KELLEY OIL & GAS CORP, 10-K, 1999-04-15

KELLEY OIL & GAS CORP
10-K, 1999-04-15
NATURAL GAS TRANSMISSION

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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998 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:

<TABLE>
<S> <C>
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
8 1/2% Convertible Subordinated Debentures due 2000 American Stock Exchange
</TABLE>

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:

<TABLE>
<S> <C>
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
Common Stock NASDAQ SmallCap Market
$2.625 Convertible Exchangeable Preferred Stock NASDAQ SmallCap Market
</TABLE>

Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [X] No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K under the Securities Exchange Act of 1934 is not contained
herein, and will not be contained, to the best of the Registrant's knowledge, in
definitive proxy or information statements incorporated in Part III of this Form
10-K or any amendments to this Form 10-K. [ ]

As of March 26, 1999, 126,022,235 shares of Common Stock and 1,733,628 shares of
Preferred Stock were outstanding, and the aggregate market values of shares held
by unaffiliated stockholders were approximately $26,942,095 and $8,499,285,
respectively.

DOCUMENTS INCORPORATED BY REFERENCE

Certain portions of the Proxy Statement for the 1999 Annual Meeting of
Stockholders are incorporated by reference into Part III of this Report.

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<PAGE> 2
PART I

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

INTRODUCTION

Kelley Oil & Gas Corporation, incorporated in Delaware in 1994, with
its subsidiaries and subsidiary partnerships (individually and collectively the
"Company"), 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 flows in a cost-efficient manner through strategic
domestic acquisitions and a program of balanced development and exploration
activities. 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.

INDUSTRY CONDITIONS / SUBSEQUENT EVENTS

During 1998, the oil and gas industry experienced a worldwide excess of
supply over demand for oil and natural gas resulting in sharply reduced prices.
As a result, many companies in the oil and gas industry, including the Company,
experienced reduced profitability and cash flows which, in turn, created
significant liquidity problems. As discussed in Note 4 to the Consolidated
Financial Statements, although the Company was in compliance with its Credit
Facility debt covenants at December 31, 1998, the Company was not in compliance
as of March 31, 1999, which could result in all borrowings under such Credit
Facility being declared immediately due and payable and the Credit Facility
being terminated and the payment of other subordinated obligations being
accelerated. In addition, other long-term debt repayments of $34.1 million are
scheduled to be made in December 1999. These uncertainties create substantial
doubt about the Company's ability to continue its operations as a going
concern. To address these liquidity issues, the Company is attempting to take
the measures discussed in the following paragraphs.

In April 1999, the Company entered into an Exploration and Development
Agreement with Phillips Petroleum Company ("Phillips") relating to certain of
the Company's interests in the Bryceland, West Bryceland and Sailes fields in
north Louisiana. Pursuant to the agreement, the Company will: (1) receive an $83
million cash payment (subject to certain post-closing adjustments), (2) retain a
42 Bcf, 8-year volumetric overriding royalty interest and a 1% override on the
excess production above such royalty interest and (3) retain 25% of its working
interest in the Cotton Valley formation. In addition, Phillips will at its risk
and expense, operate, develop, exploit and explore the properties thereby
relieving the Company of significant operating, exploration and development
costs in the future. The effective date of the transaction will be May 1, 1999
and is scheduled to close on April 30, 1999, subject to the parties obtaining
required consents and meeting substantial closing requirements.

In addition, the Company is negotiating a private offering of debt
securities (the "Notes"), the net proceeds which will be used to repay all
amounts outstanding under its Credit Facility, and some of which proceeds may be
used to redeem or otherwise retire a portion of the outstanding convertible
subordinated indebtedness. If issued, the Notes will be secured by a first lien
on substantially all of the Company's proved crude oil and natural gas
properties and guaranteed by three entities wholly-owned by the Company. The
issuance of the Notes will be conditioned upon the completion of the transaction
with Phillips noted in the preceding paragraph and upon the completion of
certain other conditions. There can be no assurance that the issuance of the
Notes will be consummated on such terms, or at all.

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While industry conditions cannot be predicted with certainty and are
dependent upon a number of commodity and economic factors beyond its control,
the Company believes the net cash proceeds from the Phillips transaction and
issuance of the Notes, if consummated, in conjunction with cash on hand and cash
flow from operations will be sufficient to provide adequate working capital and
fund its capital expenditure program during 1999. However, the Company will
continue to have significant debt outstanding and industry conditions beyond its
control may adversely affect its results of operations and financial condition.

COMPANY HISTORY

The Consolidation. The Company was formed in 1994 to consolidate the
equity ownership (the "Consolidation") of Kelley Oil & Gas Partners, Ltd.
("Kelley Partners") and Kelley Oil Corporation ("Kelley Oil"). Before the
Consolidation in 1994, Kelley Partners and developmental drilling partnership
subsidiaries of Kelley Oil ("DDPs") jointly conducted drilling activities.
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, the Company acquired Kelley Oil's
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 ("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. In 1996,
Kelley Partners was merged into the Company and each of the then outstanding
shares of ESOP Preferred Stock was redeemed for one share of the Company's
Common Stock.

Contour Transaction. In January 1996, the Company entered into
financing and related agreements with Contour Production Company L.L.C.
("Contour"), pursuant to which Contour purchased 48.0 million newly issued
shares of Common Stock for $48.0 million on February 15, 1996, and an option
(the "Contour Option") to purchase an additional 27.0 million shares of Common
Stock for $27.0 million, which was exercised on December 1, 1997. In February
1996, in connection with the first stage of Contour's investment in the Company,
John F. Bookout was appointed Chairman, President and Chief Executive Officer of
the Company, and certain other experienced oil industry executives were
appointed to senior management positions within the Company (all such
transactions are referred to collectively as the "Contour Transaction").

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
existing lines of credit.

Acquisition of Oil and Gas Properties. Effective as of December 1,
1997, the Company purchased substantially all of the assets of SCANA Petroleum
Resources, Inc. ("SPR") for approximately $110 million (the "SPR Acquisition").
The assets acquired include interests in proved oil and natural gas reserves
primarily located in Louisiana, the shallow waters of the Gulf of Mexico and
east Texas, as well as exploratory leasehold acreage in those areas ("SPR
Properties"). The Company financed this acquisition with $27 million of proceeds
received upon the exercise of the Contour Option and borrowings under the Credit
Facility. In July 1998, the Company sold, for $17.4 million, its interests in
the Waskom field acquired from SPR.

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<PAGE> 4

OPERATIONS AND PROPERTIES

Operation Activities. The Company's production is derived primarily
from four contiguous fields in the Vacherie Salt Dome region of north Louisiana,
south Louisiana and the shallow waters of the Gulf of Mexico.

Development Activities. During 1998, the Company continued development
drilling activities within its existing properties in the Vacherie Salt Dome
region of north Louisiana, where at December 31, 1998, approximately 71% of its
proved reserves were located on 46,460 gross (21,514 net) acres. In north
Louisiana, the Company drilled or participated in drilling 44 gross (21.1 net)
development wells, of which 43 gross (20.7 net) were completed as producing
wells. At year-end 1998, 156 locations included in the H.J. Gruy & Associates,
Inc. reserve report were defined as proved undeveloped locations totaling 114.6
bcfe of reserves.

Exploration Activities. The Company focuses its exploration activities
primarily on its existing leaseholdings in Terrebonne and LaFourche Parishes,
Louisiana, which the Company believes have, with higher risk, the potential for
larger reserve and production increases as compared to development activity in
north Louisiana. Additional exploration activities include the Company's
existing blocks located in the shallow waters of the Gulf of Mexico and
properties located in the Permian Basin. The Company has approximately 273,460
gross undeveloped acres of exploratory properties principally in these regions
on which it has identified over 30 prospective exploratory well sites. However,
the number, type and timing of these proposed wells is subject to continued
revision as a result of many factors, including test and drilling results on
these properties and others, the price of oil and natural gas, availability of
capital funds and drilling rigs, weather, and general economic factors. See
"Caution as to Forward-Looking Statements" and "Risk Factors".

The Company is utilizing sophisticated technologies to identify
exploration prospects and advanced geophysical techniques to continue to develop
and refine interpretations of its 3-D seismic database, which covers (i) 600
square miles, a major portion of its existing leaseholdings in Terrebonne and
LaFourche Parishes, in south Louisiana, (ii) 50 square miles offshore Texas, and
(iii) 600 square miles of its Permian Basin exploratory prospects.

In 1998, the Company drilled 15 gross (5.8 net) exploratory wells, of
which 8 gross (2.5 net) were completed as producing wells. Included in these
amounts are 3 gross (0.8 net) exploratory wells that were drilled and completed
as producing wells on acreage acquired in the SPR Acquisition.

Description of Properties. The Company's properties are located in
Louisiana, and in the Gulf of Mexico, Texas, New Mexico and Arkansas. As of
January 1, 1999, the Company owned interests in a total of 584 gross (224.5 net)
producing wells, of which 298 wells were operated by the Company, accounting for
74% of its current production. As of that date, the Company had leaseholdings
covering 174,556 gross (81,054 net) developed acres and 294,807 gross (90,703
net) undeveloped acres. Approximately 90% of its proved oil and natural gas
reserves as of January 1, 1999, was natural gas on an energy content basis. The
reserves to production ratio for these properties (based on 1998 production) was
estimated to be 8.3 as of January 1, 1999.

Significant Properties. The Company's natural gas properties in north
Louisiana are located primarily in the Sailes, Sibley, West Bryceland and Ada
fields of Webster and Bienville Parishes, while its properties in south
Louisiana are concentrated in the Orange Grove/Humphreys, Lirette, Lake Pagie,
Ouiski Bayou and Bayou Sauveur fields (Bourg prospect) in Terrebonne Parish.
Production is primarily from the Hosston (north Louisiana) and Miocene (south
Louisiana) formations. Other properties are located primarily in the shallow
waters of the Gulf of Mexico, south Louisiana, and Texas. Substantially all of
the Company's oil and natural gas properties are pledged to secure borrowings
under the Company's Credit Facility. The following table sets forth certain
information as of the dates indicated regarding the Company's interests by major
geographic region. See "Estimated Proved Reserves--Uncertainties in Estimating
Reserves and Future Net Cash Flows."

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<PAGE> 5

SIGNIFICANT PROVED PROPERTIES

<TABLE>
<CAPTION>
PROVED RESERVES AT JANUARY 1, 1999 PRODUCTION
-------------------------------------------------- -----------------------------------
YEAR ENDED
PRESENT VALUE DECEMBER 31, 1998
OF ESTIMATED -----------------------------------
GAS FUTURE NET GAS
OIL GAS EQUIVALENT CASH FLOWS(1) OIL GAS EQUIVALENT
Mbbls Mmcf (Mmcfe) (IN THOUSANDS) (Mbbls) (Mmcf) (Mmcfe)
-------- -------- ---------- --------------- -------- -------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
North Louisiana .... 604 229,565 233,189 $169,938 93 24,293 24,851
South Louisiana .... 3,735 26,555 48,965 40,369 113 4,798 5,476
Offshore ........... 475 23,976 26,826 18,955 52 5,584 5,896
Other as a group ... 480 3,463 6,343 5,022 117 882 1,584
-------- -------- -------- -------- -------- -------- --------
Totals ............. 5,294 283,559 315,323 $234,284 375 35,557 37,807
======== ======== ======== ======== ======== ======== ========
</TABLE>

(1) The estimates were prepared in accordance with SEC regulations using
market or contract prices at the end of each reported period. Prices and
operating and development costs are held constant over the estimated life of the
reserves. A discount factor of 10% was used to reflect the timing of future net
cash flow. See "Estimated Proved Reserves--Uncertainties in Estimating Reserves
and Future Net Cash Flows" and Note 11 to the Consolidated Financial Statements.

The Company has entered into an exploration and development agreement
relating to certain of its proved behind pipe and undeveloped interests in the
Bryceland, West Bryceland and Sailes fields in north Louisiana, pursuant to
which the Company expects to receive a cash payment and retain certain
overriding royalty interests on existing production and working interests in
certain currently non-producing deeper zones. If the Company consummates the
Phillips transaction, substantially more funds will be available for the
Company's drilling activities. The consummation of such transaction would be
subject to substantial closing conditions. There is no assurance that the
Company will complete the Phillips transaction as currently contemplated or at
all.

ADDITIONAL INFORMATION REGARDING THESE REGIONS IS SET FORTH BELOW.
UNLESS OTHERWISE NOTED, ACREAGE AND WELL INFORMATION IS PROVIDED AS OF DECEMBER
31, 1998, AND RESERVE INFORMATION IS PROVIDED AS OF JANUARY 1, 1999.

North Louisiana. The Company's operations in this region are 64% proved
developed, and its wells are typically drilled to a maximum depth of
approximately 10,500 feet. Operations in this region do not typically experience
geopressured formations or significant associated salt-water production. The
Company's reserves to production ratio in north Louisiana is approximately 9.4.
Its lifting costs in this region are generally low (approximately $0.17 per Mcfe
in 1998) as a result of relatively low formation pressures and minimal liquid
hydrocarbon and salt water production. In the past three years, completed wells
in north Louisiana had an average development cost of $0.69 per Mcfe with gross
average reserves per well of 2.4 Bcfe. At December 31, 1998, the Company
operated an aggregate of 222 gross (122.0 net) wells in this region and was
drilling or completing 1 gross (0.34 net) well in the region. The Company's
weighted average working interest in these properties based on estimated proved
reserves is approximately 51%. The Company's share of proved reserves associated
with these fields totaled approximately 233.2 Bcfe at December 31, 1998.

South Louisiana. The Company's operations in this region primarily are
focused on five fields in the Houma Embayment and Terrebonne Trough areas. These
areas contain high-quality reservoir rock, contributing to high production
rates. Wells are typically drilled to a depth of approximately 11,000 to 19,000
feet. The Company's share of proved reserves associated with these fields
totaled approximately 49.0 Bcfe at December 31, 1998. Production from the
Company's south Louisiana properties generally receives premium wellhead prices
because of the close proximity of the properties to transportation and market
locations, and because of their rich condensate content. The Company believes
these factors partially offset the higher operating costs associated with higher
formation pressures, salt water disposal and inland water well locations
associated with the region. At December 31, 1998, the Company operated an
aggregate of 23 gross (13.4 net) wells and was drilling 1 gross (0.50 net) well
in this region, which was subsequently completed. The Company's weighted average
working interest in these properties based on estimated proved reserves

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is approximately 56%. In 1998, the Harry S. Bourg #1 deep exploratory test was
drilled to total depth. The well has been designated as a new completion in the
Bayou Sauveur field. Development of the field will begin in the second quarter
of 1999 with the drilling of the first appraisal well, which will test most of
the sands encountered in the discovery well but at a structurally higher
position.

Offshore. The Company's operations in this region are primarily focused
in the shallow waters of the Gulf of Mexico, offshore Texas, Louisiana and
Alabama. The Company's share of proved reserves associated with these fields
totals approximately 26.8 Bcfe at December 31, 1998. At December 31, 1998, the
Company operated an aggregate of 34 gross (30.6 net) wells in this region and
had an interest in 67 gross (37.7 net) wells with a weighted average working
interest based on estimated proved reserves of approximately 74%.

JOINT VENTURE PARTNERSHIPS

The Company participates in joint ventures with industry partners to
accelerate the exploration and evaluation of its properties and to mitigate the
risks associated with exploratory drilling projects.

In December 1996, the Company entered into a joint venture with
Williams Production, Gulf Coast Company ("Williams"), a unit of The Williams
Companies, Inc., relating to the Company's south Louisiana properties. Pursuant
to the terms and conditions of this joint venture, effective December 1, 1996,
Williams purchased a 50% interest in the Company's 27,000 net acreage position
in the Houma Embayment, including 50% of the Company's interest in 23 wells and
related facilities in the Orange Grove/Humphreys and Ouiski Bayou fields, for a
total purchase price of $20.5 million, a portion of which was committed under
the joint venture to drill up to eight exploration wells in those areas.
Together with Williams, the Company drilled 3 gross (1.5 net) wells in south
Louisiana in 1998, of which 2 gross (1.0 net) were completed and are producing
and 1 gross (0.5 net) resulted in a dry hole. Pursuant to the joint venture, the
Company and Williams are expected to continue exploratory drilling in 1999 on
their south Louisiana properties. However, the Company's participation in
drilling these wells is at its discretion.

The Company is involved in other joint ventures with third-party
interest holders, including Fina Oil and Chemical Company, a subsidiary of FINA,
Inc. ("Fina"), and Cobra Oil and Gas Corporation ("Cobra"). The Fina joint
venture represents a joint exploration and development agreement covering an
area of mutual interest (the "AMI") of approximately 400,000 acres in south
Louisiana. The agreement provides for the parties to obtain 3-D seismic coverage
over all mutually agreeable prospective lands within the AMI. To date, the
Company and Fina have acquired 3-D seismic data covering approximately 450
square miles within the AMI. The Cobra program involves exploitation of
approximately 68,000 acres in Texas, New Mexico, Arkansas, Louisiana and Alabama
and includes 3-D seismic data covering approximately 975 square miles.

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ESTIMATED PROVED RESERVES

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 the Company for the years ended December 31,
1996, 1997 and 1998, which were prepared by H.J. Gruy & Associates, Inc.
("Gruy") independent petroleum engineers.

ESTIMATED PROVED RESERVES

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------------------
1996 1997 1998
---------------------- ---------------------- ----------------------
OIL GAS OIL GAS OIL GAS
(Mbbls) (Mmcf) (Mbbls) (Mmcf) (Mbbls) (Mmcf)
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
PROVED RESERVES:
Beginning balance ................. 1,387 196,273 1,466 297,634 2,953 354,867
Revisions of previous estimates ... (89) (30,519) 106 21,831 (79) (31,674)
Purchases of reserves in place .... 57 30,844 1,351 51,712 -- --
Extensions and discoveries ........ 477 128,692 256 13,892 3,082 9,512
Sale of reserves in place ......... (134) (4,190) -- -- (287) (13,589)
Production ........................ (232) (23,466) (226) (30,202) (375) (35,557)
-------- -------- -------- -------- -------- --------
Ending balance .................. 1,466 297,634 2,953 354,867 5,294 283,559
======== ======== ======== ======== ======== ========
PROVED DEVELOPED RESERVES:
Producing ......................... 608 113,831 1,856 180,307 1,062 129,787
Non-producing ..................... 369 59,634 576 77,493 919 59,037
-------- -------- -------- -------- -------- --------
Total proved developed .......... 977 173,465 2,432 257,800 1,981 188,824
======== ======== ======== ======== ======== ========
</TABLE>

The estimates of proved reserves set forth in the above table were
prepared in accordance with SEC regulations using market or contract prices at
the end of each reported period. Prices and operating and development costs are
held constant over the estimated life of the reserves.

Estimated 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.

Uncertainties in Estimating Reserves and Future Net Cash Flows. There
are numerous uncertainties in estimating quantities of proved reserves believed
to have been discovered and in projecting future rates of production and the
timing of development expenditures, including many factors beyond the control of
the Company. The reserve data set forth in this document are only estimates.
Reserve estimates are inherently imprecise and may be expected to change as
additional information becomes available. Furthermore, estimates of oil and
natural 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. Reservoir engineering is a subjective process of estimating
underground accumulations of oil and natural gas that cannot be measured
exactly, and the accuracy of any reserve estimate is a function of the quality
of available data and of engineering and geological interpretation and judgment.
Accordingly, 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 cash
flows expected therefrom prepared by different engineers or by the same
engineers at different times may vary substantially. 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. It is possible that variances from the estimates will be
material. In addition, the estimates of future net cash flows from proved
reserves of the Company 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. The Company emphasizes
with respect to the estimates prepared by independent petroleum engineers that
the discounted

6
<PAGE> 8

future net cash flows should not be construed as representative of the fair
market value of the proved reserves owned by the Company since discounted future
net cash flows are based upon projected cash flows which do not provide for
changes in oil and natural gas prices from those in effect on the date indicated
or for escalation of expenses and capital costs subsequent to such date. The
meaningfulness of such estimates is highly dependent upon the accuracy of the
assumptions upon which they were based. Accordingly, investors in the Common
Stock are cautioned not to place undue reliance on the reserve data included in
this document.

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, average sales
prices and average production expenses attributable to the Company's properties
for 1996, 1997 and 1998. Detailed additional information concerning the
Company's oil and natural gas production activities is contained in the
Supplementary Information in Note 12 to the Consolidated Financial Statements
included elsewhere in this Report.

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------
1996 1997 1998
---------- ---------- ----------
<S> <C> <C> <C>
PRODUCTION DATA:
Oil and other liquid hydrocarbons (Mbbls) ........................... 232 226 375
Natural gas (Mmcf) .................................................. 23,466 30,202 35,557
Natural gas equivalent (Mmcfe) ...................................... 24,858 31,558 37,807
AVERAGE SALES PRICE PER UNIT:
Oil and other liquid hydrocarbons (per Bbl) ......................... $ 22.11 $ 19.34 $ 13.09
Natural gas (per Mcf, including effects of hedging) ................. 2.30 2.27 2.09
Natural gas equivalent (per Mcfe, including effects of hedging) ..... 2.37 2.31 2.10
AVERAGE PRODUCTION EXPENSES PER MCFE ................................... $ .43 $ .35 $ .53
</TABLE>

PRODUCTIVE WELLS AND ACREAGE

As of December 31, 1998, the Company had leaseholdings comprising
174,556 gross (81,054 net) developed acres and 294,807 gross (90,703 net)
undeveloped acres, all located within the continental United States. The oil and
gas leases in which the Company 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 the Company'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, if applicable.

7
<PAGE> 9

The following table sets forth the Company's ownership interests in its
leaseholds as of December 31, 1998.

<TABLE>
<CAPTION>
DEVELOPED(1) UNDEVELOPED(2)
------------------------- --------------------------
GROSS ACRES NET ACRES GROSS ACRES NET ACRES
----------- --------- ----------- --------
<S> <C> <C> <C> <C>
Louisiana ........ 78,683 33,085 234,427 70,112
Texas ............ 24,055 4,366 19,429 3,162
Offshore ......... 58,840 38,772 2,830 1,054
Other states ..... 12,978 4,831 38,121 16,375
------- ------- ------- -------
Total ......... 174,556 81,054 294,807 90,703
======= ======= ======= =======
</TABLE>

(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.

As of December 31, 1998, the Company had working interests in 514 gross
(213.0 net) productive gas wells and 70 gross (11.5 net) productive oil wells
(including producing wells and wells capable of production).

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<PAGE> 10

EXPLORATION AND DEVELOPMENT

The following table sets forth the number of gross and net productive
and dry exploratory and development wells drilled by the Company.

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------
1996 1997 1998
------------ ------------ ------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C>
NORTH LOUISIANA:
Exploratory wells:
Oil .......................... -- -- -- -- -- --
Natural gas .................. -- -- -- -- 2 .72
Dry .......................... -- -- -- -- -- --
----- ----- ----- ----- ----- -----
Total ........................ -- -- -- -- 2 .72
===== ===== ===== ===== ===== =====

Development wells:
Oil .......................... 1 .03 -- -- -- --
Natural gas .................. 65 31.63 82 34.96 43 20.68
Dry .......................... 3 1.74 -- -- 1 .46
----- ----- ----- ----- ----- -----
Total ...................... 69 33.40 82 34.96 44 21.14
===== ===== ===== ===== ===== =====

Total north Louisiana:
Producing .................... 66 31.66 82 34.96 45 21.40
Dry .......................... 3 1.74 -- -- 1 .46
----- ----- ----- ----- ----- -----
Total ...................... 69 33.40 82 34.96 46 21.86
===== ===== ===== ===== ===== =====

SOUTH LOUISIANA AND OTHER:
Exploratory wells:
Oil .......................... -- -- -- -- -- --
Natural gas .................. -- -- 9 3.50 6 1.81
Dry .......................... -- -- 1 .50 7 3.22
----- ----- ----- ----- ----- -----
Total ...................... -- -- 10 4.00 13 5.03
===== ===== ===== ===== ===== =====

Development wells:
Oil .......................... -- -- -- -- 3 .04
Natural gas .................. -- -- -- -- -- --
Dry .......................... -- -- -- -- -- --
----- ----- ----- ----- ----- -----
Total ...................... -- -- -- -- 3 .04
===== ===== ===== ===== ===== =====

Total south Louisiana and other:
Producing .................... -- -- 9 3.50 9 1.85
Dry .......................... -- -- 1 .50 7 3.22
----- ----- ----- ----- ----- -----
Total ...................... -- -- 10 4.00 16 5.07
===== ===== ===== ===== ===== =====
</TABLE>

As of December 31, 1998, the Company had 1 gross (0.34 net) development
well in progress, in north Louisiana, and 1 gross (0.50 net) exploratory well in
progress in south Louisiana. Subsequent to year-end 1998, the south Louisiana
exploratory well (Bourg discovery) was completed as a producing well.

9
<PAGE> 11

MARKETING OF NATURAL GAS AND CRUDE OIL

The Company does not refine or process any of the oil and natural gas
it produces. Substantially all of the Company's natural gas is sold under 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. The Company's sales of crude oil, condensate and natural gas liquids
generally are made at prices related to posted field prices.

In addition to marketing the Company's natural gas production, it
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, monitoring and marketing functions.

The Company believes that its activities are not currently constrained
by a lack of adequate transportation systems or system capacity and does not
foresee any material disruption in available transportation for its production.
However, there can be no assurance that the Company will not encounter these
constraints in the future. In that event, the Company would be forced to seek
alternate sources of transportation and may face increased costs.

HEDGING OF NATURAL GAS

COMPETITION

The Company operates in a highly competitive environment with respect
to acquiring reserves, marketing oil and natural gas and securing trained
personnel. Many of the Company's larger competitors possess and employ financial
and personnel resources substantially greater than those available to it. 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 the Company's financial or personnel resources permit. The Company'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 the Company 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.

TITLE TO PROPERTIES

The Company's properties, in addition to being mortgaged to secure the
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 its business.

The Company believes that it 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.

10
<PAGE> 12

EMPLOYEES

As of December 31, 1998, the Company had 68 employees. The Company's
staff includes employees experienced in acquisitions, geology, geophysics,
petroleum engineering, land acquisition and management, finance and accounting.
None of the Company's employees are represented by a union. The Company has not
experienced an interruption in its operations due to any labor dispute and
believes that its working relationships with its employees are satisfactory.

REGULATION

The Company's operations are subject to extensive and continually
changing regulation, as legislation affecting the oil and natural gas industry
is under constant review for amendment and expansion. Many departments and
agencies, both federal and state, are authorized by statute to issue and have
issued rules and regulations binding on the oil and natural gas industry and its
individual participants. The failure to comply with such rules and regulations
can result in substantial penalties. The regulatory burden on the oil and
natural gas industry increases the Company's cost of doing business and,
consequently, affects its profitability. However, the Company does not believe
that it is affected in a significantly different manner by these regulations
than are its competitors in the oil and natural gas industry. Because of the
numerous and complex federal and state statutes and regulations that may affect
the Company, directly or indirectly, the following discussion of certain
statutes and regulations should not be relied upon as an exhaustive review of
all matters affecting the Company's operations.

Transportation and Production

Transportation and Sale of Natural Gas and Crude Oil. Sales of natural
gas, crude oil and condensate ("Products") can be made by the Company at market
prices not subject at this time to price controls. The price that the Company
receives from the sale of these Products is affected by the ability to transport
and cost of transporting the Products to market. Under applicable laws, the
Federal Energy Regulation Commission ("FERC") regulates both the construction of
pipeline facilities and the transportation of Products in interstate commerce.

Regulation of Drilling and Production. Drilling and production
operations of the Company are subject to regulation under a wide range of state
and federal statutes, rules, orders and regulations. State and federal statutes
and regulations govern, among other matters, the amounts and types of substances
and materials that may be released into the environment, the discharge and
disposition of waste materials, the reclamation and abandonment of wells and
facility sites and remediation of contaminated sites, and require permits for
drilling operations, drilling bonds and reports concerning operations. The
federal leases are administered by the Bureau of Land Management ("BLM") and the
Minerals Management Service ("MMS"), which are administered, along with the
Bureau of Indian Affairs, by the federal Department of the Interior. These
leases contain relatively standard terms and require compliance with detailed
MMS and BLM regulations and orders, which are subject to change. In addition to
permits required by other federal agencies (such as the Coast Guard, the Army
Corps of Engineers and the Environmental Protection Agency), lessees must obtain
a permit from the MMS or BLM prior to commencement of offshore or onshore
drilling. States in which the Company owns and operates properties have varying
laws and regulations governing conservation matters, including provisions for
the unitization or pooling of oil and natural gas properties, the establishment
of maximum rates of production from oil and natural gas wells and the regulation
of the spacing, plugging and abandonment of wells. Many states also restrict
production to the market demand for oil and natural gas and several states have
indicated interest in revising applicable regulations. The effect of these
regulations is to limit the amount of oil and natural gas the Company can
produce from its wells and to limit the number of wells or the locations at
which the Company can drill. Moreover, each state generally imposes an ad
valorem, production or severance tax with respect to the production and sale of
crude oil, natural gas and gas liquids within its jurisdiction.

Environmental Regulations

General. The various federal environmental laws, including the National
Environmental Policy Act; the Clean Air Act of 1990, as amended ("CAA"); Oil
Pollution Act of 1990, as amended ("OPA"); Water Pollution Control Act,

11
<PAGE> 13

as amended ("FWPCA"); the Resource Conservation and Recovery Act as amended
("RCRA"); the Toxic Substances Control Act; and the Comprehensive Environmental
Response, Compensation and Liability Act, as amended ("CERCLA"), and the various
state and local environmental laws, and the regulations adopted pursuant to such
law, governing the discharge of materials into the environment, or otherwise
relating to the protection of the environment, continue to be taken seriously by
the Company. In particular, the Company's drilling, development and production
operations, its activities in connection with storage and transportation of
crude oil and other liquid hydrocarbons and its use of facilities for treating,
processing or otherwise handling hydrocarbons and wastes therefrom are subject
to stringent environmental regulation, and violations are subject to reporting
requirements, civil penalties and criminal sanctions. As with the industry
generally, compliance with existing regulations increases the Company's overall
cost of business. The increased costs are not reasonably ascertainable. Such
areas affected include unit production expenses primarily related to the control
and limitation of air emissions and the disposal of produced water, capital
costs to drill exploration and development wells resulting from expenses
primarily related to the management and disposal of drilling fluids and other
oil and natural gas exploration wastes and capital costs to construct, maintain
and upgrade equipment and facilities and plug and abandon inactive well sites
and pits.

Environmental regulations historically have been subject to frequent
change by regulatory authorities, and the Company is unable to predict the
ongoing cost of compliance with these laws and regulations or the future impact
of such regulations on its operations. However, the Company does not believe
that changes to these regulations will materially adversely affect the Company's
competitive position because its competitors are similarly affected. A discharge
of hydrocarbons or hazardous substances into the environment could subject the
Company to substantial expense, including both the cost to comply with
applicable regulations pertaining to the remediation of releases of hazardous
substances into the environment and claims by neighboring landowners and other
third parties for personal injury and property damage. The Company maintains
insurance, which may provide protection to some extent against environmental
liabilities, but the coverage of such insurance and the amount of protection
afforded thereby cannot be predicted with respect to any particular possible
environmental liability and may not be adequate to protect the Company from
substantial expense.

The OPA and regulations thereunder impose a variety of regulations on
"responsible parties" related to the prevention of oil spills and liability for
damages resulting from such spills in United States waters. A "responsible
party" includes the owner or operator of an onshore facility, vessel, or
pipeline, or the lessee or permittee of the area in which an offshore facility
is located. The OPA assigns liability to each responsible party for oil removal
costs and a variety of public and private damages. The FWPCA imposes
restrictions and strict controls regarding the discharge of produced waters and
other oil and natural gas wastes into navigable waters. State laws for the
control of water pollution also provide varying civil, criminal and
administrative penalties and impose liabilities in the case of a discharge of
petroleum or its derivatives, or other hazardous substances, into state waters.
In addition, the Environmental Protection Agency ("EPA") has promulgated
regulations that require many oil and natural gas production operations to
obtain permits to discharge storm water runoff.

The CAA requires or will require most industrial operations in the
United States to incur capital expenditures in order to meet air emission
control standards developed by the EPA and state environmental agencies.
Although no assurances can be given, the Company believes implementation of such
amendments will not have a material adverse effect on its financial condition or
results of operations. RCRA is the principal federal statute governing the
treatment, storage and disposal of hazardous wastes. RCRA imposes stringent
operating requirements (and liability for failure to meet such requirements) on
a person who is either a "generator" or "transporter" of hazardous waste or an
"owner" or "operator" of a hazardous waste treatment, storage or disposal
facility. At present, RCRA includes a statutory exemption that allows oil and
natural gas exploration and production wastes to be classified as non-hazardous
waste. As a result, the Company is not required to comply with a substantial
portion of RCRA's requirements because the Company's operations generate minimal
quantities of hazardous wastes.

12
<PAGE> 14

CERCLA, also known as "Superfund", imposes liability, without regard to
fault or the legality of the original act, on certain classes of persons that
contributed to the release of a "hazardous substance" into the environment.
These persons include the "owner" or "operator" of the site and companies that
disposed or arranged for the disposal of the hazardous substances found at the
site. CERCLA also authorizes the EPA and, in some instances, third parties to
act in response to threats to the public health or the environment and to seek
to recover from the responsible classes of persons the costs they incur. In the
course of its ordinary operations, the Company may generate waste that may fall
within CERCLA's definition of a "hazardous substance". As a result, the Company
may be jointly and severally liable under CERCLA or under analogous state laws
for all or part of the costs required to clean up sites at which such wastes
have been disposed. The Company currently owns or leases, and has in the past
owned or leased, numerous properties that for many years have been used for the
exploration and production of oil and natural gas. Although the Company has
utilized operating and disposal practices that were standard in the industry at
the time, hydrocarbons or other wastes may have been disposed of or released on
or under the properties owned or leased by the Company or on or under other
locations where such wastes have been taken for disposal. In addition, many of
these properties have been operated by third parties whose actions with respect
to the treatment and disposal or release of hydrocarbons or other wastes were
not under the Company's control. These properties and wastes disposed thereon
may be subject to CERCLA, RCRA and analogous state laws. Under such laws, the
Company could be required to remove or remediate previously disposed wastes
(including wastes disposed of or released by prior owners or operators), to
clean up contaminated property (including contaminated groundwater) or to
perform remedial plugging operations to prevent future contamination.

CAUTION AS TO FORWARD-LOOKING STATEMENTS

Statements contained in this Report and other materials filed or to be
filed by the Company with the Securities and Exchange Commission (as well as
information included in oral or other written statements made or to be made by
the Company or its representatives) that are forward-looking in nature are
intended to be "forward-looking statements" within the meaning of Section 27A of
the Securities Act of 1933, as amended, and Section 21E of the Securities
Exchange Act of 1934, as amended, relating to matters such as anticipated
operating and financial performance, business prospects, developments and
results of the 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, uncertainty of reserve estimates, rates and timing of future production
of oil and gas, exploratory and development activities, acquisition risks and
activities, changes in the level and timing of future costs and expenses related
to drilling and operating activities and those risks described under "Risk
Factors" below.

Words such as "anticipated," "expect," "estimate," "project" and
similar expressions are intended to identify forward-looking statements.
Forward-looking statements include the risks described in "Risk Factors".

RISK FACTORS

The Company cautions that the following risk factors could affect its
actual results in the future in addition to "Estimated Proved
Reserves--Uncertainties in Estimating Reserves and Future Net Cash Flows"
included elsewhere in this Report.

Substantial Leverage; Inability to Service Debt; Lack of Liquidity;
Substantial Capital Requirements. As of December 31, 1998, the Company had
$327.9 million principal amount of debt outstanding, stockholders' deficit of
approximately $66.9 million and cash on hand of approximately $8.4 million.
However, there can be no assurance that the Company will have sufficient funds
to make all of its future debt service payments. Further, there can be no
assurance that the Phillips transaction or the sale of the Notes will be
consummated. If the Company does not consummate the Phillips transaction or the
sale of the Notes, the Company may be unable to make its scheduled payments of
principal and interest in 1999 and 2000. If that occurs, the Company may be
required to refinance or restructure all or a portion of its indebtedness, to
sell assets and to reduce or delay planned capital expenditures.

13
<PAGE> 15

In the currently depressed oil and natural gas commodity price
environment, the Company has limited cash flow for capital expenditures. The
ability of the Company to service its debt levels and finance capital
expenditures depends significantly on various factors including an improved oil
and natural gas commodity price environment. If the Company sells the Notes, it
is not likely to have access to a revolving credit facility to supplement its
cash needs.

Following the Phillips and the Notes transactions, if consummated, the
Company would continue to have significant debt outstanding and will be subject
to various commodity and economic factors beyond its control that may have an
impact on its ability to exploit its exploration prospects.

The Company is dependent upon its ability to obtain financing for
acquiring, exploring and developing oil and natural gas properties beyond its
internally generated cash flow. Historically, the Company has financed these
activities primarily through the issuance of debt and equity securities, through
various credit facilities and with internally generated funds. The Company
currently has plans for substantial capital expenditures to continue its
development and exploration activities. The Company's ability to expend the
capital necessary to undertake or complete future activities may be limited. No
assurance can be given that the Company will have adequate funds available to it
to carry out its strategy. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Liquidity and Capital
Resources".

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. The Company's future oil and natural gas
reserves and production, and, therefore, cash flow and income, are highly
dependent upon the Company'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. The
Company'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. Oil
prices in general have been depressed since the first quarter of 1998 while
natural gas prices have fallen approximately 18% since November 1998. No
assurance can be given as to when and if either oil or natural gas price may
recover. The prices received by the Company for its oil, natural gas and natural
gas liquids production and the levels of such production are subject to
government regulation, legislation and policies. The Company's future financial
condition and results of operations will depend, in part, upon the prices
received for its oil and natural gas production, as well as the costs of
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 the Company'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. Although domestic drilling activity is currently at a
relatively low level, resulting in less demand for such services and a general
decrease in service costs, there can be no assurance that such market conditions
will continue.

The availability of a ready market for the Company's oil and natural
gas production also depends on a number of factors, including the demand for and
supply of oil and natural gas and the proximity of reserves to pipelines or
trucking and terminal facilities. Natural gas wells may be partially or totally
shut in for lack of a market or because of inadequacy or unavailability of
natural gas pipeline or gathering system capacity.

14
<PAGE> 16

The Company's oil and natural gas business also is subject to all of
the operating risks associated with the drilling for and production of oil and
natural gas, including, but not limited to, uncontrollable flows of oil, natural
gas, brine or well fluids into the environment (including groundwater and
shoreline contamination), blowouts, cratering, mechanical difficulties, fires,
explosions, pollution and other risks, any of which could result in substantial
losses to the Company. Although the Company maintains insurance at levels that
it believes are consistent with industry practices, it is not fully insured
against all risks. Losses and liabilities arising from uninsured and
underinsured events could have a material adverse effect on the financial
condition and operations of the Company.

ITEM 3. LEGAL PROCEEDINGS

The Company is involved in various claims and lawsuits incidental to
its business. In the opinion of management, the ultimate liability thereunder,
if any, will not have a material effect on the financial condition of the
Company.

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 1998.

15
<PAGE> 17

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
SmallCap Market under the symbols "KOGC" and "KOGCP." The price ranges presented
below represent high and low sale prices for each quarter, as reported by the
NASDAQ Stock Market. On October 16, 1998, the Company was moved from the NASDAQ
National Market to the NASDAQ SmallCap Market due to the Company's failure to
maintain the minimum per share price requirements. The Company has also received
notice from NASDAQ that it is not in compliance with the NASDAQ rule regarding
minimum stock price. If the Company's stock price does not trade at or above
$1.00/share for ten consecutive days prior to April 23, 1999, the Company's
stock is subject to delisting.

<TABLE>
<CAPTION>
KOGC COMMON STOCK KOGC PREFERRED STOCK
MARKET PRICES MARKET PRICES
-------------------------- ---------------------------
HIGH LOW HIGH LOW
---------- ---------- ---------- ---------
<S> <C> <C> <C> <C>
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 29/16 26 20 3/8
Fourth quarter.............. 3 1/4 27/16 25 23 3/4

1997:
First quarter .............. $ 3 1/16 $ 1 7/8 $ 25 3/4 $ 23 3/4
Second quarter.............. 3 1/16 11 1/16 26 22 1/2
Third quarter............... 3 1/4 2 3/16 26 7/8 24 1/4
Fourth quarter.............. 3 15/16 2 1/8 25 1/2 21 1/2

1998:
First quarter .............. $ 2 13/16 $ 1 3/4 $ 25 3/4 $ 20 3/4
Second quarter.............. 2 13/16 1 15/16 28 1/2 22
Third quarter............... 2 5/16 1 23 3/8 16
Fourth quarter.............. 1 5/8 15/32 16 1/2 8
</TABLE>

As of the January 31, 1999, there were approximately 1,495 record
holders of Common Stock and 120 record holders of Preferred Stock.

Dividends on the Preferred Stock accrue quarterly at the rate of
$.65625 per share. In January 1996, the Company announced the suspension of
dividend payments on the Preferred Stock to conserve cash. On April 15, 1997,
the Board of Directors of the Company declared a dividend of $2.625 per
preferred share (approximately $4.6 million), which was paid on May 1, 1997. On
April 14, 1998, the Company declared a dividend of $2.625 per share of Preferred
Stock (approximately $4.6 million), which was paid on April 30, 1998. The
Company's existing credit facility and the Company's indenture governing its 10
3/8% Senior Subordinated Notes (the "10 3/8% Notes") restrict the payment of
future preferred dividends. As of February 1, 1999, the total amount of dividend
payments in arrears was approximately $5.7 million, covering five quarters.
Should the Company not pay dividends on the Preferred Stock for a period of six
quarters, the holders of Preferred Stock, as a group, have the right to elect
two additional directors to the Company's Board of Directors.

16
<PAGE> 18

ITEM 6. SELECTED FINANCIAL DATA

The following tables present selected financial data for the Company
that is derived from the audited consolidated financial statements of the
Company. The historical financial information for the year ended December 31,
1995 reflects the Consolidation in February 1995. Prior to the Consolidation,
the financial information reflects Kelley Oil's historical results of
Operations. The impact of the acquisition of the SPR Properties is reflected in
the selected financial data as of December 1, 1997. 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.

KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------
1994 1995 1996 1997 1998
--------- --------- ---------- -------- ---------

<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Oil and gas revenues.............................. $ 16,822 $ 36,998 $ 60,854 $ 75,864 $ 79,150
Interest and other income......................... 1,416 1,763 1,429 274 505
--------- --------- ---------- -------- ---------
Total revenues .............................. 18,238 38,761 62,283 76,138 79,655
--------- --------- ---------- -------- ---------
Production expenses............................... 3,760 10,835 10,709 10,955 19,878
Exploration expenses.............................. 7,404 23,387 5,438 5,433 12,034
General and administrative expenses............... 5,172 7,030 8,953 6,875 7,077
Interest and other debt expenses.................. 4,571 21,956 24,401 25,071 33,333
Restructuring expenses............................ 1,814 1,115 4,276 -- --
Depreciation, depletion and amortization.......... 20,474 35,591 20,440 25,853 38,602
Impairment of oil and gas properties(1)........... -- 150,138 -- -- 25,738
--------- --------- ---------- -------- ---------
Income (loss) before income taxes and
extraordinary item............................. (24,957) (211,291) (11,934) 1,951 (57,007)
Provision for taxes............................... -- -- -- -- --
--------- --------- ---------- -------- ---------
Net income (loss) before extraordinary item....... (24,957) (211,291) (11,934) 1,951 (57,007)
Extraordinary loss(2)............................. -- -- (17,030) -- --
--------- --------- ---------- -------- ---------
Net income (loss)................................. $ (24,957) $(211,291) $ (28,964) $ 1,951 $ (57,007)
========= ========= ========== ======== =========
Basic and diluted loss per common share
before extraordinary item(3) .................. $ (1.58) $ (5.31) $ (.18) $ (.03) $ (.49)
Basic and diluted loss per common share(3)........ $ (1.58) $ (5.31) $ (.37) $ (.03) $ (.49)
Weighted average common shares outstanding........ 17,653 41,032 90,113 100,757 125,783
</TABLE>

<TABLE>
<CAPTION>
AS OF DECEMBER 31,
---------------------------------------------------------------
1994 1995 1996 1997 1998
--------- --------- -------- -------- ---------
<S> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Property and equipment, net.................... $ 74,912 $ 128,642 $158,468 $293,613 $ 256,455
Long term debt, excluding current maturities... 37,242 164,980 184,253 286,183 287,500
Stockholders' equity (deficit)................. 45,180 (45,568) (30,535) (5,621) (66,939)
Total assets................................... 106,513 151,342 189,227 322,602 286,197
</TABLE>

- -----------------------
(1) Reflects noncash impairment charges against the carrying value of
proved and unproved properties under SFAS 121. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and "Notes to
Consolidated Financial Statements."
(2) Incurred in connection with the refinancing of the 13 1/2% Senior Notes
and represents the excess of the aggregate purchase price of the 13 1/2% Senior
Notes (including consent payments) over their carrying value as of the date the
refinancing was consummated.
(3) Dividends on the Company's cumulative preferred stock are deducted from
"Net Income (Loss) Before Extraordinary Item" and "Net Income (Loss)" in
calculating related per share amounts, whether or not declared, and amounted to
$2.9 million, $6.6 million, $4.6 million, $4.6 million and $4.6 million for the
years ended December 31, 1994, 1995, 1996, 1997 and 1998, respectively.

17
<PAGE> 19

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 Oil & Gas Corporation and its consolidated
subsidiaries (the "Company") are engaged in oil and natural gas exploration,
development, production and acquisition. The Company's 1998 operational
activities were focused primarily on exploiting its north Louisiana properties
and exploration activities on its south Louisiana acreage. In 1998, the Company
drilled or participated in drilling 47 gross (21.2 net) development wells and 15
gross (5.8 net) exploratory wells of which 46 gross (20.7 net) and 8 gross (2.5
net), respectively, were completed as producing wells. The Company's most
significant event was the drilling of the Harry S. Bourg #1 discovery well in
Terrebonne Parish, Louisiana which added 21.4 bcfe of proved reserves to the
Company's reserve base at year-end. The Company has a 50% working interest in
this well.

General Conditions of the Oil and Natural Gas Industry and Commodity
Prices. The prices of oil and natural gas during recent months have fallen
sharply and continue to reflect the volatility of commodity prices and the
industry generally. The Company cannot predict future prices of oil and natural
gas. Current low prices, if they continue, could adversely impact the Company's
results of operations and liquidity. The success of the Company is in part
dependent on factors outside the control of the Company, but which directly
affect the financial condition of the Company, including capital market
conditions and highly volatile oil and natural gas prices. Due to recent
industry conditions, the Company, as others within the industry, has been
required to reconsider its capital expenditures budgets, which could adversely
impact production levels, and to evaluate various financing and strategic
alternatives.

Hedging Activities. The Company periodically uses forward sales
contracts, natural gas price swap agreements, natural gas basis swap agreements
and options to reduce exposure to downward price fluctuations on its natural gas
production. The Company does not engage in speculative transactions. During
1998, the Company used price and basis swap agreements. Price swap agreements
generally provide for the Company to receive or make counterparty payments on
the differential between a fixed price and a variable indexed price for natural
gas. Basis swap agreements generally provide for the Company to receive or make
counterparty payments on the differential between a variable indexed price and
the price it receives from the sale of natural gas production, and are used to
hedge against unfavorable price movements in the relationship between such
variable indexed price and the price received for such production. Gains and
losses realized by the Company from hedging activities are included in oil and
gas revenues and average sales prices in the period that the related production
is sold. The Company's hedging activities also cover the oil and gas production
attributable to the interest in such production of the public unitholders in its
subsidiary partnerships.

Through natural gas price swap agreements, the Company hedged
approximately 49% of its natural gas production for 1998 at an average NYMEX
quoted price of $2.31 per Mmbtu before transaction and transportation costs. As
of December 31, 1998, 5,400,000 Mmbtu's of natural gas production for 1999 has
been hedged by natural gas price swap agreements at an average NYMEX quoted
price of $2.36 per Mmbtu before transaction and transportation costs. Additional
hedging activities since December 31, 1998 have increased the volumes hedged in
1999 to 10,720,000 Mmbtu of natural gas at an average NYMEX quoted price of
$2.15 per Mmbtu before transaction and transportation costs. As of December 31,
1998, 16,380,000 Mmbtu's of natural gas production for 1999 has been hedged by
natural gas basis swap agreements. Hedging activities increased revenues by
approximately $3.5 million in 1998 as compared to estimated revenues had no
hedging activities been conducted. At December 31, 1998, the unrealized gain on
the Company's existing hedging instruments for future production months in 1999
approximated $2.5 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.

18
<PAGE> 20

RESULTS OF OPERATIONS

Years Ended December 31, 1998 and 1997. The Company's oil and gas
revenues of $79.2 million for 1998 increased 4% compared to $75.9 million in
1997 primarily as a result of an increase in gas production 18%, partially
offset by lower oil prices (32%) and gas prices (8%). The increase in gas
production is primarily due to the Company's SPR acquisition and drilling
activities in north Louisiana.

Interest and other income increased from $0.3 million in 1997 to $0.5
million in 1998 primarily due to business interruption insurance proceeds
related to hurricane disruptions on offshore properties.

Production expenses for 1998 increased 81% to $19.9 million from $11.0
million in the prior year, resulting primarily from the SPR properties acquired
during the fourth quarter of 1997 and higher current period workover expenses.
Higher-cost production from the Gulf of Mexico properties acquired in the SPR
acquisition contributed to a 78% increase in lifting costs (production expenses
less ad valorem and severance taxes) per Mcfe to $.41 in 1998 as compared to
$0.23 in 1997.

Exploration expenses increased 122% from $5.4 million in 1997 to $12.0
million in 1998 due to increased dry hole, seismic and unproved property
abandonment expenses and higher overhead allocated to exploration activities.

General and administrative expenses of $7.1 million in 1998 increased
3% compared to $6.9 million last year. On a unit of production basis, general
and administrative expenses were $0.19 per Mcfe in 1998 compared to $0.22 per
Mcfe in 1997.

Interest and other debt expenses of $33.3 million in 1998 increased 33%
from $25.1 million in 1997. The increase in interest expense resulted primarily
from higher average debt levels during the current period due to increased
borrowings under the Credit Facility and issuance of the Series C Notes. In
addition to its 1998 interest expense of $28.1 million, the Company recorded
non-cash charges in 1998 of $2.2 million for amortization of debt issuance
costs, $1.0 million for accretion of note discount and $2.0 million for
accretion of debt valuation discount.

Depreciation, depletion and amortization ("DD&A") expense increased 49%
from $25.9 million in 1997 to $38.6 million in 1998, as a result of higher 1998
production levels and an increase in the units-of-production DD&A rate for oil
and gas activities from $0.80 per Mcfe in 1997 to $1.01 in 1998.

In 1998, under Statement of Financial Accounting Standards No. 121
("SFAS 121"), "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of", the Company recognized noncash impairment
charges of $25.7 million against the carrying values of its proved and unproved
oil and gas properties, aggregating $21.6 million and $4.1 million,
respectively, for the year ended December 31, 1998 (see "Property Impairment
under SFAS No. 121" in the "Notes to Consolidated Financial Statements").

The Company recognized a net loss of $(57.0) million in 1998 and net
income of $2.0 million in the prior year. The reasons for the earnings changes
are described in the foregoing discussion.

Years Ended December 31, 1997 and 1996. The Company's oil and gas
revenues of $75.9 million for 1997 increased 25% compared to $60.9 million in
1996 primarily as a result of an increase in gas production (29%), partially
offset by lower oil prices (13%) and gas prices (1%). The increase in gas
production is primarily due to the Company's drilling activities in north
Louisiana and the addition of one month of production from the SPR properties
partially offset by the sale of one-half of its interest in 23 wells and related
facilities in the Houma Embayment in Terrebonne Parish, Louisiana in the fourth
quarter of 1996.

Interest and other income decreased 79% from $1.4 million in 1996 to
$0.3 million in 1997 primarily due to higher 1996 interest income resulting from
invested funds received from the sale of common stock in February 1996 and gains
on the sale of assets recognized in 1996.

19
<PAGE> 21

Production expenses for 1997 increased 3% to $11.0 million from $10.7
million in the prior year, primarily reflecting higher overall production
levels. On a unit basis, lifting costs (production expenses less ad valorem and
severance taxes) decreased to $0.23 per Mcfe in 1997 compared to $0.31 per Mcfe
in 1996, primarily reflecting lower average costs on north Louisiana production,
which is increasing in proportion to other higher cost production.

Exploration expenses remained constant from 1996 to 1997 at $5.4
million. Increased dry hole expenses were offset by a reduction in lease rental
expense reflecting the joint exploration agreement effective December 1996 in
south Louisiana with Williams.

General and administrative expenses of $6.9 million in 1997 decreased
23% compared to $9.0 million in 1996, reflecting efficiencies obtained in the
realignment of the workforce. This decrease is somewhat offset by a reduction in
1997 in the level of general and administrative expenses either being
capitalized or allocated to exploration expense. One a unit basis, general and
administrative expenses were $0.22 per Mcfe in 1997 compared to $0.36 per Mcfe
in 1996.

Interest and other debt expenses of $25.1 million in 1997 increased 3%
from $24.4 million in 1996. The increase in interest expense resulted primarily
from higher average debt levels during the current period and the payment of
interest associated with the settlement of a lawsuit. These were partially
offset by lower interest rates under the 10 3/8% Senior Subordinated Notes than
under the 13 1/2% Senior Notes retired in October 1996, and lower debt
amortization expenses as a result of the refinancing of the 13 1/2% Senior Notes
and the bank credit facility. See "Liquidity and Capital Resources." In addition
to its 1997 interest expense of $20.9 million, the Company recorded non-cash
charges in 1997 of $1.3 million for amortization of debt issuance costs, $0.9
million for accretion of note discount and $2.0 million for accretion of debt
valuation discount.

Restructuring expense in 1996 was $4.3 million. There was no
restructuring expense in 1997.

Depreciation, depletion and amortization ("DD&A") expense increased 27%
from $20.4 million in 1996 to $25.9 million in 1997, primarily as a result of
higher 1997 production levels. The units-of-production DD&A rate for oil and gas
activities was $0.80 per Mcfe in both 1996 and 1997.

The Company recognized net income of $2.0 million in 1997 and a net
loss before extraordinary item of $(11.9) million in the prior year. The reasons
for the earnings improvement are described in the foregoing discussion.

LIQUIDITY AND CAPITAL RESOURCES

General. The Company had $327.9 million principal amount of debt
outstanding as of December 31, 1998 ($320 million recorded on the balance
sheet), requiring approximately $29.1 million in annual cash interest payments.
In addition, dividends on the Company's preferred stock accrue quarterly at a
rate of $0.65625 per share. On April 14, 1998, the Board of Directors of the
Company declared a dividend on the Company's preferred stock of $2.625 per share
(approximately $4.6 million), which was paid on April 30, 1998. The Company has
not declared the quarterly dividends of $0.65625 for five quarters including
February 1, 1999 aggregating approximately $5.7 million. Future dividends are
restricted under both the Company existing Credit Facility and the indenture for
the 10 3/8% Senior Subordinated Notes. However, the Company's outstanding
preferred stock is cumulative, requires dividends to accumulate currently at the
rate of $4.6 million annually and carries liquidation preferences over the
Common Stock totaling $48.6 million at December 31, 1998, including such
dividend arrearages. Furthermore, should the Company not pay dividends on the
preferred stock for a period of six quarters the holders of preferred stock, as
a group, have the right to elect two additional directors to the Company's Board
of Directors.

20
<PAGE> 22

Facility debt covenants at December 31, 1998, the Company was not in compliance
as of March 31, 1999, which could result in all borrowings under such Credit
Facility being declared immediately due and payable and the Credit Facility
being terminated and the payment of other subordinated obligations being
accelerated. In addition other long-term debt repayments of $34.1 million are
scheduled to be made in December 1999. These uncertainties create substantial
doubt about the Company's ability to continue its operations as a going
concern. To address these liquidity issues, the Company is attempting to take
the measures discussed in the following paragraphs.

While industry conditions cannot be predicted with certainty and are
dependent upon a number of commodity and economic factors beyond its control,
the Company believes the net cash proceeds from the Phillips transaction and
issuance of the Notes, if consummated, in conjunction with cash on hand and cash
flow from operations will be sufficient to provide adequate working capital
and fund its capital expenditure program during 1999. However, the Company
will continue to have significant debt outstanding and industry conditions
beyond its control may adversely affect its results of operations and
financial condition.

Liquidity. Net cash provided by operating activities, before working
capital adjustments, during 1998 aggregated $24.6 million. Funds used in
investing activities were comprised of capital expenditures of $56.6 million
partially offset by property sales of $17.4 million. Funds provided by financing
activities were comprised of net borrowing repayments of $0.2 million, proceeds
from the sale of notes of $29.5 million and payment of preferred dividends of
$4.6 million. Cash equivalents increased from $0.2 million at December 31, 1997
to $8.4 million as of December 31, 1998. As of December 31, 1998, the Company
had a working capital deficit of $37.4 million, compared to a working capital
deficit of $15.2 million at the end of 1997. The increased deficit is primarily
a result of the reclassification of the 7 7/8% bonds, which are redeemable on
December 15, 1999, to current portion of long-term debt.

21
<PAGE> 23

The following table sets forth on an unaudited basis net cash provided
by operating activities before working capital adjustments, net cash used in
investing activities and EBITDAX.

(IN THOUSANDS)

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------
1996 1997 1998
--------- --------- --------

<S> <C> <C> <C>
Net cash provided by operating activities before
working capital adjustments..................................... $ 23,214 $ 37,534 $ 24,603
Net cash used in investing activities.............................. (53,392) (164,275) (39,216)
EBITDAX(1)......................................................... 42,621 58,308 52,700
</TABLE>

(1) EBITDAX is calculated as net income (loss) before extraordinary items,
excluding interest expense and other debt expenses, income taxes, exploration
expenses, restructuring expense, depletion, depreciation, amortization, and
impairment of oil and gas properties. EBITDAX is not a measure of cash flow as
determined by generally accepted accounting principles ("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 the Company's operating performance or liquidity. EBITDAX is
not necessarily comparable to a similarly titled measure of another company.

On July 24, 1998, the Company sold, effective June 1, 1998, its entire
interest in the Waskom field in Harrison County, Texas for total consideration
of $17.4 million (before purchase price adjustment). These non-core assets were
acquired by the Company in the December 1997 asset purchase from SPR. The
properties were producing approximately 4.5 million cubic feet equivalent per
day. See Capital Resources.

Capital Resources. The Company's bank credit facility provides for a
maximum $140.0 million revolving credit loan and matures, with all amounts owed
thereunder becoming due and payable on December 1, 2000 (the "Credit Facility").
Availability under the Credit Facility is limited to a borrowing base (the
"Borrowing Base") determined by, among other things, the proved oil and natural
gas reserves and other assets of the borrowers and the value of those reserves
based on the underlying prices for oil and natural gas. The Borrowing Base is
redetermined at least semiannually by the agent under the Credit Facility, with
the consent of 100% of the lenders, and may be redetermined more frequently at
the election of the lenders or the borrowers. On April 14, 1998, the Borrowing
Base was set at $138 million and the threshold amount (the "Threshold Amount"),
which is the amount that would ordinarily be made available by the lenders to a
similar borrower under a borrowing base, was set at $125 million. Following the
Company's sale of its interest in the Waskom field in July, 1998, the Borrowing
Base and Threshold Amount were reduced to $130 million and $117 million,
respectively. As provided in the Credit Facility, on November 1, 1998 the
Borrowing Base was reduced to equal the Threshold Amount of $117 million.

On December 29, 1998, the Borrowing Base under the Credit Facility was
maintained at $117 million and certain terms were amended, including (i) an
increase in the margin borrowing rate to 250 basis points over LIBOR, (ii) a
reduction in the grace periods available under certain default provisions, (iii)
a change in the definition of majority banks for purposes of setting the
semi-annual Borrowing Base and implementing other provisions from 75% to 100%
and (iv) a reduction in the time allowed to cure a Borrowing Base deficiency.

At December 31, 1998, $111.5 million of borrowings and $1.5 million of
letters of credit were outstanding under the Credit Facility. The Company's
typical monthly cash flow cycle is such that the Company usually receives a
substantial portion of its proceeds from operations near the end of each month.
Accordingly, outstanding balances under the Credit Facility may be higher on any
given day during the month than at the end of the month.

As provided in the Credit Facility, a review of the Borrowing Base is
scheduled to be performed by the Company's banks by May 1, 1999. While the
amount of the Borrowing Base will not be known until such time as the banks make
the redetermination, the Company has been advised that the redetermination
likely will result in the Borrowing Base being lowered. If the Borrowing Base
were to be lowered below the level of outstanding advances,

22
<PAGE> 24

the Company would be required to repay 100% of the excess within thirty days.
Further, no additional borrowings would be available to the Company under the
Credit Facility until amounts outstanding are less than the Borrowing Base.

Further, under the current terms of the Credit Facility, certain of the
Company's financial covenants thereunder become more restrictive in future
periods. Specifically, the interest coverage ratio increases from 2.0/1 to
2.25/1 beginning with the rolling four quarters ended March 31, 1999. The
Company was not in compliance with this covenant under the Credit Facility as of
March 31, 1999. If the Company is not successful in either finding alternative
financing or negotiating a waiver of such noncompliance, all borrowings under
the Credit Facility could be declared immediately due and payable, the Credit
Facility being terminated and the payment of other subordinated obligations
being accelerated. The indebtedness under the Credit Facility is secured by
substantially all of the oil and natural gas assets of the Company.

Included in the outstanding debt at December 31, 1998 was $30.0 million
principal amount of the Company's Series C Notes issued in May 1998 at a cash
price of $1,015 per $1,000 principal amount. The net proceeds received were used
to reduce outstanding borrowings under the Credit Facility. See Note 3 - Long
Term Debt in the Notes to Consolidated Financial Statements contained in this
Report for further discussion. The Series C Notes were sold pursuant to Rule
144A of the Securities Act of 1933. The Company has registered under the
Securities Act, notes identical in terms to the Series C Notes ("Series D
Notes") and completed the exchange of the Series C Notes for the Series D Notes
on November 12, 1998.

In addition to long-term debt requiring principal payments of $34.6
million in December 1999, the Company has long-term debt obligations in the
aggregate principal amounts at maturity of $26.9 million maturing in April 2000.
The Company anticipates that it will meet this obligation with net proceeds form
oil and natural gas property sales. The Company can provide no assurance that
such property sales will be completed or that, if completed, will provide
sufficient proceeds to repay this outstanding long term debt.

Capital Commitments. The Company's 1999 capital expenditure budget
provides for $10.0 million to be expended on development drilling primarily in
north Louisiana and on the Bayou Sauveur field (Bourg prospect) in south
Louisiana and $5.0 million to be expended on exploratory prospects primarily in
south Louisiana and the shallow waters of the Gulf of Mexico. However, the
Company's ability to fund its 1999 capital expenditure budget will depend on the
actual amount of cash flow from operations and proceeds from oil and gas
property sales.

During 1998, the Company participated in drilling 62 gross (26.93 net)
wells, of which 54 gross (23.25 net) wells were completed. The 1998 drilling
performance reflects lower risk operations in north Louisiana and past
exploratory successes in south Louisiana. The Company, with its partners,
continues exploration activities in south Louisiana. As of December 31, 1998,
the Company was participating in the drilling or completing of 2 gross (0.84
net) wells.

23
<PAGE> 25

Year 2000. The Company has instigated reviews and evaluations in
response to Year 2000 issues. These issues involve the potential disruption to
systems, processes, and business practices that may occur if system hardware and
software utilized by the Company, its vendors, and customers are unable to
process year 2000 data. The planning phase is completed and the Company is
nearing completion of internal corrective measures.

The Company is working closely with its information systems and
technology vendors to install updated software, where appropriate, that will be
Year 2000 compliant. Currently, more than 90% of the critical Year 2000 internal
systems issues have been tested and corrected. The remainder are expected to be
installed and tested by the end of the third quarter of 1999.

The Company has identified those vendors and others that it believes
provide material services or are vital to its business. Discussions with these
companies to determine their Year 2000 readiness are expected to be completed in
the second quarter 1999. By mid-year 1999 the Company plans to have completed
its Year 2000 review and implemented necessary corrective measures.

The cost of reviewing and implementing corrective measures for Year
2000 issues to date has not been material to the Company and has been limited to
use of Company and vendor personnel for review and implementation of corrective
measures. The Company expects the remainder of the Year 2000 review and
corrective measures to not involve significant costs.

Based on assessments to date and compliance plans in progress, nothing
has come to the attention of management to cause it to believe that Year 2000
issues, including the cost of implementing corrective measures, will have an
adverse material impact on the business or operations of the Company.
Nevertheless, as indicated above, achieving Year 2000 readiness is subject to
risk and uncertainties, especially regarding third parties, and there can be no
assurance the Company will not be adversely affected by Year 2000 issues.

The foregoing statements are intended to be and are hereby designated
"Year 2000 Readiness Disclosures" within the meaning of the Year 2000
Information and Readiness Act.

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 natural gas prices (including the
effects of hedging) received by the Company during the periods indicated.

<TABLE>
<CAPTION>
AVERAGE AVERAGE
OIL PRICE GAS PRICE
($/BBL) ($/MCF)
--------- ---------
<S> <C> <C>
YEAR ENDED:
December 31, 1998 ........................................................... $ 13.09 $ 2.09
December 31, 1997............................................................ 19.34 2.27
December 31, 1996............................................................ 22.11 2.30
</TABLE>

24
<PAGE> 26

ITEM 7A. MARKET RISK DISCLOSURE

The Company is exposed to market risk from changes in interest rates
and commodity prices. The Company uses its Credit Facility and Senior and
Subordinated debt instruments to finance a significant portion of its
operations. The Company's exposure to market risk for interest rate changes
relates to its Credit Facility variable rate debt. In the normal course of
business the Company enters into hedging transactions, including natural gas
price and basis swap agreements, to mitigate its exposure to commodity price
movements, but not for trading or speculative purposes. In 1998, the Company
used price and basis swap agreements to reduce exposure to downward price
fluctuations for its natural gas production. For debt obligations the table
below presents principal cash flows and weighted average interest rates by year
of maturity. For natural gas price and basis swap agreements, the table presents
notional amounts in Mmbtu's and weighted average prices for contracts in place
at December 31, 1998. The information presented below should be read in
conjunction with Note 4 and Note 10 to the Consolidated Financial Statements
(amounts in thousands otherwise indicated).

<TABLE>
<CAPTION>
MATURITY DATE
----------------------------------------------------- FAIR VALUE
1999 2000 2001 2002 2003 THEREAFTER TOTAL @ 12/31/98
--------- --------- --------- --------- -------- ---------- ---------- ----------

<S> <C> <C> <C> <C> <C> <C> <C> <C>
Variable Debt:
Credit Facility
(Maturity) 7.03%(1)....... $ 111,500 $ 111,500 $ 111,500

Fixed Debt:
13.50% (Maturity)......... $ 435 435 431
7.88% (Maturity).......... 34,147 34,147 15,366
8.50% (Maturity).......... 26,856 26,856 12,085
10.38% (Maturity)......... $ 155,000 155,000 111,600
---------- --------- --------- --------- ---------
Total Maturity............... $ 34,582 $ 138,356 $ 155,000 $ 327,938 $ 250,982
========== ========= ========= ========= =========
Blended weighted
average interest rate..... 7.95% 8.5% 10.38%

Commodity price
derivatives:
Price swaps:
Notional amounts
(Mmbtu's) ............. 5,400,000
Weighted average price..... $ 2.36
Fair value at 12/31/98(2).. $ 2,506

Basis swaps:
Notional amounts
(Mmbtu's) ............. 16,380,000
Margin differential(3)..... $ (0.01)
Fair value at 12/31/98(2).. $ (142)
</TABLE>

(1) Reflects the weighted average interest rate on borrowings outstanding at
December 31, 1998.
(2) Represents estimated amounts to settle the contracts at December 31, 1998.
(3) Estimated weighted average margin differential at December 31, 1998.

25
<PAGE> 27

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES: PAGE
----

<S> <C>
Independent Auditors' Report.............................................................................. 27
Consolidated Balance Sheets - December 31, 1997 and 1998.................................................. 28
Consolidated Statements of Income (Loss) - For the years ended December 31, 1996, 1997 and 1998........... 29
Consolidated Statements of Cash Flows - For the years ended December 31, 1996, 1997 and 1998.............. 30
Consolidated Statements of Changes in Stockholders' Deficit - For the years ended
December 31, 1996, 1997 and 1998........................................................................ 31
Notes to Consolidated Financial Statements................................................................ 32
</TABLE>

26
<PAGE> 28

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 (the "Company") as of December 31, 1997
and 1998, and the related consolidated statements of income (loss), cash flows,
and changes in stockholders' deficit for each of the three years in the period
ended December 31, 1998. These financial statements are the responsibility of
the Corporation's management. Our responsibility is to express an opinion on
these financial statements based on our audits.

We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly,
in all material respects, the financial position of Kelley Oil & Gas Corporation
and subsidiaries as of December 31, 1997 and 1998, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1998, in conformity with generally accepted accounting principles.

The accompanying consolidated financial statements for the year ended
December 31, 1998 have been prepared assuming that the Company will continue as
a going concern. As discussed in Note 1 to the financial statements, the
Company's liquidity issues and difficulties in meeting certain loan agreement
covenants raise substantial doubt about its ability to continue as a going
concern. Management's plans concerning these matters are also described in Note
1. The financial statements do not include any adjustments that might result
from the outcome of this uncertainty.

DELOITTE & TOUCHE LLP

Houston, Texas
April 13, 1999

27
<PAGE> 29

KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

(IN THOUSANDS, EXCEPT SHARE DATA)

<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------
1997 1998
--------- ---------

<S> <C> <C>
ASSETS:
Cash and cash equivalents ............................................................. $ 162 $ 8,435
Accounts receivable ................................................................... 24,566 18,071
Accounts receivable - drilling programs ............................................... 718 624
Prepaid expenses and other current assets ............................................. 1,412 1,121
--------- ---------
Total current assets ................................................................ 26,858 28,251
--------- ---------
Oil and gas properties, successful efforts method:
Unproved properties, net ............................................................ 49,854 38,293
Properties subject to amortization .................................................. 463,263 496,686
Pipelines and other transportation assets, at cost .................................... 4,690 1,582
Furniture, fixtures and equipment ..................................................... 2,969 3,554
--------- ---------
520,776 540,115
Less: Accumulated depreciation, depletion and amortization ........................... (227,163) (283,660)
--------- ---------
Total property and equipment, net ................................................... 293,613 256,455
Other non-current assets, net ......................................................... 2,131 1,491
--------- ---------
Total assets ........................................................................ $ 322,602 $ 286,197
========= =========

LIABILITIES:
Accounts payable and accrued expenses ................................................. $ 41,474 $ 33,113
Accounts payable - drilling programs .................................................. 566 272
Current portion of long-term debt ..................................................... -- 32,251
--------- ---------
Total current liabilities ........................................................... 42,040 65,636
--------- ---------
Long term debt ........................................................................ 286,183 287,500
--------- ---------
Total liabilities ................................................................... 328,223 353,136
--------- ---------

COMMITMENTS AND CONTINGENCIES

STOCKHOLDERS' DEFICIT:
Preferred stock, $1.50 par value, 20,000,000 shares authorized at December
31, 1997 and 1998; 1,745,443 and 1,733,628 shares issued and outstanding at
December 31, 1997 and 1998, respectively
(liquidation value $48,977 and $48,633, respectively) ............................... 2,618 2,600
Common stock, $.01 par value, 200,000,000 shares authorized at December 31,
1997 and 1998; 125,709,093 and 126,022,235 shares issued and outstanding at
December 31, 1997 and 1998, respectively ............................................ 1,257 1,260
Additional paid-in capital ............................................................ 300,367 300,653
Accumulated deficit ................................................................... (309,863) (371,452)
--------- ---------
Total stockholders' deficit ......................................................... (5,621) (66,939)
--------- ---------
Total liabilities and stockholders' deficit ......................................... $ 322,602 $ 286,197
========= =========
</TABLE>

See Notes to Consolidated Financial Statements.

28
<PAGE> 30

KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (LOSS)

(IN THOUSANDS, EXCEPT PER SHARE DATA)

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------
1996 1997 1998
--------- --------- ---------

<S> <C> <C> <C>
REVENUES:
Oil and gas revenues ................................................... $ 60,854 $ 75,864 $ 79,150
Interest and other income .............................................. 1,429 274 505
--------- --------- ---------
Total revenues ......................................................... 62,283 76,138 79,655
--------- --------- ---------

COSTS AND EXPENSES:
Production expenses .................................................... 10,709 10,955 19,878
Exploration expenses ................................................... 5,438 5,433 12,034
General and administrative expenses .................................... 8,953 6,875 7,077
Interest and other debt expenses ....................................... 24,401 25,071 33,333
Restructuring expenses ................................................. 4,276 -- --
Depreciation, depletion and amortization ............................... 20,440 25,853 38,602
Impairment of oil and gas properties ................................... -- -- 25,738
--------- --------- ---------
Total expenses ......................................................... 74,217 74,187 136,662
--------- --------- ---------

Income (loss) before income taxes and extraordinary item .................. (11,934) 1,951 (57,007)
Income taxes ........................................................... -- -- --
--------- --------- ---------
Net income (loss) before extraordinary item ............................... (11,934) 1,951 (57,007)
Extraordinary item ..................................................... (17,030) -- --
--------- --------- ---------
Net income (loss) ......................................................... (28,964) 1,951 (57,007)
Less: cumulative preferred stock dividends ............................. (4,582) (4,582) (4,550)
--------- --------- ---------
Net loss applicable to common stock ....................................... $ (33,546) $ (2,631) $ (61,557)
========= ========= =========

Basic and diluted loss per common share before extraordinary item ......... $ (.18) $ (.03) $ (0.49)
========= ========= =========

Basic and diluted loss per common share ................................... $ (.37) $ (.03) $ (0.49)
========= ========= =========

Weighted average common shares outstanding ................................ 90,113 100,757 125,783
========= ========= =========
</TABLE>

See Notes to Consolidated Financial Statements.

29
<PAGE> 31

KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

(IN THOUSANDS)

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------
1996 1997 1998
--------- --------- ---------

<S> <C> <C> <C>
OPERATING ACTIVITIES:
Net income (loss) ...................................................... $ (28,964) $ 1,951 $ (57,007)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation, depletion and amortization ............................. 20,440 25,853 38,602
Impairment of oil and gas properties ................................. -- -- 25,738
Gain on sale of properties ........................................... (176) -- --
Exploration expenses ................................................. 5,438 5,433 12,034
Accretion and amortization of other debt expenses .................... 5,170 4,297 5,236
Restructuring expenses ............................................... 4,276 -- --
Extraordinary loss ................................................... 17,030 -- --
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable
and other current assets ........................................... (9,054) (1,297) 6,880
Increase in other non-current assets ................................. (1,945) (1,203) (526)
Increase (decrease) in accounts payable and accrued expenses ......... (2,953) 4,570 (8,655)
--------- --------- ---------
Net cash provided by operating activities .............................. 9,262 39,604 22,302
--------- --------- ---------

INVESTING ACTIVITIES:
Capital expenditures ................................................... (47,601) (53,140) (56,579)
Acquisition of oil and gas properties .................................. (11,594) (111,135) --
Proceeds from sale of properties ....................................... 5,803 -- 17,363
--------- --------- ---------
Net cash used in investing activities .................................. (53,392) (164,275) (39,216)
--------- --------- ---------

FINANCING ACTIVITIES:
Proceeds from long term borrowings ..................................... 50,000 180,500 119,100
Principal payments on long term borrowings ............................. (58,500) (82,700) (118,900)
Proceeds from sale of notes, net ....................................... 120,938 -- 29,526
Debenture conversion costs ............................................. (1,100) -- --
Proceeds from sale of common stock, net ................................ 43,998 27,545 273
Proceeds from conversion of preferred stock ............................ -- -- (2)
Retirement of notes .................................................... (113,488) -- (228)
Dividends on preferred stock ........................................... -- (4,582) (4,582)
--------- --------- ---------
Net cash provided by financing activities .............................. 41,848 120,763 25,187
--------- --------- ---------
(Decrease) increase in cash and cash equivalents .......................... (2,282) (3,908) 8,273
Cash and cash equivalents, beginning of period ............................ 6,352 4,070 162
--------- --------- ---------
Cash and cash equivalents, end of period .................................. $ 4,070 $ 162 $ 8,435
========= ========= =========
</TABLE>

See Notes to Consolidated Financial Statements.

30
<PAGE> 32

KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' DEFICIT

(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

<TABLE>
<CAPTION>
ADDITIONAL
PREFERRED COMMON PAID IN ACCUMULATED
STOCK STOCK CAPITAL DEFICIT
--------- --------- ---------- -----------

<S> <C> <C> <C> <C>
Stockholders' deficit at January 1, 1996 ........................ $ 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 pursuant to
employee incentive stock options ............................. -- -- 62 --
Syndication costs ............................................... -- -- (4,065) --
Net loss ........................................................ -- -- -- (28,964)
------- --------- --------- ---------
BALANCE AT DECEMBER 31, 1996 ................................. 2,618 983 273,096 (307,232)
------- --------- --------- ---------

Issuance of 27,000 shares of common stock in
Contour Transaction .......................................... -- 270 26,730 --
Issuance of 415 shares of common stock pursuant to
employee incentive stock options ............................. -- 4 541 --
Preferred stock dividends ....................................... -- -- -- (4,582)
Net income ...................................................... -- -- -- 1,951
------- --------- --------- ---------
BALANCE AT DECEMBER 31, 1997 ................................. 2,618 1,257 300,367 (309,863)
------- --------- --------- ---------

Conversion of 11,815 shares of preferred stock
into 40,976 share of common stock ............................ (18) 1 17 --
Issuance of 272,166 shares of common stock pursuant to
employee incentive stock options ............................. -- 2 269 --
Preferred stock dividends ....................................... -- -- -- (4,582)
Net loss ........................................................ -- -- -- (57,007)
------- --------- --------- ---------
BALANCE AT DECEMBER 31, 1998 ................................. $ 2,600 $ 1,260 $ 300,653 $(371,452)
======= ========= ========= =========
</TABLE>

See Notes to Consolidated Financial Statements.

31
<PAGE> 33

KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - INDUSTRY CONDITIONS AND LIQUIDITY

During 1998, the oil and gas industry experienced a worldwide excess of
supply over demand for oil and natural gas resulting in sharply reduced prices.
As a result, many companies in the oil and gas industry, including the Company,
experienced reduced profitability and cash flows which, in turn, created
significant liquidity problems. As discussed in Note 4 to the Consolidated
Financial Statements, although the Company was in compliance with its Credit
Facility debt covenants at December 31, 1998, the Company was not in compliance
as of March 31, 1999, which could result in all borrowings under such Credit
Facility being declared immediately due and payable and the Credit Facility
being terminated and the payment of other subordinated obligations being
accelerated. In addition other long-term debt repayments of $34.1 million are
scheduled to be made in December 1999. These uncertainties create substantial
doubt about the Company's ability to continue its operations as a going concern.
To address these liquidity issues, the Company is attempting to take the
measures discussed in the following paragraphs.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization and Operations. Kelley Oil & Gas Corporation (a Delaware
Corporation), its corporate subsidiaries and proportionate partnership interests
are referred to herein as the "Company". The Company is an independent oil & gas
company engaged in the exploration, development and acquisition of domestic oil
and gas properties, principally in the Gulf Coast region and northern Louisiana.

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. Cash payments attributable to interest on all

32
<PAGE> 34

indebtedness aggregated $19.2 million, $19.6 million and $26.5 million for the
years ended December 31, 1996, 1997 and 1998, respectively.

Financial Instruments. The Company's financial instruments consist of
cash and cash equivalents, receivables, payables and long term debt. As of
December 31, 1998, the estimated fair value of the Company's long-term debt was
$251 million. The fair value of such long-term debt 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.

Oil and Gas Properties. All of the Company's interests in its oil and
gas properties are located in the United States and are accounted for using the
successful efforts method. 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. Estimated future abandonment and site restoration
costs, net of anticipated salvage values, are amortized on a unit-of-production
basis over the life of the related reserves. Exploratory drilling costs are
initially capitalized pending determination of proved reserves but are charged
to expense if no proved reserves are found. Other exploration costs, including
geological and geophysical expenses, leasehold expiration costs and delay
rentals, are expensed as incurred. Unproved leasehold costs are capitalized and
are not amortized pending an evaluation of the exploration results. Unproved
properties are periodically assessed for impairment in value, with any
impairment charged to expense.

Property Impairment under SFAS 121. Under 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" ("SFAS 121"),
certain assets are required to be reviewed periodically for impairment whenever
circumstances indicate their carrying amount exceeds their fair value and may
not be recoverable. As a result of a decline in its proved reserves at January
1, 1999 from year-earlier levels, the Company performed an assessment of the
fair value of its oil and gas properties indicating an impairment should be
recognized as of year end. Under this analysis, the fair value for the Company's
proved oil and gas properties was estimated using escalated pricing and present
value discount factors reflecting risk assessments. The fair value of the
Company's unproved properties was predicated on current acreage cost estimates.
Based on this analysis, the Company recognized noncash impairment charges
against the carrying values of its proved and unproved oil and gas properties
under SFAS 121 aggregating $21.6 million and $4.1 million, respectively, at
December 31, 1998.

Other 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 lives of three to five years. Maintenance and repairs are
charged to expense as incurred.

Other Non-Current Assets. Other non-current assets consist primarily of
debt issue costs, net of accumulated amortization. These costs are amortized
over the anticipated term of the related debt.

Oil and Gas Revenues. The Company recognizes oil and gas revenue from
its interests in producing wells as oil and gas is produced and sold from those
wells. Oil and gas sold is not significantly different from the Company's
production entitlement. Revenues from gas marketing, net of cost of gas sold,
are included in oil and gas revenues and amounted to $1.8 million, $2.8 million
and $1.3 million for the years ended December 31, 1996, 1997 and 1998,
respectively.

Earnings per Share. In 1997, the Company implemented the Financial
Accounting Standards Board Statement of Financial Accounting Standards No. 128,
"Earnings Per Share" ("SFAS 128"). SFAS 128 establishes standards for computing
and presenting earnings per share ("EPS") and is effective for financial
statements issued for periods ending after December 15, 1997. This statement
requires restatement for all prior-period EPS data presented. The basic loss per
common share before extraordinary item and basic loss per common share as shown
on the Consolidated Statements of Income (Loss) reflects net income (loss)
before extraordinary item and net income (loss), respectively, less cumulative
preferred stock dividends, whether or not declared, divided by the weighted
average number of common

33
<PAGE> 35

shares outstanding during the respective years. The extraordinary loss per
common share for the year ended 1996 was $0.19. In calculating diluted income
(loss) per share, common shares issuable under stock options and upon conversion
of convertible subordinated debentures and convertible preferred stock are added
to the weighted average common shares outstanding when dilutive. For the years
ended December 31, 1996, 1997 and 1998, all potentially dilutive securities are
anti-dilutive and therefore are not included in the EPS calculations.
Potentially dilutive securities which could impact EPS in the future include
stock options granted to employees to purchase 4.5 million common shares, the
Company's 7 7/8% Convertible Subordinated Notes and 8 1/2% Convertible
Subordinated Debentures which can be converted into 2.5 million and 1.4 million
common shares, respectively, and the Company's $2.625 Convertible Preferred
Stock ("Preferred Stock") which can be can be converted into 6.0 million common
shares.

Stock Based Compensation. The Company applies Accounting Principles
Board Opinion No. 25 ("APB 25") and related Interpretations in accounting for
stock option and purchase plans. Under APB 25, compensation expense, if any, is
based on the intrinsic value of the equity instrument at the measurement date.
The Company has not recognized any compensation expense because the exercise
price of employee stock options equals the market price of the underlying stock
on the date of the grant.

Derivatives and Hedging Activities. See Note 10 for a discussion of
the Company's accounting policies related to hedging activities. In June 1998,
the Financial Accounting Standards Board issued Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities" ("SFAS 133"). SFAS 133 establishes accounting and reporting
standards for derivative instruments and hedging activities that require an
entity to recognize all derivatives as an asset or liability measured at its
fair value. Depending on the intended use of the derivatives, changes in its
fair value will be reported in the period of change as either a component of
earnings or a component of other comprehensive income.

SFAS 133 is effective for all fiscal quarters of fiscal years beginning
after June 15, 1999. Earlier application of SFAS 133 is encouraged, but not
prior to the beginning of any fiscal quarter that begins after issuance of the
Statement. Retroactive application to periods prior to adoption is not allowed.
The Company has not quantified the impact of adoption on its financial
statements or the date it intends to adopt.

Comprehensive Income. In June 1997, the Financial Accounting Standards
Board issued Statement of Financial Accounting Standards No. 130, "Reporting
Comprehensive Income" ("SFAS 130"). SFAS 130 establishes standards for reporting
and displaying comprehensive income and its components. SFAS 130 is effective
for periods beginning after December 15, 1997. The purpose of reporting
comprehensive income is to report a measure of all changes in equity of an
enterprise that results from recognized transactions and other economic events
of the period other than transactions with owners in their capacity as owners.
As of December 31, 1998, there are no adjustments ("Other Comprehensive Income")
to net income in deriving comprehensive income.

Risks and Uncertainties. The preparation of financial statements in
conformity with generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.

Changes in Presentation. Certain financial statement items in 1996 and
1997 have been reclassified to conform to the 1998 presentation.

NOTE 3 - ACQUISITION OF OIL AND GAS PROPERTIES

SPR Acquisition. On December 1, 1997, the Company purchased from SCANA
Petroleum Resources, Inc. ("SPR") substantially all of SPR's assets, including
its oil and gas properties, exploratory leasehold interests and associated
obligations, in exchange for approximately $110 million ("SPR Acquisition"),
subject to adjustment as provided by the Purchase and Sale Agreement between the
Company and SPR. The acquisition was accounted for using the purchase method of
accounting, and accordingly, the purchase price has been preliminarily allocated
to the assets

34
<PAGE> 36

acquired based on estimated fair values at the date of acquisition. The
operating results of the assets acquired from SPR have been included in Kelley's
Statements of Income (Loss) since December 1, 1997. The pro forma information
shown below assumes that the acquisition occurred at the beginning of each year
presented. Adjustments have been made to reflect changes in the Company's
results from the revenues and direct operating expenses of the producing
properties acquired from SPR, additional interest expense to finance the
acquisition, depreciation, depletion and amortization based on assigned fair
values to the assets acquired and general and administrative expenses incurred
from hiring additional employees. The unaudited pro forma financial data are not
necessarily indicative of financial results that would have occurred had the SPR
Acquisition occurred on January 1, 1996 and January 1, 1997, and should not be
viewed as indicative of operations in future periods.

(IN THOUSANDS, EXCEPT PER SHARE DATA)

<TABLE>
<CAPTION>
(UNAUDITED)
-----------------------------
YEAR ENDED DECEMBER 31,
-----------------------------
1996 1997
----------- -----------

<S> <C> <C>
Revenues......................................................................... $ 112,936 $ 112,142
Income (loss) before extraordinary item.......................................... (12,484) 1,315
Net income (loss)................................................................ (29,514) 1,315
Loss per common share............................................................ (0.29) (0.03)
</TABLE>

NOTE 4 - LONG TERM DEBT

Long Term Debt. The Company's long term debt at December 31, 1997 and
1998 is comprised of the following:

(IN THOUSANDS)

<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------
1997 1998
---------- ----------

<S> <C> <C>
Bank credit facilities............................................................ $ 111,300 $ 111,500
13 1/2% Senior Notes.............................................................. 435 435
10 3/8% Senior Subordinated Notes................................................. 120,615 150,662
7 7/8% Convertible Subordinated Notes............................................. 29,710 31,816
8 1/2% Convertible Subordinated Debentures........................................ 24,123 25,338
---------- ----------
286,183 319,751
Less current maturities........................................................ -- (32,251)
---------- -----------
$ 286,183 $ 287,500
========== ==========
</TABLE>

Bank Credit Facilities. The Company replaced its prior credit facility
with a new credit facility effective as of December 12, 1996 (the "Credit
Facility") that was subsequently amended and restated in connection with the SPR
Acquisition effective December 1, 1997. The borrowers under the Credit Facility
are the Company, Kelley Oil Corporation ("Kelley Oil") and Kelley Operating
Company, Ltd., with Concorde Gas Marketing, Inc. (a wholly-owned subsidiary of
the Company) and the Company's subsidiary partnerships as guarantors.

The Credit Facility provides for a maximum $140 million revolving
credit loan and matures, with all amounts owed thereunder becoming due and
payable on December 1, 2000. Availability under the Credit Facility is limited
to a borrowing base determined by, among other things, the proved oil and
natural gas reserves and other assets of the borrowers and the value of those
reserves based on the underlying prices for oil and natural gas. The Borrowing
Base is redetermined at least semiannually by the Agent under the Credit
Facility, with the consent of 100% of the lenders, and may be redetermined more
frequently at the election of the lenders or the borrowers. On April 14, 1998,
the

35
<PAGE> 37

Borrowing Base was set at $138 million and the threshold amount (the "Threshold
Amount"), which is the amount that would ordinarily be made available by the
lenders to a similar borrower under a borrowing base, was set at $125 million.
Following the Company's sale of its interest in the Waskom field in July 1998,
the Borrowing Base and Threshold Amount were reduced to $130 million and $117
million, respectively. As provided in the Credit Facility, on November 1, 1998
the Borrowing Base was reduced to equal the Threshold Amount of $117 million.

On December 29, 1998 the Borrowing Base under the Credit Facility was
maintained at $117 million and certain terms were amended, including: (i) an
increase in the margin borrowing rate to 250 basis points over LIBOR, (ii) a
reduction in the grace periods available under certain default provisions, (iii)
a change in the definition of majority banks for purposes of setting the
semi-annual Borrowing Base and implementing other provisions from 75% to 100%,
and (iv) a reduction in the time allowed to cure a Borrowing Base deficiency to
30 days.

As provided in the Credit Facility, a review of the Borrowing Base is
expected to be performed by the Company's banks by May 1, 1999. While the amount
of the Borrowing Base will not be known until such time as the banks make the
redetermination, the Company has been advised that the redetermination likely
will result in the Borrowing Base being lowered. If the Borrowing Base were to
be lowered below the level of outstanding advances, the Company would be
required to repay 100% of the excess within thirty days. Further, no additional
borrowings would be available to the Company under the Credit Facility until
amounts outstanding are less than the Borrowing Base.

Further, under the current terms of the Credit Facility, certain of the
Company's financial covenants thereunder become more restrictive in future
periods. Specifically, the interest coverage ratio increases from 2.0/1 to
2.25/1 beginning with the rolling four quarters ended March 31, 1999. The
Company was not in compliance with this covenant under the Credit Facility as of
March 31, 1999, which could result in all borrowings under the Credit Facility
being declared immediately due and payable, the Credit Facility being terminated
and the payment of other subordinated obligations being accelerated. The
indebtedness under the Credit Facility is secured by substantially all of the
oil and natural gas assets of the Company. The weighted average interest rate on
borrowings outstanding at December 31, 1998 under the Credit Facility was 7.03%.

In addition to the $140 million revolving credit loan, at December 31,
1997 the Credit Facility, as amended, provided a $32.3 million term loan ("Term
Loan Facility") for use by the Company in the event that holders of the
Company's 7 7/8% Convertible Subordinated Notes exercised their redemption right
that occurred in connection with the exercise by Contour of its option to
purchase additional common shares of the Company. Holders of $0.2 million of
these notes exercised their redemption right in January 1998, and as a result,
the Term Loan Facility was terminated without being used on January 23, 1998.

So long as no default or event of default (as defined in the Credit
Facility) is continuing, borrowings under the Credit Facility, as amended, bear
interest, at the option of the borrowers, at either (i) LIBOR plus 2.5% or (ii)
the higher of (a) the agent's prime rate plus 1.1% and (b) the federal funds
rate plus 1.5%. The Borrowers incur a quarterly commitment fee of 0.50% per
annum on the average unused portion of the borrowing base.

The Credit Facility contains covenants which, among other things, limit
the amount of debt the Company may incur, limit the placement of liens on its
assets, limit lease transactions, limit its ability to enter into certain
hedging transactions, restrict its ability to merge with or into another person
and prevent it from prepaying certain subordinated indebtedness unless certain
conditions are met. The Credit Facility also restricts the payment of dividends.
Further, certain covenants require that, for specified periods, the Company
maintain specified ratios between EBITDAX and senior indebtedness and EBITDAX
and interest on indebtedness.

36
<PAGE> 38

1996 Fourth Quarter Extraordinary Loss. 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 Notes 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 which allowed it to amend the 13 1/2% Senior Notes 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. These
transactions resulted in an extraordinary loss in the fourth quarter of 1996 of
$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. In connection with the refinancing
of the 13 1/2% Senior Notes, the Company issued an aggregate principal amount of
$125.0 million of 10 3/8% Senior Subordinated Notes due 2006 (the "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
Company may redeem up to 35% of the principal amount of the 10 3/8% Senior
Subordinated Notes before October 15, 1999 with the proceeds of an equity
offering (provided that either at least $75.0 million aggregate principal amount
of such notes remains outstanding or such redemption retires such notes in their
entirety). 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. Kelley Oil Corporation, a
wholly-owned subsidiary of the Company and Kelley Operating Company, Ltd., an
indirect wholly-owned partnership of the Company are guarantors of the 10 3/8%
Senior Subordinated Notes.

On February 3, 1997, the Company completed an exchange of $125.0
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.

In May 1998, the Company sold $30.0 million principal amount of the
Company's 10 3/8% Senior Subordinated Notes due 2006, Series C ("Series C
Notes") at a cash price of $1,015 per $1,000 principal amount. The net proceeds
received were used to reduce outstanding borrowings under the Company's bank
credit facility ("Credit Facility"). The Series C Notes are redeemable at the
option of the Company, in whole or in part, at redemption prices declining
ratably from 105.19% on October 15, 2001 to 100% at October 15, 2003 and
thereafter. The Company may redeem up to 35% of the original principal amount of
the Series C Notes before October 15, 1999 at 110.38% with the proceeds of an
equity offering (provided that either at least $18.0 million aggregate principal
amount of such notes remains outstanding or such redemption retires such notes
in their entirety). The Series C 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 holders of the Series C Notes also can require
the Company to repurchase the notes at 101% of the principal amount upon a
Change of Control, as defined. Kelley Oil Corporation, a wholly owned subsidiary
of the Company, and Kelley Operating Company, Ltd., an indirect wholly owned
partnership of the Company, are guarantors of the Series C Notes.

The Series C Notes were sold pursuant to Rule 144A of the Securities
Act of 1933. In issuing the Series C Notes, the Company agreed to use its best
efforts to register under the Securities Act notes identical in terms to the
Series C Notes ("Series D Notes"). The Company completed the exchange of the
Series C Notes for the Series D Notes on November 12, 1998.

37
<PAGE> 39

7 7/8% Convertible Subordinated Notes and 8 1/2% Convertible
Subordinated Debentures. The Company has outstanding 7 7/8% Convertible
Subordinated Notes due December 1999 (the "7 7/8% Subordinated Notes") in the
aggregate principal amount at maturity of $34.1 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"). Each $1,000 face value amount of the 7 7/8% Subordinated Notes is
convertible into 71.263 shares of the Company's Common Stock or 35.632 shares of
the Company's Common Stock and 7.435 shares of Preferred Stock. Each $1,000 face
value amount of the 8 1/2% Subordinated Debentures is convertible into 51.864
shares of the Company's Common Stock or 25.932 shares of the Company's Common
Stock and 5.411 shares of Preferred Stock.

Under the Indenture for the 7 7/8% Subordinated Notes, as amended, a
"Change in Control" is defined to occur if, among other things, any person
becomes the beneficial owner of securities representing 50% or more of the
equity interests in the Company. With the purchase by Contour of 27 million
shares on December 1, 1997, each holder of 7 7/8% Subordinated Notes, was
afforded the right, at the holder's option, subject to terms and conditions of
the Indenture, to require the Company to redeem all or any part of the holder's
notes by January 22, 1998 at a specified cash price. Holders redeemed $0.2
million of the 7 7/8% Subordinated Notes under the Change of Control provision.

Debt Maturities. The Company has aggregate debt maturities of $34.6
million in 1999, $138.4 million in 2000 and $155.0 million in 2006.

NOTE 5 - STOCKHOLDERS' DEFICIT

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 its 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. Contour voluntarily exercised its option in full on December 1,
1997 to partially fund the SPR Acquisition.

Preferred Stock. In May 1994, Kelley Oil completed a public offering of
1,380,000 shares of $2.625 Preferred Stock ("KOIL Preferred Stock") at $25 per
share. Each outstanding share of KOIL Preferred Stock was converted in the
Consolidation into one share of the Company's Preferred Stock, which has the
same terms as the KOIL 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
Preferred Stock.

In January 1996, the Company suspended the payment of the quarterly
Preferred Stock dividend scheduled for February 1, 1996 to conserve cash. On
April 15, 1997, the Board of Directors of the Company declared a dividend of
$2.625 per preferred share (approximately $4.6 million), which was paid on May
1, 1997. On April 14, 1998, the Company declared a dividend of $2.625 per share
of Preferred Stock (approximately $4.6 million), which was paid on April 30,
1998. The Company has not declared the quarterly dividends of $0.65625 per
preferred share for February 1, 1998,

38
<PAGE> 40

May 1, 1998, August 1, 1998, November 1, 1998 and February 1, 1999, aggregating
approximately $5.7 million, covering 5 quarters. Future dividends on the
Preferred Stock are prohibited under the agreement covering the New Credit
Facility. 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 3.47 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 Stock
conversion price 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. As of December 31, 1995, 1,861,619 shares of ESOP
Preferred Stock were outstanding and held by the Company's Employee Stock
Ownership Plan ("ESOP"). 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 6 - EMPLOYEE STOCK PLANS

Employee Stock Options. 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,
except options granted during 1997 and 1998 which are subject to a four year
vesting period.

Stock option activity for the Company during 1996, 1997 and 1998 was as
follows:

<TABLE>
<CAPTION>
1996 1997 1998
-------------------- ------------------- -------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
OPTIONS IN THOUSANDS OPTIONS PRICE OPTIONS PRICE OPTIONS PRICE
------- -------- ------- -------- ------- --------

<S> <C> <C> <C> <C> <C> <C>
Stock options outstanding, beginning of year ..... 2,105 $ 2.38 4,589 $ 1.63 4,601 $ 1.75
Granted ....................................... 2,520 1.01 482 2.61 727 2.20
Exercised ..................................... (36) 2.38 (415) 1.31 (272) 1.00
Surrendered or expired ........................ -- -- (55) 2.62 (559) 1.73
------ ------ ------

Stock options outstanding, end of year ........... 4,589 $ 1.63 4,601 $ 1.75 4,497 $ 1.87
====== ====== ====== ====== ====== ======
</TABLE>

In February 1995, all previously issued options to the extent
outstanding, aggregating options to acquire 234,000 shares at prices ranging
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.

39
<PAGE> 41

At December 31, 1998, approximately 3.6 million shares were available
for future option grants.

The following table summarizes information about the options
outstanding at December 31, 1998:

<TABLE>
<CAPTION>
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------------------------------------- --------------------------------
WEIGHTED WEIGHTED
AVERAGE AVERAGE
RANGE OF REMAINING WEIGHTED EXERCISE
EXERCISE PRICE OPTIONS CONTRACTUAL AVERAGE OPTIONS PRICE
LIFE (YEARS) EXERCISE PRICE
- --------------------- ------------- ----------------- ----------------- -------------- -------------

The weighted average fair value of options granted during 1996, 1997
and 1998 was $0.59, $1.51 and $1.46, respectively. The fair value of the options
granted was estimated on the date of grant using the Black-Scholes
option-pricing model with the following assumptions: weighted average risk-free
interest rate of 6.8% for 1996, 6.4% for 1997 and 5.2% for 1998; an expected
volatility of 60% for 1996 and 1997 and 78% for 1998; expected life of five
years and no dividend yield for all three years.

The Company applies 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 recognized based upon the fair market value at the grant
dates for awards under those plans consistent with the method of Statement of
Financial Accounting Standards No. 123, "Accounting for Stock Based
compensation", the Company's net loss and earnings per share for the years ended
December 31, 1996, 1997 and 1998 would have been as reflected in the pro forma
amounts indicated below:

<TABLE>
<CAPTION>
1996 1997 1998
--------- --------- ---------

<S> <C> <C> <C>
Net income (loss) before extraordinary item (in thousands)............ $ (14,512) $ 1,319 $ (57,708)
Loss per common share before extraordinary item....................... (.21) (.03) (.49)

Net income (loss) (in thousands)...................................... (31,542) $ 1,319 $ (57,708)
Loss per common share................................................. (.40) (.03) (.49)
</TABLE>

ESOP/401K. Kelley Oil established the ESOP effective January 1, 1984
for the benefit of substantially all of its employees. No ESOP contributions
were made in 1996. 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, 1997 and 1998, the Company made matching
contributions totaling $0.1 million, $0.2 million and $0.3 million,
respectively.

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<PAGE> 42

NOTE 7 - INCOME TAXES

The following table sets forth a reconciliation of the statutory
federal income tax for the years ended December 31, 1996, 1997 and 1998:

(IN THOUSANDS)

<TABLE>
<CAPTION>
1996 1997 1998
--------- --------- ---------

<S> <C> <C> <C>
Income (loss) before income taxes ............................... $ (28,965) $ 1,951 $ (57,007)
--------- --------- ---------
Income tax expense (benefit) computed at statutory rates ........ (9,848) 663 (19,382)
Increase in valuation allowance .............................. 16,322 301 16,272
Adjustment to net operating loss carryforward and other ...... (7,209) (1,459) 2,463
Permanent differences:
Nondeductible expenses ....................................... 735 708 700
Other-net .................................................... -- (213) (53)
--------- --------- ---------
Tax expense (benefit) ...................................... $ -- $ -- $ --
========= ========= =========
</TABLE>

No federal income taxes were paid for the years ended December 31,
1996, 1997 and 1998.

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>
1996 1997 1998
--------- --------- ----------

<S> <C> <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.......................................... 42,696 32,210 43,730
Net operating loss carryforwards..................................... 62,179 72,992 77,741
Charitable contribution carryforwards................................ 78 52 54
Alternative minimum tax credit carryforwards......................... 21 21 21
Valuation allowance.................................................. (104,974) (105,275) (121,546)
--------- --------- ----------
Total deferred tax assets............................................ -- -- --
--------- --------- ---------
Net deferred tax liability.............................................. $ -- $ -- $ --
========= ========= =========
</TABLE>

Net Operating Loss Carryforwards and Alternative Minimum Tax Credits.
As of December 31, 1998, the Company had cumulative net operating loss
carryforwards ("NOL") for federal income tax purposes of approximately $228
million, which expire in 2000 through 2018, and net operating loss carryforwards
for alternative minimum tax purposes of approximately $218 million, which expire
in 2008 through 2018. Due to previous ownership changes, future utilization of
the net operating loss carry forwards will be limited by Internal Revenue Code
section 382.

41
<PAGE> 43

NOTE 8 - RELATED PARTY TRANSACTIONS

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 December 31, 1998, the Company owned 19.2 million units
(91.9%) in the 1994 DDP, together with its 3.94% general partner interest.

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. In 1997, Kelley Oil reduced the estimate for
Committed Expenditures to $58.0 million based on the amount of committed capital
actually used and committed or allocated to drilling activities by the end of
the Commitment Period. In accordance with the 1994 DDP's partnership agreement,
the 1994 DDP distributed the Outside Share of uncommitted capital to its
unitholders other than Kelley Oil aggregating $0.3 million in March 1996 and
$0.1 million in July 1997.

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 December 31, 1998, Kelley Oil owned 13.4 million units (83.7%)
in the 1992 DDP, together with its 3.94% general partner interest. As of
December 31, 1998, the 1992 DDP was indebted to Kelley Oil for loans aggregating
$2.5 million ($0.4 million, net of intercompany eliminations). The Company
recorded interest income on this indebtedness of $45,000 in 1998, net of
intercompany eliminations.

Reimbursements from Affiliated Programs. The Company 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 $0.2 million, $0.1 million and $21,000 in
1996, 1997 and 1998, respectively.

Interest on DDP Commitments. During 1996, 1997 and 1998, the Company
paid or accrued interest at a market rate in the amounts, net of intercompany
elimination, of $91,000, $11,000 and zero, respectively, on deferred
subscription commitments to DDPs.

Advisory Fees. In connection with the Contour Transaction, the Company
entered into an agreement (the "Advisory Agreement") with Bessemer Partners &
Co. ("BPCO"), an affiliate of Bessemer, providing for the engagement of BPCO to
provide the Company with financial advisory services. Under the Advisory
Agreement, BPCO has assisted the Company in arranging a new credit facility and
negotiating the related agreements and is assisting the Company in restructuring
its current capital structure. For its services under the Advisory Agreement,
BPCO received an advisory fee of $2.0 million at the closing of the Contour
Transaction and $500,000 in each of December 1996, 1997 and 1998, and will
receive an additional $500,000 in each December of 1999, 2000 and 2001. In
addition, BPCO is entitled to reimbursement of expenses incurred in connection
with rendering advisory services. The Company also has agreed to indemnify BPCO
and its affiliates against certain liabilities under the Advisory Agreement.

NOTE 9 - COMMITMENTS AND CONTINGENCIES

Significant Customers. Substantially all of the Company's receivables
are due from a limited number of natural gas transmission companies and other
gas purchasers. During 1998, natural gas sales to three purchasers accounted for
48%, 22% and 18% of the Company's total sales. To date, this concentration has
not had a material adverse effect on the consolidated financial condition of the
Company.

Litigation. As previously disclosed, 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. 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 non-management 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

42
<PAGE> 44

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, plus interest from March 3, 1995 through the payment date. On
April 29, 1997, the U.S. Court of Appeals for the Fifth Circuit affirmed the
final judgement and order of the District Court. On August 4, 1997, the Company
made a cash payment of $1.7 million which included $0.2 million of interest.

Restructuring Expenses. In 1996, the Company incurred restructuring
expenses of $4.3 million associated primarily with staff reductions, related
severance settlements and reorganization costs. Accrued expenses on the balance
sheet include $0.9 million and $0.2 million at December 31, 1997 and 1998,
respectively, related to the unpaid portion of these charges.

Leases. 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, 1996, 1997 and 1998 were $1.3 million, $0.8 million and
$0.6 million, respectively. For the balance of the lease terms, minimum rentals
are as follows:

(IN THOUSANDS)

<TABLE>
<S> <C>
1999............................................................... $ 667
2000............................................................... 636
2001 .............................................................. 341
2002 .............................................................. 39
2003............................................................... 7
-------
Total.............................................................. $ 1,690
</TABLE>

The terms of the Company's office space lease provide that the Company
may terminate its rental obligation upon six months notice and incurring a
maximum obligation of $0.2 million.

NOTE 10 - HEDGING ACTIVITIES

The Company periodically uses forward sales contracts, natural gas
price swap agreements, natural gas basis swap agreements and options to reduce
exposure to downward price fluctuations on its natural gas production. The
Company does not engage in speculative transactions. During 1998, the Company
used price and basis swap agreements. Price swap agreements generally provide
for the Company to receive or make counterparty payments on the differential
between a fixed price and a variable indexed price for natural gas. Basis swap
agreements generally provide for the Company to receive or make counterparty
payments on the differential between a variable indexed price and the price it
receives from the sale of natural gas production, and are used to hedge against
unfavorable price movements in the relationship between such variable indexed
price and the price received for such production. Gains and losses realized by
the Company from hedging activities are included in oil and gas revenues and
average sales prices in the period that the related production is sold. The
Company's hedging activities also cover the oil and gas production attributable
to the interest in such production of the public unitholders in its subsidiary
partnerships.

43
<PAGE> 45

NOTE 11 - GUARANTOR FINANCIAL STATEMENTS

Kelley Oil Corporation, a wholly-owned subsidiary of the Company and
Kelley Operating Company Ltd., an indirect wholly-owned partnership of the
Company are guarantors of the Company's Series B and Series D 10 3/8% Senior
Subordinated Notes due 2006. The following guarantor consolidating condensed
financial statements present:

1. Consolidating condensed balance sheets as of December 31, 1997
and 1998, consolidating condensed statements of income (loss) for
each of the years ended December 31, 1996, 1997 and 1998 and
consolidating condensed statements of cash flows for each of the
years ended December 31, 1996, 1997 and 1998.

2. Kelley Oil & Gas Corporation (the "Parent"), combined Guarantor
Subsidiaries and combined Non-Guarantor Subsidiaries, all with
their investments in subsidiaries accounted for using the equity
method.

3. Elimination entries necessary to consolidate the Parent and all
of its subsidiaries.

CONSOLIDATING CONDENSED BALANCE SHEET

DECEMBER 31, 1997
(IN THOUSANDS)

<TABLE>
<CAPTION>
COMBINED COMBINED
GUARANTOR NON-GUARANTOR
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
---------- ------------ ------------- ------------ ------------

<S> <C> <C> <C> <C> <C>
ASSETS:
Current assets........................ $ 427,445 $ 212,780 $ 18,926 $ (632,293) $ 26,858
Property and equipment, net........... -- 276,744 17,698 (829) 293,613
Other non-current assets, net......... (141,957) 24,418 -- 119,670 2,131
---------- ---------- -------- ---------- ----------
Total assets........................ $ 285,488 $ 513,942 $ 36,624 $ (513,452) $ 322,602
========== ========== ======== ========== ==========

LIABILITIES AND STOCKHOLDERS' DEFICIT:
Current liabilities................... $ 4,926 $ 657,128 $ 12,279 $ (632,293) $ 42,040
Long term debt........................ 286,183 -- -- -- 286,183
Stockholders' deficit................. (5,621) (143,186) 24,345 118,841 (5,621)
---------- ---------- -------- ---------- ----------
Total liabilities and
stockholders' deficit........... $ 285,488 $ 513,942 $ 36,624 $ (513,452) $ 322,602
========== ========== ======== ========== ==========
</TABLE>

44
<PAGE> 46
CONSOLIDATING CONDENSED BALANCE SHEET

DECEMBER 31, 1998
(IN THOUSANDS)