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. 0-25214
KELLEY OIL & GAS CORPORATION
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 76-0447267
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)
601 JEFFERSON - 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:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
- ------------------- -----------------------------------------
8 1/2% Convertible American Stock Exchange
Subordinated Debentures
due 2000
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
- ------------------- -----------------------------------------
Common Stock Nasdaq National Market
$2.625 Convertible Nasdaq National Market
Exchangeable Preferred
Stock
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K under the Securities Exchange Act of 1934 is not contained
herein, and will not be contained, to the best of the Registrant's knowledge, in
definitive proxy or information statements incorporated in Part III of this Form
10-K or any amendments to this Form 10-K. [ ]
As of March 25, 1997, 98,295,077 shares of Common Stock and 1,745,431 shares of
Preferred Stock were outstanding, and the aggregate market value of shares held
by unaffiliated stockholders was approximately $119,450,807 and $44,290,312,
respectively.
DOCUMENTS INCORPORATED BY REFERENCE
Certain portions of the Proxy Statement for the 1997 Annual Meeting of
Stockholders are incorporated by reference into Part III of this Report.
<PAGE>
PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
INTRODUCTION
Kelley Oil & Gas Corporation, incorporated in Delaware in 1994 (the
"Company"), with its subsidiaries and subsidiary partnerships ( "Kelley"), is
engaged in the acquisition, exploration, development, and production of oil and
natural gas. The Company's strategy is to increase reserves, production and cash
flow in a cost-efficient manner through the development and exploration of
Kelley's existing properties and acquisitions of oil and gas reserves. The
Company's executive offices are located at 601 Jefferson Street, Suite 1100,
Houston, Texas 77002, and its telephone number is (713) 652-5200.
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.
THE CONSOLIDATION (1994-1995). The Company was formed in 1994 to
consolidate the equity ownership of Kelley Oil & Gas Partners, Ltd. ("Kelley
Partners") and Kelley Oil Corporation ("Kelley Oil"). Prior to the
Consolidation, drilling activities were conducted jointly by Kelley Partners and
Development Drilling Programs ("DDPs") sponsored by Kelley Oil for that purpose.
Historically, Kelley Oil (the managing general partner of Kelley Partners)
participated proportionately in these operations, with Kelley Partners retaining
one-third of its working interest in each prospect and assigning drilling rights
for the balance of its interest to a DDP. In addition to serving as managing
general partner of each DDP, Kelley Oil purchased for its own investment account
all units in DDPs that were not subscribed preemptively by other investors in
Kelley Partners. In the Consolidation, Kelley Oil retained direct ownership of
the interests in the remaining DDPs sponsored during 1994 and 1992 aggregating
92.2% and 84.3%, respectively. The Consolidation was completed on February 7,
1995 upon approval by investors in Kelley Partners and Kelley Oil.
In the Consolidation, the outstanding capital stock of Kelley Oil and
units in Kelley Partners ("Units") held by investors other than Kelley Oil and
its subsidiaries ("public unitholders") were converted into a total of 43.7
million shares of Common Stock of the Company, 2.4 million shares of the
Company's $2.625 convertible exchangeable preferred stock ("Public Preferred
Stock") and 2.2 million shares of cumulative convertible preferred stock ("ESOP
Preferred Stock") held by its Employee Stock Ownership Plan (the "ESOP"). As a
result of the Consolidation, Kelley Oil became a wholly-owned subsidiary of the
Company, and Kelley Partners became a 99.99%-owned subsidiary partnership. The
Consolidation was treated as a purchase of the public unitholders' interests in
Kelley Partners by the Company for financial accounting purposes. Accordingly,
historical financial and reserve information presented in this document reflects
Kelley Oil's historical results on a stand-alone basis prior to the
Consolidation, with the results of Kelley's combined operations recorded
thereafter.
THE CONTOUR TRANSACTION (1996). In January 1996, the Company entered
into agreements with Contour Production Company L.L.P. ("Contour") which
provided for a two-stage equity investment of $75 million in the Company by
Contour. On February 15, 1996, the first stage of the equity investment was
completed through Contour's $48 million purchase of newly issued shares of the
Company's common stock, $.01 par value ("Common Stock"), representing on such
date 49.8% of the voting shares of the Company (the "Contour Transaction").
Additionally, the Company entered into an option agreement (the "Contour
Option"), under which Contour has committed to provide the Company with $27
million in additional equity financing through an option to purchase 27 million
shares (the "Maximum Option Number") of Common Stock upon satisfaction of
certain conditions.
ACQUISTION OF PROPERTIES. On September 30, 1996, Kelley closed the
purchase of interests in certain undeveloped reserves located in the Sibley,
Sailes, West Bryceland and Ada fields in the Vacherie Salt Dome area of north
Louisiana on
1
<PAGE>
properties operated by Kelley. The purchase price for the interest was $10
million, and all capital costs, and all operating revenues and expenses incurred
since July 1, 1996 with respect to such interests were for the account of
Kelley.
INDUSTRY PARTNERSHIP. Pursuant to the terms and conditions of a joint
venture with a unit of The Williams Companies, Inc., ("Williams") effective
December 1, 1996, Williams purchased an undivided 50% interest in Kelley's
interest in its 27,000 net acreage position as well as 50% of Kelley's interest
in 23 wells and related facilities in this area (including Orange
Grove/Humphreys and Ouiski Bayou fields), in Terrebonne Parish, Louisiana. The
total purchase price was $20.5 million, a portion of which is committed under
the joint venture to drill up to eight exploration prospects in such area.
Pursuant to the joint venture, Kelley and Williams have begun an exploratory
drilling program on their south Louisiana properties.
OPERATIONS AND PROPERTIES
INTRODUCTION. Kelley is engaged in oil and natural gas exploration,
development, production and acquisitions. Kelley's activities currently are
concentrated primarily in two geographic areas: north Louisiana and south
Louisiana. At December 31, 1996, approximately 89% of Kelley's proved reserves
were located on 48,060 gross (22,705 net) acres within four fields in Webster
and Bienville Parishes of north Louisiana, where activities are focused on
lower-risk development drilling. Substantially all of the balance of Kelley's
proved reserves are located in south Louisiana, primarily in Terrebonne Parish.
Kelley's exploration activities are focused on existing leaseholds in Terrebonne
Parish where successful wells generally have the potential for larger reserves
and production as compared to development wells in north Louisiana. Kelley is
utilizing advanced geophysical techniques to re-evaluate and refine
interpretations of Kelley's 3-D seismic database.
DESCRIPTION OF PROPERTIES. Kelley's properties are located
principally in Louisiana. As of January 1, 1997, Kelley owned interests in a
total of 411 gross (165.9 net) producing wells, of which 230 wells were operated
by Kelley, accounting for 82% of Kelley's current production. As of that date,
Kelley had leaseholdings covering 88,559 gross (34,015 net) developed acres and
30,027 gross (16,438 net) undeveloped acres. Approximately 97% of Kelley's
proved oil and gas reserves (by energy content) as of January 1, 1997, was
natural gas. The reserves to production ratio for these properties (based on
1996 production rates) was estimated to be 12.3 as of January 1, 1997.
SIGNIFICANT PROPERTIES. Kelley's core natural gas properties in north
Louisiana are located in the Sailes, Sibley, West Bryceland and Ada fields of
Webster and Bienville Parishes, while its core properties in south Louisiana are
concentrated in Terrebonne Parish. Production is primarily from the Hosston
(north Louisiana) and Miocene (south Louisiana) formations. Substantially all of
Kelley's oil and gas properties are pledged to secure borrowings under the
Company's existing credit facility. The following table sets forth certain
information about Kelley's interests in its most significant fields, together
with information for all other fields combined. See "Estimated Proved
Reserves-Uncertainties in Estimating Reserves."
2
<PAGE>
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:
Sailes field......................... 231 95,923 97,309 31.8 38 6,753 6,981 28.1
West Bryceland field................. 176 90,974 92,030 30.0 12 4,289 4,361 17.5
Sibley field......................... 131 60,377 61,163 20.0 10 5,780 5,840 23.5
Ada field............................ 42 23,318 23,570 7.7 3 1,244 1,262 5.1
SOUTH LOUISIANA(1):
Orange Grove/Humphreys field......... 104 6,111 6,735 2.2 40 1,703 1,943 7.8
Ouiski Bayou field................... 104 1,222 1,846 .6 24 611 755 3.0
Fire Island field.................... 21 1,056 1,182 .4 14 667 751 3.0
OTHER:
As a group........................... 657 18,653 22,595 7.3 91 2,419 2,965 12.0
-------- ---------- ---------- ------ ----- --------- --------- ------
Total............................. 1,466 297,634 306,430 100.0 232 23,466 24,858 100.0
======== ========== ========== ====== ===== ========= ========= ======
</TABLE>
(1) Effective December 1, 1996, Kelley entered into a joint venture
whereby it sold 50% of its net acreage position as well as 50% of its interest
in 23 wells and related facilities in the Houma Embayment, including in the
Orange Grove/Humphreys and Ouiski Bayou fields. See "Management's Discussion and
Analysis of Financial Position and Results of Operations."
ADDITIONAL INFORMATION REGARDING THESE FIELDS IS SET FORTH BELOW.
UNLESS OTHERWISE NOTED, ACREAGE AND WELL INFORMATION IS PROVIDED AS OF DECEMBER
31, 1996, AND RESERVE INFORMATION IS PROVIDED AS OF JANUARY 1, 1997:
NORTH LOUISIANA. Kelley's operations in this region are focused
primarily on four contiguous fields in the Vacherie Salt Dome area. Production
is primarily from the Hosston Sandstone interval with an average thickness of
3,000 feet. Wells are typically drilled to a maximum depth of approximately
10,500 feet. Operations in this region do not typically experience high
formation pressures or significant associated liquid production or salt water
disposal. Recently, increases in recoveries from north Louisiana wells have been
achieved from revised interpretations of geological fault systems, revised
fracture stimulation techniques and regulatory changes that allowed the
commingling of production from multiple zones.
SIBLEY FIELD. The Sibley field is located in Webster Parish,
Louisiana. The Sibley field proved reserves are 86.1% developed and 50.4%
producing. Kelley has interests in 63 gross (16.7 net) wells producing primarily
from the Hosston formation at depths ranging from 6,000 to 9,000 feet. Kelley
operates 28 of the wells. Kelley completed as producers 21 gross (6.4 net) wells
in the Sibley field during 1996, and was in the process of drilling/completing 3
gross (0.5 net) wells in this field on December 31, 1996.
SAILES FIELD. The Sailes field is located in Bienville Parish,
Louisiana. The Sailes field proved reserves are 47.5% developed and 35.2%
producing. Kelley has interests in 88 gross (48.4 net) wells producing from the
Hosston formation at depths ranging from 7,000 to 10,500 feet. Kelley operates
71 of the wells. Kelley completed as producers 15 gross (9.1 net) wells in the
Sailes field during 1996, and was in the process of drilling/completing 4 gross
(2.3 net) wells in this field on December 31, 1996.
WEST BRYCELAND FIELD. The West Bryceland field is located in
Bienville Parish, Louisiana. The West Bryceland field proved reserves are 60.7%
developed and 41.0% producing. Kelley had interests in 74 gross (28.1 net) wells
producing from the Hosston formation at depths ranging from 6,500 to 10,500
feet. Kelley operates 40 of the wells. Kelley completed as producers 20 gross
(9.9 net) wells in the West Bryceland field during 1996, and was in the process
of drilling/completing 4 gross (2.5 net) wells in this field on December 31,
1996.
3
<PAGE>
ADA FIELD. The Ada field is located in Bienville and Webster
Parishes, Louisiana. The Ada field proved reserves are 39.0% developed and 15.7%
producing. Kelley has interests in 18 gross (8.1 net) wells producing primarily
from the Hosston formation at depths ranging from 6,000 to 10,000 feet. Kelley
operates 10 of the wells. Kelley completed as producers 2 gross (0.8 net) wells
in the Ada field during 1996, and was in the process of drilling/completing 1
gross (0.4 net) well in this field on December 31, 1996.
SOUTH LOUISIANA. Kelley's operations in this region primarily are
focused on four fields in the Houma Embayment area and one field in nearby
Vermilion Parish. The Houma Embayment is composed of high-quality reservoir
rock, contributing to high production rates and multiple objectives. Wells are
typically drilled to a depth of approximately 11,000 to 17,000 feet. Kelley's
south Louisiana properties generally are located in close proximity to
transportation and market locations, and production therefrom generally receives
higher prices because of its rich condensate content. The Company believes these
factors partially offset the higher operating costs associated with higher
formation pressures, salt water disposal and liquid hydrocarbon handling
associated with the region. Kelley operates an aggregate of 54 gross (39.1 net)
wells in this region and had 1 gross (0.5 net) wells in progress at December 31,
1996. Kelley's average working interest in these properties is approximately
72%. The three most significant fields are described below.
ORANGE GROVE/HUMPHREYS FIELD. The Orange Grove/Humphreys field is
located in Terrebonne Parish, Louisiana. As of year-end, all Orange
Grove/Humphreys field proved reserves are developed and 48% producing. Kelley
has interests in 12 gross (3.8 net) wells producing primarily from the Miocene
1st Hollywood and Bourg formations at depths ranging from 2,500 to 13,900 feet.
Kelley operates 11 of the wells. Kelley was in the process of drilling one gross
(.5 net) well in this field on December 31, 1996.
OUISKI BAYOU FIELD. The Ouiski Bayou field is located in Terrebonne
Parish, Louisiana. As of year-end, all Ouiski Bayou field proved reserves were
developed and producing. Kelley has interests in 3 gross (1.3 net) wells
producing from the Cib op and KK formations at depths ranging from 14,880 to
18,000 feet. Kelley operates all of the wells.
FIRE ISLAND FIELD. The Fire Island field is located in Vermilion
Parish, Louisiana. As of year-end, all Fire Island proved reserves were
developed and producing. Kelley has an interest in 1 gross (0.95 net) well,
which is operated by Kelley producing from the MA-36 formation at a depth of
14,400 feet.
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 and reviewed by Gruy at January 1,
1995.
QUANTITIES. The following table sets forth the estimated quantities
of proved and proved developed reserves of crude oil (including condensate and
natural gas liquids) and natural gas owned by Kelley 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.
4
<PAGE>
ESTIMATED PROVED RESERVES
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------------------------------------
1994 1995 1996
--------------------- -------------------- -------------------
OIL GAS OIL GAS OIL GAS
(MBBLS) (MMCF) (MBBLS) (MMCF) (MBBLS) (MMCF)
<S> <C> <C> <C> <C> <C> <C>
PROVED RESERVES:
Beginning balance................................. 1,114 64,875 1,236 93,612 1,387 196,273
Revisions of previous estimates................... 75 16,055 (1,324) (64,027) (89) (30,519)
Purchases of oil and gas properties............... -- -- 1,756 127,962 57 30,844
Extensions and discoveries........................ 218 19,379 156 66,864 477 128,692
Sale of oil and gas properties.................... -- -- (118) (10,388) (134) (4,190)
Production........................................ (171) (6,697) (319) (17,750) (232) (23,466)
-------- --------- -------- --------- ------- ---------
Ending balance................................. 1,236 93,612 1,387 196,273 1,466 297,634
======== ========= ======== ========= ======= =========
PROVED DEVELOPED RESERVES:
Producing......................................... 414 28,806 669 63,488 608 113,831
Non-producing..................................... 260 19,665 528 47,799 369 59,634
-------- --------- -------- --------- ------- ---------
Total proved developed......................... 674 48,471 1,197 111,287 977 173,465
======== ========= ======== ========= ======= =========
</TABLE>
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.
Detailed information concerning Kelley's standardized measure of
discounted future net cash flows is contained in the Supplementary Financial
Information included in Note 13 to the Company's Consolidated Financial
Statements. The Company has not filed any estimates of reserves with any federal
authority or agency during the past year other than estimates contained in
filings with the SEC.
PRODUCTION, PRICE AND COST HISTORY
The following table sets forth certain production data, the average
sales prices and average production expenses attributable to Kelley's properties
on a historical basis for 1994, 1995 and 1996, and on a pro forma basis for 1994
amd 1995 after giving effect to the Consolidation as of January 1, 1994.
Detailed additional information concerning Kelley's oil and gas production
activities is contained in the Supplementary Financial Information included in
Note 13 to the Consolidated Financial Statements.
5
<PAGE>
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------------------
1994 1995 1994 1995 1996
--------- --------- --------- --------- -------
PRO FORMA PRO FORMA
<S> <C> <C> <C> <C> <C>
PRODUCTION DATA:
Oil and other liquid hydrocarbons (Mbbls)............... 171 319 446 348 232
Natural gas (Mmcf)...................................... 6,697 17,750 18,141 18,828 23,466
Natural gas equivalent (Mmcfe).......................... 7,723 19,664 20,817 20,916 24,858
AVERAGE SALES PRICE PER UNIT:
Oil and other liquid hyrocarbons (per Bbl).............. $ 16.31 17.37 16.30 17.31 22.11
Natural gas (per Mcf)................................... 1.89 1.71 1.87 1.72 2.30
Natural gas equivalent (per Mcfe)....................... 2.01 1.83 2.03 1.84 2.37
AVERAGE PRODUCTION EXPENSES (PER MCFE)..................... 0.49 0.55 0.59 0.55 0.43
</TABLE>
PRODUCTION PERFORMANCE
Kelley's equivalent gas production for 1996 represents an 18.8%
increase when compared to 1995 pro forma production and reflects primarily the
results of the expanded six-rig north Louisiana development activities initiated
in the second quarter of 1996, net of the production sold near year-end 1996. On
a pro forma basis, equivalent gas production in 1995 was essentially unchanged
from 1994. Kelley's production in 1994 and 1995 was adversely affected by
several factors, including production declines in its south Louisiana properties
where certain major wells performed below expectations, disappointing drilling
results in south Louisiana and the sale of nonstrategic properties in July 1995.
In 1995 and 1996, revised completion techniques contributed to higher
initial flow rates in many of Kelley's new north Louisiana wells, some of which
were not completed and brought on production until late in 1995 and thus did not
contribute significantly to production until 1996. By the second quarter of
1996, the Company had expanded its drilling program in north Louisiana with as
many as six drilling rigs operating in the area over the last nine months of the
year. As a result, after declining to a total of approximately 5.1 Bcfe in the
fourth quarter of 1995, equivalent gas production increased 49.0% to 7.6 Bcfe
during the fourth quarter of 1996.
PRODUCTIVE WELLS AND ACREAGE
As of December 31, 1996, Kelley had leaseholdings comprising 88,559
gross (34,015 net) developed acres and 30,027 gross (16,438 net) undeveloped
acres, all located within the continental United States. The oil and gas leases
in which Kelley has an interest are for varying primary terms and many,
particularly in south Louisiana, require the payment of delay rentals in lieu of
drilling operations. In north Louisiana, most of Kelley's leasehold interests
are held by production; that is, so long as natural gas and oil are produced
from the properties covered thereby, the leases continue indefinitely. The
leases may be surrendered at any time by notice to the lessors, by the cessation
of production or by failure to make timely payment of delay rentals.
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<PAGE>
As of December 31, 1996, Kelley had working interests in 387 gross
(158.7 net) productive gas wells and 24 gross (7.2 net) productive oil wells
(including producing wells and wells capable of production). The following table
sets forth Kelley's ownership interests in its leaseholds as of December 31,
1996.
DEVELOPED(1) UNDEVELOPED(2)
------------------------- -------------------------
GROSS ACRES NET ACRES GROSS ACRES NET ACRES
----------- ---------- ----------- ---------
Louisiana...... 79,419 33,718 29,904 16,352
Texas.......... 6,667 221 123 86
Other states... 2,473 76 -- --
---------- ---------- ----------- ----------
Total....... 88,559 34,015 30,027 16,438
========== ========== =========== ==========
(1) Acres spaced or assignable to productive wells.
(2) Acres on which wells have not been drilled or completed to a point
that would permit the production of commercial quantities of oil and gas,
regardless of whether that acreage contains proved reserves.
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<PAGE>
DEVELOPMENT AND EXPLORATION
The following table sets forth the number of gross and net productive
and dry development wells and exploratory wells drilled by Kelley in north
Louisiana and in south Louisiana and elsewhere during the periods indicated,
with pro forma information giving effect to the Consolidation as of January 1,
1994.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------------------------------------
1994 1995 1996
--------------------- -------------------- -------------------
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
PRO FORMA PRO FORMA
--------------------- --------------------
<S> <C> <C> <C> <C> <C> <C>
NORTH LOUISIANA:
Exploratory wells:
Oil......................................... -- -- -- -- -- --
Natural gas................................. -- -- -- -- -- --
Dry......................................... -- -- -- -- -- --
-------- -------- -------- ------- ------- --------
Total..................................... -- -- -- -- -- --
======== ======== ======== ======= ======= ========
Development wells:
Oil......................................... -- -- 1 .05 1 .03
Natural gas................................. 22 8.53 22 9.26 65 31.63
Dry......................................... -- -- -- -- 3 1.74
-------- -------- -------- ------- ------- --------
Total..................................... 22 8.53 23 9.31 69 33.40
======== ======== ======== ======= ======= ========
Total north Louisiana:
Producing................................... 22 8.53 23 9.31 66 31.66
Dry......................................... -- -- -- -- 3 1.74
-------- -------- -------- ------- ------- --------
Total..................................... 22 8.53 23 9.31 69 33.40
======== ======== ======== ======= ======= ========
SOUTH LOUISIANA AND OTHER:
Exploratory wells:
Oil......................................... -- -- -- -- -- --
Natural gas................................. 3 2.09 -- -- -- --
Dry......................................... 3 2.78 1 .95 -- --
-------- -------- -------- ------- ------- --------
Total..................................... 6 4.87 1 .95 -- --
======== ======== ======== ======= ======= ========
Development wells:
Oil......................................... -- -- -- -- -- --
Natural gas................................. 6 4.57 4 3.78 -- --
Dry......................................... 1 .89 1 .95 -- --
-------- -------- -------- ------- ------- --------
Total..................................... 7 5.46 5 4.73 -- --
======== ======== ======== ======= ======= ========
Total south Louisiana and other:
Producing................................... 9 6.66 4 3.78 -- --
Dry......................................... 4 3.67 2 1.90 -- --
-------- -------- -------- ------- ------- --------
Total..................................... 13 10.33 6 5.68 -- --
======== ======== ======== ======= ======= ========
</TABLE>
As of December 31, 1996, Kelley had 4 gross (2.13 net) development
wells in progress, all in north Louisiana, and 1 gross (.50 net) exploratory
well in progress in south Louisiana.
8
<PAGE>
TITLE TO PROPERTIES. Kelley's properties, in addition to being
mortgaged to secure the Company's existing credit facility, are subject to
royalty interests, liens incident to operating agreements, liens for current
taxes and other customary burdens, including other mineral encumbrances and
restrictions. The Company does not believe that any mortgage, lien or other
burden materially interferes with the use of such properties in the operation of
Kelley's business.
The Company believes that Kelley has satisfactory title to or rights
in all of its producing properties. As is customary in the oil and natural gas
industry, minimal investigation of title is made at the time of acquisition of
undeveloped properties. Title investigation is made, and title opinions of local
counsel are generally obtained before commencement of drilling operations or at
least in connection with the preparation of division orders when production is
obtained and the revenues therefrom are allocated.
MARKETING OF NATURAL GAS AND CRUDE OIL
Kelley does not refine or process any of the oil and natural gas it
produces. The natural gas production of the Company and its subsidiaries is sold
to various purchasers and Kelley currently is able to sell, under contract or in
the spot market, all of its natural gas at market prices. Substantially all of
Kelley's natural gas is sold under short-term contracts, contracts providing for
periodic price adjustments or in the spot market. Its revenue streams are
therefore sensitive to changes in current market prices. Kelley's sales of crude
oil, condensate and natural gas liquids generally are made at prices related to
posted field prices.
In addition to marketing Kelley's natural gas production, a
subsidiary of the Company secures gas transportation arrangements, provides
nomination and gas control services, supervises gas aggregation operations and
performs revenue receipt and disbursement services as well as regulatory filing,
recordkeeping, inspection, testing and monitoring functions. Another 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. For 1995 and 1996, the marketing fee
for such services was 2% of the resale price for marketed natural gas. The
Company considers these arrangements customary among natural gas producers and
their marketing affiliates. See "Selected Financial Data" and the Consolidated
Financial Statements included elsewhere in this Report for information as to the
Company's net gas marketing revenues, which include the marketing fees received
by its subsidiary.
Kelley 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 Kelley will not encounter these
constraints in the future. In that event, Kelley 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.
9
<PAGE>
COMPETITION
Kelley operates in a highly competitive environment. Competition is
encountered in acquiring reserves, marketing oil and natural gas and securing
trained personnel. Many of Kelley's larger competitors have financial and
personnel resources substantially greater than those available to Kelley. Such
companies may be able to pay more for productive oil and natural gas properties
and to define, evaluate, bid for and purchase a greater number of properties
than Kelley's financial or personnel resources permit. Kelley's ability to
acquire additional reserves in the future will be dependent upon its ability to
evaluate and select suitable properties and to consummate transactions in a
highly competitive environment. In addition, there is substantial competition
for capital available for investment in the oil and natural gas industry. There
can be no assurance that Kelley will be able to compete successfully in the
future in acquiring reserves, developing reserves, marketing hydrocarbons,
attracting and retaining quality personnel, and raising additional capital.
REGULATION OF OIL AND GAS MARKETS
Kelley's operations are subject to extensive and continually changing
regulation, as legislation affecting the oil and natural gas industry is under
constant review for amendment and expansion. Many departments and agencies, both
federal and state, are authorized by statute to issue and have issued rules and
regulations binding on the oil and natural gas industry and its individual
participants. The failure to comply with those rules and regulations can result
in substantial penalties. The regulatory burden on the oil and natural gas
industry increases Kelley'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 Kelley, directly or
indirectly, the following discussion of certain statutes and regulations should
not be relied upon as an exhaustive review of all matters affecting Kelley's
operations.
TRANSPORTATION AND SALE OF NATURAL GAS. Prior to January 1, 1993,
various aspects of Kelley's natural gas operations were subject to regulations
by the FERC under the Natural Gas Act of 1938 (the "NGA") and the NGPA with
respect to "first sales" of natural gas, including price controls and
certificate and abandonment authority regulations. However, as a result of the
enactment of the Decontrol Act, the remaining "first sales" restrictions imposed
by the NGA and the NGPA terminated on January 1, 1993.
The FERC regulates interstate natural gas pipeline transportation
rates and service conditions. This affects the marketing of gas produced by
Kelley, and the revenues it receives for sales of natural gas. Since 1985, the
FERC has adopted policies intended to make natural gas transportation more
accessible to gas buyers and sellers on an open and nondiscriminatory basis. The
FERC's most recent action in this area, Order No. 636, reflected its finding
that, under the then-existing regulatory structure, interstate pipelines and
other gas merchants, including producers, did not compete on a "level playing
field" in selling gas. Order No. 636 instituted individual pipeline services
restructuring proceedings, designed specifically to "unbundle" the services
provided by many interstate pipelines (for example, transportation, sales and
storage) so that buyers of natural gas may secure supplies and delivery services
from the most economical source, whether interstate pipelines or other parties.
The FERC has issued final orders in the restructuring proceedings, and a number
of pipelines have filed tariff sheets reflecting refinements in the
implementation of Order No. 636 following three years of operation under the
program. In addition, the FERC has announced its intention to reexamine certain
of its transportation related policies, including the appropriate manner in
which interstate pipelines release transportation capacity under Order No. 636
and, more recently, the price that shippers can charge for released capacity.
The FERC also has issued a new policy regarding the use of nontraditional
methods of setting rates for interstate gas pipelines in certain circumstances
as alternatives to cost-of-service based rates. A number of pipelines have
obtained FERC authorization to charge negotiated rates as one alternative.
Although the FERC's actions, such as Order No. 636, do not regulate
gas producers such as Kelley, 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 Kelley'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.
10
<PAGE>
The U.S. Court of Appeals for the District of Columbia Circuit
affirmed 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 Company.
The Company 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 Kelley'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 Kelley at market prices not subject at this time to
price controls. The price that Kelley 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 Kelley'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 Kelley owns and operates properties have
regulations governing conservation matters, including provisions for the
unitization or pooling of oil and natural gas properties, the establishment of
maximum rates of production from oil and natural gas wells and the regulation of
the spacing, plugging and abandonment of wells. Many states also restrict
production to the market demand for oil and natural gas, and several states have
indicated interest in revising applicable regulations. The effect of these
regulations is to limit the amount of oil and natural gas Kelley can produce
from its wells and to limit the number of wells or the locations at which Kelley
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 Kelley's operations and costs. In
particular, Kelley's exploration, development and production operations, its
activities in connection with storage and transportation of crude oil and other
liquid hydrocarbons and its use of facilities for treating, processing or
otherwise handling hydrocarbons and wastes therefrom are subject to stringent
environmental regulation. As with the industry generally, compliance with
existing regulations increases Kelley'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 Company incurs some expenses related to the disposition of
drilling fluids and produced waters, but these costs do not constitute a
material expense. The Company anticipates that it will incur additional expenses
related to compliance
11
<PAGE>
with environmental regulations at the time it abandons a producing property or
lease. The amount of these costs will vary, but based on the Company's
experience, the amount and timing of these costs should not materially increase
its overall cost of business. In addition, the Company 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 Company is unable to predict the
ongoing cost to comply with these laws and regulations or their future impact on
its operations. However, the Company does not believe that changes to these
regulations will materially adversely affect Kelley's competitive position
because its competitors are similarly affected. A discharge of hydrocarbons or
hazardous substances into the environment could subject Kelley 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. Kelley 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 Kelley 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 Company. States in which Kelley 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 Company.
The FWPCA imposes restrictions and strict controls regarding the
discharge of produced waters and other oil and gas wastes into navigable waters.
These controls have become more stringent over the years, and it is probable
that additional restrictions will be imposed in the future. Permits must be
obtained to discharge pollutants into state and federal waters. The FWPCA
provides for civil, criminal and administrative penalties for any unauthorized
discharges of oil and other hazardous substances in reportable quantities and,
along with the OPA, imposes substantial potential liability for the costs of
removal, remediation and damages. State laws for the control of water pollution
also provide varying civil, criminal and administrative penalties and impose
liabilities in the case of a discharge of petroleum or its derivatives, or other
hazardous substances, into state waters. In addition, the Environmental
Protection Agency ("EPA") has promulgated regulations that require many oil and
gas production operations to obtain permits to discharge storm water runoff. The
Company believes that compliance with existing permits and with foreseeable new
permit requirements will not have a material adverse effect on Kelley's
financial condition or results of operations.
AIR EMISSIONS. The operations of Kelley are subject to the Federal
Clean Air Act and comparable state and local statutes. The Company believes that
Kelley's 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
Company believes implementation of such amendments will not have a material
adverse effect on Kelley's financial condition or results of operations.
SOLID WASTE. The Federal Resource Conservation and Recovery Act
("RCRA") is the principal federal statute governing the treatment, storage and
disposal of hazardous wastes. RCRA imposes stringent operating requirements (and
liability for failure to meet such requirements) on a person who is either a
"generator" or "transporter" of hazardous waste or an "owner" or "operator" of a
hazardous waste treatment, storage or disposal facility. At present, RCRA
includes a statutory exemption that allows oil and gas exploration and
production wastes to be classified as non-hazardous waste. A similar exemption
is contained in many of the state counterparts to RCRA. As a result, Kelley 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
12
<PAGE>
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 Kelley. 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 Kelley.
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, Kelley may generate waste that
may fall within CERCLA's definition of a "hazardous substance." Kelley 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.
Kelley currently owns or leases numerous properties that for many
years have been used for the exploration and production of oil and gas. Although
Kelley 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 Kelley's control. These properties
and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state
laws. Under those laws, Kelley 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 Kelley'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. Kelley may also be subject to liability for any
violation of the RCRA. Liability is unlimited in cases of willful negligence or
misconduct, and there is no limit on liability for environmental clean-up costs
or damages on claims by the state or private parties. In addition, the EPA
requires producers such as Kelley 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. Kelley 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
Kelley'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 Kelley has not been material.
EMPLOYEES
As of January 1, 1997, Kelley had 70 employees, as compared to 85 as
of January 1, 1996. Kelley's staff includes employees experienced in
acquisitions, geology, geophysics, petroleum engineering, land acquisition and
management, finance and accounting. None of Kelley's employees is represented by
a union. Kelley has never experienced an interruption in its operations from any
kind of labor dispute, and its working relationships with its employees are
satisfactory.
13
<PAGE>
ITEM 3. LEGAL PROCEEDINGS
Following Kelley Oil's announcement of the initial proposal for the
Consolidation in August 1994, four separate lawsuits were filed against Kelley
Oil and its directors relating to the Consolidation and the 1991 DDP Exchange.
In November 1994, Kelley Oil entered into a memorandum of understanding with the
plaintiffs in three of the lawsuits, providing for a proposed settlement based
on the revised Consolidation proposal negotiated by a special committee of
Kelley Oil's nonmanagement directors and the settling plaintiffs. A stipulation
and agreement of compromise, settlement and release reflecting the terms of the
proposed settlement was filed in the United States District Court for the
Southern District of Texas on November 23, 1994. At a hearing held on the same
date, the court approved the consolidation of all four lawsuits and the
certification of a unitholder class requested by the settling parties. On March
3, 1995, following a hearing on the fairness of the settlement, the court
entered a final order approving the settlement, dismissing the consolidated
lawsuits with prejudice and reducing the award of attorneys' fees and
disbursements contemplated by the stipulation to $1.5 million, payable $0.3
million in cash and the balance in Common Stock of the Company. An appeal
subsequently filed by the nonsettling plaintiff is currently pending in the
United States Court of Appeals for the Fifth Circuit. Although the Company
believes approval of the settlement and dismissal of the lawsuits should be
upheld, it could be required, if not upheld, to litigate certain claims alleged
in the lawsuits, including the adequacy and fairness of the exchange ratios for
the Consolidation.
Kelley 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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted for a vote of the Company's stockholders
during the fourth quarter of 1996.
PART II
ITEM 5. MARKET FOR THE COMPANY'S SECURITIES AND RELATED STOCKHOLDER MATTERS
The Company's Common Stock and Preferred Stock are traded on the
Nasdaq National Market under the symbols "KOGC" and "KOGCP." Prior to the
Consolidation, Kelley Oil's common stock ("KOIL Common Stock") and $2.625
convertible exchangeable preferred stock ("KOIL Preferred Stock") were traded on
the NASDAQ Stock Market under the symbols "KOIL" and "KOILP." The price ranges
presented below represent high and low sale prices for each quarter, as reported
by the Nasdaq Stock Market. The reported prices reflect the commencement of
trading in the KOIL Preferred Stock during May 1994 and the commencement of
trading in the Company's Common Stock and Preferred Stock immediately after the
Consolidation on February 8, 1995.
14
<PAGE>
<TABLE>
<CAPTION>
KOIL COMMON STOCK KOIL PREFERRED STOCK
MARKET PRICES MARKET PRICES
------------------------ ----------------------
HIGH LOW HIGH LOW
------ ------ ---- -----
<S> <C> <C> <C> <C>
1995:
First quarter.........................................$ 4 7/8 3 3/4 21 18 3/4
Second quarter........................................ 6 3/8 4 1/4 25 1/2 20 1/4
Third quarter......................................... 5 7/8 2 3/4 24 3/8 16 1/2
Fourth quarter........................................ 3 1/4 15/16 18 1/2 5 1/2
KOGC COMMON STOCK KOGC PREFERRED STOCK
MARKET PRICES MARKET PRICES
------------------------ ----------------------
HIGH LOW HIGH LOW
------ ------ ---- -----
1996:
First quarter ........................................$ 3 5/16 1 18 3/4 6 3/4
Second quarter........................................ 4 2 3/16 22 5/8 15 1/4
Third quarter......................................... 4 1/8 2 9/16 26 20 3/8
Fourth quarter........................................ 3 1/4 2 7/16 25 23 3/4
1997:
First quarter (through February 28, 1997).............$ 3 1/16 2 1/2 25 1/2 23 3/4
</TABLE>
As of the February 28, 1997, there were approximately 2,027 record
holders of Common Stock and 246 record holders of Preferred Stock.
Dividends on the Preferred Stock accrue quarterly at the rate of
$.65625 per share. Three quarterly dividends on the Preferred Stock were paid at
that rate commencing on May 1, 1995. In January 1996, the Company announced the
suspension of dividend payments on the Preferred Stock to conserve cash. The
Company's existing credit facility prohibits and the indenture governing its
10 3/8% Senior Subordinated Notes (the "10 3/8% Notes") restricts the payment of
future preferred dividends, except that the Company's existing credit facility
and the indenture permit a payment of up to $4.6 million of such dividend
arrearages on or before May 1, 1997. In the event such payment is not made, the
preferred stockholders will be entitled to elect two additional members to the
Company's Board of Directors. As of February 28, 1997, the total amount of
dividends in arrears was $5.7 million.
ITEM 6. SELECTED FINANCIAL DATA
The following tables present selected historical and pro forma
financial data for the Company. The historical financial information at and for
the years ended December 31 in each of the three years presented through 1994 is
derived from the audited consolidated financial statements of Kelley Oil. The
Consolidation was treated as a purchase of the Public Unitholders' interests in
Kelley Partners by the Company for financial accounting purposes. Accordingly,
the historical financial information for the year ended December 31, 1995
reflects Kelley Oil's historical results on a stand-alone basis through the date
of the Consolidation in February 1995, with the results of combined operations
recorded thereafter. This information should be read in conjunction with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the Consolidated Financial Statements of the Company and related
Notes included elsewhere in this Report.
The pro forma financial information presented below is unaudited and
gives effect to the Consolidation as of January 1, 1994. This information is
presented for illustrative purposes only and is not necessarily indicative of
the Company's future financial performance or results of operations.
15
<PAGE>
KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------------------------------
1992 1993 1994 1995 1994 1995 1996
---------- ---------- ---------- ---------- ---------- ---------- ----------
PRO FORMA PRO FORMA
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Oil and gas revenues.....................$ 18,098 19,711 15,487 36,042 42,348 38,550 59,016
Gas marketing revenues, net(1)........... 1,013 1,353 1,335 956 45 958 1,838
Interest and other income................ 1,386 1,506 1,416 1,763 1,593 1,768 1,429
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total revenues........................ 20,497 22,570 18,238 38,761 43,986 41,276 62,283
---------- ---------- ---------- ---------- ---------- ---------- ----------
Production expenses...................... 3,478 3,993 3,760 10,835 12,318 11,461 10,709
Exploration costs........................ 7,126 14,226 7,404 23,387 18,083 23,727 5,438
General and administrative ..............
expenses.............................. 3,478 4,079 5,172 7,030 8,308 7,398 8,953
Interest and other debt expenses......... 2,684 6,638 4,571 21,956 12,361 22,763 24,401
Restructuring charge..................... -- -- 1,814 1,115 1,814 1,115 4,276
Depreciation, depletion and..............
amortization.......................... 9,768 18,857 20,474 35,591 39,727 36,190 20,440
Impairment of oil and gas
properties(2)......................... -- -- -- 150,138 -- 150,138 --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Loss before income taxes and
extraordinary item.................... (6,037) (25,223) (24,957) (211,291) (48,625) (211,516) (11,934)
Provision (benefit) for taxes............ (1,071) -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Net loss before extraordinary item....... (4,966) (25,223) (24,957) (211,291) (48,625) (211,516) (11,934)
Extraordinary income (loss).............. -- -- -- -- -- -- (17,030)
---------- ---------- ---------- ---------- ---------- ---------- ----------
Net loss................................. (4,966) (25,223) (24,957) (211,291) (48,625) (211,516) (28,964)
Preferred stock dividends................ 729 894 2,905 6,607 4,611 7,033 --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Net loss applicable to common and........
common equivalent shares..............$ (5,695) (26,117) (27,862) (217,898) (53,236) (218,549) (28,964)
========== ========== ========== ========== ========== ========== ==========
Loss per common share before
extraordinary item (primary and
assuming full dilution)...............$ (.39) (1.63) (1.58) (5.31) (1.39) (5.07) (.13)
Loss per common share (primary and
assuming full dilution)............... (.39) (1.63) (1.58) (5.31) (1.39) (5.07) (.32)
Average common and common equivalent
shares outstanding:
Primary and assuming full dilution.... 14,531 15,967 17,653 41,032 38,276 43,123 90,113
</TABLE>
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
-------------------------------------------------------------
1992 1993 1994 1995 1996
----------- ----------- ---------- ---------- ---------
<S> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Working capital (deficit)..................................$ 15,646 2,622 3,788 (9,233) (6,040)
Property and equipment, net(3)............................. 50,019 58,018 74,912 128,642 158,468
Long term debt, excluding current maturities............... 44,763 34,814 37,242 164,980 184,253
Stockholders' equity (deficit)............................. 24,411 27,415 45,180 (45,568) (30,535)
Total assets............................................... 95,562 87,145 106,513 151,342 189,227
</TABLE>
(1)Restated gas marketing revenues to reflect net of cost of gas sold.
(2) Reflects noncash impairment charges against the carrying value of
proved and unproved properties under FAS 121. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations."
(3) Includes pipeline and other transportation assets.
16
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following information should be read in conjunction with the
information contained in the Financial Statements of the Company included
elsewhere in this Report.
GENERAL
INTRODUCTION. Kelley accounts for its interests in Kelley Partners
and the DDPs using the proportionate consolidation method, combining its share
of assets, liabilities, income and expenses of those entities with that of
Kelley. In addition to its oil and gas development and producing activities,
Kelley markets natural gas and operates natural gas gathering and transportation
systems in Louisiana.
PRO FORMA COMPARISON. Because Kelley's historical results for periods
prior to the Consolidation reflect operations of Kelley Oil alone, they are not
comparable with its operating results after February 1995, which reflect
Kelley's combined operations following the Consolidation. Accordingly, the
following discussion of comparative results of operations for the the years
ended December 31, 1994 and 1995 reflect pro forma information giving effect to
the Consolidation from the beginning of 1994. The Company believes this provides
a more meaningful comparison of results and operational trends than a comparison
based on historical results. The following table sets forth certain operating
data regarding net production, average sales prices, production expenses and
revenues associated with Kelley's oil and natural gas operations for the periods
indicated.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------
1994 1995 1996
---------- ----------- ----------
PRO FORMA PRO FORMA
---------- -----------
<S> <C> <C> <C>
PRODUCTION DATA:
Oil and other liquid hydrocarbons (Mbbls)...... 446 348 232
Natural gas (Mmcf)............................. 18,141 18,828 23,466
Natural gas equivalent (Mmcfe)................. 20,817 20,916 24,858
AVERAGE SALES PRICE PER UNIT:
Oil and other liquid hyrocarbons (per Bbl).....$ 16.30 17.31 22.11
Natural gas (per Mcf).......................... 1.87 1.72 2.30
Natural gas equivalent (per Mcfe).............. 2.03 1.84 2.37
COST PER MCFE:
Production expenses............................ .59 .55 .43
General and administrative expenses............. .40 .35 .36
Depreciation, depletion and amortization........ 1.91 1.73 .82
</TABLE>
IMPAIRMENT OF ASSETS. In the fourth quarter of 1995, the Company
implemented the Financial Accounting Standards Board's Statement No. 121,
Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of ("FAS 121"). Under FAS 121, certain assets are required to be
reviewed periodically for impairment whenever circumstances indicate their
carrying amount exceeds their fair value and may not be recoverable. As a result
of its continuing operating losses and a decline in its proved reserves at
January 1, 1996, from year-earlier pro forma levels, the Company performed an
assessment of the carrying value of Kelley's oil and gas properties indicating
an impairment should be recognized as of year end. Under this analysis, the fair
value for Kelley's proved oil and gas properties was estimated on a depletable
unit basis using escalated pricing and present value discount factors reflecting
risk assessments. The fair value of Kelley's unproved properties was predicated
on current acreage cost estimates. Based on this analysis, Kelley recognized
noncash impairment charges against the carrying values of its proved and
unproved oil and gas properties under FAS 121 aggregating $83.4 million and
$66.7 million, respectively, at December 31, 1995.
CONTOUR TRANSACTION. In January 1996 the Company entered into
agreements with Contour Production Company L.L.P. ("Contour") which provided for
a two-stage equity investment of $75 million in the Company by Contour. On
February 15, 1996, the first stage of the equity investment was completed
through Contour's $48 million purchase of newly
17
<PAGE>
issued shares of the Company's common stock, $.01 par value ("Common Stock"),
representing on such date 49.8% of the voting shares of the Company (the
"Contour Transaction"). Additionally, the Company entered into an option
agreement (the "Contour Option"), under which Contour has committed to provide
the Company with $27 million in additional equity financing through an option to
purchase 27 million shares (the "Maximum Option Number") of Common Stock upon
satisfaction of certain conditions, including the absence of any Company debt
repurchase or redemption obligations as a result of the purchase (a "Debt
Event"), but in no event later than January 2000. A Debt Event would occur upon
(i) a "Change of Control" as defined in the indenture for the Company's 13 1/2%
Senior Notes due 1999 (the "13 1/2% Notes"), (ii) a "Change in Control" as
defined in the indenture for the Company's 7 7/8% Convertible Subordinated Notes
due 1999 (the "7 7/8% Notes") or (iii) a "Redemption Event" as defined in the
indenture for the Company's 8 1/2% Convertible Subordinated Debentures due 2000
(the "8 1/2 % Debentures"). A Debt Event with respect to either series of notes
or the 8 1/2% Debentures would entitle each holder of the affected securities to
require the repurchase or redemption of the holder's securities. Contour is
required to exercise the Contour Option for the Maximum Option Number within 30
days after it concludes in its sole discretion that a Debt Event would not occur
as a result of the purchase but in no event later than January 2000. While the
exercise of the Contour Option would not cause a Debt Event under the indenture
for the 8 1/2% Debentures, waivers or consents from the holders of a majority in
aggregate principal amount of the 7 7/8% Notes would be required to avoid a Debt
Event. As is subsequently discussed under the heading "Debt Refinancing," in
October 1996 the Company refinanced substantially all of its 13 1/2% Notes,
thereby eliminating the possibility of a Debt Event as to these securities.
In connection with the Contour Transaction, the Company also (i)
obtained consents from its principal stockholders to amend its Certificate of
Incorporation to increase its authorized Common Stock from 100 million shares to
200 million shares, (ii) entered into employment agreements with John F. Bookout
and other new executives elected by the Company's Board of Directors, (iii)
reduced the size of its Board to seven members and reconstituted the Board with
three continuing directors and four designees of Contour and (iv) replaced its
credit facility. Proceeds from the Contour Transaction, after repayment of bank
debt, plus funds available under its credit facility have permitted Kelley to
continue drilling operations and permitted it to pursue acquisition
opportunities needed to execute its business strategy for replacing its
production and expanding its reserves.
THE PARTNERSHIP MERGER (1996). In March 1996, Kelley Partners was
merged into the Company (the "Partnership Merger") as part of ongoing efforts to
streamline operations and reduce costs. Prior to the Partnership Merger, Kelley
Partners had outstanding 8 1/2% Debentures in the aggregate principal amount of
$26.9 million and 7 7/8% Notes in the aggregate principal amount at maturity of
$34.4 million. Under the terms of the Consolidation, the 8 1/2% Debentures and
7 7/8% Notes became convertible into the Company's Common Stock or a combination
of its Common Stock and Public Preferred Stock instead of units in Kelley
Partners based on the exchange ratios for the units in the Consolidation. In
connection with the Partnership Merger, the two outstanding subordinated debt
issues became direct obligations of the Company.
CONVERSION OF PREFERRED STOCK (1996). In March 1996, the Special
Conversion Right for the Public Preferred Stock was triggered by the Contour
Transaction. Under the Special Conversion Right, the conversion price of the
Public Preferred Stock was reduced to $4.00 for a period of 45 days ended April
25, 1996. A total of .7 million shares of Public Preferred Stock were tendered
pursuant to the Special Conversion Right, resulting in the issuance of 4.4
million shares of Common Stock and a reduction in the outstanding Public
Preferred Stock to 1.7 million shares as of December 31, 1996.
The Company had four outstanding series of ESOP Preferred Stock,
which ranked junior in dividend and liquidation rights to the Public Preferred
Stock. In June 1996, each of the outstanding 1.9 million shares of ESOP
Preferred Stock was redeemed for one share of the Company's Common Stock.
DEBT REFINANCING. Pursuant to an offer to purchase and consent
solicitation, dated September 24, 1996, as amended, the Company offered to
purchase for cash up to the aggregate principal amount of $100 million of its 13
1/2% Notes at a cash price equal to $1,110 per $1,000 principal amount, plus
interest accrued and unpaid through the payment date (the "Tender Offer"). In
conjunction with the offering, the Company also solicited consents to the
adoption of certain amendments to the 13 1/2% Indenture pursuant to which the 13
1/2% Notes were issued (the "Solicitation"), and offered to pay each consenting
holder of the 13 1/2% Notes $30 for each $1,000 principal amount of the 13 1/2%
Notes consenting (the "Consent Payments"). The Company received the requisite
consents which allowed it to amend the 13 1/2% Indenture on
18
<PAGE>
October 28, 1996. The Company also received tenders from holders of
approximately $99.6 million principal amount of the 13 1/2% Notes. On October
29, 1996, the Company issued an aggregate principal amount of $125 million of
10 3/8% Senior Subordinated Notes Due 2006, Series A, to its placement agents
pursuant to a placement agreement dated October 25, 1996. The Company used
substantially all of the net proceeds from the offering to pay tendering and
consenting holders and associated costs. The purpose of the refinancing was to
improve the Company's financial flexibility by (i) eliminating the covenants
applicable to the 13 1/2% Notes that might impede future financing and
acquisition transactions, (ii) extending the maturities of the Company's
long-term debt and (iii) replacing senior debt with senior subordinated debt
(which provides the Company flexibility to pursue additional senior debt
financings).
On February 3, 1997, the Company completed an Exchange of $125
million aggregate principal amount of publicly registered 10 3/8% Senior
Subordinated Notes, Series B for all of the then outstanding Series A notes. The
Series B notes were substantially identical to the Series A notes.
FOURTH QUARTER EXTRAORDINARY LOSS. In connection with the refinancing
of the 13 1/2% Notes and the payment of Consent Payments pursuant to the Tender
Offer and the Solicitation, the Company incurred an extraordinary loss in the
fourth quarter of 1996 of approximately $17.0 million, representing the excess
of the aggregate purchase price of the 13 1/2% Notes (including Consent
Payments) over their carrying value as of the date of the consummation of the
Refinancing.
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
YEAR ENDED DECEMBER 31, 1996 COMPARED TO YEAR ENDED DECEMBER 31,
1995. The Company's oil and gas revenues of $59.0 million for 1996 increased
52.8% compared to $38.6 million on a pro forma basis last year as a result of
increased natural gas prices and a 25.0% increase in natural gas production to
23.5 million Mcf in 1996. The average price of natural gas increased 33.7% to
$2.30 per Mcf in 1996 from $1.72 per Mcf in 1995. Kelley's production of natural
gas steadily declined in the second and third quarters of 1995 as a result of
poor drilling results in south Louisiana. During the fourth quarter of 1995, the
Company's prior management implemented a significant reduction in drilling
activity, which adversely affected production in the first half of 1996. The
Company's current accelerated drilling program increased production
substantially in the second half of 1996. Production of crude oil and natural
gas liquids during 1996 totaled 232,470 barrels with an average sales price of
$22.11 per barrel compared to 347,697 barrels at $17.31 per barrel in 1995 pro
forma; this represented a volume decrease of 33.1% and a price increase of
27.7%. The decline in oil and condensate volumes reflects the decline in south
Louisiana gas production.
For 1996, revenues from natural gas marketing and transportation
operations, net of associated costs, increased to $1.8 million from $1.0 million
in 1995.
Production expenses for 1996 decreased 7.0% to $10.7 million from
$11.5 million in 1995 on a pro forma basis, reflecting lower average costs on
production from north Louisiana, which is increasing in proportion to other
higher cost
19
<PAGE>
production from south Louisiana. On a unit basis, production expenses decreased
21.8% from $0.55 per Mcfe in 1995 to $0.43 per Mcfe in 1996.
Exploration costs totaled $5.4 million in 1996 and $23.7 million on a
pro forma basis in the corresponding period of 1995, a decrease of 77.2%
primarily reflecting a temporary suspension of exploratory drilling pending
negotiation of a joint exploration agreement in south Louisiana. The decrease in
these expenses also reflects lower geological and geophysical expenses and
unproved leasehold impairment costs.
General and administrative expenses of $9.0 million in 1996 increased
21.6% compared to $7.4 million on a pro forma basis in the corresponding period
last year. The increase in expense was primarily attributable to bonuses and
interim salaries paid in connection with the Contour Transaction to certain
members of the Company's prior management team and a decrease in the level of
general and administrative expenses capitalized or charged to exploration
expense. The amounts capitalized or charged were $3.3 million in 1996 compared
to $6.2 million in 1995, or $2.9 million less in 1996 than in 1995. On a unit
basis, general and administrative expenses increased from $0.35 per Mcfe in 1995
to $0.36 per Mcfe in 1996.
Interest and other debt expenses of $24.4 million in 1996 increased
7.0% from $22.8 million on a pro forma basis in 1995. The increase in interest
expense resulted primarily from higher interest rates under the 13 1/2% Notes
than under the $90.0 million of bank debt refinanced with proceeds from the
offering of the 13 1/2% Notes in June 1995 and higher average debt levels during
the current period. Interest expense on the 13 1/2% Notes was recorded for
approximately ten months in 1996 compared to six months in 1995. In October 1996
the 13 1/2% Notes were replaced with the 10 3/8% Notes. Included in its 1996
interest expense, the Company recorded noncash charges of $2.1 million for
amortization of debt issuance costs, $0.9 million for accretion of note
discount, $2.0 million for accretion of debt valuation discount and $0.1 million
in imputed interest associated with the acquisition of oil and gas properties.
Depreciation, depletion and amortization ("DD&A") decreased 43.6%
from $36.2 million on a pro forma basis in 1995 to $20.4 million in 1996 despite
the increase in production during 1996, primarily as a result of (i) lower
depletion rates following impairment charges aggregating $150.1 million
recognized in the fourth quarter of 1995 against the carrying value of Kelley's
oil and gas properties under FAS 121 and (ii) an increase in quantities of
proved developed reserves. On a unit basis, DD&A decreased from $1.73 per Mcfe
in 1995 to $0.82 per Mcfe in 1996.
The Company's cost-cutting measures during 1996 included a $4.3
million restructuring charge in 1996 associated primarily with staff reductions
and related severance settlements with certain employees and various
reorganization costs. As of December 31, 1996, accounts payable and accrued
expenses include upaid restructuring charges of $3.5 million.
Kelley recognized net losses before extraordinary items of $11.9
million in 1996 and $211.5 million on a pro forma basis in 1995. Impairment
charges aggregating $150.1 million were recognized in the fourth quarter of
1995. The improvement in 1996 results was attributable to higher oil and gas
prices, increased production and lower depreciation, depletion, amortization,
exploration and production costs, partially offset by higher interest expense,
reduced capitalization of general and administrative costs and the restructuring
charge.
YEAR ENDED DECEMBER 31, 1995 COMPARED TO YEAR ENDED DECEMBER 31,
1994. Pro forma oil and gas revenues of $38.6 million for 1995 decreased 8.7%
compared to $42.3 million in 1994. Pro forma production of natural gas during
1995 increased 3.8% to 18.8 million Mcf from 18.1 million Mcf in 1994, while the
average price of natural gas decreased 8.0% to $1.72 per Mcf in 1995 from $1.87
per Mcf in the prior year. Production of crude oil and natural gas liquids in
1995 totaled 347,697 barrels, with an average sales price of $17.31 per barrel
compared to 446,283 barrels at $16.30 per barrel in 1994, representing a volume
decline of 22.1% and a price increase of 6.2% on a pro forma basis. The decline
in oil and gas condensate volumes reflects the decline in liquids rich south
Louisiana gas production.
The decrease in pro forma oil and gas revenues in 1995 was primarily
attributable to production declines in the third and fourth quarters, including
the loss of production from the divestiture of nonstrategic properties at the
beginning of the third quarter and lower natural gas prices. The prices received
for Kelley's natural gas production reflect the benefits
20
<PAGE>
of swap and option hedging arrangements, which added approximately $1.8 million
to pro forma oil and gas revenues in 1995.
Additionally, Kelley realized a gain of $0.8 million from the sale of
nonstrategic properties in July 1995. These nonstrategic properties were offered
for sale due to their high operating costs and low priority within Kelley's
development strategy. Kelley received net proceeds of $6.8 million for the
properties, which accounted for approximately 4.6% of its pro forma proved
reserves as of January 1, 1995. The sales affected production levels for the
second half of the year.
Production expenses for 1995 decreased 6.5% on a pro forma basis to
$11.5 million from $12.3 million in 1994, primarily reflecting a shift to north
Louisiana production. For the same reason, on a unit basis, pro forma production
expenses decreased to $0.55 per Mcfe in 1995 from $0.59 per Mcfe in the prior
year.
Pro forma exploration costs totaled $23.7 million in 1995 and $18.1
million in 1994, an increase of 30.9%. The increase in these expenses resulted
from higher dry hole and leasehold expiration expenses in south Louisiana.
Pro forma general and administrative expenses of $7.4 million in 1995
decreased 10.8% compared to $8.3 million in 1994, reflecting the benefits of the
restructuring implemented at the end of 1994 plus ongoing cost containment
measures. In addition, the Company incurred one-time expenses associated with
the Consolidation of $0.6 million during 1994. On a unit basis, these expenses
decreased from $0.40 per Mcfe in 1994 to $0.35 per Mcfe in 1995.
On a pro forma basis, interest and other debt expenses of $22.8
million in 1995 increased 83.9% from $12.4 million in the prior year. The
increase in interest expense resulted partially from higher debt levels and from
higher interest rates associated with the issuance of the Notes in June 1995. In
addition to its interest expense, Kelley recorded noncash charges in 1995 of
$3.8 million for amortization of debt issuance costs, of which $1.7 million
represents prepaid financing costs written off in connection with a related bank
debt refinancing. Kelley also recorded noncash charges in 1995 for accretion of
note discount and accretion of debt valuation discount of $0.8 million and $1.9
million, respectively.
DD&A decreased 8.9% on a pro forma basis from $39.7 million in 1994
to $36.2 million in 1995, generally as a result of lower net capitalized costs
in 1995. On a unit basis, DD&A decreased from $1.91 per Mcfe in 1994 to $1.73
per Mcfe in 1995.
In December 1994, the Company implemented a restructuring including
staff reductions of approximately 25% to streamline management and
administrative functions and reduce general and administrative expenses. An
additional management realignment was implemented in the fourth quarter of 1995.
Nonrecurring charges of $1.1 million and $1.8 million primarily related to
severance costs were taken in the fourth quarters of 1995 and 1994,
respectively.
Kelley recognized pro forma net losses before income taxes of $211.5
million in 1995 and $48.6 million in the prior year. The increased loss
primarily reflects noncash impairment charges of $150.1 million in 1995 against
the carrying value of proved and unproved oil and gas properties, lower gas
prices and higher interest expense and exploration costs, partially offset by
lower charges for DD&A.
LIQUIDITY AND CAPITAL RESOURCES
GENERAL. Kelley's liquidity is materially affected by cash flows
generated from its oil and gas production and has been adversely affected in
recent years prior to 1996 by unsuccessful drilling results on high risk
prospects in south Louisiana. In addition, high interest expense and
restrictions under Kelley's debt instruments after the Consolidation limited
Kelley's ability to fund drilling projects. These restrictions required the
Company to suspend preferred stock dividends and seek a substantial equity
infusion in early 1996 to avoid a financial covenant default under the credit
agreement in effect at that time. This effort resulted in the Contour
Transaction, completed in February 1996. The Contour Transaction allowed the
Company to retire its outstanding bank debt, secure a new banking facility and
improve its working capital position.
Although the Contour Transaction and the debt refinancings have
provided Kelley with the means to continue its drilling operations with the
objective of increasing its cash flow and reserves, the Company had $200.2
million face amount
21
<PAGE>
of debt outstanding as of December 31, 1996, requiring $19.0 million in annual
cash interest payments. Although dividends are generally prohibited under the
Company's existing credit facility and are restricted under the indenture for
the 10 3/8% Senior Subordinated Notes (the "Indenture"), the outstanding
preferred stock is cumulative, requires dividends to accumulate at the rate of
$4.6 million annually and carries liquidation preferences over the Common Stock
totaling $48.2 million at December 31, 1996, including such dividend arrearages.
The Company's existing credit facility permits the Company to make a $4.6
million payment of such dividend arrearages on or prior to May 1, 1997. The
Indenture also permits the Company to make such payment. The Board of Directors
of the Company, however, has not determined whether to make any payments for
dividend arrearages at this time, and any such payment must not be prohibited
under applicable corporate law.
LIQUIDITY. Net cash provided by operating activities, before working
capital adjustments, during 1996 aggregated $17.8 million. The Company's cash
position was decreased during the year by $2.3 million primarily as a result of
property and equipment expenditures of $53.8 million and net principal
retirements of $8.5 million on bank borrowings offset by the $44.0 million in
net proceeds from the issuance of Common Stock, primarily in the Contour
Transaction, $5.8 million from the sale of assets and $6.3 million from the
Refinancing. As a result of these activities, cash and cash equivalents
decreased from $6.4 million at December 31, 1995 to $4.1 million as of December
31, 1996. As of that date, Kelley had a working capital deficit of $6.0 million,
compared to a working capital deficit of $9.2 million at the end of 1995.
Net cash used in operating activities, before working capital
adjustments, aggregated $3.5 million during 1995. During the year, the Company's
cash position was increased through proceeds of $16.0 million from the issuance
of 4.0 million shares of Common Stock in an institutional private placement, net
proceeds of $95.3 million from the sale of the 13 1/2% Notes, proceeds of $37.1
million from borrowings under its credit facilities, net proceeds of $6.8
million from the sale of nonstrategic properties, cash of $1.6 million received
in the Consolidation and proceeds of $0.3 million from the exercise of employee
stock options. Funds used in investing and financing activities were comprised
of property and equipment expenditures of $47.0 million, principal payments of
$100.0 million on long-term borrowings and preferred stock dividends of $6.6
million. As a result of these activities, cash and cash equivalents decreased
from $9.3 million at December 31, 1994 to $6.4 million at December 31, 1995. As
of that date, Kelley had a working capital deficit of $9.2 million, as compared
to a working capital surplus of $3.8 million at the end of 1994.
The following table sets forth on an unaudited basis historical and
pro forma net cash provided by (used in) operating activities before working
capital adjustments, net cash used in investing activities and EBITDAX.
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------------------
1994 1995 1994 1995 1996
--------- --------- --------- --------- ---------
PRO FORMA PRO FORMA
--------- ---------
<S> <C> <C> <C> <C> <C>
Net cash provided by (used in) operating activities
before working capital adjustments.........................$ 3,671 (3,470) 6,731 (3,009) 17,811
Net cash used in investing activities......................... 42,058 37,989 75,960 39,535 47,989
EBITDAX(1).................................................... 9,306 20,896 23,360 22,417 42,621
</TABLE>
(1) EBITDAX is calculated as net income (loss) before extraordinary itmes,
excluding interest expense and other debt expenses, income taxes, exploration
costs, restructuring expense, depletion, depreciation, amortization, and
impairment of oil and gas properties. EBITDAX is not a measure of cash flow as
determined by GAAP. The Company has included information concerning EBITDAX
because EBITDAX is a measure used by certain investors in determining a
company's historical ability to service its indebtedness. EBITDAX should not be
considered as an alternative to, or more meaningful than, net income or cash
flow as determined in accordance with GAAP as an indicator of Kelley's operating
performance or liquidity. EBITDAX is not necessarily comparable to a similarly
titled measure of another company.
NEW CREDIT FACILITY. The Company replaced its previous credit
facility with its existing credit facility (the "New Credit Facility") effective
as of December 12, 1996. The borrowers under the New Credit Facility are the
Company, Kelley Oil Corporation ("Kelley Oil") and Kelley Operating Company,
Ltd. ("Kelley Operating"), with Concorde Gas Marketing, Inc. (a subsidiary of
the Company) and the Company's subsidiary partnerships as guarantors.
22
<PAGE>
The New Credit Facility provides for a maximum $125 million revolving
credit loan and matures, with all amounts owed thereunder becoming due and
payable, effective December 12, 2000. Borrowings under the New Credit Facility
are subject to a borrowing base to be determined semi-annually by the lenders
(based in part on the proved oil and gas reserves and other assets of Kelley)
which may be redetermined more frequently at the election of the lenders or the
borrowers. Initially, the borrowing base is $57.5 million. To the extent that
the borrowing base is less than the aggregate principal amount of all
outstanding loans and letters of credit under the New Credit Facility, 50% of
such deficiency must be cured within 90 days and the balance must be cured
within the next 90 days unless such deficiency is a result of an asset sale, in
which case the deficiency must be cured on the date the borrowing base is
re-determined as a result of such sale. Borrowings under the New Credit Facility
are secured by substantially all of the oil and gas assets of the Company and
its subsidiaries and the proceeds therefrom.
So long as no default or event of default (as defined in the New
Credit Facility) is continuing, borrowings under the New Credit Facility bear
interest, at the option of the borrowers, at either (i) LIBOR plus 1.0% to 1.5%
(depending on the level of utilization of the borrowing base) or (ii) the higher
of (a) the agent's prime rate and (b) the federal funds rate plus 0.5%. The
Borrowers incur a quarterly commitment fee ranging from 0.30% to 0.375% per
annum on the average unused portion of the borrowing base, depending upon the
level of utilization.
The New Credit Facility contains covenants which, among other things,
limit the amount of debt Kelley may incur, limit the placement of liens on
Kelley's assets, limit lease transactions, limit Kelley's ability to enter into
certain hedging transactions, restrict the ability of the Company or any of its
subsidiaries to merge with or into another person and prevent the Company from
prepaying certain Subordinated Indebtedness unless certain conditions are met.
Further, covenants require that, for specified periods, the Company maintain
specified ratios between EBITDAX and senior indebtedness and EBITDAX and
interest on Indebtedness.
The New Credit Facility also prohibits the payment of dividends,
except that it permits the payment on or prior to May 1, 1997 of $4.6 million on
dividend arrearages on the outstanding preferred stock. In the event such
payment is not made, the preferred stockholders will be entitled to elect two
additional members to the Company's Board of Directors.
CONTOUR. Pursuant to the second stage of Contour's equity investment
in the Company, Contour has committed to provide an additional $27.0 million in
equity financing upon satisfaction of certain conditions, including the absence
of any Company debt repurchase or redemption obligations, but in no event later
than January 2000. While exercise of such commitment cannot be assured prior to
January 2000, any proceeds received pursuant to such commitment will reduce
Kelley's dependence on outside financing to support subsequent drilling and
acquisition activities. See "General-Contour Transaction" above.
CAPITAL COMMITMENTS. In February 1994, the 1994 Development Drilling
Program (the "1994 DDP") completed a public offering of 20.9 million units at
$3.00 per unit on a preemptive basis to public unitholders in Kelley Partners.
Kelley Oil's subscription commitment to the 1994 DDP, after return of capital,
aggregated $56.0 million or 92.2% of the 1994 DDP's total. As of December 31,
1996, Kelley Oil had contributed $50.2 million to the 1994 DDP, together with
interest at a market rate on the portion of its commitment that remained
outstanding after November 1994. Kelley Oil intends to contribute the unfunded
portion of its commitment, which totaled $5.8 million at December 31, 1996,
together with interest, as funds are needed for completion of the 1994 DDP's
drilling program. Kelley Oil is the primary beneficiary of these commitments as
a result of its 92.2% ownership in the 1994 DDP, while approximately $0.5
million can be attributable to the public unitholders' interests in the 1994
DDP.
During 1997, Kelley's capital expenditures are expected to continue
to be focused on development drilling in north Louisiana, where Kelley currently
expects to expend over $30 million on drilling and completion of wells, subject
to regulatory and third party consents. In addition, Kelley plans to balance its
drilling strategy by pursuing acquisition opportunities to expand its reserve
base and operating areas, while utilizing its joint venture with Williams to
explore and develop its higher potential exploratory prospects in south
Louisiana at minimal cost to Kelley. Kelley has an active program for ongoing
evaluation of opportunities meeting its acquisition criteria. There can be no
assurance that attractive acquisition candidates will be available to the
Company on terms it deems reasonable or that any completed acquisition will
ultimately prove to be a successful undertaking by the Company.
23
<PAGE>
The Company anticipates that, except for any significant property
acquisitions, business combinations or development required by exploratory
success (and subject to price stability), cash flow from operations, and
borrowings under the New Credit Facility will be adequate to fund Kelley's debt
service obligations, expected capital expenditure requirements and working
capital needs. To fully realize Kelley's objectives for property development and
acquisitions, however, the Company may be required to pursue additional
financing alternatives.
STOCK-BASED COMPENSATION. In October 1995, the Financial Accounting
Standards Board issued Statement of Financial Accounting Standard No. 123,
Accounting for Stock Based Compensation ("FAS 123"), effective for the Company
on January 1, 1996. FAS 123 permits, but does not require, a fair-value based
method of accounting for employee stock option plans, resulting in compensation
expense being recognized in the results of operations when stock options are
granted. The Company has not elected (and does not expect to elect) to follow
the fair-value based method of accounting for stock option plans, and therefore,
no compensation expense is (or will be) recognized. However, as required by FAS
123, the Company will provide pro forma disclosure of net income and earnings
per share in the notes to its consolidated financial statements as if the
fair-value based method of accounting had been applied.
INFLATION AND CHANGING PRICES. Oil and natural gas prices, as with
most commodities, are highly volatile, have fluctuated during recent years and
generally have not followed the same pattern as inflation. The following table
shows the changes in the average oil and gas prices received by Kelley Oil
during the periods indicated.
AVERAGE AVERAGE
OIL PRICE GAS PRICE
($/BBL) ($/MCF)
--------- ---------
YEAR ENDED:
December 31, 1996......................$ 22.11 2.30
December 31, 1995 (PRO FORMA).......... 17.31 1.72
December 31, 1994 (PRO FORMA).......... 16.30 1.87
FORWARD-LOOKING STATEMENTS
FROM TIME TO TIME, THE COMPANY 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 COMPANY. 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 COMPANY,
INCLUDING RATES OF INFLATION, NATURAL GAS PRICES, RESERVE ESTIMATES, RATES AND
TIMING OF FUTURE PRODUCTION OF OIL AND GAS, AND CHANGES IN THE LEVEL AND TIMING
OF FUTURE COSTS AND EXPENSES RELATED TO DRILLING AND OPERATING ACTIVITIES.
WORDS SUCH AS "ANTICIPATED," "EXPERT," "ESTIMATE," "PROJECT" AND
SIMILAR EXPRESSIONS ARE INTENDED TO IDENTIFY FORWARD-LOOKING STATEMENTS.
FORWARD-LOOKING STATEMENTS MAY BE MADE IN MANAGEMENT'S STATEMENTS (ORALLY OR IN
WRITING) INCLUDING PRESS RELEASES, AND IN FILINGS OF THE SEC, INCLUDING THIS
REPORT.
In addition to "Uncertainties in Estimating Reserves" and other such
factors mentioned in this Report, the following additional risk factors should
be considered:
LEVERAGE. As of December 31, 1996, the Company had $200.2 million
face amount of debt outstanding and stockholders' deficit of approximately $30.5
million. The Company expects to incur additional indebtedness for future
borrowings under its credit facility as it continues its strategy for
acquisition, exploration and development of oil and gas reserves. The Company's
ability to make scheduled payments of principal, to pay interest on or to
refinance its indebtedness for money borrowed depends on its future performance
and successful implementation of its strategy, which is subject not only to its
own actions but also to general economic, financial, competitive, legislative,
regulatory and other factors beyond its control, as well as to the prevailing
market prices for oil, natural gas and natural gas liquids.
24
<PAGE>
DEPLETION OF RESERVES; NECESSITY OF SUCCESSFUL EXPLORATION AND
DEVELOPMENT. Producing oil and natural gas reservoirs generally are
characterized by declining production rates that vary depending upon reservoir
characteristics and other factors. Kelley's future oil and natural gas reserves
and production, and, therefore, cash flow and income, are highly dependent upon
Kelley's success in efficiently developing its current reserves and acquiring
additional reserves that are economically recoverable.
VOLATILITY OF OIL, NATURAL GAS AND NATURAL GAS LIQUIDS PRICES.
Kelley'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 Kelley
for its oil, natural gas and natural gas liquids production and the levels of
such production are subject to government regulation, legislation and policies.
Kelley's future financial condition and results of operations will depend, in
part, upon the prices received for Kelley's oil and natural gas production, as
well as the costs of finding, acquiring, developing and producing reserves.
OPERATING HAZARDS AND UNINSURED RISKS. Oil and gas drilling
activities are subject to numerous risks, many of which are uninsurable,
including the risk that no commercially viable oil or natural gas production
will be obtained; many of such risks are beyond Kelley's control. The decision
to purchase, explore or develop a prospect or property will depend in part on
the evaluation of data obtained through geophysical and geological analyses,
production data and engineering studies, the results of which are often
inconclusive or subject to varying interpretations. The cost of drilling,
completing and operating wells is often uncertain, and overruns in budgeted
expenditures are common risks that can make a particular project uneconomical.
Technical problems encountered in actual drilling, completion and workover
activities can delay such activity and add substantial costs to a project.
Further, drilling may be curtailed, delayed or canceled as a result of many
factors, including title problems, weather conditions, compliance with
government permitting requirements, shortages of or delays in obtaining
equipment, reductions in product prices and limitations in the market for
products. At present, the level of drilling activity in the United States has
resulted in increased demand for, and therefore increased costs associated with,
drilling equipment and the services and products of other vendors to the
industry. In particular, in connection with drilling activities in the marshy
regions of south Louisiana, there has been an increased cost of drilling
operations due to increased costs for barge rigs necessary to conduct activity
in such region. Moreover, the number of drilling contractors offering barge
drilling and workover services is limited.
The availability of a ready market for Kelley'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.
Kelley's oil and natural gas business also is subject to all of the
operating risks associated with the drilling for and production of oil and
natural gas, including, but not limited to, uncontrollable flows of oil, natural
gas, brine or well fluids into the environment (including groundwater and
shoreline contamination), blowouts, cratering, mechanical difficulties, fires,
explosions, pollution and other risks, any of which could result in substantial
losses to Kelley. Although Kelley 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 Kelley.
25
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES: PAGE
<S> <C>
Independent Auditors' Reports............................................................................. 27
Consolidated Balance Sheets - December 31, 1995 and 1996.................................................. 29
Consolidated Statements of Loss - For the years ended December 31, 1994, 1995 and 1996.................... 30
Consolidated Statements of Cash Flows - For the years ended December 31, 1994, 1995 and 1996.............. 31
Consolidated Statements of Changes in Stockholders' Equity (Deficit) - For the years ended
December 31, 1994, 1995 and 1996....................................................................... 32
Notes to Consolidated Financial Statements................................................................ 33
</TABLE>
26
<PAGE>
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Stockholders of Kelley Oil & Gas Corporation
We have audited the accompanying consolidated balance sheets of
Kelley Oil & Gas Corporation and subsidiaries as of December 31, 1996 and 1995,
and the related consolidated statements of loss, cash flows, and stockholders'
equity (deficit) for each of the two years in the period ended December 31,
1996. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and perform the 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 consolidated financial statements present
fairly, in all material respects, the financial position of Kelley Oil & Gas
Corporation and subsidiaries at December 31, 1996 and 1995, and the results of
their operations and their 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 to the consolidated financial statements, in
1995 the Company 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
27
<PAGE>
REPORT OF INDEPENDENT AUDITORS
To the Board of Directors and Stockholders of Kelley Oil & Gas Corporation
We have audited the consolidated balance sheet of Kelley Oil & Gas
Corporation (the Company) as of December 31, 1994, and the related statements of
loss, stockholders' equity, and cash flows of Kelley Oil & Gas Corporation and
Subsidiaries for the year ended December 31, 1994. The consolidated balance
sheet as of December 31, 1994 is not presented separately herein. These
financial statements are the responsibility of the Company's 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 consolidated financial statements referred to
above present fairly, in all material respects, the consolidated financial
position of Kelley Oil & Gas Corporation and Subsidiaries at December 31, 1994
and consolidated results of their operations and their cash flows for the year
ended December 31, 1994, in conformity with generally accepted accounting
principles.
Ernst & Young LLP
Houston, Texas
March 6, 1995
28
<PAGE>
KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------------
1995 1996
------------ -----------
<S> <C> <C>
ASSETS:
Cash and cash equivalents..........................................................$ 6,352 4,070
Accounts receivable................................................................ 13,753 22,519
Accounts receivable - drilling programs............................................ 2,035 1,533
Prepaid expenses and other current assets.......................................... 557 1,347
------------ -----------
Total current assets............................................................ 22,697 29,469
------------ -----------
Oil and gas properties, successful efforts method:
Unproved properties, net........................................................ 13,050 12,521
Properties subject to amortization.............................................. 287,970 338,794
Pipelines and other transportation assets, at cost ................................ 4,723 4,689
Furniture, fixtures and equipment.................................................. 1,233 1,700
------------ -----------
306,976 357,704
Less: Accumulated depreciation, depletion and amortization........................ (178,334) (199,236)
------------ -----------
Total property and equipment, net............................................... 128,642 158,468
Other non-current assets, net...................................................... 3 1,290
------------ -----------
TOTAL ASSETS....................................................................$ 151,342 189,227
============ ===========
LIABILITIES:
Accounts payable and accrued expenses..............................................$ 23,502 31,093
Accounts payable - drilling programs............................................... 8,428 4,416
------------ -----------
Total current liabilities....................................................... 31,930 35,509
------------ -----------
Long term debt..................................................................... 164,980 184,253
------------ -----------
TOTAL LIABILITIES............................................................... 196,910 219,762
------------ -----------
STOCKHOLDERS' DEFICIT:
Preferred stock, $1.50 par value, 20,000 shares authorized at December 31,
1995 and 1996; 4,304 and 1,746 shares issued and outstanding at December
31, 1995 and 1996, respectively
(liquidation value $61,058 and $48,219, respectively)........................... 6,456 2,618
Common stock, $.01 par value, 100,000 and 200,000 shares authorized at
December 31, 1995 and 1996, respectively; 44,041 and 98,293 shares
issued and outstanding at December 31, 1995 and 1996, respectively.............. 440 983
Additional paid-in capital......................................................... 225,804 273,096
Retained deficit................................................................... (278,268) (307,232)
------------ -----------
TOTAL STOCKHOLDERS' DEFICIT..................................................... (45,568) (30,535)
------------ -----------
TOTAL LIABILITIES AND STOCKHOLDERS' DEFICIT........................................$ 151,342 189,227
============ ===========
</TABLE>
See Notes to Consolidated Financial Statements.
29
<PAGE>
KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF LOSS
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------------
1994 1995 1996
------------- ------------ -----------
<S> <C> <C> <C>
Oil and gas revenues...................................................$ 15,487 36,042 59,016
Gas marketing revenues, net............................................ 1,335 956 1,838
Interest and other income.............................................. 1,416 1,763 1,429
------------- ------------ ----------
Total revenues...................................................... 18,238 38,761 62,283
------------- ------------ ----------
Production expenses.................................................... 3,760 10,835 10,709
Exploration costs...................................................... 7,404 23,387 5,438
General and administrative expenses.................................... 5,172 7,030 8,953
Interest and other debt expenses....................................... 4,571 21,956 24,401
Restructuring expense.................................................. 1,814 1,115 4,276
Depreciation, depletion and amortization............................... 20,474 35,591 20,440
Impairment of oil and gas properties................................... -- 150,138 --
------------- ------------ ----------
Total expenses...................................................... 43,195 250,052 74,217
------------- ------------ ----------
Loss before income taxes and extraordinary item........................ (24,957) (211,291) (11,934)
Income taxes........................................................... -- -- --
------------- ------------ ----------
Net loss before extraordinary item..................................... (24,957) (211,291) (11,934)
Extraordinary item..................................................... -- -- (17,030)
------------- ------------ ----------
NET LOSS............................................................... (24,957) (211,291) (28,964)
Less: cumulative preferred stock dividends............................. 2,905 6,607 --
------------- ------------ ----------
NET LOSS APPLICABLE TO COMMON STOCK....................................$ (27,862) (217,898) (28,964)
============= ============ ==========
Loss per common share before extraordinary item
(primary and assuming full dilution)................................$ (1.58) (5.31) (.13)
============= ============ ==========
Loss per common share
(primary and assuming full dilution)................................$ (1.58) (5.31) (.32)
============= ============ ==========
Average common and common equivalent shares outstanding
(primary and assuming full dilution)................................ 17,653 41,032 90,113
============= ============ ==========
</TABLE>
See Notes to Consolidated Financial Statements.
30
<PAGE>
KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------------
1994 1995 1996
---------- ----------- ----------
OPERATING ACTIVITIES:
<S> <C> <C> <C>
Net loss..........................................................$ (24,957) (211,291) (28,964)
Adjustments to reconcile net loss to net cash
provided by (used in) operating activities:
Depreciation, depletion and amortization....................... 20,474 35,591 20,440
Impairment of oil and gas properties........................... -- 150,138 --
Gain on sale of properties..................................... -- (777) (176)
Dry hole costs................................................. 4,751 18,152 35
Accretion and amortization of other debt expenses.............. 140 3,602 5,170
Debenture conversion costs..................................... 1,449 -- --
Restructuring expense.......................................... 1,814 1,115 4,276
Extraordinary loss............................................. -- -- 17,030
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable
and other current assets..................................... (1,780) 9,457 (9,054)
Decrease (increase) in other non-current assets................ (2,274) 3,075 (1,945)
Decrease in accounts payable and accrued expenses.............. (3,942) (16,103) (2,953)
------------- ------------ -----------
Net cash provided by (used in) operating activities............... (4,325) (7,041) 3,859
------------- ------------ -----------
INVESTING ACTIVITIES:
Capital expenditures.............................................. (42,323) (47,005) (42,198)
Acquisition of oil and gas properties............................. -- -- (11,594)
Cash received in consolidation.................................... -- 1,596 --
Proceeds from sale of properties.................................. 265 7,420 5,803
------------- ------------ -----------
Net cash used in investing activities............................. (42,058) (37,989) (47,989)
------------- ------------ -----------
FINANCING ACTIVITIES:
Proceeds from long term borrowings................................ 34,302 37,100 50,000
Principal payments on long term borrowings........................ (19,000) (100,000) (58,500)
Proceeds from sale of notes, net.................................. -- 95,302 120,938
Debenture conversion costs........................................ (79) -- (1,100)
Proceeds from sale of common stock, net........................... 123 16,319 43,998
Proceeds from sale of preferred stock, net........................ 32,503 -- --
Retirement of senior notes........................................ -- -- (113,488)
Dividends on preferred stock...................................... (2,905) (6,607) --
------------- ------------ -----------
Net cash provided by financing activities......................... 44,944 42,114 41,848
------------- ------------ -----------
Decrease in cash and cash equivalents............................. (1,439) (2,916) (2,282)
Cash and cash equivalents, beginning of period.................... 10,707 9,268 6,352
------------- ------------ -----------
Cash and cash equivalents, end of period..........................$ 9,268 6,352 4,070
============= ============ ===========
</TABLE>
See Notes to Consolidated Financial Statements.
31
<PAGE>
KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (DEFICIT)
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
ADDITIONAL
PREFERRED COMMON PAID IN RETAINED
STOCK STOCK CAPITAL DEFICIT
---------- ---------- ----------- -----------
<S> <C> <C> <C> <C>
Stockholders' equity at January 1, 1994.......................$ 5,055 176 57,638 (32,504)
Issuance of 1,380 shares of preferred stock,
$1.50 par value............................................ 2,070 -- 30,433 --
Issuance of 413 shares of preferred stock in..................
exchange for debentures, $1.50 par value................... 618 -- 10,454 --
Issuance of 66 shares of common stock......................... -- 1 122 --
Preferred stock cash dividends................................ -- -- -- (2,905)
Net loss...................................................... -- -- -- (24,957)
---------- ---------- ----------- -----------
BALANCE AT DECEMBER 31, 1994............................... 7,743 177 98,647 (60,366)
---------- ---------- ----------- -----------
Additional paid in capital from issuance of preferred
and common stock in consolidation.......................... -- -- 108,632 --
Issuance of 650 shares of preferred stock,
$1.50 par value, in consolidation......................... 975 -- -- --
Issuance of 20,622 shares of common stock
in consolidation.......................................... -- 206 -- --
Issuance of 4,000 shares of common stock
in private placement....................................... -- 40 15,960 --
Conversion of 1,508 shares of preferred stock into
1,508 shares of common stock............................... (2,262) 15 2,247 --
Issuance of 225 shares of common stock........................ -- 2 318 --
Syndication costs............................................. -- -- -- (4)
Preferred stock dividends..................................... -- -- -- (6,607)
Net loss -- -- -- (211,291)
---------- ---------- ----------- -----------
BALANCE AT DECEMBER 31, 1995............................... 6,456 440 225,804 (278,268)
---------- ---------- ----------- -----------
Issuance of 48,000 shares of common stock in
Contour Transaction........................................ -- 480 47,520 --
Conversion of 697 shares of preferred stock into
4,355 shares of common stock............................... (1,045) 44 1,001 --
Conversion of 1,862 shares of preferred stock into
1,862 shares of common stock............................... (2,793) 19 2,774 --
Issuance of 36 shares of common stock......................... -- -- 62 --
Syndication costs............................................. -- -- (4,065) --
Net loss...................................................... -- -- -- (28,964)
---------- ---------- ----------- -----------
BALANCE AT DECEMBER 31, 1996...............................$ 2,618 983 273,096 (307,232)
========== ========== =========== ===========
</TABLE>
See Notes to Consolidated Financial Statements.
32
<PAGE>
KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION. Kelley Oil & Gas Corporation (the "Company") was
incorporated in Delaware in September 1994 for the purpose of effecting a
consolidation (the "Consolidation") of the equity interests in Kelley Oil
Corporation, a Delaware corporation ("Kelley Oil"), and Kelley Oil & Gas
Partners, Ltd., a Texas limited partnership ("Kelley Partners") of which Kelley
Oil was the managing general partner. In the Consolidation, each outstanding
unit of limited partner interest ("Units") in Kelley Partners owned by investors
other than Kelley Oil and its subsidiaries ("Public Unitholders") was converted
into 1.2188 shares of the Company's common stock ("Common Stock") or, at the
election of each Public Unitholder, .609 of a share of Common Stock and .127 of
a share of the Company's $2.625 convertible exchangeable preferred stock
("Preferred Stock"). Stockholders of Kelley Oil received equivalent securities
of the Company on a one for one basis. Kelley Oil's 19.9% ownership interest in
Kelley Partners was not converted into the Company's Common or Preferred Stock,
since that ownership interest was reflected in the valuation of Kelley Oil and
the consideration allocated to its stockholders. The Consolidation was completed
on February 7, 1995 upon approval by investors in Kelley Oil and Kelley
Partners. As a result of the Consolidation, Kelley Oil became a wholly owned
subsidiary of the Company, and Kelley Partners became a 99.99% owned subsidiary
partnership. The Company's operations, conducted through Kelley Oil and its
subsidiaries, include the development of oil and gas properties and the
purchase, sale and transportation of natural gas. In March 1996, Kelley Partners
was merged into the Company (the "Partnership Merger"). The Company, the
corporate subsidiaries and its proportionate partnership interests are referred
to herein as "Kelley."
ACCOUNTING TREATMENT OF THE CONSOLIDATION. At the time of the
Consolidation, the Company's capital stock received by Kelley Oil's stockholders
represented a majority of the total voting power of the combined capital stock
issued by the Company in the Consolidation. Accordingly, the Consolidation has
been treated as a purchase by the Company of the Public Unitholders' interests
in Kelley Partners. As a result of the purchase accounting treatment of the
Consolidation, the Company's consolidated financial statements through December
31, 1994 reflect only Kelley Oil's historical results, and its financial
statements for 1995 reflect Kelley Oil's historical results through the date of
the Consolidation, with results of combined operations recorded thereafter.
PRINCIPLES OF CONSOLIDATION. The consolidated financial statements
include the accounts of (i) the Company, (ii) its corporate subsidiaries, all of
which are wholly owned, and (iii) the Company's proportionate interests in
Kelley Partners, its operating partnership, Kelley Operating Company, Ltd.
("Kelley Operating"), and development drilling programs sponsored by Kelley Oil
to conduct drilling operations on properties of Kelley Operating ("DDPs"). All
significant intercompany accounts and transactions have been eliminated in
consolidation.
REVENUE RECOGNITION. Kelley recognizes oil and gas revenue from its
interests in producing wells as oil and gas is produced and sold from those
wells. Oil and gas sold in production operations is not significantly different
from Kelley's share of production. Revenues from gas marketing and
transportation of natural gas are recognized upon completion of the sale and
when transported volumes are delivered and are presented net of cost of gas sold
and related operating expenses.
OIL AND GAS PROPERTIES. All of Kelley's interests in its oil and gas
properties are located in the United States. Under the successful efforts
method, the costs of successful wells, development dry holes and leases
containing productive reserves are capitalized and amortized on a
unit-of-production basis over the life of the related reserves. 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. Exploratory
drilling costs are initially capitalized pending determination of proved
reserves but are charged to expense if no proved reserves are found. Other
exploration costs, including geological and geophysical expenses, leasehold
expiration costs and delay rentals, are expensed as incurred. Unproved
properties are periodically assessed for impairment in value, with any
impairment charged to expense.
33
<PAGE>
PROPERTY IMPAIRMENT UNDER FAS 121. In the fourth quarter of 1995,
Kelley implemented the Financial Accounting Standards Board's Statement No. 121,
Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of ("FAS 121"). Under FAS 121, certain assets are required to be
reviewed periodically for impairment whenever circumstances indicate their
carrying amount exceeds their fair value and may not be recoverable. As a result
of its continuing operating losses and a decline in its proved reserves at
January 1, 1996 from year-earlier pro forma levels, Kelley performed an
assessment of the carrying value of its oil and gas properties indicating an
impairment should be recognized as of year end. Under this analysis, the fair
value for Kelley's proved oil and gas properties was estimated using escalated
pricing and present value discount factors reflecting risk assessments. The fair
value of Kelley's unproved properties was predicated on current acreage cost
estimates. Based on this analysis, Kelley recognized noncash impairment charges
against the carrying values of its proved and unproved oil and gas properties
under FAS 121 aggregating $83.4 million and $66.7 million, respectively, at
December 31, 1995.
PROPERTY AND EQUIPMENT. The costs of pipelines and other
transportation assets are depreciated using the straight-line method over the
estimated useful lives of the related assets. Furniture, fixtures and equipment
are recorded at cost and depreciated using the straight-line method over the
estimated useful life of five years. Maintenance and repairs are charged to
expense.
LOSS PER SHARE. Primary loss per share reflects net loss less
preferred stock dividends divided by the average number of common shares and
equivalents outstanding during the respective years. Common shares issuable
under stock options and upon conversion of convertible subordinated debentures
and convertible preferred stock are added to average common shares and
equivalents outstanding when dilutive.
INCOME TAXES. The tax effect of each item in the consolidated
statements of loss is recognized in the current period regardless of when the
tax is paid. Taxes on amounts that affect financial and taxable income in
different periods are reported as deferred income taxes. These temporary
differences relate primarily to (i) differences in financial reporting
provisions for depreciation and amortization and that of income tax reporting,
and (ii) the impairments to proved and unproved oil and gas properties expensed
for financial reporting but not for income tax reporting.
CASH AND CASH EQUIVALENTS. The Company considers all highly liquid
investments with an original maturity of three months or less when purchased to
be cash equivalents.
FINANCIAL INSTRUMENTS. The Company's financial instruments consist of
cash and cash equivalents, payables and debt. As of December 31, 1996, the
estimated fair value of the Company's debt was $202.6 million. The fair value of
such financial instruments has been estimated based on quoted market prices and
the Black-Scholes pricing model. The carrying amount of the Company's other
financial instruments approximates fair value.
OTHER NON-CURRENT ASSETS. Other non-current assets at December 31,
1995 and 1996 consist of debt issue costs. In 1995, the Company charged to
expense prepaid financing costs of $1.7 million in connection with a debt
refinancing and recognized impairments of goodwill aggregating $0.7 million
associated with the acquisition costs of two subsidiaries. Accumulated
amortization at December 31, 1995 and 1996 was $0.3 million and $0.4 million,
respectively.
STOCK BASED COMPENSATION. In October 1995, the Financial Accounting
Standards Board issued Statement of Financial Accounting Standard No. 123,
Accounting for Stock Based Compensation ("FAS 123"), effective for the Company
on January 1, 1996. FAS 123 permits, but does not require, a fair value based
method of accounting for employee stock option plans, resulting in compensation
expense being recognized in the results of operations when stock options are
granted. The Company plans to continue the use of its current intrinsic value
based method of accounting for stock option plans where no compensation expense
is recognized.
RISKS AND UNCERTAINTIES. The preparation of financial statements in
conformity with generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
34
<PAGE>
CHANGES IN PRESENTATION. Certain financial statement items in 1994
and 1995 have been reclassified to conform to the 1996 presentation.
NOTE 2 - AFFILIATED PROGRAMS
INTERESTS IN KELLEY PARTNERS AND KELLEY OPERATING. Through its
ownership in Kelley Oil, the Company had a 1.99% general partner interest in
Kelley Partners, and David L. Kelley, the former Chairman and Chief Executive
Officer of Kelley Oil, had a .01% general partner interest. The general partner
interests in Kelley Partners were retained by Kelley Oil and Mr. Kelley after
the Consolidation and were eliminated in the Partnership Merger. In connection
with the Partnership Merger, Kelley Partners' 98% limited partner interest in
Kelley Operating was transferred to Kelley Oil, and Petrofunds, Inc., an
indirect wholly owned subsidiary of the Company, was substituted for Mr. Kelley
as special general partner of Kelley Operating. Kelley Oil remains the managing
general partner.
STRUCTURE OF DEVELOPMENT PARTNERSHIPS. Kelley Oil and Mr. Kelley are
the general partners of the DDPs, with general partner interests of 3.94% and
.02%, respectively, for which they contributed a proportionate amount of
capital. In addition, Kelley Oil had undertaken to purchase for its own
investment account all units in DDPs that were not subscribed preemptively by
Unitholders of Kelley Partners. The DDPs have no officers, directors or
employees and utilize the management and staff of Kelley for all management and
administrative functions.
THE 1994 DDP. In February 1994, the 1994 DDP completed a public
offering of 20.9 million units of its limited and general partner interests at
$3.00 per unit. As of March 15, 1997, Kelley owned 19.2 million units (91.9%) in
the 1994 DDP, together with its 3.94% general partner interest. Kelley Oil's
subscription for units in the 1994 DDP, together with its 3.94% general partner
interest, represented a commitment aggregating $60.1 million or 92.15% of the
1994 DDP's total committed capital (the "KOIL Share"), with other unitholders
committing for the balance or 7.85% of the 1994 DDP's total committed capital
(the "Outside Share"), payable in each case 10% on subscription and the balance
through the end of November 1994. As of December 31, 1996, Kelley Oil had
contributed $50.2 million to the 1994 DDP.
The 1994 DDP's partnership agreement provides that any contributions
of the partners not used or committed to be used for drilling activities during
the two-year period from the commencement of operations through February 29,
1996 (the "Commitment Period") shall be distributed to the partners on a pro
rata basis as a return of capital. Based on the amount of committed capital
actually used and committed to drilling activities by the end of the Commitment
Period, Kelley Oil determined the adjusted level of committed partnership
capital at $60.7 million in accordance with the 1994 DDP's partnership
agreement, and the 1994 DDP then distributed the Outside Share of uncommitted
capital to its unitholders other than Kelley Oil aggregating $0.3 million in
March 1996. Because the KOIL Share of committed capital exceeded its capital
contributions at that time, Kelley Oil did not receive a distribution of
uncommitted capital. Kelley Oil intends to contribute the unfunded portion of
its commitment, currently aggregating $5.8 million (of which $5.3 million is
beneficially payable to itself), together with interest, as funds are needed for
completion of the 1994 DDP's drilling program.
THE 1992 DDP. During November 1992, the 1992 DDP completed a public
offering of 16.0 million units of limited and general partner interests at $3.00
per unit. As of March 15, 1997, Kelley Oil owned 13.4 million units (83.8%) in
the 1992 DDP, together with its 3.94% general partner interest. As of December
31, 1996, the 1992 DDP was indebted to Kelley Oil for loans and reimbursement
obligations aggregating $5.4 million. Kelley recorded interest income on this
indebtedness of $0.2 million in 1996, net of intercompany eliminations. No
interest income was recorded for 1994 or 1995.
REIMBURSEMENTS FROM AFFILIATED PROGRAMS. Kelley is reimbursed for
administrative and overhead expenses incurred in connection with the management
and administration of each of these affiliated programs. Such amounts, net of
intercompany eliminations, aggregated $1.9 million, $1.6 million and $0.2
million in 1994, 1995 and 1996, respectively.
INTEREST ON DDP COMMITMENTS. During 1994, 1995 and 1996, Kelley Oil
paid or accrued interest at a market rate in the amounts, net of intercompany
elimination, of $27,000, $229,000 and $91,000, respectively, on deferred
subscription commitments to DDPs.
35
<PAGE>
NOTE 3 - LONG TERM DEBT
LONG TERM DEBT. The Company's long term debt at December 31, 1995 and
1996 is comprised of the following items of indebtedness.
(IN THOUSANDS)
DECEMBER 31,
------------------------
1995 1996
-------- --------
Bank credit facilities ......................... $ 22,000 13,500
13 1/2% Senior Notes ........................... 95,926 435
10 3/8% Senior Subordinated Notes .............. -- 119,923
7 7/8% Subordinated Notes ...................... 25,360 27,486
8 1/2% Subordinated Debentures ................. 21,694 22,909
-------- --------
164,980 184,253
Less current maturities ..................... -- --
-------- --------
$164,980 184,253
======== ========
BANK CREDIT FACILITIES. In connection with the Consolidation, the
Company completed a refinancing in February 1995 for the outstanding bank debt
of Kelley Partners, Kelley Oil and the 1992 DDP. The refinancing was provided
under a $70 million revolving credit facility (the "Prior Credit Facility") and
a $20 million term loan facility (the "Term Facility"). The borrowers under the
facilities were Kelley Operating and Kelley Oil. Kelley Partners, the Company
and its other subsidiary partnerships were guarantors. Borrowings of $90 million
under the two facilities were used to refinance Kelley Partners' bank debt of
$69.9 million, Kelley Oil's debt of $9 million under one of its credit
facilities and borrowings of $6 million by the 1992 DDP, with the balance of
$5.1 million used for working capital, including expenses of the Consolidation.
In June 1995, proceeds from a public offering of the Company's 13
1/2% Senior Notes due June 15, 1999 in the aggregate principal amount of $100
million (the "13 1/2% Senior Notes") were used to repay all outstanding
borrowings under the two facilities, and the Term Facility was terminated. The
agreement covering the Prior Credit Facility was amended at that time to (i)
reduce the credit limit to $40 million, (ii) reduce the interest rate to the
agent bank's prime rate or, at the election of the Company, a rate ranging from
1 1/4% to 1 3/4% above a quoted Libor rate, together with a quarterly commitment
fee equal to 3/8% per annum of the unused borrowing base, (iii) eliminate all
financial covenants other than a working capital maintenance requirement and a
limitation on accounts payable above a specified level and (iv) conform the
borrowing base limitations with debt restrictions under the indenture for the 13
1/2% Senior Notes, resulting in a reduction of the borrowing base to $35
million.
In January 1996, the agreement covering the Prior Credit Facility was
further amended to (i) reduce the credit limit to $35 million, (ii) generally
limit the use of future borrowings to reduce trade payables, (iii) increase the
interest rate to 2% above the agent's prime rate and (iv) add certain financial
covenants. The financial covenants added to the Prior Credit Facility included a
current ratio test that the Company would have been unable to satisfy at the
initial measuring date on May 15, 1996 without a substantial equity infusion.
In February 1996, the Company repaid outstanding bank borrowings of
$30 million with proceeds from an equity infusion and replaced the Prior Credit
Facility with a $35 million revolving credit facility from a new bank group (the
"Interim Credit Facility"). Interest on borrowings under the Interim Credit
Facility was payable at a rate equal to (i) the higher of 1/2% above the agent
bank's prime rate or 1% above the federal funds rate in effect from time to time
or (ii) at the Company's election, 1 1/2% above a quoted Libor rate, together
with a quarterly commitment fee equal to 3/8% per annum of the unused portion of
the available borrowing base. The agreement for the Interim Credit Facility
required the payment of interest only until March 15, 1999, when all borrowings
were repayable, subject to mandatory prepayment with net proceeds from asset
sales in excess of related borrowing base reductions.
36
<PAGE>
The borrowers under the Interim Credit Facility were Kelley Operating
and Kelley Oil. The Company and its other subsidiary partnerships were
guarantors. Borrowings under the Interim Credit Facility were secured by
mortgages on all of Kelley's oil and gas and pipeline assets, together with a
security interest in production proceeds from oil and gas sales.
The Company replaced the Interim Credit Facility with a new credit
facility effective as of December 12, 1996 (the "New Credit Facility"). The
borrowers under the New Credit Facility are the Company, Kelley Oil and Kelley
Operating, with Concorde Gas Marketing, Inc. (a subsidiary of the Company) and
the Company's subsidiary partnerships as guarantors.
The New Credit Facility provides for a maximum $125 million revolving
credit loan and matures, with all amounts owed thereunder becoming due and
payable, effective December 12, 2000. Borrowings under the New Credit Facility
are subject to a borrowing base to be determined semi-annually by the lenders
(based in part on the proved oil and gas reserves and other assets of Kelley)
which may be redetermined more frequently at the election of the lenders or the
borrowers. Initially, the borrowing base is $57.5 million. To the extent that
the borrowing base is less than the aggregate principal amount of all
outstanding loans and letters of credit under the New Credit Facility, 50% of
such deficiency must be cured within 90 days and the balance must be cured
within the next 90 days unless such deficiency is a result of an asset sale, in
which case the deficiency must be cured on the date the borrowing base is
re-determined as a result of such sale. Borrowings under the New Credit Facility
are secured by substantially all of the oil and gas assets of the Company and
its subsidiaries and the proceeds therefrom.
So long as no default or event of default (as defined in the New
Credit Facility) is continuing, borrowings under the New Credit Facility bear
interest, at the option of the borrowers, at either (i) LIBOR plus 1.0% to 1.5%
(depending on the level of utilization of the borrowing base) or (ii) the higher
of (a) the agent's prime rate and (b) the federal funds rate plus 0.5%. The
Borrowers incur a quarterly commitment fee ranging from 0.30% to 0.375% per
annum on the average unused portion of the borrowing base, depending upon the
level of utilization.
The New Credit Facility contains covenants which, among other things,
limit the amount of debt Kelley may incur, limit the placement of liens on
Kelley's assets, limit lease transactions, limit Kelley's ability to enter into
certain hedging transactions, restrict the ability of the Company or any of its
subsidiaries to merge with or into another person and prevent the Company from
prepaying certain Subordinated Indebtedness unless certain conditions are met.
Further, covenants require that, for specified periods, the Company maintain
specified ratios between EBITDAX and senior indebtedness and EBITDAX and
interest on Indebtedness.
The New Credit Facility also prohibits the payment of dividends,
except that it permits the payment on or prior to May 1, 1997 of $4.6 million of
dividend arrearages on the outstanding preferred stock. In the event such
payment is not made, the preferred stockholders will be entitled to elect two
additional members to the Company's Board of Directors.
13 1/2% SENIOR NOTES. In June 1995, the Company issued $100 million
principal amount of its 13 1/2% Senior Notes and applied its net proceeds from
the offering primarily to repay outstanding bank debt of $90 million and fund
drilling operations. The 13 1/2% Senior Notes were senior unsecured obligations
of the Company, guaranteed by Kelley Oil, Kelley Operating and, prior to the
Partnership Merger, by Kelley Partners. The indenture for the 13 1/2% Senior
Notes generally limited additional borrowings by the Company and its
subsidiaries to the greater of 12 1/2% of adjusted consolidated net tangible
assets or $30 million for working capital purposes plus $5 million per year for
capital expenditures. The Company's ability to borrow the additional $5 million
per year for capital expenditures and to pay dividends on its Preferred Stock
were conditioned upon the absence of declines in oil and gas reserves from
estimated volumes at December 31, 1995. The 13 1/2% Senior Note indenture also
contained a number of other covenants that included limitations on mergers and
asset transfers, dividend and other payments and use of proceeds from asset
sales.
Pursuant to an offer to purchase and consent solicitation, dated
September 24, 1996, as amended , the Company offered to purchase for cash up to
the aggregate principal amount of $100 million of its 13 1/2% Senior Notes at a
cash price equal to $1,110 per $1,000 principal amount, plus interest accrued
and unpaid through the payment date. In conjunction with the offering, the
Company also solicited consents to the adoption of certain amendments to the 13
1/2% Senior Note indenture pursuant to which the 13 1/2% Senior Notes were
issued, and offered to pay each consenting holder of the 13 1/2% Senior Notes
$30 for each $1,000 principal amount of the 13 1/2% Senior Notes consenting. The
Company received the requisite consents
37
<PAGE>
which allowed it to amend the 13 1/2% Senior Note indenture on October 28, 1996.
The Company also received tenders from holders of approximately $99.6 million
principal amount of the 13 1/2% Senior Notes. On October 29, 1996, the Company
issued an aggregate principal amount of $125 million of 10 3/8% Senior
Subordinated Notes Due 2006 (the "10 3/8% Senior Subordinated Notes"), Series A,
to its placement agents pursuant to a placement agreement dated October 25,
1996. The Company used substantially all of the net proceeds from the offering
to pay tendering and consenting holders. The purpose of the refinancing was to
improve the Company's financial flexibility by (i) eliminating the covenants
applicable to the 13 1/2% Senior Notes that might impede future financing and
acquisition transactions, (ii) extending the maturities of the Company's
long-term debt and (iii) replacing senior debt with senior subordinated debt
(which provides the Company flexibility to pursue additional senior debt
financings).
FOURTH QUARTER EXTRAORDINARY LOSS. In connection with the refinancing
of the 13 1/2% Notes and the payment of Consent Payments pursuant to the Tender
Offer and the Solicitation, the Company incurred an extraordinary loss in the
fourth quarter of 1996 of approximately $17.0 million, representing the excess
of the aggregate purchase price of the 13 1/2% Notes (including Consent
Payments) over their carrying value as of the date of the consummation of the
Refinancing.
10 3/8% SENIOR SUBORDINATED NOTES. The 10 3/8% Senior Subordinated
Notes are redeemable at the option of the Company, in whole or in part, at
redemption prices declining from 105.19% in 2001 to 100% in 2003 and thereafter.
The 10 3/8% Senior Subordinated Notes represent unsecured obligations of the
Company and are subordinate in right of payment to all existing and future
senior indebtedness. The indenture for the notes contains conditions and
limitations, including but not limited to restrictions on additional
indebtedness, payment of dividends, redemption of capital stock, and certain
mergers and consolidations. The holder of the 10 3/8% Senior Subordinated Notes
also can require the Company to repurchase the notes at 101% of the principal
amount upon a Change of Control, as defined.
On February 3, 1997, the Company completed an exchange of
$125,000,000 aggregate principal amount of publicly registered 10 3/8% Senior
Subordinated Notes, Series B, for all of the then outstanding Series A notes.
The Series B notes were substantially identical to the Series A notes.
7 7/8% SUBORDINATED NOTES AND 8 1/2% SUBORDINATED DEBENTURES. Prior
to the Partnership Merger, Kelley Partners had outstanding 7 7/8% Convertible
Subordinated Notes due 1999 (the "7 7/8% Subordinated Notes") in the aggregate
principal amount at maturity of $34.4 million and 8 1/2% Convertible
Subordinated Debentures due April 1, 2000 (the "8 1/2% Subordinated Debentures")
in the aggregate principal amount of $26.9 million (together, the "Subordinated
Debt"). Under the terms of the Consolidation, the Subordinated Debt became
convertible into the Company's Common Stock or a combination of Common and
Preferred Stock instead of Units based on the exchange ratios for the Units in
the Consolidation. In connection with the Partnership Merger, the Subordinated
Debt became direct obligations of the Company.
ESOP LOANS. The Company historically maintained the ESOP to purchase
and hold qualifying securities for the accounts of its employees. To finance the
purchase of those securities, the ESOP obtained term loans bearing interest at
rates of prime plus 1% and 85% of that rate. The ESOP term loans were guaranteed
by Kelley Oil and were repaid in 1995.
INTEREST PAYMENTS. Cash payments attributable to interest on all
indebtedness, excluding the ESOP loans, aggregated $3.1 million, $14.2 million
and $19.2 million for the years ended December 31, 1994, 1995 and 1996,
respectively.
DEBT MATURITIES. The Company has aggregate debt maturities of $34.7
million in 1999, $40.4 million in 2000 and $125 million in 2006.
NOTE 4 - STOCKHOLDERS' EQUITY (DEFICIT)
COMMON STOCK PRIVATE PLACEMENT. In February 1995, the Company
completed an institutional private placement of 4 million shares of its Common
Stock. Proceeds of $16 million from the private placement were used to fund
drilling activities and for working capital. Pending application, $10 million of
the proceeds were used to reduce borrowings under the Prior Credit Facility.
38
<PAGE>
CONTOUR STOCK PURCHASE. In February 1996, the Company issued 48
million shares of its Common Stock at $1.00 per share to Contour Production
Company L.L.C. ("Contour") upon the closing of a Stock Purchase Agreement
between the Company and Contour (the "Contour Transaction"). The newly issued
shares represented 49.8% of the Company's voting power. In connection with the
Contour Transaction, the Company (i) entered into an option agreement with
Contour (the "Contour Option Agreement"), (ii) obtained consents from its
principal stockholders, subject to compliance with applicable securities law, to
amend its Certificate of Incorporation to increase its authorized Common Stock
from 100 million shares to 200 million shares, (iii) entered into employment
agreements with John F. Bookout, President of Contour, and three other new
executives named by him, (iv) adopted a nonqualified stock option plan for the
new executives other than Mr. Bookout, (v) amended its existing incentive stock
option plans, (vi) reduced the size of its board of directors (the "Board") to
seven members and reconstituted the Board with three continuing directors and
four designees of Contour and (vii) replaced the Prior Credit Facility with the
Interim Credit Facility.
CONTOUR OPTION. Under the Contour Option Agreement, the Company
granted Contour an option (the "Contour Option") to purchase up to 27 million
shares (the "Maximum Option Number") of Common Stock at $1.00 per share (subject
to antidilution adjustments) upon satisfaction of certain conditions, including
the absence of any Company debt repurchase or redemption obligations as a result
of the purchase (a "Debt Event"). A Debt Event would occur upon (i) a "Change of
Control" as defined in the indenture for the 13 1/2% Senior Notes, (ii) a
"Change in Control" as defined in the indenture for the 7 7/8% Subordinated
Notes or (iii) a "Redemption Event" as defined in the indenture for the 8 1/2%
Subordinated Debentures. The refinancing eliminates the possibility of a Debt
Event as to the 13 1/2% Senior Notes. A Debt Event with respect to either the 7
7/8% Subordinated Notes or the 8 1/2% Subordinated Debentures would entitle each
holder of the affected securities to require the repurchase or redemption of the
holder's securities. Contour is required to exercise the Contour Option for the
Maximum Option Number within 30 days after it concludes in its sole discretion
that a Debt Event would not occur as a result of the purchase but in no event
later than January 2000. While the exercise of the Contour Option would not
cause a Debt Event under the indenture for the 8 1/2% Subordinated Debentures,
waivers from the holders of the 7 7/8% Subordinated Notes or amendments to the
Debt Event provisions of its indenture will require consents from holders of a
majority in aggregate principal amount of the 7 7/8% Subordinated Notes.
PREFERRED STOCK. In May 1994, Kelley Oil completed a public offering
of 1,380,000 shares of KOIL $2.625 Preferred Stock at $25 per share. The shares
were convertible into KOIL Common Stock at a conversion price of $7.20 per share
and exchangeable after April 1995 at Kelley Oil's option for its 10 1/2%
Convertible Subordinated Debentures due 2004. Net proceeds from the public
offering aggregated $32.5 million, of which $19 million was used to repay
outstanding borrowings under Kelley Oil's credit facilities and the balance was
applied primarily to finance ongoing drilling operations through its investment
in the 1994 DDP. In September 1994, an additional 412,516 shares of KOIL $2.625
Preferred Stock were issued in exchange for outstanding KOIL Debentures. During
1994, Kelley Oil paid quarterly dividends on outstanding KOIL $2.625 Preferred
Stock at the rate of $.65625 per share, aggregating $2,011,000. Each outstanding
share of KOIL $2.625 Preferred Stock was converted in the Consolidation into one
share of the Company's Preferred Stock, which has the same terms as the KOIL
$2.625 Preferred Stock except for expanded voting rights.
The Company issued 649,807 shares of its Preferred Stock to Public
Unitholders in the Consolidation, resulting in a total of 2,442,323 outstanding
shares of Preferred Stock after giving effect to the shares issued to holders of
KOIL $2.625 Preferred Stock. During 1995, the Company paid quarterly dividends
on its outstanding Preferred Stock at the rate of $.65625 per share, aggregating
$5,985,000. In January 1996, the Company suspended the payment of the quarterly
Preferred Stock dividend scheduled for February 1, 1996 to conserve cash. Future
dividends on the Preferred Stock are prohibited under the agreement covering the
New Credit Facility, except that a one time payment of up to $4.6 million is
permitted prior to May 1, 1997. No interest is payable on Preferred Stock
arrearages; however, the terms of the Preferred Stock enable holders, voting
separately as a class, to elect two additional directors to the Board at each
meeting of stockholders at which directors are to be elected during any period
when Preferred Stock dividends are in arrears in an aggregate amount equal to at
least six quarterly dividends, whether or not consecutive.
Each share of Preferred Stock is convertible, at the holder's option,
into 3.4722 shares of Common Stock, equivalent to a conversion price of $7.20
per share of Common Stock relative to the $25 per share liquidation preference
of the Preferred Stock (the "Preferred Conversion Price"). Under the terms of
the Certificate of Designation governing the Preferred Stock, the Contour
Transaction triggered a special conversion right under which the Preferred
conversion price
39
<PAGE>
was reduced to $4.00 for a period of 45 days commencing March 12, 1996. On April
25, 1996, 696,823 shares of Preferred Stock were converted into 4,355,040 shares
of Common Stock under the special conversion right.
ESOP PREFERRED STOCK. From 1987 through 1992, a total of 3,370,000
shares of KOIL ESOP Preferred Stock in four separate series were issued to the
ESOP for a total of $8,948,000. Each share of KOIL ESOP Preferred Stock had
voting rights equivalent to one share of KOIL Common Stock. The KOIL ESOP
Preferred Stock was convertible into KOIL Common Stock, at any time at the
option of the ESOP, at the rate of one share of KOIL Common Stock for each share
of KOIL ESOP Preferred Stock. During 1994, Kelley Oil paid quarterly dividends
on outstanding KOIL ESOP Preferred Stock at rates ranging from $0.0375 per share
to $0.25 per share, aggregating $894,000 for the year, which were used to
service ESOP loans. In January 1995, a total of 1,135,263 shares of KOIL ESOP
Preferred Stock were converted into the same number of shares of KOIL Common
Stock upon distribution to employees affected by the year-end restructuring.
The outstanding shares of KOIL ESOP Preferred Stock were converted in
the Consolidation into four equivalent series of the Company's cumulative
convertible preferred stock ("ESOP Preferred Stock"), which ranks junior in
dividend and liquidation rights to the Company's Preferred Stock. Each share of
ESOP Preferred Stock is convertible into one share of Common Stock. During 1995,
the Company paid quarterly dividends on outstanding ESOP Preferred Stock at
rates ranging from $0.0375 per share to $0.25 per share, aggregating $622,000
for the year. Dividends on the ESOP Preferred Stock during the first three
quarters of 1995 were used to service ESOP loans, which were repaid in full at
the end of the third quarter. A dividend paid in the fourth quarter of 1995 plus
the ESOP contribution for the quarter were invested in a certificate of deposit.
As of December 31, 1995, 1,861,619 shares of ESOP Preferred Stock were
outstanding. In June 1996, each of the 1,861,619 shares of ESOP Preferred Stock
was redeemed for one share of the Company's Common Stock.
NOTE 5 - EMPLOYEE STOCK PLANS
The Company has both qualified and nonqualified stock option plans
that provide for granting of options for the purchase of common stock to key
employees. These stock options may be granted for periods up to ten years and
are generally subject to vesting periods up to three years.
Stock option activity for the Company during 1994, 1995 and 1996 was
as follows:
<TABLE>
<CAPTION>
NUMBER OF SHARES 1994 1995 1996
- ---------------- ------------- ------------- -------------
<S> <C> <C> <C>
Stock options outstanding, beginning of year................ 644,000 564,000 2,105,000
Granted:
1995 at $1.75 to $2.38................................ -- 1,766,000 --
1996 at $1.00 to $2.88................................ -- -- 2,520,000
Exercised:
1994 at $1.10 to $7.63................................ 66,000 -- --
1995 at $1.10 to $2.00................................ -- 225,000 --
1996 at $1.75......................................... -- -- 35,600
Forfeited:
1994 at $4.13......................................... 14,000 -- --
------------- ------------- -------------
Stock options outstanding, end of year
(per share: $1.00 to $4.12 at December 31, 1996)........ 564,000 2,105,000 4,589,400
============= ============= =============
</TABLE>
In February 1995, all previously issued options to the extent
outstanding, aggregating options to acquire 234,000 shares at prices from $7.00
to $7.63, were repriced at $4.13 per share. In February 1996, in connection with
the Contour Transaction, all unvested options then held by employees were fully
vested. Additionally, the then-existing plans were amended to extend the period
during which a terminated employee may exercise vested options to three years
after termination of employment.
40
<PAGE>
At December 31, 1996, options were exercisable for 2,069,400 shares
and 994,000 shares were available for future option grants.
During 1996 and 1995 the Company issued options under three stock
option plans as follows:
<TABLE>
<CAPTION>
ESTIMATED OPTION
FAIR MARKET VALUE
PLAN ISSUED OPTION PRICE GRANT DATE AT DATE OF GRANT
- ---- ------- ------------ ---------- -----------------
<C> <C> <C> <C> <C>
1995 Incentive Stock Option Plan................. 1,099,000 $ 2.375 11/08/95 $ 1.38
1995 Incentive Stock Option Plan................. 401,000 1.75 12/12/95 1.02
1996 Nonqualified Stock Option Plan.............. 2,500,000 1.00 02/15/96 .58
1996 Incentive Stock Option Plan................. 20,000 2.875 09/20/96 1.67
</TABLE>
The fair value of the options granted was estimated on the date of
grant using the Black-Scholes option-pricing model assuming a risk-free interest
rate of 6.8%, no expected dividend yield, an expected life of five years and an
expected volatility of 60%.
The Company applies the Accounting Principles Board Opinion No. 25
and related Interpretations in accounting for stock option and purchase plans.
Accordingly, no compensation cost has been recognized for the stock option
plans. Had compensation cost been determined based upon the fair market value at
the grant dates for awards under those plans consistent with the method of FASB
Statement 123, the Company's net loss and earnings per share for the year ended
December 31, 1995 and 1996 would have been as reflected in the pro forma amounts
indicated below:
1995 1996
-------- ------
Net loss before extraordinary item (in thousands)......$(211,411) (14,172)
Loss per common share before extraordinary item........ (5.31) (.16)
Net loss (in thousands)................................ (211,411) (31,202)
Loss per common share.................................. (5.31) (.35)
NOTE 6 - INCOME TAXES
The following table sets forth a reconciliation of the statutory
federal income tax for the years ended December 31, 1994, 1995 and 1996:
(IN THOUSANDS)
<TABLE>
<CAPTION>
1994 1995 1996
------------- ----------- -------
<S> <C> <C> <C>
Loss before income taxes...............................$ (24,957) (211,291) (28,965)
------------ ----------- ----------
Income tax benefit computed at statutory rates......... (8,485) (71,839) (9,848)
Increase in valuation allowance..................... 7,524 71,236 16,322
Adjustment to NOL carryforward (increase)........... -- -- (7,209)
Permanent differences:
Nondeductible expenses.............................. 922 567 735
Amortization........................................ 33 33 --
Other-net........................................... 6 3 --
------------ ----------- ----------
Tax benefit......................................$ -- -- --
============ =========== ==========
</TABLE>
41
<PAGE>
No federal income taxes were paid for the years ended December 31,
1994, 1995 and 1996.
DEFERRED INCOME TAXES. Deferred income tax provisions for the years
ended December 31, 1994, 1995 and 1996 result from the following temporary
differences:
(IN THOUSANDS)
<TABLE>
<CAPTION>
1994 1995 1996
---------- ----------- -------
<S> <C> <C> <C>
Temporary differences related to oil and gas properties:
Intangible drilling costs..........................................$ 4,985 6,387 5,523
Depreciation and depletion......................................... (5,540) (58,276) 1,034
Exploration and dry hole costs..................................... (2,517) (8,508) (1,849)
Lease rentals...................................................... 260 -- 1,279
Leasehold and equipment write-offs and sales....................... 1,152 1,611 5,375
Partnership income................................................. (419) -- --
Restructuring costs................................................... -- -- (807)
Net operating loss carryforward benefit............................... (5,418) (12,434) (26,998)
Valuation allowance................................................... 7,524 71,236 16,322
Other................................................................. (27) (16) 121
---------- ----------- ----------
Total deferred tax benefit.........................................$ -- -- --
========== =========== ==========
</TABLE>
The Company's deferred tax position reflects the net tax effects of
temporary differences between the carrying amounts of assets and liabilities for
financial reporting purposes and the amounts used for income tax reporting.
Significant components of the deferred tax liabilities and assets are as
follows:
(IN THOUSANDS)
<TABLE>
<CAPTION>
1995 1996
---------- -------
<S> <C> <C>
Deferred tax liabilities:
Tax over book depletion, depreciation and
capitalization methods on oil and gas properties........$ -- --
Deferred tax assets:
Book over tax depletion, depreciation and
capitalization methods on oil and gas properties........ 53,312 42,696
Net operating loss carryforwards........................... 35,181 62,179
Charitable contribution carryforwards...................... 138 78
Alternative minimum tax credit carryforwards............... 21 21
Valuation allowance........................................ (88,652) (104,974)
---------- ----------
Total deferred tax assets.................................. -- --
---------- ----------
Net deferred tax liability....................................$ -- --
========== ==========
</TABLE>
NET OPERATING LOSS CARRYFORWARDS AND ALTERNATIVE MINIMUM TAX CREDITS.
As of December 31, 1996, the Company had cumulative net operating loss
carryforwards ("NOL") for federal income tax purposes of approximately
$182,879,000, which expire in 2000 through 2011, and net operating loss
carryforwards for alternative minimum tax purposes of approximately
$135,066,000, which expire in 2008 through 2011. Due to previous ownership
changes, future utilization of the net operating loss carry forwards will be
limited by Internal Revenue Code section 382. The Company also had approximately
$21,000 of alternative minimum tax credit carryforwards, which have no
expiration date.
42
<PAGE>
NOTE 7 - OTHER RELATED PARTY TRANSACTIONS
ADVISORY FEES. During 1996, pursuant to an agreement dated January
23, 1996, the Company paid Bessemer Partners & Co., an affiliate of the majority
stockholder of Contour Production Company L.P., a financial advisory fee of
$2,000,000 in connection with the Contour Transaction and an advisory fee of
$500,000 for ongoing advisory services. The Company is obligated to pay
additional advisory fees of $500,000 in each of 1997 and 1998.
NOTE 8 - EMPLOYEE STOCK OWNERSHIP PLAN
Kelley Oil established the ESOP effective January 1, 1984 for the
benefit of substantially all of its employees. Kelley Oil guaranteed the ESOP
loans referred to in Note 3 (collectively, the "ESOP Loans") and recorded
deferred employee compensation balances in a like amount, which were deducted
from stockholders' equity. Prior to 1996, Kelley Oil made contributions to the
ESOP for covered employees in amounts up to 15% of their annual salaries up to a
specified level. Contribution expense was recognized using the cash payments
method. Cumulative expense under this method is greater than 80% of the
cumulative expense that would have been recognized under the shares allocated
method before deduction of dividends. Contributions and dividend payments on the
KOIL ESOP Preferred Stock and ESOP Preferred Stock were used to make scheduled
payments of principal and interest on the ESOP Loans, which were repaid in full
during 1995. For the years ended December 31, 1994 and 1995, Kelley Oil paid to
the ESOP contributions of $1,160,000 and $736,000, respectively, plus dividends
of $894,000 and $622,000, respectively. No ESOP contributions were made in 1996.
As the term loans were repaid, a corresponding portion of the stock pledged to
secure the loans was released and allocated among the participants' accounts.
Effective September 1, 1996, the ESOP was amended to include a 401(k) feature
whereby the Company is obligated to make matching contributions up to 6% of each
employee's salary. The plan also provides for additional discretionary
contributions. For 1996 the Company made matching contributions totaling
$87,814.
NOTE 9 - COMMITMENTS AND CONTINGENCIES
During 1995, the Company entered into change of control agreements
with 16 employees entitling them to severance benefits in the event their
employment is terminated under certain circumstances within two years after a
change of control, as defined in the agreements. For this purpose, the February
1996 closing under the Contour Transaction constituted a change of control. The
severance benefits amount to salary continuation for periods ranging from 12 to
36 months, depending on seniority of the covered employees, based on their
highest compensation rate during the two years prior to termination. As of March
15, 1997, ten of these agreements have been exercised obligating the Company to
aggregate severance payments of $2.1 million through August 1999. The Company's
anticipated maximum liability under the remaining agreements was $0.6 million.
Substantially all of the Company's receivables are due from a limited
number of natural gas transmission companies and other gas purchasers. To date,
this concentration has not had a material adverse effect on the consolidated
financial condition of the Company.
The Company 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
statements of the Company.
The Company leases office space and equipment under operating leases
with options to renew. Rental expenses related to these leases for the years
ended December 31, 1994, 1995 and 1996 were $2.3 million, $1.9 million and $1.3
million, respectively. For the balance of the lease terms, minimum rentals are
as follows:
1997............................... 1,142,220
1998............................... 494,425
1999............................... 16,829
--------------
Total..............................$ 1,653,474
==============
43
<PAGE>
NOTE 10 - LITIGATION SETTLEMENT
Following Kelley Oil's announcement of the initial proposal for the
Consolidation in August 1994, four separate lawsuits were filed against Kelley
Oil and its directors relating to the Consolidation and the 1991 DDP Exchange.
In November 1994, Kelley Oil entered into a memorandum of understanding with the
plaintiffs in three of the lawsuits, providing for a proposed settlement based
on a revised Consolidation proposal negotiated by a special committee of Kelley
Oil's nonmanagement directors and the settling plaintiffs. A stipulation and
agreement of compromise, settlement and release reflecting the terms of the
proposed settlement was filed in the United States District Court for the
Southern District of Texas on November 23, 1994. At a hearing held on the same
date, the court approved the consolidation of all four lawsuits and the
certification of a Unitholder class requested by the settling parties. On March
3, 1995, following a hearing on the fairness of the settlement, the court
entered a final order approving the settlement, dismissing the consolidated
lawsuits with prejudice and reducing the award of attorneys' fees and
disbursements contemplated by the stipulation to $1,479,000, payable $300,000 in
cash and the balance in Common Stock. The Company believes a pending appeal by
the non-settling plaintiff is without merit.
NOTE 11 - 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 Company has not
experienced counterparty nonperformance on these agreements and does not
anticipate any in future periods.
NOTE 12 - RESTRUCTURING EXPENSE
In each of 1994, 1995 and 1996 the Company incurred restructuring
charges of $1.1 million, $1.8 million and $4.3 million, respectively, associated
primarily with staff reductions of approximately and 36, 7 and 41 employees in
1994, 1995, and 1996, respectively, related severance settlements and
reorganization costs. Approximately $3.7 million of these expenses has been paid
through December 31, 1996. Accrued expenses on the balance sheet include $1.0
million and $3.5 million at December 31, 1995 and 1996, respectively, related to
the unpaid portion of these charges.
44
<PAGE>
NOTE 13 - SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND GAS EXPLORATION,
DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)
This footnote provides unaudited information required by Statement of
Financial Accounting Standards No. 69, "Disclosures about Oil and Gas Producing
Activities."
CAPITALIZED COSTS. Capitalized costs and accumulated depreciation,
depletion and amortization relating to the Company's oil and gas producing
activities, all of which are conducted within the continental United States, are
summarized below.
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------------
1994 1995 1996
------------- ---------- ----------
<S> <C> <C> <C>
Unevaluated properties.................................................$ 1,430 13,050 12,521
Properties subject to amortization..................................... 129,883 287,970 338,794
------------ ---------- ----------
Capitalized costs...................................................... 131,313 301,020 351,315
Accumulated depreciation, depletion and amortization................... (59,108) (173,996) (194,367)
---------- ---------- ----------
Net capitalized costs..................................................$ 72,205 127,024 156,948
========== ========== ==========
</TABLE>
COSTS INCURRED. Costs incurred in oil and gas property acquisition,
exploration and development activities are summarized below.
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------------
1994 1995 1996
------------- ---------- ----------
<S> <C> <C> <C>
Property acquisition costs:(1) (2)
Proved..............................................................$ 7,035 126,577 11,594
Unproved............................................................ 309 88,539 2,160
Exploration costs...................................................... 8,760 9,521 5,438
Development costs...................................................... 28,034 31,730 41,790
------------ ---------- ----------
Total costs incurred................................................$ 44,138 256,367 60,982
============ ========== ==========
</TABLE>
(1) Includes general and administrative costs directly related to
acquisition, exploration and development of oil and gas properties of
$2,909,000, $3,158,000 and $1,645,000 incurred in the years ended December 31,
1994, 1995 and 1996, respectively.
(2) Includes assets acquired in the Consolidation aggregating $207
million for the year ended December 31, 1995.
45
<PAGE>
RESULTS OF OPERATIONS. Results of operations for the Company's oil
and gas producing activities are summarized below.
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------------
1994 1995 1996
------------- ------------ -----------
<S> <C> <C> <C>
Oil and gas revenues..................................................$ 15,487 36,042 59,016
Gain on sale of oil and gas properties................................ -- 777 176
Production costs...................................................... (3,760) (10,835) (10,709)
Exploration and dry hole costs........................................ (7,404) (23,387) (5,438)
Depreciation, depletion and amortization.............................. (19,997) (34,355) (19,901)
Impairment of oil and gas properties.................................. -- (150,138) --
------------ ----------- -----------
Results of operations..............................................$ (15,674) (181,896) 23,144
============ =========== ===========
</TABLE>
Results of operations from oil and gas producing activities are
determined using actual historical revenues, production costs (including
production related taxes), exploration and dry hole costs and depreciation,
depletion and amortization of the capitalized costs subject to amortization.
General and administrative expenses and interest expense are excluded from this
determination of results of operations. Income tax benefit is computed by
applying the statutory tax rates to earnings before income tax expense with
recognition of tax credits and allowances relating to oil and gas producing
activities. No income tax benefit was recognized during the reported periods.
RESERVES. The following table summarizes the Company's net ownership
interests in estimated quantities of proved oil and gas reserves and changes in
net proved reserves, all of which are located in the continental United States,
for the years ended December 31, 1994, 1995 and 1996 are summarized below.
Reserves estimates contained below were prepared by H.J. Gruy & Associates, Inc.
("Gruy"), independent petroleum engineers, for 1995 and 1996, and were prepared
by the Company and reviewed by Gruy for 1994. See "Estimated Proved
Reserves-Uncertainties in Estimating Reserves" under Items 1 and 2 of this
Report.
<TABLE>
<CAPTION>
CRUDE OIL, CONDENSATE
AND NATURAL GAS LIQUIDS NATURAL GAS
(MBBLS) (MMCF)
------------------------------------ ------------------------------------
1994 1995 1996 1994 1995 1996
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
Proved developed and undeveloped reserves:
Beginning of year ........................... 1,114 1,236 1,387 64,875 93,612 196,273
Revisions of previous estimates ............. 75 (1,324) (89) 16,055 (64,027) (30,519)
Purchases of oil and gas properties ......... -- 1,756 57 -- 127,962 30,844
Extensions and discoveries .................. 218 156 477 19,379 66,864 128,692
Sale of oil and gas properties .............. -- (118) (134) -- (10,388) (4,190)
Production .................................. (171) (319) (232) (6,697) (17,750) (23,466)
-------- -------- -------- -------- -------- --------
End of year ................................. 1,236 1,387 1,466 93,612 196,273 297,634
======== ======== ======== ======== ======== ========
Proved developed reserves
at end of year .............................. 674 1,197 977 48,482 111,287 173,465
======== ======== ======== ======== ======== ========
</TABLE>
STANDARDIZED MEASURE. The following table of the Standardized Measure
of Discounted Future Net Cash Flows concerning the standardized measure of
future cash flows from proved oil and gas reserves are presented in accordance
with Statement of Financial Accounting Standards No. 69. As prescribed by this
statement, the amounts shown are based on prices and costs at the end of each
period, and with a 10% annual discount factor. Extensive judgments are involved
in estimating the timing of production and the costs that will be incurred
throughout the remaining lives of the fields.
46
<PAGE>
Accordingly, the estimates of future net revenues from proved reserves and the
present value thereof may not be materially correct when judged against actual
subsequent results. Further, since prices and costs do not remain static, and no
price or cost changes have been considered, and future production and
development costs are estimates to be incurred in developing and producing the
estimated proved oil and gas reserves, the results are not necessarily
indicative of the fair market value of estimated proved reserves, and the
results may not be comparable to estimates disclosed by other oil and gas
producers.
(IN THOUSANDS)
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
-----------------------------------------------
1994 1995 1996
----------- ----------- -----------
<S> <C> <C> <C>
Future cash inflows.....................................................$ 175,052 431,351 1,099,089
Future production costs................................................. (34,472) (76,021) (113,178)
Future development costs................................................ (22,914) (36,524) (81,932)
Future income tax expenses.............................................. (6,016) (8,577) (162,887)
----------- ----------- -----------
Future net cash flows................................................ 111,650 310,229 741,092
10% annual discount for estimating timing of cash flows................. (40,810) (139,177) (307,321)
----------- ----------- -----------
Standardized measure of discounted future net cash flows.............$ 70,840 171,052 433,771
=========== =========== ===========
</TABLE>
Future cash inflows are computed by applying year-end prices of oil
and gas to year-end quantities of proved oil and gas reserves. Future production
and development costs are computed primarily by the Company's petroleum
engineers by estimating the expenditures to be incurred in developing and
producing the Company's proved oil and gas reserves at the end of the year,
based on year-end costs and assuming continuation of existing economic
conditions.
Future income taxes are based on year-end statutory rates, adjusted
for operating loss carryforwards and tax credits. 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 Company's oil and gas properties.
The standardized measure of discounted future net cash flows as of
December 31, 1994, 1995 and 1996 was calculated using prices in effect as of
those dates, which averaged $15.65, $19.73 and $25.18, respectively, per barrel
of oil and $1.66, $2.06 and $3.66, respectively, per Mcf of natural gas.
47
<PAGE>
CHANGE IN STANDARDIZED MEASURE. Changes in standardized measure of
future net cash flows relating to proved oil and gas reserves are summarized
below.
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------------
1994 1995 1996
----------- ------------ ------------
<S> <C> <C> <C>
Changes due to current year operations:
Sales of oil and gas, net of production costs...................$ (11,727) (25,207) (48,307)
Sale of oil and gas properties.................................. -- (5,884) (6,836)
Extensions and discoveries...................................... 16,290 62,407 192,174
Purchases of oil and gas properties............................. -- 90,660 11,594
Future development costs incurred............................... 7,242 10,216 24,500
Changes due to revisions in standardized variables:
Prices and production costs..................................... (20,609) 21,055 159,292
Revisions of previous quantity estimates........................ 3,432 (22,223) (50,594)
Revisions of purchased oil and gas properties................... -- (28,199) --
Estimated future development costs.............................. (1,949) 17,676 3,254
Income taxes.................................................... 6,104 (893) (82,831)
Accretion of discount........................................... 7,179 7,145 17,575
Production rates (timing) and other............................. (6,912) (26,541) 42,898
----------- ----------- -----------
Net increase (decrease)...................................... (950) 100,212 262,719
Beginning of year............................................... 71,790 70,840 171,052
----------- ----------- -----------
End of year..................................................$ 70,840 171,052 433,771
=========== =========== ===========
</TABLE>
Sales of oil and gas, net of production costs, are based on
historical pre-tax results. Extensions and discoveries, purchases of minerals in
place and the changes due to revisions in standardized variables are reported on
a pre-tax discounted basis, while the accretion of discount is presented after
tax. Extensions and discoveries include proved undeveloped reserves attributable
to Kelley Oil's interests in drill sites assigned to DDPs but do not give effect
to the Consolidation prior to 1995.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
In connection with the Contour Transaction, the Company dismissed
Ernst & Young LLP ("E&Y") as its principal accountants, effective February 15,
1996. On the same date, the Company 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 Company's board of
directors, contingent upon the closing of the Contour Transaction. Neither of
E&Y's reports on the Company's financial statements for the years ended December
31, 1994 and 1993 contained an adverse opinion or disclaimer of opinion, or was
qualified or modified as to uncertainty, audit scope or accounting principles.
During the last two years and the interim period prior to the change in
accountants, (i) the Company 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 Company of any "reportable
event" as defined in Regulation S-K under the Securities Exchange Act of 1934
and (iii) the Company did not consult with D&T on any accounting, auditing,
financial reporting or any other matters.
48
<PAGE>
PART III
ITEMS 10, 11, 12 AND 13. EXECUTIVE OFFICERS OF THE COMPANY; EXECUTIVE
COMPENSATION; SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT;
AND CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, RESPECTIVELY.
The information called for by these Items is incorporated by
reference to the Company's definitive Proxy Statement to be filed by the Company
pursuant to Regulation 14A of the General Rules and Regulations under the
Securities and Exchange Act not later than April 30, 1997.
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 have been omitted as the schedules
are either not required under the related instructions, are not applicable or
the information required thereby is set forth in the Company's Consolidated
Financial Statements or the Notes thereto.
(3) EXHIBITS:
EXHIBIT
NUMBER: EXHIBIT
- ------- -------
2.1 Agreement and Plan of Consolidation among the Registrant, Kelley
Oil Corporation, Kelley Oil & Gas Partners, Ltd. ("Kelley
Partners") and the other parties named therein (incorporated by
reference to Exhibit 2.1 to the Registrant's Registration
Statement (the "Consolidation Registration Statement") on Form
S-4 (Reg No. 33-84338) filed September 26, 1994, as amended).
3.1 Certificate of Incorporation of the Registrant (incorporated by
reference to Exhibit 3.1 to the Consolidation Registration
Statement).
3.2 Certificate of Amendment to Certificate of Incorporation of the
Registrant dated December 20, 1994 (incorporated by reference to
Exhibit 3.2 to the Consolidation Registration Statement).
3.3 Certificate of Correction to Certificate of Incorporation of the
Registrant dated February 12, 1996 (incorporated by reference to
Exhibit 3.1 to the Registrant's Current Report on Form 8-K (File
No. 0-25214) dated February 15, 1996).
3.4 Certificate of Designation of $2.625 Convertible Exchangeable
Preferred Stock of the Registrant (incorporated by reference to
Exhibit 3.1 to the Registrant's Current Report on Form 8-K (File
No. 0-25214) dated February 10, 1995).
3.5 Certificate of Designations of Cumulative Convertible Preferred
Stock of the Registrant (incorporated by reference to Exhibit 3.2
to the Registrant's Current Report on Form 8-K (File No. 0-25214)
dated February 10, 1995).
3.6 Bylaws of the Registrant (incorporated by reference to Exhibit
3.5 to the Consolidation Registration Statement).
49
<PAGE>
4.1 Certificate representing Common Stock of the Registrant
(incorporated by reference to Exhibit 4.1 to the Consolidation
Registration Statement).
4.2 Certificate representing $2.625 Convertible Exchangeable
Preferred Stock of the Registrant (incorporated by reference to
Exhibit 4.2 to the Consolidation Registration Statement).
4.3 Supplemental Indenture dated February 7, 1995 among the
Registrant, Kelley Partners and United States Trust Company of
New York, relating to Kelley Partners' 8 1/2% Convertible
Subordinated Debentures (the "8 1/2% Debentures") due 2000
(incorporated by reference to Exhibit 4.1 to the Registrant's
Current Report on Form 8-K (File No. 0-25214) dated February 10,
1995).
4.4 Supplemental Indenture dated March 29, 1996 between the
Registrant and the United States Trust Company of New York,
relating to the 8 1/2% Debentures (incorporated by reference to
Exhibit 4.4 to the Registrant's Annual Report on Form 10-K (File
No. 0-25214) for the year ended December 31, 1995).
4.5 Supplemental Indenture dated February 7, 1995 among the
Registrant, Kelley Partners and United States Trust Company of
New York, relating to Kelley Partners' 7 7/8% Convertible
Subordinated Notes (the "7 7/8% Notes") due 1999 (incorporated by
reference to Exhibit 4.2 to the Registrant's Current Report on
Form 8-K (File No. 0-25214) dated February 10, 1995).
4.6 Supplemental Indenture dated March 29, 1996 between the
Registrant and the United States Trust Company of New York,
relating to the 7 7/8% Notes (incorporated by reference to
Exhibit 4.6 to the Registrant's Annual Report on Form 10-K (File
No. 0-25214) for the year ended December 31, 1995).
4.7 Indenture dated as of June 15, 1995 among the Registrant, as
issuer, Kelley Partners, Kelley Operating Company, Ltd. and
Kelley Oil Corporation, as guarantors, and Chemical Bank, as
trustee, relating to the Registrant's 13 1/2% Senior Notes due
1999 (incorporated by reference to Exhibit 4.5 to the
Registrant's Registration Statement on Form S-3 (Reg. No.
33-92214) dated June 9, 1995.
4.8 Supplemental Indenture dated as of October 28, 1996, among the
Registrant, as issuer, Kelley Operating Company, Ltd. and Kelley
Oil Corporation, as guarantors, and The Chase Manhattan Bank
(formerly Chemical Bank), as trustee, relating to the
Registrant's 13 1/2% Senior Notes due 1999 (incorporated by
reference to Exhibit 4.3 to the Registrant's Quarterly Report on
Form 10-Q (File No. 0-25214) for the quarterly period ended
September 20, 1996).
4.9 Indenture dated as of October 15, 1996, among the Registrant, as
issuer, Kelley Oil Corporation and Kelley Operating Company,
Ltd., as guarantors, and United States Trust Company of New York,
relating to the Registrant's 10 3/8% Senior Subordinated Notes
due 2006 (incorporated by reference to Exhibit 4.1 to the
Registrant's Quarterly Report on Form 10-Q (File No. 0-25214) for
the quarterly period ended September 30, 1996).
4.10 Form of the Registrant's 10 3/8% Senior Subordinated Note Due
2006, Series B (incorporated by reference to Exhibit 4.5 to the
Registrant's Registration Statement on Form S-4 (Reg. No.
333-18481) filed December 20, 1996, as amended).
4.11 Option Agreement dated as of February 15, 1996 between the
Registrant and Contour Production Company L.L.C. (incorporated by
reference to Exhibit 4.1 to the Registrant's Current Report on
Form 8-K (File No. 0-25214) dated February 15, 1996).
50
<PAGE>
10.1 Amended and Restated Employee Stock Ownership Plan of Kelley Oil
effective as of January 1, 1989 (incorporated by reference to
Exhibit 10.15 to Kelley Oil's Annual Report on Form 10-K (File
No. 0-17585) for the year ended December 31, 1991).
10.2 1987 Incentive Stock Option Plan (the "1987 Plan") of Kelley Oil
(incorporated by reference to Kelley Oil's Annual Report on Form
10-K (File No. 0-17585) for the year ended December 31, 1988).
10.3 1991 Incentive Stock Option Plan (the "1991 Plan") of Kelley Oil
(incorporated by reference to Exhibit 10.3 to Kelley Oil's Annual
Report on Form 10-K (File No. 0-175850 for the year ended
December 31, 1991).
10.4 1995 Incentive Stock Option Plan of the Registrant (the "1995
Plan") (incorporated by reference to Exhibit 10.4 to the
Registrant's Annual Report on Form 10-K (File No. 0-25214) for
the year ended December 31, 1995).
10.5 Amendment to the 1987 Plan, 1991 Plan and 1995 Plan (incorporated
by reference to Exhibit 10.5 to the Registrant's Current Report
on Form 8-K (File No. 0-25214) dated February 15, 1996).
10.6 1996 Nonqualified Stock Option Plan of the Registrant
(incorporated by reference to Exhibit 10.4 to the Registrant's
Current Report on Form 8-K (File No. 0-25214) dated February 15,
1996).
10.7 Employment Agreement dated as of February 15, 1996 between the
Registrant and John F. Bookout, Jr. (incorporated by reference to
Exhibit 10.2 to the Registrant's Current Report on Form 8-K (File
No. 0-25214) dated February 15, 1996).
10.8 Form of Employment Agreements dated as of February 15, 1996
between the Registrant and each of Dallas Laumbach and William
Albrecht (incorporated by reference to Exhibit 10.3 to the
Registrant's Current Report on Form 8-K (File No. 0-25214) dated
February 15, 1996).
10.9 Employment Agreement dated as of March 20, 1997 with David C.
Baggett.
10.10 Amended and Restated Credit Agreement among Kelley Oil & Gas
Corporation, Kelley Oil Corporation and Kelley Operating Company,
Ltd., as Borrowers, Concorde Gas Marketing, Inc., Kelley Partners
1992 Development Drilling Joint Venture, Kelley Partners 1994
Development Drilling Joint Venture, Kelley Partners 1992
Development Drilling Program and Kelley Partners 1994 Development
Drilling Program, as Guarantors, Texas Commerce Bank National
Association, as Agent, Chase Securities Inc., as Arranger and
Syndication Agent, and the Lenders Signatory thereto, dated as of
December 12, 1996 (incorporated by reference to Exhibit 4.3 to
the Registrant's Registration Statement on Form S-4 (Reg. No.
333-18481) filed December 20, 1996, as amended).
10.11 1996 Incentive Stock Option Plan (the "1996 Plan") of the
Registrant.
21.1 Subsidiaries of the Registrant.
23.1 Consent of Deloitte & Touche LLP.
23.2 Consent of Ernst & Young LLP.
23.3 Consent of H.J. Gruy & Associates, Inc.
(b) REPORTS ON FORM 8-K: No reports on Form 8-K were filed by the
Registrant during the fourth quarter of 1996.
51
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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 OIL & GAS CORPORATION
By: /S/ JOHN F. BOOKOUT By: /S/ DAVID C. BAGGETT
John F. Bookout David C. Baggett
Chief Executive Officer Senior Vice President
and Chief Financial Officer
By: /S/ LAWRENCE G. MARBLE
Lawrence G. Marble
Controller
(Chief Accounting Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed as of the 27th day of March, 1997 by the
following persons in their capacity as directors of the Registrant.
/S/ JOHN F. BOOKOUT /S/ WILLIAM J. MURRAY
John F. Bookout William J. Murray
/S/ JOHN J. CONKLIN, JR. /S/ OGDEN M. PHIPPS
John J. Conklin, Jr. Ogden M. Phipps
/S/ RALPH P. DAVIDSON /S/ MICHAEL B. ROTHFELD
Ralph P. Davidson Michael B. Rothfeld
/S/ WARD W. WOODS
Ward W. Woods
52
EXHIBIT 10.9
EMPLOYMENT AGREEMENT
This Agreement, made this 12th day of March, 1997, by and between Kelley
Oil & Gas Corporation, a Delaware corporation (the "Company"), and David C.
Baggett ("Executive").
WITNESSETH:
WHEREAS, the Company desires to employ Executive as Senior Vice President
and Chief Financial Officer on the terms set forth below, and Executive is
willing to accept such employment on such terms.
NOW, THEREFORE, in consideration of the foregoing and for other good and
valuable consideration, the parties hereto do hereby agree:
1. DEFINITIONS
As used in this Agreement, defined words and phrases have the meaning
first ascribed to them herein whenever the first letter of each word is
capitalized. Words used in the masculine apply equally to the feminine,
and wherever the context dictates, the plural should be read as the
singular and the singular as the plural. References to Sections are to
Sections of this Agreement. The headings at the beginning of each section
are inserted for convenience only and are not intended to describe,
interpret, define, or limit the scope, extent, or intent of this
Agreement.
a. Board" means the Company's board of directors.
b. Cause" shall be deemed to exist if, and only if:
i. Executive is convicted in a court of law of any crime (i) that
constitutes a felony relating to the Company or any other
business endeavor or (ii) that constitutes a felony which
involves moral turpitude; or
ii. Executive engages in willful misconduct or any material breach of
or willful material failure to perform his duties and
responsibilities hereunder, which misconduct, breach, or failure
shall continue after the Company, by action of the Board, shall
have advised Executive thereof in writing and shall have afforded
Executive a reasonable opportunity (which shall be at least 30
days from the date of such written advice or knowledge thereof)
to correct the acts or omissions complained of, and which
Executive shall have so failed to take action to correct within
such period.
c. "Disability" means Executive's inability to fully and competently
perform the duties hereunder for a period of at least three consecutive
months by reason of mental or physical illness or other incapacity. The
Company and Executive or his attorney-in-fact shall, based on competent
medical advice, determine whether Executive is and continues to be
disabled. If the Company and Executive or his attorney-in-fact disagree
with the determination of disability, then each of them shall appoint a
doctor and the two doctors shall select a third independent doctor
whose decision as to whether Executive has been unable to perform the
duties of the nature contemplated hereunder for a
three-consecutive-month period shall be binding on the parties.
The doctor advising the Company with regard to the Company's initial
determination of whether Executive has been disabled within the
foregoing meaning and the independent doctor selected by the two
doctors designated by the Company and Executive or his attorney-in-fact
shall be given full access to Executive's medical records and shall be
afforded a reasonable opportunity to examine Executive. The Company
agrees to instruct such doctors to maintain all information reflected
in Executive's records in full confidence and not to disclose such
information to any person (including the Company) except as may be
necessary for the
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determination described above. All references to doctor in this
paragraph 1.d shall mean a practicing doctor of medicine.
d. "Executive Officer" means Senior Vice President and Chief Financial
Officer.
e. "Notice of Termination" means a notice that sets forth the date of
termination and, in the event of termination for Cause, the facts and
circumstances claimed to provide a basis for termination of Executive's
employment.
2. TERM
This Agreement commences, subject to approval of this Agreement in all
respects by the Company's Board of Directors, effective as of March 20,
1997 (the "Commencement Date") and shall continue for 36 months after the
Commencement Date, unless sooner terminated.
3. DUTIES
During the term of his employment as provided in Section 2 above, the
Company will employ Executive in a senior executive capacity, with such
responsibilities as the Company may from time to time determine during the
term of this Agreement. Executive will comply with all applicable laws,
with all corporate documents governing the conduct of the Company's
business and affairs, and with the Company's policies.
Executive agrees to devote substantially all of his business time to the
performance of his duties hereunder.
4. COMPENSATION
a. The Company shall pay Executive for all services to be performed
hereunder during the term of this Agreement. The Company agrees to pay
to Executive an annual salary of $190,000.00, payable in semimonthly
installments in arrears on the fifteenth and last day of each calendar
month, the first such installment to be payable for the period ended
March 31, 1997.
b. The Company may, in the discretion of the Board, provide incentive
awards to Executive.
c. The Company shall provide Executive with an interest free loan of
$55,000.00, which Executive must repay to the Company on or before the
third anniversary of the Commencement Date. In addition, in the event
Executive voluntarily terminates his employment with the Company or his
employment is terminated by the Company for Cause, the loan must be
repaid on demand by the Company.
d. The Company shall pay Executive's initiation fees and membership dues
for both a luncheon club and a country club of Executive's choosing,
located in the Houston, Texas metropolitan area.
e. The Company shall, effective the Commencement Date, grant Executive a
total of 575,000 options to purchase shares of the Company's common
stock for a purchase price of $1.00 per share (the "Options"), which
shall vest in cumulative annual installments as follows: (i) 331/3% of
such Options on the first anniversary of the Commencement Date, (ii)
662/3% of such Options on the second anniversary of the Commencement
Date, and (iii) 100% of such Options on the third anniversary of the
Commencement Date.
f. In addition to the payments and awards set forth in paragraphs a,b,c,d
and e above:
i. During the term of this Agreement, upon submission of a
reasonable accounting, the Company shall reimburse Executive for
all reasonable travel, entertainment, and other business expenses
that are in compliance with company policy related to his
employment hereunder.
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ii. During the term of this Agreement, Executive shall be eligible
for the Company's employee benefit programs on the terms on which
the same are extended to the Company's executives generally,
including but not limited to a health care plan, five weeks
vacation and partial reimbursement for parking expenses.
The Company shall have the right to deduct from all payments to be made
under this Agreement any federal, state, or local taxes required by law to
be withheld from such payments.
5. NONDISCLOSURE OF CONFIDENTIAL INFORMATION
Executive agrees that, during his employment by the Company and for 1 year
thereafter, he will not use or disclose to others, directly or indirectly,
any confidential information relating to the business, prospects, or plans
of the Company or its subsidiaries. Notwithstanding the previous sentence,
Executive shall not be in violation of this section in the event of a
disclosure pursuant to a court action or governmental rule, regulation, or
proceeding (hereinafter referred to as an "Ordered Disclosure") provided
Executive has notified the Company of such Ordered Disclosure within five
business days of being personally served with such Ordered Disclosure.
Executive agrees to cooperate in good faith with the Company in responding
to such Ordered Disclosure in order to prevent, limit or impose
restrictions on such Ordered Disclosure. In no event, however, shall this
section require Executive to take action or otherwise cause Executive to
be in violation of any law or result in contempt of such Ordered
Disclosure.
Upon termination of his employment with the Company, Executive shall
surrender to the Company any and all work papers, reports, manuals,
documents, and the like (including all originals and copies thereof) in
his possession which contain confidential information relating to the
business, prospects, or plans of the Company or its affiliates.
Executive agrees that following any termination of his employment with the
Company, he will endorse strategies of the Company, and will not disclose
or cause to be disclosed any negative, adverse or derogatory comments or
information of a substantial nature about the Company or its management,
or about any product or service provided by the Company, or about the
Company's prospects for the future. The Company may seek the assistance,
cooperation or testimony of Executive following any such termination in
connection with any investigation, litigation or proceeding arising out of
matters within the knowledge of Executive and related to his position as
an officer or employee of the Company, and in any instance, Executive
shall provide such assistance, cooperation or testimony and the Company
shall pay Executive's reasonable costs and expenses in connection
therewith. In addition, if such assistance, cooperation or testimony
requires more than a nominal commitment of Executive's time, the Company
will compensate Executive for such time at a per diem rate derived from
Executive's salary from the Company at the time of Executive's
termination.
6. TERMINATION
a. This Agreement shall automatically terminate upon Executive's death or
Disability. In addition, this Agreement may be terminated by the
Company or Executive at any time for any reason whatsoever. Any
termination of Executive's employment by the Company or by Executive
(other than termination pursuant to the first sentence of this
subsection a.) shall be communicated by written Notice of Termination
to the other party hereto in accordance with Section 16.
b. Upon termination of this Agreement for any reason, Executive shall be
entitled to receive, and the Company shall pay Executive (or, if such
termination is caused by Executive's death, his estate or as may be
directed by the legal representatives of such estate) within 30 days of
the termination date, any unpaid amounts earned by or payable to
Executive through the date of termination under Sections 4.a., 4.b. (if
any) and 4.f., which amounts shall be reduced by any amounts owed to
the Company pursuant to the loan provided for in Section 4.c. (and the
principal amount of such loan shall be reduced by a corresponding
amount).
c. In addition to the amounts to which Executive is entitled under Section
6.b., if this Agreement is terminated by the Company other than for
Cause, the Company shall pay Executive in a single lump-sum payment an
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amount equal to the compensation that would have been payable under
Section 4.a. over the next 24 months had this Agreement not otherwise
been terminated, which amounts shall be reduced by any amounts owed to
the Company pursuant to the loan provided for in Section 4.c. (and the
principal amount of such loan shall be reduced by a corresponding
amount). Such compensation shall be the only compensation payable as a
result of such termination and, except as may otherwise be provided in
any other agreement or option plans, Executive shall not be entitled to
any accrued bonuses, acceleration of vesting with respect to any
options or acceleration of any other rights he may have under any
employee benefit plan or arrangement, it being understood and agreed
that the Company may terminate this Agreement at any time with or
without Cause by notice to the Executive as provided herein. The
amounts payable under this Section 6.c. shall be paid no later than 30
days after the date of termination.
7. RESTRICTIVE COVENANT
During the term of Executive's employment with the Company, and (except as
provided in clause (c) below) for a period of one year following the
termination of Executive's employment with the Company for any reason,
including termination occasioned by the expiration of this Agreement,
Executive shall not:
a. interfere with the relationship of the Company or any of its employees,
agents or representatives;
b. directly or indirectly divert or attempt to divert from the Company any
property acquisition in which the Company has been actively engaged
during the term hereof; or
c. directly or indirectly render engineering or other services of the
nature of those provided to the Company to any person, company or
entity other than the Company, provided, this clause (c) shall
terminate upon the termination of Executive's employment with the
Company.
8. INDEMNIFICATION
Except to the extent attributable to Executive's willful misconduct or
actions leading to the Company's termination of this Agreement for Cause,
the Company shall indemnify Executive against expenses (including
attorneys' fees), judgments, fines, and amounts paid in settlement
actually and reasonably incurred by him in connection with any action,
suit, or proceeding to which Executive has been made a party by reason of
his capacity as Executive Officer of the Company if Executive acted in
good faith and in a manner Executive reasonably believed to be in or not
opposed to the best interest of the Company and, with respect to any
criminal action or proceeding, had no reasonable cause to believe
Executive's conduct was unlawful. The termination of any action, suit, or
proceeding by judgment, order, settlement, conviction, or upon a plea of
nolo contendere or its equivalent, shall not, of itself, create a
presumption that Executive did not act in good faith and in a manner which
Executive reasonably believed to be in or not opposed to the best interest
of the Company, and with respect to any criminal action or proceeding, had
reasonable cause to believe that Executive's conduct was unlawful.
9. ADDITIONAL REMEDIES
In the event of a breach or a threatened breach of the terms of Section 5
or 7 of by Executive, the Company shall, in addition to all other
remedies, be entitled to a temporary or permanent injunction and/or a
decree for specific performance, in accordance with the provisions hereof,
without showing any actual damage or that monetary damages would not
provide an adequate remedy and without any bond or other security being
required.
10. NONASSIGNMENT
This Agreement is personal to Executive and shall not be assigned by him.
Executive shall not hypothecate, delegate, encumber, alienate, transfer,
or otherwise dispose of his rights and duties hereunder. The Company may
assign this Agreement without Executive's consent to any other entity who,
in connection with such assignment,
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acquires all or substantially all of the Company's assets, or into or with
which the Company is merged or consolidated.
11. WAIVER
The waiver by the Company of a breach by Executive of any provision of
this Agreement shall not be construed as a waiver of any subsequent breach
by Executive.
12. SEVERABILITY
If any clause, phrase, provision, or portion of this Agreement or the
application thereof to any person or circumstance shall be invalid or
unenforceable under any applicable law, such event shall not affect or
render invalid or unenforceable the remainder of this Agreement and shall
not affect the application of any clause, provision, or portion hereof to
other persons or circumstances.
13. DISPUTES
Each of the parties hereto hereby irrevocably agrees that any legal action
or proceeding arising out of this Agreement shall be brought only in the
state or federal courts located in the state of Texas. Each party hereto
hereby irrevocably consents to the service or process outside the
territorial jurisdiction of such courts in any such action or proceeding
by the mailing of such documents by registered United States mail, postage
prepaid, if to the Company to the address of its principal place of
business and if to Executive to the address listed in the Company's books
and records.
14. RELEVANT LAW
This Agreement shall be construed by, subject to, and governed in
accordance with the internal laws of the State of Texas.
15. NOTICES
All notices, requests, demands, and other communications in connection
with this Agreement shall be made in writing and shall be deemed to have
been given when delivered by hand or 48 hours after mailing at any general
or branch United States post office by registered or certified mail,
postage prepaid, addressed as follows, or to such other address as shall
have been designated in writing by the addressee:
a. If to the Company:
Kelley Oil & Gas Corporation
Suite 1100
601 Jefferson Street
Houston, Texas 77002
Attention: Corporate Secretary
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b. If to Executive:
David C. Baggett
Kelley Oil & Gas Corporation
Suite 1100
601 Jefferson Street
Houston, Texas 77002
16. Entire Agreement
This Agreement sets forth the entire understanding of the parties and
supersedes all prior agreements, arrangements, and communications, whether
oral or written, and this Agreement shall not be modified or amended
except by written agreement of the Company and Executive.
IN WITNESS WHEREOF, the parties hereto have executed this Agreement on the
date first set forth above.
COMPANY:
KELLEY OIL & GAS CORPORATION
By /S/ JOHN F. BOOKOUT
John F. Bookout
President and Chief Executive Officer
EXECUTIVE:
/S/ DAVID C. BAGGETT
David C. Baggett
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EXHIBIT 10.11
KELLEY OIL & GAS CORPORATION
1996 INCENTIVE STOCK OPTION PLAN
1. PURPOSE. The purpose of the 1996 Incentive Stock Option Plan (the
"Plan") is to provide an incentive to selected officers and key employees of
Kelley Oil & Gas Corporation (the "Company") and any directly or indirectly
owned subsidiary of the Company (a "Subsidiary") to increase their proprietary
interest in the Company, to continue as officers and employees and to increase
their efforts on behalf of the Company.
2. THE PLAN. The Plan provides for the grant of options ("Options") to
acquire shares of Common Stock, $.01 par value, of the Company (the "Stock").
Options granted under the Plan are intended to qualify as incentive stock
options within the meaning of section 422 of the Internal Revenue Code of 1986,
as amended (the "Code").
3. ADMINISTRATION. (a) The Plan shall be administered by the Compensation
Committee (the "Committee") of the Board of Directors of the Company (the
"Board"). A member of the Board shall be eligible to receive Options under the
Plan if he is a permitted Grantee under Section 7(a) of the Plan and he is not a
member of the Committee acting on the matter.
(b) The Committee shall have plenary authority in its discretion, subject
only to the express provisions of the Plan and of Code section 422 to: (i)
select the eligible persons who shall be granted Options ("Grantees"), the
number of shares of Stock subject to each Option and terms of the Option granted
to each Grantee, provided that, in making its determination, the Committee shall
consider the position and responsibilities of the employee, the nature and value
to the Company or a Subsidiary of his or her services and accomplishments, the
employee's present and potential contribution to the success of the Company or a
Subsidiary and any other factors that the Committee may deem relevant; (ii)
determine the dates of Option grants; (iii) prescribe the form of the
instruments evidencing Options; (iv) adopt, amend and rescind rules and
regulations for the administration of the Plan and for its own acts and
proceedings; (v) decide all questions and settle all controversies and disputes
of general applicability that may arise in connection with the Plan; and (vi)
amend certain terms of the Plan as provided in Section 9.
(c) All decisions, determinations and interpretations with respect to the
foregoing matters shall be made by the Committee and shall be final and binding
upon all persons.
4. EFFECTIVENESS AND TERMINATION OF PLAN. The Plan shall become effective
as of April 25, 1996, the date of its adoption by the Board, provided that the
Plan is approved by the stockholders of the Company within one year of its
adoption. Any Option outstanding under the Plan at the time of termination of
the Plan shall remain in effect in accordance with its terms and conditions and
those of the Plan. The Plan shall terminate on the earliest of (a) April 25,
2001, (b) the date when all shares of Stock reserved for issuance under the Plan
shall have been acquired through exercise of Options granted under the Plan or
(c) such earlier date as the Board may determine.
5. THE STOCK. The aggregate number of shares of Stock issuable under the
Plan shall be 1,000,000 or the number and kinds of shares of capital stock or
other securities substituted for the Stock as provided in Section 8. The
aggregate number of shares of Stock issuable under the Plan may be set aside out
of the authorized but unissued shares of Stock not reserved for any other
purpose or out of shares of Stock held in or acquired for the treasury of the
Company. All shares of Stock subject to an Option that terminates unexercised
for any reason may thereafter be subjected to a new Option under the Plan.
6. OPTION AGREEMENT. Each Grantee shall enter into a written agreement
with the Company setting forth the terms and conditions of the Option issued to
the Grantee, consistent with the Plan. The form of agreement to evidence Options
may be established at any time or from time to time by the Committee. No Grantee
shall have rights in any Option unless and until a written option agreement is
entered into with the Company.
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7. GRANT, TERMS AND CONDITIONS OF OPTIONS. Options may be granted by the
Committee at any time and from time to time prior to the termination of the
Plan. Except as hereinafter provided, Options granted under the Plan shall be
subject to the following terms and conditions:
(a) GRANTEES. The Grantees shall be those key employees of the Company or
its Subsidiaries (including officers and directors) selected by the Committee,
provided that no Option shall be granted under the Plan to (i) any person owning
Stock or other capital stock of the Company possessing more than 10% of the
total combined voting power of all classes of capital stock of the Company or
(ii) any director who is not an officer.
(b) PRICE. The exercise price of an Option shall be no less than the fair
market value of the Stock, without regard to any restriction, at the time the
Option is granted. The fair market value of the Stock at the time of the grant
shall be: (i) the closing price of the Stock on the trading day immediately
preceding the date of the grant (the "Valuation Date") if the Stock is listed on
a national securities exchange or the Nasdaq National Market ("NNM"); (ii) the
average of the closing bid and asked prices for the Stock on the Valuation Date
if the Stock is not listed on a national securities exchange or the NNM but is
traded over-the-counter; or (iii) such value as the Committee shall in good
faith determine if the Stock is neither listed on a national securities exchange
or the NNM nor traded in the over-the-counter market. If the Stock is listed on
a national exchange or the NNM or is traded over-the-counter but is not traded
on the Valuation Date, then the price shall be determined by the Committee by
applying the principles contained in applicable Treasury Regulations. The fair
market value of the Stock shall be determined by, and in accordance with,
procedures to be established by the Committee, whose determination shall be
final.
(c) PAYMENT FOR STOCK. The exercise price of an Option shall be paid in
full at the time of exercise (i) in cash by check, (ii) with securities of the
Company already owned by, and in the possession of, the Grantee or (iii) any
combination of cash and securities of the Company. Securities of the Company
used to satisfy the exercise price of an Option shall be valued at their fair
market value determined in accordance with the rules set forth in Section 7(b).
The exercise price shall not be subject to adjustment, except as provided in
Section 8.
(d) LIMITATION. Notwithstanding any provision of the Plan to the contrary,
an Option shall not be treated as an incentive stock option under Code section
422 to the extent to which the aggregate market value (determined as of the time
an Option is granted) of Stock for which Options (together with options granted
under all other plans of the Company) are exercisable for the first time by a
Grantee during any calendar year exceeds $100,000. The value of Stock for which
Options may be granted to a Grantee in a year may, however, exceed $100,000.
(e) DURATION AND EXERCISE OF OPTIONS. Options may be exercisable for terms
of up to but not exceeding ten years from the date of grant. Subject to the
foregoing, Options shall be exercisable at the times and in the amounts (up to
the full amount thereof) determined by the Committee at the time of grant,
provided that Options shall not vest and become exercisable until at least six
months after the date of grant. If an Option granted under the Plan is
exercisable in subsequent installments, the Committee shall determine what
events, if any, will make it subject to acceleration.
(f) TERMINATION OF EMPLOYMENT. Upon the termination of a Grantee's
employment for any reason other than "Cause" (as defined below), the Grantee
may, within six months following termination, exercise the Option with respect
to all or any part of the shares subject thereto in which the right to purchase
Stock had accrued or vested at the time of termination of employment. If the
employment of a Grantee is terminated for Cause, the Grantee's rights under any
then outstanding Option shall terminate at the time of termination of
employment. "Cause" shall mean the Grantee's conviction of a felony of any
nature or a misdemeanor involving embezzlement of corporate property.
(g) TRANSFERABILITY OF OPTION. No Option shall be transferable except by
will or the laws of descent and distribution. An Option shall be exercisable
during the Grantee's lifetime only by the Grantee.
(h) MODIFICATION, EXTENSION AND RENEWAL OF OPTIONS. Subject to the terms
and conditions and within the limitations of the Plan, the Committee may modify,
extend or renew outstanding Options granted under the Plan, or accept the
surrender of outstanding Options (to the extent not theretofore exercised) and
authorize the granting of new Options
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in substitution therefor. Notwithstanding the foregoing, however, no
modification of an Option shall, without the consent of the Grantee, alter or
impair any rights or obligations under any Option theretofore granted under the
Plan or adversely affect the status of an Option as an incentive stock option
under Code section 422.
(i) OTHER TERMS AND CONDITIONS. Option agreements may contain any other
provisions not inconsistent with the Plan that the Committee deems appropriate.
8. ADJUSTMENT FOR CHANGES IN THE STOCK. (a) In the event the shares of
Stock, as presently constituted, shall be changed into or exchanged for a
different number or kind of shares of capital stock or other securities of the
Company or of another Company (whether by reason of merger, consolidation,
recapitalization, reclassification, split, reverse split, combination of shares
or otherwise), then there shall be substituted for or added to each share of
Stock theretofore or thereafter subject to an Option the number and kind of
shares of capital stock or other securities into which each outstanding share of
Stock shall be so changed, or for which each such share shall be exchanged, or
to which each such share shall be entitled, as the case may be. The price and
other terms of outstanding Options shall also be appropriately amended to
reflect the foregoing events. In the event there shall be any other change in
the number or kind of outstanding shares of the Stock, or of any capital stock
or other securities into which the Stock shall have been changed or for which it
shall have been exchanged, if the Committee shall, in its sole discretion,
determine that the change equitably requires an adjustment in any Option
theretofore granted or which may be granted under the Plan, then adjustments
shall be made in accordance with its determination.
(b) Fractional shares resulting from any adjustment in Options pursuant to
this Section 8 may be settled in cash or otherwise as the Committee shall
determine. Notice of any adjustment shall be given by the Company to each holder
of an Option that shall have been so adjusted, and the adjustment (whether or
not notice is given) shall be effective and binding for all purposes of the
Plan.
(c) Notwithstanding Section 8(a), the Committee shall have the power, in
the event of the disposition of all or substantially all of the assets of the
Company, or the dissolution of the Company, or the merger or consolidation of
the Company with or into any other Company, or the merger or consolidation of
any other Company into the Company, or the making of a tender offer to purchase
all or a substantial portion of outstanding Stock of the Company, to amend all
outstanding Options (upon such conditions as it shall deem appropriate) to (i)
permit the exercise of Options prior to the effective date of the transaction
and to terminate all unexercised Options as of that date, or (ii) require the
forfeiture of all Options, provided the Company pays to each Grantee the excess
of the fair market value of the Stock subject to the Option (determined in
accordance with Section 7[b]) over the exercise price of the Option, or (iii)
make any other provisions that the Committee deems equitable.
9. AMENDMENT OF THE PLAN. The Committee may amend the Plan, may correct
any defect or supply any omission or reconcile any inconsistency in the Plan or
in any Option in the manner and to the extent deemed desirable to carry out the
Plan without action on the part of the stockholders of the Company; provided,
however, that, except as provided in Section 8 and this Section 9, unless the
stockholders of the Company shall have first approved thereof (a) the total
number of shares of Stock subject to the Plan shall not be increased, (b) no
Option shall be exercisable more than ten years after the date it is granted,
(c) the expiration date of the Plan shall not be extended and (d) no amendment
shall permit the exercise price of any Option to be less than the fair market
value of the Stock at the time of grant, increase the number of shares of Stock
to be received on exercise of an Option, materially increase the benefits
accruing to a Grantee under an Option or modify the eligibility requirements for
participation in the Plan.
10.INTERPRETATION AND CONSTRUCTION. The interpretation and construction of
any provision of the Plan by the Committee shall be final, binding and
conclusive for all purposes.
11.APPLICATION OF FUNDS. The proceeds received by the Company from the
sale of Stock pursuant to this Plan will be used for general corporate purposes.
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12.NO OBLIGATION TO EXERCISE OPTION. The granting of an Option shall
impose no obligation upon the Grantee to exercise an Option.
13.PLAN NOT A CONTRACT OF EMPLOYMENT. The Plan is not a contract of
employment, and the terms of employment of any Grantee shall not be affected in
any way by the Plan or related instruments except as specifically provided
therein. The establishment of the Plan shall not be construed as conferring any
legal rights upon any Grantee for a continuance of employment, nor shall it
interfere with the right of the Company or any Subsidiary to discharge any
Grantee.
14.EXPENSES OF THE PLAN. All of the expenses of administering the Plan
shall be paid by the Company.
15.COMPLIANCE WITH APPLICABLE LAW. Notwithstanding anything herein to the
contrary, the Company shall not be obligated to cause to be issued or delivered
any certificates for shares of Stock issuable upon exercise of an Option unless
and until the Company is advised by its counsel that the issuance and delivery
of the certificates is in compliance with all applicable laws, regulations of
governmental authorities and the requirements of any exchange upon which shares
of Stock are traded. The Company shall in no event be obligated to register any
securities pursuant to the Securities Act of 1933 (as now in effect or as
hereafter amended) or to take any other action in order to cause the issuance
and delivery of certificates to comply with any of those laws, regulations or
requirements. The Committee may require, as a condition of the issuance and
delivery of certificates and in order to ensure compliance with those laws,
regulations and requirements, that the Grantee make such covenants, agreements
and representations as the Committee, in its sole discretion, deems necessary or
desirable. Each Option shall be subject to the further requirement that if at
any time the Committee shall determine in its discretion that the listing or
qualification of the shares of Stock subject to the Option, under any securities
exchange requirements or under any applicable law, or the consent or approval of
any regulatory body, is necessary in connection with the granting of the Option
or the issuance of Stock thereunder, the Option may not be exercised in whole or
in part unless the listing, qualification, consent or approval shall have been
effected or obtained free of any conditions not acceptable to the Committee.
16.GOVERNING LAW. Except to the extent preempted by federal law, this Plan
shall be construed and enforced in accordance with, and governed by, the laws of
the State of Delaware.
4
EXHIBIT 21.1
SUBSIDIARIES OF THE REGISTRANT
JURISDICTION
OF
NAME INCORPORATION
- ---- -------------
Kelley Oil Corporation Delaware
* Concorde Gas Intrastate, Inc. Delaware
* Concorde Gas Marketing, Inc. Delaware
* Petrofunds, Inc. Delaware
- ------------
* Subsidiaries of Kelley Oil Corporation
EXHIBIT 23.1
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement No.
33-90932 on Form S-8, and Registration Statement No. 333-3132 on Form S-8 of our
report dated March 3, 1997, appearing in this Annual Report on Form 10-K of
Kelley Oil & Gas Corporation for the year ended December 31, 1996.
DELOITTE & TOUCHE LLP
Houston, Texas
March 26, 1997
EXHIBIT 23.2
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in the Registration
Statements (Form S-8 No. 33-90932 and Form S-8 No. 333-3132) of Kelley Oil & Gas
Corporation and in the related Prospectuses of our report dated March 6, 1995,
with respect to the consolidated financial statements of Kelley Oil & Gas
Corporation included in this Annual Report (Form 10-K) for the year ended
December 31, 1996.
ERNST & YOUNG LLP
Houston, Texas
March 26, 1997
EXHIBIT 23.3
CONSENT OF H.J. GRUY AND ASSOCIATES, INC.
We hereby consent to the use of the name H.J. Gruy and Associates, Inc.
and of the references to H.J. Gruy and Associates, Inc. and to the inclusion of
and references to our report dated February 25, 1997, prepared for Kelley Oil &
Gas Corporation in the Kelley Oil & Gas Corporation Annual Report on Form 10-K
for the year ended December 31, 1996.
H.J. Gruy and Associates, Inc.
/s/ MARILYN WILSON
Marilyn Wilson
Chief Operating Officer
March 26, 1997
Houston, Texas
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