance tax rate during the last half of 1995.
The Partnership expensed exploration and dry hole costs of $6,767,000 in
1995 and $3,389,000 in 1994, an increase of 99.7%, primarily reflecting a larger
allocation of resources to exploratory prospects in south Louisiana during 1995.
Most of the Partnership's drilling expenditures in 1994 were incurred for
development wells and were therefore capitalized.
General and administrative expenses of $620,000 in 1995 increased 596.6%
from $89,000 in 1994, reflecting the Partnership's share of administration costs
associated with development operations of the Partnership and other partnerships
managed by Kelley Oil. On a unit of production basis, these expenses decreased
to $0.14 per Mcfe in 1995 from $0.21 per Mcfe in 1994, reflecting costs savings
from a significant staff reduction by Kelley Oil at the end of 1994.
DD&A increased 309.0% from $1,618,000 in 1994 to $6,617,000 in 1995 as a
result of significantly higher depletion rates due to increased production and
reserves over the prior year. On a unit of production basis, these noncash
charges decreased to $1.54 per Mcfe in 1995 from $3.78 per Mcfe in 1994. The
Partnership recognized an additional noncash charge of $10,914,000 as of
December 31, 1995 for impairment of the carrying value of its oil and gas
properties under FAS 121. See "General-Property Impairment under FAS 121" above.
The Partnership recognized a net loss of $15,394,000 or $0.71 per Unit
in 1995 compared to a net loss of $4,099,000 or $0.19 per Unit in 1994,
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 the 1995 property impairment, aggregated $8,904,000
or $0.41 per Unit in 1995 compared to $908,000 or $0.04 per Unit in 1994.
LIQUIDITY AND CAPITAL RESOURCES
LIQUIDITY. Net cash provided by the Partnership's operating activities
during 1996, as reflected on its statements of cash flows, totaled $8,121,000.
The Partnership's cash position was increased during 1996 by payments of
subscriptions for Units and General Partner contributions aggregating
$22,920,000. During the year, funds were used in investing and financing
activities comprised primarily of property and equipment expenditures of
$12,601,000 for development of the Partnership's oil and gas properties and
distributions to partners aggregating $19,334,000. As a result of these
activities, the Partnership's cash and cash equivalents decreased from $57,000
at December 31, 1995 to $25,000 at December 31, 1996.
CAPITAL RESOURCES. The Partnership Agreement contemplates pro rata
contributions from the Unitholders and the General Partners of $62,593,242
(96.04%) and $2,580,897 (3.96%), respectively, or an aggregate of $65,174,139
("Contemplated Capital"). Under the deferred payment option applicable to
investments in the Partnership exceeding $10,000, deferred subscriptions for
Units and the General Partners' deferred contributions were payable when called
by Kelley Oil during the period ended November 30, 1994. Kelley Oil initially
subscribed for 18,821,655 Units in addition to its 3.94% General Partner
interest in the Partnership. Following defaults by Public Unitholders on a total
of 342,234
15
<PAGE>
Units, the defaulted Units were subscribed by Kelley Oil in accordance with its
undertaking in the Partnership Agreement. This increased Kelley Oil's total
subscription commitment to $60,059,529 or 92.15% of the Partnership's total
Contemplated Capital (the "KOIL Share"), with the Public Unitholders committing
for the balance or 7.85% of the total Contemplated Capital (the "Public Share").
The Partnership Agreement requires any contributions of the partners not
used or committed to be used for drilling activities during the two-year
Commitment Period ended February 29, 1996, except for necessary operating
capital, to be distributed to the partners on a pro rata basis as a return of
capital. For this purpose, "committed for use" means funds that have been
contracted or allocated by Kelley Oil for drilling, completion or other
Partnership activities, and "necessary operating capital" means funds that, in
the opinion of Kelley Oil, should remain in reserve to assure the continued
operation of the Partnership.
From its inception through December 31, 1995, a total of $43.7 million
was expended on Partnership activities, including syndication costs. At the end
of the Commitment Period in February 1996, a total of $15.5 million was
contracted or allocated for drilling an additional 34 wells during 1996 and 14
proved undeveloped locations thereafter, plus $1.5 million for drilling
overruns, contingencies and necessary operating capital. The expenditures
through 1995 plus these budgeted expenditures aggregated $60.7 million
("Committed Expenditures"). On February 29, 1996, the Contemplated Capital
exceeded the Committed Expenditures by $4.4 million or $0.20 per Unit.
Accordingly, the Public Share of the excess Contemplated Capital aggregating
$340,105 was distributed to the Public Unitholders as a return of capital in
March 1996.
During 1996, Kelley initiated a program for streamlining operations,
improving drilling efficiency and reducing lease operating costs. These efforts
generated cost savings that have effectively reduced the February 1996 estimate
for Committed Expenditures. From inception through December 31, 1996, a total of
$55.3 million was expended on Partnership activities, including syndication
costs. For the balance of the Partnership's drilling program, a total of $2.4
million has been contracted or allocated for drilling an additional seven wells
during 1997 and two proved undeveloped locations thereafter, plus $0.3 million
for drilling overruns, contingencies and necessary operating capital. The
expenditures through 1996 plus these budgeted expenditures aggregate $58.0
million, representing a total reduction of $2.7 million or $.12 per Unit in
Committed Expenditures (the "Commitment Reduction"). As a result of the
Commitment Reduction, a distribution of the excess Contemplated Capital is
expected to be made in 1997.
As of March 15, 1997, Kelley Oil had contributed $54.6 million to the
Partnership, together with interest at a market rate on the portion of its
commitment that remained outstanding after November 1994. After giving effect to
the February 1996 reduction in Contemplated Capital under the Partnership
Agreement and the additional Commitment Reduction in 1997, the KOIL Share of
Committed Expenditures will be reduced to $53.4 million, entitling Kelley Oil to
participate in the planned 1997 distribution of excess Contemplated Capital
resulting from the Commitment Reduction. Kelley Oil's return of capital will be
limited to its excess contribution aggregating $1.2 million or $.06 per Unit.
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. The Credit Facility is secured by all the
oil and gas properties and other assets of KOGC and its subsidiaries, including
the Partnership and the Joint Venture. The agreement covering the Credit
Facility provides various financial covenants as well as restrictions on
additional debt, mergers and asset sales, but limits the lenders' recourse upon
any default to Partnership and Joint Venture assets attributable to Kelley Oil's
interests in the Partnership.
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 is generally defined as the net
operating cash flow of the Partnership after deducting working capital
requirements. The Partnership made four quarterly distributions in 1996
aggregating $0.69 per Unit or a total of $14,396,000, together with $594,000 to
the General Partners for their general partner interests. In March 1997, the
Partnership made a quarterly distribution of $0.22 per Unit (aggregating
$4,590,000), together with $189,000 to the General Partners for their general
partner interests. The distributions in each quarter generally represented
substantially all of the Partnership's net available cash from prior quarter
operations. The Partnership intends to continue making quarterly distributions
consistent with its cash distribution policy.
16
<PAGE>
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 per Unit........................... $ .19 $ .50
Exploration and dry hole costs per Unit....... -- .03
Depreciation, depletion and
amortization charges per Unit............... .03 .25
-------- -------
Net available cash per Unit................. $ .22 $ .78
======== =======
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............................... $ 16.17 1.70
December 31, 1995............................... 16.58 1.71
December 31, 1996............................... 21.59 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 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 factors
mentioned in this Report, the following additional risk factors should be
considered:
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.
17
<PAGE>
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.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM:
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Independent Auditors' Reports............................................................ 20
Balance Sheets - December 31, 1995 and 1996.............................................. 22
Statements of Operations - For the period ended December 31, 1994 and the years ended
December 31, 1995 and 1996............................................................. 23
Statements of Cash Flows - For the period ended December 31, 1994 and the years ended
December 31, 1995 and 1996............................................................. 24
Statements of Changes in Partners' Equity - For the period ended December 31, 1994
and the years ended December 31, 1995 and 1996......................................... 25
Notes to Financial Statements............................................................ 26
</TABLE>
18
<PAGE>
INDEPENDENT AUDITORS' REPORT
To the Partners of Kelley Partners 1994 Development Drilling Program
We have audited the accompanying balance sheets of Kelley Partners 1994
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 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 1994 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
19
<PAGE>
REPORT OF INDEPENDENT AUDITORS
To the Partners of Kelley Partners 1994 Development Drilling Program
We have audited the balance sheet of Kelley Partners 1994 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
period from February 28, 1994 (date of inception) through December 31, 1994. 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 1994
Development Drilling Program at December 31, 1994 and results of its operations
and its cash flows for the period from February 28, 1994 (date of inception)
through December 31, 1994, in conformity with generally accepted accounting
principles.
Ernst & Young LLP
Houston, Texas
March 6, 1995
20
<PAGE>
KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM
BALANCE SHEETS
($ IN THOUSANDS)
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------
1995 1996
-------- -----
<S> <C> <C>
ASSETS:
Cash.......................................................... $ 57 25
Accounts receivable - trade................................... 141 217
Accounts receivable - affiliates.............................. 2,855 7,175
Other assets.................................................. 21 --
-------- -------
Total current assets........................................ 3,074 7.417
-------- -------
Oil and gas properties, successful efforts method:
Properties subject to amortization.......................... 31,932 43,870
Less: Accumulated depreciation, depletion & amortization... (19,217) (24,835)
-------- -------
Total oil and gas properties................................ 12,715 19,035
-------- -------
TOTAL ASSETS.................................................. $ 15,789 26,452
======== =======
LIABILITIES:
Accounts payable and accrued expenses......................... $ 7,533 2,797
Accounts payable - affiliates................................. 56 973
-------- -------
Total current liabilities................................... 7,589 3,770
-------- -------
TOTAL LIABILITIES............................................. 7,589 3,770
-------- -------
PARTNERS' EQUITY:
LP Unitholders' equity........................................ 1,985 1,527
GP Unitholders' equity........................................ 4,751 20,025
Managing and Special General Partners' equity................. 1,464 1,130
-------- -------
TOTAL PARTNERS' EQUITY........................................ 8,200 22,682
-------- -------
TOTAL LIABILITIES AND PARTNERS' EQUITY.......................... $ 15,789 26,452
======== =======
</TABLE>
See Notes to Financial Statements.
21
<PAGE>
KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM
STATEMENTS OF OPERATIONS
(IN THOUSANDS EXCEPT PER UNIT DATA)
<TABLE>
<CAPTION>
FEBRUARY 28,
1994 (DATE
OF INCEPTION)
THROUGH YEAR ENDED DECEMBER 31,
DECEMBER 31, ---------------------------------
1994 1995 1996
------------ ------------ ------------
<S> <C> <C> <C>
REVENUES:
Oil and gas sales.......................... 815 7,723 18,986
Interest income............................ 325 2,924 1,254
------------ ------------ ------------
Total revenues.......................... 1,140 10,647 20,240
------------ ------------ ------------
COSTS AND EXPENSES:
Lease operating expenses................... 68 699 1,636
Severance taxes............................ 58 424 712
Exploration and dry hole costs............. 3,389 6,767 606
General and administrative expenses........ 89 620 854
Interest expense - affiliate............... 17 -- --
Depreciation, depletion and amortization... 1,618 6,617 5,536
Impairment of oil and gas properties....... -- 10,914 --
------------ ------------ ------------
Total costs and expenses................ 5,239 26,041 9,344
------------ ------------ ------------
NET INCOME (LOSS)............................. $ (4,099) (15,394) 10,896
============ ============ ============
NET INCOME (LOSS) ALLOCABLE TO LP UNITHOLDERS. $ (227) (832) 591
============ ============ ============
NET INCOME (LOSS) ALLOCABLE TO GP UNITHOLDERS. $ (3,709) (13,953) 9,874
============ ============ ============
NET INCOME (LOSS) ALLOCABLE TO MANAGING AND
SPECIAL GENERAL PARTNERS................... $ (163) (609) 431
============ ============ ============
NET INCOME (LOSS) PER UNIT.................... $ (.19) (.71) .50
============ ============ ============
Average Units outstanding..................... 20,864 20,864 20,864
============ ============ ============
</TABLE>
See Notes to Financial Statements.
22
<PAGE>
KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM
STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
FEBRUARY 28,
1994 (DATE
OF INCEPTION)
THROUGH YEAR ENDED DECEMBER 31,
DECEMBER 31, ---------------------------------
1994 1995 1996
------------ ------------ ------------
<S> <C> <C> <C>
OPERATING ACTIVITIES:
Net income (loss)....................................................$ (4,099) (15,394) 10,896
Adjustments to reconcile net loss to net cash provided by
(used in) operating activities:
Depreciation, depletion and amortization.......................... 1,618 6,617 5,536
Impairment of oil and gas properties.............................. -- 10,914 --
Dry hole costs.................................................... 2,485 6,081 (28)
Gain on sale of oil and gas properties............................ -- -- (89)
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable..................... (3,128) 132 (4,396)
Increase (decrease) in other assets............................ (5) (16) 21
Increase (decrease) in accounts payable and accrued expenses... 3,115 4,474 (3,819)
------------ ------------ ------------
Net cash provided by (used in) operating activities.................. (14) 12,808 8,121
------------ ------------ ------------
INVESTING ACTIVITIES:
Purchases of property and equipment.................................. (18,225) (22,273) (12,601)
Sale of other non-current assets..................................... -- 68 82
Sale of oil and gas properties....................................... -- -- 780
------------ ------------ ------------
Net cash used in investing activities................................ (18,225) (22,205) (11,739)
------------ ------------ ------------
FINANCING ACTIVITIES:
Capital contributed by partners...................................... 20,563 15,870 22,920
Syndication costs charged to equity.................................. (1,562) (9) --
Distributions to partners............................................ -- (7,169) (14,989)
Distributions of uncommitted capital................................. -- -- (4,345)
------------ ------------ ------------
Net cash provided by financing activities............................ 19,001 8,692 3,586
------------ ------------ ------------
Increase (decrease) in cash and cash equivalents..................... 762 (705) (32)
Cash and cash equivalents, beginning of period....................... -- 762 57
------------ ------------ ------------
Cash and cash equivalents, end of period.............................$ 762 57 25
============ ============ ============
</TABLE>
See Notes to Financial Statements.
23
<PAGE>
KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM
STATEMENTS OF CHANGES IN PARTNERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1995 AND 1996 AND THE
PERIOD FROM FEBRUARY 28, 1994 (DATE OF INCEPTION)
THROUGH DECEMBER 31, 1994
(IN THOUSANDS)
<TABLE>
<CAPTION>
MANAGING
AND
SPECIAL
LP GP GENERAL
UNITHOLDERS UNITHOLDERS PARTNERS TOTAL
----------- ----------- -------- ------
<S> <C> <C> <C> <C>
Capital contributed..................... $ 3,435 16,272 856 20,563
Syndication costs....................... (87) (1,413) (62) (1,562)
Net loss................................ (227) (3,709) (163) (4,099)
------- ------- ------- -------
Partners' equity at December 31, 1994. 3,121 11,150 631 14,902
------- ------- ------- -------
Capital contributed..................... 84 14,061 1,725 15,870
Syndication costs....................... (1) (8) -- (9)
Distributions........................... (387) (6,499) (283) (7,169)
Net loss................................ (832) (13,953) (609) (15,394)
------- ------- ------- -------
Partners' equity at December 31, 1995. 1,985 4,751 1,464 8,200
------- ------- ------- -------
Capital contributed..................... -- 22,920 -- 22,920
Return of capital contributed........... (236) (3,937) (172) (4,345)
Distributions........................... (813) (13,583) (593) (14,989)
Net income (loss)....................... 591 9,874 431 10,896
------- ------- ------- -------
Partners' equity at December 31, 1996. $ 1,527 20,025 1,130 22,682
======= ======= ======= =======
</TABLE>
See Notes to Financial Statements.
24
<PAGE>
KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM
NOTES TO FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION. Kelley Partners 1994 Development Drilling Program, a Texas
limited partnership (the "Partnership"), commenced operations on February 28,
1994 upon completion of a public offering of 20,864,414 units of limited partner
interests and general partner interests (the "Units") in the Partnership at
$3.00 per Unit. Subscribers for more than 3,333 Units were entitled to defer up
to 90% of their subscriptions, with deferred subscriptions payable when called
through November 30, 1994. As of December 31, 1996, Unit subscriptions
aggregating $58,420,000 were paid, and subscriptions receivable were
outstanding, aggregating $5,819,000, all of which was receivable from Kelley Oil
Corporation, the managing general partner of the Partnership ("Kelley Oil"). In
addition, as of December 31, 1996, Kelley Oil had contributed $2,397,000 to the
Partnership for its 3.94% general partner interest, and David L. Kelley, special
general partner of the Partnership, had contributed $12,166 for his .02% general
partner interest.
The Partnership was formed for the sole purpose of financing 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.
As of December 31, 1996, Kelley Oil and its officers and directors owned
19,163,889 (91.9%) Units and 1,000 (.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.
Kelley Oil contributed $38,824,016 or 64.6% of its total subscription
commitment during the two-year period ended February 29, 1996 (the "Commitment
Period"), together with interest at a market rate on the portion of its
subscription commitment that remained outstanding after November 30, 1994. As of
February 29, 1996, approximately $60.7 million or 93.2% of the Partnership's
committed capital had been used or committed to drilling activities, including
syndication costs. The Partnership Agreement requires any contributions of the
partners not used or committed to be used for the drilling of development wells
during the Commitment Period, except for necessary operating capital, to be
distributed to the partners on a pro rata basis as a return of capital. In
accordance with this requirement, the Partnership distributed $340,105 of
uncommitted capital or $0.20 per Unit to the Unitholders other than Kelley Oil
(the "Public Unitholders") in March 1996, and Kelley Oil's unfunded subscription
commitment was reduced proportionately to $17.2 million as of the date of the
distribution. Future drilling activities were limited to prospects being drilled
or committed for drilling as of the end of the Commitment Period.
During 1996, KOGC and its subsidiaries (collectively, "Kelley")
initiated a program for streamlining operations, improving drilling efficiency
and reducing lease operating costs. These efforts generated cost savings that
reduced the Partnership's prior estimate for total expenditures from $60.7
million to $58 million, representing a reduction of $2.7 million or $.12 per
Unit (the "Commitment Reduction"). As a result of the Commitment Reduction, a
distribution of the excess Contemplated Capital is expected to be made in 1997.
As of March 15, 1997, Kelley Oil had contributed $54.6 million to the
Partnership, together with interest at a market rate on the portion of its
commitment that remained outstanding after November 1994. After giving effect to
the February 1996 reduction in committed capital under the Partnership Agreement
and the additional Commitment Reduction
25
<PAGE>
in 1997, the Kelley Oil's share of the Partnership's total expenditures will be
reduced to $53.4 million, entitling Kelley Oil to participate in the planned
1997 distribution of additional uncommitted capital resulting from the
Commitment Reduction. Kelley Oil's return of capital will be limited to its
excess contribution aggregating $1.2 million or $.06 per Unit.
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.
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 LongLived 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. 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 $10.9 million against the
carrying value of its oil and gas properties under FAS 121 at December 31, 1996.
SYNDICATION AND ORGANIZATION COSTS. Costs and expenses incurred in
connection with the syndication and organization of the Partnership aggregating
approximately $1,571,000 have been charged to partners' equity. These
syndication costs include approximately $750,000 of general and administrative
expenses allocated by Kelley Oil for expenses directly identified with
syndication and organization activities.
NET INCOME (LOSS) PER UNIT. Net income (loss) per Unit is computed based
on the weighted average number of Units outstanding during the period divided
into the net income (loss) allocable to the Unitholders.
FINANCIAL INSTRUMENTS. The Partnership's financial instruments consist
of cash and cash equivalents, receivables, and payables.
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 5 -
Hedging Activities.
26
<PAGE>
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 3 - 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, the 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 - CASH DISTRIBUTIONS
In addition to the March 1996 distribution of the Public Unitholders'
pro rata share of uncommitted capital and the planned 1997 distribution of
additional uncommitted capital described in Note 1 above, the Partnership has
paid quarterly cash distributions reflected in the following table. The
distribution in each quarter was based upon net available cash generated from
operations in the preceding quarter.
1995
----
First quarter..................... $.04
Second quarter.................... .09
Third quarter..................... .10
Fourth quarter.................... .10
----
Total........................... $.33
====
1996
----
First quarter..................... $.12
Second quarter.................... .18
Third quarter..................... .18
Fourth quarter.................... .21
----
Total........................... $.69
====
NOTE 3 - 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.
For the period from inception through December 31, 1994 and the years
ended December 31, 1995 and 1996, Kelley Oil was reimbursed by the Partnership
for costs directly associated with acquisition, exploration and development
activities aggregating $2,496,000, $2,649,000 and $1,245,000, respectively, and
for its allocable portion of general and administrative expenses aggregating
$52,000, $542,000 and $753,000, respectively. For the period ended December 31,
1994 and the years ended December 31, 1995 and 1996, the Partnership capitalized
$1,592,000, $1,963,000 and $611,000, respectively, of allocated direct costs to
oil and gas properties.
Kelley Partners advanced approximately $1,879,000 on behalf of the
Partnership prior to the closing of the Partnership's offering of Units for the
purpose of funding drilling activities. The entire amount of these advances,
together with interest at a market rate, was repaid following the closing of the
Partnership's offering.
KOGC maintains a $125 million revolving credit facility with a group of
bankers (the "Credit Facility"). The Partnership, the Joint Venture and KOGC's
other subsidiary partnerships are guarantors. The Credit Facility is secured by
all the oil and gas properties and other assets of the borrowers and the
guarantors, including the Partnership and the Joint Venture. The agreement
covering the Credit Facility provides various financial covenants as well as
restrictions on additional
27
<PAGE>
debt, mergers and asset sales, but limits the lenders' recourse upon any default
to Partnership and Joint Venture assets attributable to Kelley Oil's interests
in the Partnership.
Substantially all of the Partnership's gas sales are made to an
affiliated company, Concorde Gas Marketing, Inc., an indirect 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, the fee was
modified to 2% of the resale price for marketed natural gas.
NOTE 4 - SALES TO MAJOR CUSTOMERS
Sales to customers in excess of 10% of total oil and gas sales for the
period from inception through December 31, 1994 and the years ended December 31,
1995 and 1996 were as follows:
(IN THOUSANDS)
FEBRUARY 28,
1994 (DATE
OF INCEPTION)
THROUGH YEAR ENDED DECEMBER 31,
DECEMBER 31, -----------------------
1994 1995 1996
------- ----- -----
Concorde Gas Marketing(1)............. 563 6,891 17,186
Falco S & D Inc....................... 233 805 389
- ------------
(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 5 - 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.
28
<PAGE>
NOTE 6 - SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND GAS EXPLORATION,
DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)
This section provides information required by Statement of Financial
Accounting Standards No. 69, "Disclosures about Oil and Gas Producing
Activities."
CAPITALIZED COSTS. Capitalized costs and accumulated depreciation,
depletion and amortization relating to oil and gas producing activities, all of
which are conducted within the continental United States, are summarized below.
(IN THOUSANDS)
<TABLE>
<CAPTION>
FEBRUARY 28,
1994 (DATE
OF INCEPTION)
THROUGH YEAR ENDED DECEMBER 31,
DECEMBER 31, -----------------------
1994 1995 1996
------- ---- -----
<S> <C> <C> <C>
Evaluated properties subject to amortization........... $15,740 31,932 43,870
Accumulated depreciation, depletion and amortization... (1,618) (19,217) (24,835)
------- ------- -------
Net capitalized costs................................ $14,122 12,715 19,035
======= ======= =======
</TABLE>
COSTS INCURRED. All costs were incurred in oil and gas property
development activities (as defined in the Partnership Agreement) and aggregated
$19,129,000 for the period from inception through December 31, 1994 and
$22,959,000 and $13,235,087 for the years ended December 31, 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 period from inception through December 31, 1994 and the years ended
December 31, 1995 and 1996. Reserves reflected in the table at February 28, 1994
represent proved undeveloped reserves associated with drilling rights assigned
to the Partnership upon formation.
<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:
February 28, 1994 and January 1,
1995 and 1996................... 269 583 167 22,148 49,146 58,640
Revisions of previous estimates... 64 (472) 7 (136) (32,447) (15,438)
Extensions and discoveries........ 265 106 -- 27,473 45,941 439
Sales of reserves in place........ -- -- (2) -- -- (422)
Production........................ (15) (50) (49) (339) (4,000) (7,872)
------- -------- -------- ------- ------- -------
End of year..................... 583 167 123 49,146 58,640 35,347
======= ======== ======== ======= ======= =======
Proved developed reserves at
end of year ...................... 121 107 118 13,557 16,988 31,296
======= ======== ======== ======= ======= =======
</TABLE>
The reported revisions of previous reserve estimates during 1995 reflect
downward year-end revisions primarily on undeveloped locations in south
Louisiana based on reprocessed 3-D seismic data and a change in the
Partnership's drilling strategy to focus exclusively on lower risk north
Louisiana locations for the balance of its drilling program. As a result of
these factors, the Partnership performed an assessment of the carrying value of
its oil and gas properties under
29
<PAGE>
FAS 121 indicating an impairment should be recognized as of year end. See Note 1
- - Summary of Significant Accounting Policies. Based on this analysis, the
Partnership recognized a noncash impairment charge of $10.9 million against the
carrying values of its oil and gas properties under FAS 121 at December 31,
1995.
STANDARDIZED MEASURE. The table of the Standardized Measure of
Discounted Future Net Cash Flows relating to the Partnership's ownership
interests in proved oil and gas reserves as of December 31, 1994, 1995 and 1996
is shown below.
(IN THOUSANDS)
DECEMBER 31,
--------------------------------
1994 1995 1996
------- -------- -------
Future cash inflows......................... $93,218 122,415 129,261
Future production costs..................... (15,227) (16,301) (11,520)
Future development costs.................... (16,241) (14,955) (3,063)
------- ------- -------
Future net cash flows..................... 61,750 91,159 114,678
10% annual discount for estimating
timing of cash flows...................... (26,194) (35,047) (39,540)
------- ------- -------
Standardized measure of discounted
future net cash flows................... $35,556 56,112 75,138
======= ======= =======
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 had a weighted average of $15.65, $19.73 and $24.93,
respectively, per barrel of oil and $1.71, $2.03 and $3.66, respectively, per
Mcf of natural gas.
30
<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>
FEBRUARY 28,
1994 (DATE
OF INCEPTION)
THROUGH YEAR ENDED DECEMBER 31,
DECEMBER 31, -----------------------
1994 1995 1996
------- ------- -------
<S> <C> <C> <C>
Changes due to current year operations:
Sales of oil and gas, net of production costs........ $ (689) (6,600) (16,638)
Sales of oil and gas properties...................... -- -- (780)
Extensions and discoveries........................... 18,865 43,902 264
Development costs incurred during the year........... 185 4,181 12,395
Changes due to revisions in standardized variables:
Prices and production costs.......................... (6,655) (70) 48,749
Revisions of previous quantity estimates............. 332 (25,442) (36,503)
Estimated future development costs................... 1,395 8,121 178
Accretion of discount................................ 2,291 3,556 5,611
Production rates (timing) and other.................. (3,077) (7,092) 5,749
------- ------- -------
Net increase ...................................... 12,647 20,556 19,026
Beginning of period.................................. 22,909 35,556 56,112
------- ------- -------
End of year........................................ $35,556 56,112 75,138
======= ======= =======
</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 accountant, effective February 15,
1996. On the same date, the Partnership engaged Deloitte & Touche LLP ("D&T") as
its principal accountant 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. E&Y's
report on the Partnership's financial statements for the period from inception
on February 28, 1994 through December 31, 1994 did not contain an adverse
opinion or disclaimer of opinion and was not 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.
31
<PAGE>
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 January 1, 1997, and its staff includes
employees experienced in geology, geophysics, petroleum engineering, land
acquisition and management, finance, accounting and administration.
BACKGROUND OF KELLEY OIL
Kelley Oil is an 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 the Company. All directors are elected for a
term of one year and serve until their successors are duly elected and
qualified. All executive officers hold office until their successors are duly
appointed and qualified.
<TABLE>
<CAPTION>
OFFICER
OR
DIRECTOR OF
THE COMPANY
NAME AGE POSITION SINCE
- ---- --- -------- -----
<S> <C> <C> <C>
John F. Bookout.......... 74 President, Chief Executive Officer and a director 1996
David C. Baggett......... 35 Senior Vice President and Chief Financial Officer and a director 1997
Dallas D. Laumbach....... 60 Senior Vice President-Exploration and Production and a director 1996
Thomas E. Baker.......... 66 General Counsel and Corporate Secretary 1996
</TABLE>
JOHN F. BOOKOUT joined Kelley Oil as Chairman of the Board, President
and Chief Executive Officer in February 1996. He served as Chairman of the Board
of Contour Production Company L.L.C. ("Contour") since its inception in 1993.
From 1988 through 1993, he served as a member of the Supervisory Board of Royal
Dutch Petroleum. He currently serves on the board of directors of McDermott
International Inc., J. Ray McDermott, S.A. and The Investment Company of America
as well as the board of trustees of the United States Counsel for International
Business and various civic and educational bodies.
DAVID C. BAGGETT was elected Senior Vice President and Chief Financial
Officer and a director of Kelley Oil in March 1997. Previously, he was a partner
with Deloitte & Touche LLP for more than five years.
DALLAS D. LAUMBACH has served as Senior Vice President-Exploration and
Production and a director of Kelley Oil since February 1996 and has served
concurrently as President of Concorde Gas, Inc. since August 1996. He previously
served as Senior Vice President of Contour commencing in December 1993. Before
joining Contour, Mr. Laumbach served in positions of increasing responsibility
for 24 years at Shell Oil Company, concluding as Manager-Business Development in
Shell's Head Office.
THOMAS E. BAKER is an attorney and joined Kelley Oil in July 1996 as
General Counsel and Corporate Secretary. From August 1991 through June 1996, Mr.
Baker was engaged in a private consulting practice.
32
<PAGE>
BENEFICIAL OWNERSHIP REPORTING
Not applicable.
ITEM 11. EXECUTIVE COMPENSATION
Not applicable. See "Certain Relationships and Related Transactions."
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
BENEFICIAL OWNERS
The following table sets forth information as of December 31, 1996 with
respect to the only person 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 19,163,889 91.85%
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) 1,000 .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 $2,580,897 to the Partnership for their 3.96%
interest.
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, reimbursements of $2,496,000, $2,649,000 and
$1,245,000, respectively, were made for costs directly associated with the
Partnership's development drilling activities and $52,000, $542,000 and
$753,000, respectively, for Kelley Oil's general and administrative expenses
attributable to the operations of the Partnership. Costs and expenses incurred
by Kelley Oil in connection with the syndication and organization
33
<PAGE>
of the Partnership aggregating approximately $750,000 were reimbursed by the
Partnership in 1994 and charged to partners' equity.
Kelley Partners advanced $1,879,000 on behalf of the Partnership prior
to the closing of the Partnership's offering of Units to fund syndication costs
and drilling activities. The entire amount of these advances, together with
interest at a market rate, was repaid following the closing of the offering.
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: All 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. 33-72528) filed on December 7, 1993, as amended (the
"Registration Statement") and incorporated herein by
reference).
4.2 Joint Venture Agreement of Kelley Partners 1994 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.
34
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized, this 27th day of
March, 1997.
KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM
By: KELLEY OIL CORPORATION, Managing General Partner
<TABLE>
<S> <C> <C>
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)
</TABLE>
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed as of the 27th day of March, 1997 by the following
persons in their capacity as directors of the Registrant's managing general
partner.
/s/ JOHN F. BOOKOUT /s/ DALLAS D. LAUMBACH
John F. Bookout Dallas D. Laumbach
/s/ DAVID C. BAGGETT
David C. Baggett
35
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> DEC-31-1996
<CASH> 25
<SECURITIES> 0
<RECEIVABLES> 7,392
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 7,417
<PP&E> 43,870
<DEPRECIATION> 24,835
<TOTAL-ASSETS> 26,452
<CURRENT-LIABILITIES> 3,770
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 22,682
<TOTAL-LIABILITY-AND-EQUITY> 26,452
<SALES> 18,986
<TOTAL-REVENUES> 20,240
<CGS> 0
<TOTAL-COSTS> 2,954
<OTHER-EXPENSES> 6,390
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 10,896
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 10,896
<EPS-PRIMARY> .50
<EPS-DILUTED> .50
</TABLE>
